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 0-19931
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 84-1176750
(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 [ ]
Shares of Common Stock outstanding at November 13, 1998 3,007,852
Page 1 of 24
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<CAPTION>
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands)
September 30, December 31,
1998 1997
CURRENT ASSETS
<S> <C> <C>
Cash and cash equivalents $ 674 $ 4,492
Accrued oil and gas revenue 2,995 4,266
Due from affiliates 4,098 2,418
Prepaid and other assets 1,452 844
Current assets of affiliates 4,361 3,854
--------- ---------
Total current assets 13,580 15,874
-------- --------
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved oil and gas properties 322,554 294,922
Unproved mineral interests - domestic 2,895 2,250
--------- ---------
Total 325,449 297,172
Less - accumulated depreciation,
depletion, amortization and impairment (243,784) (221,141)
------- -------
Net property, plant and equipment 81,665 76,031
-------- --------
OTHER ASSETS
Deferred tax asset 100 450
Noncurrent assets of affiliate 26 16
----------- -----------
Total other assets 126 466
---------- ----------
TOTAL ASSETS $ 95,371 $ 92,371
======== ========
<FN>
(Continued on the following page)
</FN>
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<PAGE>
<TABLE>
<CAPTION>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands except Shares)
September 30, December 31,
1998 1997
CURRENT LIABILITIES
<S> <C> <C>
Accounts payable and accrued liabilities $ 2,772 $ 3,087
Current portion of long-term debt 3,188
Current portion of contract settlement obligation 1,039
Current liabilities of affiliates 8,244 6,881
--------- ---------
Total current liabilities 14,204 11,007
-------- --------
NONCURRENT LIABILITIES
Long-term debt 37,845 25,000
Long-term obligations of affiliates 7,464 7,589
Deferred liability 67 89
----------- -----------
Total noncurrent liabilities 45,376 32,678
-------- --------
Total liabilities 59,580 43,685
-------- --------
COMMITMENTS AND CONTINGENCIES (NOTE 10)
STOCKHOLDERS' EQUITY
Common stock par value $.01; 10,000,000 shares
authorized; 3,007,852 shares issued in 1998 and
2,986,812 shares issued in 1997 30 30
Additional paid-in-capital 81,283 80,111
Accumulated deficit (41,658) (27,581)
Treasury stock - 258,395 shares in 1998 and 259,278 shares in 1997 (3,864) (3,874)
--------- ---------
Stockholders' equity - Net 35,791 48,686
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 95,371 $ 92,371
======== ========
<FN>
The accompanying notes are an integral part of the financial statements.
</FN>
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<PAGE>
<TABLE>
<CAPTION>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands except per Share data)
For the Three Months Ended
September 30,
1998 1997
REVENUES:
<S> <C> <C>
Gas revenue $ 5,638 $ 3,973
Oil revenue 2,240 3,277
Pipeline and other 891 238
Interest income 19 17
--------- ---------
8,788 7,505
------ ------
EXPENSES:
Production operating 2,950 2,576
General and administrative 964 799
Interest 1,154 506
Depreciation, depletion and amortization 3,299 2,271
Impairment of oil and gas properties 3,600
Litigation 445
--------
12,412 6,152
------ ------
INCOME (LOSS) BEFORE INCOME TAXES (3,624) 1,353
------- ------
PROVISION (BENEFIT) FOR INCOME TAXES:
Current (111) 528
Deferred 350 (100)
-------- -------
239 428
-------- -------
NET INCOME (LOSS) $ (3,863) $ 925
======= =======
NET INCOME (LOSS) PER SHARE - BASIC $ (1.41) $ .34
======== ========
NET INCOME (LOSS) PER SHARE - DILUTED $ (1.41) $ .33
======== ========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
2,749 2,718
====== ======
<FN>
The accompanying notes are an integral part of the financial statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands except per Share data)
For the Nine Months Ended
September 30,
1998 1997
REVENUES:
<S> <C> <C>
Gas revenue $ 14,518 $ 12,107
Oil revenue 7,354 10,142
Pipeline and other 1,767 1,281
Interest income 164 134
---------- ----------
23,803 23,664
-------- --------
EXPENSES:
Production operating 8,467 7,523
General and administrative 2,866 2,584
Interest 2,888 1,668
Depreciation, depletion and amortization 8,043 6,272
Impairment of oil and gas properties 14,600
Litigation 550
----------
37,414 18,047
-------- --------
INCOME (LOSS) BEFORE INCOME TAXES (13,611) 5,617
-------- ---------
PROVISION FOR INCOME TAXES:
Current 116 675
Deferred 350 (100)
---------- ---------
466 575
---------- ---------
NET INCOME (LOSS) $ (14,077) $ 5,042
======== =========
NET INCOME (LOSS) PER SHARE - BASIC $ (5.13) $ 1.86
=========== ==========
NET INCOME (LOSS) PER SHARE - DILUTED $ (5.13) $ 1.78
=========== ==========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
2,746 2,718
========== =========
<FN>
The accompanying notes are an integral part of the financial statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
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) $(14,077) $ 5,042
Adjustments to reconcile net income (loss)
to net cash provided by operating activities:
Depreciation, depletion and amortization 8,043 6,272
Impairment of oil and gas properties 14,600
Amortization of deferred loan costs and
debt discount 152
Noncash interest expense 6 67
Undistributed earnings of affiliates (3,397) (2,929)
Deferred income tax (benefit) expense 350 (100)
Recoupment of take-or-pay liability (22) (21)
Changes in assets and liabilities provided (used) cash net of noncash
activity:
Accrued oil and gas sales 1,271 1,088
Due from affiliates (1,352) (497)
Prepaid and other assets (695) 456
Accounts payable and accrued liabilities (315) 165
