1
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1999
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES ACT
OF 1934
FOR THE TRANSITION PERIOD FROM TO
---------- -----------
COMMISSION FILE NO. 1-13726
CHESAPEAKE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
OKLAHOMA 73-1395733
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
6100 NORTH WESTERN AVENUE
OKLAHOMA CITY, OKLAHOMA 73118
(Address of principal executive offices) (Zip Code)
(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 August 12, 1999, there were 97,117,473 shares of the registrant's $.01
par value Common Stock outstanding.
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2
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
INDEX TO FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 1999
PART I. FINANCIAL INFORMATION
PAGE
----
Item 1. Consolidated Financial Statements:
Consolidated Balance Sheets at June 30, 1999 (Unaudited) and
December 31, 1998 3
Consolidated Statements of Operations for the Three and Six Months
Ended June 30, 1999 and 1998 (Unaudited) 4
Consolidated Statements of Cash Flows for the Six Months Ended June
30, 1999 and 1998 (Unaudited) 5
Consolidated Statements of Comprehensive Income (Loss) for the Three
and Six Months Ended June 30, 1999 and 1998 (Unaudited) 6
Notes to Consolidated Financial Statements (Unaudited) 7
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations 16
Item 3. Quantitative and Qualitative Disclosures About Market Risks 24
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 26
Item 2. Changes in Securities and Use of Proceeds 27
Item 3. Defaults Upon Senior Securities 27
Item 4. Submission of Matters to a Vote of Security Holders 27
Item 5. Other Information 27
Item 6. Exhibits and Reports on Form 8-K 27
2
3
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
JUNE 30, DECEMBER 31,
1999 1998
----------- ------------
(UNAUDITED)
($ IN THOUSANDS)
CURRENT ASSETS:
Cash and cash equivalents ........................................... $ 27,553 $ 29,520
Restricted cash ..................................................... 1,442 5,754
Accounts receivable:
Oil and gas sales .................................................. 14,379 13,835
Oil and gas marketing sales ........................................ 17,474 19,636
Joint interest and other, net of allowance for doubtful accounts
of $3,244,000 and $3,209,000 ..................................... 9,288 27,373
Related parties .................................................... 13,501 15,455
Inventory ........................................................... 4,877 5,325
Other ............................................................... 2,446 1,101
----------- ------------
Total current assets ............................................. 90,960 117,999
----------- ------------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at cost based on full-cost accounting:
Evaluated oil and gas properties ................................... 2,218,839 2,142,943
Unevaluated properties ............................................. 45,190 52,687
Less: accumulated depreciation, depletion and amortization ......... (1,622,378) (1,574,282)
----------- ------------
641,651 621,348
Other property and equipment ........................................ 78,477 79,718
Less: accumulated depreciation and amortization ..................... (39,399) (37,075)
----------- ------------
Total property and equipment ..................................... 680,729 663,991
----------- ------------
OTHER ASSETS .......................................................... 29,221 30,625
----------- ------------
TOTAL ASSETS ..................................................... $ 800,910 $ 812,615
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES:
Notes payable ....................................................... $ -- $ 25,000
Accounts payable .................................................... 18,649 36,854
Accrued liabilities and other ....................................... 34,189 46,572
Revenues and royalties due others ................................... 22,490 22,858
----------- ------------
Total current liabilities ........................................ 75,328 131,284
----------- ------------
LONG-TERM DEBT, NET ................................................... 958,118 919,076
----------- ------------
REVENUES AND ROYALTIES DUE OTHERS ..................................... 11,137 10,823
----------- ------------
DEFERRED INCOME TAXES ................................................. 4,880 --
----------- ------------
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred stock, $.01 par value, 10,000,000 shares authorized;
4,600,000 shares of 7% cumulative convertible stock issued
and outstanding at June 30, 1999 and December 31, 1998,
entitled in liquidation to $230 million plus earned but unpaid
dividends of $11.2 million and $3.2 million at June 30, 1999
and December 31, 1998, respectively ................................ 230,000 230,000
Common stock, 250,000,000 shares authorized; $.01 par value;
105,552,613 and 105,213,750 shares issued and outstanding at
June 30, 1999 and December 31, 1998, respectively .................. 1,055 1,052
Paid-in capital ..................................................... 682,506 682,263
Accumulated deficit ................................................. (1,130,998) (1,127,195)
Accumulated other comprehensive income (loss) ....................... (1,101) (4,726)
Less: treasury stock, at cost; 8,503,300 common shares
at June 30, 1999 and December 31, 1998, respectively ............... (29,962) (29,962)
Less: treasury stock, at cost; 3,600 and 0 preferred shares
at June 30, 1999 and December 31, 1998, respectively ............... (53) --
----------- ------------
Total stockholders' equity (deficit) ............................. (248,553) (248,568)
----------- ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) .................. $ 800,910 $ 812,615
=========== ===========
The accompanying notes are an integral part of these consolidated
financial statements.
3
4
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
--------------------- ---------------------
1999 1998 1999 1998
--------- --------- --------- ---------
REVENUES:
Oil and gas sales................................................... $ 68,272 $ 75,639 $ 120,078 $ 125,880
Oil and gas marketing sales......................................... 12,620 33,671 26,491 60,195
--------- --------- --------- ---------
Total revenues.................................................. 80,892 109,310 146,569 186,075
--------- --------- --------- ---------
OPERATING COSTS:
Production expenses................................................. 11,183 14,673 25,175 22,567
Production taxes.................................................... 2,798 2,621 4,788 4,165
Oil and gas marketing expenses...................................... 11,673 33,705 24,958 59,966
Impairment of oil and gas properties................................ -- 216,000 -- 466,000
Impairment of other assets.......................................... -- 10,000 -- 10,000
Oil and gas depreciation, depletion and amortization................ 24,233 43,900 47,386 75,242
Depreciation and amortization of other assets....................... 1,972 1,922 4,138 3,302
General and administrative.......................................... 3,268 5,134 7,292 9,514
--------- --------- --------- ---------
Total operating costs........................................... 55,127 327,955 113,737 650,756
--------- --------- --------- ---------
INCOME (LOSS) FROM OPERATIONS........................................ 25,765 (218,645) 32,832 (464,681)
OTHER INCOME (EXPENSE):
Interest and other income........................................... 2,967 2,571 3,840 2,795
Interest expense.................................................... (20,259) (18,665) (40,149) (29,353)
--------- --------- --------- ---------
(17,292) (16,094) (36,309) (26,558)
--------- --------- --------- ---------
INCOME (LOSS) BEFORE INCOME TAX AND EXTRAORDINARY ITEM............... 8,473 (234,739) (3,477) (491,239)
INCOME TAX EXPENSE................................................... 326 -- 326 --
--------- --------- --------- ---------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM.............................. 8,147 (234,739) (3,803) (491,239)
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt................................ -- (13,334) -- (13,334)
--------- --------- --------- ---------
NET INCOME (LOSS).................................................... 8,147 (248,073) (3,803) (504,573)
PREFERRED STOCK DIVIDENDS............................................ (4,026) (4,025) (8,052) (4,025)
--------- --------- --------- ---------
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS................... $ 4,121 $(252,098) $ (11,855) $(508,598)
========= ========= ========= =========
EARNINGS PER COMMON SHARE (BASIC AND ASSUMING DILUTION)
Income (loss) before extraordinary item............................. $ 0.04 $ (2.29) $ (0.12) $ (5.35)
Extraordinary item.................................................. -- (0.12) -- (0.15)
--------- --------- --------- ---------
Net income (loss)................................................... $ 0.04 $ (2.41) $ (0.12) $ (5.50)
========= ========= ========= =========
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING
Basic .............................................................. 97,049 104,462 97,049 92,504
========= ========= ========= =========
Assuming dilution................................................... 101,450 104,462 97,049 92,504
========= ========= ========= =========
The accompanying notes are an integral part of these consolidated
financial statements.
4
5
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
SIX MONTHS ENDED
JUNE 30,
1999 1998
---------- ----------
($ IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss ........................................................................... $ (3,803) $ (504,573)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization .......................................... 49,923 77,542
Impairment of oil and gas assets .................................................. -- 466,000
Impairment of other assets ........................................................ -- 10,000
Deferred taxes .................................................................... 326 --
Amortization of loan costs ........................................................ 1,601 1,002
Amortization of bond discount ..................................................... 35 56
Gain on sale of fixed assets and other ............................................ 98 (368)
Extraordinary loss................................................................. -- 13,334
Equity in (earnings) losses of equity investees ................................... (35) 285
Bad debt expense .................................................................. -- 516
---------- ----------
Cash provided by operating activities before changes
in current assets and liabilities ............................................. 48,145 63,794
Changes in current assets and liabilities ......................................... (579) (44,074)
---------- ----------
Cash provided by operating activities ........................................... 47,566 19,720
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration, development and acquisition of oil and gas properties ................. (85,787) (433,379)
Proceeds from sales of oil and gas properties ...................................... 17,387 --
Investment in preferred stock of Gothic ............................................ -- (39,500)
Proceeds from sales of other assets ................................................ 1,306 4,404
Long-term loans made to third parties .............................................. (511) --
Other investments .................................................................. 325 --
Repayment of long-term loan ........................................................ -- 2,000
Additions to other property and equipment .......................................... (65) (5,183)
---------- ----------
Cash used in investing activities ............................................... (67,345) (471,658)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings ................................................. 14,000 658,750
Payments on long-term borrowings ................................................... -- (474,166)
Proceeds from issuance of preferred stock .......................................... -- 222,781
Purchase of treasury stock ......................................................... (53) (17,831)
Cash received from exercise of stock options ....................................... 240 101
---------- ----------
Cash provided by financing activities ........................................... 14,187 389,635
---------- ----------
EFFECTS OF CHANGES IN EXCHANGE RATE ON CASH .......................................... 3,625 (1,867)
---------- ----------
NET DECREASE IN CASH AND CASH EQUIVALENTS ............................................ (1,967) (64,170)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD ....................................... 29,520 123,860
---------- ----------
CASH AND CASH EQUIVALENTS, END OF PERIOD ............................................. $ 27,553 $ 59,690
========== ==========
The accompanying notes are an integral part of these consolidated
financial statements.
5
6
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- ----------------------
1999 1998 1999 1998
---------- --------- --------- ---------
($ in thousands)
Net income (loss).............................................................. $ 8,147 $(248,073) $ (3,803) $(504,573)
Other comprehensive income (loss) - foreign currency translation adjustments... 2,809 (2,172) 3,625 (1,867)
---------- --------- --------- ---------
Comprehensive income (loss).................................................... $ 10,956 $(250,245) $ (178) $(506,440)
========== ========= ========= =========
The accompanying notes are an integral part of these consolidated
financial statements.
