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, 1998
[ ] 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:
Name of each exchange
Title of each class on which registered
None 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. [ ]
The aggregate market value of the voting stock held by nonaffiliates of the
registrant as of March 24, 1999 was approximately $17,249,000.
Shares of Common Stock outstanding at March 24, 1999: 3,007,852 shares.
<PAGE>
PART 1
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.
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 March 24, 1999, HPI had 108 employees.
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 has entered into financial contracts for
hedging the price of 4% of its estimated oil production for 1999.
All of HCRC's gas production is sold on the spot market or in short-term
contracts and is transported in intrastate and interstate pipelines. HCRC has
entered into financial contracts for hedging the price of between 32% and 42% of
its estimated gas production for 1999 through 2002.
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 increases or decreases in 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 other purchasers in the areas in which HCRC sells it
production. However, for the years ended December 31, 1998, 1997 and 1996,
purchases by the following companies exceeded 10% of the total oil and gas
revenues of HCRC.
1998 1997 1996
------ ------ -----
El Paso Field Services 17% 17% 11%
Williams Gas Marketing 13% 13%
Koch Oil Company 12% 23%
Conoco Inc. 12% 13%
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.
<PAGE>
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, 1998, 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
General. The following Year 2000 statements constitute a Year 2000 Readiness
Disclosure within the meaning of the Year 2000 Information and Readiness
Disclosure Act of 1998. The Year 2000 problem has arisen because many existing
computer programs use only the last two digits to refer to a year. Therefore,
these computer programs do not properly recognize and process date-sensitive
information beyond 1999. In general, there are two areas where Year 2000
problems may exist for the Company: information technology such as computers,
programs and related systems ("IT") and non-information technology systems such
as embedded technology on a silicon chip ("Non IT").
The Plan. The Company's Year 2000 Plan (the "Plan") has four phases: (i)
assessment, (ii) inventory, (iii) remediation, testing and implementation and
(iv) contingency plans. Approximately twelve months ago, the Company began its
phase one assessment of its particular exposure to problems that might arise as
a result of the new millennium. The assessment and inventory phases have been
substantially completed and have identified the Company's IT systems that must
be updated or replaced in order to be Year 2000 compliant. In particular, the
software used by the Company for reservoir engineering must be updated or
replaced. Remediation, testing and implementation are scheduled to be completed
by June 30, 1999, and the contingency plans phase of the Plan is scheduled to be
completed by September 30, 1999. However, the effects of the Year 2000 problem
on IT systems are exacerbated because of the interdependence of computer systems
in the United States. The Company's assessment of the readiness of third parties
whose IT systems might have an impact on the Company's business has thus far not
indicated any material problems; responses have been received to approximately
50% of the 172 inquiries made.
With regard to the Company's Non IT systems, the Company believes that most of
these systems can be brought into compliance on schedule. The Company's
assessment of third party readiness is not yet completed. Because the potential
problem with Non IT systems involves embedded chips, it is difficult to
determine with complete accuracy where all such systems are located. As part of
its Plan, the Company is making formal and informal inquiries of its vendors,
customers and transporters in an effort to determine the third party systems
that might have embedded technology requiring remediation.
Estimated Costs. Although it is difficult to estimate the total costs of
implementing the Plan through January 1, 2000 and beyond, the Company's
preliminary estimate is that such costs will not be material. To date, the
Company has determined that its IT systems are either compliant or can be made
compliant for less than $150,000. However, although management believes that its
estimates are reasonable, there can be no assurance, for the reasons stated in
the next paragraph, that the actual cost of implementing the Plan will not
differ materially from the estimated costs.
Potential Risks. The failure to correct a material Year 2000 problem could
result in an interruption in, or a failure of, certain normal business
activities or operations. This risk exists both as to the Company's IT and Non
IT systems, as well as to the systems of third parties. Such failures could
materially and adversely affect the Company's results of operations, cash flow
and financial condition. Due to the general uncertainty inherent in the Year
2000 problem, resulting in part from the uncertainty of the Year 2000 readiness
of third party suppliers, vendors and transporters, the Company is unable to
determine at this time whether the consequences of Year 2000 failures will have
a material impact on the Company's results of operations, cash flow or financial
condition. Although the Company is not currently able to determine the
consequences of Year 2000 failures, its current assessment is that its area of
greatest potential risk in its third party relationships is in connection with
the transporting and marketing of the oil and gas produced by the Company. The
Company is contacting the various purchasers and pipelines with which it
regularly does business to determine their state of readiness for the Year 2000.
Although the purchasers and pipelines will not guaranty their state of
readiness, the responses received to date have indicated no material problems.
The Company believes that in a worst case scenario, the failure of its
purchasers and transporters to conduct business in a normal fashion could have a
material adverse effect on cash flow for a period of six to nine months. The
Company's Year 2000 Plan is expected to significantly reduce the Company's level
of uncertainty about the compliance and readiness of these material third
parties. The evaluation of third party readiness will be followed by the
Company's development of contingency plans.
Cautionary Statement Regarding Forward-Looking Statements. In addition, the
dates for completion of the phases of the Year 2000 Plan are based on the
Company's best estimates, which were derived using numerous assumptions of
future events. Due to the general uncertainty inherent in the Year 2000 problem,
resulting in part from the uncertainty of the Year 2000 readiness of
third-parties and the interconnection of computer systems, the Company cannot
ensure its ability to timely and cost-effectively resolve problems associated
with the Year 2000 issue that may affect its operations and business.
Accordingly, shareholders and potential investors are cautioned that certain
events or circumstances could cause actual results to differ materially from
those projected, estimated or predicted.
ITEM 2 - PROPERTIES
Exploration and Development Projects and Acquisitions
In 1998, HCRC incurred $37,565,000 in direct property additions, development,
exploitation and exploration costs. The costs were comprised of $28,182,000 for
property acquisitions and approximately $9,383,000 for domestic exploration and
development. The expenditures resulted in the drilling, recompletion, or
workover of 41 development wells and 34 exploration wells. HCRC completed 37
development wells (90%) and 18 exploration wells (53%) for an overall completion
rate of 73%. HCRC's 1998 capital program led to the replacement, including
revisions to prior year reserves, of 120% of 1998 production using year-end
prices of $10.00 per bbl and $1.85 per mcf. Using five year average price of
$16.64 per bbl and $1.78 per mcf, HCRC's reserve replacement for 1998 would have
been 200% of 1998 production. Management utilizes average price reserves
internally because it believes these prices more accurately reflect the value to
be achieved over time. Excluded from these calculations are sales of reserves in
place in 1998, which were approximately 3% of 1998 production. In 1998, HCRC
expended approximately $1,672,000 for land and seismic costs, which HCRC
anticipates will yield prospects for 1999 and subsequent years.
Property Sales
During 1998, HCRC received approximately $107,000 for the sale of 67
nonstrategic properties located in eight
states.
Regional Area Descriptions and 1998 Capital Budget
The following discussion of HCRC's properties and capital projects contains
forward-looking statements that are based on current expectations, estimates and
projections about the oil and gas industry, management's beliefs and assumptions
made by management. Words such as "projects," "believes," "expects,"
"anticipates," "estimates," "plans," "could," variations of such words and
similar expressions are intended to identify such forward-looking statements.
Please refer to the section entitled "Cautionary Statement Regarding
Forward-Looking Statements" for a discussion of factors which could affect the
outcome of the forward-looking statements.
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 537
productive oil and gas wells (423 of which are operated), 38 operated shut-in
oil and gas wells and 17 (15 operated) salt water disposal wells or injection
wells. In 1998, HCRC expended approximately $11,685,000 (31%) of its capital
budget on projects in this area. HCRC spent approximately $2,200,000 for
drilling, recompletion, or workover of 23 development wells and for drilling 18
exploration wells. Seventy-eight percent of the wells drilled or recompleted are
producing. The following is a description of the significant areas and 1998
capital projects within the Greater Permian Region.
Arcadia Acquisition. In October 1998, HCRC purchased for $8,200,000 oil and gas
properties, including interests in approximately 570 wells located primarily in
Texas, numerous proven and unproven drilling locations, exploration acreage, and
3-D seismic data. HPI operates approximately 85% of the proven property value.
The acquisition added estimated proven reserves of approximately 576,000 barrels
of oil and 5.5 billion cubic feet of natural gas at five-year average prices,
and approximately 473,000 barrels of oil and 5.5 billion cubic feet of natural
gas at year-end pricing. HCRC's estimated proven reserve addition of 9.0 bcfe
represents approximately 61% of HCRC's 1998 production at five-year average
prices, and 56% of HCRC's 1998 production at year-end prices. HCRC estimates
that gross 1999 production from the properties could be approximately 1.1 bcfe.
In 1999, HCRC plans to divest approximately 400 of the wells acquired from
Arcadia. The wells to be sold are nonstrategic, nonoperated, and represent only
6% of the acquisition's production and 4% of its average price value. During
1999 HCRC plans to study areas for future development project implementation.
Carlsbad/Catclaw Area. HCRC's interests in the Carlsbad/Catclaw Area as of
December 31, 1998 consisted of 93 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 37 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. In 1998, HCRC spent
approximately $488,000 recompleting or drilling eight producing development
wells and drilling one unsuccessful exploration well. HCRC expects to continue
operated development drilling in the Hat Mesa Field.
East Keystone Area. HCRC's interest in the East Keystone Area as of December 31,
1998 consisted of 55 producing wells, 37 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 1998, HCRC had
eight development projects, of which seven were successful. HCRC's future
development plans include a total of three projects for this area.
<PAGE>
Merkle Area. HCRC's interest in the Merkle Area as of December 31, 1998 consists
of 29 producing wells, 16 of which are operated by HPI in Taylor and Nolan
Counties, Texas. 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. Based on its initial success in the
nonoperated Merkle Area, HCRC acquired 74 additional miles of proprietary 3-D
seismic data adjacent to the nonoperated area. HCRC's focus in this area is
exploration of the Canyon, Strawn, Flippen, Tannehill and Ellenberger formations
at depths of 2,500 to 6,500 feet. In 1998, HCRC drilled 11 exploration wells and
one development well, nine of which were completed. HCRC incurred approximately
$1,054,000 in costs in 1998 for the 12 wells drilled. HCRC owns an average 28.5%
working interest in the wells. Even with current low crude oil prices, continued
drilling in this area is economic, and HCRC anticipates additional 1999 drilling
to continue to exploit the reef structures.
Griffin Project. In 1998, HCRC purchased land for $105,000 and incurred costs of
approximately $452,000 to drill three exploration wells and one development well
in Gaines County, Texas. None of the four nonoperated 7,500 foot Leonardian sand
wells was successful. Due to limited delineation drilling potential in this area
and low oil prices, HCRC will delay future drilling and evaluate the viability
of the remaining exploration projects.
HCRC owns an average 25% working interest in the prospect area.
Spraberry Area. HCRC's interests in the Spraberry Area consist of 360 producing
wells, 13 salt water disposal wells and 36 shut-in wells in Dawson, Upton,
Reagan and Irion Counties, Texas. HPI operates 380 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 1998, HCRC drilled or recompleted three wells, all of
which are producing. As a result of low crude oil prices, HCRC abandoned
twenty-three wells in this area in 1998. During 1999, HCRC plans to shut-in 29
uneconomic wells and has scheduled 25 additional wells for abandonment. The
wells scheduled for shut-in produce, in total, only 40 mcfe per day, net to
HCRC, and were operating at a net loss to HCRC of $65,000 per year. Future plans
for this area include eight development wells and workovers and additional
projects contingent upon future evaluation. The price of crude oil must increase
before these projects can be considered viable.
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 23 producing gas wells 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 11 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. In South and East Texas, HCRC has interests in 203 wells, 65 of which
are operated by HPI and produce primarily from the Austin Chalk, Paluxy, Lower
Frio and Cotton Valley formations at depths from 7,000 to 13,000 feet. During
1998, HCRC expended approximately $4,240,000 (11%) of its capital budget in this
region in Louisiana and South and East Texas. The following discussion relates
to major 1998 capital projects within the region.
Bell Project. HCRC has a 30% working interest in an operated project to evaluate
the Buda, Carrizo, Woodbine, and Dexter sands in Houston County, Texas. HCRC's
drilling costs in 1998 for a 9,200-foot horizontal well were approximately
$615,000. The well encountered Buda pay and sales of production began in
December 1998, after gas processing equipment was installed. The well primarily
produces oil. HCRC achieved gross sustained production rates of 8.2 mmcfe per
day; however, due to current low oil prices, flowing rates have been reduced to
approximately 4 mmcfe per day. HCRC also incurred $375,000 in 1998 for land and
leasehold costs relating to the project. HCRC plans additional delineation
drilling in 1999. HCRC anticipates that single or multi-lateral horizontal
drilling will be the principal drilling practice used in this area. The gross
targeted potential for the project could be 2.4 bcfe per well. There can be no
assurance, however, that any well drilled will be successful.
Bison Prospect. HCRC participated in a nonoperated 18,000 foot exploratory well
in Lafayette Parish, Louisiana targeting a large Klump sands structure. Drilling
problems prevented the well from reaching total depth and testing the primary
target horizon in the prospect; however, the secondary target horizon was tested
and found to be non-productive. The well was plugged and abandoned. Total land
and drilling costs incurred by HCRC during 1998 for its 2.5% working interest
were approximately $217,000. Blue Moon Project. During 1998, HCRC entered into a
farmout arrangement under which it contributed acreage to a project drilled in
Lafayette Parish, Louisiana. A well was recently completed and tested over 14
mmcfe of gas per day. HCRC's after payout working interest in the well depends
on unit boundary determinations, but HEP anticipates that its working interest
will be between 5% and 7%. HCRC paid no capital costs for its interest in the
well, and payout is expected to occur during the second quarter of 1999.
East Smith Point. In 1998, HCRC participated in a Frio sand recompletion and a
3-D seismic review of the deep Vicksburg in Chambers County, Texas. HCRC owns a
49% working interest in the project and spent approximately $305,000 for
drilling costs and approximately $426,000 for land and geologic and geophysical
data. In 1998, the first 14,000-foot recompletion was unsuccessful. HCRC does
not plan additional activity in this area.
Esperanza Project. HCRC owns a 7.9% working interest in a nonoperated
15,400-foot directional exploration discovery in the Wilcox formation in LaVaca
County, Texas. The natural gas prospect was developed using proprietary 3-D
seismic data, and the prospect could have a gross target of 60 bcf. The initial
well has been completed and showed gross production rates of 10 mmcfd at a
flowing tubing pressure of 9,000 psi. HCRC spent approximately $365,000 in 1998
for its share of costs. HCRC plans to participate in additional wells in 1999 to
further exploit this discovery. There can be no assurance, however, that any
well drilled will be successful.
Intercoastal Prospect. In 1998, HPI took over operation of a well in which it
did not own an interest in Vermilion Parish, Louisiana. The Planulina sands were
faulted out in the original wellbore, and HCRC sidetracked the well at a depth
of 14,467 feet to test the sands. The well was drilled and logged, and the
objective sands, although well-developed, were found to contain water. The well
was plugged and abandoned. HCRC spent $263,000 to test the concept.
Mirasoles Project. In 1998, HCRC spent approximately $430,000 for land costs
related to the Mirasoles project in Kenedy County, Texas. HCRC owns an interest
in 63 square miles of proprietary 3-D seismic data which defines a large
structural prospect that could have a gross potential of 395 bcfe. HCRC spent
approximately $941,000 in 1998 for its 17.5% working interest share of the cost
of drilling a 17,000-foot Frio formation exploration well. The exploratory well
is being completed, and depending upon test results, additional delineation and
development drilling could be required to properly exploit the structure. There
can be no assurance, however, that any well drilled will be successful.
Rocky Mountain Region
HCRC has significant interests in the Rocky Mountain Region, which include
producing properties in Colorado, Montana, North Dakota and Northwest New
Mexico. HCRC has interests in 207 producing oil and gas wells, 168 of which are
operated by HPI, 27 shut-in wells, 25 of which are operated by HPI, and five
salt water disposal wells. HCRC expended approximately $20,669,000 (55%) of its
1998 capital budget in this area. Approximately $17,291,000 of the capital
budget was used for the purchase of the volumetric production payment discussed
below. In 1998, HCRC spent approximately $2,215,000 to recomplete or drill 13
development wells and to drill three exploration wells. Thirteen of the wells
were completed. A discussion of the major projects in the region follows.
