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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the Fiscal Year ended 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)
OKLAHOMA 73-1395733
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
6100 NORTH WESTERN AVENUE
OKLAHOMA CITY, OKLAHOMA 73118
Address of principal executive offices) (Zip Code)
(405) 848-8000
Registrant's telephone number, including area code
Securities registered pursuant to Section 12(b) of the Act:
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
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
September 30, 1997 was $516,707,238. At such date, there were 70,376,462 shares
of Common Stock issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy Statement for 1997 Annual Meeting
of Shareholders -- Part III
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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 result of its capitalized
costs of oil and gas properties exceeding the estimated present value of future
net revenues from the Company's proved reserves at June 30, 1997.
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.
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 in 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 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 $163 million in drilling
to explore this leasehold in fiscal 1996 and 1997. Of the Company's six project
areas identified in the Louisiana Trend, only in the Masters Creek area has the
Company consistently found commercial quantities of oil and gas in the Austin
Chalk formation.
As of June 30, 1997 the Company owned over two million net undeveloped
acres in its leasehold inventory. The Company expects that its inventory of
proved and unproved drilling locations will continue to be an important source
of new reserves, production and cash flow over the next few years. The Louisiana
Trend continues to be a key element of this existing inventory.
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The following table sets forth the Company's estimated proved reserves (net
of interests of other working and royalty interest owners and others entitled to
share in production), estimated capital expenditures and the number of potential
net drilling locations required to develop the Company's proved undeveloped
reserves at June 30, 1997:
ESTIMATED
CAPITAL
EXPENDITURES
PERCENT REQUIRED TO NUMBER OF
OF DEVELOP NET PROVED
OIL GAS GAS PROVED PUD'S UNDEVELOPED
AREAS (MBBL) (MMCF) EQUIVALENT RESERVES ($ IN 00'S) LOCATIONS
----- ------ ------- ---------- -------- ------------ -----------
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
====== ======= ======= === ======= ==
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.
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.
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
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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 50% of the
Company's planned exploration and development capital expenditures for all
areas. 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 pay 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 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. 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.
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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.
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.
YEAR ENDED JUNE 30,
-----------------------------------------------
1997 1996 1995
------------- ------------- -------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
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
== ==== === ==== === ====
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
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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. During fiscal 1998 the Company
has budgeted approximately $25 million for seismic acquisition and evaluation
and intends to conduct or participate in seismic surveys covering the following
areas:
APPROXIMATE
GROSS ACREAGE AREA TARGET FORMATIONS
- ------------- ------------------ -------------------------------
85,000 Baton Rouge, LA Tuscaloosa; Austin Chalk
55,000 Wharton County, TX Deep Wilcox; Frio and Yegua
35,000 Golden Trend, OK Multiple sand and carbonates
90,000 Lovington, NM Strawn
50,000 Williston, MT Red River
50,000 Allen Parish, LA Wilcox; Austin Chalk
WELL DATA
At June 30, 1997, the Company had interests in approximately 593 (270.1
net) producing wells, of which 129 (55.4 net) were classified as primarily oil
producing wells and 464 (214.7 net) were classified as primarily gas producing
wells.
VOLUMES, REVENUE, PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the production
volumes, revenue, average prices received and average production costs
associated with the Company's sale of oil and gas for the periods indicated:
YEAR ENDED JUNE 30,
-------------------------------
1997 1996 1995
-------- -------- -------
NET PRODUCTION:
Oil (MBbl)...................................... 2,770 1,413 1,139
Gas (MMcf)...................................... 62,005 51,710 25,114
Gas equivalent (MMcfe).......................... 78,625 60,190 31,947
OIL AND GAS SALES ($ 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
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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:
YEAR ENDED JUNE 30,
--------------------------------
1997 1996 1995
-------- -------- --------
($ IN THOUSANDS)
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 $105,878
======== ======== ========
ACREAGE
The following table sets forth as of June 30, 1997 the gross and net acres
of both developed and undeveloped oil and gas leases which the Company holds.