6
7
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. ACCOUNTING PRINCIPLES
The accompanying unaudited consolidated financial statements of Chesapeake
Energy Corporation and subsidiaries (the "Company") have been prepared in
accordance with the instructions to Form 10-Q as prescribed by the Securities
and Exchange Commission. All material adjustments (consisting solely of normal
recurring adjustments) which, in the opinion of management, are necessary for a
fair presentation of the results for the interim periods have been reflected.
The results for the three and six months ended June 30, 1999 are not necessarily
indicative of the results to be expected for the full fiscal year.
This Form 10-Q relates to the three and six months ended June 30, 1999 (the
"Current Quarter" and "Current Period", respectively) and June 30, 1998 (the
"Prior Quarter" and "Prior Period", respectively).
2. LEGAL PROCEEDINGS
Chesapeake Securities Litigation
The Company and certain of its officers and directors are defendants in a
consolidated class action suit alleging violations of the Securities Exchange
Act of 1934. The plaintiffs, in suits first filed in August 1997, assert that
the defendants made material misrepresentations and failed to disclose material
facts about the success of the Company's exploration efforts in the Louisiana
Trend. As a result, the complaint alleges the price of the Company's common
stock was artificially inflated from January 25, 1996 until June 27, 1997, when
the Company issued a press release announcing disappointing drilling results in
the Louisiana Trend and a full-cost ceiling writedown to be reflected in its
June 30, 1997 financial statements. The plaintiffs further allege that certain
of the named individual defendants sold common stock during the class period
when they knew or should have known adverse nonpublic information. The
plaintiffs seek a determination that the suit is a proper class action and
damages in an unspecified amount, together with interest and costs of
litigation, including attorneys' fees. The Company and the individual defendants
believe that these claims are without merit, and intend to defend against them
vigorously. No estimate of loss or range of estimate of loss, if any, can be
made at this time.
Bayard Securities Litigation
A purported class action alleging violations of the Securities Act of 1933 and
the Oklahoma Securities Act was filed in February 1998 against the Company and
others on behalf of investors who purchased common stock of Bayard Drilling
Technologies, Inc. ("Bayard") in, or traceable to, its initial public offering
in November 1997. Total proceeds of the offering were $254 million, of which the
Company received net proceeds of $90 million as a selling shareholder.
Plaintiffs allege that the Company, a major customer of Bayard's drilling
services and the owner of 30.1% of Bayard's common stock outstanding prior to
the offering, was a controlling person of Bayard. Plaintiffs assert that the
Bayard prospectus contained material omissions and misstatements relating to (i)
the Company's financial "problems" and their impact on Bayard's operating
results, (ii) increased costs associated with Bayard's growth strategy, (iii)
undisclosed pending related-party transactions between Bayard and third parties
other than the Company, (iv) Bayard's planned use of offering proceeds and (v)
Bayard's capital expenditures and liquidity. The alleged defective disclosures
are claimed to have resulted in a decline in Bayard's share price following the
public offering. Plaintiffs seek a determination that the suit is a proper class
action and damages in an unspecified amount or rescission, together with
interest and costs of litigation, including attorneys' fees. The Company
believes that the claims are without merit and intends to defend against them
vigorously. No estimate of loss or range of estimate of loss, if any, can be
made at this time.
Patent Litigation
In October 1996, Union Pacific Resources Company ("UPRC") sued the Company
alleging infringement of a patent for a drillbit steering method. Other claims
asserted by UPRC have been dismissed. UPRC's infringement claims against the
Company are based on services provided to the Company by a third party vendor
controlled by former UPRC employees. UPRC is seeking damages of an unspecified
amount, including actual and enhanced damages, interest, costs and attorneys'
fees. In June 1999, the issues of the validity of the patent and the Company's
alleged
7
8
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
infringement were tried to the Court. No ruling has been issued yet. If
necessary, a trial on damages will be scheduled after the ruling. No estimate of
loss or range of estimate of loss, if any, can be made at this time; however, in
reports filed in the proceeding, experts for UPRC claim that damages could be as
much as $18 million while Company experts state that the amount should not
exceed $25,000, in each case based on a reasonable royalty.
West Panhandle Litigation
The Company, Natural Gas Pipeline Company of America and MidCon Gas Services,
Inc. are defendants in 13 lawsuits filed in 1997 and 1998 by royalty owners
seeking the cancellation of oil and gas leases in the West Panhandle Field in
Texas. In April 1998, the Company acquired MC Panhandle, Inc., the owner of the
leases since January 1, 1997. Plaintiffs claim the leases terminated upon the
cessation of production for various periods between 1926 and 1997 and/or for
failure to produce in paying quantities. Plaintiffs also seek to recover
conversion damages in an amount equal to 7/8 of gross production for the period
beginning two years prior to the filing of each suit through the time of trial,
plus attorneys' fees and interest, as well as exemplary damages. Plaintiffs
assert that defendants knew the leases had terminated and therefore are bad
faith trespassers and not entitled (in the event of an adverse judgment) to
recover the value of improvements or operating costs. In the alternative,
plaintiffs seek damages for the breach of implied covenants of the leases,
i.e., for failure to protect against drainage, to maximize production, and to
reasonably develop and market. Defendants assert that any cessation of
production was excused by their timely commencement of operations to restore
production and assert affirmative defenses of limitations, waiver, estoppel,
laches and title by adverse possession under 3, 5, 10 and 25-year statutes of
adverse possession.
Four of the cases were tried to juries in May, June and July 1999, resulting in
three verdicts in favor of and one against the defendants. The juries which
found for defendants determined that the plaintiffs' termination claims were
barred by laches, adverse possession and (in two cases) revivor. The adverse
verdict found that the defendants were bad-faith trespassers and produced gas
from the leases as a result of fraud. The jury assessed $1.2 million in
exemplary damages against each of the defendants and awarded plaintiffs
attorneys' fees in the amount of $158,000. The amount of any actual damages will
be based on prior production. The parties stipulated that the value of gas
produced by defendants was $1.0 million since January 1, 1996 and $1.5 million
since January 1, 1994. The court will determine which amount of actual damages,
if either, should be awarded based on the statute of limitations and other
considerations. The Company has filed a motion for judgment notwithstanding
verdict and, if not granted, intends to appeal the decision. The other nine
cases have not been set for trial.
The Company has previously established an accrued liability that management
believes will be sufficient to cover the estimated costs of litigation for each
of the lease cancellation cases. Because of the inconsistent verdicts reached by
the juries in the four cases tried to date and because the amount of damages
sought is not specified in all of the other cases, the outcome of the remaining
trials cannot be predicted and the amount of damages that might ultimately be
awarded could differ from the estimates. Management believes, however, that the
leases are valid, there is no basis for exemplary damages and that any findings
of fraud or bad faith will be overturned on appeal. The defendants intend to
continue to vigorously defend its position.
The Company is currently involved in various other routine disputes incidental
to its business operations. While it is not possible to determine the ultimate
disposition of these matters, management, after consultation with legal counsel,
is of the opinion that the final resolution of all such currently pending or
threatened litigation is not likely to have a material adverse effect on the
consolidated financial position or results of operations of the Company.
3. IMPAIRMENT OF OIL AND GAS PROPERTIES AND OTHER ASSETS
The Company incurred an impairment of oil and gas properties charge of $216.0
million in the Prior Quarter. This writedown was caused primarily by the effects
of accounting for the Prior Quarter acquisitions using the purchase accounting
method, as well as a significant decline in oil prices from March 31, 1998 to
June 30, 1998. The Company also recorded a $10.0 million impairment in the Prior
Quarter related to certain of its gas processing and transportation assets
located in Louisiana.
8
9
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
4. EARNINGS PER SHARE
Statement of Financial Accounting Standards No. 128, Earnings Per Share ("SFAS
128") requires presentation of "basic" and "diluted" earnings per share, as
defined, on the face of the statement of operations for all entities with
complex capital structures. SFAS 128 requires a reconciliation of the numerators
and denominators of the basic and diluted EPS computations. For the Prior
Quarter, the Current Period and the Prior Period, there was no difference
between actual weighted average shares outstanding, which are used in computing
basic EPS, and diluted weighted average shares outstanding, which are used in
computing diluted EPS. Options to purchase 13.2 million and 8.3 million shares
of common stock at a weighted average exercise price of $1.74 and $4.13 were
outstanding at June 30, 1999 and 1998, respectively, but were not included in
the computation of diluted EPS in the Prior Quarter, Current Period or Prior
Period because the effect of these outstanding options would be antidilutive. A
reconciliation for the Current Quarter is as follows (in 000's, except per share
amounts):
Income Shares Per Share
(Numerator) (Denominator) Amount
----------- ------------- ---------
FOR THE QUARTER ENDED JUNE 30, 1999:
BASIC EPS
Income available to common stockholders.... $ 4,121 97,049 $ 0.04
=========
EFFECT OF DILUTIVE SECURITIES
Employee stock options..................... -- 4,401
----------- -------------
DILUTED EPS
Income available to common stockholders
and assumed conversions................. $ 4,121 101,450 $ 0.04
=========== ============= =========
5. SUBSEQUENT EVENT
The Company has a $50 million revolving bank credit facility with a committed
borrowing base of $50 million. Subsequent to June 30, 1999, the Company entered
into an amendment to the facility to extend the maturity date from August 1999
to February 2001. The amendment also increased the interest rate and certain
fees and provided for other minor modifications. As of June 30, 1999, the
Company had borrowed $39 million under this facility, which was included in
long-term debt. Borrowings under this facility are secured by certain producing
oil and gas properties. The interest rate at June 30, 1999 was 7.75% per annum.
6. SENIOR NOTES
10.5% Notes
The Company had outstanding at March 31, 1998, $90 million in aggregate
principal amount of 10.5% Senior Notes which were to mature June 1, 2001. The
10.5% Notes were senior, unsecured obligations of the Company and were fully and
unconditionally guaranteed, jointly and severally, by Guarantor Subsidiaries (as
defined below). All outstanding 10.5% Notes were acquired by the Company
effective April 30, 1998.
9.625% Notes
The Company has outstanding $500 million in aggregate principal amount of 9.625%
Senior Notes which mature May 1, 2005, and bear interest at the rate of 9.625%,
payable semiannually on each May 1 and November 1. The 9.625% Notes are senior,
unsecured obligations of the Company and are fully and unconditionally
guaranteed, jointly and severally, by the Guarantor Subsidiaries.
9.125% Notes
The Company has outstanding $120 million in aggregate principal amount of 9.125%
Senior Notes which mature April 15, 2006, and bear interest at an annual rate of
9.125%, payable semiannually on each April 15 and October 15. The 9.125% Notes
are senior, unsecured obligations of the Company and are fully and
unconditionally guaranteed, jointly and severally, by the Guarantor
Subsidiaries.
9
10
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
7.875% Notes
The Company has outstanding $150 million in aggregate principal amount of 7.875%
Senior Notes which mature March 15, 2004, and bear interest at the rate of
7.875%, payable semiannually on each March 15 and September 15. The 7.875% Notes
are senior, unsecured obligations of the Company and are fully and
unconditionally guaranteed, jointly and severally, by the Guarantor
Subsidiaries.
