UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
MARK ONE
[X] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the Fiscal Year Ended December 31, 1997
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File Number 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:
Title of each class Name of each exchange
on which registered
Class A Units of Limited Partnership Interests American Stock Exchange
Class C Units of Limited Partnership Interests American Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [x] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein and will not be contained, to the best
of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [x]
The aggregate market value of the Class A and Class C Units held by
nonaffiliates of the registrant as of February 27, 1998 was approximately
$58,218,000.
Number of Units outstanding as of February 27, 1998
Class A 9,986,254
Class B 143,773
Class C 2,464,063
Page 1 of 64
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 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 February 27, 1998, HPI had 123 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 entered into
financial contracts for hedging the price of 23% of its estimated oil production
for 1998 and 2% for 1999.
The majority of HEP's natural gas production is sold on the spot market and is
transported in intrastate and interstate pipelines. HEP entered into financial
contracts for hedging the price of between 4% and 42% of its estimated gas
production for 1998 through 2001.
The purpose of the hedges is to provide protection against price decreases and
to provide a measure of stability in the volatile environment of oil and natural
gas spot pricing. The amounts received or paid upon settlement of these
contracts are recognized as 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 purchasers in the areas in which HEP sells its
production. However, for the years ended December 31, 1997, 1996 and 1995,
purchases by the following companies exceeded 10% of the total oil and gas
revenues of the Partnership:
1997 1996 1995
---- ---- ----
Conoco Inc. 20% 28% 30%
Marathon Petroleum Company 16% 11% 14%
El Paso Field Services Company 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 involve 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, 1997, 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
As the year 2000 approaches, there are uncertainties concerning whether computer
systems will properly recognize date-sensitive information when the year changes
to 2000. Systems that do not properly recognize such information could generate
erroneous data or fail.
Because of the nature of the oil and gas industry and the necessity for the
Partnership to make reserve estimates and other plans well beyond the year 2000,
the Partnership's computer systems and software were already configured to
accommodate dates beyond the year 2000. The Partnership believes that the year
2000 will not pose significant operational problems for the Partnership's
computer systems. The Partnership has not yet completed its assessment of all of
its systems, or the computer systems of third parties with which it deals, and
while it is not possible at this time to assess the effect of a third party's
inability to adequately address year 2000 issues, the Partnership does not
believe the potential problems associated with year 2000 will have a material
effect on its financial results.
ITEM 2 - PROPERTIES
Exploration and Development Projects
In 1997, HEP incurred $16,216,000 in direct property additions and exploration
and development costs. The costs were comprised of approximately $12,983,000 for
domestic exploration and development expenditures and approximately $3,233,000
for property acquisitions. In 1997, HEP participated in approximately 102
drilling or recompletion projects, the highlights of which are discussed below.
HEP's 1997 capital program led to the replacement, including revisions to prior
year reserves, of 63% of 1997 production. Sales of reserves in place in 1997,
which were approximately 1% of 1997 production, were excluded from this
calculation. Approximately $2,130,000 of the 1997 capital expenditures were for
land and seismic data anticipated to yield prospects for 1998 and subsequent
years.
Property Sales
During 1997, HEP received approximately $133,000 for the sale of 50 nonstrategic
properties located in eight states.
Capital Projects
Greater Permian Region
HEP has expended approximately $6,400,000 of its capital budget in the Greater
Permian Region located in Texas and Southeast New Mexico. During 1997, HEP spent
approximately $4,740,000 drilling 29 development wells and 26 exploration wells,
and acquiring undeveloped acreage and geological and geophysical data. Of the
wells drilled, 39 (71%) were successful. A discussion of several of the larger
projects within the Region follows.
HEP spent approximately $1,085,000 successfully recompleting two wells, drilling
one successful development well, and drilling two unsuccessful exploration wells
in the Carlsbad/Catclaw Draw areas in Lea, Eddy and Chaves Counties, New Mexico.
HEP spent approximately $220,000 to drill six exploration and three development
wells in the nonoperated Merkle Project in the Jones, Taylor, and Nolan
Counties, Texas. Five wells were successful.
Based on the success in the nonoperated Merkle area, HEP acquired 74 additional
square miles of proprietary 3-D seismic data adjacent to the non-operated area.
In 1997, HEP incurred approximately $650,000 acquiring acreage and drilling 10
exploration wells, seven of which were successful. HEP purchased an interest in
proprietary 3-D seismic data and selected acreage within an 85 square mile area,
referred to as the Griffin Project, for approximately $495,000. In 1997, HEP
drilled one successful and one unsuccessful exploratory well in the area for
approximately $370,000. HEP is currently participating in the drilling of one
exploration well and incurred approximately $110,000 through December 31, 1997.
HEP spent approximately $1,030,000 drilling two exploration wells and nine
development wells in the Spraberry area of West Texas. Of the wells drilled,
eight (73%) are successful. In July 1997, HEP acquired additional interests in
34 of its existing wells in the area for approximately $510,000.
In 1997, HEP continued to devote capital resources to the East Keystone area in
Winkler County, Texas. HEP spent approximately $400,000 drilling 14 development
wells with a success rate of 100%.
Rocky Mountain Region
HEP expended approximately $3,040,000 of its capital budget in the Rocky
Mountain Region located in Colorado, Montana, North Dakota, Northwest New Mexico
and Wyoming. During 1997, HEP drilled or participated in the drilling or
recompletion of 17 wells, seven of which were successful. A description of the
Region's major projects follows.
In the San Juan Basin in LaPlata County, Colorado and Rio Arriba County, New
Mexico, HEP has an interest in 34 wells owned by a special purpose entity owned
by a large east coast financial institution. During 1997, seven successful
recompletions on these wells were performed and one successful exploration well
was drilled. This work and other activity in the San Juan region have yielded
significant upward revisions to HEP's estimated reserve base. HEP incurred
approximately $235,000 on four other recompletion attempts in San Juan County,
New Mexico, two of which were successful. In addition, HEP purchased additional
interests in existing wells in the area for $70,000.
In the Lone Tree area of Montana, HEP drilled two exploration wells and three
development wells for a cost of approximately $920,000. Two of the development
wells and one of the exploration wells were successful.
HEP owns an interest in the Hudson Ranch project, which is a multi-objective
exploration project generated from 120 miles of 2-D proprietary seismic data.
HEP's 1997 costs for the project are approximately $340,000. A 3-D seismic data
acquisition program is underway, and exploratory drilling is anticipated to
begin in 1998.
HEP also participated in the drilling of an 11,500 feet exploration well in the
Beach Field of North Dakota. HEP incurred approximately $215,000 for
participation in this successful well.
Gulf Coast Region
HEP expended approximately $3,610,000 of its capital budget in the Gulf Coast
Region in Louisiana and South and East Texas. During 1997, HEP drilled or
participated in the drilling of six development wells, five of which were
successful, and two unsuccessful exploration wells, for a total cost to HEP of
approximately $2,160,000.
Major projects within the Region follow.
HEP incurred approximately $770,000 developing two Jeffress Field wells in
Hidalgo County, Texas. Both wells were successful. Two successful development
wells in the Mercy Field in San Jacinto County, Texas cost HEP approximately
$450,000. HEP also spent approximately $855,000 on two unsuccessful exploration
attempts and one unsuccessful development well. Repairs and successful workovers
on wells in the Scott Field cost HEP approximately $800,000.
HEP also incurred approximately $195,000 on miscellaneous projects within the
Region for land and geological data.
Other
The remaining $3,166,000 of HEP's 1997 capital budget was devoted to all other
areas. In 1997, HEP incurred $645,000 for land, geological data and drilling
costs for 15 development wells and six exploration wells. Of the wells drilled,
17 (81%) were successful. A description of the major projects follow.
HEP is participating in an exploration prospect in Carter County, Oklahoma. This
project is a 19,000 feet deep multi-formation structural test and is currently
in the completion phase. The drilling and land costs to HEP are approximately
$355,000.
In 1997, HEP entered into an agreement with another operator to participate in
an 8,500 feet deep Spiro/Foster test well in LeFlore County, Oklahoma. The well
was a success and cost HEP approximately $265,000.
HEP also purchased additional interests in eight existing Kansas properties for
approximately $110,000.
Projects begun in the fourth quarter of 1996 have cost HEP approximately
$995,000 in 1997. These costs are primarily for work in the Gulf Coast Region
and in the Greater Permian Region. Miscellaneous land and geological and
geophysical data acquired in 1997 cost HEP approximately $690,000.
In September 1997, HEP and an unaffiliated partner were awarded a deep-water
exploration block offshore of northern Peru. Its partner is proceeding with a
1,200 mile seismic program to further evaluate the project. HEP's partner, a
major oil company, is the operator, and HEP has a carried interest until
drilling begins.
For 1998, HEP's capital budget, which will be paid from cash generated from
operations, cash on hand and borrowings under HEP's line of credit, has been set
at $25,000,000. HEP's plans include projects in Texas, New Mexico, Colorado,
North Dakota, and Montana.
Partnership Reserves, Production and Discussion by Significant Areas and Fields
The following table presents the December 31, 1997 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 28,564 692 $ 561 $ 39,289 $ 39,850
Gulf Coast Region 23,710 604 647 51,788 52,435
Rocky Mountain Region 38,430 4,012 269 29,607 29,876
Other 2,349 459 105 6,734 6,839
----- --- --- ----- -----
93,053 5,767 $1,582 $127,418 $129,000
====== ===== ===== ======= =======
The total present value of future net cash flows is calculated using year end
average oil and gas prices. At December 31, 1997, oil and gas prices averaged
$16.90 per bbl of oil and $2.30 per mcf of gas. If average oil and gas prices as
of February 27, 1998 of $15.70 per bbl of oil and $2.10 per mcf of gas had been
used, the total present value of future net cash flows would have been 12%
lower.
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, 1997 Year Ended December 31, 1996
---------------------------- ----------------------------
Natural Gas Bbls of Oil Natural Gas Bbls of Oil
(mcf) (bbls) (mcf) (bbls)
(In thousands)
Greater Permian Region 2,803 423 2,792 512
Gulf Coast Region 4,859 184 6,015 239
Rocky Mountain Region 3,562 100 3,394 137
Other 550 63 585 84
--- -- --- ---
11,774 770 12,786 972
====== === ====== ===
The following table presents the Partnership's extensions and discoveries by
significant regions.
