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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, 2002
[ ] Transition Report pursuant to Section 13 or 15(d) of the
Securities Exchange 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)
OKLAHOMA 73-1395733
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
6100 NORTH WESTERN AVENUE 73118
OKLAHOMA CITY, OKLAHOMA (Zip Code)
(Address of principal executive offices)
(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 November 4, 2002, there were 166,253,078 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, 2002
PAGE
----
PART I.
FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements (Unaudited):
Consolidated Balance Sheets at September 30, 2002 and December 31, 2001 ....................... 3
Consolidated Statements of Operations for the Three Months and Nine Months
Ended September 30, 2002 and 2001 ............................................................. 4
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2002
and 2001 ...................................................................................... 5
Consolidated Statements of Comprehensive Income (Loss) for the Three Months and Nine
Months Ended September 30, 2002 and 2001 ...................................................... 6
Notes to Consolidated Financial Statements .................................................... 7
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations............22
Item 3. Quantitative and Qualitative Disclosures About Market Risk.......................................32
Item 4. Controls and Procedures..........................................................................37
PART II.
OTHER INFORMATION
Item 1. Legal Proceedings................................................................................38
Item 2. Changes in Securities and Use of Proceeds........................................................38
Item 3. Defaults Upon Senior Securities .................................................................38
Item 4. Submission of Matters to a Vote of Security Holders..............................................38
Item 5. Other Information................................................................................38
Item 6. Exhibits and Reports on Form 8-K.................................................................38
2
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
SEPTEMBER 30, DECEMBER 31,
2002 2001
-------------- --------------
($ IN THOUSANDS)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ......................................................... $ 25,378 $ 117,594
Restricted cash ................................................................... 131 7,366
Accounts receivable:
Oil and gas sales ............................................................... 82,908 51,496
Joint interest, net of allowance for bad debts of $1,321,000 and $947,000,
respectively ................................................................. 19,617 17,364
Short-term derivatives .......................................................... 16,576 34,543
Related parties ................................................................. 2,198 9,896
Other ........................................................................... 15,374 14,951
Short-term derivative instruments ................................................. 843 97,544
Inventory and other ............................................................... 12,824 10,629
-------------- --------------
Total Current Assets ........................................................ 175,849 361,383
-------------- --------------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at cost based on full-cost accounting:
Evaluated oil and gas properties ................................................ 4,210,692 3,546,163
Unevaluated properties .......................................................... 68,995 66,205
Less: accumulated depreciation, depletion and amortization ...................... (2,060,317) (1,902,587)
-------------- --------------
2,219,370 1,709,781
Other property and equipment ...................................................... 142,904 115,694
Less: accumulated depreciation and amortization ................................... (44,561) (39,894)
-------------- --------------
Total Property and Equipment ................................................ 2,317,713 1,785,581
-------------- --------------
OTHER ASSETS:
Long-term derivatives receivable .................................................. 4,058 18,852
Deferred income tax asset ......................................................... 9,717 67,781
Long-term derivative instruments .................................................. -- 6,370
Long-term investments ............................................................. 20,734 29,849
Other assets ...................................................................... 16,562 16,952
-------------- --------------
Total Other Assets .......................................................... 51,071 139,804
-------------- --------------
TOTAL ASSETS ........................................................................ $ 2,544,633 $ 2,286,768
============== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Notes payable and current maturities of long-term debt ............................ $ -- $ 602
Accounts payable .................................................................. 83,860 79,945
Accrued interest .................................................................. 45,039 26,316
Short-term derivative instruments ................................................. 22,348 --
Other accrued liabilities ......................................................... 59,463 36,998
Revenues and royalties due others ................................................. 35,643 29,520
-------------- --------------
Total Current Liabilities ................................................... 246,353 173,381
-------------- --------------
LONG-TERM DEBT, NET ................................................................. 1,494,180 1,329,453
-------------- --------------
REVENUES AND ROYALTIES DUE OTHERS ................................................... 14,191 12,696
-------------- --------------
LONG-TERM DERIVATIVE INSTRUMENTS .................................................... 49,358 --
-------------- --------------
OTHER LIABILITIES ................................................................... 5,764 3,831
-------------- --------------
CONTINGENCIES AND COMMITMENTS (NOTE 3)
STOCKHOLDERS' EQUITY:
Preferred Stock, $.01 par value, 10,000,000 shares authorized; 2,998,000 and
3,000,000 shares of 6.75% cumulative convertible preferred stock issued and
outstanding at September 30, 2002 and December 31, 2001, respectively,
entitled in liquidation to $149.9 million and $150 million ...................... 149,900 150,000
Common Stock, $.01 par value, 350,000,000 shares authorized; 171,019,880 and
169,534,991 shares issued at September 30, 2002 and December 31, 2001,
respectively .................................................................... 1,710 1,696
Paid-in capital ................................................................... 1,038,347 1,035,156
Accumulated deficit ............................................................... (444,089) (442,974)
Accumulated other comprehensive income, net of tax of $5,934,000 and
$29,000,000, respectively ....................................................... 8,901 43,511
Less: treasury stock, at cost; 4,792,529 common shares at September 30, 2002
and December 31, 2001 ........................................................... (19,982) (19,982)
-------------- --------------
Total Stockholders' Equity .................................................. 734,787 767,407
-------------- --------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY .......................................... $ 2,544,633 $ 2,286,768
============== ==============
The accompanying notes are an integral part of these consolidated
financial statements.
