<PAGE> 1
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
(AMENDMENT NO. 3)
[X] Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the Fiscal Year ended June 30, 1997
[ ] 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)
<TABLE>
<S> <C>
OKLAHOMA 73-1395733
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
6100 NORTH WESTERN AVENUE
OKLAHOMA CITY, OKLAHOMA 73118
(Address of principal executive offices) (Zip Code)
</TABLE>
(405) 848-8000
Registrant's telephone number, including area code
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<C> <C>
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
- --------------------------------------------- ---------------------------------------------
Common Stock, par value $.01 New York Stock Exchange
9.125% Senior Notes due 2006 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. [ ]
The aggregate market value of Common Stock held by non-affiliates on
October 27, 1997 was $423,923,486. At such date, there were 70,429,017 shares of
Common Stock issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
NONE
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<PAGE> 2
PART I
ITEM 1. BUSINESS
OVERVIEW
Chesapeake Energy Corporation ("Chesapeake" or the "Company") is an
independent energy company which utilizes advanced drilling and completion
technologies to explore for and produce oil and natural gas. The Company has
traditionally been among the most active drillers of new wells in the United
States.
From inception in 1989 through June 30, 1997, Chesapeake drilled and
participated in a total of 736 gross (294 net) wells, of which 691 gross (276
net) wells were completed. From its first full fiscal year of operation ended
June 30, 1990 to the fiscal year ended June 30, 1997, the Company's estimated
proved reserves increased to 403 Bcfe from 11 Bcfe, annual production increased
to 79 Bcfe from 0.2 Bcfe, total revenue increased to $280 million from $0.6
million, and total assets increased to $949 million from $8 million. Despite
this overall favorable record of growth, in fiscal 1997 the Company incurred a
net loss of $183 million primarily as a result of a $236 million impairment of
its oil and gas properties. The impairment was the amount by which the Company's
capitalized costs of oil and gas properties exceeded the estimated present value
of future net revenues from its proved reserves at June 30, 1997.
A combination of factors in the fourth quarter of fiscal 1997 caused the
impairment. First, exploratory drilling of unevaluated leasehold, primarily in
the Louisiana Trend, failed to add significant proved reserves. In addition, oil
and gas price declines, higher drilling and completion costs and lower than
expected results from developmental drilling and production eliminated
previously established proved reserves. See Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Results of
Operations -- Impairment of Oil and Gas Properties.
In response to the fiscal 1997 loss, Chesapeake has revised its fiscal 1998
business strategy. These revisions include slowing its exploration pace in the
Louisiana Austin Chalk Trend ("Louisiana Trend") and concentrating its Louisiana
Trend drilling activities in Masters Creek; utilizing more extensive use of 3-D
seismic prior to conducting drilling operations; reducing the acquisition of
additional unproven leasehold; and selectively acquiring proved reserves as a
complement to its primary strategy of developing reserves through the drillbit.
This strategy will likely have the effect of reducing the Company's anticipated
production growth rate from exploration and development drilling.
The Company's failure to increase its reserves in fiscal 1997 while
incurring $465 million of development, exploration and acquisition costs
(including capitalized internal costs) increases its need to add reserves in
order to replace production and allow growth through acquisition or drilling.
The Company has reduced its fiscal 1998 capital expenditure budget to $225-$275
million and plans to pursue acquisitions of oil and gas properties. The failure
to add reserves economically through this new strategy would adversely affect
the Company's financial position, results of operations, and could subsequently
impede the Company's ability to acquire properties using its stock.
Reference is made to the "Glossary" that appears at the end of this Item 1
for definitions of certain terms used in this Form 10-K.
DESCRIPTION OF BUSINESS
Since its inception, Chesapeake's primary business strategy has been growth
through the drillbit. Using this strategy, the Company has expanded its reserves
and production through the acquisition and subsequent development of large
blocks of acreage.
From inception through fiscal 1994, the Company concentrated its
undeveloped leasehold acquisitions and associated drilling in the Giddings Field
of southern Texas and the Golden Trend Field of southern Oklahoma. Beginning in
fiscal 1995, Chesapeake initiated development of new project areas that were
either extensions of the Company's historical focus in the Giddings and Golden
Trend Fields or new areas which the Company believed had similar
characteristics. These additional project areas included the Knox Field in
southern Oklahoma, the Sholem Alechem Field in southern Oklahoma, the Louisiana
Trend, the Arkoma Basin in southeastern Oklahoma, the Lovington area in eastern
New Mexico, and the Williston Basin in
1
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eastern Montana and western North Dakota. In fiscal 1997, the Company also added
a large exploration project in Wharton County, Texas.
The Company invested approximately $179 million, including capitalized
interest, to acquire over one million acres of leasehold in the Louisiana Trend
from fiscal 1995 through fiscal 1997, and an additional $163 million in drilling
to explore this leasehold in fiscal 1996 and 1997. Of the Company's six project
areas identified in the Louisiana Trend, only in the Masters Creek area has the
Company consistently found commercial quantities of oil and gas in the Austin
Chalk formation.
As of June 30, 1997 the Company owned over two million net undeveloped
acres in its leasehold inventory. The Company expects that its inventory of
proved and unproved drilling locations will continue to be an important source
of new reserves, production and cash flow over the next few years. The Louisiana
Trend continues to be a key element of this existing inventory.
The following table sets forth the Company's estimated proved reserves (net
of interests of other working and royalty interest owners and others entitled to
share in production), estimated capital expenditures and the number of potential
net drilling locations required to develop the Company's proved undeveloped
reserves at June 30, 1997:
<TABLE>
<CAPTION>
ESTIMATED
CAPITAL
EXPENDITURES
PERCENT REQUIRED TO NUMBER OF
OF DEVELOP NET PROVED
OIL GAS GAS PROVED PUD'S UNDEVELOPED
AREAS (MBBL) (MMCF) EQUIVALENT RESERVES ($ IN 000'S) LOCATIONS
----- ------ ------- ---------- -------- ------------ -----------
<S> <C> <C> <C> <C> <C> <C>
Louisiana Trend............. 7,673 36,418 82,456 20% 54,529 16
Oklahoma.................... 4,483 123,393 150,291 37% 48,741 37
Giddings.................... 1,990 128,992 140,932 35% 33,825 26
Williston Basin............. 872 551 5,783 2% 2,669 3
Other Areas................. 2,355 9,412 23,542 6% 7,204 9
------ ------- ------- --- ------- --
Total............. 17,373 298,766 403,004 100% 146,968 91
====== ======= ======= === ======= ==
</TABLE>
PRIMARY OPERATING AREAS
The Company's activities are concentrated in three primary operating areas:
(i) the Louisiana Trend, (ii) the Knox, Sholem Alechem, Golden Trend, and Arkoma
Basin areas of Oklahoma, and (iii) the Navasota River and Independence areas of
the downdip Giddings Field in southern Texas.
Louisiana Austin Chalk Trend. The Louisiana Trend is the newest of the
Company's three primary operating areas and is budgeted to represent
approximately 50% of the Company's exploration and development activities in
fiscal 1998. In late 1994, Occidental Petroleum Corporation ("Occidental")
completed a horizontal Austin Chalk discovery well in the Masters Creek area of
central Louisiana. Occidental's well was drilled 200 miles east of the Company's
activity in the downdip Giddings Field and 60 miles east of the nearest previous
commercial multi-well horizontal Austin Chalk production in the Brookeland Field
of southeast Texas.
Following the announcement of Occidental's discovery well, the Company
extensively reviewed and analyzed vertical drilling reports, electric logs, mud
logs, seismic data and vertical Austin Chalk production records to arrive at a
geological conclusion that the Austin Chalk could be productive across a large
portion of central and southeastern Louisiana. Accordingly, and in competition
with Union Pacific Resources Company, Sonat, Inc., Occidental, Amoco Production
Company, Helmerich & Payne, Inc., Belco Oil & Gas Corporation and others,
Chesapeake invested approximately $179 million from fiscal 1995 through fiscal
1997 to acquire over one million acres of leasehold in the Louisiana Trend.
Beginning in fiscal 1996 and accelerating substantially by the end of fiscal
1997, Chesapeake expended an additional $163 million to initiate drilling
efforts on 56 gross (34 net) wells to evaluate this leasehold position.
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<PAGE> 4
Leasehold that is classified as unevaluated is not subject to amortization
or to the periodic ceiling test evaluations required under full cost accounting.
As leasehold is evaluated through exploration efforts including drilling, it
becomes subject to amortization and the ceiling test evaluation. At June 30,
1997, the Company had $342 million of oil and gas assets in the Louisiana Trend,
of which $275.2 million was evaluated and therefore subject to the ceiling test.
From December 1996 through April 1997, the Company initiated drilling
efforts on 15 new operated wells in the Louisiana Trend. Between April 1997 and
July 1997, the Company completed operations on ten exploratory wells in areas of
the Louisiana Trend outside of Masters Creek. Of these wells, one was completed
on April 15, 1997, one on May 3, 1997 and eight were completed after June 1,
1997. Based upon the results from these wells, which primarily became known to
the Company in late June 1997, the Company made the determination that a
significant amount of leasehold previously classified as unevaluated had become
evaluated. This determination, in combination with development in the Masters
Creek area, resulted in a transfer of approximately $91 million of previously
unevaluated leasehold costs to the full cost pool which, and in conjunction with
disappointing drilling results and the related costs thereof and lower oil and
gas prices, was the primary cause of the full cost ceiling writedown. See
"Results of Operations -- Impairment of Oil and Gas Properties" in Item 7, which
identifies the components of the impairment.
The Company believes that some portion of the Louisiana Trend outside of
the Masters Creek area, and specifically certain areas of East Baton Rouge and
Point Coupee Parishes that are prospective for the Tuscaloosa formation, may
ultimately be successfully exploited. It is the Company's intent to focus its
Louisiana drilling in fiscal 1998 primarily in the Masters Creek area and to
allow others to lead the continued exploration of areas outside of Masters
Creek.
The Masters Creek area, where as of September 30, 1997 the Company and the
Company's competitors have completed approximately 36 out of 40 wells as
commercially productive with approximately 25 additional wells currently
drilling, has generally been much more successful than the other areas within
the Louisiana Trend. As of September 30, 1997, the Company had eight rigs
operating in this area and is participating in more than 10 non-operated wells.
For fiscal 1998, the Company has budgeted $125 million to drill approximately 25
net wells targeting the Austin Chalk formation and $13 million to drill two net
wells targeting the Tuscaloosa formation. These planned expenditures, in
combination with anticipated seismic costs, represent approximately 40% of the
Company's planned exploration and development capital expenditures for all
areas. The Company, while it has significantly reduced its budget for the
Louisiana Trend from prior expectations, continues to believe there are
significant economic drilling opportunities in the Masters Creek area.
Additionally, the Company has yet to complete the various 3-D seismic programs
necessary to fully evaluate leasehold purchased for potential Tuscaloosa
production and to support the drilling of the Tuscaloosa wells planned. There
can be no assurance that the Louisiana Trend drilling will yield substantial
economic returns. Failure of the wells to produce significant quantities of
economically attractive reserves and production could have a material adverse
impact on the Company's future financial condition and results of operations,
and could result in a future ceiling limitation under rules of the Securities
and Exchange Commission.
Oklahoma. Chesapeake's largest concentration of proved reserves is located
in Oklahoma and is comprised of the Knox, Golden Trend, Sholem Alechem, and
Arkoma Basin areas. These areas are generally characterized by relatively long
lived production from multiple producing zones. The Company has conducted and is
evaluating 3-D seismic surveys over significant portions of its Oklahoma
leasehold in an effort to enhance its future drilling efforts. In fiscal 1997,
the Company invested approximately $68 million to drill 51 gross (32 net) wells
in Oklahoma. The Company has budgeted approximately $28 million in fiscal 1998
to drill 36 gross (21 net) wells in Oklahoma.
Giddings Field. Chesapeake's second largest concentration of proved
reserves and its highest concentration of present value is located in the
Giddings Field, Texas. The primary producing formation in Giddings is the Austin
Chalk formation, a fractured carbonate reservoir found at depths ranging from
7,000 feet to
3
<PAGE> 5
17,000 feet along a 15,000 square mile trend in southeastern Texas and central
Louisiana. Chesapeake has concentrated its drilling efforts in the gas prone
downdip portion of the Giddings Field, where the Austin Chalk is located at
depths below 11,000 feet.
The Giddings Field contributed approximately 44.6 Bcfe, or 57% of the
Company's total production in fiscal 1997, compared to 47.2 Bcfe or 78% in 1996.
The Company expects production to decline in this relatively mature area in
fiscal 1998. In fiscal 1997, the Company invested approximately $57 million to
drill 36 gross (19 net) wells in Giddings. The Company has budgeted
approximately $17 million to drill 18 gross (eight net) wells in Giddings during
fiscal 1998.
OTHER OPERATING AREAS
Williston Basin. During fiscal 1996, Chesapeake began acquiring leasehold
in the Williston Basin, located in eastern Montana and western North Dakota, and
as of June 30, 1997 owned more than 700,000 gross (500,000 net) acres. During
fiscal 1997, the Company drilled and successfully completed four vertical wells
targeting the Red River formation on the northern portion of its leasehold. (A
"successfully completed" well is a commercial well, i.e. one that generates
proceeds from the sale of production in excess of production expenses and
related production taxes.) On the southern portion of its leasehold, the Company
was unsuccessful in an attempt to establish horizontally drilled Red River
production. Also during fiscal 1997, the Company tested a third large area of
its Williston acreage with a successful horizontal Nesson well. Currently, the
Company is focusing its Williston efforts on continuing to develop the Nesson
formation. The Company has budgeted $6 million to drill six gross and net wells
during fiscal 1998 in the Williston Basin.