For the Year Ended 1997 For the Year Ended 1996
----------------------- -----------------------
Mcf of Gas Bbls of Oil Mcf of Gas Bbls of Oil
---------- ----------- ---------- -----------
(In thousands)
Greater Permian Region 1,423 232 704 422
Gulf Coast Region 1,527 75 176 15
Rocky Mountain Region 1,153 490 670 28
Other 125 20 133 19
------ ---- --- - --
4,228 817 1,683 484
===== ===== ===== ===
A description of the Partnership's properties by region follows.
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 512
productive oil and gas wells (443 of which are operated), 38 operated shut-in
oil and gas wells and 15 (14 operated) salt water disposal wells or injection
wells. During 1997, HEP drilled or recompleted 55 wells, 39 of which were
successful. The following is a description of the significant areas within the
Greater Permian Region.
Carlsbad/Catclaw Area. HEP's interests in the Carlsbad/Catclaw Area as of
December 31, 1997 consisted of 61 producing wells that produce primarily natural
gas and are located on the northwestern edge of the Delaware Basin in Lea, Eddy
and Chaves Counties, New Mexico. HPI operates 40 of these wells. The wells
produce at depths ranging from approximately 2,500 feet to 14,000 feet from the
Delaware, Atoka, Bone Springs and Morrow formations. During 1997, HEP
participated in the drilling or recompletion of five wells, three of which were
successful. HEP has future plans for six additional projects in this area.
East Keystone Area. HEP's interest in the East Keystone Area as of December 31,
1997 consisted of 54 producing wells, 38 of which are operated by HPI, in
Winkler County, Texas. The primary focus of this area is the development of the
Holt and San Andreas formations at a depth of 5,100 feet. During 1997, HEP had
14 development projects, all which were successful. HEP's future development
plans include a total of five projects for this area.
Merkle Area. 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. HEP's focus in this area is exploration of the
Canyon, Strawn and Ellenberger formations at depths of 3,500 to 6,500 feet. In
1997, HEP participated in the drilling or recompletion of six exploration and
three development wells, five of which were successful.
Based on its success in the nonoperated Merkle Area, HEP acquired 74 additional
miles of proprietary 3-D seismic data adjacent to the nonoperated area. In 1997,
HEP drilled ten exploration wells in the area, seven of which were successful.
All of these wells are operated by HPI. Future plans for this area include
drilling 22 exploration wells, with possible additional exploratory locations
contingent upon continued success.
Spraberry Area. HEP's interests in the Spraberry Area consist of 345 producing
wells, 11 salt water disposal wells and 29 shut-in wells in Dawson, Upton,
Reagan and Irion Counties, Texas. HPI operates 385 of these wells. Most of the
current production from the wells is from the Upper and Lower Spraberry,
Clearfork Canyon, Dean and Fusselman formations at depths ranging from 5,000
feet to 9,000 feet. During 1997, HEP drilled or recompleted 11 wells, eight of
which were successful. Future plans for this area include 20 development wells
and workovers and additional projects contingent upon future evaluation.
Gulf Coast Region
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 10 producing gas wells, one shut-in gas well and six salt water
disposal wells located in Lafayette Parish, Louisiana. The wells produce
principally from the Bol Mex formations at 13,500 to 14,500 feet and are
operated by HPI. The two most significant wells in the area are the A.L.
Boudreaux #1 and the G.S. Boudreaux Estate #1. During 1997, HEP drilled five
successful development wells, one unsuccessful development well, and two
unsuccessful exploration wells.
Rocky Mountain Region
HEP has significant interests in the Rocky Mountain Region, which includes
producing properties in Colorado, Montana, North Dakota and Northwest New
Mexico. HEP has interests in 203 producing oil and gas wells, 172 of which are
operated by HPI, 44 shut-in wells, 35 of which are operated by HPI, and five
salt water disposal wells. The following is a description of the significant
areas within the Rocky Mountain Region.
San Juan Basin. HEP's interest in the San Juan Basin consists of 82 producing
gas wells located in San Juan County, New Mexico and LaPlata County, Colorado.
HPI operates 51 wells in New Mexico, 31 of which produce from the Fruitland Coal
formation at approximately 2,200 feet and 20 of which produce from the Pictured
Cliffs, Mesa Verde and Dakota formations at 1,200 to 7,000 feet. During 1997,
HEP drilled or recompleted four wells, two of which were successful.
In 1996, HEP participated in the acquisition of interests in 38 producing gas
wells in LaPlata County, Colorado and Rio Arriba County, New Mexico from a
subsidiary of Public Service Company of Colorado. Thirty-four of the wells were
assigned to a special purpose entity owned by a large East Coast financial
institution. The wells produce from the Fruitland Coal formation at
approximately 3,200 feet. In connection with the acquisition, HEP monetized the
Section 29 tax credits generated by the wells. The project was financed through
a third party lender using a production payment structure. In 1997, HEP
successfully recompleted seven of the wells, and drilled one successful
exploration well. Future plans for this area include a total of eight projects.
Toole County Area. HEP's interests in the Toole County Area consist of 67 wells,
58 of which are operated by HPI. The oil wells produce from the Nisku formation
at depths of approximately 3,000 feet, and the gas wells produce from the Bow
Island formation at depths of 900 to 1,200 feet. During 1997, HEP drilled one
successful well. HEP has plans for future development wells and workovers in
this area.
Lone Tree, Richland County Area. HEP's interest in the Lone Tree, Richland
County area consists of 13 producing wells operated by HPI in Richland County,
Montana. The oil wells produce principally from the Mission Canyon, Interlake
and Red River formations at depths of 9,000 feet to 12,000 feet. In 1997, HEP
drilled two exploration and three development wells. Two of the development
wells and one of the exploration wells were successful.
Average Sales Prices and Production Costs
The following table presents the average oil and gas sales price and average
production costs per equivalent barrel computed at the ratio of six mcf of gas
to one barrel of oil.
1997 1996 1995
------ ------ ----
Oil and condensate -
includes the effects of hedging (per bbl) $19.08 $20.10 $17.36
Natural gas -
includes the effects of hedging (per mcf) 2.31 2.24 1.82
Production costs (per equivalent bbl of oil) 4.05 3.71 3.57
Productive Oil and Gas Wells
The following table summarizes the productive oil and gas wells as of December
31, 1997 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 650 245
Gas 320 121
--- ---
Total 970 366
=== ===
Oil and Gas Acreage
The following table sets forth the developed and undeveloped leasehold acreage
held directly by HEP as of December 31, 1997. Developed acres are acres which
are spaced or assignable to productive wells. Undeveloped acres are acres on
which wells have not been drilled or completed to a point that would permit the
production of commercial quantities of oil and gas, regardless of whether or not
such acreage contains proved reserves. Gross acres are the total number of acres
in which HEP has a working interest. Net acres are the sum of HEP's fractional
interests owned in the gross acres.
Gross Net
Developed acreage 99,250 48,200
Undeveloped acreage 284,328 77,089
------- - ------
Total 383,578 125,289
======= =======
States in which HEP holds undeveloped acreage include Texas, Louisiana, Montana,
Wyoming, New Mexico, Kansas, Colorado, North Dakota, California and Michigan.
Drilling Activity
The following table sets forth the number of wells attributable to HEP's direct
interest drilled in the most recent three years.
Year Ended December 31,
1997 1996 1995
- ----- - ----- - ----
Gross Net Gross Net Gross Net
Development Wells:
Productive 23 4.5 29 6.6 66 28.0
Dry 5 .8 4 .9 2 .5
-- -- -- -- -- --
Total 28 5.3 33 7.5 68 28.5
== === == === == ====
Exploratory Wells:
Productive 14 2.2 2 .2 5 .6
Dry 22 5.4 4 .6 1 .9
-- --- -- -- -- ----
Total 36 7.6 6 .8 6 1.5
== === == == == ===
Office Space
HPI leases office space in Denver, Colorado containing approximately 41,000
square feet, for approximately $600,000 per year. 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
Hallwood Consolidated Resources Corporation ("HCRC") is guarantor of the
remaining 40% of the obligation.
ITEM 3 - LEGAL PROCEEDINGS
See Notes 12 and 13 to the financial statements included in Item 8 - Financial
Statements and Supplementary Data.
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth
quarter of 1997.
PART II
ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED UNITHOLDER MATTERS
HEP's Class A Units are traded on the American Stock Exchange (the "Exchange")
under the symbol "HEP." As of February 27, 1998, 9,986,254 Class A Units were
outstanding, held by approximately 19,673 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 1996 $ 5 1/4 $ 3 3/4 $.13
Second quarter 1996 6 3/4 4 5/8 .13
Third quarter 1996 7 3/8 5 7/8 .13
Fourth quarter 1996 9 6 1/4 .13
---
$.52
===
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
=====
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 February 27,
1998, 2,464,063 Class C Units were outstanding, held by approximately 1,321
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 1996 $ 7 7/8 $ 6 1/2 $ .25
Second quarter 1996 8 1/2 7 3/8 .25
Third quarter 1996 9 5/8 8 .25
Fourth quarter 1996 9 7/8 8 3/4 .25
------ ------- ---
$1.00
=====
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
====
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 Years Ended December 31,
1997 1996 1995 1994 1993
- ----- - ----- - ----- - ----- - ----
(In thousands except per Unit)
Summary of Operations
Oil and gas revenues and
pipeline operations $ 44,707 $ 50,644 $ 43,454 $ 43,899 $ 44,106
Litigation settlement 11,466
Total revenue 45,103 51,066 43,780 44,482 49,613
Production operating
expense 11,060 11,511 11,298 12,177 11,200
Depreciation, depletion and
amortization 11,961 13,500 15,827 18,168 17,076
Impairment 10,943 7,345
General and administrative
expense 5,333 4,540 5,580 5,630 6,812
Net income (loss) 12,803 15,726 (9,031) (10,093) 13,064
Basic net income (loss) per
Class A and Class B Unit* 1.09 1.35 (1.07) (1.20) 1.14
Diluted net income (loss) per
Class A and Class B Unit * 1.07 1.35 (1.07) (1.20) 1.14
Distributions per Class A
and Class B Unit .52 .52 .80 .80 .80
Balance Sheet
Working capital (deficit) $ (973) $ (1,355) $ (4,363) $ (9,390) $ 7,020
Property, plant and
equipment, net 94,331 88,549 94,926 107,414 122,133
Total assets 131,603 122,792 125,152 136,281 171,624
Long-term debt 34,986 29,461 37,557 25,898 38,010
Long-term contract
settlement obligation 2,512 2,397 2,666 3,673
Deferred liability 1,180 1,533 1,718 1,931 1,504
Minority interest in
affiliates 3,258 3,336 3,042 2,923 3,346
Partners' capital 69,064 64,215 57,572 78,803 98,576
<FN>
*Per Unit amounts have been restated to reflect the adoption of Statement of
Financial Accounting Standards No. 128 "Earnings per share" ("SFAS 128") in
December 1997.
