<PAGE> 1
- --------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the Fiscal Year Ended December 31, 1998
[ ] Transition Report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
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
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
-------------------------------------------- -------------------------
<S> <C>
Common Stock, par value $.01 New York Stock Exchange
7.875% Senior Notes due 2004 New York Stock Exchange
9.625% Senior Notes due 2005 New York Stock Exchange
9.125% Senior Notes due 2006 New York Stock Exchange
8.5% Senior Notes due 2012 New York Stock Exchange
7% Cumulative Convertible Preferred Stock, par value $.01 New York Stock Exchange
</TABLE>
Securities registered pursuant to Section 12(g) of the Act:
NONE
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 [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of Common Stock held by non-affiliates on March
26, 1999 was $103,439,199. At such date, there were 96,720,308 shares of Common
Stock issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
PORTIONS OF THE REGISTRANT'S DEFINITIVE PROXY STATEMENT FOR THE 1999
ANNUAL MEETING OF SHAREHOLDERS ARE INCORPORATED BY REFERENCE IN PART III
- --------------------------------------------------------------------------------
<PAGE> 2
PART I
ITEM 1. BUSINESS
GENERAL
Chesapeake Energy Corporation ("Chesapeake" or the "Company") is an
independent oil and gas company primarily engaged in the exploration,
acquisition, development and production of onshore natural gas reserves in the
United States and Canada. Chesapeake began operations in 1989, completed an
initial public offering in 1993, and trades on the New York Stock Exchange under
the symbol CHK. The Company's principal offices are located at 6100 North
Western Avenue, Oklahoma City, Oklahoma 73118 (telephone 405/848-8000).
Chesapeake currently owns interests in approximately 5,300 producing oil and
gas wells concentrated in three primary operating areas: the Mid-Continent
region consisting of Oklahoma, southwestern Kansas and the Texas Panhandle; the
Gulf Coast region consisting primarily of the Austin Chalk Trend in Texas and
Louisiana and the Tuscaloosa Trend in Louisiana; and the Helmet area of
northeastern British Columbia. During 1998 the Company produced 130.3 Bcfe, of
which 72% was natural gas, making Chesapeake one of the top 20 public
independent oil and gas companies in the United States as measured by
production.
The following table sets forth the Company's estimated proved reserves, the
related present value (discounted at 10%) of the proved reserves (based on
weighted average prices at December 31, 1998 of $10.48 per barrel of oil and
$1.68 per Mcf of gas), and the estimated capital expenditures required to
develop the Company's proved undeveloped reserves at December 31, 1998:
<TABLE>
<CAPTION>
ESTIMATED
PERCENT PRESENT CAPEX TO
GAS OF VALUE DEVELOP
OIL GAS EQUIVALENT PROVED (DISC. @10%) PUD'S
(MBBL) (MMCF) (MMCFE) RESERVES ($ IN 000'S) ($ IN 000'S)
------------ ------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
Mid-Continent ........... 11,009 558,754 624,811 57% $ 347,937 $ 72,398
Canada .................. 33 231,773 231,969 21 156,843 28,298
Gulf Coast .............. 3,836 128,419 151,434 14 111,135 34,120
Other areas ............. 7,715 36,845 83,134 8 45,076 9,674
------------ ------------ ------------ ------------ ------------ ------------
Total ............... 22,593 955,791 1,091,348 100% $ 660,991 $ 144,490
============ ============ ============ ============ ============ ============
</TABLE>
From inception through mid-1997, Chesapeake's primary business strategy was
growth through the drillbit. In 1997, however, disappointing drilling results in
the Louisiana Austin Chalk Trend, combined with the industry's rapidly
escalating drilling costs and falling oil prices, caused management to change
the Company's business strategy. As a result of this change, in late 1997 and
1998 the Company significantly reduced its capital expenditures for exploration
drilling and acreage acquisition and focused on the acquisition of long-lived
natural gas properties in the Mid-Continent and Canada that contain numerous low
risk development opportunities. During 1998, the Company acquired approximately
750 Bcfe primarily in eight separate transactions. The total consideration given
for the acquisitions was 30.8 million shares of Company common stock, $280
million in cash, the assumption of $205 million in debt, and the incurrence of
approximately $20 million of other acquisition related costs.
The oil and gas industry is characterized by volatile product prices. During
late 1998, inflation-adjusted prices for oil reached lows not seen in 50 years.
Also, a second consecutive mild winter and the resulting high inventory of
natural gas in storage have caused gas prices to fall. These low oil and gas
prices, combined with the Company's high level of indebtedness, have caused the
Company to focus on decreasing operating and general and administrative costs
and reducing drilling capital expenditures to a level that can be financed from
operating cash flow, including proceeds from the sale of non-core, low-value oil
properties. The Company's strategy for 1999 is to maintain appropriate liquidity
levels while concentrating on further developing its core natural gas assets.
2
<PAGE> 3
DRILLING ACTIVITY
The following table sets forth the wells drilled by the Company during the
periods indicated. In the table, "gross" refers to the total wells in which the
Company has a working interest and "net" refers to gross wells multiplied by the
Company's working interest therein.
<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED ENDED YEAR ENDED JUNE 30,
DECEMBER 31, DECEMBER 31, -----------------------------------------
1998 1997 1997 1996
------------------- ------------------- ------------------- -------------------
GROSS NET GROSS NET GROSS NET GROSS NET
-------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Development:
Productive .......... 169 97.5 55 24.4 90 55.0 111 49.5
Non-productive ...... 10 5.1 1 0.3 2 0.2 4 1.6
-------- -------- -------- -------- -------- -------- -------- --------
Total ............... 179 102.6 56 24.7 92 55.2 115 51.1
======== ======== ======== ======== ======== ======== ======== ========
Exploratory:
Productive .......... 47 23.7 28 15.5 71 46.1 29 16.5
Non-productive ...... 16 8.9 2 0.9 8 5.7 4 1.4
-------- -------- -------- -------- -------- -------- -------- --------
Total ............... 63 32.6 30 16.4 79 51.8 33 17.9
======== ======== ======== ======== ======== ======== ======== ========
</TABLE>
Included in the above table for 1998, the Company drilled 11 (3.6 net)
productive development wells and one (.4 net) non-productive development wells
in Canada. Also during 1998, the Company drilled one (.3 net) productive
exploratory wells and seven (2.1 net) non-productive exploratory wells in
Canada.
WELL DATA
At December 31, 1998, the Company had interests in 5,304 (2,405 net)
producing wells, of which 219 (96 net) were classified as primarily oil
producing wells and 5,085 (2,309 net) were classified as primarily gas producing
wells.
VOLUMES, REVENUE, PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the production
volumes, revenue, average prices received and average production costs
associated with the Company's sale of oil and gas for the periods indicated:
<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED ENDED YEAR ENDED JUNE 30,
DECEMBER 31, DECEMBER 31, -------------------------------
1998 1997 1997 1996
-------------- -------------- -------------- --------------
<S> <C> <C> <C> <C>
NET PRODUCTION:
Oil (MBbl) .................................. 5,976 1,857 2,770 1,413
Gas (MMcf) .................................. 94,421 27,326 62,005 51,710
Gas equivalent (MMcfe) ...................... 130,277 38,468 78,625 60,190
OIL AND GAS SALES ($ IN 000'S):
Oil ......................................... $ 75,877 $ 34,523 $ 57,974 $ 25,224
Gas ......................................... 181,010 61,134 134,946 85,625
-------------- -------------- -------------- --------------
Total oil and gas sales ............. $ 256,887 $ 95,657 $ 192,920 $ 110,849
============== ============== ============== ==============
AVERAGE SALES PRICE:
Oil ($ per Bbl) ............................. $ 12.70 $ 18.59 $ 20.93 $ 17.85
Gas ($ per Mcf) ............................. $ 1.92 $ 2.24 $ 2.18 $ 1.66
Gas equivalent ($ per Mcfe) ................. $ 1.97 $ 2.49 $ 2.45 $ 1.84
OIL AND GAS COSTS ($ PER Mcfe):
Production expenses and taxes ............... $ .45 $ .27 $ .19 $ .14
General and administrative .................. $ .15 $ .15 $ .11 $ .08
Depreciation, depletion and amortization of oil
and gas properties....................... $ 1.13 $ 1.57 $ 1.31 $ .85
</TABLE>
Included in the above table are the results of Canadian operations during
1998. The average sales price for the Company's Canadian gas production was
$1.03 during 1998 and the Canadian production expenses and taxes were $0.24 per
Mcf.
3
<PAGE> 4
DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES
The following table sets forth certain information regarding the costs
incurred by the Company in its development, exploration and acquisition
activities during the periods indicated:
<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED ENDED YEAR ENDED JUNE 30,
DECEMBER 31, DECEMBER 31, ----------------------------
1998 1997 1997 1996
------------- ------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C> <C>
Development costs ................................ $ 150,537 $ 120,628 $ 187,736 $ 138,188
Exploration costs ................................ 68,672 40,534 136,473 39,410
Acquisition costs:
Unproved properties ............................ 26,369 25,516 140,348 138,188
Proved properties .............................. 740,280 39,245 -- 24,560
Sales of oil and gas properties .................. (15,712) -- -- --
Capitalized internal costs ....................... 5,262 2,435 3,905 1,699
Proceeds from sale of leasehold, equipment and
other .......................................... (296) (1,861) (3,095) (6,167)
------------- ------------ ------------ ------------
Total .................................. $ 975,112 $ 226,497 $ 465,367 $ 335,878
============= ============ ============ ============
</TABLE>
ACREAGE
The following table sets forth as of December 31, 1998 the gross and net
acres of both developed and undeveloped oil and gas leases which the Company
holds. "Gross" acres are the total number of acres in which the Company owns a
working interest. "Net" acres refer to gross acres multiplied by the Company's
fractional working interest. Acreage numbers are stated in thousands and do not
include options for additional leasehold held by the Company, but not yet
exercised.
<TABLE>
<CAPTION>
TOTAL DEVELOPED
DEVELOPED UNDEVELOPED AND UNDEVELOPED
------------------- ------------------- -------------------
GROSS NET GROSS NET GROSS NET
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Mid-Continent ......... 1,576 621 835 304 2,411 925
Gulf Coast ............ 451 280 1,333 1,084 1,784 1,364
Canada ................ 82 32 569 233 651 265
Other areas ........... 60 30 1,134 683 1,194 713
-------- -------- -------- -------- -------- --------
Total ....... 2,169 963 3,871 2,304 6,040 3,267
======== ======== ======== ======== ======== ========
</TABLE>
MARKETING
The Company's oil production is sold under market sensitive or spot price
contracts. The Company's natural gas production is sold to purchasers under
varying percentage-of-proceeds and percentage-of-index contracts. By the terms
of these contracts, the Company receives a percentage of the resale price
received by the purchaser for sales of residue gas and natural gas liquids
recovered after gathering and processing the Company's gas. The residue gas and
natural gas liquids sold by these purchasers are sold primarily based on spot
market prices. The revenue received by the Company from the sale of natural gas
liquids is included in natural gas sales. During 1998, the following two
customers individually accounted for 10% or more of the Company's total oil and
gas sales:
<TABLE>
<CAPTION>
PERCENT OF OIL
AMOUNT AND GAS
($ IN THOUSANDS) SALES
---------------- --------------
<S> <C> <C>
Koch Oil Company............................................................. $ 30,564 12%
Aquila Southwest Pipeline Corporation........................................ $ 28,946 11%
</TABLE>
Management believes that the loss of either of the above customers would not
have a material adverse effect on the Company's results of operations or its
financial position.
Chesapeake Energy Marketing, Inc. ("CEMI"), a wholly-owned subsidiary,
provides oil and natural gas marketing services, including commodity price
structuring, contract administration and nomination services for the Company,
its partners and other oil and natural gas producers in geographical areas in
which the Company is active.
4
<PAGE> 5
HEDGING ACTIVITIES
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 commodity 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 commodity hedging transactions related to the Company's oil and gas
production volumes or CEMI's physical purchase or sale commitments. Gains or
losses on crude oil and natural gas hedging transactions are recognized as price
adjustments in the months of related production.
As of December 31, 1998, the Company had the following natural gas swap
arrangements designed to hedge a portion of the Company's domestic gas
production for periods after December 1998:
<TABLE>
<CAPTION>
NYMEX-INDEX
VOLUME STRIKE PRICE
MONTHS (MMBTU) (PER MMBTU)
- ------ ------------- -------------
<S> <C> <C>
February 1999.................................................................... 4,300,000 $1.968
March 1999....................................................................... 4,600,000 1.968
April 1999....................................................................... 4,500,000 1.968
May 1999......................................................................... 4,600,000 1.968
June 1999........................................................................ 1,200,000 1.950
July 1999........................................................................ 1,240,000 1.950
August 1999...................................................................... 1,240,000 1.950
September 1999................................................................... 1,200,000 1.950
</TABLE>
During 1998, the Company closed transactions for natural gas previously
hedged for the period April 1999 through November 1999 for net proceeds of $0.5
million.
Subsequent to December 31, 1998, the Company entered into additional natural
gas swap arrangements for 6,100,000 MMBtu at a strike price of $1.875 for the
period from June 1999 through September 1999. Such swap arrangements, along with
those listed above and other miscellaneous transactions, were closed as of March
15, 1999, resulting in net proceeds of $4.7 million.
As of December 31, 1998, the Company had the following natural gas swap
arrangements designed to hedge a portion of the Company's Canadian gas
production for periods after December 1998:
<TABLE>
<CAPTION>
INDEX-STRIKE
VOLUME PRICE
MONTHS (MMBTU) (PER MMBTU)
- ------ ------------- -------------
<S> <C> <C>
January 1999..................................................................... 589,000 $1.60
February 1999.................................................................... 532,000 1.60
March 1999....................................................................... 589,000 1.60
April 1999....................................................................... 570,000 1.60
May 1999......................................................................... 589,000 1.60
June 1999........................................................................ 570,000 1.60
July 1999........................................................................ 589,000 1.60
August 1999...................................................................... 589,000 1.60
September 1999................................................................... 570,000 1.60
</TABLE>
If the swap arrangements listed above had been settled on December 31, 1998,
the Company would have incurred a loss of $0.8 million.
5
<PAGE> 6
As of December 31, 1998, the Company had the following oil swap arrangements
for periods after December 1998:
<TABLE>
<CAPTION>
NYMEX HEATING OIL
MINUS
MONTHLY NYMEX CRUDE OIL
VOLUME INDEX STRIKE PRICE
MONTHS (BBLS) (PER BBL)
- ------ --------------- ----------------
<S> <C> <C>
January 1999............................................................. 217,000 $ 2.957
February 1999............................................................ 196,000 2.957
March 1999............................................................... 155,000 2.900
</TABLE>
If the swap arrangements listed above had been settled on December 31, 1998,
the Company would have incurred a loss of $0.2 million. Subsequent to December
31, 1998, the Company settled the swap arrangements listed above for the periods
of January 1999 and February 1999 resulting in a $0.4 million loss.
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 and sale commitments made by CEMI.
Gains or losses on these transactions are recorded as adjustments to oil and gas
marketing sales in the consolidated statements of operations and are not
considered by management to be material.
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. For the year ended December 31, 1998, the Company's interest rate swap
resulted in a $0.7 million reduction of interest expense.
RISK FACTORS
Substantial Debt Levels Could Affect Operations.
As of December 31, 1998, we had long-term indebtedness of $920 million and
short-term bank indebtedness of $25 million. Additionally, the Company had a
working capital deficit of $13 million and stockholders' equity was a deficit of
$249 million. Our ability to meet our debt service requirements throughout the
life of the senior notes and our ability to meet our preferred stock obligations
will depend on our future performance, which will be subject to oil and gas
prices, our production levels of oil and gas, general economic conditions, and
financial, business and other factors affecting our operations. Our level of
indebtedness may have the following effects on our future operations:
o a substantial portion of our cash flow from operations may be
dedicated to the payment of interest on indebtedness and will
not be available for other purposes,
o restrictions in our debt instruments limit our ability to
borrow additional funds or to dispose of assets and may affect
our flexibility in planning for, and reacting to, changes in
the energy industry, and
o our ability to obtain additional capital in the future may be
impaired.
The short-term indebtedness described above was incurred under our commercial
bank facility which matures in August 1999. Although we believe this facility
will be renewed, we can offer no assurances that we will be able to renew the
bank facility on favorable terms. As a result of our high level of indebtedness
and poor conditions in the energy industry, Standard & Poor's Corporation and
Moody's Investors Service, in late 1998, reduced the credit ratings on our
senior notes to "B" and "B3", respectively. These ratings remain under credit
review with negative implications. Low credit ratings could negatively impact
our ability to access capital markets.
6
<PAGE> 7
The Volatility of Oil and Gas Prices Creates Uncertainties.
Our revenues, operating results and future rate of growth are highly
dependent on the prices we receive for our oil and gas. Historically, the
markets for oil and gas have been volatile and may continue to be volatile in
the future. Various factors which are beyond our control will affect prices of
oil and gas. These factors include:
o worldwide and domestic supplies of oil and gas,
o the ability of the members of the Organization of Petroleum
Exporting Countries to agree to and maintain oil price and
production controls,
o political instability or armed conflict in oil-producing
regions,
o the price and level of foreign imports,
o the level of consumer demand,
o the price and availability of alternative fuels,
o the availability of pipeline capacity,
o weather conditions, and
o domestic and foreign governmental regulations and taxes.
We are unable to predict the long-term effects of these and other conditions on
the prices of oil and gas. Lower oil and gas prices may reduce the amount of oil
and gas we produce, which may adversely affect our revenues and operating
income. Because our 1999 business strategy is to generally match our capital
expenditures for drilling activities to cash flow from operations, significant
reductions in oil and gas prices may require us to reduce our capital
expenditures. Reducing drilling will make it more difficult for us to replace
the reserves we produce.
We Must Replace Reserves to Sustain Production.
As is customary in the oil and gas exploration and production industry, our
future success depends largely upon our ability to find, develop or acquire
additional oil and gas reserves that are economically recoverable. Unless we
replace the reserves we produce through successful development, exploration or
acquisition, our proved reserves will decline. Approximately 30% by volume, or
22% by value, of our total estimated proved reserves at December 31, 1998 were
undeveloped. By their nature, undeveloped reserves are less certain. Recovery of
such reserves will require significant capital expenditures and successful
drilling operations. We cannot assure that the Company can successfully find and
produce reserves economically in the future.
Significant Capital Expenditures Will be Required to Exploit Reserves.
We have made and intend to make substantial capital expenditures in
connection with the exploration, development and production of our oil and gas
properties. Historically, we have funded our capital expenditures through a
combination of internally generated funds, equity issuances and long-term debt
financing arrangements and sale of non-core assets. From time to time, we have
used short-term bank debt, generally as a working capital facility. Future cash
flows are subject to a number of variables, such as the level of production from
existing wells, prices of oil and gas, and our success in developing and
producing new reserves and in selling non-core assets. If revenue were to
decrease as a result of lower oil and gas prices or decreased production, and
our access to capital were limited, we would have a reduced ability to replace
our reserves. If our cash flow from operations is not sufficient to fund our
capital expenditure budget, there can be no assurance that additional debt or
equity financing will be available to meet these requirements.
We May Have Additional Full-Cost Ceiling Writedowns if Oil and Gas Prices
Decline Further or if Drilling Results are Unfavorable.
The Company reported full-cost ceiling writedowns of $826 million, $110
million, and $236 million during the year ended December 31, 1998, the six month
transition period ended December 31, 1997 (the "Transition Period"), and the
fiscal year ended June 30, 1997, respectively. These writedowns were caused by
significant declines in oil and gas prices during all three periods and by poor
drilling results in 1997 and during the Transition Period. Additionally,
significant declines in prices can cause proved undeveloped reserves to become
uneconomic, and long-lived production to become "economically truncated",
further reducing proved reserves and increasing any writedown. Such economic
truncation resulted in the Company's reserves being approximately 100 Bcfe less
at
7
<PAGE> 8
December 31, 1998 than they would have been using pricing in effect as of
December 31, 1997. The Company's reserve values were calculated using weighted
average prices at December 31, 1998 of $10.48 per barrel of oil and $1.68 per
Mcf of natural gas. If prices in future periods are below the prices used at
December 31, 1998, future impairment charges will likely be incurred. Although
the Company has taken steps to reduce drilling risk, reduce operating costs, and
reduce investment in unproved leasehold, these steps may not be sufficient to
enhance future economic results or prevent additional leasehold impairment and
full-cost ceiling writedowns, which are highly dependent on future oil and gas
prices.
Drilling and Oil and Gas Operations Present Unique Risks.
Drilling activities are subject to many risks, including well blowouts,
cratering, uncontrollable flows of oil, natural gas or well fluids, fires,
formations with abnormal pressures, pollution, releases of toxic gases and other
environmental hazards and risk, any of which could result in substantial losses.
In addition, we incur the risk that we will not encounter any commercially
productive reservoirs through our drilling operations. We cannot assure you that
the new wells we drill will be productive or that we will recover all or any
portion of our investment in wells drilled. Drilling for oil and gas may involve
unprofitable efforts, not only from dry wells, but from wells that are
productive but do not produce enough reserves to return a profit after drilling,
operating and other costs.
Existing Debt Covenants Restrict Our Operations.
The indentures which govern our long-term debt contain covenants which
restrict our ability, and the ability of our subsidiaries other than CEMI, to
engage in the following activities:
o incurring additional debt,
o creating liens,
o paying dividends and making other restricted payments,
o merging or consolidating with any other entity,
o selling, assigning, transferring, leasing or otherwise
disposing of all or substantially all of our assets, and
o guaranteeing any indebtedness.
At December 31, 1998, the Company did not meet a debt incurrence test
contained in two of the senior note indentures. Thus, we will be unable to incur
unsecured non-bank debt until there is significant improvement in oil and gas
prices and/or our production levels. Additionally, the Company will not be able
to resume the payment of dividends on its common and preferred stock until it
meets the debt incurrence test.
Canadian Operations Present the Risks Associated with Conducting Business
Outside the U.S.
A portion of our business is conducted in Canada. You may review the amounts
of revenue, operating losses and identifiable assets attributable to our
Canadian operations in Note 8 of the Notes to our Consolidated Financial
Statements in Item 8. Also, Note 11 of the Consolidated Financial Statements
provides disclosures about our Canadian oil and gas producing activities. Our
operations in Canada are subject to the risks associated with operating outside
of the United States. These risks include the following:
o adverse local political or economic developments,
o exchange controls,
o currency fluctuations,
o royalty and tax increases,
o retroactive tax claims,
o negotiations of contracts with governmental entities, and
o import and export regulations.
In addition, in the event of a dispute, we may be required to litigate the
dispute in Canadian courts since we may not be able to sue foreign persons in a
United States court.
8
<PAGE> 9
Pending Legal Proceedings Could Have A Material Adverse Effect.
The Company is a defendant in two purported class actions based on federal
and state securities fraud claims. In addition, we are defending claims of
patent infringement in another pending action. While no prediction can be made
as to the outcome of these matters or the amount of damages that might be
awarded, if any, an adverse result in any of them could be material to our
financial results. See Item 3. Legal Proceedings.
The Loss of Either the CEO or the COO Could Adversely Affect Operations.
Our operations are dependent upon our Chief Executive Officer, Aubrey K.
McClendon, and our Chief Operating Officer, Tom L. Ward. The unexpected loss of
the services of either of these executive officers could have a detrimental
effect on our operations. The Company maintains $20 million key man life
insurance policies on the life of each of Messrs. McClendon and Ward.
Transactions with Executive Officers May Create Conflicts of Interest.
Messrs. McClendon and Ward have rights to participate in wells we drill
during any succeeding quarter, and they participated in every well we have
drilled through December 31, 1998. As a result of their participation, they
routinely have significant accounts payable to the Company for joint interest
billings. As of December 31, 1998, Messrs. McClendon and Ward had payables to
the Company of $2.8 million and $2.4 million, respectively, in connection with
such participation. Additionally, Messrs. McClendon and Ward have loans due on
December 31, 1999 to CEMI in the principal amounts of $4.9 million and $5.0
million (as of December 31, 1998), respectively. Such loans, which were first
made in July 1998, are collateralized and carry an annual interest rate of
9.125%. As of March 30, 1999, Messrs. McClendon and Ward's loans have been
reduced to $4.3 million and $4.6 million, respectively. The existence of these
loans and the rights to participate in wells we drill could present a conflict
of interest with respect to Messrs. McClendon and Ward.
The Ownership of A Significant Percentage of Stock by Insiders Could Influence
the Outcome of Shareholder Votes.
At March 26, 1999, our Board of Directors and senior management beneficially
owned an aggregate of 27,923,997 shares of common stock (including outstanding
vested options), which represented approximately 28% of our outstanding shares.
The ownership of Messrs. McClendon and Ward and their children's trusts
accounted for 25% of the outstanding common stock. As a result, Messrs.
McClendon and Ward, together with other officers and directors of the Company,
are in a position to significantly influence matters requiring the vote or
consent of our shareholders.
The Company Could be Adversely Affected if Our Computer Systems or Those of Our
Vendors Are Not Year 2000 Compliant.
Year 2000 issues exist when dates are recorded in computers using two
digits, rather than four, and are then used for arithmetic operations,
comparisons or sorting. A two-digit recording may recognize a date using "00" as
1900 rather than 2000, which could cause our computer systems to perform
inaccurate computations. Year 2000 issues relate not only to our systems, but
also to those used by our suppliers. We anticipate that system replacements and
modifications will resolve any Year 2000 issues that may exist with our
suppliers or their suppliers. However, we cannot guarantee that such
replacements or modifications will be completed successfully or on time and, as
a result, any failure to complete such modifications on time could materially
affect our financial and operating results in a negative way. Please read the
additional discussion regarding the Year 2000 issue and the potential impact on
our business in the section entitled "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Year 2000" later in this Form
10-K for additional information.
9
<PAGE> 10
REGULATION
General
Numerous departments and agencies, federal, state and local, issue rules and
regulations binding on the oil and gas industry, some of which carry substantial
penalties for failure to comply. The regulatory burden on the oil and gas
industry increases the Company's cost of doing business and, consequently,
affects its profitability.
Exploration and Production
The Company's operations are subject to various types of regulation at the
federal, state and local levels. Such regulation includes requiring permits for
the drilling of wells, maintaining bonding requirements in order to drill or
operate wells and regulating the location of wells, the method of drilling and
casing wells, the surface use and restoration of properties upon which wells are
drilled, the plugging and abandoning of wells and the disposal of fluids used or
obtained in connection with operations. The Company's operations are also
subject to various conservation regulations. These include the regulation of the
size of drilling and spacing units and the density of wells which may be drilled
and the unitization or pooling of oil and gas properties. In this regard, some
states (such as Oklahoma) allow the forced pooling or integration of tracts to
facilitate exploration while other states (such as Texas) rely on voluntary
pooling of lands and leases. In areas where pooling is voluntary, it may be more
difficult to form units and, therefore, more difficult to develop a prospect if
the operator owns less than 100% of the leasehold. In addition, state
conservation laws establish maximum rates of production from oil and gas wells,
generally prohibit the venting or flaring of gas and impose certain requirements
regarding the ratability of production. The effect of these regulations is to
limit the amount of oil and gas the Company can produce from its wells and to
limit the number of wells or the locations at which the Company can drill. The
extent of any impact on the Company of such restrictions cannot be predicted.
Environmental and Occupational Regulation
General. The Company's activities are subject to existing federal, state and
local laws and regulations governing environmental quality and pollution
control. It is anticipated that, absent the occurrence of an extraordinary
event, compliance with existing federal, state and local laws, rules and
regulations concerning the protection of the environment and human health will
not have a material effect upon the operations, capital expenditures, earnings
or the competitive position of the Company. The Company cannot predict what
effect additional regulation or legislation, enforcement policies thereunder and
claims for damages for injuries to property, employees, other persons and the
environment resulting from the Company's operations could have on its
activities.
Activities of the Company with respect to the exploration, development and
production of oil and natural gas are subject to stringent environmental
regulation by state and federal authorities including the United States
Environmental Protection Agency ("EPA"). Such regulation has increased the cost
of planning, designing, drilling, operating and in some instances, abandoning
wells. In most instances, the regulatory requirements relate to the handling and
disposal of drilling and production waste products and waste created by water
and air pollution control procedures. Although the Company believes that
compliance with environmental regulations will not have a material adverse
effect on operations or earnings, risks of substantial costs and liabilities are
inherent in oil and gas operations, and there can be no assurance that
significant costs and liabilities, including criminal penalties, will not be
incurred. Moreover, it is possible that other developments, such as stricter
environmental laws and regulations, and claims for damages for injuries to
property or persons resulting from the Company's operations could result in
substantial costs and liabilities.
Waste Disposal. The Company currently owns or leases, and has in the past
owned or leased, numerous properties that for many years have been used for the
exploration and production of oil and gas. Although the Company has utilized
operating and disposal practices that were standard in the industry at the time,
hydrocarbons or other wastes may have been disposed of or released on or under
the properties owned or leased by the Company or on or under other locations
where such wastes have been taken for disposal. In addition, many of these
properties have been operated by third parties whose treatment and disposal or
release of hydrocarbons or other wastes was not under the Company's control.
State and federal laws applicable to oil and natural gas wastes and properties
have gradually become more strict. Under such laws, the Company could be
required to remove or remediate previously disposed wastes (including wastes
disposed of or released by prior owners or operators)
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or property contamination (including groundwater contamination) or to perform
remedial plugging operations to prevent future contamination.
The Company generates wastes, including hazardous wastes, that are subject
to the federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes. The EPA and various state agencies have limited the disposal
options for certain hazardous and nonhazardous wastes and are considering the
adoption of stricter disposal standards for nonhazardous wastes. Furthermore,
certain wastes generated by the Company's oil and natural gas operations that
are currently exempt from treatment as hazardous wastes may in the future be
designated as hazardous wastes, and therefore be subject to considerably more
rigorous and costly operating and disposal requirements.
Superfund. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability,
without regard to fault or the legality of the original conduct, on certain
classes of persons with respect to the release of a "hazardous substance" into
the environment. These persons include the owner and operator of a site and
persons that disposed of or arranged for the disposal of the hazardous
substances found at a site. CERCLA also authorizes the EPA and, in some cases,
third parties to take actions in response to threats to the public health or the
environment and to seek to recover from responsible classes of persons the costs
of such action. In the course of its operations, the Company may have generated
and may generate wastes that fall within CERCLA's definition of "hazardous
substances". The Company may also be or have been an owner of sites on which
"hazardous substances" have been released. The Company may be responsible under
CERCLA for all or part of the costs to clean up sites at which such wastes have
been released. To date, however, neither the Company nor, to its knowledge, its
predecessors or successors have been named a potentially responsible party under
CERCLA or similar state superfund laws affecting property owned or leased by the
Company.
Air Emissions. The operations of the Company are subject to local, state and
federal regulations for the control of emissions of air pollution. Legal and
regulatory requirements in this area are increasing, and there can be no
assurance that significant costs and liabilities will not be incurred in the
future as a result of new regulatory developments. In particular, regulations
promulgated under the Clean Air Act Amendments of 1990 may impose additional
compliance requirements that could affect the Company's operations. However, it
is impossible to predict accurately the effect, if any, of the Clean Air Act
Amendments on the Company at this time. The Company may in the future be subject
to civil or administrative enforcement actions for failure to comply strictly
with air regulations or permits. These enforcement actions are generally
resolved by payment of monetary fines and correction of any identified
deficiencies. Alternatively, regulatory agencies could require the Company to
forego construction or operation of certain air emission sources.
OSHA. The Company is subject to the requirements of the federal Occupational
Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard
communication standard, the EPA community right-to-know regulations under Title
III of the federal Superfund Amendment and Reauthorization Act and similar state
statutes require the Company to organize information about hazardous materials
used, released or produced in its operations. Certain of this information must
be provided to employees, state and local governmental authorities and local
citizens. The Company is also subject to the requirements and reporting set
forth in OSHA workplace standards. The Company provides safety training and
personal protective equipment to its employees.
OPA and Clean Water Act. Federal regulations require certain owners or
operators of facilities that store or otherwise handle oil, such as the Company,
to prepare and implement spill prevention control plans, countermeasure plans
and facilities response plans relating to the possible discharge of oil into
surface waters. The Oil Pollution Act of 1990 ("OPA") amends certain provisions
of the federal Water Pollution Control Act of 1972, commonly referred to as the
Clean Water Act ("CWA"), and other statutes as they pertain to the prevention of
and response to oil spills into navigable waters. The OPA subjects owners of
facilities to strict joint and several liability for all containment and cleanup
costs and certain other damages arising from a spill, including, but not limited
to, the costs of responding to a release of oil to surface waters. The CWA
provides penalties for any discharges of petroleum product in reportable
quantities and imposes substantial liability for the costs of removing a spill.
State laws for the control of water pollution also provide varying civil and
criminal penalties and liabilities in the case of releases of
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<PAGE> 12
petroleum or its derivatives into surface waters or into the ground. Regulations
are currently being developed under OPA and state laws concerning oil pollution
prevention and other matters that may impose additional regulatory burdens on
the Company. In addition, the CWA and analogous state laws require permits to be
obtained to authorize discharges into surface waters or to construct facilities
in wetland areas. With respect to certain of its operations, the Company is
required to maintain such permits or meet general permit requirements. The EPA
has adopted regulations concerning discharges of storm water runoff. This
program requires covered facilities to obtain individual permits, participate in
a group permit or seek coverage under an EPA general permit. The Company
believes that with respect to existing properties it has obtained, or is
included under, such permits and with respect to future operations it will be
able to obtain, or be included under, such permits, where necessary. Compliance
with such permits is not expected to have a material effect on the Company.
NORM. Oil and gas exploration and production activities have been identified
as generators of concentrations of low-level naturally-occurring radioactive
materials ("NORM"). NORM regulations have recently been adopted in several
states. The Company is unable to estimate the effect of these regulations,
although based upon the Company's preliminary analysis to date, the Company does
not believe that its compliance with such regulations will have a material
adverse effect on its operations or financial condition.
Safe Drinking Water Act. The Company's operations involve the disposal of
produced saltwater and other nonhazardous oilfield wastes by reinjection into
the subsurface. Under the Safe Drinking Water Act ("SDWA"), oil and gas
operators, such as the Company, must obtain a permit for the construction and
operation of underground Class II injection wells. To protect against
contamination of drinking water, periodic mechanical integrity tests are often
required to be performed by the well operator. The Company has obtained such
permits for the Class II wells it operates. The Company also has disposed of
wastes in facilities other than those owned by the Company which are commercial
Class II injection wells.
Toxic Substances Control Act. The Toxic Substances Control Act ("TSCA") was
enacted to control the adverse effects of newly manufactured and existing
chemical substances. Under the TSCA, the EPA has issued specific rules and
regulations governing the use, labeling, maintenance, removal from service and
disposal of PCB items, such as transformers and capacitors used by oil and gas
companies. The Company may own such PCB items but does not believe compliance
with TSCA has or will have a material adverse effect on the Company's operations
or financial condition.
TITLE TO PROPERTIES
Title to properties is subject to royalty, overriding royalty, carried, net
profits, working and other similar interests and contractual arrangements
customary in the oil and gas industry, to liens for current taxes not yet due
and to other encumbrances. As is customary in the industry in the case of
undeveloped properties, only cursory investigation of record title is made at
the time of acquisition. Drilling title opinions are usually prepared before
commencement of drilling operations. From time to time, the Company's title to
oil and gas properties is challenged through legal proceedings. The Company is
routinely involved in litigation involving title to certain of its oil and gas
properties, none of which management believes will be materially adverse to the
Company, individually or in the aggregate.
OPERATING HAZARDS AND INSURANCE
The oil and gas business involves a variety of operating risks, including
the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured
formations and environmental hazards such as oil spills, gas leaks, ruptures or
discharges of toxic gases, the occurrence of any of which could result in
substantial losses to the Company due to injury or loss of life, severe damage
to or destruction of property, natural resources and equipment, pollution or
other environmental damage, clean-up responsibilities, regulatory investigation
and penalties and suspension of operations. The Company's horizontal and Deep
Tuscaloosa drilling activities involve greater risk of mechanical problems than
conventional vertical drilling operations.
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The Company maintains a $50 million oil and gas lease operator policy that
insures the Company against certain sudden and accidental risks associated with
drilling, completing and operating its wells. There can be no assurance that
this insurance will be adequate to cover any losses or exposure to liability.
The Company also carries comprehensive general liability policies and a $60
million umbrella policy. The Company and its subsidiaries carry workers'
compensation insurance in all states in which they operate and a $35 million
employment practice liability policy. While the Company believes these policies
are customary in the industry, they do not provide complete coverage against all
operating risks.
EMPLOYEES
The Company had 481 full-time employees as of December 31, 1998 and reduced
this level to 453 as of March 15, 1999. No employees are represented by
organized labor unions. The Company considers its employee relations to be good.
FACILITIES
The Company owns 13 buildings totaling approximately 86,500 square feet and
nine acres of land in an office complex in Oklahoma City that comprise its
headquarters' offices. The Company also owns field offices in Lindsay, Waynoka
and Weatherford, Oklahoma and leases office space in Garden City, Hays and
Wichita, Kansas; Oklahoma City, Oklahoma; Big Lake, College Station, Fritch and
Navasota, Texas; Lafayette, Louisiana; and in Calgary, Alberta, Canada. The
offices in Garden City, Wichita, College Station and Lafayette have been or will
be closed in the near future and the space sub-leased or terminated.
GLOSSARY
The terms defined in this section are used throughout this Form 10-K.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet of gas equivalent.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Commercial Well; Commercially Productive Well. An oil and gas well which
produces oil and gas in sufficient quantities such that proceeds from the sale
of such production exceed production expenses and taxes.
Developed Acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
Development Well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
Dry Hole; Dry Well. A well found to be incapable of producing either oil or
gas in sufficient quantities to justify completion as an oil or gas well.
Exploratory Well. A well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir or to extend a known reservoir.
Farmout. An assignment of an interest in a drilling location and related
acreage conditional upon the drilling of a well on that location.
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Formation. A succession of sedimentary beds that were deposited under the
same general geologic conditions.
Full-Cost Pool. The full-cost pool consists of all costs associated with
property acquisition, exploration, and development activities for a company
using the full-cost method of accounting. Additionally, any internal costs that
can be directly identified with acquisition, exploration and development
activities are included. Any costs related to production, general corporate
overhead or similar activities are not included.
Gross Acres or Gross Wells. The total acres or wells, as the case may be, in
which a working interest is owned.
Horizontal Wells. Wells which are drilled at angles greater than 70 from
vertical.
MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.
MBtu. One thousand Btus.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet of gas equivalent.
MMBbl. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million Btus.
MMcf. One million cubic feet.
MMcfe. One million cubic feet of gas equivalent.
Net Acres or Net Wells. The sum of the fractional working interest owned in
gross acres or gross wells.
Present Value. When used with respect to oil and gas reserves, present value
means the estimated future gross revenue to be generated from the production of
proved reserves, net of estimated production and future development costs, using
prices and costs in effect at the determination date, without giving effect to
non-property related expenses such as general and administrative expenses, debt
service and future income tax expense or to depreciation, depletion and
amortization, discounted using an annual discount rate of 10%.
Productive Well. A well that is producing oil or gas or that is capable of
production.
Proved Developed Reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved Reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved Undeveloped Location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
Proved Undeveloped Reserves. Reserves that are expected to be recovered from
new wells drilled to known reservoir on undrilled acreage or from existing wells
where a relatively major expenditure is required for recompletion.
Royalty Interest. An interest in an oil and gas property entitling the owner
to a share of oil or gas production free of costs of production.
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Tcf. One trillion cubic feet.
Tcfe. One trillion cubic feet of gas equivalent.
Undeveloped Acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether such acreage contains proved reserves.
Working Interest. The operating interest which gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.
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ITEM 2. PROPERTIES
PRIMARY OPERATING AREAS
The Company's strategy is to focus its acquisition and development efforts
in three areas: (i) the Mid-Continent (consisting of Oklahoma, southwestern
Kansas and the Texas Panhandle), (ii) the onshore Gulf Coast in Texas and
Louisiana, and (iii) the Helmet area in northeastern British Columbia. In
addition, the Company will selectively pursue exploration projects such as the
Deep Tuscaloosa in Louisiana and the Deep Wilcox in Wharton County, Texas.
Mid-Continent Region. The Company's Mid-Continent proved reserves of 625
Bcfe represented 57% of the Company's total proved reserves as of December 31,
1998 and this area produced 64 Bcfe, or 49% of the Company's 1998 production.
During 1998, the Company invested approximately $63 million to drill 165
gross (96.1 net) wells in the Mid-Continent. The Company has budgeted
approximately $50 million for the Mid-Continent during 1999, representing
approximately 56% of the Company's total budget for exploration and development
activities during the year. The Company anticipates the Mid-Continent will
contribute approximately 67 Bcfe of production during 1999, or 54% of expected
total production.
Gulf Coast. The Company's Gulf Coast proved reserves, consisting of the
Austin Chalk Trend in Texas and Louisiana and the Tuscaloosa Trend in Louisiana,
represented 151 Bcfe or 14% of the Company's total proved reserves as of
December 31, 1998. During 1998, the Gulf Coast assets produced 52 Bcfe, or 40%
of the Company's total production. The Company anticipates the Gulf Coast will
contribute approximately 38 Bcfe of production during 1999, or 31% of expected
total production.
During 1998, the Company invested approximately $109 million to drill 37
gross (17.8 net) wells in the Gulf Coast. For 1999, the Company has budgeted
approximately $6 million for Texas Austin Chalk and Louisiana Austin Chalk
drilling and $15 million for Tuscaloosa exploratory drilling activities. In the
aggregate, these Gulf Coast expenditures represent approximately 23% of the
Company's total budget for exploration and development activities in 1999.
Helmet Area. During fiscal 1996 and 1997, the Company began to evaluate the
possibility of developing a third core area of operations to complement its
activities in the Mid-Continent and Gulf Coast regions. Management believed that
the North American gas market would significantly tighten and as a result,
Canadian natural gas prices, which have significantly lagged U.S. natural gas
prices during the past 15 years, would increase in the future compared to U.S.
gas prices. During 1998, the Company entered into two transactions which
established a significant presence in a major gas field in northeastern British
Columbia.
The Company's Canadian proved reserves of 232 Bcfe represented 21% of the
Company's total proved reserves at December 31, 1998. During 1998, production
from Canada was 8 Bcfe, or 6% of the Company's total production. The Company has
budgeted $15 million to drill seven net wells in 1999 and expects production of
20 Bcfe, or 16% of the Company's estimated total production for 1999.
OTHER OPERATING AREAS
Permian Basin. In 1995 the Company initiated drilling activity in the
Permian Basin in the Lovington area of Lea County, New Mexico. In this project,
the Company is utilizing 3-D seismic technology to search for prospects that
management believes have been overlooked in this portion of the Permian Basin
because of inconclusive results provided by traditional 2-D seismic technology.
During 1998, the Company drilled seven wells in the Lovington area, four of
which were successfully completed and three were unsuccessful. The Company has
budgeted approximately $0.8 million to drill one gross (0.8 net) well in this
area during 1999.
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Wharton County, Texas. In 1997, the Company acquired approximately 25,000
net acres in Wharton County, Texas. This exploration project is seeking gas
production from the shallower Frio and Yegua sands and from the Deep Wilcox at
depths of up to 19,000 feet. The Company participated with a 55% interest in a
85,000 acre 3-D seismic program with Coastal Oil & Gas Corporation, Seagull
Energy Corporation and other industry partners during 1998 to delineate
potential future drillsites in the prospect. During 1998, the Company drilled
its first well in the prospect, which was abandoned as a dry hole.
Williston Basin. In 1996, the Company began acquiring leasehold in the
Williston Basin, located in eastern Montana and western North Dakota, and as of
December 31, 1998 owned approximately 0.9 million gross (0.6 million net) acres.
During the Transition Period, the Company drilled and successfully completed six
wells targeting the Red River formation on the northern portion of its
leasehold. During 1998, the Company invested approximately $4.2 million to drill
three gross (2.8 net) wells in the Williston Basin. The Company does not plan to
drill any wells during 1999 in the Williston Basin unless oil prices increase
significantly.