-------- --------
Net cash provided by operating activities 4,564 9,543
------- -------
INVESTING ACTIVITIES:
Additions to oil and gas properties (19,298) (2,128)
Exploration and development costs incurred (6,810) (6,538)
Proceeds from oil and gas property sales 97 26
Distributions received from affiliates 1,524 858
Other (17)
------------ ----------
Net cash used in investing activities ( 24,487) (7,799)
------- -------
FINANCING ACTIVITIES:
Proceeds from long-term debt 17,000 1,000
Payments on long-term debt (3,000)
Payments on contract settlement obligation (1,045)
Exercise of stock options 150
---------
Net cash provided by (used in)
financing activities 16,105 (2,000)
------- -------
NET DECREASE IN CASH AND CASH
EQUIVALENTS (3,818) (256)
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD 4,492 628
------- --------
END OF PERIOD $ 674 $ 372
======== ========
<FN>
The accompanying notes are an integral part of the financial statements.
</FN>
</TABLE>
<PAGE>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
(Unaudited)
NOTE 1 - ORGANIZATION AND BASIS OF PRESENTATION
Hallwood Consolidated Resources Corporation ("HCRC" or the "Company") is a
Delaware corporation engaged in the development, production, sale and
transportation of oil and gas, and in the acquisition, exploration, development
and operation of oil and gas properties. The Company's properties are primarily
located in the Rocky Mountain, Mid-Continent, Greater Permian and Gulf Coast
regions of the United States. The principal objective of the Company is to
maximize shareholder value by increasing its reserves, production and cash flow
through a balanced program of development and high potential exploration
drilling, as well as selective acquisitions.
The interim financial data in the accompanying financial statements are
unaudited; however, in the opinion of management, 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 the Company's December 31, 1997 Annual Report on
Form 10-K.
NOTE 2 - ACCOUNTING POLICIES
Consolidation
The Company accounts for its interest in affiliated oil and gas partnerships and
limited liability companies using the proportionate consolidation method of
accounting. The accompanying financial statements include the activities of the
Company and its pro rata share of the activities of Hallwood Energy Partners,
L.P. ("HEP").
Treasury Stock
At September 30, 1998 and December 31, 1997, the Company owned approximately 19%
of the outstanding units of HEP which owns approximately 46% of the Company's
common stock; consequently, the Company had an interest in 258,395 and 259,278
of its own shares at September 30, 1998 and December 31, 1997, respectively.
These shares are treated as treasury stock in the accompanying financial
statements.
Computation of Net Income (Loss) Per Share
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. HCRC 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 share is computed by dividing net income (loss) by the
weighted average number of common shares outstanding during the periods. Diluted
income per share includes the potential dilution that could occur upon exercise
of outstanding options to acquire common stock, and the effects of the warrants
described in Note 3, computed using the treasury stock method which assumes that
the increase in the number of shares is reduced by the number of shares which
could have been repurchased by the Company with the proceeds from the exercise
of the options (which were assumed to have been made at the average market price
of the common shares during the reporting period). All share and per share
information has been restated to reflect the three-for-one stock split described
in Note 5.
The following table reconciles the number of shares outstanding used in the
calculation of basic and diluted income (loss) per share. The warrants,
described in Note 3, have been ignored in the computation of diluted net income
(loss) per share in all periods and the stock options have been ignored in the
computation of diluted loss per share for the three months and for the nine
months ended September 30, 1998 because their inclusion would be anti-dilutive.
<TABLE>
<CAPTION>
Income
(Loss) Shares Per Share
(In thousands except per Share)
For the Three Months Ended September 30, 1998
<S> <C> <C> <C>
Net loss per share - basic $ (3,863) 2,749 $(1.41)
------- ----- =====
Net Loss per share - diluted $ (3,863) 2,749 $(1.41)
======= ===== =====
For the Nine Months Ended September 30, 1998
Net loss per share - basic $(14,077) 2,746 $(5.13)
------ ----- =====
Net Loss per share - diluted $(14,077) 2,746 $(5.13)
====== ===== =====
For the Three Months Ended September 30, 1997
Net income per share - basic $ 925 2,718 $ .34
======
Effect of Options 128
----------- ------
Net Income per share - diluted $ 925 2,846 $ .33
======= ===== ======
For the Nine Months Ended September 30, 1997
Net income per share - basic $ 5,042 2,718 $ 1.86
=====
Effect of Options 121
----------- ------
Net Income per share - diluted $ 5,042 2,839 $ 1.78
======= ===== =====
</TABLE>
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 established standards for reporting and display of comprehensive
income and its components (revenues, expenses, gains, and losses) in a full set
of general-purpose financial statements. SFAS 130 requires that all items that
are required to be recognized under accounting standards as components of
comprehensive income be reported in a financial statement that is displayed with
the same prominence as other financial statements. Reclassification of financial
statements for earlier periods provided for comparative purposes is required.
