================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2001
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES ACT
OF 1934
FOR THE TRANSITION PERIOD FROM____________TO____________
COMMISSION FILE NO. 1-13726
CHESAPEAKE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
<Table>
OKLAHOMA 73-1395733
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
6100 NORTH WESTERN AVENUE
OKLAHOMA CITY, OKLAHOMA 73118
(Address of principal executive offices) (Zip Code)
</Table>
(405) 848-8000
(Registrant's telephone number, including area code)
---------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
YES [X] NO [ ]
At October 23, 2001, there were 164,475,498 shares of our $.01 par
value common stock outstanding.
================================================================================
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
INDEX TO FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2001
<Table>
<Caption>
PART I. FINANCIAL INFORMATION
PAGE
----
Item 1. Consolidated Financial Statements:
Consolidated Balance Sheets at December 31, 2000 and
September 30, 2001 (Unaudited) 3
Consolidated Statements of Operations for the Three Months and
Nine Months Ended September 30, 2000 and 2001 (Unaudited) 4
Consolidated Statements of Cash Flows for the Nine Months Ended
September 30, 2000 and 2001 (Unaudited) 5
Consolidated Statements of Comprehensive Income
for the Three Months and Nine Months Ended
September 30, 2000 and 2001 (Unaudited) 6
Notes to Consolidated Financial Statements (Unaudited) 7
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations 22
Item 3. Quantitative and Qualitative Disclosures About Market Risks 29
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 33
Item 2. Changes in Securities and Use of Proceeds 33
Item 3. Defaults Upon Senior Securities 33
Item 4. Submission of Matters to a Vote of Security Holders 33
Item 5. Other Information 33
Item 6. Exhibits and Reports on Form 8-K 33
</Table>
2
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<Table>
<Caption>
DECEMBER 31, SEPTEMBER 30,
ASSETS 2000 2001
------------ ------------
($ IN THOUSANDS)
CURRENT ASSETS:
Cash and cash equivalents ..................................................................... $ -- $ 17,042
Restricted cash ............................................................................... 3,500 --
Accounts receivable:
Oil and gas sales ........................................................................... 50,109 16,449
Oil and gas marketing sales ................................................................. 46,953 40,346
Joint interest and other, net of allowances of $1,085,000 and $1,077,000,
respectively ............................................................................ 15,998 40,456
Related parties ............................................................................. 4,383 9,946
Deferred income tax asset ..................................................................... 40,819 --
Short-term derivative instruments ............................................................. -- 175,964
Inventory ..................................................................................... 3,167 4,728
Other ......................................................................................... 1,997 3,733
------------ ------------
Total Current Assets .................................................................... 166,926 308,664
------------ ------------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at cost based on full-cost accounting:
Evaluated oil and gas properties ............................................................ 2,590,512 3,318,487
Unevaluated properties ...................................................................... 25,685 60,686
Less: accumulated depreciation, depletion and amortization .................................. (1,770,827) (1,893,821)
------------ ------------
845,370 1,485,352
Other property and equipment .................................................................. 79,898 115,672
Less: accumulated depreciation and amortization ............................................... (37,034) (40,528)
------------ ------------
Total Property and Equipment ............................................................ 888,234 1,560,496
------------ ------------
OTHER ASSETS:
Investment in Gothic Energy Corporation ....................................................... 126,434 --
Deferred income tax asset ..................................................................... 229,823 94,819
Long-term derivative instruments .............................................................. -- 63,066
Long-term investments, other .................................................................. 2,000 47,767
Other assets .................................................................................. 27,009 15,786
------------ ------------
Total Other Assets ...................................................................... 385,266 221,438
------------ ------------
TOTAL ASSETS .................................................................................... $ 1,440,426 $ 2,090,598
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Notes payable and current maturities of long-term debt ........................................ $ 836 $ 817
Accounts payable .............................................................................. 62,940 83,286
Accrued property acquisitions ................................................................. 22,530 --
Accrued interest .............................................................................. 17,537 32,989
Other accrued liabilities ..................................................................... 21,637 34,913
Revenues and royalties due others ............................................................. 35,682 28,557
Income tax payable ............................................................................ 1,539 3,354
------------ ------------
Total Current Liabilities ............................................................... 162,701 183,916
------------ ------------
LONG-TERM DEBT, NET ............................................................................. 944,845 1,268,414
------------ ------------
REVENUES AND ROYALTIES DUE OTHERS ............................................................... 7,798 12,002
------------ ------------
DEFERRED INCOME TAX LIABILITY ................................................................... 11,850 9,340
------------ ------------
OTHER LIABILITIES ............................................................................... -- 3,943
------------ ------------
CONTINGENCIES (NOTE 4)
STOCKHOLDERS' EQUITY:
Preferred Stock, $.01 par value, 10,000,000 shares authorized; 624,037 and 0 shares
of 7% cumulative convertible stock issued and outstanding at December 31, 2000 and
September 30, 2001, entitled in liquidation to $31.2 million and $0 million, respectively ... 31,202 --
Common Stock, par value of $.01, 350,000,000 shares authorized; 157,819,171 and 169,259,778
shares issued at December 31, 2000 and September 30, 2001, respectively ..................... 1,578 1,693
Paid-in capital ............................................................................... 963,584 1,044,821
Accumulated deficit ........................................................................... (659,286) (491,918)
Accumulated other comprehensive income (loss) ................................................. (3,901) 78,369
Less: treasury stock, at cost; 4,788,747 and 4,792,529 common shares at December 31,
2000 and September 30, 2001, respectively ................................................... (19,945) (19,982)
------------ ------------
Total Stockholders' Equity .............................................................. 313,232 612,983
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ...................................................... $ 1,440,426 $ 2,090,598
============ ============
</Table>
The accompanying notes are an integral part of these
consolidated financial statements.
3
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
<Table>
<Caption>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ ------------------------
2000 2001 2000 2001
---------- ---------- ---------- ----------
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
REVENUES:
Oil and gas sales .................................................... $ 123,971 $ 177,746 $ 311,485 $ 574,190
Risk management income ............................................... -- 32,260 -- 94,715
Oil and gas marketing sales .......................................... 44,211 28,905 105,821 123,071
---------- ---------- ---------- ----------
Total Revenues ................................................... 168,182 238,911 417,306 791,976
---------- ---------- ---------- ----------
OPERATING COSTS:
Production expenses .................................................. 11,696 19,303 36,822 55,933
Production taxes ..................................................... 6,198 7,063 17,131 31,349
General and administrative ........................................... 3,377 3,240 9,597 10,114
Oil and gas marketing expenses ....................................... 42,917 27,946 102,583 119,337
Oil and gas depreciation, depletion and amortization ................. 25,227 46,821 74,587 124,904
Depreciation and amortization of other assets ........................ 1,849 2,164 5,551 5,954
---------- ---------- ---------- ----------
Total Operating Costs ............................................ 91,264 106,537 246,271 347,591
---------- ---------- ---------- ----------
INCOME FROM OPERATIONS ................................................ 76,918 132,374 171,035 444,385
---------- ---------- ---------- ----------
OTHER INCOME (EXPENSE):
Interest and other income ............................................ 867 132 3,726 1,384
Interest expense ..................................................... (21,680) (24,104) (64,357) (72,977)
Gothic standby credit facility costs ................................. -- -- -- (3,392)
---------- ---------- ---------- ----------
Total Other Income (Expense) ..................................... (20,813) (23,972) (60,631) (74,985)
---------- ---------- ---------- ----------
INCOME BEFORE INCOME TAX AND EXTRAORDINARY ITEM ....................... 56,105 108,402 110,404 369,400
INCOME TAX EXPENSE .................................................... 1,416 43,394 2,879 148,619
---------- ---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM ...................................... 54,689 65,008 107,525 220,781
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt, net of applicable income tax ... -- -- -- (46,000)
---------- ---------- ---------- ----------
NET INCOME ............................................................ 54,689 65,008 107,525 174,781
Preferred stock dividends ............................................ (965) -- (7,914) (728)
Gain (loss) on repurchase of preferred stock ......................... (5,321) -- 6,574 --
---------- ---------- ---------- ----------
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS ........................... $ 48,403 $ 65,008 $ 106,185 $ 174,053
========== ========== ========== ==========
EARNINGS PER COMMON SHARE -- BASIC:
Income before extraordinary item ..................................... $ 0.33 $ 0.40 $ 0.88 $ 1.36
Extraordinary item ................................................... -- -- -- (0.28)
---------- ---------- ---------- ----------
Net income ........................................................... $ 0.33 $ 0.40 $ 0.88 $ 1.08
========== ========== ========== ==========
EARNINGS PER COMMON SHARE -- ASSUMING DILUTION:
Income before extraordinary item ..................................... $ 0.31 $ 0.38 $ 0.73 $ 1.29
Extraordinary item ................................................... -- -- -- (0.27)
---------- ---------- ---------- ----------
Net income ........................................................... $ 0.31 $ 0.38 $ 0.73 $ 1.02
========== ========== ========== ==========
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT
SHARES OUTSTANDING (IN THOUSANDS):
Basic ................................................................ 146,593 164,440 121,089 161,603
========== ========== ========== ==========
Assuming dilution .................................................... 158,847 170,384 147,428 170,937
========== ========== ========== ==========
</Table>
The accompanying notes are an integral part of these
consolidated financial statements.
4
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<Table>
<Caption>
NINE MONTHS ENDED
SEPTEMBER 30,
----------------------------
2000 2001
------------ ------------
($ IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ................................................................ $ 107,525 $ 174,781
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, depletion and amortization ................................. 77,434 127,987
Risk management income ................................................... -- (94,715)
Extraordinary loss on early extinguishment of debt ....................... -- 46,000
Deferred income taxes .................................................... 2,879 148,619
Write-off of credit facility cost ........................................ -- 3,392
Amortization of loan costs ............................................... 2,704 2,871
Amortization of bond discount ............................................ 63 700
Accretion of Gothic note premium ......................................... -- (750)
Loss on sale of fixed assets and other ................................... 8 48
Equity in losses of equity investees ..................................... 131 1,331
Bad debt expense ......................................................... 256 --
Other .................................................................... (47) 274
------------ ------------
Cash provided by operating activities before changes in
current assets and liabilities ...................................... 190,953 410,538
Changes in current assets and liabilities ................................ (16,239) 30,418
------------ ------------
Cash provided by operating activities .................................. 174,714 440,956
------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of oil and gas properties ..................... (127,811) (314,452)
Purchases of oil and gas properties ....................................... (36,315) (76,055)
Sales of oil and gas properties ........................................... 1,429 1,432
Sales of non-oil and gas assets ........................................... 1,134 734
Additions to buildings and other fixed assets ............................. (5,707) (13,049)
Additions to drilling rig equipment ....................................... -- (15,393)
Additions to long-term investments ........................................ (6,194) (37,206)
Investment in Gothic Energy Corporation ................................... (24,622) --
Additions to other assets ................................................. -- (12,340)
Other ..................................................................... (2,482) (174)
------------ ------------
Cash used in investing activities ...................................... (200,568) (466,503)
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings ........................................ 166,000 372,000
Payments on long-term borrowings .......................................... (158,500) (208,000)
Cash received from issuance of senior notes ............................... -- 786,664
Cash paid to purchase senior notes ........................................ -- (830,382)
Cash paid for redemption premium on senior notes .......................... -- (75,639)
Cash received from exercise of stock options .............................. 1,005 2,929
Cash paid for preferred stock dividend .................................... -- (1,092)
Cash payments with preferred stock swaps .................................. (8,269) --
Cash paid in settlement of make-whole provision related to common stock ... -- (3,336)
Other ..................................................................... -- (10)
------------ ------------
Cash provided by financing activities .................................. 236 43,134
------------ ------------
EFFECT OF CHANGES IN EXCHANGE RATE ON CASH .................................. (313) (545)
------------ ------------
NET DECREASE IN CASH AND CASH EQUIVALENTS ................................... (25,931) 17,042
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD .............................. 38,658 --
------------ ------------
CASH AND CASH EQUIVALENTS, END OF PERIOD .................................... $ 12,727 $ 17,042
============ ============
</Table>
The accompanying notes are an integral part of these
consolidated financial statements.
5
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
<Table>
<Caption>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ ------------------------
2000 2001 2000 2001
---------- ---------- ---------- ----------
($ IN THOUSANDS)
Net income ........................................................... $ 54,689 $ 65,008 $ 107,525 $ 174,781
Other comprehensive income (loss), net of income tax:
Foreign currency translation adjustments ........................... (1,165) (2,826) (4,118) (3,551)
Cumulative effect of accounting change for financial derivatives ... -- -- -- (53,580)
Change in derivative fair value .................................... -- 64,240 -- 202,163
Reclassification of settled contacts ............................... -- (34,786) -- (60,844)
Ineffectiveness portion of derivatives qualifying for hedge
accounting ....................................................... -- (958) -- (1,918)
---------- ---------- ---------- ----------
Other comprehensive income ........................................... $ 53,524 $ 90,678 $ 103,407 $ 257,051
========== ========== ========== ==========
</Table>
The accompanying notes are an integral part of these
consolidated financial statements.
6
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2001
(UNAUDITED)
1. BASIS OF PRESENTATION AND ACCOUNTING POLICIES
Principles of Consolidation - The accompanying unaudited consolidated financial
statements of Chesapeake Energy Corporation and Subsidiaries 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 nine months ended September 30, 2001 are not
necessarily indicative of the results to be expected for the full year. This
Form 10-Q relates to the three and nine months ended September 30, 2000 (the
"Prior Quarter" and "Prior Period," respectively) and the three and nine months
ended September 30, 2001 (the "Current Quarter" and "Current Period,"
respectively).