OIL AND GAS RESERVES
The tables below set forth information as of December 31, 1998 with respect
to the Company's estimated net proved reserves, the estimated future net revenue
therefrom and the present value thereof at such date. Williamson Petroleum
Consultants, Inc., Ryder Scott Company Petroleum Engineers and H.J. Gruy and
Associates, Inc. evaluated 63%, 12% and 1%, respectively, of the Company's
combined discounted future net revenues from the Company's estimated proved
reserves at December 31, 1998. The remaining properties were evaluated
internally by the Company's engineers. All estimates were prepared based upon a
review of production histories and other geologic, economic, ownership and
engineering data developed by the Company. The present value of estimated future
net revenue shown is not intended to represent the current market value of the
estimated oil and gas reserves owned by the Company.
<TABLE>
<CAPTION>
ESTIMATED PROVED RESERVES OIL GAS TOTAL
AS OF DECEMBER 31, 1998 (MBBL) (MMCF) (MMCFE)
-------------------------- ------------- ------------- -------------
<S> <C> <C> <C>
Proved developed ................................................ 18,036 658,943 767,160
Proved undeveloped .............................................. 4,557 296,848 324,188
------------- ------------- -------------
Total proved .................................................... 22,593 955,791 1,091,348
============= ============= =============
</TABLE>
<TABLE>
<CAPTION>
ESTIMATED FUTURE
NET REVENUE PROVED PROVED TOTAL
AS OF DECEMBER 31, 1998(a) DEVELOPED UNDEVELOPED PROVED
-------------------------- ------------- ------------- -------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Estimated future net revenue .................................... $ 864,109 $ 344,532 $ 1,208,641
Present value of future net revenue ............................. $ 513,566 $ 147,425 $ 660,991
</TABLE>
- ----------
(a) Estimated future net revenue represents estimated future gross revenue
to be generated from the production of proved reserves, net of
estimated production and future development costs, using prices and
costs in effect at December 31, 1998. The amounts shown do not give
effect to non-property related expenses, such as general and
administrative expenses, debt service and future income tax expense or
to depreciation, depletion and amortization. The prices used in the
external and internal reports yield weighted average prices of $10.48
per barrel of oil and $1.68 per Mcf of gas.
The future net revenue attributable to the Company's estimated proved
undeveloped reserves of $345 million at December 31, 1998, and the $147 million
present value thereof, have been calculated assuming that the Company will
expend approximately $144 million to develop these reserves. The amount and
timing of these expenditures will depend on a number of factors, including
actual drilling results, product prices and the availability of capital.
No estimates of proved reserves comparable to those included herein have
been included in reports to any federal agency other than the Securities and
Exchange Commission.
The Company's interest used in calculating proved reserves and the estimated
future net revenue therefrom was determined after giving effect to the assumed
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<PAGE> 18
maximum participation by other parties to the Company's farmout and
participation agreements. The prices used in calculating the estimated future
net revenue attributable to proved reserves do not reflect market prices for oil
and gas production sold subsequent to December 31, 1998. There can be no
assurance that all of the estimated proved reserves will be produced and sold at
the assumed prices or that existing contracts will be honored or judicially
enforced.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and timing of development
expenditures, including many factors beyond the control of the Company. The
reserve data set forth herein represent only estimates. Reserve engineering is a
subjective process of estimating underground accumulations of oil and gas that
cannot be measured in an exact way, and the accuracy of any reserve estimate is
a function of the quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates made by different engineers
often vary. In addition, results of drilling, testing and production subsequent
to the date of an estimate may justify revision of such estimates, and such
revisions may be material. Accordingly, reserve estimates are often different
from the actual quantities of oil and gas that are ultimately recovered.
Furthermore, the estimated future net revenue from proved reserves and the
present value thereof are based upon certain assumptions, including prices,
future production levels and cost, that may not prove correct. Predictions about
prices and future production levels are subject to great uncertainty, and the
foregoing uncertainties are particularly true as to proved undeveloped reserves,
which are inherently less certain than proved developed reserves and which
comprise a significant portion of the Company's proved reserves.
See Item 1 and Note 11 of Notes to Consolidated Financial Statements
included in Item 8 for a description of the Company's primary and other
operating areas, production and other information regarding its oil and gas
properties.
ITEM 3. LEGAL PROCEEDINGS
The Company is subject to ordinary routine litigation incidental to its
business. In addition, the following matters are pending:
Securities Litigation. On January 13, 1998, a consolidated class action
complaint styled In re Chesapeake Energy Corporation Securities Litigation was
filed in the U.S. District Court for the Western District of Oklahoma. It
consolidated 12 pending purported class actions filed in August and September
1997. The action is brought on behalf of purchasers of the Company's common
stock and common stock options between January 25, 1996 and June 27, 1997. The
defendants are the Company and the following officers and directors: Aubrey K.
McClendon, Tom L. Ward, Marcus C. Rowland, Shannon T. Self, Walter C. Wilson,
Henry J. Hood, Steven C. Dixon, J. Mark Lester and Ronald A. Lefaive. The
complaint alleges violations of Sections 10(b) and 20(a) of the Securities
Exchange Act of 1934 and Rule 10b-5 thereunder.
The plaintiffs assert that the defendants made material
misrepresentations and failed to disclose material facts about the success of
the Company's exploration and drilling activities in the Louisiana Trend. The
complaint alleges the lack of disclosure artificially inflated the price of the
Company's common stock during the period beginning January 25, 1996 and ending
on 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
the Company's 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 on
March 16, 1998 filed a motion to dismiss. To date, the U.S. District Court has
not ruled on this motion. No estimate of loss or range of estimate of loss, if
any, can be made at this time.
Bayard Drilling Technologies, Inc. ("Bayard"). On July 30, 1998, the
plaintiffs in Yuan, et al. v. Bayard, et al. filed an Amended Class Action
Complaint in the U.S. District Court for the Western District of Oklahoma
alleging violations of Sections 11 and 12 of the Securities Act of 1933 and
Section 408 of the Oklahoma Securities Act by the Company and others. The action
was brought purportedly on behalf of investors who purchased Bayard common stock
in, or traceable to, Bayard's initial public offering in November 1997. The
defendants include officers and directors of Bayard who signed the registration
statement, selling shareholders (including the Company) and underwriters of the
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offering. Total proceeds of the offering were $254 million, of which the Company
received net proceeds of $90 million.
In May 1998, two additional purported class actions filed in January
and February 1998 in the District Court for Oklahoma County, Oklahoma were
dismissed without prejudice pursuant to stipulation of all parties. On May 12,
1998, the plaintiffs in the dismissed cases became co-lead plaintiffs in Yuan v.
Bayard, et al.
Plaintiffs allege that the Company, which owned 30.1% of Bayard's
outstanding common stock prior to the offering, was a controlling person of
Bayard. Plaintiffs also allege that the Company had established an interlocking
financial relationship with Bayard and was a customer of Bayard's drilling
services under allegedly below-market terms. Plaintiffs also note the fact that
Messrs. McClendon, Ward and Rowland, executive officers and directors of the
Company, were formerly directors 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 the claims
against it in this action are without merit. On September 11, 1998, the Company
and the other named defendants filed a motion to dismiss. No estimate of loss or
range of estimate of loss, if any, can be made at this time. Bayard has
subsequently agreed to merge into a wholly-owned, newly created, special purpose
subsidiary of Nabors Industries, Inc.
UPRC Patent Suit. On October 15, 1996, Union Pacific Resources Company
("UPRC") filed suit against the Company in the U.S. District Court for the
Northern District of Texas, Fort Worth Division, alleging (i) infringement and
inducing infringement of UPRC's claims to a patent for an invention involving a
method of maintaining a borehole in a stratigraphic zone during drilling, (ii)
tortious interference with contracts between UPRC and certain of its former
employees regarding the confidentiality of proprietary information of UPRC and
(iii) misappropriation of such proprietary information. On May 20, 1998, two
orders were entered granting the Company summary judgment on several issues. The
court ruled as a matter of law that UPRC's tort claims for misappropriation of
trade secrets and tortious interference with business relations are barred by
the statute of limitations. Further, the court found that UPRC's claim for
inducement to infringe its patent for a drillbit steering method is barred as to
any wells drilled by the Company prior to August 14, 1995. The only issues
remaining in the case involve the validity, potential infringement and value, if
any, of UPRC's patent.
UPRC's claims against the Company in UPRC v. Chesapeake Energy
Corporation, et al. are based on services provided to the Company by a third
party vendor controlled by former UPRC employees. UPRC is seeking injunctive
relief, damages of an unspecified amount, including actual, enhanced,
consequential and punitive damages, interest, costs and attorneys' fees. The
Company believes that it has meritorious defenses to UPRC's allegations and has
petitioned the court to declare the UPRC patent invalid. Various motions for
summary judgment filed by both parties are pending. While no prediction can be
made as to the outcome of the matter or the amount of damages that might be
awarded, if any, damage estimates have been made in reports of experts 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 the expert's view of a reasonable royalty for use of the
patent. The case has been set for trial in June 1999 on the issue of liability.
19
<PAGE> 20
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
PRICE RANGE OF COMMON STOCK
The common stock trades on the New York Stock Exchange under the symbol
"CHK". The following table sets forth, for the periods indicated, the high and
low sales prices per share (adjusted for a 2-for-1 stock split on December 31,
1996) of the common stock as reported by the New York Stock Exchange:
<TABLE>
<CAPTION>
COMMON STOCK
-----------------
HIGH LOW
------ ------
<S> <C> <C>
Fiscal year ended June 30, 1997:
First Quarter..................................................................... $34.00 $21.00
Second Quarter.................................................................... 34.13 25.69
Third Quarter..................................................................... 31.50 19.88
Fourth Quarter.................................................................... 22.38 9.25
Transition Period ended December 31, 1997:
First Quarter..................................................................... 11.50 6.31
Second Quarter.................................................................... 13.44 6.81
Fiscal year ended December 31, 1998:
First Quarter..................................................................... 7.75 5.50
Second Quarter.................................................................... 6.00 3.88
Third Quarter..................................................................... 4.06 1.13
Fourth Quarter.................................................................... 2.63 0.75
</TABLE>
At March 26, 1999 there were 1,025 holders of record of common stock and
approximately 28,000 beneficial owners.
DIVIDENDS
The Company paid quarterly dividends of $0.02 per common share from July
1997 to July 1998. In September 1998 the Board of Directors determined that
because of low oil and natural gas prices the payment of cash dividends on the
common stock should be cancelled. The payment of future cash dividends, if any,
will be reviewed periodically by the Board of Directors and will depend upon,
among other things, the Company's financial condition, funds from operations,
the level of its capital and development expenditures, its future business
prospects and any contractual restrictions.
Two of the indentures governing the Company's outstanding senior notes
contain restrictions on the Company's ability to declare and pay dividends.
Under these indentures, the Company may not pay any cash dividends on its common
or preferred stock if (i) a default or an event of default has occurred and is
continuing at the time of or immediately after giving effect to the dividend
payment, (ii) the Company would not be able to incur at least $1 of additional
indebtedness under the terms of the indentures, or (iii) immediately after
giving effect to the dividend payment, the aggregate of all dividends and other
restricted payments declared or made after the respective issue dates of the
notes exceeds the sum of specified income, proceeds from the issuance of stock
and debt by the Company and other amounts from the quarter in which the
respective note issuances occurred to the quarter immediately preceding the date
of the dividend payment. As of December 31, 1998, the Company did not meet the
debt incurrence or the restricted payment tests under these indentures.
20
<PAGE> 21
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial data of the
Company for each of the four fiscal years ended June 30, 1997, the six month
transition period ended December 31, 1997, the six months ended December 31,
1996 and the twelve months ended December 31, 1998 and 1997. The data is
derived from the consolidated financial statements of the Company. Acquisitions
made by the Company during the first and second quarters of 1998 materially
affect the comparability of the selected financial data for 1997 and 1998. Each
of the acquisitions was accounted for using the purchase method. The table
should be read in conjunction with "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the consolidated financial
statements, including the notes thereto, appearing in Items 7 and 8 of this
report.
21
<PAGE> 22
<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS ENDED
DECEMBER 31, DECEMBER 31,
------------------------------ ------------------------------
1998 1997 1997 1996
------------- ------------- ------------- -------------
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales ......................... $ 256,887 $ 198,410 $ 95,657 $ 90,167
Oil and gas marketing sales ............... 121,059 104,394 58,241 30,019
Oil and gas service operations ............ -- -- -- --
------------- ------------- ------------- -------------
Total revenues ....................... 377,946 302,804 153,898 120,186
------------- ------------- ------------- -------------
Operating costs:
Production expenses ....................... 51,202 14,737 7,560 4,268
Production taxes .......................... 8,295 4,590 2,534 1,606
Oil and gas marketing expenses ............ 119,008 103,819 58,227 29,548
Oil and gas service operations ............ -- -- -- --
Impairment of oil and gas properties ...... 826,000 346,000 110,000 --
Impairment of other assets ................ 55,000 -- -- --
Oil and gas depreciation,
depletion and amortization ............ 146,644 127,429 60,408 36,243
Depreciation and amortization of
other assets ............................ 8,076 4,360 2,414 1,836
General and administrative ................ 19,918 10,910 5,847 3,739
------------- ------------- ------------- -------------
Total operating costs ................ 1,234,143 611,845 246,990 77,240
------------- ------------- ------------- -------------
Income (loss) from operations ................ (856,197) (309,041) (93,092) 42,946
------------- ------------- ------------- -------------
Other income (expense):
Interest and other income ................. 3,926 87,673 78,966 2,516
Interest expense .......................... (68,249) (29,782) (17,448) (6,216)
------------- ------------- ------------- -------------
(64,323) 57,891 61,518 (3,700)
------------- ------------- ------------- -------------
Income (loss) before income taxes
and extraordinary item .................. (920,520) (251,150) (31,574) 39,246
Provision (benefit) for income taxes ......... -- (17,898) -- 14,325
------------- ------------- ------------- -------------
Income (loss) before extraordinary item ...... (920,520) (233,252) (31,574) 24,921
Extraordinary item:
Loss on early extinguishment of
debt, net of applicable income taxes .... (13,334) (177) -- (6,443)
------------- ------------- ------------- -------------
Net income (loss) ............................ (933,854) (233,429) (31,574) 18,478
Preferred stock dividends .................... (12,077) -- -- --
------------- ------------- ------------- -------------
Net income (loss) available to
common shareholders ..................... $ (945,931) $ (233,429) $ (31,574) $ 18,478
============= ============= ============= =============
Earnings (loss) per common share-
basic:
Income (loss) before extraordinary
item .................................... $ (9.83) $ (3.30) $ (0.45) $ 0.40
Extraordinary item ........................... (0.14) -- $ -- (0.10)
------------- ------------- ------------- -------------
Net income (loss) ............................ $ (9.97) $ (3.30) $ (0.45) $ 0.30
============= ============= ============= =============
Earnings (loss) per common share-
assuming dilution:
Income (loss) before extraordinary item ...... $ (9.83) $ (3.30) $ (0.45) $ 0.38
Extraordinary item ........................... (0.14) -- -- (0.10)
------------- ------------- ------------- -------------
Net income (loss) ............................ $ (9.97) $ (3.30) $ (0.45) $ 0.28
============= ============= ============= =============
Cash dividends declared
per common share ........................ $ 0.04 $ 0.06 $ 0.04 $ --
CASH FLOW DATA:
Cash provided by operating
activities before changes in
working capital ......................... $ 117,500 $ 152,196 $ 67,872 $ 76,816
Cash provided by
operating activities .................... 94,639 181,345 139,157 41,901
Cash used in investing activities ............ 548,050 476,209 136,504 184,149
Cash provided by (used in)
financing activities .................... 363,797 277,985 (2,810) 231,349
Effect of exchange rate
changes on cash ......................... (4,726) -- -- --
BALANCE SHEET DATA (at end of period):
Total assets ................................. $ 812,615 $ 952,784 $ 952,784 $ 860,597
Long-term debt, net of current
maturities .............................. 919,076 508,992 508,992 220,149
Stockholders' equity (deficit) ............... (248,568) 280,206 280,206 484,062
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
----------------------------------------------------------------
1997 1996 1995 1994
------------- ------------- ------------- -------------
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales ......................... $ 192,920 $ 110,849 $ 56,983 $ 22,404
Oil and gas marketing sales ............... 76,172 28,428 -- --
Oil and gas service operations ............ -- 6,314 8,836 6,439
------------- ------------- ------------- -------------
Total revenues ....................... 269,092 145,591 65,819 28,843
------------- ------------- ------------- -------------
Operating costs:
Production expenses ....................... 11,445 6,340 3,379 2,141
Production taxes .......................... 3,662 1,963 877 1,506
Oil and gas marketing expenses ............ 75,140 27,452 -- --
Oil and gas service operations ............ -- 4,895 7,747 5,199
Impairment of oil and gas properties ...... 236,000 -- -- --
Impairment of other assets ................ -- -- -- --
Oil and gas depreciation,
depletion and amortization ............ 103,264 50,899 25,410 8,141
Depreciation and amortization of
other assets ............................ 3,782 3,157 1,765 1,871
General and administrative ................ 8,802 4,828 3,578 3,135
------------- ------------- ------------- -------------
Total operating costs ................ 442,095 99,534 42,756 21,993
------------- ------------- ------------- -------------
Income (loss) from operations ................ (173,003) 46,057 23,063 6,850
------------- ------------- ------------- -------------
Other income (expense):
Interest and other income ................. 11,223 3,831 1,524 981
Interest expense .......................... (18,550) (13,679) (6,627) (2,676)
------------- ------------- ------------- -------------
(7,327) (9,848) (5,103) (1,695)
------------- ------------- ------------- -------------
Income (loss) before income taxes
and extraordinary item .................. (180,330) 36,209 17,960 5,155
Provision (benefit) for income taxes ......... (3,573) 12,854 6,299 1,250
------------- ------------- ------------- -------------
Income (loss) before extraordinary item ...... (176,757) 23,355 11,661 3,905
Extraordinary item:
Loss on early extinguishment of
debt, net of applicable income taxes .... (6,620) -- -- --
------------- ------------- ------------- -------------
Net income (loss) ............................ (183,377) 23,355 11,661 3,905
Preferred stock dividends .................... -- -- -- --
------------- ------------- ------------- -------------
Net income (loss) available to
common shareholders ..................... $ (183,377) $ 23,355 $ 11,661 $ 3,905
============= ============= ============= =============
Earnings (loss) per common share-
basic:
Income (loss) before extraordinary
item .................................... $ (2.69) $ 0.43 $ 0.22 $ 0.08
Extraordinary item ........................... (0.10) -- -- --
------------- ------------- ------------- -------------
Net income (loss) ............................ $ (2.79) $ 0.43 $ 0.22 $ 0.08
============= ============= ============= =============
Earnings (loss) per common share-
assuming dilution:
Income (loss) before extraordinary item ...... $ (2.69) $ 0.40 $ 0.21 $ 0.08
Extraordinary item ........................... (0.10) -- -- --
------------- ------------- ------------- -------------
Net income (loss) ............................ $ (2.79) $ 0.40 $ 0.21 $ 0.08
============= ============= ============= =============
Cash dividends declared
per common share ........................ $ 0.02 $ -- $ -- $ --
CASH FLOW DATA:
Cash provided by operating
activities before changes in
working capital ......................... $ 161,140 $ 88,431 $ 45,903 $ 15,527
Cash provided by
operating activities .................... 84,089 120,972 54,731 19,423
Cash used in investing activities ............ 523,854 344,389 112,703 29,211
Cash provided by (used in)
financing activities .................... 512,144 219,520 97,282 21,162
Effect of exchange rate
changes on cash ......................... -- -- -- --
BALANCE SHEET DATA (at end of period):
Total assets ................................. $ 949,068 $ 572,335 $ 276,693 $ 125,690
Long-term debt, net of current
maturities .............................. 508,950 268,431 145,754 47,878
Stockholders' equity (deficit) ............... 286,889 177,767 44,975 31,260
</TABLE>
22
<PAGE> 23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
OVERVIEW
Although the Company's oil and gas revenues, production, and proved reserves
reached record levels during the year ended December 31, 1998 (the "Current
Year"), significant declines in oil and gas prices as of December 31, 1998
resulted in downward revisions in estimates of the Company's proved oil and gas
reserves and the related present value of the estimated future net revenues from
its proved reserves. The Company recorded an $826 million oil and gas property
writedown and a net loss of $934 million during the Current Year.
In response to disappointing drilling results in Louisiana and changes
occurring in oil and natural gas markets, the Company significantly revised its
business strategy during the six months ended December 31, 1997 (the "Transition
Period"). These revisions included (i) reducing the size and risk of its
exploratory drilling program, especially in the Louisiana Trend, (ii) acquiring
significant volumes of long-lived natural gas reserves, particularly in the
Mid-Continent region of the U.S., and (iii) building a larger inventory of lower
risk drilling opportunities through acquisitions and joint ventures. Further,
the Company reduced its capital expenditure budget for exploration and
development to more closely match anticipated cash flow from operations.
As part of this revised strategy, the Company acquired various proved oil
and gas reserves through merger or through purchases of oil and gas properties.
During the Current Year, the Company acquired approximately 750 Bcfe of proved
reserves primarily in eight major transactions. Of these transactions, three
were closed in the first quarter of 1998, and five were closed during the second
quarter of 1998. These acquisitions increased oil and gas production volumes and
revenues, decreased DD&A per Mcfe, and increased production expenses during the
Current Year. Long-term debt and interest expense also increased as a result of
the financing required to fund these acquisitions. The total consideration given
for the acquisitions was 30.8 million shares of Company common stock, $280
million of cash, the assumption of $205 million of debt, and the incurrence of
approximately $20 million of other acquisition related costs.
The Company incurred an $826 million impairment of oil and gas properties in
the Current Year. The writedown was caused by a combination of several factors,
including the acquisitions completed by the Company during the Current Year,
which were accounted for using the purchase method, and the significant
decreases in oil and gas prices throughout the Current Year. Oil and gas prices
used to value the Company's proved reserves decreased from $17.62 per Bbl of oil
and $2.29 per Mcf of gas at December 31, 1997, to $10.48 per Bbl of oil and
$1.68 per Mcf of gas at December 31, 1998. Higher drilling and completion costs
and the evaluation of certain leasehold, seismic and other exploration-related
costs that were previously unevaluated were the remaining contributing factors
which led to the writedown in the Current Year.
During the Current Year, the Company participated in 242 gross (135.2 net)
wells, 156 of which were Company operated. A summary of the Company's drilling
activities and capital expenditures by primary operating area is as follows ($
in thousands):
<TABLE>
<CAPTION>
CAPITAL EXPENDITURES - OIL AND GAS PROPERTIES
----------------------------------------------------------------------------
GROSS NET SALE OF
WELLS WELLS DRILLING LEASEHOLD SUB-TOTAL ACQUISITION PROPERTIES TOTAL
---------- ---------- ---------- ---------- ---------- ----------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Mid-Continent ........... 165 96.1 $ 63,431 $ 4,779 $ 68,210 $ 662,104 $ (15,712) $ 714,602
Gulf Coast .............. 37 17.8 109,122 13,921 123,043 -- -- 123,043
Canada .................. 20 6.4 10,011 2,535 12,546 78,176 -- 90,722
All other areas ......... 20 14.9 41,611 5,134 46,745 -- -- 46,745
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Total ............... 242 135.2 $ 224,175 $ 26,369 $ 250,544 $ 740,280 $ (15,712) $ 975,112
========== ========== ========== ========== ========== ========== ========== ==========
</TABLE>
The Company's proved reserves increased 144% to an estimated 1,091 Bcfe at
December 31, 1998, an increase of 643 Bcfe from the 448 Bcfe of estimated proved
reserves at December 31, 1997 (see Note 11 of Notes to Consolidated Financial
Statements in Item 8).
23
<PAGE> 24
The Company's strategy for 1999 is to continue developing its natural gas
assets by drilling, but at a significantly reduced pace. The Company has reduced
its capital expenditure budget (before any acquisitions) to approximately $90
million and has reduced the Gulf Coast drilling component significantly.
Furthermore, the Company has increased its use of 3-D seismic to assist in
reducing exploratory risks and increasing economic returns from its drilling
programs. The Company has conducted, participated in, or is actively pursuing
more than 25 3-D seismic programs to evaluate the Company's acreage inventory.
The following table sets forth certain operating data of the Company for the
periods presented:
<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS ENDED
DECEMBER 31, DECEMBER 31, YEAR ENDED JUNE 30,
----------------------- ----------------------- -----------------------
1998 1997 1997 1996 1997 1996
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
NET PRODUCTION DATA:
Oil (MBbl) ................................... 5,976 3,511 1,857 1,116 2,770 1,413
Gas (MMcf) ................................... 94,421 59,236 27,326 30,095 62,005 51,710
Gas equivalent (MMcfe) ....................... 130,277 80,302 38,468 36,791 78,625 60,190
OIL AND GAS SALES ($ in 000's):
Oil .......................................... $ 75,877 $ 68,079 $ 34,523 $ 24,418 $ 57,974 $ 25,224
Gas .......................................... 181,010 130,331 61,134 65,749 134,946 85,625
---------- ---------- ---------- ---------- ---------- ----------
Total oil and gas sales .............. $ 256,887 $ 198,410 $ 95,657 $ 90,167 $ 192,920 $ 110,849
========== ========== ========== ========== ========== ==========
AVERAGE SALES PRICE:
Oil ($ per Bbl) .............................. $ 12.70 $ 19.39 $ 18.59 $ 21.88 $ 20.93 $ 17.85
Gas ($ per Mcf) .............................. $ 1.92 $ 2.20 $ 2.24 $ 2.18 $ 2.18 $ 1.66
Gas equivalent ($ per Mcfe) .................. $ 1.97 $ 2.47 $ 2.49 $ 2.45 $ 2.45 $ 1.84
OIL AND GAS COSTS ($ per Mcfe):
Production expenses and taxes ................ $ .45 $ .24 $ .27 $ .16 $ .19 $ .14
General and administrative ................... $ .15 $ .14 $ .15 $ .10 $ .11 $ .08
Depreciation, depletion and amortization ..... $ 1.13 $ 1.59 $ 1.57 $ .99 $ 1.31 $ .85
NET WELLS DRILLED:
Horizontal wells ............................. 20 69 27 34 76 42
Vertical wells ............................... 116 32 14 13 31 27
NET WELLS AT END OF PERIOD ..................... 2,405 401 401 210 270 187
</TABLE>
RESULTS OF OPERATIONS
Year Ended December 31, 1998 and 1997
General. In the Current Year, the Company realized a net loss of $933.9
million, or a loss of $9.97 per common share, on total revenues of $381.9
million. This compares to a net loss of $233.4 million, or a loss of $3.30 per
common share, on total revenues of $390.5 million during the year ended December
31, 1997 (the "Prior Year"). The loss in the Current Year was caused primarily
by an $826.0 million oil and gas property writedown recorded under the full-cost
method of accounting and a $55.0 million writedown of other assets. See
"Impairment of Oil and Gas Properties" and "Impairment of Other Assets".
Oil and Gas Sales. During the Current Year, oil and gas sales increased 29%
to $256.9 million versus $198.4 million for the Prior Year. The increase in oil
and gas sales resulted primarily from growth in production volumes. For the
Current Year, the Company produced 130.3 Bcfe at a weighted average price of
$1.97 per Mcfe, compared to 80.3 Bcfe produced in the Prior Year at a weighted
average price of $2.47 per Mcfe.
The following table shows the Company's production by region for the Current
Year and the Prior Year:
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
--------------------------------------------------
1998 1997
----------------------- -----------------------
MMCFE PERCENT MMCFE PERCENT
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Mid-Continent .................................... 64,038 49% 17,685 22%
Gulf Coast ....................................... 52,463 40 60,662 76
Canada ........................................... 7,746 6 -- --
All other areas .................................. 6,030 5 1,955 2
---------- ---------- ---------- ----------
Total production ........................... 130,277 100% 80,302 100%
========== ========== ========== ==========
</TABLE>
24
<PAGE> 25
Natural gas production represented approximately 72% of the Company's total
production volume on an equivalent basis in the Current Year, compared to 74% in
the Prior Year. This decrease in gas production as a percentage of total
production was primarily the result of new production in the Louisiana Trend,
which tends to produce more oil than gas. In 1999, the Company's production is
estimated to be approximately 80% gas.
For the Current Year, the Company realized an average price per barrel of
oil of $12.70, compared to $19.39 in the Prior Year. Gas price realizations
decreased from $2.20 per Mcf in the Prior Year to $1.92 per Mcf in the Current
Year. The Company's hedging activities resulted in an increase in oil and gas
revenues of $11.8 million in the Current Year and a decrease in oil and gas
revenues of $4.6 million in the Prior Year.
Oil and Gas Marketing Sales. The Company realized $121.1 million in oil and
gas marketing sales for third parties in the Current Year, with corresponding
oil and gas marketing expenses of $119.0 million, for a net margin of $2.1
million. This compares to sales of $104.4 million, expenses of $103.8 million,
and a margin of $0.6 million in the Prior Year.
Production Expenses and Taxes. Production expenses and taxes, which include
lifting costs, production taxes and ad valorem taxes, increased to $59.5 million
in the Current Year, compared to $19.3 million in the Prior Year. These
increases were primarily the result of increased production and increased
operating costs. On a unit of production basis, production expenses and taxes
increased to $0.45 per Mcfe compared to $0.24 per Mcfe in the Prior Year due
primarily to the higher per unit operating costs associated with many of the oil
and gas properties acquired during the Current Year. The Company expects that
production expenses per Mcfe will generally remain the same in 1999.
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, along with the estimated future capital expenditures
to develop proved undeveloped reserves, are depleted and charged to operations
using the unit-of-production method based on the ratio of current production to
proved oil and gas reserves as estimated by the Company's independent
engineering consultants and Company 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 $826
million in the Current Year. The writedown was caused by a combination of
several factors, including the acquisitions completed by the Company during the
Current Year, which were accounted for using the purchase method, and the
significant decreases in oil and gas prices throughout the Current Year. Oil and
gas prices used to value the Company's proved reserves decreased from $17.62 per
Bbl of oil and $2.29 per Mcf of gas at December 31, 1997, to $10.48 per Bbl of
oil and $1.68 per Mcf of gas at December 31, 1998. Higher drilling and
completion costs and the evaluation of certain leasehold, seismic and other
exploration-related costs that were previously unevaluated were the remaining
factors which contributed to the writedown in the Current Year.
Impairment of Other Assets. The Company incurred a $55 million impairment
charge during the Current Year. Of this amount, $30 million relates to the
Company's investment in preferred stock of Gothic Energy Corporation, and the
remainder was related to certain of the Company's gas processing and
transportation assets located in Louisiana. No such charge was recorded in the
Prior Year.
Oil and Gas Depreciation, Depletion and Amortization. Depreciation,
depletion and amortization ("DD&A") of oil and gas properties for the Current
Year was $146.6 million, $19.2 million higher than the Prior Year's expense of
$127.4 million. The average DD&A rate per Mcfe, which is a function of
capitalized costs, future development costs, and the related underlying reserves
in the periods presented, decreased to $1.13 in the Current Year ($1.17 in
25
<PAGE> 26
U.S. and $0.43 in Canada) compared to $1.59 in the Prior Year. The Company
expects the 1999 DD&A rate to be approximately $0.75 per Mcfe.
Depreciation and Amortization of Other Assets. Depreciation and amortization
("D&A") of other assets increased to $8.1 million in the Current Year, compared
to $4.4 million in the Prior Year. This increase was caused by increased
investments in depreciable buildings and equipment and increased amortization of
debt issuance costs as a result of the issuance of senior notes in April 1998.
General and Administrative. General and administrative ("G&A") expenses,
which are net of capitalized internal payroll and non-payroll expenses (see Note
11 of Notes to Consolidated Financial Statements), were $19.9 million in the
Current Year, up 83% from $10.9 million in the Prior Year. The increase in the
Current Year compared to the Prior Year is due primarily to increased personnel
expenses required by the Company's growth and industry wage inflation. The
Company capitalized $5.3 million and $5.3 million of internal costs in the
Current Year and Prior Year, respectively, directly related to the Company's oil
and gas exploration and development efforts. The Company anticipates that G&A
costs for 1999 will decline as a result of reduced staffing levels.
Interest and Other Income. Interest and other income for the Current Year
were $3.9 million compared to $87.7 million in the Prior Year. During the Prior
Year, the Company realized a gain on the sale of its Bayard common stock of
$73.8 million, the most significant component of interest and other income.
Interest Expense. Interest expense increased to $68.2 million in the Current
Year, compared to $29.8 million in the Prior Year. The increase was due
primarily to the issuance of $500 million of senior notes in April 1998. In
addition to the interest expense reported, the Company capitalized $6.5 million
of interest during the Current Year, compared to $10.4 million capitalized in
the Prior Year. The Company anticipates that capitalized interest for 1999 will
decrease to between $2 million and $3 million.
Provision (Benefit) for Income Taxes. The Company recorded no income taxes
in the Current Year compared to an income tax benefit of $17.9 million in the
Prior Year, before consideration of the $3.7 million tax benefit associated with
an extraordinary loss from the early extinguishment of debt.
At December 31, 1998, the Company had U.S. and Canadian net operating loss
carryforwards of approximately $571 million and $1 million, respectively, for
regular federal income taxes which will expire in future years beginning in
2007. Management believes that it cannot be demonstrated at this time that it is
more likely than not that the deferred income tax assets, comprised primarily of
the net operating loss carryforward, will be realizable in future years, and
therefore a valuation allowance of $459 million has been recorded. No deferred
tax benefit related to the exercise of employee stock options was allocated to
additional paid-in capital in the Current Year. The Company does not expect to
record any net income tax expense in 1999 based on information available at this
time.
Six Months Ended December 31, 1997 and 1996
General. For the Transition Period, the Company realized a net loss of $31.6
million, or $0.45 per common share, on total revenues of $232.9 million. This
compares to net income of $18.5 million, or $0.28 per common share, on total
revenues of $122.7 million in the six months ended December 31, 1996 (the "Prior
Period"). The loss in the Transition Period was caused by a $110.0 million asset
writedown recorded under the full-cost method of accounting, partially offset by
a gain of $73.8 million from the sale of Bayard stock. See "Impairment of Oil
and Gas Properties".
Oil and Gas Sales. During the Transition Period, oil and gas sales increased
6% to $95.7 million versus $90.2 million for the Prior Period. The increase in
oil and gas sales resulted primarily from growth in production volumes. For the
Transition Period, the Company produced 38.5 Bcfe at a weighted average price of
$2.49 per Mcfe, compared to 36.8 Bcfe produced in the Prior Period at a weighted
average price of $2.45 per Mcfe.
26
<PAGE> 27
The following table shows the Company's production by region for the
Transition Period and the Prior Period:
<TABLE>
<CAPTION>
FOR THE SIX MONTHS ENDED DECEMBER 31,
-----------------------------------------
1997 1996
------------------- -------------------
MMCFE PERCENT MMCFE PERCENT
-------- -------- --------- -------
<S> <C> <C> <C> <C>
Mid-Continent................................................. 8,852 23% 8,980 24%
Gulf Coast.................................................... 26,220 68 26,243 71
All other areas............................................... 3,396 9 1,568 5
-------- -------- --------- -------
Total production.............................................. 38,468 100% 36,791 100%
======== ======== ========= =======
</TABLE>
Natural gas production represented approximately 71% of the Company's total
production volume on an equivalent basis in the Transition Period, compared to
82% in the Prior Period. This decrease in gas production as a percentage of
total production was primarily the result of new production in the Louisiana
Trend, which tends to produce more oil than gas.
For the Transition Period, the Company realized an average price per barrel
of oil of $18.59, compared to $21.88 in the Prior Period. Gas price realizations
increased slightly from $2.18 per Mcf in the Prior Period to $2.24 per Mcf in
the Transition Period. The Company's hedging activities resulted in decreases in
oil and gas revenues of $4.3 million and $7.1 million in the Transition Period
and Prior Period, respectively.
Oil and Gas Marketing Sales. The Company realized $58.2 million in oil and
gas marketing sales for third parties in the Transition Period, with
corresponding oil and gas marketing expenses of $58.2 million. This compares to
sales of $30.0 million, expenses of $29.5 million, and a margin of $0.5 million
in the Prior Period.
Production Expenses and Taxes. Production expenses and taxes, which include
lifting costs, production taxes and excise taxes, increased to $10.1 million in
the Transition Period, compared to $5.9 million in the Prior Period. These
increases were primarily the result of increased operating costs and increased
production. On a unit of production basis, production expenses and taxes
increased to $0.27 per Mcfe compared to $0.16 per Mcfe in the Prior Period.
Impairment of Oil and Gas Properties. The Company incurred an impairment of
oil and gas properties charge of $110.0 million for the Transition Period. This
writedown was caused by several factors, including oil prices declining from
$18.38 at June 30, 1997 to $17.62 at December 31, 1997, and drilling and
completion costs continuing to escalate during the Transition Period. Higher
costs caused the Company's capital spending to exceed budgeted amounts during
the Transition Period and also increased the estimated future capital
expenditures to be incurred to develop the Company's proved undeveloped
reserves. The Company's results from wells completed during the Transition
Period in the Louisiana Trend continued to be inconsistent and production
performance from various properties in the Navasota River and Independence areas
were lower than projected at June 30, 1997. As a result of the above factors,
the Company recorded a downward revision to its proved reserves of 38 net Bcfe
in the Austin Chalk Trend as of December 31, 1997.
Excluding the purchase of additional leasehold, the Company incurred
approximately $85 million in capital expenditures in the Louisiana Trend during
the Transition Period, of which approximately $67 million were incurred in the
Masters Creek area. Approximately $16 million of the drilling costs were
incurred on Company operated wells that had not been completed at December 31,
1997.
In the Masters Creek area, the Company completed operations on 11 wells
during the Transition Period. Although 10 of the 11 wells were commercially
productive, the drilling costs incurred through December 31, 1997 of
approximately $58 million for the 10 wells were higher than anticipated and
assigned reserves were lower than expected. The lower reserve quantities were
due in part to lower oil prices at December 31, 1997. In addition, the Company
transferred approximately $11 million of previously unevaluated leasehold costs
from all areas of the Louisiana Trend to the amortization base of the full-cost
pool during the Transition Period.
In connection with the Company's acquisition of AnSon Production Corporation
("AnSon") in December 1997, which was accounted for using the purchase method,
the purchase price of approximately $43 million was allocated
27
<PAGE> 28
to the fair value of assets acquired. Based upon reserve estimates as of
December 31, 1997, the portion of the purchase price which was allocated to
evaluated oil and gas properties exceeded the associated discounted future net
revenues from AnSon's estimated proved reserves by approximately $14 million.
Oil and Gas Depreciation, Depletion and Amortization. DD&A of oil and gas
properties for the Transition Period was $60.4 million, $24.2 million higher
than the Prior Period's expense of $36.2 million. The expense in the Transition
Period was computed prior to the writedown from the impairment of oil and gas
properties charge. The average DD&A rate per Mcfe increased to $1.57 in the
Transition Period compared to $0.99 in the Prior Period.
Depreciation and Amortization of Other Assets. D&A of other assets increased
to $2.4 million in the Transition Period, compared to $1.8 million in the Prior
Period. This increase was caused by increased investments in depreciable
buildings and equipment and increased amortization of debt issuance costs as a
result of the issuance of senior notes in March 1997.
General and Administrative. G&A expenses, which are net of capitalized
internal payroll and non-payroll expenses (see Note 11 of Notes to Consolidated
Financial Statements), were $5.8 million in the Transition Period, up 56% from
$3.7 million in the Prior Period. The increase in the Transition Period compared
to the Prior Period results primarily from increased personnel expenses required
by the Company's growth and industry wage inflation. The Company capitalized
$2.4 million of internal costs in the Transition Period directly related to the
Company's oil and gas exploration and development efforts, compared to $1.1
million in the Prior Period.
Interest and Other Income. Interest and other income for the Transition
Period was $79.0 million compared to $2.5 million in the Prior Period. During
the Transition Period, the Company realized a gain on the sale of its Bayard
common stock of $73.8 million, the most significant component of interest and
other income.
Interest Expense. Interest expense increased to $17.4 million in the
Transition Period, compared to $6.2 million in the Prior Period. The increase
was due primarily to the issuance of $300 million of senior notes in March 1997.
In addition to the interest expense reported, the Company capitalized $5.1
million of interest during the Transition Period, compared to $7.6 million
capitalized in the Prior Period.
Provision (Benefit) for Income Taxes. The Company recorded no income taxes
for the Transition Period, compared to income tax expense of $14.3 million in
the Prior Period, before consideration of the $3.7 million tax benefit
associated with an extraordinary loss from the early extinguishment of debt.
At December 31, 1997, the Company had a net operating loss carryforward of
approximately $337 million for regular federal income taxes which will expire in
future years beginning in 2007. Management believed that it could not be
demonstrated at that time that it was more likely than not that the deferred
income tax assets, comprised primarily of the net operating loss carryforward,
would be realizable in future years, and therefore a valuation allowance of
$77.9 million was recorded. No deferred tax benefit related to the exercise of
employee stock options was allocated to additional paid-in capital in the
Transition Period.
Fiscal Years Ended June 30, 1997 and 1996
General. For the fiscal year ended June 30, 1997, the Company realized a net
loss of $183.4 million, or $2.79 per common share, on total revenues of $280.3
million. This compares to net income of $23.4 million, or $0.40 per common
share, on total revenues of $149.4 million in 1996. The loss in fiscal 1997
resulted from a $236 million asset writedown recorded in the fourth quarter
under the full-cost method of accounting. See "Impairment of Oil and Gas
Properties".
Oil and Gas Sales. During fiscal 1997, oil and gas sales increased 74% to
$192.9 million versus $110.8 million for fiscal 1996. The increase in oil and
gas sales resulted primarily from strong growth in production volumes and
significantly higher average oil and gas prices. For fiscal 1997, the Company
produced 78.6 Bcfe at a weighted average price of $2.45 per Mcfe, compared to
60.2 Bcfe produced in fiscal 1996 at a weighted average price of $1.84 per Mcfe.
This represents production growth of 31% for fiscal 1997 compared to fiscal
1996.
28
<PAGE> 29
The following table shows the Company's production by region for fiscal 1997
and fiscal 1996:
<TABLE>
<CAPTION>
FOR THE YEAR ENDED JUNE 30,
---------------------------------------------------
1997 1996
----------------------- -----------------------
MMCFE PERCENT MMCFE PERCENT
--------- ---------- ---------- ---------
<S> <C> <C> <C> <C>
Mid-Continent................................................. 17,370 22% 10,420 17%
Gulf Coast.................................................... 57,377 73 47,234 78
Other areas................................................... 3,878 5 2,536 5
--------- ---------- ---------- ---------
Total production.............................................. 78,625 100% 60,190 100%
========= ========== ========== =========
</TABLE>
Natural gas production represented approximately 79% of the Company's total
production volume on an equivalent basis in fiscal 1997. This compares to 86% in
fiscal 1996 and 79% in fiscal 1995. This decrease in gas production as a
percentage of total production in fiscal 1997 was the result of drilling in the
Louisiana Trend, which tends to produce more oil than gas.
For fiscal 1997, the Company realized an average price per barrel of oil of
$20.93, compared to $17.85 in fiscal 1996. The Company markets its oil on
monthly average equivalent spot price contracts and typically receives a premium
to the price posted for West Texas Intermediate crude oil.
Gas price realizations increased from fiscal 1996 to 1997 from $1.66 per Mcf
to $2.18 per Mcf, or 31%, generally as the result of market conditions. The
Company's gas price realizations in fiscal 1997 were also higher due to the
increase in Louisiana Trend gas production, which generally receives premium
prices at least equivalent to Henry Hub indexes due to the high Btu content and
favorable market location of the production.
The Company's hedging activities resulted in decreases in oil and gas
revenues of $7.4 million and $5.9 million in fiscal 1997 and 1996, respectively.
Oil and Gas Marketing Sales. In December 1995, the Company entered into the
oil and gas marketing business by acquiring a subsidiary to provide natural gas
marketing services, including commodity price structuring, contract
administration and nomination services, for the Company, its partners and other
oil and natural gas producers in geographical areas in which the Company is
active. The Company realized $76.2 million in oil and gas marketing sales for
third parties in fiscal 1997, with corresponding oil and gas marketing expenses
of $75.1 million, resulting in a gross margin of $1.1 million. This compares to
sales of $28.4 million, expenses of $27.5 million, and a margin of $0.9 million
in fiscal 1996.
