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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 (FEE REQUIRED)
FOR THE FISCAL YEAR ENDED JUNE 30, 1996
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
COMMISSION FILE NO. 1-13726
CHESAPEAKE ENERGY CORPORATION
(Exact Name of Registrant as Specified in Its Charter)
DELAWARE 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 $.10 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 amendments to
this Form 10-K. / /
The aggregate market value of Common Stock held by non-affiliates on August
30, 1996 was $904,362,133. At such date, there were 16,825,342 shares of Common
Stock issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
PROXY STATEMENT FOR 1996 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 ranks
among the five most active drillers of new wells in the United States.
From inception in 1989 through June 30, 1996, Chesapeake drilled a total of
562 gross (186 net) wells, of which 529 gross (175 net) wells were commercially
productive. As a result of its successful drilling efforts, the Company has
experienced significant growth in its proved reserves, production and revenue.
From its first full fiscal year of operation ended June 30, 1990 to the fiscal
year ended June 30, 1996, the Company's estimated proved reserves increased to
425 Bcfe from 11 Bcfe, annual production increased to 60.2 Bcfe from 0.2 Bcfe,
total revenue increased to $149.4 million from $0.6 million, and total assets
increased to $572 million from $8 million.
At June 30, 1996, the Company's estimated proved reserves consisted of 12.3
MMBbl of oil and 351.2 Bcf of gas, a total of 425 Bcfe. During fiscal 1996, the
Company's proved reserves increased from 242 Bcfe to 425 Bcfe, an increase of
183 Bcfe (76%), or a four-fold replacement of its 60.2 Bcfe of production. At
June 30, 1996, the present value of estimated future net revenue attributable to
Chesapeake's estimated proved reserves before income taxes (utilizing a 10%
discount rate) was $547 million, based on average prices at fiscal year end 1996
of $20.90 per Bbl and $2.41 per Mcf.
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.
BUSINESS STRATEGY
Since its inception, Chesapeake's 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. The Company has focused in areas where reservoirs such as fractured
carbonates offer (i) low geological risk, (ii) large reserve potential, and
(iii) the opportunity to earn attractive economic returns through the
application of advanced drilling and completion technologies.
The Company historically concentrated its undeveloped leasehold
acquisitions and associated drilling in the Giddings Field of southern Texas and
the Golden Trend Field of southern Oklahoma. Since early fiscal 1995, Chesapeake
has extensively developed new project areas that are either extensions of the
Company's historical focus in the Giddings and Golden Trend Fields or are new
areas in which the Company's geological and engineering expertise provides the
Company with competitive advantages. These additional project areas include the
Knox Field in southcentral Oklahoma, the Sholem Alechem Field in southern
Oklahoma, the Louisiana Austin Chalk Trend (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. Within the
Louisiana Trend, the Company has acquired over 1,000,000 acres, and has
identified six project areas: South Brookeland, Leesville, Masters Creek, St.
Landry, Baton Rouge and Livingston. An important element in the Company's
business strategy is to retain a higher level of ownership in these new project
areas than it historically retained in the Giddings and Golden Trend Fields.
The Company's operating areas are typically characterized by fractured
carbonate reservoirs that are known to contain oil and gas and generally cover a
large geographic region. In the past, development of these reservoirs has been
limited by both economic and technological factors. Recent advances in drilling
and completion technologies, and the resulting lower exploration costs, provide
the Company with the opportunity to develop large new reserves of oil and
natural gas and to generate attractive economic returns.
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COMPETITIVE ADVANTAGES
Management believes five competitive advantages are responsible for
Chesapeake's rapid growth and distinguish the Company from other independent
energy companies.
Growth Through the Drillbit. Employing its strategy of growth through the
drillbit, the Company has substantially increased its reserves and production.
By focusing drilling efforts on deep fractured carbonate reservoirs, management
believes the Company can continue to increase its reserves and production and
generate attractive returns by integrating the Company's advanced drilling and
completion expertise with its large inventory of undeveloped leasehold.
Dominant Leasehold Positions. Through aggressive acreage acquisition in its
existing and new project areas, the Company seeks to establish a dominant
leasehold position in each of its project areas. Such a dominant position allows
the Company to maximize its economic returns while limiting drilling
opportunities available to its competitors. Consistent with this strategy, the
Company has assembled a significant leasehold acreage inventory which included
approximately 900 proved and unproved drilling locations at June 30, 1996.
UNDEVELOPED
NUMBER OF GROSS LOCATIONS(A)
WELLS UNDEVELOPED ----------------------------
OPERATING AREA DRILLED(A) GROSS ACREAGE(B) PROVED UNEVALUATED
---------------------------- --------------- ---------------- ------------ -----------
Giddings Field.............. 178 150 69 60
Southern Oklahoma........... 196 100 85 150
Louisiana Trend............. 6 1,000 17 425
Williston Basin............. -- 550 -- 75
Other....................... 182 250 11 25
--- ----- ---
Total..................... 562 2,050 182 735
=== ===== ===
- ---------------
(a) Includes wells drilling
(b) Acreage in thousands
Technological Leadership. The Company has developed significant expertise
in the rapidly evolving technologies of horizontal drilling, 3-D seismic
evaluation, and deep fracture stimulation. The Company believes its expertise in
employing these technologies is the most important factor in its growth during
the past several years. In particular, the Company has developed considerable
horizontal drilling and completion expertise, especially in wells which target
deep fractured carbonates. Over the last several years, deeper, more complex
horizontal wells have become technically and economically feasible and the cost
of drilling these wells has decreased. As a result, the Company believes there
has been a substantial increase in the number of areas which are economically
attractive for horizontal drilling.
Superior Operating Margin. Management believes the Company's operating cost
structure is among the lowest of all publicly traded independent energy
producers. For fiscal 1996 the Company's per unit operating costs (consisting of
general and administrative expense, lease operating expense, production taxes,
and depreciation, depletion and amortization of oil and gas properties) were
$1.07 per Mcfe produced resulting in an operating margin of $0.77 per Mcfe.
Management believes the key to creating value in the independent energy industry
is the ability to generate high levels of cash flow that can be successfully
reinvested in a technologically-driven exploration program.
Management's Substantial Equity Ownership. At June 30, 1996, the Company's
management and directors beneficially owned (including outstanding vested
options of management) an aggregate of approximately 44% of the Company's
outstanding shares of Common Stock. Management believes this substantial equity
ownership provides a strong alignment of management's and investors' interests
and creates an entrepreneurial culture within the Company.
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PRIMARY OPERATING AREAS
The Company's activities are concentrated in three primary operating areas:
(i) the Navasota River and Independence areas of the downdip Giddings Field in
southern Texas, (ii) the Knox, Sholem Alechem, and Golden Trend Fields of
southern Oklahoma, and (iii) the South Brookeland, Leesville, Masters Creek, St.
Landry, Baton Rouge and Livingston areas of the Louisiana Trend.
The following table sets forth the Company's proved reserves in its primary
operating areas (net of interests of other working and royalty interest owners
and others entitled to share in production), estimated capital expenditures and
the number of potential drilling locations required to develop the Company's
proved undeveloped reserves at June 30, 1996:
ESTIMATED
CAPITAL
EXPENDITURES NUMBER OF
GAS PERCENT OF REQUIRED TO PROVED
OIL GAS EQUIVALENT PROVED DEVELOP UNDEVELOPED
AREAS (MMBL) (MMCF) (MMCFE) RESERVES ($ IN 000'S) LOCATIONS
- ----------------------------------- ------ ------- ---------- ---------- ------------ -----------
Giddings........................... 2,147 156,557 169,439 39.9% $ 38,163 69
Southern Oklahoma.................. 3,657 157,460 179,402 42.2 60,746 85
Louisiana Trend.................... 5,969 23,182 58,996 13.9 33,749 17
Williston Basin.................... -- -- -- -- -- --
Other Areas........................ 485 14,025 16,938 4.0 4,410 11
------ ------- ------- ----- -------- ---
Total.................... 12,258 351,224 424,775 100.0% $137,068 182
====== ======= ======= ===== ======== ===
GIDDINGS FIELD. Chesapeake's second largest concentration of proved
reserves and its highest concentration of present value is located in the
Giddings Field, which is currently one of the most active oil and natural gas
fields in the U.S. 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 Company believes the downdip Giddings
area is one of the largest discoveries of onshore gas in the U.S. in recent
years.
The Company believes that its success in the downdip Giddings Field is
attributable to four principal factors: (i) limited reservoir drainage from
previously drilled vertical wells; (ii) the Company's aggressive leasehold
acquisition program, which has permitted the creation of larger spacing units,
thus reducing competition for reserves from offsetting wells; (iii) continued
technological advances in horizontal drilling, which have significantly lowered
development costs, expanded the field's boundaries into deeper areas, and
increased per well productivity through the ability to drill within a more
precisely defined target zone; and (iv) the geological setting of the downdip
Austin Chalk, which is characterized by greater reservoir pressure and more
intensive fracturing than in the updip area of the Giddings Field. As a result
of these factors, the Company's downdip wells have, on average, produced greater
reserves per well while also exhibiting lower decline rates than average wells
in other areas of Austin Chalk production.
Navasota River. In February 1994, the Company drilled its first well in the
Navasota River leasehold block, located in Brazos and Grimes Counties, Texas. As
of June 30, 1996, the Company had drilled and completed 77 Navasota River wells
and was drilling seven additional wells. The Company has budgeted $30 million in
fiscal 1997 to drill 28 gross (16 net) wells in the Navasota River area.
Independence. The Company's Independence block is located in Grimes and
Washington Counties to the south and southwest (and further downdip) from the
Navasota River area. As of June 30, 1996, the Company had drilled 24
Independence wells and was drilling two additional wells. The Company has
budgeted $7 million to drill six gross (3 net) wells in fiscal 1997 in the
Independence area.
SOUTHERN OKLAHOMA. Chesapeake's largest concentration of proved reserves is
located in southern Oklahoma and is comprised of the Knox, Golden Trend and
Sholem Alechem Fields. Based on the
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Company's drilling success in late 1993 with its deeper wells (12,000 to 14,000
feet) in the Bradley area of the Golden Trend Field, the Company initiated a
deeper drilling project in 1994 in the Knox area. The Company's first two wells
in Knox were the first wells in Oklahoma to establish commingled commercial
production from the Sycamore, Woodford, Hunton and Viola formations at depths
below 15,000 feet. This success led to an aggressive and successful acreage
acquisition and drilling program during fiscal 1995 and fiscal 1996.
As of June 30, 1996, Chesapeake had successfully completed 41 of 42 wells
drilled in the Knox Field and was drilling six additional wells. The Company's
acreage inventory in the Knox area is large enough to support the drilling of
approximately 50 proved undeveloped locations and the Company believes this
inventory could increase by an additional 200 increased density or step-out
wells, subject to applicable spacing requirements. The Company has budgeted $36
million in fiscal 1997 to drill 19 gross (15 net) wells in the Knox area. During
fiscal 1996, Chesapeake doubled its assets in Knox through its acquisition of
Amerada Hess Corporation's interests in Chesapeake wells.
The Company's horizontal drilling project in the Sholem Alechem portion of
southern Oklahoma's Sho-Vel-Tum Field was initiated on the Company's belief that
the application of horizontal drilling technology could result in a significant
increase in the recovery of remaining reserves in this field. Since its
discovery more than 80 years ago, the Sho-Vel-Tum Field has produced more than
one billion barrels of oil and one trillion cubic feet of natural gas. To date
the Company has drilled 25 gross (11 net) horizontal wells and has successfully
completed all of these wells. The Company has budgeted $8 million to drill 10
gross (5 net) wells during fiscal 1997. Texaco Exploration and Production, Inc.
is the Company's 50% working interest partner in this area.
LOUISIANA AUSTIN CHALK TREND. The Louisiana Trend is the newest of the
Company's three primary operating areas and will be the focus of the Company's
exploration and development activities in the foreseeable future. In late 1994,
Occidental Petroleum Corporation ("Occidental") announced the completion of a
single lateral 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.
Based on management's belief that the Occidental well confirmed the
Company's geological premise that the Austin Chalk would be productive across a
large portion of central and southeastern Louisiana, Chesapeake invested
approximately $103 million through June 30, 1996 to acquire approximately
1,000,000 acres of leasehold in the Louisiana Trend. This large acreage position
provides the Company with the opportunity to drill up to 300-500 horizontal
Austin Chalk wells, assuming spacing units of approximately 2,000 acres and
assuming continued drilling success by Chesapeake and others in the Louisiana
Trend.
During fiscal 1996, Chesapeake operated five wells (4.9 net) in the
Louisiana Trend and participated in the second well drilled by Occidental in
this area. Production commenced from Chesapeake's first well, the Laddie James
#7-1, on June 30, 1996, and the other wells were drilling at that date.
Chesapeake has budgeted $125 million to drill 25 gross and net wells in the
Louisiana Trend during fiscal 1997, including several wells that will test the
deeper Tuscaloosa formation.
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, 1996 owned approximately 550,000 gross acres. The primary focus
of Chesapeake's exploration efforts in this area is the horizontally-drilled,
oil-prone Red River "B" formation in Bowman and Slope Counties, North Dakota and
in Fallon County, Montana. Approximately 75 Red River "B" horizontal wells have
been drilled to date by other companies in this area. The Company has budgeted
$6 million to drill six gross and net wells during fiscal 1997.
PERMIAN BASIN. In late 1994, 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
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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.
The Company has identified approximately 25 prospects in the Lovington
area, where the Company is targeting oil reserves at depths from 11,000 to
13,000 feet. The Company drilled its first well during fiscal 1996 and has
budgeted $4 million to drill six gross (5 net) wells during fiscal 1997.
ARKOMA BASIN. The Arkoma Basin is Oklahoma's second largest gas basin. In
late 1994, the Company initiated a seismic and leasehold acquisition program in
the Jackfork and Deep Spiro areas of the Arkoma Basin of southeastern Oklahoma.
The Jackfork and Deep Spiro plays are located in the southern portion of the
basin, a deeper and more geologically complex area that has been less heavily
explored than the updip northern portion.
The Company believes recent developments in 3-D seismic technology and in
drilling and completion technologies have created an excellent opportunity for
the Company to establish a significant project area in the Arkoma Basin. The
Company is targeting gas reserves at depths from 4,000 to 16,000 feet. As of
June 30, 1996, the Company had drilled 14 gross (6 net) Arkoma Basin wells on
its acreage position of approximately 125,000 gross acres. The Company has
budgeted $3 million to drill eight gross (4 net) wells during fiscal 1997.
OTHER. The Company maintains significant interests in other acreage,
primarily in Fayette, Grimes, and Karnes Counties, Texas, where the Company
conducts horizontal drilling operations targeting the Austin Chalk, Buda,
Georgetown, and Edwards formations. The Company has budgeted $6 million to drill
six gross (4 net) horizontal wells in these and other areas of Texas during
fiscal 1997.
HORIZONTAL DRILLING OPERATIONS
Horizontal drilling involves the drilling of a horizontal borehole within a
narrow segment of a single stratigraphic formation. Through June 30, 1996,
Chesapeake had drilled 275 horizontal wells in southern Texas, southern Oklahoma
and Louisiana.
In general, horizontal drilling permits the operator to intersect a greater
number of fractures than in conventional vertical drilling. This can result in
both increased initial production rates and greater ultimate recoveries of
hydrocarbons on a per well basis. Based on the Company's experience, the typical
production profile of a horizontal well reflects relatively higher production in
the early life of the well, allowing for more of the drilling costs to be
quickly recovered, followed by a significant decline in production and a
stabilization of production at lower rates thereafter. The Company believes that
horizontal drilling tends to decrease field development costs by reducing the
number of wells needed to drain a given reservoir.
The technology enabling the Company to drill profitable horizontal wells in
the Giddings Field in southern Texas, the Sholem Alechem Field in southern
Oklahoma and recently in the Louisiana Trend has progressed rapidly and has
resulted in lower finding costs. Advances in drilling technology such as
"measurement-while-drilling" tools, which provide a continuous analysis of the
drillbit's location when drilling horizontally, assist the Company's engineers
in guiding the drillbit into a more tightly defined target zone, or "sweet
spot," in the formation. Additionally, innovations in downhole motor, drillbit,
and whipstock technology have doubled the rate of drilling penetration during
the past two years and have enabled the Company to drill multiple lateral
horizontal wells. The Company's geologists are using "logging-while-drilling"
and enhanced seismic technology to more accurately locate the existence of
hydrocarbon-bearing fractures within target formations. Further innovations in
horizontal drilling tools and techniques continue at a rapid pace and management
believes such innovations will enable the Company to expand its drilling success
further downdip in the Louisiana Trend and in Giddings and into other horizontal
drilling projects elsewhere in the United States.
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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,
----------------------------------------------------
1996 1995 1994
-------------- -------------- --------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
Development:
Productive............................ 111 49.5 133 42.6 70 15.2
Non-productive........................ 4 1.6 5 2.8 4 .1
---- ---- ---- ---- ---- ----
Total................................. 115 51.1 138 45.4 74 15.3
==== ==== ==== ==== ==== ====
Exploratory:
Productive............................ 29 16.5 11 5.3 17 3.0
Non-productive........................ 4 1.4 1 .7 1 .1
---- ---- ---- ---- ---- ----
Total................................. 33 17.9 12 6.0 18 3.1
==== ==== ==== ==== ==== ====
At June 30, 1996, the Company was drilling 28 gross (16.2 net) exploratory
or development wells, of which 24 gross (12.6 net) have been successfully
completed and four gross (3.6 net) are still being drilled or tested. The
Company was also participating with minority interests in nine non-operated
wells being drilled at that date.
WELL DATA
At June 30, 1996, the Company had interests in approximately 474 producing
wells, of which 93 (29.9 net) were classified as primarily oil producing wells
and 381 (124.0 net) were classified as primarily gas producing wells.
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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,
---------------------------------
1996 1995 1994
-------- -------- -------
Net production:
Oil (MBbl)........................................ 1,413 1,139 537
Gas (MMcf)........................................ 51,710 25,114 6,927
Gas equivalent (MMcfe)............................ 60,190 31,947 10,152
Oil and gas sales ($ in 000's):
Oil............................................... $ 25,224 $ 19,784 $ 8,111
Gas............................................... 85,625 37,199 14,293
-------- -------- -------
Total oil and gas sales................... $110,849 $ 56,983 $22,404
======== ======== =======
Average sales price:
Oil ($ per Bbl)................................... $ 17.85 $ 17.36 $ 15.09
Gas ($ per Mcf)................................... $ 1.66 $ 1.48 $ 2.06
Gas equivalent ($ per Mcfe)....................... $ 1.84 $ 1.78 $ 2.21
Oil and gas costs ($ per Mcfe):
Production expenses and taxes..................... $ .14 $ .13 $ .36
General and administrative........................ $ .08 $ .11 $ .31
Depreciation, depletion and amortization of oil
and gas properties............................. $ .85 $ .80 $ .80
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,
---------------------------------
1996 1995 1994
-------- -------- -------
($ IN THOUSANDS)
Development costs................................... $143,437 $ 81,833 $26,277
Exploration costs................................... 39,410 14,129 5,358
Acquisition costs:
Unproved properties............................... 138,188 24,437 3,305
Proved properties................................. 24,560 -- --
Capitalized internal costs.......................... 1,699 586 965
Proceeds from sale of leasehold, equipment and
other............................................. (11,416) (15,107) (7,598)
-------- -------- -------
Total..................................... $335,878 $105,878 $28,307
======== ======== =======
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ACREAGE
The following table sets forth as of June 30, 1996 the gross and net acres
of both developed and undeveloped oil and gas leases which the Company holds.
"Gross" acres are the total number of acres in which the Company owns a working
interest. "Net" acres refer to gross acres multiplied by the Company's
fractional working interest. Acreage numbers are stated in thousands.
TOTAL DEVELOPED
AND UNDEVELOPED
---------------
GROSS NET
----- -----
Giddings..................................................... 251 170
Southern Oklahoma............................................ 137 48
Louisiana Trend.............................................. 1,012 900
Williston Basin.............................................. 550 381
Other Areas.................................................. 319 201
----- -----
Total.............................................. 2,269 1,700
===== =====
MARKETING
The Company's oil production is sold under market sensitive or spot price
contracts. The Company's natural gas production is sold to purchasers under
varying percentage-of-proceeds and percentage-of-index contracts. By the terms
of these contracts, the Company receives a percentage of the resale price
received by the purchaser for sales of residue gas and natural gas liquids
recovered after gathering and processing the Company's gas. The residue gas and
natural gas liquids sold by these purchasers are sold primarily based on spot
market prices. The revenue received by the Company from the sale of natural gas
liquids is included in natural gas sales. During fiscal 1996, the following
three customers individually accounted for 10% or more of the Company's total
oil and gas sales:
AMOUNT PERCENT OF OIL
($ IN THOUSANDS) AND GAS SALES
---------------- --------------
Aquila Southwest Pipeline Corporation......... $ 41,900 38%
GPM Gas Corporation........................... $ 28,700 26%
Wickford Energy Marketing, L.C................ $ 18,500 17%
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.
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 swap
arrangements that establish an index-related price above which the Company pays
the hedging partner and below which the Company is paid by the hedging partner,
the purchase of index-related puts that provide for a "floor" price to the
Company to be paid by the counter-party to the extent the price of the commodity
is below the contracted floor, and basis protection swaps. Recognized gains and
losses on hedge contracts are reported as a component of the related
transaction. Results for hedging transactions are reflected in oil and gas sales
to the extent related to the Company's oil and gas production.
As of June 30, 1996, the Company had NYMEX-based crude oil swap agreements
for 1,000 Bbl per day for July 1, 1996 through August 31, 1996 at an average
price of $17.85 per Bbl. The counter-party has the option exercisable monthly
for an additional 1,000 Bbl per day for the period July 1, 1996 through December
31, 1996 to cause a swap if the price exceeds an average $17.74 per Bbl. The
actual settlements for July and August resulted in a $0.5 million payment to the
counter-party. The Company estimates, based on NYMEX prices as of August 30,
1996, that the effect of the September through December hedges would be a $0.4
million payment to the counter-party.
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The Company has purchased Houston Ship Channel put options which guarantee
the Company an average floor price of $2.21/Mmbtu for 20,000 Mmbtu per day for
the period of November 1, 1996 through February 28, 1997. The average cost of
these puts was $0.14 per Mmbtu.
As of June 30, 1996, the Company had NYMEX-based natural gas swaps and
NYMEX/Houston Ship Channel Basis swaps for the months of July through October
1996. These transactions resulted in payments to the Company's counter-party of
approximately $2 million for the month of July 1996 and $1.5 million for the
month of August 1996. The Company estimates, based on NYMEX prices as of August
30, 1996, that the effect of the September and October hedges would be a $0.2
million payment to the counter-party.
