<PAGE> 1
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
<TABLE>
<S> <C>
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999 COMMISSION FILE NO. 0-25214
</TABLE>
CONTOUR ENERGY CO.
(Exact name of registrant as specified in its charter)
<TABLE>
<S> <C>
DELAWARE 76-0447267
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
601 JEFFERSON -- SUITE 1100
HOUSTON, TEXAS 77002
(Address of principal executive offices) (Zip Code)
</TABLE>
Registrant's telephone number, including area code: (713) 652-5200
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
<S> <C>
8 1/2% Convertible Subordinated Debentures due OTC Bulletin Board
2000
</TABLE>
Securities registered pursuant to Section 12(g) of the Act:
<TABLE>
<CAPTION>
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
<S> <C>
Common Stock OTC Bulletin Board
$2.625 Convertible Exchangeable Preferred OTC Bulletin Board
Stock
</TABLE>
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 under the Securities Exchange Act of 1934 is not contained
herein, and will not be contained, to the best of the Registrant's knowledge, in
definitive proxy or information statements incorporated in Part III of this Form
10-K or any amendments to this Form 10-K. [ ]
As of March 24, 2000, 13,212,005 shares of Common Stock and 1,363,319
shares of Preferred Stock were outstanding, and the aggregate market values of
shares held by unaffiliated stockholders were approximately $9,778,187 and
$4,679,534, respectively.
DOCUMENTS INCORPORATED BY REFERENCE
Certain portions of the Proxy Statement for the 2000 Annual Meeting of
Stockholders are incorporated by reference into Part III of this Report.
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<PAGE> 2
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
Introduction
Contour Energy Co. (formerly Kelley Oil & Gas Corporation), incorporated in
Delaware in 1994, with its subsidiaries and subsidiary partnerships
(individually and collectively the "Company"), is engaged in the acquisition,
exploration, development and production of oil and natural gas. The Company's
strategy is to increase reserves, production and cash flows in a cost-efficient
manner through strategic domestic acquisitions and a program of balanced
development and exploration activities. The Company's executive offices are
located at 601 Jefferson Street, Suite 1100, Houston, Texas 77002, and its
telephone number is (713) 652-5200.
As used in this Report, "Mcf" means thousand cubic feet, "Mmcf" means
million cubic feet, "Bcf" means billion cubic feet, "Bbl" means barrel or 42
U.S. gallons liquid volume, "Mbbl" means thousand barrels, "Mcfe" means thousand
cubic feet of natural gas equivalent using the ratio of six Mcf of natural gas
to one Bbl of crude oil, condensate and natural gas liquids, "Mmcfe" means
million cubic feet of natural gas equivalent, "Bcfe" means billion cubic feet of
natural gas equivalent, and "Mmbtu" means million British thermal units. This
Report includes various other capitalized terms that are defined when first
used.
1999 Business Developments
In 1999, the Company undertook several strategic actions in response to the
severe downturn in the industry in 1998 caused by low commodity prices and the
closing of the capital markets to smaller oil and gas companies. These actions,
described below, were designed to increase the near-term liquidity of the
Company, provide capital for its ongoing capital expenditure programs and
establish a stronger base for future growth.
In April 1999, the Company entered into an Exploration and Development
Agreement with Phillips Petroleum Company ("Phillips") relating to certain of
the Company's interests in the Bryceland, West Bryceland and Sailes fields in
north Louisiana ("Phillips Transaction"). Pursuant to the agreement, the Company
(1) received an $83 million cash payment (2) retained a 42 Bcf, 8-year
volumetric overriding royalty interest (the "VORI") and a 1% override on the
excess of production above such royalty interest and (3) retained 25% of its
working interest in the Cotton Valley formation. In addition, Phillips, will at
its risk and expense, operate, develop, exploit and explore the properties
thereby relieving the Company of significant operating, exploration and
development costs in the future. The transaction closed on May 17, 1999. The
Company recognized a gain of approximately $25.9 million in 1999 related to this
transaction.
In April 1999, the Company negotiated a private offering of $135.0 million
principal amount, 14% Senior Secured Notes (the "Notes"). The Notes are secured
by a first lien on substantially all of the Company's proved oil and natural gas
properties remaining after the sale to Phillips and guaranteed by three entities
wholly-owned by the Company. In accordance with the Notes indenture, on June 30,
1999, the Company funded $37.5 million to repurchase $35 million principal
amount of the Notes at a repurchase price equal to 104% of the principal amount,
plus accrued and unpaid interest and commitment fees to the date of the
repurchase.
On May 17, 1999, the Company funded $28.5 million to repurchase $46.1
million of the outstanding principal amounts of its 7 7/8% Convertible
Subordinated Notes due December 15, 1999 and its 8 1/2% Convertible Subordinated
Debentures due April 1, 2000 (collectively, the "Securities") at a price equal
to $590 per $1,000 principal amount (not including accrued interest paid of $1.2
million).
In addition, on May 17, 1999 the Company repaid all borrowings outstanding
under its revolving credit facility of $115.5 million plus accrued interest and
terminated the revolving credit facility and funded cash collateral for a $1.5
million letter of credit which was subsequently increased to $7.5 million. The
Company used net proceeds remaining from the transactions for general corporate
purposes. In 1999, the Company recognized an extraordinary gain of $11.1 million
related
1
<PAGE> 3
to debt repurchases and refinancings, comprised of: (i) a net gain on the
Securities tender offer and other debt retirements of $16.0 million, reduced by,
(ii) a $1.4 million premium on the $35 million Notes repurchase and the
proportionate write-off of debt issue costs of $2.4 million and (iii) the
write-off of credit facility debt issue costs of $1.1 million.
In March 2000, the Company executed a sale of a portion of its VORI. The
net proceeds from the sale approximated $20 million. Since the portion of the
reserves sold (approximately 16.5 Bcf) relates to production beginning April 1,
2003, cash flows from operations of the Company before that date are not
impacted.
The Company has received the benefits of a general increase in the level of
commodity prices over the past several months. This increase, combined with the
actions and the sale described above, have provided the Company with near-term
liquidity and capital for its ongoing operations. However, the commodity markets
are volatile and there is no certainty that current oil and natural gas prices
can be sustained at these levels. In addition, the Company continues to have
significant debt outstanding relative to its asset base and pays a high portion
of its cash flow to service such debt (see "Capital Resources"). Furthermore, as
the Company does not have a revolving credit facility, the Company does not have
ready access to incremental sources of capital to supplement its operational
requirements. The Company believes that it has the ability for the foreseeable
future based on its current condition, including economic conditions, to meet
all obligations as they come due and fund its current capital expenditure
program from cash on hand and operational cash flows. However, because of the
combination of the factors described herein (see "Risk Factors"; "Liquidity";
and "Capital Resources") and the uncertainty of drilling successes required to
sustain or increase operational cash flows, there can be no assurance that the
Company will be able to fund future obligations.
Company History
The Consolidation. The Company was formed in 1994 to consolidate the equity
ownership (the "Consolidation") of Kelley Oil & Gas Partners, Ltd. ("Kelley
Partners") and Kelley Oil Corporation ("Kelley Oil"). Before the Consolidation
in 1994, Kelley Partners and developmental drilling partnership subsidiaries of
Kelley Oil ("DDPs") jointly conducted drilling activities. Historically, Kelley
Oil (the managing general partner of Kelley Partners) participated
proportionately in these operations, with Kelley Partners retaining one-third of
its working interest in each prospect and assigning drilling rights for the
balance of its interest to a DDP. In addition to serving as managing general
partner of each DDP, Kelley Oil purchased for its own investment account all
units in DDPs that were not subscribed preemptively by other investors in Kelley
Partners. In the Consolidation, the Company acquired Kelley Oil's interests in
the remaining DDPs sponsored during 1994 and 1992 aggregating 92.2% and 84.3%,
respectively. The Consolidation was completed on February 7, 1995 upon approval
by investors in Kelley Partners and Kelley Oil.
In the Consolidation, the outstanding capital stock of Kelley Oil and units
in Kelley Partners ("Units") held by investors other than Kelley Oil and its
subsidiaries ("Public Unitholders") were converted into a total of 43.7 million
shares of Common Stock of the Company, 2.4 million shares of the Company's
$2.625 convertible exchangeable preferred stock ("Preferred Stock") and 2.2
million shares of cumulative convertible preferred stock ("ESOP Preferred
Stock") held by its Employee Stock Ownership Plan (the "ESOP"). As a result of
the Consolidation, Kelley Oil became a wholly owned subsidiary of the Company,
and Kelley Partners became a 99.99%-owned subsidiary partnership. The
Consolidation was treated as a purchase of the Public Unitholders' interests in
Kelley Partners by the Company for financial accounting purposes. In 1996,
Kelley Partners was merged into the Company and each of the then outstanding
shares of ESOP Preferred Stock was redeemed for one share of the Company's
Common Stock.
Contour Transaction. In January 1996, the Company entered into financing
and related agreements with Contour Production Company L.L.C. ("Contour"),
pursuant to which Contour purchased 48.0 million newly issued shares of Common
Stock for $48.0 million on February 15, 1996, and an option (the "Contour
Option") to purchase an additional 27.0 million shares of Common Stock for $27.0
million, which was exercised on December 1, 1997. In February 1996, in
connection with the first stage of Contour's investment in the Company, John F.
Bookout was appointed Chairman, President and Chief Executive Officer of the
Company, and certain other experienced oil industry executives were appointed to
senior management positions within the Company (all such transactions are
referred to collectively as the "Contour Transaction").
2
<PAGE> 4
On July 30, 1999, the Company's name was changed from Kelley Oil and Gas
Corporation to Contour Energy Co. and its NASDAQ ticker symbol to CONCC.
Concurrent with the name change, the Company established the authorized capital
stock of the Company at 22 million shares, 20 million of which were designated
as common stock and 2 million as preferred stock, and effected a 1 for 10
reverse stock split, reducing the total outstanding shares of common stock from
approximately 126 million to approximately 12.6 million (without giving effect
to the preferred stock exchange offer described in the following paragraph).
These actions were consented to by the Company's majority stockholder and became
effective on July 30, 1999. All historical share and per share data appearing in
this document have been restated to reflect this reverse stock split.
On June 28, 1999, the Company began an offer to exchange 15 shares of its
common stock (or 1.5 shares on a post-split basis) for each share of its $2.625
convertible exchangeable preferred stock ("Preferred Stock"). Pursuant to the
exchange offer, 368,633 shares of Preferred Stock were tendered representing
approximately 21% of the total Preferred Stock outstanding. In July 1999, the
shares were exchanged for 552,950 shares of newly issued common stock of the
Company (after giving effect to the 1 for 10 reverse stock split), increasing
the Company's shares of outstanding common stock to approximately 13.2 million.
With the exchange, the Company eliminated dividend arrearages of approximately
$1.5 million.
On August 30, 1999, at market close, the Company's shares of common stock
and convertible Preferred Stock, which traded under the symbols of CONCC and
CONCP, were delisted from the NASDAQ SmallCap Market. These actions were taken
as a result of the Company's failure to meet the requirements for continued
listing on this exchange. On August 31, 1999, at market open, the Company's
stock began trading on the OTC Bulletin Board under the symbols of CONC and
CONCP.
Operations and Properties
Operation Activities. The Company's production is derived primarily from
four contiguous fields in the Vacherie Salt Dome region of north Louisiana,
south Louisiana and the shallow waters of the Gulf of Mexico.
Development Activities. During 1999, the Company continued development
drilling activities within its existing properties in the Vacherie Salt Dome
region of north Louisiana, south Louisiana and in the Gulf of Mexico. In north
Louisiana, the Company drilled or participated in drilling 6 gross (1.36 net)
development wells, all of which were completed as producing wells. In south
Louisiana, the Company drilled or participated in drilling 1 gross (0.50 net)
well, which was not productive. In the offshore area, the Company drilled or
participated in drilling 3 gross (0.54 net) wells, of which 2 gross (0.36 net)
wells were completed as producing wells.
Exploration Activities. The Company focuses its exploration activities
primarily on its existing leaseholdings in Terrebonne and LaFourche Parishes,
Louisiana, and in the shallow waters of the Gulf of Mexico. The number, type and
timing of proposed wells in these regions is subject to continued revision as a
result of many factors, including test and drilling results on these properties
and others, the price of oil and natural gas, availability of capital funds and
drilling rigs, weather, and general economic factors. See "Caution as to
Forward-Looking Statements" and "Risk Factors".
The Company is utilizing sophisticated technologies to identify exploration
prospects and advanced geophysical techniques to continue to develop and refine
interpretations of its 3-D seismic database, which covers (i) 600 square miles,
a major portion of its existing leaseholdings in Terrebonne and LaFourche
Parishes, in south Louisiana, (ii) 131 square miles offshore, and (iii) 600
square miles of its Permian Basin exploratory prospects.
In 1999, the Company drilled 3 gross (1.02 net) exploratory wells,
including 2 gross (0.84 net) exploratory wells in southern Louisiana, and 1
gross (.18 net) well in the offshore area, all of which have been completed as
producing wells. As of December 31, 1999, the Company had 1 gross (.50 net)
exploration well in progress in south Louisiana, that was completed as a
producing well in January 2000.
Description of Properties. The Company's properties are located in
Louisiana, and in the Gulf of Mexico, Texas, New Mexico and Arkansas. As of
January 1, 2000, the Company owned interests in a total of 275 gross (81.0 net)
producing
3
<PAGE> 5
wells. As of that date, the Company had leaseholdings covering 165,205 gross
(68,752 net) developed acres and 250,796 gross (76,613 net) undeveloped acres.
Approximately 78% of its proved oil and natural gas reserves as of January 1,
2000, was natural gas on an energy content basis. The reserves to production
ratio for these properties (based on 1999 production) was estimated to be 8.3 as
of January 1, 2000.
Significant Properties. The Company's natural gas properties in north
Louisiana are located primarily in the Sailes, Sibley, West Bryceland and Ada
fields of Webster and Bienville Parishes, while its properties in south
Louisiana are concentrated in the Orange Grove/Humphreys, Lirette, Lake Pagie,
Ouiski Bayou and Bayou Sauveur fields in Terrebonne Parish. Production is
primarily from the Hosston (north Louisiana) and Miocene (south Louisiana)
formations. Other properties are located primarily in the shallow waters of the
Gulf of Mexico, south Louisiana, and Texas. Substantially all of the Company's
oil and natural gas properties are pledged to secure borrowings under the Notes.
The following table sets forth certain information as of the dates indicated
regarding the Company's interests by major geographic region. See "Estimated
Proved Reserves -- Uncertainties in Estimating Reserves and Future Net Cash
Flows."
SIGNIFICANT PROVED PROPERTIES
<TABLE>
<CAPTION>
PROVED RESERVES AT JANUARY 1, 2000 PRODUCTION
--------------------------------------------- -----------------------------
YEAR ENDED
PRESENT VALUE DECEMBER 31, 1999
OF ESTIMATED -----------------------------
GAS FUTURE NET GAS
OIL GAS EQUIVALENT CASH FLOWS(1) OIL GAS EQUIVALENT
MBBLS MMCF (MMCFE) (IN THOUSANDS) (MBBLS) (MMCF) (MMCFE)
----- ------- ---------- -------------- ------- ------ ----------
<S> <C> <C> <C> <C> <C> <C> <C>
North Louisiana......... 230 106,595 107,975 $109,494 38 12,745 12,973
South Louisiana......... 4,750 20,433 48,933 66,175 133 3,921 4,719
Offshore................ 2,167 28,471 41,473 56,482 97 5,545 6,127
Other as a group........ 476 3,201 6,057 8,940 99 181 775
----- ------- ------- -------- --- ------ ------
Totals........ 7,623 158,700 204,438 $241,091 367 22,392 24,594
===== ======= ======= ======== === ====== ======
</TABLE>
- ---------------
(1) The estimates were prepared in accordance with SEC regulations using market
or contract prices at the end of each reported period. Prices and operating
and development costs are held constant over the estimated life of the
reserves. A discount factor of 10% was used to reflect the timing of future
net cash flow. See "Estimated Proved Reserves -- Uncertainties in Estimating
Reserves and Future Net Cash Flows" and Note 12 to the Consolidated
Financial Statements.
Additional information regarding these regions is set forth below. Unless
otherwise noted, acreage and well information is provided as of December 31,
1999, and reserve information is provided as of January 1, 2000.
North Louisiana. The Company's operations in this region are 78% proved
developed, and its wells are typically drilled to a maximum depth of
approximately 10,500 feet. Operations in this region do not typically experience
geopressured formations or significant associated salt-water production. The
Company's reserves to production ratio in north Louisiana is approximately 8.3.
Its lifting costs in this region are generally low (approximately $0.14 per Mcfe
in 1999) as a result of relatively low formation pressures and minimal liquid
hydrocarbon and salt water production. The Company's share of proved reserves
associated with these fields totaled approximately 108.0 Bcfe at December 31,
1999. Included in the reserve base for north Louisiana are proved reserves
associated with the VORI retained by the Company and carved from the Sailes and
West Bryceland fields sold pursuant to the Phillips Transaction. These reserves
total 40.9 bcfe at year-end 1999 and are non-cost bearing to the Company except
for related gathering, transmission, compression costs and severance and
production taxes. In March 2000, the Company executed a sale of a portion of its
VORI for net proceeds of approximately $20 million. The portion of the VORI
reserves sold (approximately 16.5 Bcf) relates to production beginning April 1,
2003.
South Louisiana. The Company's operations in this region are primarily
focused on five fields in the Houma Embayment and Terrebonne Trough areas. These
areas contain high-quality reservoir rock, contributing to high production
rates. Wells are typically drilled to a depth of approximately 11,000 to 19,000
feet. The Company's share of proved reserves associated with these fields
totaled approximately 48.9 Bcfe at December 31, 1999. Production from the
Company's south Louisiana properties generally receives premium wellhead prices
because of the close proximity of the properties to
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transportation and market locations, and because of their rich condensate
content. The Company believes these factors partially offset the higher
operating costs associated with higher formation pressures, salt water disposal
and inland water well locations associated with the region. At December 31,
1999, the Company was drilling 1 gross (.50 net) well in this region, which was
subsequently completed as a producing well.
Offshore. The Company's operations in this region are primarily focused in
the shallow waters of the Gulf of Mexico, offshore Texas, Louisiana and Alabama.
In the Main Pass area, the Company participated in drilling 4 gross (.72 net)
wells during 1999, of which 3 gross (.54 net) wells were successfully completed.
The Company expects to continue additional development and exploration
activities in the Main Pass area in 2000. The Company has also acquired 81
square miles of additional 3D seismic in the Vermillion and Main Pass areas to
complement its offshore development and exploration efforts. The Company's share
of proved reserves associated with the Gulf of Mexico region totals
approximately 41.5 bcfe at December 31, 1999.
JOINT VENTURE PARTNERSHIPS
The Company participates in joint ventures with industry partners to
accelerate the exploration and evaluation of its properties and to mitigate the
risks associated with exploratory drilling projects.
The Company and Williams Production, Gulf Coast Company ("Williams"), a
unit of The Williams Companies, Inc., are 50/50 partners in a joint venture
covering 27,000 net acres in the Houma Embayment in south Louisiana. The Company
also has a joint exploration & development agreement with Fina Oil and Chemical
Company, a subsidiary of FINA, Inc. ("Fina"), and Cobra Oil and Gas Corporation
("Cobra"). The Fina joint venture represents a joint exploration and development
agreement covering an area of mutual interest (the "AMI") of approximately
400,000 acres in south Louisiana. The agreement provides for the parties to
obtain 3-D seismic coverage over all mutually agreeable prospective lands within
the AMI. To date, the Company and Fina have acquired 3-D seismic data covering
approximately 450 square miles within the AMI. The initial five-year term of the
agreement with Fina expires March 31, 2000, but there are provisions for
extensions in the agreements. The Company and Fina are now in discussions about
the nature and extent of an extension. The Company and Cobra Oil & Gas
Corporation are also involved in a joint venture covering approximately 68,000
acres in Texas, New Mexico, Arkansas, Louisiana and Alabama and includes 3-D
seismic data covering approximately 975 square miles.
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ESTIMATED PROVED RESERVES
The following table sets forth the estimated quantities of proved and
proved developed reserves of crude oil (including condensate and natural gas
liquids) and natural gas owned by the Company for the years ended December 31,
1997, 1998 and 1999, which were prepared by H.J. Gruy & Associates, Inc.
("Gruy") independent petroleum engineers.
ESTIMATED PROVED RESERVES
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------
1997 1998 1999
----------------- ----------------- ------------------
OIL GAS OIL GAS OIL GAS
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
------- ------- ------- ------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
PROVED RESERVES:
Beginning balance................. 1,466 297,634 2,953 354,867 5,294 283,559
Revisions of previous estimates... 106 21,831 (79) (31,674) 1,262 (10,774)
Purchases of reserves in place.... 1,351 51,712 -- -- -- --
Extensions and discoveries........ 256 13,892 3,082 9,512 1,762 15,620
Sale of reserves in place......... -- -- (287) (13,589) (328) (107,313)
Production..................... (226) (30,202) (375) (35,557) (367) (22,392)
----- ------- ----- ------- ----- --------
Ending balance................. 2,953 354,867 5,294 283,559 7,623 158,700
===== ======= ===== ======= ===== ========
PROVED DEVELOPED RESERVES:
Producing(1)...................... 1,856 180,307 1,062 129,787 2,039 94,798
Non-producing..................... 576 77,493 919 59,037 647 29,089
----- ------- ----- ------- ----- --------
Total proved developed.... 2,432 257,800 1,981 188,824 2,686 123,887
===== ======= ===== ======= ===== ========
</TABLE>
- ---------------
(1) 1999 includes 3 mbbls and 40,835 mmcf's associated with the Company's
interest in the VORI. In March 2000, the Company executed a sale of a
portion of its VORI for net proceeds of approximately $20 million. The
portion of the VORI reserves sold (approximately 16.5 Bcf) relates to
production beginning April 1, 2003.
The estimates of proved reserves set forth in the above table were prepared
in accordance with SEC regulations using market or contract prices at the end of
each reported period. Prices and operating and development costs are held
constant over the estimated life of the reserves.
Estimated proved developed reserves are reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
Proved undeveloped reserves are proved reserves that are expected to be
recovered from new wells drilled to known reservoirs on undrilled acreage for
which the existence and recoverability of reserves can be estimated with
reasonable certainty, or from existing wells where a relatively major
expenditure is required for recompletion.
Uncertainties in Estimating Reserves and Future Net Cash Flows. There are
numerous uncertainties in estimating quantities of proved reserves believed to
have been discovered and in projecting future rates of production and the timing
of development expenditures, including many factors beyond the control of the
Company. The reserve data set forth in this document are only estimates. Reserve
estimates are inherently imprecise and may be expected to change as additional
information becomes available. Furthermore, estimates of oil and natural gas
reserves, of necessity, are projections based on engineering data, and there are
uncertainties inherent in the interpretation of such data as well as the
projection of future rates of production and the timing of development
expenditures. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured
exactly, and the accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and judgment.