Oil and Gas Service Operations. On June 30, 1996, Peak USA Energy Services,
Ltd., a limited partnership ("Peak"), was formed by Peak Oilfield Services
Company (a joint venture between Cook Inlet Region, Inc. and Nabors Industries,
Inc.) and Chesapeake for the purpose of purchasing the Company's oilfield
service assets and providing rig moving, transportation and related site
construction services to the Company and others in the industry. The Company
sold its service company assets to Peak for $6.4 million, and simultaneously
invested $2.5 million in exchange for a 33.3% partnership interest in Peak. This
transaction resulted in recognition of a $1.8 million pre-tax gain during the
fourth fiscal quarter of 1996 (reported in interest and other revenues). A
deferred gain from the sale of service company assets of $0.9 million was
recorded as a reduction in the Company's investment in Peak and was amortized to
income over the estimated useful lives of the Peak assets. The Company's
investment in Peak was accounted for using the equity method, and resulted in
$0.5 million of income being included in interest and other revenues in fiscal
1997. The Company sold its partnership interest in Peak in June 1998.
Revenues from oil and gas service operations were $6.3 million in fiscal
1996. The related costs and expenses of these operations were $4.9 million for
the year ended June 30, 1996. The gross profit margin was 22% in fiscal 1996.
The gross profit margin derived from these operations is a function of drilling
activities in the period, costs of materials and supplies and the mix of
operations between lower margin trucking operations versus higher margin labor
oriented service operations.
29
<PAGE> 30
Production Expenses and Taxes. Production expenses and taxes, which include
lifting costs, production taxes and excise taxes, increased to $15.1 million in
fiscal 1997, compared to $8.3 million in fiscal 1996. This increase was
primarily the result of increased production. On a unit production basis,
production expenses and taxes increased to $0.19 per Mcfe, compared to $0.14 per
Mcfe in fiscal 1996. During fiscal 1996, a high proportion of the Company's
production was from the Giddings Field, much of which qualified for Texas
severance tax exemptions.
Impairment of Oil and Gas Properties. Prior to January 1997, the Company had
completed operations on one exploratory well in each of three separate areas
outside Masters Creek in the Louisiana Trend. Between April 1997 and July 1997,
the Company completed operations on 10 Company operated exploratory wells
located outside Masters Creek in the Louisiana Trend that resulted in the
addition of only 0.5 Bcfe of proved reserves. Cumulative well costs on these
non-Masters Creek properties were approximately $43 million as of June 30, 1997.
Of the 10 wells, one was completed on April 15, 1997, one on May 3, 1997 and
eight after June 1, 1997. Based upon this information and similar data which had
become available from outside operated properties in these non-Masters Creek
areas of the Louisiana Trend, management determined that a significant portion
of its leasehold in the Louisiana Trend outside of Masters Creek was impaired.
During the quarters ended March 31, 1997 and June 30, 1997, the Company
transferred $7.6 million and $86.3 million, respectively, of non-Masters Creek
Louisiana Trend leasehold costs to the amortization base of the full-cost pool.
The weighted average oil and gas prices used to value the Company's proved
reserves declined from $20.90 per Bbl and $2.41 per Mcf at June 30, 1996 to
$18.38 per Bbl and $2.12 per Mcf at June 30, 1997. Drilling and equipment costs
escalated rapidly in the fourth quarter of fiscal 1997 due primarily to higher
day rates for drilling rigs, thus increasing the estimated future capital
expenditures to be incurred to develop the Company's proved undeveloped
reserves. The oil and gas price declines and the increased costs to drill and
equip wells caused the Company to eliminate 35 gross proved undeveloped
locations in the Knox Field which contained an estimated 45 net Bcfe of proved
undeveloped reserves. Similar factors, combined with unfavorable drilling and
production results, eliminated approximately 93 Bcfe of proved reserves in the
Giddings and Louisiana Trend areas.
In the Independence area of the Giddings Field of Texas, a single well
completed in late March 1997, which the Company had estimated to contain 15.7
Bcfe of Company reserves at March 31, 1997, was significantly and adversely
affected by another operator's offset well which damaged the reservoir and
reduced the Company's estimated ultimate recovery to 8.0 Bcfe of reserves.
In late June 1997, management reviewed its March 31, 1997 internal estimates
of proved reserves and related present value and, after giving effect to the
fourth quarter 1997 drilling and production results, oil and gas prices, higher
drilling and completion costs, and additional leasehold acquisition costs and
delay rentals, determined that the Company had less reserve potential than had
previously been estimated. As a result, management estimated that at June 30,
1997 the Company would have capitalized costs of oil and gas properties which
would exceed its full-cost ceiling by approximately $150 million to $200
million. On June 27, 1997, the Company issued a press release which included
this estimate. Subsequently, based on the Company's final year-end estimates of
its proved reserves and related estimated future net revenues, which took into
account additional drilling and production results, management determined that
as of June 30, 1997, its capitalized costs exceeded its full-cost ceiling by
approximately $236 million. No such writedown was experienced by the Company in
fiscal 1996.
Oil and Gas Depreciation, Depletion and Amortization. DD&A of oil and gas
properties for fiscal 1997 was $103.3 million, $52.4 million higher than fiscal
1996's expense of $50.9 million. The expense in fiscal 1997 excluded the effects
of the asset writedown. The average DD&A rate per Mcfe, which is a function of
capitalized costs, future development costs, and the related underlying reserves
in the periods presented, increased to $1.31 in fiscal 1997 compared to $0.85 in
fiscal 1996.
Depreciation and Amortization of Other Assets. D&A of other assets increased
to $3.8 million in fiscal 1997, compared to $3.2 million in fiscal 1996. This
increase in fiscal 1997 was caused by an increase in D&A as a result of
increased investments in depreciable buildings and equipment and increased
amortization of debt issuance costs as a result of the issuance of senior notes
in May 1995, April 1996 and March 1997.
30
<PAGE> 31
General and Administrative. G&A expenses, which are net of capitalized
internal payroll and non-payroll expenses (see Note 11 of Notes to Consolidated
Financial Statements), were $8.8 million in fiscal 1997, up 83% from $4.8
million in fiscal 1996. The increase in fiscal 1997 compared to fiscal 1996 is
due primarily to increased personnel expenses required by the Company's growth
and industry wage inflation. The Company capitalized $3.9 million of internal
costs in fiscal 1997 directly related to the Company's oil and gas exploration
and development efforts, compared to $1.7 million in 1996.
Interest and Other Income. Interest and other income for fiscal 1997 was
$11.2 million compared to $3.8 million in fiscal 1996. During fiscal 1997, the
Company realized $8.7 million in interest, $1.6 million of other investment
income, $0.5 million from its investment in Peak, and $0.4 million in other
income. During fiscal 1996, the Company realized $3.7 million of interest and
other investment income and a $1.8 million gain related to the sale of certain
service company assets, offset by a $1.7 million loss due to natural gas basis
changes in April 1996 as a result of the Company's hedging activities.
Interest Expense. Interest expense increased to $18.6 million in fiscal 1997
as compared to $13.7 million in 1996. Interest expense in the fourth quarter of
fiscal 1997 was $8.7 million, reflecting the issuance of $300 million of senior
notes in March 1997. In addition to the interest expense reported, the Company
capitalized $12.9 million of interest during fiscal 1997, compared to $6.4
million capitalized in fiscal 1996.
Provision (Benefit) for Income Taxes. The Company recorded an income tax
benefit of $3.6 million for fiscal 1997, before consideration of the $3.8
million tax benefit associated with the extraordinary loss from the early
extinguishment of debt, compared to income tax expense of $12.9 million in 1996.
All of the income tax expense in 1996 was deferred due to tax net operating
losses and carryovers resulting from the Company's drilling program.
The Company's loss before income taxes and extraordinary item of $180.3
million created a tax benefit for financial reporting purposes of $67.7 million.
However, due to limitations on the recognition of deferred tax assets, the total
tax benefit was reduced to $3.6 million.
At June 30, 1997, the Company had a net operating loss carryforward of
approximately $300 million for regular federal income taxes which will expire in
future years beginning in 2007. Management believed that it could not be
demonstrated at that time that it was more likely than not that the deferred
income tax assets, comprised primarily of the net operating loss carryforward,
would be realizable in future years, and therefore a valuation allowance of
$64.1 million was recorded in fiscal 1997. A deferred tax benefit related to the
exercise of employee stock options of approximately $4.8 million was allocated
directly to additional paid-in capital in 1997, compared to $7.9 million in
1996.
LIQUIDITY AND CAPITAL RESOURCES
For the Years Ended December 31, 1998 and 1997
Cash Flows from Operating Activities. Cash provided by operating activities
(inclusive of changes in working capital) decreased to $94.6 million in the
Current Year, compared to $181.3 million in the Prior Year. This decrease of
$86.7 million was due primarily to reduced operating income resulting from
significant decreases in average oil and gas prices between periods, as well as
significant increases in G&A expenses and interest expense.
Cash Flows from Investing Activities. Cash used in investing activities
increased to $548.1 million in the Current Year, compared to $476.2 million in
the Prior Year. This increase was due primarily to the $279.9 million used to
acquire certain oil and gas properties and companies with oil and gas reserves
during the Current Year. However, the increase in cash used to acquire oil and
gas properties was partially offset by reduced expenditures during the Current
Year for exploratory and developmental drilling. During the Current Year and
Prior Year, the Company invested $260 million and $471 million, respectively,
for exploratory and developmental drilling. Also during the Current Year, the
Company sold its 19.9% stake in Pan East Petroleum Corp. to Poco Petroleums,
Ltd.
31
<PAGE> 32
for approximately $21.2 million. During the Prior Year the Company received net
proceeds from the sale of its investment in Bayard common stock of approximately
$73.8 million.
Cash Flows from Financing Activities. Cash provided by financing activities
increased to $363.8 million in the Current Year, compared to $278.0 million in
the Prior Year. During the Current Year, the Company retired $85 million of debt
assumed at the completion of the DLB Oil & Gas, Inc. acquisition, $120 million
of debt assumed at the completion of the Hugoton Energy Corporation acquisition,
$90 million of senior notes, and $170 million of borrowings made under its
commercial bank credit facilities. During the Current Year, the Company issued
$500 million in senior notes and $230 million in preferred stock. During the
Prior Year, the Company issued $300 million of senior notes.
For the Six Months Ended December 31, 1997 and 1996
Cash Flows from Operating Activities. Cash provided by operating activities
(inclusive of changes in components of working capital) increased to $139.2
million in the Transition Period, compared to $41.9 million in the Prior Period.
The primary reason for the increase was significant changes in the components of
current assets and liabilities, specifically $92 million of short-term
investments which were converted into cash during the Transition Period.
Cash Flows from Investing Activities. Cash used in investing activities
decreased to $136.5 million in the Transition Period, compared to $184.1 million
in the Prior Period. This decrease in cash used in investing activities was due
primarily to the $90.4 million received from the sale of the Company's
investment in Bayard common stock during the Transition Period, offset by other
investments. Approximately $189.8 million was expended by the Company in the
Transition Period for development and exploration of oil and gas properties, as
compared to $186.8 million in the Prior Period. In the Transition Period, other
property and equipment additions were $27.0 million primarily as a result of its
$11.9 million investment in the Louisiana Chalk Gathering System and Masters
Creek Gas Plant as well as additional investments in its Oklahoma City office
complex.
Cash Flows from Financing Activities. Cash used in financing activities was
$2.8 million during the Transition Period, compared to cash provided by
financing activities of $231.3 million during the Prior Period. The decrease was
due primarily to the proceeds received from the issuance of common stock during
the Prior Period of $288.1 million, which was partially offset by the net
payments on long-term borrowings of $56.8 million during the Prior Period.
For the Fiscal Years Ended June 30, 1997 and 1996
Cash Flows from Operating Activities. Cash provided by operating activities
(inclusive of changes in components of working capital) decreased to $84.1
million in fiscal 1997, compared to $121.0 million in fiscal 1996. The primary
reason for the decrease from fiscal 1996 to 1997 was significant changes in the
components of current assets and liabilities, specifically $102.9 million of
short-term investments at June 30, 1997.
Cash Flows from Investing Activities. Significantly higher cash was used in
fiscal 1997 for development, exploration and acquisition of oil and gas
properties compared to fiscal 1996. Approximately $524 million was expended by
the Company in fiscal 1997 (net of proceeds from sale of leasehold, equipment
and other), compared to $344 million in fiscal 1996. Net cash proceeds received
by the Company for sales of oil and gas equipment, leasehold and other decreased
to approximately $3.1 million in fiscal 1997, compared to $6.2 million in fiscal
1996. In fiscal 1997, other property and equipment additions were $34 million
primarily as a result of its $16.8 million investment in the Louisiana Chalk
Gathering System and Masters Creek Gas Plant as well as additional investments
in its Oklahoma City office complex.
Cash Flows from Financing Activities. On December 2, 1996, the Company
completed a public offering of 8,972,000 shares of common stock at a price of
$33.63 per share resulting in net proceeds to the Company of approximately
$288.1 million. Approximately $55.0 million of the proceeds was used to defease
the Company's
32
<PAGE> 33
$47.5 million senior notes due 2001, and $11.2 million of the proceeds was used
to retire all amounts outstanding under the Company's commercial bank credit
facilities.
On March 17, 1997, the Company concluded the sale of $150 million of 7.875%
senior notes due 2004, and $150 million of 8.5% senior notes due 2012, which
offering resulted in net proceeds to the Company of approximately $292.6
million. The 7.875% senior notes were issued at 99.92% of par and the 8.5%
senior notes were issued at 99.414% of par. The 7.875% senior notes and the 8.5%
senior notes are redeemable at the option of the Company at any time at the
redemption or make-whole prices set forth in the respective indentures.
In fiscal 1996, cash flows from financing activities were $219.5 million,
largely as the result of the issuance of 5,989,500 shares of common stock (net
proceeds to the Company of approximately $99.4 million) and $120 million of
9.125% senior notes due 2006.
Financial Flexibility and Liquidity
The Company had a working capital deficit of $13 million at December 31,
1998 and a cash balance of $30 million. The Company has a $50 million revolving
bank credit facility, which matures in August 1999, with an initial committed
borrowing base of $50 million. As of December 31, 1998, the Company had borrowed
$25 million under this facility, which was included in the working capital
deficit as a short-term obligation. Borrowings under the facility are secured by
certain producing oil and gas properties and bear interest at a rate of 7.75%
per annum as of December 31, 1998.
The senior note indentures contain various restrictions for the Company and
its restricted subsidiaries to incur additional indebtedness. As of December 31,
1998, the Company estimates that secured commercial bank indebtedness of $115
million could have been incurred within these restrictions. This restriction
does not apply to borrowings incurred by CEMI, an unrestricted subsidiary.
The senior note indentures also limit the Company's ability to make
restricted payments (as defined), including the payment of preferred stock
dividends, unless certain tests are met. As of December 31, 1998, the Company
was unable to meet the requirements to incur additional unsecured indebtedness,
and consequently was not able to pay cash dividends on its 7% cumulative
convertible preferred stock on February 1, 1999. Subsequent payments will be
subject to the same restrictions and are dependent upon variables 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.
Debt ratings for the senior notes are B3 by Moody's Investors Service and B
by Standard & Poor's Corporation as of March 19, 1999, and both have placed the
Company on review with negative implications. There are no scheduled principal
payments required on any of the senior notes until March 2004.
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 capital expenditure budget for exploration and development
activities during 1999, which are currently estimated to be approximately $90
million. The Company anticipates proceeds from miscellaneous asset sales will be
approximately $45 million during 1999. However, continued low oil and gas prices
or unfavorable drilling results could cause the Company to further reduce its
drilling program, which is largely discretionary.
YEAR 2000
Project. The Company has placed a high priority on proactively resolving
computer or embedded chip problems related to the "Year 2000" which may have
adverse material effects on its continuing operations or cash flow. This problem
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
33
<PAGE> 34
would most typically be caused by erroneous date calculations, which result 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 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 is taking 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 in use at the Company is available and has been
scheduled for implementation during the third quarter of 1999. The production
accounting system in use at the Company is also scheduled for upgrade to a Year
2000 compliant version during the first half of 1999. The timing of these
upgrades have been scheduled to be concurrent with the respective vendors'
support requirements and to take advantage of additional feature 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. Assessment continues
for lower priority software systems.
In addition, the Year 2000 compliant AS/400, on which the accounting package
resides, was upgraded to provide additional capacity in late 1997. Operating
system upgrades will be implemented in the near future for the Windows NT based
servers to complete their remediation.
Other activities either already underway or scheduled include testing of
desktop PCs, 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:
<TABLE>
<CAPTION>
PHASE
ASSESSMENT/ REMEDIATION/
COMPONENT INVENTORY PRIORITIZATION CONTINGENCY
------------------------------ ------------- -------------- -------------
<S> <C> <C> <C>
Software March 1999 May 1999 September 1999
Hardware March 1999 April 1999 June 1999
Business partners March 1999 May 1999 June 30, 1999
Embedded systems (non-IT systems) May 1999 June 1999 September 1999
</TABLE>
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.
Cost. To date, the Company has incurred minimal consulting costs for Year
2000 project planning and scope definition. The Company plans to acquire a Year
2000 assessment and testing suite in early 1999 for approximately $50,000 and to
use contract staff to assist in the financial systems upgrade at a projected
cost of $70,000. 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 and 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 a serious adverse impact on the
34
<PAGE> 35
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 September 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 is
effective for all fiscal quarters of fiscal years beginning after June 15, 1999.
FAS 133 standardizes the accounting for derivative instruments by requiring
that all derivatives be recognized as assets and liabilities and measured at
fair value. The accounting for changes in the fair value of derivatives (gains
and losses) depends on (i) whether the derivative is designated and qualifies as
a hedge, and (ii) the type of hedging relationship that exists. Changes in the
fair value of derivatives that are not designated as hedges or that do not meet
the hedge accounting criteria in FAS 133 are required to be reported in
earnings. In addition, all hedging relationships must be designated, reassessed
and documented pursuant to the provisions of FAS 133. 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-K 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-K, 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
Item 1 of this Form 10-K, 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, restrictions imposed by lenders,
liquidity and capital requirements, the effects of governmental and
environmental regulation, pending patent and securities 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 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 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
COMMODITY PRICE RISK
The Company's results of operations are highly dependent upon the prices
received for oil and natural gas production.
35
<PAGE> 36
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 commodity 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 commodity hedging transactions related to the Company's oil and gas
production volumes or CEMI's physical purchase or sale commitments. Gains or
losses on crude oil and natural gas hedging transactions are recognized as price
adjustments in the months of related production.
As of December 31, 1998, the Company had the following natural gas swap
arrangements designed to hedge a portion of the Company's domestic gas
production for periods after December 1998:
<TABLE>
<CAPTION>
NYMEX-INDEX
VOLUME STRIKE PRICE
MONTHS (MMBTU) (PER MMBTU)
- ------ ------------- -------------
<S> <C> <C>
February 1999.................................................................... 4,300,000 $ 1.968
March 1999....................................................................... 4,600,000 1.968
April 1999....................................................................... 4,500,000 1.968
May 1999......................................................................... 4,600,000 1.968
June 1999........................................................................ 1,200,000 1.950
July 1999........................................................................ 1,240,000 1.950
August 1999...................................................................... 1,240,000 1.950
September 1999................................................................... 1,200,000 1.950
</TABLE>
During 1998, the Company closed transactions for natural gas previously
hedged for the period April 1999 through November 1999 for net proceeds of $0.5
million.
Subsequent to December 31, 1998, the Company entered into additional natural
gas swap arrangements for 6,100,000 MMBtu at a strike price of $1.875 for the
period from June 1999 through September 1999. Such swap arrangements, along with
those listed above and other miscellaneous transactions, were closed as of March
15, 1999, resulting in net proceeds of $4.7 million.
As of December 31, 1998, the Company had the following natural gas swap
arrangements designed to hedge a portion of the Company's Canadian gas
production for periods after December 1998:
<TABLE>
<CAPTION>
VOLUME INDEX STRIKE PRICE
MONTHS (MMBTU) (PER MMBTU)
- ------ --------------- -----------------
<S> <C> <C>
January 1999........................................................... 589,000 $ 1.60
February 1999.......................................................... 532,000 1.60
March 1999............................................................. 589,000 1.60
April 1999............................................................. 570,000 1.60
May 1999............................................................... 589,000 1.60
June 1999.............................................................. 570,000 1.60
July 1999.............................................................. 589,000 1.60
August 1999............................................................ 589,000 1.60
September 1999......................................................... 570,000 1.60
</TABLE>
If the swap arrangements listed above had been settled on December 31, 1998,
the Company would have incurred a loss of $0.8 million.
36
<PAGE> 37
As of December 31, 1998, the Company had the following oil swap arrangements
for periods after December 1998:
<TABLE>
<CAPTION>
NYMEX HEATING OIL
MINUS
MONTHLY NYMEX CRUDE OIL
VOLUME INDEX STRIKE PRICE
MONTHS (BBLS) (PER BBL)
- ------ --------------- ----------------
<S> <C> <C>
January 1999........................................................... 217,000 $ 2.957
February 1999.......................................................... 196,000 2.957
March 1999............................................................. 155,000 2.900
</TABLE>
If the swap arrangements listed above had been settled on December 31, 1998,
the Company would have incurred a loss of $0.2 million. Subsequent to December
31, 1998, the Company settled the swap arrangements listed above for the periods
of January 1999 and February 1999 resulting in a $0.4 million loss.
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. For the year ended December 31, 1998, the Company's interest rate swap
resulted in a $0.7 million reduction of interest expense.
The table below presents principal cash flows and related weighted average
interest rates by expected maturity dates. As of December 31, 1998, the carrying
amounts of short-term borrowings are representative of fair values because of
the short-term maturity of these instruments. The fair value of the long-term
debt has been estimated based on quoted market prices.
<TABLE>
<CAPTION>
DECEMBER 31, 1998
----------------------------------------------------------------------------------------
EXPECTED FISCAL YEAR OF MATURITY
----------------------------------------------------------------------------------------
1999 2000 2001 2002 2003 THEREAFTER TOTAL FAIR VALUE
-------- ------- ------- ------- ------- ---------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
LIABILITIES: ($ IN MILLIONS)
Short-term debt - variable rate ........ $ 25 $ -- $ -- $ -- $ -- $ -- $ 25 $ 25
Average interest rate ................ 7.75% -- -- -- -- --
Long-term debt, including current
portion - fixed rate ................. $ -- $ -- $ -- $ -- $ -- $ 920 $ 920 $ 655
Average interest rate ................ -- -- -- -- -- 9.1%
</TABLE>
37
<PAGE> 38
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Consolidated Financial Statements:
Report of Independent Accountants for the Year Ended December 31, 1998, for the Six Months Ended
December 31, 1997 and for the Years Ended June 30, 1997 and 1996.......................................... 39
Consolidated Balance Sheets at December 31, 1998 and 1997 and at June 30, 1997................................ 40
Consolidated Statements of Operations for the Year Ended December 31, 1998, for the Six Months Ended
December 31, 1997 and for the Years Ended June 30, 1997 and 1996.......................................... 41
Consolidated Statements of Cash Flows for the Year Ended December 31, 1998, for the Six Months Ended
December 31, 1997 and for the Years Ended June 30, 1997 and 1996.......................................... 42
Consolidated Statements of Stockholders' Equity (Deficit) and Comprehensive Income (Loss) for the Year
Ended December 31, 1998, for the Six Months Ended December 31, 1997 and for the Years Ended
June 30, 1997 and 1996..................................................................................... 44
Notes to Consolidated Financial Statements..................................................................... 45
Financial Statement Schedules:
Schedule II - Valuation and Qualifying Accounts................................................................ 77
</TABLE>
38
<PAGE> 39
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders
of Chesapeake Energy Corporation
In our opinion, the consolidated financial statements listed in the
accompanying index present fairly, in all material respects, the financial
position of Chesapeake Energy Corporation and its subsidiaries (the "Company")
at December 31, 1998 and 1997, and at June 30, 1997, and the results of their
operations and their cash flows for the year ended December 31, 1998, for the
six months ended December 31, 1997, and for the years ended June 30, 1997 and
1996, in conformity with generally accepted accounting principles. In addition,
in our opinion, the financial statement schedules listed in the accompanying
index presents fairly, in all material respects, the information set forth
therein when read in conjunction with the related consolidated financial
statements. These financial statements and financial statement schedules are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
PRICEWATERHOUSECOOPERS LLP
Oklahoma City, Oklahoma
March 18, 1999
39
<PAGE> 40
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
-------------------------- -----------
1998 1997 1997
----------- ----------- -----------
($ IN THOUSANDS)
<S> <C> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents ................................................. $ 29,520 $ 123,860 $ 124,017
Restricted cash ........................................................... 5,754 -- --
Short-term investments .................................................... -- 12,570 104,485
Accounts receivable:
Oil and gas sales ....................................................... 13,835 10,654 10,906
Oil and gas marketing sales ............................................. 19,636 20,493 19,939
Joint interest and other, net of allowances of $3,209,000, $691,000
and $387,000, respectively ............................................ 27,373 38,781 25,311
Related parties ......................................................... 15,455 4,246 7,401
Inventory ................................................................. 5,325 5,493 4,854
Other ..................................................................... 1,101 1,624 692
----------- ----------- -----------
Total Current Assets ............................................... 117,999 217,721 297,605
----------- ----------- -----------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at cost based on full-cost accounting:
Evaluated oil and gas properties ........................................ 2,142,943 1,095,363 865,516
Unevaluated properties .................................................. 52,687 125,155 128,505
Less: accumulated depreciation, depletion and
amortization .......................................................... (1,574,282) (602,391) (431,983)
----------- ----------- -----------
621,348 618,127 562,038
Other property and equipment .............................................. 79,718 67,633 50,379
Less: accumulated depreciation and amortization ........................... (37,075) (6,573) (5,051)
----------- ----------- -----------
Total Property and Equipment ....................................... 663,991 679,187 607,366
----------- ----------- -----------
OTHER ASSETS ................................................................ 30,625 55,876 44,097
----------- ----------- -----------
TOTAL ASSETS ................................................................ $ 812,615 $ 952,784 $ 949,068
=========== =========== ===========
</TABLE>
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
<TABLE>
<S> <C> <C> <C>
CURRENT LIABILITIES:
Notes payable and current maturities of long-term debt .................... $ 25,000 $ -- $ 1,380
Accounts payable .......................................................... 36,854 81,775 86,817
Accrued liabilities and other ............................................. 46,572 42,733 28,701
Revenues and royalties due others ......................................... 22,858 28,972 29,428
----------- ----------- -----------
Total Current Liabilities .......................................... 131,284 153,480 146,326
----------- ----------- -----------
LONG-TERM DEBT, NET ......................................................... 919,076 508,992 508,950
----------- ----------- -----------
REVENUES AND ROYALTIES DUE OTHERS ........................................... 10,823 10,106 6,903
----------- ----------- -----------
CONTINGENCIES AND COMMITMENTS (NOTE 4)
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred Stock, $.01 par value, 10,000,000 shares authorized; 4,600,000, 0
and 0 shares of 7% cumulative convertible stock issued and outstanding at
December 31, 1998 and 1997, and
June 30, 1997, respectively, entitled in liquidation to $230 million .... 230,000 -- --
Common Stock, par value of $.01, 250,000,000 shares authorized;
105,213,750, 74,298,061 and 70,276,975 shares issued and outstanding
at December 31, 1998 and 1997, and June 30, 1997, respectively .......... 1,052 743 703
Paid-in capital ........................................................... 682,263 460,770 432,991
Accumulated earnings (deficit) ............................................ (1,127,195) (181,270) (146,805)
Accumulated other comprehensive income (loss) ............................. (4,726) (37) --
Less: treasury stock, at cost; 8,503,300, 0 and 0 shares at
December 31, 1998 and 1997, and June 30, 1997, respectively ............... (29,962) -- --
----------- ----------- -----------
Total Stockholders' Equity (Deficit) ............................... (248,568) 280,206 286,889
----------- ----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) ........................ $ 812,615 $ 952,784 $ 949,068
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
40
<PAGE> 41
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS ENDED YEAR ENDED JUNE 30,
DECEMBER 31, DECEMBER 31, --------------------------
1998 1997 1997 1996
----------- ----------- ----------- -----------
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
REVENUES:
Oil and gas sales ............................................... $ 256,887 $ 95,657 $ 192,920 $ 110,849
Oil and gas marketing sales ..................................... 121,059 58,241 76,172 28,428
Oil and gas service operations .................................. -- -- -- 6,314
----------- ----------- ----------- -----------
Total Revenues ................................................ 377,946 153,898 269,092 145,591
----------- ----------- ----------- -----------
OPERATING COSTS:
Production expenses ............................................. 51,202 7,560 11,445 6,340
Production taxes ................................................ 8,295 2,534 3,662 1,963
Oil and gas marketing expenses .................................. 119,008 58,227 75,140 27,452
Oil and gas service operations .................................. -- -- -- 4,895
Impairment of oil and gas properties ............................ 826,000 110,000 236,000 --
Impairment of other assets ...................................... 55,000 -- -- --
Oil and gas depreciation, depletion and amortization ............ 146,644 60,408 103,264 50,899
Depreciation and amortization of other assets ................... 8,076 2,414 3,782 3,157
General and administrative ...................................... 19,918 5,847 8,802 4,828
----------- ----------- ----------- -----------
Total Operating Costs ......................................... 1,234,143 246,990 442,095 99,534
----------- ----------- ----------- -----------
INCOME (LOSS) FROM OPERATIONS ..................................... (856,197) (93,092) (173,003) 46,057
----------- ----------- ----------- -----------
OTHER INCOME (EXPENSE):
Interest and other income ....................................... 3,926 78,966 11,223 3,831
Interest expense ................................................ (68,249) (17,448) (18,550) (13,679)
----------- ----------- ----------- -----------
(64,323) 61,518 (7,327) (9,848)
----------- ----------- ----------- -----------
INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY
ITEM ............................................................ (920,520) (31,574) (180,330) 36,209
PROVISION (BENEFIT) FOR INCOME TAXES .............................. -- -- (3,573) 12,854
----------- ----------- ----------- -----------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM ........................... (920,520) (31,574) (176,757) 23,355
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt,
net of applicable income tax of $0 and $3,804,000,
respectively .................................................. (13,334) -- (6,620) --
----------- ----------- ----------- -----------
NET INCOME (LOSS) ................................................. (933,854) (31,574) (183,377) 23,355
PREFERRED STOCK DIVIDENDS ......................................... (12,077) -- -- --
----------- ----------- ----------- -----------
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS ................ $ (945,931) $ (31,574) $ (183,377) $ 23,355
=========== =========== =========== ===========
EARNINGS (LOSS) PER COMMON SHARE:
EARNINGS (LOSS) PER COMMON SHARE-BASIC:
Income (loss) before extraordinary item ....................... $ (9.83) $ (0.45) $ (2.69) $ 0.43
Extraordinary item ............................................ (0.14) -- (0.10) --
----------- ----------- ----------- -----------
Net income (loss) ............................................. $ (9.97) $ (0.45) $ (2.79) $ 0.43
=========== =========== =========== ===========
EARNINGS (LOSS) PER COMMON SHARE-ASSUMING DILUTION:
Income (loss) before extraordinary item ....................... $ (9.83) $ (0.45) $ (2.69) $ 0.40
Extraordinary item ............................................ (0.14) -- (0.10) --
----------- ----------- ----------- -----------
Net income (loss) ............................................. $ (9.97) $ (0.45) $ (2.79) $ 0.40
=========== =========== =========== ===========
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT
SHARES OUTSTANDING (IN 000'S):
Basic ......................................................... 94,911 70,835 65,767 54,564
=========== =========== =========== ===========
Assuming Dilution ............................................. 94,911 70,835 65,767 58,342
=========== =========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
41
<PAGE> 42
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS ENDED YEAR ENDED JUNE 30,
DECEMBER 31, DECEMBER 31, ----------------------------
1998 1997 1997 1996
------------ ------------ ------------ ------------
($ IN THOUSANDS)
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS) ................................................ $ (933,854) $ (31,574) $ (183,377) $ 23,355
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO
CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization ....................... 152,204 62,028 105,591 52,768
Impairment of oil and gas assets ............................... 826,000 110,000 236,000 --
Impairment of other assets ..................................... 55,000 -- --
Deferred taxes ................................................. -- -- (3,573) 12,854
Amortization of loan costs ..................................... 2,516 794 1,455 1,288
Amortization of bond discount .................................. 98 41 217 563
Bad debt expense ............................................... 1,589 40 299 114
Gain on sale of Bayard stock ................................... -- (73,840) -- --
Gain on sale of fixed assets ................................... (90) (209) (1,593) (2,511)
Extraordinary loss ............................................. 13,334 -- 6,620 --
Equity in (earnings) losses from investments ................... 703 592 (499) --
------------ ------------ ------------ ------------
Cash provided by operating activities before changes in current
assets and liabilities ....................................... 117,500 67,872 161,140 88,431
------------ ------------ ------------ ------------
CHANGES IN ASSETS AND LIABILITIES:
(Increase) decrease in short-term investments .................. 12,027 92,127 (102,858) 622
(Increase) decrease in accounts receivable ..................... 12,191 (7,173) (19,987) (3,524)
(Increase) decrease in inventory ............................... 168 (1,584) (1,467) 78
(Increase) decrease in other current assets .................... 7,637 (1,519) 1,466 (1,525)
Increase (decrease) in accounts payable, accrued
liabilities and other ........................................ (46,785) (11,044) 48,085 25,834
Increase (decrease) in current and non-current revenues
and royalties due others ..................................... (8,099) 478 (2,290) 11,056
------------ ------------ ------------ ------------
Changes in assets and liabilities ............................ (22,861) 71,285 (77,051) 32,541
------------ ------------ ------------ ------------
Cash provided by operating activities ........................ 94,639 139,157 84,089 120,972
------------ ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of oil and gas properties .......... (260,006) (189,755) (468,462) (342,045)
Acquisitions of oil and gas companies and properties, net of
cash acquired ................................................ (279,924) -- -- --
Investment in preferred stock of Gothic Energy Corporation ..... (39,500) -- -- --
Proceeds from sale of oil and gas equipment, leasehold and
other ........................................................ 16,008 2,503 3,095 6,167
Net proceeds from sale of Bayard stock ......................... -- 90,380 -- --
Repayment of note receivable ................................... 2,000 18,000 -- --
Proceeds from sale of investment in PanEast .................... 21,245 -- --
Other proceeds from sales ...................................... 3,600 17 6,428 698
Long-term loans made to third parties .......................... -- -- (20,000) --
Investment in oil field service company ........................ -- (200) (3,048) --
Investment in gas marketing company, net of cash acquired ...... -- -- -- (363)
Other investments .............................................. -- (30,434) (8,000) --
Other property and equipment additions ......................... (11,473) (27,015) (33,867) (8,846)
------------ ------------ ------------ ------------
Cash used in investing activities ............................ (548,050) (136,504) (523,854) (344,389)
------------ ------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common stock ......................... -- -- 288,091 99,498
Proceeds from long-term borrowings ............................. 658,750 -- 342,626 166,667
Payments on long-term borrowings ............................... (474,166) -- (119,581) (48,634)
Dividends paid on common stock ................................. (5,592) (2,810) -- --
Dividends paid on preferred stock .............................. (8,050) -- -- --
Proceeds from issuance of preferred stock ...................... 222,663 -- -- --
Purchase of treasury stock ..................................... (29,962) -- -- --
Cash received from exercise of stock options ................... -- 322 1,387 1,989
Other financing ................................................ 154 (322) (379) --
------------ ------------ ------------ ------------
Cash provided by (used in) financing activities .............. 363,797 (2,810) 512,144 219,520
------------ ------------ ------------ ------------
EFFECT OF EXCHANGE RATE CHANGES ON CASH .......................... (4,726) -- -- --
------------ ------------ ------------ ------------
Net increase (decrease) in cash and cash equivalents ............. (94,340) (157) 72,379 (3,897)
Cash and cash equivalents, beginning of period ................... 123,860 124,017 51,638 55,535
------------ ------------ ------------ ------------
Cash and cash equivalents, end of period ......................... $ 29,520 $ 123,860 $ 124,017 $ 51,638
============ ============ ============ ============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
42
<PAGE> 43
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS -- (CONTINUED)
<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS ENDED YEAR ENDED JUNE 30,
DECEMBER 31, DECEMBER 31, ---------------------
1998 1997 1997 1996
------------- ------------- --------- ---------
($ IN THOUSANDS)
<S> <C> <C> <C> <C>
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAYMENTS FOR:
Interest, net of capitalized interest ......................... $ 59,881 $ 17,367 $ 12,919 $ 10,751
Income taxes .................................................. $ -- $ 500 $ -- $ --
DETAILS OF ACQUISITION OF ANSON PRODUCTION CORPORATION:
Fair value of assets acquired ................................. $ -- $ 43,000 $ -- $ --
Accrued liability for estimated cash consideration ............ $ -- $ (15,500) $ -- $ --
Stock issued (3,792,724 shares) ............................... $ -- $ (27,500) $ -- $ --
DETAILS OF ACQUISITION OF DLB OIL & GAS, INC.:
Fair value of assets acquired ................................. $ 136,500 $ -- $ -- $ --
Cash consideration ............................................ $ (17,500) $ -- $ -- $ --
Stock issued (5,000,000 shares) ............................... $ (30,000) $ -- $ -- $ --
Debt assumed .................................................. $ (85,000) $ -- $ -- $ --
Acquisition costs paid ........................................ $ (4,000) $ -- $ -- $ --
DETAILS OF ACQUISITION OF HUGOTON ENERGY CORPORATION:
Fair value of assets acquired ................................. $ 343,371 $ -- $ -- $ --
Stock options granted ......................................... $ (2,050) $ -- $ -- $ --
Stock issued (25,790,146 shares) .............................. $ (206,321) $ -- $ -- $ --
Debt assumed .................................................. $ (120,000) $ -- $ -- $ --
Acquisition costs paid ........................................ $ (15,000) $ -- $ -- $ --
</TABLE>
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:
The Company had a financing arrangement with a vendor to supply certain oil
and gas equipment inventory, which was terminated during the Transition Period.
The total amounts owed at June 30, 1997 and 1996 were $1,380,000 and $3,156,000,
respectively. No cash consideration is exchanged for inventory under this
financing arrangement until actual draws on the inventory are made.
In fiscal 1997 and 1996, the Company recognized income tax benefits of
$4,808,000 and $7,950,000, respectively, related to the disposition of stock
options by directors and employees of the Company. The tax benefits were
recorded as an adjustment to deferred income taxes and paid-in capital.
Proceeds from the issuance of $500 million of 9.625% senior notes in April
1998, $300 million of senior notes ($150 million of 7.875% senior notes and $150
million of 8.5% senior notes) in March 1997, and $120 million of 9.125% senior
notes in April 1996 are net of $11.7 million, $6.4 million and $3.9 million,
respectively, in offering fees and expenses which were deducted from the actual
cash received.
On December 22, 1997, the Company declared a dividend of $0.02 per common
share, or $1,486,000, which was paid on January 15, 1998. On June 13, 1997 the
Company declared a dividend of $0.02 per common share, or $1,405,000, which was
paid on July 15, 1997.
The accompany notes are an integral part of these consolidated financial
statements.
43
<PAGE> 44
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) AND
COMPREHENSIVE INCOME (LOSS)
<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS ENDED YEAR ENDED JUNE 30,
DECEMBER 31, DECEMBER 31, --------------------------
1998 1997 1997 1996
------------- ------------- ----------- -----------
($ IN THOUSANDS)
<S> <C> <C> <C> <C>
PREFERRED STOCK:
Balance, beginning of period ................................... $ -- $ -- $ -- $ --
Issuance of preferred stock .................................... 230,000 -- -- --
------------- ------------- ----------- -----------
Balance, end of period ......................................... 230,000 -- -- --
------------- ------------- ----------- -----------
COMMON STOCK:
Balance, beginning of period ................................... 743 703 3,008 58
Issuance of 8,972,000 shares of common stock ................... -- -- 90 --
Issuance of 5,989,500 shares of common stock ................... -- -- -- 299
Exercise of stock options and warrants ......................... -- 2 12 79
Issuance of 3,792,724 shares of common stock
to AnSon Production Corporation .......................... -- 38 -- --
Issuance of 25,790,146 shares of common stock to
Hugoton Energy Corporation ................................... 258 -- -- --
Issuance of 5,000,000 shares of common stock to
DLB Oil and Gas, Inc. ........................................ 50 -- -- --
Change in par value and other .................................. 1 -- (2,407) 2,572
------------- ------------- ----------- -----------
Balance, end of period ......................................... 1,052 743 703 3,008
------------- ------------- ----------- -----------
PAID-IN CAPITAL:
Balance, beginning of period ................................... 460,733 432,991 136,782 30,295
Exercise of stock options and warrants ......................... 153 320 1,375 1,910
Issuance of common stock ....................................... 236,013 27,459 301,593 105,516
Offering expenses and other .................................... (16,686) -- (13,974) (6,317)
Stock options issued in Hugoton purchase ....................... 2,050 -- -- --
Tax benefit from exercise of stock options ..................... -- -- 4,808 7,950
Change in par value ............................................ -- -- 2,407 (2,572)
------------- ------------- ----------- -----------
Balance, end of period ......................................... 682,263 460,770 432,991 136,782
------------- ------------- ----------- -----------
ACCUMULATED EARNINGS (DEFICIT):
Balance, beginning of period ................................... (181,270) (146,805) 37,977 14,622
Net income (loss) .............................................. (933,854) (31,574) (183,377) 23,355
Dividends on common stock ...................................... (4,021) (2,891) (1,405) --
Dividends on preferred stock ................................... (8,050) -- -- --
------------- ------------- ----------- -----------
Balance, end of period ......................................... (1,127,195) (181,270) (146,805) 37,977
------------- ------------- ----------- -----------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):
Balance, beginning of period ................................... (37) -- -- --
Foreign currency translation adjustments ....................... (4,689) (37) -- --
------------- ------------- ----------- -----------
Balance, end of period ......................................... (4,726) (37) -- --
------------- ------------- ----------- -----------
TREASURY STOCK:
Balance, beginning of period ................................... -- -- -- --
Purchases of treasury stock .................................... (29,962) -- -- --
------------- ------------- ----------- -----------
Balance, end of period ......................................... (29,962) -- -- --
------------- ------------- ----------- -----------
TOTAL STOCKHOLDERS' EQUITY (DEFICIT) ............................. $ (248,568) $ 280,206 $ 286,889 $ 177,767
============= ============= =========== ===========
COMPREHENSIVE INCOME (LOSS):
Net income (loss) .............................................. $ (933,854) $ (31,574) $ (183,377) $ 23,355
Other comprehensive income (loss) - foreign currency
translation adjustments ...................................... (4,689) (37) -- --
------------- ------------- ----------- -----------
Comprehensive income (loss) .................................... $ (938,543) $ (31,611) $ (183,377) $ 23,355
============= ============= =========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
44
<PAGE> 45
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Company
The Company is a petroleum exploration and production company engaged in the
acquisition, exploration, and development of properties for the production of
crude oil and natural gas from underground reservoirs. The Company's properties
are located in Oklahoma, Texas, Louisiana, Kansas, Montana, Colorado, North
Dakota, New Mexico and British Columbia, Canada.
The Company changed its fiscal year end from June 30 to December 31 in 1997.
The Company's results of operations and cash flows for the six months ended
December 31, 1997 (the "Transition Period") are included in these consolidated
financial statements.
Principles of Consolidation
The accompanying consolidated financial statements of Chesapeake Energy
Corporation include the accounts of its direct and indirect wholly-owned
subsidiaries (the "Company"). All significant intercompany accounts and
transactions have been eliminated. Investments in companies and partnerships
which give the Company significant influence, but not control, over the investee
are accounted for using the equity method.
Accounting Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the dates of the financial
statements and the reported amounts of revenues and expenses during the
reporting periods. Actual results could differ from those estimates.
Cash Equivalents
For purposes of the consolidated financial statements, the Company considers
investments in all highly liquid debt instruments with maturities of three
months or less at date of purchase to be cash equivalents.
Investments in Securities
The Company invests in various equity securities and short-term debt
instruments including corporate bonds and auction preferreds, commercial paper
and government agency notes. The Company has classified all of its short-term
investments in equity and debt instruments as trading securities, which are
carried at fair value with unrealized holding gains and losses included in
earnings. At December 31, 1998 and 1997, the Company had an unrealized holding
loss of $0 and $2.4 million, respectively, included in interest and other
income. At June 30, 1997, the Company had an unrealized holding loss of $0.6
million included in interest and other income. At June 30, 1996 the Company had
no trading securities. Investments in equity securities and limited partnerships
that do not have readily determinable fair values are stated at cost and are
included in noncurrent other assets. In determining realized gains and losses,
the cost of securities sold is based on the average cost method.