8.5% Notes
The Company has outstanding $150 million in aggregate principal amount of 8.5%
Senior Notes which mature March 15, 2012, and bear interest at the rate of 8.5%,
payable semiannually on each March 15 and September 15. The 8.5% Notes are
senior, unsecured obligations of the Company and are fully and unconditionally
guaranteed, jointly and severally, by the Guarantor Subsidiaries.
The Company is a holding company and owns no operating assets and has no
significant operations independent of its subsidiaries. The Company's
obligations under its Senior Notes have been fully and unconditionally
guaranteed, on a joint and several basis, by each of the Company's "Restricted
Subsidiaries" (as defined in the respective indentures governing the Senior
Notes) (collectively, the "Guarantor Subsidiaries"). Each of the Guarantor
Subsidiaries is a direct or indirect wholly-owned subsidiary of the Company.
The Senior Note indentures contain certain covenants, including covenants
limiting the Company and the Guarantor Subsidiaries with respect to asset sales,
restricted payments, the incurrence of additional indebtedness and the issuance
of preferred stock, liens, sale and leaseback transactions, lines of business,
dividend and other payment restrictions affecting Guarantor Subsidiaries,
mergers or consolidations, and transactions with affiliates. The Company is
obligated to repurchase the 9.625% and 9.125% Senior Notes in the event of a
change of control or certain asset sales.
These Senior Note indentures also limit the Company's ability to make restricted
payments (as defined in the indentures), including the payment of preferred
stock dividends, unless certain tests are met. As of December 31, 1998, March
31, 1999 and June 30, 1999, the Company was unable to meet the requirements to
incur additional unsecured indebtedness, and consequently was unable to pay the
quarterly cash dividend of $4.0 million on its 7% cumulative convertible
preferred stock on February 1, 1999, May 1, 1999 or August 1, 1999. As of June
30, 1999 the cumulative earned but unpaid dividends on the preferred stock was
$11.2 million. Subsequent payments will be subject to the same restrictions and
are dependent upon variables, most particularly oil and gas prices, that are
beyond the Company's ability to predict. This restriction does not affect the
Company's ability to borrow under or expand its secured commercial bank
facility. If the Company fails to pay dividends for six quarterly periods, the
holders of preferred stock would be entitled to elect two additional members to
the Board.
Set forth below are condensed consolidating financial statements of the
Guarantor Subsidiaries, the Company's subsidiary which is not a guarantor of the
Senior Notes (the "Non-Guarantor Subsidiary") and the Company. As of and for the
three and six months ended June 30, 1999 and 1998, Chesapeake Energy Marketing,
Inc. was the only Non-Guarantor Subsidiary. For both periods, all other
subsidiaries of the Company were Guarantor Subsidiaries. Separate financial
statements of each Guarantor Subsidiary have not been provided because
management has determined that they are not material to investors.
10
11
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF JUNE 30, 1999
($ IN THOUSANDS)
ASSETS
GUARANTOR NON-GUARANTOR COMPANY
SUBSIDIARIES SUBSIDIARY (PARENT) ELIMINATIONS CONSOLIDATED
------------ ------------- ----------- ------------ ------------
CURRENT ASSETS:
Cash and cash equivalents............... $ (9,126) $ 17,591 $ 20,530 $ -- $ 28,995
Accounts receivable, net................ 40,910 26,442 473 (13,183) 54,642
Inventory............................... 4,566 311 -- -- 4,877
Other................................... 2,071 16 359 -- 2,446
------------ ------------- ----------- ------------ ------------
Total Current Assets................. 38,421 44,360 21,362 (13,183) 90,960
------------ ------------- ----------- ------------ ------------
PROPERTY AND EQUIPMENT:
Oil and gas properties.................. 2,218,839 -- -- -- 2,218,839
Unevaluated leasehold................... 45,190 -- -- -- 45,190
Other property and equipment............ 45,916 14,801 17,760 -- 78,477
Less: accumulated depreciation,
depletion and amortization............ (1,651,974) (8,183) (1,620) -- (1,661,777)
------------ ------------- ----------- ------------ ------------
Total Property and Equipment......... 657,971 6,618 16,140 -- 680,729
------------ ------------- ----------- ------------ ------------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES................... 808,285 -- 493,738 (1,302,023) --
OTHER ASSETS.............................. 10,612 566 18,096 (53) 29,221
------------ ------------- ----------- ------------ ------------
TOTAL ASSETS......................... $ 1,515,289 $ 51,544 $ 549,336 $ (1,315,259) $ 800,910
============ ============= =========== ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES:
Notes payable and current maturities
of long-term debt..................... $ -- $ -- $ -- $ -- $ --
Accounts payable and other.............. 53,804 17,180 17,503 (13,159) 75,328
------------ ------------- ----------- ------------ ------------
Total Current Liabilities............ 53,804 17,180 17,503 (13,159) 75,328
------------ ------------- ----------- ------------ ------------
LONG-TERM DEBT............................ 39,000 -- 919,118 -- 958,118
------------ ------------- ----------- ------------ ------------
REVENUES PAYABLE.......................... 11,137 -- -- -- 11,137
------------ ------------- ----------- ------------ ------------
DEFERRED INCOME TAXES..................... 4,880 -- -- -- 4,880
------------ ------------- ----------- ------------ ------------
INTERCOMPANY PAYABLES..................... 1,372,792 1,038 (1,373,806) (24) --
------------ ------------- ----------- ------------ ------------
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred Stock......................... -- -- 230,000 -- 230,000
Common Stock............................ 27 1 1,044 (17) 1,055
Other................................... 33,649 33,325 755,477 (1,302,059) (479,608)
------------ ------------- ----------- ------------ ------------
Total Stockholders' Equity (Deficit). 33,676 33,326 986,521 (1,302,076) (248,553)
------------ ------------- ----------- ------------ ------------
TOTAL LIABILITIES AND
STOCKHOLDERS' EQUITY (DEFICIT)..... $ 1,515,289 $ 51,544 $ 549,336 $ (1,315,259) $ 800,910
============ ============= =========== ============ ============
11
12
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 1998
($ IN THOUSANDS)
ASSETS
GUARANTOR NON-GUARANTOR COMPANY
SUBSIDIARIES SUBSIDIARY (PARENT) ELIMINATIONS CONSOLIDATED
------------ ------------- ----------- ------------ ------------
CURRENT ASSETS:
Cash and cash equivalents............... $ (11,565) $ 7,000 $ 39,839 $ -- $ 35,274
Accounts receivable..................... 54,384 29,641 270 (7,996) 76,299
Inventory............................... 4,919 406 -- -- 5,325
Other................................... 721 15 365 -- 1,101
------------ ------------- ----------- ------------ ------------
Total Current Assets................. 48,459 37,062 40,474 (7,996) 117,999
------------ ------------- ----------- ------------ ------------
PROPERTY AND EQUIPMENT:
Oil and gas properties.................. 2,142,943 -- -- -- 2,142,943
Unevaluated leasehold................... 52,687 -- -- -- 52,687
Other property and equipment............ 47,628 15,109 16,981 -- 79,718
Less: accumulated depreciation,
depletion and amortization............ (1,601,931) (8,036) (1,390) -- (1,611,357)
------------ ------------- ----------- ------------ ------------
Total Property & Equipment........... 641,327 7,073 15,591 -- 663,991
------------ ------------- ----------- ------------ ------------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES................... 473,578 -- 481,150 (954,728) --
------------ ------------- ----------- ------------ ------------
OTHER ASSETS.............................. 10,610 560 19,455 -- 30,625
------------ ------------- ----------- ------------ ------------
TOTAL ASSETS......................... $ 1,173,974 $ 44,695 $ 556,670 $ (962,724) $ 812,615
============ ============= =========== ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES:
Notes payable and current maturities
of long-term debt..................... $ 25,000 $ -- $ -- $ -- $ 25,000
Accounts payable and other.............. 80,786 15,992 17,529 (8,023) 106,284
------------ ------------- ----------- ------------ ------------
Total Current Liabilities............ 105,786 15,992 17,529 (8,023) 131,284
------------ ------------- ----------- ------------ ------------
LONG-TERM DEBT............................ -- -- 919,076 -- 919,076
------------ ------------- ----------- ------------ ------------
REVENUES PAYABLE.......................... 10,823 -- -- -- 10,823
------------ ------------- ----------- ------------ ------------
INTERCOMPANY PAYABLES..................... 1,338,948 11,376 (1,350,351) 27 --
------------ ------------- ----------- ------------ ------------
STOCKHOLDERS' EQUITY (DEFICIT):
Common Stock............................ 26 1 1,042 (17) 1,052
Other................................... (281,609) 17,326 969,374 (954,711) (249,620)
------------ ------------- ----------- ------------ ------------
Total Stockholders' Equity (Deficit). (281,583) 17,327 970,416 (954,728) (248,568)
------------ ------------- ----------- ------------ ------------
TOTAL LIABILITIES AND
STOCKHOLDERS' EQUITY (DEFICIT)..... $ 1,173,974 $ 44,695 $ 556,670 $ (962,724) $ 812,615
============ ============= =========== ============ ============
12
13
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
GUARANTOR NON-GUARANTOR COMPANY
SUBSIDIARIES SUBSIDIARY (PARENT) ELIMINATIONS CONSOLIDATED
------------ ------------- ----------- ------------ ------------
FOR THE THREE MONTHS ENDED JUNE 30, 1999
REVENUES:
Oil and gas sales....................... $ 68,869 $ -- $ -- $ (597) $ 68,272
Oil and gas marketing sales............. -- 37,823 -- (25,203) 12,620
------------ ------------- ------------ ------------ ------------
Total Revenues....................... 68,869 37,823 -- (25,800) 80,892
------------ ------------- ------------ ------------ ------------
OPERATING COSTS:
Production expenses and taxes........... 13,981 -- -- -- 13,981
Oil and gas marketing expenses.......... -- 37,473 -- (25,800) 11,673
Oil and gas depreciation, depletion
and amortization...................... 24,233 -- -- -- 24,233
Other depreciation and amortization..... 1,138 20 814 -- 1,972
General and administrative.............. 2,942 324 2 -- 3,268
------------ ------------- ------------ ------------ ------------
Total Operating Costs................ 42,294 37,817 816 (25,800) 55,127
------------ ------------- ------------ ------------ ------------
INCOME (LOSS) FROM OPERATIONS............. 26,575 6 (816) -- 25,765
------------ ------------- ------------ ------------ ------------
OTHER INCOME (LOSS)
Interest and other income............... 440 2,408 29,188 (29,069) 2,967
Interest expense........................ (29,009) -- (20,319) 29,069 (20,259)
------------ ------------- ------------ ------------ ------------
(28,569) 2,408 8,869 -- (17,292)
------------ ------------- ------------ ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES......... (1,994) 2,414 8,053 -- 8,473
INCOME TAX EXPENSE (BENEFIT).............. 326 -- -- -- 326
------------ ------------- ------------ ------------ ------------
NET INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM...................... (2,320) 2,414 8,053 -- 8,147
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt,
net of applicable income tax........... -- -- -- -- --
------------ ------------- ------------ ------------ ------------