Accordingly, estimates of the economically recoverable quantities of oil and
natural gas attributable to any particular group of properties, classifications
of such reserves based on risk of recovery and estimates of the future net cash
flows expected therefrom prepared by different engineers or by the same
engineers at different times may vary substantially. There also can be no
assurance that the reserves set forth herein will ultimately be produced or that
the proved undeveloped reserves set forth herein will be developed within the
periods anticipated. It is possible that variances from the estimates will be
material. In addition, the estimates of future net cash flows from proved
reserves of the Company and the present value thereof are based
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<PAGE> 8
upon certain assumptions about future production levels, prices and costs that
may not be correct when judged against actual subsequent experience. The Company
emphasizes with respect to the estimates prepared by independent petroleum
engineers that the discounted future net cash flows should not be construed as
representative of the fair market value of the proved reserves owned by the
Company since discounted future net cash flows are based upon projected cash
flows which do not provide for changes in oil and natural gas prices from those
in effect on the date indicated or for escalation of expenses and capital costs
subsequent to such date. The meaningfulness of such estimates is highly
dependent upon the accuracy of the assumptions upon which they were based.
Accordingly, investors are cautioned not to place undue reliance on the reserve
data included in this document.
The Company has not filed any estimates of reserves with any federal
authority or agency during the past year other than estimates contained in
filings with the SEC.
7
<PAGE> 9
PRODUCTION, PRICE AND COST HISTORY
The following table sets forth certain production data, average sales
prices and average production expenses attributable to the Company's properties
for 1997, 1998 and 1999. Detailed additional information concerning the
Company's oil and natural gas production activities is contained in the
Supplementary Information in Note 12 to the Consolidated Financial Statements
included elsewhere in this Report.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1997 1998 1999
------- ------- -------
<S> <C> <C> <C>
PRODUCTION DATA:
Oil and other liquid hydrocarbons (Mbbls)................. 226 375 367
Natural gas (Mmcf)........................................ 30,202 35,557 22,392
Natural gas equivalent (Mmcfe)............................ 31,558 37,807 24,594
AVERAGE SALES PRICE PER UNIT (INCLUDING EFFECTS OF HEDGING):
Oil and other liquid hydrocarbons (per Bbl)............... $ 19.34 $ 13.09 $ 16.77
Natural gas (per Mcf)..................................... 2.27 2.09 2.12
Natural gas equivalent (per Mcfe)......................... 2.31 2.10 2.18
AVERAGE PRODUCTION EXPENSES PER MCFE........................ $ .35 $ .53 $ .64
</TABLE>
Productive Wells and Acreage
As of December 31, 1999, the Company had leaseholdings comprising 165,205
gross (68,752 net) developed acres and 250,796 gross (76,613 net) undeveloped
acres, all located within the continental United States. The oil and gas leases
in which the Company has an interest are for varying primary terms and many,
particularly in south Louisiana, require the payment of delay rentals in lieu of
drilling operations. In north Louisiana, most of the Company's leasehold
interests are held by production; that is, so long as natural gas and oil are
produced from the properties covered thereby, the leases continue indefinitely.
The leases may be surrendered at any time by notice to the lessors, by the
cessation of production or by failure to make timely payment of delay rentals,
if applicable.
The following table sets forth the Company's ownership interests in its
leaseholds as of December 31, 1999.
<TABLE>
<CAPTION>
DEVELOPED(1) UNDEVELOPED(2)
----------------------- -----------------------
GROSS ACRES NET ACRES GROSS ACRES NET ACRES
----------- --------- ----------- ---------
<S> <C> <C> <C> <C>
Louisiana.......................................... 72,451 24,090 198,592 56,499
Texas.............................................. 24,682 4,070 8,899 1,424
Offshore........................................... 55,402 35,334 2,830 1,054
Other states....................................... 12,670 5,258 40,475 17,636
------- ------ ------- ------
Total.................................... 165,205 68,752 250,796 76,613
======= ====== ======= ======
</TABLE>
- ---------------
(1) Acres spaced or assignable to productive wells.
(2) Acres 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 that acreage contains proved reserves.
As of December 31, 1999, the Company had working interests in 224 gross
(73.0 net) productive gas wells and 51 gross (8.0 net) productive oil wells
(including producing wells and wells capable of production).
8
<PAGE> 10
Exploration and Development
The following table sets forth the number of gross and net productive and
dry exploratory and development wells drilled by the Company.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1997 1998 1999
------------- ------------- ------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- ----
<S> <C> <C> <C> <C> <C> <C>
NORTH LOUISIANA:
Exploratory wells:
Oil............................................. -- -- -- -- -- --
Natural gas..................................... -- -- 2 .72 -- --
Dry............................................. -- -- -- -- -- --
-- ----- -- ----- -- ----
Total...................................... -- -- 2 .72 -- --
== ===== == ===== == ====
Development wells:
Oil............................................. -- -- -- -- -- --
Natural gas..................................... 82 34.96 43 20.68 6 1.36
Dry............................................. -- -- 1 .46 -- --
-- ----- -- ----- -- ----
Total...................................... 82 34.96 44 21.14 6 1.36
== ===== == ===== == ====
Total north Louisiana:
Producing....................................... 82 34.96 45 21.40 6 1.36
Dry............................................. -- -- 1 .46 -- --
-- ----- -- ----- -- ----
Total...................................... 82 34.96 46 21.86 6 1.36
== ===== == ===== == ====
SOUTH LOUISIANA, OFFSHORE AND OTHER:
Exploratory wells:
Oil............................................. -- -- -- -- 1 .50
Natural gas..................................... 9 3.50 6 1.81 2 .52
Dry............................................. 1 .50 7 3.22 -- --
-- ----- -- ----- -- ----
Total...................................... 10 4.00 13 5.03 3 1.02
== ===== == ===== == ====
Development wells:
Oil............................................. -- -- 3 .04 1 .18
Natural gas..................................... -- -- -- -- 1 .18
Dry............................................. -- -- -- -- 3 .97
-- ----- -- ----- -- ----
Total...................................... -- -- 3 .04 5 1.33
== ===== == ===== == ====
Total south Louisiana and other:
Producing....................................... 9 3.50 9 1.85 5 1.38
Dry............................................. 1 .50 7 3.22 3 .97
-- ----- -- ----- -- ----
Total...................................... 10 4.00 16 5.07 8 2.35
== ===== == ===== == ====
</TABLE>
As of December 31, 1999, the Company had 1 gross (.50 net) exploratory well
in progress in south Louisiana which was subsequently completed as a producing
well.
9
<PAGE> 11
Marketing of Natural Gas and Crude Oil
The Company does not refine or process any of the oil and natural gas it
produces. Substantially all of the Company's natural gas is sold under term
contracts, contracts providing for periodic price adjustments or in the spot
market. Its revenue streams are therefore sensitive to changes in current market
prices. The Company's sales of crude oil, condensate and natural gas liquids
generally are made at prices related to posted field prices.
In addition to marketing the Company's natural gas production, it secures
gas transportation arrangements, provides nomination and gas control services,
supervises gas aggregation operations and performs revenue receipt and
disbursement services as well as regulatory filing, recordkeeping, inspection,
testing, monitoring and marketing functions.
The Company believes that its activities are not currently constrained by a
lack of adequate transportation systems or system capacity and does not foresee
any material disruption in available transportation for its production. However,
there can be no assurance that the Company will not encounter these constraints
in the future. In that event, the Company would be forced to seek alternate
sources of transportation and may face increased costs.
Hedging Activities
The Company periodically uses forward sales contracts, natural gas and
crude oil price swap agreements, natural gas basis swap agreements and options
to reduce exposure to downward price fluctuations on its natural gas and crude
oil production. The Company does not engage in speculative transactions. During
1999, the Company used price and basis swap agreements to hedge its exposure to
possible declines in natural gas and crude oil prices. Additional information
concerning hedging activities of the Company during 1999 is set forth in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and in Note 10 to the Consolidated Financial Statements contained
elsewhere in this Report.
COMPETITION
The Company operates in a highly competitive environment with respect to
exploring, developing and acquiring reserves, marketing oil and natural gas and
securing trained personnel. Many of the Company's larger competitors possess and
employ financial and personnel resources substantially greater than those
available to it. Such companies may be better able to financially withstand the
costs of unsuccessful exploration and development activities. Such companies may
also be able to pay more for productive oil and natural gas properties and to
define, evaluate, bid for and purchase a greater number of properties than the
Company's financial or personnel resources permit. The Company's ability to
acquire additional reserves in the future will be dependent upon its ability to
evaluate and select suitable properties and to consummate transactions in a
highly competitive environment. In addition, there is substantial competition
for capital available for investment in the oil and natural gas industry. There
can be no assurance that the Company will be able to compete successfully in the
future in acquiring reserves, developing reserves, marketing hydrocarbons,
attracting and retaining quality personnel, and raising additional capital.
TITLE TO PROPERTIES
The Company's properties, in addition to being mortgaged to secure the
Notes, are subject to royalty interests, liens incident to operating agreements,
liens for current taxes and other customary burdens, including other mineral
encumbrances and restrictions. The Company does not believe that any mortgage,
lien or other burden materially interferes with the use of such properties in
the operation of its business.
The Company believes that it has satisfactory title to or rights in all of
its producing properties. As is customary in the oil and natural gas industry,
minimal investigation of title is made at the time of acquisition of undeveloped
properties. Title investigation is made, and title opinions of local counsel are
generally obtained before commencement of drilling operations or at least in
connection with the preparation of division orders when production is obtained
and the revenues therefrom are allocated.
10
<PAGE> 12
EMPLOYEES
As of December 31, 1999, the Company had 47 employees. The Company's staff
includes employees experienced in acquisitions, geology, geophysics, petroleum
engineering, land acquisition and management, finance and accounting. None of
the Company's employees are represented by a union. The Company has not
experienced an interruption in its operations due to any labor dispute and
believes that its working relationships with its employees are satisfactory.
REGULATION
The Company's operations are subject to extensive and continually changing
regulation, as legislation affecting the oil and natural gas industry is under
constant review for amendment and expansion. Many departments and agencies, both
federal and state, are authorized by statute to issue and have issued rules and
regulations binding on the oil and natural gas industry and its individual
participants. The failure to comply with such rules and regulations can result
in substantial penalties. The regulatory burden on the oil and natural gas
industry increases the Company's cost of doing business and, consequently,
affects its profitability. However, the Company does not believe that it is
affected in a significantly different manner by these regulations than are its
competitors in the oil and natural gas industry. Because of the numerous and
complex federal and state statutes and regulations that may affect the Company,
directly or indirectly, the following discussion of certain statutes and
regulations should not be relied upon as an exhaustive review of all matters
affecting the Company's operations.
Transportation and Production
Transportation and Sale of Natural Gas and Crude Oil. Sales of natural gas,
crude oil and condensate ("Products") can be made by the Company at market
prices not subject at this time to price controls. The price that the Company
receives from the sale of these Products is affected by the ability to transport
and cost of transporting the Products to market. Under applicable laws, the
Federal Energy Regulation Commission ("FERC") regulates both the construction of
pipeline facilities and the transportation of Products in interstate commerce.
Regulation of Drilling and Production. Drilling and production operations
of the Company are subject to regulation under a wide range of state and federal
statutes, rules, orders and regulations. State and federal statutes and
regulations govern, among other matters, the amounts and types of substances and
materials that may be released into the environment, the discharge and
disposition of waste materials, the reclamation and abandonment of wells and
facility sites and remediation of contaminated sites, and require permits for
drilling operations, drilling bonds and reports concerning operations. The
federal leases are administered by the Bureau of Land Management ("BLM") and the
Minerals Management Service ("MMS"), which are administered, along with the
Bureau of Indian Affairs, by the federal Department of the Interior. These
leases contain relatively standard terms and require compliance with detailed
MMS and BLM regulations and orders, which are subject to change. In addition to
permits required by other federal agencies (such as the Coast Guard, the Army
Corps of Engineers and the Environmental Protection Agency), lessees must obtain
a permit from the MMS or BLM prior to commencement of offshore or onshore
drilling. States in which the Company owns and operates properties have varying
laws and regulations governing conservation matters, including provisions for
the unitization or pooling of oil and natural gas properties, the establishment
of maximum rates of production from oil and natural gas wells and the regulation
of the spacing, plugging and abandonment of wells. Many states also restrict
production to the market demand for oil and natural gas and several states have
indicated interest in revising applicable regulations. The effect of these
regulations is to limit the amount of oil and natural gas the Company can
produce from its wells and to limit the number of wells or the locations at
which the Company can drill. Moreover, each state generally imposes an ad
valorem, production or severance tax with respect to the production and sale of
crude oil, natural gas and gas liquids within its jurisdiction.
Environmental Regulations
General. The various federal environmental laws, including the National
Environmental Policy Act; the Clean Air Act of 1990, as amended ("CAA"); Oil
Pollution Act of 1990, as amended ("OPA"); Water Pollution Control Act, as
amended ("FWPCA"); the Resource Conservation and Recovery Act as amended
("RCRA"); the Toxic Substances Control
11
<PAGE> 13
Act; and the Comprehensive Environmental Response, Compensation and Liability
Act, as amended ("CERCLA"), and the various state and local environmental laws,
and the regulations adopted pursuant to such law, governing the discharge of
materials into the environment, or otherwise relating to the protection of the
environment, continue to be taken seriously by the Company. In particular, the
Company's drilling, development and production operations, its activities in
connection with storage and transportation of crude oil and other liquid
hydrocarbons and its use of facilities for treating, processing or otherwise
handling hydrocarbons and wastes therefrom are subject to stringent
environmental regulation, and violations are subject to reporting requirements,
civil penalties and criminal sanctions. As with the industry generally,
compliance with existing regulations increases the Company's overall cost of
business. The increased costs are not reasonably ascertainable. Such areas
affected include unit production expenses primarily related to the control and
limitation of air emissions and the disposal of produced water, capital costs to
drill exploration and development wells resulting from expenses primarily
related to the management and disposal of drilling fluids and other oil and
natural gas exploration wastes and capital costs to construct, maintain and
upgrade equipment and facilities and plug and abandon inactive well sites and
pits.
Environmental regulations historically have been subject to frequent change
by regulatory authorities, and the Company is unable to predict the ongoing cost
of compliance with these laws and regulations or the future impact of such
regulations on its operations. However, the Company does not believe that
changes to these regulations will materially adversely affect the Company's
competitive position because its competitors are similarly affected. A discharge
of hydrocarbons or hazardous substances into the environment could subject the
Company to substantial expense, including both the cost to comply with
applicable regulations pertaining to the remediation of releases of hazardous
substances into the environment and claims by neighboring landowners and other
third parties for personal injury and property damage. The Company maintains
insurance, which may provide protection to some extent against environmental
liabilities, but the coverage of such insurance and the amount of protection
afforded thereby cannot be predicted with respect to any particular possible
environmental liability and may not be adequate to protect the Company from
substantial expense.
The OPA and regulations thereunder impose a variety of regulations on
"responsible parties" related to the prevention of oil spills and liability for
damages resulting from such spills in United States waters. A "responsible
party" includes the owner or operator of an onshore facility, vessel, or
pipeline, or the lessee or permittee of the area in which an offshore facility
is located. The OPA assigns liability to each responsible party for oil removal
costs and a variety of public and private damages. The FWPCA imposes
restrictions and strict controls regarding the discharge of produced waters and
other oil and natural gas wastes into navigable waters. State laws for the
control of water pollution also provide varying civil, criminal and
administrative penalties and impose liabilities in the case of a discharge of
petroleum or its derivatives, or other hazardous substances, into state waters.
In addition, the Environmental Protection Agency ("EPA") has promulgated
regulations that require many oil and natural gas production operations to
obtain permits to discharge storm water runoff.
The CAA requires or will require most industrial operations in the United
States to incur capital expenditures in order to meet air emission control
standards developed by the EPA and state environmental agencies. Although no
assurances can be given, the Company believes implementation of such amendments
will not have a material adverse effect on its financial condition or results of
operations. RCRA is the principal federal statute governing the treatment,
storage and disposal of hazardous wastes. RCRA imposes stringent operating
requirements (and liability for failure to meet such requirements) on a person
who is either a "generator" or "transporter" of hazardous waste or an "owner" or
"operator" of a hazardous waste treatment, storage or disposal facility. At
present, RCRA includes a statutory exemption that allows oil and natural gas
exploration and production wastes to be classified as non-hazardous waste. As a
result, the Company is not required to comply with a substantial portion of
RCRA's requirements because the Company's operations generate minimal quantities
of hazardous wastes.
12
<PAGE> 14
CERCLA, also known as "Superfund", imposes liability, without regard to
fault or the legality of the original act, on certain classes of persons that
contributed to the release of a "hazardous substance" into the environment.
These persons include the "owner" or "operator" of the site and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. CERCLA also authorizes the EPA and, in some instances, third parties to
act in response to threats to the public health or the environment and to seek
to recover from the responsible classes of persons the costs they incur. In the
course of its ordinary operations, the Company may generate waste that may fall
within CERCLA's definition of a "hazardous substance". As a result, the Company
may be jointly and severally liable under CERCLA or under analogous state laws
for all or part of the costs required to clean up sites at which such wastes
have been disposed. 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 natural 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 actions with respect
to the treatment and disposal or release of hydrocarbons or other wastes were
not under the Company's control. These properties and wastes disposed thereon
may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the
Company could be required to remove or remediate previously disposed wastes
(including wastes disposed of or released by prior owners or operators), to
clean up contaminated property (including contaminated groundwater) or to
perform remedial plugging operations to prevent future contamination.
CAUTION AS TO FORWARD-LOOKING STATEMENTS
Statements contained in this Report and other materials filed or to be
filed by the Company with the Securities and Exchange Commission (as well as
information included in oral or other written statements made or to be made by
the Company or its representatives) that are forward-looking in nature are
intended to be "forward-looking statements" within the meaning of Section 27A of
the Securities Act of 1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended, relating to matters such as anticipated
operating and financial performance, business prospects, developments and
results of the Company. Actual performance, prospects, developments and results
may differ materially from any or all anticipated results due to economic
conditions and other risks, uncertainties and circumstances partly or totally
outside the control of the Company, including rates of inflation, natural gas
prices, uncertainty of reserve estimates, rates and timing of future production
of oil and gas, exploratory and development activities, acquisition risks and
activities, changes in the level and timing of future costs and expenses related
to drilling and operating activities and those risks described under "Risk
Factors" below.
Words such as "anticipated," "expect," "estimate," "project" and similar
expressions are intended to identify forward-looking statements. Forward-looking
statements include the risks described in "Risk Factors".
RISK FACTORS
The Company cautions that the following risks identified in risk factors
could affect its actual results in the future in addition to "Estimated Proved
Reserves-Uncertainties in Estimating Reserves and Future Net Cash Flows"
included elsewhere in this Report.
Substantial Leverage; Inability to Service Debt; Lack of Liquidity;
Substantial Capital Requirements. As of December 31, 1999, the Company had
$268.5 million principal amount of debt outstanding, stockholders' deficit of
approximately $76.3 million and cash on hand of approximately $10.4 million
(excluding restricted cash of $7.5 million). The Company has principal and
interest payments of $24.2 million (includes the impact of the first quarter
2000 retirement of $0.3 million of the Company's Securities) due in April 2000.
The Company has significant debt outstanding relative to its asset base and cash
flows. The ability of the Company to service such debt is primarily dependent on
its operational cash flows which are dependent on various factors outside of its
control, including the oil and natural gas commodity markets. To the extent such
factors negatively affect cash flows, the ability of the Company to meet its
debt obligations may be impaired. Therefore, there can be no assurance that the
Company will have sufficient funds to meet all of its future debt obligations.
13
<PAGE> 15
Historically, the Company has financed its operational activities
(including acquisitions, exploration and development of oil and natural gas
properties) primarily through the issuance of debt and equity securities,
through various credit facilities and with internally generated funds. The
Company currently has plans for significant capital expenditures to continue its
operational activities. However, the Company does not currently have ready
access to additional sources of financing of such activities outside of
internally generated cash flows and proceeds from asset sales. Therefore, no
assurance can be given that the Company will have adequate funds available to
fund its operational activities and carry out its strategy. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Liquidity and Capital Resources".
Depletion of Reserves; Necessity of Successful Exploration and
Development. Producing oil and natural gas reservoirs generally are
characterized by declining production rates that vary depending upon reservoir
characteristics and other factors. The Company's future oil and natural gas
reserves and production, and, therefore, cash flow and income, are highly
dependent upon the Company's success in efficiently developing its current
reserves and acquiring additional reserves that are economically recoverable.
Volatility of Oil, Natural Gas and Natural Gas Liquids Prices. The
Company's financial results are affected significantly by the prices received
for its oil, natural gas and natural gas liquids production. Historically, the
markets for oil, natural gas and natural gas liquids have been volatile. The
prices received by the Company for its oil, natural gas and natural gas liquids
production and the levels of such production are subject to government
regulation, legislation and policies. The Company's future financial condition
and results of operations will depend, in part, upon the prices received for its
oil and natural gas production, as well as the costs of finding, acquiring,
developing and producing reserves.
Operating Hazards and Uninsured Risks. Oil and gas drilling activities are
subject to numerous risks, many of which are uninsurable, including the risk
that no commercially viable oil or natural gas production will be obtained; many
of such risks are beyond the Company's control. The decision to purchase,
explore or develop a prospect or property will depend in part on the evaluation
of data obtained through geophysical and geological analyses, production data
and engineering studies, the results of which are often inconclusive or subject
to varying interpretations. The cost of drilling, completing and operating wells
is often uncertain, and overruns in budgeted expenditures are common risks that
can make a particular project uneconomical. Technical problems encountered in
actual drilling, completion and workover activities can delay such activity and
add substantial costs to a project. Further, drilling may be curtailed, delayed
or canceled as a result of many factors, including title problems, weather
conditions, compliance with government permitting requirements, shortages of or
delays in obtaining equipment, reductions in product prices and limitations in
the market for products.
The availability of a ready market for the Company's oil and natural gas
production also depends on a number of factors, including the demand for and
supply of oil and natural gas and the proximity of reserves to pipelines or
trucking and terminal facilities. Natural gas wells may be partially or totally
shut in for lack of a market or because of inadequacy or unavailability of
natural gas pipeline or gathering system capacity.
The Company's oil and natural gas business also is subject to all of the
operating risks associated with the drilling for and production of oil and
natural gas, including, but not limited to, uncontrollable flows of oil, natural
gas, brine or well fluids into the environment (including groundwater and
shoreline contamination), blowouts, cratering, mechanical difficulties, fires,
explosions, pollution and other risks, any of which could result in substantial
losses to the Company. Although the Company maintains insurance at levels that
it believes are consistent with industry practices, it is not fully insured
against all risks. Losses and liabilities arising from uninsured and
underinsured events could have a material adverse effect on the financial
condition and operations of the Company.
14
<PAGE> 16
ITEM 3. LEGAL PROCEEDINGS
The Company is involved in various claims and lawsuits incidental to its
business. In the opinion of management, the ultimate liability thereunder, if
any, will not have a material effect on the financial condition of the Company.
In March 2000, a class action suit was brought against the Company in the
Court of Chancery of the State of Delaware, complaining, among other things,
that the Company had not taken necessary steps to facilitate the election of two
additional directors to its board by preferred stockholders. Under the charter
provisions relating to the Company's preferred stock, upon the occasion of the
dividends not being paid on such preferred stock for six quarters, the preferred
stockholders are, as a class, entitled to elect two directors to the Company's
board. Among the relief sought in such proceeding are an injunction directing
the Company to create new directorships for nominations from preferred
stockholders at the 2000 annual meeting of stockholders, directing that past
dividends be paid, declaring that the Company's reverse stock split in 1999,
which involved the settlement of fractional shares by the payment of a small
amount of cash (less than $1,500) by the Company, constituted a repurchase of
common shares in violation of the preferred stock charter provisions and was
therefore void and other relief. The Company has consistently acknowledged,
publicly and privately, the rights of such preferred stockholders to elect two
directors and believes it has not in any way encumbered the preferred
shareholders from exercising such rights. The Company believes that the
complaint and the relief sought are wholly without merit and will vigorously
defend its positions in such proceedings.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted for a vote of the Company's stockholders during
the fourth quarter of 1999.