</FN>
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS, LIQUIDITY AND CAPITAL RESOURCES
Liquidity and Capital Resources
Cash Flow
HEP generated $27,384,000 of cash flow from operating activities during 1997.
The other primary cash inflows were:
$7,000,000 in proceeds from long-term debt;
$133,000 in proceeds from the sale of property.
Cash was used primarily for:
Distributions to partners of $7,676,000;
Additions to property, exploration and development costs of $16,216,000;
Payments of long-term debt of $7,285,000.
When combined with miscellaneous other cash activity during the year, the result
was an increase in HEP's cash and cash equivalents of $1,082,00, from $5,540,000
at December 31, 1996 to $6,622,000 at December 31, 1997.
Property Purchases, Sales and Capital Budget
In 1997, HEP incurred $16,216,000 in direct property additions and exploration
and development costs. The costs were comprised of approximately $12,983,000 for
domestic exploration and development expenditures and approximately $3,233,000
for property acquisitions. HEP's 1997 capital program led to the replacement,
including revisions to prior year reserves, of 63% of 1997 production using
year-end pricing.
HEP's significant direct exploration and development expenditures in the Greater
Permian Region in 1997 included approximately $1,085,000 for successfully
recompleting or drilling three development wells, and for drilling two
unsuccessful exploration wells in the Carlsbad/Catclaw Draw areas in northeast
New Mexico; approximately $650,000 for acquiring acreage and drilling 10
exploration wells, seven of which were successful, in the operated Merkle area
in West Texas; approximately $1,030,000 for drilling two exploration wells and
nine development wells in the Spraberry area of West Texas, eight of which were
successful; approximately $510,000 for the purchase of additional interests in
the Spraberry area; and approximately $400,000 for drilling 14 development wells
in the Keystone area in West Texas, all of which were successful.
In the Lone Tree area of the Rocky Mountain Region, HEP drilled two exploration
wells and three development wells for a cost of approximately $920,000. Two of
the development wells and one of the exploration wells were successful. In the
Gulf Coast Region, HEP incurred approximately $770,000 drilling two successful
Jeffress Field development wells. HEP also spent approximately $855,000 on two
unsuccessful exploration attempts and one unsuccessful development well. Repairs
and successful workovers on wells in the Scott Field cost HEP approximately
$800,000.
Projects begun in the fourth quarter of 1996 have cost HEP approximately
$995,000 in 1997. These costs are primarily for work in the Gulf Coast Region
and in the Greater Permian Region.
For 1998, HEP's capital budget, which will be paid from cash generated from
operations, cash on hand and borrowings, has been set at $25,000,000. HEP's
plans include projects in Texas, New Mexico, Colorado, North Dakota, and
Montana.
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.
Distributions
During 1997, 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 Board of Directors of HEP's General Partner is considering the distribution
level for future quarters, taking into account oil and gas prices and the
capital needs of HEP.
Unit Option Plan
On January 31, 1995, the board of directors of the general partner approved the
adoption of the 1995 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, 1997, 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 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 line of credit to May 31, 1999. Under the Credit
Agreement and an Amended and Restated Note Purchase Agreement ("Note Purchase
Agreement") (collectively referred to as the "Credit Facilities"), HEP has a
borrowing base of $46,000,000. HEP has amounts outstanding at December 31, 1997
of $30,700,000 under the Credit Agreement and $4,286,000 under the Note Purchase
Agreement. Subsequent to December 31, 1997, HEP repaid $14,000,000 of its
borrowings under the Credit Agreement and repaid its outstanding contract
settlement obligation of $2,732,000; therefore, HEP's unused borrowing base
totaled $25,014,000 at February 27, 1998.
Borrowings under the Note Purchase Agreement bear interest at an annual rate of
11.85%, which is payable quarterly. Annual principal payments of $4,286,000
began April 30, 1992, and the debt is required to be paid in full on April 30,
1998. HEP intends to fund the payment due in April 1998 through additional
borrowings under the Credit Agreement; thus, no portion of HEP's Note Purchase
Agreement is classified as current as of December 31, 1997.
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, 1997 the applicable
interest rate was 7.5%. Interest is payable monthly, and 16 quarterly principal
payments of $2,187,000, as adjusted for the anticipated borrowings to fund the
Note Purchase Agreement payment due in 1998, commence May 31, 1999.
The borrowing base for the Credit Facilities is redetermined semiannually. The
Credit Facilities are secured by a first lien on approximately 80% in value of
HEP's oil and gas properties. Additionally, aggregate distributions paid by HEP
in any 12 month period are limited 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.
HEP entered into contracts to hedge its interest rate payments on $15,000,000 of
its debt for each of 1997 and 1998 and $10,000,000 for each of 1999 and 2000.
HEP does not use the hedges for trading purposes, but rather for the purpose of
providing a measure of predictability for a portion of HEP's interest payments
under its debt agreement, which has a floating interest rate. In general, it is
HEP's goal to hedge 50% of the principal amount of its debt for the next two
years and 25% for each year of the remaining term of the debt. HEP has entered
into four hedges, one of which is an interest rate collar pursuant to which it
pays a floor rate of 7.55% and a ceiling rate of 9.85%, and the others are
interest rate swaps with fixed rates ranging from 5.75% to 6.57%. 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 or repaid at a future date.
As of December 31, 1997, HEP had a net over-produced position of 162,000 mcf
($374,000 valued at average annual 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
162,000 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" ("SAFS
130"). SAFS 130 established standards for reporting and display of comprehensive
income and its components (revenues, expenses, gains, and losses) in a full set
of general-purpose financial statements. SFAS 130 requires that all items that
are required to be recognized under accounting standards as components of
comprehensive income be reported in a financial statement that is displayed with
the same prominence as other financial statements. Reclassification of financial
statements for earlier periods provided for comparative purposes is required.
The Partnership is required to adopt SFAS 130 on January 1, 1998. The
Partnership has not completed the process of evaluating the impact that will
result from adopting SFAS 130 or the manner that will be used to disclose the
required information in its financial statements.
Cautionary Statement Regarding Forward-Looking Statements
In the interest of providing the Partnership's Unitholders and potential
investors 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 to come to pass, management is not able to predict
the future with absolute certainty. Forward-looking statements involve known and
unknown risks and uncertainties which may cause the 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 other things, volatility of oil and gas prices, competition,
risks inherent in the Partnership's oil and gas operations, the inexact nature
of interpretation of seismic and other geological and geophysical data,
imprecision of reserve estimates, the Partnership's ability to replace and
expand oil and gas reserves, and such other risks and uncertainties described
from time to time in the Partnership's periodic reports and filings with the
Securities and Exchange Commission. Accordingly, Unitholders and potential
investors are cautioned that certain events or circumstances could cause actual
results to differ materially from those projected.
Inflation and Changing Prices
Prices obtained for oil and gas production depend upon numerous factors that are
beyond the control of HEP, including the extent of domestic and foreign
production, imports of foreign oil, market demand, domestic and worldwide
economic and political conditions, and government regulations and tax laws.
Prices for both oil and gas have fluctuated from 1995 through 1997. The
following table presents the 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)
1997 $19.35 $19.08 $2.54 $2.31
1996 20.85 20.10 2.38 2.24
1995 16.98 17.36 1.58 1.82
HEP has entered into numerous financial contracts to hedge the price of its oil
and natural gas. The purpose of the hedges is to provide protection against
price decreases and to provide a measure of stability in the volatile
environment of oil and natural gas spot pricing.
The following table provides a summary of HEP's financial contracts:
Oil
Percent of
Production Contract
Period Hedged Floor Price
(per bbl)
1998 23% $16.62
1999 2% $15.38
Between 9% and 100% of the oil volumes hedged in each year 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.
Between 59% and 100% of the 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 prices range from $17.00 to $18.85 per barrel.
Gas
Percent of
Production Contract
Period Hedged Floor Price
(per mcf)
1998 42% $2.04
1999 24% $1.87
2000 14% $2.01
2001 4% $1.55
Between 0% and 38% 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 is $2.93 per mcf.
During the first quarter through February 27, 1998, the weighted average oil
price (for barrels not hedged) was approximately $15.70 per barrel, and the
weighted average price of natural gas (for mcf not hedged) was approximately
$2.10 per mcf.
Inflation
Inflation did not have a material impact on HEP in 1997 and is not anticipated
to have a material impact in 1998.
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 1997, HEP owned interests which ranged from 57.5% to
68.2% of the Mays; in 1996 HEP's ownership in the Mays ranged from 54.5% to
68.5%, and in 1995 HEP's ownership in the Mays ranged from 54.5% to 68.3%.