Permian Basin. In fiscal 1995, the Company initiated 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 algal reef
buildups 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 fiscal 1997 the Company initiated eight wells in this project area,
seven of which were successfully completed. The Company has budgeted
approximately $14 million to drill 14 gross and net wells in this area during
fiscal 1998.
Wharton County, Texas. During fiscal 1997 the Company acquired
approximately 25,000 net acres at a cost of approximately $29 million 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 intends to participate with a 55% interest in a 55,000
acre 3-D seismic program with Coastal Oil & Gas Corporation, Seagull Energy
Corporation and other industry partners during fiscal 1998 to delineate
potential future drillsites in the vicinity of Coastal's recently completed
Zeidman Trust #2 well.
STRATEGIC INVESTMENTS
During fiscal 1997, the Company invested in a number of oil and gas related
businesses and projects. The most significant of these was the Company's May
1997 initial investment in Bayard Drilling Technologies, Inc. ("Bayard"),
consisting of an $18 million subordinated loan and the purchase of $7 million of
common stock. In August 1997, the Company agreed to invest up to an additional
$9 million and convert certain options, warrants and note amounts that will
facilitate a potential initial public offering by Bayard. On August 27, 1997
Bayard filed a registration statement for an initial public offering of its
common stock. Chesapeake, subsequent to the completion of the transaction noted
above, will own 4,194,000 shares of Bayard common stock (30.4% of the common
stock outstanding) and anticipates selling substantially all of its ownership in
Bayard in the IPO (assuming the over-allotment option is exercised) and
receiving repayment of the subordinated loan. If successful, assuming the sale
of all of the Company's Bayard stock and based on the initial filing price of
Bayard at $15 per share, the Company would receive total proceeds of
approximately $74 million (net of offering costs) and realize a pre-tax gain of
approximately $40 million. No assurance can be given, however, that Bayard will
successfully complete the initial public offering of its common stock, at what
price, or that the net proceeds or pre-tax gain discussed above will be realized
by the Company.
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<PAGE> 6
Also during fiscal 1997 the Company invested approximately $12 million for
its 50% interest in the Louisiana Austin Chalk Gathering System (a joint venture
with Mitchell Energy and Development Corporation) and $5 million for its 15.5%
interest in the Masters Creek Gas Plant (a joint venture among Union Pacific,
Sonat, Helmerich & Payne, and OXY). The Company has budgeted $4 million for its
share of the expansion of these assets during fiscal 1998. The Company considers
these mid-stream gas assets to be non-core and therefore may seek to sell them
in fiscal 1998.
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>
YEAR ENDED JUNE 30,
-----------------------------------------------
1997 1996 1995
------------- ------------- -------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Development:
Productive.................................. 90 55.0 111 49.5 133 42.6
Non-productive.............................. 2 .2 4 1.6 5 2.8
-- ---- --- ---- --- ----
Total....................................... 92 55.2 115 51.1 138 45.4
== ==== === ==== === ====
Exploratory:
Productive.................................. 71 46.1 29 16.5 11 5.3
Non-productive.............................. 8 5.7 4 1.4 1 .7
-- ---- --- ---- --- ----
Total....................................... 79 51.8 33 17.9 12 6.0
== ==== === ==== === ====
</TABLE>
At June 30, 1997, the Company was drilling 25 gross (19.8 net) exploratory
or development wells, of which 11 gross (8.1 net) wells have been successfully
completed and 12 gross (9.7 net) wells are still being drilled or tested. The
Company was also participating with minority interests in 13 non-operated wells
being drilled at that date.
1998 3-D SEISMIC SURVEY PROGRAM
The Company has increased its emphasis on the use of 3-D seismic surveys to
evaluate and define potential drilling locations. The use of 3-D, compared to
2-D, seismic technology is desirable in many situations because it (a) allows
more precise imaging of structural and stratigraphic features under the earth,
(b) allows more precise well placement minimizing dry hole risk while maximizing
the potential oil and gas recovery, and (c) eliminates certain wells from being
drilled into reservoirs too small to be economic. During fiscal 1998 the Company
has budgeted approximately $25 million for seismic acquisition and evaluation
and intends to conduct or participate in seismic surveys covering the following
areas:
<TABLE>
<CAPTION>
APPROXIMATE
GROSS ACREAGE AREA TARGET FORMATIONS
- ------------- ------------------ -------------------------------
<C> <S> <C>
85,000 Baton Rouge, LA Tuscaloosa; Austin Chalk
55,000 Wharton County, TX Deep Wilcox; Frio and Yegua
35,000 Golden Trend, OK Multiple sand and carbonates
90,000 Lovington, NM Strawn
50,000 Williston, MT Red River
50,000 Allen Parish, LA Wilcox; Austin Chalk
</TABLE>
WELL DATA
At June 30, 1997, the Company had interests in approximately 593 (270.1
net) producing wells, of which 129 (55.4 net) were classified as primarily oil
producing wells and 464 (214.7 net) were classified as primarily gas producing
wells.
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<PAGE> 7
VOLUMES, REVENUE, PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the production
volumes, revenue, average prices received and average production costs
associated with the Company's sale of oil and gas for the periods indicated:
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
-------------------------------
1997 1996 1995
-------- -------- -------
<S> <C> <C> <C>
NET PRODUCTION:
Oil (MBbl)...................................... 2,770 1,413 1,139
Gas (MMcf)...................................... 62,005 51,710 25,114
Gas equivalent (MMcfe).......................... 78,625 60,190 31,947
OIL AND GAS SALES ($ IN 000'S):
Oil............................................. $ 57,974 $ 25,224 $19,784
Gas............................................. 134,946 85,625 37,199
-------- -------- -------
Total oil and gas sales................. $192,920 $110,849 $56,983
======== ======== =======
AVERAGE SALES PRICE:
Oil ($ per Bbl)................................. $ 20.93 $ 17.85 $ 17.36
Gas ($ per Mcf)................................. $ 2.18 $ 1.66 $ 1.48
Gas equivalent ($ per Mcfe)..................... $ 2.45 $ 1.84 $ 1.78
OIL AND GAS COSTS ($ PER MCFE):
Production expenses and taxes................... $ .19 $ .14 $ .13
General and administrative...................... $ .11 $ .08 $ .11
Depreciation, depletion and amortization of oil
and gas properties........................... $ 1.31 $ .85 $ .80
</TABLE>
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>
YEAR ENDED JUNE 30,
--------------------------------
1997 1996 1995
-------- -------- --------
($ IN THOUSANDS)
<S> <C> <C> <C>
Development costs................................ $187,736 $138,188 $ 78,679
Exploration costs................................ 136,473 39,410 14,129
Acquisition costs:
Unproved properties............................ 140,348 138,188 24,437
Proved properties.............................. -- 24,560 --
Capitalized internal costs....................... 3,905 1,699 586
Proceeds from sale of leasehold, equipment and
other.......................................... (3,095) (6,167) (11,953)
-------- -------- --------
Total.................................. $465,367 $335,878 $105,878
======== ======== ========
</TABLE>
ACREAGE
The following table sets forth as of June 30, 1997 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
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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.
<TABLE>
<CAPTION>
TOTAL DEVELOPED
DEVELOPED UNDEVELOPED AND UNDEVELOPED
------------ -------------------- ----------------
GROSS NET GROSS NET GROSS NET
----- --- -------- -------- ------ ------
<S> <C> <C> <C> <C> <C> <C>
Louisiana Trend.............. 41 40 1,154(1) 1,003(1) 1,195 1,043
Oklahoma..................... 85 34 297 134 382 168
Giddings..................... 121 58 186 133 307 191
Williston Basin.............. 3 2 732 498 735 500
Other Areas.................. 27 19 331 250 358 269
--- --- -------- -------- ----- -----
Total.............. 277 153 2,700 2,018 2,977 2,171
=== === ======== ======== ===== =====
</TABLE>
- ---------------
(1) Does not include options for additional leasehold held by the Company but
not yet exercised.
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 fiscal 1997, the following
three 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>
Aquila Southwest Pipeline Corporation.................... 53,885 28%
Koch Oil Company......................................... 29,580 15%
GPM Gas Corporation...................................... 27,682 14%
</TABLE>
Management believes that the loss of any 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 the geographical areas
in which the Company is active.
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 (1)
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,
(2) 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, (3) 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 (4) basis protection swaps, which are arrangements that guarantee the price
differential of oil or gas from a specified delivery point or points. Results
from hedging transactions are reflected in oil and gas sales to the extent
related to the Company's oil and gas production. The Company only enters into
hedging transactions related to the Company's oil and gas production volumes or
CEMI physical purchase or sale commitments.
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<PAGE> 9
As of June 30, 1997, the Company had the following oil swap arrangements
for periods after June 1997:
<TABLE>
<CAPTION>
NYMEX-INDEX
STRIKE PRICE
MONTH VOLUME (BBLS) (PER BBL)
----- -------------- ------------
<S> <C> <C>
July 1997................................................. 31,000 $ 18.60
August 1997............................................... 31,000 $ 18.43
September 1997............................................ 30,000 $ 18.30
October 1997.............................................. 31,000 $ 18.19
November 1997............................................. 30,000 $ 18.13
December 1997............................................. 31,000 $ 18.08
January through June 1998................................. 724,000 $ 19.82
</TABLE>
The Company entered into oil swap arrangements to cancel the effect of the
above swaps for the months of August through December at an average price of
$21.07 per Bbl.
As of June 30, 1997, the Company had the following gas swap arrangements
for periods after June 1997:
<TABLE>
<CAPTION>
HOUSTON SHIP CHANNEL
INDEX STRIKE PRICE
MONTHS VOLUME (MMBTU) (PER MMBTU)
------ -------------- --------------------
<S> <C> <C>
July 1997......................................... 1,240,000 $2.313
August 1997....................................... 1,240,000 $2.301
September 1997.................................... 1,200,000 $2.285
October 1997...................................... 1,240,000 $2.300
</TABLE>
The Company entered into gas swap arrangements to cancel the effect of the
swaps for the months of July through October at an average price of $2.133 per
MMBtu.
The Company entered into a curve lock for approximately 4.9 Bcf of gas
which allows the Company the option to hedge April 1999 through November 1999
gas based upon a negative $0.285 differential to December 1998 gas any time
between the strike date and December 1998. A curve lock is a commodity swap
arrangement that establishes, or hedges, a price differential between one
commodity contract period and another. In markets where the forward curve is
typically negatively sloped (prompt prices exceed deferred prices), an upward
sloping price curve allows hedgers to lock in a deferred forward sale at a
higher premium to a more prompt swap by a curve lock.
For example, in the crude oil market, which typically has a negatively
sloped price curve, it may be possible for a hedger to lock in a price
relationship in which his deferred crude oil is sold at a premium to a prompter
swap, because the price curve is upwardly sloping in the future. The expectation
of the hedger is that either the market will return to its historically
negatively sloped price curve, or that prices generally will increase and the
curve lock swap will allow him to realize a premium price for the deferred
versus the more prompt price.
The Company estimates that had all of the crude oil and natural gas swap
agreements in effect for production periods beginning July 1, 1997 terminated on
June 30, 1997, based on the closing prices for NYMEX futures contracts as of
that date, the Company would have paid the various counterparties a net amount
of approximately $185,000, which would have represented the "fair value" at that
date. These agreements were not terminated.
Periodically, CEMI 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.
8
<PAGE> 10
COMPETITION
The oil and gas industry is highly competitive. The Company competes with
major and independent oil and gas companies for the acquisition of leasehold,
proven oil and gas properties, as well as for the services and labor required to
explore, develop and produce such properties. Many of these competitors have
financial, technical and other resources substantially greater than those of the
Company.
SEASONAL NATURE OF BUSINESS
Historically the demand for natural gas decreases during the summer months
and increases during the winter months. However, pipelines, utilities, local
distribution companies and industrial users may more effectively utilize natural
gas storage capacity by purchasing some of the winter load in the summer at
reduced prices.
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
9
<PAGE> 11
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) 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
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<PAGE> 12
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 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 recently
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
it will be able to obtain, or be included under, such permits, where necessary,
with minor modifications to existing facilities and operations that would not
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 oil-field 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 (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, little investigation of record title is made at the time
of acquisition (other than a preliminary review of local
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<PAGE> 13
records). Drilling title opinions are always 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 drilling
activities involve greater risk of mechanical problems than conventional
vertical drilling operations.
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 362 full-time employees as of June 30, 1997. No employees
are represented by organized labor unions. The Company considers its employee
relations to be good.
FACILITIES
The Company owns 12 buildings totaling approximately 80,000 square feet in
an office complex in Oklahoma City that comprise its headquarters' offices and
also owns a field office in Lindsay, Oklahoma. The Company leases field office
space in College Station and Navasota, Texas, Lafayette, Louisiana and Calgary,
Canada.
REINCORPORATION
On December 31, 1996, the Company changed its state of incorporation from
Delaware to Oklahoma by the merger of Chesapeake Energy Corporation, a Delaware
corporation, with and into its newly formed wholly-owned subsidiary, Chesapeake
Oklahoma Corporation. The surviving corporation changed its name to Chesapeake
Energy Corporation. Each outstanding share of Common Stock, par value $.10, of
the merged Delaware corporation was converted into one share of Common Stock,
par value $.01, of the surviving corporation. As a result of the merger, the
surviving corporation succeeded to all of the assets and is responsible for all
of the liabilities of the merged Delaware corporation. On matters of corporate
governance, the rights of the Company's security holders are now governed by
Oklahoma law, which is similar to the corporate law of Delaware.
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.
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<PAGE> 14
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.
Formation. A succession of sedimentary beds that were deposited under the
same general geologic conditions.