The Company has only limited involvement with derivative financial
instruments, as defined in Statement of Financial Accounting Standards No. 119
("SFAS No. 119") "Disclosure About Derivative Financial Instruments and Fair
Value of Financial Instruments" and does not use them for trading purposes. The
Company's objective is to hedge a portion of its exposure to price volatility
from producing crude oil and natural gas. These arrangements may expose the
Company to credit risk from its counter-parties and to basis risk.
COMPETITION
The oil and gas industry is highly competitive. The Company competes for
the acquisition of oil and gas properties with numerous other entities,
including major oil companies, other independent oil and gas concerns and
individual producers and operators. 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 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 project 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.
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Marketing and Transportation
Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of 1938,
the Natural Gas Policy Act of 1978 (the "NGPA"), and the regulations promulgated
thereunder by the Federal Energy Regulatory Commission (the "FERC"). Since 1978,
maximum selling prices of certain categories of natural gas sold in "first
sales," whether sold in interstate or intrastate commerce, have been regulated
pursuant to the NGPA. The NGPA established various categories of natural gas and
provided for graduated deregulation of price controls of several categories of
natural gas and the deregulation of sales of certain categories of natural gas.
Most "first sale" price deregulation contemplated under the NGPA has already
occurred. Moreover, in July 1989, the Natural Gas Wellhead Decontrol Act was
enacted. This Act amended the NGPA to remove both price and non-price controls
from natural gas sold in "first sales" as of January 1, 1993.
Several major regulatory changes have been implemented by the FERC from
1985 to the present that affect the economics of natural gas production,
transportation and sales. In addition, the FERC continues to promulgate
revisions to various aspects of the rules and regulations affecting those
segments of the natural gas industry, most notably interstate natural gas
transmission companies, which remain subject to the FERC's jurisdiction. These
initiatives may also affect the intrastate transportation of gas under certain
circumstances. The stated purposes of many of these regulatory changes is to
promote competition among the various sectors of the gas industry. The ultimate
impact of these complex and overlapping rules and regulations, many of which are
repeatedly subjected to judicial challenge and interpretation, 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 regulating the release of materials in the environment or otherwise
relating to the protection of the environment 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 to property,
employees, other persons and the environment resulting from the Company's
operations could have on its activities.
Activities of the Company with respect to the exploration, development and
production of oil and natural gas are subject to stringent environmental
regulation by state and federal authorities including the 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 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
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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 is 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 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 an owner of sites on which "hazardous
substances" have been released by previous owners or operators. 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 have been named a potentially responsible
party under CERCLA or similar state superfund laws affecting property owned or
leased by the Company.
Air Emissions. The operations of the Company are subject to local, state
and federal regulations for the control of emissions of air pollution. Legal and
regulatory requirements in this area are increasing, and there can be no
assurance that significant costs and liabilities will not be incurred in the
future as a result of new regulatory developments. In particular, regulations
promulgated under the Clean Air Act Amendments of 1990 may impose additional
compliance requirements that could affect the Company's operations. However, it
is impossible to predict accurately the effect, if any, of the Clean Air Act
Amendments on the Company at this time. The Company may in the future be subject
to civil or administrative enforcement actions for failure to comply strictly
with air regulations or permits. These enforcement actions are generally
resolved by payment of monetary fines and correction of any identified
deficiencies. Alternatively, regulatory agencies could require the Company to
forego construction or operation of certain air emission sources.
OSHA. The Company is subject to the requirements of the federal
Occupational Safety and Health Act ("OSHA") and comparable state statutes. The
OSHA hazard communication standard, the EPA community right-to-know regulations
under Title III of the federal Superfund Amendment and Reauthorization Act and
similar state statutes require the Company to organize information about
hazardous materials used 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
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criminal penalties and liabilities in the case of releases of petroleum or its
derivatives into surface waters or into the ground. Regulations are currently
being developed under OPA and state laws concerning oil pollution prevention and
other matters that may impose additional regulatory burdens on the Company. In
addition, the CWA and analogous state laws require permits to be obtained to
authorize discharges into surface waters or to construct facilities in wetland
areas. With respect to certain of its operations, the Company is required to
maintain such permits or meet general permit requirements. The EPA recently
adopted regulations concerning discharges of storm water runoff. This program
requires covered facilities to obtain individual permits, participate in a group
permit or seek coverage under an EPA general permit. The Company believes that
it will be able to obtain, or be included under, such permits, where necessary,
with minor modifications to existing facilities and operations that would not
have a material effect on the Company.
NORM. Oil and gas exploration and production activities have been
identified as generators of concentrations of low-level naturally-occurring
radioactive materials ("NORM"). NORM regulations have recently been adopted in
several states. The Company is unable to estimate the effect of these
regulations, although based upon the Company's preliminary analysis to date, the
Company does not believe that its compliance with such regulations will have a
material adverse effect on its operations or financial condition.
Safe Drinking Water Act. The Company's operations involve the disposal of
produced saltwater and other nonhazardous oil-field wastes by reinjection into
the subsurface. Under the Safe Drinking Water Act ("SDWA"), oil and gas
operators, such as the Company, must obtain a permit for the construction and
operation of underground Class II injection wells. To protect against
contamination of drinking water, periodic mechanical integrity tests are often
required to be performed by the well operator. The Company has obtained such
permits for the Class II wells it operates. The Company also has disposed of
wastes in facilities other than those owned by the Company (commercial Class II
injection wells).
Toxic Substances Control Act. The Toxic Substances Control Act ("TSCA") was
enacted to control the adverse effects of newly manufactured and existing
chemical substances. Under the TSCA, the EPA has issued specific rules and
regulations governing the use, labeling, maintenance, removal from service and
disposal of PCB items, such as transformers and capacitors used by oil and gas
companies. The Company may own such PCB items but does not believe compliance
with TSCA has or will have a material adverse effect on the Company's operations
or financial condition.
TITLE TO PROPERTIES
Title to properties is subject to royalty, overriding royalty, carried, net
profits, working and other similar interests and contractual arrangements
customary in the oil and gas industry, to liens for current taxes not yet due
and to other encumbrances. As is customary in the industry in the case of
undeveloped properties, little investigation of record title is made at the time
of acquisition (other than a preliminary review of local 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 $5 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
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also carries comprehensive general liability policies and a $25 million umbrella
policy. The Company and its subsidiaries carry workers' compensation insurance
in all states in which they operate. 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 344 full-time employees as of June 30, 1996 of which 68
were involved in the oil and gas service operations of the Company. The sale of
the oil and gas service operations as of June 30, 1996 resulted in a transfer of
the service employees to the purchaser. No employees are represented by
organized labor unions. The Company considers its employee relations to be good.
FACILITIES
The Company owns 11 buildings totaling approximately 74,000 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, Texas and in Lafayette, Louisiana.
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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.
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ITEM 2. PROPERTIES
OIL AND GAS RESERVES
The tables below set forth information as of June 30, 1996 with respect to
the Company's estimated net proved reserves, the estimated future net revenue
therefrom and the present value thereof at such date, based on estimates
prepared by Williamson Petroleum Consultants, Inc. ("Williamson") and the
Company's petroleum engineers. The reserves evaluated internally by the Company
constituted 0.6% of total proved reserves for fiscal 1996. 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.
For further information concerning the present value of future net revenue from
these proved reserves, see Note 10 of Notes to the Company's Consolidated
Financial Statements included in Item 8.
ESTIMATED PROVED RESERVES OIL GAS TOTAL
AS OF JUNE 30, 1996 (MMBBL) (BCF) (BCFE)
- ------------------------------------------------------------- --------- ----------- ------
Proved developed............................................. 3.7 144.7 166.6
Proved undeveloped........................................... 8.6 206.5 258.2
Total proved................................................. 12.3 351.2 424.8
ESTIMATED FUTURE NET REVENUE PROVED PROVED TOTAL
AS OF JUNE 30, 1996(A) DEVELOPED UNDEVELOPED PROVED
- ------------------------------------------------------------- --------- ----------- ------
($ IN MILLIONS)
Estimated future net revenue................................. $ 340.8 $ 454.8 $795.6
Present value of future net revenue.......................... $ 242.0 $ 305.0 $547.0
- ---------------
(a) Estimated future net revenue represents estimated future gross revenue to be
generated from the production of proved reserves, net of estimated
production and future development costs, using prices and costs in effect
at June 30, 1996. 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 report yield average prices
of $20.90 per barrel of oil and $2.41 per Mcf of gas.
The future net revenue attributable to the Company's estimated proved
undeveloped reserves of $454.8 million at June 30, 1996, and the $305 million
present value thereof, have been calculated assuming that the Company will
expend approximately $135.6 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 necessarily reflect market
prices for oil and gas production sold subsequent to June 30, 1996. 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
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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.
ITEM 3. LEGAL PROCEEDINGS
The Company is involved in ordinary routine litigation incidental to its
business. There are presently no material pending legal proceedings to which the
Company is a party or of which any of its property is subject.
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, 1996.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
PRICE RANGE OF COMMON STOCK
The Common Stock was quoted through the Nasdaq National Market under the
symbol "CSPK" from February 4, 1993 through April 27, 1995. On April 28, 1995
the Common Stock began trading on the New York Stock Exchange under the symbol
"CHK." The following table sets forth, for the periods indicated, the high and
low sales prices per share (adjusted for a 2-for-1 stock split on December 16,
1994 and 3-for-2 stock splits on December 15, 1995 and June 28, 1996) of the
Common Stock as reported by the Nasdaq National Market through April 27, 1995,
and the New York Stock Exchange thereafter:
COMMON STOCK
-------------------
HIGH LOW
------ ------
Fiscal year ended June 30, 1995:
First Quarter.................................................. $ 4.89 $ 1.72
Second Quarter................................................. 7.67 4.28
Third Quarter.................................................. 9.67 4.44
Fourth Quarter................................................. 13.39 9.33
Fiscal year ended June 30, 1996:
First Quarter.................................................. 14.56 9.06
Second Quarter................................................. 22.17 12.39
Third Quarter.................................................. 33.00 21.33
Fourth Quarter................................................. 60.75 31.00
At August 31, 1996 there were 167 holders of record of Common Stock and
approximately 7,815 beneficial owners.
DIVIDENDS
The Company has never paid cash dividends on its Common Stock. The
Company's policy is to retain its earnings to support the growth of the
Company's business. The Board of Directors of the Company does not intend to pay
cash dividends on the Company's Common Stock in the foreseeable future. The
payment of future cash dividends, if any, will be reviewed periodically by the
Board of Directors and will depend upon,
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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 restrictions imposed by the Company's present or future credit
facilities.
The Indentures governing the Company's outstanding Senior Notes and its
revolving bank credit facility contain certain restrictions on the Company's
ability to declare and pay dividends. The revolving credit facility prohibits
the Company from declaring or paying any dividends in respect of its Common
Stock unless the lender otherwise consents in writing. 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 $1 of additional indebtedness under the terms of
the Indentures, or (iii) immediately after giving effect to the dividend
payment, the aggregate of all Restricted Payments (as defined) declared or made
after the respective issue dates of the notes exceeds the sum of specified
income, proceeds from the issuance of stock and debt by the Company and other
amounts from the quarter in which the respective note issuances occurred to the
quarter immediately preceding the date of the dividend payment.
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ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial data of the
Company for each of the five fiscal years ended June 30, 1996. The data is
derived from the Consolidated Financial Statements of the Company, including the
Notes thereto, appearing elsewhere in this report. The data set forth in this
table should be read in conjunction with "Management's Discussion and Analysis
of Financial Condition and Results of Operations" and the Consolidated Financial
Statements, including the Notes thereto included elsewhere in this report.
YEAR ENDED JUNE 30,
------------------------------------------------------
1996 1995 1994 1993 1992
-------- -------- -------- ------- -------
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales.................... $110,849 $ 56,983 $ 22,404 $11,602 $10,520
Gas marketing sales.................. 28,428 -- -- -- --
Oil and gas service operations....... 6,314 8,836 6,439 5,526 7,656
Interest and other................... 3,831 1,524 981 880 542
-------- -------- -------- ------- -------
Total revenues.................. 149,422 67,343 29,824 18,008 18,718
-------- -------- -------- ------- -------
Costs and expenses:
Production expenses and taxes........ 8,303 4,256 3,647 2,890 2,103
Gas marketing expenses............... 27,452 -- -- -- --
Oil and gas service operations....... 4,895 7,747 5,199 3,653 4,113
Oil and gas depreciation, depletion
and amortization................... 50,899 25,410 8,141 4,184 2,910
Depreciation and amortization of
other assets....................... 3,157 1,765 1,871 557 974
General and administrative........... 4,828 3,578 3,135 3,620 3,314
Provision for legal and other
settlements........................ -- -- -- 1,286 --
Interest and other................... 13,679 6,627 2,676 2,282 2,577
-------- -------- -------- ------- -------
Total costs and expenses........ 113,213 49,383 24,669 18,472 15,991
-------- -------- -------- ------- -------
Income (loss) before income taxes....... 36,209 17,960 5,155 (464) 2,727
Income tax expense (benefit)............ 12,854 6,299 1,250 (99) 1,337
-------- -------- -------- ------- -------
Net income (loss)....................... $ 23,355 $ 11,661 $ 3,905 $ (365) $ 1,390
======== ======== ======== ======= =======
Net income (loss) per common share...... $ .80 $ .42 $ .16 $ (.04) $ .10
======== ======== ======== ======= =======
CASH FLOW DATA:
Cash provided by (used in) operating
activities........................... $120,972 $ 54,731 $ 19,423 $(1,499) $11,550
Cash used in investing activities....... 344,389 112,703 29,211 15,142 26,987
Cash provided by financing activities... 219,520 97,282 21,162 20,802 12,779
BALANCE SHEET DATA (AT END OF PERIOD):
Total assets............................ $572,335 $276,693 $125,690 $78,707 $61,095
Long-term debt, net of current
maturities........................... 268,431 145,754 47,878 14,051 22,154
Stockholders' equity.................... 177,767 44,975 31,260 31,432 132
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
OVERVIEW
Chesapeake's revenue, net income, operating cash flow, and production
reached record levels in 1996. Increased cash flow from operations, in
combination with the issuance of $120 million of 9.125% Senior Notes and the
sale of 3 million shares of common stock in April 1996, allowed the Company to
fund its net capital expenditures of $344 million. The Company also repaid all
amounts outstanding under its $125 million Revolving Credit Facility and
currently has $75 million of available bank credit committed under this expanded
credit facility.
During fiscal 1996, the Company participated in 148 gross wells (69.0 net),
of which 111 were operated by the Company. The Company's proved reserves
increased by 183 Bcfe to 425 Bcfe as a result of this drilling and the purchase
of proved reserves from Amerada Hess Corporation compared to 60.2 Bcfe of
production, resulting in reserve replacement in excess of 300% compared to
production.
The Company's business strategy has continued to emphasize the acquisition
of large prospective leasehold positions to provide a multi-year inventory of
drilling locations. By June 1996, the Company had increased its acreage position
to approximately 200,000 gross acres of developed leasehold and approximately 2
million gross acres of undeveloped leasehold. During 1996, the Company continued
the expansion of its exploration focus in the Louisiana Austin Chalk Trend and
began a significant acreage acquisition program in the Williston Basin. The
Company also conducted or participated in 3-D seismic programs in the Lovington
area, the Giddings Field, the Knox Field and in the Williston and Arkoma Basin
areas to evaluate the Company's acreage inventory.
The following table sets forth certain operating data of the Company for
the periods presented:
YEAR ENDED JUNE 30,
--------------------------------
1996 1995 1994
-------- ------- -------
Net Production Data:
Oil (MBbl)......................................... 1,413 1,139 537
Gas (MMcf)......................................... 51,710 25,114 6,927
Gas equivalent (MMcfe)............................. 60,190 31,947 10,152
Oil and Gas Sales ($ in 000's):
Oil................................................ $ 25,224 $19,784 $ 8,111
Gas................................................ 85,625 37,199 14,293
-------- ------- -------
Total oil and gas sales.................... $110,849 $56,983 $22,404
======== ======= =======
Average Sales Price:
Oil ($ per Bbl).................................... $ 17.85 $ 17.36 $ 15.09
Gas ($ per Mcf).................................... $ 1.66 $ 1.48 $ 2.06
Gas equivalent ($ per Mcfe)........................ $ 1.84 $ 1.78 $ 2.21
Oil and Gas Costs ($ per Mcfe):
Production expenses and taxes...................... $ .14 $ .13 $ .36
General and administrative......................... $ .08 $ .11 $ .31
Depreciation, depletion and amortization........... $ .85 $ .80 $ .80
Net Wells Drilled:
Horizontal wells................................... 42.0 28.5 11.1
Vertical wells..................................... 27.0 23.0 7.9
Net Wells at End of Period........................... 186.2 91.2 57.9
RESULTS OF OPERATIONS
General. For the fiscal year ended June 30, 1996, the Company realized net
income of $23.4 million, or $0.80 per common share, on total revenues of $149.4
million. This compares to net income of $11.7 million, or $0.42 per common
share, on total revenues of $67.3 million in 1995, and net income of $3.9
million, or $0.16
20
22
per common share, on total revenues of $29.8 million in fiscal 1994. The
significantly higher earnings in 1996 as compared to 1995 and 1994 were largely
the result of higher production and prices per Mcfe, partially offset by higher
oil and gas depreciation, depletion and amortization and higher interest costs.
Oil and Gas Sales. During fiscal 1996, oil and gas sales increased 94% to
$110.8 million versus $57.0 million for fiscal 1995 and 395% from the fiscal
1994 amount of $22.4 million. The increase in oil and gas sales resulted
primarily from strong growth in production volumes. For fiscal 1996, the Company
produced 60.2 Bcfe, at a weighted average price of $1.84 per Mcfe, compared to
31.9 Bcfe produced in fiscal 1995 at a weighted average price of $1.78 per Mcfe,
and 10.2 Bcfe produced in fiscal 1994 at a weighted average price of $2.21 per
Mcfe. This represents production growth of 89% for fiscal 1996 compared to 1995
and 490% compared to 1994.
These increases in production volumes reflect the Company's successful
exploration and development program. The following table shows the Company's
production by major field area for fiscal 1996 and fiscal 1995:
FOR THE YEAR ENDED JUNE 30,
-------------------------------------------------
1996 1995
---------------------- ----------------------
PRODUCTION PRODUCTION
(MMCFE) PERCENT (MMCFE) PERCENT
---------- ------- ---------- -------
Giddings -- Navasota River................ 28,360 47% 16,881 53%
-- Independence.................. 11,601 19% 3,784 12%
-- Other Giddings................ 7,205 12% 5,976 19%
Oklahoma -- Knox.......................... 3,901 6% 1,255 4%
-- Golden Trend.................. 2,758 5% 1,880 6%
-- Sholem Alechem................ 2,010 3% 749 2%
All Other Fields.............................. 4,355 8% 1,422 4%
------ ---- ------ ----
Total Production.................... 60,190 100% 31,947 100%
====== ==== ====== ====
The Company's gas production represented approximately 86% of the Company's
total production volume on an equivalent basis in fiscal 1996. This is compared
to 79% in fiscal 1995 and 68% in 1994. This is a result of the Company's
drilling in deeper, more gas-prone areas of the Giddings and Knox Fields.
For fiscal 1996, the Company realized an average price per barrel of oil of
$17.85, compared to $17.36 in fiscal 1995 and $15.09 in fiscal 1994. 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.
The Company realized $0.9 million less in oil revenues than it would have
received from unhedged market prices in fiscal 1996.
Gas price realizations increased from fiscal 1995 to 1996 by approximately
12%, despite lower gas revenue realized by the Company during the fourth fiscal
quarter of 1996 as a result of the hedging activity. As a result of hedging, the
Company had gas revenues during that period that were approximately $5.1 million
less than unhedged market prices. Although gas prices generally increased during
1996, the weighted average realization per Mcf in 1996 was still 19% less than
1994. The lower prices realized in 1995 were the result of lower natural gas
prices, and the fact that an increased portion of the Company's gas production
was from areas that contain leaner gas that is either not processed for liquids
or contains less energy value (Btu's) per Mcf. The Company anticipates gas
production in Louisiana will receive premium prices at least equivalent to Henry
Hub indexes due to the high Btu content and favorable market location of the
production.
Gas Marketing Sales. In December 1995, the Company entered into the gas
marketing business by acquiring all of the outstanding stock of an Oklahoma
City-based natural gas marketing company for total consideration of $725,000.
This subsidiary provides natural gas marketing services including commodity
price structuring, contract administration and nomination services for the
Company, its partners and other natural gas producers in the geographical areas
in which the Company is active.
21
23
As a result of this purchase, the Company realized $28.4 million in gas
marketing sales for third parties in fiscal 1996, with corresponding costs of
gas marketing sales of $27.5, resulting in a gross margin of $0.9 million. There
were no gas marketing activities in 1995 or 1994.
Oil and Gas Service Operations. Revenues from oil and gas service
operations were $6.3 million in fiscal 1996, down 28% from $8.8 million in
fiscal 1995, and down 2% from $6.4 million in 1994. The related costs and
expenses of these operations were $4.9 million, $7.7 million and $5.2 million
for the three years ended June 30, 1996, 1995 and 1994, respectively. The gross
profit margin of 22% in fiscal 1996 was up from the 12% margin in fiscal 1995,
and up slightly from the 19% gross margin in fiscal 1994. The gross profit
margin derived from these operations is a function of drilling activities in the
period, costs of materials and supplies and the mix of operations between lower
margin trucking operations versus higher margin labor oriented service
operations.
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
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. A deferred gain from the sale of service company assets of
$0.9 million was recorded as a reduction in the Company's investment in Peak and
will be amortized to income over the estimated useful lives of the Peak assets.
The Company's investment in Peak will be accounted for using the equity method.
Interest and Other. Interest and other income for fiscal 1996 was $3.8
million which compares to $1.5 million in 1995 and $1 million in 1994. 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 and 1994, 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 $8.3 million in
fiscal 1996, as compared to $4.3 million in fiscal 1995, and $3.6 million in
fiscal 1994. 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 $0.14 per Mcfe as compared to $0.13 per Mcfe in fiscal
1995 and $0.36 per Mcfe in 1994. Severance tax exemptions for production were
available in fiscal 1996 and 1995, and certain of the exemptions in Giddings are
applicable for production through 2001 for wells spud prior to September 1, 1996
and on a more limited basis for qualifying wells spud thereafter. The Company
expects that operating costs in fiscal 1997 will increase based on the Company's
expansion of drilling efforts into the Louisiana Trend and the Williston Basin,
because both are oil prone areas which generally have higher operating costs
than gas prone areas and because limited severance tax exemptions will be
applicable in these areas as compared to existing exemptions in Giddings.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization ("DD&A") of oil and gas properties for fiscal 1996 was $50.9
million, $25.5 million higher than fiscal 1995's expense of $25.4 million, and
$42.8 million higher than fiscal 1994's expense of $8.1 million. The average
DD&A rate per Mcfe, which is a function of capitalized costs, future development
costs, and the related underlying reserves in the periods presented, increased
to $0.85 in fiscal 1996 compared to $0.80 in fiscal 1995 and 1994. 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 could
trend upward in 1997 based on projected higher finding costs for the Louisiana
Trend.