NET INCOME (LOSS)......................... $ (2,320) $ 2,414 $ 8,053 $ -- $ 8,147
============ ============= ============ ============ ============
FOR THE THREE MONTHS ENDED JUNE 30, 1998
REVENUES:
Oil and gas sales....................... $ 74,592 $ -- $ -- $ 1,047 $ 75,639
Oil and gas marketing sales............. 11,350 49,561 -- (27,240) 33,671
------------ ------------- ------------ ------------ ------------
Total Revenues....................... 85,942 49,561 -- (26,193) 109,310
------------ ------------- ------------ ------------ ------------
OPERATING COSTS:
Production expenses and taxes........... 17,294 -- -- -- 17,294
Oil and gas marketing expenses.......... 11,081 48,817 -- (26,193) 33,705
Impairment of oil and gas properties.... 216,000 -- -- -- 216,000
Impairment of other assets.............. 10,000 -- -- -- 10,000
Oil and gas depreciation, depletion
and amortization...................... 43,900 -- -- -- 43,900
Other depreciation and amortization..... 1,198 34 690 -- 1,922
General and administrative.............. 4,800 359 (25) -- 5,134
------------ ------------- ------------ ------------ ------------
Total Operating Costs................ 304,273 49,210 665 (26,193) 327,955
------------ ------------- ------------ ------------ ------------
INCOME (LOSS) FROM OPERATIONS............. (218,331) 351 (665) -- (218,645)
------------ ------------- ------------ ------------ ------------
OTHER INCOME (LOSS)
Interest and other income............... 542 129 23,948 (22,048) 2,571
Interest expense........................ (21,876) -- (18,837) 22,048 (18,665)
------------ ------------- ------------ ------------ ------------
(21,334) 129 5,111 -- (16,094)
------------ ------------- ------------ ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES......... (239,665) 480 4,446 -- (234,739)
INCOME TAX EXPENSE (BENEFIT).............. -- -- -- -- --
------------ ------------- ------------ ------------ ------------
NET INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM...................... (239,665) 480 4,446 -- (234,739)
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt,
net of applicable income tax........... (2,164) -- (11,170) -- (13,334)
------------ ------------- ------------ ------------ ------------
NET INCOME (LOSS)......................... $ (241,829) $ 480 $ (6,724) $ -- $ (248,073)
============ ============= ============ ============ ============
13
14
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
GUARANTOR NON-GUARANTOR COMPANY
SUBSIDIARIES SUBSIDIARY (PARENT) ELIMINATIONS CONSOLIDATED
------------ ------------- ------------ ------------ ------------
FOR THE SIX MONTHS ENDED JUNE 30, 1999
REVENUES:
Oil and gas sales ................... $ 120,078 $ -- $ -- $ -- $ 120,078
Oil and gas marketing sales ......... -- 73,258 -- (46,767) 26,491
------------ ------------- ------------ ------------ ------------
Total Revenues ................... 120,078 73,258 (46,767) 146,569
------------ ------------- ------------ ------------ ------------
OPERATING COSTS:
Production expenses and taxes ....... 29,963 -- -- -- 29,963
Oil and gas marketing expenses ...... -- 71,725 -- (46,767) 24,958
Oil and gas depreciation, depletion
and amortization .................. 47,386 -- -- -- 47,386
Other depreciation and amortization.. 2,476 40 1,622 -- 4,138
General and administrative .......... 6,464 781 47 -- 7,292
------------ ------------- ------------ ------------ ------------
Total Operating Costs ............ 86,289 72,546 1,669 (46,767) 113,737
------------ ------------- ------------ ------------ ------------
INCOME (LOSS) FROM OPERATIONS ......... 33,789 712 (1,669) -- 32,832
------------ ------------- ------------ ------------ ------------
OTHER INCOME (LOSS)
Interest and other income ........... 707 2,845 58,328 (58,040) 3,840
Interest expense .................... (57,415) -- (40,774) 58,040 (40,149)
------------ ------------- ------------ ------------ ------------
(56,708) 2,845 17,554 -- (36,309)
------------ ------------- ------------ ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES ..... (22,919) 3,557 15,885 -- (3,477)
INCOME TAX EXPENSE (BENEFIT) .......... 326 -- -- -- 326
------------ ------------- ------------ ------------ ------------
NET INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM .................. (23,245) 3,557 15,885 -- (3,803)
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt,
net of applicable income tax ....... -- -- -- -- --
------------ ------------- ------------ ------------ ------------
NET INCOME (LOSS) ..................... $ (23,245) $ 3,557 $ 15,885 $ -- $ (3,803)
============ ============= ============ ============ ============
FOR THE SIX MONTHS ENDED JUNE 30, 1998
REVENUES:
Oil and gas sales ................... $ 124,207 $ -- $ -- $ 1,673 $ 125,880
Oil and gas marketing sales ......... 21,071 87,565 -- (48,441) 60,195
------------ ------------- ------------ ------------ ------------
Total Revenues ................... 145,278 87,565 -- (46,768) 186,075
------------ ------------- ------------ ------------ ------------
OPERATING COSTS:
Production expenses and taxes ....... 26,732 -- -- -- 26,732
Oil and gas marketing expenses ...... 20,617 86,117 -- (46,768) 59,966
Impairment of oil and gas properties 466,000 -- -- -- 466,000
Impairment of other assets .......... 10,000 -- -- -- 10,000
Oil and gas depreciation, depletion
and amortization .................. 75,242 -- -- -- 75,242
Other depreciation and amortization.. 2,061 54 1,187 -- 3,302
General and administrative .......... 8,874 633 7 -- 9,514
------------ ------------- ------------ ------------ ------------
Total Operating Costs ............ 609,526 86,804 1,194 (46,768) 650,756
------------ ------------- ------------ ------------ ------------
INCOME (LOSS) FROM OPERATIONS ......... (464,248) 761 (1,194) -- (464,681)
------------ ------------- ------------ ------------ ------------
OTHER INCOME (LOSS)
Interest and other income ........... 566 219 43,983 (41,973) 2,795
Interest expense .................... (41,099) -- (30,227) 41,973 (29,353)
------------ ------------- ------------ ------------ ------------
(40,533) 219 13,756 -- (26,558)
------------ ------------- ------------ ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES ..... (504,781) 980 12,562 -- (491,239)
INCOME TAX EXPENSE (BENEFIT) .......... -- -- -- -- --
------------ ------------- ------------ ------------ ------------
NET INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM .................. (504,781) 980 12,562 -- (491,239)
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt,
net of applicable income tax ....... (2,164) -- (11,170) -- (13,334)
------------ ------------- ------------ ------------ ------------
NET INCOME (LOSS) ..................... $ (506,945) $ 980 $ 1,392 $ -- $ (504,573)
============ ============= ============ ============ ============
14
15
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)
GUARANTOR NON-GUARANTOR COMPANY
SUBSIDIARIES SUBSIDIARY (PARENT) ELIMINATIONS CONSOLIDATED
------------ ------------- ------------ ------------ ------------
FOR THE SIX MONTHS ENDED JUNE 30, 1999
CASH FLOWS FROM OPERATING ACTIVITIES...... $ 22,128 $ 8,119 $ 17,319 $ -- $ 47,566
------------ ------------- ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties ................. (85,787) -- -- -- (85,787)
Proceeds from sale of oil and gas
properties ............................. 17,387 -- -- -- 17,387
Proceeds from sale of other assets ..... 1,306 -- -- -- 1,306
Other additions ........................ 427 308 (986) -- (251)
------------ ------------- ------------ ------------ ------------
(66,667) 308 (986) -- (67,345)
------------ ------------- ------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings ............... 14,000 -- -- -- 14,000
Cash paid for purchase of treasury stock -- (53) -- -- (53)
Cash received from exercise of stock
options ................................ -- -- 240 -- 240
Intercompany advances, net ............. 33,665 2,217 (35,882) -- --
------------ ------------- ------------ ------------ ------------
47,665 2,164 (35,642) -- 14,187
------------ ------------- ------------ ------------ ------------
EFFECT OF EXCHANGE RATE CHANGES
ON CASH ................................ 3,625 -- -- -- 3,625
------------ ------------- ------------ ------------ ------------
Net increase (decrease) in cash ........ 6,751 10,591 (19,309) -- (1,967)
Cash, beginning of period .............. (17,319) 7,000 39,839 -- 29,520
------------ ------------- ------------ ------------ ------------
Cash, end of period .................... $ (10,568) $ 17,591 $ 20,530 $ -- $ 27,553
============ ============= ============ ============ ============
FOR THE SIX MONTHS ENDED JUNE 30, 1998
CASH FLOWS FROM OPERATING ACTIVITIES: .... $ (609) $ (476) $ 20,805 $ -- $ 19,720
------------ ------------- ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties ................. (472,879) -- -- -- (472,879)
Proceeds from sale of assets ........... 804 -- 3,600 -- 4,404
Repayment of long-term loans ........... 2,000 -- -- -- 2,000
Other additions ........................ (3,448) (258) (1,477) -- (5,183)
------------ ------------- ------------ ------------ ------------
(473,523) (258) 2,123 -- (471,658)
------------ ------------- ------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings ............... -- -- 658,750 -- 658,750
Payments on borrowings ................. -- -- (474,166) -- (474,166)
Cash received from issuance of preferred
stock .................................. -- -- 222,781 -- 222,781
Cash paid for purchase of treasury stock -- -- (17,831) -- (17,831)
Cash received from exercise of stock
options ................................ -- -- 101 -- 101
Intercompany advances, net ............. 465,229 (2,545) (462,684) -- --
------------ ------------- ------------ ------------ ------------
465,229 (2,545) (73,049) -- 389,635
------------ ------------- ------------ ------------ ------------
EFFECT OF EXCHANGE RATE CHANGES
ON CASH ................................ (1,867) -- -- -- (1,867)
------------ ------------- ------------ ------------ ------------
Net increase (decrease) in cash ........ (10,770) (3,279) (50,121) -- (64,170)
Cash, beginning of period .............. (284) 13,694 110,450 -- 123,860
------------ ------------- ------------ ------------ ------------
Cash, end of period .................... $ (11,054) $ 10,415 $ 60,329 $ -- $ 59,690
============ ============= ============ ============ ============
15
16
PART I. FINANCIAL INFORMATION
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Three Months Ended June 30, 1999 vs. June 30, 1998
General. For the three months ended June 30, 1999 (the "Current Quarter"), the
Company had net income of $8.1 million, or $0.04 per common share after
deducting preferred dividends of $4.0 million. This compares to a net loss of
$248.1 million, or a loss of $2.41 per common share after deducting preferred
dividends of $4.0 million, in the three months ended June 30, 1998 (the "Prior
Quarter"). The loss in the Prior Quarter resulted from a $216.0 million asset
writedown recorded under the full-cost method of accounting, a $10.0 million
impairment related to certain of the Company's gas processing and transportation
assets located in Louisiana, a $13.3 million extraordinary loss on the early
extinguishment of debt, and an $8.7 million loss from recurring operations. The
asset writedown was caused by acquisitions completed by the Company in April
1998 for consideration in excess of the present value (10% discount) of the
future net revenues of the proved reserves acquired as of June 30, 1998, as well
as the evaluation of certain leasehold, seismic and other exploration-related
costs that were previously unevaluated, and by decreases in oil prices from
March 31, 1998 to June 30, 1998. See " - Impairment of Oil and Gas Properties".