Cajon Lake Field. In 1998, HCRC sidetracked a 6,000-foot Ismay formation
exploration well in San Juan County, Utah. HCRC developed the prospect from
proprietary 3-D seismic data and HPI is the operator of the project. HCRC owns
an approximate 15% working interest in the project and spent approximately
$120,000 to complete the exploration well in 1998. Sales of crude oil production
began in November; however, production will be significantly curtailed until a
natural gas pipeline is constructed to eliminate flaring. HCRC projects that the
fully developed prospect could have 6 bcfe gross potential. There can no
assurance, however, that any well drilled will be successful. Despite low oil
prices, additional delineation drilling is anticipated in 1999.
<PAGE>
Colorado Western Slope Project. HCRC drilled and completed two 5,500 foot Dakota
formation wells in the Piceance Basin in Western Colorado. HCRC owns an average
51% working interest in the wells. The wells had a combined initial production
rate of 1.5 mmcf per day, and both wells began sales of production in the third
quarter of 1998. In 1998, HCRC also recompleted an additional well. Total costs
in 1998 for the three wells were approximately $565,000. HCRC has identified
fourteen additional development locations. HCRC projects that the total project
area could have gross potential reserves of 0.8 bcfe, which is the typical
reserve potential for this area. There can no assurance, however, that any well
drilled will be successful.
Toole County Area. HCRC's interests in the Toole County Area consist of 61
producing wells and 17 shut-in wells, 66 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. In 1998, HCRC drilled three horizontal wells in the East Kevin Field
to the Nisku formation. Two of the oil wells were completed and had combined
initial production rates of 1.3 mmcfe per day. HCRC has a 50% working interest
in the project and spent approximately $728,000 in 1998. Because of current low
oil prices in this sour, lower gravity crude area, HCRC has halted the drilling
of additional development wells and has postponed the re-entry and sidetrack of
the remaining well drilled in 1998.
San Juan Basin Project - Colorado. In July 1996, HCRC and its affiliate Hallwood
Energy Partners, L.P. ("HEP") acquired interests in 34 wells in LaPlata County,
Colorado producing from the Fruitland Coal formation at approximately 3,000
feet. An unaffiliated large East Coast financial institution formed an entity to
utilize tax credits generated from the wells. All production from the wells
generates an additional payment of approximately $.68 per mcf. An affiliate of
Enron Corp. financed the project through a volumetric production payment
("VPP"). During May 1998, a limited liability company owned equally by HCRC and
HEP, purchased the VPP from the affiliate of Enron Corp. HCRC funded its
$17,291,000 share of the acquisition price from operating cash flow and
borrowings under its Credit Agreement. As a result of the acquisition, HCRC
replaced the higher cost and administratively burdensome VPP financing with
lower cost conventional borrowings under its line of credit. At the time of the
purchase, HCRC entered into a financial contract to hedge the volumes subject to
the production payment at an average price of $2.11 per mmbtu. Under the terms
of the original 1996 transaction, HCRC and HEP were already responsible for
costs associated with the wells. HPI has managed and operated the wells since
July 1996, and has increased the wells' gross production from 14 mmcf to
approximately 23.5 mmcf per day through workovers and gas gathering facilities
improvement programs. The acquisition increased HCRC's current average daily
production by 6.25 mmcf per day.
San Juan Basin Project - New Mexico. HCRC's interest in the San Juan Basin
consists of 51 producing gas wells and 10 shut-in wells located in San Juan
County, New Mexico. HPI operates all 51 producing 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. The expansion of the gathering system significantly
increased gas gathering, processing and compression capacity for the associated
properties, which resulted in gross production increases of 3.0 mmcf per day in
1998. In addition to proceeds from the sale of gas, HCRC also receives a payment
of $.36 per mcf for tax credits generated by production from the coalbed methane
wells.
Other
HCRC owns various other interests in properties in Kansas, Oklahoma, California
and South Central Texas. The remaining $971,000 of HCRC's 1998 capital
expenditures were incurred in this area. The costs include $325,000 for an
unsuccessful exploration project in Carter County, Oklahoma, $157,000 for the
completion of an exploration well in Canadian County, Oklahoma and for drilling
four unsuccessful exploration wells in Yolo County, California and other
miscellaneous projects. During 1998, HCRC also participated in two nonoperated
3-D seismic projects in nearby Solano and Colusa Counties, California. HCRC is
in the process of divesting its interests in California projects. As a result of
low oil prices and high lifting costs, HCRC plan to shut-in 35 uneconomic wells
and to outsource its field workforce in 1999. These cost reduction measures are
projected to save $230,000 per year in net operating expenses.
<PAGE>
Peru Block Z-3 Project. HCRC's partner on the Peruvian offshore Z-3 Block
completed 1,200 miles of 2-D seismic data acquisition to supplement existing
seismic data. Data interpretation is in progress, and it will be reviewed by
HCRC in the first quarter of 1999. HCRC has a 7.5% working interest in the
project, but it will not incur capital costs until actual drilling operations
begin. Although the production-sharing contract provides that drilling
operations must begin no later than January 2002, it is anticipated that the
Peruvian government will enact legislation to extend the period for all drilling
commitments by one year.
For 1999, HCRC's capital budget, which will be paid from cash generated from
operations and cash on hand, has been set at $5,152,000. HCRC has budgeted
continued low oil prices for 1999 which significantly impacts cash generated
from operations. Consequently, the capital budget has been set at a lower amount
than the budget for past years. The capital budget for 1999 will be reduced if
HCRC is required to make a principal payment on its debt and if oil and gas
prices decrease further.
Company Reserves, Production and Discussion by Significant Regions
The following table presents the December 31, 1998 reserve data by significant
regions.
<TABLE>
<CAPTION>
Present Value of
Proved Reserve Quantities Estimated Future Net Cash Flows
Proved Proved
Mcf of Gas Bbls of Oil Undeveloped Developed Total
(In thousands)
<S> <C> <C> <C> <C> <C>
Greater Permian Region 10,980 1,950 $11,480 $11,480
Gulf Coast Region 14,574 840 $1,735 19,027 20,762
Rocky Mountain Region 60,226 706 48,009 48,009
Mid-Continent Region 1,087 517 1,710 1,710
Other 140 20 45 1,994 2,039
-------- ------- -------- ------ ------
87,007 4,033 $1,780 $82,220 $84,000
====== ===== ===== ====== ======
</TABLE>
The following table presents the oil and gas production for significant regions.
<TABLE>
<CAPTION>
Production for the Production for the
Year Ended 1998 Year Ended 1997
--------------- ---------------
Mcf of Gas Bbls of Oil Mcf of Gas Bbls of Oil
---------- ----------- ---------- -----------
(In thousands)
<S> <C> <C> <C> <C>
Greater Permian Region 1,705 318 1,719 308
Gulf Coast Region 2,481 75 1,875 64
Rocky Mountain Region 5,983 104 3,977 107
Mid-Continent Region 214 201 234 214
Other 172 18 158 18
--------- ----- ------- -----
10,555 716 7,963 711
====== === ===== ===
</TABLE>
The following table presents the Company's extensions and discoveries by
significant regions.
<TABLE>
<CAPTION>
For the Year Ended 1998 For the Year Ended 1997
Mcf of Gas Bbls of Oil Mcf of Gas Bbls of Oil
(In thousands)
<S> <C> <C> <C> <C>
Greater Permian Region 217 207 529 238
Gulf Coast Region 998 186 295 21
Rocky Mountain Region 91 96 1,756 234
Mid-Continent Region 53 1 43
Other 4 314 26
------- ----- ------ -----
1,363 490 2,894 562
===== === ===== ===
</TABLE>
Average Sales Prices and Production Costs
The following table presents the average oil and gas sales price and average
production costs per equivalent mcf computed at the ratio of six mcf of gas to
one barrel of oil.
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
Average sales price (including effects of hedging):
<S> <C> <C> <C>
Oil and condensate (per bbl) $13.12 $18.87 $20.13
Natural gas (per mcf) 1.91 2.17 1.99
Production costs (per equivalent mcf) .78 .84 .78
</TABLE>
Productive Oil and Gas Wells
The following table summarizes the productive oil and gas wells as of December
31, 1998 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 1,209 104
Gas 319 65
------- ----
1,528 169
===== ===
Oil and Gas Acreage
The following table sets forth the developed and undeveloped leasehold acreage
held directly by HCRC as of December 31, 1998. 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
interest owned in the gross acres.
Gross Net
Developed acreage 91,436 28,728
Undeveloped acreage 306,437 73,727
------- --------
Total 397,873 102,455
======= =======
HCRC holds undeveloped acreage in Texas, Louisiana, Montana, Wyoming, New
Mexico, Kansas, Colorado and North Dakota.
<PAGE>
Drilling Activity
The following table sets forth the number of wells attributable to HCRC's direct
interest drilled in the most recent three years.
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------
1998 1997 1996
---- ---- ----
Gross Net Gross Net Gross Net
Development Wells:
<S> <C> <C> <C> <C> <C> <C>
Productive 11 3.4 23 4.0 29 6.2
Dry 5 1.5 4 1.0 4 1.0
-- --- -- --- -- ---
Total 16 4.9 27 5.0 33 7.2
== === == === == ===
Exploratory Wells:
Productive 17 4.9 14 2.7 1 .1
Dry 16 3.3 22 4.2 4 .6
-- --- -- --- -- ---
Total 33 8.2 36 6.9 5 .7
== === == === == ===
</TABLE>
Office Space
HCRC is guarantor of 40% of the obligation under the Denver, Colorado office
leases which are in the name of HPI. Hallwood Energy Partners, L.P. ("HEP") is
guarantor of the remaining 60% of the obligation. HPI's current lease, for
approximately $600,000 per year, expires in June 1999. During February 1999, HPI
entered into another office lease for approximately $600,000 per year. The new
lease commences upon occupancy, which is expected to be in June or July 1999,
and terminates in seven and one-half years.
ITEM 3 - LEGAL PROCEEDINGS
See Notes 14 and 15 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 1998.
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 March 24, 1999, there
were 2,123 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 shares to 10,000,000 shares.
<PAGE>
HCRC Common Stock High Low
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
First quarter 1998 21 9/16 14 1/4
Second quarter 1998 16 15/16 14 3/8
Third quarter 1998 17 3/8 12
Fourth quarter 1998 15 9 1/2
All share and per share information has been retroactively restated for the
three-for-one stock split effective August 11, 1997.
<PAGE>
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.
<TABLE>
<CAPTION>
Hallwood Consolidated Resources Corporation
As of and for the Year Ended December 31,
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
(In thousands except per share)
Summary of Operations
Oil and gas revenues and
<S> <C> <C> <C> <C> <C>
pipeline operations $ 32,230 $ 32,258 $ 34,308 $ 25,349 $ 20,459
Total revenue 32,410 32,411 34,445 25,484 20,644
Production operating expense 11,642 10,218 10,383 8,514 8,367
Depreciation, depletion and
amortization 11,463 8,605 9,246 8,206 7,340
Impairment 19,600 9,277 4,721
General and administrative expense 4,451 4,884 4,011 4,630 3,842
Net income (loss) (20,279) 5,585 8,210 (4,670) (2,974)
Net income (loss) per share - basic (7.38) 2.05 3.00 (1.48) (.93)
Net income (loss) per share - diluted (7.38) 1.97 2.91 (1.48) (.93)
Balance Sheet
Working capital (deficit) $ (5,696) $ 4,867 $ (47) $ (7,202) $ 430
Property, plant and equipment, net 87,322 76,031 67,285 65,433 55,011
Total assets 101,167 92,371 78,468 73,939 62,125
Noncurrent liabilities 53,316 32,678 24,558 21,790 11,890
Stockholders' equity 29,589 48,686 43,061 36,635 43,589
</TABLE>
<PAGE>
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
During 1998, HCRC had a net loss of $20,279,000, compared to a net income of
$5,585,000 for 1997. The 1998 period includes noncash charges in the second,
third and fourth quarters totaling $19,600,000 for property impairments which
were taken to lower the capitalized cost of HCRC's properties to an amount equal
to the present value, discounted at 10%, of the future net revenues attributable
to those properties.
HCRC's 1998 property impairments were recorded pursuant to ceiling test
limitations required by the Securities and Exchange Commission for companies
using the full cost method of accounting. The total impairment was primarily
attributable to the decline in commodity prices and the write-off of certain
unproved acreage.
The weighted average prices received by HCRC for oil and gas have declined in
each of the last four quarters. HCRC's hedges mitigated the price reductions by
increasing the average oil and gas prices by 3% and 2%, respectively. HCRC's
weighted average oil and gas prices, when the effects of hedging are considered,
were 30% and 12% lower, respectively, for 1998 compared to 1997.
Although HCRC's production for 1998 was 21% greater than the prior year, and
operating and general and administrative expenses were lower on a unit of
production basis, net income was lower because of low commodity prices and costs
associated with the resolution of litigation.
In December 1998 HCRC announced a proposal to consolidate HCRC with HEP and the
energy interests of Hallwood Group into a new corporation called Hallwood Energy
Corporation. The consolidation proposal was approved by the Board of Directors
of HCRC and the general partner of HEP in December 1998. Because of the larger
size of the new corporation, HCRC anticipates that the new company will have the
ability to take advantage of opportunities that are unavailable to smaller
entities such as HCRC and will have a better ability to raise capital. Hallwood
Energy Corporation will focus on reserve growth. A Joint Proxy
Statement/Prospectus for the consolidation was filed with the Securities
Exchange Commission on December 30, 1998 and is proceeding through the usual SEC
comment process. It is presently anticipated that the Joint Proxy
Statement/Prospectus will be mailed to shareholders of HCRC and unitholders of
HEP in April and that the consolidation will be concluded in May 1999. There can
be no assurance, however, that all conditions to the consolidation will be
satisfied by that time.
Liquidity and Capital Resources
Cash Flow
HCRC generated $6,130,000 of cash flow from operating activities during 1998.
The other primary cash inflows were:
o $25,500,000 from borrowings under long-term debt and
o $2,792,000 in distributions received from affiliates.
Cash was primarily used for:
o $37,565,000 for property additions, exploration and development costs
and
o $1,045,000 for payments on contract settlement obligation.
When combined with miscellaneous other cash activity during the year, the result
was a decrease in HCRC's cash and cash equivalents of $3,941,000 for the year,
from $4,492,000 at December 31, 1997 to $551,000 at December 31, 1998.
<PAGE>
Property Purchases, Sales and Capital Budget
In 1998, HCRC incurred $37,565,000 in direct property additions, development,
exploitation and exploration costs. The costs were comprised of $28,182,000 for
property acquisitions and approximately $9,383,000 for domestic exploration and
development. HCRC's 1998 capital program led to the replacement, including
revisions to prior year reserves, of 120% of 1998 production using year-end
prices of $10.00 per bbl and $1.85 per mcf.
In the Greater Permian Region, HCRC expended $8,385,000 acquiring oil and gas
properties, including interests in approximately 570 wells, numerous proven and
unproven drilling locations, exploration acreage, and 3-D seismic data.
Additionally, HCRC spent approximately $488,000 to recomplete or drill nine
producing development wells and one unsuccessful exploration well in the
Carlsbad/Catclaw Draw areas in Lea, Eddy and Chaves Counties, New Mexico. Also,
approximately $1,066,000 was spent to drill 11 exploration wells and one
development well, nine of which were completed in the Merkle Project. HCRC
incurred approximately $452,000 drilling three exploration wells and one
development well in the Griffin area, all of which were unsuccessful.
