UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.
For the Transition period ______________ to _______________
Commission File Number 1-12999
DOMAIN ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 76-0526147
(State or Other Jurisdiction of (I.R.S Employer
Incorporation or Organization) Identification No.)
16801 Greenspoint Park Drive, Suite 200 77060
Houston, Texas (Zip Code)
(Address of Principal Executive Offices)
Registrant's Telephone Number, Including Area Code: (281) 618-1800
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE ON WHICH
TITLE OF EACH CLASS REGISTERED
- ----------------------------------------- ------------------------------
Common Stock, Par Value $0.01 Per Share New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or such shorter period that the Registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein and will not be contained, to the best
of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of the Registrant's voting stock held by
non-affiliates on March 18, 1998, based on the closing price on the New York
Stock Exchange composite tape on such date of $12 7/8, was $89,635,377.
As of March 18, 1998, there were 15,107,719 shares of Common Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's definitive proxy statement relating to the 1998
Annual Meeting of Stockholders to be held on May 12, 1998, which will be filed
with the Securities and Exchange Commission within 120 days after December 31,
1997, are incorporated by reference in Part III of this form.
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DOMAIN ENERGY CORPORATION
Table of Contents
<TABLE>
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PAGE
PART I
<S> <C> <C>
Items 1. and 2. Business and Properties ................................................ 1
Item 3. Legal Proceedings ...................................................... 18
Item 4. Submission of Matters to a Vote of Security Holders .................... 19
Executive Officers of the Registrant ................................... 19
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters .. 20
Item 6. Selected Financial Data ................................................ 21
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations ......................................... 22
Item 8. Financial Statements and Supplementary Data ............................ 34
Item 9. Changes in and Disagreements with Accountants and Financial Disclosure 57
PART III
Item 10. Directors and Executive Officers of the Registrant ..................... 58
Item 11. Executive Compensation ................................................. 58
Item 12. Security Ownership of Certain Beneficial Owners and Management ......... 58
Item 13. Certain Relationships and Related Transactions ......................... 58
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K ........ 59
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PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
GENERAL DEVELOPMENT OF BUSINESS
Domain Energy Corporation ("Domain" or the "Company") is an independent
oil and gas company engaged in the exploration, development, production and
acquisition of oil and natural gas properties. The Company's operations are
concentrated principally in the Gulf of Mexico and Gulf Coast regions. The
Company complements these activities with its Independent Producer Finance
Program (the "IPF Program") pursuant to which it invests in oil and natural gas
reserves through the acquisition of term overriding royalty interests. Certain
terms relating to the oil and gas business are defined in the "Glossary" section
of this report. During 1997, approximately 91% of the Company's revenue was
generated by oil and natural gas sales and approximately 9% of the Company's
revenue was generated by the IPF Program. The Company's future growth will be
driven by development, exploitation drilling on its existing properties, by an
active exploration program, by the continuation of an opportunistic acquisition
strategy in the Gulf of Mexico and Gulf Coast regions and by further expansion
of the IPF Program.
The Company was formed in December 1996 and incorporated in the state of
Delaware by the management of Tenneco Ventures Corporation and an affiliate of
First Reserve Corporation to acquire (the "Acquisition") Tenneco Ventures
Corporation and certain of its affiliates (collectively, "Tenneco Ventures").
Senior management of the Company established Tenneco Ventures in 1992 as a
separate business unit of its former parent, Tenneco Inc. ("Tenneco"), to engage
in exploration and production, oil and gas program management, producer
financing and related activities. The majority of the Company's executive
officers, including the CEO, are veterans of the Tenneco organization.
In June 1997 the Company completed an initial public offering of its
Common Stock (the "IPO"), generating net proceeds of $87.8 million, $28.7
million of which were used to fund an acquisition (the "Funds Acquisition") of
oil and gas property interests from the participants in two investment programs
formerly managed by the Company and $56.1 million of which was used to repay a
substantial portion of the bank debt incurred to finance the Acquisition.
GEOGRAPHIC FOCUS. The Company concentrates its primary oil and gas
activities in the Gulf Coast region, specifically in state and federal waters
off the coasts of Texas and Louisiana. The Company believes this region is
attractive for future development, exploration and acquisition activities due to
the availability of seismic data, significant reserve potential and a well
developed infrastructure. The Company's relationships with major oil companies
and independent producers operating in the region allow continued access to new
opportunities. This geographic focus has enabled the Company to build and
utilize a base of region-specific geological, geophysical, engineering and
production expertise. The Company's geographic focus allows it to manage its
asset base with relatively few employees, thus permitting the Company to control
expenses and add Gulf Coast production at a relatively low incremental cost. The
Company engages in IPF Program activities throughout the producing regions of
the United States, with a principal geographic focus in the Gulf Coast region.
ACQUISITION OF PROPERTIES WITH UNDEREXPLOITED VALUE. The Company employs
an acquisition strategy targeted primarily at purchases of Gulf Coast region
producing properties from major oil companies and large independents. These
properties provide opportunities to increase reserves, production and cash flow
through development and exploitation drilling and lease operating expense
reduction. The Company manages its acquired properties by working proactively
with its joint interest partners to accelerate development, identify
exploitation opportunities and implement cost controls on these properties.
DEVELOPMENT, EXPLOITATION AND EXPLORATION. The Company's ability to
integrate geophysics with detailed geology, reservoir engineering and production
engineering allows it to identify multiple development and exploratory prospects
in mature producing fields that were not identifiable through earlier
technologies. The Company currently employs 12 geoscientists with an average
experience level of more than 16 years and operates eight geophysical
workstations interpreting 3-D seismic data over 13 fields and five exploratory
programs.
The Company has assembled a multiyear inventory of development,
exploitation and exploratory drilling opportunities in the Gulf Coast region and
has identified more than 72 drilling and recompletion opportunities for 1998.
Many of the properties comprising this inventory are located in fields that have
well-established production histories. The Company believes these properties may
yield significant additional recoverable reserves through the application of
advanced exploration
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and development technologies. The Company participated in the drilling of 11
development wells and 28 exploratory wells in 1997, of which 91% and 61%,
respectively, were successful.
CONTINUED EXPANSION OF THE IPF PROGRAM. The Company has leveraged its
expertise in oil and gas reserve appraisal and evaluation to develop and grow
the IPF Program. The Company believes this program offers an attractive
risk/reward balance and stable earnings. The oil and gas companies that
establish a relationship with the Company through the IPF Program often come to
view the Company as a prospective working interest partner for their drilling or
acquisition projects. Management believes that the investment opportunities,
market information and business relationships generated as a result of the IPF
Program provide the Company with a strategic advantage over other independent
oil and gas companies that are not engaged in this business. As a result of the
Company's efficiency in originating and closing IPF Program transactions in the
$0.5 to $5.0 million range, the Company currently encounters only limited
competition from alternate sources of capital for investment in quality
properties and projects of independent oil and gas companies.
OIL AND GAS ASSETS. As of December 31, 1997, the Company had proved
reserves of approximately 173.0 Bcfe, and its average daily production during
1997 was 54.3 MMcfe. Approximately 61% of these reserves were natural gas, and
approximately 44% of proved reserves were classified as proved developed
producing. As of December 31, 1997, the Company had a PV-10 Reserve Value of
$148.8 million, which does not include reserve value attributable to the IPF
program. As of December 31, 1997, the Company had transactions outstanding under
the IPF Program of $49.8 million. The Company incurred capital expenditures of
$131.3 million in 1997, including $40.2 million for investments in the IPF
Program.
CERTAIN TRANSACTIONS
MICHIGAN DISPOSITION. On April 9, 1997, the Company sold its interests
in a natural gas development project located in northwestern Michigan (the
"Michigan Development Project"). The Company views this transaction (the
"Michigan Disposition") as a disposition of non-core assets and a further
enhancement of its focus in the Gulf Coast region. The Company received $7.6
million in cash for its interest in the assets, net of debt repayment.
The Company retained its interests in Oceana Exploration Company, L.C.,
a Michigan exploration company. See "Business and Properties -- Exploration --
Michigan."
FUNDS ACQUISITION. On July 1, 1997, the Company consummated the
acquisition ( the "Funds Acquisition") of certain property interests from three
unaffiliated institutional investors ("Funds"). Such interests are primarily
located in the Gulf Coast region and, as of January 1, 1997, had combined proved
reserves of approximately 33.0 Bcfe. The interests also include 18,209 net
undeveloped leasehold acres. The aggregate purchase price for the interests was
approximately $28.4 million, which was paid in cash with a portion of the net
proceeds of the initial public offering of the Company's common stock
consummated on June 27, 1997. Upon completion of the Funds Acquisition, the
Company is no longer active in gas program management and has no current plans
to participate in this activity in the future.
MOBILE BAY BLOCK 864 ACQUISITION. On November 13, 1997, the Company paid
approximately $11.8 million to acquire an additional interest in the Mobile Bay
Block 864 Unit, increasing its 11.85% working interest position to 33.59%.
Located in shallow reservoirs off the Alabama coast, the field includes four
natural gas wells and an offshore production platform producing 32 MMcf of
natural gas per day.
ARGENTINA. In November 1997, the Company formed Domain Argentina S.A. to
explore for and acquire oil and natural gas reserves in Argentina. The Company
owns a 50% interest in Domain Argentina S.A., which is currently evaluating both
exploration and producing acreage for potential investment.
THE GULFSTAR ACQUISITION. On December 15, 1997, the Company acquired all
the outstanding capital stock of Gulfstar Energy, Inc. ("Gulfstar") and Mid Gulf
Drilling Corp. ("Mid Gulf"), together, the "Gulfstar Acquisition". The aggregate
purchase price of the companies was $16.6 million comprised of $8.6 million in
cash and 499,990 shares of the Company's common stock valued at $16.00 per
share. The acquisition includes a 3-D seismic database covering approximately
700 federal lease blocks in the shallow waters of the Gulf of Mexico. In
addition, the acquisition added net production of 5 MMcf of natural gas per day
to Domain's production base.
THE OAKVALE ACQUISITION. On February 26, 1998, the Company acquired the
Oakvale Field from Pioneer Natural Resources USA Inc. for an aggregate purchase
price of $11.5 million. The field is comprised of five producing wells with
working interests ranging from 46% to 61% and is located in Jefferson Davis
County, Mississippi, approximately 100 miles
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north of New Orleans. Production from the five producing wells is 2.6 MMcf of
natural gas per day, net to the Company's interest.
PRODUCER INVESTMENT ACTIVITIES
The Company complements its exploration and production activities with
its IPF Program through which it invests in oil and natural gas reserves through
the acquisition of term overriding royalty interests. The IPF Program was
established in 1993 and is funded by a combination of equity provided by the
Company, cash flows generated by the IPF investments and funds borrowed under
the IPF Credit Facility. The IPF Program enables independent producers to obtain
nonrecourse financing through the sale to the Company of term overriding royalty
interests. Transaction sizes for the program generally have ranged from $0.5
million to $5.0 million. From inception through December 31, 1997, the Company
completed 60 transactions under the IPF Program. The Company's reserve estimates
and reserve value shown throughout this report on Form 10-K does not include
that attributable to the IPF Program. As of December 31, 1997, the Company
estimates that the PV-10 Reserve Value attributable to the IPF Program assets
was $61.8 million with approximately 30 Bcfe of oil and gas reserves.
THE GASFUND. In May 1993, Ventures Corporation and EnCap Ventures 1993
Limited Partnership ("EnCap") finalized a partnership arrangement named the
GasFund ("GasFund"). The GasFund was a financing vehicle that utilized bank debt
supported by limited Company and EnCap credit enhancements, which provided
production-based financing to independent producers for oil and gas projects
generally exceeding $10.0 million. Revenues from IPF Activities reported
elsewhere in this report on Form 10-K for the years 1996 and 1995 include the
GasFund activities.
Currently, there are no existing obligations and no outstanding
transactions associated with the GasFund. As a result of the Company's
assessment that the market to provide financing in amounts greater than $10.0
million is competitive to the point of unattractive returns, and the reduced
credit enhancement capabilities of the Company as a result of the Acquisition,
the Company does not anticipate participating in any future GasFund
transactions.
PRODUCING PROPERTIES AND EXPLOITATION OF ASSETS
The following table sets forth the net proved reserves and average daily
production attributable to the Company's significant producing properties as of
December 31, 1997: The reserve data set forth below does not include reserves
attributable to the IPF Program.
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DECEMBER 31, 1997 1997
RESERVES AVERAGE PRODUCTION
------------------------------- --------------------------------
GAS LIQUIDS TOTAL GAS LIQUIDS TOTAL
(MMCF) (MBBL) (MMCFE) (MCFD) (BBLD) (MCFED)
---------- --------- ---------- --------- --------- -----------
OFFSHORE FIELDS
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West Delta 30 ............... 10,544.3 2,338.0 24,572.5 1,044.3 578.1 4,512.9
Matagorda Island 519 ........ 20,391.0 30.3 20,573.0 7,012.2 12.6 7,087.8
Mobile Bay 864 .............. 13,604.0 -- 13,604.0 2,147.8 -- 2,147.8
Vermilion 329 ............... 7,575.1 -- 7,575.1 1,057.2 -- 1,057.2
West Cameron 206 ............ 7,157.4 42.9 7,415.0 485.2 3.9 508.6
Other ....................... 28,744.0 140.4 29,585.7 17,913.0 324.7 19,861.2
ONSHORE FIELDS
Wasson ...................... -- 7,927.4 47,564.4 530.9 533.8 3,733.7
Michigan .................... 6,375.8 511.4 9,444.2 -- -- --
Other ....................... 10,556.3 359.8 12,715.3 13,459.9 317.9 15,367.3
---------- --------- ---------- --------- --------- -----------
Total 104,947.9 11,350.2 173,049.2 43,650.5 1,771.0 54,276.5
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WEST DELTA 30. The West Delta 30 Field is located offshore Louisiana,
approximately 65 miles south-southeast of New Orleans, in approximately 50 feet
of water. The field was discovered in 1954 and has had over 200 wells drilled.
Effective January 1, 1995, the Company acquired 70% of Shell's working interests
in this field, which ranged from 50% to 100%. The field currently produces 21.4
MMcf of natural gas per day and 1,327 Bbls of oil per day (4.7 MMcf and 877 Bbls
net to the Company's interest). Seneca Resources Corporation and Exxon Company,
U.S.A are the operators of the field. During 1997, based on the Company's
proposal and technical review, a successful development well and a successful
exploration well were drilled. To date, the first completion in the development
well has produced in excess of 1.5 Bcf of
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natural gas. The first recompletion of this well is being evaluated and is
expected to occur in the first half of 1998. The exploration well was placed on
production in February 1998 and is expected to reach a production rate of
approximately 20 MMcfd of natural gas. One additional development well is
currently drilling with another development well scheduled in 1998.
MATAGORDA ISLAND 519. The Matagorda Island 519 Field is located offshore
Texas, approximately 12 miles southeast of Matagorda County, in approximately 69
feet of water. The Company owns a 15.8% working interest in the unitized acreage
and a 25% working interest in the non-unitized acreage in this field which is
operated by Amoco Production Company. This field is currently producing 60.5
MMcf of natural gas per day and 91 Bbls of oil per day from three wells (7.9
MMcf and 12 Bbls net to the Company's interest). The Company and the operator
are evaluating the drilling of a new well and a sidetrack of an idle well in an
effort to access new reserves. Additionally, the Company acquired a 3-D seismic
survey of this field in 1997.
MOBILE BAY 864. The Mobile Bay 864 Field is located 42 miles southwest
of Mobile, Alabama. The field is in 60 feet of water and produces from two four
pile structures and two free standing conductors. The Company acquired an 11.85%
working interest from British Gas Exploration of America in 1993. On November
13, 1997, the Company acquired an additional interest in the Mobile Bay Block
864 Unit, increasing its working interest position to 33.59%. The field is
currently producing 29.7 MMcf of natural gas per day (8.3 MMcf net to the
Company's interest). In 1998, the working interest owners expect to implement
modifications to the compression system to maximize recovery and complete an
evaluation for an acceleration well to boost production rates.
VERMILION 329. The Vermilion 329 Field is located 122 miles southeast of
Cameron, Louisiana. The field is in 220 feet of water and produces from one
four-pile structure. The Company acquired a 48% working interest from Marathon
Oil Company in 1993. The field is currently producing 4.9 MMcf of natural gas
per day (1.8 MMcf net to the Company's interest). In 1998, the Company along
with the operator, Basin Exploration Inc., will be pursuing one drilling
opportunity and possibly one or two recompletions. In addition, the installation
of compression is currently being evaluated.
WEST CAMERON 206. The West Cameron 206 Field is located 36 miles south
of Cameron, Louisiana and is in 50 feet of water. This field is currently
produced from two wells. The first well began production in 1997 and currently
produces at a rate of approximately 25 MMcf of natural gas per day and 200 Bbls
of oil per day. In February 1998, the second well began producing at a rate of
approximately 20 MMcf of natural gas per day and 125 Bbls of oil per day. Net to
the Company's interest, production from these two wells is approximately 6.4
MMcf of natural gas per day and 48 Bbls of oil per day.
WASSON. The Wasson Field (discovered in 1937) is located in Gaines and
Yoakum Counties, Texas, approximately 80 miles northwest of Midland, Texas. In
June 1996 the Company acquired from Kerr-McGee Corporation 34.7% and 0.17%
working interests in the Cornell and Denver Units in this field, respectively.
This field was initially waterflooded in 1965, and a CO2 flood was initiated in
1985 utilizing the water-alternating-gas injection method of enhanced oil
recovery. The Cornell and Denver Units are currently operated by Exxon Company
U.S.A and Altura Energy, Inc. (a joint venture between Shell Offshore Inc. and
Amoco Producing Company), respectively. These two units are currently producing
43,869 Bbls of oil per day (515 Bbls net to the Company's interest). The Company
has identified numerous infill locations for future development. Additionally,
development of an upper gas-bearing zone has been proposed by Altura in the
offsetting unit and, pending Texas Railroad Commission approval, may occur in
1998.
MICHIGAN. Oceana Exploration Company, L.C ("Oceana"), a Texas limited
liability company and 80% owned subsidiary of Domain, drilled two successful
wildcat wells, the Nyman 1-18 and the Rood 1-23 in 1997. The wells tested at
combined rates exceeding 15 MMcf of natural gas per day and 500 Bbls of
condensate per day. Oceana holds a 53.7% working interest in these two wells.
Production is expected to commence from both wells at an initial rate of
approximately 10 MMcf of natural gas per day in the second quarter of 1998 when
a regional pipeline extension is completed. In February 1998, the Company
reached agreement to acquire the remaining 20% of Oceana and expects to close
this transaction in the second quarter of 1998.
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PRODUCTION, PRICES AND OPERATING EXPENSES
The following table sets forth certain production volumes, the average
realized prices and production expenses attributable to the Company's properties
for 1997, 1996 and 1995. Detailed additional information concerning the
Company's oil and gas production activities is contained in the supplemental
financial information included in Note 14 to the Consolidated and Combined
Financial Statements.
YEAR ENDED DECEMBER 31,
SUCCESSOR PREDECESSOR
--------- -----------------
1997 1996 1995
--------- --------- ------
PRODUCTION VOLUMES:
Natural gas (MMcf) ............... 15,932 21,192 18,065
Oil and condensate (MBbls) ....... 646 564 424
Total (MMcfe) .................... 19,811 24,575 20,609
AVERAGE REALIZED PRICES: (1)
Natural gas (per Mcf) ............ $ 2.26 $ 1.97 $ 1.54
Oil and condensate (per Bbl) ..... $ 17.28 $ 18.63 $ 16.76
EXPENSES (PER MCFE):
Lease operating expense (2) ...... $ 0.74 $ 0.42 $ 0.39
Production taxes ................. $ 0.07 $ 0.05 $ 0.03
(1) Reflects the actual realized prices received by the Company, including the
results of the Company's hedging activities. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Other Matters --
Hedging Activities."
(2) Lease operating expense per Mcfe increased to $0.74 in 1997 compared to
$0.42 in 1996, or $0.32. This increase was primarily due to decreased production
volumes ($0.14), increased workover expenses ($0.08) and an increase due to the
Wasson Field acquisition ($0.06).
EXPLORATION
EXPLORATION ASSETS
The Company holds approximately 144,000 net acres located primarily in
its core areas. As of December 31, 1997, this land position included 73,000 net
undeveloped acres. This land position plus the seismic licenses owned by
Gulfstar provide the resource base for the Company's exploration prospects. The
following table summarizes the Company's acreage position as of December 31,
1997:
TOTAL ACREAGE DEVELOPED UNDEVELOPED
-------------------- ACREAGE ACREAGE
AREA (GROSS) (NET) (NET) (NET)
----------- --------- ------------ -----------
Onshore:
Alabama .............. 1,291 349 349 --
Louisiana ............ 57,653 14,125 6,048 8,077
Michigan ............. 15,090 13,601 60 13,541
Mississippi .......... 3,485 808 581 227
New Mexico ........... 26,763 10,999 797 10,202
Texas ................ 80,470 13,837 3,226 10,611
------- ------- ------ ------
Total Onshore ................ 184,752 53,719 11,061 42,658
------- ------- ------ ------
Offshore:
Alabama .............. 23,040 7,407 7,407 --
Louisiana ............ 164,368 61,012 32,431 28,581
Texas ................ 74,795 22,141 20,461 1,680
------- ------- ------ ------
Total Offshore ............... 262,203 90,560 60,299 30,261
------- ------- ------ ------
Total ........................ 446,955 144,279 71,360 72,919
======= ======= ====== ======
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During 1997 the Company participated in 28 exploration wells with 17
completions, for a 61% success rate. In addition to the exploration that the
Company may conduct on its existing properties, the Company intends to continue
participation in exploration activities through various joint venture programs,
including those summarized below.
SHALLOW WATER GULF OF MEXICO. The Company, through its wholly owned
subsidiary Gulfstar, operates a joint venture with a third party utilizing 3-D
seismic data to explore for natural gas and oil in the shallow waters of the
Gulf of Mexico. The seismic data covers 700 contiguous blocks over 5,500 square
miles. Combined with Gulfstar's multi-disciplined technical approach, a large
number of high quality 3-D supported drilling opportunities have been
identified. Gulfstar has used this 3-D database to map prospective geologic
trends by region across the Gulf of Mexico from the High Island Area of offshore
Texas to the South Pelto Area of offshore Louisiana, a distance of 200 miles.
SOUTHERN MISSISSIPPI - JERICHO. The Company owns a 25% working interest
in a 3-D seismic program with a privately-held, independent exploration company.
The exploration program will be targeting the Haynesville carbonate section
across the Wiggins Uplift. Additional objectives exist above the main target, in
the Cotton Valley Formation. The Company has 154,000 gross acres under lease and
expects to shoot 70 square miles of 3-D seismic in 1998. The first exploration
well is scheduled to be drilled in late 1998 or early 1999.
MICHIGAN. Oceana Exploration Company, L.C. ("Oceana"), a Texas limited
liability company and 80% owned subsidiary of Domain, operates this ongoing
exploration play in Oceana County, Michigan. The Company has 11,000 acres under
lease, controlling 25 prospects. The first two of these prospects were drilled
in 1997, each resulting in a discovery that tested a combined gross daily rate
of over 15 MMcf of natural gas and 500 Bbls of condensate. Four additional wells
are planned for 1998. The Company has an average 56% working interest in the two
discoveries and a 60% working interest in the ongoing exploration program. In
February 1998, the Company reached agreement to acquire the remaining 20% of
Oceana and expects to close this transaction in the second quarter.