Change in Accounting Method - Effective January 1, 2001, we adopted Statement of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities. This statement establishes accounting and reporting
guidelines for our hedging activities. It requires that all derivative
instruments be recognized as assets or liabilities in the consolidated balance
sheet measured at fair value. The accounting for changes in the fair value of a
derivative instrument depends on the intended use of the derivative and the
resulting designation. For derivative instruments designated as cash flow hedges
which meet the effectiveness guidelines of SFAS 133, changes in fair value are
recognized in other comprehensive income until the hedged item is recognized in
earnings. Hedge effectiveness is measured at least quarterly based on the
relative changes in fair value between the derivative contract and the hedged
item over time. Any change in fair value resulting from ineffectiveness, as
defined by SFAS 133, is recognized immediately in earnings. Changes in fair
value of contracts that do not meet the SFAS 133 definition of a cash flow hedge
are also recognized in earnings.
Adoption of SFAS 133 at January 1, 2001 resulted in the recognition of $9.3
million of current derivative assets and $98.6 million in current derivative
liabilities. The cumulative effect of the accounting change decreased
accumulated other comprehensive income by $53.6 million, net of income tax, but
did not have an effect on our net income or earnings per share amounts.
All of our derivative instruments have been executed in connection with our oil
and natural gas hedging program. The realized derivative profit or loss is
included in oil and gas sales in the period for which the underlying production
was hedged.
If a derivative which qualified for cash flow hedge accounting is liquidated or
sold prior to maturity, the gain or loss at the time of termination remains in
accumulated other comprehensive income to be amortized into oil and gas sales
over the original term of the instrument. If a derivative which does not qualify
for cash flow hedge accounting is liquidated or sold prior to maturity, the gain
or loss at the time of termination will be amortized into oil and gas sales over
the original term of the instrument.
2. OIL AND GAS PROPERTIES
We utilize the full cost method of accounting for costs related to our oil and
gas properties. Under this method, all such costs (productive and nonproductive)
are capitalized and amortized on an aggregate basis over the estimated lives of
the properties using the units-of-production method. These capitalized costs are
subject to a ceiling test, however, which limits such pooled costs to the
aggregate of the present value of future net revenues attributable to proved oil
and gas reserves discounted at 10% plus the lower of cost or market value of
unproved properties. The full cost ceiling is evaluated at the end of each
quarter. At September 30, 2001, our unamortized costs of oil and gas properties
exceeded this ceiling amount by approximately $220 million due to low gas prices
in effect on that date. The market price for natural gas at Henry Hub was $1.83
on September 28, 2001. However, due to the subsequent recovery in market prices
for natural gas, we were not required to record a write-down of oil and gas
properties. A
7
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2001
(UNAUDITED)
decline in gas and oil prices from current levels, or other factors, without
other mitigating circumstances, could cause a future write-down of capitalized
costs and a non-cash charge against future earnings.
3. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Our results of operations and operating cash flows are impacted by changes in
market prices for oil and gas. To mitigate a portion of this exposure to adverse
market changes, we have entered into derivative instruments. All of our
derivative instruments have been entered into as hedges of oil and gas price
risk and not for speculative purposes.
We utilize derivative instruments to reduce exposure to unfavorable changes in
oil and gas prices which are subject to significant and often volatile
fluctuations. Our derivative instruments are currently comprised of swaps,
collars and cap-swaps. These instruments allow us to predict with greater
certainty the effective oil and gas prices to be received for our hedged
production.
o For swap instruments, we receive a fixed price for the respective
commodities and pay a floating market price, as defined in each
instrument, to the counterparty. The fixed-price payment and the
floating-price payment are netted, resulting in a net amount due to or
from the counterparty.
o Collars contain a fixed floor price (put) and ceiling price (call). If
the market price exceeds the call strike price or falls below the put
strike price, then we receive the fixed price and pay the market price.
If the market price is between the call and the put strike price, then
no payments are due from either party.
o For cap-swaps, we receive a fixed price for the respective commodities
and pay a floating market price. The fixed price received by Chesapeake
includes a premium in exchange for a "cap" on the counterparty's
exposure.
Pursuant to SFAS 133, our cap-swaps do not qualify for designation as cash flow
hedges. Therefore, changes in the fair value of these instruments that occur
prior to their maturity are reported in the statement of operations as risk
management income (loss). Amounts recorded in risk management income (loss) do
not represent cash gains or losses. Rather, these amounts are temporary
valuation swings in contracts or portions of contracts that are not entitled to
receive hedge accounting treatment. All amounts initially recorded in this
caption are ultimately reversed within this same caption over the respective
contract terms.
The estimated fair values of our derivative instruments as of September 30, 2001
are provided below. The associated carrying values of these instruments are
equal to the estimated fair values.
<Table>
<Caption>
SEPTEMBER 30,
2001
---------------
($ IN THOUSANDS)
Derivative assets:
Fixed-price gas swaps ................................................... $ 121,443
Fixed-price gas cap-swaps ............................................... 90,762
Fixed-price gas collars ................................................. 19,954
Fixed-price crude oil swaps ............................................. 4,836
Fixed-price crude oil cap-swaps ......................................... 2,035
---------------
Total ................................................................... $ 239,030
===============
</Table>
The fair value of our derivative instruments as of September 30, 2001 was
estimated based on market prices of gas and crude oil for the periods covered by
the instruments. The net differential between the prices in each instrument and
market prices for future periods has been applied to the volumes stipulated in
each instrument to arrive at an estimated fair value. The fair value of
derivative instruments which contain options (such as collar structures) has
been estimated based on remaining term, volatility and other factors.
8
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2001
(UNAUDITED)
Risk management income in the statement of operations for the following periods
is comprised of the following:
<Table>
<Caption>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2001 SEPTEMBER 30, 2001
------------------ ------------------
($ IN THOUSANDS)
Risk Management Income:
Change in fair value of derivatives not qualifying for
hedge accounting ......................................................... $ 37,742 $ 102,793
Reclassification of settled contracts ........................................ (6,440) (9,996)
Ineffective portion of derivatives qualifying for hedge accounting ........... 958 1,918
--------------- ---------------
$ 32,260 $ 94,715
=============== ===============
</Table>
Although derivatives often fail to achieve 100% effectiveness for accounting
purposes, our derivative instruments continue to be highly effective in
achieving the risk management objectives for which they were intended.
The change in fair value of our derivative instruments since December 31, 2000
has resulted from a decrease in market prices for oil and gas. The majority of
this change in fair value was reflected in accumulated other comprehensive
income, net of deferred income tax effects. Derivative assets reflected as
current in the September 30, 2001 consolidated balance sheet represent the
estimated fair value of derivative instrument settlements scheduled to occur
over the subsequent twelve-month period based on market prices for oil and gas
as of the balance sheet date. The derivative settlement amounts are not due and
payable until the month in which the related underlying hedged transaction
occurs.
We expect to transfer approximately $59.1 million of the balance in accumulated
other comprehensive income, based upon the market prices at September 30, 2001,
to earnings during the next 12 months when the forecasted transactions actually
occur. All forecasted transactions currently being hedged are expected to occur
by December 2003.
4. CONTINGENCIES
West Panhandle Field Cessation Cases. One of our subsidiaries, Chesapeake
Panhandle Limited Partnership ("CP") (f/k/a MC Panhandle, Inc.), and two
subsidiaries of Kinder Morgan, Inc. have been 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 we acquired in April 1998, has owned the leases since January 1, 1997. The
co-defendants are prior lessees. The plaintiffs in these cases have claimed the
leases terminated upon the cessation of production for various periods,
primarily during the 1960s. In addition, the plaintiffs have sought to recover
conversion damages, exemplary damages, attorneys' fees and interest. The
defendants have asserted 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, and there
have been appellate decisions in three of them. In January 2001, we settled the
claims of the principal plaintiffs in eight of ten cases tried or pending in the
District Court of Moore County, Texas, 69th Judicial District. The settlement
was not material to our financial condition or results of operations. In two of
these cases, we have filed petitions for review in the Texas Supreme Court with
respect to the claims of plaintiffs who were not covered by the settlement.
There are five related West Panhandle cessation cases which continue to be
pending, two in the District Court of Moore County, Texas, 69th Judicial
District, one in the District Court of Carson County, Texas, 100th Judicial
9
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2001
(UNAUDITED)
District, and two in the U.S. District Court, Northern District of Texas,
Amarillo Division. In one of the Moore County cases, CP and the other defendants
have appealed a January 2000 judgment notwithstanding verdict 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. On March
28, 2001, the Amarillo Court of Appeals reversed and rendered judgment in favor
of CP and the other defendants, finding that the subject leases had been revived
as a matter of law, making all other issues moot. Plaintiffs have filed
petitions requesting that the Texas Supreme Court accept the case for review. In
the other Moore County, Texas case, in June 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.
In February 2001, the court granted plaintiffs' motion for summary judgment on
defendants' affirmative defenses but reversed its ruling that the lease had
terminated as a matter of law. In one of the U.S. District Court cases, after a
trial in May 1999, the jury found plaintiffs' claims were barred by the payment
of shut-in royalties, laches and revivor. Plaintiffs have moved for a new trial.
There are motions pending in the remaining two cases.
We have previously established an accrued liability we believe will be
sufficient to cover the estimated costs of litigation for each of the pending
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 pending cases, the outcome of any future trials and the amount of
damages that might ultimately be awarded could differ from management's
estimates. CP and the other defendants are vigorously defending 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.
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.
5. NET INCOME PER SHARE
Statement of Financial Accounting Standards No. 128, Earnings Per Share,
requires presentation of "basic" and "diluted" earnings per share, as defined,
on the face of the statement of operations for all entities with complex capital
structures. SFAS 128 requires a reconciliation of the numerators and
denominators of the basic and diluted EPS computations.
A reconciliation for the Prior and Current Quarters and the Prior and Current
Period is as follows (in thousands, except per share data):
10
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2001
(UNAUDITED)
<Table>
<Caption>
INCOME SHARES PER SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
--------------- --------------- ---------------
FOR THE QUARTER ENDED SEPTEMBER 30, 2000:
BASIC EPS
Income available to common stockholders .................. $ 48,403 146,593 $ 0.33
===============
EFFECT OF DILUTIVE SECURITIES
Assumed conversion of 624,037 shares of
preferred stock at the beginning of the period:
Common shares assumed issued ........................... -- 4,489
Preferred stock dividends .............................. 546 --
Employee stock options ................................... -- 7,765
--------------- ---------------
DILUTED EPS
Income available to common stockholders
and assumed conversions ............................... $ 48,949 158,847 $ 0.31
=============== =============== ===============
FOR THE QUARTER ENDED SEPTEMBER 30, 2001:
BASIC EPS
Income available to common stockholders .................. $ 65,008 164,440 $ 0.40
===============
EFFECT OF DILUTIVE SECURITIES
Employee stock options ................................... -- 5,937
Warrants assumed in Gothic acquisition ................... -- 7
--------------- ---------------
DILUTED EPS
Income available to common stockholders
and assumed conversions ............................... $ 65,008 170,384 $ 0.38
=============== =============== ===============
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000:
BASIC EPS
Income available to common stockholders .................. $ 106,185 121,089 $ 0.88
===============
EFFECT OF DILUTIVE SECURITIES
Assumed conversion at the beginning of the period
of preferred shares exchanged during the period:
Common shares assumed issued ........................... -- 15,282
Preferred stock dividends .............................. 6,276 --
Gain on redemption of preferred stock .................. (6,574) --
Assumed conversion of 624,037 shares of
preferred stock at beginning of period:
Common shares assumed issued ........................... -- 4,489
Preferred stock dividends .............................. 1,638 --
Employee stock options ................................... -- 6,568
--------------- ---------------
DILUTED EPS
Income available to common stockholders
and assumed conversions ................................ $ 107,525 147,428 $ 0.73
=============== =============== ===============
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2001:
BASIC EPS
Income available to common stockholders .................. $ 174,053 161,603 $ 1.08
===============
EFFECT OF DILUTIVE SECURITIES
Assumed conversion at the beginning of the
period of preferred shares exchanged
during the period:
Common shares assumed issued ........................... -- 1,957
Preferred stock dividends .............................. 728 --
Employee stock options ................................... -- 7,370
Warrants assumed in Gothic acquisition ................... -- 7
--------------- ---------------
DILUTED EPS
Income available to common stockholders
and assumed conversions ................................ $ 174,781 170,937 $ 1.02
=============== =============== ===============
</Table>
11
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2001
(UNAUDITED)
For the Prior Quarter, the Current Quarter, the Prior Period and the Current
Period, outstanding options to purchase 0.3 million, 3.8 million, 0.7 million
and 0.3 million shares of common stock at a weighted average exercise price of
$15.65, $6.97, $10.49 and $17.25, respectively, were antidilutive because the
exercise prices of the options were greater than the average market price of our
common stock. For the Current Quarter and Current Period, outstanding warrants
to purchase 1.1 million shares of common stock at a weighted average exercise
price of $12.48 were antidilutive because the exercise prices of the warrants
were greater than the average market price of our common stock.
6. SENIOR NOTES
On April 6, 2001, we issued $800 million principal amount of 8.125% senior notes
due 2011, of which substantially all were subsequently exchanged on July 12,
2001 for substantially identical notes registered under the Securities Act of
1933. During April 2001, we used a portion of the offering proceeds to purchase
$140.7 million principal amount of our 9.625% senior notes and $3.0 million
principal amount of the 11.125% senior secured notes of Gothic Production
Corporation, a Chesapeake subsidiary. On May 7, 2001, we redeemed all $120
million principal amount of our 9.125% senior notes, the remaining $359.3
million principal amount of our 9.625% senior notes and the remaining $199.3
million principal amount of Gothic Production Corporation's 11.125% senior
secured notes. The purchase and redemption of these notes included payment of
aggregate make-whole and redemption premiums of $75.6 million which was further
adjusted by the write-off of unamortized debt costs and debt issue premiums.
