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 1-8921
HALLWOOD ENERGY PARTNERS, L. P.
(Exact name of registrant as specified in its charter)
Delaware 84-0987088
(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
Class A Units of Limited Partnership Interests American Stock Exchange
Class C Units of Limited Partnership Interests American Stock Exchange
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 Class A and Class C Units held by
nonaffiliates of the registrant as of March 24, 1999 was approximately
$30,238,000.
Number of Units outstanding as of March 24, 1999
Class A 10,011,852
Class B 143,773
Class C 2,464,063
PART I
ITEM 1 - BUSINESS
Hallwood Energy Partners, L.P. ("HEP" or the "Partnership") is a publicly traded
Delaware limited partnership engaged in the development, acquisition and
production of oil and gas properties in the continental United States. HEP's
objective is to provide its partners with an attractive return through a
combination of cash distributions and capital appreciation. To achieve its
objective, HEP utilizes operating cash flow, first, to reinvest in operations to
maintain its reserve base and production; second, to make stable cash
distributions to Unitholders; and third, to grow HEP's reserve base over time.
HEP's future growth will be driven by a combination of development of existing
projects, exploration for new reserves and select acquisitions. HEPGP Ltd.
("HEPGP") became the general partner of HEP on November 26, 1996 after the
former general partner, Hallwood Energy Corporation ("HEC") merged into The
Hallwood Group Incorporated ("Hallwood Group""). HEPGP Ltd. is a limited
partnership of which Hallwood Group is the limited partner and Hallwood G.P.,
Inc. ("Hallwood G.P."), a wholly owned subsidiary of Hallwood Group, is the
general partner. HEP commenced operations in August 1985 after completing an
exchange offer in which HEP acquired oil and gas properties and operations from
HEC, 24 oil and gas limited partnerships, of which HEC was the general partner,
and certain working interest owners that had participated in wells with HEC and
the limited partnerships.
The activities of HEP are conducted by HEP Operating Partners, L.P. ("HEPO") and
EDP Operating Ltd. ("EDPO"). HEP is the sole limited partner and HEPGP Ltd. is
the sole general partner of HEPO and of EDPO. Solely for purposes of simplicity
herein, unless otherwise indicated, all references to HEP in connection with the
ownership, exploration, development or production of oil and gas properties
include HEPO and EDPO.
HEP does not engage in any other line of business nor does it have any
employees. Hallwood Petroleum, Inc. ("HPI"), an affiliated entity, operates the
properties and administers the day to day activities of HEP and its affiliates.
On March 24, 1999, HPI has 108 employees.
Marketing
The oil and gas produced from the properties owned by HEP has typically been
marketed through normal channels for such products. The Partnership generally
sells its oil at local field prices generally paid by the principal purchasers
of crude oil in the areas where the majority of producing properties are
located. In response to the volatility in the oil markets, HEP has entered into
financial contracts for hedging the price of 2% of its estimated oil production
for 1999.
All of HEP's natural gas production is sold on the spot market or in short-term
contracts and is transported in intrastate and interstate pipelines. HEP has
entered into financial contracts for hedging the price of between 30% and 45% 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 an increase or decrease in oil or gas 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. HEP 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 HEP's business
because there are numerous other purchasers in the areas in which HEP sells its
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 Partnership:
1998 1997 1996
---- ---- ----
Conoco Inc. 23% 20% 28%
El Paso Field Services Company 11% 11%
Marathon Petroleum Company 16% 11%
Factors, if they were to occur, which might adversely affect HEP include
decreases in oil and gas prices, the reduced availability of a market for
production, rising operational costs of producing oil and gas, compliance with,
and changes in, environmental control statutes and increasing costs of
transportation.
Competition
HEP encounters competition from other oil and gas companies in all areas of its
operations, including the acquisition of exploratory prospects and proven
properties. The Partnership's competitors include major integrated oil and gas
companies and numerous independent oil and gas companies, individuals and
drilling and income programs. As described above under "Marketing," production
is sold on the spot market, thereby reducing sales competition; however, 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 is subject to federal and state governmental
regulation 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 HEP 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, the general partner cannot predict
what effect possible future public or private action may have on the business of
HEP. The general partner 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, HEP 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 HEP in the oil and gas industry.
Insurance Coverage
HEP is subject to all the risks inherent in the exploration for, and development
of, oil and gas, including blowouts, fires and other casualties. HEP maintains
insurance coverage as is customary for entities of a similar size engaged in
operations similar to that of HEP, 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 HEP'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 Partnership: 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 Partnership'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 Partnership 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 Partnership's IT systems that
must be updated or replaced in order to be Year 2000 compliant. In particular,
the software used by the Partnership 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
Partnership's assessment of the readiness of third parties whose IT systems
might have an impact on the Partnership'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 Partnership's Non IT systems, the Partnership believes that
most of these systems can be brought into compliance on schedule. The
Partnership's assessment of third party readiness is not yet completed. Because
Non IT systems are embedded chips, it is difficult to determine with complete
accuracy where all such systems are located. As part of its Plan, the
Partnership 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 Partnership's
preliminary estimate is that such costs will not be material. To date, the
Partnership 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 Partnership's IT and
Non IT systems, as well as to the systems of third parties. Such failures could
materially and adversely affect the Partnership'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 Partnership is
unable to determine at this time whether the consequences of Year 2000 failures
will have a material impact on the Partnership's results of operations, cash
flow or financial condition. Although the Partnership 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 Partnership. The Partnership is contacting the various purchasers and
pipelines with which it regularly does business to determine their state of
readiness for the Year 2000. Although in general the purchasers and pipelines
will not guaranty their state of readiness, the responses received to date have
indicated no material problems. The Partnership 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 Partnership's Year 2000 Plan is expected to
significantly reduce the Partnership'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 Partnership's development of contingency
plans.
Cautionary Statement Regarding Forward-Looking Statements. The dates for
completion of the phases of the Year 2000 Plan are based on the Partnership'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 Partnership 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, partners 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, HEP incurred $40,936,000 in direct property additions, development,
exploitation and exploration costs. The costs were comprised of $28,756,000 for
property acquisitions and approximately $12,180,000 for domestic exploration and
development. The expenditures resulted in the drilling, recompletion, or
workover of 44 development wells and 36 exploration wells. HEP completed 39
development wells (89%) and 18 exploration wells (50%) for an overall completion
rate of 71%. HEP's 1998 capital program led to the replacement, including
revisions to prior year reserves, of 72% of 1998 production using year-end
prices of $10.00 per bbl and $1.90 per mcf. Using five-year average prices of
$16.75 per bbl and $1.86 per mcf, HEP's reserve replacement for 1998 would have
been 136% 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 2% of 1998 production. In 1998, HEP
expended approximately $1,495,000 for land and seismic costs, which HEP
anticipates will yield prospects for 1999 and subsequent years.
Property Sales
During 1998, HEP received approximately $454,000 for the sale of 67 nonstrategic
properties located in eight states.
Regional Area Descriptions and 1998 Capital Budget
The following discussion of HEP'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
HEP has significant interests in the Greater Permian Region, which includes West
Texas and Southeast New Mexico. In this region, HEP 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, HEP expended approximately $12,070,000 (29%) of its capital
budget on projects in this area. HEP spent approximately $2,598,000 for
drilling, recompletion, or workover of 24 development wells and for drilling 18
exploration wells. Seventy-nine 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, HEP 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 565,000 barrels
of oil and 5.3 billion cubic feet of natural gas at five-year average prices,
and approximately 465,000 barrels of oil and 5.3 billion cubic feet of natural
gas at year-end pricing. HEP's estimated proven reserve addition of 8.7 bcfe
represents approximately 47% of HEP's 1998 production at five-year average
prices, and 43% of HEP's 1998 production at year-end prices. HEP estimates that
gross 1999 production from the properties could be approximately 1.1 bcfe. In
1999, HEP 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 HEP
plans to study the areas for future development project implementation.
Carlsbad/Catclaw Area. HEP'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, HEP spent
approximately $886,000 recompleting or drilling nine producing development wells
and drilling one unsuccessful exploration well. HEP expects to continue operated
development drilling in the Hat Mesa Field.
East Keystone Area. HEP'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, HEP had
eight development projects, of which seven were successful. HEP's future
development plans include a total of three projects for this area.
Merkle Area. HEP's interest in the Merkle Area as of December 31, 1998 consisted
of 29 producing wells, 16 of which are operated by HPI in Taylor and Nolan
Counties, Texas. HEP'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, HEP acquired 74 additional miles of proprietary 3-D
seismic data adjacent to the nonoperated area. HEP'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, HEP drilled 11 exploration wells and
one development well, nine of which were completed. HEP incurred approximately
$975,000 in costs in 1998 for the 12 wells drilled. HEP 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 HEP anticipates additional 1999 drilling
to continue to exploit the reef structures.
Griffin Project. In 1998, HEP purchased land for $102,000 and incurred costs of
approximately $420,000 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
crude oil focused area and low oil prices, HEP will delay future drilling and
evaluate the viability of the remaining exploration projects. HEP owns an
average 22% working interest in the prospect area.
Spraberry Area. HEP'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, HEP drilled or recompleted three wells, all of
which are producing. As a result of low crude oil prices, HEP abandoned
twenty-three wells in this area in 1998. During 1999, HEP 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 150 mcfe per day, net to
HEP, and were operating at a net loss to HEP of $270,000 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
HEP has significant interests in the Gulf Coast Region in Louisiana and South
and East Texas. HEP'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, HEP 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, HEP expended approximately $5,821,000 (14%) of its capital budget in this
region.
The following discussion relates to major 1998 capital projects within the
region.
Bell Project. HEP has a 30% working interest in an operated project to evaluate
the Buda, Carrizo, Woodbine, and Dexter sands in Houston County, Texas. HEP'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. HEP 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. HEP also incurred $375,000 in 1998 for land and
leasehold costs relating to the project. HEP plans additional delineation
drilling in 1999. HEP 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 wells drilled will be successful.
Bison Prospect. HEP 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 HEP during 1998 for its 7.5% working
interest were approximately $550,000.
Blue Moon Project. During 1998, HEP 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. HEP'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%. HEP 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, HEP participated in a Frio sand recompletion and a
3-D seismic review of the deep Vicksburg located in Chambers County, Texas. HEP
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.
HEP does not plan additional activity in this area.
Esperanza Project. HEP 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. HEP spent approximately $365,000 in 1998 for its share of
costs. HEP plans to participate in additional wells in 1999 to further exploit
this discovery.
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 HEP 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. HEP spent $263,000 to test the concept.
Mirasoles Project. In 1998, HEP spent approximately $430,000 for land costs
related to the Mirasoles project in Kenedy County, Texas. HEP 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. HEP 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.
Whitewater Field. HEP's share of 1998 costs associated with plugging two
nonoperated near shore platform wells in Nueces County, Texas was approximately
$600,000. HEP has abandoned this field and plans no further activity.
Rocky Mountain Region
HEP has significant interests in the Rocky Mountain Region, which include
producing properties in Colorado, Montana, North Dakota and Northwest New
Mexico. HEP 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. HEP expended approximately $21,810,000 (53%) 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, HEP spent approximately $3,125,000 to expand a New Mexico
gathering system, to recomplete or drill 12 development wells and to drill three
exploration wells. Twelve of the wells were completed. A discussion of the major
projects in the region follows.
Cajon Lake Field. In 1998, HEP sidetracked a 6,000-foot Ismay formation
exploration well in San Juan County, Utah. HEP developed the prospect from
proprietary 3-D seismic data and HPI is the operator of the project. HEP 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. HEP projects that the fully
developed prospect could have 6 bcfe gross potential. There can be no assurance,
however, that any additional wells drilled will be successful. Despite low oil
prices, additional delineation drilling is anticipated in 1999.
Colorado Western Slope Project. HEP drilled and completed two 5,500-foot Dakota
Formation wells in the Piceance Basin in western Colorado. HEP owns an average
29% 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, HEP also recompleted an additional well. Total costs
in 1998 for the three wells were approximately $390,000. HEP has identified
fourteen additional development locations. HEP 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 be no assurance, however, that any
additional wells drilled will be successful.
Toole County Area. HEP'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, HEP 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. HEP 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, HEP 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, HEP and its affiliate Hallwood
Consolidate Resources Corporation ("HCRC") 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
HEP and HCRC, purchased the VPP from the affiliate of Enron Corp. HEP funded its
$17,291,000 share of the acquisition price from operating cash flow and
borrowings under its Credit Agreement. As a result of its acquisition HEP
replaced the higher cost and administratively burdensome VPP financing with
lower cost conventional borrowings under its Credit Agreement. At the time of
the purchase, HEP 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, HEP and HCRC 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 HEP's current average daily
production by 6.25 mmcf per day.
San Juan Basin Project - New Mexico. HEP'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. Costs associated with expansion of the gathering system
for HEP's coalbed methane properties totaled approximately $1,028,000 during
1998. 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. HEP also receives a payment of $.36
per mcf for tax credits generated by production from the 31 coalbed methane
wells.
Other
HEP owns various other interests in properties in Kansas, Oklahoma, California
and South Central Texas. The remaining $1,235,000 of HEP'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, HEP also participated in two nonoperated
3-D seismic projects in nearby Solano and Colusa Counties, California. HEP is in
the process of divesting its interests in California projects.
Peru Block Z-3 Project. HEP'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 HEP
in the first quarter of 1999. HEP 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, HEP's capital budget, which will be paid from cash generated from
operations and cash on hand has been set at $11,848,000. HEP 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
oil and gas prices decrease further.
Partnership Reserves, Production and Discussion by Significant Regions
The following table presents the December 31, 1998 reserve data by significant
regions.
Proved Reserve Quantities Present Value of Future Net Cash Flows
Proved Proved
Mcf of Gas Bbls of Oil Undeveloped Developed Total
(In thousands)
Greater Permian Region 18,471 2,774 $ 16,542 $ 16,542
Gulf Coast Region 23,555 988 $ 1,791 36,146 37,937
Rocky Mountain Region 50,956 612 42,768 42,768
Other 1,957 113 19 3,734 3,753
-------- ------- -------- -------- ----------
94,939 4,487 $ 1,810 $ 99,190 $101,000
======= ====== ====== ======= =======
The following table presents the oil and gas production for significant regions
for the periods indicated.
Production for the Production for the
Year Ended December 31, 1998 Year Ended December 31, 1997
Natural Gas Bbls of Oil Natural Gas Bbls of Oil
(mcf) (bbls) (mcf) (bbls)
(In thousands)
Greater Permian Region 2,893 401 2,803 423
Gulf Coast Region 5,291 175 4,859 184
Rocky Mountain Region 5,233 133 3,562 100
Other 620 78 550 63
-------- ----- -------- -----
14,037 787 11,774 770
====== ==== ====== ====
The following table presents the Partnership's extensions and discoveries by
significant regions.