3
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ ------------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
REVENUES:
Oil and gas sales ..................................................... $ 163,012 $ 177,746 $ 456,992 $ 574,190
Risk management income (loss) ......................................... (7,046) 32,260 (86,995) 94,715
Oil and gas marketing sales ........................................... 42,216 28,905 112,334 123,071
---------- ---------- ---------- ----------
Total Revenues .................................................... 198,182 238,911 482,331 791,976
---------- ---------- ---------- ----------
OPERATING COSTS:
Production expenses ................................................... 24,950 19,303 71,252 55,933
Production taxes ...................................................... 6,807 7,063 19,934 31,349
General and administrative ............................................ 3,777 3,240 11,930 10,114
Oil and gas marketing expenses ........................................ 41,148 27,946 108,836 119,337
Oil and gas depreciation, depletion and amortization .................. 58,334 46,821 157,731 124,904
Depreciation and amortization of other assets ......................... 3,727 2,164 10,489 5,954
---------- ---------- ---------- ----------
Total Operating Costs ............................................. 138,743 106,537 380,172 347,591
---------- ---------- ---------- ----------
INCOME FROM OPERATIONS ................................................. 59,439 132,374 102,159 444,385
---------- ---------- ---------- ----------
OTHER INCOME (EXPENSE):
Interest and other income ............................................. 1,806 132 7,343 1,384
Interest expense ...................................................... (28,316) (24,104) (79,966) (72,977)
Impairment of Seven Seas warrants ..................................... (4,770) -- (4,770) --
Loss on repurchases of debt ........................................... (489) -- (1,353) --
Gothic standby credit facility costs .................................. -- -- -- (3,392)
---------- ---------- ---------- ----------
Total Other Income (Expense) ...................................... (31,769) (23,972) (78,746) (74,985)
---------- ---------- ---------- ----------
INCOME BEFORE INCOME TAX AND EXTRAORDINARY ITEM ........................ 27,670 108,402 23,413 369,400
PROVISION FOR INCOME TAXES:
Current ............................................................... -- 1,118 -- 3,354
Deferred .............................................................. 11,070 42,276 9,366 145,265
---------- ---------- ---------- ----------
Total Provision For Income Taxes .................................. 11,070 43,394 9,366 148,619
---------- ---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM ....................................... 16,600 65,008 14,047 220,781
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt, net of applicable income tax .... -- -- -- (46,000)
---------- ---------- ---------- ----------
NET INCOME ............................................................. 16,600 65,008 14,047 174,781
PREFERED STOCK DIVIDENDS ............................................... (2,526) -- (7,588) (728)
---------- ---------- ---------- ----------
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS ............................ $ 14,074 $ 65,008 $ 6,459 $ 174,053
========== ========== ========== ==========
EARNINGS PER COMMON SHARE -- BASIC:
Income before extraordinary item ...................................... $ 0.08 $ 0.40 $ 0.04 $ 1.36
Extraordinary item .................................................... -- -- -- (0.28)
---------- ---------- ---------- ----------
Net income ............................................................ $ 0.08 $ 0.40 $ 0.04 $ 1.08
========== ========== ========== ==========
EARNINGS PER COMMON SHARE -- ASSUMING DILUTION:
Income before extraordinary item ...................................... $ 0.08 $ 0.38 $ 0.04 $ 1.29
Extraordinary item .................................................... -- -- -- (0.27)
---------- ---------- ---------- ----------
Net income ............................................................ $ 0.08 $ 0.38 $ 0.04 $ 1.02
========== ========== ========== ==========
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT
SHARES OUTSTANDING :
Basic ................................................................. 166,144 164,440 165,829 161,603
========== ========== ========== ==========
Assuming dilution ..................................................... 171,182 170,384 171,540 170,937
========== ========== ========== ==========
The accompanying notes are an integral part of these consolidated
financial statements.
4
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
NINE MONTHS ENDED
SEPTEMBER 30,
------------------------
2002 2001
---------- ----------
($ IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME ............................................................................. $ 14,047 $ 174,781
ADJUSTMENTS TO RECONCILE NET INCOME TO NET
CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization ............................................. 164,365 127,987
Risk management (income) loss ........................................................ 86,995 (94,715)
Extraordinary loss on early extinguishment of debt ................................... -- 46,000
Deferred income taxes ................................................................ 9,366 145,265
Write-off of credit facility cost .................................................... -- 3,392
Amortization of loan costs ........................................................... 3,626 2,871
Equity in losses of equity investees ................................................. -- 1,331
Loss on repurchase of debt ........................................................... 1,353 --
Impairment of Seven Seas warrants .................................................... 4,770 --
Other ................................................................................ (223) 272
---------- ----------
CASH PROVIDED BY OPERATING ACTIVITIES BEFORE CHANGES IN ASSETS AND LIABILITIES ..... 284,299 407,184
Changes in assets and liabilities .................................................... 69,359 33,772
---------- ----------
CASH PROVIDED BY OPERATING ACTIVITIES .............................................. 353,658 440,956
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of oil and gas properties .................................. (252,756) (263,746)
Acquisition of unproved properties ..................................................... (46,808) (64,556)
Acquisition of oil and gas companies and proved properties, net of cash acquired ....... (291,366) (62,205)
Sales of oil and gas properties ........................................................ 1,211 1,432
Sales of non-oil and gas assets ........................................................ 75 734
Additions to other fixed assets ........................................................ (25,919) (13,049)
Additions to drilling rig equipment .................................................... (3,381) (15,393)
Additions to long-term investments ..................................................... (2,408) (37,206)
Proceeds from sale of RAM Energy notes ................................................. 4,215 --
Other .................................................................................. (46) (174)
---------- ----------
CASH USED IN INVESTING ACTIVITIES .................................................. (617,183) (454,163)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving bank credit facility ........................................... 95,818 372,000
Payments on revolving bank credit facility ............................................. (95,818) (208,000)
Cash received from issuance of senior notes ............................................ 245,984 786,664
Cash paid to repurchase senior notes ................................................... (63,541) (830,382)
Cash paid for premium on repurchase of senior notes .................................... (1,869) (75,639)
Financing charges ...................................................................... (3,671) (12,340)
Cash received from exercise of stock options ........................................... 2,129 2,929
Cash paid for preferred stock dividend ................................................. (7,649) (1,092)
Cash paid in settlement of make-whole provision related to common stock ................ -- (3,336)
Other .................................................................................. (74) (10)
---------- ----------
CASH PROVIDED BY FINANCING ACTIVITIES .............................................. 171,309 30,794
---------- ----------
Effect of changes in exchange rate on cash ............................................... -- (545)
---------- ----------
NET CHANGE IN CASH AND CASH EQUIVALENTS .................................................. (92,216) 17,042
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD ........................................... 117,594 --
---------- ----------
CASH AND CASH EQUIVALENTS, END OF PERIOD ................................................. $ 25,378 $ 17,042
========== ==========
The accompanying notes are an integral part of these consolidated
financial statements.
5
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ ------------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
($ IN THOUSANDS)
Net income ................................................................ $ 16,600 $ 65,008 $ 14,047 $ 174,781
Other comprehensive income (loss), net of income tax:
Foreign currency translation adjustments ................................ -- (2,826) -- (3,551)
Cumulative effect of accounting change for financial derivatives ........ -- -- -- (53,580)
Change in fair value of derivative instruments .......................... (3,887) 63,857 (16,859) 159,326
Reclassification of (gain) or loss on settled contracts ................. (3,274) (34,786) (19,044) (18,774)
Ineffective portion of derivatives qualifying for cash flow hedge
accounting ............................................................ 32 (575) 1,342 (1,151)
Other ................................................................... (49) -- (49) --
---------- ---------- ---------- ----------
Comprehensive income (loss) ............................................... $ 9,422 $ 90,678 $ (20,563) $ 257,051
========== ========== ========== ==========
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, 2002
(UNAUDITED)
1. BASIS OF PRESENTATION
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, 2002 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, 2001 (the
"Prior Quarter" and "Prior Period", respectively) and the three and nine months
ended September 30, 2002 (the "Current Quarter" and "Current Period",
respectively).