These costs are reflected as a $46.0 million, after tax, extraordinary loss in
the Current Period.
On January 16, 2001, we acquired Gothic and its obligations under the 11.125%
senior secured notes. See note 7. At March 31, 2001, there was outstanding
$202.3 million principal amount of 11.125% senior secured notes due 2005 which
had been issued by Gothic Production Corporation and guaranteed by Gothic Energy
Corporation. The 11.125% senior secured notes were collateralized by a second
priority lien on substantially all of the gas and oil properties owned by Gothic
Production Corporation. The notes were redeemable at Gothic Production
Corporation's option on or after May 1, 2002 at the redemption prices set forth
in the indenture or prior to May 1, 2002 at the make-whole prices set forth in
the indenture. In April 2001, we purchased $3.0 million of these notes for total
consideration of $3.5 million, including $0.1 million in interest and $0.4
million in premium. On May 7, 2001, the remaining $199.3 million was redeemed
for total consideration of $222.5 million, including $0.4 million in interest
and $22.8 million in redemption premium.
On April 22, 1998, we issued $500 million principal amount of 9.625% senior
notes due 2005. The 9.625% senior notes were redeemable at our option 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. In April 2001, we purchased $140.7 million of these notes for total
consideration of $160.2 million, including a $13.6 million premium and interest
of $5.9 million. On May 7, 2001, the remaining $359.3 million was redeemed for
total consideration of $393.3 million, including $0.6 million of interest and
$33.4 million of redemption premium.
On March 17, 1997, we issued $150 million principal amount of 7.875% senior
notes due 2004. The 7.875% senior notes are redeemable at our option at any time
prior to March 15, 2004 at the make-whole prices determined in accordance with
the indenture.
Also on March 17, 1997, we issued $150 million principal amount of 8.5% senior
notes due 2012. The 8.5% senior notes are redeemable at our option 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 in the indenture. During the quarter ended March 31, 2001, Chesapeake
purchased and subsequently retired $7.3 million of these notes for total
consideration of $7.4 million, including accrued interest of $0.2 million and
the write-off of $0.1 million of unamortized bond discount.
12
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2001
(UNAUDITED)
On April 9, 1996, we issued $120 million principal amount of 9.125% senior notes
due 2006. The 9.125% senior notes were redeemable at our option 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 in the indenture. On May 7, 2001, we redeemed these notes for total
consideration of $126.1 million, including $0.7 million in interest and $5.4
million of redemption premium.
Chesapeake is a holding company and owns no operating assets and has no
significant operations independent of its subsidiaries. Our obligations under
the 8.125% senior notes, the 7.875% senior notes and the 8.5% senior notes have
been fully and unconditionally guaranteed, on a joint and several basis, by each
of our "Restricted Subsidiaries" (as defined in the respective indentures
governing these notes) (collectively, the "guarantor subsidiaries"). Each
guarantor subsidiary is a direct or indirect wholly-owned subsidiary.
Set forth below are condensed consolidating financial statements of the
guarantor subsidiaries and our subsidiaries which are not guarantors of the
senior notes. Chesapeake Energy Marketing, Inc. was a non-guarantor subsidiary
for all periods presented. Carmen Acquisition Corp. was also a non-guarantor
subsidiary in the Current Period. Upon the acquisition of Gothic Energy
Corporation and Gothic Production Corporation on January 16, 2001, these
subsidiaries were non-guarantor subsidiaries. As of May 7, 2001, all of the
Gothic Production Corporation 11.125% senior secured notes were purchased or
redeemed and both subsidiaries became guarantor subsidiaries on May 14, 2001.
Based on these events, we have presented Gothic Energy Corporation and Gothic
Production Corporation as guarantor subsidiaries for the Current Period. All of
our other wholly-owned subsidiaries were guarantor subsidiaries during all
periods presented.
13
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2000
($ IN THOUSANDS)
<Table>
<Caption>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ........................ $ (19,868) $ 7,200 $ 12,668 $ -- $ --
Restricted cash .................................. 3,500 -- -- -- 3,500
Accounts receivable .............................. 91,903 46,903 -- (21,363) 117,443
Deferred income tax asset ........................ -- -- 40,819 -- 40,819
Inventory ........................................ 3,040 127 -- -- 3,167
Other ............................................ 1,997 -- -- -- 1,997
------------ ------------ ------------ ------------ ------------
Total Current Assets ....................... 80,572 54,230 53,487 (21,363) 166,926
------------ ------------ ------------ ------------ ------------
PROPERTY AND EQUIPMENT:
Oil and gas properties ........................... 2,590,512 -- -- -- 2,590,512
Unevaluated leasehold ............................ 25,685 -- -- -- 25,685
Other property and equipment ..................... 30,670 23,246 25,982 -- 79,898
Less: accumulated depreciation, depletion and
amortization ................................... (1,787,314) (18,153) (2,394) -- (1,807,861)
------------ ------------ ------------ ------------ ------------
Net Property and Equipment ................. 859,553 5,093 23,588 -- 888,234
------------ ------------ ------------ ------------ ------------
OTHER ASSETS:
Investments in subsidiaries and
intercompany advances .......................... -- -- (612,832) 612,832 --
Investment in Gothic Energy Corporation .......... -- 9,732 116,702 -- 126,434
Deferred tax asset ............................... -- -- 229,823 -- 229,823
Other assets ..................................... 9,890 418 89,516 (70,815) 29,009
------------ ------------ ------------ ------------ ------------
Total Other Assets ......................... 9,890 10,150 (176,791) 542,017 385,266
------------ ------------ ------------ ------------ ------------
TOTAL ASSETS ....................................... $ 950,015 $ 69,473 $ (99,716) $ 520,654 $ 1,440,426
============ ============ ============ ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES:
Notes payable and current maturities of
long-term debt ................................. $ 836 $ -- $ -- $ -- $ 836
Accounts payable and other ....................... 118,620 49,613 19,090 (25,458) 161,865
------------ ------------ ------------ ------------ ------------
Total Current Liabilities .................. 119,456 49,613 19,090 (25,458) 162,701
------------ ------------ ------------ ------------ ------------
LONG-TERM DEBT ..................................... 92,321 -- 919,244 (66,720) 944,845
------------ ------------ ------------ ------------ ------------
REVENUES AND ROYALTIES DUE OTHERS .................. 7,798 -- -- -- 7,798
------------ ------------ ------------ ------------ ------------
DEFERRED INCOME TAX LIABILITY ...................... 11,850 -- -- -- 11,850
------------ ------------ ------------ ------------ ------------
INTERCOMPANY PAYABLES .............................. 1,351,144 138 (1,351,282) -- --
------------ ------------ ------------ ------------ ------------
STOCKHOLDERS' EQUITY (DEFICIT):
Common Stock ..................................... 26 1 1,569 (18) 1,578
Other ............................................ (632,580) 19,721 311,663 612,850 311,654
------------ ------------ ------------ ------------ ------------
(632,554) 19,722 313,232 612,832 313,232
------------ ------------ ------------ ------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
(DEFICIT) .......................................... $ 950,015 $ 69,473 $ (99,716) $ 520,654 $ 1,440,426
============ ============ ============ ============ ============
</Table>
14
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF SEPTEMBER 30, 2001
($ IN THOUSANDS)
<Table>
<Caption>
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARIES PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- ------------ ------------ ------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ...................... $ (15,954) $ (167) $ 33,163 $ -- $ 17,042
Accounts receivable ............................ 84,600 40,296 1,116 (18,815) 107,197
Deferred income tax asset ...................... -- -- -- -- --
Short-term derivative instruments .............. 175,964 -- -- -- 175,964
Inventory ...................................... 4,187 541 -- -- 4,728
Other .......................................... 3,724 4 5 -- 3,733
------------ ------------ ------------ ------------ ------------
Total Current Assets ................... 252,521 40,674 34,284 (18,815) 308,664
------------ ------------ ------------ ------------ ------------
PROPERTY AND EQUIPMENT:
Oil and gas properties ......................... 3,318,487 -- -- -- 3,318,487
Unevaluated leasehold .......................... 60,686 -- -- -- 60,686
Other property and equipment ................... 57,822 23,495 34,355 -- 115,672
Less: accumulated depreciation,
depletion and amortization .................. (1,912,845) (18,541) (2,963) -- (1,934,349)
------------ ------------ ------------ ------------ ------------
Net Property and Equipment ............. 1,524,150 4,954 31,392 -- 1,560,496
------------ ------------ ------------ ------------ ------------
OTHER ASSETS:
Investments in subsidiaries and
intercompany advances ........................ -- -- (163,220) 163,220 --
Deferred income tax asset ...................... (205,519) (704) 301,042 -- 94,819
Long-term derivative instruments ............... 63,066 -- -- -- 63,066
Long-term investments, other ................... -- 8,561 39,206 -- 47,767
Other assets ................................... 6,088 2,770 76,085 (69,157) 15,786
------------ ------------ ------------ ------------ ------------
Total Other Assets ....................... (136,365) 10,627 253,113 94,063 221,438
------------ ------------ ------------ ------------ ------------
TOTAL ASSETS ..................................... $ 1,640,306 $ 56,255 $ 318,789 $ 75,248 $ 2,090,598
============ ============ ============ ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Notes payable and current
maturities of long-term debt ................ $ 817 $ -- $ -- $ -- $ 817
Accounts payable and other ..................... 137,340 32,299 32,541 (19,081) 183,099
------------ ------------ ------------ ------------ ------------
Total Current Liabilities .............. 138,157 32,299 32,541 (19,081) 183,916
------------ ------------ ------------ ------------ ------------
LONG-TERM DEBT ................................... 255,720 -- 1,081,814 (69,120) 1,268,414
------------ ------------ ------------ ------------ ------------
REVENUES AND ROYALTIES DUE
OTHERS ......................................... 12,002 -- -- -- 12,002
------------ ------------ ------------ ------------ ------------
DEFERRED INCOME TAXES ............................ 9,340 -- -- -- 9,340
------------ ------------ ------------ ------------ ------------
OTHER LIABILITIES ................................ 3,943 -- -- -- 3,943
------------ ------------ ------------ ------------ ------------
INTERCOMPANY PAYABLES ............................ 1,409,226 (906) (1,408,549) 229 --
------------ ------------ ------------ ------------ ------------
STOCKHOLDERS' EQUITY:
Common Stock ................................... 66 1 1,683 (57) 1,693
Other .......................................... (188,148) 24,861 611,300 163,277 611,290
------------ ------------ ------------ ------------ ------------
(188,082) 24,862 612,983 163,220 612,983
------------ ------------ ------------ ------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ....... $ 1,640,306 $ 56,255 $ 318,789 $ 75,248 $ 2,090,598
============ ============ ============ ============ ============
</Table>
15
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
<Table>
<Caption>
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARIES PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- ------------ ------------ ------------
FOR THE THREE MONTHS ENDED SEPTEMBER 30,
2000:
REVENUES:
Oil and gas sales .............................. $ 123,971 $ -- $ -- $ -- $ 123,971
Oil and gas marketing sales .................... -- 98,035 -- (53,824) 44,211
------------ ------------ ------------ ------------ ------------
Total Revenues .............................. 123,971 98,035 -- (53,824) 168,182
------------ ------------ ------------ ------------ ------------
OPERATING COSTS:
Production expenses and taxes .................. 17,894 -- -- -- 17,894
General and administrative ..................... 2,997 346 34 -- 3,377
Oil and gas marketing expenses ................. -- 96,741 -- (53,824) 42,917
Oil and gas depreciation, depletion
and amortization ............................. 25,227 -- -- -- 25,227
Other depreciation and amortization ............ 991 20 838 -- 1,849
------------ ------------ ------------ ------------ ------------
Total Operating Costs ....................... 47,109 97,107 872 (53,824) 91,264
------------ ------------ ------------ ------------ ------------
INCOME (LOSS) FROM OPERATIONS .................... 76,862 928 (872) -- 76,918
------------ ------------ ------------ ------------ ------------
OTHER INCOME (EXPENSE):
Interest and other income ...................... 645 166 20,965 (20,909) 867
Interest expense ............................... (21,727) -- (20,862) 20,909 (21,680)
Equity in net earnings of subsidiaries ......... -- -- 55,458 (55,458) --
------------ ------------ ------------ ------------ ------------
Total Other Income (Expense) ................ (21,082) 166 55,561 (55,458) (20,813)
------------ ------------ ------------ ------------ ------------
INCOME BEFORE INCOME TAXES ....................... 55,780 1,094 54,689 (55,458) 56,105
INCOME TAX EXPENSE ............................... 1,416 -- -- -- 1,416
------------ ------------ ------------ ------------ ------------
NET INCOME ....................................... $ 54,364 $ 1,094 $ 54,689 $ (55,458) $ 54,689
============ ============ ============ ============ ============
FOR THE THREE MONTHS ENDED SEPTEMBER 30,
2001:
REVENUES:
Oil and gas sales .............................. $ 177,746 $ -- $ -- $ -- $ 177,746
Risk management income ......................... 32,260 -- -- -- 32,260
Oil and gas marketing sales .................... -- 94,446 -- (65,541) 28,905
------------ ------------ ------------ ------------ ------------
Total Revenues .............................. 210,006 94,446 -- (65,541) 238,911
------------ ------------ ------------ ------------ ------------
OPERATING COSTS:
Production expenses and taxes .................. 26,366 -- -- -- 26,366
General and administrative ..................... 2,835 324 81 -- 3,240
Oil and gas marketing expenses ................. -- 93,487 -- (65,541) 27,946
Oil and gas depreciation, depletion
and amortization ............................. 46,821 -- -- -- 46,821