15
<PAGE> 17
PART II
ITEM 5. MARKET FOR THE COMPANY'S SECURITIES AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock and Preferred Stock are traded on the OTC
Bulletin Board under the symbols "CONC" and "CONCP." On August 30, 1999, at
market close, the Company's shares of common stock and convertible Preferred
Stock, which traded under the symbols of CONCC and CONCP, were delisted from the
NASDAQ SmallCap Market. These actions were taken as a result of the Company's
failure to meet the requirements for continued listing on this exchange. On
August 31, 1999, at market open, the Company's stock began trading on the OTC
Bulletin Board under the symbols of CONC and CONCP. The price ranges presented
below represent high and low sale prices for each quarter, as reported by the
NASDAQ Stock Market, NASDAQ SmallCap Market and the OTC Bulletin Board.
<TABLE>
<CAPTION>
CONC CONCP
COMMON STOCK PREFERRED STOCK
MARKET PRICES MARKET PRICES
-------------------------- --------------------------
HIGH LOW HIGH LOW
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
1997:
First quarter......................................... $30 5/8 $18 3/4 $25 3/4 $23 3/4
Second quarter........................................ 30 5/8 16 7/8 26 22 1/2
Third quarter......................................... 32 1/2 21 7/8 26 7/8 24 1/4
Fourth quarter........................................ 39 3/8 21 1/4 25 1/2 21 1/2
1998:
First quarter......................................... $28 1/8 $17 1/2 $25 3/4 $20 3/4
Second quarter........................................ 28 1/8 19 3/8 28 1/2 22
Third quarter......................................... 23 1/8 10 23 3/8 16
Fourth quarter........................................ 16 1/4 4 11/16 16 1/2 8
1999:
First quarter......................................... $10 5/16 $ 4 3/8 $10 1/2 $ 3 11/16
Second quarter........................................ 8 3/4 2 3/16 6 3 3/8
Third quarter......................................... 5 1 6 1/2 3 1/4
Fourth quarter........................................ 1 5/16 3/8 5 3/4 1
</TABLE>
As of the January 31, 2000, there were approximately 741 record holders of
Common Stock and 101 record holders of Preferred Stock.
Dividends on the Preferred Stock accrue quarterly at the rate of $.65625
per share. In January 1996, the Company announced the suspension of dividend
payments on the Preferred Stock to conserve cash. On April 15, 1997, the Board
of Directors of the Company declared a dividend of $2.625 per preferred share
(approximately $4.6 million), which was paid on May 1, 1997. On April 14, 1998,
the Company declared a dividend of $2.625 per share of Preferred Stock
(approximately $4.6 million), which was paid on April 30, 1998. Further
dividends are restricted under the Company's indentures governing its 10 3/8%
Senior Subordinated Notes and its 14% Senior Secured Notes. As of February 1,
2000, the total amount of dividend payments in arrears was approximately $8.1
million, covering nine quarters. Since the Company has not paid dividends on the
Preferred Stock for a period of nine quarters, the holders of Preferred Stock,
as a group, have the right to elect two additional directors to the Company's
Board of Directors. See "Legal Proceedings".
16
<PAGE> 18
ITEM 6. SELECTED FINANCIAL DATA
The following tables present selected financial data for the Company that
is derived from the audited consolidated financial statements of the Company.
The historical financial information for the year ended December 31, 1995
reflects the Consolidation in February 1995. Prior to the Consolidation, the
financial information reflects Kelley Oil's historical results of Operations.
The impact of the acquisition of the SCANA Petroleum Resources, Inc. properties
is reflected in the selected financial data as of December 1, 1997. This
information should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the Consolidated
Financial Statements of the Company and related Notes included elsewhere in this
Report.
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION)
AND SUBSIDIARIES
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------
1995 1996 1997 1998 1999
--------- -------- ------- -------- --------
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Oil and gas revenues......................... $ 36,998 $ 60,854 $75,864 $ 79,150 $ 54,107
Interest and other income.................... 1,763 1,429 274 505 1,974
Gain on sale of properties(1)................ -- -- -- -- 25,863
--------- -------- ------- -------- --------
Total revenues..................... 38,761 62,283 76,138 79,655 81,944
--------- -------- ------- -------- --------
Production expenses.......................... 10,835 10,709 10,955 19,878 15,541
Exploration expenses......................... 23,387 5,438 5,433 12,034 5,736
General and administrative expenses.......... 7,030 8,953 6,875 7,077 7,463
Interest and other debt expenses............. 21,956 24,401 25,071 33,333 38,002
Restructuring expenses....................... 1,115 4,276 -- -- --
Depreciation, depletion and amortization..... 35,591 20,440 25,853 38,602 35,986
Impairment of oil and gas properties(2)...... 150,138 -- -- 25,738 --
--------- -------- ------- -------- --------
Income (loss) before income taxes and
extraordinary item......................... (211,291) (11,934) 1,951 (57,007) (20,784)
Provision for taxes.......................... -- -- -- -- --
--------- -------- ------- -------- --------
Net income (loss) before extraordinary
item....................................... (211,291) (11,934) 1,951 (57,007) (20,784)
Extraordinary (loss) gain(3)................. -- (17,030) -- -- 11,051
--------- -------- ------- -------- --------
Net income (loss)............................ $(211,291) $(28,964) $ 1,951 $(57,007) $ (9,733)
========= ======== ======= ======== ========
Basic and diluted loss per common share
before extraordinary item(4)(5)............ $ (53.11) $ (1.83) $ (.26) $ (4.89) $ (1.94)
Basic and diluted loss per common
share(4)(5)................................ $ (53.11) $ (3.72) $ (.26) $ (4.89) $ (1.08)
Weighted average common shares
outstanding(5)............................. 4,103 9,011 10,076 12,578 12,871
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
----------------------------------------------------
1995 1996 1997 1998 1999
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Property and equipment, net........... $128,642 $158,468 $293,613 $256,455 $165,756
Long term debt, excluding current
maturities......................... 164,980 184,253 286,183 287,500 246,165
Stockholders' deficit................. (45,568) (30,535) (5,621) (66,939) (76,303)
Total assets.......................... 151,342 189,227 322,602 286,197 203,782
</TABLE>
- ---------------
(1) Reflects the gain on the sale of properties to Phillips. See "Business and
Properties", "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and "Notes to Consolidated Financial Statements."
(2) Reflects noncash impairment charges against the carrying value of proved and
unproved properties under SFAS 121. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and "Notes to
Consolidated Financial Statements."
(3) The extraordinary loss in 1996 was incurred in connection with the
refinancing of the 13 1/2% Senior Notes and represents the excess of the
aggregate purchase price of the 13 1/2% Senior Notes (including consent
payments) over their carrying value as of the date the refinancing was
consummated.
17
<PAGE> 19
The 1999 extraordinary gain of $11.1 million was related to debt
repurchases and refinancings. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations".
(4) Dividends on the Company's cumulative preferred stock are deducted from "Net
Income (Loss) Before Extraordinary Item" and "Net Income (Loss)" in
calculating related per share amounts, whether or not declared, and amounted
to $6.6 million, $4.6 million, $4.6 million, $4.6 million and $4.2 million
for the years ended December 31, 1995, 1996, 1997, 1998 and 1999,
respectively.
(5) Reflects the Company's 1 for 10 reverse stock split in 1999. See Note 5 in
Notes to Consolidated Financial Statements.
18
<PAGE> 20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following information should be read in conjunction with the
information contained in the Financial Statements of the Company included
elsewhere in this Report.
General
Introduction. Contour Energy Co. (formerly Kelley Oil & Gas Corporation)
and its consolidated subsidiaries (the "Company") are engaged in oil and natural
gas exploration, development, production and acquisition. The Company's 1999
operational activities were focused primarily on exploiting its north Louisiana
properties and exploration activities on its south Louisiana and offshore
interests. In 1999, the Company drilled or participated in drilling 11 gross
(2.69 net) development wells and 3 gross (1.02 net) exploratory wells of which 8
gross (1.72 net) and 3 gross (1.02 net), respectively, have been completed as
producing wells.
General Conditions of the Oil and Natural Gas Industry and Commodity
Prices. The prices of oil and natural gas have improved significantly over the
past several months. However, cash prices and NYMEX based prices for both oil
and natural gas continue to fluctuate significantly on an intra-month, month-to-
month, and future year basis, reflecting the volatility of commodity prices. The
Company has received the benefits of such higher prices in the form of increased
operating cash flows and is dependent on such cash flows to fund its future
obligations and capital expenditure programs. However, given the volatility of
commodity prices there can be no assurance that current levels can be sustained
(see "Risk Factors"). A decrease in the current level of commodity prices could
have a materially adverse impact on the Company's results of operations,
liquidity, and ability to meet its future obligations. Additionally, the Company
must provide cash collateral for any hedges (through swap or other agreements)
to cover counter-party risk. Hence, the volume of oil and/or natural gas
production the Company can hedge is severely limited, thereby reducing the
ability of the Company to mitigate the impact of volatile commodity prices.
Hedging Activities. The Company periodically uses forward sales contracts,
natural gas and crude oil price swap agreements, natural gas basis swap
agreements and options to reduce exposure to downward price fluctuations on its
natural gas and crude oil production. The Company does not engage in speculative
transactions. During 1999, the Company used price and basis swap agreements.
Price swap agreements generally provide for the Company to receive or make
counterparty payments on the differential between a fixed price and a variable
indexed price for natural gas and oil. Basis swap agreements generally provide
for the Company to receive or make counterparty payments on the differential
between a variable indexed price and the price it receives from the sale of
natural gas production, and are used to hedge against unfavorable price
movements in the relationship between such variable indexed price and the price
received for such production. Gains and losses realized by the Company from
hedging activities are included in oil and gas revenues and average sales prices
in the period that the related production is sold. The Company's hedging
activities also cover the oil and gas production attributable to the interest in
such production of the public unitholders in its subsidiary partnerships.
Through natural gas price swap agreements, the Company hedged approximately
65%, 49% and 50% of its natural gas production for 1997, 1998 and 1999,
respectively, at average NYMEX quoted prices of $2.35, $2.31 and $2.17, per
Mmbtu, respectively, before transaction and transportation costs. As of December
31, 1999, 1,550,000 Mmbtus of natural gas production for January 2000 has been
hedged by natural gas price swap agreements at an average NYMEX quoted price of
$2.41 per Mmbtu before transaction and transportation costs. Additional hedging
activities since December 31, 1999 have increased the volumes hedged in 2000 to
8,900,000 Mmbtus of natural gas at an average NYMEX quoted price of $2.56 per
Mmbtu before transaction and transportation costs. Through crude oil price swap
agreements, the Company hedged approximately 29% of its crude oil production for
1999 at an average NYMEX quoted price of $20.00 per bbl, before transaction and
transportation costs. No crude oil was hedged in either 1997 or 1998. As of
December 31, 1999, 30,000 bbls of crude oil production for January 2000 through
March 2000 has been hedged by crude oil price swap agreements at an average
NYMEX quoted price of $25.05 per bbl before transaction and transportation
costs. Additional hedging activities since December 31, 1999 have increased the
volumes hedged in 2000 to 182,500 bbls of crude oil production at an average
NYMEX quoted price of $26.21 per bbl before transaction and transportation
costs. Hedging activities decreased crude oil and natural gas revenues by
approximately $4.2 million in 1997 and $0.2 million in 1999, respectively, and
increased
19
<PAGE> 21
such revenues by approximately $3.5 million in 1998 as compared to estimated
revenues had no hedging activities been conducted. At December 31, 1999, the
unrealized gain on the Company's existing hedging instruments for future
production months in 2000 approximated $23,000.
The credit risk exposure from counterparty nonperformance on natural gas
forward sales contracts and derivative financial instruments is generally the
amount of unrealized gains under the contracts. The Company has not experienced
counterparty nonperformance on these agreements and does not anticipate any in
future periods.
Other Developments. Effective July 30, 1999, the name of the Company was
changed to Contour Energy Co. and its NASDAQ ticker symbol to CONCC. Concurrent
with the name change, the Company established the authorized capital stock of
the Company at 22 million shares, 20 million of which were designated as common
stock and 2 million as preferred stock, and effected a 1 for 10 reverse stock
split, reducing the total outstanding shares of common stock from approximately
126 million to approximately 12.6 million (without giving effect to the
preferred stock exchange offer described in the following paragraph). On August
30, 1999, at market close, the Company's shares of common stock and convertible
preferred stock, which traded under the symbols of CONCC and CONCP, were
delisted from the Nasdaq SmallCap Market. These actions were taken as a result
of the Company's failure to meet the requirements for continued listing on this
exchange. On August 31, 1999, at market open, the Company's stock began trading
on the OTC Bulletin Board under the symbols of CONC and CONCP.
On June 28, 1999, the Company began an offer to exchange 15 shares of its
common stock (or 1.5 shares on a post-split basis) for each share of its $2.625
convertible exchangeable preferred stock ("Preferred Stock"). Pursuant to the
exchange offer, 368,633 shares of Preferred Stock were tendered representing
approximately 21% of the total Preferred stock outstanding. In July 1999, the
shares were exchanged for 552,950 shares of newly issued common stock of the
Company (after giving effect to the 1 for 10 reverse stock split), increasing
the Company's shares of outstanding common stock to approximately 13.2 million.
With the exchange, the Company eliminated dividend arrearages of approximately
$1.5 million.
Subsequent Events. In March 2000, the Company executed a sale of a portion
of its volumetric overriding royalty interest ("VORI"). The net proceeds from
the sale approximated $20 million. Since the portion of the reserves sold
(approximately 16.5 Bcf) includes production beginning April 1, 2003, near-term
cash flows of the company were not impacted.
Results of Operations
Years Ended December 31, 1999 and 1998. The Company's oil and gas revenues
of $54.1 million for 1999 decreased 32% compared to $79.2 million in 1998
primarily as a result of lower natural gas production (37%). The decrease in gas
production is primarily due to production associated with the Company's
interests in the Bryceland, West Bryceland and Sailes fields in north Louisiana
which were sold to Phillips in the second quarter of 1999. See Liquidity and
Capital Resources for further discussion.
Interest and other income increased from $0.5 million in 1998 to $2.0
million in 1999 primarily due to higher cash balances in the current year.
Production expenses for 1999 decreased 22% to $15.5 million from $19.9
million in the prior year, resulting primarily from north Louisiana properties
sold to Phillips in the second quarter of 1999. Lifting costs (production
expenses less ad valorem and severance taxes) were $.54 per Mcfe in 1999
compared to $0.41 per Mcfe in 1998, a 32% increase, reflecting a higher
percentage of offshore properties at higher lifting costs per unit after the
second quarter 1999 sale of north Louisiana properties to Phillips.
Exploration expenses decreased 53% from $12.0 million in 1998 to $5.7
million in 1999 due to decreased dry hole, seismic and unproved property
abandonment expenses in the current year.
General and administrative ("G&A") expenses of $7.5 million included $1.9
million of costs of a non-recurring nature related to professional, consulting
and transaction costs. Ongoing G&A expenses of $5.6 million decreased 21%
20
<PAGE> 22
compared to $7.1 million in 1998. On a unit of production basis, general and
administrative expenses were $0.30 per Mcfe in 1999 compared to $0.19 per Mcfe
in 1998 reflecting the higher non-recurring professional, consulting and
transaction costs. Excluding the non-recurring costs, G&A expenses were $0.23
per mcfe in 1999.
Interest and other debt expenses of $38.0 million in 1999 increased 14%
from $33.3 million in 1998. The increase in interest expense resulted primarily
from higher average interest rates during the current year. In addition to its
1999 cash interest expense of $33.5 million, the Company recorded non-cash
charges in 1999 of $4.5 million for amortization of debt issuance costs,
accretion of note discount and accretion of debt valuation discount. The 1999
cash interest expense of $33.5 million includes approximately $2.4 million of
interest payments related to debt that was redeemed in 1999.
DD&A expenses decreased 7% from $38.6 million in 1998 to $36.0 million in
1999, primarily as a result of lower production in 1999 due to the sale of north
Louisiana properties to Phillips partially offset by $6.9 million of DD&A
expense in the current year associated with the Bayou Sauveur field (Harry Bourg
wells). The $6.9 million of DD&A expense results from the amortization of the
total well costs of both the Bourg No. 1 and Bourg No. 2 wells over the current
proved developed reserves in the Bayou Sauveur field. The units-of-production
DD&A rate for oil and gas activities was $1.01 per Mcfe in 1998 compared to
$1.43 per Mcfe in 1999. Excluding the impact of the Bayou Sauveur field, the
DD&A rate for 1999 was $1.17 per Mcfe.
In 1998, under Statement of Financial Accounting Standards No. 121 ("SFAS
121"), "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of", the Company recognized noncash impairment charges of
$25.7 million against the carrying values of its proved and unproved oil and gas
properties, aggregating $21.6 million and $4.1 million, respectively, for the
year ended December 31, 1998 (see "Oil and Gas Properties" in Note 2 to
Consolidated Financial Statements). No impairment was required in 1999.
The Company recognized a net loss of $(9.7) million in 1999 and a net loss
of $(57.0) million in the prior year. The reasons for the earnings changes are
described in the foregoing discussion.
Years Ended December 31, 1998 and 1997. The Company's oil and gas revenues
of $79.2 million for 1998 increased 4% compared to $75.9 million in 1997
primarily as a result of an increase in gas production 18%, partially offset by
lower oil prices (32%) and gas prices (8%). The increase in gas production is
primarily due to the Company's Scana Petroleum Resources ("SPR") acquisition and
drilling activities in north Louisiana.
Interest and other income increased from $0.3 million in 1997 to $0.5
million in 1998 primarily due to business interruption insurance proceeds
related to hurricane disruptions on offshore properties.
Production expenses for 1998 increased 81% to $19.9 million from $11.0
million in the prior year, resulting primarily from the SPR properties acquired
during the fourth quarter of 1997 and higher current period workover expenses.
Higher-cost production from the Gulf of Mexico properties acquired in the SPR
acquisition contributed to a 78% increase in lifting costs (production expenses
less ad valorem and severance taxes) per Mcfe to $.41 in 1998 as compared to
$0.23 in 1997.
Exploration expenses increased 122% from $5.4 million in 1997 to $12.0
million in 1998 due to increased dry hole, seismic and unproved property
abandonment expenses and higher overhead allocated to exploration activities.
G&A expenses of $7.1 million in 1998 increased 3% compared to $6.9 million
last year. On a unit of production basis, G&A expenses were $0.19 per Mcfe in
1998 compared to $0.22 per Mcfe in 1997.
Interest and other debt expenses of $33.3 million in 1998 increased 33%
from $25.1 million in 1997. The increase in interest expense resulted primarily
from higher average debt levels during the current period due to increased
borrowings under the Credit Facility and issuance of the Series C Notes. In
addition to its 1998 cash interest expense of $28.1 million, the Company
recorded non-cash charges in 1998 of $2.2 million for amortization of debt
issuance costs, $1.0 million for accretion of note discount and $2.0 million for
accretion of debt valuation discount.
21
<PAGE> 23
Depreciation, depletion and amortization ("DD&A") expense increased 49%
from $25.9 million in 1997 to $38.6 million in 1998, as a result of higher 1998
production levels and an increase in the units-of-production DD&A rate for oil
and gas activities from $0.80 per Mcfe in 1997 to $1.01 in 1998.
In 1998, under Statement of Financial Accounting Standards No. 121 ("SFAS
121"), "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of", the Company recognized noncash impairment charges of
$25.7 million against the carrying values of its proved and unproved oil and gas
properties, aggregating $21.6 million and $4.1 million, respectively, for the
year ended December 31, 1998 (see "Oil and Gas Properties" in the "Notes to
Consolidated Financial Statements").
The Company recognized a net loss of $(57.0) million in 1998 and net income
of $2.0 million in the prior year. The reasons for the earnings changes are
described in the foregoing discussion.
Liquidity and Capital Resources
General. The Company had $268.5 million principal amount of debt
outstanding as of December 31, 1999 ($254.8 million recorded on the balance
sheet), requiring approximately $31.1 million in annual cash interest payments.
The remaining outstanding principal amounts of $8.4 million of the Company's
8 1/2% Convertible Subordinated Debentures are due on April 1, 2000 (includes
the impact of the first quarter 2000 retirement of $0.3 million of these
securities).
In 1999, the Company undertook several strategic actions in response to the
severe downturn in the industry in 1998 caused by low commodity prices and the
closing of the capital markets to smaller oil and gas companies. These actions,
described below, were designed to increase the near-term liquidity of the
Company, provide capital for its ongoing capital expenditure programs and
establish a stronger base for future growth.
In April 1999, the Company entered into an Exploration and Development
Agreement with Phillips Petroleum Company ("Phillips") relating to certain of
the Company's interests in the Bryceland, West Bryceland and Sailes fields in
north Louisiana. Pursuant to the agreement, the Company (1) received an $83
million cash payment, (2) retained a 42 Bcf, 8-year volumetric overriding
royalty interest (the "VORI") and a 1% override on the excess of production
above such royalty interest and (3) retained 25% of its working interest in the
Cotton Valley formation. In addition, Phillips, will at its risk and expense,
operate, develop, exploit and explore the properties thereby relieving the
Company of significant operating, exploration and development costs in the
future. The transaction closed on May 17, 1999. The Company recognized a gain of
approximately $25.9 million in 1999 related to this transaction.
In April 1999, the Company negotiated a private offering of $135.0 million
principal amount, 14% Senior Secured Notes (the "Notes"). The Notes are secured
by a first lien on substantially all of the Company's proved oil and natural gas
properties remaining after the sale to Phillips and guaranteed by three entities
wholly-owned by the Company. In accordance with the Notes indenture, on June 30,
1999, the Company funded $37.5 million to repurchase $35 million principal
amount of the Notes at a repurchase price equal to 104% of the principal amount,
plus accrued and unpaid interest and commitment fees to the date of the
repurchase.
On May 17, 1999, the Company funded $28.5 million to repurchase $46.1
million of the outstanding principal amounts of its 7 7/8% Convertible
Subordinated Notes due December 15, 1999 and its 8 1/2% Convertible Subordinated
Debentures due April 1, 2000 (collectively, the "Securities") at a price equal
to $590 per $1,000 principal amount (not including accrued interest paid of $1.2
million).
In addition, on May 17, 1999 the Company repaid all borrowings outstanding
under its revolving credit facility of $115.5 million plus accrued interest and
terminated the revolving credit facility and funded cash collateral for a $1.5
million letter of credit which was subsequently increased to $7.5 million. The
Company used net proceeds remaining from the transactions for general corporate
purposes. In 1999, the Company recognized an extraordinary gain of $11.1 million
related to debt repurchases and refinancings, comprised of: (i) a net gain on
the Securities tender offer and other debt retirements of $16.0 million, reduced
by, (ii) a $1.4 million premium on the $35 million Notes repurchase and the
proportionate write-off of debt issue costs of $2.4 million and (iii) the
write-off of credit facility debt issue costs of $1.1 million.
22
<PAGE> 24
In the third and fourth quarters of 1999, the company retired the remaining
$5.2 million face amount of the 7 7/8% notes. The total principal paid was $4.9
million, which included $3.5 million retired at maturity in December 1999. The
company also retired $1.0 million face amount of the 8 1/2% debentures at a cost
of $0.9 million. The combination of these retirements resulted in an
extraordinary gain of $0.3 million. In the first quarter of 2000, the Company
retired an additional $0.3 million face amount of its Securities. The settlement
payments included principal amounts of $0.2 million and accrued interest of
$7,000.