"Gross" acres are the total number of acres in which the Company owns a working
interest. "Net" acres refer to gross acres multiplied by the Company's
fractional working interest. Acreage numbers are stated in thousands.
TOTAL DEVELOPED
DEVELOPED UNDEVELOPED AND UNDEVELOPED
------------ -------------------- ----------------
GROSS NET GROSS NET GROSS NET
----- --- -------- -------- ------ ------
Louisiana Trend.............. 41 40 1,154(1) 1,003(1) 1,195 1,043
Oklahoma..................... 85 34 297 134 382 168
Giddings..................... 121 58 186 133 307 191
Williston Basin.............. 3 2 732 498 735 500
Other Areas.................. 27 19 331 250 358 269
--- --- -------- -------- ----- -----
Total.............. 277 153 2,700 2,018 2,977 2,171
=== === ======== ======== ===== =====
- ---------------
(1) Does not include options for additional leasehold held by the Company but
not yet exercised.
MARKETING
The Company's oil production is sold under market sensitive or spot price
contracts. The Company's natural gas production is sold to purchasers under
varying percentage-of-proceeds and percentage-of-index contracts. By the terms
of these contracts, the Company receives a percentage of the resale price
received by the purchaser for sales of residue gas and natural gas liquids
recovered after gathering and processing the Company's gas. The residue gas and
natural gas liquids sold by these purchasers are sold primarily based on spot
market prices. The revenue received by the Company from the sale of natural gas
liquids is included in natural gas sales. During fiscal 1997, the following
three customers individually accounted for 10% or more of the Company's total
oil and gas sales:
PERCENT OF OIL
AMOUNT AND GAS
($ IN THOUSANDS) SALES
---------------- --------------
Aquila Southwest Pipeline Corporation.................... 53,885 28%
Koch Oil Company......................................... 29,580 15%
GPM Gas Corporation...................................... 27,682 14%
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.
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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. 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:
NYMEX-INDEX
STRIKE PRICE
MONTH VOLUME (BBLS) (PER BBL)
----- -------------- ------------
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
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:
HOUSTON SHIP CHANNEL
INDEX STRIKE PRICE
MONTHS VOLUME (MMBTU) (PER MMBTU)
------ -------------- --------------------
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
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.
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.
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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.
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.
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Activities of the Company with respect to the exploration, development and
production of oil and natural gas are subject to stringent environmental
regulation by state and federal authorities including the United States
Environmental Protection Agency ("EPA"). Such regulation has increased the cost
of planning, designing, drilling, operating and in some instances, abandoning
wells. In most instances, the regulatory requirements relate to the handling and
disposal of drilling and production waste products and waste created by water
and air pollution control procedures. Although the Company believes that
compliance with environmental regulations will not have a material adverse
effect on operations or earnings, risks of substantial costs and liabilities are
inherent in oil and gas operations, and there can be no assurance that
significant costs and liabilities, including criminal penalties, will not be
incurred. Moreover, it is possible that other developments, such as stricter
environmental laws and regulations, and claims for damages for injuries to
property or persons resulting from the Company's operations could result in
substantial costs and liabilities.
Waste Disposal. The Company currently owns or leases, and has in the past
owned or leased, numerous properties that for many years have been used for the
exploration and production of oil and gas. Although the Company has utilized
operating and disposal practices that were standard in the industry at the time,
hydrocarbons or other wastes may have been disposed of or released on or under
the properties owned or leased by the Company or on or under other locations
where such wastes have been taken for disposal. In addition, many of these
properties have been operated by third parties whose treatment and disposal or
release of hydrocarbons or other wastes was not under the Company's control.
State and federal laws applicable to oil and natural gas wastes and properties
have gradually become more strict. Under such laws, the Company could be
required to remove or remediate previously disposed wastes (including wastes
disposed of or released by prior owners or operators) 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
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payment of monetary fines and correction of any identified deficiencies.
Alternatively, regulatory agencies could require the Company to forego
construction or operation of certain air emission sources.