The Company adopted SFAS 130 on January 1, 1998. The Company 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 Company is required to
adopt SFAS 133 on January 1, 2000. The Company 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 3 - DEBT
On December 23, 1997, HCRC sold $25,000,000 of 10.32% Senior Subordinated Notes
("Subordinated Notes") due December 23, 2007 to a financial institution. HCRC
also sold Warrants to the lender to purchase 98,599 shares of Common Stock at an
exercise price of $28.99 per share. The Subordinated Notes bear interest at the
rate of 10.32% per annum on the unpaid balance, payable quarterly. Annual
principal payments of $5,000,000 are due on each of December 23, 2003 through
December 23, 2007.
The proceeds from the Subordinated Notes were allocated to the Subordinated
Notes and to the Warrants based upon the relative fair values of the
Subordinated Notes without the Warrants and of the Warrants themselves at the
time of issuance. The allocated value of the Warrants of $1,032,000 was recorded
as paid-in-capital. The discount on the Subordinated Notes will be amortized
over the term of the Subordinated Notes using the interest method of
amortization.
During 1997, the Company and its banks amended the Company's Credit Agreement to
extend the term date to May 31, 1999. Under the Credit Agreement, HCRC has a
borrowing base of $26,500,000. The Company had amounts outstanding of
$17,000,000 as of September 30, 1998. Subsequent to September 30, 1998, HCRC
borrowed an additional $8,500,000 for the Arcadia acquisition described in Note
9 and for capital projects, increasing its amounts outstanding to $25,500,000.
HCRC's unused borrowing base was $1,000,000 at November 13, 1998.
Borrowings against the credit line bear interest, at the option of the Company,
at either (i) the banks' Certificate of Deposit rate plus from 1.375% to1.875%,
(ii) the Euro-Dollar rate plus from 1.25% to 1.75% or (iii) the higher of the
prime rate of Morgan Guaranty Trust or the sum of one-half of 1% plus the
Federal funds rate, plus .75%. The applicable interest rate was 7.0% at
September 30, 1998. Interest is payable at least quarterly, and quarterly
principal payments of $1,594,000, as adjusted for the $8,500,000 of borrowings
made subsequent to September 30, 1998, commence May 31, 1999. The credit
facility is secured by a first lien on approximately 80% in value of the
Company's oil and gas properties.
HCRC entered into contracts to hedge its interest rate payments on $10,000,000
of its debt for 1998 and $5,000,000 for each of 1999 and 2000. HCRC does not use
the hedges for trading purposes, but rather for the purpose of providing a
measure of predictability for a portion of HCRC's interest payments under its
Credit Agreement, which has a floating interest rate. In general, it is HCRC's
goal to hedge 50% of the principal amount of its debt under the Credit Agreement
for the next two years and 25% for each year of the remaining term of the debt.
HCRC 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.
<PAGE>
NOTE 4 - STATEMENTS OF CASH FLOWS
Cash paid for interest during the nine months ended September 30, 1998 and 1997
was $2,349,000 and $1,080,000, respectively. Cash paid for income taxes during
the nine months ended September 30, 1998 and 1997 was $155,000 and $725,000,
respectively.
NOTE 5 - STOCK SPLIT
During July 1997, the stockholders of HCRC approved an increase in the number of
authorized shares of its Common Stock from 2,000,000 shares to 10,000,000
shares. HCRC also declared a three-for-one split of its outstanding Common
Stock. The stock split was effected by issuing, as a stock dividend, two
additional shares of Common Stock for each share outstanding. The stock dividend
was paid on August 11, 1997 to shareholders of record on August 4, 1997. All
share and per share information has been restated to reflect the three-for-one
stock split.
NOTE 6 - ACQUISITION
In July 1996, HCRC and its affiliate, HEP, 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 HCRC and HEP purchased the volumetric production payment from
an affiliate of Enron Corp. HCRC funded its $17,257,000 share of the acquisition
price from operating cash flow and borrowings under its Credit Agreement.
NOTE 7 - IMPAIRMENT OF OIL AND GAS PROPERTIES
During the second and third quarters of 1998, HCRC 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 $1.90 per mcf of gas and $12.75 per barrel of oil and $1.80 per mcf
of gas, respectively.
NOTE 8 - STOCK OPTION GRANT
On May 5, 1998, HCRC granted options to purchase 9,540 shares of Common Stock at
an exercise price of $15.75 per share which was equal to the fair market value
of the Common Stock 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 HCRC's 1995 Stock Option Plan. One-third of the options
vest immediately, 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.