Oil and Gas Sales. During the Current Quarter, oil and gas sales decreased to
$68.3 million from $75.6 million, a decrease of $7.3 million, or 10%. This
decrease resulted from lower oil and gas production volumes, which decreased
from 37.2 billion cubic feet equivalent of natural gas ("bcfe") in the Prior
Quarter to 33.6 bcfe in the Current Quarter, a decrease of 3.6 bcfe, or 10%. The
decrease in production volumes were primarily the result of the asset
divestitures completed during the last quarter of 1998 and first half of 1999.
For the Current Quarter, the Company produced 1.1 million barrels of oil
("mmbo") and 27.0 billion cubic feet of natural gas ("bcf"), compared to 1.8
mmbo and 26.3 bcf in the Prior Quarter. Average oil prices realized were $16.01
per barrel of oil in the Current Quarter compared to $12.85 per barrel in the
Prior Quarter, an increase of 25%. Average gas prices realized were $1.88 per
thousand cubic feet ("mcf") in the Current Quarter compared to $1.99 per mcf in
the Prior Quarter, a decrease of 6%.
For the Current Quarter, the Company realized an average price of $2.03 per
thousand cubic feet equivalent of natural gas ("mcfe"), compared to $2.03 per
mcfe in the Prior Quarter. The Company's hedging activities resulted in
increased oil and gas revenues of $2.9 million, or $0.09 per mcfe, in the
Current Quarter, compared to increases in oil and gas revenues of $2.2 million
in the Prior Quarter.
The following table shows the Company's production by region for the Current
Quarter and the Prior Quarter:
FOR THE THREE MONTHS ENDED JUNE 30,
------------------------------------------------
1999 1998
-------------------- --------------------
OPERATING AREAS MMCFE PERCENT MMCFE PERCENT
--------------------- ------- ------- ------- -------
Mid-Continent................. 18,960 57% 19,514 53%
Gulf Coast.................... 10,811 32 14,265 38
Canada........................ 3,134 9 2,414 6
Other areas................... 661 2 1,038 3
------- ------- ------- -------
Total.................... 33,566 100% 37,231 100%
======= ======= ======= =======
Natural gas production represented approximately 80% of the Company's total
production volume on a gas equivalent basis in the Current Quarter, compared to
71% in the Prior Quarter. The Company anticipates natural gas will represent
approximately 80% of anticipated 1999 production. As of June 30, 1999 natural
gas represented approximately 87% of the Company's proved reserves.
Oil and Gas Marketing Sales. The Company realized $12.6 million in oil and gas
marketing sales to third parties in the Current Quarter, with corresponding oil
and gas marketing expenses of $11.7 million. This compares to sales of
16
17
$33.7 million and expenses of $33.7 million in the Prior Quarter. The decrease
in marketing sales and cost of sales was due primarily to lower third party
sales in the Current Quarter as compared to the Prior Quarter. The increase in
gross margin between periods was due primarily to the improved operating results
from certain gas gathering, transportation and marketing assets.
Production Expenses and Taxes. Production expenses decreased to $11.2 million in
the Current Quarter, a $3.5 million decrease from $14.7 million incurred in the
Prior Quarter. The decrease was due primarily to the Company's divestiture of
higher cost oil and gas properties and the closing of various field offices. On
a production unit basis, production expenses were $0.33 and $0.39 per mcfe in
the Current and Prior Quarters, respectively. The Company anticipates production
expenses will average $0.35 to $0.40 per mcfe for 1999.
Production taxes, which consist primarily of wellhead severance taxes, were $2.8
million and $2.6 million in the Current and Prior Quarters, respectively. On a
per unit basis, production taxes were $0.08 per mcfe in the Current Quarter
compared to $0.07 per mcfe in the Prior Quarter.
Impairment of Oil and Gas Properties. The Company utilizes the full-cost method
to account for its investment in oil and gas properties. Under this method, all
costs of acquisition, exploration and development of oil and gas reserves
(including such costs as leasehold acquisition costs, geological and geophysical
expenditures, certain capitalized internal costs, dry hole costs and tangible
and intangible development costs) are capitalized as incurred. These oil and gas
property costs, including the estimated future capital expenditures to develop
proved undeveloped reserves, are depleted and charged to operations using the
unit-of-production method based on the ratio of current production to proved oil
and gas reserves as estimated by the Company's independent engineering
consultants and in-house engineers. Costs directly associated with the
acquisition and evaluation of unproved properties are excluded from the
amortization computation until it is determined whether or not proved reserves
can be assigned to the property or whether impairment has occurred. The excess
of capitalized costs of oil and gas properties, net of accumulated depreciation,
depletion and amortization and related deferred income taxes, over the
discounted future net revenues (at 10%) of proved oil and gas properties is
charged to operations.
The Company incurred an impairment of oil and gas properties charge of $216
million in the Prior Quarter, compared to no impairment charge in the Current
Quarter. The writedown in the Prior Quarter was caused by a combination of
several factors, including the acquisitions completed by the Company in April
1998. The most significant factor was the completion of the acquisition of DLB
Oil & Gas, Inc. ("DLB"), which was accounted for using the purchase method. The
purchase price, which was established in February 1998 when the terms of the
acquisition were amended (based upon a Chesapeake common stock price of $6 per
share), was allocated primarily to DLB's evaluated oil and gas properties. Based
upon reserve estimates as of June 30, 1998, the portion of the purchase price
which was allocated to evaluated oil and gas properties exceeded the associated
discounted future net revenues from DLB's estimated proved reserves by
approximately $70 million. In total, approximately $116 million of the writedown
was related to acquisitions completed during the Prior Quarter. The evaluation
of certain leasehold, seismic and other exploration-related costs that were
previously unevaluated, together with decreases in oil prices at June 30, 1998,
were the remaining contributing factors which led to the writedown in the Prior
Quarter.
Impairment of Other Assets. In the Prior Quarter, the Company incurred an
impairment charge of $10 million related to certain of the Company's gas
processing and transportation assets located in Louisiana. No such charge was
recorded in the Current Quarter.
Oil and Gas Depreciation, Depletion and Amortization. Depreciation, depletion
and amortization of oil and gas properties ("DD&A") for the Current Quarter was
$24.2 million, compared to $43.9 million in the Prior Quarter. This decrease was
caused by a decrease in the DD&A rate per mcfe from $1.18 to $0.72 in the Prior
and Current Quarters, respectively. The decrease in the DD&A rate per mcfe is
due primarily to the impairment of oil and gas properties recorded during 1998.
Depreciation and Amortization of Other Assets. Depreciation and amortization of
other assets ("D&A") increased to $2.0 million in the Current Quarter compared
to $1.9 million in the Prior Quarter. The Company anticipates D&A expense
throughout the remainder of 1999 to remain at approximately the same level.
17
18
General and Administrative. General and administrative expenses ("G&A"), which
are net of capitalized internal payroll and non-payroll expenses, were $3.3
million in the Current Quarter compared to $5.1 million in the Prior Quarter.
This decrease was primarily caused by various measures designed to lower
corporate overhead, including staff reductions and office closings which
occurred subsequent to June 30, 1998. The Company capitalized $0.8 million of
internal costs in the Current Quarter directly related to the Company's oil and
gas exploration and development efforts, compared to $1.1 million in the Prior
Quarter. The Company anticipates that G&A costs for the remainder of 1999 will
remain at generally the same level as in the Current Quarter.
Interest and Other Income. Interest and other income for the Current Quarter was
$3.0 million compared to $2.6 million in the Prior Quarter.
Interest. Interest expense increased to $20.3 million in the Current Quarter
from $18.7 million in the Prior Quarter. This increase was a result of lower
capitalized interest in the Current Quarter, higher levels of indebtedness and a
full quarter of interest on the 9.625% Senior Notes which were issued on April
22, 1998. The Company capitalized $1.0 million of interest during the Current
Quarter compared to $1.6 million capitalized in the Prior Quarter. The Company
anticipates that interest expense will remain at generally the same level as in
the Current Quarter.
Provision for Income Taxes. The Company recorded $0.3 million of income tax
expense for the Current Quarter, compared to none in the Prior Quarter. The
income tax expense in the Current Quarter is entirely related to the Company's
operations in Canada. At June 30, 1999, the Company had a net operating loss
carryforward of approximately $650 million for regular U.S. federal income taxes
which will expire in future years beginning in 2007. Management believes that it
cannot be demonstrated at this time that it is more likely than not that its
domestic deferred income tax assets, comprised primarily of the net operating
loss carryforward generated in the United States, will be realizable in future
years, and therefore a valuation allowance of $455 million has been recorded.
Six Months Ended June 30, 1999 vs. June 30, 1998
General. For the six months ended June 30, 1999 (the "Current Period"), the
Company realized a net loss of $3.8 million, or a net loss of $0.12 per common
share after deducting preferred dividends of $8.1 million. This compares to a
net loss of $504.6 million, or a net loss of $5.50 per common share after
deducting preferred dividends of $4.0 million, in the six months ended June 30,
1998 (the "Prior Period"). The loss in the Prior Period was primarily caused by
a $466.0 million asset writedown recorded under the full-cost method of
accounting, a $10.0 million impairment related to certain of the Company's gas
processing and transportation assets located in Louisiana, a $13.3 million
extraordinary loss on the early extinguishment of debt, and a $15.2 million loss
from recurring operations. The asset writedown was partially caused by the
acquisitions completed during the Prior Period for consideration in excess of
the present value (10% discount) of the future net revenues of the proved
reserves acquired as of June 30, 1998. See "- Impairment of Oil and Gas
Properties".
