UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
MARK ONE
[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
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File Number 0-19931
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 84-1176750
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
4582 South Ulster Street Parkway
Suite 1700
Denver, Colorado 80237
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (303) 850-7373
Securities Registered Pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange
None on which registered
None
Securities Registered Pursuant to Section 12(g) of the Act:
Common Stock, $.01 par value
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein and will not be contained, to the best
of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of the voting stock held by nonaffiliates of the
registrant as of February 27, 1998 was approximately $24,581,000.
Shares of Common Stock outstanding at February 27, 1998: 3,001,352 Shares.
Page 1 of 51
PART I
ITEM 1 - BUSINESS
Hallwood Consolidated Resources Corporation ("HCRC" or the "Company") is a
Delaware corporation engaged in the development, production and sale of oil and
gas, and in the acquisition, exploration, development and operation of oil and
gas properties. The principal objective of HCRC is to maximize shareholder value
by increasing its reserves, production and cash flow through a balanced program
of development and high potential exploration drilling, as well as selective
acquisitions. The Company's properties are primarily located in West Texas,
South Louisiana, New Mexico and Kansas. HCRC does not engage in any other line
of business.
Officers and Key Employees
HCRC does not have any employees. Hallwood Petroleum, Inc. ("HPI"), an affiliate
of HCRC, operates the properties and administers the day to day activities of
HCRC and its affiliates. On February 27, 1998, HPI had 123 employees. Following
are brief biographies of the officers and key employees of HCRC and HPI.
William L. Guzzetti, 54, has been President and a director of HCRC since May
1991 and of HPI since October 1989, and a director of HPI since August 1989. Mr.
Guzzetti is also an Executive Vice President of Hallwood Group and in that
capacity may devote a portion of his time to the activities of Hallwood Group,
including the management of real estate investments, acquisitions and
restructurings of entities controlled by Hallwood Group. He is a director and
President of Hallwood Realty and in that capacity may devote a portion of his
time to the activities of Hallwood Realty.
Russell P. Meduna, 43, has served as Executive Vice President of HCRC since June
1992 and of HPI since October 1989. Mr. Meduna was Vice President of HPI from
April 1989 to October 1989 and Manager of Operations from January 1989 to April
1989. He joined HPI in 1984 as Production Manager. Prior to joining HPI, he was
employed by both major and independent oil companies. Mr. Meduna is a registered
professional engineer in the States of Colorado and Texas.
Cathleen M. Osborn, 45, has served as Secretary and General Counsel of HCRC
since May 1992 and as Vice President since June 1992. She has been Vice
President, Secretary and General Counsel of HPI since September 1986. She joined
HPI in 1985 as senior staff attorney. Ms. Osborn is a member of the Colorado Bar
Association.
Robert S. Pfeiffer, 41, has served as Vice President of HCRC since June 1992 and
of HPI since August 1986. Mr. Pfeiffer became Chief Financial Officer of HCRC
and HPI in June 1994. He joined and HPI in 1984. From July 1979 to May 1984, he
was employed by Price Waterhouse as a senior accountant. Mr. Pfeiffer is a
member of the American Institute of Certified Public Accountants and the
Colorado Society of Certified Public Accountants. Mr. Pfeiffer resigned his
positions with HCRC and its affiliates effective March 6, 1998.
Betty J. Dieter, 50, has been Vice President of HPI responsible for domestic
operations since January 1995. Her previous positions with HPI have included
Operations Manager, Rocky Mountain and Mid-Continent District Manager and
Manager for Operations Accounting and Administration. She joined HPI in 1985,
and has 25 years experience in accounting and operations, 18 of which are in the
oil and gas industry. Ms. Dieter is a Certified Public Accountant.
George Brinkworth, 56 has been Vice President-Exploration of HPI since August
1994. He became associated with HPI in 1987 when he was President of a joint
venture program funded by HPI and two other domestic oil companies. Mr.
Brinkworth has 33 years experience with various exploration and production
companies, including previous responsibility for operations in the United
Kingdom, Spain, Morocco, Egypt and Indonesia. He is a registered geophysicist in
the State of California.
William H. Marble, 47, has served as Vice President of HPI since December 1990.
His previous positions with HPI have included Texas/Gulf Coast District Manager,
Manager of Nonoperated Properties and Chief Engineer. He joined a predecessor
general partner of the Partnership in 1984. Mr. Marble is a registered engineer
in the State of Colorado and has 23 years oil and gas engineering experience.
Marketing
The oil and gas produced from the properties owned by HCRC has typically been
marketed through normal channels for such products. Oil is generally sold to
purchasers at field prices posted by the principal purchasers of crude oil in
the areas where the producing properties are located. In response to the
volatility in the oil markets, HCRC entered into financial contracts for hedging
the price of 14% of its estimated oil production for 1998 and 5% for 1999.
The majority of HCRC's gas production is sold on the spot market and is
transported in intrastate and interstate pipelines. HCRC has entered into
financial contracts for hedging the price of between 5% and 31% of its estimated
gas production for 1998 through 2001.
The purpose of the hedges is to provide protection against price decreases and
to provide a measure of stability in the volatile environment of oil and natural
gas spot pricing. The amounts received or paid upon settlement of these
contracts are recognized as revenue at the time the hedged volumes are sold.
Both oil and natural gas are purchased by refineries, major oil companies,
public utilities, industrial customers and other users and processors of
petroleum products. HCRC is not confined to, nor dependent upon, any one
purchaser or small group of purchasers. Accordingly, the loss of a single
purchaser, or a few purchasers, would not materially affect HCRC's business
because there are numerous purchasers in the areas in which HCRC sells it
production. However, for the years ended December 31, 1997, 1996 and 1995,
purchases by the following companies exceeded 10% of the total oil and gas
revenues of HCRC:
1997 1996 1995
El Paso Field Services 17% 11%
Williams Gas Marketing 13%
Koch Oil Company 23% 27%
Conoco Inc. 13% 14%
Scurlock Permian Corporation 14%
Factors, if they were to occur, which might adversely affect HCRC include
decreases in oil and gas prices, the reduced availability of a market for
production, rising operating costs of producing oil and gas, compliance with and
changes in environmental control statutes and increasing costs and difficulties
of transportation.
Competition
HCRC encounters competition from other oil and gas companies in all areas of its
operations, including the acquisition of exploratory prospects and proven
properties. The Company's competitors include major integrated oil and gas
companies and numerous independent oil and gas companies, individuals and
drilling income programs. As described under "Marketing," production is sold on
the spot market, thereby reducing sales competition. Moreover, oil and gas must
compete with coal, atomic energy, hydro-electric power and other forms of
energy.
Regulation
Production and sale of oil and gas are subject to federal and state governmental
regulations in a variety of ways including environmental regulations, labor
laws, interstate sales, excise taxes and federal and Indian lands royalty
payments. Failure to comply with these regulations may result in fines,
cancellation of licenses to do business and cancellation of federal, state or
Indian leases. The production of oil and gas is subject to regulation by the
state regulatory agencies in the states in which HCRC does business. These
agencies make and enforce regulations to prevent waste of oil and gas and to
protect the rights of owners to produce oil and gas from a common reservoir. The
regulatory agencies regulate the amount of oil and gas produced by assigning
allowable production rates to wells capable of producing oil and gas.
Environmental Considerations
The exploration for, and development of, oil and gas involves the extraction,
production and transportation of materials which, under certain conditions, can
be hazardous or can cause environmental pollution problems. In light of the
current interest in environmental matters, HCRC cannot predict the effect of
possible future public or private action on its business. HCRC is continually
taking actions it believes are necessary in its operations to ensure conformity
with applicable federal, state and local environmental regulations. As of
December 31, 1997, HCRC has not been fined or cited for any environmental
violations which would have a material adverse effect upon capital expenditures,
earnings or the competitive position of HCRC in the oil and gas industry.
Insurance Coverage
HCRC is subject to all the risks inherent in the exploration for, and
development of, oil and gas, including blowouts, fires and other casualties.
HCRC maintains insurance coverage as is customary for entities of a similar size
engaged in operations similar to that of HCRC, but losses can occur from
uninsurable risks or in amounts in excess of existing insurance coverage. The
occurrence of an event which is not insured or not fully insured could have an
adverse impact upon HCRC's earnings, cash flows and financial position.
Issues Related to the Year 2000
As the year 2000 approaches, there are uncertainties concerning whether computer
systems will properly recognize date-sensitive information when the year changes
to 2000. Systems that do not properly recognize such information could generate
erroneous data or fail.
Because of the nature of the oil and gas industry and the necessity for the
Company to make reserve estimates and other plans well beyond the year 2000, the
Company's computer systems and software were already configured to accommodate
dates beyond the year 2000. The Company believes that the year 2000 will not
pose significant operational problems for the Company's computer systems. The
Company has not yet completed its assessment of all of its systems, or the
computer systems of third parties with which it deals, and while it is not
possible at this time to assess the effect of a third party's inability to
adequately address year 2000 issues the Company does not believe the potential
problems associated with the year 2000 will have a material effect on its
financial position.
ITEM 2 - PROPERTIES
Exploration and Development Projects
In 1997, HCRC incurred $12,106,000 in direct property additions and exploration
and development costs. The costs were comprised of approximately $9,284,000 for
domestic exploration and development expenditures and approximately $2,822,000
for property acquisitions. In 1997, HCRC participated in approximately 98
drilling or recompletion projects, the highlights of which are discussed below.
HCRC's 1997 capital program led to the replacement, including revisions to prior
year reserves, of 107% of 1997 production. Sales of reserves in place in 1997,
which were approximately 1% of 1997 production, were excluded from this
calculation. Approximately $2,061,000 of the 1997 capital expenditures were for
land and seismic data anticipated to yield prospects for 1998 and subsequent
years.
Property Sales
During 1997, HCRC received approximately $40,000 for the sale of 50 nonstrategic
properties located in eight states. Capital Projects
Greater Permian Region
HCRC expended approximately $5,535,000 of its capital budget on the Greater
Permian Region located in Texas and Southeast New Mexico. During 1997, HCRC
spent approximately $3,755,000 drilling 29 development wells and 26 exploration
wells and acquiring undeveloped acreage and geological and geophysical data. Of
the wells drilled, 39 (71%) were successful. A discussion of several of the
larger projects within the Region follows.
HCRC spent approximately $275,000 successfully recompleting two wells, drilling
one successful development well, and drilling two unsuccessful exploration wells
in the Carlsbad/Catclaw Draw areas in Lea, Eddy and Chaves Counties, New Mexico.
HCRC spent approximately $260,000 to drill six exploration and three development
wells in the nonoperated Merkle Project in Jones, Taylor, and Nolan Counties,
Texas. Five wells were successful.
Based on the success in the nonoperated Merkle area, HCRC acquired 74 additional
square miles of proprietary 3-D seismic data adjacent to the non-operated area.
In 1997, HCRC incurred approximately $730,000 acquiring acreage and drilling 10
exploration wells, seven of which were successful.
HCRC purchased an interest in proprietary 3-D seismic data and selected acreage
within an 85 square mile area, referred to as the Griffin Project, for
approximately $495,000. In 1997, HCRC drilled one successful and one
unsuccessful exploratory well in the area for approximately $425,000. HCRC is
currently participating in the drilling of one exploration well and incurred
approximately $120,000 through December 31, 1997.
HCRC spent approximately $850,000 drilling two exploration wells and nine
development wells in the Spraberry area of West Texas. Of the wells drilled,
eight (73%) are successful. In July, HCRC acquired additional interests in 34 of
its existing wells in the area for approximately $510,000.
In 1997, HCRC continued to devote capital resources to the East Keystone area in
Winkler County, Texas. HCRC spent approximately $380,000 drilling 14 development
wells with a success rate of 100%.
Rocky Mountain Region
HCRC expended approximately $2,205,000 of its capital budget in the Rocky
Mountain Region located in Colorado, Montana, North Dakota, Northwest New Mexico
and Wyoming. During 1997, HCRC drilled or participated in the drilling or
recompletion of 17 wells, seven which were successful. A description of the
Region's major projects follows. In the San Juan Basin in LaPlata County,
Colorado and Rio Arriba County, New Mexico, HCRC has an interest in 34 wells
owned by a special purpose entity owned by a large east coast financial
institution. During 1997, seven successful recompletions were performed and one
successful exploration well. This work and other activity in the San Juan region
have yielded significant upward revisions to HCRC's reserve base. HCRC incurred
approximately $205,000 on four recompletion attempts in San Juan County, New
Mexico, two of which were successful. In addition, HCRC purchased additional
interests in existing wells in the area for $70,000.