In March 2000, the Company sold a portion of the VORI (the "VORI Sale").
The net proceeds from the sale approximated $20 million. Since the portion of
the VORI sold (approximately 16.5 Bcf) represents production commencing April
1, 2003, the VORI Sale will not impact the Company's operating cash flows until
2003.
Dividends on the Company's preferred stock accrue quarterly at a rate of
$0.65625 per share. On April 14, 1998, the Board of Directors of the Company
declared a dividend on the Company's preferred stock of $2.625 per share
(approximately $4.6 million), which was paid on April 30, 1998. The Company has
not declared the quarterly dividends of $0.65625 for nine quarters including
February 1, 2000 aggregating approximately $8.1 million. Further dividends are
restricted under the Company's indentures governing its 10 3/8% Senior
Subordinated Notes and its 14% Senior Secured Notes. However, the Company's
outstanding preferred stock is cumulative, requires dividends to accumulate
currently at the rate of $3.6 million annually and carries liquidation
preferences over the Common Stock totaling $41.8 million at December 31, 1999,
including such dividend arrearages. Furthermore, since the Company has not paid
dividends on the preferred stock for a period of nine quarters the holders of
preferred stock, as a group, have the right to elect two additional directors to
the Company's Board of Directors. See "Legal Proceedings".
The Company has received the benefits of a general increase in the level of
commodity prices over the past several months. This increase, combined with the
actions described above and the VORI Sale, have provided the Company with
near-term liquidity and capital for its ongoing operations. However, the
commodity markets are volatile and there is no certainty that current oil and
natural gas prices can be sustained at these levels. In addition, the Company
continues to have significant debt outstanding relative to its asset base and
pays a high portion of its cash flow to service such debt (see "Capital
Resources"). Furthermore, as the Company does not have a revolving credit
facility, the Company does not have ready access to incremental sources of
capital to supplement its operational requirements. The Company believes that it
has the ability for the foreseeable future based on its current condition,
including economic conditions, to meet all obligations as they come due and fund
its current capital expenditure program from cash on hand and operational cash
flows. However, because of the combination of the factors described herein (see
"Risk Factors"; "Liquidity"; and "Capital Resources") and the uncertainty of
drilling successes required to sustain or increase operational cash flows, there
can be no assurance that the Company will be able to fund future obligations.
Liquidity. Net cash used in operating activities, before working capital
adjustments, during 1999 aggregated $(0.1) million. Funds provided by investing
activities were comprised of proceeds from the sale of north Louisiana
properties to Phillips of $83.2 million and a $6.9 million purchase price
adjustment related to a 1997 acquisition of oil and gas properties partially
offset by capital expenditures of $15.2 million and restricted cash of $7.5
million. Funds used in financing activities were comprised of net credit
facility principal payments of $111.5 million, redemption of a portion of the
Notes for $36.5 million and redemption of subordinated and senior notes of $34.9
million, partially offset by proceeds of $125.9 from the sale of the Notes. Cash
equivalents increased from $8.4 million at December 31, 1998 to $10.4 million as
of December 31, 1999. As of December 31, 1999, the Company had a working capital
deficit of $3.9 million, compared to a working capital deficit of $37.4 million
at the end of 1998.
Capital Resources. After the Company paid all amounts outstanding under the
Credit Facility, the Credit Facility was terminated and the Company is not
likely to have access to a revolving credit facility to supplement its cash
needs. The Company's typical monthly cash flow cycle is such that the Company
usually receives a substantial portion of its proceeds from operations near the
end of each month.
23
<PAGE> 25
The terms of the Notes and subordinated obligations significantly limit the
ability of the Company to incur additional funded indebtedness. Accordingly, the
Company anticipates that it will be required to meet its obligations during the
remainder of 2000 from the net proceeds of the transactions described above,
cash on hand and cash flows from operations. The Company anticipates that it
will be able to meet its obligations in 2000, including principal and interest
payments of $24.2 million (includes the impact of the first quarter 2000
retirement of $0.3 million of the Company's Securities) due in April 2000.
Non-payment of such obligations would be a default under the Company's
indentures. If that were to occur, the Company may be required to refinance or
restructure all or a portion of its indebtedness, to sell assets, or become
subject to various other creditor rights under the indentures.
The following table sets forth on an unaudited basis net cash provided by
operating activities before working capital adjustments, net cash used in
investing activities and EBITDAX.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1997 1998 1999
--------- -------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Net cash provided by (used in) operating activities before
working capital adjustments............................... $ 37,534 $ 24,603 $ (101)
Net cash provided by (used in) investing activities......... (164,275) (39,216) 67,338
EBITDAX(1).................................................. 58,308 52,700 33,675
</TABLE>
- ---------------
(1) EBITDAX is calculated as net income (loss) before extraordinary items,
excluding interest expense and other debt expenses, income taxes,
exploration expenses, depletion, depreciation, amortization, gain on sale of
oil and gas properties, impairment of oil and gas properties and other
non-cash charges of $0.6 million in 1999. EBITDAX is not a measure of cash
flow as determined by generally accepted accounting principles ("GAAP"). The
Company has included information concerning EBITDAX because EBITDAX is a
measure used by certain investors in determining a company's historical
ability to service its indebtedness. EBITDAX should not be considered as an
alternative to, or more meaningful than, net income or cash flow as
determined in accordance with GAAP as an indicator of the Company's
operating performance or liquidity. EBITDAX is not necessarily comparable to
a similarly titled measure of another company.
Capital Commitments. The Company's 2000 capital expenditure budget provides
for $15.0 million to be expended on development drilling and exploratory
activities primarily in south Louisiana and the shallow waters of the Gulf of
Mexico. However, the Company's ability to fund its 2000 capital expenditure
budget will depend on the actual amount of cash flow from operations and
proceeds from oil and gas property sales.
During 1999, the Company participated in drilling 14 gross (3.71 net)
wells, of which 11 gross (2.74 net) wells have been completed. The Company, with
its partners, continues exploration activities in south Louisiana and in the
Gulf of Mexico. As of December 31, 1999, the Company was participating in the
drilling of 1 gross (.50 net) well which was subsequently completed as a
producing well.
Year 2000. Year 2000 issues involved the potential disruption to systems,
processes, and business practices that may have occurred if system hardware and
software utilized by the Company, its vendors, and customers were unable to
process year 2000 data. The Company has not incurred any business disruptions
due to Year 2000 issues.
The foregoing statements are intended to be and are hereby designated "Year
2000 Readiness Disclosures" within the meaning of the Year 2000 Information and
Readiness Act.
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<PAGE> 26
Inflation and Changing Prices. Oil and natural gas prices, as with most
commodities, are highly volatile, have fluctuated during recent years and
generally have not followed the same pattern as inflation. The following table
shows the changes in the average oil and natural gas prices (including the
effects of hedging) received by the Company during the periods indicated.
<TABLE>
<CAPTION>
AVERAGE AVERAGE
OIL PRICE GAS PRICE
($/BBL) ($/MCF)
--------- ---------
<S> <C> <C>
YEAR ENDED:
December 31, 1999......................................... $16.77 $2.12
December 31, 1998......................................... 13.09 2.09
December 31, 1997......................................... 19.34 2.27
</TABLE>
Accounting Pronouncements. In June 1998, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities" ("SFAS 133") which was
amended in June 1999 by SFAS No. 137, "Accounting for Derivative Instruments and
Hedging Activities -- Deferral of the Effective Date of FASB Statement No.
133 -- an amendment of FASB Statement No. 133." SFAS No. 133, as amended, is
effective for fiscal years beginning after June 15, 2000, and establishes
accounting and reporting standards for derivative instruments and hedging
activities that require an entity to recognize all derivatives as an asset or
liability measured at its fair value. Depending on the intended use of the
derivative, changes in its fair value will be reported in the period of change
as either a component of earnings or a component of other comprehensive income.
Retroactive application to periods prior to adoption is not allowed. The Company
has not quantified the impact of adoption on its financial statements.
25
<PAGE> 27
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company is exposed to market risk from changes in commodity prices. The
Company uses its Senior and Subordinated debt instruments to finance a
significant portion of its operations. Prior to May 17, 1999, the Company had
market risk exposure for interest rate changes related to its Credit Facility
variable rate debt (see Note 1 in Notes to Consolidated Financial Statements).
In the normal course of business the Company enters into hedging transactions,
including natural gas and crude oil price swap agreements and natural gas basis
swap agreements, to mitigate its exposure to commodity price movements, but not
for trading or speculative purposes. In 1999, the Company used price and basis
swap agreements to reduce exposure to downward price fluctuations for its
natural gas and crude oil production. For debt obligations the table below
presents principal cash flows and weighted average interest rates by year of
maturity. For natural gas price and basis swap agreements and crude oil price
swap agreements, the table presents notional amounts in Mmbtus and bbls at
weighted average prices for contracts in place at December 31, 1999. The
information presented below should be read in conjunction with Note 4 and Note
10 to the Consolidated Financial Statements (amounts in thousands unless
otherwise indicated).
<TABLE>
<CAPTION>
MATURITY DATE
---------------------------------------------------- FAIR VALUE
2000 2001 2002 2003 2004 THEREAFTER TOTAL @ 12/31/99
---------- -------- ------ -------- -------- ---------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Fixed Debt:
14.00% (Maturity)(1)............. $4,120 $100,720 $104,840 $102,743
8.50% (Maturity)................. $ 8,696 8,696 8,696
10.38% (Maturity)................ $155,000 155,000 69,750
---------- ------ -------- -------- -------- --------
Total Maturity..................... $ 8,696 $4,120 $100,720 $155,000 $268,536 $181,189
========== ====== ======== ======== ======== ========
Blended weighted average interest
rate............................. 8.50% 14.00% 14.00% 10.38%
Commodity price derivatives:
Price swaps:
Notional amounts (Mmbtus)........ 1,550,000
Weighted average price........... $ 2.41
Fair value at 12/31/99(2)........ $ 106
(bbls)........................... 30,000
Weighted average price........... $ 25.05
Fair value at 12/31/99(2)........ $ (83)
</TABLE>
- ---------------
(1) The 14% notes mature in 2002 and 2003 at premiums ranging from 103% to 105%
of the stated principal amount.
(2) Represents estimated amounts to settle the contracts at December 31, 1999.
26
<PAGE> 28
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
CONTOUR ENERGY CO. AND SUBSIDIARIES:
Independent Auditors' Report.............................. 28
Consolidated Balance Sheets -- December 31, 1998 and
1999................................................... 29
Consolidated Statements of Income (Loss) -- For the years
ended December 31, 1997, 1998 and 1999................. 30
Consolidated Statements of Cash Flows -- For the years
ended December 31, 1997, 1998 and 1999................. 31
Consolidated Statements of Changes in Stockholders'
Deficit -- For the years ended December 31, 1997, 1998
and 1999............................................... 32
Notes to Consolidated Financial Statements................ 33
</TABLE>
27
<PAGE> 29
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of Contour Energy Co.:
We have audited the accompanying consolidated balance sheets of Contour
Energy Co. and subsidiaries (the "Company") as of December 31, 1998 and 1999,
and the related consolidated statements of income (loss), cash flows, and
changes in stockholders' deficit for each of the three years in the period ended
December 31, 1999. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the 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 audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company as of December 31,
1998 and 1999, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 1999 in conformity with
generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Houston, Texas
March 23, 2000
28
<PAGE> 30
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------
1998 1999
--------- ---------
<S> <C> <C>
ASSETS:
Cash and cash equivalents................................. $ 8,435 $ 10,370
Accounts receivable....................................... 18,071 18,389
Accounts receivable -- drilling programs.................. 624 199
Prepaid expenses and other current assets................. 1,121 1,042
--------- ---------
Total current assets.............................. 28,251 30,000
--------- ---------
Oil and gas properties, successful efforts method:
Unproved properties, net............................... 38,293 22,260
Properties subject to amortization..................... 496,686 428,116
Pipelines and other transportation assets, at cost........ 1,582 1,582
Furniture, fixtures and equipment......................... 3,554 3,596
--------- ---------
540,115 455,554
Less: Accumulated depreciation, depletion and
amortization........................................... (283,660) (289,798)
--------- ---------
Total property and equipment, net...................... 256,455 165,756
Restricted cash........................................... -- 7,500
Other non-current assets, net............................. 1,491 526
--------- ---------
Total assets...................................... $ 286,197 $ 203,782
========= =========
LIABILITIES:
Accounts payable and accrued expenses..................... $ 33,113 $ 25,207
Accounts payable -- drilling programs..................... 272 115
Current portion of long-term debt......................... 32,251 8,598
--------- ---------
Total current liabilities......................... 65,636 33,920
--------- ---------
Long term debt............................................ 287,500 246,165
--------- ---------
Total liabilities................................. 353,136 280,085
--------- ---------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' DEFICIT:
Preferred stock, $1.50 par value, 2,000,000 shares
authorized at December 31, 1998 and 1999; 1,733,628 and
1,363,319 shares issued and outstanding at December 31,
1998 and 1999, respectively (liquidation value $48,977
and $41,824, respectively)............................. 2,600 2,045
Common stock, $.10 par value, 20,000,000 shares authorized
at December 31, 1998 and 1999; 12,602,224 and
13,212,005 shares issued and outstanding at December
31, 1998 and 1999, respectively........................ 1,260 1,321
Additional paid-in capital................................ 300,653 301,516
Accumulated deficit....................................... (371,452) (381,185)
--------- ---------
Total stockholders' deficit....................... (66,939) (76,303)
--------- ---------
Total liabilities and stockholders' deficit....... $ 286,197 $ 203,782
========= =========
</TABLE>
See Notes to Consolidated Financial Statements.
29
<PAGE> 31
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1997 1998 1999
------- -------- --------
<S> <C> <C> <C>
REVENUES:
Oil and gas revenues...................................... $75,864 $ 79,150 $ 54,107
Interest and other income................................. 274 505 1,974
Gain on sale of properties................................ -- -- 25,863
------- -------- --------
Total revenues............................................ 76,138 79,655 81,944
------- -------- --------
COSTS AND EXPENSES:
Production expenses....................................... 10,955 19,878 15,541
Exploration expenses...................................... 5,433 12,034 5,736
General and administrative expenses....................... 6,875 7,077 7,463
Interest and other debt expenses.......................... 25,071 33,333 38,002
Depreciation, depletion and amortization.................. 25,853 38,602 35,986
Impairment of oil and gas properties...................... -- 25,738 --
------- -------- --------
Total expenses............................................ 74,187 136,662 102,728
------- -------- --------
Income (loss) before income taxes and extraordinary item.... 1,951 (57,007) (20,784)
Income taxes.............................................. -- -- --
------- -------- --------
Net income (loss) before extraordinary item................. 1,951 (57,007) (20,784)
Extraordinary item........................................ -- -- 11,051
------- -------- --------
Net income (loss)........................................... 1,951 (57,007) (9,733)
Less: cumulative preferred stock dividends................ (4,582) (4,550) (4,207)
------- -------- --------
Net loss applicable to common stock......................... $(2,631) $(61,557) $(13,940)
======= ======== ========
Basic and diluted loss per common share before extraordinary
item...................................................... $ (.26) $ (4.89) $ (1.94)
======= ======== ========
Basic and diluted loss per common share..................... $ (.26) $ (4.89) $ (1.08)
======= ======== ========
Weighted average common shares outstanding.................. 10,076 12,578 12,871
======= ======== ========
</TABLE>
See Notes to Consolidated Financial Statements.
30
<PAGE> 32
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1997 1998 1999
--------- -------- ---------
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss)........................................ $ 1,951 $(57,007) $ (9,733)
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization.............. 25,853 38,602 35,986
Impairment of oil and gas properties.................. -- 25,738 --
Gain on sale of properties............................ -- -- (25,863)
Exploration expenses.................................. 5,433 12,034 5,736
Accretion and amortization of other debt expenses..... 4,297 5,236 4,824
Extraordinary gain.................................... -- -- (11,051)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable and other
current assets...................................... (1,297) 6,880 186
Increase in other non-current assets.................. (1,203) (526) (493)
Increase (decrease) in accounts payable and accrued
expenses............................................ 4,570 (8,655) (8,063)
--------- -------- ---------
Net cash provided by (used in) operating activities...... 39,604 22,302 (8,471)
--------- -------- ---------
INVESTING ACTIVITIES:
Capital expenditures..................................... (53,140) (56,579) (15,204)
Proceeds from sale of oil and gas properties............. -- 17,363 83,153
Restricted cash investment............................... -- -- (7,500)
Acquisition of oil and gas properties.................... (111,135) -- --
Acquisition purchase price adjustment.................... -- 6,889
--------- -------- ---------
Net cash (used in) provided by investing activities...... (164,275) (39,216) 67,338
--------- -------- ---------
FINANCING ACTIVITIES:
Proceeds from long term borrowings....................... 180,500 119,100 4,000
Principal payments on long term borrowings............... (82,700) (118,900) (115,500)
Proceeds from sale of notes, net......................... -- 29,526 125,938
Proceeds from sale of common stock, net.................. 27,545 273 --
Proceeds from conversion of preferred stock.............. -- (2) --
Retirement of notes...................................... -- (228) (71,370)
Dividends on preferred stock............................. (4,582) (4,582) --
--------- -------- ---------
Net cash provided by (used in) financing activities...... 120,763 25,187 (56,932)
--------- -------- ---------
(Decrease) increase in cash and cash equivalents........... (3,908) 8,273 1,935
Cash and cash equivalents, beginning of period............. 4,070 162 8,435
--------- -------- ---------
Cash and cash equivalents, end of period................... $ 162 $ 8,435 $ 10,370
========= ======== =========
</TABLE>
See Notes to Consolidated Financial Statements.
31
<PAGE> 33
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' DEFICIT
(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
ADDITIONAL
PREFERRED COMMON PAID IN ACCUMULATED
STOCK STOCK CAPITAL DEFICIT
--------- ------ ---------- -----------
<S> <C> <C> <C> <C>
Stockholders' deficit at January 1, 1997............ $2,618 $ 983 $273,096 $(307,232)
Issuance of 27,000 shares of common stock in Contour
Transaction....................................... -- 270 26,730 --
Issuance of 415 shares of common stock pursuant to
employee incentive stock options.................. -- 4 541 --
Preferred stock dividends........................... -- -- -- (4,582)
Net income.......................................... -- -- -- 1,951
------ ------ -------- ---------
BALANCE AT DECEMBER 31, 1997...................... 2,618 1,257 300,367 (309,863)
------ ------ -------- ---------
Conversion of 11,815 shares of preferred stock into
40,976 shares of common stock..................... (18) 1 17 --
Issuance of 272,166 shares of common stock pursuant
to employee incentive stock options............... -- 2 269 --
Preferred stock dividends........................... -- -- -- (4,582)
Net loss............................................ -- -- -- (57,007)
------ ------ -------- ---------
BALANCE AT DECEMBER 31, 1998...................... 2,600 1,260 300,653 (371,452)
------ ------ -------- ---------
Conversion of 1,676 shares of preferred stock into
582 shares of common stock........................ (2) -- 2 --
Issuance of 56,250 shares of common stock pursuant
to employee incentive stock options............... -- 6 (6) --
Conversion of 368,633 shares of preferred stock into
552,950 shares of common stock pursuant to tender
offer............................................. (553) 55 498 --
Issuance of restricted stock........................ -- -- 369 --
Net loss............................................ -- -- -- (9,733)
------ ------ -------- ---------
BALANCE AT DECEMBER 31, 1999...................... $2,045 $1,321 $301,516 $(381,185)
====== ====== ======== =========
</TABLE>
See Notes to Consolidated Financial Statements.
32
<PAGE> 34
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- INDUSTRY CONDITIONS AND LIQUIDITY
In 1999, Contour Energy Co. (formerly Kelley Oil & Gas Corporation) ("the
Company") undertook several strategic actions in response to the severe downturn
in the industry in 1998 caused by low commodity prices and the closing of the
capital markets to smaller oil and gas companies. These actions, described
below, were designed to increase the near-term liquidity of the Company, provide
capital for its ongoing capital expenditure programs and establish a stronger
base for future growth.
In April 1999, the Company entered into an Exploration and Development
Agreement with Phillips Petroleum Company ("Phillips") relating to certain of
the Company's interests in the Bryceland, West Bryceland and Sailes fields in
north Louisiana ("Phillips Transaction"). Pursuant to the agreement, the Company
(1) received an $83 million cash payment (2) retained a 42 Bcf, 8-year
volumetric overriding royalty interest (the "VORI") and a 1% override on the
excess of production above such royalty interest and (3) retained 25% of its
working interest in the Cotton Valley formation. In addition, Phillips, will at
its risk and expense, operate, develop, exploit and explore the properties
thereby relieving the Company of significant operating, exploration and
development costs in the future. The transaction closed on May 17, 1999. The
Company recognized a gain of approximately $25.9 million in 1999 related to this
transaction.
In April 1999, the Company negotiated a private offering of $135 million
principal amount, 14% Senior Secured Notes (the "Notes"). The Notes are secured
by a first lien on substantially all of the Company's proved oil and natural gas
properties remaining after the sale to Phillips and guaranteed by three entities
wholly-owned by the Company. In accordance with the Notes indenture, on June 30,
1999, the Company funded $37.5 million to repurchase $35 million principal
amount of the Notes at a repurchase price equal to 104% of the principal amount,
plus accrued and unpaid interest and commitment fees to the date of the
repurchase.
On May 17, 1999, the Company funded $28.5 million to repurchase $46.1
million of the outstanding principal amounts of its 7 7/8% Convertible
Subordinated Notes due December 15, 1999 and its 8 1/2% Convertible Subordinated
Debentures due April 1, 2000 (collectively, the "Securities") at a price equal
to $590 per $1,000 principal amount (not including accrued interest paid of $1.2
million).
In addition, on May 17, 1999 the Company repaid all borrowings outstanding
under its revolving credit facility of $115.5 million plus accrued interest and
terminated the revolving credit facility and funded cash collateral for a $1.5
million letter of credit which was subsequently increased to $7.5 million. The
Company used net proceeds remaining from the transactions for general corporate
purposes. In 1999, the Company recognized an extraordinary gain of $11.1 million
related to debt repurchases and refinancings, comprised of: (i) a net gain on
the Securities tender offer and other debt retirements of $16.0 million, reduced
by, (ii) a $1.4 million premium on the $35 million Notes repurchase and the
proportionate write-off of debt issue costs of $2.4 million and (iii) the
write-off of credit facility debt issue costs of $1.1 million.
The remaining outstanding amounts of the Company's 8 1/2% Convertible
Subordinated Debentures of $8.4 million (including the effect of $0.3 million of
retirements in the first quarter of 2000) are due on April 1, 2000. In addition,
the Company has interest payments due in April and October, 2000 of $15.7
million and $15.4 million, respectively. In March 2000, the Company sold a
portion of the VORI (the "VORI Sale"). The net proceeds from the sale
approximated $20 million. Since the portion of the VORI sold (approximately
16.5 Bcf) represents production commencing April 1, 2003, the VORI Sale will not
impact the Company's operating cash flows until 2003.
The Company has received the benefits of a general increase in the level of
commodity prices over the past several months. The Company believes that this
increase, combined with the cash on hand subsequent to the sale of a portion of
the VORI will sustain its operations over the near term. However, the commodity
markets are volatile and there is no certainty that current oil and natural gas
prices can be sustained at these levels. In addition, the Company continues to
have significant
33
<PAGE> 35
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
debt outstanding relative to its asset base and pays a high portion of its
cash flow to service such debt. Furthermore, the Company does not have ready
access to incremental sources of capital to supplement its operational
requirements. The combination of the factors described herein and industry
conditions beyond its control, may adversely offset the Company's financial
condition, results of operations and cash flows.