Inventory
Inventory consists primarily of tubular goods and other lease and well
equipment which the Company plans to utilize in its ongoing exploration and
development activities and is carried at the lower of cost or market using the
specific identification method.
45
<PAGE> 46
Oil and Gas Properties
The Company follows the full-cost method of accounting under which all costs
associated with property acquisition, exploration and development activities are
capitalized. The Company capitalizes internal costs that can be directly
identified with its acquisition, exploration and development activities and does
not include any costs related to production, general corporate overhead or
similar activities (see Note 11). Capitalized costs are amortized on a composite
unit-of-production method based on proved oil and gas reserves. As of December
31, 1998, approximately 76% of the Company's proved reserve value (based on SEC
PV10%) was evaluated by independent petroleum engineers, with the balance
evaluated by the Company's engineers. In addition, the company's engineers
evaluate all properties quarterly. The average composite rates used for
depreciation, depletion and amortization were $1.13 ($1.17 in U.S. and $0.43 in
Canada) per equivalent Mcf in 1998, $1.57 per equivalent Mcf in the Transition
Period and $1.31 and $0.85 per equivalent Mcf in fiscal 1997 and 1996,
respectively.
Proceeds from the sale of properties are accounted for as reductions to
capitalized costs unless such sales involve a significant change in the
relationship between costs and the value of proved reserves or the underlying
value of unproved properties, in which case a gain or loss is recognized. The
costs of unproved properties are excluded from amortization until the properties
are evaluated. The Company reviews all of its unevaluated properties quarterly
to determine whether or not and to what extent proved reserves have been
assigned to the properties, and otherwise if impairment has occurred.
Unevaluated properties are grouped by major producing area where individual
property costs are not significant, and assessed individually when individual
costs are significant.
The Company reviews the carrying value of its oil and gas properties under
the full-cost accounting rules of the Securities and Exchange Commission on a
quarterly basis. Under these rules, capitalized costs, less accumulated
amortization and related deferred income taxes, shall not exceed an amount equal
to the sum of the present value of estimated future net revenues less estimated
future expenditures to be incurred in developing and producing the proved
reserves, less any related income tax effects. During 1998, capitalized costs of
oil and gas properties exceeded the estimated present value of future net
revenues from the Company's proved reserves, net of related income tax
considerations, resulting in writedowns in the carrying value of oil and gas
properties of $826 million. During the Transition Period, capitalized costs of
oil and gas properties exceeded the estimated present value of future net
revenues from the Company's proved reserves, net of related income tax
considerations, resulting in a writedown in the carrying value of oil and gas
properties of $110 million. During fiscal 1997, capitalized costs of oil and gas
properties exceeded the estimated present value of future net revenues from the
Company's proved reserves, net of related income tax considerations, resulting
in a writedown in the carrying value of oil and gas properties of $236 million.
Other Property and Equipment
Other property and equipment consists primarily of gas gathering and
processing facilities, vehicles, land, office buildings and equipment, and
software. Major renewals and betterments are capitalized while the costs of
repairs and maintenance are charged to expense as incurred. The costs of assets
retired or otherwise disposed of and the applicable accumulated depreciation are
removed from the accounts, and the resulting gain or loss is reflected in
operations. Other property and equipment costs are depreciated on both
straight-line and accelerated methods. Buildings are depreciated on a
straight-line basis over 31.5 years. All other property and equipment are
depreciated over the estimated useful lives of the assets, which range from five
to seven years.
Capitalized Interest
During 1998, the Transition Period and fiscal 1997 and 1996, interest of
approximately $6.5 million, $5.1 million, $12.9 million and $6.4 million was
capitalized on significant investments in unproved properties that were not
being currently depreciated, depleted, or amortized and on which exploration
activities were in progress.
46
<PAGE> 47
Service Operations
Certain subsidiaries of the Company performed contract services on wells the
Company operated as well as for third parties until June 30, 1996. Oil and gas
service operations revenues and costs and expenses reflected in the accompanying
consolidated statement of operations for fiscal 1996 include amounts derived
from certain of the contractual services provided. The Company's economic
interest in its oil and gas properties was not affected by the performance of
these contractual services and all intercompany profits have been eliminated.
On June 30, 1996, Peak USA Energy Services, Ltd., a limited partnership
("Peak"), was formed by Peak Oilfield Services Company (a joint venture between
Cook Inlet Region, Inc. and Nabors Industries, Inc.) and the Company for the
purpose of purchasing the Company's oilfield service assets and providing rig
moving, transportation and related site construction services. The Company sold
its service company assets to Peak for $6.4 million and simultaneously invested
$2.5 million in exchange for a 33.3% partnership interest in Peak. This
transaction resulted in recognition of a $1.8 million pre-tax gain during the
fourth fiscal quarter of 1996 reported in interest and other. A deferred gain
from the sale of service company assets of $0.9 million was amortized to income
over the estimated useful lives of the Peak assets. The Company sold its
partnership interest in Peak in June 1998.
Income Taxes
The Company has adopted Statement of Financial Accounting Standards No. 109,
Accounting for Income Taxes ("SFAS 109"). SFAS 109 requires deferred tax
liabilities or assets to be recognized for the anticipated future tax effects of
temporary differences that arise as a result of the differences in the carrying
amounts and the tax bases of assets and liabilities.
Net Income (Loss) Per Share
In February 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 128, Earnings Per Share ("SFAS 128"). 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 is effective for financial statements
issued for periods ending after December 15, 1997 and requires restatement of
all prior period earnings per share amounts. The Company has adopted SFAS 128
and has restated all prior periods presented.
SFAS 128 requires a reconciliation of the numerators and denominators of the
basic and diluted EPS computations. For 1998, the Transition Period and fiscal
1997, there was no difference between actual weighted average shares
outstanding, which are used in computing basic EPS, and diluted weighted average
shares, which are used in computing diluted EPS. Options to purchase 11.3
million, 8.3 million and 7.9 million shares of common stock at weighted average
exercise prices of $1.86, $5.49 and $7.09 were outstanding during 1998, the
Transition Period and fiscal 1997 but were not included in the computation of
diluted EPS because the effect of these outstanding options would be
antidilutive. A reconciliation for fiscal 1996 is as follows:
<TABLE>
<CAPTION>
Income Shares Per Share
(Numerator) (Denominator) Amount
----------- ------------- ---------
<S> <C> <C> <C>
FOR THE YEAR ENDED JUNE 30, 1996:
BASIC EPS
Income available to common stockholders.. $ 23,355 54,564 $ 0.43
=======
EFFECT OF DILUTIVE SECURITIES
Employee stock options................... -- 3,778
-------- --------
DILUTED EPS
Income available to common stockholders
and assumed conversions............... $ 23,355 58,342 $ 0.40
======== ======== =======
</TABLE>
47
<PAGE> 48
Gas Imbalances -- Revenue Recognition
Revenues from the sale of oil and gas production are recognized when title
passes, net of royalties. The Company follows the "sales method" of accounting
for its gas revenue whereby the Company recognizes sales revenue on all gas sold
to its purchasers, regardless of whether the sales are proportionate to the
Company's ownership in the property. A liability is recognized only to the
extent that the Company has a net imbalance in excess of the remaining gas
reserves on the underlying properties. The Company's net imbalance positions at
December 31, 1998 and 1997 and June 30, 1997 were not material.
Hedging
The Company periodically uses certain instruments to hedge its exposure to
price fluctuations on oil and natural gas transactions and interest rates.
Recognized gains and losses on hedge contracts are reported as a component of
the related transaction. Results of oil and gas hedging transactions are
reflected in oil and gas sales to the extent related to the Company's oil and
gas production, in oil and gas marketing sales to the extent related to the
Company's marketing activities, and in interest expense to the extent so
related.
Debt Issue Costs
Included in other assets are costs associated with the issuance of the
Senior Notes. The remaining unamortized costs on these issuances of Senior Notes
at December 31, 1998 totaled $19.7 million and are being amortized over the life
of the Senior Notes.
Comprehensive Income
In 1998, the Company adopted SFAS No. 130, Reporting Comprehensive Income.
This statement establishes rules for the reporting of comprehensive income and
its components. Comprehensive income consists of net income and foreign currency
translation adjustments and is presented in the Consolidated Statements of
Stockholders' Equity (Deficit) and Comprehensive Income (Loss). The adoption of
SFAS 130 had no impact on total stockholders' equity. Prior year financial
statements have been reclassified to conform to the SFAS 130 requirements. All
balance sheet accounts of foreign operations are translated into U.S. dollars at
the year-end rate of exchange and statement of operations items are translated
at the weighted average exchange rates for the year.
Reclassifications
Certain reclassifications have been made to the consolidated financial
statements for the Transition Period and the years ended June 30, 1997 and 1996
to conform to the presentation used for the December 31, 1998 consolidated
financial statements.
2. SENIOR NOTES
On April 22, 1998, the Company issued $500 million principal amount of
9.625% Senior Notes due 2005 ("9.625% Senior Notes"). The 9.625% Senior Notes
are redeemable at the option of the Company at any time on or after May 1, 2002
at the redemption prices set forth in the indenture or at the make-whole prices,
as set forth in the indenture, if redeemed prior to May 1, 2002. The Company may
also redeem at its option up to $167 million of the 9.625% Senior Notes at
109.625% of their principal amount with the proceeds of an equity offering
completed prior to May 1, 2001.
On March 17, 1997, the Company issued $150 million principal amount of
7.875% Senior Notes due 2004 ("7.875% Senior Notes"). The 7.875% Senior Notes
are redeemable at the option of the Company at any time prior to
48
<PAGE> 49
March 15, 2004 at the make-whole prices determined in accordance with the
indenture.
Also on March 17, 1997, the Company issued $150 million principal amount of
8.5% Senior Notes due 2012 ("8.5% Senior Notes"). The 8.5% Senior Notes are
redeemable at the option of the Company at any time prior to March 15, 2004 at
the make-whole prices determined in accordance with the indenture and, on or
after March 15, 2004 at the redemption prices set forth therein.
On April 9, 1996, the Company issued $120 million principal amount of 9.125%
Senior Notes due 2006 ("9.125% Senior Notes"). The 9.125% Senior Notes are
redeemable at the option of the Company at any time prior to April 15, 2001 at
the make-whole prices determined in accordance with the indenture and, on or
after April 15, 2001 at the redemption prices set forth therein. The Company may
also redeem at its option at any time on or prior to April 15, 1999 up to $42
million of the 9.125% Senior Notes at 109.125% of the principal amount thereof
with the proceeds of an equity offering.
On May 25, 1995, the Company issued $90 million principal amount of 10.5%
Senior Notes due 2002 ("10.5% Senior Notes"). In April 1998, the Company
purchased all of its 10.5% Senior Notes for approximately $99 million. The early
retirement of these notes resulted in an extraordinary charge of $13.3 million.
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 the 9.625% Senior Notes, the 9.125% Senior Notes, the 7.875%
Senior Notes and the 8.5% Senior Notes have been fully and unconditionally
guaranteed, on a joint and several basis, by each of 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.
The senior note indentures also limit the Company's ability to make
restricted payments (as defined), including the payment of preferred stock
dividends, unless certain tests are met. As of December 31, 1998, the Company
was unable to meet the requirements to incur additional unsecured indebtedness,
and consequently was not able to pay cash dividends on its 7% cumulative
convertible preferred stock on February 1, 1999 (in the amount of $4,025,000).
Subsequent payments will be subject to the same restrictions and are dependent
upon variables that are beyond the Company's ability to predict. This
restriction does not affect the Company's ability to borrow under or expand its
secured commercial bank facility. If the Company fails to pay dividends for six
quarterly periods, the holders of preferred stock would be entitled to elect two
additional members to the Board.
Set forth below are condensed consolidating financial statements of the
Guarantor Subsidiaries, the Company's subsidiaries which are not guarantors of
the Senior Notes (the "Non-Guarantor Subsidiaries") and the Company. Separate
audited financial statements of each Guarantor Subsidiary have not been provided
because management has determined that they are not material to investors.
Chesapeake Energy Marketing, Inc. ("CEMI") was a Non-Guarantor Subsidiary
for all periods presented, and the following were additional Non-Guarantor
Subsidiaries: Chesapeake Acquisition Corporation during the Transition Period,
Chesapeake Canada Corporation during fiscal 1997, and Chesapeake Gas Development
Corporation during fiscal 1996. All of the Company's other subsidiaries were
Guarantor Subsidiaries during these periods.
49
<PAGE> 50
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 1998
($ IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED
------------ ------------ ----------- ------------ ------------
<S> <C> <C> <C> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents ................... $ (11,565) $ 7,000 $ 39,839 $ -- $ 35,274
Short-term investments ...................... -- -- -- -- --
Accounts receivable ......................... 54,384 29,641 270 (7,996) 76,299
Inventory ................................... 4,919 406 -- -- 5,325
Other ....................................... 721 15 365 -- 1,101
----------- ----------- ----------- ------------ ------------
Total Current Assets ................ 48,459 37,062 40,474 (7,996) 117,999
----------- ----------- ----------- ------------ ------------
PROPERTY AND EQUIPMENT:
Oil and gas properties ...................... 2,142,943 -- -- -- 2,142,943
Unevaluated leasehold ....................... 52,687 -- -- -- 52,687
Other property and equipment ................ 47,628 15,109 16,981 -- 79,718
Less: accumulated depreciation,
depletion and amortization ............... (1,601,931) (8,036) (1,390) -- (1,611,357)
----------- ----------- ----------- ------------ ------------
Net Property and Equipment ........... 641,327 7,073 15,591 -- 663,991
----------- ----------- ----------- ------------ ------------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES ....................... 473,578 -- 481,150 (954,728) --
----------- ----------- ----------- ------------ ------------
OTHER ASSETS .................................. 10,610 560 19,455 -- 30,625
----------- ----------- ----------- ------------ ------------
TOTAL ASSETS .................................. $ 1,173,974 $ 44,695 $ 556,670 $ (962,724) $ 812,615
=========== =========== =========== ============ ============
</TABLE>
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
CURRENT LIABILITIES:
Notes payable and current
maturities of long-term debt ............. $ 25,000 $ -- $ -- $ -- $ 25,000
Accounts payable and other .................. 80,786 15,992 17,529 (8,023) 106,284
----------- ----------- ----------- ------------ ------------
Total Current Liabilities ........... 105,786 15,992 17,529 (8,023) 131,284
----------- ----------- ----------- ------------ ------------
LONG-TERM DEBT ................................ -- -- 919,076 -- 919,076
----------- ----------- ----------- ------------ ------------
REVENUES AND ROYALTIES DUE
OTHERS ...................................... 10,823 -- -- -- 10,823
----------- ----------- ----------- ------------ ------------
DEFERRED INCOME TAXES ......................... -- -- -- -- --
----------- ----------- ----------- ------------ ------------
INTERCOMPANY PAYABLES ......................... 1,338,948 11,376 (1,350,351) 27 --
----------- ----------- ----------- ------------ ------------
STOCKHOLDERS' EQUITY (DEFICIT):
Common Stock ................................ 26 1 957 (17) 967
Other ....................................... (281,609) 17,326 969,459 (954,711) (249,535)
----------- ----------- ----------- ------------ ------------
(281,583) 17,327 970,416 (954,728) (248,568)
----------- ----------- ----------- ------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY (DEFICIT) ............................ $ 1,173,974 $ 44,695 $ 556,670 $ (962,724) $ 812,615
=========== =========== =========== ============ ============
</TABLE>
50
<PAGE> 51
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 1997
($ IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------- -------------
<S> <C> <C> <C> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents .................. $ (589) $ 13,999 $ 110,450 $ -- $ 123,860
Short-term investments ..................... -- -- 12,570 -- 12,570
Accounts receivable ........................ 57,476 22,882 1,524 (7,708) 74,174
Inventory .................................. 4,918 575 -- -- 5,493
Other ...................................... 1,613 1 10 -- 1,624
------------ ------------ ------------ ------------- -------------
Total Current Assets ............... 63,418 37,457 124,554 (7,708) 217,721
------------ ------------ ------------ ------------- -------------
PROPERTY AND EQUIPMENT:
Oil and gas properties ..................... 1,056,118 39,245 -- -- 1,095,363
Unevaluated leasehold ...................... 125,155 -- -- -- 125,155
Other property and equipment ............... 41,740 10,471 15,422 -- 67,633
Less: accumulated depreciation,
depletion and amortization .............. (593,359) (14,650) (955) -- (608,964)
------------ ------------ ------------ ------------- -------------
Net property and equipment ........ 629,654 35,066 14,467 -- 679,187
------------ ------------ ------------ ------------- -------------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES ...................... 91,883 39,830 903,713 (1,035,426) --
------------ ------------ ------------ ------------- -------------
OTHER ASSETS ................................. 10,189 6,918 38,769 -- 55,876
------------ ------------ ------------ ------------- -------------
TOTAL ASSETS ................................. $ 795,144 $ 119,271 $ 1,081,503 $ (1,043,134) $ 952,784
============ ============ ============ ============= =============
</TABLE>
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
CURRENT LIABILITIES:
Notes payable and current
maturities of long-term debt ............ $ -- $ -- $ -- $ -- $ --
Accounts payable and other ................. 104,259 29,649 27,280 (7,708) 153,480
------------ ------------ ------------ ------------- -------------
Total Current Liabilities .......... 104,259 29,649 27,280 (7,708) 153,480
------------ ------------ ------------ ------------- -------------
LONG-TERM DEBT ............................... -- -- 508,992 -- 508,992
------------ ------------ ------------ ------------- -------------
REVENUES AND ROYALTIES DUE
OTHERS ..................................... 10,106 -- -- -- 10,106
------------ ------------ ------------ ------------- -------------
DEFERRED INCOME TAXES ........................ -- -- -- -- --
------------ ------------ ------------ ------------- -------------
INTERCOMPANY PAYABLES ........................ 853,958 2,959 -- (856,917) --
------------ ------------ ------------ ------------- -------------
STOCKHOLDERS' EQUITY:
Common Stock ............................... 10 3 733 (3) 743
Other ...................................... (173,189) 86,660 544,498 (178,506) 279,463
------------ ------------ ------------ ------------- -------------
(173,179) 86,663 545,231 (178,509) 280,206
------------ ------------ ------------ ------------- -------------
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY ..................................... $ 795,144 $ 119,271 $ 1,081,503 $ (1,043,134) $ 952,784
============ ============ ============ ============= =============
</TABLE>
51
<PAGE> 52
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF JUNE 30, 1997
($ IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------- -------------
<S> <C> <C> <C> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents .................. $ (6,534) $ 4,363 $ 126,188 $ -- $ 124,017
Short-term investments ..................... -- 4,324 100,161 -- 104,485
Accounts receivable ........................ 47,379 19,943 3,022 (6,787) 63,557
Inventory .................................. 4,795 59 -- -- 4,854
Other ...................................... 666 26 -- -- 692
------------ ------------ ------------ ------------- -------------
Total Current Assets ............... 46,306 28,715 229,371 (6,787) 297,605
------------ ------------ ------------ ------------- -------------
PROPERTY AND EQUIPMENT:
Oil and gas properties ..................... 865,485 31 -- -- 865,516
Unevaluated leasehold ...................... 128,519 (14) -- -- 128,505
Other property and equipment ............... 28,653 6,737 14,989 -- 50,379
Less: accumulated depreciation,
depletion and amortization .............. (436,276) -- (758) -- (437,034)
------------ ------------ ------------ ------------- -------------
Net Property and Equipment ......... 586,381 6,754 14,231 -- 607,366
------------ ------------ ------------ ------------- -------------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES ...................... 5,650 (4,833) 680,439 (681,256) --
------------ ------------ ------------ ------------- -------------
OTHER ASSETS ................................. 4,961 673 38,463 -- 44,097
------------ ------------ ------------ ------------- -------------
TOTAL ASSETS ................................. $ 643,298 $ 31,309 $ 962,504 $ (688,043) $ 949,068
============ ============ ============ ============= =============
</TABLE>
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
CURRENT LIABILITIES:
Notes payable and current
maturities of long-term debt ............ $ 1,380 $ -- $ -- $ -- $ 1,380
Accounts payable and other ................. 122,241 17,527 11,965 (6,787) 144,946
------------ ------------ ------------ ------------- -------------
Total Current Liabilities .......... 123,621 17,527 11,965 (6,787) 146,326
------------ ------------ ------------ ------------- -------------
LONG-TERM DEBT ............................... -- -- 508,950 -- 508,950
------------ ------------ ------------ ------------- -------------
REVENUES AND ROYALTIES DUE
OTHERS ..................................... 6,903 -- -- -- 6,903
------------ ------------ ------------ ------------- -------------
DEFERRED INCOME TAXES ........................ -- -- -- -- --
------------ ------------ ------------ ------------- -------------
INTERCOMPANY PAYABLES ........................ 589,111 1,492 -- (590,603) --
------------ ------------ ------------ ------------- -------------
STOCKHOLDERS' EQUITY:
Common Stock ............................... 11 1 693 (2) 703
Other ...................................... (76,348) 12,289 440,896 (90,651) 286,186
------------ ------------ ------------ ------------- -------------
(76,337) 12,290 441,589 (90,653) 286,889
------------ ------------ ------------ ------------- -------------
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY ..................................... $ 643,298 $ 31,309 $ 962,504 $ (688,043) $ 949,068
============ ============ ============ ============= =============
</TABLE>
52
<PAGE> 53
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1998:
REVENUES:
Oil and gas sales .......................... $ 254,541 $ -- $ -- $ 2,346 $ 256,887
Oil and gas marketing sales ................ -- 225,195 -- (104,136) 121,059
------------- ------------- ------------- ------------- -------------
Total Revenues ............................. 254,541 225,195 -- (101,790) 377,946
------------- ------------- ------------- ------------- -------------
OPERATING COSTS:
Production expenses and taxes .............. 59,497 -- -- -- 59,497
Oil and gas marketing expenses ............. -- 220,798 -- (101,790) 119,008
Impairment of oil and gas properties ....... 826,000 -- -- -- 826,000
Impairment of other assets ................. 47,000 8,000 -- -- 55,000
Oil and gas depreciation, depletion and
amortization.............................. 146,644 -- -- -- 146,644
Other depreciation and amortization ........ 5,204 126 2,746 -- 8,076
General and administrative ................. 18,081 1,766 71 -- 19,918
------------- ------------- ------------- ------------- -------------
Total Operating Costs ...................... 1,102,426 230,690 2,817 (101,790) 1,234,143
------------- ------------- ------------- ------------- -------------
INCOME (LOSS) FROM OPERATIONS .............. (847,885) (5,495) (2,817) -- (856,197)
------------- ------------- ------------- ------------- -------------
OTHER INCOME (EXPENSE):
Interest and other income .................. 649 2,259 100,886 (99,868) 3,926
Interest expense ........................... (96,214) (382) (71,521) 99,868 (68,249)
------------- ------------- ------------- ------------- -------------
(95,565) 1,877 29,365 -- (64,323)
------------- ------------- ------------- ------------- -------------
INCOME (LOSS) BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM ....................... (943,450) (3,618) 26,548 -- (920,520)
INCOME TAX EXPENSE (BENEFIT) ............... -- -- -- -- --
------------- ------------- ------------- ------------- -------------
NET INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM ....................... (943,450) (3,618) 26,548 -- (920,520)
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt,
net of applicable income tax ........... (2,164) -- (11,170) -- (13,334)
------------- ------------- ------------- ------------- -------------
NET INCOME (LOSS) .......................... $ (945,614) $ (3,618) $ 15,378 $ -- $ (933,854)
============= ============= ============= ============= =============
FOR THE SIX MONTHS ENDED DECEMBER 31, 1997:
REVENUES:
Oil and gas sales .......................... $ 93,384 $ 1,199 $ -- $ 1,074 $ 95,657
Oil and gas marketing sales ................ -- 101,689 -- (43,448) 58,241
------------- ------------- ------------- ------------- -------------
Total Revenues ............................. 93,384 102,888 -- (42,374) 153,898
------------- ------------- ------------- ------------- -------------
OPERATING COSTS:
Production expenses and taxes .............. 9,905 189 -- -- 10,094
Oil and gas marketing expenses ............. -- 100,601 -- (42,374) 58,227
Impairment of oil and gas properties ....... 96,000 14,000 -- -- 110,000
Oil and gas depreciation, depletion and
amortization............................. 59,758 650 -- -- 60,408
Other depreciation and amortization ........ 1,383 40 991 -- 2,414
General and administrative ................. 4,598 1,132 117 -- 5,847
------------- ------------- ------------- ------------- -------------
Total Operating Costs ...................... 171,644 116,612 1,108 (42,374) 246,990
------------- ------------- ------------- ------------- -------------
INCOME (LOSS) FROM OPERATIONS .............. (78,260) (13,724) (1,108) -- (93,092)
------------- ------------- ------------- ------------- -------------
OTHER INCOME (EXPENSE):
Interest and other income .................. 515 192 110,751 (32,492) 78,966
Interest expense ........................... (27,481) (39) (22,420) 32,492 (17,448)
------------- ------------- ------------- ------------- -------------
(26,966) 153 88,331 -- 61,518
------------- ------------- ------------- ------------- -------------
INCOME (LOSS) BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM ....................... (105,226) (13,571) 87,223 -- (31,574)
INCOME TAX EXPENSE (BENEFIT) ............... -- -- -- -- --
------------- ------------- ------------- ------------- -------------
NET INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM ....................... (105,226) (13,571) 87,223 -- (31,574)
EXTRAORDINARY ITEM ......................... -- -- -- -- --
------------- ------------- ------------- ------------- -------------
NET INCOME (LOSS) .......................... $ (105,226) $ (13,571) $ 87,223 $ -- $ (31,574)
============= ============= ============= ============= =============
</TABLE>
53
<PAGE> 54
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
FOR THE YEAR ENDED JUNE 30, 1997:
REVENUES:
Oil and gas sales ............................. $ 191,303 $ -- $ -- $ 1,617 $ 192,920
Oil and gas marketing sales ................... -- 145,942 -- (69,770) 76,172
------------- ------------- ------------- ------------- -------------
Total Revenues ................................ 191,303 145,942 -- (68,153) 269,092
------------- ------------- ------------- ------------- -------------
OPERATING COSTS:
Production expenses and taxes ................. 15,107 -- -- -- 15,107
Oil and gas marketing expenses ................ -- 143,293 -- (68,153) 75,140
Impairment of oil and gas properties .......... 236,000 -- -- -- 236,000
Oil and gas depreciation, depletion and
amortization................................. 103,264 -- -- -- 103,264
Other depreciation and amortization ........... 2,152 80 1,550 -- 3,782
General and administrative .................... 6,313 921 1,568 -- 8,802
------------- ------------- ------------- ------------- -------------
Total Operating Costs ......................... 362,836 144,294 3,118 (68,153) 442,095
------------- ------------- ------------- ------------- -------------
INCOME (LOSS) FROM OPERATIONS ................. (171,533) 1,648 (3,118) -- (173,003)
------------- ------------- ------------- ------------- -------------
OTHER INCOME (EXPENSE):
Interest and other income ..................... 778 749 49,224 (39,528) 11,223
Interest expense .............................. (37,644) (10) (20,424) 39,528 (18,550)
------------- ------------- ------------- ------------- -------------
(36,866) 739 28,800 -- (7,327)
------------- ------------- ------------- ------------- -------------
INCOME (LOSS) BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM .......................... (208,399) 2,387 25,682 -- (180,330)
INCOME TAX EXPENSE (BENEFIT) .................. (4,129) 47 509 -- (3,573)
------------- ------------- ------------- ------------- -------------
NET INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM .......................... (204,270) 2,340 25,173 -- (176,757)
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt, net of
applicable income tax..................... (769) -- (5,851) -- (6,620)
------------- ------------- ------------- ------------- -------------
NET INCOME (LOSS) ............................. $ (205,039) $ 2,340 $ 19,322 $ -- $ (183,377)
============= ============= ============= ============= =============
FOR THE YEAR ENDED JUNE 30, 1996:
REVENUES:
Oil and gas sales ............................. $ 103,712 $ 6,884 $ -- $ 253 $ 110,849
Gas marketing sales ........................... -- 34,973 -- (6,545) 28,428
Oil and gas service operations ................ 6,314 -- -- -- 6,314
------------- ------------- ------------- ------------- -------------
Total Revenues ................................ 110,026 41,857 -- (6,292) 145,591
------------- ------------- ------------- ------------- -------------
OPERATING COSTS:
Production expenses and taxes ................. 7,557 746 -- -- 8,303
Gas marketing expenses ........................ -- 33,744 -- (6,292) 27,452
Oil and gas service operations ................ 4,895 -- -- -- 4,895
Oil and gas depreciation, depletion and
amortization ................................ 48,333 2,566 -- -- 50,899
Other depreciation and amortization ........... 1,924 73 1,160 -- 3,157
General and administrative .................... 3,683 496 649 -- 4,828
------------- ------------- ------------- ------------- -------------
Total Operating Costs ......................... 66,392 37,625 1,809 (6,292) 99,534
------------- ------------- ------------- ------------- -------------
INCOME (LOSS) FROM OPERATIONS ................. 43,634 4,232 (1,809) -- 46,057
------------- ------------- ------------- ------------- -------------
OTHER INCOME (EXPENSE):
Interest and other income ..................... 1,917 238 1,676 -- 3,831
Interest expense .............................. (508) (711) (12,460) -- (13,679)
------------- ------------- ------------- ------------- -------------
1,409 (473) (10,784) -- (9,848)
------------- ------------- ------------- ------------- -------------
INCOME (LOSS) BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM ......................... 45,043 3,759 (12,593) -- 36,209
INCOME TAX EXPENSE (BENEFIT) .................. 15,990 1,335 (4,471) -- 12,854
------------- ------------- ------------- ------------- -------------
NET INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM ........................ 29,053 2,424 (8,122) -- 23,355
EXTRAORDINARY ITEM ............................ -- -- -- -- --
------------- ------------- ------------- ------------- -------------
NET INCOME (LOSS) ............................. $ 29,053 $ 2,424 $ (8,122) $ -- $ 23,355
============= ============= ============= ============= =============
</TABLE>
54
<PAGE> 55
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1998:
CASH FLOWS FROM OPERATING ACTIVITIES ............ $ 66,960 $ (13,137) $ 40,816 $ -- $ 94,639
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties ........................ (539,930) -- -- -- (539,930)
Proceeds from sale of assets .................. 16,008 -- 3,600 -- 19,608
Investment in preferred stock of Gothic Energy
Corporation ................................ (39,500) -- -- -- (39,500)
Repayment of long-term loan ................... 2,000 -- -- -- 2,000
Proceeds from sale of PanEast Petroleum
Corporation ................................ -- -- 21,245 -- 21,245
Other additions ............................... (2,510) 8,408 (17,371) -- (11,473)
------------ ------------ ------------ ------------ ------------
(563,932) 8,408 7,474 -- (548,050)
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings ............ -- -- 658,750 -- 658,750
Payments on long-term borrowings .............. -- -- (474,166) -- (474,166)
Cash received from issuance of preferred stock -- -- 222,663 -- 222,663
Cash paid for purchase of treasury stock ...... -- -- (29,962) -- (29,962)
Dividends paid on common stock and
preferred stock ............................ -- -- (13,642) -- (13,642)
Exercise of stock options ..................... -- -- 154 -- 154
Intercompany advances, net .................... 476,663 6,035 (482,698) -- --
Effect of exchange rate changes on cash ....... (4,726) -- -- -- (4,726)
------------ ------------ ------------ ------------ ------------
471,937 6,035 (118,901) -- 359,071
------------ ------------ ------------ ------------ ------------
Net increase (decrease) in cash and cash
equivalents ................................... (25,035) 1,306 (70,611) -- (94,340)
Cash, beginning of period ....................... (284) 13,694 110,450 -- 123,860
------------ ------------ ------------ ------------ ------------
Cash, end of period ............................. $ (25,319) $ 15,000 $ 39,839 $ -- $ 29,520
============ ============ ============ ============ ============
FOR THE SIX MONTHS ENDED DECEMBER 31, 1997:
CASH FLOWS FROM OPERATING ACTIVITIES ...... $ 28,598 $ (10,842) $ 121,401 $ -- $ 139,157
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties .................. (189,772) 17 -- -- (189,755)
Proceeds from sale of assets ............ 2,520 -- -- -- 2,520
Investment in service operations ........ (200) -- -- -- (200)
Other investments ....................... (26,472) -- 99,380 -- 72,908
Other additions ......................... (22,864) 1,340 (453) -- (21,977)
------------ ------------ ------------ ------------ ------------
(236,788) 1,357 98,927 -- (136,504)
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid on common stock .......... -- -- (2,810) -- (2,810)
Exercise of stock options ............... -- -- 322 -- 322
Other financing ......................... -- (322) -- -- (322)
Intercompany advances, net .............. 214,135 19,443 (233,578) -- --
------------ ------------ ------------ ------------ ------------
214,135 19,121 (236,066) -- (2,810)
------------ ------------ ------------ ------------ ------------
Net increase (decrease) in cash and cash
equivalents ............................. 5,945 9,636 (15,738) -- (157)
Cash, beginning of period ................. (6,534) 4,363 126,188 -- 124,017
------------ ------------ ------------ ------------ ------------
Cash, end of period ....................... $ (589) $ 13,999 $ 110,450 $ -- $ 123,860
============ ============ ============ ============ ============
</TABLE>
55
<PAGE> 56
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
FOR THE YEAR ENDED JUNE 30, 1997:
CASH FLOWS FROM OPERATING ACTIVITIES ... $ 165,850 $ (11,008) $ (70,753) $ -- $ 84,089
------------- ------------- ------------- ------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties ............... (468,519) 57 -- -- (468,462)
Proceeds from sale of assets ......... 9,523 -- -- -- 9,523
Investment in service operations ..... (3,048) -- -- -- (3,048)
Long-term loans to third parties ..... (2,000) -- (18,000) -- (20,000)
Other investments .................... -- -- (8,000) -- (8,000)
Other additions ...................... (24,318) (1,999) (7,550) -- (33,867)
------------- ------------- ------------- ------------- -------------
(488,362) (1,942) (33,550) -- (523,854)
------------- ------------- ------------- ------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings ............. 50,000 -- 292,626 -- 342,626
Payments on borrowings ............... (118,901) -- (680) -- (119,581)
Exercise of stock options ............ -- -- 1,387 -- 1,387
Issuance of common stock ............. -- -- 288,091 -- 288,091
Other financing ...................... -- -- (379) -- (379)
Intercompany advances, net ........... 380,735 14,645 (395,380) -- --
------------- ------------- ------------- ------------- -------------
311,834 14,645 185,665 -- 512,144
------------- ------------- ------------- ------------- -------------
Net increase (decrease) in cash and cash
equivalents .......................... (10,678) 1,695 81,362 -- 72,379
Cash, beginning of period .............. 4,144 2,668 44,826 -- 51,638
------------- ------------- ------------- ------------- -------------
Cash, end of period .................... $ (6,534) $ 4,363 $ 126,188 $ -- $ 124,017
============= ============= ============= ============= =============
FOR THE YEAR ENDED JUNE 30, 1996:
CASH FLOWS FROM OPERATING ACTIVITIES ... $ 126,868 $ 4,204 $ (10,100) $ -- $ 120,972
------------- ------------- ------------- ------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties ............... (341,246) (6,099) -- 5,300 (342,045)
Proceeds from sales .................. 12,165 -- -- (5,300) 6,865
Investment in gas marketing company .. -- 266 (629) -- (363)
Other additions ...................... (4,683) (109) (4,054) -- (8,846)
------------- ------------- ------------- ------------- -------------
(333,764) (5,942) (4,683) -- (344,389)
------------- ------------- ------------- ------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings ............. 40,350 10,300 116,017 -- 166,667
Payments on borrowings ............... (45,397) (3,200) (37) -- (48,634)
Exercise of stock options ............ -- -- 1,989 -- 1,989
Issuance of common stock ............. -- -- 99,498 -- 99,498
Intercompany advances, net ........... 162,777 (2,616) (160,161) -- --
------------- ------------- ------------- ------------- -------------
157,730 4,484 57,306 -- 219,520
------------- ------------- ------------- ------------- -------------
Net increase (decrease) in cash and cash
equivalents .......................... (49,166) 2,746 42,523 -- (3,897)
Cash, beginning of period .............. 53,227 5 2,303 -- 55,535
------------- ------------- ------------- ------------- -------------
Cash, end of period .................... $ 4,061 $ 2,751 $ 44,826 $ -- $ 51,638
============= ============= ============= ============= =============
</TABLE>
56
<PAGE> 57
3. NOTES PAYABLE AND LONG-TERM DEBT
Notes payable and long-term debt consist of the following:
<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
------------------------------ -------------
1998 1997 1997
------------- ------------- -------------
($ IN THOUSANDS)
<S> <C> <C> <C>
7.875% Senior Notes (see Note 2) ................................ $ 150,000 $ 150,000 $ 150,000
Discount on 7.875% Senior Notes ................................. (90) (106) (115)
8.5% Senior Notes (see Note 2) .................................. 150,000 150,000 150,000
Discount on 8.5% Senior Notes ................................... (774) (833) (862)
9.125% Senior Notes (see Note 2) ................................ 120,000 120,000 120,000
Discount on 9.125% Senior Notes ................................. (60) (69) (73)
9.625% Senior Notes (see Note 2) ................................ 500,000 -- --
10.5% Senior Notes (see Note 2) ................................. -- 90,000 90,000
Note payable to a vendor, collateralized by oil and gas tubulars,
payments due 60 days from shipment of the tubulars ........... -- -- 1,380
Other collateralized ............................................ 25,000 -- --
------------- ------------- -------------
Total notes payable and long-term debt .......................... 944,076 508,992 510,330
Less-- current maturities ....................................... (25,000) -- (1,380)
------------- ------------- -------------
Notes payable and long-term debt, net of current
maturities ................................................... $ 919,076 $ 508,992 $ 508,950
============= ============= =============
</TABLE>
The aggregate scheduled maturities of notes payable and long-term debt for
the next five fiscal years ending December 31, 2003 and thereafter were as
follows as of December 31, 1998 (in thousands of dollars):
<TABLE>
<S> <C>
1999........................................................................................... $ 25,000
2000........................................................................................... --
2001........................................................................................... --
2002........................................................................................... --
2003........................................................................................... --
After 2003..................................................................................... 919,076
---------
$ 944,076
=========
</TABLE>
4. CONTINGENCIES AND COMMITMENTS
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 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 have filed a motion to dismiss. No estimate of loss or range of
estimate of loss, if any, can be made at this time.
Another purported class action alleging violations of the Securities Act of
1933 and the Oklahoma Securities Act is pending against the Company and others
on behalf of investors who purchased common stock of Bayard Drilling
Technologies, Inc. ("Bayard") in its initial public offering in November 1997.
Total proceeds of the offering were $254 million, of which the Company received
net proceeds of $90.2 million as a selling shareholder. Plaintiffs allege that
the Company, which owned 30.1% of Bayard's common stock outstanding prior to the
offering, was a controlling person of Bayard. Plaintiffs also allege that the
Company had established an interlocking financial relationship with Bayard and
was a customer of Bayard's drilling services under allegedly below-market terms.
Plaintiffs also note the fact that three executive officers and directors of the
Company were formerly directors 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
57
<PAGE> 58
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. The 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 these actions are without merit and has filed a motion to dismiss.
No estimate of loss or range of estimate of loss, if any, can be made at this
time.
In October 1996, Union Pacific Resources Company ("UPRC") sued the Company
alleging infringement of a patent for a drilling method, tortious interference
with confidentiality contracts between UPRC and certain of its former employees
and misappropriation of proprietary information of UPRC. UPRC's 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 injunctive relief,
damages of an unspecified amount, including actual, enhanced, consequential and
punitive damages, interest, costs and attorneys' fees. In May 1998, the court
ruled as a matter of law that UPRC's tort claims for misappropriation of trade
secrets and tortious interference with business relations are barred by the
statute of limitations. Further, the court found that UPRC's claim for
inducement to infringe its patent for a drillbit steering method is barred as to
any wells drilled by the Company prior to August 14, 1995. The only issues
remaining in the case involve the validity, potential infringement and value, if
any, of UPRC's patent. The Company believes that it has meritorious defenses to
UPRC's allegations and has petitioned the court to declare the UPRC patent
invalid. Various motions for summary judgment are pending. No estimate of a
probable loss or range of estimate of a probable 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 $25,000, in each case based on a reasonable
royalty. This case has been set for trial in June 1999 on the issue of
liability.
The Company is currently involved in various other routine disputes
incidental to its business operations. While it is not possible to determine the
ultimate disposition of these matters, management, after consultation with legal
counsel, is of the opinion that the final resolution of all such currently
pending or threatened litigation is not likely to have a material adverse effect
on the consolidated financial position or results of operations of the Company.
The Company has employment contracts with its two principal shareholders and
its chief financial officer and various other senior management personnel which
provide for annual base salaries, bonus compensation and various benefits. The
contracts provide for the continuation of salary and benefits for the respective
terms of the agreements in the event of termination of employment without cause.
These agreements expire at various times from June 30, 2000 through June 30,
2003.
Due to the nature of the oil and gas business, the Company and its
subsidiaries are exposed to possible environmental risks. The Company has
implemented various policies and procedures to avoid environmental contamination
and risks from environmental contamination. The Company is not aware of any
potential material environmental issues or claims.
5. INCOME TAXES
The components of the income tax provision (benefit) for each of the periods
are as follows:
<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS ENDED YEAR ENDED JUNE 30,
DECEMBER 31, DECEMBER 31, ------------------------------
1998 1997 1997 1996
------------- ------------- ------------- -------------
($ IN THOUSANDS)
<S> <C> <C> <C> <C>
Current ...................... $ -- $ -- $ -- $ --
Deferred ..................... -- -- (3,573) 12,854
------------- ------------- ------------- -------------
Total .............. $ -- $ -- $ (3,573) $ 12,854
============= ============= ============= =============
</TABLE>
The effective income tax expense (benefit) differed from the computed
"expected" federal income tax expense (benefit) on earnings before income taxes
for the following reasons:
58
<PAGE> 59
<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS ENDED YEAR ENDED JUNE 30,
DECEMBER 31, DECEMBER 31, ------------------------------
1998 1997 1997 1996
------------- ------------- ------------- -------------
($ IN THOUSANDS)
<S> <C> <C> <C> <C>
Computed "expected" income tax provision (benefit) $ (322,182) $ (11,051) $ (63,116) $ 12,673
Tax percentage depletion ......................... (430) (48) (294) (238)
Valuation allowance .............................. 380,969 13,818 64,116 --
State income taxes and other ..................... (58,357) (2,719) (4,279) 419
------------- ------------- ------------- -------------
$ -- $ -- $ (3,573) $ 12,854
============= ============= ============= =============
</TABLE>
Deferred income taxes are provided to reflect temporary differences in the
basis of net assets for income tax and financial reporting purposes. The tax
effected temporary differences and tax loss carryforwards which comprise
deferred taxes are as follows:
<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS ENDED YEAR ENDED JUNE 30,
DECEMBER 31, DECEMBER 31, ------------------------------
1998 1997 1997 1996
------------- ------------- ------------- -------------
($ IN THOUSANDS)
<S> <C> <C> <C> <C>
Deferred tax liabilities:
Acquisition, exploration and development costs and
related depreciation, depletion and
amortization ................................... $ -- $ (49,657) $ (49,831) $ (63,725)
Deferred tax assets:
Acquisition, exploration and development costs and
related depreciation, depletion and
amortization ................................... 242,765 -- -- --
Net operating loss carryforwards ................. 214,602 126,485 112,889 50,776
Percentage depletion carryforward ................ 1,536 1,106 1,058 764
------------- ------------- ------------- -------------
458,903 127,591 113,947 51,540
------------- ------------- ------------- -------------
Net deferred tax asset (liability) ............... 458,903 77,934 64,116 (12,185)
Less: Valuation allowance ........................ (458,903) (77,934) (64,116) --
------------- ------------- ------------- -------------
Total deferred tax asset (liability) ............. $ -- $ -- $ -- $ (12,185)
============= ============= ============= =============
</TABLE>
SFAS 109 requires that the Company record a valuation allowance when it is
more likely than not that some portion or all of the deferred tax assets will
not be realized. In 1998, the Transition Period and fiscal 1997, the Company
recorded an $826 million writedown, a $110 million writedown and a $236 million
writedown, respectively, related to the impairment of oil and gas properties.
