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 September 30, 1998
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File Number 1-8921
HALLWOOD ENERGY PARTNERS, L. P.
(Exact name of registrant as specified in its charter)
Delaware 84-0987088
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
4582 South Ulster Street Parkway
Suite 1700
Denver, Colorado 80237
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (303) 850-7373
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 November 13, 1998
Class A 10,011,854
Class B 143,773
Class C 2,464,063
Page 1 of 25
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<CAPTION>
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
HALLWOOD ENERGY PARTNERS, L. P.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands)
September 30, December 31,
1998 1997
CURRENT ASSETS
<S> <C> <C>
Cash and cash equivalents $ 10,301 $ 6,622
Accounts receivable:
Oil and gas revenues 5,428 8,772
Trade 4,932 4,609
Due from affiliates 380 588
Prepaid expenses and other current assets 1,791 1,551
Net working capital of affiliate 442
----------
Total 23,274 22,142
-------- --------
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method):
Proved mineral interests 653,425 624,621
Unproved mineral interests - domestic 2,813 2,315
Furniture, fixtures and other 3,399 3,513
--------- ---------
Total 659,637 630,449
Less accumulated depreciation, depletion,
amortization and property impairment (556,552) (536,118)
-------- -------
Total 103,085 94,331
------- --------
OTHER ASSETS
Investment in common stock of HCRC 11,958 15,048
Deferred expenses and other assets 136 82
---------- -----------
Total 12,094 15,130
-------- --------
TOTAL ASSETS $138,453 $131,603
======= =======
<FN>
(Continued on the following page)
</FN>
</TABLE>
<TABLE>
<CAPTION>
HALLWOOD ENERGY PARTNERS, L. P.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands except Units)
September 30, December 31,
1998 1997
CURRENT LIABILITIES
<S> <C> <C>
Accounts payable and accrued liabilities $ 21,463 $ 19,915
Current portion of long-term debt 6,213
Net working capital deficit of affiliate 448
Current portion of contract settlement 2,752
------------- ---------
Total 27,676 23,115
-------- --------
NONCURRENT LIABILITIES
Long-term debt 34,987 34,986
Deferred liability 1,081 1,180
--------- ---------
Total 36,068 36,166
-------- --------
Total Liabilities 63,744 59,281
-------- --------
MINORITY INTEREST IN AFFILIATES 2,845 3,258
--------- ---------
COMMITMENTS AND CONTINGENCIES (NOTE 9)
PARTNERS' CAPITAL
Class A Units - 10,011,854 and 9,977,254 Units issued in 1998 and 1997,
respectively; 9,121,612 and 9,077,949
outstanding in 1998 and 1997, respectively 52,962 66,184
Class B Subordinated Units - 143,773 Units outstanding
in 1998 and 1997 1,261 1,411
Class C Units - 2,464,063 and 664,063 Units outstanding
in 1998 and 1997, respectively 21,385 4,868
General partner 3,165 3,580
Treasury Units - 890,242 and 899,305 Units in 1998 and
1997, respectively (6,909) (6,979)
--------- ---------
Partners' Capital - Net 71,864 69,064
-------- --------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $138,453 $131,603
======= =======
<FN>
The accompanying notes are an integral part of the financial statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
HALLWOOD ENERGY PARTNERS, L. P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands except per Unit data)
For the Three Months Ended
September 30,
1998 1997
REVENUES:
<S> <C> <C>
Gas revenue $ 7,421 $ 6,639
Oil revenue 2,626 3,564
Pipeline, facilities and other 1,067 523
Interest 241 69
--------- ---------
11,355 10,795
------ ------
EXPENSES:
Production operating 3,083 3,072
General and administrative 1,104 996
Depreciation, depletion and amortization 4,617 3,165
Impairment of oil and gas properties 6,600
Interest 734 716
-------- --------
16,138 7,949
------ -------
OTHER INCOME (EXPENSES):
Equity in earnings (loss) of HCRC (767) 138
Minority interest in net income of affiliates (203) (449)
Litigation (375) (33)
--------- ---------
(1,345) (344)
------- --------
NET INCOME (LOSS) (6,128) 2,502
CLASS C UNIT DISTRIBUTIONS ($.25 PER UNIT) 616 166
-------- --------
NET INCOME (LOSS) ATTRIBUTABLE TO GENERAL
PARTNER, CLASS A AND CLASS B LIMITED
PARTNERS $ (6,744) $ 2,336
======= =======
ALLOCATION OF NET INCOME (LOSS):
General partner $ 82 $ 532
========== ========
Class A and Class B Limited partners $ (6,826) $ 1,804
======= =======
Per Class A Unit and Class B Unit - basic $ (.74) $ .20
========= =========
Per Class A Unit and Class B Unit - diluted $ (.74) $ .19
========= =========
Weighted average Class A Units and Class B Units
outstanding 9,265 9,222
======= =======
<FN>
The accompanying notes are an integral part of the financial statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
HALLWOOD ENERGY PARTNERS, L. P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands except per Unit data)
For the Nine Months Ended
September 30,
1998 1997
REVENUES:
<S> <C> <C>
Gas revenue $21,159 $19,073
Oil revenue 8,356 11,157
Pipeline, facilities and other 2,743 2,072
Interest 567 328
-------- --------
32,825 32,630
------ ------
EXPENSES:
Production operating 9,389 8,767
General and administrative 3,353 3,250
Depreciation, depletion and amortization 11,234 8,657
Impairment of oil and gas properties 9,200
Interest 1,927 2,315
------- -------
35,103 22,989
------- ------
OTHER INCOME (EXPENSES):
Equity in earnings (loss) of HCRC (3,090) 1,384
Minority interest in net income of affiliates (787) (1,341)
Litigation (930) 240
-------- --------
(4,807) 283