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.
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<PAGE> 15
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.
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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<PAGE> 16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
OVERVIEW
Chesapeake's revenue, operating cash flow (exclusive of changes in working
capital) and production reached record levels in fiscal 1997. However,
significant expenditures for acreage acquisition and drilling costs followed by
unfavorable exploration and production results, together with increases in
drilling and equipment costs and declines in oil and gas prices as of June 30,
1997, resulted in downward revisions in estimates of the Company's proved oil
and gas reserves and the present value of the estimated future net revenues from
these reserves. Such excess caused the Company to record a $236 million asset
writedown during the fourth quarter of the year and caused the Company to report
a net loss of $183 million for the year.
Chesapeake's strategy during fiscal 1997, and particularly in the third and
fourth quarters of the year, was to identify the potential of the various areas
of the Louisiana Trend by exploratory drilling. In several large areas outside
of the Masters Creek portion of the Louisiana Trend, this exploration program
was unsuccessful. In these areas significant leasehold and drilling costs were
added to the evaluated oil and gas property pool while insignificant quantities
of oil and gas reserves were added to the Company's proved reserve base.
During fiscal 1997, the Company participated in 171 gross (107 net) wells,
of which 129 wells were operated by the Company. A summary of the Company's
drilling activities and capital expenditures by primary operating area is as
follows ($ in thousands):
<TABLE>
<CAPTION>
CAPITAL EXPENDITURES
GROSS NET ---------------------------------
WELLS WELLS DRILLING LEASEHOLD TOTAL
----- ----- -------- --------- --------
<S> <C> <C> <C> <C> <C>
Louisiana Trend.................... 50 28.7 $141,581 $ 81,287 $222,868
Oklahoma........................... 51 31.8 67,689 4,556 72,245
Texas.............................. 51 31.7 64,514 41,112 105,626
Other.............................. 19 14.8 51,237 13,391 64,628
Total.................... 171 107.0 $325,021 $140,346 $465,367
</TABLE>
The Company's proved reserves decreased 5% to an estimated 403 Bcfe at June
30, 1997, down 22 Bcfe from 425 Bcfe of estimated proved reserves at June 30,
1996 (see Note 11 of Notes to Consolidated Financial Statements in Item 8 and
"Results of Operations -- Impairment of Oil and Gas Properties"). Due to the
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, there can be no
assurance that the Company's estimated proved reserves will not decrease in the
future.
The Company's business strategy in fiscal 1997 continued to emphasize the
acquisition of large prospective leasehold positions which potentially provide a
multi-year inventory of drilling locations. As of June 30, 1997, the Company had
approximately 277,000 gross acres of developed leasehold and 2.7 million gross
acres of undeveloped leasehold. The fiscal 1997 drilling program, particularly
in Louisiana, consisted of more exploratory drilling than in previous years. The
Company's strategy for fiscal 1998 is to reduce its capital expenditure program
to approximately $225-$275 million, concentrate its Louisiana Trend drilling
activities in Masters Creek, utilize more 3-D seismic prior to conducting
drilling operations, reduce the acquisition of additional unproven leasehold,
and selectively acquire proved reserves. This strategy will likely have the
effect of reducing the Company's anticipated production growth rate from
exploration and development drilling.
To assist the Company in reducing exploratory risks and increasing economic
returns the Company has increased its use of 3-D seismic. The Company has
conducted, participated in, or is actively pursuing more than 25 3-D seismic
programs to more fully evaluate the Company's acreage inventory.
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<PAGE> 17
The following table sets forth certain operating data of the Company for
the periods presented:
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
-----------------------------
1997 1996 1995
-------- -------- -------
<S> <C> <C> <C>
NET PRODUCTION DATA:
Oil (MBbl)................................................ 2,770 1,413 1,139
Gas (MMcf)................................................ 62,005 51,710 25,114
Gas equivalent (MMcfe).................................... 78,625 60,190 31,947
OIL AND GAS SALES ($ in 000's):
Oil....................................................... $ 57,974 $ 25,224 $19,784
Gas....................................................... 134,946 85,625 37,199
-------- -------- -------
Total oil and gas sales........................... $192,920 $110,849 $56,983
======== ======== =======
AVERAGE SALES PRICE:
Oil ($ per Bbl)........................................... $ 20.93 $ 17.85 $ 17.36
Gas ($ per Mcf)........................................... $ 2.18 $ 1.66 $ 1.48
Gas equivalent ($ per Mcfe)............................... $ 2.45 $ 1.84 $ 1.78
OIL AND GAS COSTS ($ per Mcfe):
Production expenses and taxes............................. $ .19 $ .14 $ .13
General and administrative................................ $ .11 $ .08 $ .11
Depreciation, depletion and amortization.................. $ 1.31 $ .85 $ .80
NET WELLS DRILLED:
Horizontal wells.......................................... 75.7 42.0 28.5
Vertical wells............................................ 31.3 27.0 23.0
NET WELLS AT END OF PERIOD.................................. 270.1 187.0 96.4
</TABLE>
The Company completed an offering of 8,972,000 shares of common stock in
December 1996 resulting in net proceeds to the Company of approximately $288.1
million. Additionally, the Company issued $300 million in Senior Notes in March
1997. The Company used the net proceeds from these offerings, along with cash
flow from operations, to fund its net capital expenditures of $524 million,
repay all amounts outstanding under its commercial bank credit facilities, and
retire $47.5 million of Senior Notes.
RESULTS OF OPERATIONS
General. For the fiscal year ended June 30, 1997, the Company realized a
net loss of $183.4 million, or a loss of $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, and net
income of $11.7 million, or $0.21 per common share, on total revenues of $67.3
million in fiscal 1995. The loss in fiscal 1997 as compared to significantly
higher earnings in fiscal 1996 and fiscal 1995 was largely the result of a $236
million asset writedown recorded in the fourth quarter under the full cost
method of accounting. (See "Results of Operations -- 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 and 238% from the fiscal
1995 amount of $57 million. 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, and 31.9 Bcfe produced in fiscal
1995 at a weighted average price of $1.78 per Mcfe. This represents production
growth of 31% for fiscal 1997 compared to fiscal 1996 and 146% compared to
fiscal 1995.
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<PAGE> 18
The following table shows the Company's production by major field area for
fiscal 1997 and fiscal 1996:
<TABLE>
<CAPTION>
FOR THE YEAR ENDED JUNE 30,
----------------------------------------
1997 1996
------------------ ------------------
PRODUCTION PRODUCTION
------------------ ------------------
(MMCFE) PERCENT (MMCFE) PERCENT
------- ------- ------- -------
<S> <C> <C> <C> <C>
Texas........................................ 47,398 61% 49,347 82%
Oklahoma..................................... 17,370 22 10,420 17
Louisiana Trend.............................. 12,785 16 69 --
All Other Fields............................. 1,072 1 354 1
------ --- ------ ---
Total Production............................. 78,625 100% 60,190 100%
====== === ====== ===
</TABLE>
The Company's 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 and $17.36 in fiscal 1995. 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. Gas
prices in fiscal 1995 averaged $1.48 per Mcf. 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, $5.9 million, and none in fiscal 1997, 1996 and 1995,
respectively.
Oil and Gas Marketing Sales. In December 1995, the Company entered into the
oil and gas marketing business by establishing a subsidiary to provide primarily
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 the 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. There were no comparable marketing activities in fiscal 1995.
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 is being
amortized to income over the estimated useful lives of the Peak assets. The
Company's investment in Peak is accounted for using the equity method, and
resulted in $0.5 million of income being included in Interest and other revenues
in fiscal 1997.
Revenues from oil and gas service operations were $6.3 million in fiscal
1996, down 28% from $8.8 million in fiscal 1995. The related costs and expenses
of these operations were $4.9 million and $7.7 million for the two years ended
June 30, 1996 and 1995 respectively. The gross profit margin of 22% in fiscal
1996 was up from the 12% margin in fiscal 1995. The gross profit margin derived
from these operations is
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<PAGE> 19
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.
Interest and Other. Interest and other revenues for fiscal 1997 were $11.2
million which compares to $3.8 million in fiscal 1996 and $1.5 million in fiscal
1995. 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. During 1995, the Company did not incur any such gains on sale of
assets or basis losses.
Production Expenses and Taxes. Production expenses and taxes, which include
lifting costs and production and excise taxes, increased to $15.1 million in
fiscal 1997, as compared to $8.3 million in fiscal 1996 and $4.3 million in
fiscal 1995. These increases on a year-to-year basis were primarily the result
of increased production. On an Mcfe production unit basis, production expenses
and taxes increased to $0.19 per Mcfe as compared to $0.14 per Mcfe in fiscal
1996 and $0.13 per Mcfe in fiscal 1995. During fiscal 1996 and 1995, a high
proportion of the Company's production was from the Giddings Field, much of
which qualified for Texas severance tax exemptions. The Company expects that
operating costs per Mcfe will continue to increase in fiscal 1998 based on the
Company's expected production mix and drilling activities in oil prone areas
which generally have higher operating costs than gas prone areas and because a
higher percentage of the Company's production will not qualify for severance tax
exemptions as compared to the past.
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. To the
extent that capitalized costs of oil and gas properties, net of accumulated
depreciation, depletion and amortization and related deferred income taxes,
exceed the discounted future net revenues of proved oil and gas properties, such
excess costs are charged to operations.
Prior to January 1997, the Company 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 ten
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 in late June 1997, 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.
Oil and gas prices 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
18
<PAGE> 20
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 estimated discounted future net
revenues from its proved reserves, and giving effect to fourth quarter 1997
drilling and production results, oil and gas prices, higher drilling and
completion costs, and additional leasehold acquisition costs and delay rentals
incurred in areas subsequently determined to have less reserve potential than
had previously been estimated. After considering all of these factors,
management estimated that at June 30, 1997 it would have capitalized costs of
oil and gas properties which would exceed its full cost ceiling by approximately
$150 million to $200 million and on June 27, 1997, 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 or fiscal
1995.
Oil and Gas Depreciation, Depletion and Amortization. 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, and $77.9 million higher than fiscal 1995's expense of $25.4 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 and $0.80 in
fiscal 1995. The Company's DD&A rate in the future will be a function of the
results of future acquisition, exploration, development and production results,
but the Company's rate is expected to trend upward in fiscal 1998 based on
projected higher finding costs for the Louisiana Trend and higher drilling,
completing, and equipping expenses throughout the oil and gas industry.
Depreciation and Amortization of Other Assets. Depreciation and
amortization ("D&A") of other assets increased to $3.8 million in fiscal 1997,
compared to $3.2 million in fiscal 1996, and $1.8 million in fiscal 1995. 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. The Company anticipates an increase in
D&A in fiscal 1998 as a result of a full year of debt issuance cost amortization
on the Senior Notes issued in March 1997 and higher building depreciation
expense on the Company's corporate offices.
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 $8.8 million in fiscal
1997, up 83% from $4.8 million in fiscal 1996, and up from $3.6 million in
fiscal 1995. The increases in fiscal 1997 as compared to fiscal 1996 and 1995
result primarily from 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, as compared to $1.7 million in 1996 and
$0.6 million in 1995. The Company anticipates that G&A costs for fiscal 1998
will continue to increase as the result of wage inflation in the oil and gas
industry and legal fees associated with the UPRC and shareholder litigation.
Interest and Other. Interest and other expense increased to $18.6 million
in fiscal 1997 as compared to $13.7 million in 1996 and $6.6 million in fiscal
1995. Interest expense in the fourth quarter of fiscal 1997 was $8.7 million,
reflecting the issuance of the 7.875% Senior Notes and the 8.5% Senior Notes in
March 1997. In addition to the interest expense reported, the Company
capitalized $12.9 million of interest during fiscal 1997, as compared to $6.4
million capitalized in fiscal 1996 and $1.6 million in fiscal 1995. Interest
expense will
19
<PAGE> 21
increase significantly in fiscal 1998 as compared to fiscal 1997 as a result of
the $300 million Senior Notes issued in March 1997 and reduced levels of
capitalized interest expected in fiscal 1998.
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, as compared to income tax expense of $12.9 million in
1996 and $6.3 million in 1995. All of the income tax expense in 1996 and 1995
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 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 $64.1
million has been 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
and $1.2 million in fiscal 1995.
The Company does not expect to record any net income tax expense in fiscal
1998 based on information available at this time.
Hedging. Periodically the Company utilizes hedging strategies to hedge the
price of a portion of its future oil and gas production. These strategies
include (1) 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, (2) 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, (3) 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 (4) basis protection swaps. Results from hedging
transactions are reflected in oil and gas sales to the extent related to the
Company's oil and gas production. The Company has not entered into hedging
transactions unrelated to the Company's oil and gas production or physical
purchase or sale commitments.
As of June 30, 1997, the Company had the following oil swap arrangements
for periods after June 1997:
<TABLE>
<CAPTION>
NYMEX-INDEX
STRIKE PRICE
MONTH VOLUME (BBLS) (PER BBL)
----- ------------- ------------
<S> <C> <C>
July 1997................................................ 31,000 $ 18.60
August 1997.............................................. 31,000 $ 18.43
September 1997........................................... 30,000 $ 18.30
October 1997............................................. 31,000 $ 18.19
November 1997............................................ 30,000 $ 18.13
December 1997............................................ 31,000 $ 18.08
January through June 1998................................ 724,000 $ 19.82
</TABLE>
The Company entered into oil swap arrangements to cancel the effect of the
swaps for the months of August through December at an average price of $21.07
per Bbl.