The writedowns and significant tax net operating loss carryforwards (caused
primarily by expensing intangible drilling costs for tax purposes) resulted in a
net deferred tax asset at December 31, 1998 and 1997 and June 30, 1997.
Management believes it is more likely than not that the Company will generate
future tax net operating losses for at least the next five years.. Therefore,
the Company has recorded a valuation allowance equal to the net deferred tax
asset.
At December 31, 1998, the Company had U.S. and Canadian regular tax net
operating loss carryforwards of approximately $571 million and $1 million,
respectively, and U.S. alternative minimum tax net operating loss carryforwards
of approximately $196 million. The U.S. loss carryforward amounts will expire
during the years 2007 through 2018. The Company also had a percentage depletion
carryforward of approximately $4 million at December 31, 1998, which is
available to offset future federal income taxes payable and has no expiration
date.
In accordance with certain provisions of the Tax Reform Act of 1986, a
change of greater than 50% of the beneficial ownership of the Company within a
three-year period (an "Ownership Change") would place an annual limitation on
the Company's ability to utilize its existing tax carryforwards. Under
regulations issued by the Internal Revenue Service, the Company has had two
Ownership Changes. However, management believes this will not result in a
significant limitation of the tax carryforwards. Acquired tax carryforwards are
subject to separate limitations; however, management believes these will not
result in a significant limitation of the acquired tax carryforwards.
6. RELATED PARTY TRANSACTIONS
Certain directors, shareholders and employees of the Company have acquired
working interests in certain of the Company's oil and gas properties. The owners
of such working interests are required to pay their proportionate share of all
costs. As of December 31, 1998 and 1997 and June 30, 1997, the Company had
accounts receivable
59
<PAGE> 60
from related parties, primarily related to such participation, of $5.6 million,
$4.2 million and $7.4 million, respectively.
Certain officers of the Company have loans due on December 31, 1999 to CEMI
in the principal amount of $9.9 million. Such loans, which were first made in
July 1998, are collateralized and carry an annual interest rate of 9.125%.
During 1998, the six months ended December 31, 1997 and fiscal 1997 and
1996, the Company incurred legal expenses of $493,000, $388,000, $207,000 and
$347,000, respectively, for legal services provided by a law firm of which a
director is a member.
7. EMPLOYEE BENEFIT PLANS
The Company maintains the Chesapeake Energy Corporation Savings and
Incentive Stock Bonus Plan, a 401(k) profit sharing plan. Eligible employees may
make voluntary contributions to the plan which are matched by the Company for up
to 10% of the employee's annual salary with the Company's common stock. The
amount of employee contribution is limited as specified in the plan. The Company
may, at its discretion, make additional contributions to the plan. The Company
contributed $1,359,000, $418,000, $603,000 and $187,000 to the plan during 1998,
the six months ended December 31, 1997 and the fiscal years ended June 30, 1997
and 1996, respectively.
8. MAJOR CUSTOMERS AND SEGMENT INFORMATION
Sales to individual customers constituting 10% or more of total oil and gas
sales were as follows:
<TABLE>
<CAPTION>
PERCENT OF
YEAR ENDED DECEMBER 31, AMOUNT OIL AND GAS SALES
----------------------------------------------------- ---------------- -----------------
($ IN THOUSANDS)
<S> <C> <C>
1998 Koch Oil Company $ 30,564 12%
Aquila Southwest Pipeline Corporation $ 28,946 11%
SIX MONTHS ENDED DECEMBER 31,
-----------------------------------------------------
1997 Aquila Southwest Pipeline Corporation $ 20,138 21%
Koch Oil Company $ 18,594 19%
GPM Gas Corporation $ 12,610 13%
FISCAL YEAR ENDED JUNE 30,
-----------------------------------------------------
1997 Aquila Southwest Pipeline Corporation $ 53,885 28%
Koch Oil Company $ 29,580 15%
GPM Gas Corporation $ 27,682 14%
1996 Aquila Southwest Pipeline Corporation $ 41,900 38%
GPM Gas Corporation $ 28,700 26%
Wickford Energy Marketing, L.C. $ 18,500 17%
</TABLE>
Management believes that the loss of any of the above customers would not
have a material impact on the Company's results of operations or its financial
position.
The Company believes all of its material operations are part of the oil and
gas industry, and therefore reports as a single industry setment. Beginning in
1998, the Company conducted foreign operations in Canada. The geographic
distribution of the Company's revenue, operating income and identifiable assets
are summarized below ($ in thousands):
<TABLE>
<CAPTION>
UNITED
STATES CANADA CONSOLIDATED
------------- ------------- --------------
<S> <C> <C> <C>
1998:
Revenue ........................... $ 369,968 $ 7,978 $ 377,946
Operating income (loss) ........... (842,798) (13,399) (856,197)
Identifiable assets ............... 724,713 87,902 812,615
</TABLE>
60
<PAGE> 61
9. STOCKHOLDERS' EQUITY AND STOCK BASED COMPENSATION
During 1998, the Company's Board of Directors approved the expenditure of up
to $30 million to purchase outstanding Company common stock. As of August 25,
1998, the Company had purchased approximately 8.5 million shares of common stock
for an aggregate amount of $30 million pursuant to such authorization.
On April 28, 1998, the Company acquired by merger the Mid-Continent
operations of DLB Oil & Gas, Inc. ("DLB") for $17.5 million in cash, 5 million
shares of the Company's common stock, and the assumption of $90 million in
outstanding debt and working capital obligations.
On April 22, 1998, the Company issued $230 million (4.6 million shares) of
its 7% Cumulative Convertible Preferred Stock, $50 per share liquidation
preference, resulting in net proceeds to the Company of $223 million.
On March 10, 1998, the Company acquired Hugoton Energy Corporation
("Hugoton") pursuant to a merger by issuing approximately 25.8 million shares of
the Company's common stock in exchange for 100% of Hugoton's common stock.
On December 16, 1997, the Company acquired AnSon Production Corporation.
Consideration for this merger was approximately $43 million consisting of the
issuance of approximately 3.8 million shares of Company common stock and cash
consideration in accordance with the terms of the merger agreement.
On December 2, 1996, the Company completed a public offering of
approximately 9.0 million shares of common stock at a price of $33.63 per share,
resulting in net proceeds to the Company of approximately $288.1 million.
On April 12, 1996, the Company completed a public offering of approximately
6.0 million shares of common stock at a price of $17.67 per share, resulting in
net proceeds to the Company of approximately $99.4 million.
A 2-for-1 stock split of the common stock in December 1996, and a 3-for-2
stock split of the common stock in December 1995 and in June 1996 have been
given retroactive effect in these financial statements.
Stock Option Plans
Under the Company's 1992 Incentive Stock Option Plan (the "ISO Plan"),
options to purchase common stock may be granted only to employees of the Company
and its subsidiaries. Subject to any adjustment as provided by the ISO Plan, the
aggregate number of shares which may be issued and sold may not exceed 3,762,000
shares. The maximum period for exercise of an option may not be more than 10
years (or five years for an optionee who owns more than 10% of the common stock)
from the date of grant, and the exercise price may not be less than the fair
market value of the shares underlying the options on the date of grant (or 110%
of such value for an optionee who owns more than 10% of the common stock).
Options granted become exercisable at dates determined by the Stock Option
Committee of the Board of Directors. No options could be granted under the ISO
Plan after December 16, 1994.
Under the Company's 1992 Nonstatutory Stock Option Plan (the "NSO Plan"),
non-qualified options to purchase common stock may be granted only to directors
and consultants of the Company. Subject to any adjustment as provided by the NSO
Plan, the aggregate number of shares which may be issued and sold may not exceed
3,132,000 shares. The maximum period for exercise of an option may not be more
than 10 years from the date of grant, and the exercise price may not be less
than the fair market value of the shares underlying the options on the date of
grant. Options granted become exercisable at dates determined by the Stock
Option Committee of the Board of Directors. No options can be granted under the
NSO Plan after December 10, 2002.
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<PAGE> 62
Under the Company's 1994 Stock Option Plan (the "1994 Plan"), and its 1996
Stock Option Plan (the "1996 Plan"), incentive and nonqualified stock options to
purchase Common Stock may be granted to employees and consultants of the Company
and its subsidiaries. Subject to any adjustment as provided by the respective
plans, the aggregate number of shares which may be issued and sold may not
exceed 4,886,910 shares under the 1994 Plan and 6,000,000 shares under the 1996
Plan. The maximum period for exercise of an option may not be more than 10 years
from the date of grant and the exercise price may not be less than 75% of the
fair market value of the shares underlying the options on the date of grant.
Options granted become exercisable at dates determined by the Stock Option
Committee of the Board of Directors. No options can be granted under the 1994
Plan after December 16, 2004 or under the 1996 Plan after October 14, 2006.
The Company has elected to follow APB No. 25, Accounting for Stock Issued to
Employees and related interpretations in accounting for its employee stock
options. Under APB No. 25, compensation expense is recognized for the difference
between the option price and market value on the measurement date. No
compensation expense has been recognized because the exercise price of the stock
options equaled the market price of the underlying stock on the date of grant.
Pro forma information regarding net income and earnings per share is
required by SFAS No. 123 and has been determined as if the Company had accounted
for its employee stock options under the fair value method of the statement. The
fair value for these options was estimated at the date of grant using a
Black-Scholes option pricing model with the following weighted-average
assumptions for 1998, the six months ended December 31, 1997 and fiscal 1997 and
1996, respectively: interest rates (zero-coupon U.S. government issues with a
remaining life equal to the expected term of the options) of 5.20%, 6.45%, 6.74%
and 6.21%; dividend yields of 0.0%, 0.9%, 0.9% and 0.9%; volatility factors of
the expected market price of the Company's common stock of .96, .67, .60 and
.60; and weighted-average expected life of the options of four years.
The Black-Scholes option valuation model was developed for use in estimating
the fair value of traded options which have no vesting restrictions and are
fully transferable. In addition, option valuation models require the input of
highly subjective assumptions including the expected stock price volatility.
Because the Company's employee stock options have characteristics significantly
different from those of traded options, and because changes in the subjective
input assumptions can materially affect the fair value estimate, in management's
opinion the existing models do not necessarily provide a reliable single measure
of the fair value of its employee stock options.
The Company's pro forma information follows:
<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS ENDED YEAR ENDED JUNE 30,
DECEMBER 31, DECEMBER 31, ------------------------------
1998 1997 1997 1996
------------- ------------- ------------- -------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Net Income (Loss)
As reported ................ $ (933,854) $ (31,574) $ (183,377) $ 23,355
Pro forma .................. (948,014) (35,084) (190,160) 22,081
Earnings (Loss) per Share
As reported ................ $ (9.97) $ (0.45) $ (2.79) $ 0.40
Pro forma .................. (10.12) (0.50) (2.89) 0.38
</TABLE>
For purposes of the pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period, which is four
years. Because the Company's stock options vest over four years and additional
awards are typically made each year, the above pro forma disclosures are not
likely to be representative of the effects on pro forma net income for future
years. A summary of the Company's stock option activity and related information
follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED DECEMBER 31,
1998 1997
------------------------------- ------------------------------
WEIGHTED-AVG WEIGHTED-AVG
OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE
------------- -------------- ------------- --------------
<S> <C> <C> <C> <C>
Outstanding Beginning of Period .................. 8,330,381 $ 5.49 7,903,659 $ 7.09
Granted .......................................... 14,580,063 $ 2.78 3,362,207 8.29
Exercised ........................................ (108,761) $ 1.35 (219,349) 3.13
Cancelled/Forfeited .............................. (11,541,308) $ 5.64 (2,716,136) 13.87
------------- ------------- ------------- -------------
Outstanding End of Period ........................ 11,260,375 $ 1.86 8,330,381 5.49
------------- ------------- ------------- -------------
Exercisable End of Period ........................ 3,535,126 3,838,869
------------- -------------
Shares Authorized for Future Grants........ 1,761,359 4,585,973
------------- -------------
Fair Value of Options Granted During the
Period................................ $ 2.34 $ 4.98
------------- -------------
</TABLE>
62
<PAGE> 63
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
----------------------------------------------------------------------
1997 1996
--------------------------------- --------------------------------
WEIGHTED-AVG WEIGHTED-AVG
OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE
------------- --------------- ------------- ---------------
<S> <C> <C> <C> <C>
Outstanding Beginning of Year ...................... 7,602,884 $ 4.66 6,828,592 $ 1.97
Granted ............................................ 3,564,884 19.35 2,426,850 9.98
Exercised .......................................... (1,197,998) 1.95 (1,574,046) 1.31
Cancelled/Forfeited ................................ (2,066,111) 22.26 (78,512) 2.61
------------- ------------- ------------- -------------
Outstanding End of Year ............................ 7,903,659 7.09 7,602,884 4.66
------------- ------------- ------------- -------------
Exercisable End of Year ............................ 3,323,824 2,974,386
------------- -------------
Shares Authorized for Future Grants ................ 5,212,056 713,826
------------- -------------
Fair Value of Options Granted During the Year ...... $ 7.51 $ 4.84
------------- -------------
</TABLE>
The following table summarizes information about stock options outstanding
at December 31, 1998:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
----------------------------------------------------- --------------------------------
NUMBER WEIGHTED-AVG. NUMBER
RANGE OF OUTSTANDING REMAINING WEIGHTED-AVG. EXERCISABLE WEIGHTED-AVG.
EXERCISE PRICES @ 12/31/98 CONTRACTUAL LIFE EXERCISE PRICE @ 12/31/98 EXERCISE PRICE
------------------ -------------- ------------------ --------------- --------------- --------------
<S> <C> <C> <C> <C> <C>
$0.0800 - $ 0.8556 1,243,185 3.85 $0.6434 1,243,185 $ 0.6434
$1.1300 - $ 1.1300 6,708,697 9.79 $1.1300 36,563 $ 1.1300
$1.2400 - $ 2.2511 2,047,254 5.45 $1.7603 1,349,704 $ 2.0293
$2.4311 - $ 7.3100 1,062,864 7.50 $4.5489 752,239 $ 4.4790
$8.7500 - $ 8.7500 48,625 8.50 $8.7500 26,310 $ 8.7500
$10.6900 - $10.6900 18,750 8.75 $10.6900 18,750 $10.6900
$14.2500 - $14.2500 28,500 8.32 $14.2500 7,125 $14.2500
$17.6667 - $17.6667 1,500 7.26 $17.6667 750 $17.6667
$25.8750 - $25.8750 1,000 7.95 $25.8750 500 $25.8750
$30.6250 - $30.6250 100,000 7.77 $30.6250 100,000 $30.6250
------------ ---- -------- --------- --------
$0.0800 - $30.6250 11,260,375 8.10 $1.8620 3,535,126 $2.9900
</TABLE>
The exercise of certain stock options results in state and federal income
tax benefits to the Company related to the difference between the market price
of the common stock at the date of disposition (or sale) and the option price.
During 1998, the six months ended December 31, 1997 and fiscal 1997 and 1996,
$0, $0, $4,808,000 and $7,950,000, respectively, were recorded as adjustments to
additional paid-in capital and deferred income taxes with respect to such tax
benefits.
10. FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
The Company has only limited involvement with derivative financial
instruments, as defined in Statement of Financial Accounting Standards No. 119
"Disclosure About Derivative Financial Instruments and Fair Value of Financial
Instruments", and does not use them for trading purposes. The Company's primary
objective is to hedge a portion of its exposure to price volatility from
producing crude oil and natural gas. These arrangements may expose the Company
to credit risk from its counterparties and to basis risk. The Company does not
expect that the counterparties will fail to meet their obligations given their
high credit ratings.
Hedging Activities
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 commodity hedging transactions are
63
<PAGE> 64
reflected in oil and gas sales to the extent related to the Company's oil and
gas production. The Company only enters into commodity hedging transactions
related to the Company's oil and gas production volumes or CEMI's physical
purchase or sale commitments. Gains or losses on crude oil and natural gas
hedging transactions are recognized as price adjustments in the months of
related production.
As of December 31, 1998, the Company had the following natural gas swap
arrangements designed to hedge a portion of the Company's domestic gas
production for periods after December 1998:
<TABLE>
<CAPTION>
NYMEX-INDEX
VOLUME STRIKE PRICE
MONTHS (MMBTU) (PER MMBTU)
- ------ ------------- -------------
<S> <C> <C>
February 1999.................................................................... 4,300,000 $ 1.968
March 1999....................................................................... 4,600,000 1.968
April 1999....................................................................... 4,500,000 1.968
May 1999......................................................................... 4,600,000 1.968
June 1999........................................................................ 1,200,000 1.950
July 1999........................................................................ 1,240,000 1.950
August 1999...................................................................... 1,240,000 1.950
September 1999................................................................... 1,200,000 1.950
</TABLE>
During 1998, the Company has closed transactions for natural gas previously
hedged for the period April 1999 through November 1999 for net proceeds of $0.5
million.
Subsequent to December 31, 1998, the Company entered into additional natural
gas swap arrangements for 6,100,000 MMBtu at a strike price of $1.875 for the
period from June 1999 through September 1999. Such swap arrangements, along with
those listed above and other miscellaneous transactions, were closed as of March
15, 1999, resulting in net proceeds of $4.7 million (unrealized gain of $0.8
million at December 31, 1998).
As of December 31, 1998, the Company had the following natural gas swap
arrangements designed to hedge a portion of the Company's Canadian gas
production for periods after December 1998:
<TABLE>
<CAPTION>
VOLUME INDEX STRIKE PRICE
MONTHS (MMBTU) (PER MMBTU)
- ------ --------------- -----------------
<S> <C> <C>
January 1999........................................................... 589,000 $ 1.60
February 1999.......................................................... 532,000 1.60
March 1999............................................................. 589,000 1.60
April 1999............................................................. 570,000 1.60
May 1999............................................................... 589,000 1.60
June 1999.............................................................. 570,000 1.60
July 1999.............................................................. 589,000 1.60
August 1999............................................................ 589,000 1.60
September 1999......................................................... 570,000 1.60
</TABLE>
If the swap arrangements listed above had been settled on December 31, 1998,
the Company would have incurred a loss of $0.8 million.
As of December 31, 1998, the Company had the following oil swap arrangements
for periods after December 1998:
<TABLE>
<CAPTION>
NYMEX HEATING OIL
MINUS
MONTHLY NYMEX CRUDE OIL
VOLUME INDEX STRIKE PRICE
MONTHS (BBLS) (PER BBL)
- ------ --------------- ----------------
<S> <C> <C>
January 1999........................................................... 217,000 $ 2.957
February 1999.......................................................... 196,000 2.957
March 1999............................................................. 155,000 2.900
</TABLE>
If the swap arrangements listed above had been settled on December 31, 1998,
the Company would have incurred a loss of $0.2 million. Subsequent to December
31, 1998, the Company settled the swap arrangements listed above for the period
of January 1999 and February 1999 resulting in a $0.4 million loss.
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<PAGE> 65
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 or sale commitments made by CEMI.
Gains or losses on these transactions are recorded as adjustments to oil and gas
marketing sales in the consolidated statements of operations and are not
considered by management to be material.
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. For the year ended December 31, 1998, the Company's interest rate swap
resulted in a $0.7 million reduction of interest expense during 1998.
Concentration of Credit Risk
Other financial instruments which potentially subject the Company to
concentrations of credit risk consist principally of cash, short-term
investments in debt instruments and trade receivables. The Company's accounts
receivable are primarily from purchasers of oil and natural gas products and
exploration and production companies which own interests in properties operated
by the Company. The industry concentration has the potential to impact the
Company's overall exposure to credit risk, either positively or negatively, in
that the customers may be similarly affected by changes in economic, industry or
other conditions. The Company generally requires letters of credit for
receivables from customers which are judged to have sub-standard credit, unless
the credit risk can otherwise be mitigated. The cash and investments in debt
securities are with major banks or institutions with high credit ratings.
Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial
instruments is made in accordance with the requirements of Statement of
Financial Accounting Standards No. 107, "Disclosures About Fair Value of
Financial Instruments". The estimated fair value amounts have been determined by
the Company using available market information and valuation methodologies.
Considerable judgment is required in interpreting market data to develop the
estimates of fair value. The use of different market assumptions or valuation
methodologies may have a material effect on the estimated fair value amounts.
The carrying values of items comprising current assets and current
liabilities approximate fair values due to the short-term maturities of these
instruments. The Company estimates the fair value of its long-term, fixed-rate
debt using quoted market prices. The Company's carrying amount for such debt at
December 31, 1998 and 1997 and June 30, 1997 was $919.1 million, $509.0 million
and $508.9 million, respectively, compared to approximate fair values of $654.7
million, $517.0 million and $514.1 million, respectively. The carrying value of
other long-term debt approximates its fair value as interest rates are primarily
variable, based on prevailing market rates. The Company estimates the fair value
of its convertible preferred stock, which was issued in April 1998, using quoted
market prices. The Company's carrying amount for such preferred stock at
December 31, 1998 was $230 million, compared to an approximate fair value of
$48.9 million.
11. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
Net Capitalized Costs
Evaluated and unevaluated capitalized costs related to the Company's oil and
gas producing activities are summarized as follows:
65
<PAGE> 66
<TABLE>
<CAPTION>
DECEMBER 31, 1998
- ----------------- U.S. CANADA COMBINED
------------- ------------- -------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas properties:
Proved ................................................ $ 2,060,076 $ 82,867 $ 2,142,943
Unproved .............................................. 44,780 7,907 52,687
------------- ------------- -------------
Total ......................................... 2,104,856 90,774 2,195,630
Less accumulated depreciation, depletion and amortization (1,556,284) (17,998) (1,574,282)
------------- ------------- -------------
Net capitalized costs ................................... $ 548,572 $ 72,776 $ 621,348
============= ============= =============
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31, 1997
- ----------------- U.S. CANADA COMBINED
------------- ------------- -------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas properties:
Proved ................................................ $ 1,095,363 $ -- $ 1,095,363
Unproved .............................................. 125,155 -- 125,155
------------- ------------- -------------
Total ......................................... 1,220,518 -- 1,220,518
Less accumulated depreciation, depletion and amortization (602,391) -- (602,391)
------------- ------------- -------------
Net capitalized costs ................................... $ 618,127 $ -- $ 618,127
============= ============= =============
</TABLE>
<TABLE>
<CAPTION>
JUNE 30, 1997
- ------------- U.S. CANADA COMBINED
------------- ------------- -------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas properties:
Proved ................................................ $ 865,516 $ -- $ 865,516
Unproved .............................................. 128,505 -- 128,505
------------- ------------- -------------
Total ......................................... 994,021 -- 994,021
Less accumulated depreciation, depletion and amortization (431,983) -- (431,983)
------------- ------------- -------------
Net capitalized costs ................................... $ 562,038 $ -- $ 562,038
============= ============= =============
</TABLE>
Unproved properties not subject to amortization at December 31, 1998 and
1997, and June 30, 1997 consisted mainly of lease acquisition costs. The Company
capitalized approximately $6.5 million, $5.1 million and $12.9 million of
interest during 1998, the six months ended December 31, 1997 and the year ended
June 30, 1997 on significant investments in unproved properties that were not
yet included in the amortization base of the full-cost pool. The Company will
continue to evaluate its unevaluated properties; however, the timing of the
ultimate evaluation and disposition of the properties has not been determined.
Costs Incurred in Oil and Gas Acquisition, Exploration and Development
Costs incurred in oil and gas property acquisition, exploration and
development activities which have been capitalized are summarized as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1998
- ---------------------------- U.S. CANADA COMBINED
---------- ---------- ---------
($ IN THOUSANDS)
<S> <C> <C> <C>
Development costs........................................ $ 145,953 $ 4,584 $ 150,537
Exploration costs........................................ 63,245 5,427 68,672
Acquisition costs:
Unproved properties.................................... 23,834 2,535 26,369
Proved properties...................................... 662,104 78,176 740,280
Sales of oil and gas properties.......................... (15,712) -- (15,712)
Capitalized internal costs............................... 5,262 -- 5,262
Proceeds from sale of leasehold, equipment and other..... (296) -- (296)
---------- ---------- ---------
Total.......................................... $ 884,390 $ 90,722 $ 975,112
========== ========== =========
</TABLE>
66
<PAGE> 67
<TABLE>
<CAPTION>
SIX MONTHS ENDED DECEMBER 31, 1997
- ---------------------------------- U.S. CANADA COMBINED
---------- ---------- ---------
($ IN THOUSANDS)
<S> <C> <C> <C>
Development costs........................................ $ 120,628 $ -- $ 120,628
Exploration costs........................................ 40,534 -- 40,534
Acquisition costs:
Unproved properties.................................... 25,516 -- 25,516
Proved properties...................................... 39,245 -- 39,245
Sales of oil and gas properties.......................... -- -- --
Capitalized internal costs............................... 2,435 -- 2,435
Proceeds from sale of leasehold, equipment and other..... (1,861) -- (1,861)
---------- ---------- ---------
Total.......................................... $ 226,497 $ -- $ 226,497
========== ========== =========
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30, 1997
- ------------------------ U.S. CANADA COMBINED
---------- ---------- ---------
($ IN THOUSANDS)
<S> <C> <C> <C>
Development costs........................................ $ 187,736 $ -- $ 187,736
Exploration costs........................................ 136,473 -- 136,473
Acquisition costs:
Unproved properties.................................... 140,348 -- 140,348
Proved properties...................................... -- -- --
Sales of oil and gas properties.......................... -- -- --
Capitalized internal costs............................... 3,905 -- 3,905
Proceeds from sale of leasehold, equipment and other..... (3,095) -- (3,095)
---------- ---------- ---------
Total.......................................... $ 465,367 $ -- $ 465,367
========== ========== =========
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30, 1996
- ------------------------ U.S. CANADA COMBINED
---------- ---------- ---------
($ IN THOUSANDS)
<S> <C> <C> <C>
Development costs........................................ $ 138,188 $ -- $ 138,188
Exploration costs........................................ 39,410 -- 39,410
Acquisition costs:
Unproved properties.................................... 138,188 -- 138,188
Proved properties...................................... 24,560 -- 24,560
Sales of oil and gas properties.......................... -- -- --
Capitalized internal costs............................... 1,699 -- 1,699
Proceeds from sale of leasehold, equipment and other..... (6,167) -- (6,167)
---------- ---------- ---------
Total.......................................... $ 335,878 $ -- $ 335,878
========== ========== =========
</TABLE>
Results of Operations from Oil and Gas Producing Activities (unaudited)
The Company's results of operations from oil and gas producing activities
are presented below for 1998, the six months ended December 31, 1997 and for the
years ended June 30, 1997 and 1996, respectively. The following table includes
revenues and expenses associated directly with the Company's oil and gas
producing activities. It does not include any allocation of the Company's
interest costs and, therefore, is not necessarily indicative of the contribution
to consolidated net operating results of the Company's oil and gas operations.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1998
- ---------------------------- U.S. CANADA COMBINED
------------- ------------- -------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas sales ............................................. $ 248,909 $ 7,978 $ 256,887
Production costs (a) .......................................... (57,663) (1,834) (59,497)
Impairment of oil and gas properties .......................... (810,610) (15,390) (826,000)
Depletion and depreciation .................................... (143,283) (3,361) (146,644)
Imputed income tax (provision) benefit (b) .................... 285,981 5,673 291,654
------------- ------------- -------------
Results of operations from oil and gas producing activities ... $ (476,666) $ (6,934) $ (483,600)
============= ============= =============
</TABLE>
67
<PAGE> 68
<TABLE>
<CAPTION>
SIX MONTHS ENDED DECEMBER 31, 1997
- ---------------------------------- U.S. CANADA COMBINED
------------- ------------- -------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas sales ............................................. $ 95,657 $ -- $ 95,657
Production costs (a) .......................................... (10,094) -- (10,094)
Impairment of oil and gas properties .......................... (110,000) -- (110,000)
Depletion and depreciation .................................... (60,408) -- (60,408)
Imputed income tax (provision) benefit (b) .................... 31,817 -- 31,817
------------- ------------- -------------
Results of operations from oil and gas producing activities ... $ (53,028) $ -- $ (53,028)
============= ============= =============
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30, 1997
- ------------------------ U.S. CANADA COMBINED
------------- ------------- -------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas sales ............................................. $ 192,920 $ -- $ 192,920
Production costs (a) .......................................... (15,107) -- (15,107)
Impairment of oil and gas properties .......................... (236,000) -- (236,000)
Depletion and depreciation .................................... (103,264) -- (103,264)
Imputed income tax (provision) benefit (b) .................... 60,544 -- 60,544
------------- ------------- -------------
Results of operations from oil and gas producing activities ... $ (100,907) $ -- $ (100,907)
============= ============= =============
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30, 1996
- ------------------------- U.S. CANADA COMBINED
------------- ------------- -------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas sales ............................................. $ 110,849 $ -- $ 110,849
Production costs (a) .......................................... (8,303) -- (8,303)
Impairment of oil and gas properties .......................... -- -- --
Depletion and depreciation .................................... (50,899) -- (50,899)
Imputed income tax (provision) benefit (b) .................... (18,335) -- (18,335)
------------- ------------- -------------
Results of operations from oil and gas producing activities ... $ 33,312 $ -- $ 33,312
============= ============= =============
</TABLE>
- ----------------------
(a) Production costs include lease operating expenses and production taxes.
(b) The imputed income tax provision is hypothetical (at the statutory rate) and
determined without regard to the Company's deduction for general and
administrative expenses, interest costs and other income tax credits and
deductions, nor whether the hypothetical tax benefits will be realized.
Capitalized costs, less accumulated amortization and related deferred income
taxes, cannot exceed an amount equal to the sum of the present value (discounted
at 10%) of estimated future net revenues less estimated future expenditures to
be incurred in developing and producing the proved reserves, less any related
income tax effects. During 1998, capitalized costs of oil and gas properties
exceeded the estimated present value of future net revenues from the Company's
proved reserves, net of related income tax considerations, resulting in a
writedown in the carrying value of oil and gas properties of $826 million. At
December 31, 1997, capitalized costs of oil and gas properties exceeded the
estimated present value of future net revenues for the Company's proved
reserves, net of related income tax considerations, resulting in a writedown in
the carrying value of oil and gas properties of $110 million. At June 30, 1997,
capitalized costs of oil and gas properties also exceeded the estimated present
value of future net revenues for the Company's proved reserves, net of related
income tax considerations, resulting in a writedown in the carrying value of oil
and gas properties of $236 million.
Oil and Gas Reserve Quantities (unaudited)
The reserve information presented below is based upon reports prepared by
independent petroleum engineers and the Company's petroleum engineers. As of
December 31, 1998, Williamson Petroleum Consultants, Inc. ("Williamson"), Ryder
Scott Company Petroleum Engineers, H.J. Gruy and Associates, Inc. and the
Company's internal reservoir engineers evaluated 63%, 12%, 1% and 24% of the
Company's combined discounted future net revenues from the Company's estimated
proved reserves, respectively. As of December 31, 1997, Williamson, Porter
Engineering Associates, Netherland, Sewell & Associates, Inc. and internal
reservoir engineers evaluated approximately 53%, 42%, 3% and 2% the Company's
combined discounted future net revenues from the Company's estimated proved
reserves, respectively. As of June 30, 1997 and 1996, the reserves evaluated by
68
<PAGE> 69
Williamson constituted approximately 41% and 99% of the company's combined
discounted future net revenues from the Company's estimated proved reserves,
respectively, with the remaining reserves being evaluated internally. The
reserves evaluated internally in fiscal 1997 were subsequently evaluated by
Williamson with a variance of approximately 4% of total proved reserves. The
information is presented in accordance with regulations prescribed by the
Securities and Exchange Commission. The Company emphasizes that reserve
estimates are inherently imprecise. The Company's reserve estimates were
generally based upon extrapolation of historical production trends, analogy to
similar properties and volumetric calculations. Accordingly, these estimates are
expected to change, and such changes could be material and occur in the near
term as future information becomes available.
Proved oil and gas reserves represent the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are those expected to be recovered through
existing wells with existing equipment and operating methods. As of December 31,
1997, all of the Company's oil and gas reserves were located in the United
States.
Presented below is a summary of changes in estimated reserves of the Company
for 1998, the six months ended December 31, 1997 and for the fiscal years 1997
and 1996:
<TABLE>
<CAPTION>
DECEMBER 31, 1998
- ----------------- U.S. CANADA COMBINED
-------------------------- -------------------------- --------------------------
OIL GAS OIL GAS OIL GAS
(MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF)
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves, beginning of period ..... 18,226 339,118 -- -- 18,226 339,118
Extensions, discoveries and other
additions .............................. 3,448 90,879 -- -- 3,448 90,879
Revisions of previous estimates .......... (4,082) (60,477) -- -- (4,082) (60,477)
Production ............................... (5,975) (86,681) (1) (7,740) (5,976) (94,421)
Sale of reserves-in-place ................ (30) (3,515) -- -- (30) (3,515)
Purchase of reserves-in-place ............ 10,973 444,694 34 239,513 11,007 684,207
----------- ----------- ----------- ----------- ----------- -----------
Proved reserves, end of period ........... 22,560 724,018 33 231,773 22,593 955,791
=========== =========== =========== =========== =========== ===========
Proved developed reserves:
Beginning of period .................... 10,087 178,082 -- -- 10,087 178,082
=========== =========== =========== =========== =========== ===========
End of period .......................... 18,003 552,953 33 105,990 18,036 658,943
=========== =========== =========== =========== =========== ===========
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31, 1997
- ----------------- U.S. CANADA COMBINED
-------------------------- -------------------------- --------------------------
OIL GAS OIL GAS OIL GAS
(MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF)
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves, beginning of period ..... 17,373 298,766 -- -- 17,373 298,766
Extensions, discoveries and other
additions .............................. 5,573 68,813 -- -- 5,573 68,813
Revisions of previous estimates .......... (3,428) (24,189) -- -- (3,428) (24,189)
Production ............................... (1,857) (27,327) -- -- (1,857) (27,327)
Sale of reserves-in-place ................ -- -- -- -- -- --
Purchase of reserves-in-place ............ 565 23,055 -- -- 565 23,055
----------- ----------- ----------- ----------- ----------- -----------
Proved reserves, end of period ........... 18,226 339,118 -- -- 18,226 339,118
=========== =========== =========== =========== =========== ===========
Proved developed reserves:
Beginning of period .................... 7,324 151,879 -- -- 7,324 151,879
=========== =========== =========== =========== =========== ===========
End of period .......................... 10,087 178,082 -- -- 10,087 178,082
=========== =========== =========== =========== =========== ===========
</TABLE>
69
<PAGE> 70
<TABLE>
<CAPTION>
JUNE 30, 1997 U.S. CANADA COMBINED
- ------------- -------------------------- -------------------------- --------------------------
OIL GAS OIL GAS OIL GAS
(MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF)
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves, beginning of period ..... 12,258 351,224 -- -- 12,258 351,224
Extensions, discoveries and other
additions .............................. 13,874 147,485 -- -- 13,874 147,485
Revisions of previous estimates .......... (5,989) (137,938) -- -- (5,989) (137,938)
Production ............................... (2,770) (62,005) -- -- (2,770) (62,005)
Sale of reserves-in-place ................ -- -- -- -- -- --
Purchase of reserves-in-place ............ -- -- -- -- -- --
----------- ----------- ----------- ----------- ----------- -----------
Proved reserves, end of period ........... 17,373 298,766 -- -- 17,373 298,766
=========== =========== =========== =========== =========== ===========
Proved developed reserves:
Beginning of period .................... 3,648 144,721 -- -- 3,648 144,721
=========== =========== =========== =========== =========== ===========
End of period .......................... 7,324 151,879 -- -- 7,324 151,879
=========== =========== =========== =========== =========== ===========
</TABLE>
<TABLE>
<CAPTION>
JUNE 30, 1996 U.S. CANADA COMBINED
- ------------- -------------------------- -------------------------- --------------------------
OIL GAS OIL GAS OIL GAS
(MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF)
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves, beginning of period ..... 5,116 211,808 -- -- 5,116 211,808
Extensions, discoveries and other
additions .............................. 8,781 158,052 -- -- 8,781 158,052
Revisions of previous estimates .......... (669) 12,987 -- -- (669) 12,987
Production ............................... (1,413) (51,710) -- -- (1,413) (51,710)
Sale of reserves-in-place ................ -- -- -- -- -- --
Purchase of reserves-in-place ............ 443 20,087 -- -- 443 20,087
----------- ----------- ----------- ----------- ----------- -----------
Proved reserves, end of period ........... 12,258 351,224 -- -- 12,258 351,224
=========== =========== =========== =========== =========== ===========
Proved developed reserves:
Beginning of period .................... 1,973 77,764 -- -- 1,973 77,764
=========== =========== =========== =========== =========== ===========
End of period .......................... 3,648 144,721 -- -- 3,648 144,721
=========== =========== =========== =========== =========== ===========
</TABLE>
During 1998, the Company acquired approximately 750 Bcfe of proved reserves
through merger or through purchases of oil and gas properties. The total
consideration given for the acquisitions was 30.8 million shares of Company
common stock, $280 million of cash, the assumption of $205 million of debt, and
the incurrence of approximately $20 million of other acquisition related costs.
Also during 1998, the Company recorded downward revisions to the December 31,
1997 estimates of approximately 4,082 MBbl and 60,477 MMcf, or approximately 85
Bcfe. These reserve revisions were primarily attributable to lower oil and gas
prices at December 31, 1998. The weighted average prices used to value the
Company's reserves at December 31, 1998 were $10.48 per barrel of oil and $1.68
per Mcf of gas, as compared to the prices used at December 31, 1997 of $17.62
per barrel of oil and $2.29 per Mcf of gas.
For the six months ended December 31, 1997, the Company recorded downward
revisions to the June 30, 1997 reserve estimates of approximately 3,428 MBbl and
24,189 MMcf, or approximately 45 Bcfe. The reserve revisions were primarily
attributable to lower than expected results from development drilling and
production which eliminated certain previously established proven reserves.
On December 16, 1997, Chesapeake acquired AnSon Production Corporation, a
privately owned oil and gas producer based in Oklahoma City. Consideration for
this acquisition was approximately $43 million. The Company estimates that it
acquired approximately 26.4 Bcfe in connection with this acquisition.
For the fiscal year ended June 30, 1997, the Company recorded downward
revisions to the previous year's reserve estimates of approximately 5,989 MBbl
and 137,938 MMcf, or approximately 174 Bcfe. The reserve revisions were
primarily attributable to the decrease in oil and gas prices between periods,
higher drilling and completion costs, and unfavorable developmental drilling and
production results during fiscal 1997. Specifically, the Company recorded
aggregate downward adjustments to proved reserves of 159 Bcfe for the Knox,
Giddings and Louisiana Trend areas.
On April 30, 1996, the Company purchased interests in certain producing and
non-producing oil and gas properties, including approximately 14,000 net acres
of unevaluated leasehold, from Amerada Hess Corporation for
70
<PAGE> 71
$37.8 million. The properties are located in the Knox and Golden Trend fields of
southern Oklahoma, most of which are operated by the Company. In fiscal 1996 the
reserves acquired from Amerada Hess Corporation were included in both
"extensions, discoveries and other additions" and "purchase of
reserves-in-place". The fiscal 1996 presentation has been restated to remove the
acquired reserves from "extensions, discoveries and other additions" with a
corresponding offset to "revisions of previous estimate". This revision resulted
in no net change to total oil and gas reserves.
Standardized Measure of Discounted Future Net Cash Flows (unaudited)
Statement of Financial Accounting Standards No. 69 ("SFAS 69") prescribes
guidelines for computing a standardized measure of future net cash flows and
changes therein relating to estimated proved reserves. The Company has followed
these guidelines which are briefly discussed below.
Future cash inflows and future production and development costs are
determined by applying year-end prices and costs to the estimated quantities of
oil and gas to be produced. Estimates are made of quantities of proved reserves
and the future periods during which they are expected to be produced based on
year-end economic conditions. Estimated future income taxes are computed using
current statutory income tax rates including consideration for the current tax
basis of the properties and related carryforwards, giving effect to permanent
differences and tax credits. The resulting future net cash flows are reduced to
present value amounts by applying a 10% annual discount factor.
The Company's reserve values were calculated using weighted average prices
at December 31, 1998 of $10.48 per barrel of oil and $1.68 per Mcf of natural
gas. If prices in future periods are below the average realized levels at
December 31, 1998, future impairment charges will likely be incurred.
The assumptions used to compute the standardized measure are those
prescribed by the Financial Accounting Standards Board and, as such, do not
necessarily reflect the Company's expectations of actual revenue to be derived
from those reserves nor their present worth. The limitations inherent in the
reserve quantity estimation process, as discussed previously, are equally
applicable to the standardized measure computations since these estimates are
the basis for the valuation process.
The following summary sets forth the Company's future net cash flows
relating to proved oil and gas reserves based on the standardized measure
prescribed in SFAS 69:
<TABLE>
<CAPTION>
DECEMBER 31, 1998
- ----------------- U.S. CANADA COMBINED
------------- ------------- -------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows (a) ................................. $ 1,374,280 $ 474,143 $ 1,848,423
Future production costs ................................. (432,876) (52,493) (485,369)
Future development costs ................................ (124,717) (29,634) (154,351)
Future income tax provision ............................. (6,464) (143,747) (150,211)
------------- ------------- -------------
Net future cash flows ................................... 810,223 248,269 1,058,492
Less effect of a 10% discount factor .................... (303,096) (132,281) (435,377)
------------- ------------- -------------
Standardized measure of discounted future net cash flows $ 507,127 $ 115,988 $ 623,115
============= ============= =============
Discounted (at 10%) future net cash flows before income
taxes .............................................. $ 504,148 $ 156,843 $ 660,991
============= ============= =============
</TABLE>
71
<PAGE> 72
<TABLE>
<CAPTION>
DECEMBER 31, 1997
- ----------------- U.S. CANADA COMBINED
------------- ------------- -------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows (b) ................................. $ 1,100,807 $ -- $ 1,100,807
Future production costs ................................. (223,030) -- (223,030)
Future development costs ................................ (158,387) -- (158,387)
Future income tax provision ............................. (108,027) -- (108,027)
------------- ------------- -------------
Net future cash flows ................................... 611,363 -- 611,363
Less effect of a 10% discount factor .................... (181,253) -- (181,253)
------------- ------------- -------------
Standardized measure of discounted future net cash
flows............................................ $ 430,110 $ -- $ 430,110
============= ============= =============
Discounted (at 10%) future net cash flows before income
taxes ........................................... $ 466,509 $ -- $ 466,509
============= ============= =============
</TABLE>
<TABLE>
<CAPTION>
JUNE 30, 1997 U.S. CANADA COMBINED
- ------------- ------------- ------------- -------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows (c) ................................. $ 954,839 $ -- $ 954,839
Future production costs ................................. (190,604) -- (190,604)
Future development costs ................................ (152,281) -- (152,281)
Future income tax provision ............................. (104,183) -- (104,183)
------------- ------------- -------------
Net future cash flows ................................... 507,771 -- 507,771
Less effect of a 10% discount factor .................... (92,273) -- (92,273)
------------- ------------- -------------
Standardized measure of discounted future net cash
flows ........................................... $ 415,498 $ -- $ 415,498
============= ============= =============
Discounted (at 10%) future net cash flows before income
taxes ........................................... $ 437,386 $ -- $ 437,386
============= ============= =============
</TABLE>
<TABLE>
<CAPTION>
JUNE 30, 1996
- ------------- U.S. CANADA COMBINED
------------- ------------- -------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows (d) ................................. $ 1,101,642 $ -- $ 1,101,642
Future production costs ................................. (168,974) -- (168,974)
Future development costs ................................ (137,068) -- (137,068)
Future income tax provision ............................. (135,543) -- (135,543)
------------- ------------- -------------
Net future cash flows ................................... 660,057 -- 660,057
Less effect of a 10% discount factor .................... (198,646) -- (198,646)
------------- ------------- -------------
Standardized measure of discounted future net cash flows $ 461,411 $ -- $ 461,411
============= ============= =============
Discounted (at 10%) future net cash flows before income
taxes ......................................... $ 547,016 $ -- $ 547,016
============= ============= =============
</TABLE>
- ----------
(a) Calculated using weighted average prices of $10.48 per barrel of oil and
$1.68 per Mcf of gas.
(b) Calculated using weighted average prices of $17.62 per barrel of oil and
$2.29 per Mcf of gas.
(c) Calculated using weighted average prices of $18.38 per barrel of oil and
$2.12 per Mcf of gas.