Other depreciation and amortization ............ 1,606 20 538 -- 2,164
------------ ------------ ------------ ------------ ------------
Total Operating Costs ....................... 77,628 93,831 619 (65,541) 106,537
------------ ------------ ------------ ------------ ------------
INCOME (LOSS) FROM OPERATIONS .................... 132,378 615 (619) -- 132,374
------------ ------------ ------------ ------------ ------------
OTHER INCOME (EXPENSE):
Interest and other income ...................... 107 (956) 24,708 (23,727) 132
Interest expense ............................... (25,044) -- (22,787) 23,727 (24,104)
Gothic standby credit facility costs ........... -- -- -- -- --
Equity in net earnings of subsidiaries ......... -- -- 64,227 (64,227) --
------------ ------------ ------------ ------------ ------------
Total Other Income (Expense) ................ (24,937) (956) 66,148 (64,227) (23,972)
------------ ------------ ------------ ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES
AND EXTRAORDINARY ITEM ......................... 107,441 (341) 65,529 (64,227) 108,402
INCOME TAX EXPENSE (BENEFIT) ..................... 43,009 (136) 26,212 (25,691) 43,394
------------ ------------ ------------ ------------ ------------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM .......... 64,432 (205) 39,317 (38,536) 65,008
------------ ------------ ------------ ------------ ------------
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt, net
of applicable income tax .................... -- -- -- -- --
------------ ------------ ------------ ------------ ------------
NET INCOME (LOSS) ................................ $ 64,432 $ (205) $ 39,317 $ (38,536) $ 65,008
============ ============ ============ ============ ============
</Table>
16
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
<Table>
<Caption>
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARIES PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- ------------ ------------ ------------
FOR THE NINE MONTHS ENDED SEPTEMBER 30,
2000:
REVENUES:
Oil and gas sales .............................. $ 311,138 $ 347 $ -- $ -- $ 311,485
Oil and gas marketing sales .................... -- 247,133 -- (141,312) 105,821
------------ ------------ ------------ ------------ ------------
Total Revenues .............................. 311,138 247,480 -- (141,312) 417,306
------------ ------------ ------------ ------------ ------------
OPERATING COSTS:
Production expenses and taxes .................. 53,873 80 -- -- 53,953
General and administrative ..................... 8,558 936 103 -- 9,597
Oil and gas marketing expenses ................. -- 243,895 -- (141,312) 102,583
Oil and gas depreciation, depletion
and amortization ............................. 74,486 101 -- -- 74,587
Other depreciation and amortization ............ 3,025 60 2,466 -- 5,551
------------ ------------ ------------ ------------ ------------
Total Operating Costs ....................... 139,942 245,072 2,569 (141,312) 246,271
------------ ------------ ------------ ------------ ------------
INCOME (LOSS) FROM OPERATIONS .................... 171,196 2,408 (2,569) -- 171,035
------------ ------------ ------------ ------------ ------------
OTHER INCOME (EXPENSE):
Interest and other income ...................... 2,608 969 62,877 (62,728) 3,726
Interest expense ............................... (64,166) (34) (62,885) 62,728 (64,357)
Equity in net earnings of subsidiaries ......... -- -- 110,102 (110,102) --
------------ ------------ ------------ ------------ ------------
Total Other Income (Expense) ................ (61,558) 935 110,094 (110,102) (60,631)
------------ ------------ ------------ ------------ ------------
INCOME BEFORE INCOME TAXES ....................... 109,638 3,343 107,525 (110,102) 110,404
INCOME TAX EXPENSE ............................... 2,879 -- -- -- 2,879
------------ ------------ ------------ ------------ ------------
NET INCOME ....................................... $ 106,759 $ 3,343 $ 107,525 $ (110,102) $ 107,525
============ ============ ============ ============ ============
FOR THE NINE MONTHS ENDED SEPTEMBER 30,
2001:
REVENUES:
Oil and gas sales .............................. $ 574,190 $ -- $ -- $ -- $ 574,190
Risk management income ......................... 94,715 -- -- -- 94,715
Oil and gas marketing sales .................... -- 336,959 -- (213,888) 123,071
------------ ------------ ------------ ------------ ------------
Total Revenues .............................. 668,905 336,959 -- (213,888) 791,976
------------ ------------ ------------ ------------ ------------
OPERATING COSTS:
Production expenses and taxes .................. 87,282 -- -- -- 87,282
General and administrative ..................... 8,928 933 253 -- 10,114
Oil and gas marketing expenses ................. -- 333,225 -- (213,888) 119,337
Oil and gas depreciation, depletion
and amortization ............................. 124,904 -- -- -- 124,904
Other depreciation and amortization ............ 3,955 60 1,939 -- 5,954
------------ ------------ ------------ ------------ ------------
Total Operating Costs ....................... 225,069 334,218 2,192 (213,888) 347,591
------------ ------------ ------------ ------------ ------------
INCOME (LOSS) FROM OPERATIONS .................... 443,836 2,741 (2,192) -- 444,385
------------ ------------ ------------ ------------ ------------
OTHER INCOME (EXPENSE):
Interest and other income ...................... 1,246 (982) 71,250 (70,130) 1,384
Interest expense ............................... (77,059) (1) (66,047) 70,130 (72,977)
Gothic standby credit facility costs ........... -- -- (3,392) -- (3,392)
Equity in net earnings of subsidiaries ......... -- -- 212,839 (212,839) --
------------ ------------ ------------ ------------ ------------
Total Other Income (Expense) ................ (75,813) (983) 214,650 (212,839) (74,985)
------------ ------------ ------------ ------------ ------------
INCOME BEFORE INCOME TAXES
AND EXTRAORDINARY ITEM ......................... 368,023 1,758 212,458 (212,839) 369,400
INCOME TAX EXPENSE ............................... 148,067 704 84,984 (85,136) 148,619
------------ ------------ ------------ ------------ ------------
INCOME BEFORE EXTRAORDINARY ITEM ................. 219,956 1,054 127,474 (127,703) 220,781
------------ ------------ ------------ ------------ ------------
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt,
net of applicable income tax ................ (8,171) -- (37,829) -- (46,000)
------------ ------------ ------------ ------------ ------------
NET INCOME ....................................... $ 211,785 $ 1,054 $ 89,645 $ (127,703) $ 174,781
============ ============ ============ ============ ============
</Table>
17
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)
<Table>
<Caption>
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARIES PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- ------------ ------------ ------------
FOR THE NINE MONTHS ENDED SEPTEMBER 30,
2000:
CASH FLOWS FROM OPERATING ACTIVITIES ............. $ 175,178 $ (15,301) $ 14,837 $ -- $ 174,714
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties, net .................... (164,212) 1,515 -- -- (162,697)
Proceeds from sale of assets ................... 1,134 -- -- -- 1,134
Investment in Gothic ........................... -- -- (24,622) -- (24,622)
Other investments .............................. (4,194) -- (2,000) -- (6,194)
Other additions ................................ (4,172) (46) (3,971) -- (8,189)
------------ ------------ ------------ ------------ ------------
(171,444) 1,469 (30,593) -- (200,568)
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES ............. (9,724) (3,009) 12,969 -- 236
------------ ------------ ------------ ------------ ------------
EFFECT OF CHANGES IN EXCHANGE RATE ON CASH ....... (313) -- -- -- (313)
------------ ------------ ------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH .................. (6,303) (16,841) (2,787) -- (25,931)
CASH, BEGINNING OF PERIOD ........................ (7,156) 20,409 25,405 -- 38,658
------------ ------------ ------------ ------------ ------------
CASH, END OF PERIOD .............................. $ (13,459) $ 3,568 $ 22,618 $ -- $ 12,727
============ ============ ============ ============ ============
FOR THE NINE MONTHS ENDED SEPTEMBER 30,
2001:
CASH FLOWS FROM OPERATING ACTIVITIES ............. $ 409,779 $ 12,271 $ 18,906 $ -- $ 440,956
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties, net .................... (389,075) -- -- -- (389,075)
Proceeds from sale of assets ................... 734 -- -- -- 734
Additions to other property and equipment ...... (19,819) (250) (8,373) -- (28,442)
Other additions ................................ (5,846) -- (43,874) -- (49,720)
------------ ------------ ------------ ------------ ------------
(414,006) (250) (52,247) -- (466,503)
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES ............. 8,686 (19,388) 53,836 -- 43,134
------------ ------------ ------------ ------------ ------------
EFFECT OF CHANGES IN EXCHANGE RATE ON CASH ....... (545) -- -- -- (545)
------------ ------------ ------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH .................. 3,914 (7,367) 20,495 -- 17,042
CASH, BEGINNING OF PERIOD ........................ (19,868) 7,200 12,668 -- --
------------ ------------ ------------ ------------ ------------
CASH, END OF PERIOD .............................. $ (15,954) $ (167) $ 33,163 $ -- $ 17,042
============ ============ ============ ============ ============
</Table>
18
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
($ IN THOUSANDS)
<Table>
<Caption>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES PARENT ELIMINATIONS CONSOLIDATED
------------ ------------ ----------- ------------ ------------
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2000:
Net income (loss) ................................. $ 54,364 $ 1,094 $ 54,689 $ (55,458) $ 54,689
Other comprehensive income, net of income tax:
Foreign currency translation .................... (1,165) -- -- -- (1,165)
----------- ----------- ----------- ----------- -----------
Other comprehensive income ........................ $ 53,199 $ 1,094 $ 54,689 $ (55,458) $ 53,524
=========== =========== =========== =========== ===========
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2001:
Net income (loss) ................................. $ 64,432 $ (205) $ 39,317 $ (38,536) $ 65,008
Other comprehensive income, net of income tax:
Foreign currency translation .................... (2,826) -- -- -- (2,826)
Cumulative effect of accounting change for
financial derivatives ......................... -- -- -- -- --
Change in fair value of derivative instruments .. 64,240 -- -- -- 64,240
Reclassification of settled contracts ........... (34,786) -- -- -- (34,786)
Ineffectiveness portion of derivatives
qualifying for hedge accounting ............... (958) -- -- -- (958)
----------- ----------- ----------- ----------- -----------
Other comprehensive income (loss) ................. $ 90,102 $ (205) $ 39,317 $ (38,536) $ 90,678
=========== =========== =========== =========== ===========
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000:
Net income (loss) ................................. $ 106,759 $ 3,343 $ 107,525 $ (110,102) $ 107,525
Other comprehensive income, net of income tax:
Foreign currency translation ...................... (4,118) -- -- -- (4,118)
----------- ----------- ----------- ----------- -----------
Other comprehensive income ........................ $ 102,641 $ 3,343 $ 107,525 $ (110,102) $ 103,407
=========== =========== =========== =========== ===========
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2001:
Net income (loss) ................................. $ 211,785 $ 1,054 $ 89,645 $ (127,703) $ 174,781
Other comprehensive income, net of income tax:
Foreign currency translation .................... (3,551) -- -- -- (3,551)
Cumulative effect of accounting change for
financial derivatives ......................... (53,580) -- -- -- (53,580)
Change in fair value of derivative instruments .. 202,163 -- -- -- 202,163
Reclassification of settled contracts ........... (60,844) -- -- -- (60,844)
Ineffectiveness portion of derivatives
qualifying for hedge accounting ............... (1,918) -- -- -- (1,918)
----------- ----------- ----------- ----------- -----------
Other comprehensive income ........................ $ 294,055 $ 1,054 $ 89,645 $ (127,703) $ 257,051
=========== =========== =========== =========== ===========
</Table>
19
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
7. ACQUISITION OF GOTHIC ENERGY CORPORATION
We completed the acquisition of Gothic Energy Corporation on January 16, 2001 by
merging a wholly-owned subsidiary into Gothic. We issued a total of 4.0 million
shares of Chesapeake common stock in the merger. Gothic shareholders (other than
Chesapeake) received 0.1908 of a share of Chesapeake common stock (valued at
$7.00 per share, which was based on the value of Chesapeake common stock on the
day before the merger was announced) for each share of Gothic common stock. In
addition, outstanding warrants and options to purchase Gothic common stock were
converted to the right to purchase Chesapeake common stock (1.1 million shares
as of September 30, 2001 at a weighted average exercise price of $12.48 per
share) based on the merger exchange ratio. Prior to the merger, Chesapeake
purchased substantially all of Gothic's 14.125% senior secured discount notes
for total consideration valued at $80.8 million in cash and Chesapeake common
stock. Prior to the merger, we also purchased $31.6 million principal amount of
11.125% senior secured notes due 2005 issued by Gothic's operating subsidiary
and guaranteed by Gothic. The consideration for this purchase consisted of cash
and Chesapeake common stock valued at $34.8 million. Subsequent to the
acquisition, we redeemed all remaining 14.125% senior secured discount notes for
total consideration of $243,000. In February 2001, we purchased $1.0 million
principal amount of Gothic senior secured notes tendered pursuant to a
change-of-control offer at a purchase price of 101%. During April and May 2001,
we purchased or redeemed the remaining $202.3 million principal amount of the
11.125% senior secured notes for total consideration of $225.9 million,
including premium of $23.1 million and interest of $0.5 million. Subsequently,
Gothic Energy Corporation and Gothic Production Corporation became guarantor
subsidiaries of Chesapeake's senior notes.
The acquisition of Gothic was accounted for using the purchase method as of
January 1, 2001 because we had effective control as of that date, and the
results of operations of Gothic have been included since that date.
The following unaudited pro forma information has been prepared assuming Gothic
had been acquired as of January 1, 2000. The pro forma information is presented
for information purposes only and is not necessarily indicative of what would
have occurred if the acquisition had been made as of that date. In addition, the
pro forma information is not intended to be a projection of future results and
does not reflect any efficiencies that may result from the integration of
Gothic.