2. HEDGING ACTIVITIES AND FINANCIAL INSTRUMENTS
Oil and Gas 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 the exposure to
adverse market changes, we have entered into various derivative instruments. As
of September 30, 2002, our oil and gas derivative instruments were comprised of
swaps, collars, cap-swaps, straddles, strangles and basis protection swaps.
These instruments allow us to predict with greater certainty the effective oil
and gas prices to be received for our hedged production. 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.
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" limiting the counterparty's
exposure.
o For straddles, Chesapeake receives a premium from the counterparty in
exchange for the sale of a call and a put option at an established
fixed price. To the extent that the floating market price differs from
the established fixed price, Chesapeake pays the counterparty.
o For strangles, Chesapeake receives a premium from the counterparty in
exchange for the sale of a call and a put option. If the market price
exceeds the fixed price of the call option or falls below the fixed
price of the put option, then Chesapeake pays the counterparty. If the
market price settles between the fixed price of the call and put
option, no payment is due from Chesapeake.
o Basis protection swaps are arrangements that guarantee a price
differential of oil and gas from a specified delivery point.
Chesapeake receives a payment from the counterparty if the price
differential is greater than the stated terms of the contract and pays
the counterparty if the price differential is less than the stated
terms of the contract.
From time to time, we close certain swap transactions designed to hedge a
portion of our oil and natural gas production by entering into a counter-swap
instrument. Under the counter-swap we receive a floating price for the hedged
commodity and pay a fixed price to the counterparty. To the extent the
counter-swap, which does not
7
qualify for hedge accounting under SFAS 133, is designed to lock the value of an
existing SFAS 133 cash flow hedge, the net value of the swap and the
counter-swap is frozen and shown as a derivative receivable or payable in the
consolidated balance sheets. At the same time, the original swap is designated
as a non-qualifying cash flow hedge under SFAS 133.
Pursuant to SFAS 133, our cap-swaps, straddles, strangles, counter-swaps
and basis protection 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, together with any changes in fair value of cash flow hedges
resulting from ineffectiveness, are reported in the consolidated statements 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 SFAS 133 cash flow hedge accounting treatment. All amounts
initially recorded in this caption related to commodity derivatives are
ultimately reversed within this same caption and included in oil and gas sales
over the respective contract terms.
The estimated fair values of our oil and gas derivative instruments as of
September 30, 2002 are provided below. The associated carrying values of these
instruments are equal to the estimated fair values.
SEPTEMBER 30,
2002
--------------
($ IN THOUSANDS)
Derivative assets (liabilities):
Fixed-price gas swaps .......................... $ (4,800)
Fixed-price gas collars ........................ 843
Fixed-price gas cap-swaps ...................... (18,698)
Gas basis protection swaps ..................... 2,246
Gas straddles .................................. (3,235)
Gas strangles .................................. (26,808)
Fixed-price gas counter-swaps .................. 13,771
Fixed-price gas locked swaps ................... 20,634
Fixed-price crude oil swaps .................... (1,894)
Fixed-price crude oil cap-swaps ................ (3,062)
--------------
Estimated fair value ......................... (21,003)
--------------
Estimated fair value, as adjusted for premiums
received ......................................... $ 10,123(a)
==============
(a) After adjusting for the $31.1 million premium paid to Chesapeake by the
counterparty at the inception of the straddle and strangle contracts (which
is recorded in cash provided by operating activities on the accompanying
consolidated statements of cash flows), the net value of the combined
hedging portfolio at September 30, 2002 was $10.1 million.
Based upon the market prices at September 30, 2002, we expect to transfer
approximately $6.4 million of the balance in accumulated other comprehensive
income to earnings during the next 12 months when the transactions actually
occur. All transactions hedged as of September 30, 2002 are expected to mature
by December 31, 2004, with the exception of the basis protection swaps which
extend to 2009.
Additional information concerning the fair value of our oil and gas
derivative instruments is as follows ($ in thousands):
Fair value of contracts outstanding at January 1, 2002 ............... $ 157,309
Change in fair value of contracts during period ...................... (48,559)
Contracts realized or otherwise settled during the period ............ (84,150)
Fair value of new contracts when entered into during the period ...... (45,603)
---------
Fair value of contracts outstanding at September 30, 2002 ............ $ (21,003)
=========
8
Risk management income (loss) related to our oil and gas derivatives is
comprised of the following ($ in thousands):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ ------------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
Risk management income (loss):
Change in fair value of derivatives not qualifying for hedge accounting ... $ 8,056 $ 37,742 $ (34,474) $ 102,793
Reclassification of gain on settled contracts ............................. (16,764) (6,440) (52,471) (9,996)
Ineffective portion of derivatives qualifying for cash flow hedge
accounting .............................................................. (54) 958 (2,236) 1,918
---------- ---------- ---------- ----------
Total ................................................................... $ (8,762) $ 32,260 $ (89,181) $ 94,715
========== ========== ========== ==========
Interest Rate Hedging
We also utilize hedging strategies to manage interest rate exposure.
Results from interest rate hedging transactions are reflected as adjustments to
interest expense in the corresponding months covered by the derivative
agreement.
In March 2002, we entered into an interest rate swap to convert a portion
of our fixed rate debt to floating rate debt. The terms of this swap agreement
are as follows:
TERM NOTIONAL AMOUNT FIXED RATE FLOATING RATE
---- --------------- ---------- -------------
March 2002 - March 2004 $200,000,000 7.875% U.S. six-month LIBOR in
arrears plus 298.25 basis
points
At the inception of the interest rate swap agreement, a portion of the
interest rate swap was entered into to convert $129.0 million of the 7.875%
senior notes from fixed rate debt to variable rate debt. Under SFAS 133, a hedge
of interest rate risk in a recognized fixed rate liability can be designated as
a fair value hedge under which the mark-to-market value of the swap is recorded
on the consolidated balance sheets as an asset or liability with a corresponding
increase or decrease in the carrying value of the debt. During the Current
Quarter and Current Period, $21.3 million and $63.5 million face value,
respectively, of the 7.875% senior notes were purchased and subsequently
retired. In connection with the repurchase of the 7.875% senior notes, interest
rate swap hedging gains of $0.4 million and $0.9 million were recognized in the
Current Quarter and Current Period, respectively, and reduced the loss on
repurchases of debt.
In July 2002, we closed the above interest rate swap for a gain of $7.5
million. As of September 30, 2002, the remaining balance to be amortized as a
reduction to interest expense was $4.1 million. During the Current Period, $2.5
million was recognized as a reduction to interest expense.
In June 2002, we entered into an additional interest rate swap. The terms
of this swap agreement are as follows:
TERM NOTIONAL AMOUNT FIXED RATE FLOATING RATE
---- --------------- ---------- -------------
July 2002 - July 2004 $100,000,000 4.000% U.S. six-month LIBOR in
arrears
In July 2002, we closed this interest rate swap for a gain of $1.1 million.
During the Current Period, $0.1 million was recognized as a reduction to
interest expense.