OSHA. The Company is subject to the requirements of the federal
Occupational Safety and Health Act ("OSHA") and comparable state statutes. The
OSHA hazard communication standard, the EPA community right-to-know regulations
under Title III of the federal Superfund Amendment and Reauthorization Act and
similar state statutes require the Company to organize information about
hazardous materials used, released or produced in its operations. Certain of
this information must be provided to employees, state and local governmental
authorities and local citizens. The Company is also subject to the requirements
and reporting set forth in OSHA workplace standards. The Company provides safety
training and personal protective equipment to its employees.
OPA and Clean Water Act. Federal regulations require certain owners or
operators of facilities that store or otherwise handle oil, such as the Company,
to prepare and implement spill prevention control plans, countermeasure plans
and facilities response plans relating to the possible discharge of oil into
surface waters. The Oil Pollution Act of 1990 ("OPA") amends certain provisions
of the federal Water Pollution Control Act of 1972, commonly referred to as the
Clean Water Act ("CWA"), and other statutes as they pertain to the prevention of
and response to oil spills into navigable waters. The OPA subjects owners of
facilities to strict joint and several liability for all containment and cleanup
costs and certain other damages arising from a spill, including, but not limited
to, the costs of responding to a release of oil to surface waters. The CWA
provides penalties for any discharges of petroleum product in reportable
quantities and imposes substantial liability for the costs of removing a spill.
State laws for the control of water pollution also provide varying civil and
criminal penalties and liabilities in the case of releases of 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.
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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 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.
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GLOSSARY
The terms defined in this section are used throughout this Form 10-K.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet of gas equivalent.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Commercial Well; Commercially Productive Well. An oil and gas well which
produces oil and gas in sufficient quantities such that proceeds from the sale
of such production exceed production expenses and taxes.
Developed Acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
Development Well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
Dry Hole; Dry Well. A well found to be incapable of producing either oil or
gas in sufficient quantities to justify completion as an oil or gas well.
Exploratory Well. A well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir or to extend a known reservoir.
Farmout. An assignment of an interest in a drilling location and related
acreage conditional upon the drilling of a well on that location.
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%.
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Productive Well. A well that is producing oil or gas or that is capable of
production.
Proved Developed Reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved Reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved Undeveloped Location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
Proved Undeveloped Reserves. Reserves that are expected to be recovered
from new wells drilled to known reservoir on undrilled acreage or from existing
wells where a relatively major expenditure is required for recompletion.
Royalty Interest. An interest in an oil and gas property entitling the
owner to a share of oil or gas production free of costs of production.
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.
ITEM 2. PROPERTIES
OIL AND GAS RESERVES
The tables below set forth information as of June 30, 1997 with respect to
the Company's estimated net proved reserves, the estimated future net revenue
therefrom and the present value thereof at such date. Williamson Petroleum
Consultants, Inc. ("Williamson") evaluated most of the Company's Texas oil and
gas reserves and all of its Louisiana oil and gas reserves, together
representing approximately 50% of the Company's total proved reserves. The
Company internally evaluated the remaining reserves, which were subsequently
evaluated by Williamson with a variance of approximately 4% of total proved
reserves. The estimates were prepared based upon a review of production
histories and other geologic, economic, ownership and engineering data developed
by the Company. The present value of estimated future net revenue shown is not
intended to represent the current market value of the estimated oil and gas
reserves owned by the Company.