20
<PAGE> 22
As of June 30, 1997, the Company had the following gas swap arrangements
for periods after June 1997:
<TABLE>
<CAPTION>
HOUSTON SHIP CHANNEL
INDEX STRIKE PRICE
MONTH VOLUME (MMBTU) (PER BBL)
----- -------------- --------------------
<S> <C> <C>
July 1997........................................ 1,240,000 $2.313
August 1997...................................... 1,240,000 $2.301
September 1997................................... 1,200,000 $2.285
October 1997..................................... 1,240,000 $2.300
</TABLE>
The Company had entered into gas swap arrangements to cancel the effect of
the swaps for the months of July through October at an average price of $2.133
per MMBtu.
The Company has entered into a curve lock for 4.9 Bcf of gas which allows
the Company the option to hedge April 1999 through November 1999 gas based upon
a negative $0.285 differential to December 1998 gas any time between the strike
date and December 1998.
Gains or losses on the crude oil and natural gas hedging transactions are
recognized as price adjustments in the month of related production. The Company
estimates that had all of the crude oil and natural gas swap agreements in
effect for production periods beginning July 1, 1997 terminated on June 30,
1997, based on the closing prices for NYMEX futures contracts as of that date,
the Company would have paid the counterparty approximately $185,000, which would
have represented the "fair value" at that date. These agreements were not
terminated.
Periodically, the Company's oil and gas marketing subsidiary CEMI 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.
LIQUIDITY AND CAPITAL RESOURCES
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, as compared to $121.0 million in fiscal 1996 and $54.7
million in fiscal 1995. The primary reason for the decrease from fiscal 1996 to
1997 was significant changes in the components of current assets and
liabilities, specifically $102.8 million of short-term investments at June 30,
1997. Cash provided by operating activities is expected to be a significant
source for meeting forecasted cash requirements for fiscal 1998.
Cash Flows from Investing Activities. Significantly higher cash was used in
fiscal 1997 for development, exploration and acquisition of oil and gas
properties as compared to fiscal 1996 and 1995. Approximately $524 million was
expended by the Company in fiscal 1997 (net of proceeds from sale of leasehold,
equipment and other), as compared to $344 million in fiscal 1996, an increase of
$180 million, or approximately 52%. In fiscal 1995 the Company expended $113
million (net of proceeds from sale of leasehold, equipment and other). 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 as compared to
$6.2 million in fiscal 1996 and $12.0 million in fiscal 1995. 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 the purchase of additional office buildings,
improvements and related equipment in Oklahoma City.
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 $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.
21
<PAGE> 23
On March 17, 1997, the Company concluded the sale of $150 million of 7.875%
Senior Notes due 2004 (the "7.875% Senior Notes"), and $150 million of 8.5%
Senior Notes due 2012 (the "8.5% Senior Notes"), 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 April 1997 the Company terminated its
commercial bank facilities.
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 (the "9.125% Senior Notes"). The Company may, at
its option, redeem prior to April 15, 1999 up to $42 million principal amount of
the 9.125% Senior Notes at 109.125% of the principal amount thereof from equity
offering proceeds. The 9.125% Senior Notes are redeemable at the option of the
Company at any time at the redemption or make-whole prices set forth in the
Indenture.
Financial Flexibility and Liquidity. The Company had working capital of
approximately $151.3 million at June 30, 1997. During fiscal 1997, the Company
invested in a number of oil and gas related businesses and projects. The most
significant of these was the Company's initial investment made in Bayard,
consisting of an $18 million subordinated note and $7 million of common stock.
In August 1997, the Company entered into an agreement with Bayard to invest up
to an additional $9 million and convert certain options, warrants and note
amounts that will facilitate a potential initial public offering by Bayard. On
August 27, 1997 Bayard filed a registration statement for an initial public
offering of its common stock. Chesapeake, subsequent to the completion of the
transaction noted above, will own 4,194,000 shares of Bayard common stock (30.4%
of the common stock outstanding) and anticipates selling substantially all of
its ownership in Bayard in the IPO (assuming the over-allotment option is
exercised) and receiving repayment of the subordinated note. If successful,
assuming the sale of all of the Company's Bayard stock, and based on the initial
filing price of Bayard at $15 per share, the Company would receive total
proceeds of approximately $74 million (net of offering costs) and realize a
pre-tax gain of approximately $40 million. No assurance can be given, however,
that Bayard will successfully complete the initial public offering of its common
stock, at what price, or that the net proceeds or pre-tax gain discussed above
will be realized by the Company.
The Company also made investments in Louisiana Trend gas gathering and
processing facilities which it may sell during fiscal 1998. These investments
include a 50% interest in the Louisiana Austin Chalk Gathering System, and a
15.5% interest in the Masters Creek Gas Plant. If the Company decides to sell
these investments, the Company expects that the proceeds should exceed the
Company's cost basis of $16.8 million as of June 30, 1997.
The Company currently maintains no commercial bank credit facilities
because of its substantial working capital position, anticipated proceeds from
the sale of the investments described above, and expected cash flows from
operations as compared to the fiscal 1998 capital expenditure budget. Although
the Senior Note Indentures contain various restrictions on additional
indebtedness, based on asset values as of June 30, 1997, the Company estimates
it could borrow up to approximately $100 million of commercial bank debt within
these restrictions.
Debt ratings for the Senior Notes are Ba3 by Moody's Investors Service and
BB- by Standard & Poor's Corporation as of September 30, 1997. The Company's
long-term debt represented approximately 64% of total capital at June 30, 1997.
There are no scheduled principal payments required on any of the Senior Notes
until June 2002. The Company's goal is to achieve an equity to capital ratio of
at least 50% and to increase its credit ratings, ultimately achieving an
investment grade debt rating.
YEAR 2000
Year 2000 issues result from the inability of computer programs or
computerized equipment to accurately calculate, store or use a date subsequent
to December 31, 1999. The erroneous date can be interpreted in a number of
different ways; typically the year 2000 is represented as the year 1900. This
could result in a system failure or miscalculations causing disruptions of
operations, including, among other things, a temporary inability to process
transactions, send invoices, or engage in similar normal business.
22
<PAGE> 24
The Company has completed an assessment of its core financial and
operational software systems and has found them already in compliance, or the
necessary steps to bring them into compliance have been identified. These tasks
are scheduled for completion by September 1998. The Company believes that the
successful completion of these tasks will mitigate any critical Year 2000
issues. However, if these tasks are not completed on time, the Year 2000 issue
could have a material impact on the Company's ability to meet financial and
reporting requirements. It should not impact the Company's ability to continue
exploration, drilling, production, or sales activities.
Assessment of other less critical software systems and various types of
equipment is continuing and should be completed in March 1998. The Company
believes that the potential impact, if any, of these systems not being Year 2000
compliant will at most require employees to manually complete otherwise
automated tasks or calculations.
Following the completion of the aforementioned assessment, the Company will
initiate formal communication with its significant suppliers, business partners
and customers to determine the extent to which the Company is vulnerable to
those third parties' failure to correct their own Year 2000 issues. However,
there can be no guarantee that the systems of other companies on which the
Company's systems rely will be timely converted, or that a failure to convert by
another company, or a conversion that is incompatible with the Company's systems
would not have a material adverse effect on the Company. The Company has
determined it has no exposure to contingencies related to the Year 2000 issue
for the products it has sold.
The Company will utilize both internal and external resources to complete
tasks and perform testing necessary to address the Year 2000 issue. The Company
plans to complete the Year 2000 project no later than December 31, 1998.
Completion of the Year 2000 project is based on management's best estimates,
which were derived utilizing numerous assumptions of future events including the
continued availability of certain resources, third party modification plans and
other factors. However, there can be no guarantee that these estimates will be
achieved and actual results could differ materially from those plans. Specific
factors that might cause such material differences include, but are not limited
to, the availability and cost of personnel trained in this area, the ability to
locate and correct all relevant computer codes, and similar uncertainties.
FORWARD LOOKING STATEMENTS
The information contained in this Form 10-K includes certain
forward-looking statements. When used in this document, the words budget,
budgeted, anticipate, expects, estimates, believes, goals or projects and
similar expressions are intended to identify forward-looking statements. It is
important to note that Chesapeake's actual results could differ materially from
those projected by such forward-looking statements. Important factors that could
cause actual results to differ materially from those projected in the forward-
looking statements include, but are not limited to, the following: production
variances from expectations, volatility of oil and gas prices, the need to
develop and replace its reserves, the substantial capital expenditures required
to fund its operations, environmental risks, drilling and operating risks, risks
related to exploration and development drilling, the uncertainty inherent in
estimating future oil and gas production or reserves, competition, government
regulation, and the ability of the Company to implement its business strategy.
23
<PAGE> 25
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 Years Ended June
30, 1997 and 1996...................................... 25
Report of Independent Accountants for the Year Ended June
30, 1995............................................... 26
Consolidated Balance Sheets June 30, 1997 and 1996........ 27
Consolidated Statements of Operations for the Years Ended
June 30, 1997, 1996 and 1995........................... 28
Consolidated Statements of Cash Flows for the Years Ended
June 30, 1997, 1996 and 1995........................... 29
Consolidated Statements of Stockholders' Equity for the
Years Ended June 30, 1997, 1996 and 1995............... 31
Notes to Consolidated Financial Statements................ 32
</TABLE>
24
<PAGE> 26
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders
of Chesapeake Energy Corporation
We have audited the accompanying consolidated balance sheets of Chesapeake
Energy Corporation and its subsidiaries as of June 30, 1997 and 1996, and the
related consolidated statements of operations, stockholders' equity and cash
flows for the years then ended. These financial statements 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 in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audits 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. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Chesapeake
Energy Corporation and its subsidiaries as of June 30, 1997 and 1996, and the
consolidated results of their operations and their cash flows for the years then
ended in conformity with generally accepted accounting principles.
COOPERS & LYBRAND L.L.P.
Oklahoma City, Oklahoma
September 30, 1997
25
<PAGE> 27
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders
of Chesapeake Energy Corporation
In our opinion, the consolidated statements of operations, of cash flows
and of stockholders' equity for the year ended June 30, 1995 present fairly, in
all material respects, the results of operations and cash flows of Chesapeake
Energy Corporation and its subsidiaries for the year ended June 30, 1995, in
conformity with generally accepted accounting principles. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audit. We conducted our audit 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 audit provides a reasonable basis for the opinion expressed
above. We have not audited the consolidated financial statements of Chesapeake
Energy Corporation and its subsidiaries for any period subsequent to June 30,
1995.