In the Lone Tree area of Montana, HCRC drilled two exploration wells and three
development wells for a cost of approximately $85,000. Two of the development
wells and one of the exploration wells were successful.
The Hudson Ranch project is a multi-objective exploration project generated from
120 miles of 2-D proprietary seismic data. HCRC's 1997 costs for the project are
approximately $340,000. A 3-D seismic data acquisition program is underway, and
exploratory drilling is anticipated to begin in 1998.
HCRC also participated in the drilling of an 11,500 feet exploration well in the
Beach Field of North Dakota. HCRC incurred approximately $215,000 for
participation in this successful well. Expenditures in various other areas of
the region were approximately $455,000 for drilling two unsuccessful exploration
wells and one successful development well.
Gulf Coast Region
HCRC expended approximately $1,480,000 of its capital budget in the Gulf Coast
Region in Louisiana and South and East Texas. During 1997, HCRC spent
approximately $945,000 on two unsuccessful exploration attempts, one
unsuccessful development well, and one successful development well. Repairs and
successful workovers on wells in the Scott Field cost HCRC approximately
$230,000.
HCRC also incurred approximately $145,000 on miscellaneous projects within the
Region for land and geological data.
Mid-Continent and Other Areas
The remaining $2,886,000 of HCRC's 1997 capital budget was devoted to projects
in Kansas, Oklahoma and all other areas. In 1997, HCRC incurred $890,000 for
land, geological data and drilling costs for 15 development wells and six
exploration wells. Of the wells drilled, 17 (81%) were successful. A description
of the major projects follow.
HCRC is participating in an exploration prospect in Carter County, Oklahoma.
This project is a 19,000 feet deep multi-formation structural test and is
currently in the completion phase. The drilling and land costs to HCRC are
approximately $355,000.
In 1997, HCRC entered into an agreement with another operator to participate in
an 8,500 feet deep Spiro/Foster test well in LeFlore County, Oklahoma. The well
was a success and cost HCRC approximately $265,000.
HCRC also purchased additional interests in eight existing Kansas properties for
approximately $110,000.
Projects begun in the fourth quarter of 1996 have cost HCRC approximately
$525,000 in 1997. These costs are primarily for work in the Gulf Coast Region
and in the Greater Permian Region. Miscellaneous land and geological and
geophysical data acquired in 1997 cost HCRC approximately $690,000.
In September 1997, HCRC and an unaffiliated partner were awarded a deep-water
exploration block offshore of northern Peru. Its partner is proceeding with a
1,200 mile seismic program to further evaluate the project. HCRC's partner, a
major oil company, is the operator, and HCRC has a carried interest until
drilling begins.
For 1998, HCRC's capital budget, which will be paid from cash generated from
operations, cash on hand and borrowings under HCRC's line of credit, has been
set at $21,400,000. HCRC's plans include projects in Texas, New Mexico,
Colorado, North Dakota, and Montana.
Company Reserves, Production and Discussion by Significant Regions
The following table presents the December 31, 1997 reserve data by significant
regions.
Present Value of
Proved Reserve Quantities Estimated Future Net Cash Flows
Proved Proved
Mcf of Gas Bbls of Oil Undeveloped Developed Total
(In thousands)
Greater Permian Region 31,812 2,527 $ 810 $ 27,751 $ 28,561
Gulf Coast Region 9,986 223 118 20,662 20,780
Rocky Mountain Region 32,172 724 377 29,600 29,977
Mid-Continent Region 1,074 2,029 397 6,642 7,039
Other 531 22 59 1,584 1,643
------ ----- ------ ------- -------
75,575 5,525 $1,761 $86,239 $88,000
====== ===== ====== ======= =======
The present value of estimated future net cash flows is calculated using year
end average oil and gas prices. At December 31, 1997, oil and gas prices
averaged $16.77 per bbl of oil and $2.20 per mcf of gas. If average oil and gas
prices as of February 27, 1998 of $15.57 per bbl and $2.00 per mcf of gas had
been used in this calculation, the present value of estimated future net cash
flows would have been approximately 16% lower.
The following table presents the oil and gas production for significant regions.
Production for the Production for the
Year Ended 1997 Year Ended 1996
Mcf of Gas Bbls of Oil Mcf of Gas Bbls of Oil
(In thousands)
Greater Permian Region 1,719 308 1,712 376
Gulf Coast Region 1,875 64 2,269 73
Rocky Mountain Region 3,977 107 3,899 153
Mid-Continent Region 234 214 270 223
Other 158 18 130 12
----- --- ----- ----
7,963 711 8,280 837
===== === ===== ====
The following table presents the Company's extensions and discoveries by
significant regions.
For the Year Ended 1997 For the Year Ended 1996
Mcf of Gas Bbls of Oil Mcf of Gas Bbls of Oil
(In thousands)
Greater Permian Region 529 238 710 424
Gulf Coast Region 295 21 33 3
Rocky Mountain Region 1,756 234 792 34
Mid-Continent Region 43 237
Other 314 26 175 30
----- --- ----- ----
2,894 562 1,947 491
===== === ===== ====
A description of the Company's properties by region follows.
Greater Permian Region
HCRC has significant interests in the Greater Permian Region, which includes
West Texas and Southeast New Mexico. In this Region, HCRC has interests in 444
(376 of which are operated) productive oil and gas wells, 38 operated shut-in
oil and gas wells and 15 (14 operated) salt water disposal wells or injection
wells. During 1997, HCRC drilled or recompleted 55 wells, 39 of which were
successful. The following is a description of the significant areas within the
Greater Permian Region.
Carlsbad/Catclaw Area. HCRC's interests in the Carlsbad/Catclaw Area as of
December 31, 1997 consisted of 61 producing wells that produce primarily natural
gas and are located on the northwestern edge of the Delaware Basin in Lea, Eddy
and Chaves Counties, New Mexico. HPI operates 40 of these wells. The wells
produce at depths ranging from approximately 2,500 feet to 14,000 feet from the
Delaware, Atoka, Bone Springs and Morrow formations. During 1997, HCRC
participated in the drilling or recompletion of five wells, three of which were
successful. HCRC has future plans for six additional projects in this area.
East Keystone Area. HCRC's interest in the East Keystone Area as of December 31,
1997 consisted of 54 producing wells, 38 of which are operated by HPI, in
Winkler County, Texas. The primary focus of this area is the development of the
Holt and San Andreas formations at a depth of 5,100 feet. During 1997, HCRC had
14 development projects, all of which were successful. HCRC's future development
plans include five projects in this area.
Merkle Area. HCRC's nonoperated interest in the Merkle Area includes 10 square
miles of proprietary seismic data in Jones, Nolan and Taylor Counties, Texas,
which was acquired in 1995. HCRC's focus in this area is exploration of the
Canyon, Strawn and Ellenberger formations at depths of 3,500 to 6,500 feet. In
1997, HCRC participated in the drilling and recompletion of six exploration and
three development wells, five of which were successful.
Based on its success in the nonoperated Merkle Area, HCRC acquired 74 additional
miles of proprietary 3-D seismic data adjacent to the nonoperated area. In 1997,
HCRC drilled ten exploration wells in the area, seven of which were successful.
All of these wells are operated by HPI. Future plans for this area include
drilling 22 exploration wells, with possible additional locations contingent
upon continued exploration success.
Spraberry Area
HCRC's interests in the Spraberry Area consist of 345 producing wells, 11 salt
water disposal wells and 29 shut-in wells in Dawson, Upton, Reagan and Irion
Counties, Texas. HPI operates 385 of these wells. Most of the current production
from the wells is from the Upper and Lower Spraberry, Clearfork Canyon, Dean and
Fusselman formations at depths ranging from 5,000 feet to 9,000 feet. During
1997, HCRC drilled or recompleted 11 wells, eight of which were successful.
Future plans for this area include 20 development wells and workovers and
additional projects contingent upon future evaluation.
Gulf Coast Region
HCRC has significant interests in the Gulf Coast Region in Louisiana and South
and East Texas. HCRC's most significant interest in the Gulf Coast Region
consists of 10 producing gas wells, one shut-in gas well and six salt water
disposal wells located in Lafayette Parish, Louisiana. The wells produce
principally from the Bol Mex formations at 13,500 to 14,500 feet and are
operated by HPI. The two most significant wells in the area are the A.L.
Boudreaux #1 and the G.S. Boudreaux Estate #1. During 1997, HCRC drilled one
successful development well, one unsuccessful development well, and two
unsuccessful exploration wells.
Rocky Mountain Region
HCRC has significant interests in the Rocky Mountain Region, which includes
producing properties in Colorado, Montana, North Dakota and Northwest New
Mexico. HCRC has interests in 203 producing oil and gas wells, 172 of which are
operated by HPI, 44 shut-in wells, 35 of which are operated by HPI, and five
salt water disposal wells. The following is a description of the significant
areas within the Rocky Mountain Region.
San Juan Basin. HCRC's interest in the San Juan Basin consists of 82 producing
gas wells located in San Juan County, New Mexico and LaPlata County, Colorado.
HPI operates 51 wells in New Mexico, 31 of which produce from the Fruitland Coal
formation at approximately 2,200 feet and 20 of which produce from the Pictured
Cliffs, Mesa Verde and Dakota formations at 1,200 to 7,000 feet. During 1997,
HCRC drilled or recompleted four wells, two which were successful.
In 1996, HCRC participated in the acquisition of interests in 38 producing gas
wells in LaPlata County, Colorado and Rio Arriba County, New Mexico from a
subsidiary of Public Service Company of Colorado. Thirty-four of the wells were
assigned to a special purpose entity owned by a large East Coast financial
institution. The wells produce from the Fruitland Coal formation at
approximately 3,200 feet. In connection with the acquisition, HCRC monetized the
Section 29 tax credits generated by the wells. The project was financed through
a third party lender using a production payment structure. In 1997, HCRC
successfully recompleted seven of the wells, and drilled one successful
exploration well. HCRC has future plans for eight projects in this area.
Toole County Area. HCRC's interests in the Toole County Area consist of 67
wells, 58 of which are operated by HPI. The oil wells produce from the Nisku
formation at depths of approximately 3,000 feet, and the gas wells produce from
the Bow Island formation at depths of 900 to 1,200 feet. During 1997, HCRC
drilled one successful well. HCRC has plans for future development wells and
workovers in this area.
Lone Tree, Richland County Area. HCRC's interest in the Lone Tree, Richland
County area consist of 13 producing wells operated by HPI in Richland County,
Montana. The oil wells produce principally from the Mission Canyon, Interlake
and Red River formations at depths of 9,000 feet to 12,000 feet. In 1997, HCRC
drilled two exploration and three development wells. Two of the development and
one of the exploration wells were successful.
Mid-Continent Region and Other
The Mid-Continent Region and Other is comprised of wells located in Kansas,
Oklahoma, California and South Central Texas. HCRC's most significant interests
are in Kansas and consist of 224 producing wells, of which 219 are operated by
HPI and five are operated by unaffiliated entities. The wells are located in 15
counties primarily in the Central Kansas Uplift and produce principally from the
Arbuckle and numerous Lansing-Kansas City formation zones from 3,000 feet to
6,500 feet. HCRC has several projects planned for this area in the future.
Average Sales Prices and Production Costs
The following table presents the average oil and gas sales price and average
production costs per equivalent barrel computed at the ratio of six mcf of gas
to one barrel of oil.
1997 1996 1995
Average sales prices (including effects of hedging):
Oil and condensate (per bbl) $18.87 $20.13 $17.10
Natural gas (per mcf) 2.17 1.99 1.62
Production costs (per equivalent bbl) 5.01 4.68 4.49
Productive Oil and Gas Wells
The following table summarizes the productive oil and gas wells as of December
31, 1997 attributable to HCRC's direct interests. Productive wells are producing
wells and wells capable of production. Gross wells are the total number of wells
in which HCRC has an interest. Net wells are the sum of HCRC's fractional
interests owned in the gross wells.
Gross Net
Productive Wells
Oil 564 204
Gas 278 100
--- ---
842 304
=== ===
Oil and Gas Acreage
The following table sets forth the developed and undeveloped leasehold acreage
held directly by HCRC as of December 31, 1997. Developed acres are acres which
are spaced or assignable to productive wells. Undeveloped acres are acres on
which wells have not been drilled or completed to a point that would permit the
production of commercial quantities of oil and gas, regardless of whether or not
such acreage contains proved reserves. Gross acres are the total number of acres
in which HCRC has a working interest. Net acres are the sum of HCRC's fractional
interests owned in the gross acres.
