UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
MARK ONE
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 1999
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File Number 1-8921
HALLWOOD ENERGY PARTNERS, L. P.
(Exact name of registrant as specified in its charter)
Delaware 84-0987088
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
4582 South Ulster Street Parkway
Suite 1700
Denver, Colorado 80237
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (303) 850-7373
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 [ ]
The registrant is a limited partnership and issues Units (representing ownership
of limited partner interests).
Number of Units outstanding as of May 11, 1999
Class A 10,011,567
Class B 143,773
Class C 2,464,044
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
HALLWOOD ENERGY PARTNERS, L. P.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands)
March 31, December 31,
1999 1998
CURRENT ASSETS
<S> <C> <C>
Cash and cash equivalents $ 5,723 $ 11,874
Accounts receivable:
Oil and gas revenues 4,987 5,911
Trade 7,307 4,040
Due from affiliates 119
Prepaid expenses and other current assets 1,339 1,338
Net working capital of affiliate 323 236
---------- ----------
Total 19,679 23,518
-------- --------
PROPERTY, PLANT AND EQUIPMENT, at cost Oil and gas properties
(full cost method):
Proved mineral interests 667,764 664,799
Unproved mineral interests - domestic 2,739 2,694
Furniture, fixtures and other 3,447 3,411
--------- ---------
Total 673,950 670,904
Less accumulated depreciation, depletion,
amortization and property impairment (570,247) (565,899)
------- -------
Total 103,703 105,005
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OTHER ASSETS
Investment in common stock of HCRC 9,678 10,160
Deferred expenses and other assets 415 408
---------- ----------
Total 10,093 10,568
-------- --------
TOTAL ASSETS $133,475 $139,091
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(Continued on the following page)
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HALLWOOD ENERGY PARTNERS, L. P.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands except Units)
March 31, December 31,
1999 1998
CURRENT LIABILITIES
<S> <C> <C>
Accounts payable and accrued liabilities $ 18,886 $ 22,921
Current portion of long-term debt 12,676 9,319
Due from affiliates 131
----------
Total 31,693 32,240
-------- --------
NONCURRENT LIABILITIES
Long-term debt 38,024 40,381
Deferred liability 1,019 1,050
--------- ---------
Total 39,043 41,431
-------- --------
Total Liabilities 70,736 73,671
-------- --------
MINORITY INTEREST IN AFFILIATES 2,734 2,788
--------- ---------
COMMITMENTS AND CONTINGENCIES (NOTE 5)
PARTNERS' CAPITAL
Class A Units - 10,011,567 and 10,011,854 Units issued in 1999 and 1998,
respectively; 9,121,325 and 9,121,612
outstanding in 1999 and 1998, respectively 41,787 44,198
Class B Subordinated Units - 143,773 Units outstanding
in 1999 and 1998 1,125 1,143
Class C Units - 2,464,044 and 2,464,063 Units outstanding
in 1999 and 1998, respectively 21,386 21,386
General partner 2,616 2,814
Treasury Units - 890,242 Units in 1999 and
1998, respectively (6,909) (6,909)
--------- ---------
Partners' Capital - Net 60,005 62,632
-------- --------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $133,475 $139,091
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The accompanying notes are an integral part of the
financial statements.
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HALLWOOD ENERGY PARTNERS, L. P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands except per Unit data)
For the Three Months Ended
March 31,
1999 1998
REVENUES:
<S> <C> <C>
Gas revenue $ 6,490 $ 6,744
Oil revenue 2,167 3,090
Pipeline, facilities and other 1,209 700
Interest 116 140
-------- --------
9,982 10,674
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EXPENSES:
Production operating 3,058 3,061
Facilities operating 175 152
General and administrative 1,342 1,165
Depreciation, depletion and amortization 4,293 3,539
Interest 818 644
-------- --------
9,686 8,561
------- -------
OTHER INCOME (EXPENSES):
Equity in loss of HCRC (482) (94)
Minority interest in net income of affiliates (132) (313)
Litigation 45
----------- ---------
(614) (362)
-------- --------
NET INCOME (LOSS) (318) 1,751
CLASS C UNIT DISTRIBUTIONS ($.25 PER UNIT) 616 616
-------- --------
NET INCOME (LOSS) ATTRIBUTABLE TO GENERAL
PARTNER, CLASS A AND CLASS B LIMITED
PARTNERS $ (934) $ 1,135
======== =======
ALLOCATION OF NET INCOME (LOSS):
General partner $ 193 $ 310
======== ========
Class A and Class B Limited partners $ (1,127) $ 825
======= ========
Per Class A Unit and Class B Unit - basic $ (.12) $ .09
======== =========
Per Class A Unit and Class B Unit - diluted $ (.12) $ .09
======== ==========
Weighted average Class A Units and Class B Units
outstanding 9,265 9,237
======= =======
</TABLE>
The accompanying notes are an integral part of the
financial statements.
<PAGE>
<TABLE>
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HALLWOOD ENERGY PARTNERS, L. P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
For the Three Months Ended
March 31,
1999 1998
OPERATING ACTIVITIES:
<S> <C> <C>
Net income (loss) $ (318) $ 1,751
Adjustments to reconcile net income (loss) to net cash provided
by (used in) operating activities:
Depreciation, depletion and amortization 4,293 3,539
Depreciation charged to affiliates 55 63
Equity in loss of HCRC 482 94
Minority interest in net income 132 313
Undistributed (earnings) loss of affiliates (631) 253
Recoupment of take-or-pay liability (31) (33)
Gain on asset disposals (188)
Amortization of deferred loan costs and other assets 30
Noncash interest expense 15
Changes in operating assets and liabilities provided (used) cash net of
noncash activity:
Oil and gas revenues receivable 924 2,416
Trade receivables (3,267) 157
Due from affiliates (579) 8
Prepaid expenses and other current assets (1) (68)
Deferred expenses and other (7)
Accounts payable and accrued liabilities (4,035) (2,516)
Due to affiliates 131
--------
Net cash provided by (used in) operating activities (2,852) 5,834
------- -------
INVESTING ACTIVITIES:
Additions to property, plant and equipment (964) (714)
Exploration and development costs incurred (1,875) (2,555)
Proceeds from sales of property, plant and equipment 16 20
Distributions received from affiliate 1,019
-------
Net cash used in investing activities (1,804) (3,249)
------- -------
FINANCING ACTIVITIES:
Proceeds from long-term debt 1,000
Proceeds from the issuance of Class C Units net of syndication 16,520
costs
Payments of long-term debt (14,000)
Distributions paid (2,309) (2,253)
Payment of contract settlement (2,767)
Distribution paid by consolidated affiliates to minority interest (186) (500)
Exercise of Unit Options 199
Capital contribution from the general partner 171
----------- --------
Net cash used in financing activities (1,495) (2,630)
------- -------
NET DECREASE IN CASH AND CASH EQUIVALENTS (6,151) (45)
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD 11,874 6,622
------ -------
END OF PERIOD $ 5,723 $ 6,577
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</TABLE>
The accompanying notes are an integral part of the
financial statements.