PRICE WATERHOUSE LLP
Houston, Texas
September 20, 1995, except for the third paragraph of Note 9
which is as of October 9, 1997
26
<PAGE> 28
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
JUNE 30,
---------------------
1997 1996
--------- --------
($ IN THOUSANDS)
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents................................. $ 124,017 $ 51,638
Short-term investments.................................... 104,485 --
Accounts receivable:
Oil and gas sales....................................... 10,906 12,687
Oil and gas marketing sales............................. 19,939 6,982
Joint interest and other, net of allowances of $387,000
and $340,000, respectively............................ 25,311 27,661
Related parties......................................... 7,401 2,884
Inventory................................................. 4,854 5,163
Other..................................................... 692 2,158
--------- --------
Total Current Assets............................... 297,605 109,173
--------- --------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at cost based on full cost
accounting:
Evaluated oil and gas properties........................ 865,516 363,213
Unevaluated properties.................................. 128,505 165,441
Less: accumulated depreciation, depletion and
amortization.......................................... (431,983) (92,720)
--------- --------
562,038 435,934
Other property and equipment.............................. 50,379 18,162
Less: accumulated depreciation and amortization........... (5,051) (2,922)
--------- --------
Total Property and Equipment....................... 607,366 451,174
--------- --------
OTHER ASSETS................................................ 44,097 11,988
--------- --------
TOTAL ASSETS................................................ $ 949,068 $572,335
========= ========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Notes payable and current maturities of long-term debt.... $ 1,380 $ 6,755
Accounts payable.......................................... 86,817 54,514
Accrued liabilities and other............................. 28,701 14,062
Revenues and royalties due others......................... 29,428 33,503
--------- --------
Total Current Liabilities.......................... 146,326 108,834
--------- --------
LONG-TERM DEBT, NET......................................... 508,950 268,431
--------- --------
REVENUES AND ROYALTIES DUE OTHERS........................... 6,903 5,118
--------- --------
DEFERRED INCOME TAXES....................................... -- 12,185
--------- --------
CONTINGENCIES AND COMMITMENTS (NOTE 4)...................... -- --
--------- --------
STOCKHOLDERS' EQUITY:
Preferred Stock, $.01 par value, 10,000,000 shares
authorized; none issued................................. -- --
Common Stock, 100,000,000 shares authorized; par value of
$.01 and $.05 at June 30, 1997 and 1996, respectively;
70,276,975 and 60,159,826 shares issued and outstanding
at June 30, 1997 and 1996, respectively................. 703 3,008
Paid-in capital........................................... 432,991 136,782
Accumulated earnings (deficit)............................ (146,805) 37,977
--------- --------
Total Stockholders' Equity......................... 286,889 177,767
--------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.................. $ 949,068 $572,335
========= ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
27
<PAGE> 29
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
-------------------------------
1997 1996 1995
--------- -------- --------
($ IN THOUSANDS, EXCEPT
PER SHARE DATA)
-------------------------------
<S> <C> <C> <C>
REVENUES:
Oil and gas sales......................................... $ 192,920 $110,849 $ 56,983
Oil and gas marketing sales............................... 76,172 28,428 --
Oil and gas service operations............................ -- 6,314 8,836
Interest and other........................................ 11,223 3,831 1,524
--------- -------- --------
Total Revenues.......................................... 280,315 149,422 67,343
--------- -------- --------
COSTS AND EXPENSES:
Production expenses and taxes............................. 15,107 8,303 4,256
Oil and gas marketing expenses............................ 75,140 27,452 --
Oil and gas service operations............................ -- 4,895 7,747
Impairment of oil and gas properties...................... 236,000 -- --
Oil and gas depreciation, depletion and amortization...... 103,264 50,899 25,410
Depreciation and amortization of other assets............. 3,782 3,157 1,765
General and administrative................................ 8,802 4,828 3,578
Interest and other........................................ 18,550 13,679 6,627
--------- -------- --------
Total Costs and Expenses................................ 460,645 113,213 49,383
--------- -------- --------
INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY ITEM.... (180,330) 36,209 17,960
PROVISION (BENEFIT) FOR INCOME TAXES........................ (3,573) 12,854 6,299
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM..................... (176,757) 23,355 11,661
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt,
net of applicable income tax of $3,804.................. (6,620) -- --
--------- -------- --------
NET INCOME (LOSS)........................................... $(183,377) $ 23,355 $ 11,661
========= ======== ========
EARNINGS (LOSS) PER COMMON SHARE:
EARNINGS (LOSS) PER COMMON AND COMMON EQUIVALENT
SHARE-PRIMARY
Income (loss) before extraordinary item................. $ (2.69) $ 0.40 $ 0.21
Extraordinary item...................................... (0.10) -- --
--------- -------- --------
Net income (loss)....................................... $ (2.79) $ 0.40 $ 0.21
========= ======== ========
EARNINGS (LOSS) PER COMMON AND COMMON EQUIVALENT
SHARE-FULLY DILUTED
Income (loss) before extraordinary item................. $ (2.69) $ 0.40 $ 0.21
Extraordinary item...................................... (0.10) -- --
--------- -------- --------
Net income (loss)....................................... $ (2.79) $ 0.40 $ 0.21
========= ======== ========
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES
OUTSTANDING (IN 000'S)
Primary................................................. 65,767 58,342 55,872
========= ======== ========
Fully-diluted........................................... 65,767 58,922 56,606
========= ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
28
<PAGE> 30
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
-----------------------------------
1997 1996 1995
--------- --------- ---------
($ IN THOUSANDS)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)........................................... $(183,377) $ 23,355 $ 11,661
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO NET CASH
PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization.................. 105,591 52,768 26,628
Deferred taxes............................................ (3,573) 12,854 6,299
Amortization of loan costs................................ 1,455 1,288 548
Amortization of bond discount............................. 217 563 567
Bad debt expense.......................................... 299 114 308
Gain on sale of fixed assets.............................. (1,593) (2,511) (108)
Impairment of oil and gas assets.......................... 236,000 -- --
Extraordinary loss........................................ 6,620 -- --
Equity in earnings of oil field service company........... (499) -- --
CHANGES IN ASSETS AND LIABILITIES:
(Increase) decrease in short-term investments............. (102,858) 622 --
(Increase) decrease in accounts receivable................ (19,987) (3,524) (22,510)
(Increase) decrease in inventory.......................... (1,467) 78 (1,203)
(Increase) decrease in other current assets............... 1,466 (1,525) 614
Increase (decrease) in accounts payable, accrued
liabilities and other................................... 48,085 25,834 19,387
Increase (decrease) in current and non-current revenues
and royalties due others................................ (2,290) 11,056 12,540
--------- --------- ---------
Cash provided by operating activities................... 84,089 120,972 54,731
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration, development and acquisition of oil and gas
properties.............................................. (468,462) (342,045) (117,831)
Proceeds from sale of oil and gas equipment, leasehold and
other................................................... 3,095 6,167 11,953
Other proceeds from sales................................. 6,428 698 1,104
Long term loans made to third parties..................... (20,000)
Investment in oil field service company................... (3,048)
Investment in gas marketing company, net of cash
acquired................................................ -- (363) --
Other investments......................................... (8,000) -- --
Other property and equipment additions.................... (33,867) (8,846) (7,929)
--------- --------- ---------
Cash used in investing activities....................... (523,854) (344,389) (112,703)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of Common Stock.................... 288,091 99,498 --
Proceeds from long-term borrowings........................ 342,626 166,667 128,834
Payments on long-term borrowings.......................... (119,581) (48,634) (32,370)
Cash received from exercise of stock options.............. 1,387 1,989 818
Other financing........................................... (379) -- --
--------- --------- ---------
Cash provided by financing activities................... 512,144 219,520 97,282
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents........ 72,379 (3,897) 39,310
Cash and cash equivalents, beginning of period.............. 51,638 55,535 16,225
--------- --------- ---------
Cash and cash equivalents, end of period.................... $ 124,017 $ 51,638 $ 55,535
========= ========= =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAYMENTS FOR:
Interest.................................................. $ 25,854 $ 17,179 $ 6,488
Income taxes.............................................. $ -- $ -- $ --
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
29
<PAGE> 31
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS -- (CONTINUED)
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:
The Company has a financing arrangement with a vendor to supply certain oil
and gas equipment inventory. The total amounts owed at June 30, 1997, 1996 and
1995 were $1,380,000, $3,156,000 and $6,513,000, respectively. No cash
consideration is exchanged for inventory under this financing arrangement until
actual draws on the inventory are made.
In fiscal 1997, 1996 and 1995, the Company recognized income tax benefits
of $4,808,000, $7,950,000 and $1,229,000, 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 $150 million of 7.875% Senior Notes and $150
million of 8.5% Senior Notes in March 1997 are net of $6.4 million in offering
fees and expenses which were deducted from the actual cash received.
Proceeds from the issuances of $90 million of 10.5% Senior Notes in May
1995 and $120 million of 9.125% Senior Notes in April 1996 are net of $2.7
million and $3.9 million, respectively, in offering fees and expenses which were
deducted from the actual cash received.
On June 13, 1997 the Company declared a dividend of $0.02 per common share,
or $1,405,000, which was paid on July 15, 1997.
30
<PAGE> 32
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
--------------------------------
1997 1996 1995
--------- -------- -------
($ IN THOUSANDS)
<S> <C> <C> <C>
COMMON STOCK:
Balance, beginning of period........................... 3,008 58 51
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................. 12 79 7
Change in par value.................................... (2,407) 2,572 --
--------- -------- -------
Balance, end of period................................. 703 3,008 58
========= ======== =======
COMMON STOCK WARRANTS:
Balance, beginning of period........................... -- -- 5
Exercise of Common Stock Warrants...................... -- -- (5)
--------- -------- -------
Balance, end of period................................. -- -- --
--------- -------- -------
PAID-IN CAPITAL:
Balance, beginning of period........................... $ 136,782 $ 30,295 $28,243
Exercise of stock options and warrants................. 1,375 1,910 823
Issuance of Common Stock............................... 301,593 105,516 --
Offering expenses and other............................ (13,974) (6,317) --
Tax benefit from exercise of stock options............. 4,808 7,950 1,229
Change in par value.................................... 2,407 (2,572) --
--------- -------- -------
Balance, end of period................................. 432,991 136,782 30,295
========= ======== =======
ACCUMULATED EARNINGS (DEFICIT):
Balance, beginning of period........................... 37,977 14,622 2,961
Net income (loss)...................................... (183,377) 23,355 11,661
Dividends on common stock of $0.02 per share........... (1,405) -- --
--------- -------- -------
Balance, end of period................................. (146,805) 37,977 14,622
--------- -------- -------
TOTAL STOCKHOLDERS' EQUITY............................... $ 286,889 $177,767 $44,975
========= ======== =======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
31
<PAGE> 33
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 U.S. 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 primarily in Texas, Louisiana, Oklahoma,
Montana, North Dakota and New Mexico.
Principles of Consolidation
The accompanying consolidated financial statements of Chesapeake Energy
Corporation (the "Company" or "Parent") include the accounts of its wholly owned
subsidiaries Chesapeake Operating, Inc. ("COI"), Chesapeake Exploration Limited
Partnership ("CEX"), a limited partnership, Chesapeake Louisiana, L.P. ("CLLP"),
a limited partnership, Chesapeake Gas Development Corporation ("CGDC"),
Chesapeake Energy Marketing, Inc. ("CEMI"), Chesapeake Canada Corporation
("CCC"), Chesapeake Energy Louisiana Corporation ("CELC"), Lindsay Oil Field
Supply, Inc.("LOF"), Sander Trucking Company, Inc. ("STCO") and subsidiaries of
those entities. As of June 30, 1997, CGDC had been merged into CEX, and LOF and
STCO had been dissolved. All significant intercompany accounts and transactions
have been eliminated.
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
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 June 30, 1997, the Company had an unrealized holding loss of $0.6
million included in interest and other revenue. 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.
32
<PAGE> 34
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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. The
Company's oil and gas reserves are estimated annually by independent petroleum
engineers as well as the Company's internal engineers. The average composite
rates used for depreciation, depletion and amortization were $1.31, $0.85 and
$0.80 per equivalent Mcf in 1997, 1996, and 1995, 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. At June 30, 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 fourth quarter writedown in the carrying value of oil and gas
properties of $236 million.
Other Property and Equipment
Other property and equipment consists primarily of gas gathering and
processing facilities, vehicles, land, office buildings and equipment, and
software. Major renewals and betterments are capitalized while the costs of
repairs and maintenance are charged to expense as incurred. The costs of assets
retired or otherwise disposed of and the applicable accumulated depreciation are
removed from the accounts, and the resulting gain or loss is reflected in
operations. Other property and equipment costs are depreciated on both
straight-line and accelerated methods over the estimated useful lives of the
assets, which range from three to 30 years.
Leases
The Company has various operating leases primarily for transportation
equipment and field offices. Minimum lease payments under these operating leases
are as follows ($ in thousands):
<TABLE>
<CAPTION>
OPERATING
LEASES
---------
<S> <C>
1998............................................... $ 579
1999............................................... 500
2000............................................... 446
2001............................................... 446
2002............................................... 306
------
Total minimum lease payments....................... $2,277
======
</TABLE>
33
<PAGE> 35
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Capitalized Interest
During fiscal 1997, 1996 and 1995, interest of approximately $12,935,000,
$6,428,000 and $1,574,000 was capitalized on significant investments in unproved
properties that are not being currently depreciated, depleted, or amortized and
on which exploration activities are in progress.
Service Operations
Certain subsidiaries of the Company performed contractual 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 statements of operations include amounts derived from
certain of the contractual services provided. The Company's economic interest in
its oil and gas properties is 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 recorded as a
reduction in the Company's investment in Peak and will be amortized to income
over the estimated useful lives of the Peak assets. The Company's investment in
Peak is accounted for using the equity method.
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
Primary and fully diluted earnings (loss) per share for all periods have
been computed based upon the weighted average number of shares of Common Stock
outstanding after giving retroactive effect to all stock splits and the issuance
of common stock equivalents when their effect is dilutive. Dilutive options or
warrants which are issued during a period or which expire or are cancelled
during a period are reflected in both primary and fully diluted earnings per
share computations for the time they were outstanding during the period being
reported upon.
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 does not believe that
SFAS 128 will have a material impact on its earnings per share when adopted.
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
34
<PAGE> 36
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
ownership in the property. A liability is recognized only to the extent that the
Company has a net imbalance in excess of the reserves on the underlying
properties. The Company's net imbalance positions at June 30, 1997 and 1996 were
not material.
Hedging
The Company periodically uses certain instruments to hedge its exposure to
price fluctuations on oil and natural gas transactions. Recognized gains and
losses on hedge contracts are reported as a component of the related
transaction. Results for hedging transactions are reflected in oil and gas sales
to the extent related to the Company's oil and gas production (see Note 10).
Debt Issue Costs
Other assets include debt issue costs associated with the issuance of the
10.5% Senior Notes on May 25, 1995, the 9.125% Senior Notes on April 9, 1996,
and the 7.875% and 8.5% Senior Notes on March 17, 1997 (see Note 2). The
remaining unamortized costs on these issuances of Senior Notes at June 30, 1997
totaled $12.5 million and are being amortized over the life of the Senior Notes.
Stock Options
In October 1995, the Financial Accounting Standards Board issued Statement
No. 123 ("SFAS 123"), "Accounting for Stock Based Compensation". As permitted by
SFAS 123, the Company has continued its previous method of accounting for stock
compensation and has adopted the disclosure requirements of this Statement in
fiscal 1997.
Reclassifications
Certain reclassifications have been made to the consolidated financial
statements for the years ended June 30, 1996 and 1995 to conform to the
presentation used for the June 30, 1997 consolidated financial statements.
2. SENIOR NOTES
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 at the make-whole prices
determined in accordance with the indenture.
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 at the make-whole prices
determined in accordance with the indenture, or on or after March 15, 2004, at
the redemption price 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"). The 10.5% Senior Notes are
redeemable at the option of the Company at any time on or after June 1, 1999.
The Company may also redeem at its option at any time on or prior to June 1,
1998
35
<PAGE> 37
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
up to $30 million of the 10.5% Senior Notes at 110% of the principal amount
thereof with the proceeds of an equity offering.
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 10.5% 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 10.5%, 9.125%, 7.875% and 8.5% 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 10.5%
and 9.125% Senior Notes in the event of a change of control or certain asset
sales.
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.
As of and for the year ended June 30, 1997, the Guarantor Subsidiaries were
COI, CEX, CLLP, CELC and CGDC, and the Non-Guarantor Subsidiaries were CEMI and
CCC. Prior to fiscal 1997, the Guarantor Subsidiaries were COI, CEX and two
service company subsidiaries the assets of which were sold effective June 30,
1996, and the Non-Guarantor Subsidiaries were CGDC and CEMI (which was acquired
in December 1995).