Gross Net
Developed acreage 88,450 28,950
Undeveloped acreage 267,420 67,100
------- ------
Total 355,870 96,050
======= ======
States in which HCRC holds undeveloped acreage include Texas, Louisiana,
Montana, Wyoming, New Mexico, Kansas, Colorado, North Dakota, California and
Michigan.
Drilling Activity
The following table sets forth the number of wells attributable to HCRC's direct
interest drilled in the most recent three years.
Year Ended December 31,
1997 1996 1995
Gross Net Gross Net Gross Net
Development Wells:
Productive 23 4.0 29 6.2 66 14.4
Dry 4 1.0 4 1.0 2 .5
-- --- -- --- -- ----
Total 27 5.0 33 7.2 68 14.9
== === == === == ====
Exploratory Wells:
Productive 14 2.7 1 .1 6 .6
Dry 22 4.2 4 .6 5 .9
-- --- -- -- --- ---
Total 36 6.9 5 .7 11 1.5
== === == == == ===
Office Space
HCRC is guarantor of 40% of the obligation under the Denver, Colorado office
lease which is in the name of HPI. Hallwood Energy Partners, L.P. ("HEP") is
guarantor of the remaining 60% of the obligation. HPI leases 41,000 square feet
for approximately $600,000 per year.
ITEM 3 - LEGAL PROCEEDINGS
See Note 14 to the financial statements included in Item 8 - Financial
Statements and Supplementary Data.
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.
PART II
ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
HCRC's common stock has traded over the counter on the NASDAQ National Market
System under the symbol "HCRC," since June 4, 1992. As of February 27, 1998,
there were 1,495 holders of record of HCRC's common stock. The following table
sets forth, for the periods indicated, the high and low closing bid quotations
for the common stock as reported by the National Quotation Bureau. HCRC did not
pay a dividend during the periods shown. During the third quarter of 1997, the
stockholders of HCRC approved a three-for-one split of HCRC's common stock. The
stock split was effected by issuing, as a stock dividend, two additional shares
of Common Stock for each share outstanding. The stock dividend was paid on
August 11, 1997 to shareholders of record on August 4, 1997. The stockholders
also approved an increase in the number of authorized shares of common stock
from 2,000,000 to 10,000,000 shares.
HCRC Common Stock High Low
First quarter 1996 12 3/8 7 3/4
Second quarter 1996 20 1/3 10 2/3
Third quarter 1996 19 1/3 15 1/12
Fourth quarter 1996 26 2/3 16 1/3
First quarter 1997 30 1/6 22 3/4
Second quarter 1997 25 15
Third quarter 1997 30 1/2 20
Fourth quarter 1997 26 21 1/4
All share and per share information has been retroactively restated for the
three-for-one stock split effective August 11, 1997.
ITEM 6 - SELECTED FINANCIAL DATA
The following table sets forth selected financial data regarding HCRC's
financial position and results of operations as of the dates indicated. All per
share information has been restated to reflect the three-for-one stock split,
which was effective August 11, 1997.
Hallwood Consolidated Resources Corporation
As of and for the Years Ended December 31,
1997 1996 1995 1994 1993
(In thousands except per share)
Summary of Operations
Oil and gas revenues and
pipeline operations $32,258 $34,308 $25,349 $20,459 $19,792
Total revenue 32,411 34,445 25,484 20,644 21,007
Production operating expense 10,218 10,383 8,514 8,367 7,750
Depreciation, depletion and
amortization 8,605 9,246 8,206 7,340 6,414
Impairment 9,277 4,721
General and administrative
expense 4,884 4,011 4,630 3,842 3,935
Net income (loss) 5,585 8,210 (4,670) (2,974) 809
Net income (loss) per share - basic* 2.05 3.00 (1.48) (.93) .25
Net income (loss) per share - diluted* 1.97 2.91 (1.48) (.93) (.25)
Dividends per share 2.40
Balance Sheet
Working capital (deficit) $ 4,867 $ (47) $(7,202) $ 430 $ 5,973
Property, plant and
equipment, net 76,031 67,285 65,433 55,011 57,993
Total assets 92,371 78,468 73,939 62,125 70,986
Noncurrent liabilities 32,678 24,558 21,790 11,890 17,430
Stockholders' equity 48,686 43,061 36,635 43,589 46,596
<FN>
*Amounts have been restated to reflect the adoption of Statement of Financial
Accounting Standards No. 128 "Earnings per Share," during December 1997.
</FN>
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Liquidity and Capital Resources
Cash Flow
HCRC generated $9,746,000 of cash flow from operating activities during 1997.
The other primary cash inflows were:
$29,000,000 from borrowings under long-term debt;
$1,144,000 from distributions received from affiliates.
Cash was primarily used for:
$12,106,000 for property additions, exploration and development costs;
$24,000,000 for payments of long-term debt;
When combined with miscellaneous other cash activity during the year, the result
was an increase in HCRC's cash and cash equivalents of $3,864,000 for the year,
from $628,000 at December 31, 1996 to $4,492,000 at December 31, 1997.
Property Purchases, Sales and Capital Budget
In 1997, HCRC incurred $12,106,000 in direct property additions and exploration
and development costs. The costs were comprised of approximately $9,284,000 for
domestic exploration and development expenditures and approximately $2,822,000
for property acquisitions. HCRC's 1997 capital program led to the replacement,
including revisions to prior year reserves, of 107% of 1997 production using
year-end pricing.
HCRC's significant direct exploration and development expenditures in the
Greater Permian Region in 1997 included approximately $275,000 for successfully
recompleting or drilling three development wells, and for drilling two
unsuccessful exploration wells in the Carlsbad/Catclaw Draw areas in Lea, Eddy
and Chaves Counties, New Mexico; approximately $730,000 for acquiring acreage
and drilling 10 exploration wells, seven of which were successful, in the
operated Merkle area; approximately $850,000 for drilling two exploration wells
and nine development wells in the Spraberry area of West Texas, eight of which
were successful; approximately $510,000 to purchase additional interests in the
Spraberry area; and approximately $380,000 for drilling 14 development wells in
the Keystone area, all of which were successful.
In the Hudson Ranch project within the Rocky Mountain Region, HCRC incurred
$340,000 on costs associated with a multi-objective exploration project
generated from 120 miles of 2-D proprietary seismic data. In the Gulf Coast
Region, HCRC spent approximately $945,000 on two unsuccessful exploration
attempts, one unsuccessful development well, and one successful development
well.
Projects begun in the fourth quarter of 1996 have cost HCRC approximately
$525,000 in 1997. These costs are primarily for work in the Gulf Coast Region
and in the Greater Permian Region. HCRC also incurred approximately $690,000 for
miscellaneous land and geological and geophysical data.
For 1998, HCRC's capital budget, which will be paid from cash generated from
operations, cash on hand and borrowings under HCRC's line of credit has been set
at $21,400,000. HCRC's plans include projects in Texas, New Mexico, Colorado,
North Dakota, and Montana.
See Item 2 - Properties, for further discussion of HCRC's exploration and
development projects.
Long lived assets, other than oil and gas properties, are evaluated for
impairment whenever events or changes in circumstances indicate that the
carrying amount may not be recoverable. To date, the Company has not recognized
any impairment losses.
The Company made an offer to repurchase odd lot holdings of 99 or fewer shares
from its stockholders of record as of November 30, 1995. The offer was initially
for the period from November 30, 1995 through January 5, 1996 and was
subsequently extended through January 26, 1996. The Company repurchased a total
of 296,607 shares through the January 26, 1996 closing date for $2,382,000 at a
purchase price of $8.03 per share, of which $1,312,000 was expended during 1996.
On April 1, 1996, HCRC made another offer to purchase holdings of 99 or fewer
shares from its stockholders of record as of March 25, 1996. The offer was for
the period from April 1, 1996 through May 3, 1996. The Company repurchased a
total of 77,790 shares at a purchase price of $11.33 per share. HCRC resold
38,895 of these shares to HEP at the price paid by HCRC for such shares,
resulting in a net repurchase cost to HCRC of $438,000.
Financing
On December 23, 1997, HCRC sold $25,000,000 of 10.32% Senior Subordinated Notes
("Subordinated Notes") due December 23, 2007 to a financial institution. HCRC
also sold Warrants to the lender to purchase 98,599 shares of Common Stock at an
exercise price of $28.99 per share. The Subordinated Notes bear interest at the
rate of 10.32% per annum on the unpaid balance, payable quarterly. Annual
principal payments of $5,000,000 are due on each of December 23, 2003 through
December 23, 2007.
During 1997, the Company and its banks amended their credit agreement to extend
the term date of the line of credit to May 31, 1999 and to reduce the Company's
borrowing base to $10,000,000. As of December 31, 1997, the Company has no
borrowings against the credit line. Subsequent to December 31, 1997, HCRC repaid
its contract settlement obligation of $1,039,000; therefore, HCRC's unused
borrowing base totaled $10,000,000 at February 27, 1998.
Borrowings against the credit line bear interest, at the option of the Company,
at either (i) the banks' Certificate of Deposit rate plus from 1.375% to 1.875%,
(ii) the Euro-Dollar rate plus from 1.25% to 1.75% or (iii) the higher of the
prime rate of Morgan Guaranty Trust or the sum of one-half of 1% and the Federal
funds rate, plus .75%. Interest is payable at least quarterly. The credit
facility is secured by a first lien on approximately 80% in value of the
Company's oil and gas properties.
HCRC has entered into contracts to swap its interest rate payments on
$10,000,000 of its debt for 1998 and $5,000,000 for each of 1999 and 2000. In
general, it is HCRC's goal to hedge 50% of the principal amount of its debt for
the next two years and 25% for each year of the remaining term of the debt. HCRC
has entered into four swaps, of which one is an interest rate collar pursuant to
which it pays a floor rate of 7.55% and a ceiling rate of 9.85% and the others
are interest rate swaps with fixed rates ranging from 5.75% to 6.57%. Under the
swap contracts, HCRC makes interest payments on its line of credit as scheduled
and receives or makes payments based on the differential between the fixed rate
of the swap and a floating rate based on the three-month London Interbank
Offered Rate plus a defined spread.
Historically, HCRC has not used the swaps for trading purposes, but rather for
the purpose of providing a measure of predictability for a portion of HCRC's
interest payments under its line of credit, which has a floating rate of
interest. The swaps have been accounted for as hedges, and the amounts received
or paid upon settlement of the swaps were recognized as interest expense at the
time the interest payments were due. HCRC intends to continue this policy in the
future. In December 1997, HCRC used a portion of the proceeds from the issuance
of the Subordinated Notes mentioned above to repay its line of credit in full,
which resulted in the notional amount of HCRC's interest rate swaps being
unmatched by outstanding indebtedness at year end. As a result, the swaps did
not qualify for hedge accounting as of December 31, 1997. The market value of
the swaps as of December 31, 1997 was approximately $93,000.
Stock Split
During July 1997, the stockholders of HCRC approved an increase in the number of
authorized shares of its Common Stock from 2,000,000 to 10,000,000 shares. HCRC
also declared a three-for-one split of its outstanding Common Stock. The stock
split was effected by issuing, as a stock dividend, two additional shares of
Common Stock for each share outstanding. The stock dividend was paid on August
11 to shareholders of record on August 4. All share and per share information
has been restated to reflect the three-for-one stock split.
Stock Option Plans
During 1995, the Company adopted a stock option plan covering 159,000 shares of
Common Stock and granted options for all of the shares under the plan. The
options were granted effective July 1, 1995 at an exercise price of $6.67 per
share, which was equal to the fair market value of the Common Stock on the day
preceding the date of grant. The options expire on July 1, 2005, unless sooner
terminated pursuant to the provisions of the plan. During December 1996, options
to purchase 1,500 shares were exercised. During 1997, options to purchase 9,270
shares were exercised.
During the second quarter of 1997, the Company adopted a stock option plan
covering 159,000 shares of Common Stock and granted options for all of the
shares under the plan. The terms of this plan are generally consistent with the
terms of the Company's existing 1995 Stock Option Plan. The options were granted
effective June 17, 1997 at an exercise price of $20.33 per share, which was
equal to the fair market value of the Common Stock on the day of grant. The
options expire on June 17, 2007, unless sooner terminated pursuant to the
provisions of the plan. The options are exercisable one-third on June 17, 1997,
an additional one-third June 17, 1998, and the remaining one-third on June 17,
1999. In addition, the plan provides that vesting of the options may be
accelerated under certain conditions.