Depreciation and Amortization of Other Assets. Depreciation and
amortization ("D&A") of other assets increased to $3.2 million in fiscal 1996,
compared to $1.8 million in fiscal 1995, and $1.9 million in 1994. This increase
in fiscal 1996 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 the
22
24
Senior Notes in May 1995 and in April 1996. The Company anticipates an increase
in D&A in fiscal 1997 as a result of a full year of debt issuance cost
amortization on the 9.125% Senior Notes issued in April 1996 and higher building
depreciation expense on the Company's corporate offices, offset by a reduction
in depreciation expense associated with the sale of the service company assets.
General and Administrative. General and administrative ("G&A") expenses,
which are net of capitalized internal payroll and non-payroll expenses (see Note
10 of Notes to Consolidated Financial Statements), were $4.8 million in fiscal
1996, up 33% from $3.6 million in fiscal 1995, and up from $3.1 million in
fiscal 1994. The increases in fiscal 1996 compared to 1995 and 1994 result
primarily from increased personnel expenses required by the Company's growth.
The Company capitalized $1.7 million of internal costs in fiscal 1996 directly
related to the Company's oil and gas exploration and development efforts, as
compared to $0.6 million in 1995 and $1.0 million in 1994. The Company
anticipates that G&A costs for fiscal 1997 will increase by approximately 25% as
a result of the Company's continued growth and increased budgets for exploration
and development activities, increasing operations activities, and attendant
personnel and overhead requirements.
Interest and Other. Interest and other expense increased to $13.7 million
in fiscal 1996 as compared to $6.6 million in 1995 and $2.7 million in fiscal
1994. Interest expense in the fourth quarter of fiscal 1996 was approximately $4
million, reflecting the issuance of $120 million of 9.125% Senior Notes in April
1996. In addition to the interest expense reported, the Company capitalized $6.4
million of interest during fiscal 1996, as compared to $1.6 million capitalized
in 1995 and $0.4 million in 1994. Interest expense will increase significantly
in fiscal 1997 as compared to 1996 as a result of the 9.125% Senior Notes issued
in April 1996.
Income Tax Expense. The Company recorded income tax expense of $12.9
million in fiscal 1996, as compared to $6.3 million in fiscal 1995, and $1.3
million in 1994. All of the income tax expense in 1996 was deferred due to a
current year tax net operating loss resulting from the Company's active drilling
program. A substantial portion of the Company's drilling costs are currently
deductible for income tax purposes. The effective tax rate was approximately
35.5% in fiscal 1996 compared to a tax rate of 35% in 1995 and 24% in 1994. The
Company anticipates an effective tax rate of between 36 and 36.5% for fiscal
1997 as a result of Louisiana state taxes and higher activity levels in
Louisiana. Based upon the anticipated level of drilling activities in fiscal
1997, the Company anticipates that substantially all of its fiscal 1997 income
tax expense will be deferred.
Hedging. Periodically the Company utilizes hedging strategies to hedge the
price of a portion of its future oil and gas production. These strategies
include swap arrangements that establish an index-related price above which the
Company pays the hedging partner and below which the Company is paid by the
hedging partner, the purchase of index-related puts that provide for a "floor"
price to the Company to be paid by the counter-party to the extent the price of
the commodity is below the contracted floor, and basis protection swaps.
Recognized gains and losses on hedge contracts are reported as a component of
the related transaction. Results from hedging transactions are reflected in oil
and gas sales to the extent related to the Company's oil and gas production.
As of June 30, 1996, the Company had NYMEX-based crude oil swap agreements
for 1,000 Bbl per day for July 1, 1996 through August 31, 1996 at an average
price of $17.85 per Bbl. The counter-party has the option exercisable monthly
for an additional 1,000 Bbl per day for the period July 1, 1996 through December
31, 1996 to cause a swap if the price exceeds an average $17.74 per Bbl. The
actual settlements for July and August resulted in a $0.5 million payment to the
counter-party. The Company estimates, based on NYMEX prices as of August 30,
1996, that the effect of the September through December hedges would be a $0.4
million payment to the counter-party.
The Company has purchased Houston Ship Channel put options which guarantee
the Company an average floor price of $2.21/Mmbtu for 20,000 Mmbtu per day for
the period of November 1, 1996 through February 28, 1997. The average cost of
these puts was $0.14 per Mmbtu.
As of June 30, 1996, the Company had NYMEX-based natural gas swaps and
NYMEX/Houston Ship Channel Basis swaps for the months of July through October,
1996. These transactions resulted in payments to the Company's counter-party of
approximately $2 million for the month of July 1996 and $1.5 million for
23
25
the month of August 1996. The Company estimates, based on NYMEX prices as of
August 30, 1996, that the effect of the September and October hedges would be a
$0.2 million payment to the counter-party.
The Company has only limited involvement with derivative financial
instruments, as defined in SFAS No. 119 "Disclosure About Derivative Financial
Instruments and Fair Value of Financial Instruments" and does not use them for
trading purposes. The Company's objective is to hedge a portion of its exposure
to price volatility from producing crude oil and natural gas. These arrangements
may expose the Company to credit risk to its counter-parties and to basis risk.
LIQUIDITY AND CAPITAL RESOURCES
FINANCING ACTIVITIES
On April 9, 1996 the Company completed a public offering of 2,475,000
shares of Common Stock at a price of $35.33 per share resulting in net proceeds
to the Company of approximately $82.1 million. On April 12, 1996, the
underwriters exercised an over-allotment option to purchase an additional
519,750 shares of Common Stock at a price of $35.33 per share, resulting in
additional net proceeds to the Company of approximately $17.3 million.
On April 9, 1996 the Company also concluded the sale of $120 million of
9.125% Senior Notes due 2006 (the "9.125% Senior Notes"), which offering
resulted in net proceeds to the Company of approximately $116 million. The
9.125% Senior Notes were issued at 99.931% of par. Approximately $44 million of
the proceeds of these offerings was used to retire all amounts outstanding under
the Company's revolving credit facility. 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 the proceeds of any
equity offering. 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.
In fiscal 1995, cash flows from financing activities were $97.3 million,
largely as the result of issuance of $90 million of 10.5% Senior Notes due 2002
(the "10.5% Senior Notes"). The 10.5% Senior Notes are redeemable at the option
of the Company at any time on or after June 1, 1999. The Company may also redeem
at its option at any time prior to June 1, 1998 up to $30 million of the 10.5%
Senior Notes with the proceeds of an equity offering at 110% of the principal
amount thereof.
In fiscal 1994, the Company received proceeds from long term borrowings of
$48.8 million, primarily from the issuance of $47.5 million of 12% Senior Notes
due 2001 (the "12% Senior Notes") and warrants to purchase 2,190,937 shares of
the Company's Common Stock at an aggregate exercise price of $4,870. The 12%
Senior Note Indenture provides for mandatory redemption of $11.9 million on each
of March 1, 1998, 1999 and 2000. The 12% Senior Notes are redeemable at the
option of the Company at any time on or after March 1, 1998.
All of the Company's subsidiaries except Chesapeake Gas Development
Corporation ("CGDC") and Chesapeake Energy Marketing, Inc. ("CEMI") have fully
and unconditionally guaranteed on a joint and several basis all three issues of
Senior Notes, and the securities of the guaranteeing subsidiaries have been
pledged to secure obligations under the 12% Senior Notes. See Note 2 of Notes to
the Company's Consolidated Financial Statements included in Item 8 of this
report. The Senior Note Indentures contain certain covenants, including
covenants limiting the Company and the guaranteeing subsidiaries with respect to
asset sales, restricted payments, the incurrence of additional indebtedness and
the issuance of preferred stock, liens, sale and leaseback transactions, lines
of business, dividend and other payment restrictions affecting guaranteeing
subsidiaries, mergers or consolidations, and transactions with affiliates. The
Company is obligated to repurchase the Senior Notes in the event of a change of
control, the sale of certain assets or failure to maintain a specified ratio of
assets to debt.
FINANCIAL FLEXIBILITY AND LIQUIDITY
The Company had working capital of approximately $0.3 million at June 30,
1996. Additionally, the Company has unused revolving credit facility commitments
that have been increased to $75 million. The total
24
26
facility size has been set at $125 million. This facility provides for interest
at the Union Bank reference rate (8.25% at June 30, 1996), or at the option of
the Company the Eurodollar rate plus 1.375% to 1.875%, depending on the ratio of
the amount outstanding to the borrowing base. Although the Senior Note
Indentures contain various restrictions on additional indebtedness, based on
asset values as of June 30, 1996 the Company estimates it could borrow up to
$106 million within these restrictions.
The Company also maintains a limited recourse bank facility with an amount
outstanding of $12.9 million as of June 30, 1996 secured by producing oil and
gas properties owned by the Company's wholly-owned subsidiary CGDC. This
facility provides for interest at the Union Bank reference rate (8.25% at June
30, 1996). The facility has not been guaranteed by the Company or any of its
other subsidiaries and is recourse only to the assets of CGDC. CGDC used
proceeds borrowed under this facility to acquire producing oil and gas
properties from Chesapeake Exploration Limited Partnership. The terms of the
facility prohibit the payment of dividends by CGDC.
Debt ratings for the Senior Notes are Ba3 by Moody's Investors Service and
B+ by Standard & Poors Corporation. Both Moody's and S&P upgraded their ratings
during the year. The Company's long-term debt represented 60% of total capital
at June 30, 1996. The Company's goal is to achieve an equity to capital ratio of
at least 50% and a further increase in its credit ratings during fiscal 1997.
OPERATING CASH FLOWS
Cash provided by operating activities was $121 million in fiscal 1996, as
compared to $54.7 million in 1995, and $19.4 million in 1994. Operating cash
flows for 1996 include enhanced earnings primarily as a result of increased oil
and gas production. Other major factors affecting cash flows for 1996, 1995 and
1994 were increases in non-cash charges and cash flows provided by changes in
the components of assets and liabilities. Cash provided by operating activities
is expected to be the primary source for meeting forecasted cash requirements in
1997.
INVESTING CASH FLOWS
Significantly higher cash was used in fiscal 1996 for development,
exploration and acquisition of oil and gas properties as compared to fiscal 1995
and 1994. Approximately $336 million was expended by the Company in 1996 (net of
proceeds from sale of leasehold and equipment, and from providing certain
oilfield services), as compared to $106 million in 1995, an increase of $230
million, or approximately 216%. In fiscal 1994 the Company expended $27 million
(net of proceeds from sale of leasehold, equipment and other) for development
and exploration activities. Net cash proceeds received by the Company for sales
of oil and gas equipment, leasehold and other services decreased to
approximately $11 million in fiscal 1996 as compared to $15 million in 1995. In
fiscal 1996, other property and equipment additions were $8.8 million primarily
as a result of the purchase of additional office buildings in Oklahoma City.
The Company's capital spending is largely discretionary. The Company has
established a fiscal 1997 capital expenditure budget of approximately $300
million, of which $80 million is budgeted to fund drilling and completion
requirements for the development of a portion of its proved undeveloped reserves
during fiscal 1997. The Company expects to spend approximately $155 million for
drilling and completion of non-proved reserves, $10 million for seismic
programs, $42 million for acreage acquisition and $13 million for other
corporate purposes. Absent a significant increase in the Company's drilling
schedule, the Company's internally generated cash flow, existing cash resources
and credit facilities should be sufficient to fund its operating activities,
budgeted capital expenditures, and its debt service obligations in fiscal 1997.
However, the Company may seek additional capital in fiscal 1997 to expand its
exploration and development activities or reduce outstanding long-term debt. The
discretionary nature of nearly all of the Company's capital spending permits the
Company to make adjustments to its budget based upon factors such as oil and gas
pricing, exploration and development drilling results, and the continued
availability of internally generated or external capital resources.
25
27
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, believes, goals or projects and similar
expressions are intended to identify forward-looking statements. It is important
to note that Chesapeake's actual results could differ materially from those
projected by such forward-looking statements. Important factors that could cause
actual results to differ materially from those projected in the forward-looking
statements include, but are not limited to, the following: production variances
from expectations, volatility of oil and gas prices, the need to develop and
replace its reserves, the substantial capital expenditures required to fund its
operations, environmental risks, drilling and operating risks, risks related to
exploration and development drilling, uncertainties about estimates of reserves,
competition, government regulation, and the ability of the Company to implement
its business strategy.
26
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Consolidated Financial Statements:
Report of Independent Accountants for the Year Ended June 30, 1996.................. 28
Report of Independent Accountants for the Years Ended June 30, 1995 and 1994........ 29
Consolidated Balance Sheets June 30, 1996 and 1995.................................. 30
Consolidated Statements of Income for the Years Ended June 30, 1996, 1995 and
1994............................................................................. 31
Consolidated Statements of Cash Flows for the Years Ended June 30, 1996, 1995 and
1994............................................................................. 32
Consolidated Statements of Stockholders' Equity for the Years Ended June 30, 1996,
1995 and 1994.................................................................... 34
Notes to Consolidated Financial Statements.......................................... 35
27
29
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders
of Chesapeake Energy Corporation
We have audited the accompanying consolidated balance sheet of Chesapeake
Energy Corporation and its subsidiaries as of June 30, 1996, and the related
consolidated statements of income, stockholders' equity and cash flows for the
year 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 audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Chesapeake
Energy Corporation and its subsidiaries as of June 30, 1996, and the
consolidated results of their operations and their cash flows for the year then
ended in conformity with generally accepted accounting principles.
COOPERS & LYBRAND L.L.P.
Oklahoma City, Oklahoma
September 13, 1996
28
30
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders
of Chesapeake Energy Corporation
In our opinion, the consolidated balance sheet and the related consolidated
statements of income, of cash flows and of stockholders' equity as of and for
each of the two years in the period ended June 30, 1995 present fairly, in all
material respects, the financial position, results of operations and cash flows
of Chesapeake Energy Corporation and its subsidiaries as of and for each of the
two years in the period ended June 30, 1995, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audits to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above. We have not
audited the consolidated financial statements of Chesapeake Energy Corporation
for any period subsequent to June 30, 1995.
PRICE WATERHOUSE LLP
Houston, Texas
September 20, 1995, except for Note 9
which is as of September 23, 1996
29
31
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
JUNE 30,
---------------------
1996 1995
-------- --------
($ IN THOUSANDS)
CURRENT ASSETS:
Cash and cash equivalents............................................ $ 51,638 $ 55,535
Accounts receivable:
Oil and gas sales................................................. 12,687 10,644
Gas marketing sales............................................... 6,982 --
Joint interest and other, net of allowances of $340,000 and
$452,000, respectively........................................... 27,661 26,317
Related parties................................................... 2,884 4,386
Inventory............................................................ 5,163 8,926
Other................................................................ 2,158 633
-------- --------
Total Current Assets......................................... 109,173 106,441
-------- --------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at cost based on full cost accounting:
Evaluated oil and gas properties.................................. 363,213 165,302
Unevaluated properties............................................ 165,441 27,474
Less: accumulated depreciation, depletion and amortization........ (92,720) (41,821)
-------- --------
435,934 150,955
Other property and equipment......................................... 18,162 16,966
Less: accumulated depreciation and amortization...................... (2,922) (4,120)
-------- --------
Total Property and Equipment................................. 451,174 163,801
-------- --------
OTHER ASSETS........................................................... 11,988 6,451
-------- --------
TOTAL ASSETS........................................................... $572,335 $276,693
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Notes payable and current maturities of long-term debt............... $ 6,755 $ 9,993
Accounts payable..................................................... 54,514 33,438
Accrued liabilities and other........................................ 14,062 7,688
Revenues and royalties due others.................................... 33,503 23,786
-------- --------
Total Current Liabilities.................................... 108,834 74,905
-------- --------
LONG-TERM DEBT, NET.................................................... 268,431 145,754
-------- --------
REVENUES AND ROYALTIES DUE OTHERS...................................... 5,118 3,779
-------- --------
DEFERRED INCOME TAXES.................................................. 12,185 7,280
-------- --------
CONTINGENCIES AND COMMITMENTS (Note 4)................................. -- --
-------- --------
STOCKHOLDERS' EQUITY:
Preferred Stock, $.01 par value, 2,000,000 shares authorized; 0
shares issued and outstanding..................................... -- --
Common Stock, 45,000,000 shares authorized; $.10 par value at June
30, 1996, $.0022 par value at June 30, 1995; 30,079,913 and
26,311,248 shares issued and outstanding at June 30, 1996 and
1995, respectively................................................ 3,008 58
Paid-in capital...................................................... 136,782 30,295
Accumulated earnings................................................. 37,977 14,622
-------- --------
Total Stockholders' Equity................................... 177,767 44,975
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY............................. $572,335 $276,693
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
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32
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEAR ENDED JUNE 30,
--------------------------------
1996 1995 1994
-------- ------- -------
($ IN THOUSANDS, EXCEPT
PER SHARE DATA)
REVENUES:
Oil and gas sales.......................................... $110,849 $56,983 $22,404
Gas marketing sales........................................ 28,428 -- --
Oil and gas service operations............................. 6,314 8,836 6,439
Interest and other......................................... 3,831 1,524 981
-------- ------- -------
Total Revenues..................................... 149,422 67,343 29,824
-------- ------- -------
COSTS AND EXPENSES:
Production expenses and taxes.............................. 8,303 4,256 3,647
Gas marketing expenses..................................... 27,452 -- --
Oil and gas service operations............................. 4,895 7,747 5,199
Oil and gas depreciation, depletion and amortization....... 50,899 25,410 8,141
Depreciation and amortization of other assets.............. 3,157 1,765 1,871
General and administrative................................. 4,828 3,578 3,135
Interest and other......................................... 13,679 6,627 2,676
-------- ------- -------
Total Costs and Expenses........................... 113,213 49,383 24,669
-------- ------- -------
INCOME BEFORE INCOME TAXES................................... 36,209 17,960 5,155
INCOME TAX EXPENSE........................................... 12,854 6,299 1,250
-------- ------- -------
NET INCOME................................................... $ 23,355 $11,661 $ 3,905
======== ======= =======
EARNINGS PER COMMON SHARE:
NET INCOME PER COMMON SHARE
Primary................................................. $ .80 $ .42 $ .16
======== ======= =======
Fully-diluted........................................... $ .79 $ .41 $ .16
======== ======= =======
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES
OUTSTANDING
Primary................................................. 29,171 27,936 24,120
======== ======= =======
Fully-diluted........................................... 29,461 28,303 24,183
======== ======= =======
The accompanying notes are an integral part of these consolidated financial
statements.
31
33
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED JUNE 30,
------------------------------------
1996 1995 1994
--------- --------- --------
($ IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME............................................... $ 23,355 $ 11,661 $ 3,905
ADJUSTMENTS TO RECONCILE NET INCOME TO NET CASH PROVIDED
BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization............... 52,768 26,628 9,455
Deferred taxes......................................... 12,854 6,299 1,250
Amortization of loan costs............................. 1,288 548 557
Amortization of bond discount.......................... 563 567 138
Bad debt expense....................................... 114 308 222
Purchases and sales of trading securities, net......... 622 -- --
Gain on sale of fixed assets........................... (2,511) (108) --
CHANGES IN ASSETS AND LIABILITIES:
(Increase) decrease in accounts receivable............. (3,524) (22,510) (7,773)
(Increase) decrease in inventory....................... 78 (1,203) (304)
(Increase) decrease in other current assets............ (1,525) 614 (726)
Increase (decrease) in accounts payable, accrued
liabilities and other............................... 25,834 19,387 10,077
Increase in current and non-current revenues and
royalties due others................................ 11,056 12,540 2,622
--------- --------- --------
Cash provided by operating activities.......... 120,972 54,731 19,423
--------- --------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration, development and acquisition of oil and gas
properties.......................................... (347,294) (120,985) (34,654)
Proceeds from sale of oil and gas equipment, leasehold
and other........................................... 11,416 15,107 7,598
Other proceeds from sales.............................. 698 1,104 765
Investment in gas marketing company, net of cash
acquired............................................ (363) -- --
Other property and equipment additions................. (8,846) (7,929) (2,920)
--------- --------- --------
Cash used in investing activities.............. (344,389) (112,703) (29,211)
--------- --------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of Common Stock................. 99,498 -- --
Proceeds from long-term borrowings..................... 166,667 128,834 48,800
Payments on long-term borrowings....................... (48,634) (32,370) (25,738)
Placement fee on Senior Notes and Warrants............. -- -- (1,900)
Cash received from exercise of stock options........... 1,989 818 --
--------- --------- --------
Cash provided by financing activities.......... 219,520 97,282 21,162
--------- --------- --------
Net increase (decrease) in cash and cash equivalents..... (3,897) 39,310 11,374
Cash and cash equivalents, beginning of period........... 55,535 16,225 4,851
--------- --------- --------
Cash and cash equivalents, end of period................. $ 51,638 $ 55,535 $ 16,225
========= ========= ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAYMENTS FOR:
Interest............................................... $ 17,179 $ 6,488 $ 1,467
Income taxes........................................... $ -- $ -- $ 109
The accompanying notes are an integral part of these consolidated financial
statements.
32
34
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(CONTINUED)
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:
The Company has a financing arrangement with a vendor to supply certain oil
and gas equipment inventory. The total amounts owed at June 30, 1996, 1995 and
1994 were $3,156,000, $6,513,000 and $5,952,000, respectively. No cash
consideration is exchanged for inventory under this financing arrangement until
actual draws on the inventory are made.
In fiscal 1996 and 1995, the Company recognized income tax benefits of
$7,950,000 and $1,229,000, respectively, related to the disposition of stock
options by directors and employees of the Company. The tax benefits were
recorded as an adjustment to deferred income taxes and paid-in capital.
Proceeds from the issuances of $90 million of 10.5% Senior Notes in May
1995 and $120 million of 9.125% Senior Notes in April 1996 are net of $2.7
million and $3.9 million, respectively, in offering fees and expenses which were
deducted from the actual cash received.
On March 31, 1994, the Company issued 8,000 units (see Note 2) to Trust
Company of the West ("TCW") primarily in consideration for the surrender of
576,923 shares of the Company's 9% convertible preferred stock, including its
rights to dividends, warrants to purchase Common Stock and an overriding royalty
interest.