9
In April 2002, we entered into a swaption agreement in order to monetize
the embedded call option in the remaining $142.7 million of our 8.5% senior
notes. We received $7.8 million from the counterparty at the time we entered
into this agreement. The terms of the swaption are as follows:
TERM NOTIONAL AMOUNT FIXED RATE FLOATING RATE
---- --------------- ---------- -------------
March 2004 - March 2012 $142,665,000 8.500% U.S. six-month LIBOR plus
75 basis points
Under the terms of the swaption agreement, the counterparty will have the
option to initiate an interest rate swap on March 11, 2004 pursuant to the terms
shown above. If the counterparty chooses to initiate the interest rate swap, the
payments under the swap will coincide with the semi-annual interest payments on
our 8.5% senior notes which are paid on September 15 and March 15 of each year.
On each payment date, if the fixed rate exceeds the floating rate, we will pay
the counterparty, and if the floating rate exceeds the fixed rate, the
counterparty will pay us accordingly. If the counterparty does not choose to
initiate the interest rate swap, the swaption agreement will expire and no
future obligations will exist for either party.
Under SFAS 133, a fair value hedge relationship exists between the embedded
call option in the debt and the swaption agreement. Accordingly, the
mark-to-market value of the swaption is recorded on the consolidated balance
sheets as an asset or liability with a corresponding increase or decrease to the
debt's carrying value. Any change in the fair value of the swaption resulting
from ineffectiveness is recorded currently in the consolidated statements of
operations as risk management income (loss).
We have recorded a decrease in the carrying value of the debt of $20.3
million during the Current Period related to the swaption as of September 30,
2002. Of this amount, $21.4 million represents a decline in the fair value of
the swaption, offset by a loss of $1.1 million from estimated ineffectiveness of
the swaption as determined under SFAS 133. See Note 5 for the adjustments made
to the carrying value of the debt at September 30, 2002. Results of the swaption
will be reflected as adjustments to interest expense in the corresponding months
covered by the swaption agreement.
Risk management income related to our fair value hedges is comprised of the
following ($ in thousands):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2002 SEPTEMBER 30, 2002
------------------ ------------------
Risk management income:
Change in fair value of derivatives not qualifying for
fair value hedge accounting .......................................... $ 2,292 $ 4,593
Reclassification of gains on settled contracts to interest expense ...... (576) (1,307)
Ineffective portion of derivatives qualifying for
fair value hedge accounting .......................................... -- (1,100)
------------------ ------------------
Total ................................................................. $ 1,716 $ 2,186
================== ==================
Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial
instruments is made in accordance with the requirements of Statement of
Financial Accounting Standards No. 107, Disclosures About Fair Value of
Financial Instruments. We have determined the estimated fair value amounts by
using available market information and valuation methodologies. Considerable
judgment is required in interpreting market data to develop the estimates of
fair value. The use of different market assumptions or valuation methodologies
may have a material effect on the estimated fair value amounts.
The carrying values of items comprising current assets and current
liabilities approximate fair values due to the short-term maturities of these
instruments. We estimate the fair value of our long-term (including current
maturities), fixed-rate debt using primarily quoted market prices. Excluding the
impact of our fair value hedges, our carrying amount for such debt at December
31, 2001 and September 30, 2002 was $1,330.1 million and $1,512.7 million,
respectively, compared to approximate fair values of $1,343.0 and $1,529.4
million, respectively. The carrying amount for our 6.75% convertible preferred
stock at September 30, 2002 was $149.9 million, compared to the approximate fair
value of $156.5 million.
10
Concentration of Credit Risk
A significant portion of our liquidity is concentrated in cash and cash
equivalents, and derivative instruments that enable us to hedge a portion of our
exposure to price volatility from producing oil and natural gas and interest
rate volatility. These arrangements expose us to credit risk from our
counterparties. Other financial instruments which potentially subject us to
concentrations of credit risk consist principally of investments in debt
instruments and accounts receivables. Our accounts receivable are primarily from
purchasers of oil and natural gas products and exploration and production
companies which own interests in properties we operate. The concentration of
these assets in the oil and gas industry has the potential to impact our overall
exposure to credit risk, either positively or negatively, in that our customers
may be similarly affected by changes in economic, industry or other conditions.
We generally require letters of credit for receivables from customers which are
judged to have sub-standard credit, unless the credit risk can otherwise be
mitigated. Cash and cash equivalents are deposited with major banks or
institutions with high credit ratings.
3. CONTINGENCIES AND COMMITMENTS
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 16 lawsuits filed
between June 1997 and December 2001 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 16 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
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 December 2001, the Texas Supreme Court accepted for
review petitions we filed with respect to the claims of the non-settling
plaintiffs in two of the cases covered by the settlement. The Court heard oral
arguments in March 2002 and has not yet issued a decision.
There are eight other related West Panhandle cessation cases which are
pending, three in the District Court of Moore County, Texas, 69th Judicial
District, two in the District Court of Carson County, Texas, 100th Judicial
District, and three 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
another of the Moore County, Texas cases, 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 two other cases, and the
remaining three cases are in the pleading stage.
We 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
11
estimates. CP and the other defendants are vigorously defending against the
plaintiffs' claims.
Royalty Owner Litigation. Recently royalty owners have commenced litigation
against a number of companies in the oil and gas production business claiming
that amounts paid for production attributable to the royalty owners' interest
violated the terms of the applicable leases and state law, that deductions from
the proceeds of oil and gas production were unauthorized under the applicable
leases and that amounts received by upstream sellers should be used to compute
the amounts paid to the royalty owners. In the course of our oil and gas
marketing activities, a portion of the foregoing litigation has been commenced
as class action suits including five class action suits filed against Chesapeake
and others. No class has been certified in any of the cases in which Chesapeake
is a named defendant. We believe the claims asserted do not represent valid
claims or, if valid, are not material. As new cases are decided and the law in
this area continues to develop, our liability relating to the marketing of oil
and gas may increase or decrease. We will continue to monitor the court
decisions to ensure that our operations and practices minimize any exposure and
to recognize any charges that may be appropriate when we can reasonably estimate
a liability.
Chesapeake is currently involved in various other routine disputes
incidental to its business operations. 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.
4. 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 statements of operations for all entities with complex
capital structures. SFAS No. 128 requires a reconciliation of the numerator and
denominator of the basic and diluted EPS computations.