Pro Forma Information (Unaudited)
(In thousands, except per share data)
<Table>
<Caption>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2000 SEPTEMBER 30, 2000
------------------ ------------------
Revenues.............................................. $186,426 $470,413
Income before income taxes............................ $ 59,913 $112,443
Net income............................................ $ 56,904 $107,918
Earnings per common share - basic..................... $ 0.31 $ 0.77
Earnings per common share - assuming dilution......... $ 0.28 $ 0.65
</Table>
8. REVOLVING CREDIT FACILITY
On June 11, 2001, our credit agreement was amended and restated, and our
revolving credit facility was increased to $225 million, maturing September
2003, with an initial committed borrowing base of $225 million. As of September
30, 2001, we had borrowed $189 million under the facility and $1.6 million of
the facility secured various letters of credit. Borrowings under the facility
are collateralized by some of our producing oil and gas properties and bear
interest at either the reference rate of Union Bank of California, N.A. or
London Interbank Offered Rate (LIBOR), at our option, plus a margin that varies
according to total facility usage. The average interest rate on the outstanding
facility at September 30, 2001 was 7.3%. Unused portions of the facility accrue
an annual commitment fee of 0.50%. The credit facility contains various
covenants and restrictive provisions, including financial condition covenants
requiring us to maintain certain financial ratios at or above specified levels
and periodic redeterminations
20
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
of the borrowing base. In addition, extensions of credit under the facility may
not exceed the lesser of the maximum amount of indebtedness permitted under the
8.125% senior note indenture or 15% of adjusted consolidated net tangible
assets.
9. SEGMENT INFORMATION
Chesapeake has two reportable segments under SFAS No. 131, Disclosures about
Segments of an Enterprise and Related Information, consisting of exploration and
production, and marketing. The reportable segment information can be derived
from note 6 as Chesapeake Energy Marketing, Inc., which is our marketing
segment, is the only material non-guarantor subsidiary for all income statement
periods presented.
10. SUBSEQUENT EVENTS
Sale of Chesapeake Canada Corporation - On October 1, 2001, we completed the
sale of our Canadian subsidiary to a large Canadian energy producer. Proceeds
from the sale were approximately $143 million and were used to substantially
reduce our bank debt. An estimated pre-tax gain of approximately $30 million
from the sale will be reported in the fourth quarter of 2001.
Pricing of $250 Million in New Senior Notes - On October 25, 2001, Chesapeake
priced a private offering of $250 million of senior notes due 2008, which will
carry an interest rate coupon of 8.375%. The net proceeds are expected to be
approximately $248 million. The 8.375% senior notes offered by Chesapeake will
not be registered under the Securities Act of 1933, as amended, but will be
subject to an agreement requiring Chesapeake to exchange the offered notes for
registered senior notes of a substantially similar series or otherwise register
the offered notes. The 8.375% senior notes will be redeemable by us prior to
November 1, 2005 by payment of a make-whole penalty, and after November 1, 2005
at annually declining premiums. The 8.375% senior notes will be guaranteed by
the same subsidiaries that guarantee our outstanding senior notes and will be
subject to covenants substantially similar to those contained in the indenture
for our 8.125% senior notes. The net proceeds from this offering are expected to
be used for general corporate purposes, including the funding of future
acquisitions. Closing of the 8.375% senior notes offering is expected to occur
on November 5, 2001 and is subject to satisfaction of customary closing
conditions and receipt of a bank consent.
11. RECENT ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board issued SFAS Nos. 141 and
142. SFAS No. 141, Business Combinations, requires that the purchase method of
accounting be used for all business combinations initiated after June 30, 2001.
SFAS No. 142, Goodwill and Other Intangible Assets, changes the accounting for
goodwill from an amortization method to an impairment-only approach and will be
effective January 2002. We believe that adoption of these new standards will not
have an effect on our results of operations or our financial position. In June
2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Allocations.
Management is currently assessing the impact SFAS No. 143 will have on our
financial condition and results of operations, but does not believe the impact
will be material.
21
PART I. FINANCIAL INFORMATION
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
ACQUISITION OF GOTHIC ENERGY CORPORATION
We completed the acquisition of Gothic Energy Corporation on January 16, 2001 by
merging a wholly-owned subsidiary into Gothic. We issued 4.0 million shares in
the merger along with additional warrants and options to purchase our common
stock in exchange for outstanding Gothic warrants and options. Prior to the
merger, Chesapeake purchased substantially all of Gothic's 14.125% senior
secured discount notes for total consideration of $80.8 million in cash and
Chesapeake common stock. We also purchased $31.6 million principal amount of
11.125% senior secured notes due 2005 issued by Gothic's operating subsidiary
for total consideration of $34.8 million in cash and Chesapeake common stock.
Subsequent to the acquisition, we redeemed all remaining 14.125% senior secured
discount notes for total consideration of $243,000. In February 2001, we
purchased $1.0 million principal amount of Gothic senior secured notes tendered
pursuant to a change-of-control offer at a purchase price of 101%. Chesapeake
incurred $3.4 million of costs for a standby facility which were recognized in
the quarter ended March 31, 2001. During April and May 2001, we purchased or
redeemed the remaining $202.3 million of 11.125% senior secured notes for total
consideration of $225.9 million. On May 14, 2001, Gothic Energy Corporation and
Gothic Production Corporation became guarantors of Chesapeake's senior notes.
SALE OF CHESAPEAKE CANADA CORPORATION
On October 1, 2001, we completed the sale of our Canadian subsidiary to a large
Canadian energy producer. Proceeds from the sale were approximately $143 million
and were used to substantially reduce our revolving credit facility. An
estimated pre-tax gain of approximately $30 million from the sale will be
reported in the fourth quarter of 2001.
RESULTS OF OPERATIONS - Three Months Ended September 30, 2001 ("Current
Quarter") vs. September 30, 2000 ("Prior Quarter")
General. For the Current Quarter, we realized net income of $65.0 million, or
$0.38 per diluted common share. This compares to net income of $54.7 million, or
$0.31 per diluted common share, in the Prior Quarter. Net income in the Current
Quarter included a $19.4 million non-cash risk management gain (net of tax)
recorded pursuant to SFAS 133.
Oil and Gas Sales. During the Current Quarter, oil and gas sales increased 43%
to $177.7 million from $124.0 million in the Prior Quarter. For the Current
Quarter, we produced 40.8 billion cubic feet equivalent, consisting of 0.7
million barrels of oil and 36.5 billion cubic feet of gas, compared to 0.8 mmbo
and 29.1 bcf, or 33.7 bcfe, in the Prior Quarter. The production increase is
primarily the result of the Gothic acquisition. Average oil prices realized were
$27.37 per barrel of oil in the Current Quarter compared to $28.25 per bo in the
Prior Quarter, a decrease of 3%. Average gas prices realized were $4.34 per
thousand cubic feet in the Current Quarter compared to $3.52 per mcf in the
Prior Quarter, an increase of 23%.
For the Current Quarter, we realized an average price of $4.36 per thousand
cubic feet equivalent, compared to $3.68 per mcfe in the Prior Quarter,
including in each case the effects of hedging. Our hedging activities resulted
in increased oil and gas revenues of $64.4 million, or $1.58 per mcfe, in the
Current Quarter, compared to decreases in oil and gas revenues of $11.7 million,
or $0.35 per mcfe, resulting from our hedging activities in the Prior Quarter.
We utilize the full cost method of accounting for costs related to our oil and
gas properties. Under this method, all such costs (productive and nonproductive)
are capitalized and amortized on an aggregate basis over the estimated lives of
the properties using the units-of-production method. These capitalized costs are
subject to a ceiling test, however, which limits such pooled costs to the
aggregate of the present value of future net revenues attributable to proved oil
and gas reserves discounted at 10% plus the lower of cost or market value of
unproved properties. The full cost ceiling is evaluated at the end of each
quarter. At September 30, 2001, our unamortized costs of oil and gas
22
properties exceeded the ceiling test amount by approximately $220 million due to
low oil and gas prices in effect on that date. The market price for natural gas
at Henry Hub was $1.83 on September 28, 2001. However, due to the subsequent
recovery in market prices for natural gas we were not required to record a
write-down of oil and gas properties. A decline in gas and oil prices from
current levels, or other factors, without other mitigating circumstances, could
cause a future write-down of capitalized costs and a non-cash charge against
future earnings.
The following table shows our production by region for the Prior Quarter and the
Current Quarter:
<Table>
<Caption>
FOR THE THREE MONTHS ENDED SEPTEMBER 30,
--------------------------------------------------------
2000 2001
------------------------- -------------------------
OPERATING AREAS (MMCFE) PERCENT (MMCFE) PERCENT
----------------------------------- ---------- ---------- ---------- ----------
Mid-Continent ..................... 19,564 58% 29,159 72%
Gulf Coast ........................ 9,012 27 6,279 15
Canada ............................ 2,654 8 3,276 8
Permian Basin ..................... 1,664 5 1,155 3
Other areas ....................... 813 2 910 2
---------- ---------- ---------- ----------
Total ........................ 33,707 100% 40,779 100%
========== ========== ========== ==========
</Table>
Gas production represented approximately 90% of our total production volume on
an equivalent basis in the Current Quarter, compared to 86% in the Prior
Quarter.
Risk Management Income. Amounts recorded in this caption represent non-cash
gains and losses created by temporary valuation swings in derivatives or
portions of derivatives which are not entitled to receive hedge accounting. All
amounts recorded in this caption are ultimately reversed in this caption over
the respective contract terms. Risk management income for the Current Quarter
was a net gain of $32.3 million, which included a $37.8 million gain
attributable to the change in fair value for certain derivative instruments
which did not meet the definition of cash flow hedges under SFAS 133 for the
Current Quarter, $6.4 million reclassification to oil and gas sales related to
the settlement of derivative contracts and a gain of $0.9 million relating to
hedge ineffectiveness. Although derivatives often fail to achieve 100%
effectiveness for accounting purposes, our derivative instruments continue to be
highly effective in achieving the risk management objectives for which they were
intended.
Oil and Gas Marketing Sales. We realized $28.9 million in oil and gas marketing
sales for third parties in the Current Quarter, with corresponding oil and gas
marketing expenses of $27.9 million, for a margin of $1.0 million. This compares
to sales of $44.2 million, expenses of $42.9 million, and a margin of $1.3
million in the Prior Quarter. The decrease in marketing sales and cost of sales
was due primarily to a decrease in prices in the Current Quarter compared to the
Prior Quarter.
Production Expenses. Production expenses increased to $19.3 million in the
Current Quarter, a $7.6 million increase from the $11.7 million of production
expenses incurred in the Prior Quarter. On a unit of production basis,
production expenses were $0.47 and $0.35 per mcfe in the Current and Prior
Quarters, respectively. The increase in production expenses between periods is
due primarily to the additional costs associated with properties acquired since
the Prior Quarter, the increase in ad valorem taxes due to higher commodity
prices experienced in 2000, and the overall increase in costs for goods and
services that oil and gas producers have experienced in 2001.
Production Taxes. Production taxes, which consist primarily of wellhead
severance taxes, were $7.1 million and $6.2 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 $0.18 per mcfe in the Prior Quarter. The
per unit decrease is due to lower oil and gas prices in the Current Quarter. In
general, production taxes are calculated using value-based formulas that produce
higher per unit costs when oil and gas prices increase.
Oil and Gas Depreciation, Depletion and Amortization. Depreciation, depletion
and amortization of oil and gas properties for the Current Quarter was $46.8
million, compared to $25.2 million in the Prior Quarter. The DD&A rate per mcfe,
which is a function of capitalized costs, future development costs and the
related underlying reserves in the periods presented, increased from $0.75 in
the Prior Quarter to $1.15 in the Current Quarter. This increase is a result of
the Gothic acquisition and escalating drilling and equipment costs in 2001.
Chesapeake's DD&A rate in the future will be a function of the results of future
acquisition, exploration, development and production results.
23
Depreciation and Amortization of Other Assets. Depreciation and amortization of
other assets was $2.2 million in the Current Quarter and $1.8 million in the
Prior Quarter. We anticipate D&A will continue at current levels during the
remainder of 2001.
General and Administrative. General and administrative expenses, which are net
of capitalized internal costs, were $3.2 million in the Current Quarter compared
to $3.4 million in the Prior Quarter. We capitalized $2.1 million of internal
costs in the Current Quarter directly related to our oil and gas exploration and
development efforts, compared to $1.5 million in the Prior Quarter. We
anticipate that G&A costs during the remainder of 2001 will remain at
approximately the same level as the Current Period.
Interest and Other Income. Interest and other income for the Current Quarter was
$0.1 million compared to $0.9 million in the Prior Quarter. The decrease was
primarily the result of the recognition of a $1.0 million loss, which represents
our share of the net loss of RAM Energy, Inc. for the Current Quarter offset by
an increase in interest income. We acquired 49.5% of the outstanding common
stock of RAM on March 30, 2001. In addition, we have also made recent
investments in the corporate notes of RAM and Seven Seas Petroleum Inc. The
investments in these notes, which are described below under "Liquidity and
Capital Resources," will cause our future interest income to increase.
Interest Expense. Interest expense increased to $24.1 million in the Current
Quarter from $21.7 million in the Prior Quarter. The increase in the Current
Quarter was due to interest on debt assumed as a result of the Gothic
acquisition and an increase in interest expense related to the revolving credit
facility. These increases were partially offset by a decrease in interest
expense resulting from the refinancing of a significant portion of our senior
notes in April 2001. In addition to the interest expense reported, we
capitalized $1.2 million of interest during the Current Quarter compared to $0.6
million capitalized in the Prior Quarter.
Income Taxes. During the Current Quarter, we recorded income tax expense of
$43.4 million, compared to income tax expense of $1.4 million in the Prior
Quarter. The Prior Quarter expense related to our Canadian operations only. The
Prior Quarter U.S. tax expense was offset by a corresponding reduction in the
valuation allowance which had been established due to uncertainty surrounding
our ability to utilize tax net operating loss carryforwards prior to their
expiration. Based upon various factors, management determined that a valuation
allowance was no longer required as of December 31, 2000 and as a result we have
recognized income tax expense in 2001.