(d) Calculated using weighted average prices of $20.90 per barrel of oil and
$2.41 per Mcf of gas.
The principal sources of change in the standardized measure of discounted
future net cash flows are as follows:
72
<PAGE> 73
<TABLE>
<CAPTION>
DECEMBER 31, 1998
- ----------------- U.S. CANADA COMBINED
----------- ----------- -----------
($ IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure, beginning of period ............... $ 430,110 $ -- $ 430,110
Sales of oil and gas produced, net of production costs .. (191,246) (6,144) (197,390)
Net changes in prices and production costs .............. (189,817) -- (189,817)
Extensions and discoveries, net of production and
development costs ................................... 85,464 -- 85,464
Changes in future development costs ..................... 72,279 -- 72,279
Development costs incurred during the period that reduced
future development costs ............................ 28,191 -- 28,191
Revisions of previous quantity estimates ................ (64,770) -- (64,770)
Purchase of reserves-in-place ........................... 288,694 164,821 453,515
Sales of reserves-in-place .............................. (3,079) -- (3,079)
Accretion of discount ................................... 46,651 -- 46,651
Net change in income taxes .............................. 39,377 (40,855) (1,478)
Changes in production rates and other ................... (34,727) (1,834) (36,561)
----------- ----------- -----------
Standardized measure, end of period ..................... $ 507,127 $ 115,988 $ 623,115
=========== =========== ===========
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31, 1997
- ----------------- U.S. CANADA COMBINED
----------- ----------- -----------
($ IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure, beginning of period ............... $ 415,498 $ -- $ 415,498
Sales of oil and gas produced, net of production costs .. (85,563) -- (85,563)
Net changes in prices and production costs .............. 26,106 -- 26,106
Extensions and discoveries, net of production and
development costs.................................... 92,597 -- 92,597
Changes in future development costs ..................... (7,422) -- (7,422)
Development costs incurred during the period that reduced
future development costs ............................ 47,703 -- 47,703
Revisions of previous quantity estimates ................ (62,655) -- (62,655)
Purchase of reserves-in-place ........................... 25,236 -- 25,236
Sales of reserves-in-place .............................. -- -- --
Accretion of discount ................................... 43,739 -- 43,739
Net change in income taxes .............................. (14,510) -- (14,510)
Changes in production rates and other ................... (50,619) -- (50,619)
----------- ----------- -----------
Standardized measure, end of period ..................... $ 430,110 $ -- $ 430,110
=========== =========== ===========
</TABLE>
<TABLE>
<CAPTION>
JUNE 30, 1997
- ------------- U.S. CANADA COMBINED
----------- ----------- -----------
($ IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure, beginning of period ............... $ 461,411 $ -- $ 461,411
Sales of oil and gas produced, net of production costs .. (177,813) -- (177,813)
Net changes in prices and production costs .............. (99,234) -- (99,234)
Extensions and discoveries, net of production and
development costs.................................... 287,068 -- 287,068
Changes in future development costs ..................... (12,831) -- (12,831)
Development costs incurred during the period that reduced
future development costs ............................ 46,888 -- 46,888
Revisions of previous quantity estimates ................ (199,738) -- (199,738)
Purchase of reserves-in-place ........................... -- -- --
Sales of reserves-in-place .............................. -- -- --
Accretion of discount ................................... 54,702 -- 54,702
Net change in income taxes .............................. 63,719 -- 63,719
Changes in production rates and other ................... (8,674) -- (8,674)
----------- ----------- -----------
Standardized measure, end of period ..................... $ 415,498 $ -- $ 415,498
=========== =========== ===========
</TABLE>
73
<PAGE> 74
<TABLE>
<CAPTION>
JUNE 30, 1996
- ------------- U.S. CANADA COMBINED
----------- ----------- -----------
($ IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure, beginning of period ................................ $ 159,911 $ -- $ 159,911
Sales of oil and gas produced, net of production costs ................... (102,546) -- (102,546)
Net changes in prices and production costs ............................... 88,729 -- 88,729
Extensions and discoveries, net of production and development costs....... 275,916 -- 275,916
Changes in future development costs ...................................... (11,201) -- (11,201)
Development costs incurred during the period that reduced
future development costs ............................................. 43,409 -- 43,409
Revisions of previous quantity estimates ................................. 12,728 -- 12,728
Purchase of reserves-in-place ............................................ 29,641 -- 29,641
Sales of reserves-in-place ............................................... -- -- --
Accretion of discount .................................................... 18,814 -- 18,814
Net change in income taxes ............................................... (57,382) -- (57,382)
Changes in production rates and other .................................... 3,392 -- 3,392
----------- ----------- -----------
Standardized measure, end of period ...................................... $ 461,411 $ -- $ 461,411
=========== =========== ===========
</TABLE>
12. TRANSITION PERIOD COMPARATIVE DATA
The following table presents certain financial information for the twelve
months ended December 31, 1998 and 1997, and the six months ended December 31,
1997 and 1996, respectively:
<TABLE>
<CAPTION>
TWELVE MONTHS ENDED SIX MONTHS ENDED
DECEMBER 31, DECEMBER 31,
------------------------------ ------------------------------
1998 1997 1997 1996
------------- ------------- ------------- -------------
(UNAUDITED) (UNAUDITED)
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
Revenues ............................................ $ 377,946 $ 302,804 $ 153,898 $ 120,186
============= ============= ============= =============
Gross profit (loss)(a) .............................. $ (856,197) $ (309,041) $ (93,092) $ 42,946
============= ============= ============= =============
Income (loss) before income taxes
and extraordinary item ............................ $ (920,520) $ (251,150) $ (31,574) $ 39,246
Income taxes ........................................ -- (17,898) -- 14,325
------------- ------------- ------------- -------------
Income (loss) before extraordinary item ............. (920,520) (233,252) (31,574) 24,921
Extraordinary item .................................. (13,334) (177) -- (6,443)
------------- ------------- ------------- -------------
Net income (loss) ................................... $ (933,854) $ (233,429) $ (31,574) $ 18,478
============= ============= ============= =============
Earnings per share - basic
Income (loss) before extraordinary item ......... $ (9.83) $ (3.30) $ (0.45) $ 0.40
Extraordinary item .............................. (0.14) -- -- (0.10)
------------- ------------- ------------- -------------
Net income (loss) ............................... $ (9.97) $ (3.30) $ (0.45) $ 0.30
============= ============= ============= =============
Earnings per share - assuming dilution
Income (loss) before extraordinary item ......... $ (9.83) $ (3.30) $ (0.45) $ 0.38
Extraordinary item .............................. (0.14) -- -- (0.10)
------------- ------------- ------------- -------------
Net income (loss) ............................... $ (9.97) $ (3.30) $ (0.45) $ 0.28
============= ============= ============= =============
Weighted average common shares outstanding (in 000's)
Basic ........................................... 94,911 70,672 70,835 61,985
============= ============= ============= =============
Assuming dilution ............................... 94,911 70,672 70,835 66,300
============= ============= ============= =============
</TABLE>
- ----------
(a) Total revenue excluding interest and other income, less total costs and
expenses excluding interest and other expense.
74
<PAGE> 75
13. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized unaudited quarterly financial data for 1998, the six months ended
December 31, 1997 and fiscal 1997 are as follows ($ in thousands except per
share data):
<TABLE>
<CAPTION>
QUARTER ENDED
----------------------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
1998 1998 1998 1998
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
Net sales ........................................ $ 76,765 $ 109,310 $ 106,338 $ 85,533
Gross profit (loss)(a) ........................... (246,036) (218,645) 13,650 (405,166)
Net income (loss) before extraordinary item ...... (256,500) (234,739) (4,149) (425,132)
Net income (loss) ................................ (256,500) (248,073) (4,149) (425,132)
Income (loss) per share before extraordinary item:
Basic .......................................... (3.19) (2.29) (0.08) (4.44)
Diluted ........................................ (3.19) (2.29) (0.08) (4.44)
</TABLE>
<TABLE>
<CAPTION>
QUARTER ENDED
-----------------------------
SEPTEMBER 30, DECEMBER 31,
1997 1997
------------- -------------
<S> <C> <C>
Net sales ............................................ $ 72,532 $ 81,366
Gross profit (loss)(a) ............................... 8,210 (101,302)
Net Income (loss) .................................... 5,513 (37,087)
Net Income (loss) per share before extraordinary item:
Basic .............................................. .08 (.52)
Diluted ............................................ .08 (.52)
</TABLE>
<TABLE>
<CAPTION>
QUARTER ENDED
-------------------------------------------------------------
SEPTEMBER 30, DECEMBER 31, MARCH 31, JUNE 30,
1996 1996 1997 1997
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
Net sales ........................................ $ 48,937 $ 71,249 $ 79,809 $ 69,097
Gross profit (loss)(a) ........................... 14,889 28,057 25,737 (241,686)
Income (loss) before extraordinary item .......... 8,204 16,717 16,105 (217,783)
Net income (loss) ................................ 8,204 10,274 15,928 (217,783)
Income (loss) per share before extraordinary item:
Basic .......................................... .14 .26 .23 (3.12)
Diluted ........................................ .13 .25 .22 (3.12)
</TABLE>
- ----------
(a) Total revenue excluding interest and other income, less total costs and
expenses excluding interest and other expense.
Capitalized costs, less accumulated amortization and related deferred income
taxes, cannot exceed an amount equal to the sum of the present value of
estimated future net revenues less estimated future expenditures to be incurred
in developing and producing the proved reserves, less any related income tax
effects. At December 31, 1998, June 30, 1998, March 31, 1998, December 31, 1997
and June 30, 1997, capitalized costs of oil and gas properties exceeded the
estimated present value of future net revenues for the Company's proved
reserves, net of related income tax considerations, resulting in writedowns in
the carrying value of oil and gas properties of $360 million, $216 million, $250
million, $110 million and $236 million, respectively.
During the fourth quarter of 1998, the Company incurred a $55 million
impairment charge to adjust certain non-oil and gas assets to their estimated
fair values. Of this amount, $30 million related to the Company's investment in
preferred stock of Gothic Energy Corporation, and the remainder was related to
certain of the Company's gas processing and transportation assets located in
Louisiana.
14. ACQUISITIONS
During 1998, the Company acquired approximately 750 Bcfe of proved reserves
through merger or through purchases of oil and gas properties. The total
consideration given for the acquisitions was $280 million of cash,
75
<PAGE> 76
30.8 million shares of Company common stock, the assumption of $205 million of
debt, and the incurrence of approximately $20 million of other acquisition
related costs.
In March 1998, the Company acquired Hugoton Energy Corporation ("Hugoton")
pursuant to a merger by issuing 25.8 million shares of the Company's common
stock in exchange for 100% of Hugoton's common stock. The acquisition of Hugoton
was accounted for using the purchase method as of March 1, 1998, and the results
of operations of Hugoton have been included since that date.
The following unaudited pro forma information has been prepared assuming
Hugoton had been acquired as of the beginning of the periods presented. The pro
forma information is presented for informational purposes only and is not
necessarily indicative of what would have occurred if the acquisition had been
made as of those dates. In addition, the pro forma information is not intended
to be a projection of future results and does not reflect the efficiencies
expected to result from the integration of Hugoton.
Pro Forma Information (Unaudited)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1998 1997
--------------- ---------------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C>
Revenues .............................................. $ 387,638 $ 379,546
Loss before extraordinary item ........................ $ (921,969) $ (215,350)
Net loss .............................................. $ (935,303) $ (215,527)
Loss before extraordinary item per common
share .............................................. $ (9.41) $ (2.23)
Net loss per common share ............................. $ (9.55) $ (2.23)
</TABLE>
The Company acquired other businesses and oil and gas properties during the
twelve months ended December 31, 1998. The results of operations of each of
these businesses and properties, taken individually, were not material in
relation to the Company's consolidated results of operations.
76
<PAGE> 77
SCHEDULE II
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
ADDITIONS
-------------------------
BALANCE AT CHARGED BALANCE AT
BEGINNING CHARGED TO OTHER END
DESCRIPTION OF PERIOD TO EXPENSE ACCOUNTS DEDUCTIONS OF PERIOD
- -------------------------------------------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
December 31, 1998:
Allowance for doubtful accounts .......... $ 691 $ 1,589 $ 1,000 $ 71 $ 3,209
Valuation allowance for deferred tax
assets ................................. $ 77,934 $ 380,969 $ -- $ -- $ 458,903
December 31, 1997:
Allowance for doubtful accounts .......... $ 387 $ 40 $ 264 $ -- $ 691
Valuation allowance for deferred tax
assets ................................. $ 64,116 $ 13,818 $ -- $ -- $ 77,934
June 30, 1997:
Allowance for doubtful accounts .......... $ 340 $ 299 $ -- $ 252 $ 387
Valuation allowance for deferred tax
assets ................................. $ -- $ 64,116 $ -- $ -- $ 64,116
June 30, 1996:
Allowance for doubtful accounts .......... $ 452 $ 114 $ -- $ 226 $ 340
</TABLE>
77
<PAGE> 78
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information called for by this Item 10 is incorporated herein by
reference to the definitive Proxy Statement to be filed by the Company pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than April 30, 1999.
ITEM 11. EXECUTIVE COMPENSATION
The information called for by this Item 11 is incorporated herein by
reference to the definitive Proxy Statement to be filed by the Company pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than April 30, 1999.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information called for by this Item 12 is incorporated herein by
reference to the definitive Proxy Statement to be filed by the Company pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than April 30, 1999.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information called for by this Item 13 is incorporated herein by
reference to the definitive Proxy Statement to be filed by the Company pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than April 30, 1999.
78
<PAGE> 79
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial Statements. The Company's consolidated financial statements
are included in Item 8 of this report. Reference is made to the accompanying
Index to Consolidated Financial Statements.
2. Financial Statement Schedules. No financial statement schedules are
filed with this report as no schedules are applicable or required.
3. Exhibits. The following exhibits are filed herewith pursuant to the
requirements of Item 601 of Regulation S-K:
EXHIBIT
NUMBER DESCRIPTION
------ -----------
3.1 -- Registrant's Certificate of Incorporation as amended.
Incorporated herein by reference to Exhibit 3.1 to
Registrant's Amendment No. 1 to Form S-3 registration
statement (No. 333-57235).
3.2 -- Registrant's Bylaws. Incorporated herein by reference to
Exhibit 3.2 to Registrant's registration statement on Form
8-B (No. 001-13726).
4.1 -- Indenture dated as of March 15, 1997 among the
Registrant, as issuer, Chesapeake Operating, Inc.,
Chesapeake Gas Development Corporation and Chesapeake
Exploration Limited Partnership, as Subsidiary Guarantors,
and United States Trust Company of New York, as Trustee,
with respect to 7.875% Senior Notes due 2004. Incorporated
herein by reference to Exhibit 4.1 to Registrant's
registration statement on Form S-4 (No. 333-24995). First
Supplemental Indenture dated December 17, 1997 and Second
Supplemental Indenture dated February 16, 1998.
Incorporated herein by reference to Exhibit 4.1.1 to
Registrant's transition report on Form 10-K for the six
months ended December 31, 1997. Second [Third] Supplemental
Indenture dated April 22, 1998. Incorporated herein by
reference to Exhibit 4.1.1 to Registrant's Amendment No. 1
to Form S-3 registration statement (No. 333-57235). Fourth
Supplemental Indenture dated July 1, 1998. Incorporated
herein by reference to Exhibit 4.1.1 to Registrant's
quarterly report on Form 10-Q for the quarter ended
September 30, 1998.
4.2 -- Indenture dated as of March 15, 1997 among the
Registrant, as issuer, Chesapeake Operating, Inc.,
Chesapeake Gas Development Corporation and Chesapeake
Exploration Limited Partnership, as Subsidiary Guarantors,
and United States Trust Company of New York, As Trustee,
with respect to 8.5% Senior Notes due 2012. Incorporated
herein by reference to Exhibit 4.1.3 to Registrant
registration statement on Form S-4 (No. 333-24995). First
Supplemental Indenture dated December 17, 1997 and Second
Supplemental Indenture dated February 16, 1998.
Incorporated herein by reference to Exhibit 4.2.1 to
Registrant's transition report on Form 10-K for the six
months ended December 31, 1997. Second [Third] Supplemental
Indenture dated April 22, 1998. Incorporated herein by
reference to Exhibit 4.2.1 to Registrant's Amendment No. 1
to Form S-3 registration statement (No. 333-57235). Fourth
Supplemental Indenture dated July 1, 1998. Incorporated
herein by reference to Exhibit 4.2.1 to Registrant's
quarterly report on Form 10-Q for the quarter ended
September 30, 1998.
4.3 -- Indenture dated as of April 1, 1998 among the
Registrant, as Subsidiary Guarantors, and United States
Trust Company of New York, As Trustee, with respect to
9-5/8% Senior Notes due 2005. Incorporated herein by
reference to Exhibit 4.3 to Registrant registration
statement
79
<PAGE> 80
on Form S-3 (No. 333-57235). First Supplemental Indenture
dated July 1, 1998. Incorporated herein by reference to
Exhibit 4.4.1 to Registrant's quarterly report on Form 10-Q
for the quarter ended September 30, 1998.
4.4 -- Indenture dated as of April 1, 1996 among the
Registrant, its subsidiaries signatory thereto, as
Subsidiary Guarantors, and United States Trust Company of
New York, as Trustee, with respect to 9-1/8% Senior Notes,
due 2006. Incorporated herein by reference to Exhibit 4.6
to Registrant's registration statement on Form S-3 9No.
333-1588). First Supplemental Indenture dated December 30,
1996 and Second Supplemental Indenture dated December 17,
1997. Incorporated herein by reference to Exhibit 4.4.1 to
Registrant's transition report on Form 10-K for the six
months ended December 31, 1997. Third Supplemental
Indenture dated April 22, 1998. Incorporated herein by
reference to Exhibit 4.4.1 to Registrant's Amendment No. 1
to Form S-3 registration statement (No. 333-57235). Fourth
Supplemental Indenture dated July 1, 1998. Incorporated
herein by reference to Exhibit 4.3.1 to Registrant's
quarterly report on Form 10-Q for the quarter ended
September 30, 1998.
4.5 -- Agreement to furnish copies of unfiled long-term debt
Instruments. Incorporated herein by reference to
Registrant's transition report on Form 10-K for the six
months ended December 31, 1997.
4.9 -- Registration Rights Agreement dated October 22, 1997 as
amended by Amendment No. 1 dated December 22, 1997 between
Chesapeake Energy Corporation and Charles E. Davidson.
Incorporated herein by reference to Exhibit 4.9 and 4.10 to
Registrant's registration statement on Form S-4 (No.
333-48735).
4.10 -- Registration Rights Agreement between Chesapeake Energy
Corporation and certain shareholders of Hugoton Energy
Corporation. Incorporated herein by reference to
Registrant's registration statement on Form S-4 (No.
333-48735).
4.11 -- Registration Rights Agreement as of April 22, 1998 among
the Registrant and Donaldson, Lufkin & Jenrette Securities
Corporation, Morgan Stanley & Co. Incorporated, Bear
Stearns & Co. Inc., Lehman Brothers Inc. and J.P. Morgan
Securities Inc., with respect to 7% Cumulative Convertible
Preferred Stock. Incorporated herein by reference to
Exhibit 4.11 to Registrant's quarterly report on Form 10-Q
for the quarter ended March 31, 1998.
10.1.1+ -- Registrant's 1992 Incentive Stock Option Plan.
Incorporated herein by reference to Exhibit 10.1.1 to
Registrant's registration statement on Form S-4 (No.
33-93718).
10.1.2+ -- Registrant's 1992 Nonstatutory Stock Option Plan, as
Amended. Incorporated herein by reference to Exhibit 10.1.2
to Registrant's quarterly report on Form 10-Q for the
quarter ended December 31, 1996.
10.1.3+ -- Registrant's 1994 Stock Option Plan, as amended.
Incorporated herein by reference to Exhibit 10.1.3 to
Registrant's quarterly report on Form 10-Q for the quarter
ended December 31, 1996.
10.1.4+ -- Registrant's 1996 Stock Option Plan. Incorporated herein
by reference to Registrant's Proxy Statement for its 1996
Annual Meeting of Shareholders.
10.1.4.1 -- Amendment to the Chesapeake Energy Corporation 1996
Stock Option Plan. Incorporated herein by reference to
Exhibit 10.1.4.1 to Registrant's quarterly report on Form
10-Q for the quarter ended December 31, 1996.
10.2.1+ -- Amended and Restated Employment Agreement dated as of
July 1, 1998 between Aubrey K. McClendon and Chesapeake
Energy Corporation. Incorporated herein by reference to
Exhibit 10.2.1 to Registrant's quarterly report on Form
10-Q for the quarter ended September 30, 1998.
80
<PAGE> 81
10.2.2+ -- Amended and Restated Employment Agreement dated as of
July 1, 1998 between Tom L. Ward and Chesapeake Energy
Corporation. Incorporated herein by reference to Exhibit
10.2.2 to Registrant's quarterly report on Form 10-Q for
the quarter ended September 30, 1998.
10.2.3*+ -- Amended and Restated Employment Agreement dated as of
July 1, 1998 between Marcus C. Rowland and Chesapeake
Energy Corporation.
10.2.4+ -- Employment Agreement dated as of July 1, 1997 between
Steven C. Dixon and Chesapeake Energy Corporation.
Incorporated herein by reference to Exhibit 10.2.4 to
Registrant's quarterly report on Form 10-Q for the quarter
ended September 30, 1997.
10.2.5+ -- Employment Agreement dated as of July 1, 1997 between J.
Mark Lester and Chesapeake Energy Corporation. Incorporated
herein by reference to Exhibit 10.2.5 to Registrant's
annual report on Form 10-K for the year ended June 30,
1997.
10.2.6+ -- Employment Agreement dated as of July 1, 1997 between
Henry J. Hood and Chesapeake Energy Corporation.
Incorporated herein by reference to Exhibit 10.2.6 to
Registrant's annual report on Form 10-K for the year ended
June 30, 1997.
10.2.7+ -- Employment Agreement dated as of July 1, 1997 between
Ronald A. Lefaive and Chesapeake Energy Corporation.
Incorporated herein by reference to Exhibit 10.2.7 to
Registrant's annual report on Form 10-K for the year ended
June 30, 1997.
10.2.8+ -- Employment Agreement dated as of July 1, 1997 between
Martha A. Burger and Chesapeake Energy Corporation.
Incorporated herein by reference to Exhibit 10.2.8 to
Registrant's annual report on Form 10-K for the year ended
June 30, 1997.
10.2.9* -- Amendment to Employment Agreements of Steven C. Dixon,
J. Mark Lester, Henry J. Hood, Ronald A. Lefaive and Martha
A. Burger dated as of July 1, 1997.
10.3+ -- Form of Indemnity Agreement for officers and directors
of Registrant and its subsidiaries. Incorporated herein by
reference to Exhibit 10.30 to Registrant's Registration
statement on Form S-1 (No. 33-55600).
10.4.1* -- Second Amended and Restated Loan Agreement between
Aubrey K. McClendon and Chesapeake Energy Marketing, Inc.,
dated effective December 31, 1998.
10.4.2* -- Second Amended and Restated Loan Agreement between Tom
L. Ward and Chesapeake Energy Marketing, Inc., dated
effective December 31, 1998.
10.5 -- Rights Agreement dated July 15, 1998 between the
Registrant and UMB Bank, N.A., as Rights Agent.
Incorporated herein by reference to Exhibit 1 to
Registrant's registration statement on Form 8-A filed July
16, 1998. Amendment No. 1 dated September 11, 1998.
Incorporated herein by reference to Exhibit 10.3 to
Registrant's quarterly report on Form 10-Q
for the quarter ended September 30, 1998.
10.9 -- Indemnity and Stock Registration Agreement, as amended
by First Amendment (Revised) thereto, dated as of February
12, 1993, and as amended by Second Amendment thereto dated
as of October 20, 1995, among Chesapeake Energy
Corporation, Chesapeake Operating, Inc., Chesapeake
Investments, TLW Investments, Inc., et al. Incorporated
herein by reference to Exhibit 10.35 to Registrant's annual
report on Form 10-K for the year ended June 30, 1993 and
Exhibit 10.4.1 to Registrant's Quarterly report on Form
10-Q for the quarter ended December 31, 1995.
10.10 -- Partnership Agreement of Chesapeake Exploration Limited
Partnership dated December 27, 1994 between Chesapeake
Energy Corporation and Chesapeake Operating, Inc.
Incorporated
81
<PAGE> 82
herein by reference to Exhibit 10.10 to Registrant's
registration statement on Form S-4 (No. 33-93718).
10.11 -- Amended and Restated Limited Partnership Agreement of
Chesapeake Louisiana, L.P. dated June 30, 1997 between
Chesapeake Operating, Inc. and Chesapeake Energy Louisiana
Corporation.
21* -- Subsidiaries of Registrant
23.1* -- Consent of PricewaterhouseCoopers LLP
23.2* -- Consent of Williamson Petroleum Consultants, Inc.
23.3* -- Consent of Ryder Scott Company Petroleum Engineers
27* -- Financial Data Schedule
- ----------
* Filed herewith.
+ Management contract or compensatory plan or arrangement.
(b) Reports on Form 8-K
During the quarter ended December 31, 1998, the Company filed the following
Current Reports on Form 8-K dated:
October 7, 1998 announcing a significant Tuscaloosa discovery.
October 23, 1998 providing a status report on drilling activity.
November 9, 1998 announcing that it had agreed to tender its 19.9% stake in
Pan East Petroleum Corp. to Poco Petroleums Ltd. and had agreed to a
property exchange with Pan East.
November 18, 1998 reporting 1998 third quarter results.
December 8, 1998 announcing completion of a significant Tuscaloosa
discovery.
December 17, 1998 announcing capital budget and suspension of dividend of
its preferred stock.
December 22, 1998 responding to Union Pacific Resources Corporation's press
release regarding pending litigation.
82
<PAGE> 83
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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
By /s/ AUBREY K. McCLENDON
---------------------------------
Aubrey K. McClendon
Chairman of the Board and
Chief Executive Officer
Date: March 30, 1999
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
- -------------------------------------- -------------------------------------- --------------
<S> <C> <C>
/s/ AUBREY K. McCLENDON Chairman of the Board, Chief Executive March 30, 1999
- -------------------------------------- Officer and Director
Aubrey K. McClendon (Principal Executive Officer)
/s/ TOM L. WARD President, Chief Operating Officer and March 30, 1999
- -------------------------------------- Director
Tom L. Ward (Principal Executive Officer)
/s/ MARCUS C. ROWLAND Executive Vice President and Chief March 30, 1999
- -------------------------------------- Financial Officer
Marcus C. Rowland (Principal Financial Officer)
/s/ RONALD A. LEFAIVE Senior Vice President - Accounting, March 30, 1999
- -------------------------------------- Controller and Chief Accounting Officer
Ronald A. Lefaive (Principal Accounting Officer)
/s/ EDGAR F. HEIZER, JR. Director March 30, 1999
- --------------------------------------
Edgar F. Heizer, Jr.
/s/ BREENE M. KERR Director March 30, 1999
- --------------------------------------
Breene M. Kerr
/s/ SHANNON T. SELF Director March 30, 1999
- --------------------------------------
Shannon T. Self
/s/ FREDERICK B. WHITTEMORE Director March 30, 1999
- --------------------------------------
Frederick B. Whittemore
/s/ WALTER C. WILSON Director March 30, 1999
- --------------------------------------
Walter C. Wilson
</TABLE>
83
<PAGE> 84
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION PAGE
-------- ----------- ----
<S> <C> <C>
3.1 -- Registrant's Certificate of Incorporation as amended.
Incorporated herein by reference to Exhibit 3.1 to
Registrant's Amendment No. 1 to Form S-3 registration
statement (No. 333-57235).
3.2 -- Registrant's Bylaws. Incorporated herein by reference to
Exhibit 3.2 to Registrant's registration statement on Form
8-B (No. 001-13726).
4.1 -- Indenture dated as of March 15, 1997 among the
Registrant, as issuer, Chesapeake Operating, Inc.,
Chesapeake Gas Development Corporation and Chesapeake
Exploration Limited Partnership, as Subsidiary Guarantors,
and United States Trust Company of New York, as Trustee,
with respect to 7.875% Senior Notes due 2004. Incorporated
herein by reference to Exhibit 4.1 to Registrant's
registration statement on Form S-4 (No. 333-24995). First
Supplemental Indenture dated December 17, 1997 and Second
Supplemental Indenture dated February 16, 1998.
Incorporated herein by reference to Exhibit 4.1.1 to
Registrant's transition report on Form 10-K for the six
months ended December 31, 1997. Second [Third] Supplemental
Indenture dated April 22, 1998. Incorporated herein by
reference to Exhibit 4.1.1 to Registrant's Amendment No. 1
to Form S-3 registration statement (No. 333-57235). Fourth
Supplemental Indenture dated July 1, 1998. Incorporated
herein by reference to Exhibit 4.1.1 to Registrant's
quarterly report on Form 10-Q for the quarter ended
September 30, 1998.
4.2 -- Indenture dated as of March 15, 1997 among the
Registrant, as issuer, Chesapeake Operating, Inc.,
Chesapeake Gas Development Corporation and Chesapeake
Exploration Limited Partnership, as Subsidiary Guarantors,
and United States Trust Company of New York, As Trustee,
with respect to 8.5% Senior Notes due 2012. Incorporated
herein by reference to Exhibit 4.1.3 to Registrant
registration statement on Form S-4 (No. 333-24995). First
Supplemental Indenture dated December 17, 1997 and Second
Supplemental Indenture dated February 16, 1998.
Incorporated herein by reference to Exhibit 4.2.1 to
Registrant's transition report on Form 10-K for the six
months ended December 31, 1997. Second [Third] Supplemental
Indenture dated April 22, 1998. Incorporated herein by
reference to Exhibit 4.2.1 to Registrant's Amendment No. 1
to Form S-3 registration statement (No. 333-57235). Fourth
Supplemental Indenture dated July 1, 1998. Incorporated
herein by reference to Exhibit 4.2.1 to Registrant's
quarterly report on Form 10-Q for the quarter ended
September 30, 1998.
4.3 -- Indenture dated as of April 1, 1998 among the
Registrant, as Subsidiary Guarantors, and United States
Trust Company of New York, As Trustee, with respect to
9-5/8% Senior Notes due 2005. Incorporated herein by
reference to Exhibit 4.3 to Registrant registration
statement on Form S-3 (No. 333-57235). First Supplemental
Indenture dated July 1, 1998. Incorporated herein by
reference to Exhibit 4.4.1 to Registrant's quarterly report
on Form 10-Q for the quarter ended September 30, 1998.
4.4 -- Indenture dated as of April 1, 1996 among the
Registrant, its subsidiaries signatory thereto, as
Subsidiary Guarantors, and United States Trust Company of
New York, as Trustee, with respect to 9-1/8% Senior Notes,
due 2006. Incorporated herein by reference to Exhibit 4.6
to Registrant's registration statement on Form S-3 9No.
333-1588). First Supplemental Indenture dated December 30,
1996 and Second Supplemental Indenture dated December 17,
1997. Incorporated herein by reference to Exhibit 4.4.1 to
Registrant's transition report on Form 10-K for the six
months
</TABLE>
<PAGE> 85
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION PAGE
-------- ----------- ----
<S> <C> <C>
ended December 31, 1997. Third Supplemental Indenture dated
April 22, 1998. Incorporated herein by reference to Exhibit
4.4.1 to Registrant's Amendment No. 1 to Form S-3
registration statement (No. 333-57235). Fourth Supplemental
Indenture dated July 1, 1998. Incorporated herein by
reference to Exhibit 4.3.1 to Registrant's quarterly report
on Form 10-Q for the quarter ended September 30, 1998.
4.5 -- Agreement to furnish copies of unfiled long-term debt
Instruments. Incorporated herein by reference to
Registrant's transition report on Form 10-K for the six
months ended December 31, 1997.
4.9 -- Registration Rights Agreement dated October 22, 1997 as
amended by Amendment No. 1 dated December 22, 1997 between
Chesapeake Energy Corporation and Charles E. Davidson.
Incorporated herein by reference to Exhibit 4.9 and 4.10 to
Registrant's registration statement on Form S-4 (No.
333-48735).
4.10 -- Registration Rights Agreement between Chesapeake Energy
Corporation and certain shareholders of Hugoton Energy
Corporation. Incorporated herein by reference to
Registrant's registration statement on Form S-4 (No.
333-48735).
4.11 -- Registration Rights Agreement as of April 22, 1998 among
the Registrant and Donaldson, Lufkin & Jenrette Securities
Corporation, Morgan Stanley & Co. Incorporated, Bear
Stearns & Co. Inc., Lehman Brothers Inc. and J.P. Morgan
Securities Inc., with respect to 7% Cumulative Convertible
Preferred Stock. Incorporated herein by reference to
Exhibit 4.11 to Registrant's quarterly report on Form 10-Q
for the quarter ended March 31, 1998.
10.1.1+ -- Registrant's 1992 Incentive Stock Option Plan.
Incorporated herein by reference to Exhibit 10.1.1 to
Registrant's registration statement on Form S-4 (No.
33-93718).
10.1.2+ -- Registrant's 1992 Nonstatutory Stock Option Plan, as
Amended. Incorporated herein by reference to Exhibit 10.1.2
to Registrant's quarterly report on Form 10-Q for the
quarter ended December 31, 1996.
10.1.3+ -- Registrant's 1994 Stock Option Plan, as amended.
Incorporated herein by reference to Exhibit 10.1.3 to
Registrant's quarterly report on Form 10-Q for the quarter
ended December 31, 1996.
10.1.4+ -- Registrant's 1996 Stock Option Plan. Incorporated herein
by reference to Registrant's Proxy Statement for its 1996
Annual Meeting of Shareholders.
10.1.4.1 -- Amendment to the Chesapeake Energy Corporation 1996
Stock Option Plan. Incorporated herein by reference to
Exhibit 10.1.4.1 to Registrant's quarterly report on Form
10-Q for the quarter ended December 31, 1996.
10.2.1+ -- Amended and Restated Employment Agreement dated as of
July 1, 1998 between Aubrey K. McClendon and Chesapeake
Energy Corporation. Incorporated herein by reference to
Exhibit 10.2.1 to Registrant's quarterly report on Form
10-Q for the quarter ended September 30, 1998.
10.2.2+ -- Amended and Restated Employment Agreement dated as of
July 1, 1998 between Tom L. Ward and Chesapeake Energy
Corporation. Incorporated herein by reference
</TABLE>
<PAGE> 86
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION PAGE
-------- ----------- ----
<S> <C> <C>
to Exhibit 10.2.2 to Registrant's quarterly report on Form
10-Q for the quarter ended September 30, 1998.
10.2.3*+ -- Amended and Restated Employment Agreement dated as of
July 1, 1998 between Marcus C. Rowland and Chesapeake
Energy Corporation............................................ 88
10.2.4+ -- Employment Agreement dated as of July 1, 1997 between
Steven C. Dixon and Chesapeake Energy Corporation.
Incorporated herein by reference to Exhibit 10.2.4 to
Registrant's quarterly report on Form 10-Q for the quarter
ended September 30, 1997.
10.2.5+ -- Employment Agreement dated as of July 1, 1997 between J.
Mark Lester and Chesapeake Energy Corporation. Incorporated
herein by reference to Exhibit 10.2.5 to Registrant's
annual report on Form 10-K for the year ended June 30,
1997.
10.2.6+ -- Employment Agreement dated as of July 1, 1997 between
Henry J. Hood and Chesapeake Energy Corporation.
Incorporated herein by reference to Exhibit 10.2.6 to
Registrant's annual report on Form 10-K for the year ended
June 30, 1997.
10.2.7+ -- Employment Agreement dated as of July 1, 1997 between
Ronald A. Lefaive and Chesapeake Energy Corporation.
Incorporated herein by reference to Exhibit 10.2.7 to
Registrant's annual report on Form 10-K for the year ended
June 30, 1997.
10.2.8+ -- Employment Agreement dated as of July 1, 1997 between
Martha A. Burger and Chesapeake Energy Corporation.
Incorporated herein by reference to Exhibit 10.2.8 to
Registrant's annual report on Form 10-K for the year ended
June 30, 1997.
10.2.9* -- Amendment to Employment Agreements of Steven C. Dixon,
J. Mark Lester, Henry J. Hood, Ronald A. Lefaive and Martha
A. Burger dated as of July 1, 1997.............................104
10.3+ -- Form of Indemnity Agreement for officers and directors
of Registrant and its subsidiaries. Incorporated herein by
reference to Exhibit 10.30 to Registrant's Registration
statement on Form S-1 (No. 33-55600).
10.4.1* -- Second Amended and Restated Loan Agreement between
Aubrey K. McClendon and Chesapeake Energy Marketing, Inc.,
dated effective December 31, 1998.............................106
10.4.2* -- Second Amended and Restated Loan Agreement between Tom
L. Ward and Chesapeake Energy Marketing, Inc., dated
effective December 31, 1998...................................121
10.5 -- Rights Agreement dated July 15, 1998 between the
Registrant and UMB Bank, N.A., as Rights Agent.
Incorporated herein by reference to Exhibit 1 to
Registrant's registration statement on Form 8-A filed July
16, 1998. Amendment No. 1 dated September 11, 1998.
Incorporated herein by reference to Exhibit 10.3 to
Registrant's quarterly report on Form 10-Q
for the quarter ended September 30, 1998.
10.9 -- Indemnity and Stock Registration Agreement, as amended
by First Amendment (Revised) thereto, dated as of February
12, 1993, and as amended by Second Amendment thereto dated
as of October 20, 1995, among Chesapeake Energy
Corporation, Chesapeake Operating, Inc., Chesapeake
Investments, TLW Investments, Inc., et al. Incorporated
herein by reference to Exhibit 10.35 to Registrant's annual
report on Form 10-K for the year ended June 30, 1993 and
Exhibit
</TABLE>
<PAGE> 87
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION PAGE
-------- ----------- ----
<S> <C> <C>
10.4.1 to Registrant's Quarterly report on Form 10-Q for
the quarter ended December 31, 1995.
10.10 -- Partnership Agreement of Chesapeake Exploration Limited
Partnership dated December 27, 1994 between Chesapeake
Energy Corporation and Chesapeake Operating, Inc.
Incorporated herein by reference to Exhibit 10.10 to
Registrant's registration statement on Form S-4 (No.
33-93718).
10.11 -- Amended and Restated Limited Partnership Agreement of
Chesapeake Louisiana, L.P. dated June 30, 1997 between
Chesapeake Operating, Inc. and Chesapeake Energy Louisiana
Corporation.
21* -- Subsidiaries of Registrant....................................136
23.1* -- Consent of PricewaterhouseCoopers LLP.........................137
23.2* -- Consent of Williamson Petroleum Consultants, Inc..............138
23.3* -- Consent of Ryder Scott Company Petroleum Engineers............139
27* -- Financial Data Schedule.......................................140
</TABLE>
- ----------
* Filed herewith.
+ Management contract or compensatory plan or arrangement.
<PAGE> 1
EXHIBIT 10.2.3
AMENDED AND RESTATED
EMPLOYMENT AGREEMENT
between
MARCUS C. ROWLAND
and
CHESAPEAKE ENERGY CORPORATION
Effective July 1, 1998
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
-----
<S> <C>
1. Employment....................................................................................... 1
2. Executive's Duties............................................................................... 1
2.1 Specific Duties........................................................................... 1
2.2 Supervision............................................................................... 1
2.3 Rules and Regulations..................................................................... 2
2.4 Stock Investment.......................................................................... 2
3. Other Activities................................................................................. 2
3.1 Company's Activities...................................................................... 3
3.1.1 Amount of Participation............................................................ 3
3.1.2 Conditions of Participation........................................................ 4
3.2 Other Activities.......................................................................... 4
4. Executive's Compensation......................................................................... 5
4.1 Base Salary............................................................................... 5
4.2 Bonus..................................................................................... 5
4.3 Stock Options............................................................................. 5
4.4 Benefits.................................................................................. 5
4.4.1 Vacation........................................................................... 5
4.4.2 Membership Dues.................................................................... 6
4.4.3 Compensation Review................................................................ 6
4.4.4 Automobile Allowance............................................................... 6
5. Term............................................................................................. 6
6. Termination...................................................................................... 6
6.1 Termination by Company.................................................................... 6
6.1.1 Termination without Cause.......................................................... 7
6.1.2 Termination for Cause.............................................................. 7
6.2 Termination by Executive.................................................................. 7
6.3 Termination After Change in Control....................................................... 8
6.3.1 Change of Control.................................................................. 8
6.3.2 CC Termination..................................................................... 8
6.4 Incapacity of Executive................................................................... 9
6.5 Death of Executive........................................................................ 9
</TABLE>
<PAGE> 3
<TABLE>
<S> <C>
6.6 Effect of Termination..................................................................... 9
TABLE OF CONTENTS (continued)
7. Confidentiality.................................................................................. 10
8. Noncompetition................................................................................... 11
9. Proprietary Matters.............................................................................. 11
10. Arbitration...................................................................................... 12
11. Miscellaneous.................................................................................... 12
11.1 Time...................................................................................... 12
11.2 Notices................................................................................... 12
11.3 Assignment................................................................................ 13
11.4 Construction.............................................................................. 13
11.5 Entire Agreement.......................................................................... 13
11.6 Binding Effect............................................................................ 13
11.7 Attorney's Fees........................................................................... 13
11.8 Supercession.............................................................................. 13
</TABLE>
<PAGE> 4
EMPLOYMENT AGREEMENT
THIS AGREEMENT is made effective July 1, 1998, between CHESAPEAKE
ENERGY CORPORATION, an Oklahoma corporation (the "Company"), and MARCUS C.
ROWLAND, an individual (the "Executive") and replaces and supersedes those
certain Employment Agreements between Company and Executive dated March 1, 1995
and July 1, 1997.
W I T N E S S E T H:
WHEREAS, the Company desires to retain the services of the Executive
and the Executive desires to make the Executive's services available to the
Company.
NOW, THEREFORE, in consideration of the mutual promises herein
contained, the Company and the Executive agree as follows:
1. Employment. The Company hereby employs the Executive and the Executive hereby
accepts such employment subject to the terms and conditions contained in this
Agreement. The Executive is engaged as an employee of the Company, and the
Executive and the Company do not intend to create a joint venture, partnership
or other relationship which might impose a fiduciary obligation on the Executive
or the Company in the performance of this Agreement.
2. Executive's Duties. The Executive is employed on a full-time basis.
Throughout the term of this Agreement, the Executive will use the Executive's
best efforts and due diligence to assist the Company in achieving the most
profitable operation of the Company and the Company's affiliated entities
consistent with developing and maintaining a quality business operation.
2.1 Specific Duties. The Executive will serve as Chief Financial
Officer and Senior Vice President - Finance for the Company.
The Executive will perform all of the services required to
fully and faithfully execute the office and position to which
the Executive is appointed and such other services as may be
reasonably requested by the Executive's supervisor. During the
term of this Agreement, the Executive may be nominated for
election or appointed to serve as a director or officer of the
Company's subsidiaries as determined in the board of
directors' sole discretion.
2.2 Supervision. The services of the Executive will be requested
and directed by the Chief Executive Officer, Mr. Aubrey K.
McClendon.
1
<PAGE> 5
2.3 Rules and Regulations. The Company currently has an Employment
Policies Manual which addresses frequently asked questions
regarding the Company. The Executive agrees to comply with the
Employment Policies Manual except to the extent inconsistent
with this Agreement. The Employment Policies Manual is subject
to change without notice in the sole discretion of the Company
at any time.
2.4 Stock Investment. For each calendar year during which this
Agreement is in effect, the Executive agrees to hold shares of
the Company's common stock having aggregate Investment Value
equal to one hundred percent (100%) of the compensation paid
to the Executive under paragraphs 4.1 and 4.2 of this
Agreement during such calendar year. For purposes of this
section, the "Investment Value" of each share of stock will be
the higher of either (a) the price paid by the Executive for
such share as part of an open market purchase; or (b) the fair
market value on the date of exercise for shares acquired
through the exercise of employee stock options. Any shares of
common stock acquired by the Executive prior to the date of
this Agreement and still owned by the Executive during the
term of this Agreement may be used to satisfy this requirement
to acquire common stock. The Investment Value for previously
acquired stock shall be calculated using the average stock
price during the first six months of this Agreement.