On May 5, 1998, HCRC also granted options to purchase 9,540 shares of Common
Stock under its 1997 Stock Option Plan at an exercise price of $15.75 which was
equal to the fair market value of the Common Stock on the date of grant.
One-third of the options vest immediately, 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.
<PAGE>
NOTE 9 - ARBITRATION
In connection with the Demand for Arbitration filed by Arcadia Exploration and
Production Company ("Arcadia") with the American Arbitration Association against
Hallwood Consolidated Resources Corporation, Hallwood Energy Partners, L.P.,
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.
At the end of October 1998, HCRC and its affiliate, HEP, 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. HCRC'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 $12.75 per barrel of oil and
$1.90 per mcf of gas, was included in the determination of the impairment of
HCRC's oil and gas properties in the third quarter of 1998.
NOTE 10 - LEGAL PROCEEDINGS
On April 23, 1992, a lawsuit was filed in the Chancery Court for New Castle
County, Delaware, styled Tappe v. Hallwood Consolidated Resources Corporation,
Hallwood Consolidated Partners, L. P., Hallwood Oil and Gas, Inc., Hallwood
Energy Partners, L. P., and Hallwood Petroleum, Inc. (C. A. No 12536). The
lawsuit seeks to rescind the conversion of Hallwood Consolidated Partners, L.P.
("HCP") into the Company ("Conversion") and to recover damages in unspecified
amounts. The plaintiff also seeks class certification to represent similarly
situated HCP unitholders. In general, the suit alleges that the defendants
breached fiduciary duties to HCP unitholders by, among other things, proposing
allocation of common stock in the Conversion on a basis that the plaintiff
alleges is unfair, failing to require that the allocation be approved by an
independent third party, causing the costs of proposing the Conversion to be
borne indirectly by the partners of HCP whether or not the Conversion was
completed, and failing to disclose certain matters in the Consent
Statement/Prospectus soliciting consents to the Conversion. The defendants
believe that they fully considered and disclosed all material information in
connection with the Conversion, and they believe that the suit is without merit.
HCRC plans to vigorously defend this case, but because of its early stages,
cannot predict the outcome of this matter or any possible effect an adverse
outcome might have.
The Company is involved in other legal proceedings and claims which have arisen
in the ordinary course of its business and have not been finally adjudicated.
The Company believes that its liability, if any, as a result of such proceedings
and claims will not materially affect its financial condition or operations.
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
During the first nine months of 1998, HCRC had a net loss of $14,077,000,
compared to a net income of $5,042,000 for the first nine months of 1997. The
1998 period includes noncash charges in the second and third quarters totaling
$14,600,000 for property impairments which were taken to lower the capitalized
cost of HCRC's properties.
HCRC'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.
<PAGE>
The weighted average prices received by HCRC for oil and gas have declined in
each of the last three quarters. HCRC's hedges have mitigated the price
reductions, however; HCRC's weighted average oil and gas prices, when the
effects of hedging are considered, were 28% and 9% lower, respectively, for the
first nine months of 1998 compared to the first nine months of 1997.
Although HCRC's production for the first nine months of 1998 was 21% greater
than the prior year, and operating and general and administrative expenses were
lower on a unit of production basis, net income was lower because of continued
low commodity prices and costs associated with the resolution of litigation.
Liquidity and Capital Resources
Cash Flow
The Company generated $4,564,000 of cash flow from operating activities during
the first nine months of 1998. The other primary cash inflows were $17,000,000
in proceeds from long-term debt and $1,524,000 in distributions received from
affiliates. Cash was primarily used for additions to property and exploration
and development costs of $26,108,000 and for payments on contract settlement
obligation of $1,045,000 for the nine months ended September 30, 1998, resulting
in a $3,818,000 decrease in cash from $4,492,000 at December 31, 1997 to
$674,000 at September 30, 1998.
Exploration and Development Projects and Acquisitions
Through September 30, 1998, HCRC incurred $26,108,00 in direct property
additions, development, exploitation, and exploration costs. The costs were
comprised of $19,298,000 for property acquisitions and approximately $6,810,000
for domestic exploration and development. The expenditures resulted in the
drilling, recompletion, or workover of 34 development wells and 26 exploration
wells. Thirty-one development wells (91%) and 12 exploration wells (50%) were
successfully completed as producers, for an overall success rate of 72%. HCRC's
1998 capital budget was initially set at $21,426,000 but was increased to
$36,675,000. 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 Company has
deferred until 1999 certain capital expenditures originally proposed for 1998.
Management believes that the Company will be able to satisfy its remaining
capital commitments for 1998. 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
HCRC expended approximately $19,725,000 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, HCRC spent
approximately $1,560,000 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.
San Juan Basin Project - Colorado. In July 1996, HCRC and its affiliate HEP
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 HCRC and HEP, purchased from the affiliate
of Enron Corp. the volumetric production payment. HCRC 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, HCRC 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, HCRC
was already responsible for all costs associated with the wells. Hallwood
Petroleum, Inc. ("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 has increased HCRC's current average daily production by 6,750 mcf
per day.