36
<PAGE> 38
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF JUNE 30, 1997
($ IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
NON-
GUARANTOR GUARANTOR COMPANY
SUBSIDIARIES SUBSIDIARIES (PARENT) 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........ 33,486 1,904 14,989 -- 50,379
Less: accumulated depreciation,
depletion and amortization....... (436,276) -- (758) -- (437,034)
-------- ------- -------- --------- ---------
591,214 1,921 14,231 -- 607,366
-------- ------- -------- --------- ---------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES............... 817 -- 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
======== ======= ======== ========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
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>
37
<PAGE> 39
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF JUNE 30, 1996
($ IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
NON-
GUARANTOR GUARANTOR COMPANY
SUBSIDIARIES SUBSIDIARIES (PARENT) ELIMINATIONS CONSOLIDATED
------------ ------------ -------- ------------ ------------
<S> <C> <C> <C> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents............ $ 4,061 $ 2,751 $ 44,826 $ -- $ 51,638
Accounts receivable.................. 44,080 7,723 -- (1,589) 50,214
Inventory............................ 4,947 216 -- -- 5,163
Other................................ 2,155 3 -- -- 2,158
---------- ------- -------- --------- --------
Total Current Assets......... 55,243 10,693 44,826 (1,589) 109,173
---------- ------- -------- --------- --------
PROPERTY AND EQUIPMENT:
Oil and gas properties............... 338,610 24,603 -- -- 363,213
Unevaluated leasehold................ 165,441 -- -- -- 165,441
Other property and equipment......... 9,608 61 8,493 -- 18,162
Less: accumulated depreciation,
depletion and amortization........ (87,193) (8,007) (442) -- (95,642)
---------- ------- -------- --------- --------
426,466 16,657 8,051 -- 451,174
---------- ------- -------- --------- --------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES................ 519,386 8,132 382,388 (909,906) --
---------- ------- -------- --------- --------
OTHER ASSETS........................... 2,310 940 8,738 -- 11,988
---------- ------- -------- --------- --------
TOTAL ASSETS........................... $1,003,405 $36,422 $444,003 $(911,495) $572,335
========== ======= ======== ========= ========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Notes payable and current maturities
of long-term debt................. $ 3,846 $ 2,880 $ 29 $ -- $ 6,755
Accounts payable and other........... 91,069 7,339 5,260 (1,589) 102,079
---------- ------- -------- --------- --------
Total Current Liabilities.... 94,915 10,219 5,289 (1,589) 108,834
---------- ------- -------- --------- --------
LONG-TERM DEBT......................... 2,113 10,020 256,298 -- 268,431
---------- ------- -------- --------- --------
REVENUES AND ROYALTIES DUE OTHERS...... 5,118 -- -- -- 5,118
---------- ------- -------- --------- --------
DEFERRED INCOME TAXES.................. 23,950 1,335 (13,100) -- 12,185
---------- ------- -------- --------- --------
INTERCOMPANY PAYABLES.................. 824,307 8,182 73,647 (906,136) --
---------- ------- -------- --------- --------
STOCKHOLDERS' EQUITY:
Common Stock......................... 117 2 2,891 (2) 3,008
Other................................ 52,885 6,664 118,978 (3,768) 174,759
---------- ------- -------- --------- --------
53,002 6,666 121,869 (3,770) 177,767
---------- ------- -------- --------- --------
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY............................... $1,003,405 $36,422 $444,003 $(911,495) $572,335
========== ======= ======== ========= ========
</TABLE>
38
<PAGE> 40
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
NON-
GUARANTOR GUARANTOR COMPANY
SUBSIDIARIES SUBSIDIARIES (PARENT) 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
Interest and other......................................... 778 749 49,224 (39,528) 11,223
--------- --------- -------- --------- ---------
Total Revenues............................................. 192,081 146,691 49,224 (107,681) 280,315
--------- --------- -------- --------- ---------
COSTS AND EXPENSES:
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
Interest................................................... 37,644 10 20,424 (39,528) 18,550
--------- --------- -------- --------- ---------
Total Costs & Expenses..................................... 400,480 144,304 23,542 (107,681) 460,645
--------- --------- -------- --------- ---------
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
Interest and other....................................... 1,917 238 1,676 -- 3,831
--------- --------- -------- --------- ---------
111,943 42,095 1,676 (6,292) 149,422
--------- --------- -------- --------- ---------
COSTS AND EXPENSES:
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
Interest and other....................................... 508 711 12,460 -- 13,679
--------- --------- -------- --------- ---------
66,900 38,336 14,269 (6,292) 113,213
--------- --------- -------- --------- ---------
Income (loss) before income taxes........................ 45,043 3,759 (12,593) -- 36,209
Income tax expense (benefit)............................. 15,990 1,335 (4,471) -- 12,854
Net income (loss)........................................ $ 29,053 $ 2,424 $(8,122) $ -- $ 23,355
========= ========= ======== ========= =========
FOR THE YEAR ENDED JUNE 30, 1995:
REVENUES:
Oil and gas sales........................................ $ 55,417 $ 1,566 $ -- $ -- $ 56,983
Oil and gas service operations........................... 8,836 -- -- -- 8,836
Interest and other....................................... 1,394 -- 130 -- 1,524
--------- --------- -------- --------- ---------
65,647 1,566 130 -- 67,343
--------- --------- -------- --------- ---------
COSTS AND EXPENSES:
Production expenses and taxes............................ 4,045 211 -- -- 4,256
Oil and gas service operations........................... 7,747 -- -- -- 7,747
Oil and gas depreciation, depletion and amortization..... 24,775 635 -- -- 25,410
Other depreciation and amortization...................... 1,245 5 515 -- 1,765
General and administrative............................... 2,620 58 900 -- 3,578
Interest and other....................................... 570 184 5,873 -- 6,627
--------- --------- -------- --------- ---------
41,002 1,093 7,288 -- 49,383
--------- --------- -------- --------- ---------
Income (loss) before income taxes........................ 24,645 473 (7,158) -- 17,960
Income tax expense (benefit)............................. 8,639 165 (2,505) -- 6,299
--------- --------- -------- --------- ---------
Net Income (loss)........................................ $ 16,006 $ 308 $(4,653) $ -- $ 11,661
========= ========= ======== ========= =========
</TABLE>
39
<PAGE> 41
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)
<TABLE>
<CAPTION>
GUARANTOR NON-GUARANTOR COMPANY
SUBSIDIARIES SUBSIDIARIES (PARENT) 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
========= ======== ========= ======== =========
FOR THE YEAR ENDED JUNE 30, 1995:
CASH FLOWS FROM OPERATING ACTIVITIES................ $ 60,049 $ 305 $ (4,692) $ (931) $ 54,731
--------- -------- --------- -------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties............................ (113,722) (4,109) -- -- (117,831)
Proceeds from sales............................... 24,557 -- -- (11,500) 13,057
Purchase of oil and gas properties................ -- (11,500) -- 11,500 --
Other additions................................... (7,929) -- -- -- (7,929)
--------- -------- --------- -------- ---------
(97,094) (15,609) -- -- (112,703)
--------- -------- --------- -------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings.......................... 30,034 11,500 87,300 -- 128,834
Payments on borrowings............................ (32,032) (700) 362 -- (32,370)
Intercompany advances, net........................ 78,324 4,509 (83,764) 931 --
Other financing................................... -- -- 818 -- 818
--------- -------- --------- -------- ---------
76,326 15,309 4,716 931 97,282
--------- -------- --------- -------- ---------
Net increase (decrease) in cash and cash
equivalents....................................... 39,281 5 24 -- 39,310
Cash, beginning of period........................... 13,946 -- 2,279 -- 16,225
--------- -------- --------- -------- ---------
Cash, end of period................................. $ 53,227 $ 5 $ 2,303 $ -- $ 55,535
========= ======== ========= ======== =========
</TABLE>
40
<PAGE> 42
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
3. NOTES PAYABLE AND LONG-TERM DEBT
Notes payable and long-term debt consist of the following:
<TABLE>
<CAPTION>
JUNE 30,
--------------------
1997 1996
-------- --------
($ IN THOUSANDS)
<S> <C> <C>
7.875% Senior Notes (see Note 2).......................... $150,000 $ --
Discount on 7.875% Senior Notes........................... (115) --
8.5% Senior Notes (see Note 2)............................ 150,000 --
Discount on 8.5% Senior Notes............................. (862) --
9.125% Senior Notes (see Note 2).......................... 120,000 120,000
Discount on 9.125% Senior Notes........................... (73) (81)
10.5% Senior Notes (see Note 2)........................... 90,000 90,000
12% Senior Notes.......................................... -- 47,500
Discount on 12% Senior Notes.............................. -- (1,772)
Term note payable to Union Bank collateralized by CGDC,
not guaranteed by the Company, variable interest at
Union Bank's base rate (8.25% per annum at June 30,
1996), or at Eurodollar rate +1.875% collateralized by
CGDC's producing oil and gas properties, payable in
monthly installments through November 2002............. -- 12,900
Note payable to a vendor, collateralized by oil and gas
tubulars, payments due 60 days from shipment of the
tubulars.................................................. 1,380 3,156
Note payable to a bank, variable interest at a referenced
base rate + 1.75% (10% per annum at June 30, 1996),
collateralized by office buildings, payments due in
monthly installments through May 1998.................. -- 680
Notes payable to various entities to acquire oil service
equipment, interest varies from 7% to 11% per annum,
collateralized by equipment, payments due in monthly
installments through December 2000........................ -- 1,212
Other collateralized...................................... -- 1,469
Other unsecured............................................. -- 122
-------- --------
Total notes payable and long-term debt...................... 510,330 275,186
Less -- Current maturities.................................. (1,380) (6,755)
-------- --------
Notes payable and long-term debt, net of current
maturities................................................ $508,950 $268,431
======== ========
</TABLE>
The aggregate scheduled maturities of notes payable and long-term debt for
the next five fiscal years ending June 30, 2002 and thereafter were as follows
as of June 30, 1997 (in thousands of dollars):
<TABLE>
<S> <C>
1998............................................ $ 1,380
1999............................................ --
2000............................................ --
2001............................................ --
2002............................................ 90,000
After 2002...................................... 418,950
--------
$510,330
========
</TABLE>
During the quarter ended December 31, 1996, the Company exercised its
covenant defeasance rights with respect to all of its outstanding $47.5 million
of 12% Senior Notes due 2001. A combination of cash and non-
41
<PAGE> 43
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
callable U.S. Government Securities in the amount of $55.0 million was
irrevocably deposited in trust to satisfy the Company's obligations, including
accrued but unpaid interest through the date of defeasance of $1.3 million.
4. CONTINGENCIES AND COMMITMENTS
The Company and certain of its officers and directors are currently
involved in various purported class actions alleging violations of the
Securities Exchange Act of 1934. The plaintiffs assert that the defendants made
materially false and misleading statements and failed to disclose material facts
about the success of the Company's exploration efforts, principally in the
Louisiana Trend. As a result, the complaints allege, the price of the Company's
common stock was artificially inflated during periods beginning as early as
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 common stock during the class period when they knew or should
have known adverse nonpublic information. Each case seeks a determination that
the suit is a proper class action, certification of the plaintiff as a class
representative and damages in an unspecified amount, together with costs of
litigation, including attorneys' fees. The Company and the individual defendants
believe that these actions are without merit, and intend to defend against them
vigorously. No estimate of loss or range of estimate of loss, if any, can be
made at this time.
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 (a) infringement and inducing infringement
of UPRC's claim to a patent (the "UPRC Patent") for an invention involving a
method of maintaining a borehole in a stratigraphic zone during drilling, and
(b) tortious interference with certain business relations between UPRC and
certain of its former employees. UPRC's claims against the Company are based on
services provided by a third party vendor to the Company. 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
requested the court to declare the UPRC Patent invalid. The Company has also
filed a motion to limit the scope of UPRC's claims and for summary judgment. No
estimate of loss or range of estimate of loss, if any, can be made at this time.
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, 1998
through June 30, 2000.
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.
As of June 30, 1997, the Company had guaranteed $1.3 million of debt owed
by Peak.
42
<PAGE> 44
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. INCOME TAXES
The components of the income tax provision (benefit) for each of the
periods are as follows:
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
----------------------------
1997 1996 1995
------- ------- ------
($ IN THOUSANDS)
<S> <C> <C> <C>
Current................................................ $ -- $ -- $ --
Deferred............................................... (3,573) 12,854 6,299
------- ------- ------
Total........................................ $(3,573) $12,854 $6,299
======= ======= ======
</TABLE>
The effective income tax rate differed from the computed "expected" federal
income tax rate on earnings before income taxes for the following reasons:
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
-----------------------------
1997 1996 1995
-------- ------- ------
($ IN THOUSANDS)
<S> <C> <C> <C>
Computed "expected" income tax provision (benefit).... $(63,116) $12,673 $6,286
Tax percentage depletion.............................. (294) (238) (144)
Valuation allowance................................... 64,116 -- --
State income taxes and other.......................... (4,279) 419 157
-------- ------- ------
$ (3,573) $12,854 $6,299
======== ======= ======
</TABLE>
Deferred income taxes are provided to reflect temporary differences in the
basis of net assets for income tax and financial reporting purposes. The tax
effected temporary differences and tax loss carryforwards which comprise
deferred taxes are as follows:
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
--------------------------------
1997 1996 1995
-------- -------- --------
($ IN THOUSANDS)
<S> <C> <C> <C>
Deferred tax liabilities:
Acquisition, exploration and development costs and
related depreciation, depletion and
amortization..................................... $(49,831) $(63,725) $(31,220)
Deferred tax assets:
Net operating loss carryforwards................... 112,889 50,776 23,414
Percentage depletion carryforward.................. 1,058 764 526
-------- -------- --------
113,947 51,540 23,940
-------- -------- --------
Net deferred tax asset (liability)................. $ 64,116 $(12,185) $ (7,280)
Less: Valuation allowance.......................... (64,116) -- --
-------- -------- --------
Total deferred tax asset (liability)............... $ -- $(12,185) $ (7,280)
======== ======== ========
</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 the fourth quarter of fiscal 1997, the Company recorded a
$236 million write-down related to the impairment of oil and gas properties.