<PAGE>
HALLWOOD ENERGY PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1 - GENERAL
Hallwood Energy Partners, L. P. ("HEP") is a publicly traded Delaware limited
partnership engaged in the development, exploration, acquisition and production
of oil and gas properties in the continental United States. HEP's objective is
to provide its partners with an attractive return through a combination of cash
distributions and capital appreciation. To achieve its objective, HEP utilizes
operating cash flow, first, to reinvest in operations to maintain its reserve
base and production; second, to make stable cash distributions to Unitholders;
and third, to grow HEP's reserve base over time. HEP's future growth will be
driven by a combination of development of existing projects, exploration for new
reserves and select acquisitions. The general partner of HEP is HEPGP Ltd.
The activities of HEP are conducted through HEP Operating Partners, L. P.
("HEPO") and EDP Operating, Ltd. ("EDPO"). HEP is the sole limited partner and
HEPGP Ltd. is the sole general partner of HEPO and 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.
The interim financial data are unaudited; however, in the opinion of the general
partner, the interim data include all adjustments, consisting only of normal
recurring adjustments, necessary for a fair presentation of the results for the
interim periods. These financial statements should be read in conjunction with
the financial statements and accompanying notes included in HEP's 1998 Annual
Report on Form 10-K.
Accounting Policies
Consolidation
HEP fully consolidates entities in which it owns a greater than 50% equity
interest and reflects a minority interest in the consolidated financial
statements. HEP accounts for its interest in 50% or less owned affiliated oil
and gas partnerships and limited liability companies using the proportionate
consolidation method of accounting. HEP's investment in approximately 46% of the
common stock of its affiliate, Hallwood Consolidated Resources Corporation
("HCRC"), is accounted for under the equity method.
The accompanying financial statements include the activities of HEP, its
subsidiaries Hallwood Petroleum, Inc. ("HPI") and Hallwood Oil and Gas, Inc.
("Hallwood Oil"), and majority owned affiliates, the May Limited Partnerships
1983-1, 1983-2, 1983-3, 1984-1, 1984-2 and 1984-3 ("Mays").
Computation of Net Income (Loss) Per Unit
Basic income (loss) per Class A and Class B Unit is computed by dividing net
income (loss) attributable to the Class A and Class B limited partners' interest
(net income excluding income (loss) attributable to the general partner and
Class C Units) by the weighted average number of Class A Units and Class B Units
outstanding during the periods. Diluted income per Class A and Class B Unit
includes the potential dilution that could occur upon exercise of options to
acquire Class A Units, computed using the treasury stock method which assumes
that the increase in the number of Units is reduced by the number of Units which
could have been repurchased by the Partnership with the proceeds from the
exercise of the options (which were assumed to have been made at the average
market price of the Class A Units during the reporting period). The Unit options
have been ignored in the computation of diluted loss per Class A and Class B
Unit for the three months ended March 31, 1999 because their inclusion would be
antidilutive.
<PAGE>
The following table reconciles the number of Units outstanding used in the
calculation of basic and diluted income (loss) per Class A and Class B Unit.
<TABLE>
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Income (Loss) Units Per Unit
(In thousands except per Unit data)
For the Three Months Ended March 31, 1999
<S> <C> <C> <C>
Net loss per Class A Unit and Class B Unit - basic $ (1,127) 9,265 $ (.12)
------- ----- =====
Net Loss per Class A Unit and Class B Unit - diluted $ (1,127) 9,265 $ (.12)
======= ===== =====
For the Three Months Ended March 31, 1998
Net income per Class A Unit and Class B Unit - basic $ 825 9,237 $ .09
=====
Effect of Unit Options 86
---------- ------
Net Income per Class A Unit and Class B Unit - diluted $ 825 9,323 $ .09
======== ===== =====
</TABLE>
Treasury Units
HEP owns approximately 46% of the outstanding common stock of HCRC, while HCRC
owns approximately 19% of HEP's Class A Units. Consequently, HEP has an interest
in 890,242 of its own Units at March 31, 1999 and December 31, 1998. These Units
are treated as treasury Units in the accompanying financial statements.
Recently Issued Accounting Pronouncements
In June 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 130 "Reporting Comprehensive Income" ("SFAS
130"). SFAS 130 establishes standards for reporting and display of comprehensive
income and its components (revenues, expenses, gains, and losses) in a full set
of general-purpose financial statements. SFAS 130 requires that all items that
are required to be recognized under accounting standards as components of
comprehensive income be reported in a financial statement that is displayed with
the same prominence as other financial statements. Reclassification of financial
statements for earlier periods provided for comparative purposes is required.
The Partnership adopted SFAS 130 on January 1, 1998. The Partnership does not
have any items of other comprehensive income for the three month periods ended
March 31, 1999 and 1998. Therefore, total comprehensive income (loss) was the
same as net income (loss) for those periods.
In June 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 131 "Disclosures about Segments of an
Enterprise and Related Information" ("SFAS 131"). SFAS 131 establishes standards
for reporting selected information about operating segments and related
disclosures about products and services, geographic areas, and major customers.
SFAS 131 requires that an entity report financial and descriptive information
about its operating segments which are regularly evaluated by the chief
operating decision maker in deciding how to allocate resources and in assessing
performance. HEP adopted FAS 131 in 1998.
The Partnership engages in the development, production and sale of oil and gas,
and the acquisition, exploration, development and operation of oil and gas
properties in the continental United States. The Partnership's activities
exhibit similar economic characteristics and involve the same products,
production processes, class of customers, and methods of distribution.
Management of the Partnership evaluates its performance as a whole rather than
by product or geographically. As a result, HEP's operations consist of one
reportable segment.
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 "Accounting for Derivative Instruments
and Hedging Activities" ("SFAS 133"). SFAS 133 establishes standards for
derivative instruments, including certain derivative instruments embedded in
other contracts (collectively referred to as derivatives) and for hedging
activities. SFAS 133 requires that an entity recognize all derivatives as either
assets or liabilities in the statement of financial position and measure those
instruments at fair value. If certain conditions are met, a derivative may be
specifically designated as (a) a hedge of the exposure to changes in the fair
value of a recognized asset or liability or an unrecognized firm commitment, (b)
a hedge of the exposure to variable cash flows of a forecasted transaction, or
(c) a hedge of the foreign currency exposure of a net investment in a foreign
operation, an unrecognized firm commitment, an available-for-sale security, or a
foreign-currency-denominated forecasted transaction. The accounting for changes
in the fair value of a derivative (gains and losses) depends on the intended use
of the derivative and the resulting designation. The Partnership is required to
adopt SFAS 133 on January 1, 2000. The Partnership has not completed the process
of evaluating the impact that will result from adopting SFAS 133.
Reclassifications
Certain reclassifications have been made to the prior period amounts to conform
to the classifications used in the current period.
NOTE 2 - DEBT
During the first quarter of 1997, HEP and its lenders amended and restated HEP's
Second Amended and Restated Credit Agreement (as amended, the "Credit
Agreement") to extend the term date of its line of credit to May 31, 1999. The
lenders are Morgan Guaranty Trust Company, First Union National Bank and
Nationsbank of Texas. Under the Credit Agreement, HEP has a borrowing base of
$62,000,000. HEP had amounts outstanding at March 31, 1999 of $50,700,000. HEP's
unused borrowing base totaled $11,300,000 at March 31, 1999.
Borrowings against the Credit Agreement bear interest at the lower of the
Certificate of Deposit rate plus from 1.375% to 1.875%, prime plus 1/2% or the
Euro-Dollar rate plus from 1.25% to 1.75%. The applicable interest rate was 6.4%
at March 31, 1999. Interest is payable monthly, and quarterly principal payments
of $3,169,000 commence May 31, 1999. HEP intends to extend the maturity date of
its Credit Agreement prior to the commencement of the amortization period.
The borrowing base for the Credit Agreement is redetermined semiannually. The
Credit Agreement is secured by a first lien on approximately 80% in value of
HEP's oil and gas properties. Additionally, aggregate distributions paid by HEP
in any 12 month period are limited to 50% of cash flow from operations before
working capital changes and distributions received from affiliates, if the
principal amount of debt of HEP is 50% or more of the borrowing base. Aggregate
distributions paid by HEP are limited to 65% of cash flow from operations before
working capital changes and 65% of distributions received from affiliates, if
the principal amount of debt is less than 50% of the borrowing base.
As part of its risk management strategy, HEP enters into financial contracts to
hedge the interest rate payments under its Credit Agreement. HEP does not use
the hedges for trading purposes, but rather to protect against the volatility of
the cash flows under its Credit Agreement, which has a floating interest rate.
The amounts received or paid upon settlement of these transactions are
recognized as interest expense at the time the interest payments are due.
All contracts are interest rate swaps with fixed rates. As of March 31, 1999,
HEP was a party to floor contracts with three different counterparties.
The following table provides a summary of HEP's financial contracts.
Average
Amount of Contract
Period Debt Hedged Floor Rate
Last nine months of 1999 $30,000,000 5.30%
2000 30,000,000 5.65%
2001 24,000,000 5.23%
2002 25,000,000 5.23%
2003 25,000,000 5.23%
2004 4,000,000 5.23%
<PAGE>
NOTE 3 - STATEMENTS OF CASH FLOWS
Cash paid for interest during the three months ended March 31, 1999 and 1998 was
$818,000 and $599,000, respectively.
NOTE 4 - ARBITRATION
In connection with the Demand for Arbitration filed by Arcadia Exploration and
Production Company ("Arcadia") with the American Arbitration Association against
Hallwood Energy Partners, L.P., Hallwood Consolidated Resources Corporation,
E.M. Nominee Partnership Company and Hallwood Consolidated Partners, L.P.
(collectively referred to as "Hallwood"), the arbitrators ruled that the
original agreement entered into in August 1997 to purchase oil and gas
properties should proceed, with a reduction to the total purchase price of
approximately $2,500,000 for title defects. The arbitrators also ruled that
Arcadia was not entitled to enforce its claim that Hallwood was required to
purchase an additional $8,000,000 worth of properties and denied Arcadia's claim
for attorneys fees. The arbitrators granted Arcadia prejudgment interest on the
adjusted purchase price, in the amount of $452,000. That amount was accrued in
the December 31, 1998 financial statements of the Partnership and will be paid
during the second quarter of 1999.
In October 1998, HEP and its affiliate, HCRC, closed the acquisition of oil and
gas properties from Arcadia, including interests in approximately 570 wells,
numerous proven and unproven drilling locations, exploration acreage, and 3-D
seismic data. HEP's share of the purchase price was $8,200,000.
NOTE 5 - LEGAL SETTLEMENT
Concise Oil and Gas Partnership ("Concise"), a wholly owned subsidiary of the
Partnership, was a defendant in a lawsuit styled Dr. Allen J. Ellender, Jr. et
al. vs. Goldking Production Company, et al., filed in the Thirty-Second Judicial
District Court, Terrebonne Parish, Louisiana on May 30, 1996. The portion of the
lawsuit against Concise was settled in consideration of the payment by Concise
of $600,000. This amount was recorded as litigation settlement expense in the
second quarter of 1998. Concise has been dismissed with prejudice from the
lawsuit.
In addition to the litigation noted above, the Partnership and its subsidiaries
are from time to time subject to routine litigation and claims incidental to
their business, which the Partnership believes will be resolved without material
effect on the Partnership's financial condition, cash flows or operations.
NOTE 6 - SUBSEQUENT EVENT
On April 30, 1999, a Joint Proxy Statement/ Prospectus for the consolidation of
HEP with HCRC and the energy interests of The Hallwood Group Incorporated
("Hallwood Group") into a new corporation called Hallwood Energy Corporation was
declared effective by the Securities and Exchange Commission. The consolidation
must be approved by a majority of each class of outstanding Units of HEP and of
the outstanding shares of HCRC. The consummation of the consolidation is also
subject to a number of other conditions.