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Operations. Contour Energy Co. (formerly Kelley Oil & Gas
Corporation), a Delaware Corporation, its corporate subsidiaries and
proportionate partnership interests are referred to herein as the "Company". The
Company is an independent oil & gas company engaged in the exploration,
development and acquisition of domestic oil and gas properties, principally in
the Gulf Coast region and northern Louisiana.
Principles of Consolidation. The consolidated financial statements include
the accounts of (i) the Company, (ii) its corporate subsidiaries, all of which
are wholly-owned, and (iii) the Company's indirect 100% owned partnership,
Kelley Operating Company, Ltd., and (iv) its proportionate interest in
development drilling programs sponsored by Kelley Oil Corporation to conduct
drilling operations on properties of Kelley Operating Company, Ltd. ("1992 DDP"
and "1994 DDP"). All significant intercompany accounts and transactions have
been eliminated in consolidation.
Cash and Cash Equivalents. The Company considers all highly liquid
investments with an original maturity of three months or less when purchased to
be cash equivalents. Cash payments attributable to interest on all indebtedness
aggregated $19.6 million, $26.5 million and $34.1 million for the years ended
December 31, 1997, 1998 and 1999, respectively.
Financial Instruments. The Company's financial instruments consist of cash
and cash equivalents, receivables, payables, long term debt and commodity
derivatives (see Note 10). As of December 31, 1999, the estimated fair value of
the Company's long-term debt was $181.2 million. The fair value of such
long-term debt has been based on estimated market prices indicative of potential
transactions between a "willing buyer" and a "willing seller". The carrying
amount of the Company's other financial instruments approximates fair value.
Oil and Gas Properties. All of the Company's interests in its oil and gas
properties are located in the United States and are accounted for using the
successful efforts method. Under the successful efforts method, the costs of
successful wells, development dry holes and leases containing productive
reserves are capitalized and amortized on a unit-of-production basis over the
life of the related reserves. Estimated future abandonment and site restoration
costs, net of anticipated salvage values, are amortized on a unit-of-production
basis over the life of the related reserves. Exploratory drilling costs are
initially capitalized pending determination of proved reserves but are charged
to expense if no proved reserves are found. Other exploration costs, including
geological and geophysical expenses, leasehold expiration costs and delay
rentals, are expensed as incurred.
Unproved leasehold costs are capitalized and are not amortized pending an
evaluation of the exploration results. If unproved properties are determined to
be productive, the related costs are transferred to proved oil and gas
properties. If unproved properties are determined not to be productive, or if
such properties have been otherwise impaired, the excess carrying value is
charged to expense. Unproved properties are assessed quarterly for impairment in
value, with any impairment charged to expense. The Company recognized non-cash
impairment charges of $4.1 million related to unproved properties for the year
ended December 31, 1998.
The Company's proved oil and gas properties are reviewed for indications of
impairment whenever events or circumstances indicate that the carrying value of
its oil and gas properties may not be recoverable. As a levels. In addition, the
Company continues to have significant result of a decline in its proved reserves
at January 1, 1999 from year-earlier levels, the Company performed an assessment
of the fair value of its oil and gas properties indicating an impairment should
be recognized as of year end. Under this analysis, the fair value for the
Company's proved oil and gas properties was estimated using escalated pricing
and present value discount factors reflecting risk assessments. Based on this
analysis, the Company recognized noncash impairment charges against the carrying
values of its proved oil and gas properties aggregating $21.6 million for the
year ended December 31, 1998.
34
<PAGE> 36
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Other Property and Equipment. The costs of pipelines and other
transportation assets are depreciated using the straight-line method over the
estimated useful lives of the related assets. Furniture, fixtures and equipment
are recorded at cost and depreciated using the straight-line method over the
estimated useful lives of three to five years. Maintenance and repairs are
charged to expense as incurred.
Other Non-Current Assets. Other non-current assets consist primarily of
debt issue costs, net of accumulated amortization. These costs are amortized
over the anticipated term of the related debt.
Income Taxes. Deferred income taxes are provided on a liability method
whereby deferred tax assets and liabilities are established for the difference
between the financial reporting and income tax basis of assets and liabilities
as well as operating loss and tax credit carryforwards. Deferred tax assets are
reduced by a valuation allowance when, in the opinion of management, it is more
likely than not that some portion or all of the deferred tax assets will not be
realized. Deferred tax assets and liabilities are adjusted for the effects of
changes in tax laws and rates on the date of enactment.
Oil and Gas Revenues. The Company recognizes oil and gas revenue from its
interests in producing wells as oil and gas is produced and sold from those
wells. Oil and gas sold is not significantly different from the Company's
production entitlement. Revenues from gas marketing, net of cost of gas sold,
are included in oil and gas revenues and amounted to $2.8 million, $1.3 million
and $1.4 million for the years ended December 31, 1997, 1998 and 1999,
respectively.
Earnings per Share. The basic loss per common share before extraordinary
item and the basic loss per common share as shown on the Consolidated Statements
of Income (Loss) reflects net income (loss) before extraordinary item and net
income (loss), respectively, cumulative preferred stock dividends, whether or
not declared, less the excess of the fair value of the Company's preferred stock
exchange offer (see Note 5) over the fair value of the original terms ($1.6
million at July 28, 1999), divided by the weighted average number of common
shares outstanding during the respective years. The extraordinary gain per
common share for the year ended December 31, 1999 was $.86. In calculating
diluted income (loss) per share, common shares issuable under stock options and
upon conversion of convertible subordinated debentures and convertible preferred
stock are added to the weighted average common shares outstanding when dilutive.
For the years ended December 31, 1997, 1998 and 1999, all potentially dilutive
securities are anti-dilutive and therefore are not included in the EPS
calculations. Potentially dilutive securities which could impact EPS in the
future include stock options granted to employees to purchase 0.4 million common
shares, the Company's 8 1/2% Convertible Subordinated Debentures which can be
converted into 45 thousand common shares and the Company's $2.625 Convertible
Preferred Stock ("Preferred Stock") which can be can be converted into 0.5
million common shares.
Stock Based Compensation. The Company applies Accounting Principles Board
Opinion No. 25 ("APB 25") and related Interpretations in accounting for stock
option and purchase plans. Under APB 25, compensation expense, if any, is based
on the intrinsic value of the equity instrument at the measurement date. The
Company has not recognized any compensation expense because the exercise price
of employee stock options equals the market price of the underlying stock on the
date of the grant.
Derivatives and Hedging Activities. See Note 10 for a discussion of the
Company's accounting policies related to hedging activities. In June 1998, the
Financial Accounting Standards Board issued Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS 133") which was amended in June 1999 by SFAS No. 137,
"Accounting for Derivative Instruments and Hedging Activities -- Deferral of the
Effective Date of FASB Statement No. 133 -- an amendment of FASB Statement No.
133." SFAS No. 133, as amended, is effective for fiscal years beginning after
June 15, 2000, and establishes accounting and reporting standards for derivative
instruments and hedging activities that require an entity to recognize all
derivatives as an asset or liability measured at its fair value. Depending on
the intended use of the derivative, changes in its fair value will be reported
in the period of change as either a component of earnings or a component of
other comprehensive income. Retroactive application to periods prior to adoption
is not allowed. The Company has not quantified the impact of adoption on its
financial statements.
35
<PAGE> 37
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Comprehensive Income. In June 1997, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standards No. 130, "Reporting
Comprehensive Income" ("SFAS 130"). SFAS 130 establishes standards for reporting
and displaying comprehensive income and its components. SFAS 130 is effective
for periods beginning after December 15, 1997. The purpose of reporting
comprehensive income is to report a measure of all changes in equity of an
enterprise that results from recognized transactions and other economic events
of the period other than transactions with owners in their capacity as owners.
As of December 31, 1999, there are no adjustments ("Other Comprehensive Income")
to net income in deriving comprehensive income.
Risks and Uncertainties. The preparation of financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Changes in Presentation. Certain financial statement items in 1997 and 1998
have been reclassified to conform to the 1999 presentation.
NOTE 3 -- ACQUISITION OF OIL AND GAS PROPERTIES
SPR Acquisition. On December 1, 1997, the Company purchased from SCANA
Petroleum Resources, Inc. ("SPR") substantially all of SPR's assets, including
its oil and gas properties, exploratory leasehold interests and associated
obligations, in exchange for approximately $110 million ("SPR Acquisition"),
subject to adjustment as provided by the Purchase and Sale Agreement between the
Company and SPR. The acquisition was accounted for using the purchase method of
accounting, and accordingly, the purchase price has been preliminarily allocated
to the assets acquired based on estimated fair values at the date of
acquisition. The operating results of the assets acquired from SPR have been
included in Contour's Statements of Income (Loss) since December 1, 1997. The
pro forma information shown below assumes that the acquisition occurred at the
beginning of 1997. Adjustments have been made to reflect changes in the
Company's results from the revenues and direct operating expenses of the
producing properties acquired from SPR, additional interest expense to finance
the acquisition, depreciation, depletion and amortization based on assigned fair
values to the assets acquired and general and administrative expenses incurred
from hiring additional employees. The unaudited pro forma financial data are not
necessarily indicative of financial results that would have occurred had the SPR
Acquisition occurred January 1, 1997, and should not be viewed as indicative of
operations in future periods.
<TABLE>
<CAPTION>
(UNAUDITED)
-----------------------
YEAR ENDED DECEMBER 31,
1997
-----------------------
(IN THOUSANDS,
EXCEPT PER SHARE DATA)
<S> <C>
Revenues.................................................... $112,142
Income (loss) before extraordinary item..................... 1,315
Net income (loss)........................................... 1,315
Loss per common share....................................... (0.30)
</TABLE>
36
<PAGE> 38
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 4 -- LONG TERM DEBT
Long Term Debt. The Company's long term debt at December 31, 1998 and 1999
is comprised of the following:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
1998 1999
-------- --------
(IN THOUSANDS)
<S> <C> <C>
14% Senior Secured Notes.................................... $ 0 $ 94,930
Bank credit facilities...................................... 111,500 0
13 1/2% Senior Notes........................................ 435 0
10 3/8% Senior Subordinated Notes........................... 150,662 151,235
7 7/8% Convertible Subordinated Notes....................... 31,816 0
8 1/2% Convertible Subordinated Debentures.................. 25,338 8,598
-------- --------
319,751 254,763
Less current maturities..................................... (32,251) (8,598)
-------- --------
$287,500 $246,165
======== ========
</TABLE>
14% Senior Secured Notes. In April 1999, the Company negotiated a private
offering of $135 million principal amount, 14% Senior Secured Notes (the
"Notes"). The Notes are secured by a first lien on substantially all of the
Company's proved oil and natural gas properties remaining after the Phillips
Transaction and guaranteed by three entities wholly-owned by the Company. In
accordance with the Notes indenture, on June 30, 1999, the Company funded $37.5
million to repurchase $35 million principal amount of the Notes at a repurchase
price equal to 104% of the principal amount, plus accrued and unpaid interest
and commitment fees to the date of the repurchase.
In September 1999, the Company completed an exchange of publicly registered
14% Senior Secured Notes, Series B for all of the then outstanding Series A
notes. The Series B notes are substantially identical to the Series A notes. The
Notes mature in 2002 and 2003 at premiums ranging from 103% to 105% of their
stated principal amount. The Notes are redeemable at the Company's option on or
after April 15, 2001 at 105% of the stated principal amount. Beginning July 15,
2002, and thereafter on a quarterly basis, the Company will be obligated to
redeem $2.0 million of the stated principal amount of the Notes at a redemption
price equal to 103% of the stated principal amount. The Company will be
obligated to offer to repurchase a portion of the Notes at a repurchase price
equal to 104% of the stated principal amount if the Company's oil and gas
revenues, as determined by independent petroleum engineers on a quarterly basis,
fall below defined levels. In the event of certain other asset sales, the
Company will be obligated to repurchase a portion of the Notes at a repurchase
price equal to 105% of the stated principal amount. Upon a change of control, as
defined, the Company is obligated to offer to repurchase each holder's Notes at
a repurchase price equal to 101% of the stated principal amount. The indenture
for the notes contains conditions and limitations, including but not limited to,
restrictions on (1) payments of cash dividends, (2) redemptions of capital stock
for cash, (3) repayments of subordinated indebtedness with cash and (4) making
investments, including capital expenditures.
Interest expense on the Notes is payable semi-annually on each April 15 and
October 15. The Company is recognizing interest expense using an effective rate
of 15.3%.
10 3/8% Senior Subordinated Notes. In connection with the refinancing of
the 13 1/2% Senior Notes, the Company issued an aggregate principal amount of
$125.0 million of 10 3/8% Senior Subordinated Notes due 2006 (the "10 3/8%
Senior Subordinated Notes"). The 10 3/8% Senior Subordinated Notes are
redeemable at the option of the Company, in whole or in part, at redemption
prices declining from 105.19% in 2001 to 100% in 2003 and thereafter. The
10 3/8% Senior Subordinated Notes represent unsecured obligations of the Company
and are subordinate in right of payment to all existing and future senior
indebtedness. The indenture for the notes contains conditions and limitations,
including but not limited to restrictions on additional indebtedness, payment of
dividends, redemption of capital stock, and certain mergers and consolidations.
The holder of the 10 3/8% Senior Subordinated Notes also can require the Company
to repurchase the notes at 101% of the principal amount upon a Change of
Control, as defined. Kelley Oil Corporation, a wholly-owned subsidiary
37
<PAGE> 39
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
of the Company and Kelley Operating Company, Ltd., an indirect wholly-owned
partnership of the Company are guarantors of the 10 3/8% Senior Subordinated
Notes.
On February 3, 1997, the Company completed an exchange of $125.0 million
aggregate principal amount of publicly registered 10 3/8% Senior Subordinated
Notes, Series B, for all of the then outstanding Series A notes. The Series B
notes were substantially identical to the Series A notes.
In May 1998, the Company sold $30.0 million principal amount of the
Company's 10 3/8% Senior Subordinated Notes due 2006, Series C ("Series C
Notes") at a cash price of $1,015 per $1,000 principal amount. The net proceeds
received were used to reduce outstanding borrowings under the Company's bank
credit facility. The Series C Notes are redeemable at the option of the Company,
in whole or in part, at redemption prices declining ratably from 105.19% on
October 15, 2001 to 100% at October 15, 2003 and thereafter. The Company may
redeem up to 35% of the original principal amount of the Series C Notes before
October 15, 1999 at 110.38% with the proceeds of an equity offering (provided
that either at least $18.0 million aggregate principal amount of such notes
remains outstanding or such redemption retires such notes in their entirety).
The Series C Notes represent unsecured obligations of the Company and are
subordinate in right of payment to all existing and future senior indebtedness.
The indenture for the notes contains conditions and limitations, including but
not limited to restrictions on additional indebtedness, payment of dividends,
redemption of capital stock, and certain mergers and consolidations. The holders
of the Series C Notes also can require the Company to repurchase the notes at
101% of the principal amount upon a Change of Control, as defined. Kelley Oil
Corporation, a wholly owned subsidiary of the Company, and Kelley Operating
Company, Ltd., an indirect wholly owned partnership of the Company, are
guarantors of the Series C Notes.
The Series C Notes were sold pursuant to Rule 144A of the Securities Act of
1933. In issuing the Series C Notes, the Company agreed to use its best efforts
to register under the Securities Act notes identical in terms to the Series C
Notes ("Series D Notes"). The Company completed the exchange of the Series C
Notes for the Series D Notes on November 12, 1998.
7 7/8% Convertible Subordinated Notes and 8 1/2% Convertible Subordinated
Debentures. In December 1999, the Company paid off the remaining principal of
$3.5 million and interest of $0.1 million on its outstanding 7 7/8% Convertible
Subordinated Notes. At December 31, 1999, the Company had outstanding 8 1/2%
Convertible Subordinated Debentures due April 1, 2000 (the "8 1/2% Subordinated
Debentures") in the aggregate principal amount of $8.6 million (the
"Subordinated Debt"). Each $1,000 face value amount of the 8 1/2% Subordinated
Debentures is convertible into 5.1864 shares of the Company's Common Stock or
2.5932 shares of the Company's Common Stock and 5.411 shares of Preferred Stock.
In the fourth quarter of 1999, the Company retired $1.0 million face amount of
its 8 1/2% Subordinated Debentures. The settlement payments included principal
amounts of $0.9 million and accrued interest of $10,000 and the fourth quarter
of 1999 includes an extraordinary gain of $0.1 million for these transactions.
In the first quarter of 2000, the Company retired $0.3 million face amount of
its 8 1/2% Subordinated Debentures. The settlement payments included principal
amounts of $0.2 million and accrued interest of $7,000.
Debt Maturities. The Company has aggregate debt maturities of $8.7 million
in 2000, $4.1 million in 2002, $100.7 million in 2003 and $155.0 million in
2006.
NOTE 5 -- STOCKHOLDERS' DEFICIT
On June 28, 1999, the Company announced that its board of directors
approved changing the Company's name to Contour Energy Co. and its NASDAQ ticker
symbol to CONCC. Concurrent with the name change, the Company established the
authorized capital stock of the Company at 22 million shares, 20 million of
which were designated as common stock and 2 million as preferred stock, and
effected a 1 for 10 reverse stock split, reducing the total outstanding shares
of common stock from approximately 126 million to approximately 12.6 million
(without giving effect to the preferred stock exchange offer described in the
following paragraph). These actions were consented to by the Company's majority
stockholder and became effective on July 30, 1999. All historical share and per
share data appearing in this document have been restated to reflect this reverse
stock split.
38
<PAGE> 40
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
On August 30, 1999, at market close, the Company's shares of common stock
and convertible Preferred Stock, which traded under the symbols of CONCC and
CONCP, were delisted from the Nasdaq SmallCap Market. These actions were taken
as a result of the Company's failure to meet the requirements for continued
listing on this exchange. On August 31, 1999, at market open, the Company's
stock began trading on the OTC Bulletin Board under the symbols of CONC and
CONCP.
Contour Stock Purchase. In February 1996, the Company issued 48 million
shares of its Common Stock at $1.00 per share to Contour Production Company
L.L.C. ("Contour") upon the closing of a Stock Purchase Agreement between the
Company and Contour (the "Contour Transaction"). The newly issued shares
represented 49.8% of the Company's voting power. In connection with the Contour
Transaction, the Company (i) entered into an option agreement with Contour (the
"Contour Option Agreement"), (ii) obtained consents from its principal
stockholders, subject to compliance with applicable securities law, to amend its
Certificate of Incorporation to increase its authorized Common Stock from 100
million shares to 200 million shares, (iii) entered into employment agreements
with John F. Bookout, President of Contour, and three other new executives named
by him, (iv) adopted a nonqualified stock option plan for the new executives
other than Mr. Bookout, (v) amended its existing incentive stock option plans,
(vi) reduced the size of its board of directors (the "Board") to seven members
and reconstituted the Board with three continuing directors and four designees
of Contour and (vii) replaced its credit facility.
Contour Option. Under the Contour Option Agreement, the Company granted
Contour an option (the "Contour Option") to purchase up to 27 million shares
(the "Maximum Option Number") of Common Stock at $1.00 per share (subject to
antidilution adjustments) upon satisfaction of certain conditions, including the
absence of any Company debt repurchase or redemption obligations as a result of
the purchase. Contour voluntarily exercised its option in full on December 1,
1997 to partially fund the SPR Acquisition.
Preferred Stock. The Company is authorized to issue up to 2 million shares
of $1.50 par value preferred stock. At December 31, 1998, 1,733,628 shares of
preferred stock were outstanding. On June 28, 1999, the Company began an offer
to exchange 15 shares of its common stock (or 1.5 shares on a post-split basis)
for each share of its $2.625 convertible exchangeable preferred stock
("Preferred Stock"). Pursuant to the exchange offer, 368,633 shares of Preferred
Stock were tendered representing approximately 21% of the total Preferred Stock
outstanding. In July 1999, the shares were exchanged for 552,950 shares of newly
issued common stock of the Company (after giving effect to the 1 for 10 reverse
stock split), increasing the Company's shares of outstanding common stock to
approximately 13.2 million. With the exchange, the Company eliminated dividend
arrearages of approximately $1.5 million.
In January 1996, the Company suspended the payment of the quarterly
Preferred Stock dividend scheduled for February 1, 1996 to conserve cash. On
April 15, 1997, the Board of Directors of the Company declared a dividend of
$2.625 per preferred share (approximately $4.6 million), which was paid on May
1, 1997. On April 14, 1998, the Company declared a dividend of $2.625 per share
of Preferred Stock (approximately $4.6 million), which was paid on April 30,
1998. The Company has not declared the quarterly dividends of $0.65625 per
preferred share for February 1, 1998, May 1, 1998, August 1, 1998, November 1,
1998, February 1, 1999, May 1, 1999, August 1, 1999, November 1, 1999 and
February 1, 2000, aggregating approximately $8.1 million (after giving effect to
the preferred stock exchange in the third quarter of 1999), covering nine
quarters. Future dividends on the Preferred Stock are prohibited under the
indenture governing the Notes. No interest is payable on Preferred Stock
arrearages; however, the terms of the Preferred Stock enable holders, voting
separately as a class, to elect two additional directors to the Board at each
meeting of stockholders at which directors are to be elected during any period
when Preferred Stock dividends are in arrears in an aggregate amount equal to at
least six quarterly dividends, whether or not consecutive. Since the Company has
not paid dividends on the Preferred Stock for a period of nine quarters, the
holders of the Preferred Stock, as a group, have the right to elect two
additional directors to the Company's Board of Directors. See "Legal
Proceedings."
Each share of Preferred Stock is convertible, at the holder's option, into
.347 shares of Common Stock, equivalent to a conversion price of $7.20 per share
of Common Stock relative to the $25 per share liquidation preference of the
Preferred Stock (the "Preferred Conversion Price").
39
<PAGE> 41
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Restricted Stock. In June 1999, the Company issued 56,250 shares (after
giving effect to the 1 for 10 reverse stock split) of restricted common stock to
three executives as compensation for services. The restrictions expired in 1999.
The Company recorded compensation expense and additional paid in capital based
on the fair market value of the shares issued.
40
<PAGE> 42
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 6 -- EMPLOYEE STOCK PLANS
Employee Stock Options. The Company has both qualified and nonqualified
stock option plans that provide for granting of options for the purchase of
common stock to key employees. These stock options may be granted for periods up
to ten years and are generally subject to vesting periods up to three years,
except options granted during 1997 and 1998 which are subject to a four year
vesting period.
Stock option activity for the Company during 1997, 1998 and 1999 was as
follows:
<TABLE>
<CAPTION>
1997 1998 1999
------------------ ------------------ ------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
OPTIONS IN THOUSANDS ------- -------- ------- -------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
Stock options outstanding, beginning
of year............................ 459 $16.30 460 $17.50 450 $18.70
Granted............................ 48 26.10 72 22.00 215 5.80
Exercised.......................... (41) 13.10 (27) 10.00 -- --
Surrendered or expired............. (6) 26.20 (55) 17.30 (273) 17.30
--- --- ----
Stock options outstanding, end of
year............................... 460 $17.50 450 $18.70 392 $12.60
=== ====== === ====== ==== ======
</TABLE>
At December 31, 1999, approximately 0.4 million shares were available for
future option grants.