Gas Balancing
HCRC uses the sales method to account for gas balancing. Under this method, HCRC
recognizes revenue on all of its sales of production, and any over-production or
under-production is recovered at a future date.
As of December 31, 1997, HCRC had a net over-produced position of 360,000 mcf
($781,000 valued at average annual prices). The management of HCRC believes that
all future imbalances can be made up with production from existing wells or from
wells which will be drilled as offsets to current producing wells and that this
imbalance will not have a material effect on HCRC's results of operations,
liquidity and capital resources. The reserves discussed in Item 2 and Item 8
have been reduced by 360,000 mcf in order to reflect HCRC's gas balancing
position.
Recently Issued Accounting Pronouncements
In June 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 130 "Reporting Comprehensive Income" ("SAFS
130"). SAFS 130 established standards for reporting and display of comprehensive
income and its components (revenues, expenses, gains, and losses) in a full set
of general-purpose financial statements. SFAS 130 requires that all items that
are required to be recognized under accounting standards as components of
comprehensive income be reported in a financial statement that is displayed with
the same prominence as other financial statements. Reclassification of financial
statements for earlier periods provided for comparative purposes is required.
The Company is required to adopt SFAS 130 on January 1, 1998. The Company has
not completed the process of evaluating the impact that will result from
adopting SFAS 130 or the manner that will be used to disclose the required
information in its financial statements.
Cautionary Statement Regarding Forward-Looking Statements
In the interest of providing the Company's stockholders and potential investors
with certain information regarding the Company's future plans and operations,
certain statements set forth in this Form 10-K relate to management's future
plans and objectives. Such statements are "forward-looking statements" within
the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange act of 1934, as amended. Although any
forward-looking statements contained in this Form 10-K or otherwise expressed by
or on behalf of the Company are, to the knowledge and in the judgment of the
officers and directors of the Company, expected to prove true and to come to
pass, management is not able to predict the future with absolute certainty.
Forward-looking statements involve known and unknown risks and uncertainties
which may cause the Company's actual performance and financial results in future
periods to differ materially from any projection, estimate or forecasted result.
These risks and uncertainties include, among other things, volatility of oil and
gas prices, competition, risks inherent in the Company's oil and gas operations,
the inexact nature of interpretation of seismic and other geological and
geophysical data, imprecision of reserve estimates, the Company's ability to
replace and expand oil and gas reserves, and such other risks and uncertainties
described from time to time in the Company's periodic reports and filings with
the Securities and Exchange Commission. Accordingly, stockholders and potential
investors are cautioned that certain events or circumstances could cause actual
results to differ materially from those projected.
Inflation and Changing Prices
Prices obtained for oil and gas production depend upon numerous factors that are
beyond the control of HCRC, including the extent of domestic and foreign
production, imports of foreign oil, market demand, domestic and world-wide
economic and political conditions, and government regulations and tax laws.
Prices for both oil and gas have fluctuated from 1995 through 1997. The
following table sets forth the average price received by HCRC for each of the
last three years and the effects of the hedging transactions described below:
Oil Oil Gas Gas
(excluding the effects (including the effects (excluding the effects (including the effects
of hedging of hedging of hedging of hedging
transactions) transactions) transactions) transactions)
(Bbl) (Bbl) (Mcf) (Mcf)
1997 $19.13 $18.87 $2.39 $2.17
1996 20.96 20.13 2.11 1.99
1995 16.71 17.10 1.42 1.62
The Company has entered into numerous financial contracts to hedge the price of
its oil and natural gas. The purpose of the hedges is to provide protection
against price decreases and to provide a measure of stability in the volatile
environment of oil and natural gas spot pricing.
The following table provides a summary of the Company's financial contracts:
Oil
Percent of Direct Production Contract
Period Hedged Floor Price
(per bbl)
1998 14% $14.57
1999 5% 15.38
Between 30% and 100% of the oil volumes hedged in each year are subject to a
participating hedge whereby HCRC will receive the contract price if the posted
futures price is lower than the contract price, and will receive the contract
price plus 25% of the difference between the contract price and the posted
futures price if the posted futures price is greater than the contract price.
All of the volumes hedged in each year are subject to a collar agreement whereby
HCRC will receive the contract price if the spot price is lower than the
contract price, the cap price if the spot price is higher than the cap price,
and the spot price if that price is between the contract price and the cap
price. The cap prices range from $17.00 to $18.85 per barrel.
Gas
Percent of Direct Production Contract
Period Hedged Floor Price
(per mcf)
1998 31% $1.91
1999 18% 1.67
2000 9% 1.86
2001 5% 1.53
Between 0% and 37% of the gas volumes hedged in each year are subject to a
collar agreement whereby HCRC will receive the contract price if the spot price
is lower than the contract price, the cap price if the spot price is higher than
the cap price, and the spot price if that price is between the contract price
and the cap price. The cap price is $2.93 per mcf.
During the first quarter through February 27, 1998, the weighted average oil
price (for barrels not hedged) was approximately $15.57 per barrel, and the
weighted average price of natural gas (for mcfs not hedged) was approximately
$2.00 per mcf.
Inflation
Inflation did not have a material impact on the Company in 1997 and is not
anticipated to have a material impact in 1998.
Results of Operations
The following tables are presented to contrast HCRC's revenue, expense and
earnings for discussion purposes. Significant fluctuations are discussed in the
accompanying narrative.
The "direct owned" column represents HCRC's direct royalty and working share
interests in oil and gas properties. The "HEP" column represents HCRC's share of
the results of operations of HEP. HCRC owned approximately 9% of the outstanding
limited partner units of HEP through the third quarter of 1995, when HCRC's
ownership increased to approximately 19%.
TABLE OF HCRC EARNINGS FOR MANAGEMENT DISCUSSION
(In thousands except price)
For the Year Ended December 31, 1997 For the Year Ended December 31, 1996
Direct Direct
Owned HEP Total Owned HEP Total
Oil production (bbl) 576 135 711 668 169 837
Gas production (mcf) 5,951 2,012 7,963 6,134 2,146 8,280
Average oil price $18.84 $19.00 $18.87 $20.17 $19.98 $20.13
Average gas price $ 2.14 $ 2.25 $ 2.17 $ 1.93 $ 2.15 $ 1.99
Oil revenue $10,851 $2,565 $13,416 $13,476 $ 3,376 $16,852
Gas revenue 12,719 4,532 17,251 11,826 4,620 16,446
Pipeline and other revenue 1,035 556 1,591 510 500 1,010
Interest income 84 69 153 28 109 137
----- ----- ------ ------ ----- ------
Total revenue 24,689 7,722 32,411 25,840 8,605 34,445
Production operating expense 8,108 2,110 10,218 8,203 2,180 10,383
General and administrative expense 3,908 976 4,884 3,186 825 4,011
Interest expense 1,675 583 2,258 1,800 730 2,530
Depreciation, depletion, and amortization 6,621 1,984 8,605 7,050 2,196 9,246
Other 24 90 114
------ ----- ------ ------ ----- ------
20,312 5,653 25,965 20,263 6,021 26,284
INCOME BEFORE INCOME TAXES 4,377 2,069 6,446 5,577 2,584 8,161
------ ----- ------ ----- ----- ------
PROVISION (BENEFIT) FOR INCOME TAXES:
Current 961 961 301 301
Deferred (100) (100) (350) (350)
------- ------ ----- ------
861 861 (49) (49)
------ ------ ----- ------
NET INCOME $ 3,516 $2,069 $ 5,585 $ 5,626 $ 2,584 $ 8,210
====== ====== ===== ===== ===== =====
TABLE OF HCRC EARNINGS FOR MANAGEMENT DISCUSSION
(In thousands except price)
For the Year Ended December 31, 1995
Direct
Owned HEP Total
Oil production (bbl) 611 108 719
Gas production (mcf) 5,725 1,346 7,071
Average oil price $17.14 $16.84 $17.10
Average gas price $ 1.57 $ 1.87 $ 1.62
Oil revenue $10,475 $ 1,819 $12,294
Gas revenue 8,972 2,517 11,489
Pipeline and other revenue 1,299 267 1,566
Interest income 100 35 135
------ ----- ------
Total revenue 20,846 4,638 25,484
Production operating expense 7,191 1,323 8,514
General and administrative expense 3,975 655 4,630
Interest expense 1,316 482 1,798
Depreciation, depletion, and amortization 6,767 1,439 8,206
Impairment of oil and gas properties 8,943 334 9,277
Other 168 78 246
------ ----- ------
28,360 4,311 32,671
INCOME (LOSS) BEFORE INCOME TAXES (7,514) 327 (7,187)
------- ----- -------
PROVISION (BENEFIT) FOR INCOME TAXES:
Current 71 71
Deferred (2,588) (2,588)
------- ------
(2,517) (2,517)
------- ------
NET INCOME (LOSS) $(4,997) $ 327 $ (4,670)
======= ====== ========
1997 Compared to 1996
Oil Revenue
Oil revenue decreased $3,436,000 during 1997 as compared with 1996. The decrease
in revenue is comprised of a decrease in price from $20.13 per barrel in 1996 to
$18.87 per barrel in 1997 and a 15% decrease in oil production from 837,000
barrels in 1996 to 711,000 barrels in 1997. The decrease in production is due to
the temporary shut-in of two wells in Louisiana during the second quarter of
1997 while workover procedures were performed and to normal production declines.
The effect of HCRC's hedging transactions described under "Inflation and
Changing Prices" was to decrease HCRC's average oil price from $19.13 per barrel
to $18.87 per barrel, resulting in a $185,000 decrease in revenue.
Gas Revenue
Gas revenue increased $805,000 during 1997 as compared with 1996. The increase
is comprised of an increase in the average gas price from $1.99 per mcf in 1996
to $2.17 per mcf in 1997, partially offset by a decrease in production from
8,280,000 mcf in 1996 to 7,963,000 mcf in 1997. The decrease in production is
due to the temporary shut-in of two wells in Louisiana during the second quarter
of 1997 while workover procedures were performed and to normal production
declines.
The effect of HCRC's hedging activity was to decrease HCRC's average gas price
from $2.39 per mcf to $2.17 per mcf, resulting in a $1,752,000 decrease in
revenue.
Pipeline and Other
Pipeline and other revenue consists of revenue derived from salt water disposal,
incentive and tax credit payments from certain coalbed methane wells, and other
miscellaneous revenue. Pipeline and other revenue increased by $581,000 during
1997 as compared with 1996, primarily due to the receipt of insurance proceeds
during 1997, which reimbursed a portion of expense incurred in a prior period to
settle certain litigation.
Production Operating Expense
Production operating expense decreased $165,000 during 1997 as compared to 1996.
The decrease is the result of lower production taxes due to the decrease in
production discussed above.
General and Administrative Expense
General and administrative expense includes costs incurred for direct
administrative services such as legal, audit and reserve reports as well as
allocated internal overhead incurred by HPI on behalf of the Company. These
costs increased $873,000 during 1997 as compared to 1996, primarily as a result
of increased performance based compensation during 1997.
Interest Expense
Interest expense represents interest expense on the Company's outstanding debt,
interest incurred on the contract settlement liability related to a recoupable
take-or-pay settlement received in the third quarter of 1989, and the Company's
pro rata share of HEP's interest expense. The Company does not pay any of HEP's
interest expense. Interest expense decreased $272,000 in 1997 as compared to
1996, primarily as a result of a lower average debt balance during 1997.
Depreciation, Depletion and Amortization Expense
Depreciation, depletion and amortization expense associated with proved oil and
gas properties decreased $641,000 during 1997 as compared with 1996. This
decrease is due to a lower depletion rate resulting from the decreased
production discussed above.
Other
Other expense for 1996 is comprised of numerous miscellaneous items, none of
which is individually significant.
1996 Compared to 1995
Oil Revenue
Oil revenue increased $4,558,000 during 1996 as compared with 1995. The increase
in revenue is comprised of an 18% increase in price from $17.10 per barrel in
1995 to $20.13 per barrel in 1996 and a 16% increase in oil production from
719,000 barrels in 1995 to 837,000 barrels in 1996. The increase in production
is due to increased production from developmental drilling projects in West
Texas, Montana and Wyoming, partially offset by normal production declines.
The effect of HCRC's hedging transactions was to decrease HCRC's average oil
price from $20.96 per barrel to $20.13 per barrel, resulting in a $695,000
decrease in revenue.
Gas Revenue
Gas revenue increased $4,957,000 during 1996 as compared with 1995. The increase
is comprised of a 23% increase in the average gas price from $1.62 per mcf in
1995 to $1.99 per mcf in 1996 and a 17% increase in production, from 7,071,000
mcf in 1995 to 8,280,000 mcf in 1996. The increase in production is due to
increased production from developmental drilling projects in West Texas, Montana
and Wyoming, partially offset by normal production declines.