In the Gulf Coast Region, HCRC spent approximately $430,000 for land and
$941,000 to drill one Mirasoles exploration well in Kenedy County, Texas, which
is currently in the completion phase. HCRC incurred approximately $365,000 to
drill one successful exploration well relating to the Esperanza project in
LaVaca County, Texas. Approximately $375,000 was incurred by HCRC for land and
leasehold costs and an additional $615,000 for costs associated with drilling
one successful exploration well in Bell County, Texas. 1998 costs relating to
the East Smith Point project in Chambers County, Texas were approximately
$426,000 for land and geologic and geophysical data and an additional $305,000
to drill one unsuccessful exploration well in the area. In addition
approximately $217,000 was incurred in 1998 by HCRC to drill one well now
plugged and abandoned as part of the Bison project in Lafayette Parish,
Louisiana.
HCRC's significant property acquisition in the Rocky Mountain Region was
approximately $17,291,000 for the purchase of a volumetric production payment in
the Colorado San Juan Basin. Additionally, HCRC's significant exploration and
development expenditures in the Rocky Mountain Region included approximately
$120,000 to complete a successful exploration well within the Cajon Lake Field
in Utah; approximately $565,000 to drill three successful wells in the Colorado
Western Slope area; approximately $245,000 to drill an unsuccessful exploration
well in the West Sioux area of Montana; and approximately $728,000 to drill
three horizontal wells in Toole County, Montana, two of which were successful.
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 on long-lived assets other than oil and gas properties.
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 holding 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 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.
<PAGE>
Financing
On December 23, 1997, HCRC sold $25,000,000 of 10.32% Senior Subordinated Notes
("Subordinated Notes") due December 23, 2007 to The Prudential Insurance Company
of America ("Prudential"). HCRC also sold Warrants to Prudential 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.
The proceeds from the Subordinated Notes were allocated to the Subordinated
Notes and to the Warrants based upon the relative fair values of the
Subordinated Notes without the Warrants and of the Warrants themselves at the
time of issuance. The allocated value of the Warrants of $1,032,000 was recorded
as paid-in-capital. The discount on the Subordinated Notes is being amortized
over the term of the Subordinated Notes using the interest method of
amortization.
Because of the substantial property impairments taken in 1998, HCRC's net worth
at December 31, 1998, was less than the amount required under the terms of its
Subordinated Note agreement. At December 31, 1998, HCRC was not in compliance
with the net worth covenant under the Subordinated Note agreement and under its
Credit Agreement. HCRC has obtained a waiver of compliance with the covenants
from both the Subordinated Note holder and HCRC's lenders under its Credit
Agreement. In March 1999, the Subordinated Note agreement was amended to reduce
the net worth requirement to $25,000,000 until the earlier of March 31, 2000 or
the last day of the fiscal quarter immediately before the consolidation with
HEP.
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. The banks are Morgan
Guaranty Trust Company, First Union National Bank and NationsBank of Texas.
Under the Credit Agreement, HCRC has a borrowing base of $26,500,000. As of
December 31, 1998, the Company had amounts outstanding of $25,500,000. HCRC's
unused borrowing base totaled $1,000,000 at March 24, 1999.
Borrowings against the Credit Agreement 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%. The applicable interest rate was 6.75% at
December 31, 1998. Interest is payable at least quarterly, and quarterly
principal payments of $1,594,000 commence May 31, 1999. The Credit Agreement is
secured by a first lien on approximately 80% in value of the Company's oil and
gas properties.
The borrowing base for the Credit Agreement is redetermined semiannually, and
the next redetermination is scheduled for the second quarter of 1999. HCRC
anticipates that, because of low oil and gas prices, its lenders will reduce the
borrowing base and that HCRC will be required to make a principal payment on its
debt. Any required principal payment will reduce the amount available for HCRC's
capital budget.
As part of its risk management strategy, HCRC enters into financial contracts to
hedge the interest payments related to a portion of its outstanding borrowings
under its Credit Agreement. HCRC does not use the hedges for trading purposes,
but rather to protect against the variability of cash flows under its Credit
Agreement, which has a floating interest rate. The amounts received or paid upon
settlement of these transactions are recognized as interest expense at the time
the interest payments are due.
<PAGE>
As of March 24, 1999, HCRC was a party to six contracts with three
counterparties. The following table provides a summary of the Company's
financial contracts.
Average
Amount of Contract
Period Debt Hedged Floor Rate
1999 $13,000,000 5.70%
2000 15,000,000 5.65%
2001 12,000,000 5.23%
2002 12,500,000 5.23%
2003 12,500,000 5.23%
2004 2,000,000 5.23%
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 shares 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 date
of grant. The options expire on July 1, 2005, unless sooner terminated pursuant
to the provisions of the plan. During 1997, options to purchase 9,200 shares
were exercised, and during 1998 options to purchase 21,040 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 date 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.
On May 5, 1998, HCRC granted options to purchase 9,540 shares of Common Stock
under its 1997 Stock Option Plan at an exercise price of $15.75 which was equal
to the fair market value of the Common Stock on the date of grant. One-third of
the options vest immediately, and the remainder vest one-half on the first
anniversary of the date of grant and one-half on the second anniversary of the
date of grant.
On May 5, 1998, HCRC also granted options to purchase 9,540 shares of Common
Stock at an exercise price of $15.75 per share which was equal to the fair
market value of the Common Stock on the date of grant. These options were not
granted pursuant to a previously existing plan, but are subject to terms and
conditions identical to those in HCRC's 1995 Stock Option Plan. One-third of the
options vest immediately, and the remainder vest one-half on the first
anniversary of the date of grant and one-half on the second anniversary of the
date of grant.
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.
<PAGE>
As of December 31, 1998, HCRC had a net over-produced position of 347,000 mcf
($642,000 valued at year-end prices). The management of HCRC believes that this
imbalance 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 of HCRC's results of operations, liquidity and
capital resources. The reserves discussed in Item 2 and Item 8 have been reduced
by 347,000 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" ("SFAS
130"). SFAS 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 adopted SFAS 130 on January 1, 1998. The Company does not have any
items of other comprehensive income for the years ended December 31, 1998, 1997
and 1996. Therefore, total comprehensive income (loss) is the same as net income
(loss) for those years.
In June 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 131 "Disclosures about Segments of an
Enterprise and Related Information" ("SFAS 131"). SFAS 131 establishes standards
for reporting selected information about operating segments and related
disclosures about products and services, geographic areas, and major customers.
SFAS 131 requires that an entity report financial and descriptive information
about its operating segments which are regularly evaluated by the chief
operating decision maker in deciding how to allocate resources and in assessing
performance. HCRC adopted FAS 131 in 1998.
The Company engages in the development, production and sale of oil and gas, and
the acquisition, exploration, development and operation of oil and gas
properties in the continental United States. These activities exhibit similar
economic characteristics and involve the same products, production processes,
class of customers, and methods of distribution. Management of the Company
evaluates its performance as a whole rather than by product or geographically.
As a result, HCRC's operations consist of one reportable segment.
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 "Accounting for Derivative Instruments
and Hedging Activities" ("SFAS 133"). SFAS 133 establishes standards for
derivative instruments, including certain derivative instruments embedded in
other contracts (collectively referred to as derivatives) and for hedging
activities. SFAS 133 requires that an entity recognize all derivatives as either
assets or liabilities in the statement of financial position and measure those
instruments at fair value. If certain conditions are met, a derivative may be
specifically designated as (a) a hedge of the exposure to changes in the fair
value of a recognized asset or liability or an unrecognized firm commitment, (b)
a hedge of the exposure to variable cash flows of a forecasted transaction, or
(c) a hedge of the foreign currency exposure of a net investment in a foreign
operation, an unrecognized firm commitment, an available-for-sale security, or a
foreign-currency-denominated forecasted transaction. The accounting for changes
in the fair value of a derivative (gains and losses) depends on the intended use
of the derivative and the resulting designation. The Company is required to
adopt SFAS 133 on January 1, 2000. The Company has not completed the process of
evaluating the impact that will result from adopting SFAS 133.
Cautionary Statement Regarding Forward-Looking Statements
In the interest of providing the shareholders 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 meanings 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 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 others:
Volatility of oil and gas prices. It is impossible to predict future oil and gas
price movements with certainty. Declines in oil and gas prices may materially
adversely affect HCRC's financial condition, liquidity, ability to finance
planned capital expenditures and results of operations. Lower oil and gas prices
may also reduce the amount of oil and gas that HCRC can produce economically.
HCRC's revenues, profitability, future growth and ability to borrow funds or
obtain additional capital, as well as the carrying value of its properties, will
be substantially dependent upon prevailing prices of oil and gas. Historically,
the markets for oil and gas have been volatile, and they are likely to continue
to be volatile in the future. Prices for oil and gas are subject to wide
fluctuation in response to relatively minor changes in the supply of and demand
for oil and gas, market uncertainty and a variety of additional factors that are
beyond HCRC's control.
Competition from larger, more established oil and gas companies. HCRC encounters
competition from other oil and gas companies in all areas of its operations,
including the acquisition of exploratory prospects and proven properties. HCRC's
competitors include major integrated oil and gas companies and numerous
independent oil and gas companies, individuals and drilling and income programs.
Many of its competitors are large, well-established companies with substantially
larger operating staffs and greater capital resources than HCRC's and, in many
instances, have been engaged in the oil and gas business for a much longer time
than HCRC. Those companies may be able to pay more for exploratory prospects and
productive oil and gas properties, and may be able to define, evaluate, bid for
and purchase a greater number of properties and prospects than HCRC's financial
or human resources permit. HCRC's ability to explore for oil and gas prospects
and to acquire additional properties in the future will be dependent upon its
ability to conduct its operations, to evaluate and select suitable properties
and to consummate transactions in highly competitive environments.
Risks of drilling activities. HCRC's success will be materially dependent upon
the continued success of its drilling program. HCRC's future drilling activities
may not be successful and, if drilling activities are unsuccessful, such failure
will have an adverse effect on HCRC's future results of operations and financial
condition. Oil and gas drilling involves numerous risks, including the risk that
no commercially productive oil or gas reservoirs will be encountered, even if
the reserves targeted are classified as proved. The cost of drilling, completing
and operating wells is often uncertain, and drilling operations may be
curtailed, delayed or canceled as a result of a variety of factors, including
unexpected drilling conditions, pressure or irregularities in formations,
equipment failures or accidents, adverse weather conditions, compliance with
governmental requirements and shortages or delays in the availability of
drilling rigs and the delivery of equipment. Although HCRC has identified
numerous drilling prospects, there can be no assurance that such prospects will
be drilled or that oil or gas will be produced from any such identified
prospects or any other prospects.
Risks relating to the acquisition of oil and gas properties. The successful
acquisition of producing properties requires an assessment of recoverable
reserves, future oil and gas prices, operating costs, potential environmental
and other liabilities and other factors. Such assessments are necessarily
inexact and their accuracy inherently uncertain. In connection with such an
assessment, HCRC will perform a review of the subject properties that it
believes to be generally consistent with industry practices. This usually
includes on-site inspections and the review of reports filed with various
regulatory entities. Such a review, however, will not reveal all existing or
potential problems, nor will it permit a buyer to become sufficiently familiar
with the properties to fully assess their deficiencies and capabilities.
Inspections may not always be performed on every well, and structural and
environmental problems are not necessarily observable even when an inspection is
undertaken. Even when problems are identified, the seller may be unwilling or
unable to provide effective contractual protection against all or part of these
problems. There can be no assurances that any acquisition of property interests
by HCRC will be successful and, if an acquisition is unsuccessful, that the
failure will not have an adverse effect on HCRC's future results of operations
and financial condition.
<PAGE>
Hazards relating to well operations and lack of insurance. The oil and gas
business involves certain hazards such as well blowouts; craterings; explosions;
uncontrollable flows of oil, gas or well fluids; fires; formations with abnormal
pressures; pollution; and releases of toxic gas or other environmental hazards
and risks, any of which could result in substantial losses to HCRC. In addition,
HCRC may be liable for environmental damages caused by previous owners of
property purchased or leased by HCRC. As a result, substantial liabilities to
third parties or governmental entities may be incurred, the payment of which
could reduce or eliminate the funds available for exploration, development or
acquisitions or result in the loss of HCRC's properties. While HCRC believes
that it maintains all types of insurance commonly maintained in the oil and gas
industry, it does not maintain business interruption insurance. In addition,
HCRC cannot predict with certainty the circumstances under which an insurer
might deny coverage. The occurrence of an event not fully covered by insurance
could have a materially adverse effect on HCRC's financial condition and results
of operations.
Future oil and gas production depends on continually replacing and expanding
reserves. In general, the volume of production from oil and gas properties
declines as reserves are depleted, with the rate of decline depending on
reservoir characteristics. HCRC's future oil and gas production is, therefore,
highly dependent upon its ability to economically find, develop or acquire
additional reserves in commercial quantities. Except to the extent HCRC acquires
properties containing proved reserves or conducts successful exploration and
development activities, or both, the proved reserves of HCRC will decline as
reserves are produced. The business of exploring for, developing or acquiring
reserves is capital-intensive. To the extent cash flow from operations is
reduced, and external reserves of capital become limited or unavailable, HCRC's
ability to make the necessary capital investments to maintain or expand its
asset base of oil and gas reserves would be impaired. In addition, there can be
no assurance that HCRC's future exploration, development and acquisition
activities will result in additional proved reserves or that HCRC will be able
to drill productive wells at acceptable costs. Furthermore, although HCRC's
revenues could increase if prevailing prices for oil and gas increase
significantly, HCRC's finding and development costs could also increase.
Estimates of reserves and future cash flows are imprecise. Reservoir engineering
is a subjective process of estimating underground accumulations of oil and gas
that cannot be measured in an exact manner. Estimates of economically
recoverable oil and gas reserves and of future net cash flows necessarily depend
upon a number of variable factors and assumptions, such as historical production
from the area compared with production from other producing areas, the assumed
effects of regulations by governmental agencies, and assumptions concerning
future oil and gas prices, future operating costs, severance and excise taxes,
development costs and workover and remedial costs, all of which may in fact vary
considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and gas attributable to any
particular group of properties, classifications of such reserves based on risk
of recovery, and estimates of the future net cash flows expected from them
prepared by different engineers, or by the same engineers but at different
times, may vary substantially, and such reserve estimates may be subject to
downward or upward adjustment based upon such factors. In addition, the status
of the exploration and development program of any oil and gas company is
ever-changing. Consequently, reserve estimates also vary over time. Actual
production, revenues and expenditures with respect to HCRC's reserves will
likely vary from estimates, and such variances may be material.
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 worldwide
economic and political conditions and government regulations and tax laws.
Prices for both oil and gas have fluctuated from 1996 through 1998, with a
distinct downward trend in both oil and gas prices occurring in the calendar
year 1998. HCRC anticipates that both oil and gas prices will remain low
throughout 1999. In preparing its 1999 budget, HCRC has estimated that the
weighted average oil price (for barrels not hedged) will be $11.00 per barrel,
and the weighted average price of natural gas (for mcf not hedged) will be $1.70
per mcf for the year. There can be no assurance that HCRC's forecast is
accurate. If prices decrease further, it can be expected that the results of
operations and cash flow will be affected, and HCRC's capital budget will
decrease.
<PAGE>
The following table presents the weighted average prices received per year by
HCRC, and the effects of the hedging transactions discussed below.
<TABLE>
<CAPTION>
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)
<S> <C> <C> <C> <C>
1998 $12.75 $13.12 $1.87 $1.91
1997 19.13 18.87 2.39 2.17
1996 20.96 20.13 2.11 1.99
</TABLE>
As part of its risk management strategy, HCRC enters into 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 the hedge contracts are recognized as
increases or decreases in oil or gas revenue at the time the hedged volumes are
sold. During 1998, HCRC did not enter into additional oil price hedges for
future years because hedge contracts at prices HCRC considers advantageous are
not available.
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. As of March 24,
1999, HCRC was a party to 18 financial contracts with three different
counterparties.
The following table provides a summary of the Company's financial contracts:
Oil
Percent of Direct Production Contract
Period Hedged Floor Price
(per bbl)
1999 4% $14.88
All of the oil volumes hedged are subject to participating hedges 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 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 $16.50 to $18.35 per
barrel.