The following table summarizes information about the options outstanding at
December 31, 1999:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------------------------- --------------------------
WEIGHTED AVERAGE
REMAINING
RANGE OF CONTRACTUAL LIFE WEIGHTED AVERAGE WEIGHTED AVERAGE
EXERCISE PRICE OPTIONS (YEARS) EXERCISE PRICE OPTIONS EXERCISE PRICE
- -------------- ------- ---------------- ---------------- ------- ----------------
<S> <C> <C> <C> <C> <C>
$ 3.44-10.00.. 255 9.4 $ 7.00 13 $10.00
$17.50-25.60.. 127 6.9 22.00 88 21.70
$27.20-41.30.. 10 4.6 35.40 8 36.70
</TABLE>
The weighted average fair value of options granted during 1997, 1998 and
1999 was $15.10, $14.60 and $4.63, respectively. The fair value of the options
granted was estimated on the date of grant using the Black-Scholes
option-pricing model with the following assumptions: weighted average risk-free
interest rate of 6.4% for 1997, 5.2% for 1998 and 6.6% for 1999; an expected
volatility of 60% for 1997, 78% for 1998 and 106% for 1999; expected life of
five years and no dividend yield for all three years.
The Company applies Accounting Principles Board Opinion No. 25 and related
Interpretations in accounting for stock option and purchase plans. Accordingly,
no compensation cost has been recognized for the stock option plans. Had
compensation cost been recognized based upon the fair market value at the grant
dates for awards under those plans consistent with the method of Statement of
Financial Accounting Standards No. 123, "Accounting for Stock Based
compensation", the Company's net loss and earnings per share for the years ended
December 31, 1997, 1998 and 1999 would have been as reflected in the pro forma
amounts indicated below:
<TABLE>
<CAPTION>
1997 1998 1999
------ -------- --------
<S> <C> <C> <C>
Net income (loss) before extraordinary item (in
thousands)........................................... $1,319 $(57,708) $(21,153)
Loss per common share before extraordinary item........ (.03) (.49) (1.97)
Net income (loss) (in thousands)....................... $1,319 $(57,708) $(10,102)
Loss per common share.................................. (.03) (.49) (1.11)
</TABLE>
41
<PAGE> 43
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
ESOP/401K. Kelley Oil established the ESOP effective January 1, 1984 for
the benefit of substantially all of its employees. Effective September 1, 1996,
the ESOP was amended to include a 401(k) feature whereby the Company is
obligated to make matching contributions up to 6% of each employee's salary. The
plan also provides for additional discretionary contributions. For 1997, 1998
and 1999, the Company made matching contributions totaling $0.2 million, $0.3
million and $0.2 million, respectively.
NOTE 7 -- INCOME TAXES
The following table sets forth a reconciliation of the statutory federal
income tax for the years ended December 31, 1997, 1998 and 1999:
<TABLE>
<CAPTION>
1997 1998 1999
------- -------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Income (loss) before income taxes...................... $ 1,951 $(57,007) $(9,733)
------- -------- -------
Income tax expense (benefit) computed at statutory
rates................................................ 663 (19,382) (3,309)
Increase (decrease) in valuation allowance........... (1,158) 18,735 (3,150)
Permanent differences:
Nondeductible expenses............................... 708 700 378
Other -- net......................................... (213) (53) (504)
------- -------- -------
Tax expense (benefit)............................. $ -- $ -- $ --
======= ======== =======
</TABLE>
No federal income taxes were paid for the years ended December 31, 1997,
1998 and 1999.
The Company's deferred tax position reflects the net tax effects of
temporary differences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for income tax reporting.
Significant components of the deferred tax liabilities and assets are as
follows:
<TABLE>
<CAPTION>
1998 1999
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
Deferred tax liabilities:
Tax over book depletion, depreciation and
capitalization methods on oil and gas
properties................................... $ -- $ --
Deferred tax assets:
Book over tax depletion, depreciation and
capitalization methods on oil and gas
properties................................... 37,430 40,624
Net operating loss carryforwards................ 77,741 77,721
Charitable contribution carryforwards........... 54 30
Alternative minimum tax credit carryforwards.... 21 21
Valuation allowance............................. (115,246) (118,396)
--------- ---------
Total deferred tax assets....................... -- --
--------- ---------
Net deferred tax liability........................ $ -- $ --
========= =========
</TABLE>
Net Operating Loss Carryforwards and Alternative Minimum Tax Credits. As of
December 31, 1999, the Company had cumulative net operating loss carryforwards
("NOL") for federal income tax purposes of approximately
42
<PAGE> 44
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$229 million, which expire in 2000 through 2019, and net operating loss
carryforwards for alternative minimum tax purposes of approximately $218
million, which expire in 2008 through 2019. Due to previous ownership changes,
future utilization of the net operating loss carry forwards will be limited by
Internal Revenue Code section 382.
NOTE 8 -- RELATED PARTY TRANSACTIONS
The 1994 DDP. In February 1994, the Company sponsored 1994 Development
Drilling Program (the "1994 DDP") completed a public offering of 20.9 million
units of its limited and general partner interests at $3.00 per unit. As of
December 31, 1999, the Company owned 19.2 million units (91.9%) in the 1994 DDP,
together with its 3.94% general partner interest.
The 1992 DDP. During November 1992, the Company sponsored 1992 development
Drilling Program (the "1992 DDP") completed a public offering of 16.0 million
units of limited and general partner interests at $3.00 per unit. As of December
31, 1998, Kelley Oil owned 13.4 million units (83.7%) in the 1992 DDP, together
with its 3.94% general partner interest. As of December 31, 1999, the 1992 DDP
was indebted to Kelley Oil for loans aggregating $0.2 million ($26,000, net of
intercompany eliminations). The Company recorded interest income on this
indebtedness of $27,000 in 1999, net of intercompany eliminations.
Reimbursements from Affiliated Programs. The Company is reimbursed for
administrative and overhead expenses incurred in connection with the management
and administration of each of these affiliated programs. Such amounts, net of
intercompany eliminations, aggregated $0.1 million in each of 1997, 1998 and
1999.
Advisory Fees. In connection with the Contour Transaction, the Company
entered into an agreement (the "Advisory Agreement") with Bessemer Partners &
Co. ("BPCO"), an affiliate of Bessemer, providing for the engagement of BPCO to
provide the Company with financial advisory services. Under the Advisory
Agreement, BPCO has provided certain financial advisory services. For its
services under the Advisory Agreement, BPCO received an advisory fee of $2.0
million at the closing of the Contour Transaction and $500,000 in each of
December 1997, 1998 and 1999, and will receive an additional $500,000 in each
December of 2000 and 2001. In addition, BPCO is entitled to reimbursement of
expenses incurred in connection with rendering advisory services. The Company
also has agreed to indemnify BPCO and its affiliates against certain liabilities
under the Advisory Agreement.
NOTE 9 -- COMMITMENTS AND CONTINGENCIES
Significant Customers. Substantially all of the Company's receivables are
due from a limited number of natural gas transmission companies and other gas
purchasers. During 1999, natural gas sales to three purchasers accounted for
35%, 28% and 26% of the Company's total sales. To date, this concentration has
not had a material adverse effect on the consolidated financial condition of the
Company.
Litigation. The Company is involved in various claims and lawsuits
incidental to its business. In the opinion of management, the ultimate liability
thereunder, if any, will not have a material effect on the financial statements
of the Company.
43
<PAGE> 45
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Leases. The Company leases office space and equipment under operating
leases with options to renew. Rental expenses related to these leases for the
years ended December 31, 1997, 1998 and 1999 were $0.8 million, $0.6 million and
$0.6 million, respectively. For the balance of the lease terms, minimum rentals
are as follows:
<TABLE>
<CAPTION>
(IN THOUSANDS)
<S> <C>
2000................................................... $ 670
2001................................................... 328
2002................................................... 10
2003................................................... 2
2004................................................... --
------
Total.................................................. $1,010
======
</TABLE>
The terms of the Company's office space lease provide that the Company may
terminate its rental obligation upon six months notice and incurring a maximum
obligation of $0.2 million.
NOTE 10 -- HEDGING ACTIVITIES
The Company periodically uses forward sales contracts, natural gas and
crude oil price swap agreements, natural gas basis swap agreements and options
to reduce exposure to downward price fluctuations on its natural gas and crude
oil production. The Company does not engage in speculative transactions. During
1999, the Company used price and basis swap agreements. Price swap agreements
generally provide for the Company to receive or make counterparty payments on
the differential between a fixed price and a variable indexed price for natural
gas and oil. Basis swap agreements generally provide for the Company to receive
or make counterparty payments on the differential between a variable indexed
price and the price it receives from the sale of natural gas production, and are
used to hedge against unfavorable price movements in the relationship between
such variable indexed price and the price received for such production. Gains
and losses realized by the Company from hedging activities are included in oil
and gas revenues and average sales prices in the period that the related
production is sold. Additionally, the Company must provide cash collateral for
any hedges (through swap or other agreements) to cover counter-party risk. The
Company's hedging activities also cover the oil and gas production attributable
to the interest in such production of the public unitholders in its subsidiary
partnerships.
Through natural gas price swap agreements, the Company hedged approximately
65%, 49% and 50% of its natural gas production for 1997, 1998 and 1999,
respectively, at average NYMEX quoted price of $2.35, $2.31 and $2.17 per Mmbtu,
respectively, before transaction and transportation costs. As of December 31,
1999, 1,550,000 Mmbtu's of natural gas production for 2000 has been hedged by
natural gas price swap agreements at an average NYMEX quoted price of $2.41 per
Mmbtu before transaction and transportation costs. Additional hedging activities
since December 31, 1999 have increased the volumes hedged in 2000 to 8,900,000
Mmbtus of natural gas at an average NYMEX quoted price of $2.56 per Mmbtu before
transaction and transportation costs. Through crude oil price swap agreements,
the Company hedged approximately 29% of its crude oil production for 1999 at an
average NYMEX quoted price of $20.00 per bbl, before transaction and
transportation costs. No crude oil production was hedged in either 1997 or 1998.
As of December 31, 1999, 30,000 bbls of crude oil production for January 2000
through March 2000 has been hedged by crude oil price swap agreements at an
average NYMEX quoted price of $25.05 per bbl before transaction and
transportation costs. Additional hedging activities since December 31, 1999 have
increased the volumes hedged in 2000 to 182,500 bbls of crude oil production at
an average NYMEX quoted price of $26.21 per bbl before transaction and
transportation costs. Hedging activities decreased crude oil and natural gas
revenues by approximately $4.2 million in 1997 and $0.2 million in 1999,
respectively, and increased such revenues by approximately $3.5 million in 1998
as compared to estimated revenues had no hedging activities been conducted. At
December 31, 1999, the unrealized gain on the Company's existing hedging
instruments for future production months in 2000 approximated $23,000.
The credit risk exposure from counterparty nonperformance on natural gas
forward sales contracts and derivative financial instruments is generally the
amount of unrealized gains under the contracts. The Company has not experienced
counterparty nonperformance on these agreements and does not anticipate any in
future periods.
44
<PAGE> 46
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 11 -- GUARANTOR FINANCIAL STATEMENTS
Kelley Oil Corporation, a wholly-owned subsidiary of the Company and Kelley
Operating Company Ltd., an indirect wholly-owned partnership of the Company are
guarantors of the Company's Series B 14% Senior Secured Notes due 2002-2003 and
of the Company's Series B and Series D 10 3/8% Senior Subordinated Notes due
2006. Concorde Gas Marketing, Inc. ("Concorde"), a wholly owned subsidiary of
the Company, is also a guarantor of the Company's Series B 14% Senior Secured
Notes due 2002-2003. The following guarantor consolidating condensed financial
statements present:
1. Consolidating condensed balance sheets as of December 31, 1998 and
1999, consolidating condensed statements of income (loss) for each of the
years ended December 31, 1997, 1998 and 1999 and consolidating condensed
statements of cash flows for each of the years ended December 31, 1997,
1998 and 1999.
2. Contour Energy Co. (the "Parent"), combined Guarantor Subsidiaries
(other than Concorde), Concorde and combined Non-Guarantor Subsidiaries,
all with their investments in subsidiaries accounted for using the equity
method.
3. Elimination entries necessary to consolidate the Parent and all of
its subsidiaries.
CONSOLIDATING CONDENSED BALANCE SHEET
DECEMBER 31, 1998
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES CONCORDE SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ -------- ------------- ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
ASSETS:
Current assets................. $ 424,609 $ 212,946 $7,863 $ 2,996 $(620,163) $ 28,251
Property and equipment, net.... -- 243,927 -- 14,008 (1,480) 256,455
Other non-current assets,
net......................... (165,642) 18,611 -- -- 148,522 1,491
--------- --------- ------ ------- --------- --------
Total assets........... $ 258,967 $ 475,484 $7,863 $17,004 $(473,121) $286,197
========= ========= ====== ======= ========= ========
LIABILITIES AND STOCKHOLDERS'
DEFICIT:
Current liabilities............ $ 38,406 $ 641,113 $3,646 $ 2,635 $(620,164) $ 65,636
Long-term debt................. 287,500 -- -- -- -- 287,500
Stockholders' deficit.......... (66,939) (165,629) 4,217 14,369 147,043 (66,939)
--------- --------- ------ ------- --------- --------
Total liabilities and
stockholders'
deficit.............. $ 258,967 $ 475,484 $7,863 $17,004 $(473,121) $286,197
========= ========= ====== ======= ========= ========
</TABLE>
45
<PAGE> 47
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING CONDENSED BALANCE SHEET
DECEMBER 31, 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES CONCORDE SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ -------- ------------- ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
ASSETS:
Current assets................. $ 334,360 $ 128,855 $6,317 $ 737 $(440,269) $ 30,000
Property and equipment, net.... -- 161,107 -- 6,141 (1,492) 165,756
Restricted cash................ -- 7,500 -- -- -- 7,500
Other non-current assets,
net......................... (149,279) 11,540 -- -- 138,265 526
--------- --------- ------ ------ --------- --------
Total assets........... $ 185,081 $ 309,002 $6,317 $6,878 $(303,496) $203,782
========= ========= ====== ====== ========= ========
LIABILITIES AND STOCKHOLDERS'
DEFICIT:
Current liabilities............ $ 15,219 $ 456,789 $1,501 $ 680 $(440,269) $ 33,920
Long term debt................. 246,165 -- -- -- -- 246,165
Stockholders' deficit.......... (76,303) (147,787) 4,816 6,198 136,773 (76,303)
--------- --------- ------ ------ --------- --------
Total liabilities and
stockholders'
deficit.............. $ 185,081 $ 309,002 $6,317 $6,878 $(303,496) $203,782
========= ========= ====== ====== ========= ========
</TABLE>
CONSOLIDATING CONDENSED STATEMENTS OF INCOME (LOSS)
FOR THE YEAR ENDED DECEMBER 31, 1997
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES CONCORDE SUBSIDIARIES ELIMINATIONS CONSOLIDATED
-------- ------------ -------- ------------- ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
Revenues........................... $ 8 $ 57,064 $2,883 $16,625 $ (442) $ 76,138
Costs and expenses................. (27,196) (36,975) (962) (9,367) 313 (74,187)
Equity in earnings of
subsidiaries..................... 29,139 9,179 -- -- (38,318) --
-------- -------- ------ ------- -------- --------
Net income (loss)........ $ 1,951 $ 29,268 $1,921 $ 7,258 $(38,447) $ 1,951
======== ======== ====== ======= ======== ========
</TABLE>
CONSOLIDATING CONDENSED STATEMENTS OF INCOME (LOSS)
FOR THE YEAR ENDED DECEMBER 31, 1998
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES CONCORDE SUBSIDIARIES ELIMINATIONS CONSOLIDATED
-------- ------------ -------- ------------- ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
Revenues.......................... $ (18) $ 69,958 $ 1,425 $ 8,290 $ -- $ 79,655
Costs and expenses................ (33,893) (94,457) (1,053) (6,689) (570) (136,662)
Equity in earnings of
subsidiaries.................... (23,096) 1,973 -- -- 21,123 --
-------- -------- ------- ------- ------- ---------
Net income (loss)....... $(57,007) $(22,526) $ 372 $ 1,601 $20,553 $ (57,007)
======== ======== ======= ======= ======= =========
</TABLE>
46
<PAGE> 48
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING CONDENSED STATEMENTS OF INCOME (LOSS)
FOR THE YEAR ENDED DECEMBER 31, 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES CONCORDE SUBSIDIARIES ELIMINATIONS CONSOLIDATED
-------- ------------ -------- ------------- ------------- ------------
<S> <C> <C> <C> <C> <C> <C>
Revenues.................... $ -- $ 75,145 $1,450 $ 6,324 $ (975) $ 81,944
Costs and expenses.......... (38,616) (61,190) (851) (3,034) 963 (102,728)
Equity in earnings of
subsidiaries.............. 17,832 3,889 -- -- (21,721) --
Extraordinary item.......... 11,051 -- -- -- -- 11,051
-------- -------- ------ ------- -------- ---------
Net income
(loss).......... $ (9,733) $ 17,844 $ 599 $ 3,290 $(21,733) $ (9,733)
======== ======== ====== ======= ======== =========
</TABLE>
47
<PAGE> 49
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING CONDENSED STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1997
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES CONCORDE SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ -------- ------------- ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
OPERATING ACTIVITIES:
Net income.............. $ 1,951 $ 29,268 $ 1,921 $ 7,258 $(38,447) $ 1,951
Non-cash income (loss)
adjustments.......... (24,842) 16,880 1 5,097 38,447 35,583
Changes in operating
assets and
liabilities.......... (97,813) 105,584 (2,801) (2,900) -- 2,070
--------- --------- ------- -------- -------- ---------
Net cash provided by (used
in) operating
activities.............. (120,704) 151,732 (879) 9,455 -- 39,604
--------- --------- ------- -------- -------- ---------
INVESTING ACTIVITIES:
Capital expenditures.... -- (51,592) -- (1,548) -- (53,140)
Acquisition of oil and
gas properties....... -- (111,135) -- -- -- (111,135)
Capital contributed to
partnerships......... -- (5,819) -- -- 5,819 --
Distributions from
partnerships......... -- 14,014 -- -- (14,014) --
--------- --------- ------- -------- -------- ---------
Net cash used in investing
activities.............. -- (154,532) -- (1,548) (8,195) (164,275)
--------- --------- ------- -------- -------- ---------
FINANCING ACTIVITIES:
Net proceeds on long
term borrowings...... 97,800 -- -- -- -- 97,800
Proceeds from sale of
common stock, net.... 27,545 -- -- -- -- 27,545
Distributions to
partners............. -- -- -- (14,014) 14,014 --
Capital contributed by
partners............. -- -- -- 5,819 (5,819) --
Dividends on preferred
stock................ (4,582) -- -- -- -- (4,582)
--------- --------- ------- -------- -------- ---------
Net cash provided by (used
in) financing
activities.............. 120,763 -- -- (8,195) 8,195 120,763
--------- --------- ------- -------- -------- ---------
Increase (decrease) in
cash and cash
equivalents............. 59 (2,800) (879) (288) -- (3,908)
Cash and cash equivalents,
beginning of period..... 58 2,804 879 329 -- 4,070
--------- --------- ------- -------- -------- ---------
Cash and cash equivalents,
end of period........... $ 117 $ 4 $ -- $ 41 $ -- $ 162
========= ========= ======= ======== ======== =========
</TABLE>
48
<PAGE> 50
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING CONDENSED STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1998
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES CONCORDE SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ -------- ------------- ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss)............ $ (57,007) $(22,526) $ 372 $ 1,601 $ 20,553 $ (57,007)
Non-cash income (loss)
adjustments............... 28,109 70,144 -- 3,687 (20,553) 81,387
Changes in operating assets
and liabilities........... 3,869 (7,976) (372) 2,401 -- (2,078)
--------- -------- ----- ------- -------- ---------
Net cash provided by (used in)
operating activities......... (25,029) 39,642 -- 7,689 -- 22,302
--------- -------- ----- ------- -------- ---------
INVESTING ACTIVITIES:
Capital expenditures......... -- (56,579) -- -- -- (56,579)
Proceeds from sale of
property.................. -- 17,363 -- -- -- 17,363
Distributions from
partnerships.............. -- 7,730 -- -- (7,730) --
--------- -------- ----- ------- -------- ---------
Net cash used in investing
activities................... -- (31,486) -- -- (7,730) (39,216)
--------- -------- ----- ------- -------- ---------
FINANCING ACTIVITIES:
Payments on long term
borrowings................ (118,900) -- -- -- -- (118,900)
Net proceeds on long term
borrowings................ 119,100 -- -- -- -- 119,100
Redemption on subordinated
notes..................... (228) -- -- -- -- (228)
Proceeds from sale of common
stock..................... 273 -- -- -- -- 273
Proceeds from conversion of
preferred................. (2) -- -- -- -- (2)
Proceeds from sale of common
stock, net................ 29,526 -- -- -- -- 29,526
Distributions to partners.... -- -- -- (7,730) 7,730 --
Dividends on preferred
stock..................... (4,582) -- -- -- -- (4,582)
--------- -------- ----- ------- -------- ---------
Net cash provided by (used in)
financing activities......... 25,187 -- -- (7,730) 7,730 25,187
--------- -------- ----- ------- -------- ---------
Increase (decrease) in cash and
cash equivalents............. 158 8,156 -- (41) -- 8,273
Cash and cash equivalents,
beginning of period.......... 117 4 -- 41 -- 162
--------- -------- ----- ------- -------- ---------
Cash and cash equivalents, end
of period.................... $ 275 $ 8,160 $ -- $ -- $ -- $ 8,435
========= ======== ===== ======= ======== =========
</TABLE>
49
<PAGE> 51
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING CONDENSED STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES CONCORDE SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ -------- ------------- ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss)............ $ (9,733) $ 17,844 $ 599 $ 3,290 $(21,733) $ (9,733)
Non-cash income (loss)
adjustments............... (24,059) 13,267 -- (1,309) 21,733 9,632
Changes in operating assets
and liabilities........... 90,461 (98,536) (599) 304 -- (8,370)
--------- -------- ----- -------- -------- ---------
Net cash provided by (used in)
operating activities......... 56,669 (67,425) -- 2,285 -- (8,471)
--------- -------- ----- -------- -------- ---------
INVESTING ACTIVITIES:
Capital expenditures......... -- (14,953) -- (251) -- (15,204)
Proceeds from sale of
property.................. -- 73,727 -- 9,426 -- 83,153
Restricted cash investment... -- (7,500) -- -- -- (7,500)
Acquisition purchase price
adjustment................ -- 6,889 -- -- -- 6,889
Distributions from
partnerships.............. -- 11,460 -- -- (11,460) --
--------- -------- ----- -------- -------- ---------
Net cash used in investing
activities................... -- 69,623 -- 9,175 (11,460) 67,338
--------- -------- ----- -------- -------- ---------
FINANCING ACTIVITIES:
Net payments on long term
borrowings................ (111,500) -- -- -- -- (111,500)
Proceeds from sale of notes,
net....................... 125,938 -- -- -- -- 125,938
Redemption of subordinated &
senior notes.............. (34,865) -- -- -- -- (34,865)
Distributions to partners.... -- -- -- (11,460) 11,460 --
Redemption of senior secured
notes..................... (36,505) -- -- -- -- (36,505)
--------- -------- ----- -------- -------- ---------
Net cash provided by (used in)
financing activities......... (56,932) -- -- (11,460) 11,460 (56,932)
--------- -------- ----- -------- -------- ---------
Increase (decrease) in cash and
cash equivalents............. (263) 2,198 -- -- -- 1,935
Cash and cash equivalents,
beginning of period.......... 275 8,160 -- -- -- 8,435
--------- -------- ----- -------- -------- ---------
Cash and cash equivalents, end
of period.................... $ 12 $ 10,358 $ -- $ -- $ -- $ 10,370
========= ======== ===== ======== ======== =========
</TABLE>
50
<PAGE> 52
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 12 -- SUPPLEMENTARY FINANCIAL AND OPERATING INFORMATION ON OIL AND GAS
EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
This footnote provides unaudited information required by Statement of
Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing
Activities".