The effect of HCRC's hedging activity was to decrease HCRC's average gas price
from $2.11 per mcf to $1.99 per mcf, resulting in a $994,000 decrease in
revenue.
Pipeline and Other
Pipeline and other revenue decreased by $556,000 during 1996 as compared with
1995, primarily due to a payout adjustment on one of HCRC's wells which occurred
during 1995.
Production Operating Expense
Production operating expense increased $1,869,000 during 1996 as compared to
1995. The increase was the result of higher taxes due to higher production, as
well as increased operating expenses in the West Texas area.
General and Administrative Expense
General and administrative expense decreased by $619,000 during 1996 as compared
to 1995, primarily as a result of decreased performance based compensation and a
decrease in salaries expense and employee benefits expense due to personnel
reductions during 1995.
Interest Expense
Interest expense increased $732,000 in 1996 as compared to 1995, primarily as a
result of increased borrowings against the Company's credit line.
Depreciation, Depletion and Amortization Expense
Depreciation, depletion and amortization expense associated with proved oil and
gas properties increased $1,040,000 during 1996 as compared with 1995. This
increase is primarily due to a higher depletion rate due to the increased
production discussed above as well as higher capitalized costs during 1996 as a
result of capital expenditures incurred during the year.
Other
Other expense for 1996 and 1995 is comprised of numerous miscellaneous items,
none of which is individually significant.
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
FINANCIAL STATEMENTS:
Independent Auditors' Report 25
Consolidated Balance Sheets at December 31, 1997 and 1996 26-27
Consolidated Statements of Operations for the years ended
December 31, 1997, 1996 and 1995 28
Consolidated Statements of Stockholders' Equity for the years
ended December 31, 1997, 1996 and 1995 29
Consolidated Statements of Cash Flows for the years ended
December 31, 1997, 1996 and 1995 30
Notes to Consolidated Financial Statements 31-43
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) 44-47
INDEPENDENT AUDITORS' REPORT
To the Stockholders of Hallwood Consolidated Resources Corporation:
We have audited the consolidated financial statements of Hallwood Consolidated
Resources Corporation as of December 31, 1997 and 1996 and for each of the three
years in the period ended December 31, 1997, listed in the accompanying index at
Item 8. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Hallwood Consolidated Resources
Corporation at December 31, 1997 and 1996, and the results of its operations and
its cash flows for each of the three years in the period ended December 31, 1997
in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Denver, Colorado
February 27, 1998
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands except shares)
December 31,
1997 1996
CURRENT ASSETS
Cash and cash equivalents $ 4,492 $ 628
Accrued oil and gas revenues 4,266 4,808
Due from affiliates 2,418 897
Prepaid and other assets 844 493
Current assets of affiliates 3,854 3,976
------ ------
Total current assets 15,874 10,802
------ ------
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved oil and gas properties 294,922 278,581
Unproved mineral interests - domestic 2,250 1,240
------- -------
Total 297,172 279,821
Less - accumulated depreciation,
depletion, amortization and impairment (221,141) (212,536)
-------- --------
Net property, plant and equipment 76,031 67,285
-------- --------
OTHER ASSETS
Deferred tax asset 450 350
Noncurrent assets of affiliate 16 31
------ -----
Total other assets 466 381
------ ---
TOTAL ASSETS $ 92,371 $ 78,468
====== ======
<FN>
(Continued on the following page)
</FN>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands except shares)
December 31,
1997 1996
CURRENT LIABILITIES
Accounts payable and accrued liabilities 3,087 $ 2,273
Current portion of contract settlement obligation 1,039
Current portion of long-term debt 3,750
Current liabilities of affiliates 6,881 4,826
------ ------
Total current liabilities 11,007 10,849
------ ------
NONCURRENT LIABILITIES
Contract settlement obligation 948
Long-term debt 25,000 16,250
Long-term obligations of affiliates 7,589 7,243
Deferred liability 89 117
------- ------
Total noncurrent liabilities 32,678 24,558
------- ------
Total liabilities 43,685 35,407
------ ------
COMMITMENTS AND CONTINGENCIES (NOTES 11 AND 14)
STOCKHOLDERS' EQUITY
Common stock par value $.01; 10,000,000 shares
authorized; 2,986,812 shares issued in 1997 and
2,977,542 in 1996 30 30
Additional paid in capital 80,111 80,071
Accumulated deficit (27,581) (33,166)
Treasury stock - 259,278 shares in 1997 and 1996 (3,874) (3,874)
------ -------
Stockholders' Equity - net 48,686 43,061
------ -------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 92,371 $ 78,468
======= ======
<FN>
The accompanying notes are an integral
part of the financial statements.
</FN>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands except per share)
For the Years Ended December 31,
1997 1996 1995
REVENUES:
Oil revenue $ 13,416 $ 16,852 $ 12,294
Gas revenue 17,251 16,446 11,489
Pipeline and other 1,591 1,010 1,566
Interest 153 137 135
------ ------ ------
32,411 34,445 25,484
----- ------ ------
EXPENSES:
Production operating 10,218 10,383 8,514
General and administrative 4,884 4,011 4,630
Interest 2,258 2,530 1,798
Depreciation, depletion and amortization 8,605 9,246 8,206
Impairment of oil and gas properties 9,277
Other 114 246
------ ------ ------
25,965 26,284 32,671
------ ------ -------
INCOME (LOSS) BEFORE INCOME TAXES 6,446 8,161 (7,187)
------ ------ -------
PROVISION (BENEFIT) FOR INCOME TAXES:
Current 961 301 71
Deferred (100) (350) (2,588)
------ ------ -------
861 (49) (2,517)
------ ------ -------
NET INCOME (LOSS) $ 5,585 $ 8,210 $ (4,670)
====== ===== =======
NET INCOME (LOSS) PER SHARE - BASIC $ 2.05 $ 3.00 $ (1.48)
====== ===== =======
NET INCOME (LOSS) PER SHARE - DILUTED $ 1.97 $ 2.91 $ (1.48)
====== ===== =======
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING 2,719 2,733 3,165
====== ===== =======
<FN>
The accompanying notes are an integral
part of the financial statements.
</FN>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In thousands)
Additional
Common Paid in Accumulated Treasury
Stock Capital Deficit Stock Total
Balance, December 31, 1994 $ 30 $ 82,927 $(36,706) $ (2,662) $ 43,589
Increase in treasury shares (1,168) (1,168)
Repurchase and retirement of
common stock (1,116) (1,116)
Net loss (4,670) (4,670)
--- ------- -------- -------- -------
Balance, December 31, 1995 30 81,811 (41,376) (3,830) 36,635
Increase in treasury shares (44) (44)
Repurchase and retirement of
common stock (1,750) (1,750)
Exercise of common stock
options 10 10
Net income 8,210 8,210
--- ------- -------- -------- -------
Balance, December 31, 1996 30 80,071 (33,166) (3,874) 43,061
Other (21) (21)
Exercise of common stock
options 61 61
Net income 5,585 5,585
--- ------- -------- -------- -------
Balance, December 31, 1997 $ 30 $ 80,111 $(27,581) $ (3,874) $ 48,686
=== ====== ======== ======= ======
<FN>
Theaccompanying notes are an integral
part of the financial statements.
</FN>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the Years Ended December 31,
1997 1996 1995
OPERATING ACTIVITIES:
Net income (loss) $ 5,585 $ 8,210 $ (4,670)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion, amortization and impairment 8,605 9,246 17,483
Deferred income tax benefit (100) (350) (2,588)
Noncash interest expense 91 83 109
Recoupment of take-or-pay liability (28) (110) (168)
Undistributed earnings of affiliates (3,843) (5,173) (3,469)
Changes in operating assets and liabilities provided
(used)cash net of noncash activity:
Accrued oil and gas revenues 542 (2,134) 22
Due from affiliates (1,569) (1,071) (381)
Prepaid and other assets (351) (382) 91
Accounts payable and accrued liabilities 814 (1,402) 1,877
Payable to affiliates (247)
----- ----- ------
Net cash provided by operating activities 9,746 6,917 8,059
----- ----- ------
INVESTING ACTIVITIES:
Proceeds from oil and gas property sales 40 1,368 726
Additions to oil and gas properties (2,822) (2,182) (2,188)
Exploration and development costs incurred (9,284) (7,578) (7,379)
Refinance of Spraberry investment (6,338)
Distributions received from affiliates 1,144 1,144 1,096
Investment in affiliates (5,330)
------- ------- -------
Net cash used in investing activities (10,922) (13,586) (13,075)
------- ------- --------
FINANCING ACTIVITIES:
Payments of long-term debt (24,000) (2,000)
Proceeds from long-term debt 29,000 10,000 5,000
Repurchase and retirement of common stock (1,750) (1,116)
Payments on contract settlement obligation (118) (518)
Exercise of stock options 61 10
Other financing activities (21) 16 10
----- ----- ------
Net cash provided by financing activities 5,040 6,158 3,376
----- ----- ------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS 3,864 (511) (1,640)
CASH AND CASH EQUIVALENTS:
BEGINNING OF YEAR 628 1,139 2,779
----- ----- ------
END OF YEAR $ 4,492 $ 628 $ 1,139
===== ====== ======
<FN>
Theaccompanying notes are an integral
part of the financial statements.
</FN>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
Hallwood Consolidated Resources Corporation ("HCRC" or the "Company") is a
Delaware corporation engaged in the development, production, sale of oil and
gas, and in the acquisition, exploration, development and operation of oil and
gas properties. The Company's properties are primarily located in the Rocky
Mountain, Mid-Continent, Greater Permian and Gulf Coast regions of the United
States. The principal objective of the Company is to maximize shareholder value
by increasing its reserves, production and cash flow through a balanced program
of development and high potential exploration drilling, as well as selective
acquisitions.
Accounting Policies
Consolidation
HCRC accounts for its interest in affiliated oil and gas Companies and limited
liability companies using the proportionate consolidation method of accounting.
The accompanying financial statements include the activities of HCRC and its pro
rata share of the activities of Hallwood Energy Partners, L. P. ("HEP").
Property, Plant and Equipment
The Company follows the full cost method of accounting whereby all costs related
to the acquisition and development of oil and gas properties are capitalized in
a single cost center ("full cost pool") and are amortized over the productive
life of the underlying proved reserves using the units of production method.
Proceeds from property sales are generally credited to the full cost pool.
Capitalized costs of oil and gas properties may not exceed an amount equal to
the present value discounted at 10% of estimated future net revenues from proved
oil and gas reserves plus the cost, or estimated fair market value, if lower, of
unproved properties. Should capitalized costs exceed this ceiling, an impairment
is recognized. The present value of estimated future net revenues is computed by
applying year-end prices of oil and gas to estimated future production of proved
oil and gas reserves as of year end, less estimated future expenditures to be
incurred in developing and producing the proved reserves and assuming
continuation of existing economic conditions.
The Company does not accrue costs for future site restoration, dismantlement and
abandonment costs related to proved oil and gas properties because the Company
estimates that such costs will be offset by the salvage value of the equipment
sold upon abandonment of such properties. The Company's estimates are based upon
its historical experience and upon review of current properties and restoration
obligations.
Unproved properties are withheld from the amortization base until such time as
they are either developed or abandoned. These properties are evaluated
periodically for impairment.
Long lived assets other than oil and gas properties which are evaluated for
impariment as described above, are evaluated for impairment whenever events or
changes in circumstances indicate that the carrying amount may not be
recoverable. To date, the Company has not recognized any impairment losses
Derivatives
HCRC has entered into numerous financial contracts to hedge the price of its oil
and natural gas. The purpose of the hedges is to provide protection against
price decreases and to provide a measure of stability in the volatile
environment of oil and natural gas spot pricing. The amounts received or paid
upon settlement of these contracts are recognized as oil or gas revenue at the
time the hedged volumes are sold.
Gas Balancing
HCRC uses the sales method to account for gas balancing. Under this method, HCRC
recognizes revenue on all of its sales of production and any over-production or
under-production is recovered or repaid at a future date.
As of December 31, 1997, HCRC had a net over-produced position of 360,000 mcf
($781,000 valued at average annual prices). Current imbalances can be made up
with production from existing wells or from wells which will be drilled as
offsets to current producing wells. HCRC's oil and gas reserves as of December
31, 1997 have been reduced by 360,000 mcf in order to reflect HCRC's gas
balancing position.