------- --------
NET INCOME (LOSS) (7,085) 9,924
CLASS C UNIT DISTRIBUTIONS ($.75 PER UNIT) 1,848 498
------- --------
NET INCOME (LOSS) ATTRIBUTABLE TO GENERAL
PARTNER, CLASS A AND CLASS B LIMITED PARTNERS
$ (8,933) $ 9,426
======= =======
ALLOCATION OF NET INCOME (LOSS):
General partner $ 732 $ 1,408
========= =======
Class A and Class B Limited partners $ (9,665) $ 8,018
======= =======
Per Class A Unit and Class B Unit - basic $ (1.04) $ .87
========= =========
Per Class A Unit and Class B Unit - diluted $ (1.04) $ .86
========= =========
Weighted average Class A Units and Class B Units
outstanding 9,256 9,222
======= =======
<FN>
The accompanying notes are an integral part of the financial statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
HALLWOOD ENERGY PARTNERS, L. P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
For the Nine Months Ended
September 30,
1998 1997
OPERATING ACTIVITIES:
<S> <C> <C>
Net income (loss) $ (7,085) $ 9,924
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization 11,234 8,657
Impairment of oil and gas properties 9,200
Depreciation charged to affiliates 188 165
Asset disposals (188)
Amortization of deferred loan costs and other assets 54 61
Noncash interest expense 15 178
Equity in (earnings) loss of HCRC 3,090 (1,384)
Minority interest in net income 787 1,341
Undistributed (earnings) loss of affiliates (508) 73
Recoupment of take-or-pay liability (99) (97)
Changes in operating assets and liabilities provided (used) cash net of
noncash activity:
Oil and gas revenues receivable 3,344 1,976
Trade receivables (323) (305)
Due from affiliates (874) (996)
Prepaid expenses and other current assets (240) (1,031)
Accounts payable and accrued liabilities 1,548 1,488
Due to affiliates (1,772)
----------- -------
Net cash provided by operating activities 20,143 18,278
------ ------
INVESTING ACTIVITIES:
Additions to property, plant and equipment (19,772) (2,499)
Exploration and development costs incurred (9,561) (9,073)
Proceeds from sales of property, plant and equipment 189 85
Distributions received from affiliate 639
Other investing activities (21) (76)
---------- ----------
Net cash used in investing activities (28,526) (11,563)
------- -------
FINANCING ACTIVITIES:
Proceeds from long-term debt 24,500 2,000
Proceeds from the issuance of Class C Units net of syndication 16,517
costs
Payments of long-term debt (18,286) (5,285)
Distributions paid (7,072) (5,583)
Payment of contract settlement (2,767)
Distribution paid by consolidated affiliates to minority interest (1,200) (1,503)
Exercise of Unit Options 199
Capital contribution from the general partner 171
Other (115)
------------- --------
Net cash provided by (used in) financing activities 12,062 (10,486)
------- ------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
3,679 (3,771)
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD 6,622 5,540
------- -------
END OF PERIOD $ 10,301 $ 1,769
======= =======
<FN>
The accompanying notes are an integral part of the financial statements.
</FN>
</TABLE>
<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 December 31,
1997 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
During February 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 128 Earnings per Share ("SFAS 128"). SFAS
128 establishes standards for computing and presenting earnings per share (EPS),
and supersedes APB Opinion No. 15 and its related interpretations. It replaces
the presentation of primary EPS with a presentation of basic EPS, which excludes
dilution, and requires dual presentation of basic and diluted EPS for all
entities with complex capital structures. Diluted EPS is computed similarly to
fully diluted EPS pursuant to Opinion No. 15. SFAS 128 is effective for periods
ending after December 15, 1997, including interim periods, and requires
restatement of all prior period EPS data presented. HEP adopted SFAS 128
effective December 31, 1997, and has restated all prior period EPS data
presented to give retroactive effect to the new accounting standard.
<PAGE>
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 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. The
Unit options have been ignored in the computation of diluted loss per Class A
and Class B Unit for the three and nine months ended September 30, 1998 because
their inclusion would be antidilutive.
<TABLE>
<CAPTION>
Income (Loss) Units Per Unit
(In thousands except per Unit)
For the Three Months Ended September 30, 1998
<S> <C> <C> <C>
Net loss per Class A Unit and Class B Unit - basic $(6,826) 9,265 $ (.74)
------ ----- =====
Net Loss per Class A Unit and Class B Unit - diluted $(6,826) 9,265 $ (.74)
====== ===== =====
For the Nine Months Ended September 30, 1998
Net loss per Class A Unit and Class B Unit - basic $(9,665) 9,256 $(1.04)
------ ----- ======
Net Loss per Class A Unit and Class B Unit - diluted $(9,665) 9,256 $(1.04)
====== ===== =====
For the Three Months Ended September 30, 1997
Net income per Class A Unit and Class B Unit - basic $ 1,804 9,222 $ .20
=====
Effect of Unit Options 113
---------- ------
Net Income per Class A Unit and Class B Unit - diluted $ 1,804 9,335 $ .19
====== ===== =====
For the Nine Months Ended September 30, 1997
Net income per Class A Unit and Class B Unit -basic $ 8,018 9,222 $ .87
=====
Effect of Unit Options 131
---------- ------
Net Income per Class A Unit and Class B Unit - diluted $ 8,018 9,353 $ .86
====== ===== =====
</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 and 899,305 of its own Units at September 30, 1998 and December 31,
1997, respectively.