Capitalized Costs. Capitalized costs and accumulated depreciation,
depletion and amortization relating to the Company's oil and gas producing
activities, all of which are conducted within the continental United States, are
summarized below.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1997 1998 1999
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Unevaluated properties.................................... $ 49,854 $ 38,293 $ 22,260
Properties subject to amortization........................ 463,263 496,686 428,116
--------- --------- ---------
Capitalized costs......................................... 513,117 534,979 450,376
Accumulated depreciation, depletion and amortization...... (221,729) (280,640) (286,020)
--------- --------- ---------
Net capitalized costs..................................... $ 291,388 $ 254,339 $ 164,356
========= ========= =========
</TABLE>
Costs Incurred. Costs incurred in oil and gas property acquisition,
exploration and development activities are summarized below.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1997 1998 1999
-------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Property acquisition costs:
Proved.................................................... $ 73,190 $ 2,338 $ --
Unproved(1)............................................... 40,997 1,405 764
Exploration costs........................................... 9,525 25,414 7,912
Development costs........................................... 40,713 27,875 6,696
-------- ------- -------
Total costs incurred........................................ $164,425 $57,032 $15,372
======== ======= =======
</TABLE>
- ---------------
(1) Includes $40 million in unproved property acquired from SPR on December 1,
1997.
51
<PAGE> 53
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Reserves. The following table summarizes the Company's net ownership
interests in estimated quantities of proved oil and gas reserves and changes in
net proved reserves, all of which are located in the continental United States,
for the years ended December 31, 1997, 1998 and 1999. Reserves estimates
contained below were prepared by H.J. Gruy & Associates, Inc. ("Gruy"),
independent petroleum engineers.
<TABLE>
<CAPTION>
CRUDE OIL, CONDENSATE
AND NATURAL GAS LIQUIDS NATURAL GAS
(MBBLS) (MMCF)
------------------------ ----------------------------
1997 1998 1999 1997 1998 1999
------ ------ ------ ------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
Proved developed and undeveloped
reserves:
Beginning of year...................... 1,466 2,953 5,294 297,634 354,867 283,559
Revisions of previous estimates........ 106 (79) 1,262 21,831 (31,674) (10,774)
Purchases of reserves in place......... 1,351 -- -- 51,712 -- --
Extensions and discoveries............. 256 3,082 1,762 13,892 9,512 15,620
Sale of reserves in place.............. -- (287) (328) -- (13,589) (107,313)
Production............................. (226) (375) (367) (30,202) (35,557) (22,392)
----- ----- ----- ------- ------- --------
End of year............................ 2,953 5,294 7,623 354,867 283,559 158,700
===== ===== ===== ======= ======= ========
Proved developed reserves at end of
year(1)................................ 2,432 1,981 2,686 257,800 188,824 123,887
===== ===== ===== ======= ======= ========
</TABLE>
- ---------------
(1) Includes 40.9 bcf of natural gas in 1999 related to the Company's interest
in the VORI. In March 2000, the Company executed a sale of a portion of its
VORI for net proceeds of approximately $20 million. The portion of the VORI
reserves sold (approximately 16.5 Bcf) relates to production beginning April
1, 2003.
Standardized Measure. The following table of the Standardized Measure of
Discounted Future Net Cash Flows concerning the standardized measure of future
cash flows from proved oil and gas reserves are presented in accordance with
Statement of Financial Accounting Standards No. 69. As prescribed by this
statement, the amounts shown are based on prices and costs at the end of each
period, and assume continuation of existing economic conditions. Future income
taxes are based on year-end statutory rates, adjusted for operating loss
carryforwards and tax credits. A discount factor of 10% was used to reflect the
timing of future net cash flow. Extensive judgments are involved in estimating
the timing of production and the costs that will be incurred throughout the
remaining lives of the fields. Accordingly, the estimates of future net revenues
from proved reserves and the present value thereof may not be materially correct
when judged against actual subsequent results. Further, since prices and costs
do not remain static, and no price or cost changes have been considered, and
future production and development costs are estimates to be incurred in
developing and producing the estimated proved oil and gas reserves, the results
are not necessarily indicative of the fair market value of estimated proved
reserves, and the results may not be comparable to estimates disclosed by other
oil and gas producers.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1997 1998 1999
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows....................................... $ 930,357 $ 643,473 $ 519,875
Future production costs................................... (196,048) (159,378) (92,153)
Future development costs.................................. (106,123) (93,321) (57,862)
Future income tax expenses................................ (37,050) (1,627) (3,500)
--------- --------- ---------
Future net cash flows..................................... 591,136 389,147 366,360
10% annual discount for estimating timing of cash flows... (227,249) (155,677) (127,705)
--------- --------- ---------
Standardized measure of discounted future net cash
flows................................................... $ 363,887 $ 233,470 $ 238,655
========= ========= =========
</TABLE>
52
<PAGE> 54
CONTOUR ENERGY CO.
(FORMERLY KELLEY OIL & GAS CORPORATION) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The standardized measure of discounted future net cash flows as of December
31, 1997, 1998 and 1999 was calculated using prices in effect as of those dates,
which averaged $16.93, $10.81 and $24.54, respectively, per barrel of oil and
$2.49, $2.07 and $2.15, respectively, per Mcf of natural gas.
Change in Standardized Measure. Changes in standardized measure of future
net cash flows relating to proved oil and gas reserves are summarized below.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1997 1998 1999
--------- --------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Changes due to current year operations:
Sales of oil and gas, net of production costs............ $ (62,080) $ (57,940) $(38,566)
Sale of reserves in place................................ -- (15,424) (61,420)
Extensions and discoveries............................... 21,945 20,097 50,493
Purchases of reserves in place........................... 91,034 -- --
Future development costs incurred........................ 21,806 9,218 6,696
Changes due to revisions in standardized variables:
Prices and production costs.............................. (243,851) (94,569) 22,998
Revisions of previous quantity estimates................. 25,345 (29,853) (3,916)
Estimated future development costs....................... (17,413) (29,240) 31,603
Income taxes............................................. 69,489 (14,110) (1,873)
Accretion of discount.................................... 51,818 24,903 23,428
Production rates (timing) and other...................... (27,977) 56,501 (24,258)
--------- --------- --------
Net increase (decrease)............................... (69,884) (130,417) 5,185
Beginning of year.......................................... 433,771 363,887 233,470
--------- --------- --------
End of year........................................... $ 363,887 $ 233,470 $238,655
========= ========= ========
</TABLE>
Sales of oil and gas, net of production costs, are based on historical
pre-tax results. Extensions and discoveries, sales and purchases of reserves in
place and the changes due to revisions in standardized variables are reported on
a pre-tax discounted basis, while the accretion of discount is presented after
tax. Extensions and discoveries include proved undeveloped reserves attributable
to the Company's interests in drill sites assigned to DDPs.
NOTE 13 -- QUARTERLY RESULTS (UNAUDITED)
<TABLE>
<CAPTION>
1998 1999
----------------------------------------- ----------------------------------------
1ST 2ND 3RD 4TH (1) 1ST 2ND(2) 3RD 4TH
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- -------- -------- -------- -------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues................................... $23,047 $21,162 $18,630 $ 16,311 $ 15,507 $12,850 $ 12,120 $13,630
Operating profit........................... 3,245 (1,251) (85) (26,087) (2,481) (3,883) (4,629) 374
Net income (loss) before extraordinary
item..................................... (4,823) (9,433) (8,411) (34,340) (10,986) 11,410 (13,242) (7,966)
Basic and diluted income(loss) per common
share before extraordinary item.......... $ (0.05) $ (0.08) $ (0.08) $ (0.28) $ (0.96) $ 0.82 $ (1.09) $ (0.67)
</TABLE>
- ---------------
(1) Reflects non-cash impairment charges against the carrying value of proved
and unproved oil and natural gas properties (see Note 2).
(2) Reflects gain on sale of properties in the Phillips Transaction.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
53
<PAGE> 55
PART III
ITEMS 10, 11, 12 AND 13. EXECUTIVE OFFICERS OF THE COMPANY; EXECUTIVE
COMPENSATION; SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT;
AND CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, RESPECTIVELY.
The information called for by these Items is incorporated by reference to
the Company's definitive Proxy Statement to be filed by the Company pursuant to
Regulation 14A of the General Rules and Regulations under the Securities and
Exchange Act not later than April 30, 2000.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) FINANCIAL STATEMENTS AND SCHEDULES:
(1) Financial Statements: The financial statements required to be
filed are included under Item 8 of this Report.
(2) Schedules: All schedules for which provision is made in applicable
accounting regulations of the SEC have been omitted as the schedules are
either not required under the related instructions, are not applicable or
the information required thereby is set forth in the Company's Consolidated
Financial Statements or the Notes thereto.
(3) Exhibits:
<TABLE>
<CAPTION>
EXHIBIT
NUMBER: EXHIBIT
------- -------
<C> <S>
2.1 -- Agreement and Plan of Consolidation among the Registrant,
Kelley Oil Corporation, Kelley Oil & Gas Partners, Ltd.
("Kelley Partners") and the other parties named therein
(incorporated by reference to Exhibit 2.1 to the
Registrant's Registration Statement (the "Consolidation
Registration Statement") on Form S-4 (Reg No. 33-84338)
filed September 26, 1994, as amended).
3.1 -- Certificate of Incorporation of the Registrant
(incorporated by reference to Exhibit 3.1 to the
Consolidation Registration Statement).
3.2 -- Certificate of Amendment to Certificate of Incorporation
of the Registrant dated December 20, 1994 (incorporated
by reference to Exhibit 3.2 to the Consolidation
Registration Statement).
3.3 -- Certificate of Correction to Certificate of Incorporation
of the Registrant dated February 12, 1996 (incorporated
by reference to Exhibit 3.1 to the Registrant's Current
Report on Form 8-K (File No. 0-25214) dated February 15,
1996).
3.4 -- Certificate of Designation of $2.625 Convertible
Exchangeable Preferred Stock of the Registrant
(incorporated by reference to Exhibit 3.1 to the
Registrant's Current Report on Form 8-K (File No.
0-25214) dated February 10, 1995).
3.5 -- Certificate of Designations of Cumulative Convertible
Preferred Stock of the Registrant (incorporated by
reference to Exhibit 3.2 to the Registrant's Current
Report on Form 8-K (File No. 0-25214) dated February 10,
1995).
</TABLE>
54
<PAGE> 56
<TABLE>
<CAPTION>
EXHIBIT
NUMBER: EXHIBIT
------- -------
<C> <S>
3.6 -- Certificate of Merger of Kelley Oil & Gas Partners, Ltd.
into Kelley Oil & Gas Corporation dated March 28, 1996
(Incorporated by reference to Exhibit 3.6 to the
Company's Annual Report on Form 10-K (File No. 0-25214)
for the year ended December 31, 1997).
3.7 -- Certificate of Amendment to Certificate of Incorporation
of the Registrant dated April 29, 1996 (Incorporated by
reference to Exhibit 3.7 to the Company's Annual Report
on Form 10-K (File No. 0-25214) for the year ended
December 31, 1997).
3.8 -- Certificate of Amendment to Certificate of Incorporation
of the Registrant dated July 12, 1999 (incorporated by
reference to Exhibit 3.8 to the Registrant's Registration
Statement on Form S-4 (Reg. No. 333-84053) filed July 30,
1999).
3.9 -- Bylaws of the Registrant (incorporated by reference to
Exhibit 3.5 to the Consolidation Registration Statement).
4.1 -- Certificate representing Common Stock of the Registrant
(incorporated by reference to Exhibit 4.1 to the
Consolidation Registration Statement).
4.2 -- Certificate representing $2.625 Convertible Exchangeable
Preferred Stock of the Registrant (incorporated by
reference to Exhibit 4.2 to the Consolidation
Registration Statement).
4.3 -- Supplemental Indenture dated February 7, 1995 among the
Registrant, Kelley Partners and United States Trust
Company of New York, relating to Kelley Partners' 8 1/2%
Convertible Subordinated Debentures (the "8 1/2%
Debentures") due 2000 (incorporated by reference to
Exhibit 4.1 to the Registrant's Current Report on Form
8-K (File No. 0-25214) dated February 10, 1995).
4.4 -- Supplemental Indenture dated March 29, 1996 between the
Registrant and the United States Trust Company of New
York, relating to the 8 1/2% Debentures (incorporated by
reference to Exhibit 4.4 to the Registrant's Annual
Report on Form 10-K (File No. 0-25214) for the year ended
December 31, 1995).
4.5 -- Indenture dated as of October 15, 1996, among the
Registrant, as issuer, Kelley Oil Corporation and Kelley
Operating Company, Ltd., as guarantors, and United States
Trust Company of New York, relating to the Registrant's
10 3/8% Senior Subordinated Notes due 2006 (incorporated
by reference to Exhibit 4.1 to the Registrant's Quarterly
Report on Form 10-Q (File No. 0-25214) for the quarterly
period ended September 30, 1996).
4.6 -- Form of the Registrant's 10 3/8% Senior Subordinated Note
Due 2006, Series B (incorporated by reference to Exhibit
4.5 to the Registrant's Registration Statement on Form
S-4 (Reg. No. 333-18481) filed December 20, 1996, as
amended).
4.10 -- Indenture dated as of May 29, 1998, among the Company, as
issuer, Kelley Oil Corporation and Kelley Operating
Company, Ltd., as guarantors, and United States Trust
Company of New York, relating to the Company's 10 3/8%
Senior Subordinated Notes due 2006 (incorporated by
reference to Exhibit 4.7 to the Company's Registration
Statement on Form S-4 (Reg. No. 333-61681) filed August
17, 1998).
4.11 -- Form of the Company's 10 3/8 Senior Subordinated Note Due
2006, Series D (incorporated by reference to Exhibit 4.8
to the Company's Registration Statement on Form S-4 (Reg.
No. 333-61681 filed August 17, 1998).
4.12 -- Indenture dated as of April 15, 1999 among the Company,
Kelley Oil Corporation, Kelley Operating Company, Ltd.
and Concorde Gas Marketing, Inc., as guarantors, and
Norwest Bank Minnesota,
</TABLE>
55
<PAGE> 57
<TABLE>
<CAPTION>
EXHIBIT
NUMBER: EXHIBIT
------- -------
<C> <S>
National Association, relating to the Company's 14% Senior
Secured Notes due 2003, maturing at 105% of the stated
principal amount B (incorporated by reference to Exhibit
4.13 to the Registrant's Registration Statement on Form S-4
(Reg. No. 333-84053) filed July 30, 1999).
4.13 -- Form of the Company's 14% Senior Secured Notes due 2003,
maturing at 105% of the stated principal amount
(incorporated by reference to Exhibit B of Exhibit 4.13
to the Registrant's Registration Statement on Form S-4
(Reg. No. 333-84053) filed July 30, 1999).
10.1 -- Amended and Restated Employee Stock Ownership Plan of
Kelley Oil effective as of January 1, 1989 (incorporated
by reference to Exhibit 10.15 to Kelley Oil's Annual
Report on Form 10-K (File No. 0-17585) for the year ended
December 31, 1991).
10.2 -- 1987 Incentive Stock Option Plan (the "1987 Plan") of
Kelley Oil (incorporated by reference to Kelley Oil's
Annual Report on Form 10-K (File No. 0-17585) for the
year ended December 31, 1988).
10.3 -- 1991 Incentive Stock Option Plan (the "1991 Plan") of
Kelley Oil (incorporated by reference to Exhibit 10.3 to
Kelley Oil's Annual Report on Form 10-K (File No.
0-175850 for the year ended December 31, 1991).
10.4 -- 1995 Incentive Stock Option Plan of the Registrant (the
"1995 Plan") (incorporated by reference to Exhibit 10.4
to the Registrant's Annual Report on Form 10-K (File No.
0-25214) for the year ended December 31, 1995).
10.5 -- Amendment to the 1987 Plan, 1991 Plan and 1995 Plan
(incorporated by reference to Exhibit 10.5 to the
Registrant's Current Report on Form 8-K (File No.
0-25214) dated February 15, 1996).
10.6 -- 1996 Nonqualified Stock Option Plan of the Registrant
(incorporated by reference to Exhibit 10.4 to the
Registrant's Current Report on Form 8-K (File No.
0-25214) dated February 15, 1996).
10.7 -- Employment Agreement dated as of February 15, 1996
between the Registrant and John F. Bookout, Jr.
(incorporated by reference to Exhibit 10.2 to the
Registrant's Current Report on Form 8-K (File No.
0-25214) dated February 15, 1996).
10.8 -- Employment Agreement dated as of October 1, 1998 with
Rick G. Lester (incorporated by reference to exhibit
10.9 to the Registrants Annual Report on Form 10-K
(File no. 001-14286) for the year ended December 31,
1998).
10.9 -- Employment Agreement dated as of July 31, 1999 with
Kenneth R. Sanders.
10.10 -- 1996 Incentive Stock Option Plan of the Registrant
(incorporated by reference to Exhibit 10.11 to the
Registrant's Annual Report on Form 10-K (File No.
0-25214) for the year ended December 31, 1996).
10.11 -- 1997 Annual and Long-Term Incentive-Performance Plan of
the Registrant (incorporated by reference to exhibit
10.12 to the Registrants Annual Report on Form 10-K
(File no. 001-14286) for the year ended December 31,
1997).
10.12 -- Purchase and Sale Agreement, dated October 21, 1997,
between the Company and SCANA Petroleum Resources, Inc.
(incorporated by reference to Exhibit 10.2 to the
Registrant's Current Report on Form 8-K (File No.
0-25214) dated December 1, 1997).
21.1 -- Subsidiaries of the Registrant (incorporated by reference
to Exhibit 21.1 to the Registrant's Annual Report on Form
10-K (File No. 0-25214) for the year ended December 31,
1996).
23.1 -- Consent of Deloitte & Touche LLP.
</TABLE>
56
<PAGE> 58
<TABLE>
<CAPTION>
EXHIBIT
NUMBER: EXHIBIT
------- -------
<C> <S>
23.2 -- Consent of H.J. Gruy & Associates, Inc.
27 -- Financial Data Schedule (included only in the electronic
filing of this document).
</TABLE>
(b) REPORTS ON FORM 8-K:
The Company filed a Current Report on Form 8-K dated October 21, 1997
and a Current Report on Form 8-K dated December 1, 1997, filed on December
16, 1997 and amended on February 17, 1998 and March 30, 1998.
57
<PAGE> 59
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, this 3rd day of April
2000.
CONTOUR ENERGY CO.
<TABLE>
<S> <C>
By: /s/ JOHN F. BOOKOUT By: /s/ RICK G. LESTER
------------------------------------------------- -------------------------------------------------
John F. Bookout Rick G. Lester
Chief Executive Officer Senior Vice President
and Chief Financial Officer
</TABLE>
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed as of the 3rd day of April 2000 by the following persons
in their capacity as directors of the Registrant.
<TABLE>
<S> <C>
/s/ JOHN F. BOOKOUT /s/ ADAM P. GODFREY
- ----------------------------------------------------- -----------------------------------------------------
John F. Bookout Adam P. Godfrey
/s/ JOHN J. CONKLIN, JR. /s/ WILLIAM J. MURRAY
- ----------------------------------------------------- -----------------------------------------------------
John J. Conklin, Jr. William J. Murray
/s/ RALPH P. DAVIDSON /s/ EDWARD PARK
- ----------------------------------------------------- -----------------------------------------------------
Ralph P. Davidson Edward Park
/s/ WARD W. WOODS
----------------------------------
Ward W. Woods
</TABLE>
58
<PAGE> 60
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NUMBER: DESCRIPTION
------- -----------
<C> <S>
2.1 -- Agreement and Plan of Consolidation among the Registrant,
Kelley Oil Corporation, Kelley Oil & Gas Partners, Ltd.
("Kelley Partners") and the other parties named therein
(incorporated by reference to Exhibit 2.1 to the
Registrant's Registration Statement (the "Consolidation
Registration Statement") on Form S-4 (Reg No. 33-84338)
filed September 26, 1994, as amended).
3.1 -- Certificate of Incorporation of the Registrant
(incorporated by reference to Exhibit 3.1 to the
Consolidation Registration Statement).
3.2 -- Certificate of Amendment to Certificate of Incorporation
of the Registrant dated December 20, 1994 (incorporated
by reference to Exhibit 3.2 to the Consolidation
Registration Statement).
3.3 -- Certificate of Correction to Certificate of Incorporation
of the Registrant dated February 12, 1996 (incorporated
by reference to Exhibit 3.1 to the Registrant's Current
Report on Form 8-K (File No. 0-25214) dated February 15,
1996).
3.4 -- Certificate of Designation of $2.625 Convertible
Exchangeable Preferred Stock of the Registrant
(incorporated by reference to Exhibit 3.1 to the
Registrant's Current Report on Form 8-K (File No.
0-25214) dated February 10, 1995).
3.5 -- Certificate of Designations of Cumulative Convertible
Preferred Stock of the Registrant (incorporated by
reference to Exhibit 3.2 to the Registrant's Current
Report on Form 8-K (File No. 0-25214) dated February 10,
1995).
</TABLE>
<PAGE> 61
<TABLE>
<CAPTION>
EXHIBIT
NUMBER: DESCRIPTION
------- -----------
<C> <S>
3.6 -- Certificate of Merger of Kelley Oil & Gas Partners, Ltd.
into Kelley Oil & Gas Corporation dated March 28, 1996
(Incorporated by reference to Exhibit 3.6 to the
Company's Annual Report on Form 10-K (File No. 0-25214)
for the year ended December 31, 1997).
3.7 -- Certificate of Amendment to Certificate of Incorporation
of the Registrant dated April 29, 1996 (Incorporated by
reference to Exhibit 3.7 to the Company's Annual Report
on Form 10-K (File No. 0-25214) for the year ended
December 31, 1997).
3.8 -- Certificate of Amendment to Certificate of Incorporation
of the Registrant dated July 12, 1999 (incorporated by
reference to Exhibit 3.8 to the Registrant's Registration
Statement on Form S-4 (Reg. No. 333-84053) filed July 30,
1999).
3.9 -- Bylaws of the Registrant (incorporated by reference to
Exhibit 3.5 to the Consolidation Registration Statement).
4.1 -- Certificate representing Common Stock of the Registrant
(incorporated by reference to Exhibit 4.1 to the
Consolidation Registration Statement).
4.2 -- Certificate representing $2.625 Convertible Exchangeable
Preferred Stock of the Registrant (incorporated by
reference to Exhibit 4.2 to the Consolidation
Registration Statement).
4.3 -- Supplemental Indenture dated February 7, 1995 among the
Registrant, Kelley Partners and United States Trust
Company of New York, relating to Kelley Partners' 8 1/2%
Convertible Subordinated Debentures (the "8 1/2%
Debentures") due 2000 (incorporated by reference to
Exhibit 4.1 to the Registrant's Current Report on Form
8-K (File No. 0-25214) dated February 10, 1995).
4.4 -- Supplemental Indenture dated March 29, 1996 between the
Registrant and the United States Trust Company of New
York, relating to the 8 1/2% Debentures (incorporated by
reference to Exhibit 4.4 to the Registrant's Annual
Report on Form 10-K (File No. 0-25214) for the year ended
December 31, 1995).