Stock Split
During July 1997, the stockholders of HCRC approved an increase in the number of
authorized shares of its Common Stock from 2,000,000 to 10,000,000 shares. HCRC
also declared a three-for-one split of its outstanding Common Stock. The stock
split was effected by issuing, as a stock dividend, two additional shares of
Common Stock for each share outstanding. The stock dividend was paid on August
11 to shareholders of record on August 4. All share and per share information
has been restated to reflect the three-for-one stock split.
Cash and Cash Equivalents
All highly liquid investments purchased with an original maturity of three
months or less are considered to be cash equivalents.
Use of Estimates
The preparation of the financial statements for the Company in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.
Computation of Net Income (Loss) Per Share
During February 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 128 Earnings per Share ("SFAS 128"). SFAS
128 establishes standards for computing and presenting earnings per share (EPS),
and supersedes APB Opinion No. 15 and its related interpretations. It replaces
the presentation of primary EPS with a presentation of basic EPS, which excludes
dilution, and requires dual presentation of basic and diluted EPS for all
entities with complex capital structures. Diluted EPS is computed similarly to
fully diluted EPS pursuant to Opinion No. 15. SFAS 128 is effective for periods
ending after December 15, 1997, including interim periods, and requires
restatement of all prior period EPS data presented. HCRC adopted SFAS 128
effective December 31, 1997, and has restated all prior periods. EPS data
presented to give retroactive effect to the new accounting standard.
Basic income (loss) per share is computed by dividing net income (loss) by the
weighted average number of common shares. Diluted income (loss) per share
includes the potential dilution that could occur upon exercise of the options to
acquire common stock described in Note 10, and the effects of the warrants
described in Note 6, computed using the treasury stock method which assumes that
the increase in the number of shares is reduced by the number of shares which
could have been repurchased by the Company with the proceeds from the exercise
of the options (which were assumed to have been made at the average market price
of the common shares during the reporting period). All share and per share
information has been restated to reflect the three-for-one stock split.
The following table reconciles the number of shares outstanding used in the
calculation of basic and diluted income (loss) per share.
The warrants have been ignored in the computation of diluted net income (loss)
per share in all periods and the stock options have been ignored in the
computation of diluted loss per share in 1995 because their inclusion would be
anti-dilutive.
Income Shares Per Share
(In thousands except per Share)
For the Year Ended December 31, 1997
Net income per share - basic $ 5,585 2,719 $ 2.05
Effect of Options 116
----- ----- ----
Net Income per share - diluted $ 5,585 2,835 $ 1.97
====== ===== =======
For the Year Ended December 31, 1996
Net income per share - basic $ 8,210 2,733 $ 3.00
Effect of Options 87
----- ----- ----
Net Income per share - diluted $ 8,210 2,820 $ 2.91
====== ===== =======
For the Year Ended December 31, 1995
Net loss per share - basic $ (4,670) 3,165 $(1.48)
----- ----- ----
Net loss per share - diluted $ (4,670) 3,165 $(1.48)
====== ===== =======
Treasury Stock
At December 31, 1997 and 1996, the Company owns approximately 19% of the
outstanding units of HEP, which owns approximately 46% of the Company's shares;
consequently, the Company has an interest in 259,278 of its own shares at
December 31, 1997 and 1996. These shares are treated as treasury stock in the
accompanying financial statements.
Significant Customers
Both oil and natural gas are purchased by refineries, major oil companies,
public utilities, industrial customers and other users and processors of
petroleum products. HCRC is not confined to, nor dependent upon, any one
purchaser or small group of purchasers. Accordingly, the loss of a single
purchaser, or a few purchasers, would not materially affect HCRC's business
because there are numerous purchasers in the areas in which HCRC sells its
production. However, for the years ended December 31, 1997, 1996 and 1995,
purchases by the following companies exceeded 10% of the total oil and gas
revenues of the Company:
1997 1996 1995
El Paso Field Services 17% 11%
Williams Gas Marketing 13%
Koch Oil Company 23% 27%
Conoco Inc. 13% 14%
Scurlock Permian Corporation 14%
Environmental Concerns
The Company is continually taking actions it believes are necessary in its
operations to ensure conformity with applicable federal, state and local
environmental regulations. As of December 31, 1997, the Company has not been
fined or cited for any environmental violations which would have a material
adverse effect upon capital expenditures, earnings, cash flows or the
competitive position of the Company in the oil and gas industry.
Recently Issued Accounting Pronouncements
In June 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 130 "Reporting Comprehensive Income" ("SAFS
130"). SAFS 130 established standards for reporting and display of comprehensive
income and its components (revenues, expenses, gains, and losses) in a full set
of general-purpose financial statements. SFAS 130 requires that all items that
are required to be recognized under accounting standards as components of
comprehensive income be reported in a financial statement that is displayed with
the same prominence as other financial statements. Reclassification of financial
statements for earlier periods provided for comparative purposes is required.
The Company is required to adopt SFAS 130 on January 1, 1998. The Company has
not completed the process of evaluating the impact that will result from
adopting SFAS 130 or the manner that will be used to disclose the required
information in its financial statements.
Reclassifications
Certain reclassifications have been made to prior years' amounts to conform to
the classifications used in the current year.
NOTE 2 - OIL AND GAS PROPERTIES
The following table summarizes certain cost information related to the Company's
oil and gas activities, including its pro rata share of HEP's oil and gas
activities. The Company has no material long-term supply agreements, and all
reserves are located within the United States.
For the Years Ended December 31,
1997 1996 1995
(In thousands)
Property acquisition costs $ 3,350 $ 2,830 $10,912
Development costs 6,531 8,617 14,766
Exploration costs 8,064 2,206 2,885
------ ----- ------
Total $17,945 $13,653 $28,563
====== ====== ======
Depreciation, depletion, amortization and property impairment related to proved
oil and gas properties per equivalent barrel of production for the years ended
December 31, 1997, 1996 and 1995 was $4.22, $4.17 and $6.96, respectively.
At December 31, unproved properties consist of the following:
1997 1996
(In thousands)
Texas $ 935 $1,069
California 447
North Dakota 314
Other 554 171
----- -----
$2,250 $1,240
===== =====
NOTE 3 - PRINCIPAL ACQUISITIONS AND SALES
1997
During 1997, HCRC had no individually significant property acquisitions or
sales.
1996
On July 1, 1996, HCRC and HEP completed a transaction involving the acquisition
from Fuel Resources Development Co., a wholly owned subsidiary of Public Service
Company of Colorado, and other interest owners of their interests in 38 coal bed
methane wells located in LaPlata County, Colorado and Rio Arriba County, New
Mexico. Thirty-four of the wells, were assigned to 44 Canyon LLC ("44 Canyon"),
a special purpose entity owned by a large east coast financial institution. The
wells qualify for tax credits under Section 29 of the Internal Revenue Code.
Hallwood Petroleum, Inc. ("HPI") manages and operates the properties on behalf
of 44 Canyon. The $28.4 million purchase price was funded by 44 Canyon through
the sale of a volumetric production payment to an affiliate of Enron Capital &
Trade Resources Corp., a subsidiary of Enron Corp., the sale of a subordinated
production payment and certain other property interests for $3.45 million to an
affiliate of HCRC and HEP, and additional cash contributed by the owners of 44
Canyon. The affiliate of HCRC and HEP which purchased the subordinated
production payment and other property interests is owned equally by HCRC and
HEP. The interests in the four wells in Rio Arriba County were acquired directly
by HCRC and HEP.
1995
On September 29, 1995, HCRC purchased 1,158,696 Class A Units of HEP having a
market value of $5,330,000 from a nominee acting on behalf of the plaintiff
class members in a class action lawsuit against HEP pursuant to the terms of an
option in the settlement of the lawsuit. The purchase of these Class A Units
represents the indirect acquisition of approximately 1.9 million equivalent
barrels of reserves.
NOTE 4 - DERIVATIVES
HCRC has entered into numerous financial contracts to hedge the price of its oil
and natural gas. HCRC does not use these hedges for trading purposes, but rather
for the purpose of providing a protection against price decreases and to provide
a measure of stability in the volatile environment of oil and natural gas spot
pricing. The amounts received or paid upon settlement of these contracts is
recognized as oil or gas revenue at the time the hedged volumes are sold.
The financial contracts used by HCRC to hedge the price of its oil and natural
gas production are swaps, collars and participating hedges. Under the swap
contracts, HCRC sells its oil and gas production at spot market prices and
receives or makes payments based on the differential between the contract price
and a floating price which is based on spot market indices.
The following table provides a summary of HCRC's financial contracts:
Oil
Quantity of Production Contract
Period Hedged Floor Price
(bbls) (per bbl)
1995 220,000 $16.93
1996 219,000 18.47
1997 262,000 17.88
1998 82,000 14.57
1999 23,000 15.38
From 1998 forward, between 30% and 100% of the oil volumes hedged in each year
are subject to a participating hedge whereby HCRC will receive the contract
price if the posted futures price is lower than the contract price, and will
receive the contract price plus 25% of the difference between the contract price
and the posted futures price if the posted futures price is greater than the
contract price. From 1998 forward, all of the volumes hedged in each year are
subject to a collar agreement whereby HCRC will receive the contract price if
the spot price is lower than the contract price, the cap price if the spot price
is higher than the cap price, and the spot price if that price is between the
contract price and the cap price. The cap prices range from $17.00 to $18.85 per
barrel.
Gas
Quantity of Production Contract
Period Hedged Floor Price
(mcf) (mcf)
1995 1,792,000 $1.84
1996 2,429,000 1.77
1997 2,413,000 1.89
1998 1,979,000 1.91
1999 1,062,000 1.67
2000 450,000 1.86
2001 203,000 1.53
From 1998 forward, between 0% and 37% of the gas volumes hedged in each year are
subject to a collar agreement whereby HCRC will receive the contract price if
the spot price is lower than the contract price, the cap price if the spot price
is higher than the cap price, and the spot price if that price is between the
contract price and the cap price. The cap price is $2.93 per mcf.
In the event of nonperformance by the counterparties to the financial contracts,
HCRC is exposed to credit loss, but has no off-balance sheet risk of accounting
loss. The Company anticipates that the counterparties will be able to satisfy
their obligations under the contracts because the counterparties consist of
well-established banking and financial institutions which have been in operation
for many years. Certain of HCRC's hedges are secured by the lien on HCRC's oil
and gas properties which also secures HCRC's Credit Agreement described in Note
6.
NOTE 5 - RELATED PARTY TRANSACTIONS
Hallwood Petroleum, Inc. ("HPI"), an affiliated entity, manages and operates
certain oil and gas properties on behalf of other joint interest owners and the
Company. In such capacity, HPI pays all costs and expenses of operations and
distributes all revenues associated with such properties. The Company had
receivables from HPI of $2,418,000 and $897,000 as of December 31, 1997 and
1996, respectively. These amounts represent revenues net of operating costs and
expenses.
The Company reimburses HPI for actual costs and expenses, which include office
rent, salaries and associated overhead for personnel of HPI engaged in the
acquisition and evaluation of oil and gas properties (technical expenditures
which are capitalized as costs of oil and gas properties) and general and
administrative and lease operating expenditures necessary to conduct the
business of the Company (nontechnical expenditures which are expensed as general
and administrative or production operating expense). Reimbursements during 1997,
1996 and 1995 were as follows (in thousands):
Technical Nontechnical
Expenditures Expenditures
1997 $ 856 $1,225
1996 823 1,293
1995 912 1,627
Included in the nontechnical allocation from HPI attributable to the Company's
direct interest is approximately $241,000, $115,000 and $111,000 of consulting
fees under a contract with The Hallwood Group Incorporated ("Hallwood"), an
affiliated company, during the years ended December 31, 1997, 1996 and 1995,
respectively. Also included in the nontechnical allocation is $232,000, $234,000
and $263,000 in 1997, 1996 and 1995, respectively, representing costs incurred
by Hallwood and its affiliates on behalf of the Company.
During the third quarter of 1994, HPI entered into a consulting agreement with
its Chairman of the Board to provide advisory services regarding the
international activities of its affiliates. The amount of consulting fees
allocated to the Company under this agreement is $125,000 in both 1996 and 1995.
The agreement terminated effective December 31, 1996.
NOTE 6 - DEBT
On December 23, 1997, HCRC sold $25,000,000 of 10.32% Senior Subordinated Notes
("Subordinated Notes") due December 23, 2007 to a financial institution. HCRC
also sold Warrants to the lender to purchase 98,599 shares of Common Stock at an
exercise price of $28.99 per share. The Subordinated Notes bear interest at the
rate of 10.32% per annum on the unpaid balance, payable quarterly. Annual
principal payments of $5,000,000 are due on each of December 23, 2003 through
December 23, 2007.