Oil and Gas Sales. During the Current Period, oil and gas sales decreased to
$120.1 million from $125.9 million, a decrease of $5.8 million, or 5%. This
decrease resulted from lower oil and gas prices between periods, partially
offset by higher oil and gas production volumes, which increased from 60.2 bcfe
in the Prior Period to 66.9 bcfe in the Current Period, an increase of 6.7 bcfe,
or 11%. For the Current Period, the Company produced 2.4 mmbo and 52.7 bcf,
compared to 3.0 mmbo and 42.2 bcf in the Prior Period. Average oil prices
realized were $13.27 per barrel in the Current Period compared to $13.63 per
barrel in the Prior Period, a decrease of 3%. Average gas prices realized were
$1.68 per mcf in the Current Period compared to $2.01 per mcf in the Prior
Period, a decrease of 16%.
For the Current Period, the Company realized an average price of $1.80 per mcfe,
compared to $2.09 per mcfe in the Prior Period. The Company's hedging activities
resulted in increased oil and gas revenues of $3.9 million, or $0.06 per mcfe,
in the Current Period, compared to increases in oil and gas revenues of $4.0
million in the Prior Period.
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The following table shows the Company's production by region for the Current
Period and the Prior Period:
FOR THE SIX MONTHS ENDED JUNE 30,
------------------------------------------------
1999 1998
-------------------- --------------------
OPERATING AREAS MMCFE PERCENT MMCFE PERCENT
--------------------- ------- ------- ------- -------
Mid-Continent................. 35,969 54% 27,896 47%
Gulf Coast.................... 21,525 32 27,135 45
Canada........................ 5,564 8 3,144 5
Other areas................... 3,820 6 2,019 3
------- ------- ------- -------
Total.................... 66,878 100% 60,194 100%
======= ======= ======= =======
Natural gas production represented approximately 79% of the Company's total
production volume on an equivalent basis in the Current Period, compared to 70%
in the Prior Period.
Oil and Gas Marketing Sales. The Company realized $26.5 million in oil and gas
marketing sales to third parties in the Current Period, with corresponding oil
and gas marketing expenses of $25.0 million. This compares to sales of $60.2
million and expenses of $60.0 million in the Prior Period.
Production Expenses and Taxes. Production expenses increased to $25.2 million in
the Current Period, a $2.6 million increase from $22.6 million incurred in the
Prior Period. On a production unit basis, production expenses were $0.38 and
$0.37 per mcfe in the Current and Prior Periods, respectively.
Production taxes, which consist primarily of wellhead severance taxes, were $4.8
million and $4.2 million in the Current and Prior Periods, respectively. This
increase was primarily the result of increased natural gas production. On a per
unit basis, production taxes were $0.07 per mcfe in the Current Period compared
to $0.07 per mcfe in the Prior Period.
Impairment of Oil and Gas Properties. The Company utilizes the full-cost method
to account for its investment in oil and gas properties. Under this method, all
costs of acquisition, exploration and development of oil and gas reserves
(including such costs as leasehold acquisition costs, geological and geophysical
expenditures, certain capitalized internal costs, dry hole costs and tangible
and intangible development costs) are capitalized as incurred. These oil and gas
property costs, including the estimated future capital expenditures to develop
proved undeveloped reserves, are depleted and charged to operations using the
unit-of-production method based on the ratio of current production to proved oil
and gas reserves as estimated by the Company's independent engineering
consultants and in-house engineers. Costs directly associated with the
acquisition and evaluation of unproved properties are excluded from the
amortization computation until it is determined whether or not proved reserves
can be assigned to the property or whether impairment has occurred. The excess
of capitalized costs of oil and gas properties, net of accumulated depreciation,
depletion and amortization and related deferred income taxes, over the
discounted future net revenues of proved oil and gas properties is charged to
operations.
The Company incurred an impairment of oil and gas properties charge of $466.0
million in the Prior Period, compared to no impairment charge in the Current
Period. The writedown in the Prior Period was caused by a combination of several
factors, including the acquisitions completed by the Company during the Prior
Period, which were accounted for using the purchase method. The most significant
factors were the acquisitions of Hugoton Energy Corporation ("Hugoton") and DLB.
Higher drilling and completion costs, the evaluation of certain leasehold,
seismic and other exploration-related costs that were previously unevaluated,
together with decreases in oil and gas prices from December 31, 1997 to June 30,
1998 were the remaining contributing factors which led to the writedown in the
Prior Period.
Impairment of Other Assets. In the Prior Period, the Company incurred an
impairment charge of $10.0 million related to certain of the Company's gas
processing and transportation assets located in Louisiana. No such charge was
recorded in the Current Period.
Oil and Gas Depreciation, Depletion and Amortization. DD&A for the Current
Period was $47.4 million, compared to $75.2 million in the Prior Period. This
decrease was caused by a decrease in the DD&A rate per mcfe from $1.25
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to $0.71 in the Prior and Current Periods, respectively. The decrease in the
DD&A rate per mcfe is due primarily to the impairment of oil and gas properties
recorded during 1998.
Depreciation and Amortization of Other Assets. D&A increased to $4.1 million in
the Current Period compared to $3.3 million in the Prior Period. This increase
in D&A was caused by a full six months of amortization of debt issuance costs
related to the issuance of Senior Notes in April 1998.
General and Administrative. G&A, which is net of capitalized internal payroll
and non-payroll expenses, was $7.3 million in the Current Period compared to
$9.5 million in the Prior Period. This decrease was primarily caused by various
measures designed to lower corporate overhead, including staff reductions and
office closings which occurred subsequent to June 30, 1998. The Company
capitalized $2.0 million of internal costs in the Current Period directly
related to the Company's oil and gas exploration and development efforts,
compared to $3.2 million in the Prior Period.
Interest and Other Income. Interest and other income for the Current Period was
$3.8 million compared to $2.8 million in the Prior Period. This increase is due
primarily to a $1.5 million gain on the sale of certain marketing assets located
in the Mid-Continent in the Current Period.
Interest. Interest expense increased to $40.1 million in the Current Period from
$29.4 million in the Prior Period. This increase was a result of the issuance of
the 9.625% Senior Notes in April 1998 as well as lower capitalized interest in
the Current Period. The Company capitalized $2.2 million of interest during the
Current Period compared to $3.8 million capitalized in the Prior Period.
Provision for Income Taxes. The Company recorded income tax expense of $0.3
million for the Current Period, compared to none in the Prior Period. The income
tax expense in the Current Period is entirely related to the Company's
operations in Canada. Management believes that it cannot be demonstrated that it
is more likely than not that its domestic deferred income tax assets will be
realizable in future years, and therefore a valuation allowance of $455.0
million has been recorded. Consequently, there was no income tax expense or
benefit related to the Company's domestic operations during the Current and
Prior Periods.
RISK MANAGEMENT ACTIVITIES
See Item 3 - "Quantitative and Qualitative Disclosures About Market Risks".
LIQUIDITY AND CAPITAL RESOURCES
As of June 30, 1999, the Company had working capital of approximately $16
million. The Company has a $50 million revolving bank credit facility with a
committed borrowing base of $50 million. Subsequent to June 30, 1999, the
Company entered into an amendment to the facility to extend the maturity date
from August 1999 to February 2001. The amendment also increased the interest
rate and certain fees, and provided for other modifications. As of June 30,
1999, the Company had borrowed $39 million under this facility, which was
included in long-term debt. Borrowings under the facility are secured by certain
producing oil and gas properties. The interest rate at June 30, 1999 was 7.75%
per annum.
Two of the Company's Senior Note indentures contain financial covenants which
restrict the ability of the Company and its restricted subsidiaries to incur
additional indebtedness and to make restricted payments, such as paying cash
dividends and repurchasing Company stock. These restrictions do not affect the
Company's ability to borrow under or expand its secured commercial bank
facility. The Company estimates that it could have incurred up to $111 million
of secured commercial bank indebtedness as of June 30, 1999 under the most
restrictive of its indenture debt incurrence tests.
As of December 31, 1998, March 31, 1999, and June 30, 1999 the Company was
unable to meet the restricted payment test under these indentures, including the
requirement that the Company be able to incur additional unsecured indebtedness.
As a result, the Company was not able to pay cash dividends on its 7% cumulative
convertible preferred stock on February 1, 1999, May 1, 1999, or August 1, 1999.
As of June 30, 1999, the
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cumulative earned but unpaid dividends on the preferred stock was $11.2 million.
Subsequent dividend payments will be subject to the same restrictions and are
dependent upon variables that are beyond the Company's ability to predict. If
the Company fails to pay dividends for six quarterly periods, the holders of
preferred stock would be entitled to elect two additional members to the board.
None of the senior note indenture covenants apply to Chesapeake Energy
Marketing, Inc. ("CEMI"), an unrestricted subsidiary of the Company. The
Company's Board of Directors has authorized CEMI to purchase up to $10 million
of the Company's senior notes and preferred stock in open market transactions or
otherwise. In April 1999, CEMI purchased 3,600 shares of preferred stock for an
aggregate purchase price of $53,000, or $14.63 per share, in an open market
transaction. On April 22, 1999, CEMI commenced an offer to purchase up to
666,667 shares of preferred stock at $15.00 per share ($10 million in the
aggregate, plus fees and expenses). The offer expired May 20, 1999 and no shares
of preferred stock were acquired pursuant to the offer to purchase.
Debt ratings for the senior notes are B3 by Moody's Investors Service and B by
Standard & Poor's Corporation as of August 12, 1999, and both rating agencies
have had the Company on review with negative implications since December 1998.
There are no scheduled principal payments required on any of the Company's
senior notes until March 2004, when $150.0 million is due.
The Company believes it has adequate resources, including cash on hand, budgeted
cash flow from operations and proceeds from miscellaneous asset sales, to fund
its exploration and development capital expenditure budget for 1999, which is
currently estimated to be approximately $120 million. The Company anticipates
proceeds from miscellaneous asset sales will be approximately $50 million during
1999. However, lower oil and gas prices or unfavorable drilling results could
cause the Company to alter its drilling program, or the amount of anticipated
property acquisitions and/or asset sales.
The Company's cash provided by operating activities before changes in current
assets and liabilities decreased 25% to $48.1 million during the Current Period
compared to $63.8 million during the Prior Period. The decrease was due
primarily to reduced operating income as a result of a decrease in gas prices
between periods.
Cash used in investing activities decreased to $67.4 million during the Current
Period from $471.7 million in the Prior Period. The Company completed several
acquisitions requiring cash in the Prior Period which totaled $345.0 million,
compared to $6.4 million in the Current Period, and significantly decreased its
drilling activity and leasehold acquisitions in the Current Period compared to
the Prior Period. During the Current Period, the Company expended approximately
$68.3 million to initiate drilling on 80 gross (48.9 net) wells and invested
approximately $11.1 million in leasehold acquisitions. This compares to $112.0
million to initiate drilling on 91 gross (82.0 net) wells and $8.4 million to
purchase leasehold in the Prior Period.
Cash provided by financing activities was $14.2 million in the Current Period,
compared to $389.6 million in the Prior Period. During the Current Period, the
Company expanded its borrowings under its commercial bank facility by $14.0
million. During the Prior Period, the Company retired $465.0 million in debt
consisting of $85.0 million in debt assumed at the completion of the DLB
acquisition, $120.0 million in debt assumed at the completion of the Hugoton
acquisition, $90.0 million in senior notes, and $170.0 million in borrowings
made under its commercial bank credit facilities. Also during the Prior Period,
the Company issued $500.0 million in senior notes and $230.0 million in
preferred stock.