RESULTS OF OPERATIONS - Nine Months Ended September 30, 2001 ("Current Period")
vs. September 30, 2000 ("Prior Period")
General. For the Current Period, Chesapeake realized net income of $174.8
million, or $1.02 per diluted common share. This compares to $107.5 million, or
$0.73 per diluted common share in the Prior Period. Net income in the Current
Period included a $56.8 million non-cash risk management gain (net of tax)
recorded pursuant to SFAS 133, and a $46.0 million extraordinary loss in
connection with the early retirement of debt.
Oil and Gas Sales. During the Current Period, oil and gas sales increased to
$574.2 million from $311.5 million, an increase of $262.7 million, or 84%. For
the Current Period, we produced 2.1 mmbo and 107.6 bcf, compared to 2.4 mmbo and
87.2 bcf in the Prior Period. The production increase is primarily the result of
the Gothic acquisition. We have included Gothic's results of operations since
January 1, 2001 because we had effective control as of that date. Average oil
prices realized were $28.03 per barrel in the Current Period compared to $25.70
per barrel in the Prior Period, an increase of 9%. Average gas prices realized
were $4.79 per mcf in the Current Period compared to $2.86 per mcf in the Prior
Period, an increase of 67%.
For the Current Period, we realized an average price of $4.78 per mcfe, compared
to $3.06 per mcfe in the Prior Period, including in each case the effects of
hedging. Our hedging activities resulted in an increase in oil and gas revenues
of $41.1 million, or $0.34 per mcfe, in the Current Period, compared to a
decrease in oil and gas revenues of $24.9 million, or $0.24 per mcfe, resulting
from hedging activities in the Prior Period.
24
The following table shows our production by region for the Current Period and
the Prior Period:
<Table>
<Caption>
FOR THE NINE MONTHS ENDED SEPTEMBER 30,
--------------------------------------------------------
2000 2001
------------------------- -------------------------
OPERATING AREAS (MMCFE) PERCENT (MMCFE) PERCENT
----------------------------------- ---------- ---------- ---------- ----------
Mid-Continent ..................... 57,268 56% 83,553 70%
Gulf Coast ........................ 27,820 27 21,205 18
Canada ............................ 9,157 9 9,074 7
Permian ........................... 4,809 5 3,827 3
Other areas ....................... 2,669 3 2,413 2
---------- ---------- ---------- ----------
Total ........................ 101,723 100% 120,072 100%
========== ========== ========== ==========
</Table>
Gas production represented approximately 90% of our total production volume on
an equivalent basis in the Current Period, compared to 86% in the Prior Period.
Risk Management Income. Amounts recorded in this caption represent non-cash
gains and losses created by temporary valuation swings in derivatives or
portions of derivatives which are not entitled to receive hedge accounting. All
amounts recorded in this caption are ultimately reversed in this caption over
the respective contract terms. Risk management income for the Current Period was
a net gain of $94.7 million, which included a $102.8 million gain attributable
to the change in fair value for certain derivative instruments which did not
meet the definition of cash flow hedges under SFAS 133 for the Current Period,
$10.0 million reclassification to oil and gas sales related to the settlement of
derivative contracts and a gain of $1.9 million relating to hedge
ineffectiveness. Although derivatives often fail to achieve 100% effectiveness
for accounting purposes, our derivative instruments continue to be highly
effective in achieving the risk management objectives for which they were
intended.
Oil and Gas Marketing Sales. We realized $123.1 million in oil and gas marketing
sales to third parties in the Current Period, with corresponding oil and gas
marketing expenses of $119.3 million for a margin of $3.8 million. This compares
to sales of $105.8 million and expenses of $102.6 million in the Prior Period
for a margin of $3.2 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.
Production Expenses. Production expenses increased to $55.9 million in the
Current Period, a $19.1 million increase from $36.8 million incurred in the
Prior Period. On a production unit basis, production expenses were $0.47 and
$0.36 per mcfe in the Current and Prior Periods, respectively. The increase in
production expenses between periods is due primarily to the additional costs
associated with properties acquired since the Prior Period, the increase in ad
valorem taxes due to higher commodity prices and the overall increase in costs
for goods and services that oil and gas producers have experienced in 2001.
Production Taxes. Production taxes, which consist primarily of wellhead
severance taxes, were $31.3 million and $17.1 million in the Current and Prior
Periods, respectively. On a per unit basis, production taxes were $0.26 per mcfe
in the Current Period compared to $0.17 per mcfe in the Prior Period. This per
unit increase was the result of higher oil and gas prices in the Current Period.
In general, production taxes are calculated using value-based formulas that
produce higher per unit costs when oil and gas prices increase.
Oil and Gas Depreciation, Depletion and Amortization. DD&A for the Current
Period was $124.9 million, compared to $74.6 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 $0.73 to $1.04 in the Prior and Current Periods,
respectively. This increase is a result of the Gothic acquisition and escalating
drilling and equipment costs in 2001. Chesapeake's DD&A rate in the future will
be a function of the results of future acquisition, exploration, development and
production results.
Depreciation and Amortization of Other Assets. D&A increased to $6.0 million in
the Current Period compared to $5.6 million in the Prior Period. We anticipate
D&A will continue at current levels during the remainder of 2001.
General and Administrative. General and administrative expenses, which are net
of capitalized internal costs, were $10.1 million in the Current Period compared
to $9.6 million in the Prior Period. This increase is primarily due to
25
an increase in the number of employees and the general increase in overhead
associated with the growth of Chesapeake. We capitalized $6.0 million of
internal costs in the Current Period directly related to our oil and gas
exploration and development efforts, compared to $4.9 million in the Prior
Period. The increase in capitalized internal costs is primarily due to the
addition of technical employees and other related costs. We anticipate that G&A
costs during the remainder of 2001 will remain at approximately the same level
as the Current Period.
Interest and Other Income. Interest and other income for the Current Period was
$1.4 million compared to $3.7 million in the Prior Period. The decrease is
primarily the result of a reduction in other miscellaneous income and the
recognition of a $1.3 million loss, which represents our share of the net loss
of RAM Energy, Inc. for the Current Period. We acquired 49.5% of the outstanding
common stock of RAM on March 30, 2001. In addition, we have also made recent
investments in the corporate notes of RAM and Seven Seas Petroleum Inc. The
investments in the notes, which are described below under "Liquidity and Capital
Resources," will cause our future interest income to increase.
Interest Expense. Interest expense increased to $73.0 million in the Current
Period from $64.4 million in the Prior Period. The increase in the Current
Period was due to interest on the debt assumed as a result of the Gothic
acquisition in the Current Period partially offset by a decrease in interest
expense resulting from the refinancing of a significant portion of our senior
notes in April 2001. We capitalized $3.3 million of interest during the Current
Period compared to $1.9 million capitalized in the Prior Period.
Income Taxes. We recorded income tax expense of $148.6 million on pre-tax income
of $369.4 million for the Current Period, compared to $2.9 million on pre-tax
income of $110.4 million in the Prior Period. The Prior Period expense related
to our Canadian operations only. The Prior Period U.S. tax expense was offset by
a corresponding reduction in the valuation allowance which had been established
due to uncertainty surrounding our ability to utilize net tax operating loss
carryforwards prior to their expiration. Based upon various factors, management
determined that a valuation allowance was no longer required as of December 31,
2000 and as a result we recognized income tax expense in the Current Period.
Extraordinary Item. The $46.0 million extraordinary loss in the Current Period
includes the payment of aggregate make-whole and redemption premiums related to
debt repurchases and redemptions and the write-off of related unamortized debt
costs and unamortized debt issue premium in the quarter ended June 30, 2001.
RISK MANAGEMENT ACTIVITIES
See Item 3 - "Quantitative and Qualitative Disclosures About Market Risks."
LIQUIDITY AND CAPITAL RESOURCES
Chesapeake had working capital of $124.7 million at September 30, 2001.
Additionally as of September 30, 2001, we had a revolving credit facility of
$225 million, maturing September 2003, with a committed borrowing base of $225
million. As of September 30, 2001, we had borrowed $189.0 million under the
facility and $1.6 million of the facility secured various letters of credit. As
of October 24, 2001, the amount borrowed under the facility was $42.0 million
with no changes to the outstanding letters of credit. Borrowings under the
facility are collateralized by some of our producing oil and gas properties and
bear interest at either the reference rate of Union Bank of California, N.A., or
London Interbank Offered Rate (LIBOR), at our option, plus a margin that varies
according to total facility usage. The average interest rate on the outstanding
facility at September 30, 2001 was 7.3%. Unused portions of the facility accrue
an annual commitment fee of 0.50%. The credit facility contains various
covenants and restrictive provisions including financial condition covenants
requiring us to maintain certain financial ratios at or above specified levels
and periodic redeterminations of the borrowing base. In addition, extensions of
credit under the facility may not exceed the lesser of the maximum amount of
indebtedness permitted under the 8.125% senior note indenture or 15% of adjusted
consolidated net tangible assets.
Our cash provided by operating activities increased 152.4% to $441.0 million
during the Current Period compared to $174.7 million during the Prior Period.
The increase was due primarily to higher oil and gas prices realized during the
Current Period and the acquisition of Gothic Energy Corporation in January 2001.
26
Cash used in investing activities increased to $466.5 million during the Current
Period from $200.6 million in the Prior Period. During the Current Period we
expended approximately $263.7 million to initiate drilling on 409 (197.3 net)
wells and invested approximately $51.6 million in leasehold acquisitions. This
compares to $103.0 million to initiate drilling on 203 (104.3 net) wells and
$19.0 million to purchase leasehold in the Prior Period. During the Current
Period, we had acquisitions of oil and gas properties of $53.7 million and
divestitures of oil and gas properties of $1.4 million. This compares to
acquisitions of $36.3 million and divestitures of $1.4 million in the Prior
Period. We also acquired K. Stewart Petroleum Corporation for $22.4 million
during the Current Period. This acquisition included 20 bcfe of proved reserves
and more than 100 bcfe of probable and possible reserves. During the Current
Period, we had additional investments in rig equipment totaling $15.4 million
and investments in building and other fixed assets of $13.0 million.
There was $43.1 million of cash provided in financing activities in the Current
Period, compared to $0.2 million in the Prior Period. The activity in the
Current Period reflects the net increase in borrowings under our commercial bank
credit facility of $164.0 million. This is primarily offset by the $786.7
million received from the issuance of the $800 million 8.125% senior notes in
April 2001, the $830.4 million paid for the redemption of various senior secured
notes and the $2.9 million received from the exercise of stock options.
On October 1, 2001, we closed on the sale of our Canadian subsidiary which
resulted in net cash proceeds of approximately $143 million. The proceeds were
used to reduce the amounts outstanding under our revolving bank credit facility.
We have budgeted approximately $350 - $375 million for capital expenditures for
exploration and development activities for 2001, and $215 - $245 million for
2002. Additionally we expect to be actively acquiring oil and gas reserves. We
believe we have adequate resources, including cash on hand, budgeted cash flows
from operations, unused borrowing capacity on our bank facility and cash
available from our hedging activities to execute our business plan. Additional
acquisitions above budget may require equity and/or debt financings, which we
believe would be available.
During the first quarter 2001, we purchased and subsequently retired $7.3
million of our 8.5% senior notes due 2012 for total consideration of $7.4
million, including accrued interest of $0.2 million and the write-off of $0.1
million of unamortized bond discount.
On April 6, 2001, we issued $800 million principal amount of 8.125% senior notes
due 2011, of which substantially all were subsequently exchanged on July 12,
2001 for substantially identical notes registered under the Securities Act of
1933. During April 2001, we used a portion of the offering proceeds to purchase
$140.7 million principal amount of our 9.625% senior notes and $3.0 million
principal amount of the 11.125% senior secured notes of Gothic Production
Corporation, a Chesapeake subsidiary. On May 7, 2001, we redeemed all $120
million principal amount of our 9.125% senior notes, the remaining $359.3
million principal amount of our 9.625% senior notes and the remaining $199.3
million principal amount of Gothic Production Corporation's 11.125% senior
secured notes. The purchase and redemption of these notes included payment of
aggregate make-whole and redemption premiums of $75.6 million which was further
adjusted by the write-off of unamortized debt costs and debt issue premiums.
These costs are reflected as a $46.0 million, after tax, extraordinary loss in
the Current Period. The refinancing lowered the interest rate and extended the
maturity of approximately 74% of our senior notes.
As of September 30, 2001, our senior notes represented $1.1 billion of our
long-term debt and consisted of the following: $800 million principal amount of
8.125% senior notes due 2011, $150 million principal amount of 7.875% senior
notes due 2004 and $142.7 million principal amount of 8.5% senior notes due
2012. There are no scheduled principal payments required on any of the senior
notes until March 2004, when $150 million is due. Debt ratings for the senior
notes are B2 by Moody's Investor Service, B+ by Standard & Poor's Ratings
Services and BB- by Fitch, IBCA, Duff and Phelps as of September 30, 2001. Debt
ratings for our secured bank credit facility are Ba3 by Moody's Investor
Service, BB by Standard & Poor's Ratings Services and BB+ by Fitch, IBCA, Duff
and Phelps.
Our senior notes are unsecured senior obligations of Chesapeake and rank equally
with all of our other unsecured indebtedness. All of our wholly owned
subsidiaries except Chesapeake Energy Marketing, Inc. and Carmen Acquisition
Corp. guarantee the notes, including Gothic Energy Corporation and Gothic
Production Corporation as
27
of May 14, 2001. The 7.875% senior notes and the 8.5% senior notes are
redeemable at our option at any time prior to March 15, 2004 at the make-whole
price determined in accordance with the indentures, and on and after March 15,
2004, we may redeem the 8.5% senior notes at the redemption price set forth in
the indenture. We may redeem all or some of the 8.125% senior notes at any time
after April 1, 2006 and prior to such date pursuant to make-whole provisions in
the indenture. If we repurchase at least 50% of the 7.875% senior notes by
August 31, 2003, the credit facility is extended until June 2005 for an amount
equal to the total revolving credit facility commitment less the outstanding
amount of the 7.875% notes plus $50 million.