Cajon Lake Field. HCRC is currently completing the sidetracking and redrilling
of a 6,000 foot Ismay formation exploration well in San Juan County, Utah. HCRC
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 HCRC estimates that the sale of production will begin in November
1998.
Colorado Western Slope Project. HCRC successfully completed two 5,500 foot
Dakota Formation wells in the Piceance Basin in Colorado and Utah. Currently,
HCRC owns an average 46% working interest in the wells. Both wells began sales
of production in the third quarter of 1998 with combined initial production
rates of 1,500 mcf per day. In 1998, HCRC also successfully recompleted one well
in the Basin. Total costs for the three wells through September 30, 1998 are
approximately $576,000.
West Sioux Pass Prospect. In the West Sioux area of Richland County, Montana,
HCRC drilled one unsuccessful 12,405 foot operated Red River Formation
exploration well in the first quarter of 1998. HCRC's costs in 1998 are
approximately $255,000. HCRC continues to evaluate the project using the
additional data obtained from the exploratory well.
East Kevin Field Project. In Toole County, Montana, HCRC drilled two successful
horizontal wells to the Nisku Formation. The wells have combined initial
production rates of 1,300 mcfe per day. HCRC has a 50% working interest in the
projects and has spent approximately $400,000 in 1998. HCRC'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, HCRC expended approximately $2,521,000 of
its capital budget in the Greater Permian Region located in Texas and Southeast
New Mexico. HCRC spent approximately $2,026,000 for drilling, recompletion, or
workover of 21 development wells and for drilling 17 exploration wells. Thirty
(79%) of the wells drilled or recompleted were successful. The major projects
within the Region are discussed below.
Arcadia Acquisition. In October 1998, HCRC 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. HCRC
expects that the acquisition will add proven reserves of approximately 443,000
barrels of oil and 6.4 billion cubic feet of natural gas. HCRC's estimated
proven reserve addition of 9.1 bcfe represents 63% of HCRC's estimated 1998
production. HCRC estimates that 1999 production will be approximately .9 bcfe.
Catclaw Draw/Carlsbad Area Projects. HCRC spent approximately $431,000
successfully recompleting six 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, HCRC 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, HCRC drilled 11 exploration wells, nine of which were
successful. Costs incurred by HCRC in 1998 for the 11 wells drilled were
approximately $942,000. HCRC owns an average 30% 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, HCRC purchased land for $103,000 and incurred costs of
approximately $455,000 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. HCRC is evaluating the possibility of future exploration
prospects within this project. Limited delineation drilling on previous
discoveries exists in the area. HCRC owns an average 25% working interest in the
prospect area.
Gulf Coast Region
During the first nine months of 1998, HCRC expended approximately $2,941,000 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, HCRC incurred approximately $430,000 for land costs related to the
Mirasoles project in Kenedy County, Texas. HCRC also incurred approximately
$600,000 in 1998 for drilling a 17,000 foot Frio Formation exploration well,
which is currently underway. HCRC has a 17.5% working interest in this large
structural prospect defined by 63 square miles of proprietary 3-D seismic data.
Esperanza Project. HCRC 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 HCRC expects sales of
production to begin in November 1998. Costs incurred in 1998 by HCRC are
approximately $350,000 for drilling and approximately $40,000 for land.
Bell Project. HCRC has a 30% working interest in an operated project to evaluate
the Buda, Carrizo, Woodbine, and Dexter sands in Houston County, Texas. HCRC'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, HCRC also incurred
$235,000 for land and leaseholds costs relating to the project.
Mid-Continent Region
HCRC expended approximately $490,000 of its capital budget in the Mid-Continent
Region located in Oklahoma and Kansas. Major projects within the Region are
discussed below.
Stealth Project. HCRC 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. HCRC's 1998
year to date drilling and completion costs were approximately $165,000 for
HCRC's 5% working interest.
El Reno Project. HCRC 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. HCRC has a 35% working interest.
Other
The remaining $431,000 of HCRC's 1998 capital expenditures were devoted
principally to drilling four unsuccessful exploration wells in Yolo County,
California and for other miscellaneous projects. HCRC also participated in two
nonoperated 3-D seismic projects in nearby Solano and Colusa Counties,
California.
Peru Block Z-3 Project. HCRC'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. HCRC 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.
Financing
On December 23, 1997, HCRC sold $25,000,000 of 10.32% Senior Subordinated Notes
("Subordinated Notes") due December 23, 2007 to a financial institution. HCRC
also sold Warrants to the lender to purchase 98,599 shares of Common Stock at an
exercise price of $28.99 per share. The Subordinated Notes bear interest at the
rate of 10.32% per annum on the unpaid balance, payable quarterly. Annual
principal payments of $5,000,000 are due on each of December 23, 2003 through
December 23, 2007.
The proceeds from the Subordinated Notes were allocated to the Subordinated
Notes and to the Warrants based upon the relative fair values of the
Subordinated Notes without the Warrants and of the Warrants themselves at the
time of issuance. The allocated value of the Warrants of $1,032,000 was recorded
as paid-in-capital. The discount on the Subordinated Notes will be amortized
over the term of the Subordinated Notes using the interest method of
amortization.