In February 1994, pending litigation was settled pursuant to an agreement
requiring COI to pay $1.25 million, of which $250,000 plus interest was paid in
July 1994, and the balance of which was paid in June 1995.
The accompanying notes are an integral part of these consolidated financial
statements.
33
35
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEAR ENDED JUNE 30,
------------------------------
1996 1995 1994
-------- ------- -------
($ IN THOUSANDS)
PREFERRED STOCK:
Balance, beginning of period................................. $ -- $ -- $ 6
Exchange of 576,923 shares of Preferred Stock................ -- -- (6)
-------- ------- -------
Balance, end of period....................................... -- -- --
-------- ------- -------
COMMON STOCK:
Balance, beginning of period................................. 58 51 51
Issuance of 2,994,750 shares of Common Stock................. 299 -- --
Exercise of stock options and warrants....................... 79 7 --
Change in par value from $.0022 to $.10...................... 2,572 -- --
-------- ------- -------
Balance, end of period....................................... 3,008 58 51
-------- ------- -------
COMMON STOCK WARRANTS:
Balance, beginning of period................................. -- 5 --
Issuance of Common Stock Warrants............................ -- -- 5
Exercise of Common Stock Warrants............................ -- (5) --
-------- ------- -------
Balance, end of period....................................... -- -- 5
-------- ------- -------
PAID-IN CAPITAL:
Balance, beginning of period................................. 30,295 28,243 32,704
Exchange of Preferred Stock.................................. -- -- (7,494)
Issuance of Common Stock Warrants............................ -- -- 3,033
Exercise of stock options and warrants....................... 1,910 823 --
Issuance of Common Stock..................................... 105,516 -- --
Offering expenses and other.................................. (6,317) -- --
Tax benefit from exercise of stock options................... 7,950 1,229 --
Change in par value from $.0022 to $.10...................... (2,572) -- --
-------- ------- -------
Balance, end of period....................................... 136,782 30,295 28,243
-------- ------- -------
ACCUMULATED EARNINGS (DEFICIT):
Balance, beginning of period................................. 14,622 2,961 (1,329)
Net income................................................... 23,355 11,661 3,905
Preferred dividends.......................................... -- -- (340)
Cancellation of preferred dividends.......................... -- -- 725
-------- ------- -------
Balance, end of period....................................... 37,977 14,622 2,961
-------- ------- -------
TOTAL STOCKHOLDERS' EQUITY..................................... $177,767 $44,975 $31,260
======== ======= =======
The accompanying notes are an integral part of these consolidated financial
statements.
34
36
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The accompanying consolidated financial statements of Chesapeake Energy
Corporation (the "Company" or "Parent") include the accounts of Chesapeake
Operating, Inc. ("COI"), Chesapeake Exploration Limited Partnership ("CEX"), a
limited partnership, Chesapeake Gas Development Corporation ("CGDC"), Chesapeake
Energy Marketing, Inc. ("CEMI"), Lindsay Oil Field Supply, Inc. ("LOF"), Sander
Trucking Company, Inc. ("STCO") and subsidiaries of those entities. All
significant intercompany accounts and transactions have been eliminated.
In December 1995, the Company entered into the gas marketing business by
acquiring all of the outstanding stock of an Oklahoma City-based natural gas
marketing company for total consideration of $725,000. This subsidiary was
subsequently named CEMI. CEMI provides natural gas marketing services including
commodity price structuring, contract administration and nomination services for
the Company, its partners and other natural gas producers in the geographical
areas in which the Company is active.
Accounting Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the dates of the financial
statements and the reported amounts of revenues and expenses during the
reporting periods. Actual results could differ from those estimates.
Cash Equivalents
For purposes of the consolidated financial statements, the Company
considers investments in all highly liquid debt instruments with maturities of
three months or less at date of purchase to be cash equivalents.
Inventory
Inventory consists primarily of tubular goods and other lease and well
equipment which the Company plans to utilize in its ongoing exploration and
development activities and is carried at the lower of cost or market using the
specific identification method.
Oil and Gas Properties
The Company follows the full cost method of accounting under which all
costs associated with property acquisition, exploration and development
activities are capitalized. The Company capitalizes internal costs that can be
directly identified with its acquisition, exploration and development activities
and does not include any costs related to production, general corporate overhead
or similar activities (see Note 11). Capitalized costs are amortized on a
composite unit-of-production method based on proved oil and gas reserves. The
Company's oil and gas reserves are estimated annually by independent petroleum
engineers. The average composite rates used for depreciation, depletion and
amortization were $0.85, $0.80 and $0.80 per equivalent Mcf in 1996, 1995, and
1994, respectively. Proceeds from the sale of properties are accounted for as
reductions to capitalized costs unless such sales involve a significant change
in the relationship between costs and the value of proved reserves or the
underlying value of unproved properties, in which case a gain or loss is
recognized. Unamortized costs as reduced by related deferred taxes are subject
to a ceiling which limits such amounts to the estimated present value of oil and
gas reserves, reduced by operating expenses, future development costs and income
taxes. The costs of unproved properties are excluded from amortization until the
properties are evaluated.
35
37
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
On April 30, 1996, the Company purchased interests in certain producing and
non-producing oil and gas properties, including approximately 14,000 net acres
of unevaluated leasehold from Amerada Hess Corporation for $35 million, subject
to adjustment for activity after the effective date of January 1, 1996. The
properties are located in the Knox and Golden Trend fields of southern Oklahoma,
most of which are operated by the Company.
Other Property and Equipment
Other property and equipment primarily consists of vehicles, office
buildings and equipment, and software. Major renewals and betterments are
capitalized while the costs of repairs and maintenance are charged to expense as
incurred. The costs of assets retired or otherwise disposed of and the
applicable accumulated depreciation are removed from the accounts, and the
resulting gain or loss is reflected in operations. Other property and equipment
costs are depreciated on both straight-line and accelerated methods over the
estimated useful lives of the assets, which range from three to 30 years.
Leases
Included in other property and equipment in the consolidated balance sheets
is computer equipment and software held under capital leases. Minimum lease
payments under these capital leases and other operating leases are as follows:
CAPITAL OPERATING
LEASES LEASES
------- ---------
($ IN THOUSANDS)
1997...................................................... $ 62 $ 133
1998...................................................... 62 58
1999...................................................... 15 53
2000...................................................... 0 0
2001...................................................... 0 0
---- ----
Total minimum lease payments.............................. 139 $ 244
====
Less: amount relating to interest......................... (20)
----
Present value of minimum payments......................... $ 119
====
Capitalized Interest
During fiscal 1996, 1995 and 1994, interest of approximately $6,428,000,
$1,574,000 and $356,000 was capitalized on significant investments in unproved
properties that are not being currently depreciated, depleted, or amortized and
on which exploration or development activities are in progress.
Service Operations
Certain subsidiaries of the Company performed contractual services on wells
the Company operates as well as for third parties until June 30, 1996. Oil and
gas service operations revenues and costs and expenses reflected in the
accompanying consolidated statements of income include amounts derived from
certain of the contractual services provided. The Company's economic interest in
its oil and gas properties is not affected by the performance of these
contractual services and all intercompany profits have been eliminated.
On June 30, 1996, Peak USA Energy Services, Ltd., a limited partnership
("Peak"), was formed by Peak Oilfield Services Company (a joint venture between
Cook Inlet Region, Inc. and Nabors Industries, Inc.) and 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
the industry. The Company sold its
36
38
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
service company assets to Peak for $6.4 million, and simultaneously invested
$2.5 million in exchange for a 33.3% partnership interest in Peak. This
transaction resulted in recognition of a $1.8 million pre-tax gain during the
fourth fiscal quarter of 1996 reported in Interest and other. A deferred gain
from the sale of service company assets of $0.9 million was recorded as a
reduction in the Company's investment in Peak and will be amortized to income
over the estimated useful lives of the Peak assets. The Company's investment in
Peak will be accounted for using the equity method.
Income Taxes
The Company has adopted Statement of Financial Accounting Standards No.
109, "Accounting for Income Taxes" ("SFAS 109"). SFAS 109 requires deferred tax
liabilities or assets to be recognized for the anticipated future tax effects of
temporary differences that arise as a result of the differences in the carrying
amounts and the tax bases of assets and liabilities.
Net Income Per Share
Primary and fully diluted earnings per share for all periods have been
computed based upon the weighted average number of shares of Common Stock
outstanding after giving retroactive effect to all stock splits and the issuance
of common stock equivalents when their effect is dilutive. Dilutive options or
warrants which are issued during a period or which expire or are cancelled
during a period are reflected in both primary and fully diluted earnings per
share computations for the time they were outstanding during the period being
reported upon.
Gas Imbalances
The Company follows the "sales method" of accounting for its oil and gas
revenue whereby the Company recognizes sales revenue on all oil or gas sold to
its purchasers, regardless of whether the sales are proportionate to the
Company's ownership in the property. A liability is recognized only to the
extent that the Company has a net imbalance in excess of the reserves on the
underlying properties. The Company's net imbalance positions at June 30, 1996
and 1995 were not material.
Hedging
The Company periodically uses certain instruments to hedge its exposure to
price fluctuations on oil and natural gas transactions. Recognized gains and
losses on hedge contracts are reported as a component of the related
transaction. Results for hedging transactions are reflected in oil and gas sales
to the extent related to the Company's oil and gas production.
Debt Issue Costs
Other assets relate primarily to debt issue costs associated with the
issuance of the 12% Senior Notes on March 31, 1994, the 10.5% Senior Notes on
May 25, 1995, and the 9.125% Senior Notes on April 9, 1996 (see Note 2). The
remaining unamortized costs on these issuances of Senior Notes at June 30, 1996
totaled $8.7 million and are being amortized over the life of the Senior Notes.
Stock Options
In October 1995, the Financial Accounting Standards Board issued Statement
No. 123 ("SFAS 123"), "Accounting for Stock Based Compensation". As permitted by
SFAS 123, the Company plans to continue to retain its current method of
accounting for stock compensation and adopt the disclosure requirements of this
Statement in fiscal 1997.
37
39
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Reclassifications
Certain reclassifications have been made to the consolidated financial
statements for the years ended June 30, 1995 and 1994 to conform to the
presentation used for the June 30, 1996 consolidated financial statements.
2. SENIOR NOTES
On April 9, 1996, the Company completed an offering of $120 million
principal amount of 9.125% Senior Notes due 2006 ("9.125% Senior Notes"). The
9.125% Senior Notes are redeemable at the option of the Company at any time at
the redemption or make-whole prices set forth in the indenture. The Company may
also redeem at its option at any time on or prior to April 15, 1999 up to $42
million of the 9.125% Senior Notes at 109.125% of the principal amount thereof
with the proceeds of an equity offering.
On May 25, 1995, the Company completed a private offering of $90 million
principal amount of 10.5% Senior Notes due 2002 ("10.5% Senior Notes"). The
10.5% Senior Notes are redeemable at the option of the Company at any time on or
after June 1, 1999. The Company may also redeem at its option any time prior to
June 1, 1998 up to $30 million of the 10.5% Senior Notes at 110% of the
principal amount thereof with the proceeds of an equity offering. In September
1995, the Company exchanged the 10.5% Senior Notes for substantially identical
notes in a registered exchange offer (also referred to as the "10.5% Senior
Notes").
On March 31, 1994, the Company completed a private offering of 47,500 Units
consisting of an aggregate of $47.5 million principal amount of 12% Senior Notes
due 2001 ("12% Senior Notes") and warrants ("Warrants") to purchase 2,190,937
shares of the Company's Common Stock at an aggregate exercise price of $4,870.
The Warrants were valued at $3 million creating a discount on the 12% Senior
Notes. All of the Warrants were subsequently exercised. In exchange for 8,000
Units, the Company acquired from Trust Company of the West ("TCW") 576,923
shares of the Company's 9% cumulative convertible preferred stock and all rights
to dividends thereon, warrants to purchase 1,404,004 shares of the Company's
Common Stock and 50% of an outstanding overriding royalty interest held by TCW.
The 12% Senior Notes are redeemable at the option of the Company at any time on
or after March 1, 1998 at an initial premium of 106% of the principal amount
thereof, declining to no premium in 2000. The Company is required to redeem
$11,875,000 principal amount of 12% Senior Notes on each of March 1, 1998, 1999
and 2000. In November 1994, the Company exchanged the 12% Senior Notes for
substantially identical notes in a registered exchange offer (also referred to
as the "12% Senior Notes").
The Company is a holding company and owns no operating assets and has no
significant operations independent of its subsidiaries. The Company's
obligations under the 12% Senior Notes, the 10.5% Senior Notes and the 9.125%
Senior Notes have been fully and unconditionally guaranteed, on a joint and
several basis, by each of the Company's "Restricted Subsidiaries" (as defined in
the respective Indentures governing the Notes): COI, LOF, STCO, Whitmire Dozer
Service, Inc. and CEX (collectively, the "Subsidiary Guarantors"). The only
subsidiaries of the Company that are not Subsidiary Guarantors are CGDC and CEMI
(together, the "Non-Guarantor Subsidiaries"). Each of the Subsidiary Guarantors
is a direct or indirect wholly-owned subsidiary of the Company. The securities
of the Subsidiary Guarantors have been pledged to secure performance of the
Company's obligations under the 12% Senior Notes. The only affiliate securities
constituting a substantial portion of the collateral for the 12% Senior Notes
are the partnership interests in CEX.
The 12%, 10.5% and 9.125% Senior Note Indentures contain certain covenants,
including covenants limiting the Company and the Subsidiary Guarantors with
respect to asset sales; restricted payments; the incurrence of additional
indebtedness and the issuance of preferred stock; liens; sale and leaseback
transactions; lines of business; dividend and other payment restrictions
affecting Subsidiary Guarantors; mergers or consolidations; and transactions
with affiliates. The Company is also obligated to repurchase 12%,
38
40
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10.5% and 9.125% Senior Notes if it fails to maintain a specified ratio of
assets to debt and in the event of a change of control or certain asset sales.
The Company's bank credit agreement prohibits any distributions by CEX to
its partners (the Company and COI) if the maturity of any obligations to the
lender has been accelerated. The pledge agreement relating to the 12% Senior
Notes requires that all dividends and distributions from Subsidiary Guarantors
be paid to the collateral agent thereunder upon an event of default under the
12% Senior Notes Indenture. There are no other restrictions on the payment of
cash dividends by Subsidiary Guarantors.
CEX is a limited partnership which is 10% owned by COI, as sole general
partner, and 90% owned directly by the Company, as sole limited partner. CEX
owns 94% and CGDC owns 6% of the Company's producing oil and gas properties,
based on the present value of future net revenue at June 30, 1996 (discounted at
10%).
Set forth below are condensed consolidating financial statements of CEX,
the other Subsidiary Guarantors, all Subsidiary Guarantors combined, the
Non-Guarantor Subsidiaries and the Company. The CEX limited partnership
condensed financial statements were prepared on a separate entity basis as
reflected in the Company's books and records and include all material costs of
doing business as if the partnership were on a stand-alone basis except that
interest is not charged or allocated. No provision has been made for income
taxes because the partnership is not a taxpaying entity. Separate audited
financial statements of each Subsidiary Guarantor, other than CEX, have not been
provided because management has determined that they are not material to
investors.
39
41
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF JUNE 30, 1996
(IN THOUSANDS)
ASSETS
SUBSIDIARY GUARANTORS
-------------------------------- NON-
ALL GUARANTOR COMPANY
CEX OTHERS COMBINED SUBSIDIARIES (PARENT) ELIMINATIONS CONSOLIDATED
-------- -------- ---------- ------------ -------- ------------ ------------
CURRENT ASSETS:
Cash and cash equivalents......... $ -- $ 4,061 $ 4,061 $ 2,751 $44,826 $ -- $ 51,638
Accounts receivable............... 14,778 29,302 44,080 7,723 -- (1,589) 50,214
Inventory......................... -- 4,947 4,947 216 -- -- 5,163
Other............................. 1,891 264 2,155 3 -- -- 2,158
-------- -------- ---------- -------- ------- --------- --------
Total Current Assets........ 16,669 38,574 55,243 10,693 44,826 (1,589) 109,173
-------- -------- ---------- -------- ------- --------- --------
PROPERTY AND EQUIPMENT:
Oil and gas properties............ 346,821 (8,211) 338,610 24,603 -- -- 363,213
Unevaluated leasehold............. 165,441 -- 165,441 -- -- -- 165,441
Other property and equipment...... -- 9,608 9,608 61 8,493 -- 18,162
Less: accumulated depreciation,
depletion and amortization...... (84,726) (2,467) (87,193) (8,007) (442) -- (95,642)
-------- -------- ---------- -------- ------- --------- --------
427,536 (1,070) 426,466 16,657 8,051 -- 451,174
-------- -------- ---------- -------- ------- --------- --------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES............. 56,055 463,331 519,386 8,132 382,388 (909,906) --
OTHER ASSETS........................ 694 1,616 2,310 940 8,738 -- 11,988
-------- -------- ---------- -------- ------- --------- --------
TOTAL ASSETS........................ $500,954 $502,451 $1,003,405 $ 36,422 $444,003 $(911,495) $572,335
======== ======== ========== ======== ======== ========= ========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Notes payable and current
maturities of long-term debt.... $ -- $ 3,846 $ 3,846 $ 2,880 $ 29 $ -- $ 6,755
Accounts payable and other........ 789 90,280 91,069 7,339 5,260 (1,589) 102,079
-------- -------- ---------- -------- ------- --------- --------
Total Current Liabilities... 789 94,126 94,915 10,219 5,289 (1,589) 108,834
-------- -------- ---------- -------- ------- --------- --------
LONG-TERM DEBT...................... -- 2,113 2,113 10,020 256,298 -- 268,431
-------- -------- ---------- -------- ------- --------- --------
REVENUES AND ROYALTIES DUE OTHERS... -- 5,118 5,118 -- -- -- 5,118
-------- -------- ---------- -------- ------- --------- --------
DEFERRED INCOME TAXES............... -- 23,950 23,950 1,335 (13,100) -- 12,185
-------- -------- ---------- -------- ------- --------- --------
INTERCOMPANY PAYABLES............... 413,726 410,581 824,307 8,182 73,647 (906,136) --
-------- -------- ---------- -------- ------- --------- --------
STOCKHOLDERS' EQUITY:
Common Stock...................... -- 117 117 2 2,891 (2) 3,008
Other............................. 86,439 (33,554) 52,885 6,664 118,978 (3,768) 174,759
-------- -------- ---------- -------- ------- --------- --------
86,439 (33,437) 53,002 6,666 121,869 (3,770) 177,767
-------- -------- ---------- -------- ------- --------- --------
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY............................ $500,954 $502,451 $1,003,405 $ 36,422 $444,003 $(911,495) $572,335
======== ======== ========== ======== ======== ========= ========
40
42
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF JUNE 30, 1995
(IN THOUSANDS)
ASSETS
SUBSIDIARY GUARANTORS
------------------------------ NON-
ALL GUARANTOR COMPANY
CEX OTHERS COMBINED SUBSIDIARIES (PARENT) ELIMINATIONS CONSOLIDATED
-------- -------- -------- ------------ -------- ------------ ------------
CURRENT ASSETS:
Cash and cash equivalents.......... $ -- $ 53,227 $ 53,227 $ 5 $ 2,303 $ -- $ 55,535
Accounts receivable................ 9,867 30,693 40,560 777 10 -- 41,347
Inventory.......................... -- 8,895 8,895 31 -- -- 8,926
Other.............................. -- 633 633 -- -- -- 633
-------- -------- -------- ------- -------- --------- --------
Total Current Assets......... 9,867 93,448 103,315 813 2,313 -- 106,441
-------- -------- -------- ------- -------- --------- --------
PROPERTY AND EQUIPMENT:
Oil and gas properties............. 163,521 (16,723) 146,798 18,504 -- -- 165,302
Unevaluated leasehold.............. 27,474 -- 27,474 -- -- -- 27,474
Other property and equipment....... -- 12,199 12,199 -- 4,767 -- 16,966
Less: accumulated depreciation,
depletion and amortization....... (36,959) (3,847) (40,806) (4,861) (274) -- (45,941)
-------- -------- -------- ------- -------- --------- --------
154,036 (8,371) 145,665 13,643 4,493 -- 163,801
-------- -------- -------- ------- -------- --------- --------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES.............. 17,559 181,914 199,473 -- 176,795 (376,268) --
OTHER ASSETS......................... 776 41 817 123 5,511 6,451
-------- -------- -------- ------- -------- --------- --------
TOTAL ASSETS......................... $182,238 $267,032 $449,270 $14,579 $189,112 $(376,268) $276,693
======== ======== ======== ======= ======== ========= ========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Notes payable and current
maturities of long-term debt..... $ -- $ 7,757 $ 7,757 $ 2,200 $ 36 $ -- $ 9,993
Accounts payable and other......... 516 61,777 62,293 -- 2,619 -- 64,912
-------- -------- -------- ------- -------- --------- --------
Total Current Liabilities.... 516 69,534 70,050 2,200 2,655 -- 74,905
-------- -------- -------- ------- -------- --------- --------
LONG-TERM DEBT....................... 10 1,326 1,336 8,600 135,818 -- 145,754
-------- -------- -------- ------- -------- --------- --------
REVENUES AND ROYALTIES DUE OTHERS.... -- 3,779 3,779 -- -- -- 3,779
-------- -------- -------- ------- -------- --------- --------
DEFERRED INCOME TAXES................ -- 9,621 9,621 164 (2,505) -- 7,280
-------- -------- -------- ------- -------- --------- --------
INTERCOMPANY PAYABLES................ 140,236 201,959 342,195 3,307 30,766 (376,268) --
-------- -------- -------- ------- -------- --------- --------
STOCKHOLDERS' EQUITY:
Common Stock....................... -- 31 31 1 58 (32) 58
Other.............................. 41,476 (19,218) 22,258 307 22,320 32 44,917
-------- -------- -------- ------- -------- --------- --------
41,476 (19,187) 22,289 308 22,378 -- 44,975
-------- -------- -------- ------- -------- --------- --------
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY............................. $182,238 $267,032 $449,270 $14,579 $189,112 $(376,268) $276,693