ESTIMATED PROVED RESERVES OIL GAS
AS OF JUNE 30, 1997 (MBBL) (MMCF) TOTAL
------------------------- ------ ------- -------
Proved developed...................................... 7,324 151,879 195,823
Proved undeveloped.................................... 10,049 146,887 207,181
Total proved.......................................... 17,373 298,766 403,004
ESTIMATED FUTURE
NET REVENUE PROVED PROVED TOTAL
AS OF JUNE 30, 1997(A) DEVELOPED UNDEVELOPED PROVED
---------------------- --------- ----------- --------
($ IN THOUSANDS)
Estimated future net revenue..................... $336,417 $275,537 $611,954
Present value of future net revenue.............. $248,765 $188,621 $437,386
- ---------------
(a) Estimated future net revenue represents estimated future gross revenue to be
generated from the production of proved reserves, net of estimated
production and future development costs, using prices and
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costs in effect at June 30, 1997. The amounts shown do not give effect to
non-property related expenses, such as general and administrative expenses,
debt service and future income tax expense or to depreciation, depletion and
amortization. The prices used in the Williamson and internal reports yield
average prices of $18.38 per barrel of oil and $2.12 per Mcf of gas.
The future net revenue attributable to the Company's estimated proved
undeveloped reserves of $275.5 million at June 30, 1997, and the $188.6 million
present value thereof, have been calculated assuming that the Company will
expend approximately $146.9 million to develop these reserves through June 30,
2000. The amount and timing of these expenditures will depend on a number of
factors, including actual drilling results, product prices and the availability
of capital.
No estimates of proved reserves comparable to those included herein have
been included in reports to any federal agency other than the Securities and
Exchange Commission.
The Company's interest used in calculating proved reserves and the
estimated future net revenue therefrom was determined after giving effect to the
assumed maximum participation by other parties to the Company's farmout and
participation agreements. The prices used in calculating the estimated future
net revenue attributable to proved reserves do not reflect market prices for oil
and gas production sold subsequent to June 30, 1997. There can be no assurance
that all of the estimated proved reserves will be produced and sold at the
assumed prices or that existing contracts will be honored or judicially
enforced.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond the control of the
producer. The reserve data set forth herein represent only estimates. Reserve
engineering is a subjective process of estimating underground accumulations of
oil and gas that cannot be measured in an exact way, and the accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. As a result, estimates
made by different engineers often vary. In addition, results of drilling,
testing and production subsequent to the date of an estimate may justify
revision of such estimates, and such revisions may be material. Accordingly,
reserve estimates are often different from the actual quantities of oil and gas
that are ultimately recovered. Furthermore, the estimated future net revenue
from proved reserves and the present value thereof are based upon certain
assumptions, including prices, future production levels and cost, that may not
prove correct. Predictions about prices and future production levels are subject
to great uncertainty, and this is particularly true as to proved undeveloped
reserves, which are inherently less certain than proved developed reserves and
which comprise a significant portion of the Company's proved reserves. In fiscal
1997, such uncertainties resulted in a $236 million impairment of the Company's
oil and gas properties. (See "Results of Operations -- Impairment of Oil and Gas
Properties" in Item 7).
See Item 1 and Note 11 of Notes to Consolidated Financial Statements
included in Item 8 for a description of the Company's primary and other
operating areas, production and other information regarding its oil and gas
properties.
ITEM 3. LEGAL PROCEEDINGS
The following purported class actions alleging violations of Sections 10b-5
and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 thereunder have
been filed against the Company and certain of its officers and directors:
Joseph Friedman, as attorney-in-fact for Chana Wolowitz v. Chesapeake
Energy Corporation, Aubrey K. McClendon, Thomas L. Ward, Marcus C. Rowland,
Shannon T. Self, Walter C. Wilson, Henry J. Hood, Steven C. Dixon, and J.
Mark Lester, filed in the U.S. District Court for the Western District of
Oklahoma on August 21, 1997.
Albion Financial LLC v. Chesapeake Energy Corporation, Aubrey K.
McClendon, Marcus C. Rowland, Shannon T. Self, and Walter Wilson
("Albion"), filed in the U.S. District Court for the Southern District of
Texas, Houston Division, on August 29, 1997.
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Frank M. Zacco v. Chesapeake Energy Corporation, Aubrey K. McClendon,
Thomas L. Ward, Marcus C. Rowland, Shannon T. Self, Walter C. Wilson, Henry
J. Hood, Steven C. Dixon, and J. Mark Lester, filed in the U.S. District
Court for the Western District of Oklahoma on September 5, 1997.