During 1997, the Company and its banks amended their credit agreement to extend
the term date of the line of credit to May 31, 1999 and to reduce its borrowing
base to $10,000,000. As of December 31, 1997, the Company has no borrowings
against the credit line. Subsequent to December 31, 1997, HCRC repaid its
contract settlement obligation of $1,039,000; therefore, its unused borrowing
base totaled $10,000,000 at February 27, 1998.
Borrowings against the credit line bear interest, at the option of the Company,
at either (i) the banks' Certificate of Deposit rate plus from 1.35% to 1.875%,
(ii) the Euro-Dollar rate plus from 1.25% to 1.75% or (iii) the higher of the
prime rate of Morgan Guaranty Trust or the sum of one-half of 1% and the Federal
funds rate, plus .75%. Interest is payable at least quarterly. The credit
facility is secured by a first lien on approximately 80% in value of the
Company's oil and gas properties. HCRC has no debt maturing within the next five
years. Principal payments for the Subordinated Notes commence in 2003.
HCRC has entered into contracts to swap its interest rate payments on
$10,000,000 of its debt for 1998 and $5,000,000 for each of 1999 and 2000. In
general, it is HCRC's goal to hedge 50% of its debt of the principal amount of
its debt for the next two years and 25% for each year of the remaining term of
the debt. HCRC has entered into four swaps, of which one is an interest rate
collar pursuant to which it pays a floor rate of 7.55% and a ceiling rate of
9.85% and the others are interest rate swaps with fixed rates ranging from 5.75%
to 6.57%. Under the swap contracts, HCRC makes interest payments on its line of
credit as scheduled and receives or makes payments based on the differential
between the fixed rate of the swap and a floating rate based on the three-month
London Interbank Offered Rate plus a defined spread.
Historically, HCRC has not used the swaps for trading purposes, but rather for
the purpose of providing a measure of predictability for a portion of HCRC's
interest payments under its line of credit, which has a floating rate of
interest. The swaps have been accounted for as hedges, and the amounts received
or paid upon settlement of the swaps were recognized as interest expense at the
time the interest payments were due. HCRC intends to continue this policy in the
future. In December 1997, HCRC used a portion of the proceeds from the issuance
of the Subordinated Notes mentioned above to repay its line of credit in full,
which resulted in the notional amount of HCRC's interest rate swaps being
unmatched by outstanding indebtedness at year end. As a result, the swaps did
not qualify for hedge accounting as of December 31, 1997. The market value of
the swaps as of December 31, 1997 was approximately $93,000.
NOTE 7 - CONTRACT SETTLEMENT OBLIGATION
In March 1989, the Company received $2,877,000 as a recoupable take-or-pay
settlement on a contract with a gas pipeline. The settlement was recoupable
monthly in cash or gas volumes, from April 1992 through March 1996 with a
balloon payment due during the first quarter of 1998. A liability has been
recorded equal to the present value of the settlement discounted at 10.68%,
HCRC's estimated borrowing cost in 1989. The Company also repaid $640,000 which
represented the balance of suspended payments to the pipeline for previous
years, in equal monthly installments of $13,329 through March 1996. This amount
was previously recorded as an offset to the full cost pool at the time the
contract was initially abrogated by the pipeline. As payment of this obligation
was made, it was charged to the full cost pool.
At December 31, 1997, the current portion of contract settlement balance
consists of a payment of $1,044,000 due in February 1998, net of unaccreted
discount of $5,000.
NOTE 8 - STATEMENT OF CASH FLOWS
Cash paid for interest during 1997, 1996 and 1995 was $1,434,000, $1,374,000 and
$625,000, respectively. Cash paid for income taxes during 1997, 1996 and 1995
was $1,416,000, $185,000 and $122,000, respectively.
NOTE 9 - INCOME TAXES
The following is a summary of the income tax provision (benefit):
For the Years
Ended December 31,
1997 1996 1995
(In thousands)
State $ 369 $ 236 $ 62
Federal - Current 592 65 9
Deferred (100) (350) (2,588)
----- ----- -------
Total $ 861 $ (49) $(2,517)
==== ===== ======
Reconciliation's of the expected tax at the statutory tax rate to the effective
tax are as follows:
For the Years
Ended December 31,
1997 1996 1995
(In thousands)
Expected tax expense (benefit) at the
statutory rate $ 2,192 $ 2,775 $(2,443)
State taxes net of federal benefit 243 156 41
Change in valuation allowance (1,444) (3,739)
Other (130) 759 (115)
------ ----- ------
Effective tax expense (benefit) $ 861 $ (49) $(2,517)
====== ===== =======
Deferred income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for income tax purposes. The tax effects of
significant items comprising the Company's deferred tax assets and liabilities
as of December 31, 1997 and 1996 are as follows:
1997 1996
Deferred tax assets:
Net operating loss carryforward $ 2,835 $3,606
Capital loss carryforward 1,889 1,688
Temporary differences between
book and tax basis of property 461 1,235
Other
----- ------
Total 5,185 6,529
Valuation allowance (4,735) (6,179)
------ ------
Net deferred tax asset $ 450 $ 350
===== ======
The Company's net operating loss carryforwards expire between 2008 and 2010.
NOTE 10 - EMPLOYEE INCENTIVE PLANS
Every year beginning in 1992, the Company's Board of Directors has adopted an
incentive plan. Each year the Board of Directors determines the percentage of
HCRC's interest in the cash flow from certain wells drilled, recompleted or
enhanced during the year allocated to the incentive plan for that year. The
specified percentage was 2.4% for 1997 and 1996 and 1.4% for domestic wells for
1995. In 1995, HCRC also had an international incentive plan and the percentage
interest in cash flow for that plan was 3%. Beginning in 1996, the domestic and
international plans were combined. The specified percentage of cash flow is then
allocated among certain key employees who are participants in the plan for that
year. Each award under the plan (with regard to domestic properties) represents
the right to receive for five years a portion of the specified share of the cash
flow attributable to qualifying wells included in the plan for that year. In the
sixth year after the award, the participants are each paid a share of an amount
equal to a specified percentage (80% for 1997, 1996 and 1995) of the remaining
net present value of the qualifying wells, and the award for that year
terminates. The expenses attributable to the plans were $400,000 in 1997,
$119,000 in 1996 and $147,000 in 1995 and are included in general and
administrative expense in the accompanying financial statements.
During 1995, the Company adopted a stock option plan covering 159,000 shares of
Common Stock and granted options for all of the shares under the plan. The
options were granted effective July 1, 1995 at an exercise price of $6.67 per
share, which was equal to the fair market value of the Common Stock on the day
preceding the date of grant. The options expire on July 1, 2005, unless sooner
terminated pursuant to the provisions of the plan. During December 1996, options
to purchase 1,500 shares were exercised. During 1997, options to purchase 9,270
shares were exercised.
During the second quarter of 1997, the Company adopted a stock option plan
covering 159,000 shares of Common Stock and granted options for all of the
shares under the plan. The terms of this plan are generally consistent with the
terms of the Company's existing 1995 Stock Option Plan. The options were granted
effective June 17, 1997 at an exercise price of $20.33 per share, which was
equal to the fair market value of the Common Stock on the day of grant. The
options expire on June 17, 2007, unless sooner terminated pursuant to the
provisions of the plan. The options are exercisable one-third on June 17, 1997,
an additional one-third June 17, 1998, and the remaining one-third on June 17,
1999. In addition, the Plan provides that vesting of the options may accelerate
under certain conditions.
A summary of HCRC's Option Plans and the changes therein for the years ended
December 31, 1997, 1996 and 1995 follows:
1997 1996 1995
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
Outstanding at
beginning of year 157,500 $ 6.67 159,000 $6.67
Granted 159,000 20.33 159,000 $6.67
Exercised 9,270 6.67 1,500 6.67
------- ------ -------- ----- -------- ------
Outstanding at year end 307,230 $13.74 157,500 $6.67 159,000 $6.67
======= ====== ======= ==== ======== =====
Options exercisable at
year end 201,230 $10.26 104,500 $6.67 53,000 $6.67
======= ====== ======== =====
The Company has adopted the disclosure-only provisions of Statement of Financial
Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS
123"). Accordingly, no compensation cost has been recognized for the Option
Plan. Had compensation expense for the option plans been determined based on the
fair value at the grant dates, consistent with the provisions of SFAS 123,
HCRC's net income (loss) and net income (loss) per share would have been changed
to the pro forma amounts indicated below:
1997 1996 1995
Net income (loss): as reported $5,585,000 $8,210,000 $(4,670,000)
pro forma 5,488,000 7,975,000 (5,078,000)
Net income (loss)
per share - basic: as reported $2.05 $3.00 $(1.48)
pro forma 2.02 2.92 (1.60)
Net income (loss)
per share - diluted as reported $1.97 $2.91 $(1.48)
pro forma 1.94 2.83 (1.60)
The fair value of the options for disclosure purposes was estimated on the date
of the grant using the Black-Scholes Model with the following assumptions:
1995 Options 1997 Options
Expected dividend yield 0% 0%
Expected price volatility 40% 33%
Risk-free interest rate 6.2% 6.35%
Expected life of options 10 years 6 years
NOTE 11 - COMMITMENTS
The Company is guarantor of 40% of the obligation under the Denver, Colorado
office lease which is in the name of HPI. HEP is guarantor of the remaining 60%
of the obligation. HPI leases 41,000 square feet for approximately $600,000 per
year. The lease expires in 1999.
NOTE 12 - ODD LOT REPURCHASE
The Company made an offer to repurchase odd lot holdings of 99 or fewer shares
from its stockholders of record as of November 30, 1995. The offer was initially
for the period from November 30, 1995 through January 5, 1996 and was
subsequently extended through January 26, 1996. The Company repurchased a total
of 296,607 shares through the January 26, 1996 closing date. The repurchase
price was $8.03 per share.
On April 1, 1996, HCRC made another offer to purchase holdings of 99 or fewer
shares from its stockholders of record as of March 25, 1996. The offer was for
the period from April 1, 1996 through May 3, 1996. The Company repurchased a
total of 77,790 shares at a purchase price of $11.33 per share. HCRC resold
38,895 of these shares to HEP at the price paid by HCRC for such shares.
NOTE 13 - INVESTMENT IN AFFILIATED ENTITIES
HCRC accounts for its 19% investment in HEP and, in 1995, its 60% investment in
Hallwood Spraberry Drilling Company, L.L.C. ("HSD") using the pro rata method of
accounting. The following presents summarized financial information for HEP as
of and for the years ended December 31, 1997, 1996 and 1995, and for HSD as of
and for the year ended December 31, 1995. HCRC assumed direct ownership of the
properties previously held by HSD effective April 1, 1996.
HEP 1997 1996 1995
(In thousands)
Current assets $ 22,142 $ 20,380 $ 18,503
Noncurrent assets 109,461 102,412 106,649
Current liabilities 23,115 21,735 22,866
Noncurrent liabilities 33,166 33,506 41,672
Minority interest 3,258 3,336 3,042
Revenue 45,103 51,066 43,780
Net income (loss) 12,803 15,726 (9,031)
HSD 1995
(In thousands)
Current assets $ 629
Noncurrent assets 14,243
Current liabilities 1,900
Noncurrent liabilities 11,000
Revenue 4,194
Net income 1,631
No other individual entity in which HCRC owns an interest comprises in excess of
10% of the revenues, net income or assets of HCRC.
NOTE 14 - LEGAL PROCEEDINGS
On December 3, 1997, Arcadia Exploration and Production Company ("Arcadia")
filed a Demand for Arbitration with the American Arbitration Association against
Hallwood Consolidated Resources Corporation, Hallwood Energy Partners, L.P.,
E.M. Nominee Partnership Company and Hallwood Consolidated Partners, L.P.
(collectively referred to herein as "Hallwood"), claiming that Hallwood breached
a Purchase and Sale Agreement dated August 25, 1997, between Arcadia and HCRC
and HEP. Arcadia's Demand for Arbitration seeks specific performance of the
agreement which Arcadia claims requires Hallwood to purchase oil and gas
properties from Arcadia for approximately $27 million. HCRC and HEP terminated
the agreement because of environmental and title problems with the properties.