This write-down and significant tax net operating loss carryforwards (caused
primarily by expensing intangible drilling costs for tax purposes) result in a
net deferred tax asset at 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, based in part on the Company's continued drilling
efforts. Therefore, the Company has recorded a valuation allowance equal to the
net deferred tax asset.
43
<PAGE> 45
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
At June 30, 1997, the Company had regular tax net operating loss
carryforwards of approximately $300 million and alternative minimum tax net
operating loss carryforwards of approximately $45 million. These loss
carryforward amounts will expire during the years 2007 through 2012. The Company
also had a percentage depletion carryforward of approximately $2.8 million at
June 30, 1997, 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 an
Ownership Change. However, management believes this will not result in a
significant limitation of the utilization of the 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 June 30, 1997, 1996 and 1995 the Company had accounts receivable
for these costs of $7.4 million, $2.9 million and $4.4 million, respectively.
During fiscal 1997, 1996 and 1995 the Company incurred legal expenses of
$207,000, $347,000 and $516,000, respectively, for legal services provided by
the 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 up to
10% of the employees' annual salary with the Company's common stock. The amount
of employee contributions is limited as specified in the plan. The Company may,
at its discretion, make additional contributions to the plan. The Company
contributed $603,000, $187,000 and $95,000 to the plan during the fiscal years
ended June 30, 1997, 1996 and 1995, respectively.
8. MAJOR CUSTOMERS
Sales to individual customers constituting 10% or more of total oil and gas
sales were as follows:
<TABLE>
<CAPTION>
PERCENT OF
YEAR AMOUNT OIL AND GAS SALES
- ---- ---------------- -----------------
($ IN THOUSANDS)
<S> <C> <C> <C>
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%
1995 Aquila Southwest Pipeline Corporation $18,548 33%
Wickford Energy Marketing, L.C. $15,704 28%
GPM Gas Corporation $11,686 21%
</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.
44
<PAGE> 46
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. STOCKHOLDERS' EQUITY AND STOCK BASED COMPENSATION
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, which resulted in net
proceeds to the Company of approximately $288.1 million.
On April 12, 1996 the Company completed a public offering of 5,989,500
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 1994, a 3-for-2 stock
split of the Common Stock in December 1995 and June 1996, and a 2-for-1 stock
split of the Common Stock in December 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 may 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 may be granted under the
NSO Plan after December 10, 2002.
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 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 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 may 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 fiscal 1997 and 1996, respectively:
45
<PAGE> 47
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
interest rates (zero-coupon U.S. government issues with a remaining life equal
to the expected term of the options) of 6.74% and 6.21%; dividend yields of 0.9%
and 0.9%; volatility factors of the expected market price of the Company's
common stock of .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 JUNE 30,
----------------------
1997 1996
---------- --------
(IN THOUSANDS, EXCEPT
PER SHARE AMOUNTS)
<S> <C> <C>
Net Income (Loss)
As reported............................................... $(183,377) $23,355
Pro forma................................................. (190,160) 22,081
Earnings (Loss) per Share
As reported............................................... $ (2.79) $ 0.40
Pro forma................................................. (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 generally 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 JUNE 30,
---------------------------------------------------------------------------------------
1997 1996 1995
--------------------------- --------------------------- ---------------------------
WEIGHTED-AVG WEIGHTED-AVG WEIGHTED-AVG
OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE
---------- -------------- ---------- -------------- ---------- --------------
<S> <C> <C> <C> <C> <C> <C>
Outstanding -- Beginning of Year....... 7,602,884 $ 4.66 6,828,592 $1.97 5,033,340 $0.72
Granted................................ 3,564,884 19.35 2,426,850 9.98 3,185,550 3.38
Exercised.............................. (1,197,998) 1.95 (1,574,046) 1.31 (1,288,732) 0.67
Forfeited.............................. (2,066,111) 22.26 (78,512) 2.61 (101,566) 0.92
---------- ------ ---------- ----- ---------- -----
Outstanding -- End of Year............. 7,903,659 7.09 7,602,884 4.66 6,828,592 1.97
---------- ------ ---------- ----- ---------- -----
Exercisable -- End of Year............. 3,323,824 2,974,386 2,489,742
---------- ---------- ----------
Shares Authorized for Future Grants.... 5,212,056 713,826 3,102,982
---------- ---------- ----------
Fair Value of Options Granted During
the Year............................. $ 7.51 $4.84 N/A
------ -----
</TABLE>
46
<PAGE> 48
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes information about stock options outstanding
at June 30, 1997:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
----------------------------------------------- ----------------------------
NUMBER WEIGHTED-AVG. NUMBER
RANGE OF OUTSTANDING REMAINING WEIGHTED-AVG. EXERCISABLE WEIGHTED-AVG.
EXERCISE PRICES 6/30/97 CONTRACTUAL LIFE EXERCISE PRICE 6/30/97 EXERCISE PRICE
--------------- ----------- ---------------- -------------- ----------- --------------
<S> <C> <C> <C> <C> <C>
$ 0.56-$ 0.67..................... 843,767 5.36 $ 0.59 843,767 $ 0.59
$ 0.71-$ 1.33..................... 784,116 4.36 $ 1.00 784,116 $ 1.00
$ 2.25-$ 2.25..................... 1,128,883 7.30 $ 2.25 406,183 $ 2.25
$ 2.43-$ 4.92..................... 408,689 7.43 $ 3.15 394,159 $ 3.08
$ 4.92-$ 4.92..................... 974,910 7.82 $ 4.92 390,774 $ 4.92
$ 5.67-$ 5.67..................... 1,213,534 8.17 $ 5.67 217,140 $ 5.67
$ 6.47-$ 6.47..................... 180,000 8.28 $ 6.47 180,000 $ 6.47
$14.25-$14.25..................... 1,513,010 9.82 $14.25 0 $ 0.00
$14.75-$25.88..................... 756,750 6.30 $17.85 7,685 $17.67
$30.63-$30.63..................... 100,000 9.27 $30.63 100,000 $30.63
$ 0.56-$30.63..................... 7,903,659 7.44 $ 7.09 3,323,824 $ 3.29
</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 fiscal 1997, 1996 and 1995, $4,808,000, $7,950,000 and $1,229,000,
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 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 (1)
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,
(2) 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, (3) 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 (4) basis protection swaps. Results from hedging transactions are reflected
in oil and gas sales to the extent related to the Company's oil and gas
production. The Company has not entered into hedging transactions unrelated to
the Company's oil and gas production or physical purchase or sale commitments.
47
<PAGE> 49
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As of June 30, 1997, the Company had the following oil swap arrangements
for periods after June 1997:
<TABLE>
<CAPTION>
NYMEX-INDEX
MONTH VOLUME (BBLS) STRIKE PRICE (PER BBL)
----- ------------- ----------------------
<S> <C> <C>
July 1997........................................... 31,000 $18.60
August 1997......................................... 31,000 $18.43
September 1997...................................... 30,000 $18.30
October 1997........................................ 31,000 $18.19
November 1997....................................... 30,000 $18.13
December 1997....................................... 31,000 $18.08
January through June 1998........................... 724,000 $19.82
</TABLE>
The Company entered into oil swap arrangements to cancel the effect of the
swaps for the months of August through December at an average price of $21.07
per Bbl.
As of June 30, 1997, the Company had the following gas swap arrangements
for periods after June 1997:
<TABLE>
<CAPTION>
HOUSTON SHIP CHANNEL
MONTHS VOLUME (MMBTU) INDEX STRIKE PRICE (PER MMBTU)
------ -------------- ------------------------------
<S> <C> <C>
July 1997.............................. 1,240,000 $2.313
August 1997............................ 1,240,000 $2.301
September 1997......................... 1,200,000 $2.285
October 1997........................... 1,240,000 $2.300
</TABLE>
The Company entered into gas swap arrangements to cancel the effect of the
swaps for the months of July through October at an average price of $2.133 per
MMBtu.
The Company has entered into a curve lock for 4.9 Bcf of gas which allows
the Company the option to hedge April 1999 through November 1999 gas based upon
a negative $0.285 differential to December 1998 gas any time between the strike
date and December 1998. A curve lock is a swap arrangement which allows the
Company to hedge the price differential between one commodity contract period
and another.
Gains or losses on the crude oil and natural gas hedging transactions,
including "cancelled" swaps, are not recognized immediately in income, but are
deferred and recognized as price adjustments in the month of related future
production. The Company estimates that had all of the crude oil and natural gas
swap agreements in effect for production periods beginning July 1, 1997
terminated on June 30, 1997, based on the closing prices for NYMEX futures
contracts as of that date, the Company would have paid the counterparty
approximately $185,000, which would have represented the "fair value" at that
date. These agreements were not terminated. The fair value of hedging
instruments at June 30, 1996 was a loss of approximately $4.6 million.
Periodically, the Company's oil and gas marketing subsidiary CEMI 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.
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
48
<PAGE> 50
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 not considered investment grade, 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 carrying value of financial instruments included in noncurrent
other assets approximates fair value at June 30, 1997. 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 June 30, 1997 and 1996 was $508.9
million and $255.6 million, respectively, compared to approximate fair values of
$514.1 million and $261.2 million, respectively. The carrying value of other
long-term debt approximates its fair value as interest rates are primarily
variable, based on prevailing market rates.
11. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
Net Capitalized Costs
Evaluated and unevaluated capitalized costs related to the Company's oil
and gas producing activities are summarized as follows:
<TABLE>
<CAPTION>
JUNE 30,
--------------------
1997 1996
-------- --------
($ IN THOUSANDS)
<S> <C> <C>
Oil and gas properties:
Proved.................................................... $865,516 $363,213
Unproved.................................................. 128,505 165,441
-------- --------
Total............................................. 994,021 528,654
Less accumulated depreciation, depletion and amortization... (431,983) (92,720)
-------- --------
Net capitalized costs....................................... $562,038 $435,934
======== ========
</TABLE>
Unproved properties not subject to amortization at June 30, 1997 and 1996
consisted mainly of lease acquisition costs. The Company capitalized
approximately $12,935,000 and $6,428,000 of interest during the years ended June
30, 1997 and 1996 on significant investments in unproved properties that were
not being depreciated, depleted, or amortized and on which exploration or
development activities were not in progress. The Company will continue to
evaluate its unevaluated properties, however, the timing of the ultimate
evaluation and disposition of the properties has not been determined.
49
<PAGE> 51
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Costs Incurred in Oil and Gas Acquisition, Exploration and Development
Costs incurred in oil and gas property acquisition, exploration and
development activities which have been capitalized are summarized as follows:
<TABLE>
<CAPTION>
JUNE 30,
--------------------------------
1997 1996 1995
-------- -------- --------
($ IN THOUSANDS)
<S> <C> <C> <C>
Development costs........................................ $187,736 $138,188 $ 78,679
Exploration costs........................................ 136,473 39,410 14,129
Acquisition costs:
Unproved properties.................................... 140,348 138,188 24,437
Proved properties...................................... -- 24,560 --
Capitalized internal costs............................... 3,905 1,699 586
Proceeds from sale of leasehold, equipment and other..... (3,095) (6,167) (11,953)
-------- -------- --------
Total........................................... $465,367 $335,878 $105,878
======== ======== ========
</TABLE>
Results of Operations from Oil and Gas Producing Activities (unaudited)
The Company's results of operations from oil and gas producing activities
are presented below for the years ended June 30, 1997, 1996 and 1995,
respectively. The following table includes revenues and expenses associated
directly with the Company's oil and gas producing activities. It does not
include any allocation of the Company's interest costs and, therefore, is not
necessarily indicative of the contribution to consolidated net operating results
of the Company's oil and gas operations.
<TABLE>
<CAPTION>
JUNE 30,
---------------------------------
1997 1996 1995
--------- -------- --------
($ IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas sales...................................... $ 192,920 $110,849 $ 56,983
Production costs (a)................................... (15,107) (8,303) (4,256)
Impairment of oil and gas properties................... (236,000) -- --
Depletion and depreciation............................. (103,264) (50,899) (25,410)
Imputed income tax (provision) benefit(b).............. 60,544 (18,335) (9,561)
--------- -------- --------
Results of operations from oil
and gas producing activities......................... $(100,907) $ 33,312 $ 17,756
========= ======== ========
</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.
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. At 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 a fourth quarter 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
the independent petroleum engineering firm of Williamson Petroleum Consultants,
Inc. ("Williamson") and the Company's petroleum engineers as of June 30, 1997,
1996 and 1995. The reserves evaluated internally by the Company constituted
50
<PAGE> 52
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
approximately 50.0%, 0.6% and 0.5% of total proved reserves as of June 30, 1997,
1996 and 1995, respectively. 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, 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. All of the
Company's oil and gas reserves are located in the United States.