Jeff Lezak v. Chesapeake Energy Corporation, Aubrey K. McClendon,
Thomas L. Ward, Marcus C. Rowland, Shannon T. Self, Walter C. Wilson, Henry
J. Hood, Steven C. Dixon, and J. Mark Lester, filed in the U.S. District
Court for the Western District of Oklahoma on September 9, 1997.
Lisabeth Dolwig v. Chesapeake Energy Corporation, Aubrey K. McClendon,
Marcus C. Rowland, Shannon T. Self, Walter Wilson, Ronald Lefaive, and J.
Mark Lester, filed in the U.S. District Court for the Western District of
Oklahoma on September 11, 1997.
Leslie Joseph Klein IRA v. Chesapeake Energy Corporation, Aubrey K.
McClendon, Thomas L. Ward, Marcus C. Rowland, Shannon T. Self, Walter C.
Wilson, Henry J. Hood, Steven C. Dixon, and J. Mark Lester, filed in the
U.S. District Court for the Western District of Oklahoma on September 15,
1997.
Elmo G. Hubble v. Chesapeake Energy Corporation, Aubrey K. McClendon,
Marcus C. Rowland, Shannon T. Self and Walter Wilson, filed in the U.S.
District Court for the Southern District of Texas, Houston Division, on
September 17, 1997.
Jamie Gottleib, et al. v. Chesapeake Energy Corporation, Aubrey K.
McClendon, Thomas L. Ward, Marcus C. Rowland, Shannon T. Self, Walter C.
Wilson, Henry J. Hood, Steven C. Dixon, and J. Mark Lester, filed in the
U.S. District Court for the Western District of Oklahoma on September 18,
1997.
David S. Winston v. Chesapeake Energy Corporation, Aubrey K.
McClendon, Thomas L. Ward, Marcus C. Rowland, Shannon T. Self, Walter C.
Wilson, Henry J. Hood, Steven C. Dixon, and J. Mark Lester, filed in the
U.S. District Court for the Western District of Oklahoma on September 23,
1997.
Michael Spindle, et al. v. Chesapeake Energy Corporation, Aubrey K.
McClendon, Marcus C. Rowland, Shannon T. Self, Walter Wilson, Ronald
Lefaive and J. Mark Lester, filed in the U.S. District Court for the
Western District of Oklahoma on September 24, 1997.
Robert Markewich v. Chesapeake Energy Corporation, Aubrey K.
McClendon, Thomas L. Ward, Marcus C. Rowland, Shannon T. Self, Walter C.
Wilson, Henry J. Hood, Steven C. Dixon, and J. Mark Lester, filed in the
U.S. District Court for the Western District of Oklahoma on September 25,
1997.
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.
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
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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 prediction can be made as to the outcome of the matter.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the Company's security holders
during the fourth quarter of the Company's fiscal year ended June 30, 1997.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
PRICE RANGE OF COMMON STOCK
The Common Stock has been trading on the New York Stock Exchange under the
symbol "CHK" since April 28, 1995. The following table sets forth, for the
periods indicated, the high and low sales prices per share (adjusted for 3-for-2
stock splits on December 15, 1995 and June 28, 1996 and a 2-for-1 stock split on
December 31, 1996) of the Common Stock as reported by the New York Stock
Exchange:
COMMON STOCK
----------------
HIGH LOW
------ ------
Fiscal year ended June 30, 1996:
First Quarter............................................. $ 7.28 $ 4.53
Second Quarter............................................ 11.08 6.20
Third Quarter............................................. 16.50 10.67
Fourth Quarter............................................ 30.38 15.50
Fiscal year ended June 30, 1997:
First Quarter............................................. 34.00 21.00
Second Quarter............................................ 34.13 25.69
Third Quarter............................................. 31.50 19.88
Fourth Quarter............................................ 22.38 9.25
At September 30, 1997 there were 500 holders of record of Common Stock and
approximately 18,000 beneficial owners.