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 and nine month
periods ended September 30, 1998 and 1997. Therefore, total comprehensive income
(loss) was the same as net income (loss) for those periods.
During 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. Under
the Credit Agreement, HEP has a borrowing base of $62,000,000. HEP had amounts
outstanding at September 30, 1998 of $41,200,000. Subsequent to September 30,
1998, HEP borrowed an additional $8,500,000 for the Arcadia acquisition
described in Note 8 and for capital projects, increasing its amounts outstanding
to $49,700,000. HEP's unused borrowing base totaled $12,300,000 at November 13,
1998.
Borrowings against the Credit Agreement bear interest at the lower of the
Certificate of Deposit rate plus from 1.375% to 1.875%, prime plus 1/2% or the
Euro-Dollar rate plus from 1.25% to 1.75%. The applicable interest rate was 7.0%
at September 30, 1998. Interest is payable monthly, and quarterly principal
payments of $3,106,500, as adjusted for the $8,500,000 of borrowings made
subsequent to September 30, 1998, commence May 31, 1999.
The borrowing base for the Credit Agreement is redetermined semiannually. The
Credit Agreement is secured by a first lien on approximately 80% in value of
HEP's oil and gas properties. Additionally, aggregate distributions 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.
HEP entered into contracts to hedge its interest rate payments on $15,000,000 of
its debt for 1998 and $10,000,000 for each of 1999 and 2000. HEP does not use
the hedges for trading purposes, but rather for the purpose of providing a
measure of predictability for a portion of HEP's interest payments under its
Credit Agreement, which has a floating interest rate. In general, it is HEP's
goal to hedge 50% of the principal amount of its debt for the next two years and
25% for each year of the remaining term of the debt. HEP has entered into four
hedges, one of which is an interest rate collar pursuant to which it pays a
floor rate of 7.55% and a ceiling rate of 9.85%, and the others are interest
rate swaps with fixed rates ranging from 5.75% to 6.57%. The amounts received or
paid upon settlement of these transactions are recognized as interest expense at
the time the interest payments are due.
NOTE 3 - STATEMENTS OF CASH FLOWS
Cash paid for interest during the nine months ended September 30, 1998 and 1997
was $1,845,000 and $2,077,000, respectively.
NOTE 4 - CLASS C UNIT ISSUANCE
On February 17, 1998, HEP closed its public offering of 1.8 million Class C
Units, priced at $10.00 per Unit. Proceeds to HEP, net of underwriting expenses,
were approximately $16,517,000. HEP used $14,000,000 of the net proceeds to
repay borrowings under its Credit Agreement and applied the remaining proceeds
toward the repayment of HEP's outstanding contract settlement obligation at
December 31, 1997 of $2,752,000.
NOTE 5 - ACQUISITION
In July 1996, HEP and its affiliate, HCRC, acquired interests in 38 wells
located primarily in LaPlata County, Colorado. An unaffiliated large East Coast
financial institution formed an entity to utilize the tax credits generated from
the wells. The project was financed by an affiliate of Enron Corp. through a
volumetric production payment. During May 1998, a limited liability company
owned equally by HEP and HCRC purchased the volumetric production payment from
the affiliate of Enron Corp. HEP funded its $17,257,000 share of the acquisition
price from operating cash flow and borrowings under its Credit Agreement.
NOTE 6 - IMPAIRMENT OF OIL AND GAS PROPERTIES
During the second and third quarters of 1998, HEP recorded impairments of its
oil and gas properties because capitalized costs at June 30, 1998 and September
30, 1998 exceeded the present value (discounted at 10%) of estimated future net
revenues from proved oil and gas reserves, based on prices of $13.00 per barrel
of oil and $2.00 per mcf of gas and $12.80 per barrel of oil and $1.90 per mcf
of gas, respectively.
NOTE 7 - UNIT OPTION PLAN
During the second quarter of 1998, HEP adopted a Class C Unit Option Plan
covering 120,000 Class C Units. Options to purchase all of the Units were
granted effective May 5, 1998 at an exercise price of $10.00 per Unit, which was
equal to the fair market value of the Units on the date of grant. One-half of
the options vested on the date of grant, and the remainder vest on the first
anniversary of the date of grant.
On May 5, 1998, HEP granted options to purchase 25,500 Class A Units at an
exercise price of $6.625 per Unit, which was equal to the fair market value of
the Units on the date of grant. These options were not granted pursuant to a
previously existing plan but are subject to terms and conditions identical to
those in HEP's 1995 Unit Option Plan. One-third of the options vested on the
date of grant, and the remainder vest one-half on the first anniversary of the
date of grant and one-half on the second anniversary of the date of grant.
NOTE 8 - 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.
Arcadia's claim for interest on the adjusted purchase price is still pending.
<PAGE>
At the end of 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 $8,100,000. The excess
of the purchase price of the properties over the estimated net revenues
attributable to proved reserves, based on prices of $12.80 per barrel of oil and
$1.90 per mcf of gas, was included in the determination of the impairment of
HEP's oil and gas properties in the third quarter of 1998.
NOTE 9 - 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.
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
During the first nine months of 1998, HEP had a net loss of $7,085,000, compared
to a net income of $9,924,000 for the first nine months of 1997. The 1998 period
includes noncash charges in the second and third quarters totaling $9,200,000
for property impairments which were taken to lower the capitalized cost of HEP's
properties. Also included in the net loss is a noncash charge of $3,090,000
which represents HEP's equity in the loss of HCRC. This amount is largely
comprised of HEP's share of HCRC's property impairments.