The stock acquired or owned pursuant to this paragraph 2.4
must be held by the Executive at all times during the
Executive's employment by the Company or the Company's
affiliated entities. In order to administer this provision,
the Executive agrees to return to the Company's Chief
Executive Officer a semi-annual report of purchases and
ownership in a form prepared by the Company. This paragraph
will become null and void if the Company's common stock ceases
to be listed on the New York Stock Exchange or on the National
Association of Securities Dealers Automated Quotation System.
The Company has no obligation to sell or to purchase from the
Executive any of the Company's stock in connection with this
paragraph 2.4 and has made no representations or warranties
regarding the Company's stock, operations or financial
condition.
3. Other Activities. Except for the activities (the "Permitted Activities")
expressly permitted by paragraphs 3.1 and 3.2 of this Agreement, or the prior
written approval of Aubrey K. McClendon, the Executive will not: (a) engage in
business independent of the Executive's employment by the Company; (b) serve as
an officer, general partner or member in any corporation, partnership, company,
or firm; (c) directly or indirectly invest in, participate in or acquire an
interest in any oil and gas business, including, without limitation, (i)
producing oil and gas, (ii) drilling, owning or operating oil and gas leases or
2
<PAGE> 6
wells, (iii) providing services or materials to the oil and gas industry, (iv)
marketing or refining oil or gas, or (v) owning any interest in any corporation,
partnership, company or entity which conducts any of the foregoing activities.
The limitation in this paragraph 3 will not prohibit an investment by the
Executive in publicly traded securities; or the continued direct ownership and
operation of oil and gas interests and leases to the extent such interests were
owned by the Executive on March 1, 1995. Notwithstanding the foregoing, the
Executive will be permitted to participate in the following activities which
will be deemed to be approved by the Company, if such activities are undertaken
in strict compliance with this Agreement.
3.1 Company's Activities. The Executive or the Executive's
designated affiliate will be permitted to acquire a working
interest in all of the wells spudded by the Company or the
Company's subsidiary corporations, partnerships or entities
(the "Program Wells") during any Calendar Quarter (as
hereafter defined) on the terms and conditions set forth
herein. The Program Wells include any well spudded during such
Calendar Quarter in which the Company or the Company's
subsidiary corporations, partnerships or entities participate
as a nonoperator.
3.1.1 Amount of Participation. On or before the date which
is thirty (30) days before the first (1st) day of
each Calendar Quarter, the Executive will provide
notice to the compensation committee of the Company's
board of directors of the Executive's intent to
participate in the Program Wells during the
succeeding Calendar Quarter and the approximate
percentage working interest which the Executive
proposes to participate with during such Calendar
Quarter. The Executive's percentage working interest
in the Program Wells spudded during such Calendar
Quarter will be subject to approval by the
disinterested members of the compensation committee
of the Company's board of directors and to the
limitations set forth herein (the "Approved
Percentage"). The Executive's Approved Percentage
working Interest participation (determined without
consideration of any carried interest) in the Program
Wells for any Calendar Quarter will not exceed one
percent (1.0%) on an eight-eighths (8/8ths) basis. On
designation of the Approved Percentage for a Calendar
Quarter, the Executive will be deemed to have elected
to participate in each Program Well spudded during
such calendar Quarter with a working interest equal
to the following applicable percentage determined on
a well-by-well basis (the "Minimum Participation"):
(a) the Approved Percentage for a Program Well which
does not fall within clause (b) of this paragraph
3.1.1 or an Operations Well; or (b) zero percent (0%)
if the combined participation in the Program Well by
the Executive, Mr. Tom L. Ward and Mr. Aubrey K.
McClendon
3
<PAGE> 7
with such individuals' Approved Percentage under
their respective employment agreements causes the
Company's working interest (determined without
consideration of any carried interest) on the spud
date for such Program Well to be less than twelve and
one-half percent (12.5%) on an eight-eighths (8/8ths)
basis. If clause (b) of this paragraph 3.1.1
prohibits the Executive's participation in a Program
Well, then Messrs. Ward and McClendon will not be
entitled to participate in such Program Well under
their employment agreements. An "Operations Well"
means a Program Well which falls within the
provisions of clause (b) of this paragraph 3.1.1, but
for which the Executive's participation is deemed
necessary for the Company to retain operations as
determined by the disinterested members of the
compensation committee of the Company's board of
directors. If the Executive fails to provide notice
of the Executive's intent to participate and the
Executive's proposed participation prior to the
specified date as provided herein, the amount of the
Approved Percentage for the Calendar Quarter will be
deemed to be zero (0).
3.1.2 Conditions of Participation. The Participation by the
Executive in each Program Well will be on no better
terms than the terms agreed to by unaffiliated third
party participants in connection with the acquisition
of an interest in such Program Well from the Company
or its subsidiary corporations, partnerships or
entities. The Approved Percentage cannot be changed
during any Calendar Quarter without the prior
approval of the disinterested members of the
compensation committee of the Company's board of
directors. Any participation by the Executive under
this paragraph 3.1 is also conditioned upon the
Executive's participation in each Program Well
spudded during such Calendar Quarter in an amount
equal to the Minimum Participation. The Executive
hereby agrees to execute and deliver any documents
reasonably requested by the Company and hereby
appoints the Company as the Executive's agent and
attorney-in-fact to execute and deliver such
documents if the Executive fails or refuses to
execute such documents. The Executive further agrees
to pay all joint interest billings within one hundred
fifty (150) days after receipt. For purposes of this
Agreement, the term "Calendar Quarter" means the
three (3) month periods commencing on the first (1st)
day of January, April, July and October.
3.2 Other Activities. The Executive currently conducts oil and gas
business activities individually and through various related
or family owned entities including MJ Partners, a Texas
general partnership ("MJ"). The Executive will be permitted to
continue oil and gas activities individually in MJ and
4
<PAGE> 8
indirectly through related entities, but only to the extent
such activities are (a) conducted on oil and gas leases or
interests owned by the Executive or MJ as of March 1, 1993,
(b) acquired pursuant to paragraph 3.1 of this Agreement, or
(c) Approved Projects (as hereafter defined). For purposes of
this Agreement Approved Projects means an interest in an oil
and gas business which: (y) is acquired (whether directly or
indirectly) by the Executive, Affiliate of the Executive or a
related entity in an area in which the Company is not active
at the time of such acquisition and (z) which is approved by
Aubrey K. McClendon.
4. Executive's Compensation. The Company agrees to compensate the Executive as
follows:
4.1 Base Salary. A base salary (the "Base Salary"), at the initial
annual rate of not less than Two Hundred Fifty Thousand
Dollars ($250,000.00), will be paid to the Executive in equal
semi-monthly installments beginning July 15, 1998 during the
term of this Agreement.
4.2 Bonus. In addition to the Base Salary described at paragraph
4.1 of this Agreement, the Company may periodically pay bonus
compensation to the Executive. Any bonus compensation will be
at the absolute discretion of the Company in such amounts and
at such times as the board of directors of the Company may
determine.
4.3 Stock Options. In addition to the compensation set forth in
paragraphs 4.1 and 4.2 of this Agreement, the Executive may
periodically receive grants of stock options from the
Company's various stock option plans, subject to the terms and
conditions thereof.
4.4 Benefits. The Company will provide the Executive such
retirement benefits, reimbursement of reasonable expenditures
for dues, travel and entertainment and such other benefits as
are customarily provided by the Company and as are set forth
in the Company's Employment Policies Manual. The Company will
also provide the Executive the opportunity to apply for
coverage under the Company's medical, life and disability
plans, if any. If the Executive is accepted for coverage under
such plans, the Company will provide such coverage on the same
terms as is customarily provided by the Company to the plan
participants as modified from time to time. The following
specific benefits will also be provided to the Executive at
the expense of the Company:
4.4.1 Vacation. The Executive will be entitled to take
three (3) weeks of paid vacation each twelve months
during the term of this Agreement.
5
<PAGE> 9
No additional compensation will be paid for failure
to take vacation and no vacation may be carried
forward from one twelve month period to another.
4.4.2 Membership Dues. The Company will reimburse the
Executive for: (a) the monthly dues necessary to
maintain a full membership in a country club in the
Oklahoma City area selected by the Executive; and (b)
the reasonable cost of any qualified business
entertainment at such country club. All other costs,
including, without implied limitation, any initiation
costs, initial membership costs, personal use and
business entertainment unrelated to the Company will
be the sole obligation of the Executive and the
Company will have no liability with respect to such
amounts.
4.4.3 Compensation Review. The compensation of the
Executive will be reviewed not less frequently than
annually by the board of directors of the Company.
The compensation of the Executive prescribed by
paragraph 4 of this Agreement may be increased at the
discretion of the Company, but may not be reduced
without the prior written consent of the Executive.
4.4.4 Automobile Allowance. The Executive will receive a
monthly cash allowance in the amount of One Thousand
Dollars ($1,000.00) to defer a portion of the
Executive's cost of acquiring, operating and
maintaining an automobile for use in the Executive's
employment.
5. Term. In the absence of termination as set forth in paragraph 6 below, this
Agreement will extend for a term of two (2) years commencing on July 1, 1998,
and ending on June 30, 2000 (the "Expiration Date"). Unless the Company provides
thirty (30) days prior written notice of nonextension to the Executive, on each
June 30 during the term of this Agreement, the term will be automatically
extended for one (1) additional year so that the remaining term on this
Agreement will be not less than one (1) and not more than two (2) years.
6. Termination. This Agreement will continue in effect until the expiration of
the term stated at paragraph 5 of this Agreement unless earlier terminated
pursuant to this paragraph
6.1 Termination by Company. The Company will have the following
rights to terminate this Agreement:
6
<PAGE> 10
6.1.1 Termination without Cause. The Company may terminate
this Agreement without cause at any time by the
service of written notice of termination to the
Executive specifying an effective date of such
termination not sooner than sixty (60) business days
after the date of such notice (the "Termination
Date"). In the event the Executive is terminated
without cause, the Executive will receive as
termination compensation: (a) continuation of the
Base Salary provided by paragraph 4.1 during the
portion of the contract period remaining after the
date of the Executive's termination, but in any
event, through the Expiration Date; (b) any benefits
payable by operation of paragraph 4.4 of this
Agreement during the portion of the contract period
remaining after the date of the Executive's
termination, but in any event, through the Expiration
Date; and (c) any vacation pay accrued through the
Termination Date. The termination compensation in (a)
shall be paid only if the Executive executes the
Company's standard termination agreement releasing
all legally waivable claims arising from the
Executive's employment.
6.1.2 Termination for Cause. The Company may terminate this
Agreement for cause if the Executive: (a)
misappropriates the property of the Company or
commits any other act of dishonesty; (b) engages in
personal misconduct which materially injures the
Company; (c) willfully violates any law or regulation
relating to the business of the Company which results
in injury to the Company; or (d) willfully and
repeatedly fails to perform the Executive's duties
hereunder. In the event this Agreement is terminated
for cause, the Company will not have any obligation
to provide any further payments or benefits to the
Executive after the effective date of such
termination. In the event this Agreement is
terminated for cause, the Company will not have any
obligation to provide any further payments or
benefits to the Executive after the effective date of
such termination.
6.2 Termination by Executive. The Executive may voluntarily
terminate this Agreement with or without cause by the service
of written notice of such termination to the Company
specifying an effective date of such termination sixty (60)
days after the date of such notice, during which time
Executive may use remaining accrued vacation days, or at the
Company's option, be paid for such days. In the event this
Agreement is terminated by the Executive, neither the Company
nor the Executive will have any further obligations hereunder
including, without limitation, any obligation of
7
<PAGE> 11
the Company to provide any further payments or benefits to the
Executive after the effective date of such termination.
6.3 Termination After Change in Control. If, during the term of
this Agreement, there is a "Change of Control" and within two
(2) years thereafter there is a CC Termination (as hereafter
defined) then the Executive will be entitled to a severance
payment (in addition to any other rights and other amounts
payable to the Executive under this Agreement or otherwise) in
an amount equal to the sum of the following: (a) three (3)
times the Executive's Base Compensation; plus (b) the Gross-up
Amount (as hereafter defined). If the foregoing amount is not
paid within ten (10) days after the CC Termination, the unpaid
amount will bear interest at the per annum rate equal to the
prime rate published from time to time in the Wall Street
Journal. The interest rate will be adjusted on the date of a
change in such prime rate. For purposes of this Agreement the
term "Gross-up Amount" means the amount of the payment which
will result in the Executive retaining from such payment
(after paying all taxes imposed on such payment and any
interest or penalties related to such taxes) an amount equal
to any excise tax imposed by Section 4999 of the Internal
Revenue Code of 1986, as amended, together with any interest
and penalties with respect to such excise tax imposed on all
of the payments made to the Executive under this paragraph
6.3.
6.3.1 Change of Control. The term "Change of Control" means
any action of a nature that would be required to be
reported in response to Item 6(e) of Schedule 14A of
Regulation 14A under the Securities Exchange Act of
1934 with respect to the Company including, without
limitation (i) the direct or indirect acquisition by
any person after the date hereof of beneficial
ownership of the right to vote or securities of the
Company representing the right to vote thirty five
percent (35%) or more of the combined voting power of
the Company's then outstanding securities having the
right to vote for the election of directors, or (ii)
within two years of a tender offer or exchange offer
for the voting stock of the Company or as a result of
a merger, consolidation, sale of assets or contested
election (or any combination of a foregoing), a
majority of the members of the Company's board of
directors is replaced by directors who were not
nominated and approved by the board of directors.
6.3.2 CC Termination. The term "CC Termination" means any
of the following: (a) this Agreement expires in
accordance with its terms; (b) this Agreement is not
extended under paragraph 5 of
8
<PAGE> 12
this Agreement and the Executive resigns within
one (1) year after such nonextension; (c) the
Executive is terminated by the Company other than
under paragraphs 6.1.2, 6.4 or 6.5 based on adequate
grounds; (d) the Executive resigns as a result of a
change in the Executive's duties, a reduction the
Executive's then current compensation, a required
relocation more than 25 miles from the Executive's
then current place of employment or a default by the
Company under this Agreement; (e) the failure by the
Company after a Change of Control to obtain the
assumption of this Agreement, without limitation or
reduction, by any successor to the Company or any
parent corporation of the Company; or (f) after a
Change of Control has occurred, the Executive agrees
to remain employed by the Company for a period of
three (3) months to assist in the transition and
thereafter resigns.
6.4 Incapacity of Executive. If the Executive suffers from a
physical or mental condition which in the reasonable judgment
of the Company's management prevents the Executive in whole or
in part from performing the duties specified herein for a
period of three (3) consecutive months, the Executive may be
terminated. Although the termination shall be deemed as a
termination with cause, any compensation payable under
paragraph 4 of this Agreement will be continued through the
remaining contract period, but in any event, through the
Expiration Date. Notwithstanding the foregoing, the
Executive's Base Salary specified in paragraph 4.1 of this
Agreement shall be reduced by any benefits payable under any
disability plans.
6.5 Death of Executive. If the Executive dies during the term of
this Agreement, the Company may thereafter terminate this
Agreement without compensation to the Executive's estate
except: (a) the obligation to continue the Base Salary
payments under paragraph 4.1 of this Agreement for twelve (12)
months and (b) the benefits described in paragraph 4.4 of this
Agreement accrued through the effective date of such
termination.
6.6 Effect of Termination. The termination of this Agreement will
terminate all obligations of the Executive to render services
on behalf of the Company, provided that the Executive will
maintain the confidentiality of all information acquired by
the Executive during the term of his employment in accordance
with paragraph 7 of this Agreement. Except as otherwise
provided in paragraph 6 of this Agreement, no accrued bonus,
severance pay or other form of compensation will be payable by
the Company to the
9
<PAGE> 13
Executive by reason of the termination of this Agreement. All
keys, entry cards, credit cards, files, records, financial
information, furniture, furnishings, equipment, supplies and
other items relating to the Company will remain the property
of the Company. The Executive will have the right to retain
and remove all personal property and effects which are owned
by the Executive and located in the offices of the Company.
All such personal items will be removed from such offices no
later than two (2) days after the effective date of
termination, and the Company is hereby authorized to discard
any items remaining and to reassign the Executive's office
space after such date. Prior to the effective date of
termination, the Executive will render such services to the
Company as might be reasonably required to provide for the
orderly termination of the Executive's employment.
7. Confidentiality. The Executive recognizes that the nature of the Executive's
services are such that the Executive will have access to information which
constitutes trade secrets, is of a confidential nature, is of great value to the
Company or is the foundation on which the business of the Company is predicated.
The Executive agrees not to disclose to any person other than the Company's
employees or the Company's legal counsel nor use for any purpose, other than the
performance of this Agreement, any confidential information ("Confidential
Information"). Confidential Information includes data or material (regardless of
form) which is: (a) a trade secret; (b) provided, disclosed or delivered to
Executive by the Company, any officer, director, employee, agent, attorney,
accountant, consultant, or other person or entity employed by the Company in any
capacity, any customer, borrower or business associate of the Company or any
public authority having jurisdiction over the Company of any business activity
conducted by the Company; or (c) produced, developed, obtained or prepared by or
on behalf of Executive or the Company (whether or not such information was
developed in the performance of this Agreement) with respect to the Company or
any assets oil and gas prospects, business activities, officers, directors,
employees, borrowers or customers of the foregoing. However, Confidential
Information shall not include any information, data or material which at the
time of disclosure or use was generally available to the public other than by a
breach of this Agreement, was available to the party to whom disclosed on a
non-confidential basis by disclosure or access provided by the Company or a
third party, or was otherwise developed or obtained independently by the person
to whom disclosed without a breach of this Agreement. On request by the Company,
the Company will be entitled to a copy of any Confidential Information in the
possession of the Executive. The Executive also agrees that the provisions of
this paragraph 7 will survive the termination, expiration or cancellation of
this Agreement for a period of five (5) years. The Executive will deliver to the
Company all originals and copies of the documents or materials containing
Confidential Information. For purposes of paragraphs 7, 8, and 9 of this
Agreement, the Company expressly includes any of the Company's affiliated
corporations, partnerships or entities.
10
<PAGE> 14
8. Noncompetition. For a period of twelve (12) months after Executive is no
longer employed by the Company as a result of either the resignation by the
Executive pursuant to paragraph 6.2 above, or Termination for Cause pursuant to
paragraph 6.1.2 above, Executive will not: (a) acquire, attempt to acquire or
aid another in the acquisition or attempted acquisition of an interest in oil
and gas assets, oil and gas production, oil and gas leases, mineral interests,
oil and gas wells or other such oil and gas exploration, development or
production activities within five (5) miles of any operations or ownership
interests of the Company or its affiliated corporations, partnerships or
entities, provided, however, this provision shall not apply to acquisitions
within said five (5) mile radius of assets or activities of a successor entity
resulting from a "Change in Control" as described in paragraph 6.1.3., which
assets were owned or activities were being conducted (1) prior to the date of
such Change in Control, or (2) after such Change in Control but for which the
Executive had no material responsibility; and; (b) for the Executive's own
account or for the benefit of another party solicit, induce, entice or attempt
to entice any employee, contractor, customer, vendor or subcontractor to
terminate or breach any relationship with the Company or the Company's
affiliates. The Executive further agrees that the Executive will not circumvent
or attempt to circumvent the foregoing agreements by any future arrangement or
through the actions of a third party.
9. Proprietary Matters. The Executive expressly understands and agrees that any
and all improvements, inventions, discoveries, processes or know-how that are
generated or conceived by the Executive during the term of this Agreement,
whether generated or conceived during the Executive's regular working hours or
otherwise, will be the sole and exclusive property of the Company. Whenever
requested by the Company (either during the term of this Agreement or
thereafter), the Executive will assign or execute any and all applications,
assignments and or other instruments and do all things which the Company deems
necessary or appropriate in order to permit the Company to: (a) assign and
convey or otherwise make available to the Company the sole and exclusive right,
title, and interest in and to said improvements, inventions, discoveries,
processes, know-how, applications, patents, copyrights, trade names or
trademarks; or (b) apply for, obtain, maintain, enforce and defend patents,
copyrights, trade names, or trademarks of the United States or of foreign
countries for said improvements, inventions, discoveries, processes or know-how.
However, the improvements, inventions, discoveries, processes or know-how
generated or conceived by the Executive and referred to above (except as they
may be included in the patents, copyrights or registered trade names or
trademarks of the Company, or corporations, partnerships or other entities which
may be affiliated with the Company) shall not be exclusive property of the
Company at any time after having been disclosed or revealed or have otherwise
become available to the public or to a third party on a non-confidential basis
other than by a breach of this Agreement, or after they have been independently
developed or discussed without a breach of this Agreement by a third party who
has no obligation to the Company or its affiliates.
11
<PAGE> 15
10. Arbitration. The parties will attempt to promptly resolve any dispute or
controversy arising out of or relating to this Agreement or termination of the
Executive by the Company. Any negotiations pursuant to this paragraph 10 are
confidential and will be treated as compromise and settlement negotiations for
all purposes. If the parties are unable to reach a settlement amicably, the
dispute will be submitted to binding arbitration before a single arbitrator in
accordance with the Employment Dispute Resolution Rules of the American
Arbitration Association. The arbitrator will be instructed and empowered to take
reasonable steps to expedite the arbitration and the arbitrator's judgment will
be final and binding upon the parties subject solely to challenge on the grounds
of fraud or gross misconduct. Except for damages arising out of a breach of
paragraphs 7, 8 or 9 of this Agreement, the arbitrator is not empowered to award
total damages (including compensatory damages) which exceed 300% of compensatory
damages and each party hereby irrevocably waives any damages in excess of that
amount. The arbitration will be held in Oklahoma County, Oklahoma. Judgment upon
any verdict in arbitration may be entered in any court of competent jurisdiction
and the parties hereby consent to the jurisdiction of, and proper venue in, the
federal and state courts located in Oklahoma County, Oklahoma. Each party will
bear its own costs in connection with the arbitration and the costs of the
arbitrator will be borne by the party who the arbitrator determines did not
prevail in the matter. Unless otherwise expressly set forth in this Agreement,
the procedures specified in this paragraph 10 will be the sole and exclusive
procedures for the resolution of disputes and controversies between the parties
arising out of or relating to this Agreement. Notwithstanding the foregoing, a
party may seek a preliminary injunction or other provisional judicial relief if
in such party's judgment such action is necessary to avoid irreparable damage or
to preserve the status quo.
11. Miscellaneous. The parties further agree as follows:
11.1 Time. Time is of the essence of each provision of this
Agreement.
11.2 Notices. Any notice, payment, demand or communication required
or permitted to be given by any provision of this Agreement
will be in writing and will be deemed to have been given when
delivered personally or by telefacsimile to the party
designated to receive such notice, or on the date following
the day sent by overnight courier, or on the third (3rd)
business day after the same is sent by certified mail, postage
and charges prepaid, directed to the following address or to
such other or additional addresses as any party might
designate by written notice to the other party:
To the Company: Chesapeake Energy Corporation
Post Office Box 18496
Oklahoma City, OK 73154-0496
Attn: Aubrey K. McClendon
12
<PAGE> 16
To the Executive: Mr. Marcus C. Rowland
15000 Wilson Rd.
Edmond, OK 73013
11.3 Assignment. Neither this Agreement nor any of the parties'
rights or obligations hereunder can be transferred or assigned
without the prior written consent of the other parties to this
Agreement.
11.4 Construction. If any provision of this Agreement or the
application thereof to any person or circumstances is
determined, to any extent, to be invalid or unenforceable, the
remainder of this Agreement, or the application of such
provision to persons or circumstances other than those as to
which the same is held invalid or unenforceable, will not be
affected thereby, and each term and provision of this
Agreement will be valid and enforceable to the fullest extent
permitted by law. This Agreement is intended to be
interpreted, construed and enforced in accordance with the
laws of the State of Oklahoma and any litigation relating to
this Agreement will be conducted in a court of competent
jurisdiction sitting in Oklahoma County, Oklahoma.
11.5 Entire Agreement. This Agreement constitutes the entire
agreement between the parties hereto with respect to the
subject matter herein contained, and no modification hereof
will be effective unless made by a supplemental written
agreement executed by all of the parties hereto.
11.6 Binding Effect. This Agreement will be binding on the parties
and their respective successors, legal representatives and
permitted assigns. In the event of a merger, consolidation,
combination, dissolution or liquidation of the Company, the
performance of this Agreement will be assumed by any entity
which succeeds to or is transferred the business of the
Company as a result thereof.
11.7 Attorneys' Fees. If any party institutes an action or
proceeding against any other party relating to the provisions
of this Agreement or any default hereunder, the unsuccessful
party to such action or proceeding will reimburse the
successful party therein for the reasonable expenses of
attorneys' fees and disbursements and litigation expenses
incurred by the successful party.
11.8 Supercession. On execution of this Agreement by the Company
and the Executive, the relationship between the Company and
the Executive will be bound by the terms of this Agreement and
the Employment Policies
13
<PAGE> 17
Manual and not by any other agreements or otherwise. In the
event of a conflict between the Employment Policies Manual and
this Agreement, this Agreement will control in all respects.
IN WITNESS WHEREOF, the undersigned have executed this Agreement
effective the date first above written.
CHESAPEAKE ENERGY CORPORATION, an
Oklahoma corporation
By: /s/ Aubrey K. McClendon
--------------------------------------------
Aubrey K. McClendon, Chief Executive Officer
(the "Company")
By: /s/ Marcus C. Rowland
--------------------------------------------
Marcus C. Rowland, Individually
(the "Executive")
14
<PAGE> 1
EXHIBIT 10.2.9
The existing Paragraph 6.1.3 of those certain Employment Agreements dated July
1, 1997, between Chesapeake Energy Corporation and each of Steven C. Dixon, J.
Mark Lester, Henry J. Hood, Ronald A. Lefaive and Martha A. Burger is hereby
amended and superseded by the following new Paragraph 6.1.3:
If, during the term of this Agreement, there is a "Change of Control"
and within one (1) year from the effective date of such Change of
Control: (a) this Agreement expires and is not extended; or (b) the
Executive resigns as a result of (i) a reduction in the Executive's
compensation (including the Executive's then current Base Salary under
Paragraphs 4.1 of this Agreement and bonuses equal to those paid to the
Executive during calendar year 1998 under paragraph 4.2 of this
Agreement), or (ii) a required relocation more than twenty five (25)
miles from the Executive's then current place of employment; or within
two (2) years from the effective date of the Change of Control the
Executive is terminated other than under Paragraphs 6.1.2, 6.3 or 6.4
based on adequate grounds; then the Executive will be entitled to a
severance payment (in addition to any other amounts payable to the
Executive under this Agreement or otherwise, excluding any Base Salary
payable under Paragraph 6.1.1, as of the date of termination or
resignation hereunder) in an amount equal to twelve (12) months of the
Executive's then current Base Salary under Paragraph 4.1 of this
Agreement plus bonuses equal to those paid to the Executive during
calendar year 1998 under Paragraph 4.2. The term "Change of Control"
means any action of a nature that would be required to be reported in
response to Item 6(e) of Schedule 14A of Regulation 14A under the
Securities Exchange Act of 1934 with respect to Chesapeake Energy
Corporation ("Chesapeake") including, without limitation (i) the direct
or indirect acquisition by any person after the date hereof of
beneficial ownership of the right to vote or securities of Chesapeake
representing the right to vote thirty five percent (35%) or more of the
combined voting power of Chesapeake's then outstanding securities
having the right to vote for the election of directors, or (ii) a
merger, consolidation, sale of assets or contested election or (iii)
any combination of (i) and (ii) which results in a majority of the
members of Chesapeake's board of directors being replaced by directors
who were not nominated and approved by the existing board of directors.
If, during the term of this Agreement, Chesapeake sells, assigns or
conveys a material portion of Chesapeake's oil and gas reserves or a
majority of the stock of a wholly owned subsidiary and as a result
thereof within one (1) year from the closing date of such sale,
assignment or conveyance: (a) this Agreement expires and is not
extended; or (b) the Executive resigns as a result of (i) a reduction
in the Executive's compensation (including the Executive's then current
Base Salary under paragraph 4.1 of this Agreement and bonuses equal to
those paid to the Executive during calendar year 1998 under Paragraph
4.2 of this Agreement), or (ii) a required relocation more
<PAGE> 2
than twenty five (25) miles from the Executive's then current place of
employment; or within two (2) years from the closing date of such sale,
assignment or conveyance the Executive is terminated other than under
Paragraphs 6.1.2, 6.3 or 6.4 based on adequate grounds; then the
Executive will be entitled to a severance payment (in addition to any
other amounts payable to the Executive under this Agreement or
otherwise, excluding any Base Salary payable under Paragraph 6.1.1, as
of the date of termination or resignation hereunder) in an amount equal
to twelve (12) months of the Executive's then current Base Salary under
Paragraph 4.1 of this Agreement plus bonuses equal to those paid to the
Executive during calendar year 1998 under Paragraph 4.2.
<PAGE> 1
EXHIBIT 10.4.1
SECOND AMENDED AND RESTATED
LOAN AGREEMENT
between
AUBREY K. McCLENDON
and
CHESAPEAKE ENERGY MARKETING, INC.
December 31, 1998
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
1. Loan Amount..................................................1
2. Note.........................................................1
2.1 Interest............................................1
2.2 Payments............................................2
2.3 No Readvances.......................................2
2.4 Prepayments.........................................2
3. Collateral Security..........................................3
4. Conditions of Lending........................................3
4.1 Loan Documents......................................3
4.2 No Violation........................................4
4.3 Additional Information..............................4
4.4 Prior Note Interest.................................4
4.5 JIBs................................................4
4.6 No Default..........................................4
4.7 Representations.....................................4
4.8 Opinion of Counsel..................................4
4.9 Financial Statements................................4
5. Representations and Warranties...............................4
5.1 Capacity and Power..................................5
5.2 Full Disclosure.....................................5
5.3 Financial Condition.................................5
5.4 Liabilities.........................................5
5.5 Ownership...........................................5
5.7 Survival of Representations.........................5
5.8 Pelican Lake........................................6
6. Covenants of the Borrower....................................6
6.1 Financial Statements................................6
6.2 Liquidation Assets Report...........................6
6.3 Notifications.......................................6
6.4 Records Inspections.................................6
6.5 Additional Documents................................7
6.6 Taxes...............................................7
6.7 Creation of Liens...................................7
6.8 Other Agreements....................................7
6.9 Indebtedness........................................7
7. Default......................................................8
</TABLE>
i
<PAGE> 3
<TABLE>
<S> <C>
7.1 Nonpayment of Note..................................8
7.2 Other Nonpayment....................................8
7.3 Breach of Agreement.................................8
7.4 Representations and Warranties......................8
7.5 Insolvency..........................................8
7.6 Bankruptcy..........................................8
7.7 Receivership........................................8
7.8 Judgment............................................8
7.9 Insecurity..........................................9
8. Remedies.....................................................9
8.1 Termination.........................................9
8.2 Acceleration of Note................................9
8.3 Selective Enforcement...............................9
8.4 Waiver of Default...................................9
9. Miscellaneous................................................9
9.1 Expenses...........................................10
9.2 Notices............................................10
9.3 Severability.......................................10
9.4 Construction and Venue.............................11
9.5 No Waiver..........................................11
9.6 Counterparts.......................................11
9.7 Prior Agreement....................................11
</TABLE>
ii
<PAGE> 4
<TABLE>
<S> <C>
Schedule "A" - Form of Promissory Note
Schedule "B" - Liquidation Assets
Schedule "C" - Form of Second Amendment to Amended & Restated Security Agreement
</TABLE>
iii
<PAGE> 5
SECOND AMENDED AND RESTATED
LOAN AGREEMENT
THIS AGREEMENT is entered into effective the 31st day of December, 1998,
between AUBREY K. McCLENDON, an individual (the "Borrower"), and CHESAPEAKE
ENERGY MARKETING, INC., an Oklahoma corporation (the "Lender"), and amends and
restates in its entirety that certain Loan Agreement dated July 7, 1998, between
the Borrower and the Lender, as amended by that certain Amended and Restated
Loan Agreement dated July 13, 1998, as amended by that certain First Amendment
to Amended and Restated Loan Agreement dated August 19, 1998 (collectively, the
"Prior Agreement").
WHEREAS, under the Prior Agreement and the promissory note issued pursuant
thereto (the "Prior Note"), all principal of and interest on the Prior Note was
due on December 31, 1998; and
WHEREAS, the Borrower has requested that the Lender extend the maturity
date of the Prior Note and the obligations of the Borrower under the Prior
Agreement for a period not to exceed one year, and the Lender is agreeable to
such extension on the terms and conditions set forth herein and for the
consideration set forth herein and in the other Loan Documents (as hereinafter
defined).
NOW THEREFORE, the Borrower and the Lender hereby amend and restate the
Prior Agreement as follows:
W I T N E S S E T H :
1. Loan Amount. Subject to the terms and conditions of this Agreement, the
Lender agrees to extend the time of payment of the existing loan to the Borrower
in the principal amount of Four Million Eight Hundred Eighty-five Thousand
Dollars ($4,885,000.00).
2. Note. The loan to be made hereunder will be evidenced by the Promissory Note
(the "Note") in the form of Schedule "A" attached hereto as a part hereof and
payable on the following terms:
2.1 Interest. Except as otherwise provided in the Note, the unpaid
principal balance of the Note will bear interest at the per annum rate
equal to nine and one-eighth percent (9 1/8%). Except for interest
payments made pursuant to paragraph 2.4 of this Agreement, interest on
the Note will be payable quarterly commencing on March 31, 1999, and
on the last day of each successive June, September and December
thereafter until the Note is paid in full. All interest will be
computed
Initial Approval FINAL DOCUMENT
---------
---------
---------
<PAGE> 6
at a per diem charge for the actual number of days elapsed on the
basis of a year consisting of three hundred sixty-five (365) days.
2.2 Payments. Each payment on the Note including, without limitation,
payments made pursuant to paragraph 2.4 hereof, will be applied first
to any obligations of the Borrower to the Lender under the Loan
Documents other than principal and interest, then to accrued unpaid
interest on the Note, and then to the unpaid principal balance of the
Note. The entire unpaid principal balance plus all accrued and unpaid
interest on the Note will be due and payable on December 31, 1999, or
at such earlier date as required under paragraph 8 of this Agreement.
2.3 No Readvances. The Borrower understands and agrees that the Note is
not a revolving note and that on any prepayment of principal, such
prepaid amount will not be readvanced.
2.4 Prepayments. The Borrower will have the right at any time to prepay
the Note in whole or in part, without premium or penalty, but with
interest accrued to the date of prepayment. In addition, the Borrower
hereby agrees that throughout the term of the Note the Borrower will
in good faith use the Borrower's best efforts to sell that portion of
the Collateral (as hereinafter defined) described in Schedule "B"
attached hereto as a part hereof (the "Liquidation Assets") in a
manner reasonably calculated to fully repay the Note on or before
December 31, 1999. In connection with the liquidation of the
Liquidation Assets, the Borrower agrees to consult with the members of
the loan committee (the "Loan Committee") of the Board of Directors of
the Lender's parent Chesapeake Energy Corporation (the "Company"). The
Borrower further agrees that in the event the unpaid principal balance
of the Note is more than: (a) $4,600,000.00 on March 31, 1999; (b)
$4,000,000.00 on June 30, 1999; or (c) $2,500,000.00 on September 30,
1999 (each a "Payment Hurdle"), the Lender (acting through the members
of the Loan Committee if so approved by the Loan Committee on behalf
of the Lender) will have the right at any time thereafter to dispose
of the Liquidation Assets in such manner and on such terms as the
Lender (acting through the members of the Loan Committee if so
approved by the Loan Committee on behalf of the Lender) determines in
the Lender's sole discretion and the Borrower hereby fully authorizes
and empowers (without the necessity of any further consent or
authorization from the Borrower) the Lender and appoints and makes the
Lender the Borrower's true and lawful attorney-in fact and agent for
the Borrower and in the Borrower's name, place and stead with full
power of substitution, in the Lender's name or the Borrower's name or
otherwise, for the Lender's sole use and benefit, but at the
Borrower's cost and expense, to dispose of the Liquidation Assets,
without notice, provided, however, the Lender and each member of the
Loan Committee will be under no obligation or duty to exercise the
power hereby conferred upon it and will be without liability for any
act or failure to act in connection with the disposition of the
Liquidation Assets. Unless the Lender, with the approval of the Loan
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Committee, otherwise consents in writing, all dispositions of
Liquidation Assets will be for cash or freely marketable securities.
On disposition of any Collateral one hundred percent (100%) of the
proceeds net of actual out of pocket expenses will be held in trust
and promptly delivered to the Lender to be applied to the Note in
accordance with paragraph 2.2 of this Agreement. With respect to the
Liquidation Assets owned by Chesapeake Investments, an Oklahoma
Limited Partnership (the "Pledgor"), the Borrower agrees to cause the
Pledgor to fully comply with the terms of this paragraph 2.4.
Notwithstanding the provisions of the Amended and Restated Employment
Agreement between the Borrower and the Company dated effective July 1,
1998 (the "Employment Agreement") in the event that at any time (1)
joint interest billings ("JIBs") in connection with participation in
the program wells spudded by the Company or its subsidiaries (the
"Drilling Program") as contemplated under the Employment Agreement are
not paid when due, or (ii) any of the Payment Hurdles are unsatisfied
("Participation Conditions") the Borrower agrees that in either event
the Borrower will not participate in the Drilling Program wells
spudded by the Company or its subsidiary corporations during any time
in which the Participation Conditions are not satisfied.
3. Collateral Security. Payment of the Note will be secured by a first lien on
and security interest in the property (the "Collateral") described in the
Amended and Restated Security Agreement dated July 13, 1998, as amended by that
certain First Amendment to Amended and Restated Security Agreement dated August
19, 1998, as further amended by that certain Second Amendment to Amended and
Restated Security Agreement in the form of Schedule "C" attached hereto as a
part hereof (the "Security Agreement") and any other Loan Documents. The
Borrower has requested release of the lien in favor of the Lender on the
Borrower's ownership interest in the Pelican Lake Stock and a portion of the
lien in favor of the Lender on the Borrower's interest in Core Systems, both
constituting Collateral securing the Loan . Subject to the terms and conditions
set forth below, the Lender hereby agrees to such releases. The Lender will
release the Pelican Lake Stock and thirty-seven and one-half percent (37 1/2%)
of the Borrower's interest in Core Systems constituting Collateral securing the
Loan in exchange for cash proceeds of a sale of such interest to be immediately
applied to reduction of outstanding amounts on the Note, in the order provided
under the first sentence of Section 2.2. Upon receipt of such proceeds, the
Lender will release an additional thirty-seven and one-half percent (37 1/2%) of
the remaining interest of the Borrower in Core Systems (the "Additional Interest
Released"), to the effect that twenty-five percent (25%) of such interest will
be retained by the Lender as Collateral securing the Note. Provided that the
Borrower is in compliance with the Participation Conditions on the date of such
payment, proceeds of a sale of the Additional Interest Released may be used by
the Borrower at his discretion. The release of any additional Collateral from
time to time at the request of the Borrower will be in the sole discretion of
the Lender and the Loan Committee.
4. Conditions of Lending. The obligation of the Lender to perform this Agreement
and to extend the time for payment of the indebtedness evidenced by the Note is
subject to the following conditions precedent.
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4.1 Loan Documents. This Agreement, the Note, the Security Agreement,
financing statements, stock powers, and related documents and all
extensions, amendments and modifications thereof (collectively, the
"Loan Documents") will have been duly executed, acknowledged (where
appropriate) by all parties thereto and delivered to the Lender, all
in form and substance satisfactory to the Lender.
4.2 No Violation. The advance under the Note will not cause the Lender to
be in violation of any law, rule, regulation or agreement applicable
to the Lender or the Company.
4.3 Additional Information. The Lender will have received such additional
documents, instruments and information as the Lender requests
including, without limitation, current financial statements of the
Borrower and information and valuation (based on fair value)
concerning any of the Collateral designated by the Lender in writing.
4.4 Prior Note Interest. The Borrower will have paid in full all accrued
and unpaid interest on the Prior Note through and including December
31, 1998.
4.5 JIBs. No JIBs will be overdue and unpaid under the terms of the
Employment Agreement as of the date of execution of this Agreement.
4.6 No Default. No default (however defined, but excluding margin
shortages) will have occurred or be continuing under the Borrower's
credit facility with Union Bank of California, N.A. (the "Union Bank
Facility") or any other agreement evidencing indebtedness of the
Borrower, or any other material agreement, unless such default will
have been effectively waived in writing by the other party or parties
thereto.
4.7 Representations. All representations of the Borrower in the Prior
Agreement, the security agreement executed in connection with the
Prior Agreement, hereunder or otherwise made by the Borrower to the
Lender or to the Loan Committee will be true and correct on and as of
the date hereof.
4.8 Opinion of Counsel. The Lender will have received an opinion of McAfee
& Taft that the Loan Documents are enforceable against the Borrower in
accordance with the terms thereof and that the execution, delivery and
performance of this Agreement will not: (a) violate any law, rule or
regulation under the laws of the State of Oklahoma or applicable
federal law; or (b) conflict with or cause a breach under any
agreement to which the Company or any of its subsidiaries is a party
or by which any of their respective properties are bound.
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4.9 Financial Statements. The Lender and the Loan Committee will have
received financial statements of the Borrower as of February 28, 1999,
including and reflecting transactions through such date.
5. Representations and Warranties. In order to induce the Lender to enter into
and perform the Loan Documents, the Borrower represents and warrants to the
Lender as follows:
5.1 Capacity and Power. The Borrower has adequate capacity, power and
legal right to enter into, execute, deliver and perform the terms of
the Loan Documents, to borrow money, to give security for borrowings
and to consummate the transactions contemplated by the Loan Documents.
The execution, delivery and performance of the Loan Documents by the
Borrower will not violate any law, regulation, rule or any other
agreement or instrument binding on the Borrower or the Collateral.
5.2 Full Disclosure. Neither this Agreement nor any statement or document
referred to herein or delivered to the Lender by the Borrower or any
other party on behalf of the Borrower contains any material untrue
statement or omits to state a material fact necessary to make the
statements herein or therein not misleading.
5.3 Financial Condition. The Borrower's financial statements dated as of
December 31, 1998, copies of which have been furnished to the Lender
are correct and complete and fairly reflect the financial condition of
the Borrower as of the date thereof and have been prepared in
conformity with accounting principles applied on a basis consistent
with that of preceding periods. There has occurred no material adverse
change in the financial condition of the Borrower from the date of
such financial statements to the date of execution of this Agreement.
5.4 Liabilities. The Borrower has no material liabilities, direct or
contingent, and has granted no security interests or liens on the
property of the Borrower, except those disclosed in the financial
statements referred to in paragraph 5.3 of this Agreement.
5.5 Ownership. The Borrower has good and marketable title to the
Collateral, free and clear of all liens, security interests, claims or
encumbrances, except for liens and security interests in favor of the
Lender.
5.6 No Default. No default (however defined, but excluding margin
shortages) has occurred or is continuing under any other agreement,
instrument or document between the Borrower and any person or under
any agreement secured by property of the Borrower including, without
limitation, the Union Bank Facility or any other agreement evidencing
indebtedness of the Borrower other than such defaults as have been
disclosed to the Lender prior to the date hereof or that have been
effectively waived in writing by such other party.
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5.7 Survival of Representations. All representations and warranties made
by the Borrower herein will survive the delivery of the Loan
Documents, and any investigation at any time made by or on behalf of
the Lender will not diminish the Lender's right to rely thereon. All
statements contained in any certificate or other instrument delivered
by or on behalf of the Borrower under or pursuant to this Agreement or
in connection with the transactions contemplated hereby will
constitute representations and warranties made by the Borrower
hereunder.
5.8 Pelican Lake. The sole assets of Pelican Lake, Inc. are the real
property located in Minnesota and the fixtures and personal property
located on or used in connection with such real property.
6. Covenants of the Borrower. Until the expiration of the Lender's obligation to
advance funds under this Agreement and payment in full of the Note, the Borrower
agrees that, unless the Lender waives compliance in writing:
6.1 Financial Statements. The Borrower will furnish the Lender and each of
the members of the Loan Committee the Borrower's financial statements
on a quarterly basis, within thirty (30) days after the end of each
calendar quarter, commencing with the calendar quarter ending March
31, 1999, and such additional financial statements as the Lender or
the Loan Committee might reasonably request.
6.2 Liquidation Assets Report. The Borrower will furnish to the Lender,
with a copy to each member of the Loan Committee, monthly within ten
(10) days after the end of each month commencing January 31, 1999, a
report, in form and substance satisfactory to the Lender and the Loan
Committee, setting forth the status of the Borrower's efforts to
dispose of the Liquidation Assets including, without limitation,
copies of any pending sale contracts, scheduled closing dates and
estimated expenses of sale and net proceeds.
