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 [FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995
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
(State or other jurisdiction 84-0987088
ofincorporation or (I.R.S. Employer
organization) Identification Number)
4582 SOUTH ULSTER STREET
PARKWAY SUITE 1700
DENVER, COLORADO 80237
(Address of principal (Zip Code)
executive offices)
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
<TABLE>
<CAPTION>
The aggregate market value of the Class A and Class C
Units held by nonaffiliates of the registrant as of
February 27, 1996 was approximately $32,364,708.<PAGE>
Number of Units outstanding as of February 27, 1996
<S> <C>
Class A 9,977,254
Class B 143,773
Class C 480,734
</TABLE>
PART I
ITEM 1 - BUSINESS
Hallwood Energy Partners, L.P. ("HEP" or the "Partnership"), is a publicly
traded Delaware limited partnership engaged in the production, sale and
transportation of oil and gas and in the acquisition, exploration,
development and operation of oil and gas properties. The principal
objectives of HEP are to maintain or expand its reserve base and to provide
cash distributions to the holders of its units of limited partner interests
("Units"). The general partner of HEP is Hallwood Energy Corporation ("HEC")
which has been engaged in oil and gas exploration and development since its
incorporation in 1968. 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 HEC is
the sole general partner of HEPO. Hallwood G.P., Inc., a wholly-owned
subsidiary of HEC, is the sole general partner and HEP is the sole limited
partner 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, 1996, HPI had 133 employees.
MARKETING
The oil and gas produced from the properties owned by HEP has typically been
marketed through normal channels for such products. Oil is generally sold to
purchasers at field prices posted by the principal purchasers of crude oil in
the areas where the producing properties are located. In response to the
volatility in the oil markets, HEP entered into financial contracts for
hedging transactions of between 3% and 22% of its estimated oil production
for 1996 through 1999.
The majority of HEP's gas production is sold on the spot market and is
transported in intrastate and interstate pipelines. HEP entered into
financial contracts for hedging transactions of between 17% and 47% of its
estimated gas production for 1996 through 2000.
The purpose of the hedges is to provide protection against price drops 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.
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, sales to Conoco Inc. and Marathon Petroleum Company
accounted for 30% and 14%, respectively, of total oil and gas sales of the
Partnership for the year ended December 31, 1995 and 23% and 12%,
respectively, of total oil and gas sales of the Partnership for the year
ended December 31, 1994. Sales to Conoco Inc., Koch Oil Company and Marathon
Petroleum Company accounted for 21%, 11% and 10%, respectively, of total oil
and gas sales of the Partnership for the year ended December 31, 1993.
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
In the course of its exploration and development activities, HEP must compete
with other entities for the acquisition of undeveloped acreage and desirable
leaseholds. As described above under "Marketing," production is sold on the
spot market, thereby reducing sales competition; however, oil and gas must
compete with coal, atomic energy, hydro-electric power and other forms of
energy.
REGULATION
Production and sale of oil and gas is subject to federal and state
governmental regulation in a variety of ways, including environmental
regulations, labor laws, interstate sales, excise taxes and federal and
Indian lands royalty payments. Failure to comply with these regulations may
result in fines, cancellation of licenses to do business and cancellation of
federal, state or Indian leases.
The production of oil and gas is subject to regulation by the state
regulatory agencies in the states in which HEP does business. These agencies
make and enforce regulations to prevent waste of oil and gas and to protect
the rights of owners to produce oil and gas from a common reservoir. The
regulatory agencies regulate the amount of oil and gas produced by assigning
allowable production rates to wells capable of producing oil and gas.
ENVIRONMENTAL CONSIDERATIONS
The exploration for, and development of, oil and gas involves the extraction,
production and transportation of materials which, under certain conditions,
can be hazardous or can cause environmental pollution problems. In light of
the current interest in environmental matters, the general partner cannot
predict what effect possible future public or private action may have on the
business of HEP. The general partner is continually taking actions necessary
in its operations to ensure conformity with applicable federal, state and
local environmental regulations and does not presently anticipate that the
compliance with federal, state and local environmental regulations will have
a material adverse effect upon capital expenditures, earnings 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 and financial position.
ITEM 2 - PROPERTIES
OIL AND GAS PROPERTIES
The following reserve information for HEP represents estimated quantities of
proved oil and gas reserves which are located in the United States. 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 Partnership's reserves have been calculated using two methodologies:
"average price" and the pricing case mandated by the Securities and Exchange
Commission, "SEC case." Average price reserves are calculated using the
average price received per lease for the twelve months ended September 30,
1995, 1994, 1993 and 1992. SEC case reserves are calculated using the
December 31 year end price received per lease. HEP has presented average
price reserve disclosures in recent years in an attempt to mitigate the
significant price fluctuations which have historically occurred at year end.
The gas market, however, has experienced such dramatic price movements over
the past two years, that in the opinion of management, the use of an average
price no longer provides a stable measure for reserve calculation. In future
years, the Partnership will present only an SEC price case reserves.
CHANGE IN RESERVE QUANTITIES - (in thousands except for price)
The following table presents the SEC case and average price reserve
information for the Partnership.
<TABLE>
<CAPTION>
PROVED RESERVE QUANTITIES SEC Case Average Price
Reserves Reserves (1)
Gas Oil Gas Oil
(Mcf) (Bbls) (Mcf) (Bbls)
<S> <C> <C> <C> <C>
BALANCE, DECEMBER 31, 1992 103,817 6,580 102,759 6,734
Extensions and discoveries 5,213 530 5,213 530
Revisions of previous
estimates (2) (5,050) (1,134) (2,339) (191)
Sales of reserves in place (4,536) (319) (4,536) (319)
Purchase of reserves in
place 6,236 677 6,236 677
Production (14,073) (881) (14,073) (881)
------- ------ -------- -----
BALANCE DECEMBER 31, 1993 91,607 5,453 93,260 6,550
Extensions and discoveries 5,985 1,052 5,985 1,052
Revisions of previous
estimates 1,318 1,113 1,760 67
Sales of reserves in place (816) (84) (816) (84)
Purchase of reserves in
place 699 143 699 143
Production (13,208) (939) (13,208) (939)
-------- ----- ------- ----
BALANCE, DECEMBER 31, 1994 85,585 6,738 87,680 6,789
Extensions and discoveries 5,997 1,902 5,997 1,902
Revisions of previous
estimates 4,248 464 (1,809) 12
Sales of reserves in place (45) (41) (45) (41)
Purchase of reserves in
place 362 28 362 28
Production (13,035) (993) (13,035) (993)
------- ------ ------- ----
BALANCE, DECEMBER 31, 1995 83,112 8,098 79,150 7,697
====== ===== ====== =====
PROVED DEVELOPED RESERVE QUANTITIES
Balance, December 31, 1992 97,035 6,195 96,052 6,345
====== ===== ====== =====
Balance, December 31, 1993 79,858 5,006 81,511 6,093
====== ====== ====== =====
Balance, December 31, 1994 79,699 6,166 81,718 6,215
====== ====== ====== =====
Balance, December 31, 1995 77,378 7,444 73,447 7,049
====== ===== ====== =====
PRICES USED IN RESERVE CALCULATIONS - (SEE PARAGRAPH ABOVE)
December 31, 1992 $2.02 $18.13 $1.72 $19.47
December 31, 1993 $2.38 $13.27 $2.22 $17.83
December 31, 1994 $1.72 $15.80 $1.96 $15.51
December 31, 1995 $2.03 $17.95 $1.56 $16.94
</TABLE>
<TABLE>
<CAPTION>
PRESENT VALUE OF FUTURE CASH
INFLOWS
<S> <C> <C>
December 31, 1992 $141,000 $128,000
December 31, 1993 $121,000 $129,000
December 31, 1994 $104,000 $110,000
December 31, 1995 $124,000 $ 94,000
<F1>
(1) The average prices used in the reserve calculations differ
from the average prices received for calendar years 1993,
1994 and 1995 as the reserve prices were calculated based
upon the twelve month period ended September 30, for each
year presented.
<F2>
(2) Amount includes the interest conveyance relating to the SAS lawsuit
discussed in Note 13 to the Financial Statements in Item 8.
</TABLE>
EXPLORATION AND DEVELOPMENT PROJECTS
In 1995, HEP incurred $11,131,000 in direct property additions and
exploration and development costs, and $5,844,000 for indirect expenditures
through its investment in Hallwood Spraberry Drilling Company, L.L.C.
("HSD"). HEP's budget for 1995 was $11,600,000 for direct costs and
$4,200,000 for indirect costs. The costs were comprised of approximately
$1,580,000 for exploration activities in Indonesia, approximately $6,824,000
for domestic exploration and development expenditures and approximately
$2,727,000 for property acquisitions. In 1995, HEP participated in
approximately 150 drilling or recompletion projects, the highlights of which
are discussed below. Overall, HEP's 1995 capital program led to the
replacement, through acquisitions and drillings, of 131% of the equivalent
barrels produced during 1995, including revisions to prior year reserves.
Sales of reserves in place in 1995 were excluded from this calculation;
however, they were less than 2% of depletion.
CAPITAL PROJECTS
HSD has incurred approximately $5,844,000, net to HEP's interest, through
December 31, 1995 for 33 drilled wells, 30 recompletions and acquisition of
drilling leases on the Rocker "b" Ranch in Reagan County, Texas. HSD has its
own line of credit of $4,650,000, net to HEP's interest, provided by a third
party lender. Based on the initial results of the drilling and
recompletions, HEP spent approximately $907,000 on additional acreage in the
Rocker "b" Ranch during the second and third quarters, HSD has expanded its
project area to include certain sections of this acreage, and HEP has pursued
drilling on the remaining acreage. The line of credit is secured only by
certain leases on the Rocker "b" Ranch and is otherwise nonrecourse to HEP.
HSD has funded the drilling to date from the line of credit as well as from
cash flow generated from drilling activities. The 63 wells drilled or
recompleted since January 1, 1995, have increased HEP's share of production
on the Rocker "b" properties by 725 equivalent barrels of oil per day. These
wells have added a total of 1.3 million equivalent barrels of reserves, of
which 640,000 equivalent barrels were booked as proved undeveloped reserves
at December 31, 1994. An additional 400,000 equivalent barrels of reserves
were booked as proved undeveloped reserves at December 31, 1995.
HEP expended approximately $1,055,000 in 1995 for the drilling of seven
exploitation wells in Reagan County, Texas. Six of the seven wells are
currently producing at an average rate of 275 equivalent barrels of oil per
day and one well was unsuccessful. HEP has also spent approximately $530,000
on two successful development wells in Reagan County, Texas in which it has a
90% working interest. HEP also will participate in several multiple lateral,
horizontal wells in the Giddings Austin Chalk play in Lee County, Texas,
under an acreage farmout agreement completed in 1995. HEP will have working
interests between 2% and 15% in this project.
HEP spent approximately $790,000 on six successful drilling wells and nine
recompletions, seven of which were successful, in the West Texas Kermit area
where HEP has working interests ranging from 25% to 80%. Gross incremental
production on these properties is currently averaging 635 barrels of oil per
day and 1,050 mcf per day. It is anticipated that eight to ten more wells
will be drilled or recompleted in 1996. Future projects in the area include
secondary recovery in the San Andres and Holt Formations. HEP's waterflood
potential for this area is estimated by to be approximately 600,000
equivalent barrels of oil, and unitization will begin in 1996.
In Richland County, Montana, the Lewis #1 well was recompleted to the
Interlake Formation in the first quarter of 1995, and the well continues to
flow 210 barrels of oil per day and 135 mcf per day following an initial
producing rate of 496 barrels of oil per day. HEP has incurred approximately
$200,000 for the drilling of a Red River/Interlake development well which was
spud in early September and was completed in November. HEP has a 22%
working interest in the area. The flowing rate for this well is currently
averaging 200 gross barrels of oil per day. Several exploratory and
development wells are planned to be drilled within this area in 1996.
In 1995, HEP spent approximately $365,000 on an exploitation program started
in late 1994 in New Mexico. This amount includes five successful and one
unsuccessful non-operated development wells in Lea County, New Mexico, and
four successful operated recompletions in Eddy County, New Mexico, having
gross combined initial flowing potentials of 3,350 barrels of oil per day and
4,200 mcf per day. To date, thirteen successful wells have been drilled
under this program. HEP has a 5% working interest in the Lea County field
and 25% to 50% interests in the Eddy County wells. Additional drilling and
recompletion will continue in this area in 1996.
In May 1995, HEP completed an exploratory well in Hot Springs County, Wyoming
for approximately $130,000. The well continues to flow 615 barrels of oil
per day. A delineation well was drilled in August and completed in September
at a cost of $80,000 and is flowing over 600 barrels of oil per day. A third
exploratory well, on a separate but nearby structure, was drilled in October
for $60,000 and is shut-in awaiting additional evaluation. Preliminary
results from work done in early 1996 indicate it is a commercial well. In
addition to limited seismic already obtained, additional seismic data
acquisition on defined structures and other structures is being considered.
Additional drilling is also being considered for this area. HEP has a 15%
working interest in this field.
During 1995, HEP completed two additional coal bed methane development wells
and acquired working interests in the San Juan Basin of New Mexico, for a
total of approximately $220,000. The two new wells have increased gross
production in this area by 700 mcf per day, to approximately 20,000 mcf per
day. HEP has working interests in these new wells of 18% and 25%. Limited
drilling potential remains on existing acreage.
In 1995, HEP acquired interest in two three dimensional ("3-D") seismic
prospects in Taylor and Jones Counties, Texas and is pursuing two other 3-D
projects in this area. HEP participated in the drilling of a nonoperated
exploratory well in one of the 3-D prospects in this area during the third
quarter. This well is flowing 65 barrels of oil per day from the deep Strawn
Reservoir, and additional behind pipe reserves were recorded in the Canyon
Reef which is the primary target. Additional Strawn Formation development
drilling on this discovery is anticipated in 1996. HEP has a 12% interest in
this area. HEP presently holds a 44% working interest in approximately
16,000 net acres within these areas. Approximately 45 square miles of 3-D
seismic data acquisition is planned for the first half of 1996.
1996 PLANS
For 1996, HEP's capital budget, which will be paid from cash generated from
operations and cash on hand, has been set at $11,500,000. In addition to the
above mentioned activity plans, HEP's domestic exploitation plans also
include projects in the Delaware and Permian Basins of Texas, the Big Horn
Basin of Wyoming, the Sweetgrass Arch in Montana, Williston Basin of Montana
and North Dakota, the Michigan Basin, the Gulf Coast of Louisiana, Blanding
Basin in Utah, Sabine Uplift in Louisiana and others. During 1996, HEP
intends to complement its domestic operated exploration and development
activities by participating in nonoperated activities which would, in
general, limit HEP's exposure on a per well basis to less than $150,000, with
maximum working interests of 25%. HEP will consider acquisitions in
strategic areas utilizing capital budget supplemented by external financing.
Utilizing stringent screening criteria HEP will continue to consider
international projects in 1996, with an emphasis in South America.
PARTNERSHIP RESERVES, PRODUCTION AND DISCUSSION BY SIGNIFICANT AREAS AND
FIELDS
The following table presents the December 31, 1995 reserve data by
significant areas and fields.
<TABLE>
<CAPTION>
Proved Present Value of Future Net
Reserve Cash Flows
Quantities
Mcf of Bbls Proved Proved
Gas of Oil Undeveloped Developed Total
(In thousands)
<S> <C> <C> <C> <C> <C>
Scott/West Ridge 23,582 513 $ 43,188 $ 43,188
West Texas 17,304 5,040 $ 2,043 32,159 34,202
Kansas 702 550 312 2,054 2,366
San Juan Basin 11,070 214 5,177 5,391
Southeastern New
Mexico 8,830 202 8,449 8,449
East Riceville 1,803 2 2,176 2,176
South Texas 3,584 132 1,474 3,020 4,494
Other 16,237 1,659 1,611 22,123 23,734
------ ----- ----- ------ ------
83,112 8,098 $ 5,654 $118,346 $124,000
====== ===== ===== ======== ========
</TABLE>
The following table presents the oil and gas production for significant areas
and fields.
<TABLE>
<CAPTION>
Production for the Production for the
Year Ended 1995 Year Ended 1994
Mcf of Bbls of Mcf of Bbls of
Gas Oil Gas Oil
(In thousands)
<S> <C> <C> <C> <C>
Scott/West Ridge 4,501 108 3,766 112
West Texas 1,351 458 982 317
Kansas 146 60 132 68
San Juan Basin 3,216 2,075
Southeastern New
Mexico 2,067 52 2,262 21
East Riceville 286 1 280 2
South Texas 364 20 119 15
Other 1,104 294 3,592 404
------ ---- ------ ----
13,035 993 13,208 939
====== ===== ====== ====
</TABLE>
The following table presents the Partnership's extensions and discoveries by
significant areas and fields.
<TABLE>
<CAPTION>
For the Year Ended For the Year Ended
1995 1994
Mcf of Bbls of Mcf of Bbls of
Gas Oil Gas Oil
(In thousands)
<S> <C> <C> <C> <C>
Scott/West Ridge 318 7
West Texas 3,560 1,397 3,100 961
Kansas 19 117 42
San Juan Basin 794 1,940
Southeastern New
Mexico 432 97 90 25
South Texas 582 28
Other 629 361 420 17
---- ---- ---- ----
5,997 1,902 5,985 1,052
====== ===== ===== =====
</TABLE>
SCOTT/WEST RIDGE
The Scott/West Ridge area consists of 12 gas 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, an affiliate of HEP. The
four most significant wells in the area, all of which were drilled by HPI
since 1989, are the A. L. Boudreaux #1, the G. S. Boudreaux Estate #1, the
Lessin Fontenot #1 and the Evangeline Shrine Club #1. During 1995, HEP
performed three workovers in this area, two of which were successful.
Surface facilities were upgraded on several wells to improve product
handling.
WEST TEXAS
The West Texas area is comprised of two significant groups of properties each
containing significant projects. The West Texas Spraberry area consists of
367 producing wells in Borden, Upton, Reagan, Glasscock and Martin counties
of Texas. HPI and its affiliates operate 357 of these wells. Most of the
current production from these wells is from the Upper Spraberry, Jo Mill,
Dean and Upper Wolfcamp formations which are at depths that range from
approximately 5,000 to 9,000 feet. HEP discovered a new field during 1995,
adding the SRH (Clearfork) as a producing horizon to 70 wells in eastern
Reagan County. HEP drilled 44 successful wells and one dry hole, and
recompleted 30 wells on acreage in the Rocker "b" Ranch. Most of the work
was performed under a line of credit of $4,650,000 net to HEP's interest,
provided by a third party lender. The line of credit is secured only by
leases in the project area and is otherwise nonrecourse to HEP. HEP plans to
purchase additional producing wells and to perform recompletions in this area
in 1996.
The West Texas Kermit area consists of 39 wells in Gaines and Winkler
Counties, Texas, 36 of which are operated by HPI and its affiliates. The
primary focus of this area is the development of the Holt and San Andres
formations at a depth of 5,100 feet on several leases in Winkler County.
During 1995, HEP drilled seven wells, one of which was a dry hole, and
performed ten recompletions, two of which were unsuccessful. HEP also
purchased interests in eleven wells in the area in 1995. Up to ten new wells
may be drilled in 1996, and a secondary recovery project is being planned for
the area beyond 1996.
KANSAS
The Kansas area consists of 310 producing wells, of which 294 are operated by
HPI and 16 are operated by unaffiliated entities, located in 15 counties in
Kansas. The wells produce principally from the Arbuckle and numerous
Lansing-Kansas City formation zones from 3,000 feet to 6,500 feet. During
1995, HEP drilled two development wells, one of which was successful, and
performed 15 successful recompletions. The Kansas area is a mature operation
where recompletions and limited development drilling represent the most
prudent plans for future asset base protection. HEP plans to sell three
properties in this area in 1996 and will continue to evaluate and divest
nonstrategic properties.
SAN JUAN BASIN
The San Juan Basin region consists of 52 wells located in San Juan County,
New Mexico. The wells produce from the Fruitland Coal, Pictured Cliffs, Mesa
Verde and Dakota formations at depths of 1,900 to 7,000 feet. Twenty-four
wells are coal bed methane wells qualifying for the Section 29 alternative
fuels tax credit. During 1994, HEP, Hallwood Consolidated Resources
Corporation (" HCRC") and an unaffiliated entity formed a partnership to
utilize effectively the Section 29 tax credits. During 1995, HEP
successfully drilled two additional coal bed methane wells. For 1996, HEP
plans to drill one additional well.
SOUTHEASTERN NEW MEXICO
The Southeastern New Mexico area consists of 63 producing wells, 43 of which
are operated by HPI, which produce primarily gas and are located on the
northwestern edge of the Delaware Basin in Lea, Eddy and Chaves Counties, New
Mexico. These wells produce at depths ranging from approximately 2,500 feet
to 14,000 feet from the Delaware, Atoka, Bone Springs and Morrow formations.
During 1995, HEP performed nine successful recompletions and participated as
a nonoperator in six successful development wells. During 1996, HEP plans to
perform additional recompletions and to exploit development drilling
opportunities.
EAST RICEVILLE
The East Riceville area consists of three gas wells and one oil well located
in Vermillion Parish, Louisiana. The wells produce principally from the
Barton Sand formation at a depth of approximately 14,800 feet, and the wells
are operated by HPI. No significant development plans for this area are
expected for 1996.
SOUTH TEXAS
The South Texas basin consists of approximately fifteen wells which are
operated by unaffiliated entities, producing primarily from the Wilcox at
depths of 10,000 to 12,000 feet. The majority of the reserves in this area
are located in the Mercy Field in San Jacinto County in the Houston Embayment
Basin. In 1995, four miles of existing pipeline were purchased and joined
with two miles of newly-constructed pipeline. Several shallower wells of
approximate depths of 800 feet were also purchased for deepening potential
and to alleviate high salt water disposal expense. Over 500 acres of leases
were also acquired to drill a step-out test in 1996. There have also been
several successful workovers in 1995 that have potential future benefits.
PROPERTY SALES
During 1995, HEP received $394,000 in connection with the sale of properties.
The proceeds are comprised of numerous sales of various nonstrategic
properties, none of which are individually significant.
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.
<TABLE>
<CAPTION>
1995 1994 1993
<S> <C> <C> <C>
Oil and condensate -
includes the effects of
hedging (per bbl) $17.36 $16.47 $17.71
Natural gas -
includes the effects of
hedging (per mcf) 1.82 1.97 1.94
Production costs (per
equivalent bbl of oil) 3.57 3.88 3.47
</TABLE>
PRODUCTIVE OIL AND GAS WELLS
The following table summarizes the productive oil and gas wells as of
December 31, 1995 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.
<TABLE>
<CAPTION>
Gross Net
<S> <C> <C>
Productive Wells
Oil 892 378
Gas 351 114
---- ----
Total 1,243 492
==== ====
</TABLE>
OIL AND GAS ACREAGE
The following table sets forth the developed and undeveloped leasehold
acreage held directly by HEP as of December 31, 1995. 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.
<TABLE>
<CAPTION>
Gross Net
<S> <C> <C>
Developed acreage 135,500 76,800
Undeveloped acreage 189,350 39,337
-------- -------
Total 324,850 116,137
======= =======
</TABLE>
States in which HEP holds undeveloped acreage include Texas, Louisiana,
Montana, Wyoming, New Mexico, Kansas, Colorado, North Dakota and Michigan.
DRILLING ACTIVITY
The following table sets forth the number of wells attributable to HEP's
direct interests drilled in the most recent three years.
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1994 1993
Gross Net Gross Net Gross Net
<S> <C> <C> <C> <C> <C> <C>
DEVELOPMENT WELLS:
Productive 66 28.0 30 14.6 12 6.2
Dry 2 .5 4 .7 4 1.2
-- ---- -- ---- -- ---
Total 68 28.5 34 15.3 16 7.4
== ==== == ==== == ====
EXPLORATORY WELLS:
Productive 5 .6 2 .1 6 1.1
Dry 1 .9 6 1.2 10 3.9
-- ---- -- ---- -- ----
Total 6 1.5 8 1.3 16 5.0
== ==== == ==== == ====
</TABLE>
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 HCRC is guarantor of the remaining 40% of the obligation.
ITEM 3 - LEGAL PROCEEDINGS
See Notes 13 and 14 to the financial statements in Item 8 - Financial
Statements and Supplemental 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 1995.
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, 1996, 9,977,254 Class
A Units were outstanding, held by approximately 23,650 Unitholders of record;
143,773 Class B Units were outstanding, held by HEC. 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 and Class B
Unit for the corresponding periods. 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 plus distributions received from
affiliates.
<TABLE>
<CAPTION>
HEP Units High Low Distributions
<S> <C> <C> <C>
First quarter 1994 8 5/8 6 1/2 $.20
Second quarter 1994 7 3/4 6 3/8 .20
Third quarter 1994 8 6 1/8 .20
Fourth quarter 1994 6 1/2 4 7/8 .20
------
$.80
======
First quarter 1995 6 1/4 5 3/8 $.20
Second quarter 1995 5 15/16 5 1/8 .20
Third quarter 1995 5 1/2 4 .20
Fourth quarter 1995 4 11/16 3 3/4 .20
-----
$.80
======
</TABLE>
On January 17, 1996, HEP's new Class C Units began trading on the Exchange
under the symbol "HEPCWI." As of February 27, 1996, 654,481 Class C Units
were outstanding held by approximately 17,465 Unitholders of record. The
high and low reported sales prices for the Class C Units as reported on the
Exchange were $7.75 and $7.50 per Class C Unit, respectively, for the month
of January 1996.
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, described in Item 8 Note 13, all Unit and per Unit information
has been retroactively restated. In connection with the change in HEP's
reserve calculation methodology, which is further described in Item 8 -
Supplemental Oil and Gas Reserve Information, all periods have been restated
to reclassify HEP's share of internal overhead charges attributable to wells
operated by HPI from production operating expense to general and
administrative expense. Additionally, the periods prior to May 18, 1992 have
been restated to present the effects of the conversion of Hallwood
Consolidated Partners, L.P., an entity owned 40% by HEP, into a corporation,
HCRC, on a consistent basis.
<TABLE>
<CAPTION>
As of and For the Years Ended December 31,
1995 1994 1993 1992 1991
(In thousands except per
Unit)
SUMMARY OF
OPERATIONS
<S> <C> <C> <C> <C> <C>
Oil and gas
revenues and
pipeline
operations $43,454 $43,899 $ 44,106 $52,755 $ 51,961
Litigation
settlement 11,466
Total revenue 43,780 44,482 49,613 60,730 66,218
Production
operating expense 11,298 12,177 11,200 14,107 15,655
Depreciation,
depletion and
amortization 15,827 18,168 17,076 18,866 17,165
Impairment 10,943 7,345
General and
administrative
expense 5,580 5,630 6,812 7,732 8,550
Net income (loss) (9,031) (10,093) 13,064 3,613 4,468
Net income (loss)
per Unit (1.07) (1.20) 1.14 .21 .36
Distributions per
Unit .80 .80 .80 .80 1.60
BALANCE SHEET
Working capital
(deficit) $ (4,363) $ (9,390) $ 7,020 $ 6,306 $ (9,700)
Property, plant
and equipment, net 94,926 107,414 122,133 129,029 141,220
Total assets 125,152 136,281 171,624 186,087 196,766
Long-term debt 37,557 25,898 38,010 52,814 49,850
Long-term contract
settlement
obligation 2,397 2,666 3,673 4,179 4,888
Long-term lawsuit
settlement
liability 2,370
Deferred liability 1,718 1,931 1,504 1,626 1,425
Minority interest
in subsidiaries 3,042 2,923 3,346 3,782 3,344
Partners' capital 57,572 78,803 98,576 89,779 94,737
</TABLE>
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 $18,449,000 of cash flow from operating activities during 1995.
The other primary cash inflows were:
. $15,000,000 in proceeds from long-term debt;
. $394,000 in proceeds from the sale of property.
Cash was used primarily for:
. Distributions to partners of $10,020,000;
. Additions to property, exploration and development costs incurred of
$11,131,000;
. Payments of long-term debt of $7,379,000;
. Payments of contract settlement obligations of $1,336,000.
When combined with miscellaneous other cash activity during the year, the
result was an increase in HEP's cash of $2,568,000, from $2,409,000 at
December 31, 1994 to $4,977,000 at December 31, 1995.
PROPERTY PURCHASES, SALES AND CAPITAL BUDGET
In 1995, HEP incurred $11,131,000 in direct property additions and
exploration and development costs, and $5,844,000 for indirect expenditures
through its investment in HSD. HEP's budget for 1995 was $11,600,000 for
direct costs and $4,200,000 for indirect costs. The costs were comprised of
approximately $1,580,000 for Indonesia exploration, approximately $6,824,000
for domestic exploration and development expenditures and approximately
$2,727,000 for property acquisitions. Overall, HEP's 1995 capital program
led to the replacement, through acquisitions and drilling, of 131% of the
equivalent barrels produced during 1995, including revisions to prior year
reserves. Sales of reserves in place in 1995 were less than 2% of depletion.
Through HEP's investment in HSD, HEP has incurred approximately $5,844,000 on
the drilling of 33 wells, the recompletion of 30 wells and the acquisition of
additional drilling leases on the Rocker "b" Ranch in Reagan County, Texas.
HEP's significant direct exploration and development expenditures in 1995
included approximately $1,055,000 for the drilling of seven exploitation
wells in Reagan County, six of which were successful; approximately $790,000
on six successful drilling wells and nine recompletions, of which seven were
successful, in the West Texas Kermit area; approximately $200,000 for the
drilling of a Red River/Interlake development well which was successful; and
approximately $365,000 on five successful and one unsuccessful nonoperated
developmental wells and four successful operated recompletions in New Mexico.
Additionally, HEP completed a successful exploratory well in Wyoming for
approximately $130,000, drilled two successful coal bed methane developmental
wells, acquired additional working interests in the San Juan Basin for
approximately $220,000 and drilled two successful development wells in Texas
for approximately $530,000.
HEP received $394,000 during 1995 in connection with the sale of properties.
The proceeds are comprised of the sale of various nonstrategic properties,
none of which are individually significant.
For 1996, HEP's capital budget, which will be paid from cash generated from
operations and cash on hand has been set at $11,500,000. In addition to the
above mentioned activity plans, HEP's domestic exploitation plans also
include projects in the Delaware and Permian Basins of Texas, the Big Horn
Basin of Wyoming the Sweetgrass Arch in Montana, Williston Basin of Montana
and North Dakota, the Michigan Basin, the Gulf Coast of Louisiana, Blanding
Basin in Utah, Sabine Uplift in Louisiana and others. During 1996, HEP
intends to complement its domestic operated exploration and development
activities by participating in nonoperated activities which would in general,
limit HEP's exposure, on a per well basis, to less than $150,000 with maximum
working interests of 25%. HEP will consider acquisitions in strategic areas
utilizing capital budget supplemented by external financing. HEP will
continue to consider international projects in 1996, utilizing stringent
screening criteria.
During 1995, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 121 "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
("SFAS No. 121"). SFAS 121 provides the standards for accounting for the
impairment of various long-lived assets. The Partnership is required to
adopt SFAS 121 no later than 1996. HEP uses the full cost method of
accounting for its long-lived assets, which requires an impairment to be
recorded when total capitalized costs exceed the present value, discounted at
10%, of estimated future net revenues from proved oil and gas reserves.
Therefore, the adoption of SFAS 121 is not expected to have a material effect
on the financial position or results of operations of HEP.
See Item 2 - Properties, for further discussion.
DISTRIBUTIONS
During 1995 HEP declared $.80 per Unit in distributions to its Unitholders.
Oil and gas prices continue to be low, and the resulting negative effect on
cash flow from operations will impact the amount of distributions which HEP
will be able to make. <PAGE>
On January 19, 1996, HEP paid a dividend of one new Class C Unit for every 15
HEP Class A Units held as of the record date of December 18, 1995. Pursuant
to the regulation of the American Stock exchange, holders of Class A Units
who sold their Units between December 14, 1995 and January 19, 1996 also sold
their right to receive the associated Class C Unit dividend. Class C Units
are a newly created class of units that trade separately from HEP's currently
outstanding Units. The Class C Units have a distribution preference of $1.00
per year, payable quarterly, and distributions on the new units will commence
for the first quarter of 1996. Class C Units have been created to give HEP
greater flexibility in structuring future acquisitions by allowing HEP to
issue a security with a fixed distribution rate. Currently outstanding HEP
Units are referred to as Class A Units but will continue to be listed on the
American Stock Exchange using the symbol "HEP."
If there are no further adverse changes in the factors which effect HEP cash
flow, including oil and gas prices, property and partnership expenses and
other relevant information, and there is no change in the limitation in HEP's
Credit Facilities on the amount of distributions permitted, HEP believes that
it can distribute $.13 per Class A Unit and $.25 per Class C Unit for each of
the four quarters of 1996. The combined effect of the issuance of the new
Class C Units and the decrease in distributions on the Class A Units would
result in the $.80 annual distribution that has been paid since 1992 being
reduced to an annual rate of $.58 on a Class A and associated Class C Unit.
Future distributions will be determined after taking into account reduced
cash flow and the limitation in HEP's Credit Facilities on the amount of
distributions.
UNIT OPTION PLAN
On January 31, 1995, the board of directors of the general partner approved
the adoption of a Unit option plan to be used for the motivation and
retention of directors and employees performing services for HEP. The plan
authorizes the issuance of 425,000 options to purchase 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. In addition, the plan provides that
vesting of the options may be accelerated under certain conditions. The
exercise price of the options is $5.75, which was the closing price of the
Class A Units on January 30, 1995. No options have been exercised.
During 1995 the FASB issued 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. The
Partnership is required to adopt SFAS 123 no later than 1996. Because the
Partnership intends to elect only the disclosure provisions of SFAS 123, the
adoption of SFAS 123 is not expected to have a material effect on the
financial position or results of operations of HEP.
FINANCING
During the first quarter of 1995, HEP and its lenders amended and restated
HEP's Amended and Restated Credit Agreement ("Credit Agreement") to extend
the term date of its line of credit to May 31, 1997. Under the Credit
Agreement ("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 $42,000,000. HEP has amounts
outstanding at December 31, 1995 of $24,700,000 under the Credit Agreement
and $12,857,000 under the Note Purchase Agreement. HEP's borrowing base is
further reduced by an outstanding contract settlement obligation of
$2,771,000 and a capital lease obligation of $87,000; therefore, its unused
borrowing base totaled $1,585,000 at February 27, 1996.<PAGE>
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 1996 through
additional borrowings under the Credit Agreement; thus, no portion of HEP's
Note Purchase Agreement is classified as current as of December 31, 1995.
Borrowings against the Credit Agreement bear interest at the lower of the
Certificate of Deposit rate plus 1.875%, prime plus 1/2% or the Euro-Dollar
rate plus 1.75%. At December 31, 1995 the applicable interest rate was 7.5%.
Interest is payable monthly, and 16 quarterly principal payments of
$1,812,000, as adjusted for the anticipated borrowings to fund the Note
Purchase Agreement payment due in 1996, commence May 31, 1997.
The borrowing base for the Credit Facilities is redetermined semiannually in
March and September of each year. 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
plus distributions received from affiliates.
The current portion of long-term debt represents a capital lease obligation
of $87,000.
Included in net working capital deficit of affiliates is $4,650,000, net to
HEP's interest, which represents the current portion of the long-term debt of
HSD. HSD's line of credit of $4,650,000, net to HEP's interest, which is
provided by a third party lender, is secured by certain leases held by HSD
and is otherwise nonrecourse to HEP. Borrowings under the line of credit
bear interest at the prime rate plus 8.5% (17% at December 31, 1995).
Interest is payable monthly, and the entire outstanding principal is due on
August 31, 1996. The current intention is to refinance the debt on or before
the due date so as to extend the repayment term.
HEP entered into contracts to hedge its interest rate payments on $5,000,000
of its debt through the end of 1995, $10,000,000 for 1996 and 1997 and
$5,000,000 for 1998. 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 each year of the remaining term of the debt. HEP has
entered into two 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
other of which is an interest rate swap with a fixed rate of 5.74%. The
amounts received or paid upon settlement of these transactions are recognized
as interest expense at the time the interest payments are due.
GAS BALANCING
HEP uses the sales method for recording its gas balancing. Under this
method, HEP recognizes revenue on all of its sales of production, and any
over-production or under-production is recovered at a future date.
As of December 31, 1995, HEP had a net over-produced position of 105,000 mcf
($191,000 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 2 and Item 8
have been decreased by 105,000 mcf in order to reflect HEP's gas balancing
position.
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 significantly in 1995. The
following table presents the average prices received per year by HEP, and the
effects of the hedging transactions discussed below.
<TABLE>
<CAPTION>
Oil Oil Gas Gas
(excluding (including (excluding (including
effects effect effects effects
of hedging of hedging of hedging of hedging
transactions) transactions) transactions) transactions)
(per bbl) (per bbl) (per mcf) (per mcf)
<C> <C> <C> <C> <C>
1995 $16.98 $17.36 $1.58 $1.82
1994 15.50 16.47 1.90 1.97
1993 16.79 17.71 2.12 1.94
</TABLE>
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 drops 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:
<TABLE>
<CAPTION>
Oil
Percent of
Production Contract
Period Hedged Floor Price
(per bbl)
<C> <C> <C>
1996 22% $15.08
1997 18% $14.87
1998 15% $14.83
1999 3% $15.38
</TABLE>
Between 16% 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 between 25% and 75% of the difference between the contract price
and the posted futures price if the posted futures price is greater than the
contract price. Between 75% 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
$16.50 to $18.85.
<TABLE>
<CAPTION>
Gas
Percent of
Production Contract
Period Hedged Floor Price
(per mcf)
<C> <C> <C>
1996 47% $2.04
1997 39% $2.06
1998 41% $2.10
1999 17% $2.01
2000 20% $2.01
</TABLE>
Between 0% and 50% 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 prices range from $2.65 to $2.93.
During the first quarter through February 14, 1996, the oil price (for
barrels not hedged) averaged between $17.00 and $18.50 per barrel. The
weighted average price of natural gas (for mcf not hedged) was between $1.35
and $4.00 per mcf.
INFLATION
Inflation did not have a material impact on HEP in 1995 and is not
anticipated to have a material impact in 1996.
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 1995, HEP owned interests which ranged
from 54.5% to 68.3% of the Mays; in 1994 HEP's ownership in the Mays ranged
from 54.1% to 67.8%; and in 1993 HEP's ownership in the Mays ranged from
53.9% to 67.0%.
<TABLE>
<CAPTION>
TABLE OF HEP EARNINGS FOR MANAGEMENT DISCUSSION
(In thousands except price)
For the Year Ended December 31, 1995
For the Year Ended December 31, 1995
Direct
Owned Mays Total
<S> <C> <C> <C>
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, facilities
and other revenue 2,444 2,444
Interest income 263 63 326
----- --- ----
Total revenue 39,030 4,750 43,780
------ ----- ------
Production operating
expense 10,658 640 11,298
Facilities operating
expense 794 794
General and
administrative
expense 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 expense 4,245 4,245
Litigation
settlement expense 337 49 386
Equity in loss of
HCRC 2,273 2,273
Minority interest 1,465 1,465
----- ----- -----
Total expense 48,439 4,372 52,811
------ ------ -------
Net income (loss) $ (9,409) $ 378 $ (9,031)
========= ======== =========
</TABLE>
<TABLE>
<CAPTION>
TABLE OF HEP EARNINGS FOR MANAGEMENT DISCUSSION
(In thousands except price)
FOR THE YEAR ENDED DECEMBER 31, 1994
For the Year Ended December 31, 1994
Direct
Owned Mays Total
<S> <C> <C> <C>
Oil production (bbl) 826 113 939
Gas production (mcf) 11,521 1,687 13,208
Average oil price $16.54 $15.98 $16.47
Average gas price $ 1.93 $ 2.22 $ 1.97
Oil revenue $ 13,664 $ 1,806 $ 15,470
Gas revenue 22,287 3,739 26,026
Pipeline, facilities and
other revenue 2,403 2,403
Interest income 525 58 583
--- --- ---
Total revenue 38,879 5,603 44,482
------- ------ ------
Production operating expense 11,491 686 12,177
Facilities operating expense 730 730
General and administrative
expense 5,107 523 5,630
Depreciation, depletion, and
amortization 15,894 2,274 18,168
Impairment of oil and gas
properties 7,345 7,345
Interest expense 3,839 3,839
Litigation settlement
expense 3,370 3,370
Equity in loss of HCRC 1,499 1,499
Minority interest 1,822 1,822
Other (5) (5)
------ ----- ------
Total expense 49,270 5,305 54,575
------ ----- -------
Net income (loss) $(10,391) $ 298 $(10,093)
======== ====== =========
</TABLE>
<TABLE>
<CAPTION>
TABLE OF HEP EARNINGS FOR MANAGEMENT DISCUSSION
(In thousands except price)
FOR THE YEAR ENDED DECEMBER 31, 1993
For the Year Ended December 31, 1993
Direct
Owned Mays Total
<S> <C> <C> <C>
Oil production (bbl) 781 100 881
Gas production (mcf) 12,171 1,902 14,073
Average oil price $17.73 $17.52 $17.71
Average gas price $ 1.88 $ 2.34 $ 1.94
Oil revenue $ 13,847 $ 1,752 $ 15,599
Gas revenue 22,848 4,446 27,294
Gas marketing and
transportation 5,046 5,046
Pipeline, facilities and
other revenue 1,624 (411) 1,213
Interest income 407 54 461
------ ----- ------
Total revenue 43,772 5,841 49,613
------ ------ ------
Production operating expense 10,442 758 11,200
Facilities operating expense 489 489
Gas purchase and
transportation 4,611 4,611
General and administrative
expense 6,188 624 6,812<PAGE>
Depreciation, depletion, and
amortization 14,834 2,242 17,076
Interest expense 4,688 4,688
Litigation settlement
expense 1,015 683 1,698
Equity in (loss) of HCRC (112) (112)
Minority interest 1,549 1,549
Litigation settlement income (11,466) (11,466)
Other 4 4
------ ------ ------
Total expense 30,693 5,856 36,549
------ ------ ------
Net income (loss) $ 13,079 $ (15) $ 13,064
======== ======== =======
</TABLE>
1995 COMPARED TO 1994
GENERAL
The fluctuations related to the "Mays" column are either insignificant or
attributable to the same reasons set forth below.
OIL REVENUE
Oil revenue for HEP's direct owned properties increased $1,837,000 during
1995 as compared with 1994. The increase is comprised of a 5% increase in
the average oil price from $16.54 per barrel in 1994 to $17.32 per barrel in
1995, combined with an 8% increase in production, from 826,000 barrels in
1994 to 895,000 barrels in 1995. The increase in production is due to
increased production from developmental drilling projects in West Texas,
offset by normal production declines.
The effect of HEP's hedging transactions described under "Inflation and
Changing Prices" on the direct owned properties was to increase HEP's average
oil price from $16.90 per barrel to $17.32 per barrel, resulting in a
$376,000 increase in revenue for 1995.
GAS REVENUE
For HEP's direct owned properties, gas revenue decreased by $1,465,000 during
1995 as compared with 1994. The decrease is comprised of a slight decrease
in gas production from 11,521,000 mcf during 1994 to 11,497,000 mcf during
1995 combined with a 6% decrease in the average gas price from $1.93 per mcf
in 1994 to $1.81 per mcf in 1995. The decrease in production is due to
decreases in allowable production limits and normal production declines,
partially offset by increased production from developmental drilling projects
in West Texas.
The effect of HEP's hedging transactions on the direct owned properties as
described under "Inflation and Changing Prices" was to increase HEP's average
gas price from $1.54 per mcf to $1.81 per mcf, representing an $3,104,000
increase in revenues for 1995.
INTEREST INCOME
The decrease in total interest income of $257,000 during 1995 as compared
with 1994 resulted from a lower average cash balance during 1995 as compared
with 1994.
PRODUCTION OPERATING EXPENSE
Production operating expense for HEP direct decreased $833,000 during 1995 as
compared with 1994, primarily as a result of general cost reductions in West
Texas.
FACILITIES OPERATING EXPENSE
Facilities operating expense represents operating expenses associated with
various smaller gathering systems operated by HEP. The increase in
facilities operating expense of $64,000 is primarily due to the increased
maintenance activity during 1995.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE
Total depreciation, depletion and amortization expense decreased $2,341,000
during 1995 as compared with 1994. The decrease is primarily the result of
lower capitalized costs in 1995 as compared with 1994, primarily due to the
property impairment recorded during the second quarter of 1995 and the fourth
quarter of 1994.
IMPAIRMENT OF OIL AND GAS PROPERTIES
Impairment of oil and gas properties during 1995 represents the impairment of
$7,000,000 recorded because capitalized costs at June 30, 1995 exceeded the
present value (discounted at 10%) of estimated future net revenues from
proved oil and gas reserves, based on prices at that date of $16.50 per bbl
of oil and $1.50 per mcf of gas, as well as the write-off of HEP's Indonesian
operations of $3,943,000. The impairment of oil and gas properties during
1994 represents an impairment of $6,000,000 recorded because capitalized
costs at December 31, 1994 exceeded the present value (discounted at 10%) of
estimated future net revenues from proved oil and gas reserves, based on
prices at that date of $15.80 per bbl of oil and $1.72 per mcf of gas, as
well as the write-off of certain foreign drilling projects of $1,345,000.
INTEREST EXPENSE
Total interest expense for HEP increased by $406,000 during 1995 as compared
with 1994. The increase is due to a higher average outstanding debt balance
during 1995 as compared to 1994.
LITIGATION SETTLEMENT EXPENSE
Litigation settlement expense during 1995 consists primarily of expenses
incurred to settle various individually insignificant claims against HEP.
Litigation settlement expense during 1994 represents the settlement of claims
against HEP which are further discussed in Note 13 to the Financial
Statements in Item 8, as well as an amount paid to settle a claim for
royalties on a 1989 take-or-pay settlement.
EQUITY IN EARNINGS (LOSS) OF HCRC
Equity in loss of HCRC represents HEP's share of its equity investment in
HCRC. HEP's equity in HCRC's loss increased by $774,000 during 1995 as
compared to 1994. The increase is primarily the result of HCRC's impairment
expense resulting from the write-off of its Indonesian operations during
1995, as well as a second quarter property impairment recorded by HCRC.
1994 COMPARED TO 1993
GENERAL
The fluctuations related to the "Mays" column are either insignificant or
attributable to the same reasons set forth below.
OIL REVENUE
Oil revenue for HEP's direct owned properties decreased $183,000 during 1994
as compared with 1993. The decrease is comprised of a 7% decrease in the
average oil price from $17.73 per barrel in 1993 to $16.54 per barrel in
1994, partially offset by a 6% increase in production from 781,000 barrels in
1993 to 826,000 barrels in 1994. The increase in production is due to
property acquisitions which occurred late in 1993 combined with increased
production from developmental drilling projects in West Texas, offset by
normal production declines.
The effect of HEP's hedging transactions described under "Inflation and
Changing Prices" on the direct owned properties was to increase HEP's average
oil price from $15.43 per barrel to $16.54 per barrel, resulting in a
$917,000 increase in revenue for 1994.
GAS REVENUE
For HEP's direct owned properties, gas revenue decreased by $561,000 during
1994 as compared with 1993. The decrease is comprised of a 5% decrease in
gas production from 12,171,000 mcf during 1993 to 11,521,000 mcf during 1994
offset by a 3% increase in the average gas price from $1.88 per mcf in 1993
to $1.93 per mcf in 1994. The decrease in production is due to decreased
production in the Scott Field, due to decreases in allowable production
limits and normal production declines, partially offset by increased
production from property acquisitions which occurred late in 1993.
The effect of HEP's hedging transactions on the direct owned properties as
described under "Inflation and Changing Prices" was to increase HEP's average
gas price from $1.86 per mcf to $1.93 per mcf, representing an $806,000
increase in revenues for 1994.
GAS MARKETING
Gas marketing and transportation revenue and expense represent gas marketing
activities conducted by HEP in West Virginia, including purchases and sales
through a pipeline interconnect between two interstate gas pipelines in
Cabell County, West Virginia. The decrease in this activity during 1994 as
compared with 1993 is the result of discontinued third party gas marketing
activity due to the sale of the West Virginia properties in March 1993.
PIPELINE, FACILITIES AND OTHER REVENUE
Total 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, further described in Note 3 to the Financial Statements in
Item 8. Total pipeline and other revenue increased $1,190,000 during 1994 as
compared with 1993. The increase is the result of incentive payments
received during 1994, combined with an increase in facilities income arising
primarily from the connection of several wells in the Catclaw Draw and La
Plata areas in New Mexico during 1994.
INTEREST INCOME
The increase in total interest income of $122,000 during 1994 as compared
with 1993 resulted from a higher average cash balance during 1994 as compared
with 1993.
PRODUCTION OPERATING EXPENSE
Production operating expense for HEP direct increased $1,049,000 during 1994
as compared with 1993, primarily as a result of increased salt water disposal
costs in the Scott/West Ridge area, increased ad valorem tax expense and
increased operating expenses due to property acquisitions which occurred late
in 1993.
FACILITIES OPERATING EXPENSE
The increase in facilities operating expense of $241,000 is primarily due to
the connection of several wells in the Catclaw Draw and the La Plata areas in
New Mexico during 1993 and 1994.
GENERAL AND ADMINISTRATIVE EXPENSE
General and administrative expense for HEP direct includes costs incurred for
direct administrative services such as legal, audit and reserve reports as
well as allocated internal overhead incurred by the operating company on
behalf of HEP. These expenses decreased by $1,081,000 during 1994 as
compared with 1993, primarily as a result of a $400,000 decrease in legal
expenses during 1994 as well as a $500,000 decrease in allocated internal
overhead incurred by HPI.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE
Total depreciation, depletion and amortization expense increased $1,092,000
during 1994 as compared with 1993. The increase is primarily the result of
higher capitalized costs in 1994 as compared with 1993, primarily due to
property acquisitions previously discussed.
IMPAIRMENT OF OIL AND GAS PROPERTIES
Impairment of oil and gas properties represents the impairment expense of
$6,000,000 recorded because capitalized costs at December 31, 1994 exceeded
the present value (discounted at 10%) of estimated future net revenues from
proved oil and gas reserves, based on prices at that date of $15.80 per bbl
of oil and $1.72 per mcf of gas, as well as the write-off of certain foreign
drilling projects of $1,345,000.
INTEREST EXPENSE
Total interest expense for HEP decreased by $849,000 during 1994 as compared
with 1993. The decrease is due to a lower average outstanding debt balance
during 1994 as compared to 1993, partially offset by higher interest rates.
LITIGATION SETTLEMENT EXPENSE
Litigation settlement expense represents the settlement of claims against HEP
which are further discussed in Note 13 to the Financial Statements in Item 8,
as well as an amount paid to settle a claim for royalties on a 1989 take-or-
pay settlement.
EQUITY IN EARNINGS (LOSS) OF HCRC
HEP's equity in HCRC's earnings (loss) decreased by $1,611,000 during 1994 as
compared to 1993. The decrease is primarily the result of HCRC's impairment
of its oil and gas properties which exceeded the present value (discounted at
10%) of estimated future net revenues from proved oil and gas reserves and
the impairment of certain foreign drilling projects which HCRC is no longer
pursuing.
LITIGATION SETTLEMENT INCOME
Litigation settlement income in 1993 represents the proceeds from a lawsuit
settlement which is further discussed in Note 13 to the Financial Statements
in Item 8 of Form 10-K for the year ended December 31, 1995.
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
FINANCIAL STATEMENTS: PAGE
Independent Auditors' Report 27
Consolidated Balance Sheets at December 31, 1995 and 1994 28-29
Consolidated Statements of Operations for the years
ended December 31, 1995, 1994 and 1993 30
Consolidated Statements of Cash Flows for the years
ended December 31, 1995, 1994 and 1993 31
Consolidated Statements of Partners' Capital for the
years ended December 31, 1995, 1994 and 1993 32
Notes to Consolidated Financial Statements 33-49
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION - (UNAUDITED) 50-53
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, 1995 and 1994 and for each of the three
years in the period ended December 31, 1995, 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, 1995 and 1994, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1995 in
conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP<PAGE>
Denver, Colorado
February 27, 1996
<TABLE>
<CAPTION>
HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31,
1995 1994
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents $ 4,977 $ 2,409
Accounts receivable:
Oil and gas sales 6,767 6,220
Trade 2,860 3,042
Due from affiliates 2,808 1,647
Prepaid expenses and other current
assets 1,091 1,352
------ ------
Total 18,503 14,670
------- -------
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost
method):
Proved mineral interests 601,323 588,758
Unproved mineral interests -
domestic 684 380
Unproved mineral interest - foreign 2,399
Furniture, fixtures and other 3,090 2,980
-------- --------
Total 605,097 594,517
Less accumulated depreciation,
depletion, amortization and
property impairment (510,171) (487,103)
--------- -------
Total 94,926 107,414
-------- -------
OTHER ASSETS
Investment in common stock of HCRC 11,491 13,764
Deferred expenses and other assets 232 433
------- -------
Total 11,723 14,197
------ -------
TOTAL ASSETS $125,152 $136,281
======= =======
</TABLE>
<TABLE>
<CAPTION>
HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31,
1995 1994
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable and accrued
liabilities $ 17,344 $ 18,407
Net working capital deficit of
affiliate 5,061 103
Current portion of contract
settlement 374 1,425
Current portion of long-term debt 87 4,125
--- ---
Total 22,866 24,060
------ ------
NONCURRENT LIABILITIES
Long-term debt 37,557 25,898
Contract settlement 2,397 2,666
Deferred liability 1,718 1,931
------- -------
Total 41,672 30,495
------- ------
Total Liabilities 64,538 54,555
------ ------
MINORITY INTEREST IN SUBSIDIARIES 3,042 2,923
----- -----
PARTNERS' CAPITAL
Class A Units - 9,977,254 Units
issued, 9,193,159 and 9,659,504
outstanding at December 31, 1995
and 1994, respectively 59,614 77,342
Class B subordinated Units -
143,773 Units outstanding 1,062 1,350
Class C Units - No Units issued
General Partner 2,981 4,051
Treasury Units - 784,095 and
317,750 Units at 1995 and 1994,
respectively (6,085) (3,940)
------- -------
Partners' Capital - Net 57,572 78,803
------ ------
TOTAL LIABILITIES AND PARTNERS'
CAPITAL $125,152 $136,281
======== =========
</TABLE>
<TABLE>
<CAPTION>
HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands except per Unit)
For the Years Ended December 31,
1995 1994 1993
<S> <C> <C> <C>
REVENUES:
Oil revenue $ 17,240 $ 15,470 $ 15,599
Gas revenue 23,770 26,026 27,294
Gas marketing and
transportation 5,046
Pipeline, facilities and other 2,444 2,403 1,213
Interest 326 583 461
------ ------ -----
43,780 44,482 49,613
------ ------ ------
EXPENSES:
Production operating 11,298 12,177 11,200
Facilities operating 794 730 489
Gas purchases and
transportation 4,611
General and administrative 5,580 5,630 6,812
Depreciation, depletion and
amortization 15,827 18,168 17,076
Impairment of oil and gas
properties 10,943 7,345
Interest 4,245 3,839 4,688
Litigation settlement 386 3,370 1,698
------ ------ ------
49,073 51,259 46,574
------ ------ ------
OTHER INCOME (EXPENSES):
Equity in earnings (loss) of
HCRC (2,273) (1,499) 112
Minority interest in net
income of subsidiaries (1,465) (1,822) (1,549)
Litigation settlement 11,466
Other 5 (4)
------- ------ ------
(3,738) (3,316) 10,025
------- ------- ------
NET INCOME (LOSS) $ (9,031) $(10,093) $ 13,064
======== ======= =======
ALLOCATION OF NET INCOME LOSS:
General partner $ 1,289 $ 1,631 $ 2,394
======== ======== ========
Limited partners $(10,320) $(11,724) $ 10,670
======== ========= =========
Per Class A Unit and Class B
Unit $ (1.07) $(1.20) $ 1.14
====== ===== ======
Weighted average Class A Units
and Class B Units outstanding 9,683 9,807 9,365
===== ===== =====
</TABLE>
<TABLE>
<CAPTION>
HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the Years Ended
December 31,
1995 1994 1993
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss) $ (9,031) $(10,093) $ 13,064
Adjustments to reconcile net
income (loss) to net cash
provided by operating
activities:
Depreciation, depletion,
amortization and impairment 26,770 25,513 17,076
Depreciation charged to
affiliates 256 348 395
Amortization of deferred
loan costs and other assets 201 260 319
Noncash interest expense 289 394 485
Minority interest in net
income 1,465 1,822 1,549
Take-or-pay recoupment (571) (313)
Equity in (earnings) loss
of HCRC 2,273 1,499 (112)
Undistributed (earnings)
loss of affiliates (886) 158 95
--- --- ---
Cash from operations before
working capital changes 20,766 19,588 32,871
Changes in operating assets
and liabilities provided
(used) cash net of noncash
activity:
Oil and gas sales
receivable (547) 3,341 1,247
Trade receivable 182 2,757 2,460
Due from affiliates (1,161) (1,529) 368
Prepaid expenses and other
current assets 261 3,590 (2,406)
Accounts payable and
accrued liabilities (1,052) (6,172) (5,228)
------- ------ -------
Net cash provided by
operating activities 18,449 21,575 29,312
------ ------ ------
INVESTING ACTIVITIES:
Additions to property, plant
and equipment (2,727) (3,657) (6,269)
Exploration and development
costs incurred (8,404) (9,978) (6,287)
Proceeds from sales of
property, plant and equipment 394 2,599 4,549<PAGE>
Distributions received from
affiliates 3,204
Decrease in restricted cash 2,050
Other investing activities (25) (117)
--- --- ---
Net cash used in
investing activities (10,737) (11,061) (2,870)
-------- -------- -------
FINANCING ACTIVITIES:
Payments of long-term debt (7,379) (12,375) (19,421)
Proceeds from long-term debt 15,000 4,300 4,300
Distributions paid (10,020) (9,547) (8,703)
Distributions paid by
consolidated subsidiaries to
minority shareholders (1,346) (2,245) (1,985)
Payment of contract settlement (1,336) (1,343) (1,150)
Other financing activities (63) (34) (72)
--- --- ---
Net cash used in
financing activities (5,144) (21,244) (27,031)
------- ------- --------
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS 2,568 (10,730) (589)
CASH AND CASH EQUIVALENTS:
BEGINNING OF YEAR 2,409 13,139 13,728
--- --- ---
END OF YEAR $ 4,977 $ 2,409 $ 13,139
======= ======= =======
</TABLE>
<TABLE>
<CAPTION>
HALLWOOD ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(In thousands except Units)
General Class A Class B Treasury
Partner Units Units Units
<S> <C> <C> <C> <C>
BALANCE,
DECEMBER 31, 1992 $ 4,646 $ 87,461 $ 1,586 $ (3,914)
Adjustments
relating to
therepurchase of
Units previously
held by non-U.S.
citizens
Issuance of Units 4,703
Syndication costs (3)
Cancellation of
previously
escrowed Units
Distributions (2,168) (6,684) (115)
Net income 2,394 10,479 191
------ ------- --- -----
BALANCE,
DECEMBER 31, 1993 4,872 95,956 1,662 (3,914)
Increase in
Treasury Units (26)
Syndication costs (34)
Distributions (2,452) (7,052) (116)
Net income (loss) 1,631 (11,528) (196)
------ ------- ----- ----
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)
======= ======= ======= ========
<FN>1
(Consolidated Statements of Partners' Capital - Continued)
</TABLE>
<TABLE>
<CAPTION>
Class A Class B Treasury
Units Units Units
<S> <C> <C> <C>
BALANCE,
DECEMBER 31, 1992 9,125,078 143,773 313,725
Adjustments
relating to the
repurchase of
Units previously
held by non-U.S.
citizens (107)
Issuance of Units 549,908
Syndication costs
Cancellation of
previously
escrowed Units (11,350)
Distributions
Net income
--- --- ---
BALANCE,
DECEMBER 31, 1993 9,663,529 143,773 313,725
Increase in
Treasury Units (4,025) 4,025
Syndication costs
Distributions
Net income (loss)
--- --- ---
BALANCE,
DECEMBER 31, 1994 9,659,504 143,773 317,750
Increase in
Treasury Units (466,345) 466,345
Syndication costs
Distributions
Net income (loss)
------- ------- ------
BALANCE,
DECEMBER 31, 1995 9,193,159 143,773 784,095
========= ======= ========
<FN>1
The accompanying notes are an integral part of the financial
statements.
</TABLE>
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 production, sale and
transportation of oil and gas and in the acquisition, exploration,
development and operation of oil and gas properties. The Partnership's
properties are primarily located in the Rocky Mountain, Mid-Continent, Texas
and Gulf Cost regions of the United States. The principal objectives of HEP
are to maintain or expand its reserve base and to provide cash distributions
to holders of its units representing limited partner interests ("Units").
The general partner of HEP is Hallwood Energy Corporation ("HEC") which has
been engaged in oil and gas exploration and development since its
incorporation in 1968. 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 HEC is the sole general partner of HEPO. Hallwood G.P., Inc. ("HGPI"), a
wholly-owned subsidiary of HEC, is the sole general partner and HEP is the
sole limited partner 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.
ACCOUNTING POLICIES
CONSOLIDATION
HEP fully consolidates majority owned entities 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 40% 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"). Also included is
HEP's pro rata share of the activities of Nycotex Gas Transport ("Nycotex")
through March 31, 1993, the effective date of its disposition.
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 drops 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, 1995, HEP had a net over-produced position of 105,000 mcf
($191,100 valued at average 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 December 31, 1995 reserves have been decreased by
105,000 mcf in order to reflect HEP's gas balancing position.
ALLOCATIONS
Partnership costs and revenues are allocated to Unitholders and the general
partner pursuant to the partnership agreement ("the Agreement") as set forth
below.
<TABLE>
<CAPTION>
General
Unitholders Partner
<S> <C> <C>
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 90% 10%
completion
All other costs and
revenues 75% 25%
All other costs and
revenues 98% 2%
<FN>1
(1) The percentages set forth above are for wells drilled under<PAGE>
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.
</TABLE>
PROPERTY, PLANT AND EQUIPMENT
HEP follows the full cost method of accounting whereby all costs related to
the acquisition 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.
During 1995, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
("SFAS 121"). SFAS 121 provides the standards for accounting for the
impairment of various long-lived assets. HEP is required to adopt SFAS 121
no later than 1996. HEP uses the full cost method of accounting for its only
long-lived assets, which requires an impairment to be recorded when total
capitalized costs exceed the present value, discounted at 10%, of estimated
future net revenues from proved oil and gas reserves. Therefore, the
adoption of SFAS 121 is not expected to have a material effect on the
financial position or results of operations of HEP.
DEFERRED LIABILITY
The deferred liability as of December 31, 1995 and 1994 consists primarily of
HEP's share of the unrecouped portion of a 1989 take-or-pay settlement which
is recoupable in gas volumes through February 1997.
DISTRIBUTIONS
HEP paid a $.20 per Unit distribution on February 15, 1996 to Unitholders of
record on December 31, 1995. This amount and the general partner
distribution were accrued as of year end. At December 31, 1995 and 1994,
distributions payable of $2,477,000 and $2,505,000, respectively were
included in accounts payable and accrued liabilities. HEP declared
distributions of $.80 per Unit for each of the years ended December 31, 1995
and 1994.
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 IRS 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
and results of operations of HEP.
As of December 31, 1995, the inside tax basis of HEP's net assets exceeds the
book basis by approximately $34,000,000.
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
Net income per Unit is computed by dividing net income attributable to the
limited partners' interest by the weighted average number of Class A Units
and Class B Units outstanding. 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 13.
At December 31, 1995, HEP owns approximately 40% of the outstanding common
stock of HCRC, which owns approximately 19% of HEP's Class A and Class B
Units; consequently, HEP has an interest in 784,095 of its own Units. These
Units are treated as treasury Units in the accompanying financial statements.
The Unit options described in Note 9 have been considered in the computation
of net income per Unit but are antidilutive in 1995.
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
Sales to Conoco Inc. and Marathon Petroleum Company accounted for 30% and
14%, respectively of total oil and gas sales of HEP for the year ended
December 31, 1995, and 23% and 12%, respectively, of total oil and gas sales
of the Partnership for the year ended December 31, 1994. Sales to Conoco
Inc., Koch Oil Company and Marathon Petroleum Company accounted for 21%, 11%
and 10%, respectively, of total oil and gas sales of HEP for the year ended
December 31, 1993. Although the Partnership sells the majority of its oil
and gas production to a few purchasers, there are numerous other purchasers
in the area, therefore, the loss of its significant customers would not
adversely affect HEP's operations.
ENVIRONMENTAL CONCERNS
HEP is continually taking actions necessary in its operations to ensure
conformity with applicable federal, state and local environmental
regulations. As of December 31, 1995, 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.
RECLASSIFICATION
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:
<TABLE>
<CAPTION>
For the Years Ended
December 31,
1995 1994 1993
(In thousands)
Property acquisition
costs:
<S> <C> <C> <C>
Proved $ 2,727 $ 3,724 $ 7,631
Unproved 793 183 1,468
Development costs 11,880 4,995 4,877
Exploration costs 2,368 4,983 1,410
--- --- ---
Total $17,768 $13,885 $15,386
======== ======= =======
</TABLE>
Depreciation, depletion, amortization and impairment expense, related to
proved properties, per equivalent barrel of production for the years ended
December 31, 1995, 1994 and 1993, was $7.21, $7.70 and $5.29, respectively.
At December 31, unproved domestic properties consist of the following:
<TABLE>
<CAPTION>
1995 1994
(In thousands)
<S> <C> <C>
South Louisiana $ 86 $335
Texas 227
Utah 137
Other 234 45
--- ---
$684 $380
=== ===
</TABLE>
At December 31, 1994, unproved foreign properties represented HEP's
investment in its Indonesian project which was abandoned during the first
quarter of 1995.
NOTE 3 - PRINCIPAL ACQUISITIONS AND SALES
1995
During 1995, HEP had no individually significant property acquisitions or
sales.
1994
During the second quarter of 1994, HEP and HCRC formed a limited partnership
with a third party for the purpose of producing natural gas qualified for the
Section 29 tax credit under the Internal Revenue Code. A limited liability
company owned by HEP and HCRC is the general partner of the partnership.
HEP and HCRC sold a term working interest in certain wells in San Juan
County, New Mexico to the limited partnership, in return for which HEP and
HCRC received a cash payment totaling $3,400,000 when the sale was closed.
HEP and HCRC will receive 97% of the cash flow from production from the wells
sold through the year 2002, and 80% of the cash flow thereafter. HEP and
HCRC will also receive quarterly cash incentive payments equal to 34% of the
Section 29 tax credit generated from the production from the wells. HEP and
HCRC will share in all proceeds 55% and 45%, respectively. HEP recorded its
$1,870,000 share of the cash payment received as a credit to oil and gas
properties in the accompanying financial statements.
1993
During September and October 1993, HEP and its affiliate HCRC completed the
following transactions which resulted in the acquisition of interests in the
following properties (the purchase amounts are net to HEP): 130 wells in
twelve counties in central Kansas for $1,200,000, of which $367,000 was paid
in cash and $833,000 was paid in the form of 96,607 Class A Units; six wells
in Comanche County, Kansas for $750,000; nine wells in Russell County, Kansas
for $600,000; three wells in San Juan County, New Mexico for $425,000; and
nine wells in Toole County, Montana for $350,000. Additionally, HEP acquired
50% of the stock of Sunburst Exploration, Inc. ("Sunburst") for $1,700,000 by
issuing 197,103 Class A Units. The remaining 50% of the stock was acquired
by HCRC. Sunburst owns interests in 130 wells in Toole County, Montana, 45
of which are operated by Sunburst.
These acquisitions were effective as of various dates from August 1 through
October 29, 1993 and added an estimated 464,000 barrels of oil and 5 billion
cubic feet of gas to HEP's reserves at December 31, 1993.
On March 5, 1993, HEP sold its interest in Nycotex and its West Virginia
properties which included natural gas reserves estimated at approximately 3.4
billion cubic feet of gas. The proceeds after adjustments were approximately
$1,600,000.
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 drops 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:
<TABLE>
<CAPTION>
Oil
Quantity of Production
Period Hedged Contract Floor Price
(bbl) (per bbl)
<C> <C> <C>
1993 439,000 $18.53
1994 361,000 17.93
1995 380,000 17.41
1996 200,000 15.08
1997 148,000 14.87
1998 103,000 14.83
1999 16,000 15.38
</TABLE>
From 1995 forward, between 16% 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 between 25% and 75% of the
difference between the contract price and the posted futures price if the
posted futures price is greater than the contract price. From 1995 forward,
between 75% 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 $16.50 to
$18.85.
<TABLE>
<CAPTION>
Gas
Quantity of Production
Period Hedged Contract Floor Price
(mcf) (per mcf)
<C> <C> <C>
1993 6,413,000 $1.69
1994 6,461,000 1.88
1995 6,439,000 1.94
1996 5,180,000 2.04
1997 3,946,000 2.06
1998 3,635,000 2.10
1999 1,260,000 2.01
2000 1,244,000 2.01
</TABLE>
From 1995 forward, between 0% and 50% 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 prices range from
$2.65 to $2.93.
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 40% interest in HCRC using the equity method
of accounting. The following presents summarized financial information for
HCRC at December 31, 1995, 1994 and 1993:
<TABLE>
<CAPTION>
1995 1994 1993
(In thousands)
<S> <C> <C> <C>
Current assets $ 7,931 $ 7,076 $12,933
Noncurrent assets 65,627 55,049 58,053
Current liabilities 15,133 6,646 6,960
Noncurrent
liabilities 21,790 11,890 17,430
Revenue 25,484 20,644 21,007
Net income (loss) (4,670) (2,974) 809
</TABLE>
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 shares of its common stock in a
repurchase offer which was completed January 26, 1996. As a result of this
transaction, HEP's ownership in HCRC increased to 44% at the end of January
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:
<TABLE>
<CAPTION>
As of December 31,
1995 1994 1993
<S> <C> <C> <C>
Unproved properties -
domestic $ 230 $ 93 $ 106
Unproved properties -
foreign 959 826
Proved properties 94,925 89,284 87,282
Accumulated
depreciation,
depletion, amortization
and property impairment (74,168) (68,587) (66,602)
-------- -------- -------
Net property $ 20,987 $ 21,749 $ 21,612
======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
COSTS INCURRED IN OIL AND GAS ACTIVITIES:
For the Years Ended
December 31,
1995 1994 1993
<S> <C> <C> <C>
Acquisition costs $4,168 $1,531 $2,961
Development costs 2,124 1,531 1,028
Exploration costs 845 825 518
------ ------ ------
Total $7,137 $3,887 $4,507
====== ====== ======
</TABLE>
RESULTS OF OPERATIONS FOR OIL AND GAS ACTIVITIES:
<TABLE>
<CAPTION>
For the Years Ended December 31,
1995 1994 1993
<S> <C> <C> <C>
Oil and gas revenue $ 7,825 $ 6,522 $ 6,741
Production operating
expense (2,894) (3,008) (2,736)
Depreciation,
depletion, amortization
and property impairment
expense (2,792) (3,695) (1,822)
Income tax benefit
(expense) (813) 73 (633)
--- --- ---
Net income (loss)
from oil and gas
activities $ 1,326 $ (108) $ 1,550
======= ======== =======
</TABLE>
PROVED OIL AND GAS RESERVE QUANTITIES:
<TABLE>
<CAPTION>
Gas Oil
Mcf Bbls
(unaudited)
<S> <C> <C>
Balance, December 31, 1995 15,782 2,482
======= ======
Balance, December 31, 1994 14,548 1,771
====== ======
Balance, December 31, 1993 15,277 1,268
====== ======
</TABLE>
<TABLE>
<CAPTION>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS:
(unaudited)
<S> <C>
December 31, 1995 $25,532
=======
December 31, 1994 $16,466
=======
December 31, 1993 $18,810
=======
</TABLE>
NOTE 6 - DEBT
HEP's long-term debt at December 31, 1995 and 1994 consisted of the
following:
<TABLE>
<CAPTION>
1995 1994
(In thousands)<PAGE>
<S> <C> <C>
Note Purchase Agreement $12,857 $17,143
Credit Agreement 24,700 12,700
Capital lease obligation -
monthly payments of $8,423,
which include interest at
5.5%, through December 1,
1996 87 180
--- ---
Total 37,644 30,023
Less current maturities (87) (4,125)
------- -------
Long-term debt $37,557 $25,898
======= ========
</TABLE>
During the first quarter of 1995, HEP and its lenders amended and restated
HEP's Amended and Restated Credit Agreement ("Credit Agreement") to extend
the term date of its line of credit to May 31, 1997. Under the Credit
Agreement ("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 $42,000,000. HEP has amounts
outstanding at December 31, 1995 of $24,700,000 under the Credit Agreement
and $12,857,000 under the Note Purchase Agreement. HEP's borrowing base is
further reduced by an outstanding contract settlement obligation of
$2,771,000 and a capital lease obligation of $87,000; therefore, its unused
borrowing base totaled $1,585,000 at February 27, 1996.
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 1996 through
additional borrowings under the Credit Agreement; thus, no portion of HEP's
Note Purchase Agreement is classified as current as of December 31, 1995.
Borrowings against the Credit Agreement bear interest at the lower of the
Certificate of Deposit rate plus 1.875%, prime plus 1/2% or the Euro-Dollar
rate plus 1.75%. At December 31, 1995 the applicable interest rate was 7.5%.
Interest is payable monthly, and 16 quarterly principal payments of
$1,812,000, as adjusted for the anticipated borrowings to fund the Note
Purchase Agreement payment due in 1996, commence May 31, 1997.
The borrowing base for the Credit Facilities is redetermined semiannually in
March and September of each year. 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
plus distributions received from affiliates.
The current portion of long-term debt represents a capital lease obligation
of $87,000.
Included in net working capital deficit of affiliates is $4,650,000, net to
HEP's interest, which represents the current portion of the long-term debt of
HSD. HSD's line of credit of $4,650,000, net to HEP's interest, which is
provided by a third party lender, is secured by certain leases held by HSD
and is otherwise nonrecourse to HEP. Borrowings under the line of credit
bear interest at the prime rate plus 8.5% (17% at December 31, 1995).
Interest is payable monthly, and the entire outstanding principal is due on
August 31, 1996. The current intention is to refinance the debt on or before
the due date so as to extend the repayment term.
HEP entered into contracts to hedge its interest rate payments on $5,000,000
of its debt through the end of 1995, $10,000,000 for 1996 and 1997 and
$5,000,000 for 1998. 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 each year of the remaining term of the debt. HEP has
entered into two 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
other of which is an interest rate swap with a fixed rate of 5.74%. 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, 1995, HEP's debt maturity schedule is as follows:
<TABLE>
<CAPTION>
(In thousands)
<C> <C>
1996 $ 87
1997 9,721
1998 11,532
1999 7,246
2000 7,246
Thereafter 1,812
---
37,644
Less: Current maturities of
long-term debt (87)
---
Long-term debt balance at
December 31, 1995 $37,557
=======
</TABLE>
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 is 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 is also repaying $1,629,000 which represents
suspended payments to the pipeline for previous years in equal monthly
installments of $33,937 which began April 1992 and which will continue
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 is made it will be charged to the
full cost pool.
At December 31, 1994, HEP's five year contract settlement obligation maturity
schedule, including accretion of discount, is as follows:
<TABLE>
<CAPTION>
(In thousands)
<S> <C>
1996 $ 428
1997 -
1998 2,814
1999 -
2000 -
---
3,242
Less: Unaccreted discount at
December 31, 1995 (471)
Current maturities of
contract settlement debt (374)
---
Long-term contract settlement
balance at December 31, 1995 $2,397
======
</TABLE>
NOTE 8 - PARTNERS' CAPITAL
HEP Units that trade on the American Stock Exchange under the symbol "HEP"
are referred to as "Class A 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 will be maintained for the
benefit of the Class B Units for any distributions suspended under 2
above. The amount in the deficit account will be 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 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. HEP is not aware of any hostile effort to acquire control, but
believes that the rights plan represents a sound and reasonable means of
safeguarding the interests of the Unitholders.
NOTE 9 - UNIT OPTION PLAN
On January 31, 1995, the board of directors of the general partner approved
the adoption of a Unit Option Plan to be used for the motivation and
retention of directors and employees performing services for HEP. The plan
authorizes the issuance of 425,000 options to purchase 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. In addition, the plan provides that
vesting of the options may be accelerated under certain conditions. The
exercise price of the options is $5.75, which was the closing price of the
Class A Units on January 30, 1995.
During 1995 the FASB issued 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. The
Partnership is required to adopt SFAS 123 no later than 1996. Because the
Partnership intends to elect only the disclosure provisions of SFAS 123, the
adoption of SFAS 123 is not expected to have a material effect on the
financial position or results of operations of HEP.
Under the terms of the Domestic Incentive Plans ("Plans") which have been
adopted for every year beginning in 1992, the Board of Directors of the
general partner each year determines a percentage of HEP's interest in the
cash flow from certain wells drilled, recompleted or enhanced during the year
which will be allocated to the Plan for that year. The specified percentage
was 1.4% for the 1995 Plan and 1% for the 1994 and 1993 Plans. 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 represents
the right to receive for five years a portion of the specified share of the
cash award, the participants are each paid a share of an amount equal to a
specified percentage (80% for 1995, 40% for 1994 and 1993) of the remaining
net present value of the qualifying wells and the award for that year
terminates. The expense attributable to the Plans was $119,000 in 1995,
$88,000 in 1994 and $37,000 in 1993 and is included in general and
administrative expense in the accompanying financial statements.<PAGE>
NOTE 10 - PIPELINE, FACILITIES AND OTHER
Included in pipeline, facilities and other income is a loss of $120,000 in
1993 representing HEP's share of the net pipeline loss of Nycotex. Nycotex
was a gas gathering and transmission facility in West Virginia which was
owned by HEP and HCRC. HEP's 28% share of the gross activity of Nycotex is
as follows:
<TABLE>
<CAPTION>
1993
<S> <C>
Sales $ 696
Cost of purchased gas (708)
Pipeline operating expense (108)
---
Net pipeline loss $ (120)
===
</TABLE>
HEP sold its interest in Nycotex and its West Virginia properties which
included natural gas reserves estimated at approximately 3.4 billion cubic
feet of gas. The proceeds were $2,808,000 after adjustments, and the sale
closed on March 5, 1993.
NOTE 11 - RELATED PARTY TRANSACTIONS
HPI manages and operates certain oil and gas properties on behalf of
independent joint interest owners, HEP and its affiliates. In such capacity,
HPI pays all costs and expenses of operations and distributes all revenues
associated with such properties. HPI has receivables from affiliates of HEP
of $2,808,000 and $1,647,000 at December 31, 1995 and 1994, respectively,
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 include 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 1995, 1994 and 1993
were as follows:
<TABLE>
<CAPTION>
1995 1994 1993
(In thousands)
<S> <C> <C> <C>
Technical $1,100 $ 747 $ 570
Nontechnical 1,321 1,502 1,918
</TABLE>
Included in the nontechnical allocation attributable to HEP's direct interest
for 1995, 1994 and 1993 is approximately $156,000, $159,000 and $167,000,
respectively of consulting fees under a consulting agreement, which expires
June 30, 1997, with The Hallwood Group Incorporated ("Hallwood"), the parent
of HEC. Also included in the nontechnical allocation is $369,000, $363,000
and $350,000 in 1995, 1994 and 1993, respectively, representing costs
incurred by Hallwood 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
international activities of its affiliates. The amount of consulting fees
allocated to the Partnership under this agreement is $125,000 and $62,500 in
1995 and 1994, respectively.
NOTE 12 - STATEMENT OF CASH FLOWS
Cash paid during 1995, 1994 and 1993 for interest totaled $3,356,000,
$3,185,000 and $3,889,000, respectively.
The noncash financing and investing activities of HEP for the year ended
December 31, 1993 was as follows (there were no noncash activities during
1994 and 1995):
<TABLE>
<CAPTION>
<S>
Acquisition of oil and gas properties <C>
for Class A Units $2,533,000
==========
Issuance of Class A Units in
satisfaction of a liability $2,170,000
==========
</TABLE>
NOTE 13 - LITIGATION SETTLEMENTS
During 1995, the parties settled the lawsuit styled Stutes v. Hallwood
Petroleum, Inc. et al. The plaintiff in the lawsuit alleged that as a result
of exposure to benzene in the petroleum he was hauling from various wells
owned and operated by approximately 80 defendants, he contracted myelogenous
leukemia. HEP owns an interest in certain of the wells covered by the
lawsuit. HEP's share of the settlement not covered by insurance is $19,000.
In 1994, the Minerals Management Service ("MMS") of the Bureau of Land
Management notified HEP that the MMS had preliminarily determined that the
MMS was owed royalty payments on take-or-pay settlements involving federal
oil and gas leases. In the fourth quarter of 1995, HEP and the MMS reached
an agreement in principle that HEP would pay $321,000 in settlement of all
claims. This amount has been accrued in the December 31, 1995 financial
statements and HEP anticipates that the settlement amount will be paid in the
first quarter of 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 only, 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.
On June 24, 1993, HEP settled two lawsuits and all related claims with
Louisiana Intrastate Gas Corporation ("LIG"). The lawsuits against LIG
involved the prices paid for natural gas production under a long-term gas
contract. The settlement terminates the contract with LIG and resolves all
issues and claims relating to the gas purchase contract for the Northeast
Montegut Field located in Terrebonne Parish, Louisiana. The proceeds from
the settlement after payment of royalties and related legal costs are
reflected in HEP's earnings during the year ended December 31, 1993 and were
used to pay down debt and for working capital purposes.
In January 1994, Hallwood Oil paid $525,000 to the former shareholders of the
general partner of a predecessor entity to settle a claim for payment of
Hallwood Oil's $800,000 guaranty of the promissory note of a former
affiliate. The promissory note was made in 1985 when EDP was formed. This
payment was accrued as litigation settlement expense as of December 31, 1993.
In February 1994, HEP and the other parties to the lawsuit styled SAS
Exploration, Inc. v. Hall Financial Group, Inc. et al. settled the lawsuit.
The plaintiffs alleged that certain leases in the A. L. Boudreaux #1 and A.
M. Duhon #1 wells expired and terminated at the end of their primary lease
terms as a result of production being from Bol Mex 4 Sand rather than the A.
B. Sand. In the settlement, the plaintiffs and the defendants cross-conveyed
interests in certain leases to one another and HEP paid the defendants
$388,000. The cash paid by HEP was paid from the revenues attributable to
the disputed leases that were escrowed beginning in February 1990. The cash
paid by HEP, as well as its share of the cash paid by the Mays, were included
in litigation settlement expense in the December 31, 1993 financial
statements. The interest conveyance resulted in a decrease in HEP's
consolidated reserves as of December 31, 1993 totaling 698,000 mcf of gas,
15,000 bbls of oil and $1,317,000 in discounted future net revenues. This
reduction has been included in the revisions line in the Supplemental Oil and
Gas Reserve Information for the year ended December 31, 1993.
NOTE 14 - LEGAL PROCEEDINGS
In June 1993, 14 lawsuits were filed against HEP in the 15th Judicial
District Court, Lafayette Parish, Louisiana, Docket Nos. 93-2332-F through
93-2345-F, styled Lamson Petroleum Corporation v. Hallwood Petroleum, Inc. et
al. The plaintiffs in the lawsuits claim that they have 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, Mary Guilbeau #1 well, Evageline
Shrine Club #1 well and Duhon #1 well and are entitled to a portion of the
production for the wells dating from February 1990. The plaintiffs are
claiming between .4% and 2.3% of HEP's interest in the wells. HEP has not
recognized revenue attributable to the contested leases since January 1993.
These revenues, totaling $303,000 at December 31, 1995, have been placed in
escrow pending resolution of the lawsuits. At this time, HEP believes that
the difference between the escrowed amount and the amount of any liability
that may result upon resolution of this matter will not be material.
In June 1995, an additional lawsuit was filed against HEP in the 15th
Judicial District Court, Lafayette Parish, Louisiana, Docket No. 95-2601 3B,
styled Lamson Petroleum Corporation v. Hallwood Petroleum, Inc. et al. The
plaintiffs in the lawsuit claim that they have additional 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, Mary Guilbeau #1 well and Duhon #1
well and are entitled to a portion of the production from the wells. HEP has
not yet determined the amount of its interest in the properties which is at
issue. At this time, HEP believes that the difference between the amount
already in escrow as a result of the litigation described in the preceding
paragraph and the amount of any liability that may result upon resolution of
this matter and the matter described in the preceding paragraph will not be
material.
The Partnership is involved in other legal proceedings and claims which have
arisen in the ordinary course of its business and have not been finally
adjudicated. The Partnership believes that its liability, if any, as a
result of such proceedings and claims will not materially affect its
financial condition or operations.
NOTE 15 - 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:
<TABLE>
<CAPTION>
Year Ending
December 31, Annual Rentals
(in thousands)
<C> <C>
1996 $ 622
1997 632
1998 632
1999 316
------
$2,202
======
</TABLE>
NOTE 16 - ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
The following disclosure of the estimated fair value of financial instruments
is made in accordance with the requirements of SFAS No. 107, "Disclosures
about Fair Value of Financial Instruments." The estimated fair value amounts
have been determined by the Partnership, using available market information
and appropriate valuation methodologies. However, considerable judgment is
necessarily required in interpreting market data to develop the estimates of
fair value. Accordingly, the estimates presented herein are not necessarily
indicative of the amounts that the Partnership could realize in a current
market exchange. The use of different market assumptions and/or estimation
methodologies may have a material effect on the estimated fair value amounts.
<TABLE>
<CAPTION>
December 31, 1995
Carrying Estimated
Amount Fair Value
(In thousands)
<S>
LIABILITIES:
<C> <C>
Oil and gas hedge contracts $ - $ 472
Interest rate hedge contracts - 20
Current portion of contract
settlement 374 374
Current portion of long-term debt 87 87
Long-term debt 37,557 38,179<PAGE>
Contract settlement 2,397 2,377
</TABLE>
The estimated fair value of the oil and gas hedge contracts is determined by
multiplying the difference between year end oil and gas prices 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 estimated fair value of the interest rate hedge contracts is computed by
multiplying the difference between the year end 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 current portions of contract settlement and long-term debt are carried in
the accompanying balance sheets at an amount which is a reasonable estimate
of their fair value.
The estimated fair value of long-term debt and contract settlement is
determined using interest rates that could be available to the Partnership
for similar instruments with similar terms.
The fair value estimates presented herein are based on pertinent information
available to management as of December 31, 1995. Although management is not
aware of any factors that would significantly affect the estimated fair value
amounts, such amounts have not been comprehensively revalued for purposes of
these financial statements since that date, and current estimates of fair
value may differ significantly from the amounts presented herein.
HALLWOOD ENERGY PARTNERS, L.P.
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
DECEMBER 31, 1995
(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 have 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, 1995, oil and gas prices averaged $17.95 per bbl of
oil and $2.03 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, 1995 prices result in 8.1 million bbls of oil, and 83
billion cubic feet of gas and a standardized measure of $124,000,000. The
Mays are included on a consolidated basis, and 70,000 bbls of oil and 1.8
billion cubic feet of gas, representing a discounted present value of
$4,000,000, 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 0.4 million bbls of oil and 6.2 billion
cubic feet of gas with a standardized measure of $10,000,000 at December 31,
1995.
As of December 31, 1994, HEP no longer includes its share of internal
overhead charges attributable to wells operated by HPI in lease operating
expense for reserve calculation purposes. These overhead charges are now
included in general and administrative expenses in HEP's financial
statements. This change resulted in an upward revision of HEP's reserves
during 1994 of 1,180,000 barrels of oil, 5,752,000 mcf of gas and $8,354,000
of discounted future net cash flows. This change was implemented to conform
HEP's reserve calculation methodology to, what management believes is, a more
accurate representation of reserves and the most common practice of HEP's
industry peers.
HEP's standardized measure of future net cash flows has been decreased by
$472,000 at December 31, 1995 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%.
<TABLE>
<CAPTION>
HALLWOOD ENERGY PARTNERS, L.P.
RESERVE QUANTITIES
(In thousands)
(Unaudited)
Gas Oil
Mcf Bbls
PROVED RESERVES:
<S> <C> <C>
Balance, December 31, 1992 103,817 6,580
Extensions and discoveries 5,213 530
Revisions of previous estimates (a) (5,050) (1,134)
Sales of reserves in place (4,536) (319)
Purchase of reserves in place 6,236 677
Production (14,073) (881)
--- ---
Balance, December 31, 1993 91,607 5,453
Extensions and discoveries 5,985 1,052
Revisions of previous estimates 1,318 1,113
Sales of reserves in place (816) (84)
Purchase of reserves in place 699 143
Production (13,208) (939)
--- ---
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
====== =====
PROVED DEVELOPED RESERVES:
Balance, December 31, 1993 79,858 5,006
====== =====
Balance, December 31, 1994 79,699 6,166
====== ======
Balance, December 31, 1995 77,378 7,444
====== =====
<FN>1
(a) Amount includes the interest conveyance relating to the
SAS lawsuit discussed in Note 13 to the Financial
Statements.
</TABLE>
<TABLE>
<CAPTION>
HALLWOOD ENERGY PARTNERS, L. P.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(In thousands)
(Unaudited)
December 31,
1995 1994 1993
<S> <C> <C> <C>
Future cash flows $317,000 $262,000 $286,000
Future production and
development costs (130,000) (109,000) (107,000)
-------- --------- --------
Future net cash flows before
discount 187,000 153,000 179,000
10% discount to present value (63,000) (49,000) (58,000)
-------- -------- --------
Standardized measure of
discounted future net cash
flows $124,000 $104,000 $121,000
======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
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,
1995 1994 1993
<S> <C> <C> <C>
Standardized measure of
discounted future net cash
flows at beginning of year $104,000 $121,000 $141,000
Sales of oil and gas
produced, net of production
costs (29,712) (29,319) (31,693)
Net changes in prices and
production costs 17,015 (19,175) (2,783)<PAGE>
Extensions, discoveries and
other additions, net of
future production and
development costs 16,836 10,537 8,430
Changes in estimated future
development costs (11,868) (5,614) (6,248)
Development costs incurred 11,880 4,995 4,877
Revisions of previous
quantity estimates 6,817 6,852 (11,906)
Purchases of reserves in place 513 1,334 10,343
Sales of reserves in place (281) (1,131) (6,478)
Accretion of discount 10,400 12,100 14,100
Changes in production rates
and other (1,600) 2,421 1,358
------- ----- -----
Standardized measure of
discounted future net cash
flows at end of year $124,000 $104,000 $121,000
======== ======= =======
</TABLE>
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 Hallwood Energy
Corporation, a Texas corporation organized in 1968.
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.
HEC is the sole general partner of HEP. Hallwood Petroleum, Inc., performs
duties related to the management of HEP, including the operation of various
properties in which HEP owns an interest.
Section 16(a) of the Securities Exchange Act of 1934 requires the officers
and directors of HEC, 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, 1995, all officers and directors of HEC and greater than ten-percent
beneficial owners complied with applicable filing requirements.
ITEM 11 - EXECUTIVE COMPENSATION
HEP pays no salaries or other direct remuneration to officers, directors or
key employees of the general partner. HEP is charged for a portion of
compensation paid by the general partner based upon the general partner's
allocation procedures which are applied consistently to all entities which it
manages.
For information regarding reimbursement made to the general partner see Item
8 - Financial Statements and Supplementary Data (Note 11 to the Financial
Statements).
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth information as of February 27, 1996, about any
individual, partnership or corporation which is known to HEP to be the
beneficial owner of more than 5% of each class of Units issued and
outstanding.
<TABLE>
<CAPTION>
Name and Address of Owner Class A Class A
Unit Unit
Amount Percent
<S> <C> <C> <C> <C>
Hallwood Energy Corporation 657,260 (1) 6.5 (1)
3710 Rawlins Street, Suite 1500
Dallas, Texas 75219
Hallwood Consolidated Resources 1,948,189 19.5
Corporation
4582 S. Ulster Street Parkway,
Suite 1700
Denver, Colorado 80237
Heartland Advisors, Inc. 620,000 (2) 6.2 (2)
790 North Milwaukee Street
Milwaukee, WI 53202
<FN>1
(Continued)
</TABLE>
<TABLE>
<CAPTION>
Name and Address of Owner Class C Class C
Unit Unit
Amount Percent
<S> <C> <C>
Hallwood Energy Corporation 53,400 7.9
3710 Rawlins Street, Suite 1500
Dallas, Texas 75219
Hallwood Consolidated Resources 129,879 19.5
Corporation
4582 S. Ulster Street Parkway,
Suite 1700
Denver, Colorado 80237
Heartland Advisors, Inc.
790 North Milwaukee Street
Milwaukee, WI 53202<PAGE>
<FN>1
(1) Includes 143,773 Class B Units (100% of the Class B Units)
which are convertible into Class A Units one-for-one.
<FN>2
(2) According to the Schedule 13 G filed by Heartland Advisors, Inc.,
the Partnership Units to which this 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 such an
interest relating to more than 5% of the class.
</TABLE>
As of February 27, 1996, officers and directors of the general partner, as a
group, held 803 Class A Units and currently exercisable options to purchase
133,167 Class A Units, or 1.4% of the total Class A Units currently
outstanding assuming exercise of all currently exercisable options, and 52
Class C Units, or less than .01% of the total Class C Units currently
outstanding.
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 11 to the
Financial Statements).
PART IV
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Financial Statements and Financial Statement Schedules. (See
Index at Item 8).
(b) Reports on Form 8-K.
HEP filed no current reports on Form 8-K during the last quarter
of the period covered by this report.
(c) Exhibits.
(1) 4.1 - Third Amended and Restated Agreement of Limited Partnership of
Hallwood Energy Partners, L. P.
(5) 4.2 - Unit Purchase Rights Agreement dated as of February 6, 1995
between HEP and The First National Bank of Boston.
4.3 - First 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.
(7) 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.
(8) 10.6 - Financial Consulting Agreement between The Hallwood Group
Incorporated and Hallwood Petroleum, Inc. dated June 30, 1993.
(4) 10.7 - Financial Consulting Agreement between The Hallwood Group
Incorporated and Hallwood Petroleum, Inc. dated June 30, 1994.
*(4) 10.8 - Compensation Agreement between Hallwood Petroleum, Inc. and
Anthony J. Gumbiner dated August 1, 1994.
*(7) 10.9 - Domestic Incentive Plan between the Partnership and Hallwood
Petroleum, Inc. dated January 14, 1993.
*(8) 10.10 - 1995 Unit Option Plan
*(7) 10.11 - 1995 Unit Option Plan Loan Program<PAGE>
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 the same exhibit number filed
with the Registrant's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1994.
(5) 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.
(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, 1993.
(7) 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.
(8) 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.
*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: HALLWOOD ENERGY
CORPORATION
GENERAL PARTNER
Date: February 29, 1996 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 February 29, 1996
Anthony J. Gumbiner Board and Director
(Chief Executive
Officer)
/s/Brian M. Troup Director February 29, 1996
Brian M. Troup
/s/Hans-Peter Holinger Director February 29, 1996
Hans-Peter Holinger
/s/Rex A. Sebastian Director February 29, 1996
Rex A. Sebastian
/s/Robert S. Pfeiffer Principal February 29, 1996
Robert S. Pfeiffer Accounting Officer
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from Form 10-K
for the year ended December 31, 1995 for Hallwood Energy Partners, L.P. and is
qualified in its entirety by reference to such Form 10-K.
</LEGEND>
<CIK> 0000768172
<NAME> HALLWOOD ENERGY PARTNERS, L.P.
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<CASH> 4,977
<SECURITIES> 0
<RECEIVABLES> 12,435
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 18,503
<PP&E> 605,097
<DEPRECIATION> 510,171
<TOTAL-ASSETS> 125,152
<CURRENT-LIABILITIES> 22,866
<BONDS> 37,557
0
0
<COMMON> 0
<OTHER-SE> 57,572
<TOTAL-LIABILITY-AND-EQUITY> 125,152
<SALES> 41,010
<TOTAL-REVENUES> 43,780
<CGS> 0
<TOTAL-COSTS> 12,092
<OTHER-EXPENSES> 36,474
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 4,245
<INCOME-PRETAX> (9,031)
<INCOME-TAX> 0
<INCOME-CONTINUING> (9,031)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (9,031)
<EPS-PRIMARY> (1.07)
<EPS-DILUTED> (1.07)
</TABLE>
EXHIBIT 21
LIST OF SUBSIDIARIES OF
HALLWOOD ENERGY PARTNERS, L. P.
HEP Operating Partners, L.P., a Delaware limited partnership
EDP Operating, Ltd., a Colorado limited partnership
SODP, Inc., a Texas corporation
Hallwood Oil and Gas, Inc., a California corporation
Hallwood Petroleum, Inc., a Delaware corporation
Hallwood Consolidated Resources Corporation, a Delaware corporation
May Drilling Partnership 1983-1, a Texas general partnership
May Drilling Partnership 1983-2, a Texas general partnership
May Drilling Partnership 1983-3, a Texas general partnership
May Drilling Partnership 1984-1, a Texas general partnership
May Drilling Partnership 1984-2, a Texas general partnership
May Drilling Partnership 1984-3, a Texas general partnership
Hallwood Spraberry Drilling Company, L.L.C., a Colorado limited liability
company
Hallwood San Juan, L.L.C., a Delaware limited liability company
Sunburst Exploration, Inc., a California corporation<PAGE>
EXHIBIT 1
FIRST AMENDMENT TO THE THIRD AMENDED AND RESTATED
AGREEMENT OF LIMITED PARTNERSHIP
OF
HALLWOOD ENERGY PARTNERS, L.P.
This First Amendment (this "Amendment") to the Third Amended and Restated
Agreement of Limited Partnership of Hallwood Energy Partners, L.P. (the
"Partnership"), is executed by Hallwood Energy Corporation, a Texas corporation,
as General Partner of the Partnership (the "General Partner"), and by Hallwood
Energy Corporation, on behalf of the Limited Partners on the books and records
of the Partnership, pursuant to the powers of attorney executed by such Limited
Partners.
W I T N E S S E T H:
WHEREAS, the board of directors of the General Partner deems it to be in
the best interest of the Partnership to amend the Third Amended and Restated
Agreement of Limited Partnership (the "Partnership Agreement") to allow for the
creation and issuance of Class C Units (the "Class C Units") of the Partnership;
and
WHEREAS, a vote of the Limited Partners is not required to approve the
Amendment and the issuance of the Class C Units.
NOW, THEREFORE, in consideration of the foregoing the Partnership
Agreement is amended as follows:
1. Definitions. Capitalized terms used in this Amendment that are
defined in the Partnership Agreement shall have the same meaning as assigned
therein when used in this Amendment, unless otherwise provided herein.
2. Amendments to the Partnership Agreement.
A. Article I is hereby amended by adding the following
definitions, to be deemed placed in the appropriate alphabetical order:
(i) "Adjusted Capital Account: A Partner's Capital Account
balance (as determined after giving effect to all adjustments attributable to
allocations of items of profit and loss realized by the Partnership, and all
adjustments attributable to contributions and distributions of money and
property effected, on or before the effective date of such determination),
modified as follows:
(a) Decreased by the items (if any) of the
Partnership's loss that reasonably are expected to be allocated to such Partner
pursuant to section 704(e)(2) or 706(d) of the Code or Treasury Regulation
section 1.751-1(b)(2)(ii) (as determined under Treasury Regulation section
1.704-1(b)(2)(ii)(d));
(b) Decreased by adjustments that reasonably are
expected to be made to such Partner's Capital Account under Treasury Regulation
section 1.704-1(b)(2)(iv)(k);
(c) Increased by the amount (if any) of such Partner's
share of nonrecourse minimum gain determined in accordance with the provisions
of Treasury Regulation section 1.704-2(g)(1);
(d) Increased by the amount (if any) of such Partner's
share of partner nonrecourse debt minimum gain determined in accordance with the
provisions of Treasury Regulation section 1.704-2(i)(5); and
(e) Increased by the amount (if any) that such Partner
is obligated to contribute to the Partnership pursuant to any provision of this
Agreement or is treated as being obligated to contribute subsequently to the
capital of the Partnership as determined under Treasury Regulation section
1.704-1(b)(2)(ii)(c)."
(ii) "Class C Units: Defined in Article XX."
(iii) "Class C Partners: The Record Holders of the Class C
Units."
(iv) "Class A Units: The class of Partnership Units that
were the only class of Partnership Units to be traded on the American Stock
Exchange immediately prior to the date of this Amendment."
(v) "Excess Capital Account: The excess of a unit's
positive Capital Account balance over the Unpaid Preference Amount attributable
to such unit. The Excess Capital Account of each Class A Unit and Class B
Subordinated Unit shall be zero."
(vi) "Terminating Capital Transaction: Any sale or other
disposition of all or substantially all of the then remaining assets of the
Partnership which is entered into in connection with the dissolution,
termination and winding up of the Partnership or which will result in the
dissolution of the Partnership."
(vii) "Unpaid Preference Amount: The aggregate cumulative
amount required to be distributed with respect to the Class C Units for the
current and all prior years less any distributions previously made with respect
to the Class C Units for the current and all prior years pursuant to Section
20.3(a).
B. Article I is hereby amended by deleting the definition of the
terms "Riley Ridge Partner," "Riley Ridge Unit" and "Unit."
C. The Partnership Agreement is hereby amended by deleting the
term "Unit" (but not "Partnership Unit," "Class B Subordinated Unit" or "Class B
Subordinated Units") and replacing it with the term "Class A Unit" wherever it
appears.
D. The Partnership Agreement is hereby amended by deleting
references to the terms "Riley Ridge Partner" and "Riley Ridge Unit" wherever
they appear.
E. Section 4.7 is hereby amended by deleting clause (d) thereof
in its entirety and substituting the following in lieu thereof:
"(d) A Capital Account shall be separately maintained for each unit
and no Capital Account shall be attributable to any Class C Unit immediately
after its issuance. Generally, a transferee of a Partnership Interest shall
succeed to the Capital Account attributable to the transferred interest and
there shall be no adjustment to the Capital Accounts as a result of such
transfer. If a transfer causes a termination of the Partnership under Section
708(b)(1)(B) of the Code, the Partnership Assets shall be deemed to have been
distributed in liquidation of the Partnership to the Partners and Assignees
(including the transferee of the Partnership Interest) pursuant to Sections 15.3
and 15.4 and recontributed by such Partners and Assignees in reconstitution of
the Partnership. The Capital Accounts of such reconstituted Partnership shall
be maintained in accordance with the principles of this Section 4.7."
F. Section 5.1 is hereby amended by deleting it in its entirety
and substituting the following in lieu thereof:
"5.1 Income and Loss.
(a) For purposes of maintaining the Capital Accounts and in
determining the rights of the Partners and Assignees among themselves and except
as provided in Section 5.1(b) with respect to items of income, gain loss and
deduction attributable to Terminating Capital Transactions and the provisions of
Sections 5.1(c) through (i), 1% of each item of income, gain, loss and deduction
(computed in accordance with Section 4.7(b) but subject to adjustment for any
allocations required by Sections 5.1(c) through (i)) shall be allocated to the
General Partner with the remaining items of income, gain, loss and deduction
allocated among the Limited Partners and Assignees as follows:
(i) Each remaining item of income or gain shall be allocated
among the Limited Partners and Assignees as follows and in the following
order of priority:
(A) First, to the Class C Units pro rata in accordance
with their Percentage Interests until the aggregate amount of income and
gain allocated pursuant to this Section 5.1(a)(i)(A) is equal to the
aggregate amount of loss or deduction allocated pursuant to Section
5.1(a)(ii)(B);
(B) Second, to the Class C Units pro rata in
accordance with their Percentage Interests until the aggregate amount of
income and gain allocated during the current year and all prior years
pursuant to this Section 5.1(a)(i)(B) (including any gross income
allocations under Section 5.1(h)) is equal to the aggregate amount
required to be distributed with respect to the Class C Units during the
current year and all prior years pursuant to Section 20.3(a) (whether or
not actually distributed); and
(C) Thereafter, to the Class A Units and Class B
Subordinated Units pro rata in accordance with their Percentage Interests.
(ii) Each remaining item of loss or deduction shall be
allocated among the Limited Partners and Assignees as follows and in the
following order of priority:
(A) First, to the Class A Units and Class B
Subordinated Units pro rata in accordance with their Percentage Interests to the
least extent necessary so as to reduce the positive Adjusted Capital Account
balance of each such unit to zero;
(B) Second, to the Class C Units pro rata in
accordance with their Percentage Interests to the least extent necessary so as
to reduce the positive Adjusted Capital Account balance of each such unit to
zero; and
(C) Thereafter, to the Class A Units and Class B
Subordinated Units pro rata in accordance with their Percentage Interests.
(b) Notwithstanding anything in the foregoing to the contrary, 1%
of each item of income, gain, loss or deduction attributable to a Terminating
Capital Transaction shall be allocated to the General Partner with the remaining
items of income, gain, loss or deduction attributable to such Terminating
Capital Transaction allocated among the Limited Partners and Assignees (as
determined after giving effect to all adjustments attributable to allocations of
items of income, gain and loss realized by the Partnership during the fiscal
year in question pursuant to the provisions Section 5.1(a) and any adjustments
attributable to contributions and distributions of money and property effected
prior to such Terminating Capital Transaction pursuant to this Agreement) as
follows:
(i) Each remaining item of income or gain attributable to a
Terminating Capital Transaction shall be allocated among the Limited Partners
and Assignees as follows and in the following order of priority:
(A) First, to the Class C Units pro rata in accordance
with their Percentage Interests until the positive Capital Account balance of
each Class C Unit is equal to the Unpaid Preference Amount attributable to that
unit;
(B) Second, to the least extent necessary to cause the
Excess Capital Account of the units to be in the same proportion to one another
as their Percentage Interests; and
(C) Thereafter, among the Class A Units, Class B
Subordinated Units and Class C Units pro rata in accordance with their
Percentage Interests.
(ii) Each remaining item of loss or deduction attributable to
a Terminating Capital Transaction shall be allocated among the Limited Partners
and Assignees as follows and in the following order of priority:
(A) First, to the least extent necessary to cause the
Excess Capital Account of the units to be in the same proportion to one another
as their Percentage Interests;
(B) Second, to the units pro rata in accordance with
their Percentage Interests to the least extent necessary to reduce the Excess
Capital Account of each unit to zero;
(C) Third, to the Class C Units pro rata in accordance
with their Percentage Interests to the least extent necessary to reduce the
positive Capital Account balance of each such unit to zero; and
(D) Thereafter, to the Class A Units and Class B
Subordinated Units pro rata in accordance with their Percentage Interests.
(c) The General Partner may, for any fiscal year of the
Partnership, make such other or additional allocations as it deems appropriate
to (i) cause the allocations of Partnership book income, gains, losses and
deductions to comply with the requirements of section 704 of the Code or (ii)
achieve and maintain the uniformity of the intrinsic tax characteristics of all
units, so long as such allocations do not adversely affect in any material way
the interests of the holders of the units in current or future distributions.
The General Partner may amend this Agreement to the extent necessary to
accomplish the purposes of this Section 5.1.
(d) Notwithstanding anything in the provisions of Section 5.1 to
the contrary, to the extent that a Partner's Adjusted Capital Account has a
deficit balance or would have a deficit balance as a result of any such
allocation while any other Partner has a positive balance in its Adjusted
Capital Account (as determined after giving effect to all adjustments
attributable to allocations of items of Partnership income, gain, expense and
loss made pursuant to the preceding provisions of this Section 5.1 for such
year), such item of expense or loss shall be allocated among the Partners whose
Adjusted Capital Account balances are positive (pro rata in accordance with such
positive balances) to the extent necessary first to reduce the balances of such
other Partners' Adjusted Capital Accounts to zero, it being the intention of the
Partners that no Partner's Adjusted Capital Account balance shall fall below
zero while any other Partner's Adjusted Capital Account has a positive balance.
In the event that all of the Partner's Adjusted Capital Account balances are
reduced to zero, all further expenses and losses shall be allocated solely to
the General Partner. Notwithstanding anything in this Agreement to the
contrary, each Partner who has been allocated an item of expense or loss
pursuant to this Section 5.1(d) shall be specially allocated items of
Partnership income and gain in an amount equal to such items of expense or loss
as quickly as possible.
(e) Pursuant to section 1.704-1(b)(2)(ii)(d) of the Treasury
Regulations (relating to "qualified income offsets"), Partnership income and
gain shall be allocated, before any other allocation is made pursuant to the
provisions of Section 5.1(a) for such year, among the Partners with deficit
balances in their Adjusted Capital Accounts in the amounts and the manner
sufficient to eliminate such deficit balances as quickly as possible.
An allocation under this Section 5.1(e) shall be made only if and to the extent
that a Partner or Assignee would have an Adjusted Capital Account deficit after
all other allocations provided for in this Section 5.1 have been tentatively
made as if this Section 5.1(e) were not in the Agreement.
(f) All nonrecourse deductions as determined under the Treasury
Regulations shall be allocated among the Partners pro rata in accordance with
their respective Percentage Interests (excluding any Percentage Interest
attributable to the Class C Units).
(g) The allocations set forth in Sections 5.1(d), (e) and (f) (the
"Regulatory Allocations") are intended to comply with certain requirements of
Treasury Regulation sections 1.701-1(b) and 1.704-2. The Regulatory Allocations
may effect results which would not be consistent with the manner in which the
Partners intend to divide Partnership distributions. Accordingly, the General
Partner is authorized to divide other allocations of income, gain, loss and
deduction among the Partners so as to prevent the Regulatory Allocations from
distorting the manner in which Partnership distributions would be divided among
the Partners under Article XV of this Agreement. In general, the reallocation
will be accomplished by specially allocating other items of income, gain, loss
and deduction, to the extent they exist, among the Partners so that the net
amount of the Regulatory Allocations and the special allocations to each Partner
is zero. The General Partner will have discretion to accomplish this result in
any reasonable manner that is consistent with section 704 of the Code and the
related Treasury Regulations.
(h) If at any time the allocation provisions of Section
5.1(a)(i)(B) do not result in the allocation of items of income or gain at least
equal to the aggregate distributions actually made with respect to the Class C
Units during the current year and all prior years pursuant to Section 20.3, the
Limited Partners and Assignees holding Class C Units shall be specially
allocated items of gross income or gain of the Partnership, pro rata in
accordance with their Percentage Interests attributable to their Class C Units,
such that the aggregate amount of income and gain allocated under Section
5.1(a)(i)(B) and this Section 5.1(h) is equal to the aggregate amount of
distributions actually made with respect to the Class C Units during the current
year and all prior years pursuant to Section 20.3. All allocations made under
this section 5.1(h) shall be considered as made pursuant to Section 5.1(a)(i)(B)
for all purposes of this Agreement.
(i) If at any time the allocation provisions of this Article V do
not result in the allocation to the General Partner of at least 1% of each of
the Partnership's material items of income, gain, loss, deduction, or credit,
the General Partner shall be allocated so much more of each of those items as
will cause the General Partner to be allocated at all times 1% of each of those
items. However, the 1% standard shall not take precedence over the allocations
required by section 704(c) of the Code or the provisions of Section 5.2(e).
(j) For purposes of allocating the excess nonrecourse liabilities
of the Partnership under Treasury Regulation section 1.752-3(a)(3), the Partners
agree that each Partner's Percentage Interest (excluding any Percentage Interest
attributable to the Class C Units) shall be treated as such Partner's "interest
in partnership profits" for purposes of Treasury Regulation section 1.752-
3(a)(3)."
G. Section 5.2 is hereby amended by deleting clause (a) thereof
in its entirety and substituting the following in lieu thereof:
"(a) For federal income tax purposes, except as otherwise provided
herein or required by section 704(c) of the Code or Treasury Regulation section
1.704-1(b)(2)(iv)(f), each item of amount realized, income, gain, loss,
deduction and credit of the Partnership shall be allocated among the Partners
and Assignees in the same manner as each correlative item of income, gain, loss
or deduction (computed in accordance with Section 4.7(b)) is allocated pursuant
to Section 5.1. The General Partner may use any method permitted under the Code
for purposes of making allocations required by section 704(c) of the Code or
Treasury Regulation section 1.704-1(b)(2)(iv)(f)."
H. Section 5.2(b) is hereby amended by adding clause (iv) as
follows:
"(iv) Notwithstanding anything in this Section 5.2(b) to the contrary, no
Adjusted Basis allocable under this Section 5.2(b) shall be allocated to any
Partner or Assignee with respect to the Class C Units held by such person,
unless the General Partner determines that another method of allocation is
required by the Code or applicable Treasury Regulations."
I. Section 5.2 is hereby further amended by deleting clause (k)
thereof in its entirety.
J. Section 5.4 is hereby amended by deleting the fourth sentence
thereof in its entirety and substituting the following in lieu thereof:
"Except as provided in Article XVIII, Article XIX and Article XX,
all distributions shall be made concurrently to all Partners who are Record
Holders on the Record Date set for purposes of such distribution and to the
General Partner in accordance with the Percentage Interests of such Partners as
of the Record Date.
K. Section 16.1 is hereby amended by deleting clause (f)(iii)
thereof in its entirety and substituting the following in lieu thereof:
"(iii) necessary or desirable in order to facilitate the
trading of the Class A Units or Class C Units or comply with any rule,
regulation, guideline or requirement of any securities exchange on which the
Class A Units or Class C Units are or will be listed for trading, compliance
with any of which the General Partner deems to be in the best interests of the
Partnership and the Limited Partners."
L. The Partnership Agreement is hereby amended by deleting
Article XVIII in its entirety.
M. The Partnership Agreement is hereby amended by inserting a new
Article XX in the appropriate place to read in its entirety as follows and by
renumbering the remaining sections of the Partnership Agreement:
"ARTICLE XX
CLASS C UNITS
20.1 Definitions. "Class C Units" shall mean that class of Partnership
Units described in this Article XX.
20.2 Designation of Class. A class of Partnership Units is designated
the "Class C Units" of the Partnership. Such class shall be deemed for all
purposes to be issued pursuant to Section 4.2(a). Class C Units will be
transferable in accordance with the terms of this Agreement and will be subject
to redemption as provided in Section 11.6. The Class C Units will share in the
Partnership's allocations and distributions as set forth in Article V and
Section 20.3.
20.3 Distribution Rights.
(a) Notwithstanding anything in this Agreement to the contrary,
subject to the prior rights of the holders of senior securities, if any, the
holders of the Class C Units, in preference to the holders of the Class A Units
and Class B Subordinated Units, shall be entitled to receive, when, as and if
declared by the General Partner, cumulative cash distributions at, but not
exceeding, the rate of $1.00 per Class C Unit per annum, payable quarterly to
holders of record of the Class C Units on March 31, June 30, September 30 and
December 31 in each year, beginning March 31, 1996. Such distributions shall
accrue and be cumulative from March 31, 1996.
(b) So long as any Class C Units shall remain outstanding, the
Partnership may not declare or make any cash distributions on the Class A Units
or Class B Subordinated Units unless all accrued and unpaid distributions on the
Class C Units have been paid or declared and duly provided for. This section
shall not prohibit or restrict the purchase, acquisition or redemption of or
other transaction affecting the Class A Units and Class B Subordinated Units,
regardless whether accrued distributions have been paid on the Class C Units.
20.4 Voting Rights. The Class C Units shall vote as a separate class on
all matters required or otherwise brought for a vote of the Partnership.
20.5 Provisions Controlling. To the extent that the provisions of this
Article XX conflict with any other provisions of the Agreement, the provisions
of this Article XX shall control."
3. Ratification. Except as specified hereinabove, all other terms of
the Partnership Agreement shall remain unchanged and are hereby ratified and
confirmed. All references to "this Agreement" or "the Agreement" appearing in
the Partnership Agreement, and all references to the Partnership Agreement
appearing in any other document or instrument shall be deemed to refer to the
Partnership Agreement as amended by this Amendment.
IN WITNESS WHEREOF, this Amendment has been duly executed by the General
Partner on this the 7th day of December, 1995.
GENERAL PARTNER
HALLWOOD ENERGY CORPORATION
By:/s/Cathleen M. Osborn
------------------------------
Cathleen M. Osborn
Title: Vice President
Attest:/s/Diane M. Blieszner
-------------------------
Diane M. Blieszner
Title: Assistant Secretary<PAGE>
EXHIBIT 23.1
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No. 33-
76668 of Hallwood Energy Partners, L.P. on Form S-2 of our report dated
February 27, 1996, appearing in this Annual Report on Form 10-K of Hallwood
Energy Partners, L.P. for the year ended December 31, 1995.
DELOITTE & TOUCHE LLP
Denver, Colorado
February 27, 1996<PAGE>
EXHIBIT 23.2
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No. 33-
73946 of Hallwood Energy Partners, L. P. on Form S-4 of our report dated
February 27, 1996, appearing in this Annual Report on Form 10-K of Hallwood
Energy Partners, L. P. for the year ended December 31, 1995.
DELOITTE & TOUCHE LLP
Denver, Colorado
February 27, 1996<PAGE>