HEP's 1998 property impairments were recorded pursuant to ceiling test
limitations required by the Securities and Exchange Commission for companies
using the full cost method of accounting. The total impairment was primarily
attributable to the decline in commodity prices, the difference between the
purchase price negotiated in August 1997 for the Arcadia properties and the
value at current prices of those properties, and the write-off of certain
unproved acreage.
The weighted average prices received by HEP for oil and gas have declined in
each of the last three quarters. HEP's hedges have mitigated the price
reductions, however; HEP's weighted average oil and gas prices, when the effects
of hedging are considered, were 29% and 8% lower, respectively, for the first
nine months of 1998 compared to the first nine months of 1997.
Although HEP's production for the first nine months of 1998 was 16% greater than
the prior year, and operating, general and administrative and interest expenses
were lower on a unit of production basis, net income was lower because of
continued low commodity prices and litigation costs associated with the
resolution of litigation.
Liquidity and Capital Resources
Cash Flow
HEP generated $20,143,000 of cash flow from operating activities during the
first nine months of 1998.
<PAGE>
The other primary cash inflows were:
o Proceeds from long-term debt of $24,500,000;
o Proceeds from the issuance of Class C Units, net of syndication
costs, of $16,517,000;
o Distributions received from affiliate of $639,000;
o Exercise of Unit Options of $199,000; and
o Capital contribution from the general partner of $171,000.
Cash was used primarily for:
o Additions to property and development costs incurred of $29,333,000;
o Payments of long-term debt of $18,286,000;
o Distributions to Unitholders of $7,072,000 and
o Payment of contract settlement of $2,767,000.
When combined with miscellaneous other cash activity during the period, the
result was an increase of $3,679,000 in HEP's cash from $6,622,000 at December
31, 1997 to $10,301,000 at September 30, 1998.
Exploration and Development Projects and Acquisitions
Through September 30, 1998, HEP incurred $29,333,000 in direct property
additions, development, exploitation, and exploration costs. The costs were
comprised of $19,772,000 for property acquisitions and approximately $9,561,000
for domestic exploration and development. The expenditures resulted in the
drilling, recompletion, or workover of 38 development wells and 28 exploration
wells. Thirty-four development wells (89%) and 14 exploration wells (50%) were
successfully completed as producers, for an overall success rate of 73%. HEP's
1998 capital budget was initially set at $25,000,000 but was increased to
$40,250,000. The increase allowed for the purchase of the volumetric production
payment and for the purchase of oil and gas reserves through an acquisition
which closed in October 1998, both of which are discussed below. The remaining
budget for 1998 includes future projects in more than 10 areas.
Significant acquisition, exploration, and development projects for 1998 are
discussed below.
Rocky Mountain Region
HEP expended approximately $20,645,000 of its capital budget in the Rocky
Mountain Region located in Colorado, Montana, North Dakota, Northwest New Mexico
and Wyoming. Of this amount, approximately $17,291,000 was for the purchase of
the volumetric production payment discussed below. In 1998, HEP spent
approximately $2,343,000 expanding the New Mexico gathering system, successfully
recompleting five operated development wells, drilling four successful
development wells, and drilling two unsuccessful operated exploration wells. A
discussion of the major projects in the Region follows.
<PAGE>
San Juan Basin Project - Colorado.
In July 1996, HEP and its affiliate HCRC
acquired interests in 34 wells in LaPlata County, Colorado. An unaffiliated
large East Coast financial institution formed an entity to utilize tax credits
generated from the wells. The project was financed by an affiliate of Enron
Corp. through a volumetric production payment. During May 1998, a limited
liability company, owned equally by HEP and HCRC, purchased from the affiliate
of Enron Corp. the volumetric production payment. HEP funded its $17,291,000
share of the acquisition price from operating cash flow and borrowings under its
Credit Agreement. At the time of the purchase, HEP entered into a financial
contract to hedge the volumes subject to the production payment at an average
price of $2.11 per mmbtu. Under the terms of the original 1996 transaction, HEP
was already responsible for all costs associated with the wells. HPI has managed
and operated the wells since July 1996, and has increased the wells' production
from 14 to 26 mmcf per day through successful workover and gas gathering
facilities improvement programs. The acquisition increased HEP's current average
daily production by 6,750 mcf per day.
San Juan Basin Project - New Mexico.
Costs associated with a gathering system
for HEP's New Mexico coalbed methane properties totaled approximately $938,000
during 1998. HEP expects the gathering system to significantly increase gas
gathering, processing and compression capacity for the associated properties.
The project should be completed in the fourth quarter of 1998. On the completed
portion of the project, production has increased 3.0 gross mmcf per day. HEP
owns an approximate 35% working interest in the wells.
Cajon Lake Field.
HEP is currently completing the sidetracking and redrilling of a 6,000 foot
Ismay formation exploration well in San Juan County, Utah. HEP owns an
approximate 15% working interest in the operated well and has incurred
approximately $90,000 in 1998. Initial tests of the Ismay formation are
promising, and HEP estimates that the sale of production will begin in November
1998.
Colorado Western Slope Project.
HEP successfully completed two 5,500 foot Dakota Formation wells in the Piceance
Basin in Colorado and Utah. HEP owns an average 29% working interest in the
wells. Both wells began sales of production in the third quarter of 1998, and
they had a combined initial production rate of 1,500 mcf per day. In 1998, HEP
also successfully recompleted one well in the Basin. Total costs for the three
wells through September 30, 1998 are approximately $365,000.
West Sioux Pass Prospect.
In the West Sioux area of Richland County, Montana, HEP drilled one unsuccessful
12,405 foot operated Red River Formation exploration well in the first quarter
of 1998. HEP's costs in 1998 are approximately $255,000. HEP continues to
evaluate the project using the additional data obtained from the exploratory
well.