For the Year Ended December 31, 1998 For the Year Ended December 31, 1997
Mcf of Gas Bbls of Oil Mcf of Gas Bbls of Oil
(In thousands)
Greater Permian Region 217 167 1,423 232
Gulf Coast Region 1,201 164 1,527 75
Rocky Mountain Region 78 83 1,153 490
Other 46 1 125 20
------- ------ ------ -----
1,542 415 4,228 817
===== ==== ===== ====
Average Sales Prices and Production Costs
The following table presents the average oil and gas sales price and average
production costs per equivalent mcf of gas computed at the ratio of six mcf of
gas to one barrel of oil.
1998 1997 1996
------ ------ -----
Oil and condensate -
includes the effects of hedging (per bbl) $13.65 $19.08 $20.10
Natural gas -
includes the effects of hedging (per mcf) 2.02 2.31 2.24
Production costs (per equivalent mcf of gas) .65 .67 .62
Productive Oil and Gas Wells
The following table summarizes the productive oil and gas wells as of December
31, 1998 attributable to HEP's direct interests. Productive wells are producing
wells and wells capable of production. Gross wells are the total number of wells
in which HEP has an interest. Net wells are the sum of HEP's fractional
interests owned in the gross wells.
Gross Net
Productive Wells
Oil 1,263 164
Gas 352 69
----- ----
Total 1,615 233
===== ===
Oil and Gas Acreage
The following table sets forth the developed and undeveloped leasehold acreage
held directly by HEP 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 HEP has a working interest. Net acres are the sum of HEP's fractional
interests owned in the gross acres.
Gross Net
Developed acreage 101,257 46,771
Undeveloped acreage 323,108 82,976
------- --------
Total 424,365 129,747
======= =======
HEP holds undeveloped acreage in Texas, Louisiana, Montana, Wyoming, New Mexico,
Kansas, Colorado and North Dakota.
Drilling Activity
The following table sets forth the number of wells attributable to HEP's direct
interests drilled in the most recent three years.
Year Ended December 31,
1998 1997 1996
------ ------ -----
Gross Net Gross Net Gross Net
Development Wells:
Productive 12 3.6 23 4.5 29 6.6
Dry 5 1.5 5 .8 4 .9
--- --- --- ---- --- ----
Total 17 5.1 28 5.3 33 7.5
== === == === == ===
Exploratory Wells:
Productive 17 4.3 14 2.2 2 .2
Dry 17 3.0 22 5.4 4 .6
-- --- -- --- - --
Total 34 7.3 36 7.6 6 .8
== === == === = ==
Office Space
HPI leases office space in Denver, Colorado under a lease which expires in June
1999, for approximately $600,000 per year. 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. The lease payments are included in the
allocation of general and administrative expenses to HEP and other affiliated
entities. HEP is guarantor of 60% of the lease obligation, and HCRC is guarantor
of the remaining 40% of the obligation.
ITEM 3 - LEGAL PROCEEDINGS
See Notes 13 and 14 to the financial statements included in Item 8 - Financial
Statements and Supplementary Data.
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth
quarter of 1998.
PART II
ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED UNITHOLDER MATTERS
HEP's Class A Units are traded on the American Stock Exchange (the "Exchange")
under the symbol "HEP." As of March 24, 1999, 10,011,852 Class A Units were
outstanding, held by approximately 18,386 unitholders of record and 143,773
Class B Units were outstanding, held by Hallwood Group. The Class B Units are
not publicly traded. The following table sets forth, for the periods indicated,
the high and low reported sales prices for the Class A Units as reported on the
Exchange and the distributions paid per Class A Unit for the corresponding
periods.
Class A Units High Low Distributions
First quarter 1997 $ 10 3/4 $ 8 1/16 $ .13
Second quarter 1997 9 7 1/8 .13
Third quarter 1997 8 15/16 6 15/16 .13
Fourth quarter 1997 10 1/4 7 1/2 .13
----
$ .52
First quarter 1998 $ 8 5/8 $ 6 3/8 $ .13
Second quarter 1998 7 6 .13
Third quarter 1998 7 4 11/16 .13
Fourth quarter 1998 5 7/8 3 .13
----
$ .52
On January 17, 1996, HEP's Class C Units began trading on the Exchange under the
symbol "HEPC." On February 17, 1998, HEP closed its public offering of 1.8
million Class C Units which were priced at $10.00 per Unit. As of March 24,
1999, 2,464,063 Class C Units were outstanding, held by approximately 13,822
unitholders of record. The following table sets forth, for the periods
indicated, the high and low reported sales prices for the Class C Units as
reported on the Exchange and distributions paid per Class C Unit for the
corresponding periods.
Class C Units High Low Distributions
>
First quarter 1997 $ 10 $ 8 5/8 $ .25
Second quarter 1997 9 3/8 8 3/4 .25
Third quarter 1997 10 1/2 8 7/8 .25
Fourth quarter 1997 14 7/8 10 .25
-----
$1.00
First quarter 1998 $ 11 $ 9 1/8 $ .25
Second quarter 1998 9 13/16 8 3/8 .25
Third quarter 1998 8 1/2 6 3/4 .25
Fourth quarter 1998 7 15/16 5 7/8 .25
-----
$1.00
HEP's debt agreements limit aggregate distributions paid by HEP in any twelve
month period to 50% of cash flow from operations before working capital changes
and 50% of distributions received from affiliates, if the principal amount of
debt of HEP is 50% or more of the borrowing base. Aggregate distributions paid
by HEP are limited to 65% of cash flow from operations before working capital
changes and 65% of distributions received from affiliates, if the principal
amount of debt is less than 50% of the borrowing base.
ITEM 6 - SELECTED FINANCIAL DATA
The following table sets forth selected financial data regarding HEP's financial
position and results of operations as of the dates indicated. As a result of the
issuance of Class A Units in connection with a litigation settlement, all Unit
and per Unit information for periods prior to December 31, 1995 has been
retroactively restated.
As of and For the Year Ended December 31,
-----------------------------------------
1998 1997 1996 1995 1994
------ ------ ------- ------ -----
(In thousands except per Unit)
Summary of Operations
Oil and gas revenues and
pipeline operations $ 43,177 $ 44,707 $ 50,644 $ 43,454 $ 43,899
Total revenue 43,586 45,103 51,066 43,780 44,482
Production operating expense 12,175 11,060 11,511 11,298 12,177
Depreciation, depletion and
amortization 15,720 11,961 13,500 15,827 18,168
Impairment 14,000 10,943 7,345
General and administrative
expense 5,045 5,333 4,540 5,580 5,630
Net income (loss) (13,895) 12,803 15,726 (9,031) (10,093)
Basic net income (loss) per
Class A and Class B Unit (1.86) 1.09 1.35 (1.07) (1.20)
Diluted net income (loss) per
Class A and Class B Unit (1.86) 1.07 1.35 (1.07) (1.20)
Distributions per Class A Unit .52 .52 .52 .80 .80
Distributions per Class B Unit .80 .80
Balance Sheet
Working capital deficit $ (8,722) $ (973) $ (1,355) $ (4,363) $ (9,390)
Property, plant and equipment,
net 105,005 94,331 88,549 94,926 107,414
Total assets 139,091 131,603 122,792 125,152 136,281
Long-term debt 40,381 34,986 29,461 37,557 25,898
Long-term contract settlement
obligation 2,512 2,397 2,666
Deferred liability 1,050 1,180 1,533 1,718 1,931
Minority interest in affiliates 2,788 3,258 3,336 3,042 2,923
Partners' capital 62,632 69,064 64,215 57,572 78,803
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS, LIQUIDITY AND CAPITAL RESOURCES
During 1998, HEP had a net loss of $13,895,000, compared to net income of
$12,803,000 for 1997. The 1998 period includes noncash charges in the second,
third and fourth quarters totaling $14,000,000 for property impairments which
were taken to lower the capitalized cost of HEP's properties to an amount equal
to the present value, discounted at 10%, of the future net revenues attributable
to those properties. Also included in the net loss is a noncash charge of
$4,888,000 which represents HEP's equity in the loss of HCRC. This amount is
largely comprised of HEP's share of HCRC's property impairments.
HEP'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 HEP for oil and gas have declined in
each of the last four quarters. HEP's hedges mitigated the price reductions, by
increasing both the average oil and gas prices by 6%. HEP's weighted average oil
and gas prices, when the effects of hedging are considered, were 28% and 13%
lower, respectively, for 1998 compared to 1997.
Although HEP's production for 1998 was 14% greater than the prior year, and
operating, general and administrative and interest 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, HEP announced a proposal to consolidate HEP with HCRC 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, HEP anticipates that the new company will have the ability to take
advantage of opportunities that are unavailable to smaller entities such as HEP
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
unitholders of HEP and shareholders of HCRC 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
HEP generated $26,277,000 of cash flow from operating activities during 1998.
The other primary cash inflows were:
o Proceeds from long-term debt of $33,000,000;
o Proceeds from the issuance of Class C Units, net of syndication costs of
$16,518,000;
o Distributions received from affiliate of $1,583,000;
o Proceeds from the sale of property of $454,000;
o Exercise of Unit Options of $199,000; and
o Capital contribution from the general partner of $171,000.
Cash was used primarily for:
o Additions to property, exploration and development costs of $40,936,000;
o Payments of long-term debt of $18,286,000;
o Distributions to partners of $9,495,000; and
o Payment of contract settlement of $2,767,000.
When combined with miscellaneous other cash activity during the year, the result
was an increase in HEP's cash and cash equivalents of $5,252,000 from $6,622,000
at December 31, 1997 to $11,874,000 at December 31, 1998.
Property Purchases, Sales and Capital Budget
In 1998, HEP incurred $40,936,000 in direct property additions, development,
exploitation and exploration costs. The costs were comprised of $28,756,000 for
property acquisitions and approximately $12,180,000 for domestic exploration and
development. HEP's 1998 capital program led to the replacement, including
revisions to prior year reserves, of 72% of 1998 production. This reserve
replacement figure is calculated using year-end prices of $10.00 per barrel of
oil and $1.90 per mcf of gas. If five-year average prices of $16.75 per bbl and
$1.86 per mcf are used, HEP replaced 136% of 1998 production.
In the Greater Permian Region, HEP 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, HEP spent approximately $886,000 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 $975,000 was spent to drill 11 exploration wells and one
development well, nine of which were completed in the Merkle Project. HEP
incurred approximately $420,000 drilling three exploration wells and one
development well in the Griffin area, all of which were unsuccessful.
In the Gulf Coast Region, HEP spent approximately $430,000 for land and $941,000
to drill one Mirasoles project exploration well in Kenedy County, Texas which is
currently in the completion phase. HEP incurred approximately $365,000 to drill
one successful exploration well in LaVaca County, Texas. Approximately $375,000
was incurred by HEP 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. Approximately $550,000 was incurred in 1998 by HEP to drill one well now
plugged and abandoned as part of the Bison project in Lafayette Parish,
Louisiana, and approximately $600,000 for plugging costs associated with two
nonoperated near shore platform wells in the Whitewater Field.
HEP'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, HEP's significant exploration and
development expenditures in the Rocky Mountain Region included approximately
$1,028,000 to expand a New Mexico gathering system; approximately $120,000 to
complete a successful exploration well within the Cajon Lake Field in Utah;
approximately $390,000 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 HEP'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 Partnership has not
recognized any impairment losses on long-lived assets other than oil and gas
properties.
Distributions
During 1998, HEP declared distributions of $.52 per Class A Unit and $1.00 per
Class C Unit to its Unitholders. Distributions on the Class B Units are
suspended if the Class A Units receive a distribution of less than $.20 per
Class A Unit per calendar quarter. In any quarter for which distributions of
$.20 or more per unit are made on the Class A Units, the Class B Units are
entitled to be paid, in whole or in part, suspended distributions. The Class C
Units have a distribution preference of $1.00 per year, payable quarterly, which
began in the first quarter of 1996. HEP may not declare or make any cash
distributions on the Class A or Class B Units unless all accrued and unpaid
distributions on the Class C Units have been paid.
The Board of Directors of HEP's General Partner is considering the distribution
level for future quarters, taking into account oil and gas prices, cash flow,
long-term debt and borrowing base levels, and the capital needs of HEP.
Unit Option Plans
On January 31, 1995, the Board of Directors of the general partner approved the
adoption of the 1995 Class A Unit Option Plan to be used for the motivation and
retention of directors, employees and consultants performing services for HEP.
The plan authorizes the issuance of options to purchase 425,000 Class A Units.
Grants of the total options authorized were made on January 31, 1995, vesting
one-third at that time, an additional one-third on January 31, 1996 and the
remaining one-third on January 31, 1997. The exercise price of the options is
$5.75, which was the closing price of the Class A Units on January 30, 1995. As
of December 31, 1998, 34,600 options have been exercised.
During the second quarter of 1998, HEP adopted a Class C Unit Option Plan
covering 120,000 Class C Units. Options to purchase all of the Units were
granted effective May 5, 1998 at an exercise price of $10.00 per Unit, which was
equal to the fair market value of the Units on the date of grant. One-half of
the options vested on the date of grant, and the remainder vest on the first
anniversary of the date of grant. As of December 31, 1998, no options have been
exercised.
On May 5, 1998, HEP granted options to purchase 25,500 Class A Units at an
exercise price of $6.625 per Unit, which was equal to the fair market value of
the Units 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 HEP's 1995 Unit Option Plan. One-third of the options vested on the
date of grant, 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. As of
December 31, 1998, no options have been exercised.
During 1996, HEP adopted the disclosure provisions of Statement of Financial
Accounting Standards No. 123, "Accounting for Stock Based Compensation" ("SFAS
123"). SFAS 123 requires entities to use the fair value method to either account
for, or disclose, stock based compensation in their financial statements.
Because the Partnership elected the disclosure only provisions of SFAS 123, the
adoption of SFAS 123 did not have a material effect on the financial position or
results of operations of HEP.
Financing
During the first quarter of 1997, HEP and its lenders amended HEP's Second
Amended and Restated Credit Agreement (as amended, the "Credit Agreement") to
extend the term date of its Credit Agreement to May 31, 1999. The lenders are
Morgan Guaranty Trust Company, First Union National Bank and NationsBank of
Texas. Under the Credit Agreement, HEP has a borrowing base of $62,000,000. HEP
had amounts outstanding at December 31, 1998 of $49,700,000. HEP's unused
borrowing base totaled $12,300,000 at March 24, 1999.
Borrowings against the Credit Agreement bear interest at the lower of the
Certificate of Deposit rate plus from 1.375% to 1.875%, prime plus 1/2% or the
Euro-Dollar rate plus from 1.25% to 1.75%. The applicable interest rate was
7.125% at December 31, 1998. Interest is payable monthly, and quarterly
principal payments of $3,106,500 commence May 31, 1999.