TABLE OF HEP EARNINGS FOR MANAGEMENT DISCUSSION
(In thousands except price)
For the Year Ended December 31, 1997 For the Year Ended December 31, 1996
------------------------------------ ------------------------------------
Direct Direct
Owned Mays Total Owned Mays Total
Oil production (bbl) 691 79 770 862 110 972
Gas production (mcf) 10,426 1,348 11,774 11,003 1,783 12,786
Average oil price $18.94 $20.27 $19.08 $19.92 $21.52 $20.10
Average gas price $ 2.23 $ 2.91 $ 2.31 $ 2.11 $ 3.05 $ 2.24
Oil revenue $13,089 $1,601 $14,690 $17,167 $2,367 $19,534
Gas revenue 23,302 3,918 27,220 23,178 5,440 28,618
Pipeline and other revenue 2,797 2,797 2,492 2,492
Interest income 324 72 396 356 66 422
--- ---- --- ------ ----- ------
Total revenue 39,512 5,591 45,103 43,193 7,873 51,066
------ ------ ------ ------- ------ ------
Production operating 10,498 562 11,060 10,782 729 11,511
Facilities operating 641 641 726 726
General and administrative 4,953 380 5,333 4,131 409 4,540
Depreciation, depletion, and amortization 10,630 1,331 11,961 11,729 1,771 13,500
Interest 3,096 3,096 3,878 3,878
Equity in income of HCRC (1,348) (1,348) (1,768) (1,768)
Minority interest 1,797 1,797 2,723 2,723
Litigation settlement (income) expense (234) (6) (240) 223 7 230
---- ---- ---- ---- ------ ------
Total expense 28,236 4,064 32,300 29,701 5,639 35,340
------ ----- ------ ------ ----- ------
Net income $11,276 $1,527 $12,803 $13,492 $2,234 $15,726
====== ===== ====== ====== ===== ======
TABLE OF HEP EARNINGS FOR MANAGEMENT DISCUSSION
(In thousands except price)
For the Year Ended December 31, 1995
Direct
Owned Mays Total
Oil production (bbl) 895 98 993
Gas production (mcf) 11,497 1,538 13,035
Average oil price $17.32 $17.74 $17.36
Average gas price $ 1.81 $ 1.92 $ 1.82
Oil revenue $ 15,501 $ 1,739 $ 17,240
Gas revenue 20,822 2,948 23,770
Pipeline and other revenue 2,444 2,444
Interest 263 63 326
--- -- ---
Total revenue 39,030 4,750 43,780
------ ----- ------
Production operating 10,658 640 11,298
Facilities operating 794 794
General and administrative 5,131 449 5,580
Depreciation, depletion, and amortization 14,058 1,769 15,827
Impairment of oil and gas properties 10,943 10,943
Interest 4,245 4,245
Equity in loss of HCRC 2,273 2,273
Minority interest 1,465 1,465
Litigation settlement expense 337 49 386
--- -- ---
Total expense 48,439 4,372 52,811
------ ----- ------
Net income (loss) $ (9,409) $ 378 $ (9,031)
======== ======= =======
1997 Compared to 1996
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.
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.
Pipeline, Facilities and Other
Pipeline, facilities 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 $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
Facilities operating expense represents operating expenses associated with
various smaller gathering systems operated by HEP. 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 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 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 of HCRC
Equity in earnings of HCRC represents HEP's share of its equity investment in
HCRC. HEP's equity in HCRC's earnings 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 Partnership resulting primarily
from decreased production from their properties.
Litigation Settlement Income (Expense)
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.
1996 Compared to 1995
Oil Revenue
Oil revenue increased $2,294,000 during 1996 as compared with 1995. The increase
is comprised of a 16% increase in the average oil price from $17.36 per barrel
in 1995 to $20.10 per barrel in 1996, partially offset by a decrease in
production, from 993,000 barrels in 1995 to 972,000 barrels in 1996. The
decrease in production is due to property sales and to normal production
declines.
The effect of HEP's hedging transactions was to decrease HEP's average oil price
from $20.85 per barrel to $20.10 per barrel, resulting in a $729,000 decrease in
oil revenue for 1996.
Gas Revenue
Gas revenue increased by $4,848,000 during 1996 as compared with 1995. The
increase is comprised of a 23% increase in the average gas price from $1.82 per
mcf in 1995 to $2.24 per mcf in 1996, partially offset by a decrease in gas
production from 13,035,000 mcf during 1995 to 12,786,000 mcf during 1996. The
decrease in production is due to decreases in allowable production limits and to
normal production declines, partially offset by increased production from
exploratory and developmental drilling projects in Montana, Wyoming and West
Texas.
The effect of HEP's hedging transactions was to decrease HEP's average gas price
from $2.38 per mcf to $2.24 per mcf, representing a $1,790,000 decrease in gas
revenues for 1996.
Interest Income
The increase in interest income of $96,000 during 1996 as compared with 1995
resulted from a higher average cash balance during 1996 as compared with 1995.
Production Operating Expense
Production operating expense increased $213,000 during 1996 as compared with
1995, primarily as a result of increased production taxes due to the 17%
increase in oil and gas revenue during 1996 discussed above.
Facilities Operating Expense
The decrease in facilities operating expense of $68,000 is primarily due to
decreased maintenance activity during 1996.
General and Administrative Expense
General and administrative expenses decreased $1,040,000 during 1996 as compared
with 1995 primarily due to a decrease in performance based compensation, a
decrease in salaries expense and employee benefits expense due to personnel
reductions during 1995 and lower legal expense in 1996 due to the settlement of
a significant lawsuit during 1995.
Depreciation, Depletion and Amortization Expense
Depreciation, depletion and amortization expense decreased $2,327,000 during
1996 as compared with 1995. The decrease is primarily the result of lower
capitalized costs in 1996 as compared with 1995, primarily due to the property
impairments recorded during 1995 and 1994.
Interest Expense
Interest expense decreased by $367,000 during 1996 as compared with 1995. The
decrease is due to a lower average outstanding debt balance during 1996 as
compared to 1995.
Equity in Earnings (Loss) of HCRC
HEP's equity in HCRC's earnings increased by $4,041,000 during 1996 as compared
to 1995. The increase is primarily the result of a 6% increase in HEP's
ownership of HCRC resulting from HEP's purchase of 38,895 shares of common stock
of HCRC during the second quarter of 1996. Also contributing to the increase
were higher oil and gas prices for HCRC during 1996 and the inclusion in 1995 of
impairment expense resulting from the write-off of HCRC's investment in an
Indonesian project and other property impairments.
Litigation Settlement Expense
Litigation settlement expense during 1996 and 1995 consists primarily of
expenses incurred to settle various individually insignificant claims against
HEP.
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page No.
FINANCIAL STATEMENTS:
Independent Auditors' Report 25
Consolidated Balance Sheets at December 31, 1997 and 1996 26-27
Consolidated Statements of Operations for the years
ended December 31, 1997, 1996 and 1995 28
Consolidated Statements of Partners' Capital for the
years ended December 31, 1997, 1996 and 1995 29
Consolidated Statements of Cash Flows for the years
ended December 31, 1997, 1996 and 1995 30
Notes to Consolidated Financial Statements 31-47
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION - (UNAUDITED) 48-51
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, 1997 and 1996 and for each of the three years
in the period ended December 31, 1997, 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, 1997 and 1996, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1997 in conformity
with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Denver, Colorado
February 27, 1998
HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31,
1997 1996
----- ----
CURRENT ASSETS
Cash and cash equivalents $ 6,622 $ 5,540
Accounts receivable:
Oil and gas revenues 8,772 9,405
Trade 4,609 4,507
Due from affiliates 588
Prepaid expenses and other current assets 1,551 928
------- -----
Total 22,142 20,380
------- ------
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method):
Proved mineral interests 624,621 607,875
Unproved mineral interests - domestic 2,315 1,244
Furniture, fixtures and other 3,513 3,366
------- -----
Total 630,449 612,485
Less accumulated depreciation, depletion,
amortization and property impairment (536,118) (523,936)
------- -------
Total 94,331 88,549
OTHER ASSETS
Investment in common stock of HCRC 15,048 13,700
Deferred expenses and other assets 82 163
------ ------
Total 15,130 13,863
------ ------
TOTAL ASSETS $131,603 $122,792
======== ========
<FN>
(Continued on the following page)
</FN>
HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31,
1997 1996
- ----- - ----
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 19,915 $ 15,185
Due to affiliates 159
Net working capital deficit of affiliate 448 581
Current portion of contract settlement 2,752
Current portion of long-term debt 5,810
------- ------
Total 23,115 21,735
------- ------
NONCURRENT LIABILITIES
Long-term debt 34,986 29,461
Contract settlement 2,512
Deferred liability 1,180 1,533
------- ------
Total 36,166 33,506
------- ------
Total Liabilities 59,281 55,241
------- ------
MINORITY INTEREST IN AFFILIATES 3,258 3,336
------- ------
COMMITMENTS AND CONTINGENCIES (NOTE 14)
PARTNERS' CAPITAL
Class A Units - 9,977,254 Units issued, 9,077,949
outstanding in 1997 and 1996 66,184 61,487
Class B Subordinated Units - 143,773 Units issued
and outstanding in 1997 and 1996 1,411 1,254
Class C Units - 664,063 Units issued and outstanding in
1997 and 1996 4,868 5,146
General Partner 3,580 3,307
Treasury Units - 899,305 Units in 1997 and 1996 (6,979) (6,979)
------- ------
Partners' Capital - Net 69,064 64,215
------- ------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $131,603 $122,792
======== ========
<FN>
The accompanying notes are an integral part of the
financial statements.
</FN>
HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands except per Unit)
For the Years Ended December 31,
1997 1996 1995
- ----- - ----- - ----
REVENUES:
Oil revenue $ 14,690 $ 19,534 $ 17,240
Gas revenue 27,220 28,618 23,770
Pipeline, facilities and other 2,797 2,492 2,444
Interest 396 422 326
------- ------- -----
45,103 51,066 43,780
------- ------- -----
EXPENSES:
Production operating 11,060 11,511 11,298
Facilities operating 641 726 794
General and administrative 5,333 4,540 5,580
Depreciation, depletion and amortization 11,961 13,500 15,827
Impairment of oil and gas properties 10,943
Interest 3,096 3,878 4,245
------- ------- -----
32,091 34,155 48,687
------- ------- -----
OTHER INCOME (EXPENSES):
Equity in earnings (loss) of HCRC 1,348 1,768 (2,273)
Minority interest in net income of affiliates (1,797) (2,723) (1,465)
Litigation settlement 240 (230) (386)
------- ------- -----
(209) (1,185) (4,124)
------- ------- -----
NET INCOME (LOSS) 12,803 15,726 (9,031)
CLASS C UNIT DISTRIBUTIONS ($1.00 PER UNIT) 664 664
------- ------- -----
NET INCOME (LOSS) ATTRIBUTABLE TO GENERAL PARTNER, CLASS
A AND CLASS B LIMITED PARTNERS $ 12,139 $ 15,062 $ (9,031)
CLASS B LIMITED PARTNERS ======== ======== ========
ALLOCATION OF NET INCOME (LOSS):
General partner $ 2,097 $ 2,569 $ 1,289
======== ========
Class A and Class B Limited partners $ 10,042 $ 12,493 $(10,320)
====== ======= =======
Per Class A Unit and Class B Unit - basic $ 1.09 $ 1.35 $ (1.07)
======= ========= =========
Per Class A Unit and Class B Unit - diluted $ 1.07 $ 1.35 $ (1.07)
======= ========= =========
Weighted average Class A Units and Class B
Units outstanding 9,222 9,240 9,683
======== ======== =====
<FN>
The accompanying notes are an integral part of the
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
Balance, December 31, 1994 $ 4,051 $ 77,342 $ 1,350 $ (3,940)
Increase in Treasury Units (2,145)
Syndication costs (63)
Distributions (2,359) (7,517) (116)
Net income (loss) 1,289 (10,148) (172)
----- ------- ----
Balance, December 31, 1995 2,981 59,614 1,062 (6,085)
Increase in Treasury Units (894)
Syndication costs (12)
Issuance of Class C Units (5,146) $5,146
Distributions (2,243) (5,270) (664)
Net income 2,569 12,301 192 664
----- ------ --- --- -------
Balance, December 31, 1996 3,307 61,487 1,254 5,146 (6,979)
Syndication costs (278)
Distributions (1,824) (5,188) (664)
Net income 2,097 9,885 157 664
----- ----- --- --- --------
Balance, December 31, 1997 $ 3,580 $ 66,184 $1,411 $4,868 $(6,979)
====== ====== ===== ===== ======
<FN>
The accompanying notes are an integral part of the
financial statements.