======== ======== ======== ======= ======== ========= ========
41
43
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
SUBSIDIARY GUARANTORS
------------------------------ NON-
ALL GUARANTOR COMPANY
CEX OTHERS COMBINED SUBSIDIARIES (PARENT) ELIMINATIONS CONSOLIDATED
-------- -------- -------- ------------ -------- ------------ ------------
FOR THE YEAR ENDED JUNE 30, 1996:
REVENUES:
Oil and gas sales.................. $103,712 $ -- $103,712 $ 6,884 $ -- $ 253 $110,849
Gas marketing sales................ -- -- -- 34,973 -- (6,545) 28,428
Oil and gas service operations..... -- 6,314 6,314 -- -- -- 6,314
Interest and other................. (1,473) 3,390 1,917 238 1,676 -- 3,831
-------- -------- ------- ------- -------- ------- --------
102,239 9,704 111,943 42,095 1,676 (6,292) 149,422
-------- -------- ------- ------- -------- ------- --------
COSTS AND EXPENSES:
Production expenses and taxes...... 7,225 332 7,557 746 -- -- 8,303
Gas marketing expenses............. -- -- -- 33,744 -- (6,292) 27,452
Oil and gas service operations..... -- 4,895 4,895 -- -- -- 4,895
Oil and gas depreciation, depletion
and amortization................. 48,333 -- 48,333 2,566 -- -- 50,899
Other depreciation and
amortization..................... 258 1,666 1,924 73 1,160 -- 3,157
General and administrative......... 1,090 2,593 3,683 496 649 -- 4,828
Interest and other................. 370 138 508 711 12,460 -- 13,679
-------- -------- ------- ------- -------- ------- --------
57,276 9,624 66,900 38,336 14,269 (6,292) 113,213
-------- -------- ------- ------- -------- ------- --------
Income (loss) before income
taxes............................ 44,963 80 45,043 3,759 (12,593) -- 36,209
Income tax expense (benefit)....... -- 15,990 15,990 1,335 (4,471) -- 12,854
-------- -------- ------- ------- -------- ------- --------
Net income (loss).................. $ 44,963 $(15,910) $29,053 $ 2,424 $ (8,122) $ -- $ 23,355
======== ======== ======= ======= ======== ======= ========
FOR THE YEAR ENDED JUNE 30, 1995:
REVENUES:
Oil and gas sales.................. $ 55,417 $ -- $55,417 $ 1,566 $ -- $ -- $ 56,983
Oil and gas service operations..... -- 8,836 8,836 -- -- -- 8,836
Interest and other................. -- 1,394 1,394 -- 130 -- 1,524
-------- -------- ------- ------- -------- ------- --------
55,417 10,230 65,647 1,566 130 -- 67,343
-------- -------- ------- ------- -------- ------- --------
COSTS AND EXPENSES:
Production expenses and taxes...... 3,494 551 4,045 211 -- -- 4,256
Oil and gas service operations..... -- 7,747 7,747 -- -- -- 7,747
Oil and gas depreciation, depletion
and amortization................. 24,769 6 24,775 635 -- -- 25,410
Other depreciation and
amortization..................... 138 1,107 1,245 5 515 -- 1,765
General and administrative......... 931 1,689 2,620 58 900 -- 3,578
Interest and other................. 352 218 570 184 5,873 -- 6,627
-------- -------- ------- ------- -------- ------- --------
29,684 11,318 41,002 1,093 7,288 -- 49,383
-------- -------- ------- ------- -------- ------- --------
Income (loss) before income
taxes............................ 25,733 (1,088) 24,645 473 (7,158) -- 17,960
Income tax expense (benefit)....... -- 8,639 8,639 165 (2,505) -- 6,299
-------- -------- ------- ------- -------- ------- --------
Net Income (loss).................. $ 25,733 $ (9,727) $16,006 $ 308 $ (4,653) $ -- $ 11,661
======== ======== ======= ======= ======== ======= ========
FOR THE YEAR ENDED JUNE 30, 1994:
REVENUES:
Oil and gas sales.................. $ 22,404 $ -- $22,404 $ -- $ -- $ -- $ 22,404
Oil and gas service operations..... -- 6,439 6,439 -- -- -- 6,439
Interest and other................. -- 622 622 -- 359 -- 981
-------- -------- ------- ------- -------- ------- --------
22,404 7,061 29,465 -- 359 -- 29,824
-------- -------- ------- ------- -------- ------- --------
COSTS AND EXPENSES:
Production expenses and taxes...... 3,185 462 3,647 -- -- -- 3,647
Oil and gas service operations..... -- 5,199 5,199 -- -- -- 5,199
Oil and gas depreciation, depletion
and amortization................. 8,141 -- 8,141 -- -- -- 8,141
Other depreciation and
amortization..................... 171 1,536 1,707 -- 164 -- 1,871
General and administrative......... 823 2,169 2,992 -- 143 -- 3,135
Interest and other................. 507 1,492 1,999 -- 677 -- 2,676
-------- -------- ------- ------- -------- ------- --------
12,827 10,858 23,685 -- 984 -- 24,669
-------- -------- ------- ------- -------- ------- --------
Income (loss) before income
taxes............................ 9,577 (3,797) 5,780 -- (625) -- 5,155
Income tax expense (benefit)....... -- 1,400 1,400 -- (150) -- 1,250
-------- -------- ------- ------- -------- ------- --------
Net income (loss).................. $ 9,577 $ (5,197) $ 4,380 $ -- $ (475) $ -- $ 3,905
======== ======== ======= ======= ======== ======= ========
42
44
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)
SUBSIDIARY GUARANTORS
-------------------------------- NON-
ALL GUARANTOR COMPANY
CEX OTHERS COMBINED SUBSIDIARIES (PARENT) ELIMINATIONS CONSOLIDATED
--------- -------- --------- ------------ --------- ------------ ------------
FOR THE YEAR ENDED JUNE 30, 1996:
CASH FLOWS FROM OPERATING
ACTIVITIES.......................... $ 91,286 $ 35,582 $ 126,868 $ 4,204 $ (10,100) $ -- $ 120,972
CASH FLOWS FROM INVESTING ACTIVITIES
Oil and gas properties.............. (329,507) (16,988) (346,495) (6,099) -- 5,300 (347,294)
Proceeds from sales................. 7,458 9,956 17,414 -- -- (5,300) 12,114
Investment in gas marketing
company........................... -- -- -- 266 (629) -- (363)
Other additions..................... (177) (4,506) (4,683) (109) (4,054) -- (8,846)
--------- -------- --------- -------- --------- -------- ----------
(322,226) (11,538) (333,764) (5,942) (4,683) -- (344,389)
--------- -------- --------- -------- --------- -------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings............ 39,000 1,350 40,350 10,300 116,017 -- 166,667
Payments on borrowings.............. (44,010) (1,387) (45,397) (3,200) (37) -- (48,634)
Cash received from exercise of stock
options........................... -- -- -- -- 1,989 -- 1,989
Cash received from issuance of
common stock...................... -- -- -- -- 99,498 -- 99,498
Intercompany advances, net.......... 235,950 (73,173) 162,777 (2,616) (160,161) -- --
--------- -------- --------- -------- --------- -------- ----------
230,940 (73,210) 157,730 4,484 57,306 -- 219,520
--------- -------- --------- -------- --------- -------- ----------
Net increase (decrease) in cash and
cash equivalents.................... -- (49,166) (49,166) 2,746 42,523 -- (3,897)
Cash, beginning of period............. -- 53,227 53,227 5 2,303 -- 55,535
--------- -------- --------- -------- --------- -------- ----------
Cash, end of period................... $ -- $ 4,061 $ 4,061 $ 2,751 $ 44,826 $ -- $ 51,638
========= ======== ========= ======== ========= ======== ==========
FOR THE YEAR ENDED JUNE 30, 1995:
CASH FLOWS FROM OPERATING
ACTIVITIES.......................... $ 46,753 $ 13,296 $ 60,049 $ 305 $ (4,692) $ (931) $ 54,731
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties.............. (111,980) (4,896) (116,876) (4,109) -- -- (120,985)
Proceeds from sales................. 16,579 11,132 27,711 -- -- (11,500) 16,211
Purchase of oil and gas
properties........................ -- -- -- (11,500) -- 11,500 --
Other additions..................... -- (7,929) (7,929) -- -- -- (7,929)
--------- -------- --------- -------- --------- -------- ----------
(95,401) (1,693) (97,094) (15,609) -- -- (112,703)
--------- -------- --------- -------- --------- -------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings............ 28,433 1,601 30,034 11,500 87,300 -- 128,834
Payments on borrowings.............. (28,433) (3,599) (32,032) (700) 362 -- (32,370)
Intercompany advances, net.......... 48,648 29,676 78,324 4,509 (83,764) 931 --
Other financing..................... -- -- -- -- 818 -- 818
--------- -------- --------- -------- --------- -------- ----------
48,648 27,678 76,326 15,309 4,716 931 97,282
--------- -------- --------- -------- --------- -------- ----------
Net increase (decrease) in cash and
cash equivalents.................... -- 39,281 39,281 5 24 -- 39,310
Cash, beginning of period............. -- 13,946 13,946 -- 2,279 -- 16,225
--------- -------- --------- -------- --------- -------- ----------
Cash, end of period................... $ -- $ 53,227 $ 53,227 $ 5 $ 2,303 $ -- $ 55,535
========= ======== ========= ======== ========= ======== ==========
FOR THE YEAR ENDED JUNE 30, 1994:
CASH FLOWS FROM OPERATING
ACTIVITIES.......................... $ 13,131 $ 7,707 $ 20,838 $ -- $ (1,415) $ -- $ 19,423
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties.............. (33,466) (1,188) (34,654) -- -- -- (34,654)
Proceeds from sales................. 3,268 5,095 8,363 -- -- -- 8,363
Other additions..................... (159) (1,782) (1,941) -- (979) -- (2,920)
--------- -------- --------- -------- --------- -------- ----------
(30,357) 2,125 (28,232) -- (979) -- (29,211)
--------- -------- --------- -------- --------- -------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings............ -- 8,800 8,800 -- 40,000 -- 48,800
Payments on borrowings.............. (10,201) (15,537) (25,738) -- -- -- (25,738)
Intercompany advances, net.......... 27,250 6,715 33,965 -- (33,965) -- --
Other financing..................... -- -- -- -- (1,900) -- (1,900)
--------- -------- --------- -------- --------- -------- ----------
17,049 (22) 17,027 -- 4,135 -- 21,162
--------- -------- --------- -------- --------- -------- ----------
Net increase (decrease) in cash and
cash equivalents.................... (177) 9,810 9,633 -- 1,741 -- 11,374
Cash, beginning of period............. 177 4,136 4,313 -- 538 -- 4,851
--------- -------- --------- -------- --------- -------- ----------
Cash, end of period................... $ -- $ 13,946 $ 13,946 $ -- $ 2,279 $ -- $ 16,225
========= ======== ========= ======== ========= ======== ==========
43
45
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. NOTES PAYABLE AND LONG-TERM DEBT
Notes payable and long-term debt consist of the following:
JUNE 30,
---------------------
1996 1995
-------- --------
($ IN THOUSANDS)
9.125% Senior Notes (see Note 2)............................... $120,000 $ --
Discount on 9.125% Senior Notes................................ (81) --
10.5% Senior Notes (see Note 2)................................ 90,000 90,000
12% Senior Notes (see Note 2).................................. 47,500 47,500
Discount on 12% Senior Notes................................... (1,772) (2,333)
Term note payable to Union Bank collateralized by CGDC, not
guaranteed by the Company, variable interest at Union Bank's
base rate (8.25% per annum at June 30, 1996), or at
Eurodollar rate +1.875% collateralized by CGDC's producing
oil and gas properties, payable in monthly installments
through November 2002........................................ 12,900 10,800
Term note payable to Union Bank, variable interest at Union
Bank's base rate or at Eurodollar rate + an incremental rate
(8.25% per annum at June 30, 1996), collateralized by CEX's
producing oil and gas properties and guaranteed by the
Company...................................................... -- 10
Note payable to a vendor, collateralized by oil and gas
tubulars, payments due 60 days from shipment of the
tubulars..................................................... 3,156 6,513
Note payable to a bank, variable interest at a referenced base
rate + 1.75% (10% per annum at June 30, 1996), collateralized
by office buildings, payments due in monthly installments
through May 1998............................................. 680 686
Notes payable to various entities to acquire oil service
equipment, interest varies from 7% to 11% per annum,
collateralized by equipment, payments due in monthly
installments through December 2000........................... 1,212 2,162
Other collateralized........................................... 1,469 230
Other, unsecured............................................... 122 179
-------- --------
Total notes payable and long-term debt......................... 275,186 155,747
Less -- Current maturities..................................... (6,755) (9,993)
-------- --------
Notes payable and long-term debt, net of current maturities.... $268,431 $145,754
======== ========
The aggregate scheduled maturities of notes payable and long-term debt for
the next five fiscal years ending June 30, 2001 and thereafter were as follows
as of June 30, 1996 (in thousands of dollars):
1997.............................................................. $ 6,755
1998.............................................................. 14,234
1999.............................................................. 13,637
2000.............................................................. 13,344
2001.............................................................. 14,565
After 2001........................................................ 212,651
--------
$275,186
========
In April 1993, CEX entered into an oil and gas reserve-based reducing
revolving credit facility (the "Revolving Credit Facility") with Union Bank. The
Revolving Credit Facility has been amended from time to
44
46
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
time, most recently in September 1996. Concurrent with the September 1996
amendment, the Company increased the facility size to $125 million and expanded
its bank group with Union Bank remaining as agent.
The maturity date of the Revolving Credit Facility is April 30, 2001. The
facility provides for interest at the Union Bank reference rate (8.25% at June
30, 1996) or, at the option of the Company the Eurodollar rate plus 1.375% to
1.875% depending on the ratio of the amount outstanding to the borrowing base.
Borrowings are collateralized by a first priority lien on substantially all of
CEX's proved producing reserves, and are unconditionally guaranteed by the
Company. At June 30, 1996 and 1995 there was $0 and $10,000 outstanding under
the Revolving Credit Facility, respectively.
The amount of credit available at any time under the Revolving Credit
Facility is the lesser of the commitment amount or the borrowing base. The
borrowing base is reduced each month by a specified amount. Both the borrowing
base and the monthly reduction amount are redetermined by Union Bank each May 1
and November 1 and may be redetermined at any other time upon the request of CEX
or Union Bank. To the extent the amount outstanding at any time exceeds the
borrowing base, CEX must reduce the amount outstanding or add additional
collateral. At June 30, 1996, the commitment amount and the borrowing base under
the Revolving Credit Facility were $35 million, and the monthly reduction amount
was $700,000. The Revolving Credit Facility was amended in September 1996 to
provide for a borrowing base and a commitment amount of $75 million, with a
monthly reduction amount of $1,750,000. The Revolving Credit Facility contains
customary financial covenants, limitations on indebtedness and liabilities,
liens, prepayments of other indebtedness (including the 12%, 10.5% and 9.125%
Senior Notes) and loans, investments and guarantees by the Company and prohibits
the payment of dividends on the Company's Common Stock.
The Company's wholly-owned subsidiary, CGDC, has a credit facility with
Union Bank (the "Term Credit Facility"), with an outstanding balance of $12.9
million at June 30, 1996. Collateral for the Term Credit Facility is limited to
CGDC's producing oil and gas properties. The Term Credit Facility has not been
guaranteed by the Company or any of its other subsidiaries and is recourse only
to the assets of CGDC. CGDC acquired producing oil and gas properties from CEX
in December 1994, June 1995 and December 1995 in exchange for $5.5 million, $6
million and $5.3 million in cash, respectively, using proceeds borrowed under
this facility. CGDC has not guaranteed the payment of the Company's 12%, 10.5%
or 9.125% Senior Notes, nor has the capital stock of CGDC been pledged as
collateral for such indebtedness. The terms of the Term Credit Facility prohibit
the payment of dividends by CGDC.
4. CONTINGENCIES AND COMMITMENTS
The Company is currently involved in various routine disputes incidental to
its business operations. While it is not possible to determine the ultimate
disposition of these matters, management, after consultation with legal counsel,
is of the opinion that the final resolution of all currently pending or
threatened litigation is not likely to have a material adverse effect on the
consolidated financial position or results of operations of the Company.
The Company has employment contracts with its two principal shareholders
and its chief financial officer and various other senior management personnel
which provide for annual base salaries, bonus compensation and various benefits.
The contracts provide for the continuation of salary and benefits for the
respective terms of the agreements in the event of termination of employment
without cause. These agreements expire June 30, 1997 through June 30, 1998.
Due to the nature of the oil and gas business, the Company and its
subsidiaries are exposed to possible environmental risks. The Company has
implemented various policies and procedures to avoid environmental contamination
and risks from environmental contamination. The Company is not aware of any
potential environmental issues or claims.
45
47
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. INCOME TAXES
As discussed in Note 1, the Company has adopted SFAS 109. The components of
the income tax provision for each of the periods are as follows:
YEAR ENDED JUNE 30,
-----------------------------
1996 1995 1994
------- ------ ------
($ IN THOUSANDS)
Current................................................. $ -- $ -- $ --
Deferred................................................ 12,854 6,299 1,250
------- ------ ------
Total......................................... $12,854 $6,299 $1,250
======= ====== ======
The effective income tax rate differed from the computed "expected" federal
income tax rate on earnings before income taxes for the following reasons:
YEAR ENDED JUNE 30,
-----------------------------
1996 1995 1994
------- ------ ------
($ IN THOUSANDS)
Computed "expected" income tax provision................ $12,673 $6,286 $1,753
Tax percentage depletion................................ (238) (144) (780)
Other................................................... 419 157 277
------- ------ ------
$12,854 $6,299 $1,250
======= ====== ======
Deferred income taxes are provided to reflect temporary differences in the
basis of net assets for income tax and financial reporting purposes. The tax
effected temporary differences and tax loss carryforwards which comprise
deferred taxes are as follows:
YEAR ENDED JUNE 30,
----------------------------------
1996 1995 1994
-------- -------- --------
($ IN THOUSANDS)
Deferred tax liabilities:
Acquisition, exploration and development costs and
related depreciation, depletion and
amortization..................................... $(63,725) $(31,220) $(15,872)
------- ------ ------
Deferred tax assets:
Net operating loss carryforwards................... 50,776 23,414 12,879
Percentage depletion carryforward.................. 764 526 780
------- ------ ------
51,540 23,940 13,659
------- ------ ------
Total Deferred Income Taxes........................ $(12,185) $ (7,280) $ (2,213)
======= ====== ======
At June 30, 1996, the Company had regular tax net operating loss
carryforwards of approximately $140 million and alternative minimum tax net
operating loss carryforwards of approximately $15 million. These loss
carryforward amounts will expire during the years 2007 through 2011. The Company
also had a percentage depletion carryforward of approximately $2.3 million at
June 30, 1996, which is available to offset future federal income taxes payable
and has no expiration date.
In accordance with certain provisions of the Tax Reform Act of 1986, a
change of greater than 50% of the beneficial ownership of the Company within a
three-year period (an "Ownership Change") would place an annual limitation on
the Company's ability to utilize its existing tax carryforwards. Under
regulations issued by
46
48
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the Internal Revenue Service, the Company does not believe that an Ownership
Change has occurred as of June 30, 1996.
6. RELATED PARTY TRANSACTIONS
Certain directors, shareholders and employees of the Company have acquired
working interests in certain of the Company's oil and gas properties. The owners
of such working interests are required to pay their proportionate share of all
costs. As of June 30, 1996, 1995 and 1994 the Company had accounts receivable
for these costs of $2.9 million, $4.4 million and $1.7 million, respectively.
During fiscal 1996, 1995 and 1994 the Company incurred legal expenses of
$347,000, $516,000 and $631,000, respectively, for legal services provided by
the law firm of which a director is a member.
7. EMPLOYEE BENEFIT PLANS
Effective October 1, 1989, the Company established a 401(K) profit sharing
plan. On December 1, 1993, the Company amended the plan and established the
Chesapeake Energy Savings and Incentive Plan. On January 1, 1996 the Company
amended the plan and established the Chesapeake Energy Corporation Savings and
Incentive Stock Bonus Plan (the "Savings and Incentive Stock Bonus Plan").
Eligible employees may make voluntary contributions to the Savings and Incentive
Stock Bonus Plan which are matched by the Company up to 10% of the employees'
annual salary with the Company's common stock. The amount of employee
contributions is limited as specified in the Savings and Incentive Stock Bonus
Plan. The Company may, at its discretion, make additional contributions to the
Savings and Incentive Stock Bonus Plan. The Company contributed $187,000,
$95,000 and $70,000 to the Savings and Incentive Stock Bonus Plan during the
fiscal years ended June 30, 1996, 1995 and 1994, respectively.
8. MAJOR CUSTOMERS
Sales to individual customers constituting 10% or more of total oil and gas
sales were as follows:
AMOUNT
---------------- PERCENT OF
YEAR ($ IN THOUSANDS) OIL AND GAS SALES
- ---- -----------------
1996 Aquila Southwest Pipeline Corporation $ 41,900 38%
GPM Gas Corporation $ 28,700 26%
Wickford Energy Marketing, L.C. $ 18,500 17%
1995 Aquila Southwest Pipeline Corporation $ 18,548 33%
Wickford Energy Marketing, L.C. $ 15,704 28%
GPM Gas Corporation $ 11,686 21%
1994 Wickford Energy Marketing, L.C. $ 6,190 28%
GPM Gas Corporation $ 6,105 27%
Plains Marketing and Transportation, $ 2,659 12%
Inc.
Texaco Exploration & Production, Inc. $ 2,249 10%
Management believes that the loss of any of the above customers would not
have a material impact on the Company's results of operations or its financial
position.
9. STOCKHOLDERS' EQUITY
On April 9, 1996 the Company completed a public offering of 2,475,000
shares of Common Stock at a price of $35.33 per share, resulting in net proceeds
(after offering costs) to the Company of approximately $82.1 million. On April
12, 1996, the underwriters exercised an over-allotment option to purchase an
47
49
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
additional 519,750 shares of Common Stock at a price of $35.33 per share,
resulting in additional net proceeds (after offering costs) to the Company of
approximately $17.3 million. The net proceeds from the offering were used to
fund a portion of the Company's exploration and development capital expenditures
and for general corporate purposes.
On March 31, 1994, the Company issued 12% Senior Notes and Warrants for
2,190,937 shares of the Company's Common Stock (see Note 2). The Warrants were
valued at $3.04 million and are recorded as Common Stock Warrants and paid-in
capital on the accompanying consolidated balance sheets. A portion of the 12%
Senior Notes and Warrants were issued to Trust Company of the West in exchange
for preferred stock, warrants to purchase Common Stock and an overriding royalty
interest.
A 1.8-for-1 stock split of the Common Stock in January 1993, a 2-for-1
stock split of the Common Stock in December 1994, and 3-for-2 stock splits of
the Common Stock in December 1995 and June 1996 have been given retroactive
effect in these financial statements.
Stock Option Plans
Under the Company's 1992 Incentive Stock Option Plan (the "ISO Plan"),
options to purchase Common Stock may be granted only to employees of the Company
and its subsidiaries. Subject to any adjustment as provided by the ISO Plan, the
aggregate number of shares which may be issued and sold may not exceed 1,881,000
shares. The maximum period for exercise of an option may not be more than ten
years (or five years for an optionee who owns more than 10% of the Common Stock)
from the date of grant, and the exercise price may not be less than the fair
market value of the shares underlying the options on the date of grant (or 110%
of such value for an optionee who owns more than 10% of the Common Stock).
Options granted become exercisable at dates determined by the Stock Option
Committee of the Board of Directors. No options may be granted under the ISO
Plan after December 16, 1994.
Under the Company's 1992 Nonstatutory Stock Option Plan (the "NSO Plan"),
non-qualified options to purchase Common Stock may be granted only to directors
and consultants of the Company. Subject to any adjustment as provided by the NSO
Plan, the aggregate number of shares which may be issued and sold may not exceed
1,566,000 shares. The maximum period for exercise of an option may not be more
than ten years from the date of grant, and the exercise price may not be less
than the fair market value of the shares underlying the options on the date of
grant. Options granted become exercisable at dates determined by the Stock
Option Committee of the Board of Directors. No options may be granted under the
NSO Plan after December 10, 2002.
Under the Company's 1994 Stock Option Plan (the "1994 Plan"), incentive and
nonqualified stock options to purchase Common Stock may be granted to employees
of the Company and its subsidiaries. Subject to any adjustment as provided by
the 1994 Plan, the aggregate number of shares which may be issued and sold may
not exceed 2,443,455 shares. The maximum period for exercise of an option may
not be more than ten years from the date of grant, and the exercise price may
not be less than the fair market value of the shares underlying the options on
the date of grant. Options granted become exercisable at dates determined by the
Stock Option Committee of the Board of Directors. No options may be granted
under the 1994 Plan after December 16, 2004.
48
50
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
# OF OPTION
OPTIONS PRICES
--------- -------------
Options outstanding at June 30, 1993...................... 885,780 $1.11- $2.67
Options granted........................................... 1,640,250 $1.11- $1.71
Options exercised......................................... -- -
Options terminated........................................ (9,360) $1.11- $1.33
Options outstanding at June 30, 1994...................... 2,516,670 $1.11- $2.67
Options granted........................................... 1,592,775 $4.50- $9.84
Options exercised......................................... (644,366) $1.11- $2.67
Options terminated........................................ (50,783) $1.11- $4.50
Options outstanding at June 30, 1995...................... 3,414,296 $1.11- $9.84
Options granted........................................... 1,213,425 $11.33-$35.33
Options exercised......................................... (787,023) $1.11-$35.33
Options terminated........................................ (39,256) $1.11-$11.33
Options outstanding at June 30, 1996...................... 3,801,442 $1.11-$35.33
The exercise of certain stock options results in state and federal income
tax benefits to the Company related to the difference between the market price
of the Common Stock at the date of disposition (or sale) and the option price.
During fiscal 1996 and 1995, $7,950,000 and $1,229,000 was recorded as an
adjustment to additional paid-in capital and deferred income taxes with respect
to such tax benefits.
10. FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
The Company has only limited involvement with derivative financial
instruments, as defined in Statement of Financial Accounting Standards No. 119
"Disclosure About Derivative Financial Instruments and Fair Value of Financial
Instruments" and does not use them for trading purposes. The Company's objective
is to hedge a portion of its exposure to price volatility from producing crude
oil and natural gas. These arrangements may expose the Company to credit risk
from its counter-parties and to basis risk.
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 swap
arrangements that establish an index-related price above which the Company pays
the hedging partner and below which the Company is paid by the hedging partner,
the purchase of index-related puts that provide for a "floor" price to the
Company to be paid by the counter-party to the extent the price of the commodity
is below the contracted floor, and basis protection swaps.
As of June 30, 1996, the Company had established NYMEX-based crude oil swap
agreements for 1,000 Bbl per day for July 1, 1996 through August 31, 1996 at an
average price of $17.85 per Bbl. The counter-party has the option exercisable
monthly for an additional 1,000 Bbl per day for the period July 1, 1996 through
December 31, 1996 to cause a swap if the price exceeds an average $17.74 per
Bbl. The actual settlements for July and August resulted in a $0.5 million
payment to the counter-party. The Company estimates, based on NYMEX prices as of
August 30, 1996, that the effect of the September through December hedges would
be a $0.4 million payment to the counter-party.
The Company has purchased Houston Ship Channel put options which guarantee
the Company an average floor price of $2.21/Mmbtu for 20,000 Mmbtu per day for
the period of November 1, 1996 through February 28, 1997. The average cost of
these puts was $0.14 per Mmbtu.
As of June 30, 1996, the Company had NYMEX-based natural gas swaps and
NYMEX/Houston Ship Channel Basis swaps for the months of July through October
1996. These transactions resulted in payments to
49
51
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the Company's counter-party of approximately $2 million for the month of July
1996 and $1.5 million for the month of August 1996. The Company estimates, based
on NYMEX prices as of August 30, 1996, that the effect of the September and
October hedges would be a $0.2 million payment to the counter-party.
Concentration of Credit Risk
Financial instruments which potentially subject the Company to
concentrations of credit risk consist principally of trade receivables. The
Company's accounts receivable are primarily from purchasers of oil and natural
gas products and exploration and production companies which own interests in
properties operated by the Company. The industry concentration has the potential
to impact the Company's overall exposure to credit risk, either positively or
negatively, in that the customers may be similarly affected by changes in
economic, industry or other conditions. The Company generally requires letters
of credit for receivables from customers which are not considered investment
grade, unless the credit risk can otherwise be mitigated.
Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial
instruments is made in accordance with the requirements of Statement of
Financial Accounting Standards No. 107, "Disclosures About Fair Value of
Financial Instruments." The estimated fair value amounts have been determined by
the Company using available market information and valuation methodologies.
Considerable judgment is required in interpreting market data to develop the
estimates of fair value. The use of different market assumptions or valuation
methodologies may have a material effect on the estimated fair value amounts.
The carrying values of items comprising current assets and current
liabilities approximate fair values due to the short-term maturities of these
instruments. The Company estimates the fair value of its long-term, fixed-rate
debt using quoted market prices. The Company's carrying amount for such debt at
June 30, 1996 and 1995 was $255.6 million and $135.2 million, respectively,
compared to approximate fair values of $261.2 million and $137.8 million,
respectively. The carrying value of other long-term debt approximates its fair
value as interest rates are primarily variable, based on prevailing market
rates.
11. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
Net Capitalized Costs
Evaluated and unevaluated capitalized costs related to the Company's oil
and gas producing activities are summarized as follows:
JUNE 30,
---------------------
1996 1995
-------- --------
($ IN THOUSANDS)
Oil and gas properties:
Proved....................................................... $363,213 $165,302
Unproved..................................................... 165,441 27,474
-------- --------
Total................................................ 528,654 192,776
Less accumulated depreciation, depletion and amortization...... (92,720) (41,821)
-------- --------
Net capitalized costs.......................................... $435,934 $150,955
======== ========
Unproved properties not subject to amortization at June 30, 1996 and 1995,
consist mainly of lease acquisition costs. The Company capitalized approximately
$6,428,000 and $1,574,000 of interest during the years ended June 30, 1996 and
1995 on significant investments in unproved properties that are not being
currently depreciated, depleted, or amortized and on which exploration or
development activities are in progress. The Company will continue to evaluate
its unevaluated properties; however, the timing of the ultimate evaluation and
disposition of the properties has not been determined.
50
52
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Costs Incurred in Oil and Gas Acquisition, Exploration and Development
Costs incurred in oil and gas property acquisition, exploration and
development activities which have been capitalized are summarized as follows:
JUNE 30,
---------------------------------
1996 1995 1994
-------- -------- -------
($ IN THOUSANDS)
Development costs................................... $143,437 $ 81,833 $26,277
Exploration costs................................... 39,410 14,129 5,358
Acquisition costs:
Unproved properties............................... 138,188 24,437 3,305
Proved properties................................. 24,560 -- --
Capitalized internal costs.......................... 1,699 586 965
Proceeds from sale of leasehold, equipment and
other............................................. (11,416) (15,107) (7,598)
-------- -------- -------
Total..................................... $335,878 $105,878 $28,307
======== ======== =======
Results of Operations from Oil and Gas Producing Activities (unaudited)
The Company's results of operations from oil and gas producing activities
are presented below for the years ended June 30, 1996, 1995 and 1994,
respectively. The following table includes revenues and expenses associated
directly with the Company's oil and gas producing activities. It does not
include any allocation of the Company's interest costs and, therefore, is not
necessarily indicative of the contribution to consolidated net operating results
of the Company's oil and gas operations.
JUNE 30,
---------------------------------
1996 1995 1994
-------- -------- -------
($ IN THOUSANDS)
Oil and gas sales................................... $110,849 $ 56,983 $22,404
Production costs(a)................................. (8,303) (4,256) (3,647)
Depletion and depreciation.......................... (50,899) (25,410) (8,141)
Imputed income tax provision(b)..................... (18,335) (9,561) (3,610)
-------- -------- -------
Results of operations from oil and gas producing
activities........................................ $ 33,312 $ 17,756 $ 7,006
======== ======== =======
- ---------------
(a) Production costs include lease operating expenses and production taxes.
(b) The imputed income tax provision is hypothetical and determined without
regard to the Company's deduction for general and administrative expenses,
interest costs and other income tax credits and deductions.
Oil and Gas Reserve Quantities (unaudited)
The reserve information presented below is based upon reports prepared by
the independent petroleum engineering firm of Williamson Petroleum Consultants,
Inc. ("Williamson") as of June 30, 1996, 1995 and 1994 and the Company's
petroleum engineers as of June 30, 1996 and 1995. The reserves evaluated
internally by the Company constituted approximately 0.6% and 0.5% of total
proved reserves as of June 30, 1996 and 1995, respectively. The information is
presented in accordance with regulations prescribed by the Securities and
Exchange Commission. The Company emphasizes that reserve estimates are
inherently imprecise. The Company's reserve estimates were generally based upon
extrapolation of historical production trends, analogy
51
53
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
to similar properties and volumetric calculations. Accordingly, these estimates
are expected to change, and such changes could be material, as future
information becomes available.
Proved oil and gas reserves represent the estimated quantities of crude
oil, natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are those expected to be recovered through
existing wells with existing equipment and operating methods.
Presented below is a summary of changes in estimated reserves of the
Company based upon the reports prepared by Williamson for 1996, 1995 and 1994,
along with those prepared by the Company's petroleum engineers for 1996 and
1995:
JUNE 30,
-----------------------------------------------------------
1996 1995 1994
----------------- ----------------- -----------------
OIL GAS OIL GAS OIL GAS
(MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF)
------ ------- ------ ------- ------ -------
Proved reserves, beginning of
year........................ 5,116 211,808 4,154 117,066 9,622 79,763
Extensions, discoveries and
other additions............. 8,924 173,577 2,345 129,444 2,335 82,965
Revisions of previous
estimate.................... (812) (2,538) (244) (9,588) (868) (5,523)
Production.................... (1,413) (51,710) (1,139) (25,114) (537) (6,927)
Sale of reserves-in-place..... -- -- -- -- (6,398) (33,212)
Purchase of
reserves-in-place........... 443 20,087 -- -- -- --
------ ------- ------ ------- ------ -------
Proved reserves, end of
year........................ 12,258 351,224 5,116 211,808 4,154 117,066
====== ======= ====== ======= ====== =======
Proved developed reserves, end
of year..................... 3,648 144,721 1,973 77,764 1,313 30,445
====== ======= ====== ======= ====== =======
On April 30, 1996, the Company purchased interests in certain producing and
non-producing oil and gas properties, including approximately 14,000 net acres
of unevaluated leasehold, from Amerada Hess Corporation for $35 million, subject
to adjustment for activity after the effective date of January 1, 1996. The
properties are located in the Knox and Golden Trend fields of southern Oklahoma,
most of which are operated by the Company.
In October 1993, the Company entered into a joint development agreement
covering a 20,000 gross acre development area in the Fayette County portion of
the Giddings Field in southern Texas. The Company's ownership interests in the
proved undeveloped properties covered by the joint development agreement were
significantly less than those used in the June 30, 1993 reserve report. The
impact of the reduced ownership percentages is reflected as sales of reserves in
place in fiscal 1994 in the preceding table.
Standardized Measure of Discounted Future Net Cash Flows (unaudited)
Statement of Financial Accounting Standards No. 69 ("SFAS 69") prescribes
guidelines for computing a standardized measure of future net cash flows and
changes therein relating to estimated proved reserves. The Company has followed
these guidelines which are briefly discussed below.
Future cash inflows and future production and development costs are
determined by applying year-end prices and costs to the estimated quantities of
oil and gas to be produced. Estimates are made of quantities of proved reserves
and the future periods during which they are expected to be produced based on
year-end economic conditions. Estimated future income taxes are computed using
current statutory income tax rates including consideration for the current tax
basis of the properties and related carryforwards, giving effect to
52
54
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
permanent differences and tax credits. The resulting future net cash flows are
reduced to present value amounts by applying a 10% annual discount factor.
The assumptions used to compute the standardized measure are those
prescribed by the Financial Accounting Standards Board and, as such, do not
necessarily reflect the Company's expectations of actual revenue to be derived
from those reserves nor their present worth. The limitations inherent in the
reserve quantity estimation process, as discussed previously, are equally
applicable to the standardized measure computations since these estimates are
the basis for the valuation process.
The following summary sets forth the Company's future net cash flows
relating to proved oil and gas reserves based on the standardized measure
prescribed in SFAS 69:
JUNE 30,
----------------------------------
1996 1995 1994
---------- -------- --------
($ IN THOUSANDS)
Future cash inflows................................. $1,101,642 $427,377 $307,600
Future production costs............................. (168,974) (75,927) (50,765)
Future development costs............................ (137,068) (76,543) (47,040)
Future income tax provision......................... (173,439) (46,537) (36,847)
---------- -------- --------
Future net cash flows............................... 622,161 228,370 172,948
Less effect of a 10% discount factor................ (171,973) (69,359) (54,340)
---------- -------- --------
Standardized measure of discounted future net cash
flows............................................. $ 450,188 $159,011 $118,608
========== ======== ========
The principal sources of change in the standardized measure of discounted
future net cash flows are as follows:
JUNE 30,
---------------------------------
1996 1995 1994
--------- -------- --------
($ IN THOUSANDS)
Standardized measure, beginning of year............. $ 159,011 $118,608 $119,744
Sales of oil and gas produced, net of production
costs............................................. (102,546) (52,727) (18,757)
Net changes in prices and production costs.......... 87,736 (25,574) (10,795)
Extensions and discoveries, net of production and
development costs................................. 292,255 93,969 99,175
Changes in future development costs................. (11,201) 3,406 (2,855)
Development costs incurred during the period that
reduced future development costs.................. 43,409 23,678 9,855
Revisions of previous quantity estimates............ (10,505) (11,204) (13,107)
Purchase of undeveloped reserves-in-place........... 29,641 -- --
Sales of reserves-in-place.......................... -- -- (66,372)
Accretion of discount............................... 18,814 14,126 14,166
Net change in income taxes.......................... (67,705) (6,486) (720)
Changes in production rates and other............... 11,279 1,215 (11,726)
--------- -------- --------
Standardized measure, end of year................... $ 450,188 $159,011 $118,608
========= ======== ========
53
55
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
12. QUARTERLY FINANCIAL DATA (unaudited)
Summarized unaudited quarterly financial data for fiscal 1996 and 1995 are
as follows ($ in thousands except per share data):
QUARTER ENDED
------------------------------------------------------
SEPTEMBER 30, DECEMBER 31, MARCH 31, JUNE 30,
1995 1995 1996 1996
------------- ------------ --------- --------
Net sales............................... $21,988 $ 31,766 $44,145 $ 47,692
Gross profit(a)......................... 6,368 11,368 14,741 13,580
Net income.............................. 2,915 5,459 7,623 7,358
Net income per share:
Primary............................... .10 .19 .26 .23
Fully-diluted......................... .10 .19 .26 .23
QUARTER ENDED
------------------------------------------------------
SEPTEMBER 30, DECEMBER 31, MARCH 31, JUNE 30,
1994 1994 1995 1995
------------- ------------ --------- --------
Net sales............................... $13,042 $ 14,186 $15,788 $ 22,803
Gross profit(a)......................... 4,559 5,805 4,997 7,702
Net income.............................. 2,336 3,248 2,305 3,772
Net income per share:
Primary............................... .09 .12 .08 .13
Fully-diluted......................... .09 .12 .08 .13
- ---------------
(a) Total revenue excluding interest and other income, less total costs and
expenses excluding interest and other expense.
54
56
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Effective July 1, 1996, Price Waterhouse LLP sold its Oklahoma City
practice to Coopers & Lybrand L.L.P. and resigned as the Company's independent
accountants. The Company's decision to change independent accountants and retain
Coopers & Lybrand L.L.P. was approved by the Audit Committee of the Board of
Directors and by the Board of Directors. During the period Price Waterhouse LLP
was engaged by the Company, Price Waterhouse LLP did not issue any report on the
Company's financial statements containing an adverse opinion, disclaimer of
opinion, or qualification. There were no disagreements between the Company and
Price Waterhouse LLP on any matter of accounting principles or practices,
financial statement disclosure or auditing scope or procedure, nor were there
any reportable events.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information called for by this Item 10 is incorporated herein by
reference to the definitive Proxy Statement to be filed by the Company pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than October 28, 1996.
ITEM 11. EXECUTIVE COMPENSATION
The information called for by this Item 11 is incorporated herein by
reference to the definitive Proxy Statement to be filed by the Company pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than October 28, 1996.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information called for by this Item 12 is incorporated herein by
reference to the definitive Proxy Statement to be filed by the Company pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than October 28, 1996.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information called for by this Item 13 is incorporated herein by
reference to the definitive Proxy Statement to be filed by the Company pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than October 28, 1996.
55
57
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial Statements. The Company's Consolidated Financial
Statements are included in Item 8 of this report. Reference is made to the
accompanying Index to Consolidated Financial Statements.
2. Financial Statement Schedules. No financial statement schedules are
filed with this report as no schedules are applicable or required. The
Financial Statements of Chesapeake Exploration Limited Partnership are
included in this Item 14. Reference is made to the accompanying Index to
Chesapeake Exploration Limited Partnership Financial Statements.
3. Exhibits. The following exhibits are filed herewith pursuant to the
requirements of Item 601 of Regulation S-K:
EXHIBIT
NUMBER DESCRIPTION
------ -----------
3.1 -- Registrant's Certificate of Incorporation. Incorporated herein by
reference to Exhibit 3.1 to Registrant's quarterly report on Form
10-Q for the quarter ended December 31, 1995.
3.2 -- Registrant's Bylaws. Incorporated herein by reference to Exhibit 3.2
to Registrant's registration statement on Form S-1 (No. 33-55600).
4.1* -- Second Amended and Restated Credit Agreement dated as of September
20, 1996, by and among Chesapeake Energy Corporation, Chesapeake
Exploration Limited Partnership, an Oklahoma Limited Partnership and
Union Bank of California, N.A., as agent and the lenders from time to
time parties hereto.
4.2 -- Indenture dated as of March 31, 1994, as amended by First
Supplemental Indenture dated May 9, 1994, Second Supplemental
Indenture dated as of August 31, 1994 and Third Supplemental
Indenture dated December 27, 1994, among Chesapeake Energy
Corporation, its subsidiaries signatory thereto as Subsidiary
Guarantors and United States Trust Company of New York, as Trustee.
Incorporated herein by reference to Exhibits 4.2 and 4.2(a) to
Registrant's registration statement on Form S-4 (No. 33-78218)
Exhibit 4.2.1 to Registrant's quarterly report on Form 10-Q for the
quarter ended September 30, 1994 and Exhibit 4.2.1 to Registrant's
annual report on Form 10-K for the year ended June 30, 1995.
4.3 -- Indenture dated as of May 15, 1995 among Chesapeake Energy
Corporation, its subsidiaries signatory thereto as Subsidiary
Guarantors and United States Trust Company of New York, as Trustee.
Incorporated herein by reference to Exhibit 4.3 to Registrant's
registration statement on Form S-4 (No. 33-93718).
4.4 -- Indenture dated April 1, 1996 among Chesapeake Energy Corporation,
its subsidiaries signatory thereto as Subsidiary Guarantors and
United States Trust Company of New York, as Trustee. Incorporated
herein by reference to Exhibit 4.6 to Registrant's registration
statement on Form S-3 Registration Statement (No. 333-1588)
4.5 -- Agreement to furnish copies of unfiled long-term debt instruments.
Incorporated herein by reference to Exhibit 4.3 to Registrant's
annual report on Form 10-K for the year ended June 30, 1993.
56
58
EXHIBIT
NUMBER DESCRIPTION
------ -----------
4.7 -- Pledge Agreement dated as of March 31, 1994, as amended by First
Amendment to Pledge Agreement dated as of August 31, 1994 and Second
Amendment to Pledge Agreement dated as of December 27, 1994, among
Chesapeake Energy Corporation, Chesapeake Operating, Inc., Lindsay
Oil Field Supply, Inc. and United States Trust Company of New York.
Incorporated herein by reference to Exhibit B to Indenture filed as
Exhibit 4.2 to Registrant's registration statement on Form S-4 (No.
33-78218), Exhibit 4.7.1 Registrant's quarterly report on Form 10-Q
for the quarter ended December 31, 1995, and to Exhibit 4.7.1 to
Registrant's annual report on Form 10-K for the year ended June 30,
1995.
4.8 -- Stock Registration Agreement dated May 21, 1992 between Chesapeake
Energy Corporation and various lenders, as amended by First Amendment
thereto dated May 26, 1992. Incorporated herein by reference to
Exhibits 10.26.1 and 10.26.2 to Registrant's registration statement
on Form S-1 (No. 33-55600).
10.1.1+ -- Registrant's 1992 Incentive Stock Option Plan. Incorporated herein by
reference to Exhibit 10.1.1 to Registrant's registration statement on
Form S-4 (No. 33-93718).
10.1.2+* -- Registrant's 1992 Nonstatutory Stock Option Plan.
10.1.3+ -- Registrant's 1994 Stock Option Plan. Incorporated herein by reference
to Exhibit 99 to Registrant's registration statement on Form S-8 (No.
33-88196).
10.2.1+ -- Employment Agreement dated as of July 1, 1995 between Aubrey K.
McClendon and Chesapeake Energy Corporation. Incorporated herein by
reference to Exhibit 10.2.1 to Registrant's quarterly report on Form
10-Q for the quarter ended September 30, 1995.
10.2.2+ -- Employment Agreement dated as of July 1, 1995 between Tom L. Ward and
Chesapeake Energy Corporation. Incorporated herein by reference to
Exhibit 10.2.2 to Registrant's quarterly report on Form 10-Q for the
quarter ended September 30, 1995.