The following securities were not included in the calculation of diluted
earnings per share, as the effect was antidilutive:
o For the Prior Quarter, the Current Quarter, the Prior Period and the
Current Period, outstanding warrants to purchase 1.1 million shares of
common stock at a weighted average exercise price of $12.61 were
antidilutive because the exercise prices of the warrants were greater than
the average price of the common stock.
o For the Prior Quarter, the Current Quarter, the Prior Period and the
Current Period, outstanding options to purchase 3.8 million, 7.8 million,
0.3 million and 0.5 million shares of common stock at a weighted average
exercise price of $6.97, $6.56, $17.25 and $12.77, respectively, were
antidilutive because the exercise prices of the options were greater than
the average market price of the common stock.
o Diluted shares in the Current Quarter and Current Period do not include the
assumed conversion of the outstanding 6.75% preferred stock (convertible
into 19.5 million common shares) and the Current Period does not include
the common stock equivalent of preferred stock outstanding prior to
conversion of 7,611 shares, as the effects were antidilutive.
12
A reconciliation for the periods presented is as follows:
INCOME SHARES PER SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
------------- ------------- -------------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2002:
BASIC EPS
Income available to common shareholders ................................... $ 14,074 166,144 $ 0.08
=============
EFFECT OF DILUTIVE SECURITIES
Employee stock options .................................................... -- 5,031
Warrants assumed in Gothic acquisition .................................... -- 7
------------- -------------
DILUTED EPS
Income available to common shareholders and assumed
conversions ............................................................. $ 14,074 171,182 $ 0.08
============= ============= =============
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2001:
BASIC EPS
Income available to common shareholders ................................... $ 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 shareholders and assumed
conversions ............................................................. $ 65,008 170,384 $ 0.38
============= ============= =============
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2002:
BASIC EPS
Income available to common shareholders ................................... $ 6,459 165,829 $ 0.04
=============
EFFECT OF DILUTIVE SECURITIES
Employee stock options .................................................... -- 5,704
Warrants assumed in Gothic acquisition .................................... -- 7
------------- -------------
DILUTED EPS
Income available to common shareholders and assumed
conversions ............................................................. $ 6,459 171,540 $ 0.04
============= ============= =============
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2001:
BASIC EPS
Income available to common shareholders ................................... $ 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 issued .................................................... -- 1,957
Preferred stock dividends ............................................... 728 --
Employee stock options .................................................... -- 7,370
Warrants assumed in Gothic acquisition .................................... -- 7
------------- -------------
DILUTED EPS
Income available to common shareholders and assumed
conversions ............................................................. $ 174,781 170,937 $ 1.02
============= ============= =============
5. SENIOR NOTES AND REVOLVING CREDIT FACILITY
At September 30, 2002, our long-term debt consisted of the following ($ in
thousands):
7.875% senior notes, due 2004 .................... $ 86,459
8.375% senior notes, due 2008 .................... 250,000
8.125% senior notes, due 2011 .................... 800,000
8.5% senior notes, due 2012 ...................... 142,665
9.0% senior notes, due 2012 ...................... 250,000
Revolving bank credit facility ................... --
Discount on senior notes ......................... (16,439)
Discount for interest rate swaps and swaption .... (18,505)
-----------
Total .......................................... $ 1,494,180
===========
13
During the Current Period, we purchased and subsequently retired $63.5
million of the 7.875% senior notes for total consideration of $66.3 million,
including $0.9 million of accrued interest and $1.9 million of redemption
premium. Subsequent to September 30, 2002, we purchased $25.6 million of the
7.875% senior notes for total consideration of $26.8 million, including $0.2
million in accrued interest and $1.0 million in redemption premium.
In August 2002, we issued $250 million principal amount of 9% senior notes
due 2012, which were subsequently exchanged on October 24, 2002 for
substantially identical notes registered under the Securities Act of 1933.
On September 30, 2002, we had a $225 million revolving bank credit facility
(with a committed borrowing base of $225 million) which matures in September
2003. As of September 30, 2002, we had no outstanding borrowings under this
facility and were using $25.5 million of the facility to secure various letters
of credit. During November 2002, we increased the credit facility to $250
million (with a committed borrowing base of $225 million). We expect to increase
the borrowing base to $250 million and to extend the term of the credit facility
to June 2005 during the fourth quarter of 2002. Borrowings under the facility
are collateralized by certain 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 unused portion of the facility is subject
to an annual commitment fee of 0.50%. Interest is payable quarterly. The
collateral value and borrowing base are redetermined periodically.
The credit facility contains various covenants and restrictive provisions
which restrict our ability to incur additional indebtedness, sell properties,
pay dividends, purchase or redeem our capital stock, make investments or loans,
purchase certain of our senior notes, create liens, and make acquisitions. The
credit facility requires us to maintain a current ratio of at least 1 to 1 (as
defined in the credit facility) and a fixed charge coverage ratio of at least
2.5 to 1. If we should fail to perform our obligations under these and other
covenants, the revolving credit commitment could be terminated and any
outstanding borrowings under the facility could be declared immediately due and
payable. If such an acceleration involved principal in excess of $10.0 million,
the acceleration would constitute an event of default under our senior note
indentures, which could in turn result in the acceleration of our senior note
indebtedness. The credit facility also has cross default provisions that apply
to other indebtedness we may have with an outstanding principal balance in
excess of $5.0 million.
Our senior notes are unsecured senior obligations of Chesapeake and rank
equally with all of our other unsecured indebtedness. The senior note indentures
contain covenants limiting us and our guarantor subsidiaries with respect to
asset sales; restricted payments; the incurrence of additional indebtedness and
the issuance of preferred stock; liens; sale and leaseback transactions; lines
of business; dividend and other payment restrictions affecting guarantor
subsidiaries; mergers or consolidations; and transactions with affiliates. The
senior note indentures also limit our ability to make restricted payments (as
defined), including the payment of cash dividends, unless the debt incurrence
and other tests are met.
Chesapeake is a holding company and owns no operating assets and has no
significant operations independent of its subsidiaries. Our obligations under
all our senior notes have been fully and unconditionally guaranteed, on a joint
and several basis, by each of our "restricted subsidiaries" (as defined in the
respective indentures governing these notes) (collectively, the "guarantor
subsidiaries"). Each guarantor subsidiary is a direct or indirect wholly-owned
subsidiary.
Set forth below are condensed consolidating financial statements of the
guarantor subsidiaries and Chesapeake Energy Marketing, Inc, which is not a
guarantor of the senior notes and was a non-guarantor subsidiary for all periods
presented. All of our other wholly-owned subsidiaries were guarantor
subsidiaries during all periods presented.