<PAGE>
During 1997, the Company and its banks amended the Company's Credit Agreement to
extend the term date to May 31, 1999. Under the Credit Agreement, HCRC has a
borrowing base of $26,500,000. The Company had amounts outstanding of
$17,000,000 as of September 30, 1998. Subsequent to September 30, 1998, HCRC
borrowed an additional $8,500,000 for the Arcadia acquisition described above
and for capital projects, increasing its amounts outstanding to $25,500,000.
HCRC's unused borrowing base was $1,000,000 at November 13, 1998.
Borrowings against the credit line bear interest, at the option of the Company,
at either (i) the banks' Certificate of Deposit rate plus from 1.375% to1.875%,
(ii) the Euro-Dollar rate plus from 1.25% to 1.75% or (iii) the higher of the
prime rate of Morgan Guaranty Trust or the sum of one-half of 1% plus the
Federal funds rate, plus .75%. The applicable interest rate was 7.0% at
September 30, 1998. Interest is payable at least quarterly, and quarterly
principal payments of $1,594,000, as adjusted for the $8,500,000 of borrowings
made subsequent to September 30, 1998, commence May 31, 1999. The credit
facility is secured by a first lien on approximately 80% in value of the
Company's oil and gas properties.
HCRC entered into contracts to hedge its interest rate payments on $10,000,000
of its debt for 1998 and $5,000,000 for each of 1999 and 2000. HCRC does not use
the hedges for trading purposes, but rather for the purpose of providing a
measure of predictability for a portion of HCRC's interest payments under its
Credit Agreement, which has a floating interest rate. In general, it is HCRC's
goal to hedge 50% of the principal amount of its debt under the Credit Agreement
for the next two years and 25% for each year of the remaining term of the debt.
HCRC 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 Company's: 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 Company'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 Company 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 Company's IT systems that must be updated or
replaced in order to be Year 2000 compliant. In particular, the software used by
the Company 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 Company 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 Company's assessment of the readiness
of third parties whose IT systems might have an impact on the Company'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 Company's Non IT systems, the Company believes that most of
these systems can be brought into compliance on schedule. The Company'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 Company 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
Company'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 Company's IT and Non
IT systems, as well as to the systems of third parties. Such failures could
materially and adversely affect the Company'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 Company is unable to
determine at this time whether the consequences of Year 2000 failures will have
a material impact on the Company's results of operations, cash flow or financial
condition. Although the Company 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 Company. The Company is contacting the various
purchasers and pipelines with which it regularly does business to determine
their state of readiness for the Year 2000. The Company's Year 2000 Plan is
expected to significantly reduce the Company'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 Company's development of
contingency plans.
Cautionary Statement Regarding Forward-Looking Statements
In the interest of providing the shareholders with certain information regarding
the Company'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 within the meanings of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange
Act of 1934, as amended. Although any forward-looking statements contained in
this Form 10-Q or otherwise expressed by or on behalf of the Company 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 Company'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 Company's oil and gas operations, the inexact nature of
interpretation of seismic and other geological and geophysical data, imprecision
of reserve estimates, the Company's ability to replace and expand oil and gas
reserves, and such other risks and uncertainties described from time to time in
the Company'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 Company'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
Company 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, shareholders and potential investors are cautioned that
certain events or circumstances could cause actual results to differ materially
from those projected, estimated or predicted.
<PAGE>
Inflation and Changing Prices
Prices
Prices obtained for oil and gas production depend upon numerous factors that are
beyond the control of the Company, 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 the Company and the effects of the hedging
transactions described 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> <C>
First quarter 1997 $23.56 $20.49 $2.64 $2.41
Second quarter 1997 17.85 17.88 1.91 1.87
Third quarter 1997 18.20 18.31 2.09 1.96
Fourth quarter 1997 18.60 18.60 2.72 2.38
First quarter 1998 14.92 15.08 1.98 1.93
Second quarter 1998 13.06 13.38 1.90 1.89
Third quarter 1998 12.05 12.44 1.76 1.88
</TABLE>
The Company 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 paid or received
upon settlement of hedge contracts are recognized as oil or gas revenue at the
time the hedged volumes are sold. During 1998, HCRC has not entered into
additional oil price hedges for future years because hedge contracts at prices
HCRC considers advantageous are not available.
The following table provides a summary of the Company's outstanding financial
contracts:
<TABLE>
<CAPTION>
Oil
Percent of Direct Contract
Period Production Hedged Floor Price
(per bbl)
<S> <C> <C>
Last three months of 1998 14% $14.57
1999 4% 15.38
</TABLE>
Between 30% and 100% of the oil volumes hedged in each year are subject to a
participating hedge whereby HCRC will receive the contract price if the posted
futures price is lower than the contract price, and will receive the contract
price plus 25% of the difference between the contract price and the posted
futures price if the posted futures price is greater than the contract price.
All of the volumes hedged in each year are subject to a collar agreement whereby
HCRC 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 $18.35 per barrel.
<PAGE>
<TABLE>
<CAPTION>
Gas
Percent of Direct Contract
Period Production Hedged Floor Price
(per mcf)
<S> <C> <C>
Last three months of 1998 49% $2.03
1999 41% 1.98
2000 37% 2.02
2001 36% 2.00
2002 35% 2.06
</TABLE>
Between 0% and 8% of the gas volumes hedged in each year are subject to a collar
agreement whereby HCRC will receive the contract price if the spot price is
lower than the contract price, the cap price if the spot price is higher than
the cap price, and the spot price if that price is between the contract price
and the cap price. The cap price is $2.93 per mcf.
During the fourth quarter through October 30, 1998, the weighted average oil
price (for barrels not hedged) was approximately $12.80 per barrel and the
weighted average price of natural gas (for mcf not hedged) was approximately
$1.80 per mcf.
Inflation
Inflation is not anticipated to have a material impact on the Company in 1998.
Results of Operations
The following tables are presented to contrast HCRC's revenue, expense and
earnings for discussion purposes. Significant fluctuations are discussed in the
accompanying narrative.
The "direct owned" column represents HCRC's direct royalty and working interests
in oil and gas properties. The "HEP" column represents HCRC's share of the
results of operations of HEP; HCRC owned approximately 19% of the outstanding
limited partner units of HEP during 1997 and 1998.
<PAGE>
<TABLE>
<CAPTION>
TABLE OF HCRC EARNINGS FOR MANAGEMENT DISCUSSION
(In thousands except price)
<PAGE>
For the Quarter Ended September 30, 1998 For the Quarter Ended September 30, 1997
---------------------------------------- ----------------------------------------
Direct Direct
Owned HEP Total Owned HEP Total
<S> <C> <C> <C> <C> <C> <C>
Gas production (mcf) 2,351 649 3,000 1,500 523 2,023
Oil production (bbl) 144 36 180 145 34 179
Average gas price (per mcf) $ 1.85 $ 1.99 $ 1.88 $1.92 $2.08 $1.96
Average oil price (per bbl) $12.27 $13.14 $12.44 $18.33 $18.21 $18.31
Gas revenue $ 4,345 $ 1,293 $ 5,638 $ 2,886 $ 1,087 $ 3,973
Oil revenue 1,767 473 2,240 2,658 619 3,277
Pipeline and other 693 198 891 149 89 238
Interest income 16 3 19 5 12 17
--------- ---------- --------- ---------- --------- ---------
Total revenue 6,821 1,967 8,788 5,698 1,807 7,505
------- ------- ------- ------- ------- -------
Production operating expense 2,410 540 2,950 2,034 542 2,576
General and administrative expense 763 201 964 619 180 799
Interest expense 1,016 138 1,154 372 134 506
Depreciation, depletion and amortization 2,591 708 3,299 1,586 685 2,271
Impairment of oil and gas properties 3,600 3,600
Litigation 375 70 445
--------- --------- -------- ----------- -----------
Total expense 10,755 1,657 12,412 4,611 1,541 6,152
------- ------- ------- ------- ------- -------
Income (loss) before income taxes (3,934) 310 (3,624) 1,087 266 1,353
-------- ------- -------- ------- -------- -------
Provision (benefit) for income taxes:
Current (111) (111) 528 528
Deferred 350 350 (100) (100)
------- ------- -------- --------
239 239 428 428
------- ------- -------- --------
Net income (loss) $ (4,173) $ 310 $ (3,863) $ 659 $ 266 $ 925
======== ====== ======== ======= ======== =======
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
TABLE OF HCRC EARNINGS FOR MANAGEMENT DISCUSSION
(In thousands except price)
<PAGE>
For the Nine Months Ended September 30, 1998 For the Nine Months Ended September 30, 1997
-------------------------------------------- --------------------------------------------
Direct Direct
Owned HEP Total Owned HEP Total
<S> <C> <C> <C> <C> <C> <C>
Gas production (mcf) 5,859 1,799 7,658 4,336 1,465 5,801
Oil production (bbl) 433 106 539 433 102 535
Average gas price (per mcf) $ 1.86 $ 2.00 $ 1.90 $ 2.06 $ 2.17 $ 2.09
Average oil price (per bbl) $13.53 $14.11 $13.64 $18.92 $19.10 $18.96
Gas revenue $10,923 $ 3,595 $14,518 $ 8,930 $ 3,177 $ 12,107
Oil revenue 5,858 1,496 7,354 8,194 1,948 10,142
Pipeline and other 1,253 514 1,767 858 423 1,281
Interest income 72 92 164 76 58 134
--------- ------- ------ -------- -------- --------
Total revenue 18,106 5,697 23,803 18,058 5,606 23,664
------ ----- ------ ------- ------- -------
Production operating expense 6,788 1,679 8,467 5,952 1,571 7,523
General and administrative expense 2,257 609 2,866 1,994 590 2,584
Interest expense 2,525 363 2,888 1,232 436 1,668
Depreciation, depletion and amortization 6,244 1,799 8,043 4,826 1,446 6,272
Impairment of oil and gas properties 14,600 14,600
Litigation 375 175 550
--------- ------- ------- ----------- -----------
Total expense 32,789 4,625 37,414 14,004 4,043 18,047
------ ------ ------ ------- ------- -------
Income (loss) before income taxes (14,683) 1,072 (13,611) 4,054 1,563 5,617
------- ------ ------- ------- ------- -------
Provision for income taxes:
Current 116 116 675 675
Deferred 350 350 (100) (100)
------- ------- -------- --------
466 466 575 575
------- ------- -------- --------
Net income (loss) $(15,149) $ 1,072 $(14,077) $ 3,479 $ 1,563 $ 5,042
======= ====== ======= ======= ======= =======
</TABLE>
<PAGE>
Third Quarter of 1998 Compared to the Third Quarter of 1997
Gas Revenue
Gas revenue increased $1,665,000 during the third quarter of 1998 compared with
the third quarter of 1997. The increase is comprised of an increase in gas
production from 2,023,000 mcf in 1997 to 3,000,000 mcf in 1998 partially offset
by a decrease in price from $1.96 per mcf in 1997 to $1.88 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 the Company's hedging transactions, as described under "Inflation
and Changing Prices," during the third quarter of 1998 was to increase the
Company's average gas price from $1.76 to $1.88 per mcf, resulting in a $360,000
increase in revenue.
Oil Revenue
Oil revenue decreased $1,037,000 during the third quarter of 1998 as compared
with the third quarter of 1997. The decrease in revenue is comprised of a
decrease in the average oil price from $18.31 per barrel in 1997 to $12.44 per
barrel in 1998, partially offset by an increase in production from 179,000
barrels in 1997 to 180,000 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 HCRC's hedging transactions during the third quarter of 1998, was
to increase the Company's average oil price from $12.05 per barrel to $12.44 per
barrel, resulting in a $70,000 increase in revenue.
Pipeline and Other
Pipeline and other revenue consists of revenue derived from salt water disposal,
incentive and tax credit payments from certain coal bed methane wells and other
miscellaneous items. Pipeline and other revenue increased $653,000 during the
third quarter of 1998 compared with the third quarter of 1997 due to increased
incentive payment income resulting from HCRC's acquisition of a volumetric
production payment during May 1998.
Production Operating Expense
Production operating expense increased $374,000 during the third quarter of 1998
compared with the third quarter of 1997, primarily as a result of increased
production taxes due to the increase in oil and gas production as discussed
above.
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 HPI, an affiliate of HCRC, which manages
and operates certain oil and gas properties on behalf of the Company. These
costs increased $165,000 during the third quarter of 1998 as compared with the
third quarter of 1997 primarily due to an increase in salaries expense.
Interest Expense
Interest expense increased $648,000 during the third quarter of 1998 compared
with the third quarter of 1997 due to a higher average outstanding debt balance
during 1998.
Depreciation, Depletion and Amortization Expense
Depreciation, depletion and amortization expense increased $1,028,000 primarily
due to a higher depletion rate in 1998 resulting from the increase in oil and
gas production previously discussed, as well as higher capitalized costs.
<PAGE>
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 $12.75 per barrel of oil and
$1.80 per mcf of gas.
Litigation
Litigation expense during the third quarter of 1998 is comprised of the costs
related to the Arcadia arbitration described in Note 9 of the accompanying
financial statements.
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 $2,411,000 during the first nine months of 1998 compared
with the first nine months of 1997. The increase is comprised of an increase in
production from 5,801,000 mcf in 1997 to 7,658,000 mcf in 1998, partially offset
by a decrease in the average price from $2.09 per mcf to $1.90 per mcf. The
production increase is primarily due to the acquisition of a volumetric
production payment during May 1998.
The effect of HCRC's hedging transactions was to increase HCRC's average gas
price from $1.87 per mcf to $1.90 per mcf, representing a $230,000 increase in
revenue from hedging transactions.
Oil Revenue
Oil revenue decreased $2,788,000 during the first nine months of 1998 compared
with the first nine months of 1997. The decrease is comprised of a decrease in
the average oil price from $18.96 per barrel in 1997 to $13.64 per barrel in
1998, partially offset by an increase in production from 535,000 barrels in 1997
to 539,000 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 HCRC's hedging transactions was to increase HCRC's average oil
price from $13.35 per barrel to $13.64 per barrel, representing a $156,000
increase in revenues.
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 $1.90 per mcf of gas, as well as the third quarter property impairment
previously discussed.
Litigation
Litigation settlement of affiliate during the first nine months of 1998 is
comprised of HCRC's pro rata share of HEP's litigation settlement expense
incurred for the settlement of a property related lawsuit, in addition to the
costs of the Arcadia arbitration described above.
<PAGE>
PART II - OTHER INFORMATION
ITEM 1 - LEGAL PROCEEDINGS
Reference is made to Item 8 - Note 14 of Form 10-K for the year
ended December 31, 1997 and Note 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 Company
has duly caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
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 Consolidated Resources
Corporation and is qualified in its entirety by reference to such Form 10-Q.
</LEGEND>
<CIK> 0000883953
<NAME> Hallwood Consolidated Resources Corporation
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> SEP-30-1998
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0
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