Additionally, Arcadia seeks incidental and special damages, prejudgment
interests and attorneys' fees and costs. Hallwood filed its Answering Statement
and Counterclaim asserting that it properly terminated and/or rescinded the
Agreement and seeking refund of Hallwood's earnest money deposit, prejudgment
interest, attorneys' fees and costs. HCRC's management intends to vigorously
defend the claims asserted by Arcadia and intends to vigorously pursue the
counterclaim against Arcadia. This matter is currently in its preliminary stages
as pre-hearing discovery has only just commenced. Thus, it is too early to
predict the ultimate outcome of this arbitration proceeding.
On April 23, 1992, a lawsuit was filed in the Chancery Court for New Castle
County, Delaware, styled Tappe v. Hallwood Consolidated Resources Corporation,
Hallwood Consolidated Partners, L. P., Hallwood Oil and Gas, Inc., Hallwood
Energy Partners, L. P., and Hallwood Petroleum, Inc. (C. A. No 12536). The
lawsuit seeks to rescind the conversion of Hallwood Consolidated Partners, L.P.
("HCP") into the Company ("Conversion") and to recover damages in unspecified
amounts. The plaintiff also seeks class certification to represent similarly
situated HCP unitholders. In general, the suit alleges that the defendants
breached fiduciary duties to HCP unitholders by, among other things, proposing
allocation of common stock in the Conversion on a basis that the plaintiff
alleges is unfair, failing to require that the allocation be approved by an
independent third party, causing the costs of proposing the Conversion to be
borne indirectly by the partners of HCP whether or not the Conversion was
completed, and failing to disclose certain matters in the Consent
Statement/Prospectus soliciting consents to the Conversion. The defendants
believe that they fully considered and disclosed all material information in
connection with the Conversion, and they believe that the suit is without merit.
HCRC plans to vigorously defend this case, but because of its early stages,
cannot predict the outcome of this matter or any possible effect an adverse
outcome might have.
The Company is involved in other legal proceedings and claims which have arisen
in the ordinary course of its business and have not been finally adjudicated.
The Company believes that its liability, if any, as a result of such proceedings
and claims will not materially affect its financial condition or operations.
NOTE 15 - ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
The following disclosure of the estimated fair value of financial instruments is
made in accordance with the requirements of SFAS No. 107, "Disclosures about
Fair Value of Financial Instruments." The estimated fair value amounts have been
determined by the Company, using available market information and appropriate
valuation methodologies. However, considerable judgment is necessarily required
in interpreting market data to develop the estimates of fair value. Accordingly,
the estimates presented herein are not necessarily indicative of the amounts
that the Company could realize in a current market exchange. The use of
different market assumptions and/or estimation methodologies may have a material
effect on the estimated fair value amounts.
December 31, 1997
Carrying Estimated Fair
Amount Value
(In thousands)
Liabilities:
Oil and gas hedge contracts $ -0- $ 1,060
Long-term debt 25,000 25,000
The estimated fair value of the oil and gas hedge contracts is determined by
multiplying the difference between contract termination prices for oil and gas
and the hedge contract price by the quantities under contract. This amount has
been discounted using an interest rate that could be available to the Company.
Long-term debt is carried in the accompanying balance sheet at an amount which
is a reasonable estimate of its fair value.
The fair value estimates presented herein are based on pertinent information
available to management as of December 31, 1997. Although management is not
aware of any factors that would significantly affect the estimated fair value
amounts, such amounts have not been comprehensively revalued for purposes of
these financial statements since that date, and current estimates of fair value
may differ significantly from the amounts presented herein.
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
(Unaudited)
The following reserve quantity and future net cash flow information for the
Company represents proved reserves which are located in the United States. The
reserve estimates presented have been prepared by in-house petroleum engineers,
and a majority of these reserves has been reviewed by independent petroleum
engineers. The determination of oil and gas reserves is based on estimates which
are highly complex and interpretive. The estimates are subject to continuing
change as additional information becomes available.
The standardized measure of discounted future net cash flows provides a
comparison of the Company's proved oil and gas reserves from year to year. Under
the guidelines set forth by the Securities and Exchange Commission, the
calculation is performed using year end prices. At December 31, 1997, oil and
gas prices averaged $16.77 per bbl of oil and $2.20 per mcf of gas for the
Company, including its interest in HEP. Future production costs are based on
year end costs and include severance taxes. The present value of future cash
inflows is based on a 10% discount rate. The reserve calculations using these
December 31, 1997 prices result in 5.5 million bbls of oil, 76 billion cubic
feet of gas and a standardized measure of $88,000,000. This standardized measure
is not necessarily representative of the market value of the Company's
properties.
HCRC's standardized measure of future net cash flows has been decreased by
$1,935,000 at December 31, 1997 for the effect of its hedge contracts. This
amount represents the difference between year end oil and gas prices and the
hedge contract prices multiplied by the quantities subject to contract,
discounted at 10%.
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
RESERVE QUANTITIES
(Unaudited)
(In thousands)
Gas Oil
(Mcf) (Bbls)
Proved Reserves:
Balance, December 31, 1994 42,924 4,959
Extensions and discoveries 7,548 2,761
Revisions of previous estimates 2,790 131
Sales of reserves in place (52) (151)
Purchases of reserves in place 7,533 664
Production (7,071) (719)
------- -----
Balance, December 31, 1995 53,672 7,645
Extensions and discoveries 1,947 491
Revisions of previous estimates 7,701 (28)
Sales of reserves in place (1,627) (160)
Purchases of reserves in place 11,488 70
Production (8,280) (837)
------- -----
Balance, December 31, 1996 64,901 7,181
Extensions and discoveries 2,894 562
Revisions of previous estimates 15,261 (1,672)
Sales of reserves in place (163) (3)
Purchases of reserves in place 645 168
Production (7,963) (711)
------- -----
Balance, December 31, 1997 75,575 5,525
====== =====
Proved Developed Reserves:
Balance, December 31, 1995 49,854 6,657
====== =====
Balance, December 31, 1996 63,044 6,431
====== =====
Balance, December 31, 1997 73,250 5,080
====== =====
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(Unaudited)
(In thousands)
December 31,
1997 1996 1995
Future sales $227,000 $413,000 $243,000
Future production and development costs (100,000) (158,000) (106,000)
Provision for income tax (8,000) (30,000) (4,000)
-------- ------- --------
Future cash flows 119,000 225,000 133,000
10% discount to present value (31,000) (91,000) (48,000)
-------- ------- --------
Standardized measure of discounted future
net cash flows $ 88,000 $134,000 $ 85,000
======= ======= =========
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(Unaudited)
(In thousands)
For the Years Ended December 31,
1997 1996 1995
Standardized measure of discounted future net cash flows
at beginning of year $134,000 $ 85,000 $ 52,000
Sales of oil and gas produced, net of
production costs (20,449) (22,915) (15,268)
Net changes in prices and production costs (71,933) 46,516 11,325
Extensions and discoveries net of future
production and development costs 5,616 7,011 22,133
Changes in estimated future development costs (6,480) (7,292) (15,738)
Development costs incurred 6,531 8,617 14,766
Revisions of previous quantity estimates 4,688 10,802 3,280
Purchase of reserves in place 1,482 17,061 10,571
Sale of reserves in place (162) (3,707) (879)
Accretion of discount 13,439 8,513 5,200
Net change in income taxes 16,206 (15,332) (2,121)
Changes in production rates and other 5,062 (274) (269)
Standardized measure of discounted ------ ------- -------
future net cash flows at end of year $88,000 $134,000 $ 85,000
====== ======= =======
The standardized measure of discounted future net cash flows is calculated using
year end average oil and gas prices. At December 31, 1997, oil and gas prices
averaged $16.77 per bbl of oil and $2.20 per mcf of gas. If average oil and gas
prices as of February 27, 1998 of $15.57 per bbl of oil and $2.00 per mcf of gas
had been used in this calculation, the standardized measure of discounted future
net cash flows would have been approximately 16% lower.
ITEM 9 - DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
PART III
ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item will be included in the
definitive proxy statement of HCRC relating to HCRC's 1998 Annual
Meeting of Shareholders to be filed with the SEC pursuant to
Regulation 14A, which information is incorporated herein by
reference.
ITEM 11 - EXECUTIVE COMPENSATION
The information required by this item will be included in the
definitive proxy statement of HCRC relating to HCRC's 1998 Annual
Meeting of Shareholders, to be filed with the SEC pursuant to
Regulation 14A, which information is incorporated herein by
reference.
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item will be included in the
definitive proxy statement of HCRC relating to HCRC's 1998 Annual
Meeting of Shareholders, to be filed with the SEC pursuant to
Regulation 14A, which information is incorporated herein by
reference.
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item will be included in the
definitive proxy statement of HCRC relating to HCRC's 1998 Annual
Meeting of Shareholders, to be filed with the SEC pursuant to
Regulation 14A, which information is incorporated herein by
reference.
PART IV
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Financial Statements and Financial Statement Schedules
See Index at Item 8
Reports on Form 8-K
No reports on Form 8-K were filed during the quarter ended
December 31, 1997.
Exhibits
(1) 3.1 Restated Certificate of Incorporation of HCRC, as
amended through January 21, 1992
(1) 3.2 Bylaws of HCRC
(2) 3.3 Amendment to Bylaws of HCRC
(3) 3.4 Certificate of Amendment of Restated Certificate of
Incorporation dated November 9, 1995.
(7) 3.5 Certificate of Amendment of Restated Certificate of
Incorporation, effective August 1, 1997.
4.1 Common Stock Purchase Warrant dated December 23, 1997.
4.2 Registration Rights Agreement dated as of December 23, 1997.
(1) 10.1 Agreement of Limited Partnership of Hallwood
Consolidated Partners, L.P. (originally, agreement of HCP
Acquisition, L. P.)
(1) 10.5 Management Agreement between Hallwood Petroleum, Inc. and HCRC
(4) 10.7 Amended and Restated Credit Agreement dated as of March 31,
1995 among HCRC and the Banks listed therein.
10.8 Extension of Management Agreement between HCRC and Hallwood
Petroleum, Inc. dated May 1, 1997.
* (4) 10.9 Domestic Incentive Plan between HCRC and Hallwood Petroleum,
Inc. dated January 14, 1993.
* (5) 10.10 1995 Stock Option Plan
* (5) 10.11 1995 Stock Option Loan Program
(7) 10.13 Second Amended and Restated Credit Agreement dated as of May
31, 1997.
* (7) 10.14 1997 Stock Option Plan
* (8) 10.15 1997 Stock Option Plan Loan Program
(8) 10.16 Amendment No. 1 to Second Amended and Restated Credit
Agreement dated as of October 31, 1997.
10.17 Subordinated Note and Warrant Purchase Agreement dated as of
December 23, 1997.
10.18 Amendment No. 2 to Second Amended and Restated Credit Agreement
dated as of December 23, 1997.
(6) 21 Subsidiaries of Registrant
23.1 Consent of Deloitte & Touche LLP
23.2 Consent of Deloitte & Touche LLP
- -------------------------------------
(1) Incorporated by reference to the Registrant's Registration
Statement No. 33-45729 on Form S-4 filed on February 14, 1992.
(2) Incorporated by reference to the Annual Report on Form 10-K
for the year ended December 31, 1992.
(3) Incorporated by reference to the Quarterly Report on Form 10-Q
for the quarter ended September 30, 1995.
(4) Incorporated by reference to the Quarterly Report on Form
10-Q for the quarter ended March 31, 1995.
(5) Incorporated by reference to the Quarterly Report on Form
10-Q for the quarter ended June 30, 1995.
(6) Incorporated by reference to the Annual Report on Form 10-K
for the year ended December 31, 1995.
(7) Incorporated by reference to the Quarterly Report on Form
10-Q for the quarter ended June 30, 1997.
(8) Incorporated by reference to the Quarterly Report on Form 10-Q
for the quarter ended September 30, 1997.
* Designates management contract or compensatory plan
or arrangement.
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.
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
Date: February 27, 1998 By: /s/William L. Guzzetti
William L. Guzzetti
President and Director
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
Signature Capacity Date
/s/Anthony J. Gumbiner Chairman of the Board and February 27, 1998
Anthony J. Gumbiner Director
/s/Brian M. Troup Director February 27, 1998
Brian M. Troup
/s/John R. Isaac,Jr. Director February 27, 1998
John R. Isaac, Jr.
/s/Jerry A. Lubliner Director February 27, 1998
Jerry A. Lubliner
/s/Hamilton P. Schrauff Director February 27, 1998
Hamilton P. Schrauff
Bill M. Van Meter Director February 27, 1998
/s/Robert S. Pfeiffer Vice President - February 27, 1998
Robert S. Pfeiffer Chief Financial Officer
(Principal Accounting Officer)