The borrowing base for the Credit Agreement is redetermined semiannually, and
the next redetermination is scheduled for the second quarter of 1999. HEP
anticipates that, because of low oil and gas prices, its lenders will reduce the
borrowing base. HEP does not anticipate that a reduced borrowing base will have
a material adverse effect. The Credit Agreement is secured by a first lien on
approximately 80% in value of HEP's oil and gas properties. Additionally,
aggregate distributions which may be paid by HEP in any 12 month period are
limited to 50% of cash flow from operations before working capital changes and
distributions received from affiliates, if the principal amount of debt of HEP
is 50% or more of the borrowing base. Aggregate distributions which may be paid
by HEP are limited to 65% of cash flow from operations before working capital
changes and 65% of distributions which may be received from affiliates, if the
principal amount of debt is less than 50% of the borrowing base.
As a part of its risk management strategy, HEP enters into financial contracts
to hedge the interest payments related to a portion of its outstanding
borrowings under its Credit Agreement. HEP does not use the hedges for trading
purposes, but rather 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.
As of March 24, 1999, HEP was a party to six contracts with three
counterparties. The following table provides a summary of HEP's financial
contracts.
Average
Amount of Contract
Period Debt Hedged Floor Rate
1999 $27,000,000 5.70%
2000 30,000,000 5.65%
2001 24,000,000 5.23%
2002 25,000,000 5.23%
2003 25,000,000 5.23%
2004 4,000,000 5.23%
Gas Balancing
HEP uses the sales method for recording its gas balancing. Under this method,
HEP 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, HEP had a net over-produced position of 157,000 mcf
($298,000 valued at year-end gas prices). The general partner believes that this
imbalance can be made up from production on existing wells or from wells which
will be drilled as offsets to existing wells and that this imbalance will not
have a material effect on HEP's results of operations, liquidity and capital
resources. The reserves disclosed in Item 8 have been decreased by 157,000 mcf
in order to reflect HEP'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 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 Partnership adopted SFAS 130 on January 1, 1998. The Partnership 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 periods.
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. HEP adopted FAS 131 in 1998.
The Partnership 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. In addition, the Partnership's
activities exhibit similar economic characteristics and involve the same
products, production processes, class of customers, and methods of distribution.
Management of the Partnership evaluates its performance as a whole rather than
by product or geographically. As a result, HEP'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 Partnership is required to
adopt SFAS 133 on January 1, 2000. The Partnership 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 partners with certain information regarding the
Partnership'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. Although any forward-looking statements
contained in this Form 10-K or otherwise expressed by or on behalf of the
Partnership are, to the knowledge and in the judgment of the officers and
directors of the general partner, 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 Partnership'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 HEP'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 HEP can produce economically.
HEP'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 HEP's control.
Competition from larger, more established oil and gas companies. HEP encounters
competition from other oil and gas companies in all areas of its operation,
including the acquisition of exploratory prospects and proven properties. HEP'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 HEP's and, in many
instances, have been engaged in the oil and gas business for a much longer time
than HEP. 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 HEP's financial
or human resources permit. HEP'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. HEP's success will be materially dependent upon
the continued success of its drilling program. HEP's future drilling activities
may not be successful and, if drilling activities are unsuccessful, such failure
will have an adverse effect on HEP'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 HEP 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, HEP 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 HEP will be
successful and, if an acquisition is unsuccessful, that the failure will not
have an adverse effect on HEP's future results of operations and financial
condition.
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 HEP. In addition,
HEP may be liable for environmental damages caused by previous owners of
property purchased or leased by HEP. 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 HEP's properties. While HEP 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, HEP
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 HEP'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. HEP'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 HEP acquires
properties containing proved reserves or conducts successful exploration and
development activities, or both, the proved reserves of HEP 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, HEP'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 HEP's future exploration, development and acquisition
activities will result in additional proved reserves or that HEP will be able to
drill productive wells at acceptable costs. Furthermore, although HEP's revenues
could increase if prevailing prices for oil and gas increase significantly,
HEP'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 HEP'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 HEP, including the extent of domestic and foreign
production, imports of foreign oil, market demand, domestic and worldwide
economic and political conditions, storage capacity 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. HEP anticipates that both oil and gas prices will remain low
throughout 1999. In preparing its 1999 budget, HEP 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 HEP's forecast is accurate.
If prices decrease further, it can be expected that the results of operations
and cash flow will be affected, and HEP's capital budget will decrease.
The following table presents the weighted average prices received per year by
HEP, and the effects of the hedging transactions discussed below.
Oil Oil Gas Gas
(excluding effects (including effects (excluding effects (including effects
of hedging of hedging of hedging of hedging
transactions) transactions) transactions) transactions)
(per bbl) (per bbl) (per mcf) (per mcf)
1998 $12.82 $13.65 $1.99 $2.02
1997 19.35 19.08 2.54 2.31
1996 20.85 20.10 2.38 2.24
As part of its risk management strategy, HEP 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 hedge contracts are recognized as oil or gas
revenue at the time the hedged volumes are sold. During 1998, HEP did not enter
into additional oil price hedges for future years because hedge contracts at
prices HEP considers advantageous are not available.
The financial contracts used by HEP to hedge the price of its oil and natural
gas production are swaps, collars and participating hedges. Under the swap
contracts, HEP 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, HEP was a party to 26 financial contracts with three different
counterparties.
The following table provides a summary of HEP's financial contracts.
Oil
Percent of
Production Contract
Period Hedged Floor Price
(per bbl)
1999 2% $14.88
All of the oil volumes hedged are subject to a participating hedge whereby HEP
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 HEP 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
Production Contract
Period Hedged Floor Price
(per mcf)
1999 45% $2.02
2000 42% $2.07
2001 38% $2.04
2002 30% $2.09
Between 15% and 25% of the gas volumes hedged in each year are subject to a
collar agreement whereby HEP will receive the contract price if the spot price
is lower than the contract price, the cap price is 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 $2.63 per mcf to $2.80 per mcf.
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 mcf not hedged) was approximately $1.65 per
mcf.
Inflation
Inflation did not have a material impact on HEP 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 HEP's revenue, expense and
earnings for discussion purposes. Significant fluctuations are discussed in the
accompanying narrative. The "direct owned" column represents HEP's direct
royalty and working interests in oil and gas properties. The "Mays" column
represents the results of operations of six May Limited Partnerships which are
consolidated with HEP. In 1998, HEP owned interests which ranged from 54.8% to
69.1% of the Mays; in 1997 HEP's ownership in the Mays ranged from 54.7% to
68.7%, and in 1996 HEP's ownership in the Mays ranged from 54.5% to 68.5%.
TABLE OF HEP 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 Mays Total Owned Mays Total
Gas production (mcf) 12,893 1,144 14,037 10,426 1,348 11,774
Oil production (bbl) 735 52 787 691 79 770
Average gas price $ 1.99 $ 2.38 $ 2.02 $ 2.23 $ 2.91 $ 2.31
Average oil price $ 13.69 $ 13.04 $ 13.65 $ 18.94 $ 20.27 $ 19.08
Gas revenue $ 25,643 $2,723 $ 28,366 $23,302 $3,918 $27,220
Oil revenue 10,063 678 10,741 13,089 1,601 14,690
Pipeline and other revenue 4,070 4,070 2,797 2,797
Interest income 346 63 409 324 72 396
-------- ------- -------- -------- ------- --------
Total revenue 40,122 3,464 43,586 39,512 5,591 45,103
------- ----- ------- ------ ----- ------
Production operating 11,740 435 12,175 10,498 562 11,060
Facilities operating 498 498 641 641
General and administrative 4,671 374 5,045 4,953 380 5,333
Depreciation, depletion, and amortization 14,500 1,220 15,720 10,630 1,331 11,961
Impairment of oil and gas properties 14,000 14,000
Interest 2,797 2,797 3,096 3,096
Equity in (income) loss of HCRC 4,888 4,888 (1,348) (1,348)
Minority interest 976 976 1,797 1,797
Litigation 1,382 1,382 (234) (6) (240)
-------- --------- -------- ------- ------- --------
Total expense 54,476 3,005 57,481 28,236 4,064 32,300
------- ----- ------- ------ ----- ------
Net income (loss) $(14,354) $ 459 $(13,895) $11,276 $1,527 $12,803
====== ======= ====== ====== ===== ======
TABLE OF HEP EARNINGS FOR MANAGEMENT DISCUSSION
(In thousands except price)
For the Year Ended December 31, 1996
Direct
Owned Mays Total
Gas production (mcf) 11,003 1,783 12,786
Oil production (bbl) 862 110 972
Average gas price $ 2.11 $ 3.05 $ 2.24
Average oil price $ 19.92 $ 21.52 $ 20.10
Gas revenue $23,178 $ 5,440 $28,618
Oil revenue 17,167 2,367 19,534
Pipeline and other revenue 2,492 2,492
Interest income 356 66 422
------- ------- -------
Total revenue 43,193 7,873 51,066
------ ----- ------
Production operating 10,782 729 11,511
Facilities operating 726 726
General and administrative 4,131 409 4,540
Depreciation, depletion, and amortization 11,729 1,771 13,500
Interest 3,878 3,878
Equity in income of HCRC (1,768) (1,768)
Minority interest 2,723 2,723
Litigation 223 7 230
------- ------- -------
Total expense 29,701 5,639 35,340
------ ----- ------
Net income $13,492 $2,234 $15,726
====== ===== ======
1998 Compared to 1997
Gas Revenue
Gas revenue increased $1,146,000 during 1998 compared with 1997. The increase is
comprised of an increase in gas production from 11,774,000 mcf during 1997 to
14,037,000 mcf during 1998, partially offset by a decrease in the average gas
price from $2.31 per mcf in 1997 to $2.02 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 HEP's hedging transactions as described under "Inflation and
Changing Prices" was to increase HEP's average gas price from $1.99 per mcf to
$2.02 per mcf, representing a $421,000 increase in gas revenues for 1998.
Oil Revenue
Oil revenue decreased $3,949,000 during 1998 compared with 1997. The decrease is
comprised of a decrease in the average oil price from $19.08 per barrel in 1997
to $13.65 per barrel in 1998, partially offset by an increase in production,
from 770,000 barrels in 1997 to 787,000 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. The production increase was partially offset by
normal production declines.
The effect of HEP's hedging transactions was to increase HEP's average oil price
from $12.82 per barrel to $13.65 per barrel, resulting in a $653,000 increase in
oil revenue for 1998.
Pipeline and Other
Pipeline and other revenue consists primarily of facilities income from two
gathering systems located in New Mexico, revenues derived from salt water
disposal and incentive payments related to certain wells in San Juan County, New
Mexico. Pipeline facilities and other revenue increased $1,273,000 during 1998
compared with 1997 primarily due to an increase in incentive payment income
resulting from HEP's acquisition of a volumetric production payment during May
1998.
Interest Income
The increase in interest income of $13,000 during 1998 compared with 1997
resulted from a higher average cash balance during 1998 compared with 1997.
Production Operating Expense
Production operating expense increased $1,115,000 during 1998 compared with
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.
Facilities Operating Expense
Facilities operating expense represents operating expenses associated with
various smaller gathering systems operating by HEP. The decrease in facilities
operating expense of $143,000 is primarily due to decreased maintenance activity
during 1998 compared with 1997.
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 the operating company on behalf of HEP.
These expenses decreased $288,000 during 1998 compared with 1997 primarily due
to a decrease in performance based compensation during 1998.
Depreciation, Depletion and Amortization Expense
Depreciation, depletion and amortization expense increased $3,759,000 during
1998 compared with 1997. The 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 property
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 $2.00 per mcf of gas, $12.80 per bbl
of oil and $1.90 per mcf of gas and $10.00 per bbl of oil and $1.90 per mcf of
gas, respectively.
Interest Expense
Interest expense decreased $299,000 during 1998 as compared with 1997. The
decrease is due to a lower average outstanding debt balance during 1998 as
compared to 1997.
Equity in Earnings (Loss) of HCRC
Equity in earnings (loss) of HCRC represents HEP's share of its equity
investment in HCRC. HEP's equity in HCRC's earnings decreased $6,236,000 during
1998 as compared to 1997. The decrease is primarily the result of property
impairments recorded by HCRC during 1998.
Minority Interest in Net Income of Affiliates
Minority interest in net income of affiliates represents unaffiliated partners'
interest in the net income of the May Partnerships. The decrease of $821,000 is
due to a decrease in the net income of the May Partnerships resulting primarily
from lower oil and gas prices and decreased production from their properties.
Litigation
Litigation expense during 1998 includes the settlement of the Ellender lawsuit
described in Item 8, Note 14, and the costs related to the Arcadia arbitration
described in Item 8, Note 13. Litigation income during 1997 is comprised of
insurance proceeds which reimbursed a portion of expense incurred in a prior
period to settle certain litigation.
1997 Compared to 1996
Gas Revenue
Gas revenue decreased by $1,398,000 during 1997 as compared with 1996. The
decrease is comprised of a decrease in gas production from 12,786,000 mcf during
1996 to 11,774,000 mcf during 1997, partially offset by an increase in the
average gas price from $2.24 per mcf in 1996 to $2.31 per 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 HEP's hedging transactions as described under "Inflation and
Changing Prices" was to decrease HEP's average gas price from $2.54 per mcf to
$2.31 per mcf, representing a $2,708,000 decrease in gas revenues for 1997.
Oil Revenue
Oil revenue decreased $4,844,000 during 1997 as compared with 1996. The decrease
is comprised of a decrease in the average oil price from $20.10 per barrel in
1996 to $19.08 per barrel in 1997, and a decrease in production, from 972,000
barrels in 1996 to 770,000 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 HEP's hedging transactions described under "Inflation and Changing
Prices" was to decrease HEP's average oil price from $19.35 per barrel to $19.08
per barrel, resulting in a $208,000 decrease in oil revenue for 1997.
Pipeline and Other
Pipeline and other revenue increased $305,000 during 1997 as compared with 1996
primarily due to increased salt water disposal income.
Interest Income
The decrease in interest income of $26,000 during 1997 as compared with 1996
resulted from a lower average cash balance during 1997 as compared with 1996.
Production Operating Expense
Production operating expense decreased $451,000 during 1997 as compared with
1996, primarily as a result of decreased production taxes due to the 13%
decrease in oil and gas revenue during 1997 discussed above.
Facilities Operating Expense
The decrease in facilities operating expense of $85,000 is primarily due to
decreased maintenance activity during 1997 as compared with 1996.
General and Administrative Expense
General and administrative expense increased $793,000 during 1997 as compared
with 1996 primarily due to an increase in performance based compensation and an
increase in bank fees due to the extension of the term date of HEP's line of
credit during 1997.