Gas
Percent of Direct Production Contract
Period Hedged Floor Price
(per mcf)
1999 42% $1.95
2000 33% 1.95
2001 33% 1.92
2002 32% 1.98
During the first quarter through March 24, 1999, the weighted average oil price
(for barrels not hedged) was approximately $10.95 per barrel, and the weighted
average price of natural gas (for mcfs not hedged) was approximately $1.65 per
mcf. Inflation
Inflation did not have a material impact on the Company in 1998, 1997 and 1996
and is not anticipated to have a material impact in 1999.
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 19% of the
outstanding limited partner units of HEP during 1996, 1997 and 1998.
<PAGE>
<TABLE>
<CAPTION>
TABLE OF HCRC EARNINGS FOR MANAGEMENT DISCUSSION
(In thousands except price)
For the Year Ended December 31, 1998 For the Year Ended December 31, 1997
------------------------------------ ------------------------------------
Direct Direct
Owned HEP Total Owned HEP Total
<S> <C> <C> <C> <C> <C> <C>
Gas production (mcf) 8,139 2,416 10,555 5,951 2,012 7,963
Oil production (bbl) 576 140 716 576 135 711
Average gas price $ 1.87 $ 2.04 $ 1.91 $ 2.14 $ 2.25 $ 2.17
Average oil price $12.97 $13.71 $13.12 $18.84 $19.00 $18.87
Gas revenue $15,222 $4,920 $20,142 $12,719 $4,532 $17,251
Oil revenue 7,473 1,919 9,392 10,851 2,565 13,416
Pipeline and other 1,947 749 2,696 1,035 556 1,591
Interest income 112 68 180 84 69 153
------- ------- ------- -------- ------- ---------
Total revenue 24,754 7,656 32,410 24,689 7,722 32,411
Production operating 9,349 2,293 11,642 8,108 2,110 10,218
General and administrative 3,535 916 4,451 3,908 976 4,884
Interest 3,634 526 4,160 1,675 583 2,258
Depreciation, depletion, and amortization 8,948 2,515 11,463 6,621 1,984 8,605
Impairment of oil and gas properties 19,600 19,600
Litigation 827 260 1,087
------- ------ ------- ----------- --------- -------
45,893 6,510 52,403 20,312 5,653 25,965
INCOME (LOSS) BEFORE INCOME
TAXES (21,139) 1,146 (19,993) 4,377 2,069 6,446
------- ----- ------- ------- ----- -------
PROVISION (BENEFIT) FOR
INCOME TAXES:
Current (164) (164) 961 961
Deferred 450 450 (100) (100)
--------- --------- -------- --------
286 286 861 861
--------- --------- -------- --------
NET INCOME (LOSS) $(21,425) $1,146 $(20,279) $ 3,516 $2,069 $ 5,585
======= ===== ======= ======= ===== =======
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
TABLE OF HCRC EARNINGS FOR MANAGEMENT DISCUSSION
(In thousands except price)
For the Year Ended December 31, 1996
Direct
Owned HEP Total
<S> <C> <C> <C>
Gas production (mcf) 6,134 2,146 8,280
Oil production (bbl) 668 169 837
Average gas price $ 1.93 $ 2.15 $ 1.99
Average oil price $20.17 $19.98 $20.13
Gas revenue $11,826 $4,620 $16,446
Oil revenue 13,476 3,376 16,852
Pipeline and other 510 500 1,010
Interest income 28 109 137
---------- ------ --------
Total revenue 25,840 8,605 34,445
Production operating 8,203 2,180 10,383
General and administrative 3,186 825 4,011
Interest 1,800 730 2,530
Depreciation, depletion, and amortization 7,050 2,196 9,246
Other 24 90 114
---------- ------- --------
20,263 6,021 26,284
INCOME BEFORE INCOME TAXES 5,577 2,584 8,161
------- ----- -------
PROVISION (BENEFIT) FOR
INCOME TAXES:
Current 301 301
Deferred (350) (350)
------- -------
(49) (49)
-------- --------
NET INCOME $5,626 $2,584 $8,210
===== ===== =====
</TABLE>
<PAGE>
1998 Compared to 1997
Gas Revenue
Gas revenue increased $2,891,000 during 1998 compared with 1997. The increase is
comprised of an increase in production from 7,963,000 mcf in 1997 to 10,555,000
mcf in 1998 partially offset by a decrease in the average gas price from $2.17
per mcf in 1997 to $1.91 per mcf in 1998. Production increased because two
temporarily shut-in wells were back on line. The two wells were temporarily
shut-in during the second quarter of 1997 while workover procedures were
performed. The increase in gas production is also due to an expansion of the
gathering system in San Juan County, New Mexico during 1998.
The effect of HCRC's hedging activity was to increase HCRC's average price from
$1.87 per mcf to $1.91 per mcf, resulting in a $422,000 increase in revenue.
Oil Revenue
Oil revenue decreased $4,024,000 during 1998 compared with 1997. The decrease in
revenue is primarily due to a decrease in price from $18.87 per barrel in 1997
to $13.12 per barrel in 1998, partially offset by an increase in production from
711,000 barrels in 1997 to 716,000 barrels in 1998. Production increased
slightly because two temporarily shut-in wells were back on line. The two wells
were temporarily shut-in during the second quarter of 1997 while workover
procedures were performed. This increase in production was partially offset by
normal production declines.
The effect of HCRC's hedging transactions was to increase HCRC's average oil
price from $12.75 per barrel to $13.12 per barrel, resulting in a $265,000
increase in revenue.
Pipeline and Other
Pipeline and other revenue consists of revenue derived from saltwater disposal,
incentive and tax credit payments from certain coalbed methane wells, and other
miscellaneous revenue. Pipeline and other revenue increased $1,105,000 during
1998 compared to 1997, primarily due to increased incentive payment income
resulting from HCRC's acquisition of a volumetric production payment during May
1998.
Interest Income
Interest income increased $27,000 during 1998 compared with 1997 primarily due
to an increase in the average cash balance during 1998.
Production Operating Expense
Production operating expense increased $1,424,000 during 1998 compared to 1997.
The increase is due to increased operating costs resulting from the drilling
projects completed during 1997 as well as the additional operating expenses
related to the properties acquired in the Arcadia acquisition during October
1998.
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 decreased $433,000 during 1998 compared to 1997, primarily as a result of
decreased performance based compensation during 1998.
Interest Expense
Interest expense increased $1,902,000 in 1998 compared to 1997, primarily as a
result of a higher average debt balance during 1998.
<PAGE>
Depreciation, Depletion and Amortization Expense
Depreciation, depletion and amortization expense associated with proved oil and
gas properties increased $2,858,000 during 1998 compared with 1997. This
increase is due to a higher depletion rate resulting from the increased
production discussed above, as well as higher capitalized costs during 1998.
Impairment of Oil and Gas Properties
Impairment of oil and gas properties during 1998 represents the impairments
recorded during 1998 because capitalized costs exceeded the present value
(discounted at 10%) of estimated future net revenues from proved oil and gas
reserves at June 30, 1998, September 30, 1998 and December 31, 1998, based on
prices of $13.00 per barrel of oil and $1.90 per mcf of gas, $12.75 per barrel
of oil and $1.80 per mcf of gas and $10.00 per barrel of oil and $1.85 per mcf
of gas, respectively.
Litigation
Litigation expense during 1998 is comprised of the costs related to the Arcadia
arbitration described in Item 8, Note 14.
1997 Compared to 1996
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.
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 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.
Pipeline and Other
Pipeline and other revenue increased $581,000 during 1997 as compared to 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.
<PAGE>
General and administrative Expense
General and administrative expense increased $873,000 during 1997 as compared to
1996, primarily as a result of increased performance based compensation during
1997.
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 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.
<PAGE>
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
HCRC's primary market risks relate to changes in interest rates and in the
prices received from sales of oil and natural gas. HCRC's primary risk
management strategy is to partially mitigate the risk of adverse changes in its
cash flows caused by increases in interest rates on its variable rate debt, and
decreases in oil and natural gas prices, by entering into derivative financial
and commodity instruments, including swaps, collars and participating commodity
hedges. By hedging only a portion of its market risk exposures, HCRC is able to
participate in the increased earnings and cash flows associated with decreases
in interest rates and increases in oil and natural gas prices; however, it is
exposed to risk on the unhedged portion of its variable rate debt and oil and
natural gas production.
Historically, HCRC has attempted to hedge the exposure related to its variable
rate debt and its forecasted oil and natural gas production in amounts which it
believes are prudent based on the prices of available derivatives and, in the
case of production hedges, the Company's deliverable volumes. HCRC attempts to
manage the exposure to adverse changes in the fair value of its fixed rate debt
agreements by issuing fixed rate debt only when business conditions and market
conditions are favorable.
HCRC does not use or hold derivative instruments for trading purposes nor does
it use derivative instruments with leveraged features. HCRC's derivative
instruments are designated and effective as hedges against its identified risks,
and do not of themselves expose HCRC to market risk because any adverse change
in the cash flows associated with the derivative instrument is accompanied by an
offsetting change in the cash flows of the hedged transaction.
Notes 1 and 4 to the financial statements provide further disclosure with
respect to derivatives and related accounting policies.
All derivative activity is carried out by personnel who have appropriate skills,
experience and supervision. The personnel involved in derivative activity must
follow prescribed trading limits and parameters that are regularly reviewed by
the Board of Directors and by senior management. HCRC uses only well-known,
conventional derivative instruments and attempts to manage its credit risk by
entering into financial contracts with reputable financial institutions.
Following are disclosures regarding HCRC's market risk sensitive instruments by
major category. Investors and other users are cautioned to avoid simplistic use
of these disclosures. Users should realize that the actual impact of future
interest rate and commodity price movements will likely differ from the amounts
disclosed below due to ongoing changes in risk exposure levels and concurrent
adjustments to hedging positions. It is not possible to accurately predict
future movements in interest rates and oil and natural gas prices.
Interest Rate Risks (non trading) - HCRC uses both fixed and variable rate debt
to partially finance operations and capital expenditures. As of December 31,
1998, HCRC's debt consists of $25.5 million in borrowings under its Credit
Agreement which bear interest at a variable rate, and $25 million in borrowings
under its 10.32% Senior Subordinated Notes which bear interest at a fixed rate.
HCRC hedges a portion of the risk associated with its variable rate debt through
derivative instruments, which consist of interest rate swaps and collars. Under
the swap contracts, HCRC makes interest payments on its Credit Agreement as
scheduled and receives or makes payments based on the differential between the
fixed rate of the swap and a floating rate plus a defined differential. These
instruments reduce HCRC's exposure to increases in interest rates on the hedged
portion of its debt by enabling it to effectively pay a fixed rate of interest
or a rate which only fluctuates within a predetermined ceiling and floor. A
hypothetical increase in interest rates of two percentage points would cause a
loss in income and cash flows of $510,000 during 1999, assuming that outstanding
borrowings under the Credit Agreement remain at current levels. This loss in
income and cash flows would be offset by a $201,500 increase in income and cash
flows associated with the interest rate swap and collar agreements that are in
effect for 1999.
A hypothetical decrease in interest rates of two percentage points would cause
an increase in the fair value of $2,282,000 in HCRC's Senior Subordinated Notes
from their fair value at December 31, 1998.
<PAGE>
Commodity Price Risk (non trading) - HCRC hedges a portion of the price risk
associated with the sale of its oil and natural gas production through the use
of derivative commodity instruments, which consist of swaps, collars and
participating hedges. These instruments reduce HCRC's exposure to decreases in
oil and natural gas prices on the hedged portion of its production by enabling
it to effectively receive a fixed price on its oil and natural gas sales or a
price that only fluctuates between a predetermined floor and ceiling. HCRC's
participating hedges also enable HCRC to receive 25% of any increase in prices
over the fixed prices specified in the contracts. As of March 24, 1999, HCRC had
entered into derivative commodity hedges covering an aggregate of 23,000 barrels
of oil and 11,787,000 mcf of gas that extend through 2002. Under the these
contracts, HCRC sells its oil and natural 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 amount
received or paid upon settlement of these contracts is recognized as oil or
natural gas revenues at the time the hedged volumes are sold. A hypothetical
decrease in oil and natural gas prices of 10% from the prices in effect as of
December 31, 1998 would cause a loss in income and cash flows of $2,890,000
during 1999, assuming that oil and gas production remain at 1998 levels. This
loss in income and cash flows would be offset by a $705,000 increase in income
and cash flows associated with the oil and natural gas derivative contracts that
are in effect for 1999.
<PAGE>
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
<TABLE>
<CAPTION>
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
FINANCIAL STATEMENTS:
<S> <C>
Independent Auditors' Report 31
Consolidated Balance Sheets at December 31, 1998 and 1997 32-33
Consolidated Statements of Operations for the years ended
December 31, 1998, 1997 and 1996 34
Consolidated Statements of Stockholders' Equity for the years ended
December 31, 1998, 1997 and 1996 35
Consolidated Statements of Cash Flows for the years ended
December 31, 1998, 1997 and 1996 36
Notes to Consolidated Financial Statements 37-49
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) 50-53
</TABLE>
<PAGE>
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, 1998 and 1997 and for each of the three
years in the period ended December 31, 1998, 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, 1998 and 1997, and the results of its operations and
its cash flows for each of the three years in the period ended December 31, 1998
in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Denver, Colorado
March 24, 1999
<PAGE>
<TABLE>
<CAPTION>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands except shares)
December 31,
1998 1997
CURRENT ASSETS
<S> <C> <C>
Cash and cash equivalents $ 551 $ 4,492
Accrued oil and gas revenue 3,053 4,266
Due from affiliates 4,246 2,418
Prepaid and other assets 285 115
Current assets of affiliates 4,431 3,854
--------- ---------
Total current assets 12,566 15,145
-------- --------
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved oil and gas properties 336,713 294,922
Unproved mineral interests - domestic 2,813 2,250
--------- ---------
Total 339,526 297,172
Less - accumulated depreciation, depletion,
amortization and impairment (252,204) (221,141)
------- -------
Net property, plant and equipment 87,322 76,031
-------- --------
OTHER ASSETS
Deferred expenses 1,201 729
Deferred tax asset 450
Noncurrent assets of affiliate 78 16
----------- -----------
Total other assets 1,279 1,195
--------- ---------
TOTAL ASSETS $101,167 $ 92,371
======= ========
<FN>
(Continued on the following page)
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands except shares)
December 31,
1998 1997
CURRENT LIABILITIES
<S> <C> <C>
Accounts payable and accrued liabilities $ 3,886 $ 3,087
Current portion of long-term debt 4,781
Current portion of contract settlement obligation 1,039
Current liabilities of affiliates 9,595 6,881
--------- ---------
Total current liabilities 18,262 11,007
-------- --------
NONCURRENT LIABILITIES
Long-term debt 44,774 25,000
Long-term obligations of affiliates 8,482 7,589
Deferred liability 60 89
---------- ----------
Total noncurrent liabilities 53,316 32,678
-------- --------
Total liabilities 71,578 43,685
-------- --------
COMMITMENTS AND CONTINGENCIES (NOTE 11)
STOCKHOLDERS' EQUITY
Common stock, par value $.01 per share; 10,000,000 shares authorized;
3,007,852 shares issued in 1998 and 2,986,812 shares
issued in 1997 30 30
Additional paid-in capital 81,283 80,111
Accumulated deficit (47,860) (27,581)
Treasury stock - 258,395 shares in 1998 and 259,278
shares in 1997 (3,864) (3,874)
--------- ---------
Stockholders' equity - net 29,589 48,686
--------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $101,167 $ 92,371
======= ========
<FN>
The accompanying notes are an integral part of the consolidated
financial statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands except per share)
For the Year Ended December 31,
1998 1997 1996
REVENUES:
<S> <C> <C> <C>
Gas revenue $ 20,142 $ 17,251 $ 16,446
Oil revenue 9,392 13,416 16,852
Pipeline and other 2,696 1,591 1,010
Interest 180 153 137
--------- --------- ---------
32,410 32,411 34,445
------- ------- -------
EXPENSES:
Production operating 11,642 10,218 10,383
General and administrative 4,451 4,884 4,011
Interest 4,160 2,258 2,530
Depreciation, depletion and amortization 11,463 8,605 9,246
Impairment of oil and gas properties 19,600
Litigation 1,087
Other 114
----------- ----------- --------
52,403 25,965 26,284
------- ------- -------
INCOME (LOSS) BEFORE INCOME TAXES (19,993) 6,446 8,161
------- -------- --------
PROVISION (BENEFIT) FOR INCOME TAXES:
Current (164) 961 301
Deferred 450 (100) (350)
-------- -------- --------
286 861 (49)
-------- -------- ---------
NET INCOME (LOSS) $(20,279) $ 5,585 $ 8,210
======= ======== ========
NET INCOME (LOSS) PER SHARE - BASIC $ (7.38) $ 2.05 $ 3.00
========= ========= =========
NET INCOME (LOSS) PER SHARE - DILUTED $ (7.38) $ 1.97 $ 2.91
========= ========= =========
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING 2,747 2,719 2,733
======== ======== ========
<FN>
The accompanying notes are an integral part of the consolidated
financial statements.