HISTORICAL RESULTS
Domain's exploration and development drilling activity since 1995 is set
forth in the following table:
YEAR ENDED DECEMBER 31,
-------------------------------------------
1997 1996 1995
--------------- ---------------- -----------
GROSS NET GROSS NET GROSS NET
-------- ------ ------- ------ ------- -----
OFFSHORE DRILLING ACTIVITY:
Development:
Productive ................. 6.00 3.12 5.00 1.50 2.00 0.50
Non-productive ............. 1.00 1.00 -- -- -- --
----- ---- ----- ---- ----- ----
Total .............. 7.00 4.12 5.00 1.50 2.00 0.50
Exploratory:
Productive ................. 2.00 0.45 2.00 0.60 4.00 1.30
Non-productive ............. 2.00 0.59 1.00 0.20 4.00 0.90
----- ---- ----- ---- ----- ----
Total .............. 4.00 1.04 3.00 0.80 8.00 2.20
ONSHORE DRILLING ACTIVITY:
Development:
Productive ................. 4.00 1.27 2.00 0.30 4.00 0.70
Non-productive ............. -- -- 2.00 0.60 1.00 0.10
----- ---- ----- ---- ----- ----
Total .............. 4.00 1.27 4.00 0.90 5.00 0.80
Exploratory:
Productive ................. 15.00 5.12 18.00 2.00 15.00 1.80
Non-productive ............. 9.00 2.57 12.00 1.70 25.00 4.60
----- ---- ----- ---- ----- ----
Total .............. 24.00 7.69 30.00 3.70 40.00 6.40
During 1997, the Company participated in drilling activities on 39 gross
wells. Of the 39 (14.12 net) wells, 27 (9.96 net) are being completed, or have
been completed, as commercial producers, and 12 (4.16 net) were dry holes. The
Company had no wells drilling at December 31, 1997.
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The following table sets forth the number of productive oil and natural
gas wells in which the Company owned an interest as of December 31, 1997:
TOTAL PRODUCTIVE WELLS
----------------------------
GROSS NET
------------- -------------
OFFSHORE
Natural gas ..................................... 81.00 30.00
Oil ............................................. 38.00 17.12
---------- -------------
Total .................................. 119.00 47.12
ONSHORE
Natural gas ..................................... 50.00 11.71
Oil (1) ......................................... 807.00 25.44
---------- -------------
Total .................................. 857.00 37.15
TOTAL OFFSHORE AND ONSHORE
Natural gas ..................................... 131.00 41.70
Oil (1) ......................................... 845.00 42.56
---------- -------------
Total .................................. 976.00 84.26
========== =============
(1) Includes 724 gross wells in the Wasson Field (Denver Unit) in which the
Company holds a 0.17% working interest.
OIL AND NATURAL GAS RESERVES
The following table summarizes the estimates of the Company's historical
net proved reserves as of December 31, 1997, 1996 and 1995, and the present
values attributable to these reserves at such dates. The reserve data and
present values as of December 31, 1995 have been estimated by DeGolyer and
MacNaughton ("D&M") and Netherland, Sewell & Associates, Inc. ("NSA"). The
reserve data and present values as of December 31, 1996 have been estimated by
(i) NSA with respect to the West Delta 30 Field, (ii) by other third-party
petroleum engineers with respect to the Michigan Development Project and (iii)
by D&M with respect to all of the Company's other oil and natural gas
properties. The reserve data and present values as of December 31, 1997 have
been estimated by (i) NSA with respect to the West Delta 30 Field, (ii) by other
third-party petroleum engineers with respect to the West Cameron 206 Field and
(iii) by D&M with respect to all of the Company's other oil and natural gas
properties. See "Producing Properties and Exploitation of Assets". The reserve
data set forth below does not include reserves or reserve value attributable to
the IPF Program. At December 31, 1997, the Company estimates that the PV-10
Reserve Value attributable to IPF Program assets was $61.8 million.
AS OF DECEMBER 31,
-------------------------------
1997(2) 1996(1)(2) 1995(2)
-------------------------------
PROVED RESERVES:
Natural gas (MMcf) .................. 104,948 81,338 82,682
Oil and condensate (MBbl) ........... 11,350 11,380 2,197
Total (MMcfe) ....................... 173,049 149,616 95,865
PROVED DEVELOPED PRODUCING RESERVES:
Natural gas (MMcf) .................. 53,496 36,293 45,386
Oil and condensate (MBbl) (5) ....... 3,840 9,248 1,219
Total (MMcfe) ....................... 76,538 91,781 52,700
PV-10 Reserve Value (in thousands) ............ $148,789 $184,816 $103,931
Standardized measure of discounted future net
cash flows
(after-tax) (in thousands) .................... $127,671 $154,424 $ 98,999
Reserve Life Index (in years) (3) ............. 8.7x 6.0x 4.7x
RESERVE REPLACEMENT DATA:
Finding Costs (per Mcfe) ............ $ 0.94 $ 0.25 $ 1.02
Production replacement ratio (4) .... 365.9% 217.9% 222.8%
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(1) Includes the Company's proportionate share of reserves attributable to the
Michigan Development Project.
(2) The present values as of December 31, 1997 were prepared using a weighted
average WTI sales price of $18.70 per Bbl of oil and a Henry Hub sales price of
$2.55 per MMbtu of natural gas and the present values as of December 31, 1996
and 1995 were prepared using a weighted average WTI sales price of $22.50 and
$18.76 per Bbl of oil and Henry Hub sales prices of $3.38 and $3.30 per MMbtu of
natural gas, respectively. In each case, present values reflect the impact of
hedges in place at the respective dates.
(3) Calculated by dividing year-end proved reserves by annual actual production
for the most recent year.
(4) Equals current period reserve additions through acquisitions of reserves,
extensions and discoveries, and revisions to estimates divided by the production
for such period.
(5) Proved developed producing reserves for oil and condensate decreased to 3.8
million barrels in 1997 compared to 9.2 million barrels in 1996, a decrease of
5.4 million barrels. This decrease was primarily the result of a
reclassification of a portion of the reserves attributable to the Wasson Field
from proved developed to proved undeveloped at year end 1997.
The estimation of reserve data is a subjective process of estimating the
recovery of underground accumulations of oil and natural gas that cannot be
measured in an exact manner, and the accuracy of any reserve estimate is a
function of the quality of the available data, the assumptions made, and
engineering and geological interpretation and judgment. Estimates of
economically recoverable oil and natural gas reserves and future net cash flows
therefrom necessarily depend upon a number of variable factors and assumptions,
including historical production from the area compared with production from
other producing areas, the assumed effects of regulation by governmental
agencies and assumptions concerning future oil and natural gas prices, future
operating costs, severance and excise taxes, development costs and workover and
remedial costs, all of which may in fact vary considerably from actual results.
Any such estimates are therefore inherently imprecise, and estimates by other
engineers, or by the same engineers at a different time, might differ materially
from those included herein. Actual prices, production, development expenditures,
operating expenses and quantities of recoverable oil and natural gas reserves
will vary from those assumed in the estimates and it is likely that such
variances will be significant. Any significant variance from the assumptions
could result in the actual quantity of the Company's reserves and future net
cash flow therefrom being materially different from the estimates set forth in
this report on Form 10-K. In addition, the Company's estimated reserves may be
subject to downward or upward revision, based upon production history, results
of future exploration and development, prevailing oil and natural gas prices,
operating and development costs and other factors.
Estimates with respect to proved undeveloped reserves that may be
developed and produced in the future are often based upon volumetric
calculations and upon analogy to similar types of reserves rather than actual
production history. Estimates based on these methods are generally less reliable
than those based on actual production history. Subsequent evaluation of the same
reserves based upon production history will result in variations, which may be
substantial, in the estimated reserves.
The present value of future net cash flows shown above should not be
construed as the current market value, or the market value as of December 31,
1997, or any prior date, of the estimated oil and natural gas reserves
attributable to the Company's properties. In accordance with applicable
requirements of the Commission, the estimated discounted future net cash flows
from estimated proved reserves are based on prices and costs as of the date of
the estimate unless such prices or costs are contractually determined at such
date. Actual future prices and costs may be materially higher or lower. Actual
future net cash flows also will be affected by factors such as actual
production, supply and demand for oil and natural gas, curtailments or increases
in consumption by natural gas purchasers, changes in governmental regulations or
taxation and the impact of inflation on costs.
The Company's PV-10 Reserve Value as of December 31, 1997 was prepared
using a weighted average WTI sales price of $18.70 per Bbl of oil and a Henry
Hub sales price of $2.55 per MMbtu of natural gas. These prices were
substantially lower than prices used by the Company to calculate PV-10 Reserve
Value as of December 31, 1996. The Company estimates that a substantial decline
in prices relative to year-end 1997 would cause a substantial decline in the
Company's PV-10 Reserve Value. For example, a $0.10 per MMbtu decline in natural
gas prices, holding all other variables constant, would decrease the Company's
December 31, 1997 PV-10 Reserve Value by approximately $7.8 million, or 5.3%,
and a $1.00 per Bbl decline in oil and condensate prices would decrease the
Company's PV-10 Reserve Value by approximately $4.0 million, or 2.7%. While the
foregoing calculations should assist the reader in understanding the effect of a
decline in oil and natural gas prices on the
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Company's PV-10 Reserve Value, such calculations assume that quantities of
recoverable reserves are constant and therefore would not be accurate if prices
decreased to a level at which reserves would no longer be economically
recoverable.
OIL AND GAS MARKETING
The Company sells all of its natural gas production to third parties
based on short-term index prices. The Company marketed volumes averaging 43.6
MMcf per day during 1997. During 1997, natural gas sold to El Paso Energy
Marketing Company ("EPMC") accounted for approximately 57% of the Company's
natural gas production with the remainder sold to various other third parties.
In December 1997, the Company terminated its arrangement with EPMC and entered
into a marketing arrangement with Cokinos Energy Corporation ("Cokinos") to
purchase those gas volumes previously bought by EPMC.
Natural gas sales averaged 43.6 MMcf per day in 1997 down from 58.1 MMcf
per day in 1996. The average sales price for natural gas was $2.51 per Mcf, an
increase of $0.10 per Mcf over 1996, or 4.1 % . This does not take into account
any gains or losses from the Company's hedging activities.
The Company also sells all of its crude oil and condensate production to
third parties. Texon was the largest purchaser of the Company's crude oil and
condensate during 1997, purchasing on average 1,272 MBbls per day, or 76%. Crude
oil and condensate sales averaged 1,676 Bbls per day in 1997. The average prices
realized for crude oil and condensate was $18.52 per Bbl, a decrease of $2.38
per Bbl from 1996, or 11.4%. This does not take into account any gains or losses
from the Company's hedging activities.
With regard to the Company's natural gas liquids ("NGLs"), NGL sales
averaged 95 Bbls per day during 1997. In 1997, all of the Company's NGLs were
purchased by various third parties. The average price realized for NGLs was
$18.09 per Bbl, an increase of $1.67 per Bbl over 1996, or 10.2%.
RISK MANAGEMENT
From time to time, the Company uses various hedging arrangements,
predominately financial instruments, such as swaps, futures, options and collars
to manage its commodity price risk. However, to the extent that the Company has
an open position, the Company may be exposed to risk from fluctuating market
prices. For additional information relating to risk management, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Other Matters -- Hedging Activities."
COMPETITION
The Company encounters competition from other companies in all areas of
its operations, including the acquisition of producing properties and its IPF
Program. The Company's competitors include major integrated oil and gas
companies and numerous independent oil and gas companies, individuals and
drilling and income programs and, in the case of its IPF Program, affiliates of
investment, commercial and merchant banking firms and affiliates of large
interstate pipeline companies. Many of its competitors are large,
well-established companies with substantially larger operating staffs and
greater capital resources than the Company's and which, in many instances, have
been engaged in the oil and gas business for a much longer time than the
Company. Such companies may be able to pay more for productive natural gas and
oil properties and exploratory prospects and to define, evaluate, bid for and
purchase a greater number of properties and prospects than the Company's
financial or human resources permit. The Company's ability to acquire additional
properties and to discover reserves in the future, and to grow its IPF Program,
will be dependent upon its ability to evaluate and select suitable properties
and to consummate transactions in this highly competitive environment.
SEASONALITY
Historically, demand for natural gas has been seasonal in nature, with
peak demand and typically higher prices occurring during the colder winter
months.
REGULATION
The availability of a ready market for oil and natural gas production
depends upon numerous factors beyond the Company's control. These factors
include regulation of oil and natural gas production, federal, state and local
laws and
9
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regulations governing environmental quality and pollution control, state limits
on allowable rates of production by a well or proration unit, the supply of oil
and natural gas available for sale, the availability of adequate pipeline and
other transportation and processing facilities and the marketing of competitive
fuels. For example, a productive natural gas well may be "shut-in" because of an
oversupply of natural gas or the lack of an available natural gas pipeline in
the areas in which the Company conducts its operations. Federal, state and local
laws and regulations generally are intended to prevent waste of oil and natural
gas, protect rights to produce oil and natural gas between owners in a common
reservoir, control the amount of oil and natural gas produced by assigning
allowable rates of production and control contamination of the environment.
REGULATION OF OIL AND NATURAL GAS EXPLORATION AND PRODUCTION. The
Company's exploration and production operations are subject to various types of
regulation at the federal, state and local levels. Such regulation includes
requiring permits for the drilling of wells, maintaining bonding requirements in
order to drill or operate wells, and regulating the location of wells, the
method of drilling and casing wells, the surface use and restoration of
properties upon which wells are drilling and the plugging and abandonment of
wells. The Company's operations are also subject to various conservation laws
and regulations. These include the regulation of the size of drilling and
spacing units or proration units and the density of wells that may be drilled
and unitization or pooling of oil and gas properties. In this regard, some
states allow the forced pooling or integration of tracts to facilitate
exploration while other states rely on voluntary pooling of lands and leases. In
addition, state conservation laws establish maximum rates of production from oil
and natural gas wells, generally prohibit the venting or flaring of natural gas
and impose certain requirements regarding the ratability of production. The
effect of these regulations is to limit the amounts of oil and natural gas the
Company's operator or the Company can produce from its wells, and to limit the
number of wells the Company can drill or the locations thereof. In addition,
numerous departments and agencies, both federal and state, are authorized by
statute to issue rules and regulations binding on the oil and gas industry and
its individual members, some of which carry substantial penalties for failure to
comply. The regulatory burden on the oil and gas industry increases the
Company's cost of doing business and, consequently, affects its profitability.
Inasmuch as such laws and regulations are frequently expanded, amended or
reinterpreted, the Company is unable to predict the future cost or impact of
complying with such regulations.
NATURAL GAS MARKETING AND TRANSPORTATION. Federal legislation and
regulatory controls in the United States have historically affected the price of
the natural gas produced by the Company and the manner in which such production
is marketed. The transportation and sale or resale of natural gas in interstate
commerce is regulated pursuant to the Natural Gas Act of 1938 (the "NGA"), the
Natural Gas Policy Act of 1978 (the "NGPA"), the Outer Continental Shelf Lands
Act (the "OCSLA") and the Federal Energy Regulatory Commission (the "FERC").
Although maximum selling prices of natural gas were regulated in the past, on
July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 ("Decontrol Act")
was enacted, which amended the NGPA to remove completely by January 1, 1993
price and nonprice controls for all "first sales" of domestic natural gas, which
include all sales by the Company of its production; consequently, sales of the
Company's natural gas production currently may be made at market prices, subject
to applicable contract provisions. The FERC's jurisdiction over natural gas
transportation was unaffected by the Decontrol Act.
The FERC also has jurisdiction over transportation and gathering of oil
and natural gas in the Outer Continental Shelf ("OCS") under the OCSLA. The FERC
also regulates interstate natural gas transportation rates and service
conditions, which affect the marketing of natural gas produced by the Company,
as well as the revenues received by the Company for sales of such natural gas.
Since the latter part of 1985, the FERC has endeavored to make interstate
natural gas transportation more accessible to natural gas buyers and sellers on
an open and nondiscriminatory basis. The FERC's efforts have significantly
altered the marketing and pricing of natural gas. Commencing in April 1992, the
FERC issued Order Nos. 636, 636-A, 636-B and 636-C (collectively, "Order No.
636"), which, among other things, require interstate pipelines to "restructure"
to provide transportation separate or "unbundled" from the pipelines' sales of
natural gas. Also, Order No. 636 requires pipelines to provide open-access
transportation on a basis that is equal for all natural gas supplies. Order No.
636 has been implemented through negotiated settlements in individual pipeline
service restructuring proceedings. In many instances, the result of the Order
No. 636 and related initiatives has been to reduce substantially or bring to an
end the interstate pipelines' traditional role as wholesalers of natural gas in
favor of providing only storage and transportation services. The FERC has issued
final orders in virtually all pipeline restructuring proceedings, and has now
commenced a series of one year reviews to determine whether refinements are
required regarding individual pipeline implementations of Order No. 636.
Pipeline tariffs are revised from time to time to implement changes in
transportation rates and terms and conditions of sale.
The FERC has issued a statement of policy and a request for comments
concerning alternatives to its traditional cost-of-service rate making
methodology. This policy statement articulates the criteria that the FERC will
use to evaluate proposals to charge market-based rates for the transportation of
natural gas. The policy statement also provides that the FERC will consider
proposals for negotiated rates for individual shippers of natural gas, so long
as a cost-of service-based rate is
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<PAGE>
available as a recourse rate. The FERC also has requested comments on whether it
should allow gas pipelines the flexibility to negotiate the terms and conditions
of transportation service with prospective shippers. The Company cannot predict
what further action the FERC will take on these matters; however, the Company
does not believe that it will be affected by any action taken materially
differently than other natural gas producers and marketers with which it
competes.
The FERC has announced its intention to reexamine certain of its
transportation-related policies, including the manner in which interstate
pipeline shippers may release interstate pipeline capacity under Order No. 636
for resale in the secondary market. While any resulting FERC action would affect
the Company only indirectly, the FERC's current rules and policies may have the
effect of enhancing competition in natural gas markets by, among other things,
encouraging non-producer natural gas marketers to engage in certain purchase and
sale transactions. The Company cannot predict what action the FERC will take on
these matters, nor can it accurately predict whether the FERC's actions will
achieve the goal of increasing competition in markets in which the Company's
natural gas is sold. However, the Company does not believe that it will be
affected by any action taken materially differently than other natural gas
producers and marketers with which it competes.
In May 1995, the FERC issued a policy statement on how interstate gas
pipelines can recover the costs of new pipeline facilities. While this policy
statement affects the Company only indirectly, in its present form the new
policy should enhance competition in natural gas markets and facilitate
construction of gas supply laterals. Requests for rehearing of this policy
statement were denied on April 29, 1996. The Company cannot predict what action
the FERC will take on individual proceedings applying its policy.
Commencing in May 1994, the FERC issued a series of orders in individual
cases that delineate a new gathering policy in light of the interstate pipeline
industry's restructuring under Order No. 636. As a general matter, gathering is
exempt from the FERC's jurisdiction; however, the courts have held that where
the gathering is performed by the interstate pipelines in association with the
pipeline's jurisdictional transportation activities, the FERC retains regulatory
control over the associated gathering services to prevent abuses. Among other
matters, the FERC slightly narrowed its statutory tests for establishing
gathering status and reaffirmed that, except in situations in which the gatherer
acts in concert with an interstate pipeline affiliate to frustrate the FERC's
transportation policies, the FERC does not generally have jurisdiction over
natural gas gathering facilities and services. In the FERC's opinion, such
facilities and services are more properly regulated by state authorities. In
addition, the FERC has approved several transfers proposed by interstate
pipelines of gathering facilities to unregulated independent or affiliated
gathering companies. Certain of the FERC's orders delineating its new gathering
policy recently were the subject of an opinion issued by the United States Court
of Appeals for the District of Columbia Circuit. That opinion generally upheld
the FERC's policy of approving the interstate pipeline's proposed "spindown" of
its gathering facilities to an unregulated affiliate company, but remanded to
the FERC that portion of the FERC's orders imposing so-called "default
contracts" by which the unregulated affiliate was obligated to continue existing
gathering services to customers under "default contracts" for up to two years
after spindown. It remains unclear whether the FERC will attempt to reimpose
such conditions or will otherwise act in response to producer requests for
additional protection against perceived monopolistic action by pipeline-related
gatherers. In addition, in February 1996, the FERC issued a policy statement
that, among other matters, reaffirmed, with some clarifications, its
long-standing test for determining whether particular pipeline facilities
perform a jurisdictional transmission function or nonjurisdictional gathering
function. While changes to the FERC's gathering policy affect the Company only
indirectly, such changes could affect the price and availability of capacity on
certain gathering facilities, and thus access to certain interstate pipelines,
which, in turn, could affect the price of gas at the wellhead and in markets in
which the Company competes. However, the Company does not believe that it will
be affected by these changes to the FERC's gathering policy materially
differently than other natural gas producers with which it competes.
Proposals and proceedings that might affect the natural gas industry are
considered from time to time by Congress, the FERC, state regulatory bodies and
the courts. The Company cannot predict when or if any such proposals might
become effective, or their effect, if any, on the Company's operations. The
natural gas industry historically has been very heavily regulated; therefore,
there is no assurance that the less stringent regulatory approach recently
pursued by the FERC and Congress will continue indefinitely into the future.
FEDERAL OFFSHORE LEASING. Certain of the Company's operations are
conducted on federal oil and gas leases administered by the Minerals Management
Service ("MMS"). The MMS issues such leases through competitive bidding. These
leases contain relatively standardized terms and require compliance with
detailed MMS regulations and orders pursuant to the OCSLA (which are subject to
change by the MMS). For offshore operations, lessees must obtain MMS approval
for exploration plans and development and production plans prior to the
commencement of such operations. In addition to permits required from other
agencies (such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency), lessees must obtain a permit from the MMS
prior to the commencement of drilling. The MMS has promulgated
11
<PAGE>
regulations requiring offshore production facilities located on the OCS to meet
stringent engineering and construction specifications. The MMS also has issued
regulations restricting the flaring or venting of natural gas and prohibiting
the flaring of liquid hydrocarbons and oil without prior authorization.
Similarly, the MMS has promulgated other regulations governing the plugging and
abandonment of wells located offshore and the removal of all production
facilities. To cover the various obligations of lessees on the OCS, the MMS
generally requires that lessees post substantial bonds or other acceptable
assurances that such obligations will be met. The cost of such bonds or other
security can be substantial and there is no assurance that the Company can
obtain bonds or other security in all cases. See " -- Environmental Matters."
The MMS issued a notice of proposed rulemaking in which it proposed to
amend its regulations governing the calculation of royalties and the valuation
of crude oil produced from federal leases. The proposed rule would modify the
valuation procedures for both arm's length and non-arm's length crude oil
transactions to decrease reliance on posted prices and assign a value to crude
oil that better reflects market value, establish a new MMS form for collecting
value differential data, and amend the valuation procedure for the sale of
federal royalty oil. The Company cannot predict at this stage of the rulemaking
proceeding how it might be affected by this amendment to the MMS regulations.
In April 1997, after two years of study, the MMS withdrew proposed
changes to the way it values natural gas for royalty payments. These proposed
changes would have established an alternative market-based method to calculate
royalties on certain natural gas sold to affiliates or pursuant to non-arm's
length sales contracts.
The OCSLA requires that all pipelines operating on or across the OCS
provide open-access, non-discriminatory service. Although the FERC has opted not
to impose the regulations of Order No. 509, which implements these requirements
of the OCSLA, on gatherers and other non-jurisdictional entities, the FERC has
retained the authority to exercise jurisdiction over those entities if necessary
to permit non-discriminatory access to services on the OCS. If the FERC were to
apply Order No. 509 to gatherers in the OCS, eliminate the exemption of
gathering lines, and redefine its jurisdiction over gathering lines, the result
would be a reduction in available pipeline space for existing shippers in the
Gulf of Mexico and elsewhere.
OIL SALES AND TRANSPORTATION RATES. Sales of crude oil, condensate and
gas liquids by the Company are not regulated and are made at market prices. The
price the Company receives from the sale of these products is affected by the
cost of transporting the products to market. Effective as of January 1, 1995,
the FERC implemented regulations establishing an indexing system for
transportation rates for oil pipelines, which, subject to certain conditions and
limitations, would generally index such rates to inflation. The Company is not
able to predict with certainty what effect, if any, these regulations will have
on it, but other factors being equal, under certain conditions the regulations
may cause increased transportation costs and may reduce wellhead prices for such
commodities.