East Kevin Field Project.
In Toole County, Montana, HEP drilled two successful horizontal wells to the
Nisku Formation. The wells have combined initial production rates of 1,300 mcfe
per day. HEP has a 50% working interest in the projects and has spent
approximately $400,000 in 1998. HEP's third quarter 1998 drilling costs for a
third well, which is currently being completed, are approximately $250,000.
Greater Permian Region
During the first nine months of 1998, HEP expended approximately $3,440,000 of
its capital budget in the Greater Permian Region located in Texas and Southeast
New Mexico. HEP spent approximately $2,315,000 for drilling, recompletion, or
workover of 22 development wells and for drilling 17 exploration wells.
Thirty-one (79%) of the wells drilled or recompleted were successful. The major
projects within the Region are discussed below.
Arcadia Acquisition.
In October 1998, HEP purchased for $8,100,000 oil and gas properties, including
interests in approximately 570 wells, numerous proven and unproven drilling
locations, exploration acreage, and 3-D seismic data. Approximately 85% in value
of the proved properties are operated by HPI. HEP expects that the acquisition
will add proven reserves of approximately 425,000 barrels of oil and 6.1 billion
cubic feet of natural gas. HEP's estimated proven reserve addition of 8.7 bcfe
represents 47% of HEP's estimated 1998 production. HEP estimates that 1999
production will be approximately .9 bcfe.
Catclaw Draw/Carlsbad Area Projects.
HEP spent approximately $726,000 successfully recompleting seven operated wells
and drilling one successful development well in the Carlsbad/Catclaw Draw areas
in Lea, Eddy and Chaves Counties, New Mexico. Merkle Project. In 1997, HEP
acquired 74 square miles of proprietary 3-D seismic data in Jones, Taylor and
Nolan Counties, Texas, in a project area originated in 1995. Target zones in
this area include the Canyon Reef, Strawn, Flippan, Tannehill, and Ellenberger
Formations ranging in depth from 2,500 feet to 6,000 feet. In 1998, HEP drilled
11 exploration wells, nine of which were successful. Costs incurred by HEP in
1998 for the 11 wells drilled were approximately $870,000. HEP owns an average
28.5% working interest in the wells. Two wells are currently underway. Future
drilling has been deferred because of current low crude oil prices.
Griffin Project.
In 1998, HEP purchased land for $100,000 and incurred costs of approximately
$420,000 to drill three exploration wells and one development well in Gaines
County, Texas. None of the four nonoperated 7,500 foot Leonardian Sand wells
were successful. HEP is evaluating the possibility of future exploration
prospects within this project. Limited delineation drilling on previous
discoveries exists in the area. HEP owns an average 22% working interest in the
prospect area.
Gulf Coast Region
During the first nine months of 1998, HEP expended approximately $4,330,000 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.
In 1998, HEP incurred approximately $430,000 for land costs
related to the Mirasoles project in Kenedy County, Texas. HEP also incurred
approximately $600,000 in 1998 for drilling a 17,000 foot Frio Formation
exploration well, which is currently underway. 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.
HEP owns a 7.5% working interest in a non-operated 15,400 foot directional
exploration well testing the Wilcox formation in LaVaca County, Texas. The
drilling efforts were successful, and HEP expects sales of production to begin
in November 1998. Costs incurred in 1998 by HEP are approximately $350,000.
Bell Project.
HEP has a 30% working interest in an operated project to evaluate the Buda,
Carrizo, Woodbine, and Dexter sands in Houston County, Texas. HEP's drilling
costs in 1998 for a 9,200 foot horizontal well were approximately $540,000. The
well encountered Buda pay and flow test rates between 3,552 and 8,239 mcf per
day. Sale of production is expected to begin in December 1998, following
installation of gas processing equipment. In 1998, HEP also incurred $235,000
for land and leaseholds costs relating to the project.
Mercy Field Project.
HEP participated in a successful 10,450 foot nonoperated development well in the
Wilcox formation located in San Jacinto County, Texas. Costs incurred in 1998
are approximately $192,000. No additional Mercy fieldwork is anticipated in the
remainder of 1998.
Whitewater Field.
HEP's share of 1998 costs associated with plugging two nonoperated near shore
platform wells were approximately $600,000. This field is now abandoned, and no
additional work is anticipated.
Mid-Continent Region
HEP expended approximately $350,000 of its capital budget in the Mid-Continent
Region located in Oklahoma and Kansas. Major projects within the Region are
discussed below.
Stealth Project.
HEP is participating in an Arkoma Basin exploration prospect in
Carter County, Oklahoma. This nonoperated project is a 19,000 feet deep
multi-formation structural test of the Hunton, Viola, Sycamore, and Springer
Formations and is currently in the completion phase. The operator was unable to
test the targeted Hunton and Viola Formation objectives because of mechanical
problems and found that the Sycamore Formation produced at subcommercial gas
rates. The operator is evaluating a Springer Formation completion. HEP's 1998
year to date drilling and completion costs were approximately $165,000 for HEP's
5% working interest.
El Reno Project.
HEP incurred costs of approximately $157,000 in 1998 to complete one successful
exploration well in Canadian County, Oklahoma. The well was completed in the Red
Fork Formation and is currently producing 750 mcfe per day. HEP has a 35%
working interest.
Other
The remaining $568,000 of HEP's 1998 capital expenditures were devoted
principally to drilling four unsuccessful exploration wells in Yolo County,
California and for other miscellaneous projects. HEP also participated in two
nonoperated 3-D seismic projects in nearby Solano and Colusa Counties,
California.