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
During the first three months of 1999, HEP had a net loss of $934,000, compared
to a net income of $1,135,000 for the first three months of 1998. The weighted
average prices received by HEP for oil and gas have declined in each of the last
four quarters. HEP's hedges have mitigated the price reductions. HEP's weighted
average oil and gas prices, when the effects of hedging are considered, were 25%
and 13% lower, respectively, for the first three months of 1999 compared to the
first three months of 1998.
<PAGE>
In December 1998, HEP announced a proposal to consolidate HEP with HCRC and the
energy interests of Hallwood Group into a new corporation called Hallwood Energy
Corporation. The consolidation proposal was approved by the Board of Directors
of HCRC and the general partner of HEP in December 1998. Because of the larger
size of the new corporation, HEP anticipates that the new company will have the
ability to take advantage of opportunities that are unavailable to smaller
entities such as HEP and will have a better ability to raise capital. Hallwood
Energy Corporation will focus on reserve growth. A Joint Proxy
Statement/Prospectus for the consolidation, filed with the Securities Exchange
Commission, was declared effective on April 30, 1999. The Joint Proxy
Statement/Prospectus was mailed on May 4, 1999, to unitholders of HEP and
stockholders of HCRC of record as of April 14, 1999. A meeting of the limited
partners of the Partnership will be held on May 25, 1999.
If the consolidation is approved, public holders of Class A Units of Hallwood
Energy Partners will receive 0.7417 of a share of common stock of Hallwood
Energy Corporation for each Class A Unit they now hold, and public holders of
Class C Units will receive one share of redeemable preferred stock of Hallwood
Energy Corporation for each Class C Unit they now hold. Public stockholders of
Hallwood Consolidated Resources will receive 1.5918 shares of common stock of
Hallwood Energy Corporation for each share of stock they now hold. Hallwood
Group will also contribute its energy interests to Hallwood Energy Corporation
in exchange for additional shares of common stock of Hallwood Energy
Corporation.
Liquidity and Capital Resources
Cash Flow
HEP used $2,852,000 of cash flow in operating activities during the first three
months of 1999.
The primary cash inflows were:
o Proceeds from long-term debt of $1,000,000; and
o Distributions received from affiliate of $1,019,000;
Cash was used primarily for:
o Additions to property and development costs incurred of $2,839,000; and
o Distributions to Unitholders of $2,309,000.
When combined with miscellaneous other cash activity during the period, the
result was a decrease of $6,151,000 in HEP's cash from $11,874,000 at December
31, 1998 to $5,723,000 at March 31, 1999.
Exploration and Development Projects and Acquisitions
Through March 31, 1999, HEP incurred $2,839,000 in direct property additions,
development, exploitation, and exploration costs. The costs were comprised of
$964,000 for property acquisitions and approximately $1,875,000 for domestic
exploration and development. HEP's 1999 capital budget is set at $11,848,000.
During the first quarter of 1999, HEP postponed development drilling and
recompletions for many oil-targeted projects due to the historically low oil
prices experienced during that time. In April of 1999, oil prices began to
rebound and HEP is reevaluating the economics of these projects. The significant
capital expenditures for first quarter 1999 are discussed below.
<PAGE>
Rocky Mountain Region
HEP expended approximately $732,000 of its capital budget in the Rocky Mountain
Region located in Colorado, Montana, North Dakota, Northwest New Mexico and
Wyoming. Of this amount, approximately $626,000 was for the purchase of
overriding royalty interests and working interests in 18 of the coal bed methane
properties currently owned and operated by HEP, located in San Juan County, New
Mexico. Most of the interests purchased qualify for tax credits under Section 29
of the Internal Revenue Code. The majority of the acquired interests were
purchased by 44 Canyon LLC ("44 Canyon") a special purpose entity owned by a
large East Coast financial institution in exchange for cash, a production
payment, and promissory notes. HEP's activity in the area began in 1990 and the
acquisition increases HEP's net current average daily production by 475 mcf per
day.
Greater Permian Region
During the first quarter of 1999, HEP spent approximately $436,000 of its
capital budget in the Greater Permian Region located in Texas and Southeast New
Mexico. The major projects within the Region are discussed below.
Catclaw Draw/Carlsbad Area Projects. HEP incurred approximately $238,000
successfully recompleting one operated well and drilling one development well in
the Carlsbad/Catclaw Draw areas in Lea, Eddy and Chaves Counties, New Mexico.
The development well is currently being completed.
Other Projects. HEP expended approximately $198,000 during first quarter of 1999
on various maintenance and facilities projects, and also for completing work
which commenced in 1998.
Gulf Coast Region
In the first quarter of 1999, HEP expended approximately $1,210,000 of its
capital budget in the Gulf Coast Region in Louisiana and South and East Texas.
The following are major projects within the Region.
Mirasoles Project. HEP incurred approximately $444,000 related to the Mirasoles
project in Kenedy County, Texas during the first quarter of 1999. HEP began
drilling the 17,000 foot Frio Formation exploration well in 1998 and is
completing the well, starting with the lower most zone and moving uphole. Eight
potential pay zones are identified in this exploration well, and the lower most
zone was abandoned for mechanical reasons following encouraging, but extremely
preliminary results. HEP has a 17.5% working interest in this large structural
prospect defined by 63 square miles of proprietary 3-D seismic data.
Esperanza Project. In the first three months of 1999, HEP incurred approximately
$141,000 for costs associated with a non-operated 15,400 foot directional
exploration well which tested the Wilcox formation in LaVaca County, Texas. The
well was completed in 1998 and HEP owns a 7.5% working interest in the well.
Current gross gas production is approximately 9,500 mcf per day. HEP began
drilling an additional exploration well in the second quarter of 1999, and
development drilling is anticipated in the latter months of 1999.
Boca Chica Project. During the first quarter of 1999, HEP participated in a
directionally drilled 10,000 foot exploration well in the Big Hum formation from
the shore to a bottom hole location under the waters of the Gulf of Mexico.
Despite the well testing wet, the exploration results were sufficiently
encouraging that working interest owners agreed to shoot 3D seismic in the third
quarter of 1999 to evaluate future potential. It is anticipated that a second
attempt will be made in the first quarter of 2000, possibly reentering the
existing wellbore or using a shallow water drilling rig. For its 12.5% working
interest, HEP spent approximately $226,000.
Other
The remaining $461,000 of HEP's first quarter 1999 capital expenditures were
devoted principally to technical general and administrative expenditures and
numerous other projects which are completed or underway and which are
individually less significant.