ENVIRONMENTAL MATTERS
The Company's operations are subject to federal, state and local laws
and regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. These laws and regulations may
require the acquisition of a permit before drilling commences, restrict the
types, quantities and concentration of various substances that can be released
into the environment in connection with drilling and production activities,
limit or prohibit drilling activities on certain lands lying within wilderness,
wetlands and other protected areas, require remedial measures to prevent
pollution from former operations, such as pit closure and plugging abandoned
wells, and impose substantial liabilities for pollution resulting from the
Company's operations. In addition, these laws, rules and regulations may
restrict the rate of oil and natural gas production below the rate that would
otherwise exist. The regulatory burden on the oil and gas industry increases the
cost of doing business and consequently affects its profitability. Changes in
environmental laws and regulations occur frequently, and any changes that result
in more stringent and costly waste handling, disposal and clean-up requirements
could have a significant impact on the operating costs of the Company, as well
as the oil and gas industry in general. Management believes that the Company is
in substantial compliance with current applicable environmental laws and
regulations and that continued compliance with existing requirements will not
have a material adverse effect on the Company.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
who are considered to be responsible for the release of a "hazardous substance"
into the environment. These persons include the owner or operator of the
disposal site or sites where the release occurred and companies that disposed or
arranged for the disposal of the hazardous substances. Under CERCLA, such
persons may be subject to joint and several liability for the costs of cleaning
up the hazardous substances that have been released into the environment
(including pre-remedial investigations and post-remedial monitoring), for
damages to natural resources. In some instances, neighboring landowners and
other third
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<PAGE>
parties file claims based on common law theories of tort liability for personal
injury and property damage allegedly caused by the release of hazardous
substances at a CERCLA site.
The Company generates wastes, including hazardous wastes, that are
subject to the federal Resource Conservation and Recovery Act ("RCRA") and
comparable state statutes. The EPA and various state agencies have limited the
disposal options for certain hazardous and nonhazardous wastes. Furthermore,
certain wastes generated by the Company's oil and natural gas operations that
are currently exempt from treatment as "hazardous wastes" may in the future be
designated as "hazardous wastes," and therefore be subject to more rigorous and
costly operating and disposal requirements.
The Company currently owns or leases, and has in the past owned or
leased, numerous properties that for many years have been used for the
exploration and production of oil and gas. Although the Company has utilized
operating and disposal practices that were standard in the industry at the time,
hydrocarbons or other wastes may have been disposed of or released on or under
the properties owned or leased by the Company or on or under other locations
where such wastes have been taken for disposal. In addition, many of these
properties have been operated by third parties whose treatment and disposal or
release of hydrocarbons or other wastes was not under the Company's control.
These properties and the 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) or property contamination (including
groundwater contamination) or to perform remedial plugging operations to prevent
future contamination.
The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder
impose a variety of requirements on "responsible parties" related to the
prevention of oil spills and liability for damages resulting from such spills in
"waters of the United States." A "responsible party" includes the owner or
operator of a facility or vessel, or the lessee or permittee of the area in
which an offshore facility is located. The term "waters of the United States"
has been broadly defined to include not only the waters of the Gulf of Mexico
but also inland waterbodies, including wetlands, playa lakes and intermittent
streams. A 1996 amendment to the OPA also requires owners and operators of
"offshore facilities" (including those located in coastal inland waters, such as
bays or estuaries) to establish $35.0 million in financial responsibility to
cover environmental cleanup and restoration costs likely to be incurred in
connection with an oil spill. Offshore facilities are facilities used for
exploring for, drilling for or producing oil or transporting oil from facilities
engaged in oil exploration, drilling or production. If it is determined that an
increase in the amount of financial responsibility required is warranted, the
President has the authority to raise such to an amount not exceeding $150.0
million. In any event, the impact of any adjustment to the annual required
financial responsibility is not expected to be any more burdensome to the
Company than it will be to other similarly situated companies involved in oil
and gas exploration and production.
OPA imposes a variety of additional requirements on responsible parties
for vessels or oil and gas facilities related to the prevention of oil spills
and liability for damages resulting from such spills in waters of the United
States. OPA assigns liability to each responsible party for oil spill removal
costs and a variety of public and private damages from oil spills. OPA
establishes a liability limit for offshore facilities of all removal costs plus
$75.0 million. A party cannot take advantage of liability limits if the spill is
caused by gross negligence or willful misconduct or resulted from violation of a
federal safety, construction or operating regulation. If a party fails to report
a spill or to cooperate fully in the cleanup, liability limits likewise do not
apply. Few defenses exist to the liability for oil spills imposed by OPA. OPA
also imposes other requirements on facility operators, such as the preparation
of an oil spill contingency plan. Failure to comply with ongoing requirements or
inadequate cooperation in a spill event may subject a responsible party to civil
or criminal enforcement actions. As of the date hereof, the Company is not the
subject of any civil or criminal enforcement actions under the OPA and is in
substantial compliance with the requirements of the OPA.
In addition, the OCSLA authorizes regulations relating to safety and
environmental protection applicable to lessees and permittees operating in the
OCS. Specific design and operational standards may apply to OCS vessels, rigs,
platforms, vehicles and structures. Violations of lease conditions or
regulations issued pursuant to OCSLA can result in substantial civil and
criminal penalties, as well as potential court injunctions curtailing operations
and the cancellation of leases. Such enforcement liabilities can result from
either governmental or private prosecution. As of the date hereof, the Company
is not the subject of any civil or criminal enforcement actions under the OCSLA
and is in substantial compliance with the requirements under the OCSLA.
The Clean Water Act ("CWA") imposes restrictions and strict controls
regarding the discharge of produced waters and other oil and gas wastes into
navigable waters. Permits must be obtained to discharge pollutants into state
and federal waters. The CWA provides for civil, criminal and administrative
penalties for any unauthorized discharges of oil and other
13
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hazardous substances in reportable quantities and, along with the OPA, imposes
substantial potential liability for the costs of removal, remediation and
damages. State laws for the control of water pollution also provide civil,
criminal and administrative penalties and liabilities in the case of a discharge
of petroleum or its derivatives into state waters. The U.S. Environmental
Protection Agency ("EPA") issued general permits prohibiting the discharge of
produced water and produced sand derived from oil and gas point source
facilities into coastal waters in Louisiana and Texas, which became effective as
of January 1, 1997. Although the costs of compliance with zero discharge
mandates under federal or state law may be significant, the entire industry will
experience similar costs and the Company believes that these costs will not have
a material adverse effect on the Company's financial condition and operations.
Certain oil and gas exploration and production facilities are required to obtain
permits for their storm water discharges and costs may be associated with
treatment of wastewater, or developing storm water pollution prevention plans.
In addition, the Coastal Zone Management Act authorizes state implementation and
development of management measures for nonpoint source pollution designed to
restore and protect coastal waters.
EMPLOYEES
On December 31, 1997, the Company employed 52 full-time employees and 10
full-time contractors. The Company believes that its relationships with its
employees are good. None of the Company's employees are covered by a collective
bargaining agreement.
OFFICES
The Company currently leases approximately 29,000 square feet of office
space in Houston, Texas, where its principal office is located and an additional
9,400 square feet of office space in Houston, Texas, where Gulfstar is located.
The Gulfstar lease will expire on May 31, 1998 and staff currently located there
will relocate to the Company's principal office.
14
<PAGE>
CAUTIONARY STATEMENT FOR PURPOSES OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Domain desires to take advantage of the "safe harbor" provisions
contained in Section 27A of the Securities Act of 1933, as amended (the "1933
Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the
"1934 Act"), and is including this statement herein in order to do so.
From time to time, the Company's management or persons acting on the
Company's behalf may wish to make, either orally or in writing, forward-looking
statements (which may come within the meaning of Section 27A of the 1933 Act and
Section 21E of the 1934 Act), to inform existing and potential security holders
regarding various matters including, without limitation, projections regarding
future income, oil and gas production, production and sales volumes of the
Company's products, oil and gas reserves and the replacement thereof, capital
spending, as well as predictions as to the timing and success of specific
projects. Such forward-looking statements are generally accompanied by words
such as "estimate", "project", "predict", "believes", "expect", "anticipate",
"goal" or other words that convey the uncertainty of future events or outcomes.
Forward-looking statements by their nature are subject to certain risks,
uncertainties and assumptions and will be influenced by various factors. Should
one or more of these forecasts or underlying assumptions prove incorrect, actual
results could vary materially. The factors below are believed to be important
factors (but not necessarily all the important factors) that could cause actual
results to differ materially from those expressed in any forward-looking
statement made by or on behalf of the Company. Unpredictable or unknown factors
not discussed herein could also have material adverse effects on actual results
of matters which are the subject of forward-looking statements. The Company does
not intend to update these cautionary statements.
VOLATILITY OF OIL AND NATURAL GAS PRICES; MARKETABILITY OF PRODUCTION
The Company's financial condition, profitability, future rate of growth
and ability to borrow funds or obtain additional capital, as well as the
carrying value of its oil and natural gas properties, are substantially
dependent upon prevailing prices of, and demand for, oil and natural gas. The
energy markets have historically been, and are likely to continue to be,
volatile, and prices for oil and natural gas are subject to large fluctuations
in response to relatively minor changes in the supply and demand for oil and
natural gas, market uncertainty and a variety of additional factors beyond the
control of the Company. These factors include the level of consumer product
demand, weather conditions, the actions of the Organization of Petroleum
Exporting Countries, domestic and foreign governmental regulations, political
stability in the Middle East and other petroleum producing areas, the foreign
and domestic supply of oil and natural gas, the price of foreign imports, the
price and availability of alternative fuels and overall economic conditions. A
substantial or extended decline in oil or natural gas prices could have a
material adverse effect on the Company's financial position, results of
operations, quantities of oil and natural gas reserves that may be economically
produced, carrying value of its proved reserves, borrowing capacity and access
to capital. In addition, the marketability of the Company's production depends
upon a number of factors beyond the Company's control, including the
availability and capacity of transportation and processing facilities, the
effect of federal and state regulation of oil and natural gas production and
transportation, changes in supply due to drilling by other producers and changes
in demand. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations."
RISK OF HEDGING ACTIVITIES
The Company's use of energy swap arrangements to reduce its sensitivity
to oil and natural gas price volatility is subject to a number of risks. If the
Company's reserves are not produced at the rates estimated by the Company due to
inaccuracies in the reserve estimation process, operational difficulties or
regulatory limitations, or otherwise, the Company would be required to satisfy
its obligations under potentially unfavorable terms. If the Company enters into
financial instrument contracts for the purpose of hedging prices and the
estimated production volumes are less than the amount covered by these
contracts, the Company would be required to mark-to-market these contracts and
recognize any and all losses within the determination period. Further, under
financial instrument contracts the Company may be at risk for basis
differential, which is the difference in the quoted financial price for contract
settlement and the actual physical point of delivery price. The Company will
from time to time attempt to mitigate basis differential risk by entering into
basis swap contracts. Substantial variations between the assumptions and
estimates used by the Company in its hedging activities and actual results
experienced could materially adversely affect the Company's anticipated profit
margins and its ability to manage risk associated with fluctuations in oil and
natural gas prices. Furthermore, the fixed price sales and hedging contracts
limit the benefits the Company will realize if actual prices rise above the
contract prices.
16
<PAGE>
As of December 31, 1997, approximately 30.8% of the Company's projected
1998 oil production and approximately 18.6% of its projected 1998 natural gas
production were committed to hedging contracts. In addition, the Company has
hedges in place covering a portion of its projected oil production through the
year 2000. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Other Matters -- Hedging Activities".
RESERVE REPLACEMENT RISKS
The Company's future performance is dependent upon its ability to
identify, acquire and develop additional oil and natural gas reserves that are
economically recoverable. Without successful drilling or acquisition activities,
the Company's reserves and revenues will decline. No assurances can be given
that the Company will be able to identify, acquire or develop additional
reserves at an acceptable cost.
The successful acquisition of producing properties requires an
assessment of recoverable reserves, future oil and natural gas prices, operating
costs, potential environmental and other liabilities and other factors beyond
the Company's control. This assessment is necessarily inexact and its accuracy
is inherently uncertain. In connection with such an assessment, the Company
typically performs, or retains a third party to perform, a review of the subject
properties, which review the Company believes is generally consistent with
industry practices. This review, however, will not reveal all existing or
potential problems, nor will it permit the Company to become sufficiently
familiar with the properties to assess fully their deficiencies and
capabilities. Inspections may not be performed on every well, and structural and
environmental problems are not necessarily observable even when an inspection is
undertaken. The Company generally assumes preclosing liabilities, including
environmental liabilities, in connection with property acquisitions and
generally acquires interests in the properties on an "as is" basis. With respect
to its acquisitions to date, the Company has no material commitments for capital
expenditures to comply with existing environmental requirements. There can be no
assurance that any properties acquired by the Company will be successfully
developed or produced, and the acquisition of any such properties that are not
successfully developed or produced could have a material adverse effect on the
Company.
Drilling activities are subject to many risks, including the risk that
no commercially productive reservoirs will be encountered. There can be no
assurance that any new wells drilled by the Company will be productive or that
the Company will recover all or any portion of its investment. Drilling for oil
and natural gas may involve unprofitable efforts, not only from dry wells, but
from wells that are productive but do not produce sufficient net revenues to
return a profit after drilling, operating and other costs. The cost of drilling,
completing and operating wells is often uncertain. In addition, the Company's
use of 3-D seismic requires greater pre-drilling expenditures than traditional
drilling strategies. The Company's drilling operations may be curtailed, delayed
or canceled as a result of numerous factors, many of which are beyond the
Company's control, including economic conditions, mechanical problems, title
problems, weather conditions, compliance with governmental requirements and
shortages or delays in the delivery of equipment and services. There can be no
assurances that any of the Company's future drilling activities will be
successful, and unsuccessful drilling activities by the Company may have a
material adverse effect on the Company.
NON-OPERATOR STATUS
The majority of the Company's producing properties are operated by other
industry partners. However, the Company does operate the Mustang Island 846/847
Field, the Main Pass 154 Field, the Chandeleur 37 Field, and the Company's
interests in Michigan. The Company also operates the wells acquired in the
Oakvale Acquisition. On those properties which others operate, the Company has a
limited ability to exercise control over operations or the associated costs of
such operations. The success of the Company's investment in a drilling or
acquisition activity on such properties is therefore dependent upon a number of
factors that are outside of the Company's control, including the competence and
financial resources of the operator. Such factors include the availability of
future capital resources of the other participants for the drilling of wells and
the approval of other participants of the drilling of wells on the properties in
which the Company has an interest. The Company's reliance on the operator and
other working interest owners and its limited ability to control certain costs
could have a material adverse effect on the realization of expected rates of
return on the Company's investment in drilling or acquisition activities.
OPERATING RISKS
The oil and natural gas business involves a variety of operating risks,
including the risk of fire, explosions, blow-outs, pipe failure, abnormally
pressured formations and environmental hazards such as oil spills, gas leaks,
ruptures or discharges of toxic gases. Any of these occurrences could result in
substantial losses to the Company due to injury or loss of life, severe damage
to or destruction of property, natural resources and equipment, pollution or
other environmental damage, clean-up
16
<PAGE>
responsibilities, regulatory investigation and penalties and suspension of
operations. Moreover, offshore operations are subject to a variety of operating
risks peculiar to the marine environment, including hurricanes or other adverse
weather conditions, more extensive governmental regulation (including
regulations that may, in certain circumstances, impose strict liability for
pollution damage) and interruption or termination of operations by governmental
authorities based on environmental or other considerations. The presence of
unanticipated pressure or irregularities in formations, miscalculations or
accidents may cause a drilling or production operation to be unsuccessful,
resulting in a total loss of the Company's investment in such operation.
Although the Company maintains insurance coverage it believes is customary in
the industry for companies of similar size, it is not fully insured against
certain of these risks, either because such insurance is not available or
because of the high premium costs. There can be no assurance that any insurance
obtained by the Company will be adequate to cover any losses or liabilities, or
that such insurance will continue to be available or available on terms that are
acceptable to the Company.
RELIANCE ON ESTIMATES OF OIL AND NATURAL GAS RESERVES
The reserve data set forth in this report on Form 10-K represent only
estimates of D&M, NSA and other third party petroleum engineers. The estimation
of reserve data is a subjective process of estimating the recovery of
underground accumulations of oil and natural gas that cannot be measured in an
exact manner, and the accuracy of any reserve estimate is a function of the
quality of the available data, the assumptions made, and engineering and
geological interpretation and judgment. Estimates of economically recoverable
oil and natural gas reserves and future net cash flows therefrom necessarily
depend upon a number of variable factors and assumptions, including historical
production from the area compared with production from other producing areas,
the assumed effects of regulation by governmental agencies and assumptions
concerning future oil and natural gas prices, future operating costs, severance
and excise taxes, development costs and workover and remedial costs, all of
which may in fact vary considerably from actual results. Any such estimates are
therefore inherently imprecise, and estimates by other engineers, or by the same
engineers at a different time, might differ materially from those included
herein. Actual prices, production, development expenditures, operating expenses
and quantities of recoverable oil and natural gas reserves will vary from those
assumed in the estimates, and it is likely that such variances will be
significant. Any significant variance from the assumptions could result in the
actual quantity of the Company's reserves and future net cash flows therefrom
being materially different from the estimates set forth in this report on Form
10-K. In addition, the Company's estimated reserves may be subject to downward
or upward revision, based upon production history, results of future exploration
and development, prevailing oil and natural gas prices, operating and
development costs and other factors. The Company's properties may also be
susceptible to hydrocarbon drainage from production by other operators on
adjacent properties.
The present value of future net cash flows set forth in this Form 10-K
should not be construed as the current market value or the value at any prior
date of the estimated oil and natural gas reserves attributable to the Company's
properties. In accordance with applicable requirements of the Securities and
Exchange Commission (the "Commission"), the estimated discounted future net cash
flows from estimated proved reserves are based on prices and costs as of the
date of the estimate unless such prices or costs are contractually determined at
such date. Actual future prices and costs may be materially higher or lower.
Actual future net cash flows also will be affected by factors such as actual
production, supply and demand for oil and natural gas, curtailments or increases
in consumption by natural gas purchasers, changes in governmental regulations or
taxation and the impact of inflation on costs. In addition, the 10% discount
factor used to calculate the present value of future net cash flows is not
necessarily the most appropriate discount factor based on interest rates in
effect from time to time and risks associated with the Company or the oil and
gas industry in general.
LAWS AND REGULATION
The Company's forward-looking statements are generally based upon the
assumption of a stable legal and regulatory environment. The Company's ability
to economically produce and market its gas and oil production is affected and
could possibly be restrained by a number of legal and regulatory factors,
including , but not limited to, federal and state laws and regulation of natural
gas and oil production, federal and state tax laws and regulations, state limits
on allowable rates of production by well or proration unit, as well as by laws
and regulations which may affect the amount of natural gas and oil available for
sale, the availability of adequate pipeline and other transportation and
processing facilities and the marketing of competitive fuels.
The Company's operations are also subject to extensive federal, state
and local laws and regulations relating to the generation, storage, handling,
emission, transportation and discharge of materials into the environment. It is
possible that increasingly strict requirements will be imposed by environmental
laws and enforcement policies thereunder. The Company's forward-looking
statements are generally based upon the expectations that it will not be
required in the near future to expend
17
<PAGE>
amounts that are material in relation to its total capital expenditures program
by reason of environmental laws and regulations. However, inasmuch as such laws
and regulations are frequently changed, the Company is unable to predict the
ultimate cost of such compliance.
CERTAIN RISKS AFFECTING THE COMPANY'S IPF PROGRAM
The Company's IPF Program involves an up-front cash payment for the
purchase of a term overriding royalty interest pursuant to which the Company
receives an agreed upon share of revenues from identified properties. The
producer's obligation to deliver such revenues is nonrecourse to the producer
insofar as the producer generally is not liable to the Company for any failure
to meet its payment obligation except for such failures attributable to the
producer's failure to operate prudently, title failure or certain other causes
within the control of the producer. Consequently, the Company's ability to
realize successful investments through its producer finance business is subject
to the Company's ability to estimate accurately the volumes of recoverable
reserves from which the applicable production payment is to be discharged and
the operator's ability to recover these reserves. The Company's interest is
believed to constitute a property interest and, therefore, in the event of the
producer's bankruptcy or similar event, outside of the reach of the producer's
creditors; however, such creditor (or the producer as debtor-in-possession or a
trustee for the producer in a bankruptcy proceeding) may argue that the
transaction should be characterized as a loan, in which case the Company may
have only a creditor's claim for repayment of the amounts advanced. As
non-operating interests, the Company's ownership of these production payments
should not expose the Company to liability attendant to the ownership of direct
working interests, such as environmental liabilities and liabilities for
personal injury or death or damage to the property of others, although no
assurances can be made in this regard. Finally, as the producer's obligation is
only to deliver a specified share of revenues, subject to the ability of the
burdened reserves to produce such revenues, the Company bears the risk that
future revenues delivered will be insufficient to amortize the purchase price
paid by the Company for the interest or to provide any investment return
thereon.
The Company operates the IPF Program through its indirect wholly-owned
subsidiary, Domain Energy Finance Corporation ("IPF Company"). IPF Company has a
$150.0 million revolving credit facility with a bank (the "IPF Credit Facility")
pursuant to which it finances a portion of the IPF Program. The borrowing base
under the facility as of December 31, 1997 was $40.0 million. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Liquidity and Capital Resources -- IPF Credit Facility."
COMPETITION
The Company encounters competition from other companies in all areas of
its operations, including the acquisition of producing properties and its IPF
Program. The Company's competitors include major integrated oil and natural gas
companies and numerous independent oil and natural gas companies, individuals
and drilling and income programs and, in the case of its IPF Program, affiliates
of investment, commercial and merchant banking firms and affiliates of large
interstate pipeline companies. Many of its competitors are large,
well-established companies with substantially larger operating staffs and
greater capital resources than the Company and which, in many instances, have
been engaged in the oil and gas business for a much longer time than the
Company. Such companies may be able to pay more for producing oil and natural
gas properties and exploratory prospects and to define, evaluate, bid for and
purchase a greater number of properties and prospects than the Company's
financial or human resources permit. The Company's ability to acquire additional
properties and to discover reserves in the future, as well as its ability to
grow its IPF Program, will be dependent upon its ability to evaluate and select
suitable properties and exploration prospects and to consummate transactions in
this highly competitive environment.
ITEM 3. LEGAL PROCEEDINGS
In April 1997, MarkWest Michigan, Inc. ("MarkWest") filed a demand for
arbitration with the American Arbitration Association seeking to enforce its
alleged preferential purchase right with respect to the Michigan Development
Project and claiming that the sale by the Company of its interest in a portion
of the Michigan Development Project should be declared void. Subsequently,
MarkWest filed an amended demand for arbitration, which dismissed the Company
and named Michigan Energy Company L.L.C. as sole respondent. These arbitration
proceedings were enjoined by an injunctive order issued by the District Court of
Harris County, Texas. On November 11, 1997, as part of Michigan Energy Company
L.L.C's sale of its interest in the Michigan Development Project to MarkWest
Michigan, Inc., a full and absolute release was executed releasing all claims,
including specifically all matters in the pending arbitration before the
American Arbitration Association.
Various claims have been filed naming joint working interest owners of
the Company in the ordinary course of business, particularly claims alleging
personal injuries, for which the Company would be responsible for its pro rata
share of
18
<PAGE>
any uninsured damages or settlement costs. No pending or threatened claims,
actions or proceedings against the Company are expected to have a material
adverse effect on the Company's financial condition or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the
fourth quarter of 1997.
EXECUTIVE OFFICERS OF THE REGISTRANT
In reliance on General Instruction G (3) to Form 10-K, information on
executive officers of the Company is included in this Part I. The executive
officers of the Company are elected by, and serve until their successors are
elected by, the Board of Directors. Information with respect to the executive
officers of the Company is set forth below:
NAME AGE POSITION
-------------------------- ---- -----------------------------------
Michael V. Ronca ......... 44 President and Chief Executive Officer
Michael L. Harvey ....... 50 Executive Vice President
Herbert A. Newhouse ...... 53 Executive Vice President
Catherine L. Sliva ....... 39 Executive Vice President and Secretary
Rick G. Lester ........... 46 Vice President, Chief Financial
Officer, Treasurer and Assistant
Secretary
Michael V. Ronca has been the President and Chief Executive Officer of
the Company and has served as a Director of the Company since its inception in
1996. Mr. Ronca has been President of the Company's predecessor entities since
1993. Prior to starting the Company's predecessor entities, Mr. Ronca served in
various financial and management positions within Tenneco. Ronca's
responsibilities included portfolio management, non-security related
investments, acquisition and disposition analysis, strategic planning,
operational direction, and investor relations.