Peru Block Z-3 Project. HEP's partner on the Peruvian offshore Z-3 Block
completed 1,200 miles of seismic data acquisition to supplement existing seismic
data. Data processing is currently underway. HEP has a 7.5% working interest in
this project, but will not incur capital costs until actual drilling operations
begin. The production-sharing contract calls for drilling operations to begin no
later than January 2001.
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 $16,517,000. 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 November 13, 1998 to Unitholders of record on September 30, 1998.
Distributions on the Class B Units are suspended if the Class A Units receive a
distribution of less than $.20 per Class A Unit per calendar quarter. In any
quarter for which distributions of $.20 or more per unit are made on the Class A
Units, the Class B Units are entitled to be paid, in whole or in part, suspended
distributions.
The Class C Units have a distribution preference of $1.00 per year, payable
quarterly, which began in the first quarter of 1996. HEP may not declare or make
any cash distributions on the Class A or Class B Units unless all accrued and
unpaid distributions on the Class C Units have been paid.
The Board of Directors of HEP's General Partner is considering the distribution
level for future quarters, taking into account oil and gas prices and the
capital needs for HEP.
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. Under
the Credit Agreement, HEP has a borrowing base of $62,000,000. HEP had amounts
outstanding at September 30, 1998 of $41,200,000. Subsequent to September 30,
1998, HEP borrowed an additional $8,500,000 for the Arcadia acquisition
described above and for capital projects, increasing its amounts outstanding to
$49,700,000. HEP's unused borrowing base totaled $12,300,000 at November 13,
1998.
Borrowings against the Credit Agreement bear interest at the lower of the
Certificate of Deposit rate plus from 1.375% to 1.875%, prime plus 1/2% or the
Euro-Dollar rate plus from 1.25% to 1.75%. The applicable interest rate was 7.0%
at September 30, 1998. Interest is payable monthly, and quarterly principal
payments of $3,106,500, as adjusted for the $8,500,000 of borrowings made
subsequent to September 30, 1998, commence May 31, 1999.
The borrowing base for the Credit Agreement is redetermined semiannually. The
Credit Agreement is secured by a first lien on approximately 80% in value of
HEP's oil and gas properties. Additionally, aggregate distributions 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.
HEP entered into contracts to hedge its interest rate payments on $15,000,000 of
its debt for 1998 and $10,000,000 for each of 1999 and 2000. HEP does not use
the hedges for trading purposes, but rather for the purpose of providing a
measure of predictability for a portion of HEP's interest payments under its
Credit Agreement, which has a floating interest rate. In general, it is HEP's
goal to hedge 50% of the principal amount of its debt for the next two years and
25% for each year of the remaining term of the debt. HEP has entered into four
hedges, one of which is an interest rate collar pursuant to which it pays a
floor rate of 7.55% and a ceiling rate of 9.85%, and the others are interest
rate swaps with fixed rates ranging from 5.75% to 6.57%. The amounts received or
paid upon settlement of these transactions are recognized as interest expense at
the time the interest payments are due.
Year 2000 Update
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 phase has been substantially
completed and has identified the Partnership IT systems that must be updated or
replaced in order to be Year 2000 compliant. In particular, the software used by
the Partnership for reservoir engineering must be updated or replaced. The
inventory phase of the Plan is currently underway and is expected to be
completed by December 31, 1998. 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.
To date, the Partnership has determined that its IT systems are either compliant
or can be made compliant without material cost. 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; the
process of inquiring of third parties and reviewing their responses is underway
but is not complete.
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. However, although
management believes that its estimates are reasonable, there can be no
assurance, for the reasons stated in the next paragraph, that the actual cost of
implementing the Plan will not differ materially from the estimated costs.
Potential Risks. The failure to correct a material Year 2000 problem could
result in an interruption in, or a failure of, certain normal business
activities or operations. This risk exists both as to the Partnership's IT and
Non IT systems, as well as to the systems of third parties. Such failures could
materially and adversely affect the Partnership's results of operations, cash
flow and financial condition. Due to the general uncertainty inherent in the
Year 2000 problem, resulting in part from the uncertainty of the Year 2000
readiness of third party suppliers, vendors and transporters, the Partnership is
unable to determine at this time whether the consequences of Year 2000 failures
will have a material impact on the Partnership's results of operations, cash
flow or financial condition. Although the Partnership is not currently able to
determine the consequences of Year 2000 failures, its current assessment is that
its area of greatest potential risk 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. 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
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. 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. In addition, 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, 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 throughout 1997 and through
the third quarter of 1998. 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 - 1997 $22.10 $21.08 $2.89 $2.52
Second quarter - 1997 17.71 17.71 2.02 1.98
Third quarter - 1997 18.40 18.47 2.25 2.13
Fourth quarter - 1997 18.72 18.69 2.92 2.56
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
</TABLE>
<PAGE>
HEP has entered into numerous financial contracts to hedge the price of its oil
and natural gas. The purpose of the hedges is to provide protection against
price decreases and to provide a measure of stability in the volatile
environment of oil and natural gas spot pricing. The amounts received or paid
upon settlement of hedge contracts are recognized as oil or gas revenue at the
time the hedged volumes are sold. During 1998, HEP has not entered into
additional oil price hedges for future years because hedge contracts at prices
HEP considers advantageous are not available.
The following table provides a summary of HEP's outstanding financial contracts:
Oil
Percent of Production Contract
Period Hedged Floor Price
(per bbl)
Last three months of 1998 22% $16.62
1999 2% 15.38
Between 9% and 100% of the oil volumes hedged in each year are subject to a
participating hedge whereby HEP will receive the contract price if the posted
futures price is lower than the contract price, and will receive the contract
price plus 25% of the difference between the contract price and the posted
futures price if the posted futures price is greater than the contract price.