DIVIDENDS
The Company initiated a quarterly dividend with the payment of $0.02 per
common share on July 15, 1997. The payment of future cash dividends, if any,
will be reviewed periodically by the Board of Directors and will depend upon,
among other things, the Company's financial condition, funds from operations,
the level of its capital and development expenditures, its future business
prospects and any contractual restrictions.
Certain of the Indentures governing the Company's outstanding Senior Notes
contain certain restrictions on the Company's ability to declare and pay
dividends. Under the Indentures, the Company may not pay any cash dividends in
respect of its Common Stock if (i) a default or an event of default has occurred
and is continuing at the time of or immediately after giving effect to the
dividend payment, (ii) the Company would not be able to incur at least $1 of
additional indebtedness under the terms of the Indentures, or (iii) immediately
after giving effect to the dividend payment, the aggregate of all Restricted
Payments (as defined) declared or made after the respective issue dates of the
notes exceeds the sum of specified income, proceeds from the issuance of stock
and debt by the Company and other amounts from the quarter in which the
respective note issuances occurred to the quarter immediately preceding the date
of the dividend payment.
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STOCK REPURCHASE AUTHORIZATION
In August 1997, the Company's Board of Directors authorized the Company to
expend up to $50 million in connection with purchases of the Company's
outstanding common stock from time to time through open market transactions,
block or privately negotiated purchases, or otherwise. To date, the Company has
not repurchased any shares under the Board authorization.
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ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial data of the
Company for each of the five fiscal years ended June 30, 1997. The data is
derived from the Consolidated Financial Statements of the Company, including the
Notes thereto, appearing elsewhere in this report. The data set forth in this
table should be read in conjunction with "Management's Discussion and Analysis
of Financial Condition and Results of Operations" and the Consolidated Financial
Statements, including the Notes thereto included elsewhere in this report. On
June 13, 1997 the Company declared a dividend of $0.02 per common share which
was paid on July 15, 1997.
YEAR ENDED JUNE 30,
----------------------------------------------------
1997 1996 1995 1994 1993
--------- -------- -------- -------- -------
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales...................... $ 192,920 $110,849 $ 56,983 $ 22,404 $11,602
Oil and gas marketing sales............ 76,172 28,428 -- -- --
Oil and gas service operations......... -- 6,314 8,836 6,439 5,526
Interest and other..................... 11,223 3,831 1,524 981 880
--------- -------- -------- -------- -------
Total revenues.................... 280,315 149,422 67,343 29,824 18,008
--------- -------- -------- -------- -------
Costs and expenses:
Production expenses and taxes.......... 15,107 8,303 4,256 3,647 2,890
Oil and gas marketing expenses......... 75,140 27,452 -- -- --
Oil and gas service operations......... -- 4,895 7,747 5,199 3,653
Impairment of oil and gas properties... 236,000 -- -- -- --
Oil and gas depreciation, depletion and
amortization......................... 103,264 50,899 25,410 8,141 4,184
Depreciation and amortization of
other assets......................... 3,782 3,157 1,765 1,871 557
General and administrative............. 8,802 4,828 3,578 3,135 3,620
Provision for legal and other
settlements.......................... -- -- -- -- 1,286
Interest and other..................... 18,550 13,679 6,627 2,676 2,282
--------- -------- -------- -------- -------
Total costs and expenses.......... 460,645 113,213 49,383 24,669 18,472
--------- -------- -------- -------- -------
Income (loss) before income taxes and
extraordinary item..................... (180,330) 36,209 17,960 5,155 (464)
Provision (benefit) for income taxes...... (3,573) 12,854 6,299 1,250 (99)
--------- -------- -------- -------- -------
Income (loss) before extraordinary item... (176,757) 23,355 11,661 3,905 (365)
Extraordinary item:
Loss on early extinguishment of debt,
net of applicable income taxes of
$3,804............................... (6,620) -- -- -- --
--------- -------- -------- -------- -------
Net income (loss)......................... $(183,377) $ 23,355 $ 11,661 $ 3,905 $ (365)
========= ======== ======== ======== =======
Earnings (loss) per common and common
equivalent share:
Income (loss) before extraordinary item... $ (2.69) $ 0.40 $ 0.21 $ 0.08 $ (0.02)
Extraordinary item........................ (0.10) -- -- -- --
--------- -------- -------- -------- -------
Net income (loss)......................... $ (2.79) $ 0.40 $ 0.21 $ 0.08 $ (0.02)
========= ======== ======== ======== =======
CASH FLOW DATA:
Cash provided by (used in) operating
