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 March 31, 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 March 10, 2002, there were 165,935,028 shares of our $.01 par value
common stock outstanding.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
INDEX TO FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2002
PAGE
----
PART I.
FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements (Unaudited):
Consolidated Balance Sheets at December 31, 2001 and March 31, 2002 ........................... 3
Consolidated Statements of Operations for the Three Months Ended March 31, 2001
and 2002 ...................................................................................... 4
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2001
and 2002 ...................................................................................... 5
Consolidated Statements of Comprehensive Income for the Three Months Ended
March 31, 2001 and 2002 ....................................................................... 6
Notes to Consolidated Financial Statements .................................................... 7
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations............19
Item 3. Quantitative and Qualitative Disclosures About Market Risk.......................................25
PART II.
OTHER INFORMATION
Item 1. Legal Proceedings................................................................................29
Item 2. Changes in Securities and Use of Proceeds........................................................29
Item 3. Defaults Upon Senior Securities .................................................................29
Item 4. Submission of Matters to a Vote of Security Holders..............................................29
Item 5. Other Information................................................................................29
Item 6. Exhibits and Reports on Form 8-K.................................................................29
2
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
DECEMBER 31, MARCH 31,
2001 2002
----------- -----------
($ IN THOUSANDS)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents .............................................................. $ 117,594 $ 121,952
Restricted cash ........................................................................ 7,366 255
Accounts receivable:
Oil and gas sales .................................................................... 51,496 63,922
Joint interest, net of allowances of $947,000 and $1,093,000, respectively ........... 17,364 19,131
Short-term derivatives ............................................................... 34,543 32,900
Related parties ...................................................................... 9,896 6,419
Other ................................................................................ 14,951 17,143
Short-term derivative instruments ...................................................... 97,544 --
Inventory and other .................................................................... 10,629 10,461
----------- -----------
Total Current Assets ............................................................. 361,383 272,183
----------- -----------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at cost based on full-cost accounting:
Evaluated oil and gas properties ..................................................... 3,546,163 3,636,641
Unevaluated properties ............................................................... 66,205 60,007
Less: accumulated depreciation, depletion and amortization ........................... (1,902,587) (1,951,205)
----------- -----------
1,709,781 1,745,443
Other property and equipment ........................................................... 115,694 123,222
Less: accumulated depreciation and amortization ........................................ (39,894) (41,723)
----------- -----------
Total Property and Equipment ..................................................... 1,785,581 1,826,942
OTHER ASSETS:
Long-term derivatives receivable ....................................................... 18,852 12,220
Deferred income tax asset .............................................................. 67,781 103,875
Long-term derivative instruments ....................................................... 6,370 --
Long-term investments .................................................................. 29,849 28,546
Other assets ........................................................................... 16,952 15,624
----------- -----------
Total Other Assets ............................................................... 139,804 160,265
----------- -----------
TOTAL ASSETS ............................................................................. $ 2,286,768 $ 2,259,390
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Notes payable and current maturities of long-term debt ................................. $ 602 $ 380
Accounts payable ....................................................................... 79,945 57,120
Accrued interest ....................................................................... 26,316 41,514
Short-term derivative instruments ...................................................... -- 9,947
Other accrued liabilities .............................................................. 36,998 40,773
Revenues and royalties due others ...................................................... 29,520 29,579
----------- -----------
Total Current Liabilities ........................................................ 173,381 179,313
----------- -----------
LONG-TERM DEBT, NET ...................................................................... 1,329,453 1,308,424
----------- -----------
REVENUES AND ROYALTIES DUE OTHERS ........................................................ 12,696 12,643
----------- -----------
LONG-TERM DERIVATIVE INSTRUMENTS ......................................................... -- 39,091
----------- -----------
OTHER LIABILITIES ........................................................................ 3,831 3,831
----------- -----------
CONTINGENCIES AND COMMITMENTS (NOTE 3)
STOCKHOLDERS' EQUITY:
Preferred Stock, $.01 par value, 10,000,000 shares authorized; 3,000,000
shares of 6.75% cumulative convertible preferred stock, issued and outstanding
at December 31, 2001 and March 31, 2002, entitled in liquidation to $150
million .............................................................................. 150,000 150,000
Common Stock, $.01 par value, 350,000,000 shares authorized, 169,534,991 and
170,588,773 shares issued at December 31, 2001 and March 31, 2002, respectively ...... 1,696 1,706
Paid-in capital ........................................................................ 1,035,156 1,038,322
Accumulated deficit .................................................................... (442,974) (473,147)
Accumulated other comprehensive income, net of tax of $29,000,000 and $12,793,000,
respectively ......................................................................... 43,511 19,189
Less: treasury stock, at cost; 4,792,529 common shares at December 31, 2001
and March 31, 2002 ................................................................... (19,982) (19,982)
----------- -----------
Total Stockholders' Equity ....................................................... 767,407 716,088
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ............................................... $ 2,286,768 $ 2,259,390
=========== ===========
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 MARCH 31,
------------------------------
2001 2002
------------- -------------
($ IN THOUSANDS, EXCEPT
PER SHARE AMOUNTS)
REVENUES:
Oil and gas sales .......................................... $ 221,219 $ 141,971
Risk management loss ....................................... -- (79,468)
Oil and gas marketing sales ................................ 56,165 27,333
------------- -------------
Total Revenues ........................................... 277,384 89,836
------------- -------------
OPERATING COSTS:
Production expenses ........................................ 17,788 22,060
Production taxes ........................................... 14,295 5,216
General and administrative ................................. 4,001 4,294
Oil and gas marketing expenses ............................. 54,478 26,507
Oil and gas depreciation, depletion and amortization ....... 38,173 48,619
Depreciation and amortization of other assets .............. 1,953 3,110
------------- -------------
Total Operating Costs .................................... 130,688 109,806
------------- -------------
INCOME (LOSS) FROM OPERATIONS ................................ 146,696 (19,970)
------------- -------------
OTHER INCOME (EXPENSE):
Interest and other income .................................. 569 954
Interest expense ........................................... (25,889) (26,960)
Gothic standby credit facility costs ....................... (3,392) --
------------- -------------
Total Other Income (Expense) ............................. (28,712) (26,006)
------------- -------------
INCOME (LOSS) BEFORE INCOME TAXES ............................ 117,984 (45,976)
PROVISION (BENEFIT) FOR INCOME TAXES ......................... 47,696 (18,390)
------------- -------------
NET INCOME (LOSS) ............................................ 70,288 (27,586)
PREFERRED STOCK DIVIDENDS .................................... (546) (2,532)
------------- -------------
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS ........... $ 69,742 $ (30,118)
============= =============
EARNINGS (LOSS) PER COMMON SHARE:
Basic .................................................... $ 0.44 $ (0.18)
============= =============
Assuming dilution ........................................ $ 0.41 $ (0.18)
============= =============
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES
OUTSTANDING:
Basic .................................................... 157,707 165,372
============= =============
Assuming dilution ........................................ 170,326 165,372
============= =============
The accompanying notes are an integral part
of these consolidated financial statements.
4
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
THREE MONTHS ENDED MARCH 31,
------------------------------
2001 2002
------------- -------------
($ IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS) ............................................. $ 70,288 $ (27,586)
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO NET
CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization .................... 39,116 50,526
Risk management loss ........................................ -- 79,468
Deferred income taxes ....................................... 47,696 (18,390)
Write-off of credit facility cost ........................... 3,392 --
Amortization of loan costs .................................. 1,010 1,203
Amortization of bond discount ............................... 19 244
Accretion of Gothic note premium ............................ (704) --
Loss on sale/disposal of fixed assets and other ............. 25 48
Loss on repurchase of debt .................................. -- 591
Gain on sale of RAM Energy notes ............................ -- (461)
Bad debt expense ............................................ -- 140
Other ....................................................... 64 129
------------- -------------
Cash provided by operating activities before changes
in current assets and liabilities ........................ 160,906 85,912
Changes in assets and liabilities ........................... 45,443 31,385
------------- -------------
Cash provided by operating activities ..................... 206,349 117,297
------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of oil and gas properties ......... (109,859) (83,281)
Purchases of oil and gas properties ........................... (43,980) (894)
Sales of oil and gas properties ............................... 140 --
Sales of non-oil and gas assets ............................... 35 31
Additions to buildings and other fixed assets ................. (13,060) (7,413)
Additions to drilling rig equipment ........................... -- (216)
Additions to long-term investments ............................ -- (2,408)
Proceeds from sale of RAM Energy notes ........................ -- 4,215
Other ......................................................... 269 7
------------- -------------
Cash used in investing activities ......................... (166,455) (89,959)
------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings ............................ 93,000 --
Payments on long-term borrowings .............................. (103,500) --
Cash paid to repurchase senior notes .......................... (8,255) (21,000)
Cash paid for premium on repurchase of senior notes ........... -- (440)
Cash paid for financing costs related to debt ................. (712) (84)
Cash received from exercise of stock options .................. 2,191 1,181
Cash paid for preferred stock dividend ........................ (546) (2,587)
Other ......................................................... -- (50)
------------- -------------
Cash used in financing activities ......................... (17,822) (22,980)
------------- -------------
Effect of changes in exchange rate on cash ...................... (869) --
------------- -------------
NET INCREASE IN CASH AND CASH EQUIVALENTS ....................... 21,203 4,358
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD .................. -- 117,594
------------- -------------
CASH AND CASH EQUIVALENTS, END OF PERIOD ........................ $ 21,203 $ 121,952
============= =============
The accompanying notes are an integral part
of these consolidated financial statements.
5
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
THREE MONTHS ENDED MARCH 31,
------------------------------
2001 2002
------------- -------------
($ IN THOUSANDS)
Net income (loss) ......................................................... $ 70,288 $ (27,586)
Other comprehensive income (loss), net of income tax:
Foreign currency translation adjustments ................................ (3,219) --
Cumulative effect of accounting change for financial derivatives ........ (53,580) --
Change in fair value of derivative instruments .......................... 42,138 (10,730)
Reclassification of settled contracts ................................... 18,326 (14,086)
Ineffective portion of derivatives qualifying for hedge accounting ...... -- 494
------------- -------------
Comprehensive income (loss) .............................................. $ 73,953 $ (51,908)
============= =============
The accompanying notes are an integral part
of these consolidated financial statements.
6
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2002
(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 months ended March 31, 2002 are not necessarily indicative
of the results to be expected for the full year. This Form 10-Q relates to the
three months ended March 31, 2001 (the "Prior Quarter") and the three months
ended March 31, 2002 (the "Current Quarter").
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 this exposure to
adverse market changes, we have entered into derivative instruments. As of March
31, 2002, our 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.
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 which establish a
fixed price. To the extent that the 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 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.
7
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 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
March 31, 2002 are provided below. The associated carrying values of these
instruments are equal to the estimated fair values.
MARCH 31,
2002
----------------
($ IN THOUSANDS)
Derivative assets (liabilities):
Fixed-price gas swaps.................... $ (18,504)
Fixed-price gas collars.................. 7,046
Fixed-price gas cap-swaps................ 25,949
Gas basis protection swaps............... (6,222)
Gas straddles............................ (25,825)
Gas strangles............................ (31,004)
Fixed-price gas counter-swaps............ 2,239
Fixed-price gas locked swaps............. 43,716
Fixed-price crude oil cap-swaps.......... (2,286)
Fixed-price crude oil locked swaps....... 1,404
---------
Total................................... $ (3,487)(a)
=========
(a) After adjusting for the $40.9 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 March 31, 2002 was $37.4 million.
We expect to transfer approximately $12.9 million of the balance in
accumulated other comprehensive income, based upon the market prices at March
31, 2002, to earnings during the next 12 months when the forecasted transactions
actually occur. All forecasted transactions hedged as of March 31, 2002 are
expected to mature by December 2005.
Additional information concerning the fair value of our oil and gas
derivative instruments is as follows ($ in thousands):
Fair value of contracts outstanding at January 1, 2002 ............ ...... $ 157,309
Change in fair value of contracts during period .......................... (69,712)
Contracts realized or otherwise settled during the period ................ (48,554)
Fair value of new contracts when entered into during the period .......... (42,530)
Changes in fair values attributable to changes in valuation
techniques and assumptions ............................................. --
------------
Fair value of contracts outstanding at March 31, 2002 ............. ...... $ (3,487)
============
Risk management loss related to our oil and gas derivatives for the three
months ended March 31, 2002 is comprised of the following ($ in thousands):
Risk Management Loss:
Change in fair value of derivatives not qualifying for hedge
accounting ......................................................... $(53,414)
Reclassification of settled contracts ................................ (25,077)
Ineffective portion of derivatives qualifying for hedge accounting ... (824)
--------
Total ............................................................... $(79,315)
========
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.
8
Interest Rate Risk
We also utilize hedging strategies to manage interest rate exposure. 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 the swap agreement are as
follows:
MONTHS 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
If the floating rate is less than the fixed rate, the counterparty will pay
us accordingly. If the floating rate exceeds the fixed rate, we will pay the
counterparty. Payments under the interest rate swap coincide with the
semi-annual interest payments on our 7.875% senior notes which are due September
15 and March 15 of each year beginning September 15, 2002.
A portion of the interest rate swap was entered into to convert $129 million
of the 7.875% senior notes from fixed rate debt to variable rate debt. Under
SFAS 133, a hedge of the interest rate risk in a recognized fixed rate liability
can be designated as a fair value hedge. Accordingly, 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 to the debt's carrying
value.
The remaining $71 million of the interest rate swap has not been designated
as a fair value hedge. The mark-to-market value of this portion of the
instrument is recorded as a derivative asset or liability on the consolidated
balance sheets with the offsetting amount reflected in risk management income
(loss) on the consolidated statements of operations. The amount recorded in risk
management income (loss) will be reversed and reflected in interest expense when
the swap is settled.
The estimated fair value of the interest rate swap at March 31, 2002 was a
liability of approximately $0.4 million comprised of $0.2 million reflected as
risk management loss and $0.2 million reflected as a reduction to long-term
debt. Results from interest rate hedging transactions are reflected as
adjustments to interest expense in the corresponding months covered by the swap
agreement.
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. Our carrying
amount for such debt at March 31, 2002 and December 31, 2001 was $1,308.8
million and $1,330.1 million, respectively, compared to approximate fair values
of $1,322.2 million and $1,343.0 million, respectively. The carrying value of
other long-term debt approximates its fair value as interest rates are primarily
variable, based on prevailing market rates. The carrying amount for our 6.75%
convertible preferred stock at March 31, 2002 was $150.0 million, which
approximated its fair value as of that date.
Concentration of Credit Risk
A significant portion of our liquidity is concentrated in cash and cash
equivalents, including restricted cash, 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 industry
concentration has the potential to impact our overall exposure to credit risk,
either positively or negatively,
9
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 plaintiffs in two of
these cases who were not covered by the settlement. The Court heard oral
arguments in March 2002.
There are eight other related West Panhandle cessation cases which continue
to be 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 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. 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.
10
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 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 quarter ended March 31, 2002, 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 during the
Current Quarter.
o For the quarter ended March 31, 2002 and 2001, outstanding options to
purchase 0.8 million and 0.1 million shares of common stock at a
weighted average exercise price of $10.05 and $25.00, respectively,
were antidilutive because the exercise prices of the options were
greater than the average market price of the common stock.
o As a result of the Current Quarter's net loss to common shareholders,
the diluted shares do not include the effect of outstanding stock
options to purchase 5.2 million shares of common stock at a weighted
average exercise price of $3.81, the assumed conversion of the
outstanding 6.75% preferred stock (convertible into 19.5 million common
shares) or warrants to purchase 6,567 shares of common stock at a
weighted average exercise price of $0.05 as the effects were
antidilutive.
A reconciliation for the quarter ended March 31, 2001 is as follows:
INCOME SHARES PER SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
------------ ------------ ------------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
FOR THE QUARTER ENDED MARCH 31, 2001:
BASIC EPS
Income available to common shareholders ..................... $ 69,742 157,707 $ 0.44
============
EFFECT OF DILUTIVE SECURITIES
Assumed conversion at the beginning of the period
of preferred shares exchanged during the period:
Preferred stock dividends ................................. 546 --
Assumed conversion of 624,037 shares of 7% preferred
stock at beginning of period .............................. -- 4,489
Employee stock options ...................................... -- 8,130
------------ ------------
DILUTED EPS
Income available to common shareholders and assumed
conversions ............................................... $ 70,288 170,326 $ 0.41
============ ============ ============
On November 13, 2001, we issued 3.0 million shares of 6.75% cumulative
convertible preferred stock, par value $0.01 per share and liquidation
preference $50 per share, in a private offering. We subsequently registered
under the Securities Act of 1933 shares of the preferred stock and underlying
common stock for resale by the holders.
5. SENIOR NOTES AND REVOLVING CREDIT FACILITY
On November 5, 2001, Chesapeake closed a private offering of $250.0 million
of 8.375% senior notes due 2008, all of which were exchanged on January 23, 2002
for substantially identical notes registered under the Securities Act of 1933.
The 8.375% senior notes will be redeemable by us prior to November 1, 2005 at
the make-whole prices determined in accordance with the indenture, and on and
after November 1, 2005 at annually declining redemption prices.
On April 6, 2001, we issued $800.0 million principal amount of 8.125% senior
notes due 2011, all of which were subsequently exchanged for substantially
identical notes registered under the Securities Act of 1933. The 8.125% senior
notes will be redeemable by us prior to April 1, 2006 at the make-whole prices
determined in accordance with the indenture, and on and after April 1, 2006 at
annually declining redemption prices.
11
On March 17, 1997, we issued $150.0 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. During the Current Quarter, we purchased and
subsequently retired $21.0 million of these notes for total consideration of
$21.9 million, including $0.5 million of accrued interest and $0.4 million of
redemption premium.
Also on March 17, 1997, we issued $150.0 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 annually declining
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.
The senior note indentures contain covenants limiting us and the guarantor
subsidiaries with respect to asset sales; restricted payments; the incurrence of
additional indebtedness and the issuance of preferred stock; liens; sale and
leaseback transactions; lines of business; dividend and other payment
restrictions affecting guarantor subsidiaries; mergers or consolidations; and
transactions with affiliates. The 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
the 8.375% senior notes, 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.
We have a $225 million revolving bank credit facility (with a committed
borrowing base of $225 million) which matures in September 2003. As of March 31,
2002, we had no outstanding borrowings under this facility and were using $21.3
million of the facility to secure various letters of credit. 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 maturity
of the bank credit facility can be extended to June 2005 provided certain
conditions are met.
The credit facility agreement contains various covenants and restrictive
provisions including incurring additional indebtedness, selling properties,
paying dividends, purchasing or redeeming our capital stock, making investments
or loans, purchasing certain of our senior notes, creating liens, and making
acquisitions. The credit facility agreement requires us to maintain a current
ratio of at least 1 to 1 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.
Such acceleration, if involving a principal amount of $10 million or more, 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 agreement also has cross default provisions that apply to other
indebtedness we may have with an outstanding principal amount in excess of $5.0
million.
Set forth below are condensed consolidating financial statements of the
guarantor subsidiaries and our subsidiaries which are not guarantors of the
senior notes. Chesapeake Energy Marketing, Inc. was a non-guarantor subsidiary
for all periods presented. All of our other wholly-owned subsidiaries were
guarantor subsidiaries during all periods presented.
12
CONDENSED CONSOLIDATED BALANCE SHEET
AS OF DECEMBER 31, 2001
($ 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 .......................... 113,493 30,380 2,715 (18,338) 128,250
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 (DEFICIT)
CURRENT LIABILITIES:
Notes payable and current maturities of
long-term debt ............................ $ 602 $ -- $ -- $ -- $ 602
Accounts payable and other current
liabilities ............................... 127,967 36,755 26,338 (18,281) 172,779
------------- ------------- ----------- ------------- -------------
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 (DEFICIT):
Common Stock ................................. 66 1 1,686 (57) 1,696
Other ........................................ (38,688) 17,567 765,721 21,111 765,711
------------- ------------- ----------- ------------- -------------
Total Stockholders' Equity (Deficit) . (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
============= ============= =========== ============= =============
13
CONDENSED CONSOLIDATED BALANCE SHEET
AS OF MARCH 31, 2002
($ IN THOUSANDS)
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- ----------- ------------ ------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ........................ $ (28,789) $ 10,136 $ 140,860 $ -- $ 122,207
Accounts receivable .............................. 118,455 40,917 4,384 (24,241) 139,515
Inventory and other .............................. 10,080 366 15 -- 10,461
----------- ----------- ----------- ----------- -----------
Total Current Assets ...................... 99,746 51,419 145,259 (24,241) 272,183
----------- ----------- ----------- ----------- -----------
PROPERTY AND EQUIPMENT:
Oil and gas properties ........................... 3,636,641 -- -- -- 3,636,641
Unevaluated leasehold ............................ 60,007 -- -- -- 60,007
Other property and equipment ..................... 55,633 23,810 43,779 -- 123,222
Less: accumulated depreciation,
depletion and amortization ..................... (1,970,575) (18,897) (3,456) -- (1,992,928)
----------- ----------- ----------- ----------- -----------
Net Property and Equipment ................ 1,781,706 4,913 40,323 -- 1,826,942
----------- ----------- ----------- ----------- -----------
OTHER ASSETS:
Investments in subsidiaries and
intercompany advances .......................... -- -- 85,892 (85,892) --
Long-term derivative receivable .................. 12,220 -- -- -- 12,220
Deferred income tax asset ........................ (26,226) (1,455) 131,556 -- 103,875
Long-term investments ............................ -- -- 28,546 -- 28,546
Other assets ..................................... 4,790 251 10,583 -- 15,624
----------- ----------- ----------- ----------- -----------
Total Other Assets ........................ (9,216) (1,204) 256,577 (85,892) 160,265
----------- ----------- ----------- ----------- -----------
TOTAL ASSETS ....................................... $ 1,872,236 $ 55,128 $ 442,159 $ (110,133) $ 2,259,390
=========== =========== =========== =========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES:
Notes payable and current maturities
of long-term debt .............................. $ 380 $ -- $ -- $ -- $ 380
Accounts payable and other current liabilities ... 122,717 38,916 41,547 (24,247) 178,933
----------- ----------- ----------- ----------- -----------
Total Current Liabilities ................. 123,097 38,916 41,547 (24,247) 179,313
----------- ----------- ----------- ----------- -----------
LONG-TERM DEBT ..................................... -- -- 1,308,424 -- 1,308,424
----------- ----------- ----------- ----------- -----------
REVENUES AND ROYALTIES DUE OTHERS .................. 12,643 -- -- -- 12,643
----------- ----------- ----------- ----------- -----------
LONG-TERM DERIVATIVE INSTRUMENTS ................... 38,660 -- 431 -- 39,091
----------- ----------- ----------- ----------- -----------
OTHER LIABILITIES .................................. 3,831 -- -- -- 3,831
----------- ----------- ----------- ----------- -----------
INTERCOMPANY PAYABLES .............................. 1,627,707 (3,382) (1,624,331) 6 --
----------- ----------- ----------- ----------- -----------
STOCKHOLDERS' EQUITY (DEFICIT):
Common Stock ..................................... 66 1 1,696 (57) 1,706
Other ............................................ 66,232 19,593 714,392 (85,835) 714,382
----------- ----------- ----------- ----------- -----------
Total Stockholders' Equity (Deficit) .... 66,298 19,594 716,088 (85,892) 716,088
----------- ----------- ----------- ----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY (DEFICIT) ................................. $ 1,872,236 $ 55,128 $ 442,159 $ (110,133) $ 2,259,390
=========== =========== =========== =========== ===========
14
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ---------- -------- ------------ ------------
FOR THE THREE MONTHS ENDED MARCH 31, 2001:
REVENUES:
Oil and gas sales ...................................... $ 221,219 $ -- $ -- $ -- $ 221,219
Oil and gas marketing sales ............................ -- 133,913 -- (77,748) 56,165
----------- ---------- -------- ----------- -----------
Total Revenues ....................................... 221,219 133,913 -- (77,748) 277,384
----------- ---------- -------- ----------- -----------
OPERATING COSTS:
Production expenses and taxes .......................... 32,083 -- -- -- 32,083
General and administrative ............................. 3,543 350 108 -- 4,001
Oil and gas marketing expenses ......................... -- 132,226 -- (77,748) 54,478
Oil and gas depreciation, depletion and amortization ... 38,173 -- -- -- 38,173
Other depreciation and amortization .................... 1,062 20 871 -- 1,953
----------- ---------- -------- ----------- -----------
Total Operating Costs ................................ 74,861 132,596 979 (77,748) 130,688
----------- ---------- -------- ----------- -----------
INCOME (LOSS) FROM OPERATIONS ............................ 146,358 1,317 (979) -- 146,696
----------- ---------- -------- ----------- -----------
OTHER INCOME (EXPENSE):
Interest and other income .............................. 442 75 22,734 (22,682) 569
Interest expense ....................................... (27,814) (1) (20,756) 22,682 (25,889)
Gothic standby credit facility costs ................... -- -- (3,392) -- (3,392)
Equity in net earnings of subsidiaries ................. -- -- 71,724 (71,724) --
----------- ---------- -------- ----------- -----------
Total Other Income (Expense) ......................... (27,372) 74 70,310 (71,724) (28,712)
----------- ---------- -------- ----------- -----------
INCOME (LOSS) BEFORE INCOME TAXES ........................ 118,986 1,391 69,331 (71,724) 117,984
INCOME TAX EXPENSE (BENEFIT) ............................. 48,097 556 (957) -- 47,696
----------- ---------- -------- ----------- -----------
NET INCOME (LOSS) ........................................ $ 70,889 $ 835 $ 70,288 $ (71,724) $ 70,288
=========== ========== ======== =========== ===========
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ---------- -------- ------------ ------------
FOR THE THREE MONTHS ENDED MARCH 31, 2002:
REVENUES:
Oil and gas sales ...................................... $ 141,971 $ -- $ -- $ -- $ 141,971
Risk management loss ................................... (79,315) -- (153) -- (79,468)
Oil and gas marketing sales ............................ -- 89,465 -- (62,132) 27,333
----------- ---------- -------- ----------- -----------
Total Revenues ....................................... 62,656 89,465 (153) (62,132) 89,836
----------- ---------- -------- ----------- -----------
OPERATING COSTS:
Production expenses and taxes .......................... 27,276 -- -- -- 27,276
General and administrative ............................. 3,630 451 213 -- 4,294
Oil and gas marketing expenses ......................... -- 88,639 -- (62,132) 26,507
Oil and gas depreciation, depletion and amortization ... 48,619 -- -- -- 48,619
Other depreciation and amortization .................... 2,171 277 662 -- 3,110
----------- ---------- -------- ----------- -----------
Total Operating Costs ................................ 81,696 89,367 875 (62,132) 109,806
----------- ---------- -------- ----------- -----------
INCOME (LOSS) FROM OPERATIONS ............................ (19,040) 98 (1,028) -- (19,970)
----------- ---------- -------- ----------- -----------
OTHER INCOME (EXPENSE):
Interest and other income .............................. 209 99 28,115 (27,469) 954
Interest expense ....................................... (26,569) -- (27,860) 27,469 (26,960)
Equity in net earnings of subsidiaries ................. -- -- (27,122) 27,122 --
----------- ---------- -------- ----------- -----------
Total Other Income (Expense). ........................ (26,360) 99 (26,867) 27,122 (26,006)
----------- ---------- -------- ----------- -----------
INCOME (LOSS) BEFORE INCOME TAXES ........................ (45,400) 197 (27,895) 27,122 (45,976)
INCOME TAX EXPENSE (BENEFIT) ............................. (18,160) 79 (309) -- (18,390)
----------- ---------- -------- ----------- -----------
NET INCOME (LOSS) ........................................ $ (27,240) $ 118 $(27,586) $ 27,122 $ (27,586)
=========== ========== ======== =========== ===========
15
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- -------- ------------ ------------
FOR THE THREE MONTHS ENDED MARCH 31, 2001:
CASH FLOWS FROM OPERATING
ACTIVITIES .......................................... $ 200,370 $ (1,721) $ 79,424 $ (71,724) $ 206,349
----------- ----------- -------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties, net ......................... (153,699) -- -- -- (153,699)
Proceeds from sale of assets ........................ 35 -- -- -- 35
Additions to other property and equipment ........... (8,745) (890) (3,425) -- (13,060)
Other ............................................... 269 -- -- -- 269
----------- ----------- -------- ----------- -----------
Cash (used in) provided by investing activities ..... (162,140) (890) (3,425) -- (166,455)
----------- ----------- -------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings .................. -- -- 93,000 -- 93,000
Payments on long-term borrowings .................... -- -- (103,500) -- (103,500)
Cash paid for financing cost related to debt ........ (99) -- (613) -- (712)
Cash dividends paid on preferred stock .............. -- -- (546) -- (546)
Cash paid for repurchase on senior notes ............ (1,020) -- (7,235) -- (8,255)
Exercise of stock options ........................... -- -- 2,191 -- 2,191
Intercompany advances, net .......................... (46,514) (4,066) (21,144) 71,724 --
----------- ----------- -------- ----------- -----------
Cash (used in) provided by financing activities ..... (47,633) (4,066) (37,847) 71,724 (17,822)
Effect of exchange rate changes on cash ............... (869) -- -- -- (869)
----------- ----------- -------- ----------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS ......................................... (10,272) (6,677) 38,152 -- 21,203
CASH, BEGINNING OF PERIOD ............................. (19,868) 7,200 12,668 -- --
----------- ----------- -------- ----------- -----------
CASH, END OF PERIOD ................................... $ (30,140) $ 523 $ 50,820 $ -- $ 21,203
=========== =========== ======== =========== ===========
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- -------- ------------ ------------
FOR THE THREE MONTHS ENDED MARCH 31, 2002:
CASH FLOWS FROM OPERATING
ACTIVITIES .......................................... $ 107,118 $ (7,847) $ (9,096) $ 27,122 $ 117,297
----------- ----------- -------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties, net ......................... (84,175) -- -- -- (84,175)
Proceeds from sale of assets ........................ 31 -- -- -- 31
Additions to other property, plant and equipment
and other ......................................... (2,051) (268) (5,303) -- (7,622)
Other investments, net .............................. -- -- 1,807 -- 1,807
----------- ----------- -------- ----------- -----------
Cash (used in) provided by investing activities ..... (86,195) (268) (3,496) -- (89,959)
----------- ----------- -------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash paid for financing costs related to debt ....... -- -- (84) -- (84)
Cash paid for repurchase of senior notes ............ -- -- (21,000) -- (21,000)
Cash paid for repurchase premium on senior notes .... -- -- (440) -- (440)
Cash dividends paid on preferred stock .............. -- -- (2,587) -- (2,587)
Exercise of stock options ........................... -- -- 1,181 -- 1,181
Other ............................................... -- -- (50) -- (50)
Intercompany advances, net .......................... (38,654) (1,463) 67,239 (27,122) --
----------- ----------- -------- ----------- -----------
Cash (used in) provided by financing activities ..... (38,654) (1,463) 44,259 (27,122) (22,980)
----------- ----------- -------- ----------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS ......................................... (17,731) (9,578) 31,667 -- 4,358
CASH, BEGINNING OF PERIOD ............................. (11,313) 19,714 109,193 -- 117,594
----------- ----------- -------- ----------- -----------
CASH, END OF PERIOD ................................... $ (29,044) $ 10,136 $140,860 $ -- $ 121,952
=========== =========== ======== =========== ===========
16
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
($ IN THOUSANDS)
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- -------- ------------ ------------
FOR THE THREE MONTHS ENDED MARCH 31, 2001:
Net income (loss) .................................... $ 70,889 $ 835 $ 70,288 $ (71,724) $ 70,288
Other comprehensive income (loss) net of
income tax -
Foreign currency translation adjustments ............ (3,219) -- -- -- (3,219)
Cumulative effect of accounting change for
financial derivatives, net of income tax ......... (53,580) -- -- -- (53,580)
Change in fair value of derivative instruments ...... 42,138 -- -- -- 42,138
Reclassification of settled contracts ............... 18,326 -- -- -- 18,326
Equity in net other comprehensive income
(loss) of subsidiaries ........................... -- -- 3,665 (3,665) --
------------ ------------ -------- ------------ ------------
Comprehensive income (loss) .......................... $ 74,554 $ 835 $ 73,953 $ (75,389) $ 73,953
============ ============ ======== ============ ============
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- -------- ------------ ------------
FOR THE THREE MONTHS ENDED MARCH 31, 2002:
Net income (loss) .................................... $ (27,240) $ 118 $(27,586) $ 27,122 $ (27,586)
Other comprehensive income (loss) net of
income tax -
Change in fair value of derivative instruments ...... (10,730) -- -- -- (10,730)
Reclassification of settled contracts ............... (14,086) -- -- -- (14,086)
Ineffectiveness portion of derivatives
qualifying for hedge accounting .................. 494 -- -- -- 494
Equity in net other comprehensive income
(loss) of subsidiaries ............................. -- -- (24,322) 24,322 --
------------ ------------ -------- ------------ ------------
Comprehensive income (loss) .......................... $ (51,562) $ 118 $(51,908) $ 51,444 $ (51,908)
============ ============ ======== ============ ============
17
6. 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 5 as Chesapeake Energy Marketing, Inc., which is our marketing
segment, is the only non-guarantor subsidiary for all income statement periods
presented.
7. SUBSEQUENT EVENT
On April 19, 2002, we entered into an agreement and plan of merger pursuant
to which we will acquire Canaan Energy Corporation in a cash merger through a
Chesapeake subsidiary. Under the agreement, all outstanding common shares of
Canaan, other than the Canaan shares owned by Chesapeake and those that dissent,
will be converted into the right to receive $18.00 per share in cash, and
outstanding options to acquire Canaan common stock will be converted into the
right to receive, for each share of Canaan common stock to be received upon
exercise, the merger consideration less the per share exercise price and
withholding taxes. We expect the aggregate net cash consideration for the merger
will be $118 million, including the retirement of Canaan's outstanding
indebtedness of approximately $33 million (net of stock option proceeds and
working capital). The acquisition is subject to approval by Canaan's
shareholders. Canaan's management and directors have agreed to vote their 1.2
million common shares in favor of the agreement. These shares, together with the
Canaan shares we own, represent 37% of Canaan's outstanding common shares. The
merger is expected to close in the third quarter of 2002. Under certain
circumstances, Canaan has agreed to provide Chesapeake with a $5.0 million
break-up fee in the event the transaction is not completed. We intend to pay for
the transaction with cash on hand.
8. 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 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. We have not yet determined the effect of the adoption of SFAS No. 143 on
our financial position or results of operations.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets. SFAS 144 was effective January 1, 2002. This
statement supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of, and amends Accounting
Principles Board Opinion No. 30 for the accounting and reporting of discontinued
operations, as it relates to long-lived assets. Adoption of SFAS 144 did not
affect our financial position or results of operations.
18
PART I. FINANCIAL INFORMATION
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
OVERVIEW
The following table sets forth certain information regarding the production
volumes, oil and gas sales, average sales prices received and expenses for the
periods indicated:
QUARTER ENDED MARCH 31,
---------------------------
2001 2002
------------ ------------
NET PRODUCTION:
Oil (mbbl) ...................................... 686 830
Gas (mmcf) ...................................... 36,040 36,933
Gas equivalent (mmcfe) .......................... 40,156 41,913
OIL AND GAS SALES ($ IN THOUSANDS):
Oil ............................................. $ 19,904 $ 19,958
Gas ............................................. 201,315 122,013
------------ ------------
Total oil and gas sales ................... $ 221,219 $ 141,971
============ ============
AVERAGE SALES PRICE:
Oil ($ per bbl) ................................. $ 29.01 $ 24.05
Gas ($ per mcf) ................................. $ 5.59 $ 3.30
Gas equivalent ($ per mcfe) ..................... $ 5.51 $ 3.39
EXPENSES ($ PER MCFE):
Production expenses and taxes ................... $ 0.80 $ 0.65
General and administrative ...................... $ 0.10 $ 0.10
Depreciation, depletion and amortization ........ $ 0.95 $ 1.16
NET WELLS DRILLED ................................. 81 57
NET WELLS AT END OF PERIOD ........................ 3,338 3,620
RESULTS OF OPERATIONS -- THREE MONTHS ENDED MARCH 31, 2002 ("CURRENT QUARTER")
VS. MARCH 31, 2001 ("PRIOR QUARTER")
General. For the Current Quarter, Chesapeake had a net loss available to
common shareholders of $30.1 million, or a loss of $0.18 per diluted common
share, on total revenues of $89.8 million. This compares to net income available
to common shareholders of $69.7 million, or $0.41 per diluted common share, on
total revenues of $277.4 million during the Prior Quarter. The Current Quarter's
net loss included, on a pre-tax basis, a non-cash $79.5 million risk management
loss.
Oil and Gas Sales. During the Current Quarter, oil and gas sales decreased
36% to $142.0 million from $221.2 million in the Prior Quarter. For the Current
Quarter, we produced 41.9 billion cubic feet equivalent, consisting of 0.8
million barrels of oil and 36.9 billion cubic feet of gas, compared to 0.7 mmbbl
and 36.0 bcf, or 40.2 bcfe, in the Prior Quarter. The production increase is
primarily the result of various acquisitions which occurred in late 2001 and
successful drilling results, partially offset by the sale of our Canadian
reserves effective October 1, 2001. Average oil prices realized were $24.05 per
bbl in the Current Quarter compared to $29.01 per bbl in the Prior Quarter, a
decrease of 17%. Average gas prices realized were $3.30 per thousand cubic feet
in the Current Quarter compared to $5.59 per mcf in the Prior Quarter, a
decrease of 41%.
The following table shows our production by region for the Prior Quarter and
the Current Quarter:
FOR THE THREE MONTHS ENDED MARCH 31,
--------------------------------------
2001 2002
----------------- -----------------
OPERATING AREAS (MMCFE) PERCENT (MMCFE) PERCENT
------- ------- ------- -------
Mid-Continent ............ 26,888 67% 31,793 76%
Gulf Coast ............... 8,268 21 7,261 17
Canada ................... 2,688 7 -- --
Permian Basin ............ 1,559 4 2,064 5
Other areas .............. 753 1 795 2
------- ------- ------- -------
Total .......... 40,156 100% 41,913 100%
======= ======= ======= =======
Gas production represented approximately 88% of our total production volume
on an equivalent basis in the Current Quarter, compared to 90% in the Prior
Quarter.
19
For the Current Quarter, we realized an average price of $3.39 per mcfe,
compared to $5.51 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 $48.6 million, or $1.16 per mcfe, in the Current Quarter, compared
to decreases in oil and gas revenues of $30.5 million, or $0.76 per mcfe, in the
Prior Quarter.
Risk Management Loss. Chesapeake recognized a $79.5 million risk management
loss in the Current Quarter, compared to no such income (loss) in the Prior
Quarter. Risk management loss for the Current Quarter consisted of a $53.4
million loss related to changes in fair value of derivatives not designated as
cash flow hedges, $25.1 million of reclassifications related to the settlement
of such contracts, a $0.8 million loss associated with the ineffective portion
of derivatives qualifying for hedge accounting and a $0.2 million loss
associated with the portion of our interest rate swap that does not qualify for
fair value hedge accounting.
Pursuant to SFAS 133, our cap-swaps, straddles, strangles, counter-swaps and
basis protection swaps do not qualify for designation as cash flow hedges. There
is also a portion of our interest rate swap that does not qualify as a fair
value hedge. Therefore, changes in fair value of these instruments that occur
prior to their maturity, together with any change in fair value of hedges
resulting from ineffectiveness, 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 and are included in oil
and gas sales and interest expense, as applicable, over the respective contract
terms. Detailed information about our oil and gas hedging positions appears in
Item 3 - Quantitative and Qualitative Disclosures About Market Risk.
Oil and Gas Marketing Sales. We generated $27.3 million in oil and gas
marketing sales for third parties in the Current Quarter, with corresponding oil
and gas marketing expenses of $26.5 million, for a net margin of $0.8 million.
This compares to sales of $56.2 million, expenses of $54.5 million, and a net
margin of $1.7 million in the Prior Quarter. The decrease in marketing sales and
cost of sales was due primarily to a decrease in oil and gas prices in the
Current Quarter compared to the Prior Quarter, partially offset by a 25%
increase in volumes marketed by Chesapeake Energy Marketing, Inc. in the Current
Quarter.
Production Expenses. Production expenses, which include lifting costs and ad
valorem taxes, increased to $22.1 million in the Current Quarter, a $4.3 million
increase from the $17.8 million of production expenses incurred in the Prior
Quarter. On a unit of production basis, production expenses were $0.53 and $0.44
per mcfe in the Current and Prior Quarters, respectively. The increase in costs
on a per unit basis in the Current Quarter is due primarily to increased field
service costs, higher production costs associated with properties acquired in
2001 and an increase in ad valorem taxes. We expect that lease operating
expenses per mcfe for the remainder of 2002 will range from $0.50 to $0.55.
Production Taxes. Production taxes were $5.2 million and $14.3 million in
the Current and Prior Quarters, respectively. On a per unit basis, production
taxes were $0.12 per mcfe in the Current Quarter compared to $0.36 per mcfe in
the Prior Quarter. The decrease in the Current Quarter was the result of
decreased prices and new statutory exemptions on certain wells in Oklahoma and
Texas. In general, production taxes are calculated using value-based formulas
that produce higher per unit costs when oil and gas prices are higher. We expect
production taxes for the remainder of 2002 to be approximately 7% of oil and gas
sales revenues after excluding any impact from hedging.
General and Administrative. General and administrative expenses, which are
net of capitalized internal costs, were $4.3 million in the Current Quarter
compared to $4.0 million in the Prior Quarter.
Chesapeake follows the full-cost method of accounting under which all costs
associated with property acquisition, exploration and development activities are
capitalized. We capitalize internal costs that can be directly identified with
our acquisition, exploration and development activities and do not include any
costs related to production, general corporate overhead or similar activities.
We capitalized $2.5 million and $1.8 million of internal costs in the Current
Quarter and Prior Quarter, respectively, directly related to our oil and gas
exploration and development efforts. We anticipate that general and
administrative expenses for the remainder of 2002 will be between $0.10 and
$0.11 per mcfe, which is approximately the same level as 2001 and the Current
Quarter.
Oil and Gas Depreciation, Depletion and Amortization. Depreciation,
depletion and amortization of oil and gas properties for the Current Quarter was
$48.6 million, compared to $38.2 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
20
in the periods presented, increased from $0.95 in the Prior Quarter to $1.16 per
mcfe in the Current Quarter. We expect the DD&A rate for the remainder of 2002
to be between $1.15 and $1.25 per mcfe.
Depreciation and Amortization of Other Assets. Depreciation and amortization
of other assets was $3.1 million in the Current Quarter, compared to $2.0
million in the Prior Quarter. The increase in the Current Quarter was primarily
the result of higher depreciation recorded on recently acquired fixed assets.
Other property and equipment costs are depreciated on both straight-line and
accelerated methods. Buildings are depreciated on a straight-line basis over
31.5 years. Drilling rigs are depreciated on a straight-line basis over 12
years. All other property and equipment are depreciated over the estimated
useful lives of the assets, which range from five to seven years. We expect
depreciation and amortization of other assets to average between $0.06 and $0.08
per mcfe for the remainder of 2002.
Interest and Other Income. Interest and other income for the Current Quarter
was $1.0 million compared to $0.6 million in the Prior Quarter. The increase was
primarily the result of additional interest income from significant cash
balances held during the Current Quarter. Also, the recognition of a $0.5
million gain on the sale of RAM Energy, Inc. notes was offset by a $0.6 million
loss on the repurchase of our 7.875% senior notes.
Interest Expense. Interest expense increased to $27.0 million in the Current
Quarter from $25.9 million in the Prior Quarter. The increase in the Current
Quarter is due to a $166.6 million increase in average long-term borrowings in
the Current Quarter compared to the Prior Quarter, partially offset by a
decrease in the overall average interest rate. In addition to the interest
expense reported, we capitalized $1.1 million of interest during the Current
Quarter, compared to $0.9 million capitalized in the Prior Quarter, on
significant investments in unproved properties that were not being currently
depreciated, depleted or amortized and on which exploration activities were in
progress. Interest is capitalized using the weighted average interest rate of
our outstanding borrowings. We anticipate that capitalized interest for the
remainder of 2002 will be between $3.0 million and $4.0 million.
Gothic Standby Credit Facility Costs. During the Prior Quarter, we obtained
a standby commitment for a $275 million credit facility, consisting of a $175
million term loan and a $100 million revolving credit facility which, if needed,
would have replaced our then existing revolving credit facility. The term loan
was available to provide funds to repurchase any of Gothic Production
Corporation's 11.125% senior secured notes tendered following the closing of the
Gothic acquisition in January 2001 pursuant to a change-of-control offer to
purchase. In February 2001, we purchased $1.0 million of notes tendered for 101%
of such amount. We did not use the standby credit facility and the commitment
terminated in February 2001. Chesapeake incurred $3.4 million of costs for the
standby facility, which were recognized in the Prior Quarter.
Provision (Benefit) for Income Taxes. Chesapeake recorded an income tax
benefit of $18.4 million in the Current Quarter, compared to income tax expense
of $47.7 million in the Prior Quarter. Income tax expense for the Prior Quarter
was comprised of $43.2 million related to our domestic operations and $4.5
million related to our Canadian operations which were sold on October 1, 2001.
We anticipate that all 2002 income tax expense will be deferred.
CASH FLOWS FROM OPERATING, INVESTING, AND FINANCING ACTIVITIES
Cash Flows from Operating Activities. Cash provided by operating activities
decreased 43% to $117.3 million during the Current Quarter compared to $206.3
million during the Prior Quarter. The decrease was due primarily to lower oil
and gas prices realized during the Current Quarter.
Cash Flows from Investing Activities. Cash used in investing activities
decreased to $90.0 million during the Current Quarter from $166.5 million in the
Prior Quarter. During the Current Quarter we expended approximately $75.9
million to initiate drilling on 119 (57.4 net) wells and invested approximately
$7.4 million in leasehold acquisitions. This compares to $95.5 million to
initiate drilling on 163 (80.8 net) wells and $14.4 million to purchase
leasehold in the Prior Quarter. During the Current Quarter, we had acquisitions
of oil and gas properties of $0.9 million and no divestitures of oil and gas
properties. This compares to cash used in acquisitions of oil and gas companies
and properties of $44.0 million and divestitures of $0.1 million in the Prior
Quarter. During the Current Quarter, we had additional investments in other
assets of $7.4 million compared to $13.1 million in the Prior Quarter. The
Current Quarter included additional investments in the common stock of two oil
and gas companies totaling $2.4 million and $4.2 million in proceeds related to
the sale of RAM Energy, Inc. notes.
Cash Flows from Financing Activities. There was $23.0 million of cash used
in financing activities in the Current Quarter, compared to $17.8 million in the
Prior Quarter. The activity in the Current Quarter reflects the repurchase of
$21.0 million of our 7.875% senior notes, $1.2 million in cash received from the
exercise of stock
21
options, and $2.6 million used to pay dividends on the 6.75% preferred stock.
The activity in the Prior Quarter includes $10.5 million in net reductions in
long-term borrowings, $8.3 million used to repurchase long-term debt, and $2.2
million in cash received from the exercise of stock options.