</FN>
</TABLE>
<TABLE>
<CAPTION>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In thousands)
Additional
Common Paid-in Accumulated Treasury
Stock Capital Deficit Stock Total
<S> <C> <C> <C> <C> <C>
Balance, December 31, 1995 $ 30 $ 81,811 $(41,376) $ (3,830) $ 36,635
Repurchase and retirement
of common stock (1,750) (1,750)
Exercise of common stock
options 10 10
Increase in treasury shares (44) (44)
Net income 8,210 8,210
------ ---------- -------- --------- --------
Balance, December 31, 1996 30 80,071 (33,166) (3,874) 43,061
Exercise of common stock
options 61 61
Other (21) (21)
Net income 5,585 5,585
----- ---------- -------- ---------- --------
Balance, December 31, 1997 30 80,111 (27,581) (3,874) 48,686
Exercise of common stock
options 140 140
Allocated value of common
stock warrants 1,032 1,032
Decrease in treasury shares 10 10
Net loss (20,279) (20,279)
----- ---------- -------- ---------- --------
Balance, December 31, 1998 $ 30 $ 81,283 $(47,860) $ (3,864) $ 29,589
===== ======= ======= ======= =======
<FN>
The accompanying notes are an integral part of the consolidated
financial statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the Year Ended December 31,
1998 1997 1996
OPERATING ACTIVITIES:
<S> <C> <C> <C>
Net income (loss) $ (20,279) $ 5,585 $ 8,210
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization 11,463 8,605 9,246
Impairment of oil and gas properties 19,600
Amortization of deferred loan costs and debt
discount 203
Deferred income tax (benefit) expense 450 (100) (350)
Noncash interest expense 6 91 83
Recoupment of take-or-pay liability (29) (28) (110)
Undistributed earnings of affiliates (5,040) (3,843) (5,173)
Changes in operating assets and liabilities provided (used) cash net of
noncash activity:
Accrued oil and gas revenue 1,213 542 (2,134)
Due from affiliates (1,498) (1,569) (1,071)
Prepaid and other assets (286) 378 (382)
Deferred expenses (472) (729)
Accounts payable and accrued liabilities 799 814 (1,402)
---------- --------- --------
Net cash provided by operating activities 6,130 9,746 6,917
-------- -------- --------
INVESTING ACTIVITIES:
Additions to oil and gas properties (28,182) (2,822) (2,182)
Exploration and development costs incurred (9,383) (9,284) (7,578)
Proceeds from oil and gas property sales 107 40 1,368
Distributions received from affiliates 2,792 1,144 1,144
Investment in Spraberry properties (6,338)
------------- ------------- ---------
Net cash used in investing activities (34,666) (10,922) (13,586)
-------- -------- --------
FINANCING ACTIVITIES:
Proceeds from long-term debt 25,500 29,000 10,000
Payments of long-term debt (24,000) (2,000)
Repurchase and retirement of common stock (1,750)
Payments on contract settlement obligation (1,045) (118)
Exercise of stock options 140 61 10
Other financing activities (21) 16
------------- ---------- ----------
Net cash provided by financing activities 24,595 5,040 6,158
-------- -------- --------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS (3,941) 3,864 (511)
CASH AND CASH EQUIVALENTS:
BEGINNING OF YEAR 4,492 628 1,139
-------- -------- --------
END OF YEAR $ 551 $ 4,492 $ 628
========= ======== ========
<FN>
The accompanying notes are an integral part of the consolidated
financial statements.
</FN>
</TABLE>
<PAGE>
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, and 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 partnerships 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. During the second, third and
fourth quarters of 1998, using oil and gas prices of $13.00 per barrel of oil
and $1.90 per mcf of gas, $12.75 per barrel of oil and $1.80 per mcf of gas and
$10.00 per barrel of oil and $1.85 per mcf of gas, respectively, HCRC recorded
oil and gas property impairment expense totaling $19,600,000.
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
impairment 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 on
long-lived assets other than oil and gas properties.
<PAGE>
Derivatives
As of March 24, 1999, HCRC was a party to 18 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 increases or
decreases in oil or gas revenue at the time the hedged volumes are sold.
As of March 24, 1999, HCRC was a party to six financial contracts to hedge the
interest payments under its Credit Agreement. The purpose of the hedges is to
protect against the variability of the cash flows under its Credit Agreement
which has a floating interest rate. The amounts received or paid upon settlement
of these transactions are recognized as interest expense at the time the
interest payments are due.
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, 1998, HCRC had a net over-produced position of 347,000 mcf
($642,000 valued at year-end 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, 1998
have been reduced by 347,000 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 shares 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, 1997 to shareholders of record on August 4, 1997. 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 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
Basic income (loss) per share is computed by dividing net income (loss) by the
weighted average number of common shares. Diluted income per share includes the
potential dilution that could occur upon exercise of the options to acquire
common stock described in Note 10, 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). The
warrants described in Note 6 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 1998 because their inclusion
would be antidilutive. 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.
<TABLE>
<CAPTION>
Income (Loss) Shares Per Share
(In thousands except per Share)
For the Year Ended December 31, 1998
<S> <C> <C> <C>
Net loss per share - basic $(20,279) 2,747 $(7.38)
------ ------ =====
Net loss per share - diluted $(20,279) 2,747 $(7.38)
======= ====== =====
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
====== ===== ====
</TABLE>
Treasury Stock
At December 31, 1998 and 1997, 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 258,395 and 259,278 of its own
shares at December 31, 1998 and 1997, respectively. 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 other purchasers in the areas in which HCRC sells it
production. However, for the years ended December 31, 1998, 1997 and 1996,
purchases by the following companies exceeded 10% of the total oil and gas
revenues of the Company:
1998 1997 1996
---- ---- ----
El Paso Field Services 17% 17% 11%
Williams Gas Marketing 13% 13%
Koch Oil Company 12% 23%
Conoco Inc. 12% 13%
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, 1998, 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.
<PAGE>
Recently Issued Accounting Pronouncements
In June 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 130 "Reporting Comprehensive Income" ("SFAS
130"). SFAS 130 establishes standards for reporting and 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 adopted SFAS 130 on January 1, 1998. The Company does not have any
items of other comprehensive income for the years ended December 31, 1998, 1997
and 1996. Therefore, total comprehensive income (loss) is the same as net income
(loss) for those years.
In June 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 131 "Disclosures about Segments of an
Enterprise and Related Information" ("SFAS 131"). SFAS 131 establishes standards
for reporting selected information about operating segments and related
disclosures about products and services, geographic areas, and major customers.
SFAS 131 requires that an entity report financial and descriptive information
about its operating segments which are regularly evaluated by the chief
operating decision maker in deciding how to allocate resources and in assessing
performance. HCRC adopted FAS 131 in 1998.
The Company engages in the development, production and sale of oil and gas, and
the acquisition, exploration, development and operation of oil and gas
properties in the continental United States. These activities exhibit similar
economic characteristics and involve the same products, production processes,
class of customers, and methods of distribution. Management of the Company
evaluates its performance as a whole rather than by product or geographically.
As a result, HCRC's operations consist of one reportable segment.
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 "Accounting for Derivative Instruments
and Hedging Activities" ("SFAS 133"). SFAS 133 establishes standards for
derivative instruments, including certain derivative instruments embedded in
other contracts (collectively referred to as derivatives) and for hedging
activities. SFAS 133 requires that an entity recognize all derivatives as either
assets or liabilities in the statement of financial position and measure those
instruments at fair value. If certain conditions are met, a derivative may be
specifically designated as (a) a hedge of the exposure to changes in the fair
value of a recognized asset or liability or an unrecognized firm commitment, (b)
a hedge of the exposure to variable cash flows of a forecasted transaction, or
(c) a hedge of the foreign currency exposure of a net investment in a foreign
operation, an unrecognized firm commitment, an available-for-sale security, or a
foreign-currency-denominated forecasted transaction. The accounting for changes
in the fair value of a derivative (gains and losses) depends on the intended use
of the derivative and the resulting designation. The Company is required to
adopt SFAS 133 on January 1, 2000. The Company has not completed the process of
evaluating the impact that will result from adopting SFAS 133.
Reclassifications
Certain reclassifications have been made to prior years' amounts to conform to
the classifications used in the current year.
<PAGE>
NOTE 2 - OIL AND GAS PROPERTIES
The following table summarizes 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.
<TABLE>
<CAPTION>
For the Year Ended December 31,
1998 1997 1996
(In thousands)
<S> <C> <C> <C>
Property acquisition costs $32,172 $ 3,350 $ 2,830
Development costs 6,904 6,531 8,617
Exploration costs 6,552 8,064 2,206
------- ------- -------
Total $45,628 $17,945 $13,653
====== ====== ======
</TABLE>
Depreciation, depletion, amortization and property impairment related to proved
oil and gas properties per equivalent mcf of production for the years ended
December 31, 1998, 1997 and 1996 was $2.09, $.70 and $.70, respectively.
At December 31, unproved properties consist of the following:
1998 1997
---- ----
(In thousands)
Texas $2,004 $ 935
North Dakota 499 314
California 447
Other 310 554
------- -------
$2,813 $2,250
===== =====
NOTE 3 - PRINCIPAL ACQUISITIONS AND SALES
As a result of the arbitration discussed in Note 14, HCRC completed an
$8,200,000 acquisition of properties located primarily in Texas during October
1998. The acquisition included interests in 570 wells, numerous proven and
unproven drilling locations, exploration acreage and 3-D seismic data.
In July 1996, HCRC and its affiliate, HEP, acquired interests in 38 wells
located primarily in LaPlata County, Colorado. An unaffiliated large East Coast
financial institution formed an entity to utilize the tax credits generated from
the wells. The project was financed by an affiliate of Enron Corp. through a
volumetric production payment. During May 1998, a limited liability company
owned equally by HCRC and HEP purchased the volumetric production payment from
the affiliate of Enron Corp. HCRC funded its $17,257,000 share of the
acquisition price from operating cash flow and borrowings under its Credit
Agreement.
During 1997, HCRC had no individually significant property acquisitions or
sales.
NOTE 4 - DERIVATIVES
As part of its risk management strategy, HCRC enters into 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 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. As of March 24,
1999, HCRC was a party to 18 financial contracts with three different
counterparties.
The following table provides a summary of HCRC's financial contracts:
Oil
Quantity of Production Contract
Period Hedged Floor Price
(bbls) (per bbl)
1996 219,000 $18.47
1997 262,000 17.88
1998 82,000 14.07
1999 23,000 14.88
All of the oil volumes hedged in 1999 are subject to participating hedges
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 1999 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
$16.50 to $18.35 per barrel.
<PAGE>
Gas
Quantity of Production Contract
Period Hedged Floor Price
(mcf) (per mcf)
1996 2,429,000 $1.77
1997 2,413,000 1.89
1998 3,545,000 1.96
1999 4,237,000 1.95
2000 2,923,000 1.95
2001 2,503,000 1.92
2002 2,124,000 1.98
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 $4,246,000 and $2,418,000 and as of December 31, 1998
and 1997, respectively. The amounts consist primarily of 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 1998, 1997 and 1996 were as follows (in
thousands):
Technical Nontechnical
Expenditures Expenditures
1998 $984 $1,392
1997 856 1,225
1996 823 1,293
Included in the nontechnical allocation from HPI attributable to the Company's
direct interest is approximately $241,000 during the years ended December 31,
1998 and 1997 and $115,000 during the year ended December 31, 1996 of consulting
fees under a contract with The Hallwood Group Incorporated ("Hallwood"), an
affiliated company. Also included in the nontechnical allocation is $246,000,
$232,000 and $234,000 in 1998, 1997 and 1996, 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 was $125,000 in 1996. 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 The Prudential Insurance Company
of America ("Prudential"). HCRC also sold Warrants to Prudential 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.
The proceeds from the Subordinated Notes were allocated to the Subordinated
Notes and to the Warrants based upon the relative fair values of the
Subordinated Notes without the Warrants and of the Warrants themselves at the
time of issuance. The allocated value of the Warrants of $1,032,000 was recorded
as paid-in-capital. The discount on the Subordinated Notes is being amortized
over the term of the Subordinated Notes using the interest method of
amortization.
At December 31, 1998, HCRC was not in compliance with one of the debt covenants
in its Subordinated Note agreement which requires HCRC to maintain a minimum
level of consolidated net worth. This also resulted in noncompliance with a
covenant under HCRC's Credit Agreement. HCRC received waivers of compliance with
this covenant as of December 31, 1998 from the Subordinated Note holder and from
HCRC's lenders under its Credit Agreement. The Subordinated Note agreement was
amended to reduce the required level of net worth. As a result, the obligations
under these agreements have been classified as noncurrent liabilities as of
December 31, 1998.
<PAGE>
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. The banks are Morgan
Guaranty Trust Company, First Union National Bank and NationsBank of Texas.
Under the Credit Agreement, HCRC has a borrowing base of $26,500,000. As of
December 31, 1998, the Company had amounts outstanding of $25,500,000. HCRC's
unused borrowing base totaled $1,000,000 at March 24, 1999.
Borrowings against the Credit Agreement 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%. The applicable interest rate was 6.75% at
December 31, 1998. Interest is payable at least quarterly, and quarterly
principal payments of $1,594,000 commence May 31, 1999. The Credit Agreement is
secured by a first lien on approximately 80% in value of the Company's oil and
gas properties.
The borrowing base for the Credit Agreement is redetermined semiannually, and
the next redetermination is scheduled for the second quarter of 1999. HCRC
anticipates that, because of low oil and gas prices, its lenders will reduce the
borrowing base and that HCRC will be required to make a principal payment on its
debt. Any required principal payment will reduce the amount available for HCRC's
capital budget.
At December 31, 1998, HCRC's debt maturity schedule is as follows.
(In thousands)
1999 $ 4,781
2000 6,375
2001 6,375
2002 6,375
2003 6,594
Thereafter 19,055
------
Total $49,555
As part of its risk management strategy, HCRC enters into contracts to hedge its
interest rate payments related to a portion of its outstanding borrowings under
its Credit Agreement. HCRC does not use the hedges for trading purposes, but
rather to protect against the volatility of the cash flows under its Credit
Agreement, which has a floating interest rate. The amounts received or paid upon
settlement of these transactions are recognized as interest expense at the time
the interest payments are due.
Approximately one third of the debt hedged in 1998 was subject to a collar
agreement with a floor rate of 7.55% and a ceiling rate of 9.85%. All other
contracts are interest rate swaps with fixed rates. As of March 24, 1999, HCRC
was a party to six contracts with three different counterparties.
The following table provides a summary of HCRC's financial contracts.
Amount of Contract
Period Debt Hedged Floor Rate
1996 $ 7,000,000 7.00%
1997 10,000,000 6.84%
1998 10,000,000 7.00%
1999 13,000,000 5.70%
2000 15,000,000 5.65%
2001 12,000,000 5.23%
2002 12,500,000 5.23%
2003 12,500,000 5.23%
2004 2,000,000 5.23%
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 was recorded
equal to the present value of the settlement discounted at 10.68%, HCRC's
estimated borrowing rate at the time of the settlement. At December 31, 1997,
the current portion of contract settlement balance consisted of a payment of
$1,045,000 net of unaccreted discount of $6,000, which was paid during February
1998.