14
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF SEPTEMBER 30, 2002
($ IN THOUSANDS)
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- ------------ ------------ ------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ...................... $ (31,480) $ 19,555 $ 37,434 $ -- $ 25,509
Accounts receivable ............................ 94,452 51,930 6,168 (32,453) 120,097
Short-term derivative accounts receivable ...... 16,576 -- -- -- 16,576
Short-term derivative instruments .............. 843 -- -- -- 843
Inventory and other ............................ 12,288 531 5 -- 12,824
------------ ------------ ------------ ------------ ------------
Total Current Assets .................... 92,679 72,016 43,607 (32,453) 175,849
------------ ------------ ------------ ------------ ------------
PROPERTY AND EQUIPMENT:
Oil and gas properties ......................... 4,210,692 -- -- -- 4,210,692
Unevaluated leasehold .......................... 68,995 -- -- -- 68,995
Other property and equipment ................... 60,945 28,803 53,156 -- 142,904
Less: accumulated depreciation,
depletion and amortization ................... (2,081,287) (19,696) (3,895) -- (2,104,878)
------------ ------------ ------------ ------------ ------------
Net Property and Equipment .............. 2,259,345 9,107 49,261 -- 2,317,713
------------ ------------ ------------ ------------ ------------
OTHER ASSETS:
Investments in subsidiaries and
intercompany advances ........................ -- -- 333,080 (333,080) --
Long-term derivative receivable ................ 4,058 -- -- -- 4,058
Deferred income tax asset ...................... (118,144) (1,928) 129,789 -- 9,717
Long-term investments .......................... -- -- 20,734 -- 20,734
Other assets ................................... 3,628 117 12,850 (33) 16,562
------------ ------------ ------------ ------------ ------------
Total Other Assets ...................... (110,458) (1,811) 496,453 (333,113) 51,071
------------ ------------ ------------ ------------ ------------
TOTAL ASSETS ..................................... $ 2,241,566 $ 79,312 $ 589,321 $ (365,566) $ 2,544,633
============ ============ ============ ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Notes payable and current maturities
of long-term debt ............................ $ -- $ -- $ -- $ -- $ --
Accounts payable ............................... 100,515 51,441 -- (32,453) 119,503
Accrued interest ............................... 429 -- 44,610 -- 45,039
Accrued liabilities ............................ 46,558 3,133 9,766 6 59,463
Short-term derivative instruments .............. 22,348 -- -- -- 22,348
------------ ------------ ------------ ------------ ------------
Total Current Liabilities ............... 169,850 54,574 54,376 (32,447) 246,353
------------ ------------ ------------ ------------ ------------
LONG-TERM DEBT ................................... -- -- 1,494,180 -- 1,494,180
------------ ------------ ------------ ------------ ------------
REVENUES AND ROYALTIES DUE OTHERS ................ 14,191 -- -- -- 14,191
------------ ------------ ------------ ------------ ------------
LONG-TERM DERIVATIVE INSTRUMENTS ................. 20,132 -- 29,226 -- 49,358
------------ ------------ ------------ ------------ ------------
OTHER LIABILITIES ................................ 5,764 -- -- -- 5,764
------------ ------------ ------------ ------------ ------------
INTERCOMPANY PAYABLES ............................ 1,724,481 (1,194) (1,723,248) (39) --
------------ ------------ ------------ ------------ ------------
STOCKHOLDERS' EQUITY:
Common Stock ................................... 66 1 1,700 (57) 1,710
Other .......................................... 307,082 25,931 733,087 (333,023) 733,077
------------ ------------ ------------ ------------ ------------
Total Stockholders' Equity .............. 307,148 25,932 734,787 (333,080) 734,787
------------ ------------ ------------ ------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY ......................................... $ 2,241,566 $ 79,312 $ 589,321 $ (365,566) $ 2,544,633
============ ============ ============ ============ ============
15
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2001
($ IN THOUSANDS)
NON-
GUARANTOR GUARANTOR
SUBSIDIARY SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ...................... $ (7,905) $ 19,714 $ 113,151 $ -- $ 124,960
Accounts receivable ............................ 78,950 30,380 2,715 (18,338) 93,707
Short-term derivative receivable ............... 34,543 -- -- -- 34,543
Short-term derivative instruments .............. 97,544 -- -- -- 97,544
Inventory and other ............................ 10,208 421 -- -- 10,629
------------ ------------ ------------ ------------ ------------
Total Current Assets ................... 213,340 50,515 115,866 (18,338) 361,383
------------ ------------ ------------ ------------ ------------
PROPERTY AND EQUIPMENT:
Oil and gas properties ......................... 3,546,163 -- -- -- 3,546,163
Unevaluated leasehold .......................... 66,205 -- -- -- 66,205
Other property and equipment ................... 53,681 23,537 38,476 -- 115,694
Less: accumulated depreciation, depletion
and amortization ........................... (1,920,613) (18,668) (3,200) -- (1,942,481)
------------ ------------ ------------ ------------ ------------
Net Property and Equipment ............. 1,745,436 4,869 35,276 -- 1,785,581
------------ ------------ ------------ ------------ ------------
OTHER ASSETS:
Investments in subsidiaries and
intercompany advances ....................... -- -- (21,054) 21,054 --
Long-term derivative receivable ................ 18,852 -- -- -- 18,852
Deferred income tax asset ...................... (218,596) (1,376) 287,753 -- 67,781
Long-term derivative instruments ............... 6,370 -- -- -- 6,370
Long-term investments .......................... -- -- 29,849 -- 29,849
Other assets ................................... 5,589 334 11,050 (21) 16,952
------------ ------------ ------------ ------------ ------------
Total Other Assets ..................... (187,785) (1,042) 307,598 21,033 139,804
------------ ------------ ------------ ------------ ------------
TOTAL ASSETS ..................................... $ 1,770,991 $ 54,342 $ 458,740 $ 2,695 $ 2,286,768
============ ============ ============ ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Notes payable and current maturities of
long-term debt .............................. $ 602 $ -- $ -- $ -- $ 602
Accounts payable ............................... 92,203 35,600 -- (18,338) 109,465
Accrued interest ............................... -- -- 26,316 -- 26,316
Accrued liabilities ............................ 35,764 1,155 22 57 36,998
------------ ------------ ------------ ------------ ------------
Total Current Liabilities .............. 128,569 36,755 26,338 (18,281) 173,381
------------ ------------ ------------ ------------ ------------
LONG-TERM DEBT ................................... -- -- 1,329,453 -- 1,329,453
------------ ------------ ------------ ------------ ------------
REVENUES AND ROYALTIES DUE OTHERS ................ 12,696 -- -- -- 12,696
------------ ------------ ------------ ------------ ------------
OTHER LIABILITIES ................................ 3,831 -- -- -- 3,831
------------ ------------ ------------ ------------ ------------
INTERCOMPANY PAYABLES ............................ 1,664,517 19 (1,664,458) (78) --
------------ ------------ ------------ ------------ ------------
STOCKHOLDERS' EQUITY:
Common Stock ................................... 66 1 1,686 (57) 1,696
Other .......................................... (38,688) 17,567 765,721 21,111 765,711
------------ ------------ ------------ ------------ ------------
Total Stockholders' Equity ............. (38,622) 17,568 767,407 21,054 767,407
------------ ------------ ------------ ------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY ........................................... $ 1,770,991 $ 54,342 $ 458,740 $ 2,695 $ 2,286,768