Michael L. Harvey has been Executive Vice President of the Company since
completion of the Gulfstar Acquisition in December 1997 and has served as a
Director of the Company since February 1998. In 1991, Mr. Harvey and certain
investors formed Gulfstar Energy, Inc., a company engaged in the exploration,
development and production of oil and natural gas in the shallow waters of the
Gulf of Mexico. Mr. Harvey served as Chief Executive Officer of Gulfstar Energy,
Inc. until it was merged into a subsidiary of the Company in December 1997.
Herbert A. Newhouse has been Executive Vice President of the Company
since its inception in 1996. Mr. Newhouse is responsible for exploration,
production and evaluation activities for the Company, including geological,
geophysical and engineering technical evaluations. Mr. Newhouse joined Tenneco
Ventures in 1995 as Vice President. Mr. Newhouse served as Vice President of
Production for North Central Oil Corporation for the six years prior to 1995.
Catherine L. Sliva has been Executive Vice President and Secretary of
the Company since its inception in 1996 and is principally responsible for the
IPF Program, strategic planning and analysis, and investor relations. Ms. Sliva
has been with Tenneco Ventures since 1992.
Rick G. Lester has been Vice President, Chief Financial Officer,
Treasurer and Assistant Secretary of the Company since its inception in 1996
with overall responsibility for its accounting and taxation, financial analysis,
and financing and banking activities. Mr. Lester has been with Tenneco Ventures
since 1992.
19
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The Company's Common Stock is listed on the New York Stock Exchange
("NYSE") under the symbol "DXD". The following table sets forth, for the
calendar quarters indicated, the high and low closing prices of the Common Stock
as reported by the NYSE since the Common Stock began trading on June 24, 1997.
COMMON STOCK
1997 HIGH LOW
---------------------------------- ----------- ----------
Second Quarter (from June 24) 13 1/2 13 1/2
Third Quarter 19 1/4 13 9/16
Fourth Quarter 20 14 3/4
On March 18, 1998, the closing price of the Common Stock, as reported by
the NYSE was $12 7/8 per share and there were 86 holders of record of Common
Stock. This number does not include stockholders for whom shares are held in a
"nominee" or "street" name.
SECURITIES SOLD
On December 12, 1997, the Company sold an aggregate of 499,990 shares of
Common Stock for an aggregate value of $8.0 million to the former shareholders
of Gulfstar Energy, Inc. and Mid Gulf Drilling Corp. in exchange for their
equity interests in these companies. The Company relied on Section 4(2) of the
Securities Act of 1933, as amended, in effecting these transactions.
DIVIDEND POLICY
The Company intends to retain its earnings to provide funds for
reinvestment in the Company's businesses, including exploration, development and
production activities, and, therefore, does not anticipate declaring or paying
cash dividends in the foreseeable future. The Company is a holding company that
conducts substantially all of its operations through its subsidiaries. As a
result, the Company's ability to pay dividends on the Common Stock would be
dependent on the cash flows of its subsidiaries. Payment of dividends is also
subject to then existing business conditions and the business results, cash
requirements and financial condition of the Company, and will be at the
discretion of the Board of Directors. In addition, the terms of the Company
Credit Facility currently prohibit the payment of dividends by the Company. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources".
20
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data set forth below for the Company for the five
years ended December 31, 1997 should be read in conjunction with the
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Consolidated and Combined Financial Statements and the Notes
thereto included elsewhere in this report on Form 10-K.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
SUCCESSOR PREDECESSOR
--------- ---------------------------------
(IN THOUSANDS, EXCEPT PER SHARE DATA) 1997 1996 1995 1994 1993
--------- ------- -------- -------- ------
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Oil and natural gas (1) ...... $47,251 $ 52,274 $34,877 $5,340 $ 1,922
IPF Activities (2) ........... 4,779 4,369 2,356 1,417 200
Other ........................ 238 (413) 414 283 --
------- -------- ------- ------ -------
Total revenues ........ 52,268 56,230 37,647 7,040 2,122
------- -------- ------- ------ -------
Expenses:
Lease operating .............. 14,924 10,207 7,980 1,790 218
Production and severance taxes 1,417 1,340 710 18 2
Depreciation, depletion and
amortization ............... 16,072 24,920 22,692 3,101 987
General and administrative,
net ........................ 4,237 3,361 2,780 52 681
Corporate overhead
allocation ................. -- 4,827 2,627 944 257
Stock compensation (3)........ 4,587 -- -- -- --
------- -------- ------- ------ -------
Total operating
expenses ............. 41,237 44,655 36,789 5,905 2,145
------- -------- ------- ------ -------
Income (loss) from operations ....... 11,031 11,575 858 1,135 (23)
Interest expense, net ............... 3,774 150 -- -- --
------- -------- ------- ------ -------
Income (loss) before income taxes.... 7,257 11,425 858 1,135 (23)
Income tax provisions ............... 4,094 4,394 351 735 2
------- -------- ------- ------ -------
Net income (loss) ................... $ 3,163 $ 7,031 $ 507 $ 400 $ (25)
======= ======== ======= ====== =======
Net income per share:
Basic ......................... $ 0.27
Assuming dilution ............. $ 0.26
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-----------------------------------------------
SUCCESSOR PREDECESSOR
-------------------- --------------------------
1997 1996 1995 1994 1993
--------- ---------- -------- --------- -------
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents .... $ 4,731 $ 36 $ -- $11,467 $ 1,635
Property, plant and equipment,
net ........................ 137,974 66,176 111,724 93,823 11,544
IPF Program notes
receivable ................. 49,765 21,710 7,991 4,023 4,215
Total assets ................. 212,549 122,429 137,096 117,755 23,493
Long-term debt (including
current maturities) ........ 63,720 79,412 -- -- --
Parent advances .............. -- -- 112,832 104,504 19,491
Stockholders' equity ......... 132,034 28,577 572 65 (335)
</TABLE>
(1) Oil and natural gas sales increased from $5.3 million in 1994 to $52.3
million in 1996 primarily as a result of the Company's acquisition of
producing properties in 1994 and 1995, results of drilling activities in
1994, 1995 and 1996, and an increase in the net realized price of natural
gas in 1996 relative to 1994 and 1995.
(2) IPF Activities includes income from the Company's IPF Program and the
Company's "GasFund" partnership with a financial advisor. See "Business and
Properties - Producer Investment Activities."
(3) Stock compensation expense for 1997 represents noncash charges.
21
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
The following discussion is intended to assist in understanding the
Company's historical financial position and results of operations as of December
31, 1997 and 1996, and for each year of the three-year period ended December 31,
1997. The Company's historical financial statements and notes thereto included
elsewhere in this report on Form 10-K contain detailed information that should
be referred to in conjunction with this discussion.
GENERAL
The Company is an independent oil and gas company engaged in the
exploration, development, production and acquisition of oil and natural gas
properties, principally in the Gulf Coast region. The Company complements these
activities with its Independent Producer Finance Program ("IPF Program")
pursuant to which it invests in oil and natural gas reserves through the
acquisition of term overriding royalty interests accounted for as notes
receivable. As of December 31, 1997, the Company had estimated net proved
reserves of 173.0 Bcfe. Approximately 61% of the Company's net proved reserves
at such date were natural gas and approximately 44% of proved reserves were
classified as proved developed producing. As of December 31, 1997, the Company
had a PV-10 Reserve Value of $148.8 million, which does not include reserve
value attributable to the IPF Program. The Company had outstanding IPF Program
notes receivable of $49.8 million as of December 31, 1997. During 1997,
approximately 91% of the Company's revenue was generated by oil and natural gas
sales and approximately 9% of the Company's revenue was generated by the IPF
Program.
On December 31, 1996, the Company acquired all of the outstanding
capital stock of its operating subsidiaries, Domain Energy Ventures Corporation
("Ventures Corporation") and Domain Energy Production Corporation ("Production
Corporation" and, together with Ventures Corporation, the "Predecessor"). The
Company accounted for the acquisition (the "Acquisition") using the purchase
method of accounting, under which the purchase price has been allocated to the
assets acquired and liabilities assumed based upon their fair values at the
acquisition date.
On December 15, 1997, the Company acquired all of the outstanding
capital stock of Gulfstar Energy, Inc. and Mid Gulf Drilling Corp. (the
"Gulfstar Acquisition"). The Company accounted for the Gulfstar Acquisition
using the purchase method of accounting, under which the purchase price has been
allocated to the assets acquired and liabilities assumed based upon preliminary
fair values at the acquisition date.
The Company's selected historical consolidated and combined financial
data included elsewhere in this report on Form 10-K has been derived from the
audited Consolidated and Combined Financial Statements of the Company. The
selected balance sheet data at December 31, 1997 reflects the Acquisition that
occurred on December 31, 1996 and the Gulfstar Acquisition that occurred on
December 15, 1997. The selected balance sheet data at December 31, 1996 reflects
the Acquisition that occurred on that date. The income statement data at other
dates and for other periods reflects the combined financial position and results
of operations of Ventures Corporation and Production Corporation with
intercompany transactions and account balances eliminated.
Prior to the Acquisition, Ventures Corporation and Production
Corporation were included in the consolidated federal income tax return of
Tenneco Inc. ("Tenneco"), as a result of which Tenneco received all benefit for
such entities' historical tax losses. In connection with the Acquisition, the
Company agreed and filed an election under Sections 338(g) and 338(h)(10) of the
Internal Revenue Code of 1986, as amended, pursuant to which the Company
allocated the purchase price paid by the Company among the assets of these
companies to determine the basis of assets acquired in accordance with the
principles of Treasury Regulation 1.338(h)(10)-1(f)(1)(ii).
The Company's revenue, profitability and future rate of growth are
substantially dependent upon prevailing prices for oil and natural gas, which
are dependent upon numerous factors beyond the Company's control, such as
economic, political and regulatory developments and competition from other
sources of energy. The energy markets have historically been highly volatile,
and future decreases in oil or natural gas prices could have a material adverse
effect on the Company's financial position, results of operations, quantities of
oil and natural gas reserves that may be economically produced and access to
capital.
The Company uses the full cost method of accounting for its investments
in oil and natural gas properties. Under such methodology, all costs of
exploration, development and acquisition of oil and natural gas reserves are
capitalized into separate country by country "full cost pools" as incurred and
properties in each pool are depleted and charged to operations using the
unit-of-production method based on a ratio of current production to total proved
oil and natural gas reserves. To the extent
22
<PAGE>
that such capitalized costs (net of accumulated depreciation, depletion, and
amortization) less deferred taxes exceed the present value (using a 10% discount
rate) of estimated future net cash flows from proved oil and natural gas
reserves and the lower of cost or fair value of unproved properties, such excess
costs are charged to operations. If a write-down were required, it would result
in a non-cash charge to earnings but would not have an impact on cash flows.
ACCOUNTING FOR IPF PROGRAM ACTIVITY
Through its IPF Program, the Company acquires term overriding royalty
interests in oil and gas properties owned by independent producers. Because the
capital advanced to a producer for these interests is repaid from an agreed upon
share of cash revenues from the sale of production until the capital advanced
plus a contractual return is paid in full, the Company accounts for the term
overriding royalty interests as notes receivable. Under this accounting method,
the Company recognizes only the interest income portion of payments received
from a producer as revenues on its income statement. The remaining cash receipts
are recorded as a reduction in notes receivable on the Company's balance sheet
and as IPF Program return of capital on the Company's statement of cash flows.
If, instead of acquiring dollar-denominated term overriding royalty
interests, the Company were purchasing term overriding royalty interests
requiring delivery of a specified quantity of oil and gas, IPF Program results
would be accounted for differently. Specifically, in 1997, the Company's EBITDA
would increase by $12.1 million and IPF Program return of capital in the
consolidated statement of cash flows would decrease by the same amount. To more
accurately reflect the actual cash flows generated by the Company, IPF Program
return of capital is identified separately to allow such cash receipts to be
combined with EBITDA.
The Company reviews the IPF Program portfolio on a quarterly basis
(giving effect to commodity prices, production levels and reserve estimates) to
determine if any transactions are at risk of loss of principal. Although to
date, the Company has not incurred any losses on notes outstanding under the IPF
Program, as of December 31, 1997, the Company has established a non-cash reserve
for potential future losses of $437,000, which is netted against IPF Program
notes receivable in the Company's consolidated balance sheet.
23
<PAGE>
RESULTS OF OPERATIONS
The following table summarizes certain financial data, non-GAAP
financial data, production volumes, average realized prices and expenses for the
Company's operations for the periods shown:
YEAR ENDED DECEMBER 31,
-----------------------
SUCCESSOR PREDECESSOR
----------- ---------------------
1997 1996 1995
----------- ---------- ----------
FINANCIAL DATA (in thousands):
Revenues
Natural gas ....................... $ 36,082 $ 41,767 $ 27,772
Oil and Condensate ................ 11,169 10,507 7,105
IPF Activities (1) ................ 4,779 4,369 2,356
Total revenues ......................... 52,268 56,230 37,647
Total operating expenses ............... 41,237 44,655 36,789
-------- -------- --------
Operating income ....................... $ 11,031 $ 11,575 $ 858
======== ======== ========
Net income ............................. $ 3,163 $ 7,031 $ 507
Net cash provided by operating
activities .......................... $ 21,014 $ 34,553 $ 19,933
Net cash used in investing
activities .......................... $(87,602) $(47,329) $(39,728)
Net cash provided by financing
activities .......................... $ 71,283 $ 12,776 $ 8,328
NON-GAAP FINANCIAL DATA (in thousands):
EBITDA (2) ............................. $ 31,690 $ 36,495 $ 23,550
IPF Program return of capital (3) ...... 12,109 4,618 2,638
-------- -------- --------
EBITDA plus IPF Program return
of capital .......................... $ 43,799 $ 41,113 $ 26,188
======== ======== ========
PRODUCTION VOLUMES:
Natural gas (MMcf) ..................... 15,932 21,192 18,065
Oil and condensate (MBbls) ............. 646 564 424
Total (MMcfe) .......................... 19,811 24,575 20,609
AVERAGE REALIZED PRICES: (4)
Natural gas (per Mcf) .................. $ 2.26 $ 1.97 $ 1.54
Oil and condensate (per Bbl) ........... $ 17.28 $ 18.63 $ 16.76
EXPENSES (PER MCFE):
Lease operating (6) .................... $ 0.74 $ 0.42 $ 0.39
Production taxes ....................... $ 0.07 $ 0.05 $ 0.03
Depreciation, depletion, and
amortization ........................ $ 0.78 $ 1.01 $ 1.08
General and administrative, net(5) ..... $ 0.17 $ 0.12 $ 0.16
(1) IPF Activities for 1996 and 1995 include income from the Company's IPF
Program and the Company's "GasFund" partnership with a financial investor. See
"Business and Properties -- Producer Investment Activities."
(2) EBITDA represents earnings before stock compensation expense, interest,
income taxes, depreciation, depletion and amortization. The Company believes
that EBITDA may provide additional information about the Company's ability to
meet its future requirements for debt service, capital expenditures and working
capital. EBITDA is a financial measure commonly used in the oil and gas industry
and should not be considered in isolation or as a substitute for net income,
operating income, net cash provided by operating activities or any other measure
of financial performance presented in accordance with generally accepted
accounting principles or as a measure of a company's profitability or liquidity.
Because EBITDA excludes some, but not all, items that affect net income and may
vary among companies, the EBITDA calculation presented above may not be
comparable to similarly titled measures of other companies.
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<PAGE>
(3) To more accurately reflect the actual cash flows generated by the Company,
IPF Program return of capital is identified separately to allow such cash
receipts to be combined with EBITDA.
(4) Reflects the actual realized prices received by the Company, including the
results of the Company's hedging activities. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Other Matters --
Hedging Activities."
(5) Includes production attributable to properties managed for the Funds for the
periods indicated and excludes fees received from investors and overhead
allocations from Tenneco. Including Tenneco allocations, average net general and
administrative expenses per Mcfe for the years ended December 31, 1996 and 1995
would be $0.28 and $0.20, respectively.
(6) Lease operating expense per Mcfe increased to $0.74 in 1997 compared to
$0.42 in 1996, or $0.32. This increase was primarily due to decreased production
volumes ($0.14), increased workover expenses ($0.08) and an increase due to the
Wasson Field acquisition ($0.06).
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Oil and natural gas revenues decreased from $52.3 million in 1996 to
$47.3 million in 1997, a decrease of $5.0 million, or 9.6%. Production volumes
for oil and condensate increased from 564 MBbls in 1996 to 646 MBbls in 1997, an
increase of 82 MBbls, or 14.5%. Production volumes for natural gas decreased
from 21.2 Bcf in 1996 to 15.9 Bcf in 1997, a decrease of 5.3 Bcf, or 24.8%. The
decrease in natural gas production was primarily due to natural declines in
production from certain fields, reduced capital expenditures prior to the
Acquisition in 1996 as well as the sale of certain properties. This was
partially offset by an increase in production resulting from the Funds
Acquisition. The decrease in total production decreased revenues by $8.9
million. This was partially offset by a 14.7% increase in the average realized
price received for the Company's natural gas and a 7.2% decrease in the average
realized price received for the Company's oil and condensate. These changes in
realized prices increased revenues by $3.9 million.
The Company realized an average oil, condensate and natural gas liquids
price of $18.50 per Bbl and an average gas price of $2.51 per Mcf for the year
ended December 31, 1997. Net of hedging results, the Company realized average
prices of $17.28 per Bbl and $2.26 per Mcf, respectively. These hedging
activities decreased 1997 oil and natural gas revenues by approximately $4.6
million. The Company realized an average oil, condensate and natural gas liquids
price of $20.88 per Bbl and an average gas price of $2.41 per Mcf for the year
ended December 31, 1996. Net of hedging results, the Company realized average
prices of $18.63 per Bbl and $1.97 per Mcf, respectively. These hedging
activities decreased 1996 oil and natural gas revenues by approximately $10.5
million.
Revenues from IPF Activities increased from $4.4 million in 1996 to $4.8
million in 1997, an increase of $0.4 million, or 9.4%. The 1996 activities
include $1.5 million for fees earned related to GasFund financings. Excluding
the effect of these fees, revenues from IPF Activities increased by $1.9
million, or 65.5%, in 1997 compared to 1996, primarily due to increased
financing activities.
Lease operating expenses increased from $10.2 million in 1996 to $14.9
million in 1997, an increase of $4.7 million, or 46.2%. This increase was
primarily due to an increase of $1.1 million as a result of the Wasson Field
acquisition completed in June 1996, an increase of $1.4 million in workover
expense, and an increase of $1.4 million relating to the Funds Acquisition
completed on July 1, 1997. The Wasson Field, which is in tertiary recovery, had
a relatively low purchase price based on reserves, but relatively high lease
operating expenses. On an Mcfe basis, lease operating expenses increased from
$0.42 in 1996 to $0.74 in 1997, an increase of $0.32, or 76.2%. The increase in
lease operating expenses per Mcfe was primarily due to decreased production
volumes ($0.14), increased workover expenses ($0.08), and an increase as a
result of the Wasson Field acquisition ($0.06).
Depreciation, depletion and amortization ("DD&A") expense decreased from
$24.9 million in 1996 to $16.1 million in 1997, a decrease of $8.8 million. This
was primarily the result of lower natural gas production volumes ($4.8 million)
and a 22.8% decrease in the DD&A rate ($4.0 million) from $1.01 to $0.78 per
Mcfe primarily resulting from the reduced cost basis attributable to the
Company's oil and gas properties purchased in the Acquisition.
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<PAGE>
General and administrative expense increased from $3.4 million in 1996
to $4.2 million in 1997, an increase of $0.8 million, or 23.5%. This increase
reflects a decrease in the reimbursement of overhead paid to the Company via its
funds management from $0.3 million in 1996 to zero in 1997 and a $0.5 million
decrease in the capitalization of general and administrative expense in 1997 as
compared to 1996.
The corporate overhead allocation from Tenneco decreased from $4.8
million in 1996 to zero in 1997 due to the Acquisition and elimination of
Tenneco's allocated overhead.
Stock compensation expense increased from zero in 1996 to $4.6 million
in 1997 due to the implementation of the Stock Purchase and Option Plan. See
Note 10 to the Consolidated and Combined Financial Statements - "Stock Purchase
and Option Plan".
Net interest expense increased from $0.2 million in 1996 to $3.8 million
in 1997. This increase was due to higher borrowings under the Company's
revolving credit facilities due to increased IPF Program investments, the
Acquisition and higher oil and gas capital expenditures in 1997.
Income tax expense decreased from $4.4 million in 1996 to $4.1 million
in 1997, a decrease of $0.3 million, or 6.8%. This decrease was primarily due to
a decrease in income before taxes from $11.4 million in 1996 to $7.3 million in
1997. This decrease was partially offset by an increase in the effective tax
rate from 38% in 1996 to 56% in 1997. This increase in the effective tax rate
was due to the tax treatment of certain portions of stock compensation expense.
Net income was $7.0 million in 1996 compared to $3.2 million in 1997, as
a result of the factors described above.
YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995
Oil and natural gas revenues increased from $34.9 million in 1995 to
$52.3 million in 1996, an increase of $17.4 million, or 49.9%. Production
volumes for oil and condensate increased from 424 MBbls in 1995 to 564 MBbls in
1996, an increase of 140 MBbls, or 33.0%. Production volumes for natural gas
increased from 18.1 Bcf in 1995 to 21.2 Bcf in 1996, an increase of 3.1 Bcf, or
17.3%. The increase in oil and natural gas production was due to new wells being
successfully drilled and completed during 1996, as well as acquisitions of
producing properties. The increase in total net production increased revenues by
$7.2 million. In addition, the Company experienced an 11.2% increase in average
oil and condensate prices and a 27.9% increase in average natural gas prices.
Increases in average oil and natural gas prices were directly attributable to
general improved market conditions.
The Company realized an average oil, condensate and natural gas liquids
price of $20.88 per Bbl and an average gas price of $2.41 per Mcf for the year
ended December 31, 1996. Net of hedging results, the Company realized average
prices of $18.63 per Bbl and $1.97 per Mcf, respectively. These hedging
activities decreased 1996 oil and natural gas revenues by approximately $10.5
million. This loss of revenue was the result of hedges made at the direction of
Tenneco in late 1995. For the year ended December 31, 1995, the Company realized
an average oil, condensate and natural gas liquids price of $16.31 per Bbl and
an average natural gas price of $1.54 per Mcf. Net of hedging results, the
Company realized an average oil price of $16.76 per Bbl. These hedging
activities increased 1995 oil revenues by approximately $0.2 million. The
Company had no natural gas hedging activities in 1995.
Revenues from IPF Activities increased from $2.4 million in 1995 to $4.4
million in 1996, an increase of $2.0 million, or 85.4%. This increase was the
result of a $1.0 million increase in IPF Program revenues and a $1.0 million
increase in GasFund revenues. The 1996 activities include $1.5 million for fees
earned related to GasFund financings. Excluding the effect of these fees,
revenues from IPF Activities increased by $0.5 million, or 20.8%, in 1996
compared to 1995. IPF Program revenues increased as the result of a 100%
increase in IPF Program customers, and a corresponding increase in investments,
at year-end 1996 compared to year-end 1995.
Lease operating expenses increased from $8.0 million in 1995 to $10.2
million in 1996, an increase of $2.2 million, or 27.9%. On an Mcfe basis, lease
operating expenses increased from $0.39 in 1995 to $0.42 in 1996, an increase of
$0.03, or 7.7%. The increase in lease operating expenses was primarily
attributable to increased production volumes. On a per unit basis, the increase
was primarily attributable to the acquisition in June 1996 of an interest in the
Wasson Field, which is undergoing tertiary enhanced recovery and the expenses
associated therewith.
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<PAGE>
DD&A expense increased from $22.7 million in 1995 to $24.9 million in
1996, an increase of $2.2 million. This was the result of higher oil and gas
production volumes partially offset by a 6.5% decrease in the DD&A rate from
$1.08 to $1.01 per Mcfe. The reduced DD&A rate was attributable to the
acquisition of low cost reserves in the Wasson Field.
General and administrative expense increased from $2.8 million in 1995
to $3.4 million in 1996, an increase of $0.6 million, or 20.9%. This increase
reflects a decrease in the reimbursement of overhead paid to the Company via its
funds management from $1.1 million in 1995 to zero in 1996 partially offset by
an increase in the capitalization of general and administrative expense in 1996
of $0.5 million as compared to 1995.