YEAR 2000
Project. The Company has placed a high priority on proactively resolving
computer or embedded chip problems related to the "Year 2000" problem which may
have adverse material effects on its continuing operations or cash flow. These
problems would be caused by the inability of a component (software, hardware or
equipment with embedded microprocessors) to correctly process date data in and
between the 20th and 21st centuries and therefore fail to properly perform its
intended functions, and/or to exchange correct date data with other components.
This problem would most typically be caused by erroneous date calculations,
which results from using two digits to signify a year (century implied),
handling leap years incorrectly or the use of "special" values that can be
confused with legitimate calendar dates. The scope of the Year 2000 project
includes conducting an inventory of the
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Company's software, hardware and "embedded systems" equipment, assessing
potential for failure and the associated risk, prioritizing the need for
remedial actions, identifying an appropriate action, then implementing and
testing. In addition, the Company will take a similar approach to mitigating
risks associated with the Year 2000 readiness of material business partners
(vendors, suppliers, customers, etc.). The project will also identify
contingency plans to cope with unexpected events resulting from Year 2000
issues.
Beginning in mid-1997, the Company began an assessment of its core financial and
operational software systems. Three critical systems were identified with date
sensitivities: oil and gas financial accounting, production accounting, and
land/lease administration. A Year 2000 compliant release of the oil and gas
financial accounting package used by the Company is available and has been
scheduled for implementation during the third quarter of 1999. The Year 2000
ready version of the production accounting system was successfully implemented
during June 1999. The timing of remaining upgrades has been scheduled to be
concurrent with the respective vendors' support requirements and to take
advantage of additional features or performance enhancements. A project has been
underway since early 1997 to implement a completely revamped version of the
land/lease administration package in use at the Company to provide significantly
increased functionality and reliability. The terms of this development
arrangement stipulated Year 2000 compliance. Preliminary versions of the system
have been installed and are being tested. As part of the testing, Year 2000
compliance will be assured. Final conversion of all users to the new release is
scheduled to be complete in late October 1999.
All hardware has been verified Year 2000 ready with the exception of a few items
that support various legacy functions. These functions are scheduled to be
retired before year-end and the associated hardware will also be retired.
Other activities either already underway or scheduled, include assessment of
material business partners, and inventory of embedded systems in field
locations. The following table summarizes the current overall status of the
project with anticipated completion dates:
PHASE
------------------------------------------------------
ASSESSMENT/ REMEDIATION/
COMPONENT INVENTORY PRIORITIZATION CONTINGENCY
--------------------------------- ----------- -------------- --------------
Software Completed Completed November 1999
Hardware Completed Completed Completed
Business partners Completed August 1999 August 1999
Embedded systems (non-IT systems) August 1999 August 1999 September 1999
The following schedule changes were made in the Current Quarter:
o Changes in the Software Remediation schedule were due to delays in the
delivery of vendor products. Contingency plans to guard against
further delays have been put in place.
o Business Partner assessment was deferred pending availability of
critical personnel. Personnel have now been assigned and priority
adjusted to recover the original schedule.
In addition to the above, during the third quarter of 1999 the Company will
develop an overall contingency plan to assure continued operations which will
include precautionary measures. Specific elements of this plan have been
identified and developed.
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Cost. To date, the Company has incurred minimal consulting costs for Year 2000
project planning and scope definition. Expenses to date have totaled $65,000,
composed of $39,000 software and $26,000 consulting. For currently identified
software systems requiring a Year 2000 upgrade, the vendor is providing that
upgrade under the terms of existing maintenance agreements, and thus no
additional license or upgrade fees are required. In all cases these upgrades had
been previously scheduled to maintain desired vendor support. No upgrade project
schedule has been accelerated to achieve Year 2000 compliance, nor has any
project been deferred because of Year 2000 concerns or efforts. An accurate cost
cannot be determined prior to conclusion of the Assessment/Prioritization phase,
but it is expected total project expenditures, including the use of outside
consultants, should not exceed $1 million. This does not include any costs which
may be assessed by joint venture partners on properties not operated by the
Company.
Risks/Contingency. The failure to remediate critical systems (software, hardware
or embedded systems), or the failure of a material business partner to resolve
critical Year 2000 issues could have serious adverse impact on the ability of
the Company to continue operations and meet obligations. At the current time, it
is believed that any interruption in operation will be minor and short-lived and
will pose no safety or environmental risks. However, until all assessment phases
have been completed it is impossible to accurately identify the risks, quantify
potential impacts or establish a contingency plan. The Company has not yet
clearly identified the most reasonably likely worst case scenario if the Company
and material business partners do not achieve Year 2000 compliance on a timely
basis. The Company currently intends to complete its contingency planning by
November 30, 1999 with testing and training to take place early in the fourth
quarter.
RECENTLY ISSUED ACCOUNTING STANDARDS
On June 15, 1998, the Financial Accounting Standards Board issued FAS No. 133,
Accounting for Derivative Instruments and Hedging Activities ("FAS 133"). FAS
133 establishes a new model for accounting for derivatives and hedging
activities and supersedes and amends a number of existing standards. FAS 133
(as amended by FAS 137) is effective for all fiscal quarters of fiscal years
beginning after June 15, 2000.
FAS 133 standardizes the accounting for derivative instruments by requiring that
all derivatives be recognized as assets and liabilities and measured at fair
value. The accounting for changes in the fair value of derivatives (gains and
losses) depends on whether the derivative is designated and qualifies as a
hedge, and the type of hedging relationship that exists. Changes in the fair
value of derivatives that are not designated as hedges or that do not meet the
hedge accounting criteria in FAS 133 are required to be reported in earnings. In
addition, all hedging relationships must be designated, reassessed and
documented pursuant to the provisions of FAS 133. The Company has not yet
determined the impact that adoption of FAS 133 will have on the financial
statements.
FORWARD LOOKING STATEMENTS
This Form 10-Q 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. All statements other than statements of historical facts
included in this Form 10-Q, including, without limitation, statements regarding
oil and gas reserve estimates, planned capital expenditures, expected oil and
gas production, the Company's financial position, business strategy and other
plans and objectives for future operations, expected future expenses,
realization of deferred tax assets, and Year 2000 compliance efforts, are
forward-looking statements. Although the Company believes that the expectations
reflected in such forward-looking statements are reasonable, it can give no
assurance that such expectations will prove to have been correct. Factors that
could cause actual results to differ materially from those expected by the
Company, including, without limitation, factors discussed under Risk Factors in
the Company's Form 10-K for the year ended December 31, 1998, are substantial
indebtedness, impairment of asset value, need to replace reserves, substantial
capital requirements, ability to supplement capital resources with asset sales,
fluctuations in the prices of oil and gas, uncertainties inherent in estimating
quantities of oil and gas reserves, projecting future rates of production and
the timing of development expenditures, competition, operating risks, risks
associated with foreign operations, restrictions imposed by lenders, liquidity
and capital requirements, the effects of governmental and environmental
regulation, pending patent, securities and lease cancellation litigation,
adverse changes in the market for the Company's oil and gas production and the
Company's ability to successfully address Year 2000 issues. Readers are
cautioned not to place undue reliance on these forward-looking statements, which
speak only as of the
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date hereof. The Company undertakes no obligation to release publicly the result
of any revisions to these forward-looking statements that may be made to reflect
events or circumstances after the date hereof, including, without limitation,
changes in the Company's business strategy or planned capital expenditures, or
to reflect the occurrence of unanticipated events.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
COMMODITY PRICE RISK
Periodically the Company utilizes hedging strategies to hedge the price of a
portion of its future oil and gas production. These strategies include (i) swap
arrangements that establish an index-related price above which the Company pays
the counterparty and below which the Company is paid by the counterparty, (ii)
the purchase of index-related puts that provide for a "floor" price below which
the counterparty pays the Company the amount by which the price of the commodity
is below the contracted floor, (iii) the sale of index-related calls that
provide for a "ceiling" price above which the Company pays the counterparty the
amount by which the price of the commodity is above the contracted ceiling, and
(iv) basis protection swaps, which are arrangements that guarantee the price
differential of oil or gas from a specified delivery point or points. Results
from hedging transactions are reflected in oil and gas sales to the extent
related to the Company's oil and gas production. The Company only enters into
hedging transactions related to the Company's oil and gas production volumes or
physical purchase or sale commitments of its oil and gas marketing subsidiary.
Gains or losses on crude oil and natural gas hedging transactions are recognized
as price adjustments in the months of related production.
Prior to June 30, 1999, the Company entered into and closed transactions
designed to hedge a portion of the Company's domestic oil and gas production.
The net unrecognized gains resulting from these transactions, $0.6 million, will
be recognized as price adjustments in the months of related production. These
hedging gains and losses are set forth below ($ in 000's):
HEDGING GAINS (LOSSES)
----------------------------------
MONTH GAS OIL TOTAL
------------------- ------- -------- -------
July 1999.......... 210 (73) 137
August 1999........ 180 (73) 107
September 1999..... 144 (70) 74
October 1999....... 421 (72) 349
November 1999...... 102 (69) 33
December 1999...... -- (71) (71)
------- -------- -------
$ 1,057 $ (428) $ 629
======= ======== =======
Subsequent to June 30, 1999, the Company entered into the following natural gas
swap arrangements designed to hedge a portion of the Company's domestic gas
production.
MONTHLY NYMEX-INDEX
VOLUME STRIKE PRICE
MONTHS (MMBTU) (PER MMBTU)
------------------- ------- ------------
April 2000................. 600,000 $ 2.41
May 2000................... 620,000 $ 2.41
June 2000.................. 600,000 $ 2.41
July 2000.................. 620,000 $ 2.41
August 2000................ 620,000 $ 2.41
September 2000............. 600,000 $ 2.41
October 2000............... 620,000 $ 2.41
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Subsequent to June 30, 1999, the Company entered into the following crude oil
collar transactions related to its domestic oil production:
VOLUME NYMEX-DEFINED NYMEX-DEFINED
MONTHS (BBLS) HIGH STRIKE PRICE LOW STRIKE PRICE
--------------------------- ------- ----------------- ----------------
July 1999.................. 155,000 $ 19.710 $ 17.50
August 1999................ 310,000 $ 20.255 $ 17.75
September 1999............. 300,000 $ 20.255 $ 17.75
October 1999............... 310,000 $ 20.255 $ 17.75
November 1999.............. 300,000 $ 20.255 $ 17.75
December 1999.............. 310,000 $ 20.255 $ 17.75
January 2000............... 310,000 $ 20.255 $ 17.75
February 2000.............. 290,000 $ 20.255 $ 17.75
March 2000................. 310,000 $ 20.255 $ 17.75
April 2000................. 300,000 $ 20.255 $ 17.75
May 2000................... 310,000 $ 20.255 $ 17.75
June 2000.................. 300,000 $ 20.255 $ 17.75
July 2000.................. 155,000 $ 20.800 $ 18.00
As of June 30, 1999, the Company had the following natural gas swap arrangement
designed to hedge a portion of the Company's Canadian gas production for periods
after June 1999:
INDEX STRIKE PRICE
VOLUME (PER MMBTU)
MONTHS (MMBTU) (IN US $)
------------------------------ ------- ------------------
July 1999..................... 589,000 $1.60
If the Canadian gas swap arrangement listed above had been settled on June 30,
1999, the Company would have incurred a loss of $0.2 million. Prior to June 30,
1999 the Company also entered into additional transactions designed to hedge a
portion of the Company's Canadian gas production during August through September
1999. Such transactions were closed in May 1999. The net loss resulting from
these transactions of $0.6 million (in US $) will be recognized as price
adjustments in the months of related production.