4.5 -- Indenture dated as of October 15, 1996, among the
Registrant, as issuer, Kelley Oil Corporation and Kelley
Operating Company, Ltd., as guarantors, and United States
Trust Company of New York, relating to the Registrant's
10 3/8% Senior Subordinated Notes due 2006 (incorporated
by reference to Exhibit 4.1 to the Registrant's Quarterly
Report on Form 10-Q (File No. 0-25214) for the quarterly
period ended September 30, 1996).
4.6 -- Form of the Registrant's 10 3/8% Senior Subordinated Note
Due 2006, Series B (incorporated by reference to Exhibit
4.5 to the Registrant's Registration Statement on Form
S-4 (Reg. No. 333-18481) filed December 20, 1996, as
amended).
4.10 -- Indenture dated as of May 29, 1998, among the Company, as
issuer, Kelley Oil Corporation and Kelley Operating
Company, Ltd., as guarantors, and United States Trust
Company of New York, relating to the Company's 10 3/8%
Senior Subordinated Notes due 2006 (incorporated by
reference to Exhibit 4.7 to the Company's Registration
Statement on Form S-4 (Reg. No. 333-61681) filed August
17, 1998).
4.11 -- Form of the Company's 10 3/8 Senior Subordinated Note Due
2006, Series D (incorporated by reference to Exhibit 4.8
to the Company's Registration Statement on Form S-4 (Reg.
No. 333-61681 filed August 17, 1998).
4.12 -- Indenture dated as of April 15, 1999 among the Company,
Kelley Oil Corporation, Kelley Operating Company, Ltd.
and Concorde Gas Marketing, Inc., as guarantors, and
Norwest Bank Minnesota,
</TABLE>
<PAGE> 62
<TABLE>
<CAPTION>
EXHIBIT
NUMBER: DESCRIPTION
------- -----------
<C> <S>
National Association, relating to the Company's 14% Senior
Secured Notes due 2003, maturing at 105% of the stated
principal amount B (incorporated by reference to Exhibit
4.13 to the Registrant's Registration Statement on Form S-4
(Reg. No. 333-84053) filed July 30, 1999).
4.13 -- Form of the Company's 14% Senior Secured Notes due 2003,
maturing at 105% of the stated principal amount
(incorporated by reference to Exhibit B of Exhibit 4.13
to the Registrant's Registration Statement on Form S-4
(Reg. No. 333-84053) filed July 30, 1999).
10.1 -- Amended and Restated Employee Stock Ownership Plan of
Kelley Oil effective as of January 1, 1989 (incorporated
by reference to Exhibit 10.15 to Kelley Oil's Annual
Report on Form 10-K (File No. 0-17585) for the year ended
December 31, 1991).
10.2 -- 1987 Incentive Stock Option Plan (the "1987 Plan") of
Kelley Oil (incorporated by reference to Kelley Oil's
Annual Report on Form 10-K (File No. 0-17585) for the
year ended December 31, 1988).
10.3 -- 1991 Incentive Stock Option Plan (the "1991 Plan") of
Kelley Oil (incorporated by reference to Exhibit 10.3 to
Kelley Oil's Annual Report on Form 10-K (File No.
0-175850 for the year ended December 31, 1991).
10.4 -- 1995 Incentive Stock Option Plan of the Registrant (the
"1995 Plan") (incorporated by reference to Exhibit 10.4
to the Registrant's Annual Report on Form 10-K (File No.
0-25214) for the year ended December 31, 1995).
10.5 -- Amendment to the 1987 Plan, 1991 Plan and 1995 Plan
(incorporated by reference to Exhibit 10.5 to the
Registrant's Current Report on Form 8-K (File No.
0-25214) dated February 15, 1996).
10.6 -- 1996 Nonqualified Stock Option Plan of the Registrant
(incorporated by reference to Exhibit 10.4 to the
Registrant's Current Report on Form 8-K (File No.
0-25214) dated February 15, 1996).
10.7 -- Employment Agreement dated as of February 15, 1996
between the Registrant and John F. Bookout, Jr.
(incorporated by reference to Exhibit 10.2 to the
Registrant's Current Report on Form 8-K (File No.
0-25214) dated February 15, 1996).
10.8 -- Employment Agreement dated as of October 1, 1998 with
Rick G. Lester (incorporated by reference to exhibit
10.9 to the Registrants Annual Report on Form 10-K
(File no. 001-14286) for the year ended December 31,
1998).
10.9 -- Employment Agreement dated as of July 31, 1999 with
Kenneth R. Sanders.
10.10 -- 1996 Incentive Stock Option Plan of the Registrant
(incorporated by reference to Exhibit 10.11 to the
Registrant's Annual Report on Form 10-K (File No.
0-25214) for the year ended December 31, 1996).
10.11 -- 1997 Annual and Long-Term Incentive-Performance Plan of
the Registrant (incorporated by reference to exhibit
10.12 to the Registrants Annual Report on Form 10-K
(File no. 001-14286) for the year ended December 31,
1997).
10.12 -- Purchase and Sale Agreement, dated October 21, 1997,
between the Company and SCANA Petroleum Resources, Inc.
(incorporated by reference to Exhibit 10.2 to the
Registrant's Current Report on Form 8-K (File No.
0-25214) dated December 1, 1997).
21.1 -- Subsidiaries of the Registrant (incorporated by reference
to Exhibit 21.1 to the Registrant's Annual Report on Form
10-K (File No. 0-25214) for the year ended December 31,
1996).
23.1 -- Consent of Deloitte & Touche LLP.
</TABLE>
<PAGE> 63
<TABLE>
<CAPTION>
EXHIBIT
NUMBER: DESCRIPTION
------- -----------
<C> <S>
23.2 -- Consent of H.J. Gruy & Associates, Inc.
27 -- Financial Data Schedule (included only in the electronic
filing of this document).
</TABLE>
<PAGE> 1
EXHIBIT 10.9
EMPLOYMENT AGREEMENT
This Agreement, made this 1st day of August, 1999, by and between
Contour Energy Co., a Delaware corporation (the "Company"), and Kenneth R.
Sanders ("Executive").
WITNESSETH:
WHEREAS, the Company desires to employ Executive as Senior Vice
President - Exploration and Production on the terms set forth below, and
Executive is willing to accept such employment on such terms.
NOW, THEREFORE, in consideration of the foregoing and for other good and
valuable consideration, the parties hereto do hereby agree:
1. DEFINITIONS
As used in this Agreement, defined words and phrases have the meaning
first ascribed to them herein whenever the first letter of each word is
capitalized. Words used in the masculine apply equally to the feminine,
and wherever the context dictates, the plural should be read as the
singular and the singular as the plural. References to Sections are to
Sections of this Agreement. The headings at the beginning of each
section are inserted for convenience only and are not intended to
describe, interpret, define, or limit the scope, extent, or intent of
this Agreement.
a. "Board" means the Company's board of directors.
b. "Cause" shall be deemed to exist if, and only if:
i. Executive is convicted in a court of law of any crime (i) that
constitutes a felony relating to the Company or any other
business endeavor or (ii) that constitutes a felony which
involves moral turpitude; or
ii. Executive engages in willful misconduct or any material breach of
or willful material failure to perform his duties and
responsibilities hereunder, which misconduct, breach, or failure
shall continue after the Company, by action of the Board, shall
have advised Executive thereof in writing and shall have afforded
Executive a reasonable opportunity (which shall be at least 30
days from the date of such written advice or knowledge thereof)
to correct the acts or omissions complained of, and which
Executive shall have so failed to take action to correct within
such period.
<PAGE> 2
c. "Disability" means Executive's inability to fully and competently
perform the duties hereunder for a period of at least three
consecutive months by reason of mental or physical illness or other
incapacity. The Company and Executive or his attorney-in-fact shall,
based on competent medical advice, determine whether Executive is and
continues to be disabled. If the Company and Executive or his
attorney-in-fact disagree with the determination of disability, then
each of them shall appoint a doctor and the two doctors shall select
a third independent doctor whose decision as to whether Executive has
been unable to perform the duties of the nature contemplated
hereunder for a three-consecutive-month period shall be binding on
the parties.
The doctor advising the Company with regard to the Company's initial
determination of whether Executive has been disabled within the
foregoing meaning and the independent doctor selected by the two
doctors designated by the Company and Executive or his
attorney-in-fact shall be given full access to Executive's medical
records and shall be afforded a reasonable opportunity to examine
Executive. The Company agrees to instruct such doctors to maintain
all information reflected in Executive's records in full confidence
and not to disclose such information to any person (including the
Company) except as may be necessary for the determination described
above. All references to doctor in this paragraph 1.d shall mean a
practicing doctor of medicine.
d. "Executive Officer" means Senior Vice President - Exploration and
Production.
e. "Notice of Termination" means a notice that sets forth the date of
termination and, in the event of termination for Cause, the facts and
circumstances claimed to provide a basis for termination of
Executive's employment.
f. "Change of Control" means if (i) the Company is merged or
consolidated with another corporation and as a result of such merger
or consolidation less than 50% of the outstanding voting securities
of the surviving or resulting corporation are owned in the aggregate
by the former shareholders of the Company; (ii) the Company sells all
or substantially all of its assets to another corporation, which is
not a wholly-owned subsidiary of the Company; (iii) any person or
group within the meaning of the Securities Exchange Act of 1934, as
amended, acquires (together with voting securities of the Company
held by such person or group) 30% or more of the outstanding voting
securities of the Company (whether directly, indirectly, beneficially
or of record) pursuant to any transaction or combination of
transactions; (iv) there is a change of control of the Company of a
nature that would be required to be reported in response to Item 6(e)
of Schedule 14A of Regulation 14A promulgated under the Securities
Exchange Act of 1934, as amended, whether or not the Company is then
subject to such reporting requirements; or (v) the individuals who,
at the beginning of any period of twelve consecutive months,
constituted the Board of Directors cease, for any reason, to
constitute at least a majority thereof, unless the nomination for
election or election by the Company's shareholders of each new
director of the Company was approved by a vote of at least two-thirds
of the directors then still in office who either were directors at
the
<PAGE> 3
beginning of such period or whose election or nomination for election
was previously so approved. Notwithstanding the foregoing, however, a
Change of Control shall not be deemed to have occurred upon issuance
of capital stock by the Company approved by a vote of at least
two-thirds of the directors then in office.
2. TERM
This Agreement commences effective as of August 1, 1999 (the
"Commencement Date"), shall continue for 12 months from the Commencement
Date, unless sooner terminated by a Notice of Termination under the
provisions of this Agreement, and each year thereafter, unless either of
the parties gives thirty (30) days written notice that the Agreement
shall not be extended for the ensuing year, which notice shall not be
deemed to be a Notice of Termination under the provisions of this
Agreement.
3. DUTIES
During the term of his employment as provided in Section 2 above, the
Company will employ Executive in a senior executive capacity, with such
responsibilities as the Company may from time to time determine during
the term of this Agreement, which shall include the engineering and
development functions. Executive will comply with all applicable laws,
with all corporate documents governing the conduct of the Company's
business and affairs, and with the Company's policies.
Executive agrees to devote substantially all of his business time to the
performance of his duties hereunder.
4. COMPENSATION
a. The Company shall pay Executive for all services to be performed
hereunder during the term of this Agreement. The Company agrees to
pay to Executive an annual salary of $190,000.00, payable in
semimonthly installments in arrears on the fifteenth and last day of
each calendar month, the first such installment to be payable for the
period ended August 15, 1999.
b. The Executive shall participate in the Company's 1997 Annual and
Long-Term Incentive-Performance Plan (the "1997 Plan"), in accordance
with the terms and provisions of the Plan, (i) as to annual
performance awards, commencing as of August 1, 1999 to the extent in
1999 his participation award exceeds $50,000, and annually thereafter
as provided in the 1997 Plan so long as the 1997 Plan remains in
effect, and Executive is employed by the Company annually thereafter,
and (ii) as to stock options, the Company shall grant Executive a
total of 25,000 options to purchase shares of the Company's common
stock for a purchase price as determined under the Plan (the "1997
Plan Options"), which shall vest in cumulative annual installments as
follows: (i) 25% of such 1997 Plan Options on the first anniversary
of the Commencement Date, or 33 1/3% upon termination of employment
by the Company if employment is terminated by
<PAGE> 4
the Company before the second anniversary and not terminated for
Cause or a Change of Control, (ii) 50% of such 1997 Plan Options on
the second anniversary of the Commencement Date, (iii) 75% of such
1997 Plan Options on the third anniversary of the Commencement Date
and (iv) 100% of such 1997 Plan Options on the fourth anniversary of
the Commencement Date.
c. In addition to the Options granted under the 1997 Plan, the Company
shall, effective the Commencement Date, grant Executive a total of
37,500 options to purchase shares of the Company's common stock for a
purchase price of $10.00 per share (the "1996 Plan Options"), which
shall vest in cumulative annual installments as follows: (i) 33 1/3%
of such 1996 Plan Options on the first anniversary of the
Commencement Date, (ii) 66 2/3% of such 1996 Plan Options on the
second anniversary of the Commencement Date, and (iii) 100% of such
1996 Plan Options on the third anniversary of the Commencement Date.
d. The Company agrees to pay Executive in addition to payments and
awards set forth in paragraphs a, b and c above, an initial bonus of
$50,000.00 payable within ten (10) business days of the Commencement
Date.
e. In addition to the payments and awards set forth in paragraphs a, b,
c and d above:
i. During the term of this Agreement, upon submission of a
reasonable accounting, the Company shall reimburse Executive for
all reasonable travel, entertainment, and other business
expenses that are in compliance with company policy related to
his employment hereunder.
ii. During the term of this Agreement, Executive shall be eligible
for the Company's employee benefit programs on the terms on
which the same are extended to the Company's executives
generally, including but not limited to the Company's Section
401(k) plan, a health care plan, five weeks vacation and
reimbursement for unreserved parking expenses.
iii. During the term of this Agreement, Executive shall be entitled
to reimbursement for membership fees and dues for a business
club (luncheon or athletic) and a country club (to include
initiation fees of approximately $5,000.00).
The Company shall have the right to deduct from all payments to be made
under this Agreement any federal, state, or local taxes required by law
to be withheld from such payments.
5. NONDISCLOSURE OF CONFIDENTIAL INFORMATION
Executive agrees that, during his employment by the Company and for 1
year thereafter, he will not use or disclose to others, directly or
indirectly, any confidential information relating
<PAGE> 5
to the business, prospects, or plans of the Company or its subsidiaries.
Notwithstanding the previous sentence, Executive shall not be in
violation of this section in the event of a disclosure pursuant to a
court action or governmental rule, regulation, or proceeding
(hereinafter referred to as an "Ordered Disclosure") provided Executive
has notified the Company of such Ordered Disclosure within five business
days of being personally served with such Ordered Disclosure. Executive
agrees to cooperate in good faith with the Company in responding to such
Ordered Disclosure in order to prevent, limit or impose restrictions on
such Ordered Disclosure. In no event, however, shall this section
require Executive to take action or otherwise cause Executive to be in
violation of any law or result in contempt of such Ordered Disclosure.
Upon termination of his employment with the Company, Executive shall
surrender to the Company any and all work papers, reports, manuals,
documents, and the like (including all originals and copies thereof) in
his possession which contain confidential information relating to the
business, prospects, or plans of the Company or its affiliates.
Executive agrees that following any termination of his employment with
the Company, he will endorse strategies of the Company, and will not
disclose or cause to be disclosed any negative, adverse or derogatory
comments or information of a substantial nature about the Company or its
management, or about any product or service provided by the Company, or
about the Company's prospects for the future. The Company may seek the
assistance, cooperation or testimony of Executive following any such
termination in connection with any investigation, litigation or
proceeding arising out of matters within the knowledge of Executive and
related to his position as an officer or employee of the Company, and in
any instance, Executive shall provide such assistance, cooperation or
testimony and the Company shall pay Executive's reasonable costs and
expenses in connection therewith. In addition, if such assistance,
cooperation or testimony requires more than a nominal commitment of
Executive's time, the Company will compensate Executive for such time at
a per diem rate derived from Executive's salary from the Company at the
time of Executive's termination.
6. TERMINATION
a. This Agreement shall automatically terminate upon Executive's death
or Disability. In addition, this Agreement may be terminated by the
Company or Executive at any time for any reason whatsoever. Any
termination of Executive's employment by the Company or by Executive
(other than termination pursuant to the first sentence of this
subsection a.) shall be communicated by written Notice of Termination
to the other party hereto in accordance with Section 15.
b. Upon termination of this Agreement for any reason, Executive shall be
entitled to receive, and the Company shall pay Executive (or, if such
termination is caused by Executive's death, his estate or as may be
directed by the legal representatives of such estate) within 30 days
of the termination date, any unpaid amounts earned by or payable to
Executive through the date of termination under Sections 4.a. and
4.e. (if any).
<PAGE> 6
c. In addition to the amounts to which Executive is entitled under
Section 6.b., if this Agreement is terminated by the Company other
than for Cause or other than a Change of Control, the Company shall
pay Executive in a single lump-sum payment an amount equal to the
compensation that would have been payable under Section 4.a. over the
next twelve (12) months plus any vested options, in any event not
less than 1/3 of the Initial Grant under the 1997 Plan had this
Agreement not otherwise been terminated. The amounts payable under
this Section 6.c. shall be paid no later than 30 days after the date
of termination.
d. In addition to the amounts to which Executive is entitled under
Section 6.b., if this Agreement is terminated by the Company because
of a Change of Control, the Company shall pay Executive in a single
lump-sum payment an amount equal to (i) the compensation that would
have been payable under Section 4.a. over the next twenty-four (24)
months had this Agreement not otherwise been terminated, and (ii) all
unvested options accelerated to 100% vesting. Such compensation shall
be the only compensation payable as a result of such termination
because of a Change of Control. The amounts payable under this
Section 6.d. shall be paid no later than 30 days after the date of
termination.
7. RESTRICTIVE COVENANT
During the term of Executive's employment with the Company, and (except
as provided in clause (c) below) for a period of one year following the
termination of Executive's employment with the Company for any reason,
including termination occasioned by the expiration of this Agreement,
Executive shall not:
a. interfere with the relationship of the Company or any of its
employees, agents or representatives;
b. directly or indirectly divert or attempt to divert from the Company
any property acquisition in which the Company has been actively
engaged during the term hereof; or
c. directly or indirectly render financial or other services of the
nature of those provided to the Company to any person, company or
entity other than the Company, provided, this clause (c) shall
terminate upon the termination of Executive's employment with the
Company.
<PAGE> 7
8. INDEMNIFICATION
Except to the extent attributable to Executive's willful misconduct or
actions leading to the Company's termination of this Agreement for
Cause, the Company shall indemnify Executive against expenses (including
attorneys' fees), judgments, fines, and amounts paid in settlement
actually and reasonably incurred by him in connection with any action,
suit, or proceeding to which Executive has been made a party by reason
of his capacity as Executive Officer of the Company if Executive acted
in good faith and in a manner Executive reasonably believed to be in or
not opposed to the best interest of the Company and, with respect to any
criminal action or proceeding, had no reasonable cause to believe
Executive's conduct was unlawful. The termination of any action, suit,
or proceeding by judgment, order, settlement, conviction, or upon a plea
of nolo contendere or its equivalent, shall not, of itself, create a
presumption that Executive did not act in good faith and in a manner
which Executive reasonably believed to be in or not opposed to the best
interest of the Company, and with respect to any criminal action or
proceeding, had reasonable cause to believe that Executive's conduct was
unlawful.
9. ADDITIONAL REMEDIES
In the event of a breach or a threatened breach of the terms of Section
5 or 7 by Executive, the Company shall, in addition to all other
remedies, be entitled to a temporary or permanent injunction and/or a
decree for specific performance, in accordance with the provisions
hereof, without showing any actual damage or that monetary damages would
not provide an adequate remedy and without any bond or other security
being required.
10. NONASSIGNMENT
This Agreement is personal to Executive and shall not be assigned by
him. Executive shall not hypothecate, delegate, encumber, alienate,
transfer, or otherwise dispose of his rights and duties hereunder. The
Company may assign this Agreement without Executive's consent to any
other entity who, in connection with such assignment, acquires all or
substantially all of the Company's assets, or into or with which the
Company is merged or consolidated.
11. WAIVER
The waiver by the Company of a breach by Executive of any provision of
this Agreement shall not be construed as a waiver of any subsequent
breach by Executive.
12. SEVERABILITY
If any clause, phrase, provision, or portion of this Agreement or the
application thereof to any person or circumstance shall be invalid or
unenforceable under any applicable law, such event shall not affect or
render invalid or unenforceable the remainder of this Agreement and
shall not affect the application of any clause, provision, or portion
hereof to other persons or circumstances.
<PAGE> 8
13. DISPUTES
Each of the parties hereto hereby irrevocably agrees that any legal
action or proceeding arising out of this Agreement shall be brought only
in the state or federal courts located in the state of Texas. Each party
hereto hereby irrevocably consents to the service or process outside the
territorial jurisdiction of such courts in any such action or proceeding
by the mailing of such documents by registered United States mail,
postage prepaid, if to the Company to the address of its principal place
of business and if to Executive to the address listed in the Company's
books and records.
14. RELEVANT LAW
This Agreement shall be construed by, subject to, and governed in
accordance with the internal laws of the State of Texas.
15. NOTICES
All notices, requests, demands, and other communications in connection
with this Agreement shall be made in writing and shall be deemed to have
been given when delivered by hand or 48 hours after mailing at any
general or branch United States post office by registered or certified
mail, postage prepaid, addressed as follows, or to such other address as
shall have been designated in writing by the addressee:
a. If to the Company:
Contour Energy Co.
Suite 1100
601 Jefferson Street
Houston, Texas 77002
Attention: Corporate Secretary
b. If to Executive:
Kenneth R. Sanders
Contour Energy Co.
Suite 1100
601 Jefferson Street
Houston, Texas 77002
<PAGE> 9
16. Entire Agreement
This Agreement sets forth the entire understanding of the parties and
supersedes all prior agreements, arrangements, and communications,
whether oral or written, and this Agreement shall not be modified or
amended except by written agreement of the Company and Executive.
IN WITNESS WHEREOF, the parties hereto have executed this Agreement on
the date first set forth above.
COMPANY:
CONTOUR ENERGY CO.
By /s/ JOHN F. BOOKOUT
------------------------------------------
John F. Bookout
President and Chief Executive Officer
EXECUTIVE:
--------------------------------------------
<PAGE> 1
EXHIBIT 23.1
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos.
33-90932, 333-3132, and 333-51753 on Form S-8 of our report dated March 23,
2000, appearing in the Annual Report on Form 10-K of Contour Energy Co. for the
year ended December 31, 1999.
DELOITTE & TOUCHE LLP
Houston, Texas
April 3, 2000
<PAGE> 1
EXHIBIT 23.2
[H.J. GRUY AND ASSOCIATES, INC. LETTERHEAD]
CONSENT OF H.J. GRUY AND ASSOCIATES, INC.
We hereby consent to the use of the name H.J. Gruy and Associates, Inc. and of
references to H.J. Gruy and Associates, Inc. and to the inclusion of and
references to our report dated February 8, 2000, prepared for Contour Energy Co.
in the Contour Energy Co. Annual Report on Form 10-K for the year ended
December 31, 1999.
H.J. GRUY AND ASSOCIATES, INC.
/s/ MARILYN WILSON
----------------------------------------
Marilyn Wilson, PE
President and Chief Operating Officer
March 28, 2000
Houston, Texas
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