Depreciation, Depletion and Amortization Expense
Depreciation, depletion and amortization expense decreased $1,539,000 during
1997 as compared with 1996. The decrease is primarily the result of a lower
depletion rate in 1997 as compared with 1996, due to the 13% decrease in
production discussed above.
Interest Expense
Interest expense decreased $782,000 during 1997 as compared with 1996. The
decrease is due to a lower average outstanding debt balance during 1997 as
compared to 1996.
Equity in Earnings (Loss) of HCRC
HEP's equity in HCRC's earnings (loss) decreased $420,000 during 1997 as
compared to 1996. The decrease is primarily the result of lower oil and gas
revenues during 1997 caused primarily by HCRC's decreased oil and gas
production.
Minority Interest in Net Income of Affiliates
Minority interest in net income of affiliates represents unaffiliated partners'
interest in the net income of the May Partnerships. The decrease of $926,000 is
due to a decrease in the net income of the May Partnerships resulting primarily
from decreased production from their properties.
Litigation
Litigation settlement income during 1997 is comprised of insurance proceeds
which reimbursed a portion of expense incurred in a prior period to settle
certain litigation. Litigation settlement expense during 1996 consists primarily
of expenses incurred to settle various individually insignificant claims against
HEP.
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
HEP's primary market risks relate to changes in interest rates and in the prices
received from sales of oil and natural gas. HEP'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, HEP 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, HEP 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 Partnership's deliverable volumes. HEP 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.
HEP does not use or hold derivative instruments for trading purposes nor does it
use derivative instruments with leveraged features. HEP's derivative instruments
are designated and effective as hedges against its identified risks, and do not
of themselves expose HEP 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 5 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 of the general partner and by senior management. HEP 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 HEP'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) - HEP uses both fixed and variable rate debt
to partially finance operations and capital expenditures. As of December 31,
1998, HEP's debt consists of borrowings under its Credit Agreement which bears
interest at a variable rate. HEP hedges a portion of the risk associated with
this variable rate debt through derivative instruments, which consist of
interest rate swaps and collars. Under the swap contracts, HEP 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 HEP'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 $995,000
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 $520,000 increase in income and cash flows associated with the interest rate
swap and collar agreements that are in effect for 1999.
Commodity Price Risk (non trading) - HEP 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 HEP'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 gas sales or a price that
only fluctuates between a predetermined floor and ceiling. HEP's participating
hedges also enable HEP to receive 25% of any increase in prices over the fixed
prices specified in the contracts. As of March 24, 1999, HEP has entered into
derivative commodity hedges covering an aggregate of 16,000 barrels of oil and
18,308,000 mcf of gas that extend through 2002. Under the these contracts, HEP
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 $3,800,000 during 1999, assuming
that oil and gas production remain at 1998 levels. This loss in income and cash
flows would be offset by a $1,220,000 increase in income and cash flows
associated with the oil and natural gas derivative contracts that are in effect
for 1999.
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page No.
FINANCIAL STATEMENTS:
Independent Auditors' Report 33
Consolidated Balance Sheets at December 31, 1998 and 1997 34-35
Consolidated Statements of Operations for the years ended
December 31, 1998, 1997 and 1996 36
Consolidated Statements of Partners' Capital for the years
ended December 31, 1998, 1997 and 1996 37
Consolidated Statements of Cash Flows for the years ended
December 31, 1998, 1997 and 1996 38
Notes to Consolidated Financial Statements 39-55
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) 56-59
INDEPENDENT AUDITORS' REPORT
To the Partners of Hallwood Energy Partners, L. P.:
We have audited the consolidated financial statements of Hallwood Energy
Partners, L.P. as of December 31, 1998 and 1997 and for each of the three years
in the period ended December 31, 1998, listed in the index at Item 8. These
financial statements are the responsibility of the partnership'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 Energy Partners, L.P. 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
HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31,
1998 1997
CURRENT ASSETS
Cash and cash equivalents $ 11,874 $ 6,622
Accounts receivable:
Oil and gas revenues 5,911 8,772
Trade 4,040 5,069
Due from affiliates 119 588
Prepaid expenses and other current assets 1,338 1,091
Net working capital of affiliate 236
---------- --------
Total 23,518 22,142
-------- --------
PROPERTY, PLANT AND EQUIPMENT, at cost Oil and gas properties (full cost
method):
Proved mineral interests 664,799 624,621
Unproved mineral interests - domestic 2,694 2,315
Furniture, fixtures and other 3,411 3,513
--------- ---------
Total 670,904 630,449
Less accumulated depreciation, depletion,
amortization and property impairment (565,899) (536,118)
------- -------
Total 105,005 94,331
------- --------
OTHER ASSETS
Investment in common stock of HCRC 10,160 15,048
Deferred expenses and other assets 408 82
---------- -----------
Total 10,568 15,130
-------- --------
TOTAL ASSETS $139,091 $131,603
======= =======
<FN>
(Continued on the following page)
</FN>
HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except Units)
December 31,
1998 1997
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 22,921 $ 19,915
Current portion of long-term debt 9,319
Net working capital deficit of affiliate 448
Current portion of contract settlement 2,752
------------- ---------
Total 32,240 23,115
-------- --------
NONCURRENT LIABILITIES
Long-term debt 40,381 34,986
Deferred liability 1,050 1,180
--------- ---------
Total 41,431 36,166
-------- --------
Total liabilities 73,671 59,281
-------- --------
MINORITY INTEREST IN AFFILIATES 2,788 3,258
--------- ---------
COMMITMENTS AND CONTINGENCIES (NOTE 16)
PARTNERS' CAPITAL
Class A Units - 10,011,854 and 9,977,254 Units issued in 1998 and 1997,
respectively; 9,121,612 and 9,077,949
Units outstanding in 1998 and 1997, respectively 44,198 66,184
Class B Subordinated Units - 147,773 Units outstanding
in 1998 and 1997 1,143 1,411
Class C Units - 2,464,063 and 664,063 Units outstanding in
1998 and 1997, respectively 21,386 4,868
General Partner 2,814 3,580
Treasury Units - 890,242 and 899,305 Units in 1998
and 1997, respectively (6,909) (6,979)
--------- ---------
Partners' capital - net 62,632 69,064
-------- --------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $139,091 $131,603
======= =======
<FN>
The accompanying notes are an integral part of the
consolidated financial statements.
</FN>
HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands except per Unit)
For the Year Ended December 31,
1998 1997 1996
REVENUES:
Gas revenue $ 28,366 $ 27,220 $ 28,618
Oil revenue 10,741 14,690 19,534
Pipeline and other 4,070 2,797 2,492
Interest 409 396 422
--------- --------- --------
43,586 45,103 51,066
------- ------- -------
EXPENSES:
Production operating 12,175 11,060 11,511
Facilities operating 498 641 726
General and administrative 5,045 5,333 4,540
Depreciation, depletion and amortization 15,720 11,961 13,500
Impairment of oil and gas properties 14,000
Interest 2,797 3,096 3,878
-------- -------- --------
50,235 32,091 34,155
------- ------- -------
OTHER INCOME (EXPENSES):
Equity in earnings (loss) of HCRC (4,888) 1,348 1,768
Minority interest in net income of affiliates (976) (1,797) (2,723)
Litigation (1,382) 240 (230)
-------- -------- ---------
(7,246) (209) (1,185)
-------- -------- --------
NET INCOME (LOSS) (13,895) 12,803 15,726
CLASS C UNIT DISTRIBUTIONS ($1.00 PER UNIT) 2,464 664 664
-------- ------- -------
NET INCOME (LOSS) ATTRIBUTABLE TO
GENERAL PARTNER, CLASS A AND
CLASS B LIMITED PARTNERS $(16,359) $ 12,139 $ 15,062
======= ======= =======
ALLOCATION OF NET INCOME (LOSS):
General partner $ 886 $ 2,097 $ 2,569
========= ======== ========
Class A and Class B Limited partners $(17,245) $ 10,042 $ 12,493
======= ======= =======
Per Class A Unit and Class B Unit - basic $ (1.86) $ 1.09 $ 1.35
========= ========= =========
Per Class A Unit and Class B Unit - diluted $ (1.86) $ 1.07 $ 1.35
========= ========= =========
Weighted average Class A Units and Class B
Units outstanding 9,258 9,222 9,240
======= ======= =======
<FN>
The accompanying notes are an integral part of the
consolidated financial statements.
</FN>
HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(In thousands)
General Class A Class B Class C Treasury
Partner Units Units Units Units Total
Balance, December 31, 1995 $ 2,981 $ 59,614 $ 1,062 $ (6,085) $ 57,572
Increase in Treasury Units (894) (894)
Syndication costs (12) (12)
Issuance of Class C Units (5,146) $5,146
Distributions (2,243) (5,270) (664) (8,177)
Net income 2,569 12,301 192 664 15,726
------- ------- ------- ------ --------- -------
Balance, December 31, 1996 3,307 61,487 1,254 5,146 (6,979) 64,215
Syndication costs (278) (278)
Distributions (1,824) (5,188) (664) (7,676)
Net income 2,097 9,885 157 664 12,803
------- ------ ------- ------ --------- -------
Balance, December 31, 1997 3,580 66,184 1,411 4,868 (6,979) 69,064
Issuance of Class C Units, net of
syndication costs 16,518 16,518
General Partner contribution 171 171
Exercise of Unit Options 199 199
Decrease in Treasury Units 70 70
Distributions (1,823) (5,208) (2,464) (9,495)
Net income (loss) 886 (16,977) (268) 2,464 (13,895)
-------- ------- -------- ------ ------- -------
Balance, December 31, 1998 $ 2,814 $ 44,198 $ 1,143 $ 21,386 $ (6,909) $ 62,632
======= ======= ======= ======= ======== =======
<FN>
The accompanying notes are an integral part of the
consolidated financial statements.
</FN>
HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the Year Ended December 31,
---------------------------------
1998 1997 1996
------ ------ -----
OPERATING ACTIVITIES:
Net income (loss) $(13,895) $ 12,803 $ 15,726
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Depreciation, depletion and amortization 15,720 11,961 13,500
Impairment of oil and gas properties 14,000
Depreciation charged to affiliates 249 221 265
Asset disposals (188)
Amortization of deferred loan costs and other assets 82 81 167
Noncash interest expense 15 241 219
Minority interest in net income 976 1,797 2,723
Take-or-pay recoupment (130) (126) (376)
Equity in (earnings) loss of HCRC 4,888 (1,348) (1,768)
Undistributed (earnings) loss of affiliates (1,319) 197 (187)
Changes in operating assets and liabilities provided (used) cash net of
noncash activity:
Oil and gas revenues receivable 2,861 633 (2,638)
Trade receivables 1,029 (562) (1,647)
Due from affiliates (362) (2,948) 2,808
Prepaid expenses and other current assets (247) (163) 163
Deferred expenses and other assets (408)
Accounts payable and accrued liabilities 3,006 4,730 (2,159)
Due to affiliates (133) (373)
----------- -------- --------
Net cash provided by operating activities 26,277 27,384 26,423
------ ------ ------
INVESTING ACTIVITIES:
Additions to property, plant and equipment (28,756) (3,233) (3,148)
Exploration and development costs incurred (12,180) (12,983) (9,467)
Proceeds from sales of property, plant and equipment 454 133 5,294
Distributions received from affiliate 1,583
Investment in affiliates (20) (76) (449)
Investment in Spraberry properties (4,715)
Other investing activities (29)
----------- ---------
Net cash used in investing activities (38,919) (16,188) (12,485)
------ ------ ------
FINANCING ACTIVITIES:
Payments of long-term debt (18,286) (7,285) (11,373)
Proceeds from the issuance of Class C Units, net
of syndication costs 16,518
Proceeds from long-term debt 33,000 7,000 9,000
Distributions paid (9,495) (7,676) (8,177)
Distributions paid by consolidated affiliates
to minority interest (1,446) (1,875) (2,429)
Payment of contract settlement (2,767) (305)
Exercise of Unit Options 199
Capital contribution from the general partner 171
Other financing activities (278) (91)
----------- -------- ---------
Net cash provided by (used in) financing activities 17,894 (10,114) (13,375)
------- ------ ------
NET INCREASE IN CASH AND CASH
EQUIVALENTS 5,252 1,082 563
CASH AND CASH EQUIVALENTS:
BEGINNING OF YEAR 6,622 5,540 4,977
------- ------- -------
END OF YEAR $ 11,874 $ 6,622 $ 5,540
======= ======= =======
<FN>
The accompanying notes are an integral part of the
consolidated financial statements.
</FN>
HALLWOOD ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
Hallwood Energy Partners, L.P. ("HEP" or the "Partnership") is a publicly traded
Delaware limited partnership engaged in the development, acquisition and
production of oil and gas properties in the continental United States. HEP's
objective is to provide its partners with an attractive return through a
combination of cash distributions and capital appreciation. To achieve its
objective, HEP utilizes operating cash flow, first, to reinvest in operations to
maintain its reserve base and production; second to make stable cash
distributions to Unitholders; and third, to grow HEP's reserve base over time.
HEP's future growth will be driven by a combination of development of existing
projects, exploration for new reserves and select acquisitions. HEPGP Ltd.
became the general partner of HEP on November 26, 1996 after its former general
partner, Hallwood Energy Corporation ("HEC") merged into The Hallwood Group
Incorporated ("Hallwood Group"). HEPGP Ltd. is a limited partnership of which
Hallwood Group is the limited partner and Hallwood G.P., Inc. ("Hallwood G.P."),
a wholly owned subsidiary of Hallwood Group, is the general partner. HEP
commenced operations in August 1985 after completing an exchange offer in which
HEP acquired oil and gas properties and operations from HEC, 24 oil and gas
limited partnerships of which HEC was the general partner, and certain working
interest owners that had participated in wells with HEC and the limited
partnerships.
The activities of HEP are conducted through HEP Operating Partners, L.P.
("HEPO") and EDP Operating, Ltd. ("EDPO"). HEP is the sole limited partner and
HEPGP Ltd. is the sole general partner of HEPO and EDPO. Solely for purposes of
simplicity herein, unless otherwise indicated, all references to HEP in
connection with the ownership, exploration, development or production of oil and
gas properties include HEPO and EDPO.
Accounting Policies
Consolidation
HEP fully consolidates entities in which it owns a greater than 50% equity
interest and reflects a minority interest in the consolidated financial
statements. HEP accounts for its interest in 50% or less owned affiliated oil
and gas partnerships and limited liability companies using the proportionate
consolidation method of accounting. HEP's investment in approximately 46% of the
common stock of its affiliate, Hallwood Consolidated Resources Corporation
("HCRC"), is accounted for under the equity method.
The accompanying financial statements include the activities of HEP, its
subsidiaries, Hallwood Petroleum, Inc. ("HPI") and Hallwood Oil and Gas, Inc.
("Hallwood Oil") and majority owned affiliates, the May Limited Partnerships
1983-1, 1983-2, 1983-3, 1984-1, 1984-2, 1984-3 ("Mays").