Between 59% and 100% of the volumes hedged in each year are subject to a collar
agreement whereby HEP will receive the contract price if the spot price is lower
than the contract price, the cap price if the spot price is higher than the cap
price, and the spot price if that price is between the contract price and the
cap price. The cap prices range from $17.00 to $18.85.
<PAGE>
Gas
Percent of Production Contract
Period Hedged Floor Price
(per mcf)
Last three months of 1998 58% $2.07
1999 47% 2.05
2000 45% 2.10
2001 40% 2.08
2002 33% 2.14
Between 7% and 10% 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 $2.59 to $2.93.
During the fourth quarter through October 30, 1998 the weighted average oil
price (for barrels not hedged) was approximately $12.80 per barrel. The weighted
average price of natural gas (for mcf not hedged) during that period was
approximately $1.90 per mcf.
Inflation
Inflation is not anticipated to have a material impact on the Partnership in
1998.
Results of Operations
The following tables are presented to contrast HEP's revenue, expense and
earnings for discussion purposes. Significant fluctuations are discussed in the
accompanying narrative. The "direct owned" column represents HEP's direct
royalty and working interests in oil and gas properties. The "Mays" column
represents the results of operations of six May Limited Partnerships which are
consolidated with HEP. In 1998, HEP owned interests which ranged from 54.8% to
69.1% and in 1997, 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 September 30, 1998 For the Quarter Ended September 30, 1997
---------------------------------------- ----------------------------------------
Direct Direct
Owned Mays Total Owned Mays Total
<S> <C> <C> <C> <C> <C> <C>
Gas production (mcf) 3,524 278 3,802 2,734 380 3,114
Oil production (bbl) 188 13 201 171 22 193
Average gas price (per mcf) $ 1.94 $ 2.16 $ 1.95 $ 2.08 $ 2.54 $ 2.13
Average oil price (per bbl) $ 13.13 $ 12.08 $ 13.06 $ 18.42 $ 18.86 $ 18.47
Gas revenue $ 6,820 $ 601 $ 7,421 $ 5,675 $ 964 $ 6,639
Oil revenue 2,469 157 2,626 3,149 415 3,564
Pipeline, facilities and other revenue 1,067 1,067 523 523
Interest income 226 15 241 53 16 69
-------- -------- ------- -------- -------- --------
Total revenue 10,582 773 11,355 9,400 1,395 10,795
------ ------- ------ ------- ------ ------
Production operating expense 2,982 101 3,083 2,933 139 3,072
General and administrative expense 1,019 85 1,104 902 94 996
Depreciation, depletion, and amortization 4,279 338 4,617 2,876 289 3,165
Impairment of oil and gas properties 6,600 6,600
Interest expense 734 734 716 716
Equity in (income) loss of HCRC 767 767 (138) (138)
Minority interest in net income of affiliates 203 203 449 449
Litigation 375 375 9 24 33
--------- ----------- --------- ---------- -------- ----------
Total expense 16,756 727 17,483 7,298 995 8,293
------ ------- ------ ------- ------ -------
Net income (loss) $ (6,174) $ 46 $ (6,128) $ 2,102 $ 400 $ 2,502
======= ========= ======= ======= ====== =======
</TABLE>
<TABLE>
<CAPTION>
TABLE OF HEP EARNINGS FOR MANAGEMENT DISCUSSION
(In thousands except price)
For the Nine Months Ended September 30, 1998 For the Nine Months Ended September 30, 1997
-------------------------------------------- --------------------------------------------
Direct Direct
Owned Mays Total Owned Mays Total
<S> <C> <C> <C> <C> <C> <C>
Gas production (mcf) 9,568 895 10,463 7,563 1,025 8,588
Oil production (bbl) 553 41 594 521 60 581
Average gas price (per mcf) $ 1.99 $ 2.39 $ 2.02 $ 2.15 $ 2.75 $ 2.22
Average oil price (per bbl) $ 14.11 $ 13.54 $ 14.07 $ 19.06 $ 20.47 $ 19.20
Gas revenue $19,016 $2,143 $21,159 $16,255 $ 2,818 $19,073
Oil revenue 7,801 555 8,356 9,929 1,228 11,157
Pipeline, facilities and other revenue 2,743 2,743 2,072 2,072
Interest income 517 50 567 272 56 328
-------- -------- -------- -------- --------- --------
Total revenue 30,077 2,748 32,825 28,528 4,102 32,630
------ ------ ------ ------ ------ ------
Production operating expense 9,049 340 9,389 8,345 422 8,767
General and administrative expense 3,078 275 3,353 2,958 292 3,250
Depreciation, depletion, and amortization 10,321 913 11,234 7,754 903 8,657
Impairment of oil and gas properties 9,200 9,200
Interest expense 1,927 1,927 2,315 2,315
Equity in (income) loss of HCRC 3,090 3,090 (1,384) (1,384)
Minority interest in net income of affiliates 787 787 1,341 1,341
Litigation 930 930 (234) (6) (240)
------- ---------- -------- -------- --------- --------
Total expense 37,595 2,315 39,910 19,754 2,952 22,706
------ ------ ------ ------ ------- ------
Net income (loss) $ (7,518) $ 433 $ (7,085) $ 8,774 $ 1,150 $ 9,924
======= ======= ======= ======= ======= =======
</TABLE>
<PAGE>
Third Quarter of 1998 Compared to Third Quarter of 1997
Gas Revenue
Gas revenue increased $782,000 during the third quarter of 1998 compared with
the third quarter of 1997. The increase is the result of an increase in
production from 3,114,000 mcf in 1997 to 3,802,000 mcf in 1998 partially offset
by a decrease in the average gas price from $2.13 per mcf in 1997 to $1.95 per
mcf in 1998. 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 third quarter of 1998, was to increase HEP's
average gas price from $1.85 per mcf to $1.95 per mcf, representing a $380,000
increase in revenue from hedging transactions.
