UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
Form 10-QSB
[X] QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the quarterly period ended March 31, 2001
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File Number 0-14731
HALLADOR PETROLEUM COMPANY
(Exact name of registrant as specified in its charter)
COLORADO 84-1014610
(State of incorporation) (IRS Employer Identification No.)
1660 Lincoln Street, Suite 2700, Denver, Colorado 80264
(Address of principal executive offices)
303-839-5504 FAX: 303-832-3013
(Issuer's telephone numbers)
Check whether the issuer (1) filed all reports required to be filed by Section
13 or 15(d) of the Securities Exchange Act during the past 12 months, and (2)
has been subject to such filing requirements for the past 90 days.
Yes [x] No [ ]
Shares outstanding as of May 14, 2001: 7,093,150
PART I. FINANCIAL INFORMATION
Consolidated Balance Sheet
(in thousands)
March 31, December 31,
2001 2000*
--------- -----------
ASSETS
Current assets:
Cash and cash equivalents $ 2,661 $ 2,489
Accounts receivable-
Oil and gas sales 619 716
Well operations 282 583
------ ------
Total current assets 3,562 3,788
------ ------
Oil and gas properties, at cost (successful efforts):
Unproved properties 336 313
Prepaid drilling cost - East Texas well 477
Proved properties 22,424 21,597
Less - accumulated depreciation,
depletion, amortization and impairment (15,334) (15,123)
------ ------
7,426 7,264
------ ------
Oil and gas operator bonds 312 312
Investment in Catalytic Solutions 175 175
Other assets 48 51
------ ------
$11,523 $11,590
====== ======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 595 $ 626
Oil and gas sales payable 368 440
Bank debt 231
------ ------
Total current liabilities 1,194 1,066
------ ------
Bank debt 231
------
Key employee bonus plan 301 295
------ ------
Minority interest 5,450 5,441
------ ------
Stockholders' equity:
Preferred stock, $.10 par value; 10,000,000
shares authorized; none issued
Common stock, $.01 par value; 100,000,000
shares authorized; 7,093,150 shares issued 71 71
Additional paid-in capital 18,061 18,061
Accumulated deficit (13,554) (13,575)
------ ------
4,578 4,557
------ ------
$11,523 $11,590
====== ======
- ------------------------------
*Derived from the Form 10-KSB.
See accompanying notes.
Consolidated Statement of Operations
(in thousands, except per share amounts)
Three months ended March 31,
2001 2000
--------- --------
Revenue:
Oil $1,287 $1,629
Gas 485 226
NGLs 128 93
Interest and other 43 24
----- -----
1,943 1,972
----- -----
Costs and expenses:
Lease operating 1,120 897
Exploration costs
Geological and geophysical 2
Dry hole expense 30
Delay rentals 18 30
Depreciation, depletion and amortization 214 233
General and administrative 247 242
Purchase of employee stock options 300
Interest 14 28
----- -----
1,913 1,462
----- -----
Income before minority interest 30 510
Minority interest (9) (153)
----- -----
Net income $ 21 $ 357
===== =====
Basic and diluted income per share $ * $ 0.05
===== =====
Weighted average shares outstanding-basic 7,093 7,093
===== =====
Weighted average shares outstanding-diluted 7,438 7,093
===== =====
- -----------------------------------------
*Not meaningful, less than $.01 per share.
See accompanying notes.
Consolidated Statement of Cash Flows
(in thousands)
Three months ended March 31,
2001 2000
--------- --------
Net cash provided by operating activities $ 545 $ 774
----- -----
Cash flows from investing activities:
Properties (373) (715)
Other assets (10)
----- -----
Net cash used in investing activities (373) (725)
----- -----
Net increase in cash and cash equivalents 172 49
Cash and cash equivalents, beginning of period 2,489 1,957
----- -----
Cash and cash equivalents, end of period $2,661 $2,006
===== =====
See accompanying notes.
Notes to Financial Statements
1. The interim financial data is unaudited; however, in our opinion, it
includes all adjustments, consisting only of normal recurring adjustments
necessary for a fair statement of the results for the interim periods.
The financial statements included herein have been prepared pursuant to
the SEC's rules and regulations. Certain information and footnote
disclosures normally included in GAAP financial statements have been
condensed or omitted pursuant to the SEC's rules and regulations.
2. Our organization and business, the accounting policies we follow and other
information are contained in the notes to our financial statements filed
as part of our 2000 Form 10-KSB. This quarterly report should be read in
conjunction with such annual report.
MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION
RESULTS OF OPERATIONS
YEAR-TO-DATE COMPARISON
- -----------------------
The table below (in thousands) provides sales data and average prices
for the period.