<PAGE>
Class C Unit Issuance
On February 17, 1998, HEP closed its public offering of 1.8 million Class C
Units, priced at $10.00 per Unit. Proceeds to HEP, net of underwriting expenses,
were approximately $16,520,000. HEP used $14,000,000 of the net proceeds to
repay borrowings under its Credit Agreement and applied the remaining proceeds
toward the repayment of HEP's outstanding contract settlement obligation at
December 31, 1997 of $2,752,000.
Distributions
HEP declared distributions of $.13 per Class A Unit and $.25 per Class C Unit,
payable on May 14, 1999 to Unitholders of record on March 31, 1999.
Distributions on the Class B Units are suspended if the Class A Units receive a
distribution of less than $.20 per Class A Unit per calendar quarter. In any
quarter for which distributions of $.20 or more per unit are made on the Class A
Units, the Class B Units are entitled to be paid, in whole or in part, suspended
distributions.
The Class C Units have a distribution preference of $1.00 per year, payable
quarterly, which began in the first quarter of 1996. HEP may not declare or make
any cash distributions on the Class A or Class B Units unless all accrued and
unpaid distributions on the Class C Units have been paid.
Financing
During the first quarter of 1997, HEP and its lenders amended and restated HEP's
Second Amended and Restated Credit Agreement (as amended, the "Credit
Agreement") to extend the term date of its line of credit to May 31, 1999. The
lenders are Morgan Guaranty Trust Company, First Union National Bank and
Nationsbank of Texas. Under the Credit Agreement, HEP has a borrowing base of
$62,000,000. HEP had amounts outstanding at March 31, 1999 of $50,700,000. HEP's
unused borrowing base totaled $11,300,000 at March 31, 1999.
Borrowings against the Credit Agreement bear interest at the lower of the
Certificate of Deposit rate plus from 1.375% to 1.875%, prime plus 1/2% or the
Euro-Dollar rate plus from 1.25% to 1.75%. The applicable interest rate was 6.4%
at March 31, 1999. Interest is payable monthly, and quarterly principal payments
of $3,169,000 commence May 31, 1999. HEP intends to extend the maturity date of
its Credit Agreement prior to the commencement of the amortization period.
The borrowing base for the Credit Agreement is redetermined semiannually. The
Credit Agreement is secured by a first lien on approximately 80% in value of
HEP's oil and gas properties. Additionally, aggregate distributions paid by HEP
in any 12 month period are limited to 50% of cash flow from operations before
working capital changes and distributions received from affiliates, if the
principal amount of debt of HEP is 50% or more of the borrowing base. Aggregate
distributions paid by HEP are limited to 65% of cash flow from operations before
working capital changes and 65% of distributions received from affiliates, if
the principal amount of debt is less than 50% of the borrowing base.
As part of its risk management strategy, HEP enters into financial contracts to
hedge the interest rate payments under its Credit Agreement. HEP does not use
the hedges for trading purposes, but rather to protect against the volatility of
the cash flows under its Credit Agreement, which has a floating interest rate.
The amounts received or paid upon settlement of these transactions are
recognized as interest expense at the time the interest payments are due.
All contracts are interest rate swaps with fixed rates. As of March 31, 1999,
HEP was a party to four contracts with three different counterparties.
<PAGE>
The following table provides a summary of HEP's financial contracts.
Average
Amount of Contract
Period Debt Hedged Floor Rate
Last nine months of 1999 $30,000,000 5.30%
2000 30,000,000 5.65%
2001 24,000,000 5.23%
2002 25,000,000 5.23%
2003 25,000,000 5.23%
2004 4,000,000 5.23%
Issues Related to the Year 2000
General. The following Year 2000 statements constitute a Year 2000 Readiness
Disclosure within the meaning of the Year 2000 Information and Readiness
Disclosure Act of 1998. The Year 2000 problem has arisen because many existing
computer programs use only the last two digits to refer to a year. Therefore,
these computer programs do not properly recognize and process date-sensitive
information beyond 1999. In general, there are two areas where Year 2000
problems may exist for the Partnership: information technology such as
computers, programs and related systems ("IT") and non-information technology
systems such as embedded technology on a silicon chip ("Non IT").
The Plan. The Partnership's Year 2000 Plan (the "Plan") has four phases: (i)
assessment, (ii) inventory, (iii) remediation, testing and implementation and
(iv) contingency plans. Approximately twelve months ago, the Partnership began
its phase one assessment of its particular exposure to problems that might arise
as a result of the new millennium. The assessment and inventory phases have been
substantially completed and have identified the Partnership's IT systems that
must be updated or replaced in order to be Year 2000 compliant. Remediation,
testing and implementation are scheduled to be completed by June 30, 1999, and
the contingency plans phase of the Plan is scheduled to be completed by
September 30, 1999.
However, the effects of the Year 2000 problem on IT systems are exacerbated
because of the interdependence of computer systems in the United States. The
Partnership's assessment of the readiness of third parties whose IT systems
might have an impact on the Partnership's business has thus far not indicated
any material problems; responses have been received to approximately 66% of the
180 inquiries made.
With regard to the Partnership's Non IT systems, the Partnership believes that
most of these systems can be brought into compliance on schedule. The
Partnership's assessment of third party readiness is not yet completed. Because
Non IT systems are embedded chips, it is difficult to determine with complete
accuracy where all such systems are located. As part of its Plan, the
Partnership is making formal and informal inquiries of its vendors, customers
and transporters in an effort to determine the third party systems that might
have embedded technology requiring remediation.
Estimated Costs. Although it is difficult to estimate the total costs of
implementing the Plan through January 1, 2000 and beyond, the Partnership's
preliminary estimate is that such costs will not be material. To date, the
Partnership has determined that its IT systems are either compliant or can be
made compliant for less than $100,000. However, although management believes
that its estimates are reasonable, there can be no assurance, for the reasons
stated in the next paragraph, that the actual cost of implementing the Plan will
not differ materially from the estimated costs.
<PAGE>
Potential Risks. The failure to correct a material Year 2000 problem could
result in an interruption in, or a failure of, certain normal business
activities or operations. This risk exists both as to the Partnership's IT and
Non IT systems, as well as to the systems of third parties. Such failures could
materially and adversely affect the Partnership's results of operations, cash
flow and financial condition. Due to the general uncertainty inherent in the
Year 2000 problem, resulting in part from the uncertainty of the Year 2000
readiness of third party suppliers, vendors and transporters, the Partnership is
unable to determine at this time whether the consequences of Year 2000 failures
will have a material impact on the Partnership's results of operations, cash
flow or financial condition. Although the Partnership is not currently able to
determine the consequences of Year 2000 failures, its current assessment is that
its area of greatest potential risk in its third party relationships is in
connection with the transporting and marketing of the oil and gas produced by
the Partnership. The Partnership is contacting the various purchasers and
pipelines with which it regularly does business to determine their state of
readiness for the Year 2000. Although in general the purchasers and pipelines
will not guaranty their state of readiness, the responses received to date have
indicated no material problems. The Partnership believes that in a worst case
scenario, the failure of its purchasers and transporters to conduct business in
a normal fashion could have a material adverse effect on cash flow for a period
of six to nine months. The Partnership's Year 2000 Plan is expected to
significantly reduce the Partnership's level of uncertainty about the compliance
and readiness of these material third parties. The evaluation of third party
readiness will be followed by the Partnership's development of contingency
plans.
Cautionary Statement Regarding Forward-Looking Statements. The dates for
completion of the phases of the Year 2000 Plan are based on the Partnership's
best estimates, which were derived using numerous assumptions of future events.
Due to the general uncertainty inherent in the Year 2000 problem, resulting in
part from the uncertainty of the Year 2000 readiness of third-parties and the
interconnection of computer systems, the Partnership cannot ensure its ability
to timely and cost-effectively resolve problems associated with the Year 2000
issue that may affect its operations and business. Accordingly, partners are
cautioned that certain events or circumstances could cause actual results to
differ materially from those projected, estimated or predicted.
Cautionary Statement Regarding Forward-Looking Statements
In the interest of providing the partners with certain information regarding the
Partnership's future plans and operations, certain statements set forth in this
Form 10-Q relate to management's future plans and objectives. Such statements
are forward-looking statements. Although any forward-looking statements
contained in this Form 10-Q or otherwise expressed by or on behalf of the
Partnership are, to the knowledge and in the judgment of the officers and
directors of the general partner, expected to prove true and come to pass,
management is not able to predict the future with absolute certainty.
Forward-looking statements involve known and unknown risks and uncertainties
which may cause the Partnership's actual performance and financial results in
future periods to differ materially from any projection, estimate or forecasted
result. Please refer to the Partnership's Annual Report on Form 10-K for
additional statements concerning important factors that could cause actual
results to differ materially from the Partnership's expectations. These risks
and uncertainties include, among other things, volatility of oil and gas prices,
competition, risks inherent in the Partnership's oil and gas operations, the
inexact nature of interpretation of seismic and other geological and geophysical
data, imprecision of reserve estimates, the Partnership's ability to replace and
expand oil and gas reserves, and such other risks and uncertainties described
from time to time in the Partnership's periodic reports and filings with the
Securities and Exchange Commission. Accordingly, Unitholders and potential
investors are cautioned that certain events or circumstances could cause actual
results to differ materially from those projected, estimated or predicted.
Inflation and Changing Prices
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 fluctuated significantly, with a distinct downward
trend in both oil and gas prices occurring in the calendar year 1998 and through
the first quarter of 1999. In preparing its 1999 budget, HEP has estimated that
the weighted average oil price (for barrels not hedged) will be $11.00 per
barrel, and the weighted average price of natural gas (for mcf not hedged) will
be $1.70 per mcf for the year. The Partnership presently believes oil and gas
prices for the remainder of 1999 will exceed the budgeted prices. However, there
can be no assurance that HEP's forecast is accurate. If prices decrease below
the forecasted levels, it can be expected that the results of operations and
cash flow will be affected, and HEP's budget will decrease. The following table
presents the weighted average prices received each quarter by HEP and the
effects of the hedging transactions discussed below.
<PAGE>
<TABLE>
<CAPTION>
Oil Oil Gas Gas
(excluding the (including the (excluding the (including the
effects of effects of effects of effects of
hedging hedging hedging hedging
transactions) transactions) transactions) transactions)
(per bbl) (per bbl) (per mcf) (per mcf)
<S> <C> <C> <C> <C>
First quarter - 1998 $14.80 $15.30 $2.11 $2.07
Second quarter - 1998 13.03 13.82 2.08 2.06
Third quarter - 1998 12.19 13.06 1.85 1.95
Fourth quarter - 1998 11.12 12.29 1.96 2.02
First quarter - 1999 11.33 11.41 1.65 1.81
</TABLE>
As part of its risk management strategy, HEP enters into financial contracts to
hedge the price of its oil and natural gas. The purpose of the hedges is to
provide protection against price decreases and to provide a measure of stability
in the volatile environment of oil and natural gas spot pricing. The amounts
received or paid upon settlement of hedge contracts are recognized as oil or gas
revenue at the time the hedged volumes are sold.
The financial contracts used by HEP to hedge the price of its oil and natural
gas production are swaps, collars and participating hedges. Under the swap
contracts, HEP sells its oil and gas production at spot market prices and
receives or makes payments based on the differential between the contract price
and a floating price which is based on spot market indices. As of May 3, 1999,
HEP was a party to 31 financial contracts with five different counterparties.
The following table provides a summary of HEP's outstanding financial contracts:
Oil Contract
Percent of Production Delivered
Period Hedged Floor Price
(per bbl)
Last nine months of 1999 24% $14.71
Approximately 9% of the oil volumes hedged are subject to a participating hedge
whereby HEP will receive the contract price if the posted futures price is lower
than the contract price, and will receive the contract price plus 25% of the
difference between the contract price and the posted futures price if the posted
futures price is greater than the contract price. Additionally, 9% of the
volumes hedged are subject to a collar agreement whereby HEP will receive the
contract price if the spot price is lower than the contract price, the cap price
if the spot price is higher than the cap price, and the spot price if that price
is between the contract price and the cap price. The cap prices range from
$16.50 to $18.35.
<PAGE>
Gas Contract
Percent of Production Delivered
Period Hedged Floor Price
(per mcf)
Last nine months of 1999 53% $2.01
2000 45% 2.08
2001 38% 2.04
2002 30% 2.09
Between 12% and 25% of the gas volumes hedged in each year are subject to a
collar agreement whereby HEP will receive the contract price if the spot price
is lower than the contract price, the cap price if the spot price is higher than
the cap price, and the spot price if that price is between the contract price
and the cap price. The cap prices range from $2.63 per mcf to $2.80 per mcf.
During the second quarter through May 3, 1999 the weighted average oil price
(for barrels not hedged) was approximately $15.20 per barrel. The weighted
average price of natural gas (for mcf not hedged) during that period was
approximately $1.75 per mcf.
Inflation
Inflation did not have a material impact on HEP in 1998 and is not anticipated
to have a material impact in 1999.
Results of Operations
The following tables are presented to contrast HEP's revenue, expense and
earnings for discussion purposes. Significant fluctuations are discussed in the
accompanying narrative. The "direct owned" column represents HEP's direct
royalty and working interests in oil and gas properties. The "Mays" column
represents the results of operations of six May Limited Partnerships which are
consolidated with HEP. In 1999, HEP owned interests which ranged from 54.8% to
69.1% and in 1998, HEP owned interests which ranged from 54.7% to 68.7% of the
Mays.
<PAGE>
<TABLE>
<CAPTION>
TABLE OF HEP EARNINGS FOR MANAGEMENT DISCUSSION
(In thousands except price)
For the Quarter Ended March 31, 1999 For the Quarter Ended March 31, 1998
------------------------------------ ------------------------------------
Direct Direct
Owned Mays Total Owned Mays Total
<S> <C> <C> <C> <C> <C> <C>
Gas production (mcf) 3,351 229 3,580 2,945 320 3,265
Oil production (bbl) 181 9 190 187 15 202
Average gas price (per mcf) $ 1.80 $ 1.94 $ 1.81 $ 2.02 $ 2.47 $ 2.07
Average oil price (per bbl) $ 11.38 $ 12.00 $ 11.41 $ 15.30 $ 15.27 $ 15.30
Gas revenue $ 6,045 $ 445 $ 6,490 $ 5,952 $ 792 $ 6,744
Oil revenue 2,059 108 2,167 2,861 229 3,090
Pipeline, facilities and other revenue 1,209 1,209 700 700
Interest income 106 10 116 122 18 140
-------- --------- -------- -------- -------- --------
Total revenue 9,419 563 9,982 9,635 1,039 10,674
------ -------- ------ ------- ------ ------
Production operating expense 2,979 79 3,058 2,940 121 3,061
Facilities operating expense 175 175 152 152
General and administrative expense 1,244 98 1,342 1,066 99 1,165
Depreciation, depletion, and amortization 4,036 257 4,293 3,217 322 3,539
Interest expense 818 818 644 644
Equity in loss of HCRC 482 482 94 94
Minority interest in net income of affiliates 132 132 313 313
Litigation (45) (45)
----------- ----------- ----------- --------- ---------- ---------
Total expense 9,734 566 10,300 8,068 855 8,923
------ -------- ------ ------- ------ -------
Net income (loss) $ (315) $ (3) $ (318) $ 1,567 $ 184 $ 1,751
======== ========== ======== ======= ====== =======
</TABLE>
<PAGE>
First Quarter of 1999 Compared to First Quarter of 1998
Gas Revenue
Gas revenue decreased $254,000 during the first quarter of 1999 compared with
the first quarter of 1998. The decrease is the result of a decrease in the
average gas price from $2.07 per mcf in 1998 to $1.81 per mcf in 1999 partially
offset by an increase in production from 3,265,000 mcf in 1998 to 3,580,000 mcf
in 1999. The increase in production is primarily due to the acquisition of a
volumetric production payment during May 1998.
The effect of HEP's hedging transactions as described under "Inflation and
Changing Prices," during the first quarter of 1999, was to increase HEP's
average gas price from $1.65 per mcf to $1.81 per mcf, representing a $573,000
increase in revenue from hedging transactions.
Oil Revenue
Oil revenue decreased $923,000 during the first quarter of 1999 compared with
the first quarter of 1998. The decrease is the result of a decrease in the
average oil price from $15.30 per barrel in 1998 to $11.41 in 1999, and a
decrease in production from 202,000 barrels in 1998 to 190,000 barrels in 1999.
The decrease in oil production is primarily due to normal production declines.
The effect of HEP's hedging transactions during the first quarter of 1999, was
to increase HEP's average oil price from $11.33 per barrel to $11.41 per barrel,
resulting in a $15,000 increase in revenue from hedging transactions.
Pipeline, Facilities and Other
Pipeline, facilities and other revenue consists primarily of facilities income
from two gathering systems located in New Mexico, revenues derived from salt
water disposal and incentive payments related to certain wells in San Juan
County, New Mexico and LaPlata County, Colorado. Pipeline, facilities and other
revenue increased $509,000 during the first quarter of 1999 compared with the
first quarter of 1998 primarily due to increased incentive payment income from
the acquisition of the volumetric production payment during May 1998.
Interest Income
Interest income decreased $24,000 during the first quarter of 1999 compared with
the first quarter of 1998 due to a lower average cash balance during 1999.
General and Administrative
General and administrative expense includes costs incurred for direct
administrative services such as legal, audit and reserve reports as well as
allocated internal overhead incurred by the operating company on behalf of HEP.
These expenses increased $177,000 during the first quarter of 1999 primarily due
to increased salaries expense.
Depreciation, Depletion and Amortization Expense
Depreciation, depletion and amortization expense increased $754,000 during the
first quarter of 1999 compared with the first quarter of 1998. The increase is
primarily the result of higher capitalized costs and a higher depletion rate in
1999 due to the increase in production previously discussed.
Interest
Interest expense increased $174,000 during the first quarter of 1999 compared
with the first quarter of 1998 due to a higher average outstanding debt balance
during 1999.
<PAGE>
Equity in Loss of HCRC
Equity in loss of HCRC increased $388,000 during the first quarter of 1999
compared with the first quarter of 1998. The increase is primarily due to
decreased oil revenue caused by lower oil prices and increased interest expense
due to HCRC's higher average outstanding debt balance during 1999.
Minority Interest in Net Income of Affiliates
Minority interest in net income of affiliates represents unaffiliated partners'
interest in the net income of the May Partnerships. The decrease of $181,000
during the first quarter of 1999 compared with the first quarter of 1998 is due
to a decrease in the net income of the May Partnerships resulting primarily from
lower oil prices received for sales from their properties.
Litigation
Litigation income during the first quarter of 1998 represents the settlement of
a take-or-pay contract claim.
<PAGE>
ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
HEP's primary market risks relate to changes in interest rates and in the prices
received from sales of oil and natural gas. HEP's primary risk management
strategy is to partially mitigate the risk of adverse changes in its cash flows
caused by increases in interest rates on its variable rate debt and decreases in
oil and natural gas prices, by entering into derivative financial and commodity
instruments, including swaps, collars and participating commodity hedges. By
hedging only a portion of its market risk exposures, HEP is able to participate
in the increased earnings and cash flows associated with decreases in interest
rates and increases in oil and natural gas prices; however, it is exposed to
risk on the unhedged portion of its variable rate debt and oil and natural gas
production.
Historically, HEP has attempted to hedge the exposure related to its variable
rate debt and its forecasted oil and natural gas production in amounts which it
believes are prudent based on the prices of available derivatives and, the
Partnership's estimated debt levels and deliverable volumes. HEP attempts to
manage the exposure to adverse changes in the fair value of its fixed rate debt
agreements by issuing fixed rate debt only when business conditions and market
conditions are favorable.
HEP does not use or hold derivative instruments for trading purposes nor does it
use derivative instruments with leveraged features. HEP's derivative instruments
are designated and effective as hedges against its identified risks, and do not
of themselves expose HEP to market risk because any adverse change in the cash
flows associated with the derivative instrument is accompanied by an offsetting
change in the cash flows of the hedged transaction.
All derivative activity is carried out by personnel who have appropriate skills,
experience and supervision. The personnel involved in derivative activity must
follow prescribed trading limits and parameters that are regularly reviewed by
the Board of Directors of the general partner and by senior management. HEP uses
only well-known, conventional derivative instruments and attempts to manage its
credit risk by entering into financial contracts with reputable financial
institutions.
Following are disclosures regarding HEP's market risk sensitive instruments by
major category. Investors and other users are cautioned to avoid simplistic use
of these disclosures. Users should realize that the actual impact of future
interest rate and commodity price movements will likely differ from the amounts
disclosed below due to ongoing changes in risk exposure levels and concurrent
adjustments to hedging positions. It is not possible to accurately predict
future movements in interest rates and oil and natural gas prices.
Interest Rate Risks (non-trading) - HEP uses both fixed and variable rate debt
to partially finance operations and capital expenditures. As of March 31, 1999,
HEP's debt consists of borrowings under its Credit Agreement which bears
interest at a variable rate. HEP hedges a portion of the risk associated with
this variable rate debt through derivative instruments, which consist of
interest rate swaps and collars. Under the swap contracts, HEP makes interest
payments on its Credit Agreement as scheduled and receives or makes payments
based on the differential between the fixed rate of the swap and a floating rate
plus a defined differential. These instruments reduce HEP's exposure to
increases in interest rates on the hedged portion of its debt by enabling it to
effectively pay a fixed rate of interest or a rate which only fluctuates within
a predetermined ceiling and floor. A hypothetical increase in interest rates of
two percentage points would cause a loss in income and cash flows of $760,500
during the remaining nine months of 1999, assuming that outstanding borrowings
under the Credit Agreement remain at current levels. This loss in income and
cash flows would be offset by a $450,000 increase in income and cash flows
associated with the interest rate swap and collar agreements that are in effect
for the remaining nine months of 1999.
<PAGE>
Commodity Price Risk (non-trading) - HEP hedges a portion of the price risk
associated with the sale of its oil and natural gas production through the use
of derivative commodity instruments, which consist of swaps, collars and
participating hedges. These instruments reduce HEP's exposure to decreases in
oil and natural gas prices on the hedged portion of its production by enabling
it to effectively receive a fixed price on its oil and gas sales or a price that
only fluctuates between a predetermined floor and ceiling. HEP's participating
hedges also enable HEP to receive 25% of any increase in prices over the fixed
prices specified in the contracts. As of May 3, 1999, HEP has entered into
derivative commodity hedges covering an aggregate of 167,000 barrels of oil and
17,934,000 mcf of gas that extend through 2002. Under the these contracts, HEP
sells its oil and natural gas production at spot market prices and receives or
makes payments based on the differential between the contract price and a
floating price which is based on spot market indices. The amount received or
paid upon settlement of these contracts is recognized as oil or natural gas
revenues at the time the hedged volumes are sold. A hypothetical decrease in oil
and natural gas prices of 10% from the prices in effect as of March 31, 1999
would cause a loss in income and cash flows of $2,512,000 during the remaining
nine months of 1999, assuming that oil and gas production remain at levels
during the last nine months of 1998. This loss in income and cash flows would be
offset by a $1,165,000 increase in income and cash flows associated with the oil
and natural gas derivative contracts that are in effect for the remaining nine
months of 1999.
<PAGE>
PART II -OTHER INFORMATION
ITEM 1 - LEGAL PROCEEDINGS
Reference is made to Item 8 - Notes 12 and 13 of Form 10-K for
the year ended December 31, 1998 and Notes 7 and 8 of this
Form 10-Q.
ITEM 2 - CHANGES IN SECURITIES
None.
ITEM 3 - DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5 - OTHER INFORMATION
None.
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
a) Exhibit
27 Financial Data Schedule
b) Reports on Form 8-K
None.
<PAGE>
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Partnership has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
HALLWOOD ENERGY PARTNERS, L. P.
By: HEPGP LTD.
General Partner
By: HALLWOOD G. P., INC.
General Partner
Date: May 11, 1999 By: /s/Thomas J. Jung
Thomas J. Jung, Vice President
(Chief Financial Officer)
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from Form 10-Q
for the three months ended March 31, 1999 for Hallwood Energy Partners, L.P.and
is qualified in its entirety by reference to such Form 10-Q.
</LEGEND>
<CIK> 0000768172
<NAME> Hallwood Energy Partners, L.P.
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> MAR-31-1999
<CASH> 5,723
<SECURITIES> 0
<RECEIVABLES> 12,294
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 19,679
<PP&E> 673,950
<DEPRECIATION> 570,247
<TOTAL-ASSETS> 133,475
<CURRENT-LIABILITIES> 31,693
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 60,005
<TOTAL-LIABILITY-AND-EQUITY> 133,475
<SALES> 9,866
<TOTAL-REVENUES> 9,982
<CGS> 0
<TOTAL-COSTS> 3,233
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 818
<INCOME-PRETAX> (318)
<INCOME-TAX> 0
<INCOME-CONTINUING> (318)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (318)
<EPS-PRIMARY> (.12)
<EPS-DILUTED> (.12)
</TABLE>