Presented below is a summary of changes in estimated reserves of the
Company based upon the reports prepared by Williamson and the Company's
petroleum engineers for 1997, 1996 and 1995:
<TABLE>
<CAPTION>
JUNE 30,
-------------------------------------------------------
1997 1996 1995
----------------- ---------------- ----------------
OIL GAS OIL GAS OIL GAS
(MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF)
------ -------- ------ ------- ------ -------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves, beginning of
year............................ 12,258 351,224 5,116 211,808 4,154 117,066
Extensions, discoveries and other
additions....................... 13,874 147,485 8,781 158,052 2,549 138,372
Revisions of previous estimate.... (5,989) (137,938) (669) 12,987 (448) (18,516)
Production........................ (2,770) (62,005) (1,413) (51,710) (1,139) (25,114)
Sale of reserves-in-place......... -- -- -- -- -- --
Purchase of reserves-in-place..... -- -- 443 20,087 -- --
------ -------- ------ ------- ------ -------
Proved reserves, end of year...... 17,373 298,766 12,258 351,224 5,116 211,808
====== ======== ====== ======= ====== =======
Proved developed reserves,
end of year..................... 7,324 151,879 3,648 144,721 1,973 77,764
====== ======== ====== ======= ====== =======
</TABLE>
As of the fiscal year ended June 30, 1997, the Company recorded revisions
to the previous years' reserve estimates of approximately six million barrels of
oil and 138 million Mcf, or approximately 174 Bcfe. The reserve revisions are
primarily attributable to the decrease in oil and gas pricing between periods,
escalating development costs at June 30, 1997, and unfavorable developmental
drilling and production results during fiscal 1997. Specifically, the Company
recorded downward adjustments to proved reserves of 159 Bcfe in 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 $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 in the current year 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.
In prior years, the Company reported "Extensions, discoveries and other
additions" net of current year production related thereto. The Company began
reporting this category inclusive of current year production in fiscal 1997 and
restated fiscal 1996 and fiscal 1995 quantities accordingly. A corresponding
change in fiscal
51
<PAGE> 53
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
1996 and fiscal 1995 was recorded to "Revisions of previous estimate" with no
net change to year-end reserve quantities.
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 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>
JUNE 30,
------------------------------------
1997 1996 1995
--------- ---------- ---------
($ IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows............................. $ 954,839 $1,101,642 $ 427,377
Future production costs......................... (190,604) (168,974) (75,927)
Future development costs........................ (152,281) (137,068) (76,543)
Future income tax provision..................... (104,183) (135,543) (51,789)
--------- ---------- ---------
Future net cash flows........................... 507,771 660,057 223,118
Less effect of a 10% discount factor............ (92,273) (198,646) (63,207)
--------- ---------- ---------
Standardized measure of discounted future net
cash flows.................................... $ 415,498 $ 461,411 $ 159,911
========= ========== =========
</TABLE>
52
<PAGE> 54
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The principal sources of change in the standardized measure of discounted
future net cash flows are as follows:
<TABLE>
<CAPTION>
JUNE 30,
--------------------------------
1997 1996 1995
--------- --------- --------
($ IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure, beginning of year............ $ 461,411 $ 159,911 $118,608
Sales of oil and gas produced, net of production
costs............................................ (177,813) (102,546) (52,727)
Net changes in prices and production costs......... (99,234) 88,729 (24,807)
Extensions and discoveries, net of production and
development costs................................ 287,068 275,916 108,644
Changes in future development costs................ (12,831) (11,201) 3,406
Development costs incurred during the period that
reduced future development costs................. 46,888 43,409 23,678
Revisions of previous quantity estimates........... (199,738) 12,728 (21,595)
Purchase of reserves-in-place...................... -- 29,641 --
Accretion of discount.............................. 54,702 18,814 14,126
Net change in income taxes......................... 63,719 (57,382) (5,586)
Changes in production rates and other.............. (8,674) 3,392 (3,836)
--------- --------- --------
Standardized measure, end of year.................. $ 415,498 $ 461,411 $159,911
========= ========= ========
</TABLE>
For an explanation of the reclassifications made to the standardized
measure of discounted future net cash flows in fiscal 1996 and fiscal 1995, see
discussion of Oil and Gas Reserve Quantities included above.
53
<PAGE> 55
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
12. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized unaudited quarterly financial data for fiscal 1997 and 1996 are
as follows ($ in thousands except per share data):
<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)
Net income (loss) before extraordinary
item................................ 8,204 10,274 15,928 (217,783)
Net income (loss) per share before
extraordinary item:
Primary............................. .13 .15 .22 (3.12)
Fully-diluted....................... .13 .15 .22 (3.12)
</TABLE>
<TABLE>
<CAPTION>
QUARTER ENDED
----------------------------------------------------
SEPTEMBER 30, DECEMBER 31, MARCH 31, JUNE 30,
1995 1995 1996 1996
------------- ------------ --------- ---------
<S> <C> <C> <C> <C>
Net sales............................. $21,988 $31,766 $44,145 $ 47,692
Gross profit(a)....................... 6,368 11,368 14,741 13,580
Net income............................ 2,915 5,459 7,623 7,358
Net income per share:
Primary............................. .05 .10 .13 .12
Fully-diluted....................... .05 .09 .13 .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, can 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. At 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 a fourth
quarter writedown in the carrying value of oil and gas properties of $236
million.
54
<PAGE> 56
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:
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
3.1 -- Registrant's Certificate of Incorporation. Incorporated
herein by reference to Exhibit 3.1 to Registrant's
quarterly report on Form 10-Q for the quarter ended
December 31, 1996.
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 registration statement on Form S-4 (No.
333-24995).
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).
4.3 -- Indenture dated as of May 15, 1995 among Chesapeake
Energy Corporation, its subsidiaries signatory thereto as
Subsidiary Guarantors and United States Trust Company of
New York, as Trustee, with respect to 10.5% Senior Notes
due 2002. Incorporated herein by reference to Exhibit 4.3
to Registrant's registration statement on Form S-4 (No.
33-93718).
4.4 -- Indenture dated April 1, 1996 among Chesapeake Energy
Corporation, its subsidiaries signatory thereto as
Subsidiary Guarantors and United States Trust Company of
New York, as Trustee, with respect to 9.125% Senior Notes
due 2006. Incorporated herein by reference to Exhibit 4.6
to Registrant's registration statement on Form S-3
Registration Statement (No. 333-1588)
4.5 -- Agreement to furnish copies of unfiled long-term debt
instruments.
4.8 -- Stock Registration Agreement dated May 21, 1992 between
Chesapeake Energy Corporation and various lenders, as
amended by First Amendment thereto dated May 26, 1992.
Incorporated herein by reference to Exhibits 10.26.1 and
10.26.2 to Registrant's registration statement on Form
S-1 (No. 33-55600).
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).
</TABLE>
55
<PAGE> 57
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
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.
10.2.1+ -- Employment Agreement dated as of July 1, 1997 between
Aubrey K. McClendon and Chesapeake Energy Corporation.
10.2.2+ -- Employment Agreement dated as of July 1, 1997 between Tom
L. Ward and Chesapeake Energy Corporation.
10.2.3+ -- Employment Agreement dated as of July 1, 1997 between
Marcus C. Rowland and Chesapeake Energy Corporation.
10.2.4+ -- Employment Agreement dated as of July 1, 1995 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, 1995.
10.2.5+ -- Employment Agreement dated as of July 1, 1997 between J.
Mark Lester and Chesapeake Energy Corporation.
10.2.6+ -- Employment Agreement dated as of July 1, 1997 between
Henry J. Hood and Chesapeake Energy Corporation.
10.2.7+ -- Employment Agreement dated as of July 1, 1997 between
Ronald A. Lefaive and Chesapeake Energy Corporation.
10.2.8+ -- Employment Agreement dated as of July 1, 1997 between
Martha A. Burger and Chesapeake Energy Corporation.
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).
10.9 -- 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 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.
11 -- Statement of Net Income (Loss) Per Share.
</TABLE>
56
<PAGE> 58
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
21 -- Subsidiaries of Registrant
23.1* -- Consent of Coopers & Lybrand L.L.P.
23.2* -- Consent of Price Waterhouse LLP
23.3* -- Consent of Williamson Petroleum Consultants, Inc.
27 -- Financial Data Schedule
</TABLE>
- ---------------
* Filed herewith.
+ Management contract or compensatory plan or arrangement.
(b) Reports on Form 8-K
During the quarter ended June 30, 1997, the Company filed the following
Current Reports on Form 8-K dated
April 2, 1997 announcing the completion of its Brown #1-H in Washington
County, Texas,
April 24, 1997 reporting third quarter and first nine months fiscal 1997
results, and
June 27, 1997 announcing refocused Louisiana drilling program and expected
asset writedown.
57
<PAGE> 59
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this amendment on Form
10-K/A to be signed on its behalf by the undersigned thereunto duly authorized
on February 11, 1998.
CHESAPEAKE ENERGY CORPORATION
By /s/ MARCUS C. ROWLAND
-----------------------------------
Marcus C. Rowland
Senior Vice President -- Finance
and
Chief Financial Officer
(Principal Financial Officer)
58
<PAGE> 60
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
3.1 -- Registrant's Certificate of Incorporation. Incorporated
herein by reference to Exhibit 3.1 to Registrant's
quarterly report on Form 10-Q for the quarter ended
December 31, 1996.
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 registration statement on Form S-4 (No.
333-24995).
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).
4.3 -- Indenture dated as of May 15, 1995 among Chesapeake
Energy Corporation, its subsidiaries signatory thereto as
Subsidiary Guarantors and United States Trust Company of
New York, as Trustee, with respect to 10.5% Senior Notes
due 2002. Incorporated herein by reference to Exhibit 4.3
to Registrant's registration statement on Form S-4 (No.
33-93718).
4.4 -- Indenture dated April 1, 1996 among Chesapeake Energy
Corporation, its subsidiaries signatory thereto as
Subsidiary Guarantors and United States Trust Company of
New York, as Trustee, with respect to 9.125% Senior Notes
due 2006. Incorporated herein by reference to Exhibit 4.6
to Registrant's registration statement on Form S-3
Registration Statement (No. 333-1588)
4.5 -- Agreement to furnish copies of unfiled long-term debt
instruments.
4.8 -- Stock Registration Agreement dated May 21, 1992 between
Chesapeake Energy Corporation and various lenders, as
amended by First Amendment thereto dated May 26, 1992.
Incorporated herein by reference to Exhibits 10.26.1 and
10.26.2 to Registrant's registration statement on Form
S-1 (No. 33-55600).
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.
10.2.1+ -- Employment Agreement dated as of July 1, 1997 between
Aubrey K. McClendon and Chesapeake Energy Corporation.
</TABLE>
<PAGE> 61
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
10.2.2+ -- Employment Agreement dated as of July 1, 1997 between Tom
L. Ward and Chesapeake Energy Corporation.
10.2.3+ -- Employment Agreement dated as of July 1, 1997 between
Marcus C. Rowland and Chesapeake Energy Corporation.
10.2.4+ -- Employment Agreement dated as of July 1, 1995 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, 1995.
10.2.5+ -- Employment Agreement dated as of July 1, 1997 between J.
Mark Lester and Chesapeake Energy Corporation.
10.2.6+ -- Employment Agreement dated as of July 1, 1997 between
Henry J. Hood and Chesapeake Energy Corporation.
10.2.7+ -- Employment Agreement dated as of July 1, 1997 between
Ronald A. Lefaive and Chesapeake Energy Corporation.
10.2.8+ -- Employment Agreement dated as of July 1, 1997 between
Martha A. Burger and Chesapeake Energy Corporation.
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).
10.9 -- 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 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.
11 -- Statement of Net Income (Loss) Per Share.
21 -- Subsidiaries of Registrant
23.1* -- Consent of Coopers & Lybrand L.L.P.
23.2* -- Consent of Price Waterhouse LLP
23.3* -- Consent of Williamson Petroleum Consultants, Inc.
27 -- Financial Data Schedule
</TABLE>
- ---------------
* Filed herewith.
+ Management contract or compensatory plan or arrangement.
<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 and 333-07255) and Form S-3 (File Nos. 333-04027
and 333-12533) of our report dated September 30, 1997, on our audits of the
consolidated financial statements of Chesapeake Energy Corporation as of June
30, 1997 and 1996 and for the years then ended, which report is included in this
Annual Report on Form 10-K/A.
COOPERS & LYBRAND L.L.P.
Oklahoma City, Oklahoma
February 9, 1998
<PAGE> 1
EXHIBIT 23.2
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 and 333-07255) and Form S-3 (File Nos. 333-04027
and 333-12533) of our report dated September 20, 1995, except for the third
paragraph of Note 9 which is as of October 9, 1997, on our audit of the
consolidated financial statements of Chesapeake Energy Corporation for the year
ended June 30, 1995, which report is included in this Annual Report on Form
10-K/A.
PRICE WATERHOUSE LLP
Houston, Texas
February 9, 1998
<PAGE> 1
EXHIBIT 23.3
CONSENT OF WILLIAMSON PETROLEUM CONSULTANTS, INC.
As independent oil and gas consultants, Williamson Petroleum Consultants,
Inc. hereby consents to (a) the use of our reserve report entitled "Evaluation
of Oil and Gas Reserves to the Interests of Chesapeake Energy Corporation in
Certain Properties in Louisiana and Texas, Effective June 30, 1997, for
Disclosure to the Securities and Exchange Commission, Williamson Project 7.8496"
dated September 17, 1997 and all references to our firm included in or made a
part of the Chesapeake Energy Corporation Annual Report on Form 10-K/A to be
filed with the Securities and Exchange Commission on or about February 11, 1998
and (b) to the incorporation by reference of this Form 10-K/A for the year
ending June 30, 1997 in the Registration Statements on Form S-8 (Nos. 33-84256,
33-84258, 33-88196, 333-07255, 33-89282, and 333-27525) and on Form S-3 (Nos.
333-04027 and 333-12533).
/s/ WILLIAMSON PETROLEUM CONSULTANTS, INC.
----------------------------------------------
WILLIAMSON PETROLEUM CONSULTANTS, INC.
Houston, Texas
February 11, 1998