In addition to commodity hedging transactions related to the Company's oil and
gas production, CEMI periodically enters into various hedging transactions
designed to hedge against physical purchase commitments made by CEMI. Gains or
losses on these transactions are recorded as adjustments to Oil and Gas
Marketing Sales in the consolidated statements of operations and are not
considered by management to be material.
INTEREST RATE RISK
The Company also utilizes hedging strategies to manage fixed-interest rate
exposure. Through the use of a swap arrangement, the Company believes it can
benefit from stable or falling interest rates and reduce its current interest
expense. During the Current Quarter, the Company's interest rate swap resulted
in a $0.6 million reduction of interest expense.
The table below presents principal cash flows and related weighted average
interest rates by expected maturity dates. As of June 30, 1999, the carrying
amounts of short-term borrowings are representative of fair values because of
the short-term maturity of these instruments. The fair value of the long-term
debt has been estimated based on quoted market prices.
JUNE 30, 1999
----------------------------------------------------------------------------------------
YEAR OF MATURITY
---------------------------------------------------------------------------------------
1999 2000 2001 2002 2003 THEREAFTER TOTAL FAIR VALUE
-------- -------- -------- -------- -------- ---------- ----- ----------
LIABILITIES: ($ IN MILLIONS)
Long-term debt - variable rate $ -- $ -- $ 39 $ -- $ -- $ -- $ 39 $ 39
Average interest rate............ -- -- 7.75% -- -- -- -- --
Long-term debt, including current
portion - fixed rate............. $ -- $ -- $ -- $ -- $ -- $ 920 $ 920 $ 816
Average interest rate............ -- -- -- -- -- 9.1% -- --
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PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The Company is subject to ordinary routine litigation incidental to its
business. In addition, the Company and certain of its officers and directors are
defendants in pending actions which are described in Item 3 of the Company's
annual report on Form 10-K for the year ended December 31, 1998. Subsequent
developments are as follows:
Union Pacific Resources Company v. Chesapeake Energy Corporation, et al., U.S.
District Court for the Northern District of Texas, Fort Worth Division, was
tried to the Court in June 1999. The issues were limited to the validity of a
UPRC patent and the Company's alleged infringement of the patent. No ruling has
been issued yet. If necessary, a trial on damages will be scheduled after the
ruling. UPRC originally filed the case against the Company in October 1996.
UPRC's claims are based on services provided to the Company by a third party
vendor controlled by former UPRC employees. UPRC is seeking damages of an
unspecified amount, including actual, enhanced, consequential and punitive
damages, interest, costs and attorneys' fees.
West Panhandle Field Cessation Cases. A subsidiary of the Company, Chesapeake
Panhandle Limited Partnership ("CP") (f/k/a MC Panhandle, Inc.), Natural Gas
Pipeline Company of America ("NGPL") and MidCon Gas Services, Inc. are
defendants in thirteen lawsuits filed in 1997 and 1998 by royalty owners seeking
the cancellation of oil and gas leases in the West Panhandle Field in Texas. The
Company acquired MC Panhandle, Inc. on April 30, 1998. MC Panhandle, Inc. has
owned the leases since January 1, 1997. Plaintiffs claim the leases terminated
upon the cessation of production for various periods between 1926 and 1997
and/or for failure to produce in paying quantities. Plaintiffs also seek to
recover conversion damages in an amount equal to 7/8 of gross production for the
period beginning two years prior to the filing of each suit through the time of
trial, plus attorneys' fees and interest, as well as exemplary damages.
Plaintiffs assert that NGPL, which was a prior lessee, knew that the leases had
terminated and that, therefore, defendants are bad faith trespassers and not
entitled (in the event of an adverse judgment) to recover the value of
improvements or operating costs. In the alternative, plaintiffs seek damages for
the breach of implied covenants of the leases, i.e., for failure to protect
against drainage, to maximize production, and to reasonably develop and market.
Defendants assert that any cessation of production was excused by their timely
commencement of operations to restore production and assert affirmative defenses
of limitations, waiver, estoppel, laches and title by adverse possession under
3, 5, 10 and 25-year statutes of adverse possession.
Following are the cases pending in the District Court of Moore County, Texas,
69th Judicial District:
o Lois Law, et al. v. NGPL, et al., No. 97-70, filed December 22, 1997, jury
trial in June 1999, verdict for defendants
o A.C. Smith, et al. v. NGPL, et al., No. 98-47, first filed January 26, 1998
and refiled May 29, 1998, notice given that summary judgment terminating
leases will be entered
o Joseph H. Pool, et al. v. NGPL, et al.,
No. 98-30, first filed December 17, 1997 and refiled May 11, 1998,
jury trial in June 1999, verdict for defendants
No. 98-36, first filed February 2, 1998 and refiled May 20, 1998, jury
trial in July 1999, verdict for plaintiffs
No. 98-35, first filed February 2, 1998 and refiled May 20, 1998
No. 98-49, first filed March 10, 1998 refiled May 29, 1998
No. 98-50, first filed March 18, 1998 and refiled May 29, 1998
No. 98-51, first filed December 2, 1997 and refiled May 29, 1998
No. 98-48, first filed February 2, 1998 and refiled May 29, 1998
No. 98-70, first filed March 23, 1998 and refiled October 22, 1998
The Pool cases listed above were first filed in the U.S. District Court,
Northern District of Texas, Amarillo Division. Other related cases pending are
the following:
o Phillip Thompson, et al. v. NGPL, et al, U.S. District Court, Northern
District of Texas, Amarillo Division, Nos. CV-012 and CV-106, filed January
8, 1998 and March 18, 1998, respectively (actions consolidated), jury trial
in May 1999, verdict for defendants
26
27
o Craig Fuller, et al. v. NGPL, et al., District Court of Carson County,
Texas, 100th Judicial District, No. 8456, filed June 23, 1997, cross
motions for summary judgment pending
o Ralph W. Coon, et al. v. MC Panhandle, Inc., et al., U.S. District Court,
Eastern District of Texas, Lufkin Division, No. 2:98-CV-63, filed March 27,
1998
Four of the cases listed above were tried in May, June and July 1999. Three
resulted in verdicts in favor of CP and the other defendants (Thompson, Law and
Pool No. 98-30), and one, Pool No. 98-36, resulted in a verdict against them.
The juries which found for defendants determined that the plaintiff's
termination claims were barred by laches, adverse possession and (in two cases)
revivor. The jury in Pool No. 98-36 found that the defendants were bad-faith
trespassers and produced gas from the leases as a result of fraud. The jury
assessed $1.2 million in exemplary damages against CP and each of the other two
defendants and awarded plaintiffs attorneys' fees in the amount of $158,000. The
parties stipulated that the value of gas produced by defendants was $1 million
since January 1, 1996 and $1.5 million since January 1, 1994. The court will
determine which amount of actual damages, if either, should be awarded based on
the statute of limitations and other considerations. CP has filed motions for
judgment in Thompson, Law and Pool No. 98-30 and a motion for judgment
notwithstanding verdict in Pool No. 98-36. The Company intends to appeal the
decision if the latter motion is not granted. The other nine cases have not been
set for trial.
The Company has previously established an accrued liability that management
believes will be sufficient to cover the estimated costs of litigation for each
of these cases. Because of the inconsistent verdicts reached by the juries in
the four cases tried to date and because the amount of damages sought is not
specified in all of the other cases, the outcome of the remaining trials and the
amount of damages that might ultimately be awarded could differ from
management's estimates. Management believes, however, that the leases are valid,
there is no basis for exemplary damages and that any findings of fraud or bad
faith will be overturned on appeal. CP and the other defendants intend to
vigorously defend against the plaintiff's claims.
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
The Company's annual meeting of shareholders was held on June 23, 1999. In the
election of directors, Aubrey K. McClendon received 78,688,202 votes for
election, and 1,455,980 shares were withheld from voting. Shannon T. Self
received 78,693,249 votes for election, and 1,450,933 shares were withheld from
voting. The other directors whose terms continued after the meeting are Breene
M. Kerr, Walter C. Wilson, Edgar F. Heizer, Jr. and Frederick B. Whittemore.
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:
27
28
Exhibit No.
-----------
10.1.5 Registrant's 1999 Stock Option Plan
10.2.1 First Amendment to the Amended and Restated
Employment Agreement dated as of December 31, 1998
between Aubrey K. McClendon and Chesapeake Energy
Corporation.
10.2.2 First Amendment to the Amended and Restated
Employment Agreement dated as of December 31, 1998
between Tom L. Ward and Chesapeake Energy
Corporation.
12 Computation of Ratios
27 Financial Data Schedule
(b) Reports on Form 8-K
During the quarter ended June 30, 1999, the Company filed the
following current reports on Form 8-K:
On April 1, 1999, the Company filed a current report on Form 8-K
reporting under Item 5 that the Board of Directors approved the
repurchase of up to $10 million of the Company's senior notes and/or
its convertible preferred stock.
On May 5, 1999, the Company filed a current report on Form 8-K
reporting under Item 5 that the Company issued a press release
announcing the first quarter 1999 results.
28
29
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)
August 16, 1999 /s/ Aubrey K. McClendon
- --------------- ---------------------------------------
Date Aubrey K. McClendon
Chairman and
Chief Executive Officer
August 16, 1999 /s/ Marcus C. Rowland
- --------------- ---------------------------------------
Date Marcus C. Rowland
Executive Vice President and
Chief Financial Officer
29
30
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
10.1.5 Registrant's 1999 Stock Option Plan
10.2.1 First Amendment to the Amended and Restated Employment
Agreement dated as of December 31, 1998 between Aubrey K.
McClendon and Chesapeake Energy Corporation.
10.2.2 First Amendment to the Amended and Restated Employment
Agreement dated as of December 31, 1998 between Tom L. Ward
and Chesapeake Energy Corporation.
12 Computation of Ratios
27 Financial Data Schedule