</FN>
HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the Years Ended December 31,
1997 1996 1995
---- - ----- - ----
OPERATING ACTIVITIES:
Net income (loss) $ 12,803 $ 15,726 $ (9,031)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion, amortization and
impairment 11,961 13,500 26,770
Depreciation charged to affiliates 221 265 256
Amortization of deferred loan costs and
other assets 81 167 201
Noncash interest expense 241 219 289
Minority interest in net income 1,797 2,723 1,465
Take-or-pay recoupment (126) (376) (571)
Equity in (earnings) loss of HCRC (1,348) (1,768) 2,273
Undistributed (earnings) loss of affiliates 197 (187) (886)
Changes in operating assets and liabilities
provided (used) cash net of noncash activity:
Oil and gas revenues receivable 633 (2,638) (547)
Trade receivables (102) (1,647) 182
Due from affiliates (2,948) 2,808 (1,161)
Prepaid expenses and other current assets (623) 163 261
Accounts payable and accrued liabilities 4,730 (2,159) (1,052)
Due to affiliates (133) (373)
------ ------ ------
Net cash provided by operating activites 27,384 26,423 18,449
------ ------ ------
INVESTING ACTIVITIES:
Additions to property, plant and equipment (3,233) (3,148) (2,727)
Exploration and development costs incurred (12,983) (9,467) (8,404)
Proceeds from sales of property, plant and equipment 133 5,294 394
Investment in affiliates (76) (449)
Refinance of Spraberry investment (4,715)
Other investing activities (29)
------ ------- -------
Net cash used in investing activities (16,188) (12,485) (10,737)
------- ------- -------
FINANCING ACTIVITIES:
Payments of long-term debt (7,285) (11,373) (7,379)
Proceeds from long-term debt 7,000 9,000 15,000
Distributions paid (7,676) (8,176) (10,020)
Distributions paid by consolidated affiliates to
minority interest (1,875) (2,429) (1,346)
Payment of contract settlement (305) (1,336)
Other financing activities (278) (92) (63)
------ --- -----
Net cash used in financing activities (10,114) (13,375) (5,144)
------- ------- ------
NET INCREASE IN CASH AND CASH
EQUIVALENTS 1,082 563 2,568
CASH AND CASH EQUIVALENTS:
BEGINNING OF YEAR 5,540 4,977 2,409
------ ----- -----
END OF YEAR $ 6,622 $ 5,540 $ 4,977
======== ======== ========
<FN>
The accompanying notes are an integral part of the
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
HEP has entered into numerous financial contracts to hedge the price of its oil
and natural gas. The purpose of the hedges is to provide protection against
price decreases and to provide a measure of stability in the volatile
environment of oil and natural gas spot pricing. The amounts received or paid
upon settlement of these contracts are recognized as oil or gas revenue at the
time the hedged volumes are sold.
Gas Balancing
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, 1997, HEP had a net over-produced position of 162,000 mcf
($374,000 valued at average gas prices). The general partner believes that this
imbalance can be made up from or repaid by 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, 1997 have been
decreased by 162,000 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%
<FN>
(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.
</FN>
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.
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.
Deferred Liability
The deferred liability as of December 31, 1997 and 1996 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, 1998 to Unitholders of record on December 31, 1997. This amount and
the general partner distribution were accrued as of year end. At December 31,
1997 and 1996, distributions payable of $2,093,000 and $1,996,000, 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 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
effect of its activities accrues 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, 1997 and 1996, the income tax bases of the
Partnership's oil and gas properties were approximately $94,000,000 and
$94,400,000, 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
During February 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 128 Earnings per Share ("SFAS 128"). SFAS
128 establishes standards for computing and presenting earnings per share (EPS),
and supersedes APB Opinion No. 15 and its related interpretations. It replaces
the presentation of primary EPS with a presentation of basic EPS, which excludes
dilution, and requires dual presentation of basic and diluted EPS for all
entities with complex capital structures. Diluted EPS is computed similarly to
fully diluted EPS pursuant to Opinion No. 15. SFAS 128 is effective for periods
ending after December 15, 1997, including interim periods, and requires
restatement of all prior period EPS data presented. HEP adopted SFAS 128
effective December 31, 1997, and has restated all prior period EPS data
presented to give retroactive effect to the new accounting standard.
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 9, 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).
All Unit and per Unit information has been restated to reflect the issuance of
Class A Units in connection with a lawsuit settlement further described in Note
12.
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.
Unit options have been ignored in the computation of diluted loss per share in
1995 because their inclusion would be anti-dilutive.
Income Units Per Unit
(In thousands except per Unit)
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
======= ===== =====
For the Year Ended December 31, 1995
Net loss per Class A Unit and Class B Unit - basic $(10,320) 9,683 $(1.07)
------- ----- =====
Net loss per Class A Unit and Class B Unit - diluted $(10,320) 9,683 $(1.07)
======= ===== =====
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 899,305 of its own Units at December 31, 1997 and 1996. These 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, 1997, 1996
and 1995, purchases by the following companies exceeded 10% of the total oil and
gas revenues of the Partnership:
1997 1996 1995
---- ---- ----
Conoco Inc. 20% 28% 30%
Marathon Petroleum Company 16% 11% 14%
El Paso Field Services Company 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, 1997, 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" ("SAFS
130"). SAFS 130 established standards for reporting and display of comprehensive
income and its components (revenues, expenses, gains, and losses) in a full set
of general-purpose financial statements. SFAS 130 requires that all items that
are required to be recognized under accounting standards as components of
comprehensive income be reported in a financial statement that is displayed with
the same prominence as other financial statements. Reclassification of financial
statements for earlier periods provided for comparative purposes is required.
The Partnership is required to adopt SFAS 130 on January 1, 1998. The
Partnership has not completed the process of evaluating the impact that will
result from adopting SFAS 130 or the manner that will be used to disclose the
required information in its financial statements.
Reclassifications
Certain reclassifications have been made to prior years' amounts to conform to
the classifications used in the current year.
NOTE 2 - OIL AND GAS PROPERTIES
The following table summarizes certain cost information related to HEP's oil and
gas activities:
For the Years Ended December 31,
1997 1996 1995
- ----- - ----- - ----
(In thousands)
Property acquisition costs:
Proved $ 1,942 $ 2,321 $ 2,727
Unproved 1,071 560 793
Development costs 7,607 8,218 11,333
Exploration costs 6,950 2,200 2,915
------- ----- -----
Total $17,570 $13,299 $17,768
====== ====== ======
Depreciation, depletion, amortization and impairment expense related to proved
oil and gas properties, per equivalent barrel of production for the years ended
December 31, 1997, 1996 and 1995, was $4.38, $4.35 and $7.21, respectively.
At December 31, unproved properties consist of the following:
1997 1996
---- ----
(In thousands)
Texas $ 982 $1,062
California 447
North Dakota 314
Other 571 182
------- ------
$2,314 $1,244
===== =====
NOTE 3 - PRINCIPAL ACQUISITIONS AND SALES
On July 1, 1996, HEP and HCRC completed a transaction involving the acquisition
from Fuel Resources Development Co., a wholly owned subsidiary of Public Service
Company of Colorado, and other interest owners of their interests in 38 coal bed
methane wells located in LaPlata County, Colorado and Rio Arriba County, New
Mexico. Thirty-four of the wells, were assigned to 44 Canyon LLC ("44 Canyon"),
a special purpose entity owned by a large east coast financial institution. The
wells qualify for tax credits under Section 29 of the Internal Revenue Code. HPI
manages and operates the properties on behalf of 44 Canyon. The $28.4 million
purchase price was funded by 44 Canyon through the sale of a volumetric
production payment to an affiliate of Enron Capital & Trade Resources Corp., a
subsidiary of Enron Corp., the sale of a subordinated production payment and
certain other property interests for $3.45 million to an affiliate of HEP and
HCRC, and additional cash contributed by the owners of 44 Canyon. The affiliate
of HEP and HCRC which purchased the subordinated production payment and other
property interests is owned equally by HEP and HCRC. The interests in the four
wells in Rio Arriba County were acquired directly by HEP and HCRC.
During 1997 and 1995, HEP had no individually significant property acquisitions
or sales.
NOTE 4 - DERIVATIVES
HEP has entered into numerous 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 a protection against price decreases and to provide
a measure of stability in the volatile environment of oil and natural gas spot
pricing. The amounts received or paid upon settlement of these contracts is
recognized as oil or gas revenue at the time the hedged volumes are sold.
The financial contracts used by 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.
The following table provides a summary of HEP's financial contracts:
Oil
Quantity of Production
Period Hedged Contract Floor Price
(bbl) (per bbl)
1995 380,000 $17.41
1996 300,000 18.33
1997 346,000 17.78
1998 175,000 16.62
1999 16,000 15.38
From 1998 forward, between 9% and 100% of the oil volumes hedged in each year
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. From 1998 forward, between 59% and 100% of the 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 prices range from $17.00
to $18.85.
Gas
Quantity of Production
Period Hedged Contract Floor Price
(mcf) (per mcf)
1995 6,439,000 $1.94
1996 5,479,000 1.94
1997 5,386,000 1.97
1998 4,835,000 2.04
1999 2,460,000 1.87
2000 1,244,000 2.01
2001 272,000 1.55
From 1998 forward, between 0% and 38% 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 is $2.93 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 Facilities described in Note 6.