Derivatives
As of March 24, 1999, HEP was a party to 26 financial contracts to hedge the
price of its oil and natural gas. The purpose of the hedges is to provide
protection against price decreases and to provide a measure of stability in the
volatile environment of oil and natural gas spot pricing. The amounts received
or paid upon settlement of these contracts are recognized as oil or gas revenue
at the time the hedged volumes are sold.
As of March 24 1999, HEP was a party to six financial contracts to hedge the
interest payments under its Credit Agreement. The purpose of the hedges is the
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
HEP uses the sales method for recording its gas balancing. Under this method,
HEP recognizes revenue on all of its sales of production, and any
over-production or under-production is recovered at a future date.
As of December 31, 1998, HEP had a net over-produced position of 157,000 mcf
($298,000 valued at year-end gas prices). The general partner believes that this
imbalance can be made up with production on existing wells or from wells which
will be drilled as offsets to existing wells and that this imbalance will not
have a material effect on HEP's results of operations, liquidity and capital
resources. HEP's oil and gas reserves as of December 31, 1998 have been
decreased by 157,000 mcf in order to reflect HEP's gas balancing position.
Allocations
Partnership costs and revenues are allocated to Class A and Class B Unitholders
and the general partner pursuant to the partnership agreement as set forth
below.
Unitholders General Partner
Property Costs and Revenues
Initial acquisition costs -
Acreage other than exploratory 100% 0%
Exploratory acreage 98% 2%
Producing wells -
Costs and revenues 98% 2%
Development wells (1) -
Costs through completion 100% 0%
All other costs and revenues 95% 5%
Exploratory wells (1) -
Costs through completion 90% 10%
All other costs and revenues 75% 25%
All other costs and revenues 98% 2%
(1) These percentages are for wells drilled under the EDPO partnership
agreement. The majority of wells drilled under the HEPO partnership
agreement share costs through completion in a ratio of 7.5% to the
general partner and 92.5% to the Unitholders and share all other costs
and revenues in a ratio of 18.75% to the general partner and 81.25% to
the Unitholders.
Property, Plant and Equipment
HEP 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 current 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
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 $2.00 per mcf of gas, $12.80 per barrel of oil and $1.90 per mcf of gas
and $10.00 per barrel of oil and $1.90 per mcf of gas, respectively, HEP
recorded oil and gas property impairments totaling $14,000,000.
HEP does not accrue costs for future site restoration, dismantlement and
abandonment costs related to proved oil and gas properties because the
Partnership estimates that such costs will be offset by the salvage value of the
equipment sold upon abandonment of such properties. The Partnership'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. The 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, HEP has not recognized any impairment losses on long-lived
assets other than oil and gas properties.
Deferred Liability
The deferred liability as of December 31, 1998 and 1997 consists primarily of
HEP's share of the unrecouped portion of a 1989 take-or-pay settlement, which is
recoupable in gas volumes.
Distributions
HEP paid a $.13 per Class A Unit and a $.25 per Class C Unit distribution on
February 12, 1999 to Unitholders of record on December 31, 1998. This amount and
the general partner distribution were accrued as of year end. At December 31,
1998 and 1997, distributions payable of $2,423,000 and $2,093,000, respectively
were included in accounts payable and accrued liabilities. HEP declared
distributions of $.52 per Class A Unit and $1.00 per Class C Unit for 1998, 1997
and 1996.
Income Taxes
No provision for federal income taxes is included in HEP's financial statements
because, as a partnership, it is not subject to federal income tax and the tax
effects of its activities accrue to the partners. In certain circumstances,
partnerships may be held to be associations taxable as corporations. The
Internal Revenue Service has issued regulations specifying circumstances under
current law when such a finding may be made, and management has obtained an
opinion of counsel based on those regulations that HEP is not an association
taxable as a corporation. A finding that HEP is an association taxable as a
corporation could have a material adverse effect on the financial position, cash
flows and results of operations of HEP.
As a result of differences between the accounting treatment of certain items for
income tax purposes and financial reporting purposes, primarily depreciation,
depletion and amortization of oil and gas properties and the recognition of
intangible drilling costs as an expense or capital item, the income tax basis of
oil and gas properties differs from the basis used for financial reporting
purposes. At December 31, 1998 and 1997, the income tax bases of the
Partnership's oil and gas properties were approximately $94,100,000 and
$94,000,000, respectively.
Cash and Cash Equivalents
All highly liquid investments purchased with an original maturity of three
months or less are considered to be cash equivalents.
Computation of Net Income Per Unit
Basic income (loss) per Class A and Class B Unit is computed by dividing net
income (loss) attributable to the Class A and Class B limited partners' interest
(net income excluding income (loss) attributable to the general partner and
Class C Units) by the weighted average number of Class A Units and Class B Units
outstanding during the periods. Diluted income per Class A and Class B Unit
includes the potential dilution that could occur upon exercise of the options to
acquire Class A Units described in Note 10, computed using the treasury stock
method which assumes that the increase in the number of Units is reduced by the
number of Units which could have been repurchased by the Partnership with the
proceeds from the exercise of the options (which were assumed to have been made
at the average market price of the Class A Units during the reporting period).
Unit options have been ignored in the computation of diluted loss per share in
1998 because their inclusion would be anti-dilutive.
The following table reconciles the number of Units outstanding used in the
calculation of basic and diluted income (loss) per Class A and Class B Unit.
Income
(Loss) Units Per Unit
(In thousands except per Unit)
For the Year Ended December 31, 1998
Net loss per Class A Unit and Class B Unit - basic $(17,245) 9,258 $(1.86)
------ ----- =====
Net Loss per Class A Unit and Class B Unit - diluted $(17,245) 9,258 $(1.86)
====== ===== =====
For the Year Ended December 31, 1997
Net income per Class A Unit and Class B Unit - basic $ 10,042 9,222 $ 1.09
=====
Effect of Unit Options 137
------------ ------
Net Income per Class A Unit and Class B Unit - diluted $ 10,042 9,359 $ 1.07
======= ===== =====
For the Year Ended December 31, 1996
Net income per Class A Unit and Class B Unit - basic $ 12,493 9,240 $ 1.35
=====
Effect of Unit Options 13
------------- -------
Net Income per Class A Unit and Class B Unit - diluted $ 12,493 9,253 $ 1.35
======= ===== =====
Treasury Units
HEP owns approximately 46% of the outstanding common stock of HCRC, while HCRC
owns approximately 19% of HEP's Class A Units. Consequently, HEP has an interest
in 890,242 and 899,305 of its own Units at December 31, 1998 and 1997,
respectively. The Units are treated as Treasury Units in the accompanying
financial statements.
Use of Estimates
The preparation of the financial statements for the Partnership in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from these estimates.
Significant Customers
Although the Partnership sells the majority of its oil and gas production to a
few purchasers, there are numerous other purchasers in the area in which HEP
sells its production; therefore, the loss of its significant customers would not
adversely affect HEP's operations. 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 Partnership:
1998 1997 1996
---- ---- ----
Conoco Inc. 23% 20% 28%
El Paso Field Services Company 11% 11%
Marathon Petroleum Company 16% 11%
Environmental Concerns
HEP 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, HEP 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 HEP in the oil and gas
industry.
Recently Issued Accounting Pronouncements
In June 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 130 "Reporting Comprehensive Income" (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 Partnership adopted SFAS 130 on January 1, 1998. The Partnership 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 periods.
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. HEP adopted FAS 131 in 1998.
The Partnership 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. In addition, the Partnership's
activities exhibit similar economic characteristics and involve the same
products, production processes, class of customers, and methods of distribution.
Management of the Partnership evaluates its performance as a whole rather than
by product or geographically. As a result, HEP'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 Partnership is required to
adopt SFAS 133 on January 1, 2000. The Partnership 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.
NOTE 2 - OIL AND GAS PROPERTIES
The following table summarizes cost information related to HEP's oil and gas
activities:
For the Year Ended December 31,
1998 1997 1996
(In thousands)
Property acquisition costs:
Proved $28,397 $ 1,942 $ 2,321
Unproved 379 1,071 560
Development costs 8,087 7,607 8,218
Exploration costs 6,043 6,950 2,200
------- ------- -------
Total $42,906 $17,570 $13,299
====== ====== ======
Depreciation, depletion, amortization and impairment expense related to proved
oil and gas properties per equivalent mcf of production for the years ended
December 31, 1998, 1997 and 1996, was $1.57, $.73 and $.73, respectively.
At December 31, unproved properties consist of the following:
1998 1997
---- ----
(In thousands)
Texas $1,857 $ 982
North Dakota 499 314
California 447
Other 338 572
------ ------
$2,694 $2,315
===== =====
NOTE 3 - PRINCIPAL ACQUISITIONS AND SALES
As a result of the arbitration discussed in Note 13, HEP 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, HEP and its affiliate, HCRC, 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 HEP and HCRC purchased the volumetric production payment from
the affiliate of Enron Corp. HEP funded its $17,257,000 share of the acquisition
price from operating cash flow and borrowings under its Credit Agreement.
During 1997, HEP had no individually significant property acquisitions or sales.
NOTE 4 - CLASS C UNIT ISSUANCE
On February 17, 1998, HEP closed its public offering of 1.8 million Class C
Units, priced at $10.00 per Unit. Proceeds to HEP, net of underwriting expenses,
were approximately $16,518,000. HEP used $14,000,000 of the net proceeds to
repay borrowings under its Credit Agreement and applied the remaining proceeds
toward the repayment of HEP's outstanding contract settlement obligation at
December 31, 1997 of $2,752,000.
NOTE 5 - DERIVATIVES
As part of its risk management strategy, HEP enters into financial contracts to
hedge the price of its oil and natural gas. HEP 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 HEP to hedge the price of its oil and natural
gas production are swaps, collars and participating hedges. Under the swap
contracts, HEP 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, HEP was a party to 26 financial contracts with three different
counterparties.
The following table provides a summary of HEP's financial contracts:
Oil
Quantity of Production
Period Hedged Contract Floor Price
(bbls) (per bbl)
1996 300,000 $18.33
1997 346,000 17.78
1998 175,000 16.62
1999 16,000 14.88
All of the oil volumes hedged in 1999 are subject to a participating hedge
whereby HEP 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 HEP 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
Quantity of Production
Period Hedged Contract Floor Price
(mcf) (per mcf)
1996 5,479,000 $1.94
1997 5,386,000 1.97
1998 7,101,000 2.09
1999 6,655,000 2.02
2000 5,037,000 2.07
2001 3,892,000 2.04
2002 2,724,000 2.09
From 1999 forward, between 15% and 25% of the gas volumes hedged in each year
are subject to a collar agreement whereby HEP will receive the contract price if
the spot price is lower than the contract price, the cap price if the spot price
is higher than the cap price, and the spot price if that price is between the
contract price and the cap price. The cap price ranges from $2.63 per mcf to
$2.80 per mcf.
In the event of nonperformance by the counterparties to the financial contracts,
HEP is exposed to credit loss, but has no off-balance sheet risk of accounting
loss. The Partnership 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 HEP's hedges are secured by the lien on
HEP's oil and gas properties which also secures HEP's Credit Agreement described
in Note 7.
NOTE 6 - INVESTMENT IN AFFILIATED CORPORATION
HEP accounts for its approximate 46% interest in HCRC using the equity method of
accounting. The following presents summarized financial information for HCRC at
December 31, 1998, 1997 and 1996.
1998 1997 1996
---- ---- ----
(In thousands)
Current assets $12,566 $15,145 $10,802
Noncurrent assets 88,601 77,226 67,666
Current liabilities 18,262 11,007 10,849
Noncurrent liabilities 53,316 32,678 24,558
Revenue 32,410 32,411 34,445
Net income (loss) (20,279) 5,585 8,210
No other individual entity in which HEP owns an interest comprises in excess of
10% of the revenues, net income or assets of HEP.
HCRC repurchased approximately 99,000 and 78,000 shares of its common stock in
odd lot repurchase offers which were completed January 26, 1996 and May 3, 1996,
respectively. HCRC resold 38,895 of these shares to HEP at the price paid by
HCRC for such shares. As a result of these transactions, HEP's ownership in HCRC
increased from 40% to 46% at the end of May 1996.
The following amounts represent HEP's share of the property related costs and
reserve quantities and values of its equity investee HCRC (in thousands):
Capitalized Costs Relating to Oil and Gas Activities:
As of December 31,
1998 1997 1996
Unproved properties $ 1,286 $ 1,040 $ 573
Proved properties 147,600 118,966 113,085
Accumulated depreciation, depletion,
amortization and property impairment (100,890) (92,511) (89,175)
------- ------- -------
Net property $ 47,996 $ 27,495 $ 24,483
======= ======= =======
Costs Incurred in Oil and Gas Activities:
For the Year Ended of December 31,
1998 1997 1996
Acquisition costs $ 12,879 $ 1,303 $ 1,008
Development costs 2,636 2,060 3,670
Exploration costs 2,606 2,851 382
-------- ------ -------
Total $ 18,121 $ 6,214 $ 5,060
======= ====== ======
For the Year Ended December 31,
1998 1997 1996
Oil and gas revenue $ 10,372 $10,889 $11,690
Production operating expense (4,272) (3,746) (3,790)
Depreciation, depletion, amortization
and property impairment expense (13,773) (3,336) (3,257)
Income tax benefit (expense) (761) 23
------------ -------- ---------
Net income (loss) from oil and gas activities $ (7,673) $ 3,046 $ 4,666
======== ======= =======
Proved Oil and Gas Reserve Quantities:
Gas Oil
Mcf Bbl
(unaudited)
Balance, December 31, 1998 32,000 1,470
====== =====
Balance, December 31, 1997 27,268 2,065
====== =====
Balance, December 31, 1996 22,786 2,680
====== =====
Standardized Measure of Discounted Future Net Cash Flows:
(unaudited)
December 31, 1998 $30,134
======
December 31, 1997 $31,245
======
December 31, 1996 $47,701
======
NOTE 7 - DEBT
HEP's long-term debt at December 31, 1998 and 1997 consists of the following:
1998 1997
---- ----
(In thousands)
Credit Agreement $49,700 $30,700
Note Purchase Agreement 4,286
------------ -------
Total 49,700 34,986
Less current maturities 9,319
-------
Long-term debt $40,381 $34,986
====== ======
During the first quarter of 1997, HEP and its lenders amended HEP's Second
Amended and Restated Credit Agreement (as amended, the "Credit Agreement") to
extend the term date of its Credit Agreement to May 31, 1999. The lenders are
Morgan Guaranty Trust Company, First Union National Bank and NationsBank of
Texas. Under the Credit Agreement HEP has a borrowing base of $62,000,000. HEP
had amounts outstanding at December 31, 1998 of $49,700,000. HEP's unused
borrowing base totaled $12,300,000 at March 24, 1999.