============ ============ ============ ============ ============
16
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2002:
REVENUES:
Oil and gas sales .............................. $ 163,012 $ -- $ -- $ -- $ 163,012
Risk management income (loss) .................. (8,764) -- 1,718 -- (7,046)
Oil and gas marketing sales .................... -- 134,510 -- (92,294) 42,216
------------ ------------ ------------ ------------ ------------
Total Revenues ............................... 154,248 134,510 1,718 (92,294) 198,182
------------ ------------ ------------ ------------ ------------
OPERATING COSTS:
Production expenses and taxes .................. 31,757 -- -- -- 31,757
General and administrative ..................... 3,301 471 5 -- 3,777
Oil and gas marketing expenses ................. -- 133,442 -- (92,294) 41,148
Oil and gas depreciation, depletion and
amortization ................................. 58,334 -- -- -- 58,334
Other depreciation and amortization ............ 2,668 487 572 -- 3,727
------------ ------------ ------------ ------------ ------------
Total Operating Costs ........................ 96,060 134,400 577 (92,294) 138,743
------------ ------------ ------------ ------------ ------------
INCOME FROM OPERATIONS ........................... 58,188 110 1,141 -- 59,439
------------ ------------ ------------ ------------ ------------
OTHER INCOME (EXPENSE):
Interest and other income ...................... 275 300 24,532 (28,560) (3,453)
Interest expense ............................... (27,990) (2) (28,884) 28,560 (28,316)
Equity in net earnings of subsidiaries ......... -- -- 18,526 (18,526) --
------------ ------------ ------------ ------------ ------------
Total Other Income (Expense) ................. (27,715) 298 14,174 (18,526) (31,769)
------------ ------------ ------------ ------------ ------------
INCOME BEFORE INCOME TAXES ....................... 30,473 408 15,315 (18,526) 27,670
INCOME TAX EXPENSE ............................... 12,191 164 (1,285) -- 11,070
------------ ------------ ------------ ------------ ------------
NET INCOME ....................................... $ 18,282 $ 244 $ 16,600 $ (18,526) $ 16,600
============ ============ ============ ============ ============
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
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)
Equity in net earnings of subsidiaries ......... -- -- 89,918 (89,918) --
------------ ------------ ------------ ------------ ------------
Total Other Income (Expense) ................. (24,937) (956) 91,839 (89,918) (23,972)
------------ ------------ ------------ ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES ................ 107,441 (341) 91,220 (89,918) 108,402
INCOME TAX EXPENSE ............................... 43,009 (136) 26,212 (25,691) 43,394
------------ ------------ ------------ ------------ ------------
NET INCOME (LOSS) ................................ $ 64,432 $ (205) $ 65,008 $ (64,227) $ 65,008
============ ============ ============ ============ ============
17
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2002:
REVENUES:
Oil and gas sales .............................. $ 456,992 $ -- $ -- $ -- $ 456,992
Risk management income (loss) .................. (89,182) -- 2,187 -- (86,995)
Oil and gas marketing sales .................... -- 362,939 -- (250,605) 112,334
------------ ------------ ------------ ------------ ------------
Total Revenues ............................... 367,810 362,939 2,187 (250,605) 482,331
------------ ------------ ------------ ------------ ------------
OPERATING COSTS:
Production expenses and taxes .................. 91,186 -- -- -- 91,186
General and administrative ..................... 10,296 1,363 271 -- 11,930
Oil and gas marketing expenses ................. -- 359,441 -- (250,605) 108,836
Oil and gas depreciation, depletion and
amortization ................................. 157,731 -- -- -- 157,731
Other depreciation and amortization ............ 7,323 1,257 1,909 -- 10,489
------------ ------------ ------------ ------------ ------------
Total Operating Costs ........................ 266,536 362,061 2,180 (250,605) 380,172
------------ ------------ ------------ ------------ ------------
INCOME FROM OPERATIONS ........................... 101,274 878 7 -- 102,159
------------ ------------ ------------ ------------ ------------
OTHER INCOME (EXPENSE):
Interest and other income ...................... 1,427 511 82,349 (83,067) 1,220
Interest expense ............................... (80,620) (10) (82,403) 83,067 (79,966)
Equity in net earnings of subsidiaries ......... -- -- 14,075 (14,075) --
------------ ------------ ------------ ------------ ------------
Total Other Income (Expense) ................. (79,193) 501 14,021 (14,075) (78,746)
------------ ------------ ------------ ------------ ------------
INCOME BEFORE INCOME TAXES ....................... 22,081 1,379 14,028 (14,075) 23,413
INCOME TAX EXPENSE (BENEFIT) ..................... 8,833 552 (19) -- 9,366
------------ ------------ ------------ ------------ ------------
NET INCOME ....................................... $ 13,248 $ 827 $ 14,047 $ (14,075) $ 14,047
============ ============ ============ ============ ============
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
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 ......... -- -- 297,975 (297,975) --
------------ ------------ ------------ ------------ ------------
Total Other Income (Expense) ................. (75,813) (983) 299,786 (297,975) (74,985)
------------ ------------ ------------ ------------ ------------
INCOME BEFORE INCOME TAXES
AND EXTRAORDINARY ITEMS ........................ 368,023 1,758 297,594 (297,975) 369,400
INCOME TAX EXPENSE ............................... 148,067 704 84,984 (85,136) 148,619
------------ ------------ ------------ ------------ ------------
NET INCOME BEFORE EXTRAORDINARY ITEMS ............ 219,956 1,054 212,610 (212,839) 220,781
EXTRAORDINARY ITEMS:
Loss on early extinguishment of debt,
net of applicable income tax .......... (8,171) -- (37,829) -- (46,000)
------------ ------------ ------------ ------------ ------------
NET INCOME ....................................... $ 211,785 $ 1,054 $ 174,781 $ (212,839) $ 174,781
============ ============ ============ ============ ============
18
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- --------- ------------ ------------
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2002:
CASH FLOWS FROM OPERATING
ACTIVITIES ......................................... $ 311,819 $ (1,205) $ 57,119 $ (14,075) $ 353,658
------------ ------------- --------- ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties, net ........................ (297,199) -- (292,520) -- (589,719)
Proceeds from sale of assets ....................... 75 -- -- -- 75
Additions to other property, plant and
equipment and other .............................. (5,977) (5,266) (14,676) -- (25,919)
Other investments, net ............................. (3,411) (16) 1,807 -- (1,620)
------------ ------------- --------- ------------ ------------
Cash (used in) provided by investing activities .... (306,512) (5,282) (305,389) -- (617,183)
------------ ------------- --------- ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving bank credit facility ....... 95,818 -- -- -- 95,818
Cash paid for financing costs related to debt ...... (95,818) -- -- -- (95,818)
Cash paid for repurchase of senior notes ........... -- -- (63,541) -- (63,541)
Cash paid for repurchase premium on senior notes ... -- -- (1,869) -- (1,869)
Cash received on issuance of senior notes .......... -- -- 245,984 -- 245,984
Cash dividends paid on preferred stock ............. -- -- (7,649) -- (7,649)
Exercise of stock options .......................... -- -- 2,129 -- 2,129
Financing charges .................................. -- -- (3,671) -- (3,671)
Other .............................................. -- -- (74) -- (74)
Intercompany advances, net ......................... (25,605) 6,328 5,202 14,075 --