LIQUIDITY AND CAPITAL RESOURCES
Sources of Liquidity
Chesapeake had working capital of $92.9 million at March 31, 2002, including
$122.0 million in cash. Additionally, we have a $225 million revolving bank
credit facility (with a committed borrowing base of $225 million) which matures
in September 2003. As of March 31, 2002 we had no outstanding borrowings under
the facility and were using $21.3 million of the facility to secure various
letters of credit. We believe we will have adequate resources, including
operating cash flows, working capital and proceeds from our revolving bank
credit facility, to fund our capital expenditure budget for exploration and
development activities during the remainder of 2002, which is currently
estimated to be approximately $330 million before the pending Canaan
acquisition, and $450 million pro forma for the Canaan acquisition. Further, our
drilling program is largely discretionary and can be adjusted to match changing
circumstances. Based on our current cash flow assumptions and giving effect to
the Canaan acquisition, we expect operating cash flow to reach $400 million
during 2002. Any operating cash flow not needed to fund our drilling program
will be available for acquisitions, debt repayments or other general corporate
purposes in 2002.
A significant portion of our liquidity is concentrated in cash and cash
equivalents, including restricted cash, and derivative instruments that enable
us to hedge a portion of our exposure to price volatility from producing oil and
natural gas. 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 industry
concentration 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.
Our liquidity is not dependent on the use of off-balance sheet financing
arrangements, such as the securitization of receivables or obtaining access to
assets through special purpose entities. We have not relied on off-balance sheet
financing arrangements in the past and we do not intend to rely on such
arrangements in the future as a source of liquidity. We are not a commercial
paper issuer.
Contractual Obligations and Commercial Commitments
We have a $225 million revolving bank credit facility (with a committed
borrowing base of $225 million) which matures in September 2003. As of March 31,
2002, we had no outstanding borrowings under this facility and were using $21.3
million of the facility to secure various letters of credit. 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 collateral value and borrowing base are
redetermined periodically. The unused portion of the facility is subject to an
annual commitment fee of 0.50%. Interest is payable quarterly.
The credit facility agreement contains various covenants and restrictive
provisions including incurring additional indebtedness, selling properties,
paying dividends, purchasing or redeeming our capital stock, making investments
or loans or purchasing certain of our senior notes, creating liens, and making
acquisitions. The credit facility agreement requires us to maintain a current
ratio of at least 1 to 1 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.
Such acceleration, if involving a principal amount of $10 million or more, 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 agreement also has cross default provisions that apply to other
indebtedness we may have with an outstanding principal amount in excess of $5.0
million.
As of March 31, 2002, senior notes represented $1.3 billion of our long-term
debt and consisted of the following: $800.0 million principal amount of 8.125%
senior notes due 2011, $250.0 million principal amount of 8.375% senior notes
due 2008, $129.0 million principal amount of 7.875% senior notes due 2004 and
$142.7 million
22
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 $128.0
million is due, giving effect to the repurchase and retirement of $21.0 million
of our 7.875% senior notes in the Current Quarter and an additional $1.0 million
in April 2002. Debt ratings for the senior notes are B1 by Moody's Investor
Service, B+ by Standard & Poor's Ratings Services and BB- by Fitch Ratings as of
March 31, 2002. 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 Ratings.
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. guarantee the notes. The
7.875% 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 indenture. On or
after March 15, 2004, we may redeem the 8.5% senior notes at the redemption
prices set forth in the indenture and prior to such date pursuant to make-whole
provisions in the indenture. We may redeem the 8.125% senior notes at any time
on or after April 1, 2006 at the redemption prices set forth in the indenture
and prior to such date pursuant to make-whole provisions in the indenture. We
may redeem the 8.375% senior notes at any time on or after November 1, 2005 at
the redemption prices set forth in the indenture and prior to such date pursuant
to make-whole provisions in the indenture. If we repurchase at least an
additional $53 million of the 7.875% senior notes by August 31, 2003, we may
extend the bank credit facility until June 2005 for an amount equal to the total
revolving credit facility commitment less the outstanding amount of the 7.875%
senior notes plus $50 million.
The indentures for the 8.125% and 8.375% senior notes contain 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 covenants do not affect our
ability to borrow under or expand our secured credit facility. As of March 31,
2002, we estimate that secured commercial bank indebtedness of approximately
$397 million could have been incurred under the most restrictive indenture
covenant. The indenture covenants do not apply to Chesapeake Energy Marketing,
Inc., an unrestricted subsidiary.
Some of our commodity price and interest rate risk management arrangements
require us to deliver cash collateral or other assurances of performance to the
counterparties in the event that our payment obligations with respect to our
commodity price and interest rate risk management transactions exceed certain
levels. At March 31, 2002, we had posted $20.0 million of collateral with one of
our counterparties. Future collateral requirements are uncertain and will depend
on arrangements with our counterparties and the level of volatility in natural
gas and oil prices and interest rates.
Investing and Financing Transactions
In private transactions completed in the fourth quarter of 2001 and the
Current Quarter, we acquired 7.65% of the outstanding common stock of Canaan
Energy Corporation, an oil and gas exploration and production company, for cash
consideration totaling $4.0 million, or $12.00 per share. On April 19, 2002, we
entered into an agreement and plan of merger pursuant to which we will acquire
Canaan Energy Corporation in a cash merger through a Chesapeake subsidiary.
Under the agreement, all outstanding common shares of Canaan, other than the
Canaan shares owned by Chesapeake and those that dissent, will be converted into
the right to receive $18.00 per share in cash, and outstanding options to
acquire Canaan common stock will be converted into the right to receive, for
each share of Canaan common stock to be received upon exercise, the merger
consideration less the per share exercise price and withholding taxes. We expect
the aggregate net cash consideration for the merger will be $118 million,
including the retirement of Canaan's outstanding indebtedness of approximately
$33 million (net of stock option proceeds and working capital). The acquisition
is subject to approval by Canaan's shareholders. Canaan's management and
directors have agreed to vote their 1.2 million common shares in favor of the
agreement. These shares, together with the Canaan shares we own, represent 37%
of Canaan's outstanding common shares. The merger is expected to close in the
third quarter of 2002. Under certain circumstances, Canaan has agreed to provide
Chesapeake with a $5.0 million break-up fee in the event the transaction is not
completed. We intend to pay for the transaction with cash on hand.
We value Canaan's estimated 100 bcfe of proved reserves at $1.14 per mcfe
after allocation of $4 million of the purchase price to Canaan's undeveloped
leasehold inventory and other assets. Canaan's proved reserves are 91% natural
gas, 74% proved developed and are located almost exclusively in Chesapeake's
core Mid-Continent
23
operating area. Based on current production rates of 21,000 mcfe per day
(approximately 8 bcfe per year), Canaan's reserves-to-production ratio is 12.5.
In the Current Quarter, we purchased and subsequently retired $21.0 million
of our 7.875% senior notes due 2004 for total consideration of $21.9 million,
including accrued interest of $0.5 million and $0.4 million of redemption
premium. In April 2002, we purchased and retired an additional $1.0 million of
these notes for $1.0 million including accrued interest.
See Note 2 of the notes to consolidated financial statements included in
this report for a discussion of our hedging activities and financial
instruments.
RECENTLY ISSUED ACCOUNTING STANDARDS
See Note 8 of the notes to the consolidated financial statements included in
this report for a summary of recently issued accounting standards.
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. 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 are described under "Risk
Factors" in Item 1 of our Form 10-K for the year ended December 31, 2001. These
factors include:
o the volatility of oil and gas prices,
o our substantial indebtedness,
o the cost and availability of drilling and production services,
o our commodity price risk management activities, including counterparty
contract performance risk,
o uncertainties inherent in estimating quantities of oil and gas
reserves, projecting future rates of production and the timing of
development expenditures,
o our ability to replace reserves,
o the availability of capital,
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.
24
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 this exposure to
adverse market changes, we have entered into derivative instruments. As of March
31, 2002, our 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.
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 which establish a
fixed price. To the extent that the 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 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 ineffectivness, 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 are ultimately reversed within this same
caption and included in oil and gas sales over the respective contract terms.