2001 2000
------------------------ ----------------------
Sales Average Sales Average
Volume Price Revenue Volume Price Revenue
------- ------- ------ ------ ----- -------
Oil - barrels
South Cuyama field 53 $24.13 $1,279 61 $26.60 $1,623
Other * * 8 * * 6
Gas - mcf
South Cuyama field 14 7.00 98 10 2.70 27
Northern California 18 11.67 210 45 2.40 108
South Texas 8 6.88 55 29 2.14 62
New Mexico 16 7.31 117 13 2.08 27
Other * * 5 * * 2
NGLs - barrels
South Cuyama field 3.7 27.30 101 3.6 20.56 74
New Mexico 1.2 21.67 26 1.2 15.00 18
Other * * 1 * * 1
- ----------------
* Not meaningful
Current oil and gas prices for the South Cuyama Field are about $25.00 per
barrel for oil and $16.00 per MCF for gas. Current gas prices in Northern
California are $12.45 per MCF, South Texas prices are $4.71 and New Mexico
prices are $4.95.
The table below (in thousands) shows lease operating expenses (LOE) by field.
2001 2000
---- ----
South Cuyama field $1,066 $873
Northern California 4 2
South Texas 9 3
New Mexico 29 15
Other 12 4
Oil revenue is down compared to last year due to lower prices and volumes.
Even though gas volumes declined, gas revenue doubled compared to last year due
to higher prices. NGL revenue increased due to higher prices as indicated in
the tables above.
LOE increased due to higher costs in the South Cuyama field.
On January 19, 2001, we purchased from certain employees 177,777 options at a
cost of $1.6875 per option (about $300,000), which was recorded as compensation
expense.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
Cash and cash flow from operations are expected to enable us to meet our
obligations as they become due during the next several years.
THE FOLLOWING DISCUSSION UPDATES THE MD&A CONTAINED IN ITEM 6 OF THE 2000 FORM
10-KSB AND THE TWO DISCUSSIONS SHOULD BE READ TOGETHER.
PROSPECT DEVELOPMENT AND EXPLORATION ACTIVITY
- ---------------------------------------------
South Cuyama Field
------------------
During October 2000, we completed a 3-D project on adjoining acreage east of
the SC Field. The cost of this project was $350,000 to the 100%. We have a
70% WI in this project. The data was evaluated during January 2001 and several
drillable prospects were identified.
The first exploratory gas well (the Cox 41-5) was drilled during March 2001.
Currently, the well is producing 2,000 MCF per day from a depth of about 3,400
feet. We are the operator and own a 70% WI (60% NRI). The cost to drill and
complete this well was about $260,000 to the 100%. This well is an important
step in validating our 3-D seismic project. We are reviewing our 3-D seismic
data to identify other locations to drill.
Because of the California electricity crisis natural gas prices are at an all-
time high. Due to the success of the Cox 41-5, in April, we sent our gas
purchaser, Aera Energy, L.L.C. (AERA), a contract termination notice. We were
able to cancel the contract prematurely effective April 1, 2001 by paying AERA
$50,000. Our new gas contract is with Enserco Energy Inc. This contract pays
market prices, is month to month and can be cancelled by either party with 30
days notice. Currently we are selling the gas for about $16 per MCF. We have
no way of estimating how long these high prices will continue.
We estimate the gas reserves for this well to the 100% to be about 1,800,000
MCF (1.8 BCF). The zone we are currently producing from has estimated gas
reserves of 330,000 MCF. The zone above it has estimated reserves of 1,330,000
MCF and the upper most zone has estimated reserves of 165,000 MCF. Because
of these unprecedented natural gas prices in California we plan to drill during
the second quarter an offset to the Cox 41-5 in order to produce from this
middle zone. The estimated cost to drill and complete this well is $250,000.
We will have a 70% WI (60% NRI) in this well.
Two development oil wells were drilled during March 2001, one is producing
about 20 barrels per day and the other was abandoned during the drilling phase.
We had planned to drill two development oil wells during April 2001, but only
one was drilled and the other may be drilled later. The well that was drilled
is in the completion stage.
In January 2001, our monthly electricity costs increased by about $12,000 due
to the California electrical crisis. We have been told by PG&E that our summer
electricity costs will increase significantly due to the crisis. Last year our
average monthly electricity cost in the field was $73,000; we estimate that our
summer average monthly electricity could be double that amount. With all of
the current uncertainty and turmoil that exists in the California electrical
marketplace, we can provide no assurance as to the timing and nature of the
resolution of the electrical crisis. If electrical costs continue to increase,
we will have to shut in certain oil wells. As this crisis continues, future
cash flow will decrease and so will reserve estimates.
We are performing a study to develop the proper strategy to optimize the cash
flow from the SC Field considering these higher electricity costs.
The Merlin Prospect of the Sac Basin - Northern California
-----------------------------------------------------------
This field is located about 70 miles north of Sacramento, California. Equity
Oil Company (Equity) of Salt Lake City, Utah is the operator. Presently we
have two producing gas wells. These wells have an estimated remaining life
of four years. We are participating with Equity in an exploratory gas well
to be drilled in late May 2001. We will have a 37% WI (30%NRI) in this well
and the estimated costs to drill and complete to the 100% are $550,000.
South Texas
-----------
This gas field is located about 75 miles west of Houston in Colorado County.
Marquee Corporation of Corpus Christi, Texas is the operator of these gas
wells. We have a 14% WI (11% NRI) in this field. Presently, we have two
producing gas wells. These wells have an estimated remaining life of three
years.
During March 2001, we recompleted an existing well and it is producing 400
MCF per day. