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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
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Total Costs and Expenses........................... 113,213 49,383 24,669
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INCOME BEFORE INCOME TAXES................................... 36,209 17,960 5,155
INCOME TAX EXPENSE........................................... 12,854 6,299 1,250