The indenture for the 8.125% senior notes contains covenants limiting our
ability and our restricted subsidiaries' ability to incur additional
indebtedness; pay dividends on our capital stock or redeem, repurchase or retire
our capital stock or subordinated indebtedness; make investments and other
restricted payments; create restrictions on the payment of dividends or other
amounts to us from our restricted subsidiaries; incur liens; engage in
transactions with affiliates; sell assets; and consolidate, merge or transfer
assets. The debt incurrence covenant does not affect our ability to borrow under
or expand our secured credit facility. As of September 30, 2001, we estimate
that secured commercial bank indebtedness of approximately $1.2 billion could
have been incurred under the indenture. The indenture covenants do not apply to
Chesapeake Energy Marketing, Inc. and Carmen Acquisition Corp., both
unrestricted subsidiaries.
On May 1, 2001, we redeemed all of the outstanding shares of our 7% cumulative
convertible preferred stock at a redemption price of $52.45 per share, payable
in 5.7 shares of common stock and cash of $2.45. Prior to redemption, the
preferred stock was convertible into common stock at a conversion price of $6.95
per share.
On March 30, 2001, we issued 1.1 million shares of Chesapeake common stock in
exchange for 1.3 million shares of RAM Energy, Inc. common stock, representing
49.5% of its outstanding equity securities. Our shares were valued at $8.854
each, or $9.9 million in total. We agreed to adjust the consideration for our
acquisition of RAM shares by making a cash payment to the RAM shareholders equal
to the shortfall if they sold the Chesapeake shares they received at a price
less than $8.854 per share. In the Current Quarter, the RAM shareholders sold
all their shares of Chesapeake common stock at prices below this level and we
made cash payments of approximately $3.3 million to them to cover the shortfall.
We also received an option granted by one of the RAM shareholders to purchase an
additional 1.0% of RAM's outstanding equity securities. The option is
exercisable for a year beginning in February 2002 for an aggregate exercise
price of $202,000 in cash. In addition, we have also made recent investments in
the corporate notes of RAM.
On July 24, 2001, we purchased $22.5 million principal amount of 12% senior
secured notes due 2004 issued by Seven Seas Petroleum Inc. and detachable
seven-year warrants to purchase approximately 12.6 million shares of Seven Seas
common stock at an exercise price of approximately $1.78 per share. The shares
issuable upon exercise of the warrants will represent 20% of Seven Seas common
stock after completion of a rights offering and other transactions contemplated
by Seven Seas. Seven Seas has granted us registration rights with respect to the
warrant shares. Seven Seas common stock is listed for trading on the American
Stock Exchange. The chairman and chief executive officer of Seven Seas has
granted us an option that could require him to purchase a portion of our notes
and warrants if he has not invested at least $10.0 million in Seven Seas notes
after the proposed rights offering The 12% senior secured notes and $22.5
million of notes acquired by other parties are secured by a pledge of
substantially all of the assets owned by Seven Seas, including all of the Seven
Seas subsidiaries which hold the concessions to the company's oil and gas
interests in Colombia.
On September 21, 2001, our board of directors authorized the repurchase of up to
$50 million of our common stock, either through direct purchases or put options.
We have not made any repurchases or written any put options to date under this
program.
On October 25, 2001, Chesapeake priced a private offering of $250 million of
senior notes due 2008, which will carry an interest rate coupon of 8.375%. The
net proceeds are expected to be approximately $248 million. The
8.375% senior notes offered by Chesapeake will not be registered under the
Securities Act of 1933, as amended, but will be subject to an agreement
requiring Chesapeake to exchange the offered notes for registered senior notes
of a substantially similar series or otherwise register the offered notes. The
8.375% senior notes will be redeemable by us prior to November 1, 2005 by
payment of a make-whole penalty, and after November 1, 2005 at annually
declining premiums. The 8.375% senior notes will be guaranteed by the same
subsidiaries that guarantee our outstanding senior notes and will be subject to
covenants substantially similar to those contained in the indenture for our
8.125% senior notes. Closing of the 8.375% senior notes offering is expected to
occur on November 5, 2001 and is subject to satisfaction of customary closing
conditions and receipt of a bank consent.
The net proceeds from the pending offering of 8.375% senior notes are expected
to be used for general corporate purposes, including the funding of future
acquisitions. Chesapeake is in various stages of negotiations for the purchase
of over $300 million of Mid-Continent oil and gas assets in several
transactions. The assets primarily consist of relatively long-lived proved
producing gas reserves located in Oklahoma. We believe that many of these
properties have significant development potential. If successful in some or all
of these negotiations, we would acquire the assets directly through asset
purchases or indirectly through the acquisition of privately-held companies.
Proceeds from the senior notes offering would be used to fund these
acquisitions, although there is no assurance as to the timing or magnitude of
any acquisitions or the ultimate success of any of these negotiations.
Additional funding, if any, required for these acquisitions would be obtained
from cash flow, borrowings under our existing credit facility, monetization of
some of our hedging positions or a possible offering of equity securities by
Chesapeake.
Recently Issued Accounting Standards
In June 2001, the Financial Accounting Standards Board issued SFAS Nos. 141 and
142. SFAS No. 141, Business Combinations, requires that the purchase method of
accounting be used for all business combinations initiated after June 30, 2001.
SFAS No. 142, Goodwill and Other Intangible Assets, changes the accounting for
goodwill from an amortization method to an impairment-only approach and will be
effective January 2002. We believe that adoption of these new standards will not
have an effect on our results of operations or our financial position. In June
2001,
28
the FASB issued SFAS No. 143, Accounting for Asset Retirement Allocations.
Management is currently assessing the impact SFAS No. 143 will have on our
financial condition and results of operations, but we believe the impact will be
immaterial.
FORWARD-LOOKING STATEMENTS
This report 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 give our current expectations or forecasts
of future events. These statements are based on our historical operating trends,
our estimate of proved reserves as of September 30, 2001 and our current
derivative contract position. They include statements regarding oil and gas
reserve estimates, planned capital expenditures, the drilling of oil and gas
wells and future acquisitions, expected oil and gas production, cash flow and
anticipated liquidity, business strategy and other plans and objectives for
future operations, expected future expenses and utilization of net operating
loss carryforwards. Statements concerning the fair values of derivative
contracts and their estimated contribution to our future results of operations
are based upon market information as of a specific date. These market prices are
subject to significant volatility.
Although we believe the expectations and forecasts reflected in these and other
forward-looking statements are reasonable, we can give no assurance they will
prove to have been correct. They can be affected by inaccurate assumptions or by
known or unknown risks and uncertainties. Factors that could cause actual
results to differ materially from expected results include oil and gas reserve
impairments resulting from lower prices and other factors described under "Risk
Factors" in our Form 10-K, as amended, for the year ended December 31, 2000.
These factors include:
o the volatility of oil and gas prices,
o our substantial indebtedness,
o our commodity price risk management activities,
o the cost and availability of drilling and production services,
o our ability to replace reserves,
o the availability of capital,
o uncertainties inherent in estimating quantities of oil and gas
reserves, projecting future rates of production and the timing
of development expenditures,
o uncertainties in evaluating oil and gas reserves of acquired
properties and associated potential liabilities,
o drilling and operating risks,
o our ability to generate future taxable income sufficient to
utilize our NOLs before expiration,
o future ownership changes which could result in additional
limitations to our NOLs,
o adverse effects of governmental and environmental regulation,
o losses possible from pending or future litigation,
o the strength and financial resources of our competitors, and
o the loss of officers or key employees.
We caution you not to place undue reliance on these forward-looking statements,
which speak only as of the date of this report, and we undertake no obligation
to update this information. We urge you to carefully review and consider the
disclosures made in this and 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.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
COMMODITY RISK MANAGEMENT ACTIVITY
Our results of operations and operating cash flows are impacted by changes in
market prices for oil and gas. To mitigate a portion of this exposure to adverse
market changes, we have entered into derivative instruments. All of our
derivative instruments have been entered into as hedges of oil and gas price
risk and not for speculative purposes.
29
We utilize derivative instruments to reduce exposure to unfavorable changes in
oil and gas prices which are subject to significant and often volatile
fluctuations. Our derivative instruments are currently comprised of swaps,
collars and cap-swaps. These instruments allow us to predict with greater
certainty the effective oil and gas prices to be received for our hedged
production.
o For swap instruments, we receive a fixed price for the hedged commodity
and pay a floating market price, as defined in each instrument, to the
counterparty. The fixed-price payment and the floating-price payment
are netted, resulting in a net amount due to or from the counterparty.
o Collars contain a fixed floor price (put) and ceiling price (call). If
the market price exceeds the call strike price or falls below the put
strike price, then we receive the fixed price and pay the market price.
If the market price is between the call and the put strike price, then
no payments are due from either party.
o For cap-swaps, we receive a fixed price for the hedged commodity and
pay a floating market price. The fixed price received by Chesapeake
includes a premium in exchange for a "cap" on the counterparty's
exposure.
Pursuant to SFAS 133, our cap-swaps do not qualify for designation as cash flow
hedges. Therefore, changes in the fair value of these instruments that occur
prior to their maturity are reported in the statement of operations as risk
management income (loss). Amounts recorded in risk management income (loss) do
not represent cash gains or losses. Rather, these amounts are temporary
valuation swings in contracts or portions of contracts that are not entitled to
receive hedge accounting treatment. All amounts initially recorded in this
caption are ultimately reversed within this same caption over the respective
contract terms.
The estimated fair values of our derivative instruments as of September 30, 2001
are provided below. The associated carrying values of these instruments are
equal to the estimated fair values.
<Table>
<Caption>
SEPTEMBER 30,
2001
---------------
($ IN THOUSANDS)
Derivative assets:
Fixed-price gas swaps .......................... $ 121,443
Fixed-price gas cap-swaps ...................... 90,762
Fixed-price gas collars ........................ 19,954
Fixed-price crude oil swaps .................... 4,836
Fixed-price crude oil cap-swaps ................ 2,035
---------------
Total .......................................... $ 239,030
===============
</Table>
The fair value of our derivative instruments as of September 30, 2001 was
estimated based on market prices of gas and crude oil for the periods covered by
the instruments. The net differential between the prices in each instrument and
market prices for future periods has been applied to the volumes stipulated in
each instrument to arrive at an estimated fair value. The fair value of
derivative instruments which contain options (such as collar structures) has
been estimated based on remaining term, volatility and other factors.
Risk management income in the statement of operations for the following period
is comprised of the following:
<Table>
<Caption>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2001 SEPTEMBER 30, 2001
------------------ ------------------
($ IN THOUSANDS)
Risk Management Income:
Change in fair value of derivatives not qualifying for
hedge accounting .................................................... $ 37,742 $ 102,793
Reclassification of settled contracts ................................... (6,440) (9,996)
Ineffective portion of derivatives qualifying for hedge accounting ...... 958 1,918
--------------- ---------------
$ 32,260 $ 94,715
=============== ===============
</Table>
Although derivatives often fail to achieve 100% effectiveness for accounting
purposes, our derivative instruments continue to be highly effective in
achieving the risk management objectives for which they were intended.
The change in fair value of our derivative instruments since December 31, 2000
has resulted from a decrease in market prices for gas and crude oil. The
majority of this change in fair value is reflected in accumulated other
comprehensive income, net of deferred income tax effects, in the September 30,
2001 consolidated balance sheet. Derivative assets reflected as current in the
consolidated balance sheet represent the estimated fair value of
30
derivative instrument settlements scheduled to occur over the subsequent
twelve-month period based on market prices for oil and gas as of the balance
sheet date. The derivative settlement amounts are not due and payable until the
month in which the related underlying hedged transaction occurs.
We expect to transfer approximately $59.1 million of the balance in accumulated
other comprehensive income, based upon the market prices at September 30, 2001,
to earnings during the next 12 months when the forecasted transactions actually
occur. All forecasted transactions currently being hedged are expected to occur
by December 2003.
As of September 30, 2001, we had the following derivative instruments designed
to hedge a portion of our domestic gas production for periods after September
2001:
<Table>
<Caption>
SWAPS CAP-SWAPS COLLARS
---------------------- --------------------------------- -----------------------------------------
NYMEX
NYMEX NYMEX CAPPED NYMEX NYMEX
INDEX INDEX LOW DEFINED DEFINED
STRIKE STRIKE STRIKE LOW HIGH
PRICE PRICE PRICE STRIKE STRIKE
VOLUME ($ PER VOLUME ($ PER ($ PER VOLUME PRICE PRICE
(MMBTU) MMBTU) (MMBTU) MMBTU) MMBTU) (MMBTU) ($ PER MMBTU) ($ PER MMBTU)
---------- ------ ---------- ------ ------ --------- ------------- -------------
4th Quarter 2001 21,180,000 4.21 11,020,000 5.94 4.62 5,520,000 4.00 6.08
---------- ---------- ----------
Total 2001 21,180,000 4.21 11,020,000 5.94 4.62 5,520,000 4.00 6.08
---------- ---------- ----------
1st Quarter 2002 12,350,000 4.15 18,900,000 5.32 4.10 1,800,000 4.00 5.75
2nd Quarter 2002 9,100,000 3.76 22,750,000 4.55 3.55 3,640,000 4.00 5.38
3rd Quarter 2002 9,200,000 3.83 23,000,000 4.57 3.57 3,680,000 4.00 5.38
4th Quarter 2002 12,860,000 3.99 18,120,000 4.49 3.49 2,460,000 4.00 5.56
---------- ---------- ----------
Total 2002 43,510,000 3.95 82,770,000 4.72 3.67 11,580,000 4.00 5.47
---------- ---------- ----------
1st Quarter 2003 14,090,000 4.03 12,600,000 3.79 2.79 -- -- --
2nd Quarter 2003 13,650,000 3.62 12,740,000 3.42 2.42 -- -- --
3rd Quarter 2003 13,800,000 3.72 12,880,000 3.50 2.50 -- -- --
4th Quarter 2003 13,800,000 3.89 12,880,000 3.69 2.69 -- -- --
---------- ----------
Total 2003 55,340,000 3.82 51,100,000 3.60 2.60 -- -- --
---------- ----------
</Table>
Subsequent to September 30, 2001, we settled the gas swaps, gas cap-swaps and
gas collars for October 2001. Gains in the following amounts will be recognized
as price adjustments in October 2001: $21.1 million for gas swaps, $3.1 million
for gas cap-swaps and $3.9 million for gas collars.