Oil Revenue
Oil revenue decreased $938,000 during the third quarter of 1998 compared with
the third quarter of 1997. The decrease is the result of a decrease in the
average oil price from $18.47 per barrel in 1997 to $13.06 in 1998, partially
offset by an increase in production from 193,000 barrels in 1997 to 201,000
barrels in 1998. Oil production increased primarily because two temporarily
shut-in wells were back on line. The two wells were temporarily shut-in during
the third quarter of 1997 while workover procedures were performed.
The effect of HEP's hedging transactions during the third quarter of 1998, was
to increase HEP's average oil price from $12.19 per barrel to $13.06 per barrel,
resulting in a $175,000 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 $544,000 during the third quarter of 1998 compared with the
third quarter of 1997 primarily due to increased incentive payment income from
the acquisition of the volumetric production payment during May 1998.
Interest Income
Interest income increased $172,000 during the third quarter of 1998 compared
with the third quarter of 1997 due to a higher average cash balance during 1998.
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 $108,000 during the third quarter of 1998 primarily due
to increased salaries expense.
Depreciation, Depletion and Amortization Expense
Depreciation, depletion and amortization expense increased $1,452,000 during the
third quarter of 1998 compared with the third quarter of 1997. The increase is
primarily the result of higher capitalized costs and a higher depletion rate in
1998 due to the increase in production previously discussed.
Impairment of Oil and Gas Properties
Impairment of oil and gas properties during the third quarter of 1998 represents
the impairment recorded because capitalized costs at September 30, 1998 exceeded
the present value (discounted at 10%) of estimated future net revenues from
proved oil and gas reserves, based on prices of $12.80 per bbl of oil and $1.90
per mcf of gas.
<PAGE>
Equity in Earnings (Loss) of HCRC
Equity in earnings (loss) of HCRC decreased $905,000 during the third quarter of
1998 compared with the third quarter of 1997. The decrease 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 1998.
Minority Interest in Net Income of Affiliates
Minority interest in net income of affiliates represents unaffiliated partners'
interest in the net income of the May Partnerships. The decrease of $246,000 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 expense during the third quarter of 1998 is comprised of the costs
related to the Arcadia arbitration described in Note 8 of the accompanying
financial statements. Litigation expense during the third quarter of 1997 is
related to several property related claims, none of which is individually
significant.
First Nine Months of 1998 Compared to the First Nine Months of 1997
The comparisons for the first nine months of 1998 and the first nine months of
1997 are consistent with those discussed in the third quarter of 1998 compared
to the third quarter 1997 except for the following:
Gas Revenue
Gas revenue increased $2,086,000 during the first nine months of 1998 compared
with the first nine months of 1997. The increase is the result of an increase in
production from 8,588,000 mcf in 1997 to 10,463,000 mcf in 1998 partially offset
by a decrease in price from $2.22 per mcf in 1997 to $2.02 per mcf in 1998. 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 during the first nine months of 1998
was to increase HEP's average gas price from $2.00 per mcf to $2.02 per mcf
representing a $209,000 increase in revenue from hedging transactions.
Oil Revenue
Oil revenue decreased $2,801,000 during the first nine months of 1998 compared
with the first nine months of 1997. The decrease is due to a decrease in the
average oil price from $19.20 per barrel in 1997 to $14.07 per barrel in 1998
partially offset by an increase in production from 581,000 barrels in 1997 to
594,000 barrels in 1998. Oil production increased primarily because two
temporarily shut-in wells were back on line. The two wells were temporarily
shut-in during the third quarter of 1997 while workover procedures were
performed.
The effect of HEP's hedging transactions during the first nine months of 1998
was to increase HEP's average oil price from $13.35 per barrel to $14.07 per
barrel, representing an increase in revenue from hedging transactions of
$428,000.
Production Operating Expense
Production operating expense increased $622,000 during the first nine months of
1998 compared with the first nine months of 1997. The increase is primarily due
to increased production taxes and operating expenses due to the increase in
production previously discussed.
Impairment of Oil and Gas Properties
Impairment of oil and gas properties during the first nine months of 1998
includes an impairment at June 30, 1998 based on prices of $13.00 per bbl of oil
and $2.00 per mcf of gas, as well as the third quarter property impairment
previously discussed. Interest Expense
Interest expense decreased $388,000 during the first nine months of 1998
compared to the first nine months of 1997, primarily as a result of lower
average outstanding debt during 1998.
Equity in Earnings (Loss) of HCRC
Equity in earnings (loss) of HCRC decreased $4,474,000 during the first nine
months of 1998 compared to the first nine months of 1997. The decrease is
primarily due to a property impairment recorded by HCRC during the first nine
months of 1998.
Litigation
Litigation expense during the first nine months of 1998 includes the settlement
of the Ellender lawsuit described in Note 9 of the accompanying financial
statements in addition to the costs of the Arcadia arbitration described above.
Litigation income during the first nine months of 1997 is comprised of insurance
proceeds which reimbursed a portion of expense incurred in a prior period to
settle certain litigation.
<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, 1997 and Notes 8 and 9 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: November 13, 1998 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 quarter ended September 30, 1998 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> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> SEP-30-1998
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