The corporate overhead allocation from Tenneco increased from $2.6
million in 1995 to $4.8 million in 1996, an increase of $2.2 million, or 83.7%.
The increase was primarily due to approximately $2.0 million in costs related to
severance payments, retention bonuses and other costs associated with the merger
of Tenneco with an affiliate of El Paso Natural Gas Company.
Income tax expense increased from $0.4 million in 1995 to $4.4 million
in 1996, an increase of $4.0 million, or 1152%. This was due to an increase in
income before taxes from $0.9 million in 1995 to $11.4 million in 1996 and a
decrease in the effective tax rate from 41% in 1995 to 38% in 1996.
Net income was $0.5 million in 1995 compared to $7.0 million in 1996, as
a result of the factors described above.
LIQUIDITY AND CAPITAL RESOURCES
During 1997, cash flow from operations was $21.0 million, compared with
$34.5 million in 1996. Net cash flow from operations before changes in operating
assets and liabilities for 1997 was $27.7 million compared with $39.5 million in
1996, a decrease of $11.8 million. This decrease was primarily the result of
lower revenues ($4.0 million) due to a decline in production, higher lease
operating expenses and production taxes ($4.8 million), higher interest expense
($3.6 million) and lower deferred taxes ($3.3 million), partially offset by
lower corporate overhead allocation ($3.9 million).
Working capital, excluding current maturities on long-term debt, was
$13.7 million at December 31, 1997 and $22.8 million at December 31, 1996.
Net cash used in investing activities was $87.6 million in 1997, an
increase of $40.3 million or 85.1% over 1996, primarily due to increased oil and
gas property acquisitions and increased investment in the IPF Program. Oil and
gas property acquisitions in 1997 included $28.4 million for the Funds
Acquisition, $7.5 million for the Gulfstar Acquisition and $11.8 million for the
additional working interest in Mobile Bay 864. IPF Program investments increased
by $21.1 million in 1997, or 110.9%, over 1996. These increases in investing
activities were partially offset by an increase in proceeds from the sale of
oil and gas properties and the Company's equity investment in Michigan ($9.9
million), proceeds from the sale of restricted certificate of deposit ($8.0
million), an increase in IPF Program return of capital ($7.5 million), lower
investments in other assets ($1.7 million) and lower investment in drilling
activities ($1.4 million).
The following table sets forth the Company's capital expenditure and IPF
Program investments for each of the past three years (in thousands):
YEAR ENDED DECEMBER 31,
-----------------------------
SUCCESSOR PREDECESSOR
--------- -----------------
1997 1996 1995
-------- -------- ------
Acquisition of oil and natural gas properties .. $ 55,372 $ 8,513 $18,393
Development and exploitation ................... 18,894 7,506 7,834
Exploration .................................... 16,804 12,126 23,677
IPF Program .................................... 40,164 18,608 6,606
-------- ------- -------
Total ..................................... $131,234 $46,753 $56,510
======== ======= =======
The Company's 1998 planned exploration and development capital spending
program is $100.0 million, including $55.0 million for acquisitions. The
Company's planned 1998 IPF Program investment is $50.0 million. Future capital
expenditures and IPF Program investments remain subject to business conditions
affecting the industry, particularly changes in prices and demand for natural
gas and crude oil. The Company believes it can fund the 1998 capital spending
program and IPF Program investments as well as continue current production rates
at current market prices. The Company will continue to
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<PAGE>
monitor prices and evaluate options should prices decline. It is expected that
future cash requirements for capital expenditures and IPF Program investments
will come from operating activities and future financings.
Cash flows provided from financing activities was $71.3 million in 1997,
reflecting net proceeds of $87.0 million from the issuance of common stock,
$67.8 million in proceeds from debt borrowings less $83.5 million in repayments
of debt borrowings. In 1996, cash flow from financing activities was $12.8
million reflecting $7.0 million from debt borrowings, $6.6 million in parent
advances less $0.8 million in repayments of debt borrowings.
ISSUANCE OF COMMON STOCK. The Company raised approximately $89.3
million through the sale of common stock in various transactions in 1997. On
February 21, 1997, the Company issued 390,307 shares of its common stock in a
private offering to the management of the Company. For the sale of such shares
the Company received $1,085,328 in cash and accepted notes payable from certain
managers in the amount of $546,026. On April 3, 1997, the Company issued 95,696
shares of its common stock in a private offering to the employees of the
Company. For the sale of such shares the Company received $400,000 in cash. In
February 1998, payments relating to the management notes were received for all
amounts outstanding, including accrued interest.
On June 27, 1997, the Company consummated the initial public offering
("IPO") of its Common Stock pursuant to which it issued 6,000,000 shares for an
aggregate purchase price of $75.3 million. Concurrently therewith, the Company
sold 643,037 shares of Common Stock to First Reserve Fund VII, Limited
Partnership at the public offering price for an aggregate purchase price of $8.7
million (the "Concurrent Sale"). On July 9, 1997, the Company issued an
additional 303,400 shares of Common Stock pursuant to the over-allotment option
granted to the underwriters in the IPO for an aggregate purchase price of $3.8
million. The net proceeds received by the Company from the issuance of these
shares was $87.8 million. The following table shows the use of the net proceeds
received:
USE OF PROCEEDS (IN MILLIONS)
-----------------------------
Acquisition of oil and gas properties $ 28.7
Repayment of debt 56.1
IPO closing costs 1.3
Working capital 1.7
The Company also issued 499,990 shares of common stock at a value of
$16.00 per share as part of the Gulfstar Acquisition.
COMPANY CREDIT FACILITY. In connection with the Acquisition, the Company
entered into a $65.0 million revolving credit facility (the "Company Credit
Facility") maturing on December 31, 1999 with a group of banks led by The Chase
Manhattan Bank (the "Lenders"). As of December 31, 1997, borrowings outstanding
under the Company Credit Facility totaled $34.5 million. The borrowing base
under the facility was $50.0 million as of December 31, 1997 , and is subject to
a scheduled redetermination every six months (and such other redeterminations as
the Lenders may elect to perform each year) by the Lenders at the Lenders' sole
discretion and in accordance with their customary practices and standards in
effect from time to time for reserve-based loans to borrowers similar to the
Company. See Note 7 of the Notes to the Consolidated and Combined Financial
Statements regarding Long-Term Debt.
IPF CREDIT FACILITY. Domain Energy Finance Corporation ("IPF Company"),
an indirect wholly-owned subsidiary of the Company, has a $150.0 million
revolving credit facility (the "IPF Credit Facility") with Compass Bank-Houston
("Compass") as agent pursuant to which it finances a portion of the IPF Program.
The IPF Credit Facility matures June 1, 1999 at which time all amounts owed
thereunder are due and payable. The IPF Credit Facility is secured by
substantially all of IPF Company's oil and gas interests, including the notes
receivable generated therefrom. IPF Company's obligations under such facility
are nonrecourse to the Company. The borrowing base under the facility as of
December 31, 1997 was $40.0 million and is subject to a scheduled
redetermination by Compass every six months and such other redeterminations as
Compass may elect to perform each year. As of December 31, 1997, approximately
$29.2 million was outstanding under the IPF Credit Facility. See Note 7 of the
Notes to the Consolidated and Combined Financial Statements regarding Long-Term
Debt.
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<PAGE>
ENVIRONMENTAL MATTERS
The Company is responsible for the payment of abandonment costs on its
oil and natural gas properties pro rata to its working interest. The Company
accrues for its expected future abandonment liabilities as a component of
depletion, depreciation and amortization as the properties are produced. As of
December 31, 1997, total pro forma undiscounted abandonment costs estimated to
be incurred through the year 2007 were approximately $21.4 million for
properties in federal and state waters. The Company does not consider
abandonment costs estimated to be incurred on its onshore properties to be
significant at this time. Estimates of abandonment costs and their timing may
change due to many factors, including actual drilling and production results,
inflation rate, and changes in environmental laws and regulations.
The Minerals Management Services ("MMS") requires lessees of Outer
Continental Shelf ("OCS") properties to post bonds in connection with the
plugging and abandonment of wells located offshore in the federal OCS and the
removal of all production facilities. Operators in the OCS waters of the Gulf of
Mexico are currently required to post an area-wide bond of $3.0 million or
$500,000 per producing lease, which the Company has provided. Under certain
circumstances, the MMS has the authority to suspend or terminate operations on
federal leases for failure to comply with the applicable bonding requirements or
other regulations applicable to plugging and abandonment. Any such suspensions
or terminations of the Company's operations could have a material adverse effect
on the Company's financial condition and results of operations.
During 1997, 1996 and 1995, the Company did not incur any significant
charges to income for environmental remediation costs and made no related
payments. At December 31, 1997, the Company did not have a separate
environmental remediation reserve for Superfund or similar clean-up sites.
On the basis of management's best assessment of the ultimate amount and
timing of the contingencies associated with environmental matters, any expenses
or judgments related to such matters are not expected to have a material adverse
effect on the Company's financial condition, results of operations or cash
flows.
ACCOUNTING PRONOUNCEMENTS
In June 1997, the Financial Accounting Standards Board issued Statement
No. 130, "Reporting Comprehensive Income," (SFAS 130) and Statement No. 131,
"Disclosures About Segments of an Enterprise and Related Information," (SFAS
131). SFAS 130 and SFAS 131 are effective for periods beginning after December
15, 1997. SFAS 130 establishes standards for reporting and displaying
comprehensive income and its components. SFAS 131 establishes standards for the
way that public business enterprises report information about operating segments
in interim and annual financial statements. These two statements will have no
effect on the Company's 1997 financial statements, but management is continuing
to evaluate what, if any, additional disclosures may be required when these two
statements are adopted in 1998.
YEAR 2000
The Company has initiated a review of its current financial system,
economic modeling system, as well as other purchased computer systems and
software utilized by the company. Pending completion of this review, the Company
is unable to estimate what expenditures or disruptions of operations relating to
year 2000 processing issues may result. The cost to achieve year 2000 compliance
will be charged against earnings as incurred. Such cost may be material. In
addition, no assurance can be given that total year 2000 compliance can be
achieved because of the significant degree of interdependence with third party
suppliers, service providers and customers.
OTHER MATTERS
NATURAL GAS BALANCING. The Company incurs certain gas production volume
imbalances in the ordinary course of business and utilizes the sales method to
account for such imbalances. Under this method, income is recorded based on the
Company's net revenue interest in production taken for delivery. Management does
not believe that the Company had any material gas imbalances as of December 31,
1997 or 1996.
29
<PAGE>
OPERATIONS OUTSIDE THE UNITED STATES. In November 1997, the Company
formed Domain Argentina S.A. to explore for and acquire oil and gas reserves in
Argentina. The Company owns a 50% interest in Domain Argentina S.A., which is
currently evaluating both exploration and producing acreage for investment. The
Company has not previously conducted any operations outside the United States.
Non-U.S. operations are subject to certain political, economic and other
uncertainties not encountered in U.S. operations, including risks of war and
civil disturbances (or other risks that may limit or disrupt markets),
expropriation and the general hazards associated with the assertion of national
sovereignty over certain areas in which operations are conducted. Operations
outside the United States may face the additional risk of fluctuating currency
values, hard currency shortages, controls of currency exchange and repatriation
of income or capital. No prediction can be made as to what governmental
regulations may be enacted in the future that could adversely affect the
international oil and gas industry.
Although the Company does not, as of the date hereof, have any plans or
commitments for non-U.S. operations other than in Argentina, it could in the
future expand its non-U.S. operations, which could result in the expenditure of
a material amount of funds.
HEDGING ACTIVITIES. From time to time, the Company uses certain
financial instruments, such as futures contracts, options and collars to manage
its commodity price risk. Under such financial instrument contracts, the Company
may still be at risk for basis differential, which is the difference in the
quoted financial price for contract settlement and the actual physical point of
delivery price. The Company will from time to time attempt to mitigate basis
differential risk by entering into basis swap contracts. The Company limits its
open positions under these contracts not to exceed the volume of production
controlled by the Company. The Company has established internal controls to
monitor such positions against established limits. However, to the extent that
the Company has an open position, the Company may be exposed to risk from
fluctuating market prices.
The Company realized $4.6 million and $10.5 million of pre-tax losses in
1997 and 1996, respectively, and a pre-tax gain of approximately $0.2 million in
1995 as a result of various hedging transactions for natural gas and crude oil.
Since these transactions were considered to be hedges on production, these
losses are included in oil and natural gas revenues and are reflected in the
average realized price of the particular products.
As of December 31, 1997, the Company has sold natural gas futures
contracts covering an average of 15 MMcfd of its expected natural gas production
from January 1, 1998 through October 31, 1998. Under these contracts, the
Company will receive an average price of $2.14 per MMbtu.
As of December 31, 1997, the Company has sold under a swap agreement 532
Bbld, 402 Bbld, and 278 Bbld of its expected crude oil production for 1998, 1999
and 2000, respectively. Under this swap agreement, the Company will receive
prices per barrel of $17.91, $18.48 and $19.07 for 1998, 1999 and 2000,
respectively.
Based on forward price quotes from brokers and NYMEX forward prices as
of December 31, 1997, the deferred pre-tax loss to the Company for the hedged
transactions for 1998, 1999 and 2000 would be approximately $0.3 million. The
actual gains or losses realized by the Company from such hedges may vary
significantly from the foregoing amounts due to the fluctuations of prices in
the commodity market.
Subsequent to December 31, 1997, the Company terminated its oil swap
agreements for 1999 and 2000. The Company received $47,673 in settlement of
these swap agreements.
Subsequent to December 31, 1997, the Company sold natural gas futures
contracts covering an average of 30 MMcfd of its expected natural gas production
for March 1998 through June 1998. Under these contracts, the Company will
receive an average price of $2.20 per MMbtu for March 1998 and $2.28 per MMbtu
for April 1998 through June 1998.
30
<PAGE>
GLOSSARY
The following are definitions of certain terms used in this report on Form
10-K.
Bbl. One barrel of crude oil, condensate or other liquids equal to 42 U.S.
gallons.
Bbld. One barrel of crude oil (Bbl) per day.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet of natural gas equivalent.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 degrees Fahrenheit to 59.5
degrees Fahrenheit under specific conditions.
DEVELOPED ACREAGE. The number of acres which are allocated or assignable
to producing wells or wells capable of production.
DEVELOPMENT WELL. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive in an
attempt to recover proved undeveloped reserves.
EXPLORATORY WELL. A well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir or to extend a known reservoir.
FINDING COSTS. Expressed in terms of dollars per Mcfe, calculated by
dividing the amount of total capital expenditures for oil and gas activities
less the amount associated with unproven properties by the amount of estimated
net proved reserves added (purchases of oil and gas reserves plus extensions and
discoveries) during the same period.
GROSS ACRES OR GROSS WELLS. The number of acres or wells in which the
Company has a working interest.
LEASE OPERATING EXPENSE. Costs incurred to operate and maintain wells and
related equipment and facilities including applicable operating costs of support
equipment and facilities and other costs of operating and maintaining those
wells and related equipment and facilities.
MBbl. One thousand barrels.
Mcf. One thousand cubic feet.
Mcfd. One thousand cubic feet per day.
Mcfe. One thousand cubic feet of natural gas equivalent.
Mcfed. One thousand cubic feet of natural gas equivalent per day.
MMBbl. One million barrels.
MMbtu. One million Btus.
MMcf. One million cubic feet.
MMcfd. One million cubic feet per day.
MMcfe. One million cubic feet of natural gas equivalent.
MMcfed. One million cubic feet of natural gas equivalent per day.
31
<PAGE>
NATURAL GAS EQUIVALENT. Cubic feet of natural gas equivalent, determined
using the ratio of one Bbl of crude oil, condensate or natural gas liquids to
six Mcf of natural gas.
NET ACRES OR NET WELLS. The sum of the fractional working interests owned
in gross acres or gross wells.
OVERRIDING ROYALTY INTEREST. A royalty interest which is carved out of a
lessee's working interest under an oil and gas lease.
PRODUCTIVE WELL. A well that is producing oil and gas or that is capable of
production.
PROVED DEVELOPED NONPRODUCING RESERVES. Proved developed reserves expected
to be recovered from zones behind casing in existing wells.
PROVED DEVELOPED PRODUCING RESERVES. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and able to produce to market.
PROVED DEVELOPED RESERVES. Proved reserves that can be expected to be
recovered from completion intervals currently open in existing wells and able to
produce to market.
PROVED RESERVES. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
PROVED UNDEVELOPED RESERVES. Proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion.
PV-10 RESERVE VALUE. The pre-tax present value, discounted at 10% per
annum, of future net cash flows from estimated proved reserves (including the
estimated cost of abandonment and future development), calculated holding prices
and costs constant at amounts in effect on the date of the estimate (unless such
prices or costs are subject to change pursuant to contractual provisions). The
difference between the PV-10 Reserve Value and the standardized measure of
discounted future net cash flows is the present value of income taxes applicable
to such future net cash flows.
RECOMPLETION. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
RESERVE LIFE INDEX. Calculated by dividing year-end proved reserves by
annual production for the most recent year.
ROYALTY INTEREST. An interest in an oil and gas property entitling the
owner to a share of oil or gas production free of costs of production.
SPUD. To start (or restart) the drilling of a new well.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS. The present
value, discounted at 10% per annum, of future net cash flows from estimated
proved reserves, calculated holding prices and costs constant at amounts in
effect on the date of the estimate (unless such prices or costs are subject to
change pursuant to contractual provisions) and in all instances in accordance
with the Commission's rules for inclusion of oil and gas reserve information in
financial statements filed with the Commission.
TERM OVERRIDING ROYALTY INTEREST. An overriding royalty interest with a
fixed duration.
UNDEVELOPED ACREAGE. Lease acreage on which wells have not been
participated in or completed to a point that would permit the production of
commercial quantities of oil and gas regardless of whether such acreage contains
proved reserves.
WATERFLOOD. The injection of water into a reservoir to fill pores vacated
by produced fluids, thus maintaining reservoir pressure and assisting
production.
WORKING INTEREST. A cost bearing interest which gives the owner the right
to drill, produce and conduct oil and gas operations on the property, as well as
a right to a share of production therefrom.
32
<PAGE>
WORKOVER. Operations on a producing well to restore or increase production.
WTI. West Texas Intermediate.
33
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
PAGE
----
Independent Auditors' Report ............................................... 35
Consolidated Balance Sheets as of December 31, 1997 and 1996 ............... 36
Consolidated and Combined Statements of Income for Each of the Three Years
in the Period Ended December 31, 1997 ................................... 37
Consolidated and Combined Statements of Stockholders' Equity for Each of the
Three Years in the Period Ended December 31, 1997 ....................... 38
Consolidated and Combined Statements of Cash Flows for Each of the Three
Years in the Period Ended December 31, 1997 ............................. 39
Notes to Consolidated and Combined Financial Statements .................... 40
34
<PAGE>
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholders of
Domain Energy Corporation
We have audited the accompanying consolidated balance sheets of Domain Energy
Corporation and subsidiaries (the "Company"), the Successor, as of December 31,
1997 and 1996 and the related statements of income, stockholders' equity and
cash flows for the year ended December 31, 1997 and for the period from December
30, 1996 (date of incorporation) to December 31, 1996. We have also audited the
accompanying combined statements of income, stockholder's equity and cash flows
of Tenneco Ventures Corporation and Tenneco Gas Production Corporation (the
"Tenneco Entities"), the Predecessor, for each of the two years in the period
ended December 31, 1996. 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 financial statements present fairly, in all material
respects, the consolidated financial position of the Company and its
subsidiaries as of December 31, 1997 and 1996 and the results of operations and
cash flows for the Successor and the Predecessor for the applicable periods
indicated above in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Houston, Texas
February 17, 1998
35
<PAGE>
DOMAIN ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(NOTE 1)
(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
SUCCESSOR
----------------------
DECEMBER 31,
----------------------
1997 1996
---------- ----------
ASSETS
<S> <C> <C>
Cash and cash equivalents ......................................... $ 4,731 $ 36
Restricted certificate of deposit ................................. -- 8,000
Accounts receivable ............................................... 12,562 19,456
IPF Program notes receivable, current portion ..................... 8,873 7,874
Notes receivable - stockholders ................................... 546 --
Prepaid and other assets .......................................... 2,858 1,968
--------- --------
Total current assets ........................................ 29,570 37,334
IPF Program notes receivable, net ................................. 40,892 13,836
Oil and natural gas properties, full cost method
Proved properties ............................................ 116,782 53,514
Unproved properties .......................................... 36,603 12,662
Less: Accumulated depreciation, depletion and amortization ....... (15,411) --
--------- --------
Total oil and natural gas properties, net .................... 137,974 66,176
Other assets, net ................................................. 4,113 5,083
--------- --------
Total assets ................................................ $ 212,549 $122,429
========= ========
LIABILITIES
Accounts payable and accrued expenses ............................. $ 15,907 $ 14,060
Current maturities of long-term debt .............................. -- 24,900
--------- --------
Total current liabilities ................................... 15,907 38,960
Long-term debt .................................................... 63,720 54,512
Total liabilities ........................................... 79,627 93,472
Minority interest ................................................. 888 380
Commitments and contingencies
STOCKHOLDERS' EQUITY
Preferred stock:
$0.01 par value, 5,000,000 shares authorized, none issued ...... -- --
Common stock:
$0.01 par value, 15,080,000 shares authorized and 7,177,681
issued and outstanding at December 31, 1996 and 25,000,000
shares authorized, 15,110,111 issued and 15,107,719 outstanding
at December 31, 1997 ........................................... 151 72
Additional paid-in capital ........................................ 128,730 28,505
Treasury stock .................................................... (10) --
Retained earnings ................................................. 3,163 --
--------- --------
Total stockholders' equity .................................. 132,034 28,577
--------- --------
Total liabilities and stockholders' equity .................. $ 212,549 $122,429
========= ========
</TABLE>
The accompanying notes are an integral part of the consolidated and combined
financial statements.
36
<PAGE>
DOMAIN ENERGY CORPORATION
CONSOLIDATED AND COMBINED STATEMENTS OF INCOME
(NOTE 1)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
YEAR ENDED DECEMBER 31,
------------------------------
SUCCESSOR PREDECESSOR
--------- --------------------
1997 1996 1995
------- -------- -------
REVENUE
Oil and natural gas ...................... $47,251 $ 52,274 $34,877
IPF Activities ........................... 4,779 4,369 2,356
Other .................................... 238 (413) 414
------- -------- -------
Total revenues ............... 52,268 56,230 37,647
------- -------- -------
EXPENSES
Lease operating .......................... 14,924 10,207 7,980
Production and severance taxes ........... 1,417 1,340 710
Depreciation, depletion and amortization . 16,072 24,920 22,692
General and administrative, net .......... 4,237 3,361 2,780
Corporate overhead allocation ............ -- 4,827 2,627
Stock compensation ....................... 4,587 -- --
------- -------- -------
Total operating expenses ....... 41,237 44,655 36,789
Income from operations ................... 11,031 11,575 858
Interest expense ......................... 3,774 150 --
------- -------- -------
Income before taxes ...................... 7,257 11,425 858
Income tax provision ..................... 4,094 4,394 351
------- -------- -------
Net income ............................... $ 3,163 $ 7,031 $ 507
======= ======== =======
Net income per common share:
Basic ............................... $ 0.27
Assuming dilution ................... $ 0.26
The accompanying notes are an integral part of the consolidated and combined
financial statements.