NOTE 8 - STATEMENT OF CASH FLOWS
Cash paid for interest during 1998, 1997 and 1996 was $3,292,000, $1,434,000 and
$1,374,000, respectively. A net cash refund of income tax expense of $336,000
was received during 1998. Cash paid for income taxes during 1997 and 1996 was
$1,416,000 and $185,000, respectively.
NOTE 9 - INCOME TAXES
The following is a summary of the income tax provision (benefit):
<TABLE>
<CAPTION>
For the Year
Ended December 31,
1998 1997 1996
(In thousands)
<S> <C> <C> <C>
State $ 13 $ 369 $ 236
Federal - Current (177) 592 65
Deferred 450 (100) (350)
---- ---- ----
Total $ 286 $ 861 $ (49)
==== ==== =====
</TABLE>
Reconciliations of the expected tax at the statutory tax rate to the effective
tax are as follows:
<TABLE>
<CAPTION>
For the Year
Ended December 31,
1998 1997 1996
(In thousands)
Expected tax expense (benefit) at the
<S> <C> <C> <C>
statutory rate $(6,797) $ 2,192 $ 2,775
State taxes net of federal benefit 8 243 156
Change in valuation allowance 6,859 (1,444) (3,739)
Other 216 (130) 759
------ ------ ------
Effective tax expense (benefit) $ 286 $ 861 $ (49)
====== ====== =======
</TABLE>
<PAGE>
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 amount used for income tax purposes. The tax effects of
significant items comprising the Company's deferred tax assets and liabilities
as of December 31, 1998 and 1997 are as follows:
1998 1997
---- ----
Deferred tax assets:
Net operating loss carryforward $ 5,187 $ 2,835
Capital loss carryforward 1,763 1,889
Temporary differences between
book and tax basis of property 4,110 461
Minimum tax credit carryforward 534
---------
Total 11,594 5,185
Valuation allowance (11,594) (4,735)
------ ------
Net deferred tax asset $ -0- $ 450
========== =======
The Company's net operating loss carryforwards expire between 2008 and 2013.
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 2.75% for 1998 and 2.4% for 1997 and 1996. The
specified percentage of cash flow is 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 1998, 1997 and 1996) of the remaining net present value of the
qualifying wells, and the award for that year terminates. The expenses
attributable to the plans were $123,000 in 1998, $400,000 in 1997 and $119,000
in 1996 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 the years ended
December 31, 1998, 1997 and 1996, options to purchase 21,040, 9,270 and 1,500
shares, respectively, 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 date 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.
On May 5, 1998, HCRC granted options to purchase 9,540 shares of Common Stock
under its 1997 Stock Option Plan at an exercise price of $15.75 which was equal
to the fair market value of the Common Stock on the date of grant. One-third of
the options vest immediately, and the remainder vest one-half on the first
anniversary of the date of grant and one-half on the second anniversary of the
date of grant.
<PAGE>
On May 5, 1998, HCRC also granted options to purchase 9,540 shares of Common
Stock at an exercise price of $15.75 per share which was equal to the fair
market value of the Common Stock on the date of grant. These options were not
granted pursuant to a previously existing plan, but are subject to terms and
conditions identical to those in HCRC's 1995 Stock Option Plan. One-third of the
options vest immediately, and the remainder vest one-half on the first
anniversary of the date of grant and one-half on the second anniversary of the
date of grant.
A summary of options to purchase HCRC's common stock and the changes therein for
the years ended December 31, 1998, 1997 and 1996 follows:
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
Outstanding at
<S> <C> <C> <C> <C> <C> <C>
beginning of year 307,230 $13.74 157,500 $ 6.67 159,000 $ 6.67
Granted 19,080 15.75 159,000 20.33
Expired (9,540) 20.33
Exercised (21,040) 6.67 (9,270) 6.67 (1,500) 6.67
-------- ------ -------- ------ -------- -----
Outstanding at
end of year 295,730 $10.54 307,230 $13.74 157,500 $ 6.67
======= ===== ======= ===== ======= =====
Options exercisable
at year end 233,190 $19.40 201,230 $10.26 104,500 $ 6.67
======= ===== ======= ===== ======= =====
</TABLE>
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 options granted
by the Company. Had compensation expense for the options granted 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:
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Net income (loss): as reported $(20,279,000) $5,585,000 $8,210,000
pro forma (20,789,000) 4,627,000 8,025,000
Net income (loss) per share - basic:
as reported $(7.38) $2.05 $3.00
pro forma (7.57) 1.70 2.94
Net income (loss) per share - diluted:
as reported $(7.38) $1.97 $2.91
pro forma (7.57) 1.63 2.85
</TABLE>
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:
<TABLE>
<CAPTION>
1995 Options 1997 Options 1998 Options
------------ ------------ ------------
<S> <C> <C> <C>
Expected dividend yield 0% 0% 0%
Expected price volatility 40% 33% 29%
Risk-free interest rate 6.2% 6.35% 6.4%
Expected life of options 10 years 6 years 10 years
</TABLE>
<PAGE>
NOTE 11 - COMMITMENTS
The Company is a guarantor of 40% of the obligation under the Denver, Colorado
office leases which are in the name of HPI. HEP is guarantor of the remaining
60% of the obligation. HPI leases office facilities under an operating lease
which expires in June 1999 for approximately $600,000 per year. During February
1999, HPI entered into another lease, for approximately $600,000 per year. The
new lease commences upon occupancy, which is expected to be in June or July
1999, and terminates in seven and one-half years.
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 using the pro rata method of
accounting. The following presents summarized financial information for HEP as
of and for the years ended December 31, 1998, 1997 and 1996.
HEP 1998 1997 1996
--- ---- ---- ----
(In thousands)
Current assets $ 23,518 $ 22,142 $ 20,380
Noncurrent assets 115,573 109,461 102,412
Current liabilities 32,240 23,115 21,735
Noncurrent liabilities 41,431 36,166 33,506
Minority interest 2,788 3,258 3,336
Revenue 43,586 45,103 51,066
Net income (loss) (13,895) 12,803 15,726
No other individual entity in which HCRC owns an interest comprises in excess of
10% of the revenues, net income (loss) or assets of HCRC.
NOTE 14 - ARBITRATION
In connection with the Demand for Arbitration filed by Arcadia Exploration and
Production Company ("Arcadia") 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 as "Hallwood"), the arbitrators ruled that the
original agreement entered into in August 1997 to purchase oil and gas
properties should proceed, with a reduction in the total purchase price of
approximately $2,500,000 for title defects. The arbitrators also ruled that
Arcadia was not entitled to enforce its claim that Hallwood was required to
purchase an additional $8,000,000 in properties and denied Arcadia's claim for
attorneys fees. The arbitrators granted Arcadia prejudgment interest on the
adjusted purchase price, but an issue exists between Hallwood and Arcadia as to
the proper calculation of the limitation which the panel placed on the amount of
prejudgment interest. The parties plan to ask the arbitrators to rule on this
issue. The Company has accrued $452,000 in its financial statements as of
December 31, 1998 in connection with this dispute.
<PAGE>
In October 1998, HCRC and its affiliate, HEP, closed the acquisition of oil and
gas properties from Arcadia pursuant to the ruling, which included interests in
approximately 570 wells, numerous proven and unproven drilling locations,
exploration acreage, and 3-D seismic data. HCRC's share of the purchase price
was $8,200,000.
NOTE 15 - LEGAL PROCEEDINGS
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 sought to rescind the conversion of Hallwood Consolidated Partners, L.P.
("HCP") into the Company ("Conversion") and to recover damages in unspecified
amounts. In January 1999, the plaintiff and the defendants entered into a joint
stipulation of dismissal, with prejudice as to the plaintiff only. The court
approved the dismissal.
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 16 - 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, 1998
Carrying Estimated Fair
Amount Value
(In thousands)
Assets (Liabilities):
Oil and gas hedge contracts $ -0- $ 1,921
Interest rate hedge contracts -0- (404)
Long-term debt (49,555) (47,659)
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.
The estimated fair value of the interest rate hedge contracts is computed by the
difference between the quoted contract termination interest rate and the
contract interest rate by the amounts under contract. This amount has been
discounted using an interest rate that could have been available to the Company.
The estimated fair value of long-term debt is computed using interest rates that
could be available to the Company for similar instruments with similar terms.
The fair value estimates presented herein are based on pertinent information
available to management as of December 31, 1998. 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.
<PAGE>
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. No
consideration has been given to future income taxes as of December 31, 1998
because the tax basis of HCRC's oil and gas properties and net operating loss
carryforwards exceed future net cash flows. Under the guidelines set forth by
the Securities and Exchange Commission, the calculation is performed using year
end prices. The oil and gas prices used at December 31, 1998, 1997 and 1996 were
$10.00 per bbl and $1.85 per mcf, $16.77 per bbl and $2.20 per mcf and $23.96
per bbl and $3.75 per mcf, respectively, 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, 1998 prices
result in 4 million bbls of oil, 87 billion cubic feet of gas and a standardized
measure of $84,000,000. 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 increased by
$2,717,000 at December 31, 1998 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 under contract, discounted at
10%.
<PAGE>
<TABLE>
<CAPTION>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
RESERVE QUANTITIES
(Unaudited)
(In thousands)
Gas Oil
(Mcf) (Bbls)
Proved Reserves:
<S> <C> <C> <C> <C>
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
Extensions and discoveries 1,363 490
Revisions of previous estimates (8,515) (1,858)
Sales of reserves in place (297) (35)
Purchases of reserves in place 29,436 627
Production (10,555) (716)
------- -------
Balance, December 31, 1998 87,007 4,033
====== =====
Proved Developed Reserves:
Balance, December 31, 1996 63,044 6,431
====== =====
Balance, December 31, 1997 73,250 5,080
====== =====
Balance, December 31, 1998 83,717 3,173
====== =====
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(Unaudited)
(In thousands)
December 31,
-----------------
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Future sales $215,000 $227,000 $413,000
Future production and development costs (94,000) (100,000) (158,000)
Provision for income tax* (8,000) (30,000)
------------ -------- --------
Future cash flows 121,000 119,000 225,000
10% discount to present value (37,000) (31,000) (91,000)
-------- -------- --------
Standardized measure of discounted future
net cash flows $ 84,000 $ 88,000 $134,000
======== ======== =======
<FN>
*No consideration has been given to future income taxes as of December 31, 1998
since the tax basis of HCRC's oil and gas properties and net operating loss
carryforwards exceed future net cash flows.
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(Unaudited)
(In thousands)
For the Year Ended December 31,
1998 1997 1996
Standardized measure of discounted future net cash
<S> <C> <C> <C>
flows at beginning of year $ 88,000 $134,000 $ 85,000
Sales of oil and gas produced, net of production costs (17,892) (20,449) (22,915)
Net changes in prices and production costs (10,359) (71,933) 46,516
Extensions and discoveries net of future production
and development costs 3,411 5,616 7,011
Changes in estimated future development costs (9,542) (6,480) (7,292)
Development costs incurred 6,904 6,531 8,617
Revisions of previous quantity estimates (15,587) 4,688 10,802
Purchases of reserves in place 26,316 1,482 17,061
Sales of reserves in place (402) (162) (3,707)
Accretion of discount 8,818 13,439 8,513
Net change in income taxes 5,825 16,206 (15,332)
Changes in production rates and other (1,492) 5,062 (274)
-------- -------- --------
Standardized measure of discounted future
net cash flows at end of year $ 84,000 $ 88,000 $134,000
======== ======== =======
</TABLE>
<PAGE>
ITEM 9 - DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURES
None.
PART III
ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Directors, 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 March 24, 1999, HPI had 108 employees. Following are
brief biographies of the directors, officers and key employees of HCRC and HPI.
Anthony J. Gumbiner, 54, has served as a director of the HCRC since February
1992. He has also served as Chairman of the Board of Directors of The Hallwood
Group Incorporated ("Hallwood Group"), a diversified holding company with real
estate, textile products, hotel and energy operations, since 1981 and as Chief
Executive Officer of Hallwood Group since April 1984. He has been Chairman of
the Board since 1984 and Chief Executive Officer since 1987 of the general
partner of HEP. Mr. Gumbiner has also served as Chairman of the Board of
Directors and as a director of Hallwood Holdings S.A., a Luxembourg real estate
investment company, since March 1984. He has been a director of Hallwood Realty
Corporation ("Hallwood Realty"), which is the general partner of Hallwood Realty
Partners, L.P., since November 1990. He is a Solicitor of the Supreme Court of
Judicature of England.
William L. Guzzetti, 55, 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, 44, 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, 46, 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.
Thomas J. Jung, 50, has served as Vice President and Chief Financial Officer of
Hallwood G.P., HCRC and HPI since May 1998. From January 1997 until April 1998,
he was a Senior Financial Associate with Trinity Petroleum Management, and
during that period, he also provided consulting services to other companies
involved in the development, financing, management and monetization of tax
credits for alternative energy projects. From 1994 to 1996, he was Chief
Executive Officer of FAR Gas Acquisitions Corp. From 1986 to 1994, he was Vice
President and Chief Financial Officer of NICOR Exploration & Production Company
and Reliance Pipeline Company.
Betty J. Dieter, 51, 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 26 years experience in accounting and operations, 19 of which are in the
oil and gas industry. Ms. Dieter is a Certified Public Accountant.
<PAGE>
George Brinkworth, 57, has been Vice President-Exploration and International
Division 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 34 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, 48, 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 24 years oil and gas engineering experience.
Brian M. Troup, 51, has served as a director of HCRC since February 1992. He has
been President and Chief Operating Officer of Hallwood Group since April 1986,
and he is a director. Mr. Troup has been a director of the general partner of
HEP since May 1984. Mr. Troup is a director of Hallwood Holdings S.A. and of
Hallwood Realty. He is an associate of the Institute of Bankers in Scotland and
a member of the Society of Investment Analysts in the United Kingdom.
John R. Isaac, Jr., 49, has served as a director of HCRC since June 1992. Since
October 1997, Mr. Isaac has been Chief Executive Officer and President of Ideas,
Inc., a retail consulting company. From February 1996 to October 1997, Mr. Isaac
was President and Chief Executive Office of Thorn Americas, Inc., parent of
Rent-A-Center USA. From March 1995 until February 1996, Mr. Isaac was President
and Chief Operating Officer of Rent-A-Center USA. From February 1991 to February
1995, Mr. Isaac was President and Chief Operating Officer of Everything's A
Dollar, a division of Value Merchants, Inc. He was President and Chief Executive
Officer of Hallwood Industries Incorporated from August 1987 to October 1991. He
was President of Tradevest, Inc., a mail order catalog retailer, from 1986 to
1987, and a Vice President of Service Merchandise Co., Inc., a catalog showroom
retailer, from 1981 to 1986.
Jerry A. Lubliner, 43, has served as a director of HCRC since June 1992. Dr.
Lubliner is a medical doctor who has been in private practice since 1986. From
1986 to 1988, he was Associate Chief-Sports Medicine at the Hospital for Joint
Diseases-Orthopedic Institute in New York. Dr. Lubliner is a Fellow of the
American Academy of Orthopedic Surgeons. He is also a director of New York
Orthopedics and Sports Medicine, P.C.
Hamilton P. Schrauff, 62, has served as a director of HCRC since September 1996.
From March 1997 until June 1998, he was Chief Financial Officer of Burns
Controls Company. From March 1996 to January 1997 he was Vice President of
Capital Alliance. From August 1995 to February 1996 he was an independent
financial consultant. From October 1991 to August 1995 he was Vice President and
Chief Financial Officer of Basic Capital Management, Inc., Syntek Asset
Management, Inc., American Realty Trust Investors, Inc., Income Opportunity
Realty Trust and Transcontinental Realty Investors, Inc. From October 1991 to
February 1994 he was Executive Vice President and Chief Financial Officer of
National Income Realty Trust and Vinland Property Trust. From December 1990 to
October 1991 he was Vice President Finance-Partnership Investments of Hallwood
Group. From October 1980 to October 1990 he was Vice President Finance and
Treasurer, and from November 1976 to September 1980 he was Vice President
Finance of Texas Oil and Gas Corporation. Mr. Schrauff is a Certified Public
Accountant and a Certified Financial Planner. He is a member of the American
Institute of Certified Public Accountants, the Texas Society of Certified Public
Accountants and the Financial Executives Institute.