NOTE 5 - 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, 1997, 1996 and 1995:
1997 1996 1995
- ----- - ----- - ----
(In thousands)
Current assets $15,874 $10,802 $ 8,312
Noncurrent assets 76,497 67,666 65,627
Current liabilities 10,043 10,849 15,514
Noncurrent liabilities 32,678 24,558 21,790
Revenue 32,411 34,445 25,484
Net income (loss) 5,585 8,160 (4,670)
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,
1997 1996 1995
- ----- - ----- - ----
Unproved properties $ 1,040 $ 573 $ 230
Proved properties 118,966 113,085 94,925
Accumulated depreciation, depletion,
amortization and property impairment (92,511) (89,175) (74,168)
-------- ------- -------
Net property $ 27,494 $ 24,483 $ 20,987
======== ======== ========
Costs Incurred in Oil and Gas Activities:
For the Years Ended December 31,
1997 1996 1995
- ----- - ----- - ----
Acquisition costs $1,303 $1,008 $4,168
Development costs 2,060 3,670 2,124
Exploration costs 2,851 382 845
----- --- ---
Total $6,214 $5,060 $7,137
===== ===== =====
Results of Operations for Oil and Gas Activities:
For the Years Ended December 31,
1997 1996 1995
- ----- - ----- ----
Oil and gas revenue $10,889 $11,690 $ 7,825
Production operating expense (3,746) (3,790) (2,894)
Depreciation, depletion, amortization
and property impairment expense (3,336) (3,257) (2,792)
Income tax benefit (expense) (761) 23 (813)
-------- ----- ------
Net income from oil and gas
activities $ 3,046 $ 4,666 $ 1,326
======= ======= =======
Proved Oil and Gas Reserve Quantities:
Gas Oil
Mcf Bbl
(unaudited)
Balance, December 31, 1997 27,268 2,065
====== =====
Balance, December 31, 1996 22,786 2,680
====== =====
Balance, December 31, 1995 15,782 2,482
====== =====
Standardized Measure of Discounted Future Net Cash Flows:
(unaudited)
December 31, 1997 $ 31,245
=======
December 31, 1996 $47,701
======
December 31, 1995 $25,532
======
NOTE 6 - DEBT
HEP's long-term debt at December 31, 1997 and 1996 consisted of the following:
1997 1996
---- - ----
(In thousands)
Note Purchase Agreement $ 4,286 $ 8,571
Credit Agreement 30,700 26,700
------ ------
Total 34,986 35,271
Less current maturities (5,810)
------ ------
Long-term debt $34,986 $29,461
======= =======
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 line of credit to May 31, 1999. Under the Credit
Agreement and an Amended and Restated Note Purchase Agreement ("Note Purchase
Agreement") (collectively referred to as the "Credit Facilities"), HEP has a
borrowing base of $46,000,000. HEP has amounts outstanding at December 31, 1997
of $30,700,000 under the Credit Agreement and $4,286,000 under the Note Purchase
Agreement. Subsequent to December 31, 1997, HEP repaid $14,000,000 of its
borrowings under the Credit Agreement and repaid its contract settlement
obligation of $2,752,000; therefore, HEP's unused borrowing base totaled
$25,014,000 at February 27, 1998.
Borrowings under the Note Purchase Agreement bear interest at an annual rate of
11.85%, which is payable quarterly. Annual principal payments of $4,286,000
began April 30, 1992, and the debt is required to be paid in full on April 30,
1998. HEP intends to fund the payment due in April 1998 through additional
borrowings under the Credit Agreement; thus, no portion of HEP's Note Purchase
Agreement is classified as current as of December 31, 1997.
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, 1997 the applicable
interest rate was 7.5%. Interest is payable monthly, and 16 quarterly principal
payments of $2,187,000, as adjusted for the anticipated borrowings to fund the
Note Purchase Agreement payment due in 1998, commence May 31, 1999.
The borrowing base for the Credit Facilities is redetermined semiannually. The
Credit Facilities are secured by a first lien on approximately 80% in value of
HEP's oil and gas properties. Additionally, aggregate distributions paid by HEP
in any 12 month period are limited 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.
HEP entered into contracts to hedge its interest rate payments on $15,000,000 of
its debt for each of 1997 and 1998 and $10,000,000 for each of 1999 and 2000.
HEP does not use the hedges for trading purposes, but rather for the purpose of
providing a measure of predictability for a portion of HEP's interest payments
under its debt agreement, which has a floating interest rate. In general, it is
HEP's goal to hedge 50% of the principal amount of its debt for the next two
years and 25% for each year of the remaining term of the debt. HEP has entered
into four hedges, one
of which is an interest rate collar pursuant to which it pays a floor rate of
7.55% and a ceiling rate of 9.85%, and the others are interest rate swaps with
fixed rates ranging from 5.75% to 6.57%. The amounts received or paid upon
settlement of these transactions are recognized as interest expense at the time
the interest payments are due. At December 31, 1997, HEP's debt maturity
schedule is as follows:
(In thousands)
1998 $
1999 6,561
2000 8,748
2001 8,748
2002 8,748
Thereafter 2,181
-------
Total $34,986
========
NOTE 7 - 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 has been recorded equal to the present value of
this amount discounted at 10.68%, HEP's estimated borrowing cost at the time of
settlement. HEP also repaid $1,629,000 which represented suspended payments to
the pipeline for previous years in equal monthly installments of $33,937 which
began April 1992 and continued through March 1996. This amount was previously
recorded as an offset to the full cost pool at the time the contract was
initially abrogated by the pipeline. As payment of this obligation was made it
was charged to the full cost pool.
At December 31, 1997, the current contract settlement balance consists of a
payment of $2,767,000 due in February 1998, net of unaccreted discount of
$15,000.
NOTE 8 - 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 equal to or greater than
$.20 per Class A Unit are made on Class A Units.
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 9 - 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 2.4% for 1997 and 1996 and 1.4% for domestic
wells for 1995. In 1995, HEP also had an international incentive plan and the
percentage interest in cash flow for that plan was 3%. Beginning in 1996, the
domestic and international plans were combined. The specified percentage of cash
flow is then allocated among certain key employees who are participants in the
Plan for that year. Each award under the plan (with regard to domestic
properties) represents the right to receive for five years a portion of the
specified share of the cash award, at the conclusion of which the participants
are each paid a share of an amount equal to a specified percentage (80% for
1997, 1996 and 1995) of the remaining net present value of the qualifying wells,
and the award for that year terminates. The expenses attributable to the plans
were $277,000 in 1997, $148,000 in 1996 and $119,000 in 1995 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 Unit Option Plan ("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.
A summary of options granted under the Option Plan and the changes therein
during the years ended December 31, 1997, 1996 and 1995 is presented below:
1997 1996 1995
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
Granted 425,000 $5.75
------------- -------- -------------- -------- ------- ----
Outstanding at end of year 425,000 $5.75 425,000 $5.75 425,000 $5.75
======= ==== ======= ==== ======= ====
Options exercisable at year end 425,000 $5.75 283,330 $5.75 141,665 $5.75
======= ==== ======= ==== ======= ====
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 the Option Plan. Had compensation expense for the Option Plan
been determined based on the fair value at the grant date for the options
awarded in 1995 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:
1997 1996 1995
---- ---- ----
Net income (loss): as reported $12,803,000 $15,726,000 $(9,031,000)
pro forma 12,730,000 15,544,000 (9,432,000)
Net income (loss)
per Class A and B Unit - basic:
as reported $1.09 $1.35 $(1.07)
pro forma $1.08 1.33 $(1.11)
Net income (loss)
per Class A and Class B Unit - diluted
as reported $1.07 $1.35 $(1.07)
pro forma $1.07 $1.33 $(1.11)
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:
Expected dividend yield 6%
Expected price volatility 28%
Risk-free interest rate 7.6%
Expected life of options 10 years
NOTE 10 - 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 $588,000 at
December 31, 1997 and payables to affiliates of HEP of $159,000 at December 31,
1996, which represent net revenues net of operating costs and expenses. The
intercompany balances are settled monthly.
HPI is reimbursed by HEP for costs and expenses which includes 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 1997, 1996 and 1995 were
as follows:
1997 1996 1995
- ---- - ----- - ----
(In thousands)
Technical $966 $1,249 $1,100
Nontechnical 896 1,110 1,321
Included in the nontechnical allocation attributable to HEP's direct interest
for 1997, 1996 and 1995 is approximately $275,000, $152,000 and $156,000,
respectively, of consulting fees under a consulting agreement with Hallwood
Group. Also included in the nontechnical allocation is $301,000, $309,000 and
$369,000 in 1997, 1996 and 1995, 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. This agreement was terminated effective December 1996. The
amount of consulting fees allocated to the Partnership under this agreement was
$125,000 in both 1996 and 1995.
NOTE 11 - STATEMENT OF CASH FLOWS
Cash paid during 1997,1996 and 1995 for interest totaled $2,775,000, $3,492,000
and $3,356,000, respectively.
NOTE 12 - LITIGATION SETTLEMENTS
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. In September 1995, the court order approving the
settlement in the class action lawsuit styled In re. Hallwood Energy Partners,
L.P. Securities Litigation became final. As part of the settlement, on September
28, 1995, HEP paid $2,870,000 in cash (which was recorded as an expense in the
December 31, 1994 financial statements as the estimated cost associated with the
litigation) and issued 1,158,696 Class A Units with a market value of $5,330,000
to a nominee of the class. HCRC subsequently exercised an option to purchase
these Units from the nominee for $5,330,000 in cash. Other defendants
contributed an additional $900,000 in cash to the settlement. The net proceeds
of the settlement were distributed to a class consisting of former owners of
limited partner interests in Energy Development Partners, Ltd. ("EDP") who
exchanged their units in that entity for Units of HEP pursuant to the merger of
EDP and HEP on May 9, 1990 (the "Transaction").
Upon issuance, these Class A Units were treated, for financial statement
purposes, as additional Class A Units issued in connection with the Transaction,
which was accounted for as a reorganization of entities under common control, in
a manner similar to a pooling of interest, and have been reflected as
outstanding Class A Units since May 9, 1990, the date of the Transaction. As a
result of the settlement, the number of Units outstanding and the net income
(loss) per Class A Unit and Class B Unit have been retroactively restated for
all periods subsequent to the Transaction date.