Borrowings against the Credit Agreement bear interest at the lower of the
Certificate of Deposit rate plus from 1.375% to 1.875%, prime plus 1/2% or the
Euro-Dollar rate plus from 1.25% to 1.75%. At December 31, 1998, the applicable
interest rate was 7.125%. Interest is payable monthly, and quarterly principal
payments of $3,106,500 commence May 31, 1999.
The borrowing base for the Credit Agreement is redetermined semiannually. The
Credit Agreement is secured by a first lien on approximately 80% in value of
HEP's oil and gas properties. Additionally, aggregate distributions which may be
paid by HEP in any 12 month period are limited to 50% of cash flow from
operations before working capital changes and distributions received from
affiliates, if the principal amount of debt of HEP is 50% or more of the
borrowing base. Aggregate distributions which may be paid by HEP are limited to
65% of cash flow from operations before working capital changes and 65% of
distributions which may be received from affiliates, if the principal amount of
debt is less than 50% of the borrowing base.
At December 31, 1998, HEP's debt maturity schedule is as follows.
(In thousands)
1999 $ 9,319
2000 12,425
2001 12,425
2002 12,425
2003 3,106
-------
Total $49,700
As part of its risk management strategy, HEP enters into financial contracts to
hedge the interest rate payments under its Credit Agreement. HEP 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, HEP
was a party to six contracts with three different counterparties.
The following table provides a summary of HEP's financial contracts.
Average
Amount of Contract
Period Debt Hedged Floor Rate
1996 $10,000,000 6.65%
1997 15,000,000 6.56%
1998 15,000,000 6.84%
1999 27,000,000 5.70%
2000 30,000,000 5.65%
2001 24,000,000 5.23%
2002 25,000,000 5.23%
2003 25,000,000 5.23%
2004 4,000,000 5.23%
NOTE 8 - CONTRACT SETTLEMENT OBLIGATION
In the first quarter of 1989, HEP settled a take-or-pay contract claim on its
Bethany-Longstreet field. In accordance with the settlement, HEP received
$7,623,000 in cash. This amount was recoupable in cash or gas volumes from April
1992 through March 1996, with a cash balloon payment due during the first
quarter of 1998. A liability was recorded equal to the present value of this
amount discounted at 10.68%, HEP's estimated borrowing rate at the time of
settlement. At December 31, 1997, the current contract settlement balance
consisted of a payment of $2,767,000 net of unaccreted discount of $15,000,
which was paid during February 1998.
NOTE 9 - PARTNERS' CAPITAL
HEP Units that trade on the American Stock Exchange under the symbol "HEP" are
referred to as "Class A Units," and Units that trade under the symbol "HEPC" are
referred to as "Class C Units."
Class B Subordinated Units
The Class B Units have equal liquidation rights and identical tax allocation
rights and provisions to the Class A Units. However, the Class B Units have the
following subordinated distribution provisions:
1. Distribution rights equal to Class A Units while the Class A Units
receive distributions of $.20 or more per Class A Unit per calendar
quarter.
2. No current distribution right should Class A Units receive distributions
less than $.20 per Class A Unit for any calendar quarter.
3. An accumulated distribution deficit account is maintained for the benefit
of the Class B Units for any distributions suspended under 2 above. The
amount in the deficit account is payable in whole or in part to the Class B
Unitholders in any quarter in which distributions are equal to or greater
than $.20 per Class A Unit.
The Class B Units may be converted into Class A Units on a 1:1 ratio at the
option of the holder or holders thereof. Upon conversion, any amount remaining
unpaid in the accumulated distribution deficit account relating to Class B Units
converted is waived.
The Class B Units vote as a separate class on all matters required or otherwise
brought for a vote of the Unitholders of HEP.
Class C Units
The Class C Units were issued on January 19, 1996 to Class A Unitholders in the
ratio of one Class C Unit for every 15 Class A Units outstanding. In connection
with the issuance of the Class C Units, HEP transferred $5,146,000 of partners
capital from the Class A Unitholders to the Class C Unitholders based on the
initial trading price of the Class C Units.
The Class C Units have a distribution preference of $1.00 per year, payable
quarterly, commencing in the first quarter of 1996. HEP may not declare or make
any cash distributions on the Class A or Class B Units unless all accrued and
unpaid distributions on the Class C Units have been paid.
Class C Units vote as a separate class on all matters submitted to the
Unitholders of HEP for a vote.
Rights Plan
On February 6, 1995 the Board of Directors of the general partner approved the
adoption of a rights plan designed to protect Unitholders in the event of a
takeover action that would otherwise deny them the full value of their
investment. Under the terms of the rights plan, one right was distributed for
each Class A Unit of HEP to holders of record at the close of business on
February 17, 1995. The rights trade with the Class A Units. The rights will
become exercisable only in the event, with certain exceptions, that an acquiring
party accumulates 15% or more of HEP's Class A Units, or if a party announces an
offer to acquire 30% or more of HEP. The rights will expire on February 6, 2005.
In addition, upon the occurrence of certain events, holders of the rights will
be entitled to purchase, for $24, either HEP Class A Units or shares in an
"acquiring entity," with a market value at that time of $48.
HEP will generally be entitled to redeem the rights at one cent per right at any
time until the tenth day following the acquisition of a 15% position in its
Units.
NOTE 10 - EMPLOYEE INCENTIVE PLANS
Every year beginning in 1992, the Board of Directors of the general partner has
adopted an incentive plan. Each year the Board of Directors determines the
percentage of HEP'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 2.40% for 1997 and 1996.
The specified percentage of cash flow is then allocated among certain key
employees who are participants in the Plan for that year. Each award under the
plan (with regard to domestic properties) represents the right to receive for
five years a portion of the specified share of the cash award, at the conclusion
of which 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 $125,000 in 1998, $277,000 in 1997 and
$148,000 in 1996 and are included in general and administrative expense in the
accompanying financial statements.
On January 31, 1995, the Board of Directors of the general partner approved the
adoption of the Class A Unit Option Plan to be used for the motivation and
retention of directors, employees and consultants performing services for HEP.
The plan authorizes the issuance of options to purchase 425,000 Class A Units.
Grants of the total options authorized were made on January 31, 1995, vesting
one-third at that time, an additional one-third on January 31, 1996 and the
remaining one-third on January 31, 1997. The exercise price of the options is
$5.75, which was the closing price of the Class A Units on January 30, 1995.
On May 5, 1998, HEP granted options to purchase 25,500 Class A Units at an
exercise price of $6.625 per Unit, which was equal to the fair market value of
the Units 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 HEP's 1995 Class A Unit Option Plan. One-third of the options vested on
the date of grant, 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.
During the second quarter of 1998, HEP adopted a Class C Unit Option Plan
covering 120,000 Class C Units. Options to purchase all of the Units were
granted effective May 5, 1998 at an exercise price of $10.00 per Unit, which was
equal to the fair market value of the Units on the date of grant. One-half of
the options vested on the date of grant, and the remainder vest on the first
anniversary of the date of grant.
A summary of options granted to purchase Class A Units and the changes therein
during the years ended December 31, 1998, 1997, and 1996 is presented below:
1998 1997 1996
------ ------ -----
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Units Price Units Price Units Price
Outstanding at beginning
of year 425,000 $ 5.75 425,000 $5.75 425,000 $5.75
Granted 25,500 6.625
Exercised (34,600) 5.75
------- ------ ------------- -------- -------------
Outstanding at end of year 415,900 $ 5.80 425,000 $5.75 425,000 $5.75
======= ====== ======= ==== ======= ====
Options exercisable at year end 398,900 $ 5.80 425,000 $5.75 283,330 $5.75
======= ====== ======= ==== ======= ====
A summary of options granted under the Class C Unit Option Plan and the
changes therein during the year ended December 31, 1998 is presented below:
Weighted
Average
Exercise
Units Price
Outstanding at beginning of year -- $ --
Granted 120,000 10.00
------- -----
Outstanding at end of year 120,000 $10.00
======= =====
Options exercisable at year end 60,000 $10.00
======== =====
The Partnership 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 to purchase Class A and Class C Units. Had
compensation expense for options granted been determined based on the fair value
at the grant date for the options, consistent with the provisions of SFAS 123,
HEP's net income (loss) and net income (loss) per Unit would have been reduced
to the pro forma amounts indicated below:
1998 1997 1996
------ ------ -----
Net income (loss): as reported $(13,895,000) $12,803,000 $15,726,000
pro forma (14,022,000) 12,730,000 15,544,000
Net income (loss) per Class A and B Unit - basic:
as reported $(1.86) $1.09 $1.35
pro forma $(1.88) $1.08 $1.33
Net income (loss) per Class A and B Unit - diluted:
as reported $(1.86) $1.07 $1.35
pro forma $(1.88) $1.07 $1.33
The fair value of the Unit options for disclosure purposes was estimated on the
date of the grant using the Binomial Option Pricing Model with the following
assumptions:
1995 Class A 1998 Class A 1998 Class C
Option Plan Options Option Plan
Expected dividend yield 6% 8% 11%
Expected price volatility 28% 27% 29%
Risk-free interest rate 7.6% 6.4% 6.4%
Expected life of options 10 years 10 years 10 years
NOTE 11 - RELATED PARTY TRANSACTIONS
HPI manages and operates certain oil and gas properties on behalf of independent
joint interest owners, HEP and its affiliates. In such capacity, HPI pays all
costs and expenses of operations and distributes all revenues associated with
such properties. HPI has receivables from affiliates of HEP of $119,000 and
$588,000 at December 31, 1998 and 1997, respectively, which represent net
revenues net of operating costs and expenses. The intercompany balances are
settled monthly. During 1998, HEPGP had a payable balance to HPI which ranged
from $182,000 to $729,000.
HPI is reimbursed by HEP for 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 lease operating and general
and administrative expenses necessary to conduct the business of HEP
(nontechnical expenditures which are expensed as general and administrative or
production operating expenses). Reimbursements during 1998, 1997, and 1996 were
as follows:
1998 1997 1996
---- ---- ----
(In thousands)
Technical $1,398 $966 $1,249
Nontechnical 924 896 1,110
Included in the nontechnical allocation attributable to HEP's direct interest
for 1998, 1997 and 1996 is approximately $274,000, $275,000, and $152,000,
respectively, of consulting fees under a consulting agreement with Hallwood
Group. Also included in the nontechnical allocation is $317,000, $301,000 and
$309,000 in 1998, 1997 and 1996, respectively, representing costs incurred by
Hallwood Group and its affiliates on behalf of the Partnership.
During the third quarter of 1994, HPI entered into a consulting agreement with
its Chairman of the Board to provide advisory services regarding the activities
of its affiliates. The agreement was terminated effective December 1996. The
amount of consulting fees allocated to the Partnership under this agreement was
$125,000 in 1996.
NOTE 12 - STATEMENT OF CASH FLOWS
Cash paid during 1998, 1997 and 1996 for interest totaled $2,700,000, $2,775,000
and $3,492,000, respectively.
NOTE 13 - ARBITRATION
In connection with the Demand for Arbitration filed by Arcadia Exploration and
Production Company ("Arcadia") with the American Arbitration Association against
Hallwood Energy Partners, L.P., Hallwood Consolidated Resources Corporation,
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 Partnership has accrued $452,000 in its financial statements as of
December 31, 1998 in connection with this dispute.
In October 1998, HEP and its affiliate, HCRC, 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. HEP's share of the purchase price was
$8,200,000.
NOTE 14 - LITIGATION SETTLEMENTS
Concise Oil and Gas Partnership ("Concise"), a wholly owned subsidiary of the
Partnership, was a defendant in a lawsuit styled Dr. Allen J. Ellender, Jr. et
al. vs. Goldking Production Company, et al., filed in the Thirty-Second Judicial
District Court, Terrebonne Parish, Louisiana on May 30, 1996. The portion of the
lawsuit against Concise was settled in consideration of the payment by Concise
of $600,000. This amount was recorded as litigation settlement expense in the
second quarter of 1998. Concise has been dismissed with prejudice from the
lawsuit.
In June 1996, HEP and the other parties to the lawsuits styled Lamson Petroleum
Corporation v. Hallwood Petroleum, Inc. et al. settled the lawsuits. The
plaintiffs in the lawsuits claimed they had valid leases covering streets and
roads in the units of the A. L. Boudreaux #1 well, G. S. Boudreaux #1 well, Paul
Castille #1 well, Evangeline Shrine Club #1 well and Duhon #1 well, which
represented approximately .4% to 2.3% of HEP's interest in these properties, and
they were entitled to a portion of the production from the wells dating from
February 1990. In the settlement, HEP and the plaintiffs agreed to cross-convey
interests in certain leases to one another, and HEP agreed to pay the plaintiffs
$728,000. HEP had not recognized revenue attributable to the contested leases
since January 1993. These revenues plus accrued interest, totaling $506,000, had
been placed in escrow pending the resolution of the lawsuits. The excess of the
cash paid over the escrowed amounts is reflected as litigation settlement
expense in the accompanying financial statements. The cross-conveyance of the
interests in the leases resulted in a decrease in HEP's reserves of $374,000 in
future net revenues, discounted at 10% based on oil and gas prices in effect as
of December 31, 1996.
NOTE 15 - COMMITMENTS
HPI currently leases office facilities under an operating lease which 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. The lease payments are included in the allocation of general and
administrative expenses to HEP and other affiliated entities. HEP is guarantor
of 60% of the lease obligation, and HCRC is guarantor of the remaining 40% of
the obligation. Rent expense under these leases is allocated to HEP and its
affiliates. Remaining commitments under these leases mature as follows:
Year Ending
December 31, Annual Rentals
(In thousands)
1999 $ 316
2000 601
2001 601
2002 601
2003 601
Thereafter 1,979
$4,699
Rent expense allocated to HEP was $287,000, $288,000 and $304,000 for the years
ended December 31, 1998, 1997 and 1996, respectively.
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 Partnership, 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 Partnership 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 $ -- $ 4,254
Interest rate hedge contracts -- (812)
Long-term debt (49,700) (49,700)
The estimated fair value of the interest rate hedge contracts is computed by
multiplying 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 be available to the
Partnership.
The estimated fair value of the oil and gas hedge contracts is determined by
multiplying the difference between the quoted termination prices for oil and gas
and the hedge contract prices by the quantities under contract. This amount has
been discounted using an interest rate that could be available to the
Partnership.
Long-term debt is carried in the accompanying balance sheet at an amount which
is a reasonable estimate of its fair value.
The fair value estimates presented herein are based on pertinent information
available to management as of December 31, 1998. Although management is not
aware of any factors that would significantly affect the estimated fair value
amounts, such amounts have not been comprehensively reevaluated for purposes of
these financial statements since that date, and current estimates of fair value
may differ significantly from the amounts presented herein.