activities............................. $ 84,089 $120,972 $ 54,731 $ 19,423 $(1,499)
Cash used in investing activities......... 523,854 344,389 112,703 29,211 15,142
Cash provided by financing activities..... 512,144 219,520 97,282 21,162 20,802
BALANCE SHEET DATA: (at end of period)
Total assets.............................. $ 949,068 $572,335 $276,693 $125,690 $78,707
Long-term debt, net of current
maturities............................. 508,950 268,431 145,754 47,878 14,051
Stockholders' equity...................... 286,889 177,767 44,975 31,260 31,432
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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):
CAPITAL EXPENDITURES
GROSS NET ---------------------------------
WELLS WELLS DRILLING LEASEHOLD TOTAL
----- ----- -------- --------- --------
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
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 $250-$275 million, concentrate its Louisiana Trend drilling
activities in Masters Creek, utilize more 3-D seismic prior to conducting
drilling operations, reduce the acquisition of additional unproven leasehold,
and selectively acquire proved reserves. This strategy will likely have the
effect of reducing the Company's anticipated production growth rate from
exploration and development drilling to between 10% and 15% per year.
To assist the Company in reducing exploratory risks and increasing economic
returns the Company has increased its use of 3-D seismic. The Company has
conducted, participated in, or is actively pursuing more than 25 3-D seismic
programs to more fully evaluate the Company's acreage inventory.
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21
The following table sets forth certain operating data of the Company for
the periods presented:
YEAR ENDED JUNE 30,
-----------------------------
1997 1996 1995
-------- -------- -------
NET PRODUCTION DATA:
Oil (MBbl)................................................ 2,770 1,413 1,139
Gas (MMcf)................................................ 62,005 51,710 25,114
Gas equivalent (MMcfe).................................... 78,625 60,190 31,947
OIL AND GAS SALES ($ 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
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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The following table shows the Company's production by major field area for
fiscal 1997 and fiscal 1996:
FOR THE YEAR ENDED JUNE 30,
----------------------------------------
1997 1996
------------------ ------------------
PRODUCTION PRODUCTION
------------------ ------------------
(MMCFE) PERCENT (MMCFE) PERCENT
------- ------- ------- -------
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%
====== === ====== ===
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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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
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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
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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. 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:
NYMEX-INDEX
STRIKE PRICE
MONTH VOLUME (BBLS) (PER BBL)
----- ------------- ------------
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
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.
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26
As of June 30, 1997, the Company had the following gas swap arrangements
for periods after June 1997:
HOUSTON SHIP CHANNEL
INDEX STRIKE PRICE
MONTH VOLUME (MMBTU) (PER BBL)
----- -------------- --------------------
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
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.
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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 & Poors 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.
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
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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.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
-- Not applicable
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
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Consolidated Financial Statements:
Report of Independent Accountants for the Years Ended June
30, 1997 and 1996...................................... 30
Report of Independent Accountants for the Year Ended June
30, 1995............................................... 31
Consolidated Balance Sheets June 30, 1997 and 1996........ 32
Consolidated Statements of Operations for the Years Ended
June 30, 1997, 1996 and 1995........................... 33
Consolidated Statements of Cash Flows for the Years Ended
June 30, 1997, 1996 and 1995........................... 34
Consolidated Statements of Stockholders' Equity for the
Years Ended June 30, 1997, 1996 and 1995............... 36
Notes to Consolidated Financial Statements................ 37
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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 suppor