NOTE 13 - LEGAL PROCEEDINGS
On December 3, 1997, Arcadia Exploration and Production Company ("Arcadia")
filed a Demand for Arbitration 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 herein as "Hallwood"), claiming that Hallwood breached
a Purchase and Sale Agreement dated August 25, 1997, between Arcadia and HEP and
HCRC. Arcadia's Demand for Arbitration seeks specific performance of the
agreement which Arcadia claims requires Hallwood to purchase oil and gas
properties from Arcadia for approximately $27 million. HEP and HCRC terminated
the agreement because of environmental and title problems with the properties.
Additionally, Arcadia seeks incidental and special damages, prejudgment
interests and attorneys' fees and costs. Hallwood filed its Answering Statement
and Counterclaim asserting that it properly terminated and/or rescinded the
Agreement and seeking refund of Hallwood's earnest money deposit, prejudgment
interest, attorneys' fees and costs. HEP's management intends to vigorously
defend the claims asserted by Arcadia and intends to vigorously pursue the
counterclaim against Arcadia. This matter is currently in its preliminary stages
as pre-hearing discovery has only just commenced. Thus, it is too early to
predict the ultimate outcome of this arbitration proceeding.
Concise Oil and Gas Partnership ("Concise"), a wholly owned subsidiary of the
Partnership, is 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 approximately
150 plaintiffs in this proceeding are seeking unspecified damages for alleged
breaches of certain oil, gas and mineral leases in the Northeast Montegut Field,
Terrebonne Parrish, Louisiana. In addition, they are asking for an accounting
from Concise for production of natural gas for the period of time from 1983
through November 1987. Specifically, as to the claims against Concise, the suit
alleges that Concise failed to obtain the prices to which it was allegedly
entitled for natural gas sold in this field in the 1980s under a long-term
natural gas sales contract. The plaintiffs, royalty and overriding royalty
owners, allege that as a result of the alleged imprudent marketing practices,
they are entitled to their share of the prices which Concise should have
obtained. Plaintiffs have also sued approximately 35 other companies and
individuals, and allege that Concise is jointly and severally liable with the
rest of the defendants for the claims raised by the plaintiffs. The judge has
recently ruled against the plaintiffs on their claim of joint and several
liability, and has also ruled that the applicable statute of limitations is
three years, rather than ten years as the
plaintiffs claimed. The claims raised against the other defendants are similar
in substance to those raised against Concise, but seek damages and an accounting
for the period of time from 1983 until the present time. While the trial of this
case is currently set for August 1998, the trial date will most likely be
continued beyond that date. The outcome of this litigation cannot be predicted
with certainty. However, the Partnership believes that the claims asserted
against Concise are without merit and intends to vigorously defend against them.
In addition to the litigation noted above, the Partnership and its subsidiaries
are from time to time subject to routine litigation and claims incidental to
their business, which the Partnership believes will be resolved without material
effect on the Partnership's financial condition, cash flows or operations.
NOTE 14 - COMMITMENTS
HPI leases office facilities under operating leases which expire in 1999. Rent
expense under these leases is allocated to HEP and its affiliates. Remaining
commitments under these leases mature as follows:
Year Ending Annual Rentals
December 31, (in thousands)
1998 $632
1999 316
---
$948
Rent expense allocated to HEP was $288,000, $304,000 and $299,000 for the years
ended December 31, 1997, 1996 and 1995, respectively.
NOTE 15 - ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
The following disclosure of the estimated fair value of financial instruments is
made in accordance with the requirements of SFAS No. 107, "Disclosures about
Fair Value of Financial Instruments." The estimated fair value amounts have been
determined by the 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, 1997
Carrying Estimated Fair
Amount Value
(In thousands)
Liabilities:
Interest rate hedge contracts $ -0- $ 186
Oil and gas hedge contracts -0- 1,029
Current portion of contract settlement 2,752 2,752
Long-term debt 34,986 34,986
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.
The current portion of the contract settlement is carried in the accompanying
balance sheets at an amount which is a reasonable estimate of its fair value.
Long-term debt is carried in the accompanying balance sheet at an amount which
is a reasonable estimate of its fair value.
The fair value estimates presented herein are based on pertinent information
available to management as of December 31, 1997. Although management is not
aware of any factors that would significantly affect the estimated fair value
amounts, such amounts have not been comprehensively revalued for purposes of
these financial statements since that date, and current estimates of fair value
may differ significantly from the amounts presented herein.
NOTE 16 - SUBSEQUENT EVENT
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 discounts
and expenses, were approximately $16,315,000. HEP used $14,000,000 of the net
proceeds to repay borrowings under its Credit Agreement and applied the
remaining net proceeds toward the repayment of HEP's outstanding contract
settlement obligation of $2,752,000.
HALLWOOD ENERGY PARTNERS, L.P.
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
DECEMBER 31, 1997
(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. At
December 31, 1997, oil and gas prices averaged $16.90 per bbl of oil and $2.30
per mcf of gas 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, 1997
prices result in 5.8 million bbls of oil, and 93.1 billion cubic feet of gas and
a standardized measure of $129,000,000. The Mays are included on a consolidated
basis, and 53,000 bbls of oil and 1.5 billion cubic feet of gas, representing a
discounted present value of $3,700,000 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 200,000 bbls of
oil and 6 billion cubic feet of gas with a standardized measure of $10,000,000
at December 31, 1997.
HEP's standardized measure of future net cash flows has been decreased by
$2,620,000 at December 31, 1997 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, 1994 85,585 6,738
Extensions and discoveries 5,997 1,902
Revisions of previous estimates 4,248 464
Sales of reserves in place (45) (41)
Purchase of reserves in place 362 28
Production (13,035) (993)
------- ----
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)
Purchase 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)
Purchase of reserves in place 619 128
Production (11,774) (770)
------- ----
Balance, December 31, 1997 93,053 5,767
====== =====
Proved Developed Reserves:
Balance, December 31, 1995 73,378 7,444
====== =====
Balance, December 31, 1996 85,848 7,056
====== =====
Balance, December 31, 1997 89,816 5,181
====== =====
HALLWOOD ENERGY PARTNERS, L. P.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(In thousands)
(Unaudited)
December 31,
------------
1997 1996 1995
---- ---- ----
Future cash flows $ 293,000 $ 509,000 $ 317,000
Future production and development costs (115,000) (175,000) (130,000)
------- -------- --------
Future net cash flows before discount 178,000 334,000 187,000
10% discount to present value (49,000) (128,000) (63,000)
------- -------- -------
Standardized measure of discounted future net cash
flows $ 129,000 $ 206,000 $ 124,000
========= ========= =========
HALLWOOD ENERGY PARTNERS, L. P.
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(In thousands)
(Unaudited)
For the Years Ended December 31,
--------------------------------
1997 1996 1995
---- ---- ----
Standardized measure of discounted future net
cash flows at beginning of year $206,000 $124,000 $104,000
Sales of oil and gas produced, net of production
costs (30,209) (35,915) (29,712)
Net changes in prices and production costs (78,965) 75,085 17,015
Extensions and discoveries, net of future
production and development costs 9,592 7,144 16,836
Changes in estimated future development costs (10,012) (6,515) (11,321)
Development costs incurred 7,607 8,218 11,333
Revisions of previous quantity estimates (8) 20,032 6,817
Purchases of reserves in place 1,457 14,721 513
Sales of reserves in place (204) (9,742) (281)
Accretion of discount 20,600 12,400 10,400
Changes in production rates and other 3,142 (3,428) (1,600)
----- ------ ------
Standardized measure of discounted future net
cash flows at end of year $129,000 $206,000 $124,000
======= ======= =======
The standardized measure of discounted future net cash flows is calculated using
year end average oil and gas prices. At December 31, 1997, oil and gas prices
averaged $16.90 per bbl of oil and $2.30 per mcf of gas. If average oil and gas
prices as of February 27, 1998 of $15.70 per bbl of oil and $2.10 per mcf of gas
had been used in this calculation, the standardized measure of discounted future
net cash flows would have been approximately 12% lower.
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 operation 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, 53, 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, 54, 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, 43, 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, 45, 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.
Robert S. Pfeiffer, 41, has served as Vice President of Hallwood G.P. and HPI
since August 1986. He was Vice President of HEC from June 1991 until November
1996. Mr. Pfeiffer became Chief Financial Officer of HPI in June 1994. He has
been Vice President of HPI since June 1992. He joined Hallwood G.P. and HPI in
1984. From July 1979 to May 1984, he was employed by Price Waterhouse as a
senior accountant. Mr. Pfeiffer is a member of the American Institute of
Certified Public Accountants and the Colorado Society of Certified Public
Accountants. Mr. Pfeiffer resigned his positions with Hallwood G.P. and all
affiliated entities effective March 6, 1998.
Betty J. Dieter, 50, has been Vice President of HPI responsible for domestic
operations since January 1995. Her previous positions with HPI have included
Operations Manager, Rocky Mountain and Mid-Continent District Manager and
Manager for Operations Accounting and Administration. She joined HPI in 1985,
and has 25 years experience in accounting and operations, 18 of which are in the
oil and gas industry. Ms. Dieter is a Certified Public Accountant.
George Brinkworth, 55, has been Vice President-Exploration of HPI since August
1994. He became associated with HPI in 1987 when he was President of a joint
venture program funded by HPI and two other domestic oil companies. Mr.
Brinkworth has 33 years experience with various exploration and production
companies, including previous responsibility for operations in the United
Kingdom, Spain, Morocco, Egypt and Indonesia. He is a registered geophysicist in
the State of California.
William H. Marble, 47, has served as Vice President of HPI since December 1990.
His previous positions with HPI have included Texas/Gulf Coast District Manager,
Manager of Nonoperated Properties and Chief Engineer. He joined a predecessor
general partner of the Partnership in 1984. Mr. Marble is a registered engineer
in the State of Colorado and has 23 years oil and gas engineering experience.
Brian M. Troup, 50, 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. 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, 55, 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, 68, 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, 63, has served as a director of Hallwood G.P. since March
1997. He was a director of HEC from March 1995 until November 1996. 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. Mr.
Collins is now a private investor.
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, 1997, all officers and directors of Hallwood G.P., Inc. and greater than
ten-percent beneficial owners complied with applicable filing requirements.
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 1997 the Partnership reimbursed HPI for approximately
$1,286,000 of expenses, of which $604,958 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, 1997) for services to the Partnership, its
subsidiaries and its General Partner for the years ended December 31, 1997,
1996, and 1995.