HALLWOOD ENERGY PARTNERS, L.P.
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
DECEMBER 31, 1998
(Unaudited)
The following reserve quantity and future net cash flow information for HEP
represents proved reserves which are located in the United States. The reserves
have been estimated by HPI's in-house engineers. 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 HEP's proved oil and gas reserves from year to year. No
consideration has been given to future income taxes for HEP as it is not a tax
paying entity. Under the guidelines set forth by the Securities and Exchange
Commission (SEC), 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
$1.90 per mcf, $16.90 per bbl and $2.30 per mcf and $24.18 per bbl and $3.76 per
mcf, respectively, for HEP, including its indirect interests in affiliated
partnerships and the Mays. 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 4.5 million bbls of oil, and 94.9 billion cubic feet of gas and
a standardized measure of $101,000,000. The Mays are included on a consolidated
basis, and 28,000 bbls of oil and 1.1 billion cubic feet of gas, representing a
discounted present value of $2,100,000 are attributable to the minority
ownership of these entities. This standardized measure is not necessarily
representative of the market value of HEP's properties. The portion of the
reserves attributable to the general partner's interest totaled 203,000 bbls of
oil and 5 billion cubic feet of gas with a standardized measure of $7,000,000 at
December 31, 1998.
HEP's standardized measure of future net cash flows has been increased by
$2,771,000 at December 31, 1998 for the effects of its hedge contracts. This
amount represents the difference between year end oil and gas prices and the
hedge contract prices multiplied by the quantities subject to contract,
discounted at 10%.
HALLWOOD ENERGY PARTNERS, L.P.
RESERVE QUANTITIES
(In thousands)
(Unaudited)
Gas Oil
Mcf Bbls
Proved Reserves:
Balance, December 31, 1995 83,112 8,098
Extensions and discoveries 1,683 484
Revisions of previous estimates 10,552 385
Sales of reserves in place (3,369) (481)
Purchases of reserves in place 9,350 17
Production (12,786) (972)
------- --------
Balance, December 31, 1996 88,542 7,531
Extensions and discoveries 4,228 817
Revisions of previous estimates 11,578 (1,930)
Sales of reserves in place (140) (9)
Purchases of reserves in place 619 128
Production (11,774) (770)
------- --------
Balance, December 31, 1997 93,053 5,767
Extensions and discoveries 1,542 415
Revisions of previous estimates (9,369) (1,385)
Sales of reserves in place (244) (35)
Purchases of reserves in place 23,994 512
Production (14,037) (787)
------- --------
Balance, December 31, 1998 94,939 4,487
======= =======
Proved Developed Reserves:
Balance, December 31, 1996 85,848 7,056
======= =======
Balance, December 31, 1997 89,816 5,181
======= =======
Balance, December 31, 1998 90,915 3,577
======= =======
HALLWOOD ENERGY PARTNERS, L.P.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(In thousands)
(Unaudited)
December 31,
1998 1997 1996
---- ---- ----
Future cash flows $ 245,000 $ 293,000 $ 509,000
Future production and development costs (102,000) (115,000) (175,000)
------- -------- --------
Future net cash flows before discount 143,000 178,000 334,000
10% discount to present value (42,000) (49,000) (128,000)
--------- --------- --------
Standardized measure of discounted
future net cash flows $ 101,000 $ 129,000 $ 206,000
========= ========= =========
HALLWOOD ENERGY PARTNERS, L.P.
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(In thousands)
(Unaudited)
For the Year Ended December 31,
-------------------------------
1998 1997 1996
---- ---- ----
Standardized measure of discounted future net
cash flows at beginning of year $129,000 $206,000 $124,000
Sales of oil and gas produced, net of production costs (26,932) (30,209) (35,915)
Net changes in prices and production costs (21,211) (78,965) 75,085
Extensions and discoveries, net of future production
and development costs 3,546 9,592 7,144
Changes in estimated future development costs (9,738) (10,012) (6,515)
Development costs incurred 8,087 7,607 8,218
Revisions of previous quantity estimates (15,547) (8) 20,032
Purchases of reserves in place 23,802 1,457 14,721
Sales of reserves in place (399) (204) (9,742)
Accretion of discount 12,936 20,600 12,400
Changes in production rates and other (2,544) 3,142 (3,428)
-------- -------- ---------
Standardized measure of discounted future net
cash flows at end of year $101,000 $129,000 $206,000
======= ======= =======
ITEM 9 - DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURES
None.
PART III
ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The registrant is a limited partnership managed by the general partner and has
no officers or directors. The general partner is HEPGP Ltd., a Colorado limited
partnership. The general partner of HEPGP Ltd. is Hallwood G.P., Inc., a
Delaware corporation, which is a wholly owned subsidiary of Hallwood Group.
The principal duties and powers of the general partner are arranging financing
for HEP, seeking out, negotiating and acquiring for HEP suitable leases and
other prospects, managing properties owned by HEP, generally dealing for HEP
with third parties and attending to the general administration of HEP and its
relations with the limited partners.
Hallwood Petroleum, Inc. ("HPI") performs duties related to the management of
HEP, including the operations of various properties in which HEP owns an
interest.
Directors, Officers and Key Employees
Neither the Partnership nor its general partner has any employees. Following are
brief biographies of the directors, officers and key employees of Hallwood G.P.
and HPI.
Anthony J. Gumbiner, 54, has served as a director and Chief Executive Officer of
Hallwood G.P. since March 1997. He was Chairman of the Board of Hallwood Energy
Corporation ("HEC") from May 1984 until HEC's merger into The Hallwood Group
Incorporated ("Hallwood Group") in November 1996. He was Chief Executive Officer
of HEC from February 1987 to November 1996. He has also served as Chairman of
the Board of Directors of Hallwood Group, a diversified holding company with
energy, real estate, textile products and hotel operations, since 1981 and as
Chief Executive Officer of Hallwood Group since April 1984. Mr. Gumbiner has
been a director and Chief Executive Officer of Hallwood Consolidated Resources
Corporation ("HCRC") since February 1992. 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 of Hallwood G.P. and HPI since
October 1989, and a director of Hallwood G.P. and HPI since August 1989. He was
President, Chief Operating Officer and a director of HEC from February 1985
until November 1996. Mr. Guzzetti joined HEC in February 1976 as Vice President,
Secretary and General Counsel and served in these positions until November 1980.
He served as Senior Vice President, Secretary and General Counsel of HEC from
November 1980 until February 1985, when he became President of HEC. Mr. Guzzetti
has been President, Chief Operating Officer and a director of HCRC since May
1991. 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 Hallwood G.P.
and HPI since October 1989. He was Executive Vice President of HEC from June
1991 until November 1996. He was Vice President of HEC from May 1990 until June
1991. Mr. Meduna became Executive Vice President of HCRC in June 1992. Mr.
Meduna was Vice President of Hallwood G.P. and 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 Vice President, Secretary and General
Counsel of Hallwood G.P. and HPI since September 1986. She was Vice President,
Secretary and General Counsel of HEC from June 1991 until November 1996. Ms.
Osborn became Secretary and General Counsel of HCRC in May 1992 and Vice
President in June 1992. She joined Hallwood G.P. and 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.
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 Hallwood G.P. since March 1997.
Mr. Troup was a director of HEC from May 1984 until November 1996. He has been
President and Chief Operating Officer of Hallwood Group since April 1986, and he
is a director of Hallwood Group. He has been a director of HCRC since February
1992. 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.
Hans-Peter Holinger, 56, has served as a director of Hallwood G.P. since March
1997. He was a director of HEC from May 1984 until November 1996. Mr. Holinger
served as Managing Director of Interallianz Bank Zurich A.G. from 1977 to
February 1993. Since February 1993, he has been the majority owner of Holinger
Asset Management AG, Zurich. Mr. Holinger is a citizen of Switzerland.
Rex A. Sebastian, 69, has served as a director of Hallwood G.P. since March
1997. He was a director of HEC from January 1993 until November 1996. Mr.
Sebastian is a member of the board of directors of Ferro Corporation. He served
as Senior Vice President--Operations of Dresser Industries, Inc. from January
1975 until his retirement in July 1985. He joined Dresser in 1966. Mr. Sebastian
is now a private investor.
Nathan C. Collins, 64, has served as a director of Hallwood G.P. since March
1997. He was a director of HEC from March 1995 until November 1996. Since
February 1999, he has been a consultant in banking products development for
Nordstrom, Inc. He is also a director of First State Bank of Flagstaff. From
March 1, 1995 to March 1, 1996, he was President, Chief Executive Officer and a
director of Flemington National Bank & Trust Co. in Flemington, New Jersey. From
November 1987 until December 1994, he was Chairman of the Board of Directors,
President and Chief Executive Officer of BancTexas Group Inc. He began his
banking career in August 1964 with the Valley National Bank in Phoenix, Arizona
and held various positions there, finally becoming Executive Vice President,
Senior Credit Officer and Manager of Asset/Liability Group of the bank.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires the officers and
directors of Hallwood G.P., Inc., and persons who own more than ten percent of
HEP's Units, 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 HEP 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, HEP believes that, during the year ended December
31, 1998, all officers and directors of Hallwood G.P., Inc. 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 Units of HEP.
ITEM 11 - EXECUTIVE COMPENSATION
General
Neither the Partnership nor its general partner has any employees. Management
services are provided to the Partnership by HPI, a subsidiary of the
Partnership. Employees of HPI perform all duties related to the management of
the Partnership on behalf of the General Partner. Since HPI also performs
services for HCRC, the Partnership 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 Partnership and the
Partnership's performance relative to HCRC and other related entities. The
allocation procedure is applied consistently to all related entities for which
HPI performs services. In 1998 the Partnership reimbursed HPI for approximately
$2,322,000 of expenses, of which $548,000 was attributable to compensation paid
to executive officers of Hallwood G.P.
Compensation of Executive Officers
The following table sets forth the compensation to the Chief Executive Officer
of Hallwood G.P. and each of the four other most highly compensated officers of
Hallwood G.P. whose compensation paid by HPI exceeded $100,000 (determined for
the year ended December 31, 1998) for services to the Partnership, its
subsidiaries and its General Partner for the years ended December 31, 1998, 1997
and 1996.
Summary Compensation Table
Long Term
Annual Compensation Compensation
Securities
Underlying LTIP All Other
Name & Principal Position Year Salary Bonus Options/SARs Payouts Compensation
- ------------------------- ---- ------ ----- ------------ ------- ------------
(#) (1)
Anthony J. Gumbiner (2) 1998 $ 0 $ 0 (5) $ (6) $ 0
Chief Executive 1997 0 0 (3) (6) 0
Officer 1996 250,000 0 0 (6) 0
William L. Guzzetti 1998 204,811 162,800 (5) 30,523 4,800
President and Chief 1997 204,294 143,870 (3) 42,854 4,750
Operating Officer 1996 204,294 131,500 0 33,170 5,699
Russell P. Meduna 1998 163,664 99,000 (5) 30,523 4,800
Executive Vice 1997 163,664 111,520 (3) 42,854 4,750
President 1996 163,664 101,900 0 33,170 4,500
Thomas J. Jung 1998 82,850 60,000 (4)(5) 0 1,922
Vice President and
Chief Financial Officer
Cathleen M. Osborn 1998 119,614 74,500 (5) 21,458 4,800
Vice President and 1997 105,685 100,000 (3) 30,124 4,750
General Counsel 1996 105,685 62,400 0 23,092 4,500
<FN>
(1) Employer contribution to 401(k) and a service award of $1,199 paid to Mr. Guzzetti in 1996.
</FN>
<FN>
(2) For 1996, Mr. Gumbiner had a Compensation Agreement with HPI.
$250,000 was paid under this agreement 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. During
1997 and 1998, the Partnership participated in a new financial
consulting agreement between HPI and Hallwood Group, pursuant to which
Hallwood Group received a fee of $550,000 from the Partnership and
its affiliates. 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 HCRC 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 Company Options/SARs (#)
Thomas J. Jung HEP 25,500
HCRC 9,540
</FN>
<FN>
(5) Consists of the following HEP Class C Unit options granted in 1998.
Securities Underlying
Name Options/SARs (#)
Anthony J. Gumbiner 34,588
William L. Guzzetti 16,588
Russell P. Meduna 14,118
Cathleen M. Osborn 10,024
Thomas J. Jung 10,024
</FN>
<FN>
(6) Payments were made to HSC Financial, with which Mr. Gumbiner is
associated, in the amount of $67,977 for 1998, $54,750 for 1997 and
$9,943 for 1996.
</FN>
Option Grants and Exercises in Last Fiscal Year
The following table sets forth the options to purchase Class C Units of HEP
granted to executive officers during 1998. No options to purchase Class C Units
granted to executive officers were exercised in 1998.
Option/SAR Grants in Last Fiscal Year
Potential Realized Value at
Assumed Annual Rates of
Unit 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 $16.29 $25.94
Name Granted (1) Fiscal Year ($/Unit) Date Unit Price Unit Price
---- ----------- ------------- ---------- ---------- ---------- ----------
Anthony J Gumbiner 34,588 24 $10.00 05/05/08 $217,522 $551,244
William L. Guzzetti 16,588 11 10.00 05/05/08 104,321 264,370
Russell P. Meduna 14,118 10 10.00 05/05/08 88,787 225,005
Cathleen M. Osborn 10,024 7 10.00 05/05/08 63,040 159,757
Thomas J. Jung 10,024 7 10.00 05/05/08 63,040 159,757
<FN>
(1) Options have a ten-year term and vest cumulatively 1/2 on the grant
date and 1/2 on first anniversary of the grant date. All Options
vest immediately in the event of certain changes in control of HEP.
</FN>
<FN>
(2) Securities and Exchange Commission Rules require calculation of
potential realizable value assuming that the market price of the Class
C Units appreciates in value at 5% and 10% annualized rates. At a 5%
annualized rate of appreciation, the Class C Unit price would be
$16.29 at the end of ten years. At a 10% annualized rate of
appreciation, the Class C Unit price would be $25.94 at the end of ten
years. No gain to an executive officer is possible without an
appreciation in Class C Unit value, which will benefit all holders
of Class C Units. The actual value an executive officer may receive
depends on market prices for the Class C Units, and there can be no
assurance that the amounts reflected will actually be realized.
</FN>
The following table sets forth the options to purchase Class A Units of HEP
granted to an executive officer during 1998. None of these options were
exercised in 1998.
Option/SAR Grants in Last Fiscal Year
Potential Realized Value at
Assumed Annual Rates of
Unit 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 $10.79 $17.18
Name Granted (1) Fiscal Year ($/Share) Date Unit Price Unit Price
---- ----------- ------------- ----------- ---------- ---------- ----------
Thomas J. Jung 25,500 18 $6.625 05/05/08 $106,244 $269,243
<FN>
(1) Options have a ten-year term and vest cumulatively over three years at the
rate of 1/3 on the grant date and the first two anniversaries of the grant
date. All Options vest immediately in the event of certain changes in
control of HEP.