10.2.3+ -- Employment Agreement dated as of March 1, 1995 between Marcus C.
Rowland and Chesapeake Energy Corporation. Incorporated herein by
reference to Exhibit 10.2.3 to Registrant's quarterly report on Form
10-Q for the quarter ended September 30, 1995.
10.2.4+ -- Employment Agreement dated as of July 1, 1995 between Steven C. Dixon
and Chesapeake Energy Corporation. Incorporated herein by reference
to Exhibit 10.2.4 to Registrant's quarterly report on Form 10-Q for
the quarter ended September 30, 1995.
10.2.5+ -- Employment Agreement dated as of July 1, 1995 between J. Mark Lester
and Chesapeake Energy Corporation. Incorporated herein by reference
to Exhibit 10.2.5 to Registrant's quarterly report on Form 10-Q for
the quarter ended September 30, 1995.
10.2.6+ -- Employment Agreement dated as of July 1, 1995 between Henry J. Hood
and Chesapeake Energy Corporation. Incorporated herein by reference
to Exhibit 10.2.6 to Registrant's quarterly report on Form 10-Q for
the quarter ended September 30, 1995.
10.2.7+ -- Employment Agreement dated as of May 1, 1995 between Ronald A.
Lefaive and Chesapeake Energy Corporation. Incorporated herein by
reference to Exhibit 10.2.7 to Registrant's quarterly report on Form
10-Q for the quarter ended September 30, 1995.
10.2.8+* -- Employment Agreement dated as of July 1, 1995 between Martha A.
Burger and Chesapeake Operating, Inc.
57
59
EXHIBIT
NUMBER DESCRIPTION
------ -----------
10.3+ -- Form of Indemnity Agreement for officers and directors of Registrant
and its subsidiaries. Incorporated herein by reference to Exhibit
10.30 to Registrant's registration statement on Form S-1 (No.
33-55600).
10.9 -- Indemnity and Stock Registration Agreement, as amended by First
Amendment (Revised) thereto, dated as of February 12, 1993, and as
amended by Second Amendment thereto dated as of October 20, 1995,
among Chesapeake Energy Corporation, Chesapeake Operating, Inc.,
Chesapeake Investments, TLW Investments, Inc., et al. Incorporated
herein by reference to Exhibit 10.35 to Registrant's annual report on
Form 10-K for the year ended June 30, 1993 and Exhibit 10.4.1 to
Registrant's quarterly report on Form 10-Q for the quarter ended
December 31, 1995.
10.10 -- Partnership Agreement of Chesapeake Exploration Limited Partnership
dated December 27, 1994 between Chesapeake Energy Corporation and
Chesapeake Operating, Inc. Incorporated herein by reference to
Exhibit 10.10 to Registrant's registration statement on Form S-4 (No.
33-93718).
11* -- Statement re computation of per share earnings.
21 -- Subsidiaries of Registrant. Incorporated herein by reference to
Exhibit 21 to Registrant's quarterly report on Form 10-Q for the
quarter ended December 31, 1995.
23.1* -- Consent of Coopers & Lybrand L.L.P.
23.2* -- Consent of Price Waterhouse LLP
23.3* -- Consent of Williamson Petroleum Consultants, Inc.
27* -- Financial Data Schedule
- ---------------
* Filed herewith.
+ Management contract or compensatory plan or arrangement.
(b) Reports on Form 8-K
During the quarter ended June 30, 1996, the Company filed a Current Report
on Form 8-K dated April 30, 1996 (filed on May 15, 1996) reporting the
acquisition of interest in certain producing and nonproducing oil and gas
properties from Amerada Hess Corporation. Form 8-K/A was filed July 15, 1996 to
add financial information to such Current Report.
58
60
INDEX TO CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP
FINANCIAL STATEMENTS
PAGE
----
Report of Independent Accountants for the Year Ended June 30, 1996.................... 60
Report of Independent Accountants for the Years Ended June 30, 1995 and 1994.......... 61
Balance Sheets at June 30, 1996 and June 30, 1995..................................... 62
Statements of Income for the Years Ended June 30, 1996, 1995, and 1994................ 63
Statements of Partners' Capital for the Years Ended June 30, 1996, 1995, and 1994..... 64
Statements of Cash Flows for the Years Ended June 30, 1996, 1995, and 1994............ 65
Notes to Financial Statements......................................................... 66
59
61
REPORT OF INDEPENDENT ACCOUNTANTS
To the General Partner and Limited Partner of
Chesapeake Exploration Limited Partnership
We have audited the accompanying balance sheet of Chesapeake Exploration
Limited Partnership ("CEX") as of June 30, 1996, and the related consolidated
statements of income, partners' capital and cash flows for the year then ended.
These financial statements are the responsibility of the CEX management. Our
responsibility is to express an opinion on these financial statements based on
our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of CEX as of June 30, 1996, and
the results of its operations and its cash flows for the year then ended in
conformity with generally accepted accounting principles.
As more fully described in Note 1, CEX is a limited partnership owned by
Chesapeake Energy Corporation ("CEC") and Chesapeake Operating, Inc. ("COI").
CEX has no employees and it is dependent on the financial resources of CEC and
COI as well as being dependent on management by COI. Accordingly, CEX has
significant transactions with CEC and COI which are disclosed in Note 4. The
financial statements of CEX should be read in conjunction with the consolidated
financial statements of CEC.
COOPERS & LYBRAND L.L.P.
Oklahoma City, Oklahoma
September 13, 1996
60
62
REPORT OF INDEPENDENT ACCOUNTANTS
To the General Partner and Limited Partner of
Chesapeake Exploration Limited Partnership
In our opinion, the balance sheet and the related statements of income, of
partners' capital and of cash flows as of and for each of the two years in the
period ended June 30, 1995 present fairly, in all material respects, the
financial position, results of operations and cash flows of Chesapeake
Exploration Limited Partnership ("CEX" formerly Chesapeake Exploration Company)
as of and for each of the two years in the period ended June 30, 1995, in
conformity with generally accepted accounting principles. These financial
statements are the responsibility of CEX's management; our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with generally accepted
auditing standards which require that we plan and perform the audits to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above. We have not
audited the financial statements of CEX for any period subsequent to June 30,
1995.
As more fully described in Note 1, CEX is a limited partnership owned by
Chesapeake Energy Corporation ("CEC") and Chesapeake Operating, Inc. ("COI").
CEX has no employees and it is dependent on the financial resources of CEC and
COI as well as being dependent on management by COI. Accordingly, CEX has
significant transactions with CEC and COI which are disclosed in Note 4. The
financial statements of CEX should be read in conjunction with the consolidated
financial statements of CEC.
PRICE WATERHOUSE LLP
Houston, Texas
September 20, 1995
61
63
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP
(A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
BALANCE SHEETS
ASSETS
JUNE 30,
---------------------
1996 1995
-------- --------
($ IN THOUSANDS)
CURRENT ASSETS:
Accounts receivable.................................................. $ 14,778 $ 9,867
Prepaid expenses..................................................... 1,891 --
-------- --------
Total Current Assets......................................... 16,669 9,867
-------- --------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at cost based on full cost accounting:....... 346,821 163,521
Unevaluated properties............................................... 165,441 27,474
Less: accumulated depreciation, depletion and amortization........... (84,726) (36,959)
-------- --------
Total Property and Equipment................................. 427,536 154,036
-------- --------
INTERCOMPANY RECEIVABLES:
Chesapeake Energy Corporation........................................ 47,502 14,682
Chesapeake Gas Development Corporation............................... 8,171 2,877
Other................................................................ 382 --
-------- --------
56,055 17,559
-------- --------
OTHER ASSETS........................................................... 694 776
-------- --------
TOTAL ASSETS........................................................... $500,954 $182,238
======== ========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accrued Expenses..................................................... $ 789 $ 516
-------- --------
Total Current Liabilities.................................... 789 516
-------- --------
LONG-TERM DEBT......................................................... -- 10
-------- --------
INTERCOMPANY PAYABLES:
Lindsay Oil Field Supply............................................. 2,190 2,190
Chesapeake Operating, Inc............................................ 411,536 138,046
-------- --------
413,726 140,236
-------- --------
CONTINGENCIES AND COMMITMENTS (Note 3)................................. -- --
-------- --------
PARTNERS' CAPITAL:
Contributions........................................................ 424 424
Accumulated Earnings................................................. 86,015 41,052
-------- --------
Total Partners' Capital...................................... 86,439 41,476
-------- --------
TOTAL LIABILITIES & PARTNERS' CAPITAL.................................. $500,954 $182,238
======== ========
The accompanying notes are an integral part of these financial statements.
62
64
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP
(A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
STATEMENTS OF INCOME
YEAR ENDED JUNE 30,
--------------------------------
1996 1995 1994
-------- ------- -------
($ IN THOUSANDS)
REVENUES:
Oil and gas sales.......................................... $103,712 $55,417 $22,404
Other income (expense)..................................... (1,473) -- --
-------- ------- -------
Total Revenues..................................... 102,239 55,417 22,404
-------- ------- -------
COSTS AND EXPENSES:
Production expenses and taxes.............................. 7,225 3,494 3,185
Oil and gas depreciation, depletion and amortization....... 48,333 24,769 8,141
General and administrative................................. 1,090 931 823
Amortization............................................... 258 138 171
Interest................................................... 370 352 507
-------- ------- -------
Total Costs and Expenses........................... 57,276 29,684 12,827
-------- ------- -------
NET INCOME................................................... $ 44,963 $25,733 $ 9,577
======== ======= =======
The accompanying notes are an integral part of these financial statements.
63
65
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP
(A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
STATEMENTS OF PARTNERS' CAPITAL
CEC COI TOTAL
------- ------ -------
($ IN THOUSANDS)
Balance at June 30, 1993....................................... $ 5,549 $ 617 $ 6,166
1994 Net Income................................................ 8,619 958 9,577
------- ------ -------
Balance at June 30, 1994....................................... $14,168 $1,575 $15,743
1995 Net Income................................................ 23,160 2,573 25,733
------- ------ -------
Balance at June 30, 1995....................................... $37,328 $4,148 $41,476
1996 Net Income................................................ 40,467 4,496 44,963
------- ------ -------
Balance at June 30, 1996....................................... $77,795 $8,644 $86,439
======= ====== =======
The accompanying notes are an integral part of these financial statements.
64
66
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP
(A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
STATEMENTS OF CASH FLOWS
YEAR ENDED JUNE 30,
------------------------------------
1996 1995 1994
--------- --------- --------
($ IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME............................................... $ 44,963 $ 25,733 $ 9,577
ADJUSTMENTS TO RECONCILE NET INCOME TO NET CASH PROVIDED
BY OPERATING ACTIVITIES:
Oil and gas depreciation, depletion and amortization... 48,333 24,769 8,141
Amortization........................................... 258 138 171
General and administrative -- Allocated................ 1,090 931 814
CHANGES IN ASSETS AND LIABILITIES:
Increase (decrease) in assets/liabilities.............. (3,358) (4,818) (5,572)
--------- --------- --------
Cash provided by operating activities............... 91,286 46,753 13,131
--------- --------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and acquisition of oil and gas
properties.......................................... (329,507) (111,980) (33,466)
Proceeds from leasehold sales.......................... 2,158 5,079 3,268
Sale of producing properties........................... 5,300 11,500 --
Other.................................................. (177) -- (159)
--------- --------- --------
Cash used in investing activities................... (322,226) (95,401) (30,357)
--------- --------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings..................... 39,000 28,433 --
Payments on long-term borrowings....................... (44,010) (28,433) (10,201)
Intercompany advances.................................. 415,270 144,596 42,496
Intercompany payments.................................. (179,320) (95,948) (15,246)
--------- --------- --------
Cash provided by financing activities............... 230,940 48,648 17,049
--------- --------- --------
Net (decrease) increase in cash and cash equivalents..... -- -- (177)
Cash and cash equivalents, beginning of period........... -- -- 177
--------- --------- --------
Cash and cash equivalents, end of period................. $ -- $ -- $ --
========= ========= ========
CASH INTEREST PAID....................................... $ 563 $ 453 $ 507
========= ========= ========
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:
During the three years ended June 30, 1996, CEX had non-cash intercompany
transactions with the Company consisting primarily of allocated general and
administrative expenses. In fiscal 1996 and 1995, the difference between the net
book value and the proceeds from the sale of oil and gas properties sold to CGDC
of $782,000 and $2,852,000, respectively, resulted in a non-cash transfer.
The accompanying notes are an integral part of these consolidated financial
statements.
65
67
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP
(A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
NOTES TO FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Chesapeake Exploration Limited Partnership, an Oklahoma limited partnership
("CEX"), was formed on December 27, 1994 and acquired Chesapeake Exploration
Company ("Exploration") by merger on such date. Exploration was a general
partnership which was 10% owned by Chesapeake Operating, Inc. ("COI") and 90%
owned by Chesapeake Energy Corporation ("CEC" or the "Company"). CEC owns 100%
of the Common Stock of COI. CEX is 10% owned by COI as the sole general partner,
and 90% owned directly by the Company, as the sole limited partner.
Effective December 31, 1994, COI transferred to CEX all of the Company's
undeveloped leasehold acreage, thereby formalizing their prior economic
arrangement. Historically, COI had transferred undeveloped leasehold acreage to
CEX on a property-by-property basis as drilling commenced. CEX also owns
substantially all of the Company's proved developed oil and gas properties.
Accordingly, the financial statements of CEX include costs related to proved
undeveloped properties and unevaluated properties, as well as proved producing
properties. The change in partnership structure and the transfer of undeveloped
leasehold by COI to CEX have been accounted for as a reorganization of entities
under common control in a manner similar to a pooling-of-interests.
The CEX financial statements were prepared on a separate entity basis as
reflected in the Company's books and records and include all material costs of
doing business as if the partnership were on a stand-alone basis, except that
interest is not charged on intercompany accounts, or allocated.
Capital is provided by advances from CEC and COI, and to a lesser extent
directly by CEX's bank credit facilities.
These financial statements should be read in conjunction with CEC's
consolidated financial statements.
Accounting Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.
Oil and Gas Properties
CEC, and therefore CEX, follows the full cost method of accounting under
which all costs associated with property acquisition, exploration and
development activities are capitalized. CEX capitalizes internal costs that can
be directly identified with its acquisition, exploration and development
activities. Such costs do not include any costs related to production, general
corporate overhead or similar activities (see Note 7). Capitalized costs are
amortized on a composite unit-of-production method based on proved oil and gas
reserves. CEX's oil and gas reserves are estimated annually by independent
petroleum engineers. The average composite rates used for depreciation,
depletion and amortization were $.85, $.80 and $.80 per equivalent Mcf in 1996,
1995 and 1994, respectively. Proceeds from the sale of properties are accounted
for as reductions to capitalized costs unless such sales involve a significant
change in the relationship between costs and the value of proved reserves or the
underlying value of unproved properties, in which case a gain or loss is
recognized. Unamortized costs, as reduced by related deferred taxes, are subject
to a ceiling which limits such amounts to the estimated present value of oil and
gas reserves, reduced by operating expenses, future development costs and income
taxes. The costs of unproved properties are excluded from amortization until the
properties are evaluated.
66
68
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP
(A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
On April 30, 1996, CEX purchased interests in certain producing and
non-producing oil and gas properties, including approximately 14,000 net acres
of unevaluated leasehold, from Amerada Hess Corporation for $35 million, subject
to adjustment for activity after the effective date of January 1, 1996. The
properties are located in the Knox and Golden Trend fields of southern Oklahoma,
most of which are operated by the Company.
Capitalized Interest
During fiscal 1996, 1995 and 1994, interest of approximately $6,428,000,
$1,574,000 and $356,000 was capitalized on significant investments in unproved
properties that are not being currently depreciated, depleted, or amortized and
on which exploration or development activities are in progress.
Intercompany Transactions
COI, as operator of the majority of CEX's producing properties, bills CEX,
as non-operator, on a monthly basis for services performed as operator pursuant
to a standard operating agreement which is common in the industry. Expenses
related to the operations of CEX are recorded via such joint interest billings
and via intercompany expense allocations to CEX by COI. CEX has no employees. In
the CEC consolidated group, COI employs all management personnel and employees,
except for employees of the service company subsidiaries, and the preponderance
of general and administrative expenses are reflected in the financial records of
COI. COI allocates a portion of its general and administrative expenses to CEX
each period. This allocation is based on a per well charge at a rate common in
the industry plus an estimate of time spent on CEX activities by officers and
employees of COI.
CEC makes advances to CEX as needed. Certain of CEC's service subsidiaries
perform contractual services on CEX's wells for third parties. These
subsidiaries bill COI, as operator, and COI in turn bills CEX through monthly
joint interest billings in accordance with the terms of the standard operating
agreement.
It is CEC's policy not to demand payment of intercompany accounts. Interest
is not allocated by the Company, nor is interest charged on intercompany
accounts. CEC may, at its discretion, but it is not required to, contribute
intercompany accounts to capital.
Income Taxes
CEX is a partnership and, accordingly, its taxable income or loss is
allocated to the limited partner and the general partner and is ultimately
included in CEC's consolidated tax returns.
Gas Imbalances
CEX follows the "sales method" of accounting for its oil and gas revenue
whereby CEX recognizes sales revenue on all oil or gas sold to its purchasers,
regardless of whether the sales are proportionate to CEX's ownership in the
property. A liability is recognized only to the extent that CEX has a net
imbalance in excess of the reserves on the underlying properties. CEX's net
imbalance positions at June 30, 1996 and 1995 were not material.
Hedging
The Company, on behalf of CEX, periodically uses certain instruments to
hedge its exposure to price fluctuations on oil and natural gas transactions.
Recognized gains and losses on hedge contracts are reported as a component of
the related transaction. Results for hedging transactions are reflected in oil
and gas sales to the extent related to CEX's oil and gas production.
67
69
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP
(A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Reclassifications
Certain reclassifications have been made to the CEX financial statements
for the years ended June 30, 1995 and 1994 to conform to the presentation used
for the June 30, 1996 financial statements.
2. LONG-TERM DEBT
In April 1993, CEX entered into an oil and gas reserve-based reducing
revolving credit facility (the "Revolving Credit Facility") with Union Bank. The
Revolving Credit Facility has been amended from time to time, most recently in
September 1996. Concurrent with the September 1996 amendment, CEX increased the
facility size to $125 million and expanded its bank group with Union Bank
remaining as agent.
The maturity date of the Revolving Credit Facility is April 30, 2001. The
facility provides for interest at the Union Bank reference rate (8.25% at June
30, 1996) or, at the option of CEX the Eurodollar rate plus 1.375% to 1.875%
depending on the ratio of the amount outstanding to the borrowing base.
Borrowings are collateralized by a first priority lien on substantially all of
CEX's proved producing reserves, and are unconditionally guaranteed by the
Company. At June 30, 1996 and 1995 there was $0 and $10,000 outstanding under
the Revolving Credit Facility, respectively.
The amount of credit available at any time under the Revolving Credit
Facility is the lesser of the commitment amount or the borrowing base. The
borrowing base is reduced each month by a specified amount. Both the borrowing
base and the monthly reduction amount are redetermined by Union Bank each May 1
and November 1 and may be redetermined at any other time upon the request of CEX
or Union Bank. To the extent the amount outstanding at any time exceeds the
borrowing base, CEX must reduce the amount outstanding or add additional
collateral. At June 30, 1996, the commitment amount and the borrowing base under
the Revolving Credit Facility were $35 million, and the monthly reduction amount
was $700,000. The Revolving Credit Facility was amended in September 1996 to
provide for a borrowing base and a commitment amount of $75 million, with a
monthly reduction amount of $1,750,000. The Revolving Credit Facility contains
customary financial covenants, limitations on indebtedness and liabilities,
liens, prepayments of other indebtedness and loans, investments and guarantees
by the Company and prohibits the payment of dividends on the Company's Common
Stock.
3. CONTINGENCIES AND COMMITMENTS
CEX has fully and unconditionally guaranteed CEC's obligations under the
$47.5 million principal amount of 12% Senior Notes due 2001, issued March 31,
1994, the $90 million principal amount of 10.5% Senior Notes due 2002, issued
May 25, 1995, and the $120 million principal amount of 9.125% Senior Notes due
2006, issued April 9, 1996. In addition, the CEX partnership interests have been
pledged as collateral under the 12% Senior Notes.
4. RELATED PARTY TRANSACTIONS
CEX has significant transactions with COI, CEC, CGDC and other affiliated
companies included in the CEC consolidated group, including:
COI as operator for CEX:
(a) acquires oil and gas properties,
(b) drills and equips wells,
(c) operates the majority of CEX's wells,
(d) sells interests in proved undeveloped properties to third parties,
and
68
70
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP
(A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(e) contracts services from affiliated entities in the CEC
consolidated group and from third parties on behalf of CEX.
Capitalized costs associated with these transactions are reflected in the
balance sheet as oil and gas properties and unevaluated properties for each
period presented. Production expenses and taxes included in the statement of
operations for each of the periods presented reflect expenses billed by COI to
CEX for operations. Allocated general and administrative expenses reflect
amounts allocated to CEX by COI.
The Company makes periodic advances (and contributions) to CEX.
The transactions included in the following intercompany balances are
summarized as follows:
OTHER
COI CEC CGDC SUBSIDIARIES
--------- -------- -------- ------------
($ IN THOUSANDS)
BALANCE AT JUNE 30, 1993......................... $ (34,593) $(14,047) $ -- $ 1,033
========= ======== ======== ======
Joint Interest Billing........................... $ (31,925) $ (553) $ -- $ --
Cash Collected for CEX........................... 15,118 -- -- --
Debt Payments.................................... (10,135) (573) -- --
Other............................................ (123) 124 -- --
--------- -------- -------- ------
BALANCE AT JUNE 30, 1994......................... $ (61,658) $(15,049) $ -- $ 1,033
========= ======== ======== ======
Joint Interest Billing........................... $(131,018) $ (30) $ -- $ --
Cash Collected for CEX........................... 55,889 39,758 -- --
Debt Payments.................................... (23) (9,933) -- --
Transfer of Properties to CGDC................... -- -- 2,852 --
Other............................................ (1,236) (64) 25 (3,223)
--------- -------- -------- ------
BALANCE AT JUNE 30, 1995......................... $(138,046) $ 14,682 $ 2,877 $ (2,190)
========= ======== ======== ======
Joint Interest Billing........................... $(140,928) $ -- $ -- $ --
Cash Collected for CEX........................... 40,392 44,000 -- --
Debt Payments.................................... -- (5,848) -- --
Transfer of Properties to CGDC................... -- -- 5,515 --
Acquisition of properties........................ (162,748) -- -- --
Other............................................ (10,206) (5,332) (221) 382
--------- -------- -------- ------
BALANCE AT JUNE 30, 1996......................... $(411,536) $ 47,502 $ 8,171 $ (1,808)
========= ======== ======== ======
69
71
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP
(A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
5. MAJOR CUSTOMERS
Sales to individual customers constituting 10% or more of total oil and gas
sales were as follows:
PERCENT OF
AMOUNTS OIL AND GAS SALES
---------------- -----------------
YEAR ($ IN THOUSANDS)
1996 Aquila Southwest Pipeline Corporation $ 41,900 40%
GPM Gas Corporation $ 28,700 28%
Wickford Energy Marketing, L.C. $ 18,500 18%
1995 Aquila Southwest Pipeline Corporation $ 18,548 33%
Wickford Energy Marketing, L.C. $ 15,704 28%
GPM Gas Corporation $ 11,686 21%
1994 Wickford Energy Marketing, L.C. $ 6,190 28%
GPM Gas Corporation $ 6,105 27%
Plains Marketing and Transportation, Inc. $ 2,659 12%
Texaco Exploration & Production, Inc. $ 2,249 10%
Management believes that the loss of any of the above customers would not
have a material impact on CEX's results of operations or its financial position.
6. FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
The Company, on behalf of CEX, has only limited involvement with derivative
financial instruments, as defined in Statement of Financial Accounting Standards
No. 119 "Disclosure About Derivative Financial Instruments and Fair Value of
Financial Instruments" and does not use them for trading purposes. The Company's
objective is to hedge a portion of its exposure to price volatility from
producing crude oil and natural gas. These arrangements may expose the Company
to credit risk from its counter-parties and to basis risk.
Hedging Activities
Periodically the Company, on behalf of CEX, utilizes hedging strategies to
hedge the price of a portion of its future oil and gas production. These
strategies include swap arrangements that establish an index-related price above
which the Company pays the hedging partner and below which the Company is paid
by the hedging partner, the purchase of index-related puts that provide for a
"floor" price to the Company to be paid by the counter-party to the extent the
price of the commodity is below the contracted floor, and basis protection
swaps.
As of June 30, 1996, the Company had NYMEX-based crude oil swap agreements
for 1,000 Bbl per day for July 1, 1996 through August 31, 1996 at an average
price of $17.85 per Bbl. The counter-party has the option exercisable monthly
for an additional 1,000 Bbl per day for the period July 1, 1996 through December
31, 1996 to cause a swap if the price exceeds an average $17.74 per Bbl. The
actual settlements for July and August resulted in a $0.5 million payment to the
counter-party. The Company estimates, based on NYMEX prices as of August 30,
1996 that the effect of the September through December hedges would be a $0.4
million payment to the counter-party.
The Company has purchased Houston Ship Channel put options which guarantee
the Company an average floor price of $2.21/Mmbtu for 20,000 Mmbtu per day for
the period of November 1, 1996 through February 28, 1997. The average cost of
these puts was $0.14 per Mmbtu.
As of June 30, 1996, the Company had NYMEX-based natural gas swaps and
NYMEX/Houston Ship Channel Basis swaps for the months of July through October
1996. These transactions resulted in payments to
70
72
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP
(A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
the Company's counter-party of approximately $2 million for the month of July
1996 and $1.5 million for the month of August 1996. The Company estimates, based
on NYMEX prices as of August 30, 1996, that the effect of the September and
October hedges would be a $0.2 million payment to the counter-party.
Concentration of Credit Risk
Financial instruments which potentially subject CEX to concentrations of
credit risk consist principally of trade receivables. CEX's accounts receivable
are primarily from purchasers of oil and natural gas products and exploration
and production companies which own interests in properties operated by the
Company. The industry concentration has the potential to impact CEX's overall
exposure to credit risk, either positively or negatively, in that the customers
may be similarly affected by changes in economic, industry or other conditions.
The Company generally requires letters of credit for receivables from customers
which are not considered investment grade, unless the credit risk can otherwise
be mitigated.
Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial
instruments is made in accordance with the requirements of Statement of
Financial Accounting Standards No. 107, "Disclosures About Fair Value of
Financial Instruments". The estimated fair value amounts have been determined by
the Company using available market information and valuation methodologies.
Considerable judgment is required in interpreting market data to develop the
estimates of fair value. The use of different market assumptions or valuation
methodologies may have a material effect on the estimated fair value amounts.
The carrying values of items comprising current assets and current
liabilities approximate fair values due to the short-term maturities of these
instruments. Based on the borrowing rates currently available to CEX for bank
loans with similar terms and average maturities, the fair value of long-term
debt approximates the carrying value.
7. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
Net Capitalized Costs
Evaluated and unevaluated capitalized costs related to CEX's oil and gas
producing activities are summarized as follows:
JUNE 30,
---------------------
1996 1995
-------- --------
($ IN THOUSANDS)
Oil and gas properties:
Proved......................................................... $346,821 $163,521
Unproved....................................................... 165,441 27,474
-------- --------
Total........................................................ 512,262 190,995
Less accumulated depreciation, depletion and amortization...... (84,726) (36,959)
-------- --------
Net capitalized costs.......................................... $427,536 $154,036
======== ========
Unproved properties not subject to amortization at June 30, 1996 and 1995,
consist mainly of lease acquisition costs. CEX capitalized approximately
$6,428,000 and $1,574,000 of interest during the years ended June 30, 1996 and
1995 on significant investments in unproved properties that are not being
currently depreciated, depleted, or amortized and on which exploration or
development activities are in progress. CEX will continue to evaluate its
unevaluated properties; however, the timing of the ultimate evaluation and
disposition of the properties has not been determined.
71
73
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP
(A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Costs Incurred in Oil and Gas Acquisition, Exploration and Development
Costs incurred in oil and gas property acquisition, exploration and
development activities which have been capitalized are summarized as follows:
JUNE 30,
---------------------------------
1996 1995 1994
-------- -------- -------
($ IN THOUSANDS)
Development costs................................... $129,445 70,562 24,803
Exploration costs................................... 36,532 14,129 5,358
Acquisition costs:
Unproved properties............................... 138,188 24,437 3,305
Proved properties................................. 24,560 -- --
Sale of producing properties........................ (5,300) (11,500) --
Proceeds from sale of leasehold..................... (2,158) (5,079) (3,268)
-------- -------- -------
Total..................................... $321,267 $ 92,549 $30,198
======== ======== =======
Results of Operations from Oil and Gas Producing Activities (unaudited)
CEX's results of operations from oil and gas producing activities are
presented below for the years ended June 30, 1996, 1995 and 1994, respectively.
The following table includes revenues and expenses associated directly with
CEX's oil and gas producing activities. It does not include any allocation of
CEC's interest costs and, therefore, is not necessarily indicative of the
contribution to consolidated net operating results of CEX's oil and gas
operations.
JUNE 30,
---------------------------------
1996 1995 1994
-------- -------- -------
($ IN THOUSANDS)
Oil and gas sales................................... $103,712 $ 55,417 $22,404
Production costs(a)................................. (7,225) (3,494) (3,185)
Depletion and depreciation.......................... (48,333) (24,769) (8,141)
-------- -------- -------
Results of operations from oil and gas producing
activities........................................ $ 48,154 $ 27,154 $11,078
======== ======== =======
- ---------------
(a) Production costs include lease operating expenses and production taxes.
Oil and Gas Reserve Quantities (Unaudited)
The reserve information presented below is based upon reports prepared by
the independent petroleum engineering firm of Williamson Petroleum Consultants,
Inc. ("Williamson") as of June 30, 1996, June 30, 1995 and June 30, 1994 and the
Company's petroleum engineers as of June 30, 1996 and 1995. The reserves
evaluated by the Company's petroleum engineers constituted approximately 0.6%
and 0.5% of total proved reserves as of June 30, 1996 and 1995, respectively.
The information is presented in accordance with regulations prescribed by the
Securities and Exchange Commission. CEX emphasizes that reserve estimates are
inherently imprecise. CEX's reserve estimates were generally based upon
extrapolation of historical production trends, analogy to similar properties and
volumetric calculations. Accordingly, these estimates are expected to change,
and such changes could be material, as future information becomes available.
Proved oil and gas reserves represent the estimated quantities of crude
oil, natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in
72
74
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP
(A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
future years from known reservoirs under existing economic and operating
conditions. Proved developed oil and gas reserves are those expected to be
recovered through existing wells with existing equipment and operating methods.
Presented below is a summary of changes in estimated reserves of CEX based
upon the reports prepared by Williamson for 1996, 1995 and 1994 along with those
prepared by the Company's petroleum engineers for 1996 and 1995.
JUNE 30,
-----------------------------------------------------------
1996 1995 1994
----------------- ----------------- -----------------
OIL GAS OIL GAS OIL GAS
(MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF)
------ ------- ------ ------- ------ -------
Proved reserves, beginning of year.... 4,848 199,526 4,154 117,066 9,622 79,763
Extensions, discoveries and other
additions........................... 8,924 173,576 2,345 129,444 2,335 82,965
Revisions of previous estimate........ (895) (2,589) (243) (9,587) (868) (5,523)
Production............................ (1,304) (49,320) (1,006) (22,723) (537) (6,927)
Sale of reserves-in-place............. (74) (6,359) (402) (14,674) (6,398) (33,212)
Purchase of reserves-in-place......... 443 20,087 -- -- -- --
------ ------- ------ ------- ------ -------
Proved reserves, end of year.......... 11,942 334,921 4,848 199,526 4,154 117,066
====== ======= ====== ======= ====== =======
Proved developed reserves, end of
year................................ 3,214 126,590 1,705 65,481 1,313 30,445
====== ======= ====== ======= ====== =======
On April 30, 1996, the Company purchased interests in certain producing and
non-producing oil and gas properties, including approximately 14,000 net acres
of unevaluated leasehold, from Amerada Hess Corporation for $35 million, subject
to adjustment for activity after the effective date of January 1, 1996. The
properties are located in the Knox and Golden Trend fields of southern Oklahoma,
most of which are operated by the Company.
In October 1993, CEX entered into a joint development agreement covering a
20,000 gross acre development area in the Fayette County portion of the Giddings
Field in southern Texas. CEX's ownership interests in the proved undeveloped
properties covered by the joint development agreement were significantly less
than those used in the June 30, 1993 reserve report. The impact of the reduced
ownership percentages is reflected as sales of reserves in place in fiscal 1994
in the preceding table.
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
Statement of Financial Accounting Standards No. 69 ("SFAS 69") prescribes
guidelines for computing a standardized measure of future net cash flows and
changes therein relating to estimated proved reserves. CEX has followed these
guidelines which are briefly discussed below.
Future cash inflows and future production and development costs are
determined by applying year-end prices and costs to the estimated quantities of
oil and gas to be produced. Estimates are made of quantities of proved reserves
and the future periods during which they are expected to be produced based on
year-end economic conditions. Estimated future income taxes are computed using
current statutory income tax rates including consideration for the current tax
basis of the properties and related carryforwards, giving effect to permanent
differences and tax credits. The income tax effect of these future cash inflows
will be recognized by CEX's partners. The resulting future net cash flows are
reduced to present value amounts by applying a 10% annual discount factor.
The assumptions used to compute the standardized measure are those
prescribed by the Financial Accounting Standards Board and, as such, do not
necessarily reflect CEX's expectations of actual revenue to
73
75
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP
(A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
be derived from those reserves nor their present worth. The limitations inherent
in the reserve quantity estimation process, as discussed previously, are equally
applicable to the standardized measure computations since these estimates are
the basis for the valuation process.
The following summary sets forth CEX's future net cash flows relating to
proved oil and gas reserves based on the standardized measure prescribed in SFAS
69:
JUNE 30,
------------------------------------
1996 1995 1994
---------- -------- --------
($ IN THOUSANDS)
Future cash inflows....................................... $1,055,631 $402,027 $307,600
Future production costs................................... (161,223) (70,558) (50,765)
Future development costs.................................. (136,927) (76,542) (47,040)
Future income tax provision............................... (163,374) (42,519) (36,847)
---------- -------- --------
Future net cash flows..................................... 594,107 212,408 172,948
Less effect of a 10% discount factor...................... (160,659) (63,496) (54,340)
---------- -------- --------
Standardized measure of discounted future net cash
flows................................................... $ 433,448 $148,912 $118,608
========== ======== ========
The principal sources of change in the standardized measure of discounted
future net cash flows are as follows:
JUNE 30,
----------------------------------
1996 1995 1994
-------- -------- --------
($ IN THOUSANDS)
Standardized measure, beginning of year.................... $148,912 $118,608 $119,744
Sales of oil and gas produced, net of production costs..... (96,408) (51,923) (18,757)
Net changes in prices and production costs................. 78,501 (32,623) (10,795)
Extensions and discoveries, net of production and
development
costs.................................................... 292,255 93,969 99,175
Changes in future development costs........................ (11,084) 3,406 (2,855)
Development costs incurred during the period that reduced
future development costs................................. 43,409 23,678 9,855
Revisions of previous quantity estimates................... (11,338) (11,286) (13,107)
Purchase of undeveloped reserves-in-place.................. 29,641 -- --
Sales of reserves in-place................................. (5,835) (7,514) (66,372)
Accretion of discount...................................... 17,550 14,125 14,166
Net change in income taxes................................. (65,117) (3,944) (720)
Changes in production rates and other...................... 12,962 2,416 (11,726)
-------- -------- --------
Standardized measure, end of year.......................... $433,448 $148,912 $118,608
======== ======== ========
74
76
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
CHESAPEAKE ENERGY CORPORATION
By /s/ AUBREY K. McCLENDON
------------------------------------
Aubrey K. McClendon
Chairman of the Board and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
- --------------------------------------------- ---------------------------- ------------------
/s/ AUBREY K. McCLENDON Chairman of the Board, Chief September 30, 1996
- --------------------------------------------- Executive Officer and
Aubrey K. McClendon Director (Principal
Executive Officer)
/s/ TOM L. WARD President, Chief Operating September 30, 1996
- --------------------------------------------- Officer and Director
Tom L. Ward (Principal Executive
Officer)
/s/ MARCUS C. ROWLAND Vice President -- Finance September 30, 1996
- --------------------------------------------- and Chief Financial
Marcus C. Rowland Officer (Principal
Financial Officer)
/s/ RONALD A. LEFAIVE Controller (Principal September 30, 1996
- --------------------------------------------- Accounting Officer)
Ronald A. Lefaive
/s/ EDGAR F. HEIZER, JR. Director September 30, 1996
- ---------------------------------------------
Edgar F. Heizer, Jr.
/s/ BREENE M. KERR Director September 30, 1996
- ---------------------------------------------
Breene M. Kerr
/s/ SHANNON T. SELF Director September 30, 1996
- ---------------------------------------------
Shannon T. Self
/s/ FREDERICK B. WHITTEMORE Director September 30, 1996
- ---------------------------------------------
Frederick B. Whittemore
/s/ WALTER C. WILSON Director September 30, 1996
- ---------------------------------------------
Walter C. Wilson
75
77
INDEX TO EXHIBITS
EXHIBIT SEQUENTIAL
NUMBER DESCRIPTION PAGE NO.
- ---------- ----------- ----------
3.1 -- Registrant's Certificate of Incorporation. Incorporated herein by
reference to Exhibit 3.1 to Registrant's quarterly report on Form
10-Q for the quarter ended December 31, 1995.
3.2 -- Registrant's Bylaws. Incorporated herein by reference to Exhibit 3.2
to Registrant's registration statement on Form S-1 (No. 33-55600).
4.1* -- Second Amended and Restated Credit Agreement dated as of September
20, 1996, by and among Chesapeake Energy Corporation, Chesapeake
Exploration Limited Partnership, an Oklahoma Limited Partnership and
Union Bank of California, N.A., as agent and the lenders from time to
time parties hereto.
4.2 -- Indenture dated as of March 31, 1994, as amended by First
Supplemental Indenture dated May 9, 1994, Second Supplemental
Indenture dated as of August 31, 1994 and Third Supplemental
Indenture dated December 27, 1994, among Chesapeake Energy
Corporation, its subsidiaries signatory thereto as Subsidiary
Guarantors and United States Trust Company of New York, as Trustee.
Incorporated herein by reference to Exhibits 4.2 and 4.2(a) to
Registrant's registration statement on Form S-4 (No. 33-78218)
Exhibit 4.2.1 to Registrant's quarterly report on Form 10-Q for the
quarter ended September 30, 1994 and Exhibit 4.2.1 to Registrant's
annual report on Form 10-K for the year ended June 30, 1995.
4.3 -- Indenture dated as of May 15, 1995 among Chesapeake Energy
Corporation, its subsidiaries signatory thereto as Subsidiary
Guarantors and United States Trust Company of New York, as Trustee.
Incorporated herein by reference to Exhibit 4.3 to Registrant's
registration statement on Form S-4 (No. 33-93718).
4.4 -- Indenture dated April 1, 1996 among Chesapeake Energy Corporation,
its subsidiaries signatory thereto as Subsidiary Guarantors and
United States Trust Company of New York, as Trustee. Incorporated
herein by reference to Exhibit 4.6 to Registrant's registration
statement on Form S-3 Registration Statement (No. 333-1588)
4.5 -- Agreement to furnish copies of unfiled long-term debt instruments.
Incorporated herein by reference to Exhibit 4.3 to Registrant's
annual report on Form 10-K for the year ended June 30, 1993.
4.7 -- Pledge Agreement dated as of March 31, 1994, as amended by First
Amendment to Pledge Agreement dated as of August 31, 1994 and Second
Amendment to Pledge Agreement dated as of December 27, 1994, among
Chesapeake Energy Corporation, Chesapeake Operating, Inc., Lindsay
Oil Field Supply, Inc. and United States Trust Company of New York.
Incorporated herein by reference to Exhibit B to Indenture filed as
Exhibit 4.2 to Registrant's registration statement on Form S-4 (No.
33-78218), Exhibit 4.7.1 Registrant's quarterly report on Form 10-Q
for the quarter ended December 31, 1995, and to Exhibit 4.7.1 to
Registrant's annual report on Form 10-K for the year ended June 30,
1995.
4.8 -- Stock Registration Agreement dated May 21, 1992 between Chesapeake
Energy Corporation and various lenders, as amended by First Amendment
thereto dated May 26, 1992. Incorporated herein by reference to
Exhibits 10.26.1 and 10.26.2 to Registrant's registration statement
on Form S-1 (No. 33-55600).
10.1.1+ -- Registrant's 1992 Incentive Stock Option Plan. Incorporated herein by
reference to Exhibit 10.1.1 to Registrant's registration statement on
Form S-4 (No. 33-93718).
10.1.2+* -- Registrant's 1992 Nonstatutory Stock Option Plan.
78
EXHIBIT SEQUENTIAL
NUMBER DESCRIPTION PAGE NO.
- ---------- ----------- ----------
10.1.3+ -- Registrant's 1994 Stock Option Plan. Incorporated herein by reference
to Exhibit 99 to Registrant's registration statement on Form S-8 (No.
33-88196).
10.2.1+ -- Employment Agreement dated as of July 1, 1995 between Aubrey K.
McClendon and Chesapeake Energy Corporation. Incorporated herein by
reference to Exhibit 10.2.1 to Registrant's quarterly report on Form
10-Q for the quarter ended September 30, 1995.
10.2.2+ -- Employment Agreement dated as of July 1, 1995 between Tom L. Ward and
Chesapeake Energy Corporation. Incorporated herein by reference to
Exhibit 10.2.2 to Registrant's quarterly report on Form 10-Q for the
quarter ended September 30, 1995.
10.2.3+ -- Employment Agreement dated as of March 1, 1995 between Marcus C.
Rowland and Chesapeake Energy Corporation. Incorporated herein by
reference to Exhibit 10.2.3 to Registrant's quarterly report on Form
10-Q for the quarter ended September 30, 1995.
10.2.4+ -- Employment Agreement dated as of July 1, 1995 between Steven C. Dixon
and Chesapeake Energy Corporation. Incorporated herein by reference
to Exhibit 10.2.4 to Registrant's quarterly report on Form 10-Q for
the quarter ended September 30, 1995.
10.2.5+ -- Employment Agreement dated as of July 1, 1995 between J. Mark Lester
and Chesapeake Energy Corporation. Incorporated herein by reference
to Exhibit 10.2.5 to Registrant's quarterly report on Form 10-Q for
the quarter ended September 30, 1995.
10.2.6+ -- Employment Agreement dated as of July 1, 1995 between Henry J. Hood
and Chesapeake Energy Corporation. Incorporated herein by reference
to Exhibit 10.2.6 to Registrant's quarterly report on Form 10-Q for
the quarter ended September 30, 1995.
10.2.7+ -- Employment Agreement dated as of May 1, 1995 between Ronald A.
Lefaive and Chesapeake Energy Corporation. Incorporated herein by
reference to Exhibit 10.2.7 to Registrant's quarterly report on Form
10-Q for the quarter ended September 30, 1995.
10.2.8+* -- Employment Agreement dated as of July 1, 1995 between Martha A.
Burger and Chesapeake Operating, Inc.
10.3+ -- Form of Indemnity Agreement for officers and directors of Registrant
and its subsidiaries. Incorporated herein by reference to Exhibit
10.30 to Registrant's registration statement on Form S-1 (No.
33-55600).
10.9 -- Indemnity and Stock Registration Agreement, as amended by First
Amendment (Revised) thereto, dated as of February 12, 1993, and as
amended by Second Amendment thereto dated as of October 20, 1995,
among Chesapeake Energy Corporation, Chesapeake Operating, Inc.,
Chesapeake Investments, TLW Investments, Inc., et al. Incorporated
herein by reference to Exhibit 10.35 to Registrant's annual report on
Form 10-K for the year ended June 30, 1993 and Exhibit 10.4.1 to
Registrant's quarterly report on Form 10-Q for the quarter ended
December 31, 1995.
10.10 -- Partnership Agreement of Chesapeake Exploration Limited Partnership
dated December 27, 1994 between Chesapeake Energy Corporation and
Chesapeake Operating, Inc. Incorporated herein by reference to
Exhibit 10.10 to Registrant's registration statement on Form S-4 (No.
33-93718).
11* -- Statement re computation of per share earnings.
79
EXHIBIT SEQUENTIAL
NUMBER DESCRIPTION PAGE NO.
- ---------- ----------- ----------
21 -- Subsidiaries of Registrant. Incorporated herein by reference to
Exhibit 21 to Registrant's quarterly report on Form 10-Q for the
quarter ended December 31, 1995.
23.1* -- Consent of Coopers & Lybrand L.L.P.
23.2* -- Consent of Price Waterhouse LLP
23.3* -- Consent of Williamson Petroleum Consultants, Inc.
27* -- Financial Data Schedule
- ---------------
* Filed herewith.
+ Management contract or compensatory plan or arrangement.