37
<PAGE>
DOMAIN ENERGY CORPORATION
CONSOLIDATED AND COMBINED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
PREDECESSOR
----------------------------------------------------------------------
ADDITIONAL NOTES
PAID RECEIVABLE TOTAL
COMMON IN - TREASURY RETAINED STOCKHOLDER'S
STOCK CAPITAL STOCKHOLDERS STOCK EARNINGS EQUITY
---------- ---------- ----------- ---------- ---------- -------------
<S> <C> <C> <C> <C> <C> <C>
Balance at January 1, 1995 $2 $ -- $ -- $ -- $63 $65
Net income................... -- -- -- -- 507 507
---------- ---------- ----------- ---------- ---------- ------------
Balance at December 31, 1995 2 -- -- -- 570 572
Net income -- -- -- -- 7,031 7,031
---------- ---------- ----------- ---------- ---------- ------------
Balance at December 31, 1996
(prior to the Acquisition) $2 $ -- $ -- $ -- $7,601 $7,603
========== ========== =========== ========== ========== ============
SUCCESSOR
----------------------------------------------------------------------
ADDITIONAL NOTES
PAID RECEIVABLE TOTAL
COMMON IN - TREASURY RETAINED STOCKHOLDERS'
STOCK CAPITAL STOCKHOLDERS STOCK EARNINGS EQUITY
---------- ---------- ----------- ---------- ----------- ------------
Balance at December 30, 1996
(date of incorporation)...... $ -- $ -- $ -- $ -- $ -- $ --
Issuance of common stock, net 72 27,505 -- -- -- 27,577
Issuance of detachable stock
options ... 1,000 -- -- -- 1,000
---------- ---------- ----------- ---------- ----------- -----------
Balance at December 31, 1996 72 28,505 -- -- -- 28,577
Issuance of common stock, net 79 95,438 (546) -- -- 94,971
Repayment of notes
(February 1998)................ -- -- 546 -- -- 546
Purchase of common stock........ -- -- -- (10) -- (10)
Stock compensation.............. -- 4,787 -- -- -- 4,787
Net income...................... -- -- -- -- 3,163 3,163
---------- ---------- ----------- ---------- ----------- -----------
Balance at December 31, 1997 $151 $128,730 $ -- $(10) $3,163 $132,034
========== ========== =========== ========== =========== ===========
</TABLE>
The accompanying notes are an integral part of the consolidated and combined
financial statements.
38
<PAGE>
DOMAIN ENERGY CORPORATION
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
(NOTE 1)
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------
SUCCESSOR PREDECESSOR
----------------------------- --------------------
FOR THE PERIOD FROM
DECEMBER 30 ,1996
(DATE OF INCORPORATION)
1997 TO DECEMBER 31,1996 1996 1995
--------- ------------------- --------- ---------
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING
ACTIVITIES:
Net income .................................... $ 3,163 $ -- $ 7,031 $ 507
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 16,072 -- 24,920 22,692
Stock compensation ...................... 4,587 -- -- --
Deferred income taxes ................... 3,359 -- 6,702 883
Minority interest ....................... 508 -- 380 --
Allowance for doubtful IPF investments .. -- -- 437 --
Changes in operating assets and liabilities:
Decrease (increase) in accounts
receivable .................................... 998 -- (7,584) (6,731)
Decrease (increase) in prepaids and
other current assets ................. (705) -- 83 (956)
Increase (decrease) in accounts payable
and accrued expenses ................. (6,968) -- 2,584 3,538
-------- --------- -------- --------
Net cash provided by operating activities ..... 21,014 -- 34,553 19,933
CASH FLOWS FROM INVESTING
ACTIVITIES:
Acquisition of the Tenneco Entities ........... -- (96,164) -- --
Purchase of restricted certificate of deposit . -- (8,000) -- --
Investment in oil and natural gas properties .. (42,439) -- (32,023) (44,118)
Investment in Funds Acquisition ............... (28,419) -- -- --
Investment in Gulfstar Acquisition, net of cash
acquired .................................... (7,464) -- -- --
Proceeds from sale of oil and natural gas
properties .................................. 3,862 -- 1,546 8,275
Proceeds from sale of equity investments ...... 7,622 -- -- --
IPF Program investments of capital (notes
receivable) ................................. (40,164) -- (19,045) (6,606)
IPF Program return of capital (notes
receivable) ................................. 12,109 -- 4,618 2,638
Proceeds from sale of restricted certificate of
deposit ..................................... 8,000 -- -- --
Investments and other assets .................. (709) -- (2,425) 83
-------- --------- -------- --------
Net cash used in investing activities ......... (87,602) (104,164) (47,329) (39,728)
CASH FLOWS FROM FINANCING
ACTIVITIES:
Proceeds from debt borrowings ................. 67,830 73,200 6,968 --
Repayments of debt borrowings ................. (83,508) -- (756) --
Advances from Parent, net ..................... -- -- 6,564 8,328
Issuance of common stock, net ................. 86,961 31,000 -- --
-------- --------- -------- --------
Net cash provided by financing activities ..... 71,283 104,200 12,776 8,328
Increase in cash and cash equivalents ......... 4,695 36 -- (11,467)
Cash and cash equivalents, beginning of period 36 -- -- 11,467
-------- --------- -------- --------
Cash and cash equivalents, end of period ...... $ 4,731 $ 36 $ -- $ --
======== ========= ======== ========
</TABLE>
The accompanying notes are an integral part of the consolidated and combined
financial statements.
39
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
1. ORGANIZATION, BASIS OF PRESENTATION AND NATURE OF OPERATIONS
Through December 11, 1996, Tenneco Ventures Corporation ("Ventures") and
Tenneco Gas Production Corporation ("Production" and together with Ventures, the
"Tenneco Entities") were indirect subsidiaries of Tenneco, Inc. ("Tenneco"). As
a result of a merger between Tenneco and a subsidiary of El Paso Natural Gas
Company ("El Paso"), Ventures and Production became wholly owned indirect
subsidiaries of El Paso for the period from December 12, 1996 to December 31,
1996. On December 31, 1996, Domain Energy Corporation ("Domain") acquired all of
the outstanding common stock of Ventures and Production (the "Acquisition").
Domain was incorporated in Delaware in December 1996 to acquire such common
stock and had no operations prior to the Acquisition. Unless otherwise
indicated, references to the Company are to Domain and its subsidiaries at and
subsequent to December 31, 1996 and to the combined activities of the Tenneco
Entities prior to December 31, 1996. References to the Parent are to Tenneco or
its affiliates prior to December 11, 1996 and to El Paso from December 12, 1996
to December 31, 1996.
The Company was capitalized on December 31, 1996 with the issuance of
7,177,681 shares of common stock for $30.0 million and borrowings of $66.2
million under its credit facilities. The Company completed the Acquisition for a
total cash purchase price of approximately $96.2 million and the assumption of
liabilities of approximately $16.8 million. The Company did not assume the
liability of $124.1 million due to the parent of the Tenneco Entities. The
Company has accounted for the Acquisition using the purchase method of
accounting. The assets and liabilities of the Tenneco Entities have been
recorded in the Company's balance sheet at December 31, 1996 at their estimated
fair market values, summarized as follows (in thousands):
ASSETS: LIABILITIES:
Accounts receivable -- trade......$ 19,456 Accounts payable ....$ (10,624)
IPF Program notes receivable...... 21,710 Long-term debt........ (6,212)
Oil and gas properties............ 66,176 Total liabilities ...$ (16,836)
===========
Other assets...................... 5,658
-----------
Total assets....................$ 113,000
==========
The financial statements of the Tenneco Entities for each of the years
ended December 31, 1996 and 1995 have been combined to reflect their combined
historical results of operations.
The following unaudited pro forma summary presents the consolidated
results of operations of the Company for the years ended December 31, 1995 and
1996 as if the Acquisition had occurred at the beginning of each fiscal year (in
thousands):
1995 1996
---- ----
Revenues................................ $ 37,647 $ 56,230
Net income.............................. $ 3,024 $ 9,714
The Company is an independent oil and gas company engaged in the
exploration, development, production and acquisition of oil and natural gas
properties, principally in the Gulf Coast region. The Company complements these
activities with its Independent Producer Finance Program ("IPF Program")
pursuant to which it invests in oil and natural gas reserves through the
acquisition of term overriding royalty interests.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION AND COMBINATION -- The consolidated balance
sheets at December 31, 1997 and 1996 include the accounts of the Company and its
majority-owned subsidiaries. Prior to July 1, 1997, the Company sponsored and
managed two oil and gas investment programs for unaffiliated institutional
investors (the "Funds"). The Company had a 10% interest in one program and a 30%
interest in the other. The Company and the investors each owned direct undivided
interests in oil and gas properties. The Company accounted for its interests in
the Funds using the pro rata method of consolidation. On July 1, 1997, the
Company acquired the direct undivided interests of the Funds. See Note 6.
40
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - (CONTINUED)
Until April 9, 1997, the Company owned 35% of the voting capital stock
of Michigan Production Company L.L.C. ("MPC") and 28% of the voting capital
stock of Michigan Energy Company, L.L.C. ("MEC"). Both were accounted for using
the equity method of accounting. On April 9, 1997, the Company sold its MPC and
MEC equity investments. See Note 5.
The following presents combined summary information for MPC and MEC (in
thousands):
As of Year Ended
December 31, December 31,
1996 1996
------------ -------------
Current assets ........... $1,654 Revenues ............. $690
Non-current assets........ 35,601 Operating expenses.... 953
Current liabilities....... 6,640 Net income ........... (520)
Non-current liabilities... 27,587
The combined financial statements of the Tenneco Entities include their
combined accounts and the combined accounts of their majority-owned
subsidiaries. All significant intercompany accounts and transactions have been
eliminated.
OIL AND GAS PROPERTIES -- Investments in oil and gas properties are
accounted for using the full cost method of accounting. All costs associated
with the acquisition, exploration, exploitation and development of oil and gas
properties are capitalized. General and administrative costs of $2.3 million,
$2.6 million and $2.1 million were included in capitalized costs for the years
ended December 31, 1997, 1996 and 1995, respectively. Such capitalized costs
include payroll and other related costs attributable to the Company's
acquisition and exploration activities. Interest cost of $0.8 million was
included in the capitalized costs for the year ended December 31, 1997
representing the cost of borrowings relating to the Company's unproven
properties. Costs related to production, development, and the IPF Program
activities are expensed within the presented year and not capitalized.
Oil and gas properties are amortized using the unit-of-production method
using estimates of proved reserve quantities. Investments in unproved properties
are not amortized until proved reserves associated with the projects can be
determined or until impairment occurs. If the results of the assessment indicate
that the properties are impaired, the amount of impairment is added to the
proved oil and gas property costs to be amortized. The amortizable base includes
future development costs and, where significant, dismantlement, restoration, and
abandonments costs, net of estimated salvage values. The depletion rate per Mcfe
for the years ended December 31, 1997, 1996 and 1995 was $0.78, $1.01 and $1.08,
respectively.
Sales of proved and unproved properties are accounted for as adjustments
of capitalized costs with no gain or loss recognized, unless such adjustments
would significantly alter the relationship between capitalized costs and proved
reserves. Abandonments of properties are accounted for as adjustments of
capitalized costs with no loss recognized.
In addition, the total capitalized costs of oil and gas properties are
subject to a "ceiling test," which limits such costs to the estimated present
value, discounted at a 10% interest rate, of future net cash flows from proved
reserves, based on current economic and operating conditions, plus the lower of
cost or fair value of unproved properties. If capitalized costs exceed this
limit, the excess is charged to depreciation, depletion and amortization.
OTHER ASSETS -- Other capital cost, including computer equipment, 3-D
workstations, furniture and fixtures, debt issuance costs and organizational
costs are amortized over a three to five year period using the straight-line
method.
INDEPENDENT PRODUCER FINANCE PROGRAM -- Through its IPF Program, the
Company acquires term overriding royalty interests in oil and gas properties
owned by independent producers. Because the funds advanced to a producer for
these interests are repaid from an agreed upon share of cash proceeds from the
sale of production until the amount advanced plus interest is paid in full, the
Company accounts for the term overriding royalty interests as notes receivable.
Under this accounting method, the Company recognizes only the interest income
portion of payments received from a producer as revenues from IPF Activities on
its income statement. The remaining cash receipts are recorded as a reduction in
notes
41
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - (CONTINUED)
receivable on the Company's balance sheet and as IPF Program return of capital
on the Company's statement of cash flows. The Company records an impairment for
its investments on a case-by-case basis when it determines repayment to be
doubtful.
PARENT ADVANCES. -- Prior to the Acquisition, Parent advances to the
Company for net working capital and capital expenditure requirements were
recorded as non-current liabilities on the combined balance sheet. The Parent
did not charge the Company any interest expense on the funds utilized by the
Company.
INCOME TAXES -- Through December 31, 1996, the Company's taxable income
is included in a consolidated United States income tax return with the Parent.
The intercompany tax allocation policy between the Company and the Parent
provided that each member of the consolidated group compute a provision for
income taxes on a separate return basis.
The Company follows Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes" (FAS 109). This statement requires deferred tax
assets and liabilities to be determined by applying tax regulations existing at
the end of a reporting period to the cumulative temporary differences between
the tax bases of assets and liabilities and their reported amounts in the
financial statements. See Note 11.
OIL AND GAS HEDGING ACTIVITIES -- The Company periodically uses
derivative financial instruments to manage price risks related to oil and
natural gas sales and not for speculative purposes. For book purposes, gains and
losses related to the hedging of anticipated transactions are recognized as
income when the hedged transaction occurs.
The Company primarily utilizes price swap agreements with major energy
companies to accomplish its hedging objectives. The price swap agreements
generally provide for the Company to receive or make counter-party payments on
the differential between a fixed price and a variable indexed price. Total oil
and natural gas sales hedged during the years ended December 31, 1997, 1996 and
1995 were 244,540 Bbls and 12,010 MMbtus, 258,710 Bbls and 16,025 MMbtus and
65,840 Bbls and zero MMbtus, respectively. Gains (losses) realized by the
Company under such hedging arrangements, and reported as an increase (reduction)
of revenues, were ($4.6 million), ($10.5 million) and $0.2 million for the years
ended December 31, 1997, 1996 and 1995, respectively. The following table sets
forth the Company's open hedging contracts for oil and natural gas under various
price swap agreements with major energy companies as of December 31, 1997:
CRUDE OIL NATURAL GAS
------------------------------- ------------------------
WEIGHTED AVERAGE WEIGHTED AVERAGE
FIXED SALES FIXED SALES
BBLS PRICE MMBTU PRICE
---------- ------------------- ---------- -------------
Jan 1998 -- Dec 1998 194,210 $17.91 4,560 $2.14
Jan 1999 -- Dec 2000 248,340 $18.72 -- --
Subsequent to December 31, 1997, the Company terminated its oil swap
agreements for 1999 and 2000. The Company received $47,673 in settlement of
these swap agreements.
Subsequent to December 31, 1997, the Company sold natural gas futures
contracts covering an average of 30 MMcfd of its expected natural gas production
for March 1998 through June 1998. Under these contracts, the Company will
receive an average price of $2.20 per MMbtu for March 1998 and $2.28 per MMbtu
for April 1998 through June 1998.
REVENUE RECOGNITION -- The Company recognizes oil and gas revenue from
its interests in producing wells as oil and gas is sold from those wells. Oil
and gas sold in production operations is not significantly different from the
Company's share of production. The Company recognizes financing revenues from
its IPF activities using the effective interest rate method.
The Company utilizes the sales method to account for gas production
volume imbalances. Under this method, income is recorded based on the Company's
net revenue interest in production taken for delivery. Management does not
believe that the Company had any material natural gas imbalances at December 31,
1997 or 1996.
42
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - (CONTINUED)
FINANCIAL INSTRUMENTS -- The Company's financial instruments consist of
cash, accounts and notes receivable, payables, long-term debt and oil and
natural gas commodity hedges. The carrying amount of cash, accounts receivable
and payables approximates fair value because of the short-term nature of these
items. Based on current industry and other conditions, management believes that
the carrying value of its IPF Program notes receivable approximates, at a
minimum, their fair value. The carrying value of long-term debt approximates
fair value because the individual borrowings bear interest at floating market
rates. Assuming a market price based on the twelve-month strip as of December
31, 1997, the Company's projected losses from open hedge contracts were
approximately $0.3 million as of December 31, 1997. Considerable judgment is
required in developing these estimates and, accordingly, no assurance can be
given that the estimated values presented herein are indicative of amounts that
would be realized in a full market exchange.
USE OF ESTIMATES -- The preparation of financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenue and expenses during
the reporting periods. Actual results could differ from these estimates.
Significant estimates include depreciation, depletion and amortization of proved
producing oil and natural gas properties; estimates of proved oil and natural
gas reserve volumes; and discounted future net cash flows.
CONCENTRATION OF RISK -- Substantially all of the Company's accounts and
notes receivable result from oil and natural gas sales, joint interest billings
and lending activities to third parties in the oil and natural gas industry.
This concentration of customers, joint interest owners and borrowers may impact
the Company's overall credit risk in that these entities may be similarly
affected by changes in economic and other conditions.
CHANGE IN PRESENTATION -- Certain 1996 and 1995 amounts have been
reclassified to conform to the 1997 presentation.
MAJOR CUSTOMERS -- The Company has sold to certain major customers oil
and gas production representing 57%, 57% and 56% of its oil and gas revenues for
the years 1997, 1996 and 1995, respectively. Based upon the current demand for
oil and gas, the Company believes that the loss of any of these purchasers would
not have a material adverse effect on the Company.
STATEMENTS OF CASH FLOWS -- The statements of cash flows are presented
using the indirect method and consider all highly liquid investments with
maturities at the time of purchase of three months or less to be cash
equivalents.
Supplemental cash flow information may be summarized as follows (in
thousands):
SUCCESSOR PREDECESSOR
---------------------- ----------------
1997 1996 1996 1995
----------- ---------- --------- ------
Interest expense paid ................... $ 4,401 $ -- $307 $ --
Income taxes paid ....................... 445 -- -- --
Acquisitions:
Total cash consideration:
The Acquisition .................. $ -- 96,164 $-- $ --
Funds Acquisition ................ 28,419 -- -- --
Gulfstar Acquisition ............. 8,000 -- -- --
Fair value of assets acquired:
The Acquisition .................. $ -- 113,000 $-- $ --
Funds Acquisition ................ 28,419 -- -- --
Gulfstar Acquisition ............. 17,802 -- -- --
Liabilities assumed:
The Acquisition ................. $ -- 16,836 $-- $--
Gulfstar Acquisition ............ 1,802 -- -- --
Non-Cash Items:
Stock issued in connection with
Gulfstar Acquisition............. $ 8,000 $ -- $-- $ --
43
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - (CONTINUED)
EARNING PER SHARE --- The Financial Accounting Standards Board issued
Statement No. 128, "Earnings Per Share," (SFAS 128) in February 1997. SFAS 128,
which is effective for periods ended after December 15, 1997, establishes
standards for computing and presenting earnings per share (EPS). SFAS 128
replaces the presentation of primary EPS previously prescribed by Accounting
Principles Board Opinion No. 15 (APB 15) with a presentation of basic EPS which
is computed by dividing income available to common stockholders by the
weighted-average number of common shares outstanding for the period. SFAS 128
also requires dual presentation of basic and diluted EPS. Diluted EPS is
computed similarly to fully diluted EPS pursuant to APB 15 and assumes the
exercise of dilutive stock options less the number of treasury shares assumed to
be purchased from the proceeds using the average market price of the Company's
Common Stock. For the year ended December 31, 1997, the Company has adopted this
statement.
The following table is a reconciliation of the numerators and
denominators of the basic and diluted earning per share computations for net
income (in thousands, except per share data):
FOR THE YEAR ENDED DECEMBER 31, 1997
---------------------------------------
INCOME SHARES PER SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ------
BASIC EPS
Income available to common
stockholders ........................ $3,163 11,578 $0.27
=======
EFFECT OF DILUTIVE SECURITIES
Stock options .......................... -- 548
---------- ---------
DILUTED EPS
Income available to common
stockholders ........................ $3,163 12,126 $0.26
=========== ======== =======
The Company had no options outstanding at December 31, 1997 which have
not been included in the EPS computation.
EMPLOYEE STOCK-BASED COMPENSATION -- In October 1995, Financial
Accounting Standards Board Statement No. 123, "Accounting for Stock Based
Compensation" (SFAS 123) was issued. Under SFAS 123, the Company is permitted to
either record expenses for stock options and other stock-based employee
compensation plans based on their fair value at the date of grant or to apply
the existing standard, Accounting Principles Board Opinion No. 25 (APB 25) and
recognize compensation expense, if any, based on the intrinsic value of the
equity instrument at the measurement date. The Company has elected to continue
to follow APB 25. See Note 10.
3. NOTES RECEIVABLE -- INDEPENDENT PRODUCER FINANCING
At December 31, 1997 and 1996, the Company had total outstanding notes
receivable related to its IPF Program of $49.8 million and $21.7 million,
respectively. The notes receivable result from the Company's purchase of
production payments in the form of term overriding royalty interests in exchange
for an agreed upon share of revenues from identified properties until the amount
invested and a specified rate of return on investment is paid in full. During
1997 and 1996, the Company realized returns from the IPF Program of 14.5% and
17.7%, respectively. The weighted average returns expected by the Company on the
notes receivable outstanding at December 31, 1997 and December 31, 1996 were
19.0% and 20.9%, respectively. While the independent producer's obligation to
deliver such revenues is nonrecourse to the producer, management believes that
the Company's overriding royalty interest constitutes a property interest and
therefore, such property interest and the underlying oil and gas reserves
effectively serve as security for the notes receivable. Based on reserve data
available, the Company has estimated that $8.9 million and $7.9 million of notes
receivable at December 31, 1997 and 1996 will be repaid in the next twelve
months and has classified such amounts as current assets.
In fiscal 1996, the Company established an allowance for doubtful
accounts of approximately $0.4 million related to its IPF Program, which is the
balance of such account at December 31, 1997 and 1996. No other allowance
activity occurred
44
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - (CONTINUED)
during the three years ended December 31, 1997. The allowance for doubtful
accounts was zero for the year ended December 31, 1995. Based on the December
31, 1997 notes receivable balance, expected principal payments in each of the
next five years are as follows (in thousands):
1998.................................... $ 8,873
1999.................................... $ 8,857
2000.................................... $ 7,721
2001.................................... $ 7,063
2002.................................... $ 5,691
4. UNEVALUATED PROPERTY
Oil and natural gas properties not subject to amortization consist of
the cost of undeveloped leaseholds, and exploratory and developmental wells in
progress. These costs are reviewed periodically by management for impairment,
with the impairment provision included in the cost of oil and natural gas
properties subject to amortization. Factors considered by management in its
impairment assessment include drilling results by the Company and other
operators, the terms of oil and gas leases not held by production and available
funds for exploration and development. The following table summarizes the cost
of the properties not subject to amortization for the year cost was incurred (in
thousands):
DECEMBER 31,
----------------------
Year cost incurred: 1997 1996
---------- -----------
1996 $ 10,385 $ 12,662
1997 26,218 --
---------- -----------
$ 36,603 $ 12,662
========== ===========
5. SALE OF NON-CORE ASSETS
On April 9, 1997, the Company sold its interest in a natural gas
development project located in northwest Michigan, previously accounted for
under the equity method, (the "Michigan Development Project"). The Company
received $7.6 million in cash for its interest, net of debt repayment. The
aggregate sales price approximated the Company's book value. Additionally, in
1997 the Company received $3.9 million from the sale of other non-core assets.
6. ACQUISITIONS
On July 1, 1997, the Company consummated the acquisition (the "Funds
Acquisition") of certain property interests from three unaffiliated
institutional investors. Such interests are primarily located in the Gulf Coast
region and, as of January 1, 1997, had combined proved reserves of approximately
33.0 Bcfe. The interests also include 18,209 net undeveloped leasehold acres.
The aggregate purchase price for the interests was approximately $28.4 million,
which was paid in cash with a portion of the net proceeds of the initial public
offering of the Company's common stock consummated on June 27, 1997.
The following unaudited pro forma summary presents the consolidated
results of operations of the Company for the years ended December 31, 1997 and
1996 as if the Funds Acquisition had occurred at the beginning of each fiscal
year. The 1996 pro forma amounts also give effect to the Acquisition discussed
in Note 1.
(in thousands, except per share data)
YEAR ENDED YEAR ENDED
DECEMBER 31, 1997 DECEMBER 31, 1996
----------------- -----------------
Revenues $ 58,289 $ 70,409
Net income $ 4,443 $ 14,272
Net income per share (1) $ 0.37 N/A
------------
(1) EPS assuming dilution.
45
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - (CONTINUED)
On December 15, 1997, the Company acquired all of the outstanding
capital stock of Gulfstar Energy, Inc. and Mid Gulf Drilling Corp. (the
"Gulfstar Acquisition"). The aggregate purchase price of these privately held,
independent energy companies was $16.6 million, comprised of $8.6 million in
cash and 499,990 shares of the Company's common stock valued at $16.00 per
share.