</FN>
<FN>
(2) Securities and Exchange Commission Rules require calculation of potential
realizable value assuming that the market price of the Class A Units
appreciates in value at 5% and 10% annualized rates. At a 5% annualized
rate of appreciation, the Class A Unit price would be $10.79 at the end of
ten years. At a 10% annualized rate of appreciation, the Class A Unit price
would be $17.18 at the end of ten years. No gain to an executive officer is
possible without an appreciation in Class A Unit value, which will benefit
all holders of Class A Units. The actual value an executive officer may
receive depends on market prices for the Class A Units, and there can be no
assurance that the amounts reflected will actually be realized.
</FN>
The following table shows exercises of options to purchase Units and shares of
common stock during 1998 and the value of unexercised options on December 31,
1998.
Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values
Number of Securities
Underlying Value of Unexercised
Unexercised In-the-Money
Name Options/SARs Options/SARs
at FY - End (#) at FY -End ($)
Units Acquired Value Exercisable/ Exercisable/
on Exercise (#) Realized ($) Unexercisable (1)(3) Unexercisable (2)(4)
--------------- ------------ -------------------- --------------------
Anthony J. Gumbiner HEP 144,794 / 17,294 0 / 0
HCRC 4,000 33,820 75,500 / 15,900 189,221 / 0
William L. Guzzetti HEP 72,044 / 8,294 0 / 0
HCRC 39,750 / 7,950 103,271 / 0
Russell P. Meduna HEP 66,559 / 7,059 0 / 0
HCRC 2,500 21,700 34,600 / 7,420 85,561 / 0
Cathleen M. Osborn HEP 9,100 11,497 21,412 / 5,012 0 / 0
HCRC 5,000 42,900 10,900 / 3,180 19,658 / 0
Thomas J. Jung HEP 13,512 / 22,012 0 / 0
HCRC 6,360 / 12,720 0 / 0
<FN>
(1) The HEP Class A Unit 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. The HEP Class C Unit
Options have a ten year term and vest 1/2 on the date of grant and 1/2
on the first anniversary of the grant date. All options vest
immediately in the event of certain changes in control of the
Partnership.
</FN>
<FN>
(2) The exercise price of the HEP Class A Unit Options granted in 1995 and
in 1998 is $5.75 and $6.625 per Class A Unit, respectively. The
exercise price of the HEP Class C Unit Options granted in 1998 is
$10.00 per Class C Unit. The closing price of the Class A Units was
$3.625 on December 31, 1998 and the closing price of the Class C Units
was $6.625 on December 31, 1998.
</FN>
<FN>
(3) The HCRC 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>
(4) The exercise price of the HCRC options granted in 1995 is $6.67 per
share, and the exercise price of the HCRC options granted in 1997 is
$20.33 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>
Long-Term Incentive Plan
The following table describes performance units awarded to the executive
officers of Hallwood G.P. for 1998 under the incentive Plan (as described below)
for the Partnership and affiliated entities. The value of awards under each plan
depends primarily on the Partnership's success in drilling, completing and
achieving production from new wells each year and from certain recompletions and
enhancements of existing wells.
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)
---- ----------- --------------- -----------------------
Anthony J. Gumbiner(2) -- -- $ --
William L. Guzzetti 0.0727 2003 18,176
Russell P. Meduna 0.0727 2003 18,176
Cathleen M. Osborn 0.0545 2003 13,625
<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 $95,453, was made to HSC Financial, with which Mr. Gumbiner is
associated. The payout period ends in 2003.
</FN>
The Incentive Plan for the Partnership and its affiliated entities, including
HCRC, 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 Hallwood G.P. (the "Board")
annually determines the portion of the Partnership'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 Partnership'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 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
HEP's drilling activity.
Director Compensation
Each director of Hallwood G.P. who is not an officer of Hallwood G.P. or 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. Holinger, Sebastian and Collins
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 Hallwood G.P. makes compensation decisions for the
Partnership during the first quarter of each year. Mr. Gumbiner is Chief
Executive Officer of Hallwood G.P. 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 also Chief Executive Officer and a director of
HCRC, of which Mr. Troup is a director and Mr. Guzzetti is a director and
President. Messrs. Gumbiner, Troup and Guzzetti served on HCRC's Board of
Directors which made compensation decisions for HCRC in January 1998. 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 Partnership participates in a financial consulting agreement between HPI and
Hallwood Group, pursuant to which Hallwood Group furnishes consulting and
advisory services to HPI, the Partnership 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 $274,000 and $275,000 was paid in 1998 and
1997, respectively by the Partnership pursuant to this arrangement. For 1996,
Mr. Gumbiner had a compensation agreement with HPI pursuant to which Mr.
Gumbiner was paid $250,000 by HPI, the Partnership and their affiliates. This
agreement was terminated effective December 31, 1996. See "Summary Compensation
Table" and footnotes for additional discussion of this arrangement.
The Partnership reimburses Hallwood Group for expenses incurred on behalf of the
Partnership. In 1998, 1997 and 1996 the Partnership reimbursed Hallwood Group
for approximately $317,000, $301,000 and $309,000 of expenses, respectively.
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 the Partnership to be
the beneficial owner of more than 5% of each class of Units issued and
outstanding and each executive officer and director of Hallwood G.P. and all
executive officers and directors as a group.
Amount
Title of Beneficially
Name Class of Units Owned Percent of Class
The Hallwood Group Incorporated (1) Class A 657,260(5) 6.5
Class B 143,773 100.0
Class C 43,816 1.8
Hallwood Consolidated Resources Corporation (2) Class A 1,948,189 19.5
Class C 129,877 5.3
Heartland Advisors, Inc. (3) Class A 803,760(6) 8.0
Estate of William Baxter Lee, III (4) Class A 715,000(7) 7.1
Class C 40,033(8) 1.6
Anthony J. Gumbiner Class A 127,500(9) 1.3
Class C 17,294(10) *
William L. Guzzetti Class A 63,850(9) *
Class C 8,300(10) *
Russell P. Meduna Class A 59,500(9) *
Class C 7,059(10) *
Cathleen M. Osborn Class A 16,400(9) *
Class C 5,112(10) *
Thomas J. Jung Class A 8,500(9) *
Class C 5,012(10) *
Brian M. Troup Class A 85,000(9) *
Class C 11,294(10) *
Hans-Peter Holinger Class A - -
Class C - -
Rex A. Sebastian Class A 400 *
Class C 26 *
Nathan C. Collins Class A - -
Class C - -
Bill M. Van Meter Class A - -
Class C - -
All directors and executive officers of Class A 361,150(11) 3.7
Hallwood G.P. as a group (9 persons) Class C 54,097(12) *
- ----------------------
<FN>
* Less than 1%
</FN>
<FN>
(1) The address of Hallwood Group is 3710 Rawlins Street, Suite 1500,
Dallas, Texas 75219.
</FN>
<FN>
(2) The address of Hallwood Consolidated Resources is 4582 S. Ulster Street
Parkway, Suite 1700, Denver, Colorado 80237.
</FN>
<FN>
(3) The address of Heartland Advisors, Inc. is 790 North Milwaukee Street,
Milwaukee, WI 53202.
</FN>
<FN>
(4) 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>
(5) Includes 143,773 Class B Units (100% of the Class B Units) that are
convertible into Class A Units one-for-one.
</FN>
<FN>
(6) According to the Amendment No. 4 to Schedule 13G filed January 26, 1999 by
Heartland Advisors, Inc., the Units to which the schedule relates are held
in investment advisory accounts of Heartland Advisors, Inc. As a result,
various persons have the right to receive or the power to direct the receipt
of dividends from, or the proceeds from the sale of, the securities. No
such account is known to have an interest relating to more than 5% of the
class.
</FN>
<FN>
(7) According to Schedule 13G dated February 23, 1999.
</FN>
<FN>
(8) According to Schedule 13G dated February 23, 1999.
</FN>
<FN>
(9) The following numbers of Class A Units issuable upon the exercise of
currently exercisable options are included in the amounts shown:
Mr. Gumbiner, 127,500; Mr. Troup, 85,000; Mr. Guzzetti, 63,750;
Mr. Meduna, 59,500; Ms. Osborn, 16,400; Mr. Jung 8,500.
</FN>
<FN>
(10)The following numbers of Class C Units issuable upon the exercise of
currently exercisable options are included in the amounts shown:
Mr. Gumbiner, 17,294; Mr. Troup, 11,294; Mr. Guzzetti, 8,294;
Mr. Meduna, 7,059; Ms. Osborn, 5,012; Mr. Jung, 5,012.
</FN>
<FN>
(11)Consists of 500 Class A Units and currently exercisable options to purchase
360,650 Class A Units.
</FN>
<FN>
(12)Consists of 132 Class C Units and currently exercisable options to purchase
53,965 Class C Units.
</FN>
See Item 8 - Financial Statements and Supplementary Data (Note 10 to the
Financial Statements) for a description of HEP's Unit Option Plans.
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
See Item 8 - Financial statements and Supplementary Data (Note 11 to the
Financial Statements).
PART IV
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Financial Statements and Financial Statement Schedules. (See Index at
Item 8).
(b) Reports on Form 8-K.
HEP filed no current reports on Form 8-K during the last quarter of the
period covered by this report.
(c) Exhibits.
(1) 4.1 - Third Amended and Restated Agreement of Limited Partnership
of Hallwood Energy Partners, L.P.
(4) 4.2 - Unit Purchase Rights Agreement dated as of February 6,
1995 between HEP and The First National Bank of Boston.
(7) 4.3 - First Amendment to the Third Amended and Restated
Agreement of Limited Partnership of Hallwood Energy
Partners, L. P.
(8) 4.4 - Amendment to the Third Amended and Restated Agreement of
Limited Partnership of Hallwood Energy Partners, L.P.
(12) 4.5 - Correction to the First Amendment to the Third Amended
and Restated Limited Partnership Agreement of Hallwood
Energy Partners, L.P.
(3) 10.1 - Third Amended and Restated Agreement of Limited Partnership
of HEP Operating Partners, L.P.
(5) 10.3 - Second Amended and Restated Credit Agreement dated March 31,
1995
(2) 10.4 - Amended and Restated Note Purchase Agreement dated May 7,
1990. (Exhibit 10.2)
(3) 10.5 - Amended and Restated Agreement of Limited Partnership of
EDP Operating, Ltd.
*(5) 10.9 - Domestic Incentive Plan between the Partnership and Hallwood
Petroleum, Inc. dated January 14, 1993
*(6) 10.10 - 1995 Unit Option Plan
*(5) 10.11 - 1995 Unit Option Plan Loan Program
(8) 10.12 - Amendment to the Third Amended and Restated Agreement of
Limited Partnership of HEP Operating Partners, L.P.
(8) 10.13 - Second Amendment to the Second Amended and Restated
Agreement of Limited Partnership of HEP Operating
Partners, L.P.
*(9) 10.14 - Financial Consulting Agreement dated as of December 31, 1996
(10) 10.15 - Third Amended and Restated Credit Agreement dated as of
May 31, 1997
(11) 10.16 - Amendment No. 1 to Third Amended and Restated Credit
Agreement dated as of October 31, 1997
*(13) 10.17 - 1998 Class C Unit Option Plan dated May 5, 1998
*(13) 10.18 - 1998 Class C Unit Option Loan Program dated May 5, 1998
*(13) 10.19 - Class A Unit Option letter to Thomas Jung dated May 5, 1998
(13) 10.20 - Extension of Management Agreement between Hallwood
Petroleum, Inc. and HEP dated May 5, 1998.
(14) 10.21 - Merger and Asset Contribution Agreement By and Among
Hallwood Energy Corporation, and HEC Acquisition
Corp., Hallwood Energy Partners, L.P. and HCRC
Acquisition Corp., Hallwood Consolidated Resources
Corporation and HEPGP Ltd. dated as of December 15, 1998.
(7) 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 Prospectus/Proxy Statement dated February
14, 1990 as supplemented March 22, 1990, March 30, 1990 and April 5,
1990, of Hallwood Energy Partners, L.P., filed as part of Registration
Statement No. 33-33452.
(2) Incorporated by reference to the exhibit shown in parentheses
filed with current report on Form 8-K dated May 9, 1990 of
Hallwood Energy Partners, L.P.
(3) Incorporated by reference to the same exhibit number filed with the
Registrant's Annual Report on Form 10-K for fiscal year ended
December 31, 1990.
(4) Incorporated by reference to Exhibit 1 filed with the Registrant's
Form 8-A for Limited Partner Unit Purchase Rights filed with the SEC
on February 8, 1995.
(5) Incorporated by reference to the same exhibit number filed with
Registrant's Quarterly Report on Form 10-Q for the quarter ended
March 31, 1995.
(6) Incorporated by reference to the same exhibit number filed with the
Registrant's Annual Report on Form 10-K for fiscal year ended December
31, 1994.
(7) Incorporated by reference to the same exhibit number filed with the
Registrant's Annual Report on Form 10-K for the fiscal year ended
December 31, 1995.
(8) Incorporated by reference to the same exhibit number filed with the
Registrant's Annual Report on Form 10-K for the fiscal year ended
December 31, 1996.
(9) Incorporated by reference to the same exhibit number filed with
the Registrant's Quarterly Report on Form 10-Q for the quarter ended
March 31, 1997.
(10) Incorporated by reference to the same exhibit number filed with
the Registrant's Quarterly Report on Form 10-Q for the quarter ended
June 30, 1997.
(11) Incorporated by reference to the same exhibit number filed with
the Registrant's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1997.
(12) Incorporated by reference to same exhibit number filed with the
Registrant's Quarterly Report on Form 10-Q ended March 31, 1998.
(13) Incorporated by reference to same exhibit number filed with the
Registrant's Quarterly Report on Form 10-Q ended June 30, 1998.
(14) Incorporated by reference to Schedule 14A of HEP dated
December 30,1998.
*Designates management contracts or compensatory plans or arrangements.
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 ENERGY PARTNERS, L.P.
BY: HEPGP LTD
General Partner
BY: HALLWOOD G.P., INC.
General Partner
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 (Chief Executive Officer)
/s/Brian M. Troup Director March 24, 1999
Brian M. Troup
/s/Hans-Peter Holinger Director March 24, 1999
Hans-Peter Holinger
/s/Rex A. Sebastian Director March 24, 1999
Rex A. Sebastian
/s/Nathan C. Collins Director March 24, 1999
Nathan C. Collins
/s/Thomas J. Jung Principal Accounting Officer March 24, 1999
Thomas J. Jung
INDEX TO EXHIBITS
Page
Exhibit 23.1 - Consent of Deloitte & Touche LLP 75
Exhibit 23.2 - Consent of Deloitte & Touche LLP 76