Bill M. Van Meter, 65, has served as a director of HCRC since September 1996.
From 1986 until May 1996, Mr. Van Meter was President of the Energy Companies of
ONEOK division of ONEOK Inc. From 1958 to 1996, Mr. Van Meter was employed by
both major and independent oil companies.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires the officers and
directors of HCRC and persons who own more than ten percent of the Common Stock,
to file reports of ownership and changes in ownership with the Securities and
Exchange Commission. Officers, directors and greater than ten percent owners are
required by SEC regulation to furnish HCRC with copies of all Section 16(a)
forms they file.
Based solely on its review of the copies of such forms received by it, or
written representations from certain reporting persons that no forms were
required for those persons, HCRC believes that, during the year ended December
31, 1998, all officers and directors of the Company and greater than ten-percent
beneficial owners complied with applicable filing requirements, except that Mr.
Thomas Jung filed his initial statement of beneficial ownership late. Mr. Jung
did not beneficially own any Common Stock of HCRC.
ITEM 11 - EXECUTIVE COMPENSATION
General
The Company has no employees. Management services are provided to the Company by
HPI, an affiliate of the Company. Employees of HPI perform all duties related to
the management of the Company, including the operations of various properties in
which the Company owns an interest. The Company is charged for management
services by HPI based on an allocation procedure that takes into account the
amount of time spent on management, the number of properties owned by the
Company and the Company's performance relative to its affiliates. The allocation
procedure is applied consistently to all related entities for which HPI performs
services. In 1998 the Company reimbursed HPI for approximately $2,376,000 of
expenses, of which $442,000 was attributable to compensation paid to executive
officers of the Company.
Compensation of Executive Officers
The following table sets forth the compensation to the Chief Executive Officer
and each of the four other most highly compensated officers whose compensation
paid by HPI exceeded $100,000 (determined for the year ended December 31, 1998).
<PAGE>
<TABLE>
<CAPTION>
Summary Compensation Table
Long Term
Annual Compensation Compensation
Securities
Underlying LTIP All Other
Name & Principal Position Year Salary Bonus Options/SARs Payouts Compensation
- ------------------------- ---- ------ ----- ------------ ------- ------------
(#) (1)
<S> <C> <C> <C> <C> <C> <C>
Anthony J. Gumbiner (2) 1998 $ 0 $ 0 0 $ (5) $ 0
Chief Executive 1997 0 0 (3) (5) 0
Officer 1996 125,000 0 0 (5) 0
William L. Guzzetti 1998 79,038 71,876 0 15,032 1,852
President and Chief 1997 82,535 65,677 (3) 24,855 1,919
Operating Officer 1996 82,943 60,490 0 14,927 2,314
Russell P. Meduna 1998 63,159 43,709 0 15,032 1,852
Executive Vice 1997 66,120 50,909 (3) 24,855 1,919
President 1996 66,448 46,874 0 14,927 1,827
Thomas J. Jung 1998 31,972 26,490 (4) 0 742
Vice President and
Chief Financial Officer
Cathleen M. Osborn 1998 46,160 32,892 0 10,568 1,852
Vice President and 1997 42,697 45,650 (3) 17,472 1,919
General Counsel 1996 42,908 28,704 0 10,391 1,827
<FN>
(1) Employer contribution to 401(k) and a service award of $487 paid to Mr
Guzzetti in 1996.
</FN>
<FN>
(2) For 1996, Mr. Gumbiner had a Compensation Agreement with HPI.
$125,000 of his compensation was allocated to the Company in 1996.
The Compensation Agreement terminated effective December 1996. In
addition to compensation listed in the table. HPI had a consulting
agreement with Hallwood Group for 1996, pursuant to which Hallwood
Group received an annual consulting fee of $300,000 from affiliates of
HPI. The Company paid approximately $122,000 in 1996 pursuant to
this arrangement. During 1997 and 1998, the Company participate
in a new financial consulting agreement between HPI and Hallwood
Group, pursuant to which Hallwood Group received a fee of $550,000
from affiliates of HPI. The Company paid Hallwood Group
approximately $241,000 in 1998 and 1997 for the Company's share of the
consulting agreement. The consulting services were provided by HSC
Financial Corporation ("HSC Financial"), through the services of Mr.
Gumbiner and Mr. Troup, and Hallwood Group paid the annual fee
it received to HSC Financial.
</FN>
<FN>
(3) Consists of the following options granted in 1997, which have been
adjusted for a 3-for-1 split effective in 1997.
Securities Underlying
Name Options/SARs (#)
Anthony J. Gumbiner 47,700
William L. Guzzetti 23,850
Russell P. Meduna 22,260
Cathleen M. Osborn 9,540
</FN>
<FN>
(4) Consists of the following options granted in 1998.
Securities Underlying
Name Options/SARs (#)
Thomas J. Jung 19,080
</FN>
<FN>
(5) Payments were made to HSC Financial, with which Mr. Gumbiner is associated,
in the amount of $33,479 for 1998, $31,755 in 1997 and $4,474 for 1996.
</FN>
</TABLE>
Option Grants and Exercises in Last Fiscal Year
The following table sets forth the options to purchase Common Stock of the
Company granted to executive officers during 1998.
<TABLE>
<CAPTION>
Option/SAR Grants in Last Fiscal Year
Potential Realized Value at
Assumed Annual Rates of
Stock Price Appreciation
Individual Grants for Option Term (2)
Number of % of Total
Securities Options/SARs
Underlying Granted Exercise or 5% 10%
Options/SARs Employees in Base Price Expiration $25.66 $40.85
Name Granted (1) Fiscal Year ($/Share) Date Share Price Share Price
---- ----------- ------------- ----------- ---------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Thomas J. Jung 19,080 100 $15.75 05/05/08 $189,989 $478,936
<FN>
(1) Options have a ten-year term and vest cumulatively over two years at the
rate of 1/3 on the grant date and the 1/3 on first two anniversaries of the
grant date. All options vest immediately in the event of certain changes in
control of HCRC.
</FN>
<FN>
(2) Securities and Exchange Commission Rules require calculation of potential
realizable value assuming that the market price of the Common Stock appreciates
in value at 5% and 10% annualized rates. At a 5% annualized rate of
appreciation, the Common Stock price would be $25.66 at the end of ten years. At
a 10% annualized rate of appreciation, the Common Stock price would be $40.85 at
the end of ten years. No gain to an executive officer is possible without an
appreciation in Common Stock value, which will benefit all holders of Common
Stock. The actual value an executive officer may receive depends on market
prices for the Common Stock, and there can be no assurance that the amounts
reflected will actually be realized.
</FN>
</TABLE>
<PAGE>
The following table shows exercises of options to purchase Common Stock during
1998 and the value of the unexercised options on December 31, 1998.
<TABLE>
<CAPTION>
Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values
Number of Securities
Underlying Value of Unexercised
Unexercised In-the-Money
Options/SARs Options/SARs
at FY - End (#) at FY -End ($)
Stock Acquired Value Exercisable/ Exercisable/
Name on Exercise (#) Realized ($) Unexercisable (1) Unexercisable (2)
---- --------------- ------------ ----------------- -----------------
<S> <C> <C> <C> <C> <C> <C>
Anthony J. Gumbiner 4,000 $33,820 75,500 / 15,900 189,221 / 0
William L. Guzzetti 39,750 / 7,950 103,271 / 0
Russell P. Meduna 2,500 21,700 34,600 / 7,420 85,561 / 0
Cathleen M. Osborn 5,000 42,900 10,900 / 3,180 19,658 / 0
Thomas J. Jung 6,360 / 12,720 0 / 0
<FN>
(1) The options have a ten-year term and vest cumulatively over three years
at the rate of 1/3 on each of the date of grant and the first two
anniversaries of the grant date. All options vest immediately in the
event of certain changes in control of the Company. The number of
options has been adjusted to reflect a 3-for-1 stock split effective in
1997.
</FN>
<FN>
(2) The exercise price of the options granted in 1995 is $6.67 per share,
the exercise price of the options granted in 1997 is $20.33 per share
and the exercise price of the options granted in 1998 is $15.75 per
share. The closing price of the common stock was $11.00 on December 31,
1998. The exercise prices have been adjusted to reflect a 3-for-1 stock
split effective in 1997.
</FN>
</TABLE>
Long-Term Incentive Plan
The following table describes performance units awarded to the executive
officers of the Company for 1998 under the incentive Plan (as described below)
for the Company and affiliated entities. The value of awards under each plan
depends primarily on the Company's success in drilling, completing and achieving
production from new wells each year and from certain recompletions and
enhancements of existing wells. The amounts shown below are the portion of
awards under the plan allocated to the Company.
<PAGE>
<TABLE>
<CAPTION>
Long-Term Incentive Plan Awards in Last Fiscal Year
Performance or Estimated Future
Number of Other Period Payouts under Non-Stock
Name Units Unit Payout Price-Based Plans (1)
---- ----------- --------------- -----------------------
<S> <C> <C> <C>
Anthony J. Gumbiner(2) -- -- $ --
William L. Guzzetti 0.0727 2003 8,951
Russell P. Meduna 0.0727 2003 8,951
Cathleen M. Osborn 0.0545 2003 6,710
<FN>
(1) The amount represents an award under the Incentive Plan. There are no
minimum, maximum or target amounts payable under the Incentive Plan.
Payments under the awards will be equal to the indicated percentage of
Plan net cash flow from certain wells for the first five years after an
award and, in the sixth year, the indicated percentage of 80% of the
remaining net percent value of estimated future production from the
wells allocated to the Plan. The amounts shown above are estimates
based on estimated reserve quantities and future prices. Because of the
uncertainties inherent in estimating quantities of reserves and prices,
it is not possible to predict cash flow or remaining net present value
of estimated future production with any degree of certainty.
</FN>
<FN>
(2) In addition, an award of .3818 units, with an estimated future payout
of $47,010, was made to HSC Financial, with which Mr. Gumbiner is
associated. The payout period ends in 2003.
</FN>
</TABLE>
The Incentive Plan for the Company is intended to provide incentive and
motivation to HPI's key employees to increase the oil and gas reserves of the
various affiliated entities for which HPI provides services and to enhance those
entities' ability to attract, motivate and retain key employees and consultants
upon whom, in large measure, those entities' success depends.
Under the Incentive Plan, the Board of Directors of the Company (the "Board")
annually determines the portion of the Company's collective interests in the
cash flow from certain international projects and from domestic wells drilled,
recompleted or enhanced during that year (the "Plan Year") which will be
allocated to participants in the plan and the participants will receive payment
in the sixth year of an award. The portion allocated to participants in the plan
is referred to as the Plan Cash Flow. The Board then determines which key
employees and consultants may participate in the plan for the Plan Year and
allocates the Plan Cash Flow among the participants. Awards under the plan do
not represent any actual ownership interest in the wells. Awards are made in the
Board's discretion.
Each award under the Incentive Plan represents the right to receive for five
years a specified share of the Plan Cash Flow attributable to certain domestic
wells drilled, recompleted or enhanced during the Plan Year. In the sixth year
afterward, the participant is paid an amount equal to a specified percentage of
the remaining net present value of estimated future production from the wells
and the award is terminated. Cash flow from international projects, if any,
allocated to the Incentive Plan is paid to participants for a 10-year period,
with no buy-out for estimated future production.
The awards for the 1998 Plan Year were made in January 1998. No other awards
were made in 1998. For the 1998 Plan Year, the Compensation Committee of
Hallwood G.P. determined that the total Plan Cash Flow would be equal to 2.75%
of the cash flow of the domestic wells completed, recompleted or enhanced during
the Plan Year. Accordingly, the value of awards for each Plan Year depends
primarily on the Company's success in drilling, completing and achieving
production from new wells each year and from certain recompletions and
enhancements of existing wells. The Compensation Committee also determined that
the participants' interests in eligible domestic wells for the 1998 Plan Year
would be purchased in the sixth year
<PAGE>
at 80% of the remaining net present value of the wells completed in the Plan
Year. The Compensation Committee also determined that the total award would be
allocated among key employees primarily on the basis of salary, and, to a lesser
extent, on the basis of contribution to HCRC's drilling activity.
Director Compensation
Each director of the Company who is not an officer of HCRC or an employee of
HPI, is paid an annual fee of $20,000 that is proportionately reduced if the
director attends fewer than four regularly scheduled meetings of the Board
during the year. During 1998, Messrs. Lubliner, Van Meter and Schrauff were each
paid $20,000. In addition, all directors are reimbursed for their expenses in
attending meetings of the Board and committees.
Compensation Committee Interlocks and Insider Participation
The Board of Directors of HCRC makes compensation decisions for the Company
during the first quarter of each year. Mr. Gumbiner is Chief Executive Officer
and serves on the compensation committee of Hallwood Group, of which Mr. Troup
is President and Mr. Guzzetti is Executive Vice President. Mr. Gumbiner is Chief
Executive Officer and a director, and Mr. Guzzetti is President and a director,
of Hallwood Realty. During 1998, Mr. Gumbiner and Mr. Guzzetti served on the
compensation committee of Hallwood Realty.
The Company participates in a financial consulting agreement between HPI and
Hallwood Group, pursuant to which Hallwood Group furnishes consulting and
advisory services to HPI, the Company and their affiliates. Under the terms of
this agreement, HPI and its affiliates are obligated to pay Hallwood Group
$550,000 per year until June 30, 2000. The agreement automatically renews for
successive three year terms; either party may terminate the agreement on not
less than 30 days written notice prior to the expiration of any three year term.
The financial consulting agreement replaced both a previous financial consulting
agreement and a compensation agreement with Mr. Gumbiner. Under the terms of the
previous financial consulting agreement, HPI and its affiliates were obligated
to pay Hallwood Group three annual payments of $300,000 beginning June 30, 1994,
and Hallwood group was obligated to furnish consulting and advisory services to
HPI and its affiliates through June 30, 1997. In 1997, the consulting services
were provided by HSC Financial Corporation, through the services of Mr. Gumbiner
and Mr. Troup, and Hallwood Group paid the annual fee it received to HSC
Financial. A fee of approximately $241,000 was paid in 1998 and 1997 and
$122,000 was paid in 1996, by the Company pursuant to this arrangement. For
1996, Mr. Gumbiner had a compensation agreement with HPI under which the Company
was allocated $125,000 in consulting fees. This agreement was terminated
effective December 31, 1996.
The Company reimburses Hallwood Group for expenses incurred on behalf of the
Company. The Company reimbursed Hallwood Group for approximately $246,000,
$232,000 and $234,000 of expenses during 1998, 1997 and 1996, respectively.
<PAGE>
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table shows information, as of March 24, 1999, about any
individual, partnership or corporation that is known to Hallwood Consolidated
Resources to be the beneficial owner of more than 5% of Hallwood Consolidated
Resources Common Stock issued and outstanding and each executive officer and
director of Hallwood Consolidated Resources and all executive officers and
directors of Hallwood Consolidated Resources as a group.
<TABLE>
<CAPTION>
Amount
Beneficially
Name Owned Percent of Class
<S> <C> <C>
Hallwood Energy Partners, L.P. (1) 1,374,465(5) 45.7
Heartland Advisors, Inc. (2) 476,500(6) 15.8
Estate of William Baxter Lee, III (3) 293,800(7) 9.8
FMR Corp. (4) 241,550(8) 8.0
Anthony J. Gumbiner 1,449,965(9)(10) 47.0
William L. Guzzetti 1,414,215(9)(10) 46.4
Russell P. Meduna 34,879(10) 1.2
Cathleen M. Osborn 10,990(10) *
Thomas J. Jung 6,360(10) *
Brian M. Troup 53,000(10) 1.7
Jerry A. Lubliner - -
Hamilton P. Schrauff - -
Bill M. Van Meter - -
John R. Isaac, Jr. - -
All directors and executive officers of 1,594,944(11) 49.4
HCRC as a group (10 persons)
- ----------------------
<FN>
* Less than 1%
</FN>
<FN>
(1) The address of Hallwood Energy Partners is 4582 S. Ulster Street Parkway,
Suite 1700, Denver, Colorado 80237.