The following unaudited pro forma summary presents the consolidated
results of operations of the Company for the years ended December 31, 1997 and
1996 as if the Gulfstar Acquisition had occurred at the beginning of each fiscal
year. The 1997 and 1996 pro forma amounts also give effect to the Acquisition
and to the Funds Acquisition discussed above.
(in thousands, except per share data)
YEAR ENDED YEAR ENDED
DECEMBER 31, 1997 DECEMBER 31, 1996
----------------- -----------------
Revenues $ 61,946 $ 71,685
Net income $ 4,699 $ 13,537
Net income per share (1) $ 0.37 N/A
(1) EPS assuming dilution. EPS calculation assumes that 499,990 share of common
stock issued in connection with the Gulfstar Acquisition was outstanding for the
entire year
7. LONG-TERM DEBT
At December 31, 1997 and 1996, notes payable and long-term debt
consisted of the following (in thousands):
DECEMBER 31,
---------------------
1997 1996
------- -------
Company Credit Facility ........................ $34,552 $61,200
Indebtedness to Fund VII ....................... -- 7,000
IPF Credit Facility ............................ 29,168 11,212
------- -------
Long-term debt ................................. $63,720 $79,412
Less current maturities ........................ -- (24,900)
------- -------
$63,720 $54,512
======= =======
COMPANY CREDIT FACILITY -- In connection with the Acquisition, the
Company entered into a $65.0 million revolving credit facility maturing on
December 31, 1999 (the "Company Credit Facility") with a group of banks led by
The Chase Manhattan Bank (the "Lenders"). The Company Credit Facility is secured
by approximately 80% of the aggregate value of the Company's oil and gas
properties and substantially all of the Company's other property (other than IPF
Program related properties), including the capital stock of Ventures and
Production and is also guaranteed by Ventures and Production. Amounts available
under the Company Credit Facility are subject to a borrowing base with scheduled
redeterminations every six months (and such other redeterminations as the
Lenders may elect to perform) by the Lenders at the Lenders' sole discretion and
in accordance with their customary practices and standards in effect from time
to time for reserve-based loans to borrowers similar to the Company. The
borrowing base under the Company Credit Facility at December 31, 1997 was $50.0
million.
Absent a default or an event of default, borrowings under the Company
Credit Facility accrue interest at LIBOR plus a margin of 1.50% to 2.50% per
annum depending on the total amount outstanding or, at the option of the
Company, at the greater of (i) the prime rate and (ii) the federal funds
effective rate plus 0.50%, plus a margin of 0.50% to 1.50% depending on the
total amount outstanding. The Company also incurs a quarterly commitment fee
ranging from 0.375% to 0.50% per annum on the average unused portion of the
Lenders' aggregate commitment depending on the total amount outstanding and an
administrative fee of $25,000 payable annually in advance. The interest rate on
the amounts outstanding at December 31, 1997 was 7.97%.
46
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - (CONTINUED)
The Company Credit Facility contains a number of covenants that, among
other things, restrict the ability of the Company to dispose of assets, incur
additional indebtedness, pay dividends, enter into certain investments or
acquisitions, repurchase or redeem capital stock, engage in mergers or
consolidations, or engage in certain transactions with subsidiaries and
affiliates and that will otherwise restrict corporate activities. In addition,
such facility requires the Company to maintain a specified minimum tangible net
worth and to comply with certain prescribed financial ratios. Further, under
such facility, an event of default is deemed to occur if any person, other than
the Company's officers, Fund VII or any other investment fund, the managing
general partner of which is First Reserve Corporation ("First Reserve"), becomes
the beneficial owner, directly or indirectly, of more than 40% of the
outstanding shares of Common Stock.
IPF CREDIT FACILITY -- Domain Energy Finance Corporation ("IPF
Company"), an indirect wholly-owned subsidiary of the Company, has a $150.0
million revolving credit facility (the "IPF Credit Facility") agented by Compass
Bank-Houston ("Compass") through which it finances a portion of the IPF Program.
The IPF Credit Facility matures June 1, 1999 at which time all amounts owed
thereunder are due and payable. The IPF Credit Facility is secured by
substantially all of IPF Company's oil and gas term overriding royalty
interests, including the notes receivable generated therefrom. The borrowing
base under the facility as of December 31, 1997 was $40.0 million and is subject
to a scheduled redetermination by Compass every six months and such other
redeterminations as Compass may elect to perform each year. Absent a default or
an event of default (as defined therein), borrowings under the IPF Credit
Facility accrue interest at LIBOR plus a margin of 1.75 to 2.25% per annum
depending on the total amount outstanding or, at the option of the IPF Company,
the prime rate published in THE WALL STREET JOURNAL. The Company also incurs a
quarterly commitment fee ranging from 0.375% to 0.50% per annum on the average
unused portion of the aggregate commitment depending on the total amount
outstanding and an administrative fee of $15,000 payable annually in advance.
The interest rate on the amounts outstanding as of December 31, 1997 was 8.21%.
The IPF Credit Facility contains a number of covenants that, among other
things, restrict the ability of IPF Company to incur additional indebtedness or
grant liens on its properties, guarantee indebtedness of any other person,
dispose of assets, make loans in excess of $100,000 other than in the ordinary
course of its business, issue additional shares of capital stock, engage in
certain transactions with affiliates, enter into any new line of business or
amend certain of its material contracts. In addition, such facility requires IPF
Company to maintain a specified minimum tangible net worth.
The IPF Credit Facility restricts the ability of the IPF Company to
dividend cash to its parent, Ventures, or otherwise advance cash to the Company.
At December 31, 1997, IPF Company net assets of approximately $10.4 million were
restricted.
INDEBTEDNESS TO FUND VII -- Prior to the Acquisition, Tennessee Gas
Pipeline Company ("TGPL"), the former wholly-owning parent of Ventures, was a
guarantor with respect to certain indebtedness (the "Michigan Senior Debt") of a
partnership formed to participate in a development project in Michigan in which
Ventures was at the time a general partner. In connection with the Acquisition,
the Company formed Domain Energy Guarantor Corporation ("Guarantor
Corporation"), for the sole purpose of assuming the obligations of TGPL under
such guaranty. As security for its obligations under the guaranty, Guarantor
Corporation purchased an $8.0 million certificate of deposit issued by the
lender in respect of the Michigan Senior Debt and assigned and pledged such
certificate to the lender.
To enable Guarantor Corporation to purchase the $8.0 million certificate
pledged as collateral for its guaranty of the Michigan Senior Debt, First
Reserve Fund VII, Limited Partnership ("Fund VII"), the Company's sole
stockholder at December 31, 1996, loaned Guarantor Corporation $8.0 million
evidenced by a Subordinated Promissory Note dated December 31, 1996 (the
"Note"). The full principal amount of the Note was scheduled to mature on
December 31, 1999. Interest accrued on the Note at a rate per annum equal to the
interest rate per annum earned by Guarantor Corporation on the $8.0 million
certificate and was payable quarterly. The obligations of Guarantor Corporation
under the Note were expressly made subordinated and subject in right of payment
to the prior payment in full of the Michigan Senior Debt. Pursuant to the terms
of the Note, Fund VII had the right to convert the Note into common stock. In
accordance with APB 14, $1.0 million of the Note was reclassified from notes
payable to additional paid-in capital on the Company's financial statements. As
a result of the reclassification the effective interest rate on the Note
increased from 4.60% to 5.26%. The remaining $7.0 million of the Note was
classified as current maturities of long-term debt at December 31, 1996 in
keeping with Fund VII's intent to exercise
47
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - (CONTINUED)
its option to acquire common stock concurrent with consummation of the Company's
initial public offering ("the Offering"). Upon consummation of the Offering, in
June 1997, the Note was repaid.
8. RELATED PARTY TRANSACTIONS
Prior to the Acquisition, the Company paid an affiliate of the Parent
for various administrative support services, including treasury, legal, tax,
human resources and administration. Allocations were based on the Company's
percentage of total assets as compared to the Parent's total assets. Included in
the 1996 allocation was approximately $2.0 million of costs that were directly
related to severance payments, retention bonuses and other costs associated with
the merger of Tenneco with an affiliate of El Paso Natural Gas Company.
Management of the Company believes that the allocations were reasonable and
approximate those costs which would have been incurred from unrelated parties.
Prior to the Acquisition, the Parent also advanced various amounts to
the Company for working capital and capital expenditure requirements. The Parent
did not charge the Company any interest expense on the funds utilized by the
Company. The average amounts of advances outstanding from the Parent were
approximately $118.5 million and $107.7 million for the years ended December 31,
1996 and 1995, respectively. A summary of the activity in the advances from
Parent account follows (in thousands):
1996 1995
---------- ----------
Beginning balance, January 1, $112,832 $ 104,504
Cash advances, net 1,737 5,545
Corporate overhead allocation......................... 4,827 2,627
Other allocations (accrued taxes)................ 4,734 156
Liability to Parent at Acquisition date not
assumed by the Company (12,413) --
---------- ----------
Ending balance, December 31 $ -- $112,832
========== ==========
In 1997, the Company paid First Reserve, the managing partner of Fund
VII, a fee of $500,000 for financial advisory services rendered in connection
with the Acquisition.
9. STOCKHOLDERS' EQUITY
COMMON STOCK -- As of June 20, 1997, the Company was authorized to issue
up to 25,000,000 shares of Common Stock, $.01 par value per share. All share
amounts in the financial statements have been retroactively restated to present
a 754-for-one stock split effected on June 20, 1997. As of December 31, 1997,
there were 15,110,111 shares of Common Stock issued and 15,107,719 outstanding
with 2,392 shares held in treasury. As of December 31, 1996, there were
7,177,681 shares of Common Stock issued and outstanding. Holders of Common Stock
are entitled to one vote for each share held and are not entitled to cumulative
voting for the purpose of electing directors and have no preemptive or similar
right to subscribe for, or to purchase, any shares of Common Stock or other
securities to be issued by the Company in the future. Accordingly, the holders
of more than 50% in voting power of the shares of Common Stock voting generally
for the election of directors will be able to elect all of the Company's
directors.
OPTION TO ACQUIRE COMMON STOCK -- Pursuant to the Subscription
Agreement, dated December 31, 1996 (the "First Reserve Subscription Agreement"),
between the Company and Fund VII, the Company granted to Fund VII an option (the
"First Reserve Option") to acquire 1,914,048 shares of Common Stock for an
aggregate purchase price of $8.0 million plus any accrued interest on the Note
(the "Option Price") (see Note 7). The Option Price could be paid by Fund VII
(i) prior to the date on which the Note has been paid in full, by delivery to
the Company of the Note together with the payment in cash of any principal or
interest payments on the Note previously received by Fund VII and (ii) after the
date on which the Note has been paid in full, by payment of the Option Price in
cash. In connection with the Offering the Company and Fund VII agreed to
restructure the terms of the First Reserve Option as set forth below.
48
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - (CONTINUED)
The Company and Fund VII agreed that concurrently with consummation of
the Offering, Fund VII would purchase a number of shares of Common Stock at the
Offering price such that the aggregate purchase price paid by Fund VII for such
shares equals $8,681,000. The amount of $8,681,000 represents the sum of (i) the
outstanding principal balance of the Note plus estimated accrued interest
thereon through June 15, 1997 and (ii) $500,000 in cash to be paid by Fund VII.
This transaction was completed on June 24, 1997.
In accordance with APB 14, $1.0 million of the Note, representing the
estimated fair value of the First Reserve Option, has been reclassified from
notes payable to additional paid-in capital. See Note 7.
PREFERRED STOCK -- The Board of Directors is authorized, without action
by the holders of Common Stock, to issue up to 5,000,000 shares of preferred
stock, $.01 par value per share (the "Preferred Stock"), in one or more series,
to establish the number of shares to be included in each such series and to fix
the designations, preferences, relative, participating, optional and other
special rights of the shares of each such series and the qualifications,
limitations and restrictions thereof. Such matters may include, among others,
voting rights, conversion and exchange privileges, dividend rates, redemption
rights, sinking fund provisions and liquidation rights that could be superior
and prior to the Common Stock. As of December 31, 1997 and 1996, no shares of
preferred stock were issued and outstanding.
10. STOCK-BASED COMPENSATION
The Company maintains two stock-based compensation plans, which are
described below. The Company applies APB Opinion No. 25 and related
interpretations in accounting for its stock-based compensation plans. In October
1995, the FASB issued Statement of Financial Accounting Standard No. 123,
"Accounting for Stock-Based Compensation" (FAS 123), which encourages, but does
not require, all entities to record compensation expense on all stock-based
compensation plans based upon fair value. However, pro forma disclosures as if
the Company adopted the cost recognition provisions of FAS 123 in 1997 are
presented below.
STOCK PURCHASE AND OPTION PLAN -- In 1996, the Company adopted the
Amended and Restated 1996 Stock Purchase and Option Plan for Key Employees of
Domain Energy Corporation and Affiliates (the "Stock Purchase and Option Plan").
The Stock Purchase and Option Plan authorizes the issuance of options to acquire
up to 867,091 shares of Common Stock and the Company has reserved 867,091 shares
of Common Stock for issuance in connection therewith. The Stock Purchase and
Option Plan is administered by the Compensation Committee of the Board of
Directors. Pursuant to the Stock Purchase and Option Plan, the Company may grant
to employees, directors or other persons having a unique relationship with the
Company or its affiliates, singly or in combination, Incentive Stock Options,
Other Stock Options, Stock Appreciation Rights, Restricted Stock, Purchase
Stock, Dividend Equivalent Rights, Performance Units, Performance Shares or
Other Stock-Based Grants, in each case as such terms are defined therein. The
terms of any such grant will be determined by the Compensation Committee and set
forth in a separate grant agreement. The exercise price will be at least equal
to 100% of fair market value of the Common Stock on the date of grant in the
case of Incentive Stock Options and the exercise price of Other Stock Options
will be at least equal to 50% of fair market value of the Common Stock on the
date of grant, provided that options to purchase up to 433,546 shares of Common
Stock may be granted with an exercise price equal to $.01 per share, which is
the par value of the Common Stock. Non-Qualified Stock Options and Other Stock
Options may be exercisable for up to ten years.
On February 21, 1997 (the "Grant Date"), the Company granted to the
officers of the Company, pursuant to separate Non-Qualified Stock Option
Agreements (collectively, as amended, the "Stock Option Agreements") between the
Company and each of such persons, options to purchase a total of 753,998 shares
of Common Stock under the Stock Purchase and Option Plan. In addition, the
Company has granted options to purchase an aggregate of 95,696 shares of Common
Stock to other employees of the Company. Under the terms of the Stock Option
Agreements, 50% of the options granted to each such person are designated as
time options (collectively, the "Time Options"), with an exercise price equal to
$4.18 per share, and 50% are designated as performance options (collectively,
the "Performance Options"), with an exercise price equal to $.01 per share. The
Time Options become exercisable as to 20% of the shares of Common Stock subject
thereto on the first anniversary of the Grant Date and are exercisable as to an
additional 20% of such shares upon each anniversary of the Grant Date
thereafter. The Performance Options become exercisable at any time following the
second anniversary of the Grant Date, when the Investment Return Hurdle (as such
term is defined) is met; provided that the Performance Options become
exercisable as to 100% of the shares of Common Stock subject thereto on the
ninth anniversary of the Grant Date.
49
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - (CONTINUED)
At December 31, 1997, the Company had an additional 24,574 options
available to grant. The following is a summary of all stock option activity for
1997:
Number Weighted
of Shares of Average
Underlying Exercise
Options Prices
----------------- -------------
Outstanding at December 31, 1996...... -- --
Granted 869,704 $ 2.36
Exercised -- --
Forfeited (7,177) $ 2.10
Expired -- --
----------------- -------------
Outstanding at December 31, 1997...... 862,527 $ 2.36
================= =============
Exercisable at December 31, 1997....... 6,670 $13.50
The weighted average per share fair value of options granted during 1997
was $3.28.
The fair value of each option granted during 1997 was estimated as of
the date of grant using the Black-Sholes option-pricing model with the following
weighted-average assumptions for grants in 1997: no dividend yield; expected
volatility of zero for options granted prior to the Offering and an expected
volatility of 44.6% for options granted on or after the Offering; risk-free
interest rates ranging from 5.44% to 6.70% ; and an expected option life of 2.50
years.
The following table summarizes information about stock options
outstanding and exercisable at December 31, 1997:
<TABLE>
<CAPTION>
Weighted Average Weighted Weighted
Range of Remaining Average Average
Exercise Contractual Exercise Exercise
Prices Outstanding Life Price Exercisable Price
--------------- ------------ ------------------ ------------- ------------ ------------
<S> <C> <C> <C> <C> <C>
$ 0.01 to $4.18 842,517 9.25 $ 2.10 -- --
$13.50 20,010 9.50 $13.50 6,670 $13.50
--------------- ------------ ------------------ ------------- ------------ ------------
$ 0.01 to $13.50 862,527 9.26 $ 2.36 6,670 $13.50
</TABLE>
MANAGEMENT INVESTOR SUBSCRIPTION AGREEMENTS AND RELATED TRANSACTIONS --
On February 21, 1997, each of the Company's officers and other managers of the
Company (the "Management Investors") entered into a Management Investor
Subscription Agreement with the Company pursuant to which the Management
Investors purchased an aggregate of 390,307 shares of Common Stock at $4.18 per
share. To facilitate such purchases, the Company loaned the Management Investors
an aggregate of approximately $546,000. All such indebtedness of such persons
accrues interest at the rate of 8% per annum, payable semiannually; provided
that each Management Investor may elect to satisfy his or her semiannual
interest payment obligation by increasing the principal amount of the
indebtedness owed to the Company by the amount of interest otherwise payable. As
security for such loans made by the Company, each Management Investor pledged to
the Company, and granted a first priority security interest in, the shares of
Common Stock purchased by such Management Investor pursuant to its respective
Management Investor Subscription Agreement and is required to pledge, and grant
a first priority security interest in, all other shares of Common Stock that
each such person may subsequently acquire, including, without limitation, upon
exercise of options to purchase shares of Common Stock. Such loans were repaid
in full in February 1998. In addition, in April 1997, other employees of the
Company purchased 95,696 shares of Common Stock at an average price of $4.18 per
share.
STOCK OPTION PLAN FOR NONEMPLOYEE DIRECTORS --The Company has adopted
the Domain Energy Corporation 1997 Stock Option Plan for Nonemployee Directors
(the "Nonemployee Director Plan"). The objective of the Nonemployee Director
Plan is to enable the Company to attract and retain the services of outstanding
nonemployee directors by affording them an opportunity to acquire a proprietary
interest in the Company through automatic, non-discretionary awards of options
exercisable to purchase shares of Common Stock.
50
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - (CONTINUED)
Each member of the Board of Directors who is not an employee of the
Company or its subsidiaries is eligible to receive options under the Nonemployee
Director Plan. On the effective date of the Nonemployee Director Plan, each such
of the five eligible directors were automatically granted an option to purchase
4,002 shares of Common Stock. Future eligible directors will also be granted an
option to purchase an identical number of shares of Common Stock upon their
initial appointment or election to the Board of Directors. The exercise price of
the options will be equal to the fair market value of the Common Stock on the
date of grant. The options may be exercised for a period of ten years commencing
on the date of grant as follows: (i) up to one-third of the total number of
shares of Common Stock subject to an option may be purchased as of the date of
grant; (ii) up to an additional one-third of the total number of shares of
Common Stock subject to an option may be purchased as of the date of the annual
meeting of stockholders of the Company in the year following the year in which
the option was granted ("Second Vesting Date"), provided that the holder of the
option is an eligible director immediately following such meeting; and (iii) the
balance of the total number of shares of Common Stock subject to an option may
be purchased as of the date of the annual meeting of stockholders next following
the Second Vesting Date ("Final Vesting Date"), provided that the holder of the
option is an eligible director immediately following such meeting.
COMPENSATION EXPENSE -- For purposes of determining compensation expense
pursuant to APB 25, the measurement date for the stock options granted to
officers of the Company is December 31, 1996 as on that date each officer knew
the number of options (both Time Options and Performance Options) that they
would be granted, the number of shares that they would be entitled to receive
upon exercise of the options and the option exercise price. The measurement date
for other options granted and stock sold is the date of the grant or sale.
Compensation expense is calculated based on the difference in the proceeds that
the Company receives upon issuance of the stock and the estimated fair value of
the stock at the measurement date. The Company recognized stock compensation
expense of $4,587,000 in 1997 and anticipates recognizing stock compensation
expense based on actual stock acquired and in accordance with the vesting
schedule of options granted as follows:
1998 ............................ $1,158,000
1999 ............................ 227,000
2000 ............................ 37,000
2001 ............................ 18,000
2002 ............................ 3,000
Pursuant to APB 25, the Company recognized a charge of $4.6 million as
compensation expense for equity-based compensation awarded in 1997. If the fair
value based method of accounting in FAS 123 had been applied, the Company would
have recognized $4.8 million in 1997 as compensation expense. The Company's pro
forma net income and earnings per common share for 1997 is presented below (in
thousands, except per share data):
1997
------------
Net income - as reported ............................. $3,163
Net income - pro forma ............................... $2,995
Diluted earnings per common share - as reported ...... $ 0.26
Diluted earnings per common share - pro forma ........ $ 0.25
Because it is likely that additional options will be granted in future
years and will vest ratably, the reported pro forma results are not necessarily
representative of the effects on reported pro forma results for future years.
11. INCOME TAXES
The provision for income taxes consists of the following (in thousands):
51
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - (CONTINUED)
YEAR ENDED DECEMBER 31,
-----------------------
SUCCESSOR PREDECESSOR
---------- ----------------------
1997 1996 1995
---------- ----------------------
Federal:
Current (1) ...................... $ 445 $(2,965) $(518)
Deferred ......................... 3,359 6,511 791
State:
Current .......................... 290 657 (14)
Deferred ......................... -- 191 92
------ ------- -----
Income tax expense .................... $4,094 $ 4,394 $ 351
====== ======= =====
(1) In 1997, $445,000 of current federal income taxes represents alternative
minimum taxes paid.
The following table sets forth a reconciliation of the statutory federal
income tax with the Company's effective tax rate (in thousands):
SUCCESSOR PREDECESSOR
---------- --------------
1997 1996 1995
---------- ------- -----
Income before income taxes ....................... $ 7,257 $11,425 $ 858
---------- ------- -----
Income tax computed at statutory rates............ $ 2,540 $ 3,999 $ 300
State taxes, net of federal benefit............... 189 551 54
Other ............................................ 1,365 (156) (3)
---------- ------- -----
Income tax expense ............................... $ 4,094 $ 4,394 $ 351
========= ======= =====
(1) In 1997, the Company recorded $3.9 million of stock compensation expense for
which it will receive no tax deduction.
Deferred income taxes reflect the tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts calculated for income tax purposes. The components of
deferred tax assets and liabilities pursuant to FAS 109 are as follows (in
thousands):
DECEMBER 31, DECEMBER 31,
1997 1996
----------- ------------
Deferred tax liability:
Oil and gas properties .................... $ 13,081 $ --
----------- ------------
Deferred tax asset:
Alternative minimum tax ................... 445 --
Net operating loss carryforwards .......... 12,441 --
Other, net ............................... 310 --
----------- ------------
13,196 --
Valuation Allowance ............................ -- --
----------- ------------
Net deferred tax asset .................... $ 115 $ --
=========== ============
As of December 31, 1996, the Company had no deferred tax liability. As a
result of the Acquisition and the corresponding election made by El Paso and the
Company to step-up the tax basis in the assets acquired, there are no temporary
differences in the carrying amounts of assets and liabilities for financial
reporting and income tax purposes.
As of December 31, 1997, the Company has a net operating loss ("NOL")
carryforward for federal income tax purposes of approximately $35.5 million that
may be used in future years to offset taxable income. Utilization of the
Company's NOL carryforward is subject to annual limitations due to certain stock
ownership changes that have occurred. To the extent not utilized, the NOL
carryforward will begin to expire in 2006. The Company does not believe a
deferred tax asset valuation is required because all tax carryovers are expected
to be fully utilized.
52
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - (CONTINUED)
12. COMMITMENTS AND CONTINGENCIES
From time to time, the Company is a party to certain lawsuits and claims
arising in the ordinary course of business. While the outcome of lawsuits and
claims cannot be predicted with certainty, management does not expect these
matters will have a materially adverse effect on the Company's financial
condition, results of operations or cash flows.