6.3 Notifications. The Borrower will give prompt written notice to the
Lender and each member of the Loan Committee of: (a) any event of
default; (b) any event of default or acceleration under any other
lending arrangement to which the Borrower is a party; (c) all material
litigation affecting the Borrower or the Collateral; and (d) any other
matter which has resulted in, or might result in (i) a material
adverse change in the financial condition of the Borrower, or (ii) a
material adverse change in the ability of the Borrower to perform the
Borrower's obligations, warranties, covenants and conditions of the
Loan Documents.
6.4 Records Inspections. The Borrower will and will cause the Pledgor to
maintain full and accurate accounts and records of the Borrower's and
the Pledgor's respective businesses on a basis consistent with prior
periods. The Borrower will and will cause the Pledgor to permit the
Lender and the Lender's designated representatives
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including, without limitation, the Loan Committee, to have access to
the Borrower's and the Pledgor's respective records and accounts at
all reasonable times to perform such inspections, audits and
examinations as the Lender or the Loan Committee might reasonably
request from time to time. In addition, the Borrower agrees that if
any Payment Hurdle is not met, upon request of the Lender or the Loan
Committee, the Borrower will and will cause the Pledgor to permit the
Lender or members of the Loan Committee from time to time to consult
with any managers, investment bankers, brokers or similar persons
assisting in the liquidation of the Liquidation Assets, and the
Borrower will and will cause the Pledgor to assist the Lender or such
members of the Loan Committee in obtaining consultations with
management and key representatives of the companies whose securities
constitute Liquidation Assets.
6.5 Additional Documents. The Borrower will promptly, on demand by the
Lender or the Loan Committee, perform or cause to be performed such
actions and execute or cause to be executed all such additional
agreements, contracts, indentures, documents and instruments as might
be reasonably requested by the Lender or the Loan Committee to satisfy
the requirements of this Agreement.
6.6 Taxes. All taxes, assessments, governmental charges and levies imposed
on the Borrower, the Pledgor or their respective assets, income and
profits will be paid prior to the date on which penalties attached
thereto, provided that the Borrower will not be required to pay any
such charge which is being contested in good faith by proper
proceedings.
6.7 Creation of Liens. The Borrower will not create, assume or suffer to
exist any deed of trust, mortgage, pledge, security interest,
encumbrance or other lien (including the lien of an attachment,
judgment or execution) securing a charge or obligation affecting any
property of the Borrower, excluding only: (a) liens for governmental
charges which are not delinquent or the validity of which is being
contested in good faith by appropriate proceedings and as to which
adequate reserves have been established under generally accepted
accounting principles; (b) deposits made to secure statutory and other
obligations incurred in the ordinary course of the Borrower's
business; (c) liens to the Lender contemplated by this Agreement; (d)
liens in existence on the date hereof, liens on the Pelican Lake stock
or liens otherwise securing indebtedness permitted by paragraph 6.9
hereof; and (e) liens specifically approved after the date of this
Agreement by the Loan Committee in writing. The Borrower will cause
the Pledgor not to create, assume or suffer to exist any deed of
trust, mortgage, pledge, security interest, encumbrance or other lien
(including the lien of an attachment, judgment or execution) securing
a charge or obligation affecting any of the Collateral pledged by the
Pledgor.
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6.8 Other Agreements. The Borrower will not enter into any agreement that
limits or restricts the ability of the Borrower to comply with the
terms of the Loan Documents.
6.9 Indebtedness. The Borrower agrees that he will not incur or permit to
exist any indebtedness of the Borrower, or indebtedness secured by a
lien or security interest on any property of the Borrower, other than:
(a) the indebtedness in effect on the date hereof and described in the
most recent financial statements delivered to the Lender and the Loan
Committee; (b) indebtedness incurred to refinance or restructure any
indebtedness referred to in (a) above; (c) indebtedness a material
portion of which is incurred to pay principal or interest on the Note;
(d) indebtedness secured by the Pelican Lake Stock; and (e) other
indebtedness not to exceed $500,000.00.
7. Default. The Lender may terminate all of the Lender's obligations under the
Loan Documents and may declare the Note and all other indebtedness and
obligations of the Borrower owing to the Lender to be due and payable if any of
the following events of default occur and have not been cured or waived by the
Lender:
7.1 Nonpayment of Note. Default in payment when due of any interest on or
principal of the Note; or
7.2 Other Nonpayment. Default in the payment of any amount payable to the
Lender under the terms of the Loan Documents or any agreement in
connection therewith; or
7.3 Breach of Agreement. (a) Default in the performance or observance of
any covenant contained in the Loan Documents, any other agreement
between the Borrower and the Lender or under the terms of any other
instrument delivered to the Lender in connection with this Agreement;
or (b) default has occurred in any other agreement evidencing
indebtedness of the Borrower, after giving effect to any grace periods
with respect thereto, unless such default has been cured or waived in
writing; or
7.4 Representations and Warranties. Any representation, statement,
certificate, schedule or report made or furnished to the Lender on
behalf of the Borrower proves to be false or erroneous in any material
respect or any warranty ceases to be complied with in any material
respect; or
7.5 Insolvency. The Borrower admits the inability to pay the Borrower's
debts as such debts mature; or
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7.6 Bankruptcy. The institution of bankruptcy, reorganization,
readjustment of debt, liquidation or receivership proceedings by or
against the Borrower under the Bankruptcy Code, as amended, or any
party thereof, or under any other laws, whether state or federal, for
the relief of debtors, now or hereafter existing; or
7.7 Receivership. The appointment of a receiver or trustee for the
Borrower or for any substantial part of the Collateral; or
7.8 Judgment. Entry by any court of a final judgment against the Borrower
or an attachment of any part of the Collateral by any means,
including, without limitation, levy, distraint, replevin or self-help,
which is not discharged or stayed within ten (10) days thereof; or
7.9 Insecurity. The Lender or the Loan Committee deems, in its sole
judgment, for any reason that the likelihood of repayment of the Note
is insecure regardless of whether the Borrower is otherwise in
compliance hereunder.
8. Remedies. On the occurrence of any event of default the Lender may, at the
Lender's option:
8.1 Termination. Terminate the Lender's obligations hereunder.
8.2 Acceleration of Note. Declare the Note and all sums due pursuant to
the Loan Documents to be immediately due and payable, whereupon the
same will become forthwith due and payable, and the Lender will be
entitled to proceed to selectively and successively enforce the
Lender's rights under the Loan Documents or any other instruments
delivered to the Lender in connection with the Loan Documents;
provided that if any event of default specified in paragraphs 7.5, 7.6
or 7.7 will occur, all amounts owing under the Loan Documents,
including the Note, will thereafter become due and payable
concurrently therewith, and the Lender's obligations hereunder will
automatically terminate, without presentment, demand, protest, notice
of default, notice of acceleration or intention to accelerate or other
notice of any kind, all of which the Borrower hereby expressly waives.
8.3 Selective Enforcement. The Lender is not required to proceed against
the Collateral to satisfy the obligations of the Borrower hereunder
which are general obligations of the Borrower. The Lender may elect to
proceed against the Collateral in any order or priority, however, the
Borrower will be liable for any deficiency. In the event the Lender
elects to selectively and successively enforce the Lender's rights
under any one or more of the instruments securing payment of the
indebtedness evidenced by the Note, such action will not be deemed a
waiver or discharge of any remaining indebtedness hereunder or of any
other lien or encumbrance securing payment of any of the indebtedness
evidenced by the Note
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until such time as the Lender has been paid in full all sums advanced
by the Lender plus all accrued interest thereon.
8.4 Waiver of Default. The Lender may, solely by an instrument or
instruments in writing, approved by the Loan Committee and signed by
the Lender, waive any default which has occurred and any of the
consequences of such default, and, in such event, the Lender and the
Borrower will be restored to their respective former positions, rights
and obligations hereunder. Any default so waived will, for all
purposes of this Agreement, be deemed to have been cured and not to be
continuing, but no such waiver will extend to any subsequent or other
default or impair any consequence of such subsequent or other default.
9. Miscellaneous. It is further agreed as follows:
9.1 Expenses. All reasonable out-of-pocket expenses incurred by the Lender
in connection with the enforcement of the Loan Documents including,
without limitation, reasonable attorneys' fees, will be paid by the
Borrower. In addition, the Borrower will pay all recording fees and
all other costs and fees incurred in connection with the loan or the
Loan Documents.
9.2 Notices. All notices, requests and demands will be served by hand
delivery, telefacsimile or by registered or certified mail, with
return receipt requested, as follows:
To the Borrower: Mr. Aubrey K. McClendon
6100 North Western
Oklahoma City, Oklahoma 73118
Fax No. (405) 848-8588
To the Lender: Chesapeake Energy Marketing, Inc.
6100 North Western
Oklahoma City, Oklahoma 73118
Attention: Mr. Marcus C. Rowland
Fax No. (405) 879-9580
To the Loan
Committee: Mr. Edgar F. Heizer, Jr.
Dover House
Tucker's Town, Bermuda H502
Fax No. (441) 293-5557
Mr. Walter C. Wilson
2001 Kirby Drive, Suite 1107
Houston, Texas 77019-6033
Fax No. (713) 520-5950
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or at such other address as either party designates for such purpose a
written notice to the other party. Notice will be deemed to have been
given on the date actually received in the event of personal or
telefacsimile delivery or on the date two (2) days after notice is
deposited in the mail, properly addressed, postage prepaid.
9.3 Severability. In the event any one or more of the provisions contained
in any of the Loan Documents is determined to be invalid, illegal or
unenforceable in any respect in any jurisdiction, the validity,
legality and enforceability of such provision or provisions will not
in any way be affected or impaired thereby in any other jurisdiction
nor will the validity, legality and enforceability of the remaining
provisions contained in the Loan Documents in any way be affected or
impaired thereby.
9.4 Construction and Venue. This Agreement, the documents issued hereunder
and that certain letter dated March 22, 1999 from the Borrower to
Frederick B. Whittemore, Edgar F. Heizer, Jr. and Walter C. Wilson
(the "Letter") are executed and delivered as an incident to a lending
transaction negotiated and to be performed in Oklahoma County,
Oklahoma and together constitute the agreement of the parties hereto.
The Loan Documents and the Letter are intended to constitute a
contract made under the laws of the State of Oklahoma and to be
construed in accordance with the internal laws of the State of
Oklahoma. The descriptive headings of the paragraphs of this Agreement
are for convenience only and are not to be used in the construction of
the content of this Agreement. All actions relating to or arising
under the Loan Documents will be instituted in the courts of the State
of Oklahoma sitting in Oklahoma County, Oklahoma, or the United States
District Court for the Western District of Oklahoma, and the Borrower
irrevocably and unconditionally waives any objection to the venue in
such court and any claim that any action has been brought in an
inconvenient forum.
9.5 No Waiver. No advance of loan proceeds under the Loan Documents will
constitute a waiver of any of the Borrower's representations,
warranties, conditions or covenants under the Loan Documents.
9.6 Counterparts. This Agreement may be executed via telefacsimile in two
or more counterparts and it will not be necessary that the signatures
of all parties hereto be contained on any one counterpart hereof. Each
counterpart will be deemed an original, but all counterparts together
will constitute one and the same instrument.
9.7 Prior Agreement. This Second Amended and Restated Loan Agreement is an
amendment and restatement of the Prior Agreement, executed in
replacement of,
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but not in extinguishment of, the Prior Agreement. In the event that
this Agreement or the Note are deemed not to be in force and effect,
the Prior Agreement and the Prior Note will be in force and effect,
under the terms and conditions set forth therein. In such event, the
Lender will not be deemed to have waived any of its rights and
benefits under the Prior Agreement or the Prior Note.
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IN WITNESS WHEREOF, the Borrower and the Lender have executed this
Agreement effective on the date first above written.
/s/ AUBREY K. McCLENDON
--------------------------------------------
AUBREY K. McCLENDON, individually
(the "Borrower")
CHESAPEAKE ENERGY MARKETING, INC., an
Oklahoma corporation
By /s/ MARCUS C. ROWLAND
-----------------------------------------
Marcus C. Rowland, Vice President
and Chief Financial Officer
(the "Lender")
The execution by the Lender of this Agreement has been approved by the
undersigned who constitute all of the members of the Loan Committee.
/s/ WALTER C. WILSON
--------------------------------------------
WALTER C. WILSON, individually
/s/ EDGAR F. HEIZER, JR.
--------------------------------------------
EDGAR F. HEIZER, JR., individually
(the "Loan Committee")
13
<PAGE> 1
EXHIBIT 10.4.2
SECOND AMENDED AND RESTATED
LOAN AGREEMENT
BETWEEN
TOM L. WARD
AND
CHESAPEAKE ENERGY MARKETING, INC.
DECEMBER 31, 1998
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
1. Loan Amount...............................................1
2. Note......................................................1
2.1 Interest.........................................1
2.2 Payments.........................................2
2.3 No Readvances....................................2
2.4 Prepayments......................................2
3. Collateral Security.......................................3
4. Conditions of Lending.....................................3
4.1 Loan Documents...................................3
4.2 No Violation.....................................3
4.3 Additional Information...........................3
4.4 Prior Note Interest..............................4
4.5 JIBs.............................................4
4.6 No Default.......................................4
4.7 Representations..................................4
4.8 Opinion of Counsel...............................4
4.9 Financial Statements.............................4
5. Representations and Warranties............................4
5.1 Capacity and Power...............................4
5.2 Full Disclosure..................................4
5.3 Financial Condition..............................5
5.4 Liabilities......................................5
5.5 Ownership........................................5
5.6 No Default.......................................5
5.7 Survival of Representations......................5
6. Covenants of the Borrower.................................5
6.1 Financial Statements.............................5
6.2 Liquidation Assets Report........................5
6.3 Notifications....................................6
6.4 Records Inspections..............................6
6.5 Additional Documents.............................6
6.6 Taxes............................................6
6.7 Creation of Liens................................7
6.8 Other Agreements.................................7
6.9 Indebtedness.....................................7
</TABLE>
i
<PAGE> 3
<TABLE>
<S> <C>
7. Default...................................................7
7.1 Nonpayment of Note...............................7
7.2 Other Nonpayment.................................7
7.3 Breach of Agreement..............................7
7.4 Representations and Warranties...................8
7.5 Insolvency.......................................8
7.6 Bankruptcy.......................................8
7.7 Receivership.....................................8
7.8 Judgment.........................................8
7.9 Insecurity.......................................8
8. Remedies..................................................8
8.1 Termination......................................8
8.2 Acceleration of Note.............................8
8.3 Selective Enforcement............................9
8.4 Waiver of Default................................9
9. Miscellaneous.............................................9
9.1 Expenses.........................................9
9.2 Notices..........................................9
9.3 Severability....................................10
9.4 Construction and Venue..........................10
9.5 No Waiver.......................................11
9.6 Counterparts....................................11
</TABLE>
ii
<PAGE> 4
<TABLE>
<S> <C>
Schedule "A" - Form of Promissory Note
Schedule "B" - Liquidation Assets
Schedule "C" - Form of Second Amendment to Amended and Restated Security Agreement
Schedule "D" - Form of Mortgage, Security Agreement and Financing Statement
</TABLE>
iii
<PAGE> 5
SECOND AMENDED AND RESTATED
LOAN AGREEMENT
THIS AGREEMENT is entered into effective the 31st day of December, 1998,
between TOM L. WARD, an individual (the "Borrower"), and CHESAPEAKE ENERGY
MARKETING, INC., an Oklahoma corporation (the "Lender"), and amends and restates
in its entirety that certain Loan Agreement dated July 7, 1998, between the
Borrower and the Lender, as amended by that certain Amended and Restated Loan
Agreement dated July 13, 1998, as amended by that certain First Amendment to
Amended and Restated Loan Agreement dated August 19, 1998 (collectively, the
"Prior Agreement").
WHEREAS, under the Prior Agreement and the promissory note issued pursuant
thereto (the "Prior Note"), all principal of and interest on the Prior Note was
due on December 31, 1998; and
WHEREAS, the Borrower has requested that the Lender extend the maturity
date of the Prior Note and the obligations of the Borrower under the Prior
Agreement for a period not to exceed one year, and the Lender is agreeable to
such extension on the terms and conditions set forth herein and for the
consideration set forth herein and in the other Loan Documents (as hereinafter
defined).
NOW THEREFORE, the Borrower and the Lender hereby amend and restate the
Prior Agreement as follows:
W I T N E S S E T H :
1. Loan Amount. Subject to the terms and conditions of this Agreement, the
Lender agrees to extend the time of payment of the existing loan to the Borrower
in the principal amount of Five Million Dollars ($5,000,000.00).
2. Note. The loan to be made hereunder will be evidenced by the Promissory Note
(the "Note") in the form of Schedule "A" attached hereto as a part hereof and
payable on the following terms:
2.1 Interest. Except as otherwise provided in the Note, the unpaid
principal balance of the Note will bear interest at the per annum rate
equal to nine and one-eighth percent (9 1/8%). Except for interest
payments made pursuant to paragraph 2.4 of this Agreement, interest on
the Note will be payable quarterly commencing on March 31, 1999, and
on the last day of each successive June, September and December
thereafter until the Note is paid in full. All interest will be
computed
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at a per diem charge for the actual number of days elapsed on the
basis of a year consisting of three hundred sixty-five (365) days.
2.2 Payments. Each payment on the Note including, without limitation,
payments made pursuant to paragraph 2.4 hereof, will be applied first
to any obligations of the Borrower to the Lender under the Loan
Documents other than principal and interest, then to accrued unpaid
interest on the Note, and then to the unpaid principal balance of the
Note. The entire unpaid principal balance plus all accrued and unpaid
interest on the Note will be due and payable on December 31, 1999. or
at such earlier date as required under paragraph 8 of this Agreement.
2.3 No Readvances. The Borrower understands and agrees that the Note is
not a revolving note and that on any prepayment of principal, such
prepaid amount will not be readvanced.
2.4 Prepayments. The Borrower will have the right at any time to prepay
the Note in whole or in part, without premium or penalty, but with
interest accrued to the date of prepayment. In addition, the Borrower
hereby agrees that throughout the term of the Note the Borrower will
in good faith use the Borrower's best efforts to sell that portion of
the Collateral (as hereinafter defined) described in Schedule "B"
attached hereto as a part hereof (the "Liquidation Assets") in a
manner reasonably calculated to fully repay the Note on or before
December 31, 1999. In connection with the liquidation of the
Liquidation Assets, the Borrower agrees to consult with the members of
the loan committee (the "Loan Committee") of the Board of Directors of
the Lender's parent Chesapeake Energy Corporation (the "Company"). The
Borrower further agrees that in the event the unpaid principal balance
of the Note is more than: (a) $4,600,000.00 on March 31, 1999; (b)
$4,000,000.00 on June 30, 1999; or (c) $2,500,000.00 on September 30,
1999 (each a "Payment Hurdle"), the Lender (acting through the members
of the Loan Committee if so approved by the Loan Committee on behalf
of the Lender) will have the right at any time thereafter to dispose
of the Liquidation Assets in such manner and on such terms as the
Lender (acting through the members of the Loan Committee if so
approved by the Loan Committee on behalf of the Lender) determines in
the Lender's sole discretion and the Borrower hereby fully authorizes
and empowers (without the necessity of any further consent or
authorization from the Borrower) the Lender and appoints and makes the
Lender the Borrower's true and lawful attorney-in fact and agent for
the Borrower and in the Borrower's name, place and stead with full
power of substitution, in the Lender's name or the Borrower's name or
otherwise, for the Lender's sole use and benefit, but at the
Borrower's cost and expense, to dispose of the Liquidation Assets,
without notice, provided, however, the Lender and each member of the
Loan Committee will be under no obligation or duty to exercise the
power hereby conferred upon it and will be without liability for any
act or failure to act in connection with the disposition of the
Liquidation Assets. Unless the Lender, with the approval of the Loan
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Committee, otherwise consents in writing, all dispositions of
Liquidation Assets will be for cash or freely marketable securities.
On disposition of any Collateral one hundred percent (100%) of the
proceeds net of actual out of pocket expenses will be held in trust
and promptly delivered to the Lender to be applied to the Note in
accordance with paragraph 2.2 of this Agreement. With respect to the
Liquidation Assets owned by TLW Investments Inc., an Oklahoma
corporation (the "Pledgor"), the Borrower agrees to cause the Pledgor
to fully comply with the terms of this paragraph 2.4. Notwithstanding
the provisions of the Amended and Restated Employment Agreement
between the Borrower and the Company dated effective July 1, 1998 (the
"Employment Agreement") in the event that at any time (1) joint
interest billings ("JIBs") in connection with participation in the
program wells spudded by the Company or its subsidiaries (the
"Drilling Program") as contemplated under the Employment Agreement are
not paid when due, or (ii) any of the Payment Hurdles are unsatisfied
("Participation Conditions") the Borrower agrees that in either event
the Borrower will not participate in the Drilling Program wells
spudded by the Company or its subsidiary corporations during any time
in which the Participation Conditions are not satisfied.
3. Collateral Security. Payment of the Note will be secured by a first lien on
and security interest in the property (the "Collateral") described in the
Amended and Restated Security Agreement dated July 13, 1998, as amended by that
certain First Amendment to Amended and Restated Security Agreement dated August
19, 1998, as further amended by that certain Second Amendment to Amended and
Restated Security Agreement in the form of Schedule "C" attached hereto as a
part hereof (the "Security Agreement"), the Mortgage, Security Agreement and
Financing Statement in the form of Schedule "E" attached hereto as a part hereof
(the "Mortgage") and any other Loan Documents. The release of any Collateral
from time to time at the request of the Borrower will be in the sole discretion
of the Lender and the Loan Committee.
4. Conditions of Lending. The obligation of the Lender to perform this Agreement
and to extend the time for payment of the indebtedness evidenced by the Note is
subject to the following conditions precedent.
4.1 Loan Documents. This Agreement, the Note, the Security Agreement, the
Mortgage, financing statements, stock powers, and related documents
and all extensions, amendments and modifications thereof
(collectively, the "Loan Documents") will have been duly executed,
acknowledged (where appropriate) by all parties thereto and delivered
to the Lender, all in form and substance satisfactory to the Lender.
4.2 No Violation. The advance under the Note will not cause the Lender to
be in violation of any law, rule, regulation or agreement applicable
to the Lender or the Company.
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4.3 Additional Information. The Lender will have received such additional
documents, instruments and information as the Lender requests
including, without limitation, current financial statements of the
Borrower and information and valuation (based on fair value)
concerning any of the Collateral designated by the Lender in writing.
4.4 Prior Note Interest. The Borrower will have paid in full all accrued
and unpaid interest on the Prior Note through and including December
31, 1998.
4.5 JIBs. No JIBs will be overdue and unpaid under the terms of the
Employment Agreement as of the date of execution of this Agreement.
4.6 No Default. No default (however defined, but excluding margin
shortages) will have occurred or be continuing under the Borrower's
credit facility with Union Bank of California, N.A. (the "Union Bank
Facility") or any other agreement evidencing indebtedness of the
Borrower, or any other material agreement, unless such default will
have been effectively waived in writing by the other party or parties
thereto.
4.7 Representations. All representations of the Borrower in the Prior
Agreement, the security agreement executed in connection with the
Prior Agreement, hereunder or otherwise made by the Borrower to the
Lender or to the Loan Committee will be true and correct on and as of
the date hereof.
4.8 Opinion of Counsel. The Lender will have received an opinion of McAfee
& Taft that the Loan Documents are enforceable against the Borrower in
accordance with the terms thereof and that the execution, delivery and
performance of this Agreement will not: (a) violate any law, rule or
regulation under the laws of the State of Oklahoma or applicable
federal law; or (b) conflict with or cause a breach under any
agreement to which the Company or any of its subsidiaries is a party
or by which any of their respective properties are bound.
4.9 Financial Statements. The Lender and the Loan Committee will have
received financial statements of the Borrower as of December 31, 1998,
including and reflecting transactions through such date.
5. Representations and Warranties. In order to induce the Lender to enter into
and perform the Loan Documents, the Borrower represents and warrants to the
Lender as follows:
5.1 Capacity and Power. The Borrower has adequate capacity, power and
legal right to enter into, execute, deliver and perform the terms of
the Loan Documents, to borrow money, to give security for borrowings
and to consummate the transactions contemplated by the Loan Documents.
The execution, delivery and performance of the Loan Documents by the
Borrower will not violate any law, regulation, rule or any other
agreement or instrument binding on the Borrower or the Collateral.
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5.2 Full Disclosure. Neither this Agreement nor any statement or document
referred to herein or delivered to the Lender by the Borrower or any
other party on behalf of the Borrower contains any material untrue
statement or omits to state a material fact necessary to make the
statements herein or therein not misleading.
5.3 Financial Condition. The Borrower's financial statements dated as of
December 31, 1998, copies of which have been furnished to the Lender
are correct and complete and fairly reflect the financial condition of
the Borrower as of the date thereof and have been prepared in
conformity with accounting principles applied on a basis consistent
with that of preceding periods. There has occurred no material adverse
change in the financial condition of the Borrower from the date of
such financial statements to the date of execution of this Agreement.
5.4 Liabilities. The Borrower has no material liabilities, direct or
contingent, and has granted no security interests or liens on the
property of the Borrower, except those disclosed in the financial
statements referred to in paragraph 5.3 of this Agreement.
5.5 Ownership. The Borrower has good and marketable title to the
Collateral, free and clear of all liens, security interests, claims or
encumbrances, except for liens and security interests in favor of the
Lender.
5.6 No Default. No default (however defined, but excluding margin
shortages) has occurred or is continuing under any other agreement,
instrument or document between the Borrower and any person or under
any agreement secured by property of the Borrower including, without
limitation, the Union Bank Facility or any other agreement evidencing
indebtedness of the Borrower other than such defaults as have been
disclosed to the Lender prior to the date hereof or that have been
effectively waived in writing by such other party.
5.7 Survival of Representations. All representations and warranties made
by the Borrower herein will survive the delivery of the Loan
Documents, and any investigation at any time made by or on behalf of
the Lender will not diminish the Lender's right to rely thereon. All
statements contained in any certificate or other instrument delivered
by or on behalf of the Borrower under or pursuant to this Agreement or
in connection with the transactions contemplated hereby will
constitute representations and warranties made by the Borrower
hereunder.
6. Covenants of the Borrower. Until the expiration of the Lender's obligation to
advance funds under this Agreement and payment in full of the Note, the Borrower
agrees that, unless the Lender waives compliance in writing:
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6.1 Financial Statements. The Borrower will furnish the Lender and each of
the members of the Loan Committee the Borrower's financial statements
on a quarterly basis, within thirty (30) days after the end of each
calendar quarter, commencing with the calendar quarter ending March
31, 1999, and such additional financial statements as the Lender or
the Loan Committee might reasonably request.
6.2 Liquidation Assets Report. The Borrower will furnish to the Lender,
with a copy to each member of the Loan Committee, monthly within ten
(10) days after the end of each month commencing January 31, 1999, a
report, in form and substance satisfactory to the Lender and the Loan
Committee, setting forth the status of the Borrower's efforts to
dispose of the Liquidation Assets including, without limitation,
copies of any pending sale contracts, scheduled closing dates and
estimated expenses of sale and net proceeds.
6.3 Notifications. The Borrower will give prompt written notice to the
Lender and each member of the Loan Committee of: (a) any event of
default; (b) any event of default or acceleration under any other
lending arrangement to which the Borrower is a party; (c) all material
litigation affecting the Borrower or the Collateral; and (d) any other
matter which has resulted in, or might result in (i) a material
adverse change in the financial condition of the Borrower, or (ii) a
material adverse change in the ability of the Borrower to perform the
Borrower's obligations, warranties, covenants and conditions of the
Loan Documents.
6.4 Records Inspections. The Borrower will and will cause the Pledgor to
maintain full and accurate accounts and records of the Borrower's and
the Pledgor's respective businesses on a basis consistent with prior
periods. The Borrower will and will cause the Pledgor to permit the
Lender and the Lender's designated representatives including, without
limitation, the Loan Committee, to have access to the Borrower's and
the Pledgor's respective records and accounts at all reasonable times
to perform such inspections, audits and examinations as the Lender or
the Loan Committee might reasonably request from time to time. In
addition, the Borrower agrees that if any Payment Hurdle is not met,
upon request of the Lender or the Loan Committee, the Borrower will
and will cause the Pledgor to permit the Lender or members of the Loan
Committee from time to time to consult with any managers, investment
bankers, brokers or similar persons assisting in the liquidation of
the Liquidation Assets, and the Borrower will and will cause the
Pledgor to assist the Lender or such members of the Loan Committee in
obtaining consultations with management and key representatives of the
companies whose securities constitute Liquidation Assets.
6.5 Additional Documents. The Borrower will promptly, on demand by the
Lender or the Loan Committee, perform or cause to be performed such
actions and execute or cause to be executed all such additional
agreements, contracts, indentures,
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documents and instruments as might be reasonably requested by the
Lender or the Loan Committee to satisfy the requirements of this
Agreement.
6.6 Taxes. All taxes, assessments, governmental charges and levies imposed
on the Borrower, the Pledgor or their respective assets, income and
profits will be paid prior to the date on which penalties attached
thereto, provided that the Borrower will not be required to pay any
such charge which is being contested in good faith by proper
proceedings.
6.7 Creation of Liens. The Borrower will not create, assume or suffer to
exist any deed of trust, mortgage, pledge, security interest,
encumbrance or other lien (including the lien of an attachment,
judgment or execution) securing a charge or obligation affecting any
property of the Borrower, excluding only: (a) liens for governmental
charges which are not delinquent or the validity of which is being
contested in good faith by appropriate proceedings and as to which
adequate reserves have been established under generally accepted
accounting principles; (b) deposits made to secure statutory and other
obligations incurred in the ordinary course of the Borrower's
business; (c) liens to the Lender contemplated by this Agreement; (d)
liens in existence on the date hereof or liens otherwise securing
indebtedness permitted by paragraph 6.9 hereof; and (e) liens
specifically approved after the date of this Agreement by the Loan
Committee in writing. The Borrower will cause the Pledgor not to
create, assume or suffer to exist any deed of trust, mortgage, pledge,
security interest, encumbrance or other lien (including the lien of an
attachment, judgment or execution) securing a charge or obligation
affecting any of the Collateral pledged by the Pledgor.
6.8 Other Agreements. The Borrower will not enter into any agreement that
limits or restricts the ability of the Borrower to comply with the
terms of the Loan Documents.
6.9 Indebtedness. The Borrower agrees that he will not incur or permit to
exist any indebtedness of the Borrower, or indebtedness secured by a
lien or security interest on any property of the Borrower, other than:
(a) the indebtedness in effect on the date hereof and described in the
most recent financial statements delivered to the Lender and the Loan
Committee; (b) indebtedness incurred to refinance or restructure any
indebtedness referred to in (a) above; (c) indebtedness a material
portion of which is incurred to pay principal or interest on the Note;
and (d) other indebtedness not to exceed $500,000.00.
7. Default. The Lender may terminate all of the Lender's obligations under the
Loan Documents and may declare the Note and all other indebtedness and
obligations of the Borrower owing to the Lender to be due and payable if any of
the following events of default occur and have not been cured or waived by the
Lender:
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7.1 Nonpayment of Note. Default in payment when due of any interest on or
principal of the Note; or
7.2 Other Nonpayment. Default in the payment of any amount payable to the
Lender under the terms of the Loan Documents or any agreement in
connection therewith; or
7.3 Breach of Agreement. (a) Default in the performance or observance of
any covenant contained in the Loan Documents, any other agreement
between the Borrower and the Lender or under the terms of any other
instrument delivered to the Lender in connection with this Agreement;
or (b) default has occurred in any other agreement evidencing
indebtedness of the Borrower, after giving effect to any grace periods
with respect thereto, unless such default has been cured or waived in
writing; or
7.4 Representations and Warranties. Any representation, statement,
certificate, schedule or report made or furnished to the Lender on
behalf of the Borrower proves to be false or erroneous in any material
respect or any warranty ceases to be complied with in any material
respect; or
7.5 Insolvency. The Borrower admits the inability to pay the Borrower's
debts as such debts mature; or
7.6 Bankruptcy. The institution of bankruptcy, reorganization,
readjustment of debt, liquidation or receivership proceedings by or
against the Borrower under the Bankruptcy Code, as amended, or any
party thereof, or under any other laws, whether state or federal, for
the relief of debtors, now or hereafter existing; or
7.7 Receivership. The appointment of a receiver or trustee for the
Borrower or for any substantial part of the Collateral; or
7.8 Judgment. Entry by any court of a final judgment against the Borrower
or an attachment of any part of the Collateral by any means,
including, without limitation, levy, distraint, replevin or self-help,
which is not discharged or stayed within ten (10) days thereof; or
7.9 Insecurity. The Lender or the Loan Committee deems, in its sole
judgment, for any reason that the likelihood of repayment of the Note
is insecure regardless of whether the Borrower is otherwise in
compliance hereunder.
8. Remedies. On the occurrence of any event of default the Lender may, at the
Lender's option:
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8.1 Termination. Terminate the Lender's obligations hereunder.
8.2 Acceleration of Note. Declare the Note and all sums due pursuant to
the Loan Documents to be immediately due and payable, whereupon the
same will become forthwith due and payable, and the Lender will be
entitled to proceed to selectively and successively enforce the
Lender's rights under the Loan Documents or any other instruments
delivered to the Lender in connection with the Loan Documents;
provided that if any event of default specified in paragraphs 7.5, 7.6
or 7.7 will occur, all amounts owing under the Loan Documents,
including the Note, will thereafter become due and payable
concurrently therewith, and the Lender's obligations hereunder will
automatically terminate, without presentment, demand, protest, notice
of default, notice of acceleration or intention to accelerate or other
notice of any kind, all of which the Borrower hereby expressly waives.
8.3 Selective Enforcement. The Lender is not required to proceed against
the Collateral to satisfy the obligations of the Borrower hereunder
which are general obligations of the Borrower. The Lender may elect to
proceed against the Collateral in any order or priority, however, the
Borrower will be liable for any deficiency. In the event the Lender
elects to selectively and successively enforce the Lender's rights
under any one or more of the instruments securing payment of the
indebtedness evidenced by the Note, such action will not be deemed a
waiver or discharge of any remaining indebtedness hereunder or of any
other lien or encumbrance securing payment of any of the indebtedness
evidenced by the Note until such time as the Lender has been paid in
full all sums advanced by the Lender plus all accrued interest
thereon.
8.4 Waiver of Default. The Lender may, solely by an instrument or
instruments in writing, approved by the Loan Committee and signed by
the Lender, waive any default which has occurred and any of the
consequences of such default, and, in such event, the Lender and the
Borrower will be restored to their respective former positions, rights
and obligations hereunder. Any default so waived will, for all
purposes of this Agreement, be deemed to have been cured and not to be
continuing, but no such waiver will extend to any subsequent or other
default or impair any consequence of such subsequent or other default.
9. Miscellaneous. It is further agreed as follows:
9.1 Expenses. All reasonable out-of-pocket expenses incurred by the Lender
in connection with the enforcement of the Loan Documents including,
without limitation, reasonable attorneys' fees, will be paid by the
Borrower. In addition, the Borrower will pay all recording fees and
all other costs and fees incurred in connection with the loan or the
Loan Documents.
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9.2 Notices. All notices, requests and demands will be served by hand
delivery, telefacsimile or by registered or certified mail, with
return receipt requested, as follows:
To the Borrower: Mr. Tom L. Ward
6100 North Western
Oklahoma City, Oklahoma 73118
Fax No. (405) 848-8588
To the Lender: Chesapeake Energy Marketing, Inc.
6100 North Western
Oklahoma City, Oklahoma 73118
Attention: Mr. Marcus C. Rowland
Fax No. (405) 879-9580
To the Loan
Committee: Mr. Edgar F. Heizer, Jr.
Dover House
Tucker's Town, Bermuda H502
Fax No. (441) 293-5557
Mr. Walter C. Wilson
2001 Kirby Drive, Suite 1107
Houston, Texas 77019-6033
Fax No. (713) 520-5950
or at such other address as either party designates for such purpose a
written notice to the other party. Notice will be deemed to have been
given on the date actually received in the event of personal or
telefacsimile delivery or on the date two (2) days after notice is
deposited in the mail, properly addressed, postage prepaid.
9.3 Severability. In the event any one or more of the provisions contained
in any of the Loan Documents is determined to be invalid, illegal or
unenforceable in any respect in any jurisdiction, the validity,
legality and enforceability of such provision or provisions will not
in any way be affected or impaired thereby in any other jurisdiction
nor will the validity, legality and enforceability of the remaining
provisions contained in the Loan Documents in any way be affected or
impaired thereby.
9.4 Construction and Venue. This Agreement, the documents issued hereunder
and that certain letter dated March 22, 1999 from the Borrower to
Frederick B. Whittemore, Edgar F. Heizer, Jr. and Walter C. Wilson
(the "Letter") are executed and delivered as an incident to a lending
transaction negotiated and to be
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<PAGE> 15
performed in Oklahoma County, Oklahoma and together constitute the
agreement of the parties hereto. The Loan Documents and the Letter are
intended to constitute a contract made under the laws of the State of
Oklahoma and to be construed in accordance with the internal laws of
the State of Oklahoma. The descriptive headings of the paragraphs of
this Agreement are for convenience only and are not to be used in the
construction of the content of this Agreement. All actions relating to
or arising under the Loan Documents will be instituted in the courts
of the State of Oklahoma sitting in Oklahoma County, Oklahoma, or the
United States District Court for the Western District of Oklahoma, and
the Borrower irrevocably and unconditionally waives any objection to
the venue in such court and any claim that any action has been brought
in an inconvenient forum.
9.5 No Waiver. No advance of loan proceeds under the Loan Documents will
constitute a waiver of any of the Borrower's representations,
warranties, conditions or covenants under the Loan Documents.
9.6 Counterparts. This Agreement may be executed via telefacsimile in two
or more counterparts and it will not be necessary that the signatures
of all parties hereto be contained on any one counterpart hereof. Each
counterpart will be deemed an original, but all counterparts together
will constitute one and the same instrument.
9.7 Prior Agreement. This Second Amended and Restated Loan Agreement is an
amendment and restatement of the Prior Agreement, executed in
replacement of, but not in extinguishment of, the Prior Agreement. In
the event that this Agreement or the Note are deemed not to be in
force and effect, the Prior Agreement and the Prior Note will be in
force and effect, under the terms and conditions set forth therein. In
such event, the Lender will not be deemed to have waived any of its
rights and benefits under the Prior Agreement or the Prior Note.
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IN WITNESS WHEREOF, the Borrower and the Lender have executed this
Agreement effective on the date first above written.
/s/ TOM L. WARD
--------------------------------------------
TOM L. WARD, individually
(the "Borrower")
CHESAPEAKE ENERGY MARKETING, INC., an
Oklahoma corporation
By /s/ MARCUS C. ROWLAND
------------------------------------------
Marcus C. Rowland, Vice President
and Chief Financial Officer
(the "Lender")
The execution by the Lender of this Agreement has been approved by the
undersigned which constitute all of the members of the Loan Committee.
/s/ WALTER C. WILSON
--------------------------------------------
WALTER C. WILSON, individually
/s/ EDGAR F. HEIZER, JR.
--------------------------------------------
EDGAR F. HEIZER, JR., individually
(the "Loan Committee")
12
<PAGE> 1
EXHIBIT 21
SUBSIDIARIES OF CHESAPEAKE ENERGY CORPORATION
(AN OKLAHOMA CORPORATION)
<TABLE>
<CAPTION>
Corporations State of Organization
- ------------- ---------------------
<S> <C>
The Ames Company, Inc. Oklahoma
Chesapeake Acquisition Corporation Oklahoma
Chesapeake Acquisitions, Ltd. Alberta, Canada
Chesapeake Canada Corporation Alberta, Canada
Chesapeake Energy Louisiana Corporation Oklahoma
Chesapeake Energy Marketing, Inc. Oklahoma
Chesapeake Mid-Continent Corp. Oklahoma
Chesapeake Operating, Inc. Oklahoma
Chesapeake Royalty Company Oklahoma
Partnerships
- ------------
Chesapeake Exploration Limited Partnership Oklahoma
Chesapeake Louisiana, L. P. Oklahoma
Chesapeake Panhandle Limited Partnership Oklahoma
</TABLE>
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration statements of
Chesapeake Energy Corporation on Form S-8 (File Nos. 33-84256, 33-84258,
33-89282, 33-88196, 333-27525, 333-07255, 333-46129 and 333-48585) and Form S-3
(File Nos. 333-50547 and 333-57235) of our report dated March 18, 1999 on our
audit of the consolidated financial statements of Chesapeake Energy Corporation
for the year ended December 31, 1998, the six months ended December 31, 1997 and
for the years ended June 30, 1997 and 1996, which report is included in this
Annual Report on Form 10-K.
PRICEWATERHOUSECOOPERS LLP
Oklahoma City, Oklahoma
March 18, 1999
<PAGE> 1
EXHIBIT 23.2
CONSENT OF WILLIAMSON PETROLEUM CONSULTANTS, INC.
As independent oil and gas consultants, Williamson Petroleum Consultants,
Inc. hereby consents to (a) the use of our reserves reports dated March 19, 1999
entitled "Evaluation of Oil and Gas Reserves to the Interests of Chesapeake
Energy Corporation in Certain Major-Value Properties in Arkansas, Colorado,
Louisiana, Montana, New Mexico, North Dakota, Oklahoma, Texas and Wyoming,
Effective December 31, 1998, for Disclosure to the Securities and Exchange
Commission, Utilizing Aries Software, Williamson Project 8.8655" and "Evaluation
of Oil and Gas Reserves to the Interests of Chesapeake Energy Corporation in
Certain Major-Value Properties in British Columbia, Canada, Effective December
31, 1998, for Disclosure to the Securities and Exchange Commission, Utilizing
Canadian Aries Software, Williamson Project 8.8655" and all references to our
firm included in or made a part of the Chesapeake Energy Corporation Annual
Report on Form 10-K to be filed with the Securities and Exchange Commission on
or about March 30, 1999 and (b) to the incorporation by reference of this Form
10-K for the year ended December 31, 1998 in the Registration Statements on Form
S-8 (Nos. 33-84256, 33-84258, 33-88196, 333-07255, 33-89282, 333-27525,
333-46129 and 333-48585) and on Form S-3 (Nos. 333-50547 and 333-57235).
WILLIAMSON PETROLEUM CONSULTANTS, INC.
Houston, Texas
March 30, 1999
<PAGE> 1
EXHIBIT 23.3
CONSENT OF RYDER SCOTT COMPANY PETROLEUM ENGINEERS
As independent oil and gas consultants, Ryder Scott Company Petroleum
Engineers hereby consents to (a) the use of our reserve report dated as of
December 31, 1998 and all references to our firm included in or made a part of
the Chesapeake Energy Corporation Annual Report on Form 10-K to be filed with
the Securities and Exchange Commission on or about March 31, 1999 and (b) to the
incorporation by reference of this Form 10-K for the year ended December 31,
1998 in the Registration Statements on Form S-8 (Nos. 33-84256, 33-84258,
33-88196, 333-07255, 33-89282, 333-27525, 333-46129 and 333-48585) and on Form
S-3 (Nos. 333-50547 and 333-57235).
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
March 30, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from Balance
Sheet as of December 31, 1998, and Statement of Income for calendar year ended
December 31, 1998.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 35,274
<SECURITIES> 0
<RECEIVABLES> 79,508
<ALLOWANCES> 3,209
<INVENTORY> 5,325
<CURRENT-ASSETS> 117,999
<PP&E> 2,275,348
<DEPRECIATION> 1,611,357
<TOTAL-ASSETS> 812,615
<CURRENT-LIABILITIES> 131,284
<BONDS> 919,076
0
230,000
<COMMON> 1,052
<OTHER-SE> (479,620)
<TOTAL-LIABILITY-AND-EQUITY> 812,615
<SALES> 377,946
<TOTAL-REVENUES> 381,872
<CGS> 1,234,143
<TOTAL-COSTS> 1,302,392
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 1,589
<INTEREST-EXPENSE> 68,249
<INCOME-PRETAX> (920,520)
<INCOME-TAX> 0
<INCOME-CONTINUING> (920,520)
<DISCONTINUED> 0
<EXTRAORDINARY> (13,334)
<CHANGES> 0
<NET-INCOME> (933,854)
<EPS-PRIMARY> (9.97)
<EPS-DILUTED> (9.97)
</TABLE>