25
As of March 31, 2002, we had the following open oil and gas derivative
instruments designed to hedge a portion of our gas production for periods after
March 2002:
FAIR
WEIGHTED- WEIGHTED- VALUE AT
AVERAGE AVERAGE MARCH 31,
AVERAGE PUT CALL WEIGHTED- SFAS 2002
STRIKE STRIKE STRIKE AVERAGE 133 PREMIUMS ($ IN
VOLUME PRICE PRICE PRICE DIFFERENTIAL HEDGE RECEIVED THOUSANDS)
------ ----- ----- ----- ------------ ----- -------- ----------
NATURAL GAS (mmbtu):
Swaps:
2002................ 29,560,000 $ 2.85 $ -- $ -- $ -- Yes $ -- $(16,240)
2003................ 2,700,000 3.03 -- -- -- Yes -- (2,264)
Cap-Swaps:
2002................ 63,870,000 4.54 3.54 -- -- No -- 37,753
2003................ 51,100,000 3.60 2.60 -- -- No -- (11,804)
Collars:
2002................ 9,780,000 -- 4.00 5.42 -- Yes -- 7,046
Straddles:
2002................ 24,420,000 -- 2.37 2.37 -- No 12,430 (25,825)
Strangles:
2003................ 14,600,000 -- 3.20 3.70 -- No 12,629 (14,414)
2004................ 14,640,000 -- 3.40 3.90 -- No 15,884 (16,590)
Basis Protection Swaps:
2003................ 91,250,000 -- -- -- (0.15) No -- (1,704)
2004................ 91,500,000 -- -- -- (0.15) No -- (2,154)
2005................ 91,250,000 -- -- -- (0.16) No -- (2,364)
Counter-Swaps:
2003................ 16,500,000 3.68 -- -- -- No -- 2,239
Locked Swaps:
2002................ -- -- -- -- -- No -- 25,214
2003................ -- -- -- -- -- No -- 18,502
------- -------
TOTAL GAS 40,943 (2,605)
------- -------
OIL (bbls):
Cap-Swaps:
2002................ 1,650,000 24.97 20.19 -- -- No -- (2,286)
Locked-Swaps:
2002................ -- -- -- -- -- No -- 1,404
------- -------
TOTAL OIL -- -- -- -- -- -- -- (882)
------- -------
TOTAL GAS AND OIL $40,943(a) $(3,487)(a)
======= =======
----------
(a) After adjusting for the $40.9 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), the net value of the
combined hedging portfolio at March 31, 2002 was $37.5 million.
We have established the fair value of all derivative instruments using
estimates of fair value reported by our counterparties. The actual contribution
to our future results of operations will be based on the market prices at the
time of settlement and may be more or less than the fair value estimates used at
March 31, 2002.
26
Additional information concerning the fair value of our oil and gas
derivative instruments is as follows ($ in thousands):
Fair value of contracts outstanding at January 1, 2002 .................. $ 157,309
Change in fair value of contracts during period ......................... (69,712)
Contracts realized or otherwise settled during the period ............... (48,554)
Fair value of new contracts when entered into during the period ......... (42,530)
Changes in fair values attributable to changes in valuation
techniques and assumptions ............................................ --
---------
Fair value of contracts outstanding at March 31, 2002 ................... $ (3,487)
=========
Risk management loss related to our oil and gas derivatives for the three
months ended March 31, 2002 is comprised of the following ($ in thousands):
Risk Management Loss:
Change in fair value of derivatives not qualifying for hedge
accounting ............................................................ $ (53,414)
Reclassification of settled contracts ................................... (25,077)
Ineffective portion of derivatives qualifying for hedge accounting ...... (824)
---------
Total ................................................................. $ (79,315)
=========
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 the fair value of our derivative instruments since January 1,
2002 resulted from an increase in market prices for natural gas and crude oil.
Derivative instruments reflected as current in the 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 consolidated balance sheet dates. 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 $12.9 million of the balance in
accumulated other comprehensive income, based upon the market prices at March
31, 2002, to earnings during the next 12 months when the forecasted transactions
actually occur. All forecasted transactions hedged as of March 31, 2002 are
expected to mature by December 2005.
INTEREST RATE
We also utilize hedging strategies to manage interest rate exposure. 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 the swap agreement are as
follows:
MONTHS 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
If the floating rate is less than the fixed rate, the counterparty will pay
us accordingly. If the floating rate exceeds the fixed rate, we will pay the
counterparty. Payments under the interest rate swap coincide with the
semi-annual interest payments on our 7.875% senior notes which are due on
September 15 and March 15 of each year beginning September 15, 2002.
A portion of the interest rate swap was entered into to convert $129 million
of the 7.875% senior notes from fixed rate debt to variable rate debt. Under
SFAS 133, a hedge of the interest rate risk in a recognized fixed rate liability
can be designated as a fair value hedge. Accordingly, 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 to the debt's carrying
value.
The remaining $71 million of the interest rate swap has not been designated
as a fair value hedge. The mark-to-market value of this portion of the
instrument is recorded as a derivative asset or liability on the consolidated
balance sheets with the offsetting amount reflected in risk management income
(loss) on the consolidated statements
27
of operations. The amount recorded in risk management income (loss) will be
reversed and reflected in interest expense when the swap is settled.
The estimated fair value of the interest rate swap at March 31, 2002 was a
liability of approximately $0.4 million comprised of $0.2 million reflected as
risk management loss and $0.2 million reflected as a reduction to long-term
debt. Results from interest rate hedging transactions are reflected as
adjustments to interest expense in the corresponding months covered by the swap
agreement.
The table below presents principal cash flows and related weighted average
interest rates by expected maturity dates. The fair value of the fixed-rate
long-term debt has been estimated based on quoted market prices.
MARCH 31, 2002
--------------------------------------------------------------------------------------------
YEARS OF MATURITY
--------------------------------------------------------------------------------------------
2002 2003 2004 2005 2006 THEREAFTER TOTAL FAIR VALUE
-------- ------ -------- ------ ------ ---------- ---------- ----------
($ IN MILLIONS)
LIABILITIES:
Long-term debt, including
current portion--fixed
rate ......................... $ 0.4 $ -- $ 129.0 $ -- $ -- $ 1,192.6 $1,322.0(1) $1,322.2
Average interest rate ........ 9.1% -- 7.9% -- -- 8.2% 8.2% 8.2%
Long-term debt--variable ....... $ -- $ -- $ -- $ -- $ -- $ -- $ -- $ --
rate
Average interest rate ........ -- -- -- -- -- -- -- --
----------
(1) This amount does not include the discount of ($13.0) million included in
long-term debt and the value of the interest rate swap of ($0.2) million
which qualifies for SFAS 133 fair value hedge accounting.
28
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
We are subject to ordinary routine litigation incidental to our business,
none of which is expected to have a material adverse effect on Chesapeake. In
addition, Chesapeake is a defendant in other pending actions which are described
in Note 3 of the notes to the consolidated financial statements included in this
report and Item 3 of our Annual Report on Form 10-K for the year ended December
31, 2001.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
Not applicable
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
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
NUMBER DESCRIPTION
4.6.1 Consent and waiver letter dated April 15, 2002 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.
10.1.11 Registrant's 2002 Nonqualified Stock Option Plan
(b) Reports on Form 8-K
During the quarter ended March 31, 2002, we filed the following current
reports on Form 8-K:
On January 22, 2002, we filed a current report on Form 8-K reporting
under Item 5 that we had issued a press release declaring a quarterly cash
dividend on our preferred stock.
On February 5, 2002 we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release announcing fourth quarter and 2001
full-year earnings release and conference call dates.
On February 21, 2002, we filed a current report on Form 8-K reporting
under Item 5 that we had issued a press release announcing strong 2001 results
with cash flow, EBITDA and production setting records. The press release also
contained information on 2001 finding costs, proved reserves, our hedging
program, exploration activities and an overview of results for the past three
years. We furnished under Item 9 updates to our full year 2002 forecasts, cap-ex
budget and balance sheet goals.
On March 12, 2002, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release announcing a proposal to acquire
Canaan Energy Corporation for $12.00 per share in cash.
29
On March 18, 2002, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release announcing that we were deferring our
tender offer for the outstanding shares of Canaan Energy Corporation pending
discussions with Canaan management.
30
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
By: /s/ MARCUS C. ROWLAND
-------------------------------------
Marcus C. Rowland
Executive Vice President and
Chief Financial Officer
Date: May 15, 2002
31
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- -----------
4.6.1 Consent and waiver letter dated April 15, 2002 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.
10.1.11 Registrant's 2002 Nonqualified Stock Option Plan