401(K) PLAN -- Effective December 31, 1996, the Company has offered its
employees an employee 401(k) savings plan (the "401(k) Plan"). The 401(k) Plan
covers all full-time employees and entitles each to contribute up to 15% of his
or her annual compensation subject to maximum limitations imposed by the
Internal Revenue Code. The 401(k) Plan allows for employer matching of up to 8%
of the employee's contributions based on years of participation in the plan,
including years of participation in the 401(k) plan previously offered by
Tenneco. The Company's contributions to the 401(k) Plan during 1997 were
$146,000.
The Company has entered into operating lease agreements for office space
in Houston, Texas with the lease term expiring on September 30, 2002.
Future minimum lease payments required as of December 31, 1997 related
to these and other normal operating leases are as follows::
Year ended December 31,
1998 .................................... $ 490,000
1999 .................................... 440,000
2000 .................................... 428,000
2001 .................................... 420,000
2002 .................................... 315,000
-----------
Total minimum lease payments $ 2,093,000
===========
Rent expense for the years ended December 31, 1997, 1996 and 1995 was
$253,000, $604,000 and $545,000, respectively.
13. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
QUARTER ENDED
------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
PREDECESSOR (IN THOUSANDS, EXCEPT PER 1996 1996 1996 1996
SHARE DATA) --------- -------- ------------- ------------
<S> <C> <C> <C> <C>
Revenues ........................... $ 16,143 $ 14,686 $ 13,531 $ 11,870
Operating income (loss) (1) ........ 4,096 6,126 2,047 (694)
Net income (loss) .................. 2,754 3,855 982 (560)
Net income per share ............... -- -- -- --
<CAPTION>
QUARTER ENDED
------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
SUCCESSOR (IN THOUSANDS, EXCEPT PER 1997 1997 1997 1997
SHARE DATA) --------- -------- ------------- ------------
-----------
Revenues .............................. $ 13,222 $ 9,841 $ 13,671 $ 15,534
Operating income ...................... 2,525 1,908 3,321 3,277
Net income (loss) (3) ................. (319) 673 1,634 1,175
Net income (loss) per share (2) ....... $ (0.03) $ 0.08 $ 0.11 $ 0.08
</TABLE>
(1) The fourth quarter 1996 includes $2.1 million of corporate overhead which is
$1.2 million greater than the average of the first three quarters. This amount
includes costs related to the merger between Tenneco and an affiliate of El
Paso.
(2) Assuming dilution.
53
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - (CONTINUED)
(3) The first quarter of 1997 includes $3.2 million of stock compensation
expense which is $2.7 million greater than the average of the last three
quarters. This amount includes cost related to stock purchases made by the
Company's management.
14. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
This footnote provides unaudited information required by SFAS 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 (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------
1997 1996
--------- -------
<S> <C> <C>
Proved producing oil and natural gas properties ............ $ 116,782 $53,514
Unevaluated properties ..................................... 36,603 12,662
--------- -------
153,385 66,176
Less: Accumulated depreciation, depletion and amortization . (15,411) --
--------- -------
Net capitalized costs ...................................... $ 137,974 $66,176
========= =======
Company's share of equity method investee's net capitalized
cost (sold in 1997) ............. $ -- $17,815
</TABLE>
COSTS INCURRED -- Costs incurred in oil and gas property acquisition,
exploration and development activities are summarized below (in thousands):
YEAR ENDED DECEMBER 31,
--------------------------------
SUCCESSOR PREDECESSOR
---------- -------------------
1997 1996 1995
---------- -------- --------
Property acquisition costs:
Proved .......................... $ 39,762 $ 7,781 $ 15,186
Unproved ........................ 15,610 732 3,207
Exploration costs .................... 16,804 12,126 23,677
Development costs .................... 18,894 7,506 7,834
---------- -------- --------
Total costs incurred ................. $ 91,070 $ 28,145 $ 49,904
========== ======== ========
Company's share of equity method
investee's cost incurred
(sold in 1997)...................... $ -- $ 17,978 $ --
RESULTS OF OPERATIONS -- Results of operations for oil and gas producing
activities (including operating overhead) were as follows (in thousands):
YEAR ENDED DECEMBER 31,
-----------------------------------
SUCCESSOR PREDECESSOR
---------- --------------------
1997 1996 1995
---------- ------- -------
REVENUES
Sales ........................... $ 47,251 $52,274 $34,877
Other revenues .................. 238 (413) 414
---------- ------- -------
Total revenues ............. 47,489 51,861 35,291
---------- ------- -------
EXPENSES
Production costs ................ 16,341 11,547 8,690
Depreciation, depletion and
amortization................... 15,411 24,919 22,339
---------- ------- -------
Income before taxes ............. 15,737 15,395 4,262
Provision for income taxes ...... 5,744 5,921 1,743
---------- ------- -------
Results of operations for oil
and gas producing activities... $ 9,993 $ 9,474 $ 2,519
========== ======= =======
54
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - (CONTINUED)
The difference between the above results of operations and the amounts
reported in the Consolidated and Combined Statements of Income is primarily
attributable to excluding IPF Program related activities, general and
administrative expense, stock compensation expense, corporate overhead
allocation, amortization of other assets and interest expense.
RESERVES -- Proved reserves are estimated quantities of oil and natural
gas which geological and engineering data demonstrate with reasonable certainty
to be recoverable in future years from known reservoirs under existing economic
and operating conditions. Proved developed reserves are proved reserves that can
reasonably be expected to be recovered through existing wells with existing
equipment and operating methods.
Proved oil and natural gas reserve quantities and the related discounted
future net cash flows before income taxes for the periods presented are based on
estimates prepared by DeGolyer and MacNaughton, Netherland, Sewell & Associates,
Inc., and other third-party independent petroleum engineers. Such estimates have
been prepared in accordance with guidelines established by the Securities and
Exchange Commission.
The Company's net ownership interests in estimated quantities of proved
oil and natural gas reserves and changes in net proved reserves, all of which
are located in the continental United States, are summarized below.
<TABLE>
<CAPTION>
OIL, CONDENSATE AND NATURAL GAS LIQUIDS (BBLS)
----------------------------------------------
SUCCESSOR PREDECESSOR
----------------------------- -----------
1997 1996 1995
------------ ----------- -----------
<S> <C> <C> <C>
Proved developed and undeveloped reserves:
Beginning of year .................... 10,128,061 2,197,181 4,109,442
Revisions of previous estimates ...... (232,597) 289,216 (704,308)
Purchase of oil and gas properties ... 1,546,024 8,152,514 1,713,328
Extensions and discoveries ........... 570,129 180,286 179,224
Sale of oil and gas properties ....... (15,005) (127,305) (2,676,505)
Production ........................... (646,394) (563,831) (424,000)
------------ ----------- -----------
End of year .......................... 11,350,218 10,128,061 2,197,181
============ ============ ===========
Proved developed reserves at end
of year (1) 5,708,044 9,775,753 1,701,656
Equity in proved reserves of equity
investee (sold in 1997) ........... -- 1,251,592 --
<CAPTION>
NATURAL GAS (MCF)
-----------------------------------------------
SUCCESSOR PREDECESSOR
----------------------------- -----------
1997 1996 1995
------------ ----------- -----------
Proved developed and undeveloped reserves:
Beginning of year ................... 60,094,539 82,682,380 73,398,877
Revisions of previous estimates ..... 103,428 (2,920,927) 5,769,806
Purchase of oil and gas properties .. 40,465,190 -- 19,898,227
Extensions and discoveries .......... 20,624,856 4,743,646 13,083,241
Sale of oil and gas properties ...... (407,603) (3,218,665) (11,402,771)
Production .......................... (15,932,493) (21,191,895) (18,065,000)
------------ ----------- -----------
End of year ......................... 104,947,917 60,094,539 82,682,380
============ =========== ===========
Proved developed reserves at end of
year............................... 84,444,975 47,495,614 65,178,731
Equity in proved reserves of equity
investee (sold in 1997) ........... -- 21,243,379 --
</TABLE>
55
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - (CONTINUED)
<TABLE>
<CAPTION>
TOTAL (MCFE)
-----------------------------------------
SUCCESSOR PREDECESSOR
--------------------------- -----------
1997 1996 1995
------------ ------------ -----------
Proved developed and undeveloped reserves:
<S> <C> <C> <C>
Beginning of year ............................ 120,862,905 95,865,466 98,055,529
Revisions of previous estimates .............. (1,292,154) (1,185,631) 1,543,958
Purchase of oil and gas properties ........... 49,741,334 48,915,084 30,178,195
Extensions and discoveries ................... 24,045,630 5,825,362 14,158,585
Sale of oil and gas properties ............... (497,633) (3,982,495) (27,461,801)
Production ................................... (19,810,857) (24,574,881) (20,609,000)
------------ ------------ -----------
End of year .................................. 173,049,225 120,862,905 95,865,466
============ ============ ===========
Proved developed reserves at end of year .......... 118,693,238 106,150,132 75,388,667
Equity in proved reserves of equity investee
(sold in 1997) .................................. -- 28,752,931 --
</TABLE>
(1) Proved developed oil, condensate and natural gas liquids reserves decreased
by 4.1 million barrels in 1997 as compared to 1996. This decrease was the
result of the reclassification of a portion of the reserves attributable to the
Wasson Field from proved developed to proved undeveloped at year end 1997.
STANDARDIZED MEASURE -- The table of the Standardized Measure of
Discounted Future Net Cash Flows relating to the Company's ownership interests
in proved oil and gas reserves as of year end is shown below (in thousands):
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-------------------------------------
SUCCESSOR PREDECESSOR
----------------------- ---------
1997 1996 1995
---------- --------- ---------
<S> <C> <C> <C>
Future cash inflows ................................................ $ 434,977 $ 422,377 $ 210,818
Future oil and gas operating expenses .............................. (172,347) (204,741) (43,204)
Future development costs ........................................... (52,3780 (31,208) (38,680)
Future net cash flows before income taxes .......................... 210,252 186,428 128,934
10% annual discount of future net cash flows before income taxes
. .................................................................. (61,463) (38,591) (25,003)
Discounted future net cash flows before income taxes ............... 148,789 147,837 103,931
Future income tax expenses, net of 10% annual discount ............. (21,118) (22,491) (4,932)
---------- --------- ---------
Standardized measure of discounted future net cash flows ........... $ 127,671 $ 125,346 $ 98,999
========== ========= =========
Company's share of equity method investee's standardized measure of
discounted future net cash flows (sold in 1997) $ -- $ 29,078 $ --
</TABLE>
Future cash flows are computed by applying year-end prices of oil and
natural gas to year-end quantities of proved oil and natural gas reserves.
Year-end prices utilized for oil and natural gas were $18.70/Bbl and $2.55/MMbtu
in 1997, $22.50/Bbl and $3.38/MMbtu in 1996 and $18.76/Bbl and $3.30/MMbtu in
1995. The Company estimates that a substantial decline in prices relative to
year-end 1997 would cause a substantial decline in the Company's PV-10 Reserve
Value. For example, a $0.10 per MMbtu decline in natural gas prices, holding all
other variables constant, would decrease the Company's December 31, 1997 PV-10
Reserve Value by approximately $7.8 million, or 5.3%, and a $1.00 per Bbl
decline in oil and condensate prices would decrease the Company's PV-10 Reserve
Value by approximately $4.0 million, or 2.7%. While the foregoing calculations
should assist the reader in understanding the effect of a decline in oil and
natural gas prices on the Company's PV-10 Reserve Value, such calculations
assume that quantities of recoverable reserves are constant and therefore would
not be accurate if prices decreased to a level at which reserves would no longer
be economically recoverable.
Future operating expenses and development costs are computed primarily
by the Company's petroleum engineers by estimating the expenditures to be
incurred in developing and producing the Company's proved oil and natural gas
reserves at the end of the year, based on year end costs and assuming
continuation of existing economic conditions.
56
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - (CONTINUED)
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 flows. The standardized measure of
discounted future net cash flows is not intended to represent the replacement
cost or fair market value of the Company's oil and gas properties.
The standardized measure of discounted future net cash flows does not
purport, nor should it be interpreted, to present the fair value of the
Company's oil and natural gas reserves. An estimate of fair value would also
take into account, among other things, the recovery of reserves not presently
classified as proved, anticipated future changes in prices and costs, and a
discount factor more representative of the time value of money, and the risks
inherent in reserve estimates.
CHANGE IN STANDARDIZED MEASURE -- Changes in standardized measure of
future net cash flows relating to proved oil and gas reserves are summarized
below (in thousands):
<TABLE>
<CAPTION>
SUCCESSOR PREDECESSOR
-------- -------------------
1997 1996 1995
-------- -------- --------
Changes due to current operations:
<S> <C> <C> <C>
Sales of oil and gas, net of production costs $(30,910) $(40,727) $(26,200)
Sales of reserves in place ................... (478) (4,639) (20,027)
Extensions and discoveries ................... 34,617 7,941 18,595
Purchase of reserves in place ................ 57,398 12,601 21,143
Future development costs incurred ............ 4,385 7,270 7,834
Changes due to revisions in standardized variables:
Price and production costs ................... (77,123) 52,020 23,926
Revisions of previous quantity estimates ..... (3,571) (1,857) (950)
Estimated future development costs ........... 962 (1,187) (8,825)
Income taxes ................................. 1,373 (17,560) (11,613)
Accretion of discount ........................ 14,784 10,393 6,181
Production rates (timing) and other .......... 888 2,092 20,443
-------- -------- --------
Net increase ...................................... 2,325 26,347 30,507
Beginning of year ................................. 12,5346 98,999 68,492
-------- -------- --------
End of year ....................................... $127,671 $125,346 $ 98,999
======== ======== ========
</TABLE>
Sales of oil and natural gas, net of oil and natural gas operating
expenses and future development costs are based on historical pre-tax results.
Sales of reserves in place, extensions and discoveries, purchases of reserves in
place and the changes due to revisions in standardized variables are reported on
a pre-tax discounted basis.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None
57
<PAGE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
ITEM 11. EXECUTIVE COMPENSATION.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
For the information called for by Item 10., reference is made to Part I
of this Form 10-K For the information called for by Items 10, 11, 12 and 13,
reference is made to the Company's definitive proxy statement for its Annual
Meeting of Stockholders to be held on May 12, 1998, which will be filed with the
SEC within 120 days after December 31, 1997, and which is incorporated herein by
reference.
58
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) Index to Financial Statements
(1) Financial Statements
PAGE
Independent Auditors' Report.................... 35
Consolidated Balance Sheets..................... 36
Consolidated and Combined Statements of Income..... 37
Consolidated and Combined Statements of
Stockholders' Equity............................... 38
Consolidated and Combined Statements of Cash
Flows.............................................. 39
Notes to Consolidated and Combined Financial
Statements......................................... 40
(2) Financial Statement Schedules
No schedules have been included herein because the information required
to be submitted has been included in the Company's Consolidated and Combined
Financial Statements or the notes thereto, or the required information is
inapplicable.
PAGE
(3) Index of Exhibits.................................. 59
See Index of Exhibits for a list of those exhibits filed herewith, which
index also includes and identifies management contracts or compensatory plans or
arrangements required to be filed as exhibits to this Form 10-K by Item
601(10)(iii) of Regulation S-K.
(b) Reports on Form 8-K.
The Company filed the following report on Form 8-K during the
fourth quarter of 1997:
DATE OF REPORT DESCRIPTION OF EVENT
----------------- --------------------
December 15, 1997 Acquisition of significant
assets. No financial statements were
filed in connection therewith.
(c) Index of Exhibits
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
----------- -----------
<S> <C>
3.1 Amended and Restated Certificate of Incorporation of the Company (incorporated
by reference to Exhibit 3.1 of the Company's Quarterly Report on Form 10-Q for the
quarter end June 30, 1997).
3.2 Second Amended and Restated By-laws of the Company (incorporated by reference to
Exhibit 3.2 of the Company's Quarterly Report on Form 10-Q for the quarter ended
June 30, 1997).
59
<PAGE>
10.1 Stock Purchase Agreement, dated as of December 24, 1996, between
El Paso Natural Gas Company and Teleo Ventures, Inc. (incorporated
by reference to Exhibit 10.1 of the Company's Registration Statement
on Form S-1 filed with the Commission on April 4, 1997).
10.2 Assignment and Assumption Agreement, dated as of December 31, 1996,
between Teleo Ventures, Inc. and the Company (incorporated by reference
to Exhibit 10.2 of the Company's Registration Statement on Form S-1
filed with the Commission on April 4, 1997).
10.3 Credit Agreement ,dated as of June 7, 1996, between Domain Energy
Finance Corporation (formerly known as Tenneco Ventures Finance
Corporation) and Compass Bank--Houston (including the First Amendment
and the Second Amendment thereto) (incorporated by reference to Exhibit
10.3 of the Company's Registration Statement on Form S-1 filed with the
Commission on April 4, 1997 and Exhibit 10.3 of Amendment No. 1 to the
Company's Registration Statement on Form S-1 filed with the Commission
on May 21, 1997.)
10.4 Subscription Agreement, dated as of December 31, 1996, between First
Reserve Fund VII, Limited Partnership and the Company (incorporated by
reference to Exhibit 10.4 of the Company's Registration Statement on Form
S-1 filed with the Commission on April 4, 1997).
10.5 Amended and Restated Management Investor Subscription Agreement, dated
effective as of December 31, 1996, between Michael V. Ronca and the Company
(incorporated by reference to Exhibit 10.5 of the Company's Registration
Statement on Form S-1 filed with the Commission on April 4, 1997.)
10.6 Management Investor Subscription Agreement, dated as of February 21, 1997,
between Herbert A. Newhouse and the Company, with similar agreements
with Catherine L. Sliva, Rick G. Lester, Douglas H. Woodul, Stephen M.
Curran, Dean R. Bouillion and Lucynda S. Herrin (incorporated by reference
to Exhibit 10.6 of the Company's Registration Statement on Form S-1 filed
with the Commission on April 4, 1997).
10.7 Promissory Note, dated February 21, 1997, by Michael V. Ronca in favor of
the Company, with similar Promissory Notes by Herbert A. Newhouse,
Catherine L. Sliva, Rick G. Lester, Douglas H. Woodul, Steven M. Curran
and Lucynda S. Herrin (incorporated by reference to Exhibit 10.7 of the
Company's Registration Statement on Form S-1 filed with the Commission on
April 4, 1997).
10.8 Pledge Agreement, dated as of February 21, 1997, between the Company and
Michael V. Ronca, with similar agreements with Herbert A. Newhouse,
Catherine L. Sliva, Rick G. Lester, Douglas H. Woodul, Steven M. Curran
and Lucynda S. Herrin (incorporated by reference to Exhibit 10.8 of the
Company's Registration Statement on Form S-1 filed with the Commission on
April 4, 1997).
10.9 Employment Agreement, dated as of December 31, 1996, between Michael V.
Ronca and the Company (incorporated by reference to Exhibit 10.9 of the
Company's Registration Statement on Form S-1 filed with the Commission on
April 4, 1997).
60
<PAGE>
10.10 Credit Agreement, dated as of December 31, 1996, among the Company,
Ventures Corporation, Production Corporation, The Chase Manhattan Bank,
Compass Bank, Toronto Dominion (Texas), Inc. and The Chase Manhattan
Bank as Administrative Agent (incorporated by reference to Exhibit 10.10 of
the Company's Registration Statement on Form S-1 filed with the Commission
on April 4, 1997).
10.11 Amended and Restated 1996 Stock Purchase and Option Plan for Key
Employees of Domain Energy Corporation and Affiliates (incorporated by
reference to Exhibit 10.11 of the Company's Registration Statement on Form
S-1 filed with the Commission on April 4, 1997).
10.12 Amended and Restated Non-Qualified Stock Option Agreement, dated as of
April 3, 1997, between the Company and Michael V. Ronca, with similar
agreements with Herbert A. Newhouse, Catherine L. Sliva, Rick G. Lester,
Douglas H. Woodul, Steven M. Curran, Dean R. Bouillion and Lucynda S.
Herrin (incorporated by reference to Exhibit 10.12 of Amendment No. 1 to the
Company's Registration Statement on Form S-1 filed with the Commission on
May 21, 1997).
10.13 Purchase Agreement, dated as of April 30, 1997, among Production Corporation,
as Purchaser, each of GE APPL Corp., GTPT Corporation and Zeta MT Holding, Inc.,
as Sellers, and NationsBank of Texas, N.A., as QPAM (incorporated by reference
to Exhibit 10.13 of Amendment No. 1 to the Company's Registration Statement on
Form S-1 filed with the Commission on May 21, 1997).
10.14 Form of Domain Energy Corporation 1997 Stock Option Plan for Nonemployee Directors
(incorporated by reference to Exhibit 10.14 of Amendment No. 2 to the Company's
Registration Statement on Form S-1 filed with the Commission on June 2, 1997).
10.15 Securities Purchase Agreement, dated as of November 21, 1997, between the Company
and Enron Finance Corp. (incorporated by reference to Exhibit 2.1 of the Company's
Current Report on Form 8-K dated December 15, 1997).
10.16 Agreement and Plan of Merger, dated as of November 21, 1997, among the Company,
Domain Gulf Acquisition Corp. and Gulfstar Energy, Inc. (incorporated by reference
to Exhibit 2.1 of the Company's Current Report on Form 8-K dated December 15, 1997).
21.1 List of Subsidiaries of the Company.
23.1 Consent of Deloitte & Touche LLP.
27.1 Financial Data Schedule.
</TABLE>
61
<PAGE>
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.
DOMAIN ENERGY CORPORATION
(Registrant)
By:/s/ RICK G. LESTER
Rick G. Lester
Vice President, Chief Financial
Officer and Treasurer
Date: March 23, 1998
Pursuant to the requirements of the Securities and Exchange Act of 1934,
this report has been signed by the following persons on behalf of the registrant
in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
/s/ JONATHAN S. LINKER Chairman of the Board March 23, 1998
Jonathan S. Linker
/s/ MICHAEL V. RONCA Director, President and Chief March 23, 1998
Michael V. Ronca Executive Officer
(principal executive officer)
/s/ MICHAEL L. HARVEY Director and Executive Vice March 23, 1998
Michael L. Harvey President
/s/ STEVEN H. PRUETT Director March 23, 1998
Steven H. Pruett
/s/ GARY K. WRIGHT Director March 23, 1998
Gary K. Wright
/s/ RICK G. LESTER Vice President, Chief Financial
Rick G. Lester Officer and Treasurer March 23, 1998
(Principal financial and
accounting officer)
62
EXHIBIT 21.1
LIST OF SUBSIDIARIES
Domain Energy Finance Corporation
Domain Energy Guarantor Corporation
Domain Energy International Corporation
Domain Argentina S.A.
Domain Energy Production Company
Domain Energy Ventures Corporation
Gulfstar Energy, Inc.
Gulfstar Seismic, Inc.
Gulfstar 3-D Seismic Partnership I
Matrix Energy-T Limited Partnership
Michigan Gas Fund I
Mid-Gulf Drilling Corp.
New York Gas Fund I
Oceana Exploration Company, L.C.
Texas Gas Fund I
Texas Gas Fund II
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement
No. 333-37939 of Domain Energy Corporation on Form S-8 of our report dated
February 17, 1998, appearing in this Annual Report on Form 10-K of Domain Energy
Corporation for the year ended December 31, 1997.
DELOITTE & TOUCHE LLP
Houston, Texas
March 23, 1998
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 4,731
<SECURITIES> 0
<RECEIVABLES> 12,562
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 29,570
<PP&E> 153,385
<DEPRECIATION> 15,411
<TOTAL-ASSETS> 212,549
<CURRENT-LIABILITIES> 15,907
<BONDS> 63,720
0
0
<COMMON> 151
<OTHER-SE> 131,883
<TOTAL-LIABILITY-AND-EQUITY> 212,549
<SALES> 52,030
<TOTAL-REVENUES> 52,268
<CGS> 0
<TOTAL-COSTS> 16,341
<OTHER-EXPENSES> 24,896
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 3,774
<INCOME-PRETAX> 7,257
<INCOME-TAX> 4,094
<INCOME-CONTINUING> 3,163
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 3,163
<EPS-PRIMARY> 0.27
<EPS-DILUTED> 0.26
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