------------ ------------- --------- ------------ ------------
Cash provided by financing activities .............. (25,605) 6,328 176,511 14,075 171,309
------------ ------------- --------- ------------ ------------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS ........................................ (20,298) (159) (71,759) -- (92,216)
------------ ------------- --------- ------------ ------------
CASH, BEGINNING OF PERIOD ............................ (11,313) 19,714 109,193 -- 117,594
------------ ------------- --------- ------------ ------------
CASH, END OF PERIOD .................................. $ (31,611) $ 19,555 $ 37,434 $ -- $ 25,378
============ ============= ========= ============ ============
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- --------- ------------ ------------
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2001:
CASH FLOWS FROM OPERATING
ACTIVITIES ......................................... $ 409,779 $ 12,271 $ 231,745 $ (212,839) $ 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 .................................... (174) -- (37,206) -- (37,380)
------------ ------------- --------- ------------ ------------
Cash (used in) provided by investing activities .... (408,334) (250) (45,579) -- (454,163)
------------ ------------- --------- ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving bank credit facility ....... 372,000 -- -- -- 372,000
Payments on revolving bank credit facility ........ (208,000) -- -- -- (208,000)
Cash paid for financing costs related to debt ...... -- -- -- -- --
Cash dividends paid on preferred stock ............. -- -- (1,092) -- (1,092)
Cash paid for repurchase of senior notes ........... -- -- (830,382) -- (830,382)
Cash paid for repurchase premium on senior notes ... -- -- (75,639) -- (75,639)
Financing charges .................................. (5,672) -- (6,668) -- (12,340)
Cash received on issuance of senior notes .......... -- -- 786,664 -- 786,664
Exercise of stock options .......................... -- -- 2,929 -- 2,929
Cash paid in settlement of make-whole provision
related to common stock ......................... -- -- (3,336) -- (3,336)
Other .............................................. -- -- (10) -- (10)
Intercompany advances, net ......................... 8,686 (19,388) (202,137) 212,839 --
------------ ------------- --------- ------------ ------------
Cash (used in) provided by financing activities .... 167,014 (19,388) (329,671) 212,839 30,794
------------ ------------- --------- ------------ ------------
Effect of exchange rate changes on cash ............ (545) -- -- -- (545)
------------ ------------- --------- ------------ ------------
NET INCREASE (DECREASE) IN CASH ...................... 167,914 (7,367) (143,505) -- 17,042
CASH, BEGINNING OF PERIOD ............................ (19,868) 7,200 12,668 -- --
------------ ------------- --------- ------------ ------------
CASH, END OF PERIOD .................................. $ 148,046 $ (167) $(130,837) $ -- $ 17,042
============ ============= ========= ============ ============
19
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
($ IN THOUSANDS)
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- -------- ------------ ------------
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2002:
Net income ................................................ $ 18,282 $ 244 $ 16,600 $ (18,526) $ 16,600
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative instruments ........... (3,887) -- -- -- (3,887)
Reclassification of (gain) or loss on settled contracts .. (3,274) -- -- -- (3,274)
Ineffective portion of derivatives qualifying for
cash flow hedge accounting ............................ 32 -- -- -- 32
Other .................................................... -- -- (49) -- (49)
Equity in net other comprehensive income
(loss) of subsidiaries .................................. -- -- (7,129) 7,129 --
------------ ------------- -------- ------------ ------------
Comprehensive income ...................................... $ 11,153 $ 244 $ 9,422 $ (11,397) $ 9,422
============ ============= ======== ============ ============
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- ------- ------------ ------------
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)
Change in fair value of derivative instruments ........... 63,857 -- -- -- 63,857
Reclassification of (gain) or loss on settled contracts .. (34,786) -- -- -- (34,786)
Ineffective portion of derivatives qualifying for
cash flow hedge accounting ............................. (575) -- -- -- (575)
Equity in net other comprehensive income
(loss) of subsidiaries .................................. -- -- 25,670 (25,670) --
------------ ------------- ------- ------------ ------------
Comprehensive income (loss) ............................... $ 90,102 $ (205) $64,987 $ (64,206) $ 90,678
============ ============= ======= ============ ============
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- -------- ------------ ------------
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2002:
Net income ................................................ $ 13,248 $ 827 $ 14,047 $ (14,075) $ 14,047
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative instruments ........... (16,859) -- -- -- (16,859)
Reclassification of (gain) or loss on settled contracts .. (19,044) -- -- -- (19,044)
Ineffective portion of derivatives qualifying for
cash flow hedge accounting .............................. 1,342 -- -- -- 1,342
Other .................................................... -- -- (49) -- (49)
Equity in net other comprehensive income
(loss) of subsidiaries .................................. -- -- (34,561) 34,561 --
------------ ------------- -------- ------------ ------------
Comprehensive income (loss) ............................... $ (21,313) $ 827 $(20,563) $ 20,486 $ (20,563)
============ ============= -------- ============ ============
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- -------- ------------ ------------
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2001:
Net income ................................................ $ 211,785 $ 1,054 $ 89,645 $ (127,703) $ 174,781
Other comprehensive income (loss), 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 ........... 159,326 -- -- -- 159,326
Reclassification of (gain) or loss on settled contracts .. (18,774) -- -- -- (18,774)
Ineffective portion of derivatives qualifying for
cash flow hedge accounting ............................. (1,151) -- -- -- (1,151)
Equity in net other comprehensive income
(loss) of subsidiaries .................................. -- -- 82,270 (82,270) --
------------ ------------- -------- ------------ ------------
Comprehensive income ...................................... $ 294,055 $ 1,054 $171,915 $ (209,973) $ 257,051
============ ============= ======== ============ ============
20
6. SEGMENT INFORMATION
Chesapeake has two reportable segments under SFAS No. 131, Disclosures
about Segments of an Enterprise and Related Information. One segment is related
to our exploration and production activities, and the other segment is related
to oil and gas marketing activities. The reportable segment information can be
derived from the condensed consolidating financial statements included in Note
5. The separate results and financial condition of Chesapeake Energy Marketing,
Inc., our wholly owned subsidiary which conducts all our marketing activities,
are reflected in the column captioned "Non-Guarantor Subsidiary."
7. RECENT ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards 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 was effective in January
2002. We have adopted these new standards, which have not had a significant
effect on our results of operations or our financial position.
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations. SFAS No. 143 is effective for fiscal years beginning after June 15,
2002 and establishes an accounting standard requiring the recording of the fair
value of liabilities asso