</FN>
<FN>
(2) The address of Heartland Advisors, Inc. is 790 North Milwaukee Street,
Milwaukee, WI 53202.
</FN>
<FN>
(3) The address of the Estate of William Baxter Lee, III, is c/o Glankler Brown,
PLLC, 1700 One Commerce Sq., Memphis, TN 38103.
</FN>
<FN>
(4) The address of FMR Corp. is 82 Devonshire Street, Boston, MA 02109.
</FN>
<PAGE>
<FN>
(5) Includes 40,323 shares held by Hallwood Oil and Gas, Inc., a subsidiary
of Hallwood Energy Partners. Hallwood Energy Partners has sole voting and
investment power with respect to the shares reported. The general partner
of Hallwood Energy Partners is HEPGP Ltd., a limited partnership, the
general partner of which is Hallwood G.P. The executive officers of
Hallwood G.P. and Hallwood Consolidated Resources are the same
individuals: Anthony J. Gumbiner, William L. Guzzetti, Russell R. Meduna,
Cathleen M. Osborn and Thomas J. Jung.
</FN>
<FN>
(6) Information is from Amendment No. 6 to the Schedule 13G of Heartland
Advisors dated January 26, 1999. The Schedule 13G states that the shares
are held in investment advisory accounts of Heartland Advisors, Inc. and
that the interests of one such account, Heartland Value Fund, a series of
Heartland Group, Inc., a registered investment company, relates to more
than 5% of the Common Stock.
</FN>
<FN>
(7) Information is from Schedule 13G filed February 23, 1999.
</FN>
<FN>
(8) According to Schedule 13G filed February 12, 1999, Fidelity Management &
Research Company is the beneficial owner of the shares and acts as
investment adviser to Fidelity Low-Price Stock Fund which owns the
shares. Edward C. Johnson 3d, FMR Corp. and Fidelity Low-Price Stock Fund
each has sole power to dispose of the shares. The power to vote the
shares resides with the Board of Trustees of Fidelity Low-Price Stock
Fund.
</FN>
<FN>
(9) Includes 1,374,465 shares beneficially owned by Hallwood Energy
Partners. Mr. Gumbiner is Chief Executive Officer and Mr. Guzzetti
is President and a director of the general partner of the general
partner of Hallwood Energy Partners.
</FN>
<FN>
(10) The following numbers of shares issuable upon the exercise of currently
exercisable options are included in the amounts shown: Mr. Troup, 53,000
shares; Mr. Gumbiner, 75,500 shares; Mr. Guzzetti, 39,750 shares; Mr.
Meduna, 34,600 shares; Ms. Osborn, 10,900 shares and Mr. Jung 6,360
shares.
</FN>
<FN>
(11) Consists of 1,374,465 shares beneficially owned by Hallwood Energy
Partners, currently exercisable options to purchase 220,110 shares and
369 shares owned by directors and executive officers.
</FN>
</TABLE>
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
See Item 8 - Financial Statements and Supplementary Data (Note 5 to the
Financial Statements).
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, 1998.
<PAGE>
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.
(9) 4.1 Common Stock Purchase Warrant dated December 23, 1997.
(9) 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.
(7) 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.
(9) 10.17 Subordinated Note and Warrant Purchase Agreement dated as of
December 23, 1997.
(9) 10.18 Amendment No. 2 to Second Amended and Restated Credit
Agreement dated as of December 23, 1997.
* (10)10.19 Option Letter to Thomas Jung dated May 5, 1998
(10)10.20 Extension of Management Agreement between Hallwood Petroleum,
Inc., and HCRC dated May 5, 1998.
(11)10.21 Merger and Asset Contribution Agreement By and Among
Hallwood Energy Corporation, and HEC Acquisition
Partnership, L.P., HEC Acquisition Corp., Hallwood
Consolidated Resources Corporation and HEPGP Ltd. dated as
of December 15, 1998.
10.22 Letter Amendment No. 1 to Subordinated Note and Warrant
Purchase Agreement.
(6) 21 Subsidiaries of Registrant
23.1 Consent of Deloitte & Touche LLP
23.2 Consent of Deloitte & Touche LLP
27 Financial Data Schedule
- ------------------
(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.
(9) Incorporated by reference to the Annual Report of Form 10-K for the
year ended December 31, 1997.
(10) Incorporated by reference to the Quarterly Report on Form
10-Q for the quarter ended June 30, 1998
(11) Incorporated by reference to Schedule 14A of HCRC dated December 30,
1998.
* Designates management contract or compensatory plan or arrangement.
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
Date: March 24 , 1999 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 March 24, 1999
Anthony J. Gumbiner Director
/s/Brian M.Troup Director March 24, 1999
Brian M. Troup
/s/John R. Isaac,Jr. Director March 24, 1999
John R. Isaac, Jr.
/s/Jerry A. Lubliner Director March 24, 1999
Jerry A. Lubliner
/s/Hamilton P. Schrauff Director March 24, 1999
Hamilton P. Schrauff
/s/Bill M. Van Meter Director March 24, 1999
Bill M. Van Meter
/s/Thomas J. Jung Vice President March 24, 1999
Thomas J. Jung Chief Financial Officer
(Principal Accounting Officer)
<PAGE>
INDEX TO EXHIBITS
Page
Exhibit 10.22 - Letter Amendment No. 1 to Subordinated Note and
Warrant Purchase Agreement 68-72
Exhibit 23.1 - Consent of Deloitte & Touche LLP 73
Exhibit 23.2 - Consent of Deloitte & Touche LLP 74
<PAGE>
Hallwood Consolidated Resources Corporation
- --------------------------------------------------------------------------------
4582 S. Ulster St. Pkwy o Suite 1700 o Stanford Place III o P.O. Box 378111
Denver, Colorado 80237 o (303) 850-7373
- --------------------------------------------------------------------------------
LETTER AMENDMENT NO. 1
March 15, 1999
The Prudential Insurance Company of America
c/o Prudential Capital Group
2200 Ross Avenue, Suite 4200E
Dallas, Texas 75201
Ladies and Gentlemen:
We refer to the Subordinated Note and Warrant Purchase Agreement
dated as of December 23, 1997 (the "Agreement") among the undersigned, Hallwood
Consolidated Resources Corporation (the "Company"), and you. Unless otherwise
defined herein, the terms defined in the Agreement shall be used herein as
therein defined.
Paragraph 6A(2) of the Agreement requires that the Company not
permit Consolidated Net Worth on the last day of any fiscal quarter, commencing
with the fiscal quarter ending December 31, 1997, to be less than the sum of (i)
$31,255,900 plus (ii) 100% of any Equity Proceeds plus (iii) the cumulative
total of 50% of Consolidated Net Income for each fiscal quarter after September
30, 1997 in which Consolidated Net Income is positive. On December 31, 1998, the
Consolidated Net Worth requirement contained in paragraph 6A(2) was $31,417,267.
Because of a total of $19,600,000 in property impairments recorded during 1998,
Consolidated Net Worth was $29,589,000 at December 31, 1998. The Company
requests that you waive the requirements of paragraph 6A(2) for the fourth
quarter of 1998, provided that Consolidated Net Worth during such period was not
less than $29,000,000.
In addition, the Company is contemplating a consolidation (the
"Consolidation") of the Company, Hallwood Energy Partners, L.P. ("HEP") and the
energy interests of The Hallwood Group Incorporated into Hallwood Energy
Corporation, a newly formed corporation ("HEC"). As a result of the
Consolidation, the Company and HEP will become wholly-owned subsidiaries of HEC.
In addition, the equity interests in HEP owned by the Company (representing
approximately 19.00% of the outstanding limited partnership interests of HEP)
will not be converted into securities of HEC.
Whether or not the Company proceeds with the Consolidation,
the Company anticipates that it will not be in compliance with paragraph 6A(2)
during 1999 and has requested that you amend the covenant to permit the Company
to go forward with the Consolidation without being in default, despite the
transfer of the HEP interests. In addition, the Company would amend paragraph 6A
of the Agreement such that the Consolidated Net Worth requirement and the Total
Debt to EBITDA ratio would each be applicable to HEC on a consolidated basis and
would be defined in a manner, and would have compliance levels, satisfactory to
you and the Company. Finally, the Company or HEC would pay you an amendment fee
of $75,000 on the effective date of the assumption.
Based on the foregoing, you have indicated your willingness to
waive the default occasioned by noncompliance with paragraph 6A(2) for the
fourth quarter of 1998 and to give a conditional amendment to such covenant,
provided that the Company agrees with the other conditions set forth herein.
Accordingly, it is hereby agreed by you and us as follows:
1. Waiver. The holders of the Notes hereby agree to waive the
Event of Default occasioned by noncompliance by the Company with paragraph 6A(2)
as of December 31, 1998, provided that the Consolidated Net Worth at such date
was not less than $29,000,000.
2. Amendments. The Agreement is, effective the date first
above written, hereby amended as follows:
(a) Paragraph 6A(2). Consolidated Net Worth.
Paragraph 6A(2) of the Agreement is amended in its
entirety to read as follows:
6A(2). Consolidated Net Worth. Consolidated Net
Worth on the last day of any fiscal quarter (I)
commencing with the fiscal quarter ending December 31,
1997 and ending December 31, 1998, to be less than the
sum of (i) $31,255,900 plus (ii) 100% of any Equity
Proceeds plus (iii) the cumulative total of 50% of
Consolidated Net Income for each fiscal quarter after
September 30, 1997 in which Consolidated Net Income is
positive, to and including the fiscal quarter ended on
such measurement date, (II) commencing with the fiscal
quarter ending March 31, 1999 and ending on the earlier
of the fiscal quarter ending March 31, 2000 and the
last day of the fiscal quarter ending immediately
before the Consolidation, to be less than $25,000,000,
and (III) at any time after the earlier of March 31,
2000 and the last day of the fiscal quarter ending
immediately before the Consolidation, to be less than
the sum of (x) $31,417,267 plus (y) 100% of any Equity
Proceeds received after December 31, 1998 plus (z) the
cumulative total of 50% of Consolidated Net Income for
each fiscal quarter after December 31, 1998 in which
Consolidated Net Income is positive, to and including
the fiscal quarter ended on such measurement date.
(b) Paragraph 8A. Acceleration. Paragraph 8A of the Agreement
is amended by (I) adding the word "or" after clause (xv) and adding a new clause
(xvi) to read as follows:
(xvi) the Company shall merge or consolidate with
or into, or convey, transfer, lease, or otherwise
dispose of all or substantially all of its assets to
HEC, HEP or any other entity, pursuant to the
Consolidation or any other corporate reorganization
without the obligations of the Company under the
Agreement and Notes being assumed by HEC or such other
entity and the obligations of HEC or such other entity
under the Agreement and the Notes being guaranteed on a
subordinated basis substantially similar to paragraph 7
by each of the Company and HEP, all in a manner
satisfactory to the Required Holders;
(c) Paragraph 11B. Other Terms. Paragraph 11B is amended by
adding the following definitions in the appropriate alphabetical order:
"Consolidation" shall mean the consolidation of the
Company, HEP and the energy interests of The Hallwood
Group Incorporated into HEC.
"HEC" shall mean Hallwood Energy Corporation, a
Delaware corporation.
On and after the effective date of this letter amendment, each
reference in the Agreement to "this Agreement", "hereunder", "hereof", or words
of like import referring to the Agreement, and each reference in the Notes to
"the Agreement", "thereunder", "thereof", or words of like import referring to
the Agreement, shall mean the Agreement as amended by this letter amendment. The
Agreement, as amended by this letter amendment, is and shall continue to be in
full force and effect and is hereby in all respects ratified and confirmed. The
execution, delivery and effectiveness of this letter amendment shall not, except
as expressly provided herein, operate as a waiver of any right, power or remedy
under the Agreement nor constitute a waiver of any provision of the Agreement.
This letter amendment may be executed in any number of
counterparts and by any combination of the parties hereto in separate
counterparts, each of which counterparts shall be an original and all of which
taken together shall constitute one and the same letter amendment. The
effectiveness of this letter amendment is conditioned upon the accuracy of the
factual matters set forth above. The Company hereby confirms its agreement to
pay the fees, charges and disbursements of your special counsel incurred in
connection with this letter amendment.
If you agree to the terms and provisions hereof, please evidence
your agreement by executing and returning at least a counterpart of this letter
amendment to the Company at 4582 S Ulster St. Pkwy., Suite 1700, Denver,
Colorado 80237, Attention: Legal Department. This letter amendment shall become
effective as of the date first above written when and if:
(i) counterparts of this letter amendment shall have been executed by us
and you;
(ii) the consent attached hereto shall have been executed by the Guarantor;
and
(iii) you shall have received an amendment fee of $25,000 by
wire transfer to the account specified in the Purchaser
Schedule attached to the Agreement.
Very truly yours,
HALLWOOD CONSOLIDATED RESOURCES
CORPORATION
By:
Thomas J. Jung,
Vice President and Chief
Financial Officer
Agreed as of the date first above written:
THE PRUDENTIAL INSURANCE COMPANY
OF AMERICA
By:
Vice President
<PAGE>
CONSENT
The undersigned, as Guarantor under the Senior Subordinated
Guaranty dated as of December 23, 1997 (the "Guaranty") in favor of The
Prudential Insurance Company of America, a party to the Agreement referred to in
the foregoing letter amendment, hereby consents to said letter amendment and
hereby confirms and agrees that the Guaranty is, and shall continue to be, in
full force and effect and is hereby confirmed and ratified in all respects
except that, upon the effectiveness of, and on and after the date of, said
letter amendment, all references in the Guaranty to the Agreement, "thereunder",
"thereof", or words of like import referring to the Agreement shall mean the
Agreement as amended by said letter amendment.
HALLWOOD CONSOLIDATED PARTNERS, L.P.
BY: HALLWOOD CONSOLIDTED RESOURCES CORPORATION, GENERAL
PARTNER
By:
Thomas J. Jung
Vice President and Chief Financial Officer
March 15, 1999
<PAGE>
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No.
333-1154 of Hallwood Consolidated Resources Corporation on Form S-8 of our
report dated March 24, 1999, appearing in this Annual Report on Form 10-K of
Hallwood Consolidated Resources Corporation for the year ended December 31,
1998.
DELOITTE & TOUCHE LLP
Denver, Colorado
March 24, 1999
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No.
333-34105 of Hallwood Consolidated Resources Corporation on Form S-8 of our
report dated March 24, 1999, appearing in this Annual Report on Form 10-K of
Hallwood Consolidated Resources Corporation for the year ended December 31,
1998.
DELOITTE & TOUCHE LLP
Denver, Colorado
March 24, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from Form 10-K
for the year ended December 31, 1998 for Hallwood Consolidated Resources
Corporation and is qualified in its entirety by reference to such Form 10-K.
</LEGEND>
<CIK> 0000883953
<NAME> Hallwood Consolidated Resources Corporation
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 551
<SECURITIES> 0
<RECEIVABLES> 7,299
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 12,566
<PP&E> 339,526
<DEPRECIATION> 252,204
<TOTAL-ASSETS> 101,167
<CURRENT-LIABILITIES> 18,262
<BONDS> 0
0
0
<COMMON> 30
<OTHER-SE> 29,559
<TOTAL-LIABILITY-AND-EQUITY> 101,167
<SALES> 32,230
<TOTAL-REVENUES> 32,410
<CGS> 0
<TOTAL-COSTS> 11,642
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 4,160
<INCOME-PRETAX> (19,993)
<INCOME-TAX> 286
<INCOME-CONTINUING> (20,279)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (20,279)
<EPS-PRIMARY> (7.38)
<EPS-DILUTED> (7.38)
</TABLE>