As of September 30, 2001, we had the following open derivative instruments
designed to hedge a portion of our domestic crude oil production for periods
after September 2001:
<Table>
<Caption>
SWAPS CAP-SWAPS
----------------------- -------------------------------------
NYMEX
NYMEX NYMEX CAPPED
INDEX INDEX LOW
STRIKE STRIKE STRIKE
VOLUME PRICE VOLUME PRICE PRICE
(MBBLS) ($ PER BBL) (MBBLS) ($ PER BBL) ($ PER BBL)
------- ----------- ------- ----------- -----------
4th Quarter 2001 670 28.80 -- -- --
---
Total 2001 670 28.80 -- -- --
---
1st Quarter 2002 360 25.86 270 25.64 20.64
2nd Quarter 2002 362 25.19 273 25.41 20.41
3rd Quarter 2002 62 25.00 276 25.18 20.18
4th Quarter 2002 -- -- 276 24.98 19.98
--- -----
Total 2002 784 25.48 1,095 25.30 20.30
--- -----
</Table>
31
Subsequent to September 30, 2001, we closed transactions designed to hedge a
portion of our natural gas production in 2002 and 2003. The net unrecognized
gains resulting from these transactions, $35.9 million, will be recognized as
price adjustments in the months of related production. These hedging gains are
set forth below ($ in thousands):
<Table>
<Caption>
HEDGING GAINS (LOSSES)
----------------------
1st Quarter 2002 $ 6,836
2nd Quarter 2002 4,758
3rd Quarter 2002 4,605
4th Quarter 2002 4,058
-------
Total 2002 $20,257
=======
1st Quarter 2003 $ 5,218
2nd Quarter 2003 3,326
3rd Quarter 2003 3,645
4th Quarter 2003 3,487
-------
Total 2003 $15,676
=======
</Table>
INTEREST RATE RISK
The table below presents principal cash flows and related weighted average
interest rates by expected maturity dates. The fair value of the long-term debt
has been estimated based on quoted market prices.
<Table>
<Caption>
SEPTEMBER 30, 2001
-------------------------------------------------------------------------------------------
YEARS OF MATURITY
-------------------------------------------------------------------------------------------
2001 2002 2003 2004 2005 THEREAFTER TOTAL FAIR VALUE
-------- -------- -------- -------- -------- ---------- -------- ----------
($ IN MILLIONS)
LIABILITIES:
Long-term debt, including current
portion -- fixed rate .............. $ 0.8 $ -- $ -- $ 150.0 $ -- $ 942.7 $1,093.5 $1,032.5
Average interest rate ................ 9.1% -- -- 7.9% -- 8.2% 8.1% --
Long-term debt -- variable rate ...... $ -- $ -- $ 189.0 $ -- $ -- $ -- $ 189.0 $ 189.0
Average interest rate ................ -- -- 7.3% -- -- -- 7.3% --
</Table>
Changes in interest rates affect the amount of interest we earn on our cash,
cash equivalents and short-term investments and the interest rate we pay on
borrowings under our revolving credit facility. We are not presently using any
interest rate derivative instruments to manage exposure to interest rate
changes. All of our other long-term indebtedness is fixed rate and therefore
does not expose us to the risk of earnings or cash flow loss due to changes in
market interest rates.
32
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
We are subject to ordinary routine litigation incidental to our business none of
which are expected to have a material adverse effect on Chesapeake. In addition,
Chesapeake is a defendant in other pending actions which are described in Item 3
of our Annual Report on Form 10-K for the year ended December 31, 2000.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
-- Not applicable
ITEM 3. DEFAULTS UPON SENIOR SECURITIES OR DIVIDEND ARREARAGES
-- Not applicable
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
-- Not applicable
ITEM 5. OTHER INFORMATION
-- Not applicable
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
The following exhibits are filed as a part of this report:
Exhibit No.
4.1.1 Sixth Supplemental Indenture, dated as of December 31, 1999,
to Indenture dated as of March 15, 1997 among Chesapeake
Energy Corporation, as Issuer, its subsidiaries signatory
thereto, as Subsidiary Guarantors, and Bank of New York, as
Trustee, with respect to 7-7/8% Senior Notes due 2004.
4.1.2 Seventh Supplemental Indenture, dated as of September 12,
2001, to Indenture dated as of March 15, 1997 among
Chesapeake Energy Corporation, as Issuer, its subsidiaries
signatory thereto, as Subsidiary Guarantors, and Bank of New
York, as Trustee, with respect to 7-7/8% Senior Notes due
2004.
4.1.3 Eighth Supplemental Indenture, dated as of October 1, 2001,
to Indenture dated as of March 15, 1997 among Chesapeake
Energy Corporation, as Issuer, its subsidiaries signatory
thereto, as Subsidiary Guarantors, and The Bank of New York,
as Trustee, with respect to 7-7/8% Senior Notes due 2004.
4.2.1 Sixth Supplemental Indenture, dated as of December 31, 1999,
to Indenture dated as of March 15, 1997 among Chesapeake
Energy Corporation, as Issuer, its subsidiaries signatory
thereto, as Subsidiary Guarantors, and Bank of New York, as
Trustee, with respect to 8-1/2% Senior Notes due 2012.
4.2.2 Seventh Supplemental Indenture, dated as of September 12,
2001, to Indenture dated as of March 15, 1997 among
Chesapeake Energy Corporation, as Issuer, its subsidiaries
signatory thereto, as Subsidiary Guarantors, and Bank of New
York, as Trustee, with respect to 8-1/2% Senior Notes due
2012.
33
4.2.3 Eighth Supplemental Indenture, dated as of October 1, 2001,
to Indenture dated as of March 15, 1997 among Chesapeake
Energy Corporation, as Issuer, its subsidiaries signatory
thereto, as Subsidiary Guarantors, and The Bank of New York,
as Trustee, with respect to 8-1/2% Senior Notes due 2012.
4.3.1 Second Supplemental Indenture, dated as of September 12,
2001, to Indenture dated as of April 6, 2001 among
Chesapeake Energy Corporation, as Issuer, its subsidiaries
signatory thereto, as Subsidiary Guarantors, and Bank of New
York, as Trustee, with respect to 8-1/8% Senior Notes due
2011.
4.3.2 Third Supplemental Indenture, dated as of October 1, 2001,
to Indenture dated as of April 6, 2001 among Chesapeake
Energy Corporation, as Issuer, its subsidiaries signatory
thereto, as Subsidiary Guarantors, and The Bank of New York,
as Trustee, with respect to 8-1/8% Senior Notes due 2011.
4.6.1 Consent and waiver letter dated September 10, 2001 with
respect to Second Amended and Restated Credit Agreement,
dated as of June 11, 2001, among Chesapeake Energy
Corporation, Chesapeake Exploration Limited Partnership, as
Borrower, Bear Stearns Corporate Lending Inc., as
Syndication Agent, Union Bank of California, N.A., as
Administrative Agent and Collateral Agent, and other lenders
party thereto.
4.6.2 Consent and waiver letter dated October 5, 2001 with respect
to Second Amended and Restated Credit Agreement, dated as of
June 11, 2001, among Chesapeake Energy Corporation,
Chesapeake Exploration Limited Partnership, as Borrower,
Bear Stearns Corporate Lending Inc., as Syndication Agent,
Union Bank of California, N.A., as Administrative Agent and
Collateral Agent, and other lenders party thereto.
4.7 Second Amended and Restated Employment Agreement dated as of
July 1, 2001, between Aubrey K. McClendon and Chesapeake
Energy Corporation.
4.8 Second Amended and Restated Employment Agreement dated as of
July 1, 2001, between Tom L. Ward and Chesapeake Energy
Corporation.
12 Computation of ratios of earnings to fixed charges.
(b) Reports on Form 8-K
During the quarter ended September 30, 2001, we filed the
following current reports on Form 8-K:
On July 17, 2001, we filed a current report on Form 8-K reporting under Item 5
that we had issued a press release on July 13, 2001 announcing the schedule for
our second quarter 2001 earnings release and providing information for accessing
the related conference call.
On July 27, 2001, we filed a current report on Form 8-K reporting under Item 9
the posting on our web site of operating assumptions and projections for the
third quarter of 2001 and full years 2001 and 2002.
On July 27, 2001, we filed a current report on Form 8-K reporting under Item 5
that we had issued a press release on July 26, 2001 announcing our earnings for
the second quarter of 2001, our hedges of 2001-2003 natural gas production, the
anticipated sale of our Canadian subsidiary, the reduction of our drilling
cap-ex budget, updated 2001 and 2002 forecasts, and recent investments we have
made.
On August 13, 2001, we filed a current report on Form 8-K containing in Item 5 a
description of our capital stock. It amended and superseded the description of
capital stock in our registration statement on Form 8-B, as amended by our
filing on Form 8-K on December 18, 2000.
34
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CHESAPEAKE ENERGY CORPORATION
(Registrant)
By: /s/ Aubrey K. McClendon
----------------------------------------
Aubrey K. McClendon
Chairman and Chief Executive Officer
October 26, 2001 By: /s/ Marcus C. Rowland
-------------------------------- ----------------------------------------
Date Marcus C. Rowland
Executive Vice President and
Chief Financial Officer
35
INDEX TO EXHIBITS
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
4.1.1 Sixth Supplemental Indenture, dated as of December 31, 1999,
to Indenture dated as of March 15, 1997 among Chesapeake
Energy Corporation, as Issuer, its subsidiaries signatory
thereto, as Subsidiary Guarantors, and Bank of New York, as
Trustee, with respect to 7-7/8% Senior Notes due 2004.
4.1.2 Seventh Supplemental Indenture, dated as of September 12,
2001, to Indenture dated as of March 15, 1997 among Chesapeake
Energy Corporation, as Issuer, its subsidiaries signatory
thereto, as Subsidiary Guarantors, and Bank of New York, as
Trustee, with respect to 7-7/8% Senior Notes due 2004.
4.1.3 Eighth Supplemental Indenture, dated as of October 1, 2001, to
Indenture dated as of March 15, 1997 among Chesapeake Energy
Corporation, as Issuer, its subsidiaries signatory thereto, as
Subsidiary Guarantors, and The Bank of New York, as Trustee,
with respect to 7-7/8% Senior Notes due 2004.
4.2.1 Sixth Supplemental Indenture, dated as of December 31, 1999,
to Indenture dated as of March 15, 1997 among Chesapeake
Energy Corporation, as Issuer, its subsidiaries signatory
thereto, as Subsidiary Guarantors, and Bank of New York, as
Trustee, with respect to 8-1/2% Senior Notes due 2012.
4.2.2 Seventh Supplemental Indenture, dated as of September 12,
2001, to Indenture dated as of March 15, 1997 among Chesapeake
Energy Corporation, as Issuer, its subsidiaries signatory
thereto, as Subsidiary Guarantors, and Bank of New York, as
Trustee, with respect to 8-1/2% Senior Notes due 2012.
4.2.3 Eighth Supplemental Indenture, dated as of October 1, 2001, to
Indenture dated as of March 15, 1997 among Chesapeake Energy
Corporation, as Issuer, its subsidiaries signatory thereto, as
Subsidiary Guarantors, and The Bank of New York, as Trustee,
with respect to 8-1/2% Senior Notes due 2012.
4.3.1 Second Supplemental Indenture, dated as of September 12, 2001,
to Indenture dated as of April 6, 2001 among Chesapeake Energy
Corporation, as Issuer, its subsidiaries signatory thereto, as
Subsidiary Guarantors, and Bank of New York, as Trustee, with
respect to 8-1/8% Senior Notes due 2011.
4.3.2 Third Supplemental Indenture, dated as of October 1, 2001, to
Indenture dated as of April 6, 2001 among Chesapeake Energy
Corporation, as Issuer, its subsidiaries signatory thereto, as
Subsidiary Guarantors, and The Bank of New York, as Trustee,
with respect to 8-1/8% Senior Notes due 2011.
4.6.1 Consent and waiver letter dated September 10, 2001 with
respect to Second Amended and Restated Credit Agreement,
dated as of June 11, 2001, among Chesapeake Energy
Corporation, Chesapeake Exploration Limited Partnership, as
Borrower, Bear Stearns Corporate Lending Inc., as Syndication
Agent, Union Bank of California, N.A., as Administrative Agent
and Collateral Agent, and other lenders party thereto.
4.6.2 Consent and waiver letter dated October 5, 2001 with respect
to Second Amended and Restated Credit Agreement, dated as of
June 11, 2001, among Chesapeake Energy Corporation, Chesapeake
Exploration Limited Partnership, as Borrower, Bear Stearns
Corporate Lending Inc., as Syndication Agent, Union Bank of
California, N.A., as Administrative Agent and Collateral
Agent, and other lenders party thereto.
12 Computation of ratios of earnings to fixed charges.
</Table>