Summary Compensation Table
Long Term
Annual Compensation Compensation
Securities LTIP
Year Salary Bonus Underlying Payouts All Other
Name & Principal Position Options/SARs (#) Compensation (1)
- ------------------------- ---------------- - ----------------
Anthony J. Gumbiner (2)....... 1997 $ 0 $ 0 (4) $ 0 $ 0
Chief Executive 1996 250,000 0 0 0 0
Officer 1995 250,000 0 (3) 0 0
William L. Guzzetti........... 1997 204,294 143,870 (4) 42,854 4,750
President and Chief 1996 204,294 131,500 0 33,170 5,699
Operating Officer 1995 204,412 75,000 (3) 15,753 6,004
Russell P. Meduna............. 1997 163,664 111,520 (4) 42,854 4,750
Executive Vice 1996 163,664 101,900 0 33,170 4,500
President 1995 167,364 161,000 (3) 15,753 4,810
Robert S. Pfeiffer (5) 1997 107,518 102,880 (4) 30,124 4,750
Vice President and 1996 107,518 56,700 0 23,092 4,300
Chief Financial Officer 1995 109,949 94,000 (3) 11,692 3,160
Cathleen M. Osborn............ 1997 105,685 100,000 (4) 30,124 4,750
Vice President and 1996 105,685 62,400 0 23,092 4,500
General Counsel 1995 109,069 95,000 (3) 11,692 3,160
- ----------------------
(1) Employer contribution to 401(k) and a service award of $1,199 paid to
Mr. Guzzetti in 1996.
(2) For 1995 and 1996, Mr. Gumbiner had a Compensation Agreement with HPI.
$250,000 was paid under this agreement in 1995 and 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 1995 and 1996, pursuant to which Hallwood Group
received an annual consulting fee of $300,000 from affiliates of HPI.
During 1997, 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.
(3) Consists of the following options granted in 1995. The HCRC Options
have been adjusted to give effect to a 3-for-1 split effective in 1997.
Name Company Securities Underlying
Options/SARs (#)
Anthony J. Gumbiner.......................... HEP 127,500
HCRC 47,700
William L. Guzzetti.......................... HEP 63,750
HCRC 23,850
Russell P. Meduna............................ HEP 59,500
HCRC 22,260
Robert S. Pfeiffer........................... HEP 25,500
HCRC 9,540
Cathleen M. Osborn........................... HEP 25,500
HCRC 9,540
(4) 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
Robert S. Pfeiffer........................... 9,540
Cathleen M. Osborn........................... 9,540
(5) Mr. Pfeiffer resigned his positions with Hallwood G.P. and all affiliated
entities effective March 6, 1998.
Option Grants and Exercises in Last Fiscal Year
The following table sets forth the options to purchase Common Stock of HCRC
granted to executive officers during 1997. No options granted to executive
officers were exercised in 1997.
Option/SAR Grants in Last Fiscal Year
Potential Realized Value at
Assumed Annual Rates of Stock
Price Appreciation for Option
Individual Grants Term (2)
Number of % of Total
Securities Options/SARs
Underlying Granted Exercise or 5% 10%
Options/SARs Employees in Base Price Expiration $33.16 $52.73
Granted Fiscal Year ($/Share) Date Share Price Share Price
(1)
Name
Anthony J. Gumbiner 47,700 30 $20.33 06/17/07 $609,865 $1,545,517
William L. Guzzetti 23,850 15 20.33 06/17/07 304,932 772,759
Russell P. Meduna 22,260 14 20.33 06/17/07 284,604 742,242
Robert S. Pfeiffer(3) 9,540 6 20.33 06/17/07 121,973 309,104
Cathleen M. Osborn 9,540 6 20.33 06/17/07 121,973 309,104
(1) Options have a ten-year term and vest cumulatively over three years at
the rate of 1/3 on each of 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 HCRC.
(2) Securities and Exchange Commission Rules require calculation of
potential realizable value assuming that the market price of the Common
Stock appreciates in value at 5% and 10% annualized rates. At a 5%
annualized rate of appreciation, the Common Stock price would be $33.16
at the end of ten years. At a 10% annualized rate of appreciation, the
Common Stock price would be $52.73 at the end of ten years. No gain to
an executive officer is possible without an appreciation in Common
Stock value, which will benefit all holders of Common Stock. The actual
value an executive officer may receive depends on market prices for the
Common Stock, and there can be no assurance that the amounts reflected
will actually be realized.
(3) Mr. Pfeiffer resigned from HCRC effective March 6, 1998, and his
options terminated on that date.
Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values
Number of Securities Underlying Value of Unexercised
Unexercised Options/SARs at FY-End (#) In-the-Money Options/SARs at FY-End
Exercisable/Unexercisable (1)(3) ($)
--------------------------------
Name Exercisable/Unexercisable (2)(4)
Anthony J. Gumbiner HEP 127,500 / 0 334,688 / 0
HCRC 63,600 / 31,800 805,494 / 76,956
William L. Guzzetti HEP 63,750 / 0 167,344 / 0
HCRC 31,800 / 15,900 402,747 / 38,478
Russell P. Meduna HEP 59,500 / 0 156,188 / 0
HCRC 29,680 / 14,840 375,897 / 35,913
Robert S. Pfeiffer HEP 25,500 / 0 66,938 / 0
HCRC 12,720 / 6,360 161,099 / 15,391
Cathleen M. Osborn HEP 25,500 / 0 66,938 / 0
HCRC 12,720/ 6,360 161,099 / 15,391
- ----------------------
(1) All of the HEP options expire January 31, 2005.
(2) The exercise price of the HEP options is $5.75 per Class A Unit.
The closing price of the Class A Units was $8.375 on December 31, 1997.
(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.
(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 $22.25 on
December 31, 1997. The exercise prices have been adjusted to reflect a
3-for-1 stock split effective in 1997.
Long-Term Incentive Plan
The following table describes performance units awarded to the executive
officers of Hallwood G.P. for 1997 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 Until Payout Price-Based Plans(1)
Anthony J. Gumbiner(2) -- -- $ --
William L. Guzzetti 0.0820 2002 23,266
Russell P. Meduna 0.0820 2002 23,266
Robert S. Pfeiffer 0.0560 2002 15,889
Cathleen M. Osborn 0.0560 2002 15,889
- -----------------------
(1) This 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 present 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.
(2) In addition, an award of .4200 units, with an estimated future payout of
$119,165, was made to HSC Financial, with which Mr. Gumbiner is associated.
The payout period ends in 2002.
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 percentage of the remaining net
present value of estimated future production from domestic wells for which 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
after the award, 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 1997 Plan Year were made in January 1997. No other awards
were made in 1997. For the 1997 Plan Year, the Compensation Committee of
Hallwood G.P. determined that the total Plan Cash Flow would be equal to 2.4% 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 1997 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, to the extent of 70% of the total award, and on
individual performance, to the extent of 30% of the total award.
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 1997, 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 1997. Mr.
Gumbiner is Chief Executive Officer and a director, and Mr. Guzzetti is
President and a director, of Hallwood Realty. During 1997, 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 $275,000 was paid in 1997 by the Partnership
pursuant to this arrangement. For 1995 and 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 1997, the Partnership reimbursed Hallwood Group for
approximately $301,000 of expenses.
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table shows information, as of February 27, 1998, 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/directors as a group.
Amount
Beneficially
Name and Address of Owner Title of Class Owned Percent of Class
------------------------- -------------- --- ------ ----------------
The Hallwood Group Incorporated Class A Units (1) 657,260 6.5
3710 Rawlins Street, Suite 1500 Class B Units 143,773 100.0
Dallas, Texas 75219 Class C Units 43,816 1.8
Hallwood Consolidated Resources Corporation Class A Units 1,948,189 19.5
4582 S. Ulster Street Parkway, Suite 1700 Class C Units 129,877 5.3
Denver, Colorado 80237
Heartland Advisors, Inc Class A Units (2) 880,200 8.8
790 North Milwaukee Street
Milwaukee, Wisconsin 53202
William Baxter Lee, III Class A Units (3) 707,000 7.1
c/o Glankler Brown, PLLC Class C Units (3) 37,000 1.5
1700 One Commerce Square
Memphis, Tennessee
Anthony J. Gumbiner Class A Units 127,500 *
William L. Guzzetti Class A Units 63,850 *
Class C Units 6 *
Russell P. Meduna Class A Units 59,500 *
Cathleen M. Osborn Class A Units 25,500 *
Robert S. Pfeiffer Class A Units 16,803 *
Class C Units 20 *
Brian M. Troup Class A Units 85,000 *
Hans-Peter Holinger
Rex A. Sebastian Class A Units 400 *
Class C Units 26 *
Nathan C. Collins
All directors and executive officers as a Class A Units (4) 378,553 3.7
group (9 persons) Class C Units 52 *
- ------------
* Less than 1%.
(1) Includes 143,773 Class B Units (100% of the Class B Units) that are
convertible into Class A Units one-for one.
(2) According to the Amendment to Schedule 13G filed January 30, 1998 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.
(4) According to Schedules 13D dated November 26, 1997.
(5) Consists of 803 Class A Units and currently exercisable options to purchase
377,750 Class A Units.
See Item 8 - Financial Statements and Supplementary Data (Note 9 to the
Financial Statements) for a description of HEP's Unit Option Plan.
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
See Item 8 - Financial Statements and Supplementary Data (Note 10 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.
(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
(10) 10.12 - Amendment to the Third Amended and Restated Agreement of
Limited Partnership of HEP Operating Partners, L.P.
(10) 10.13- Second Amendment to the Second Amended and Restated
Agreement of Limited Partnership of EDP Operating, Ltd.
*(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
(7) 21 - Subsidiaries of Registrant
23.1 - Consent of Deloitte & Touche LLP
23.2 - Consent of Deloitte & Touche LLP
--------------
(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 Form10-Q for the quarter
ended September 30, 1997.
*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: February 27, 1998 By: /s/William L.Guzzetti
William L. Guzzetti
President and Director
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
Signature Capacity Date
/s/Anthony J. Gumbiner Chairman of the Board and February 27, 1998
Anthony J. Gumbiner Director (Chief Executive Officer)
/s/Brian M. Troup Director February 27, 1998
Brian M. Troup
/s/Hans-Peter Holinger Director February 27, 1998
Hans-Peter Holinger
/s/Rex A. Sebastian Director February 27, 1998
Rex A. Sebastian
/s/Nathan C. Collins Director February 27, 1998
Nathan C. Collins
/s/Robert S. Pfeiffer Principal Accounting Officer February 27, 1998
Robert S. Pfeiffer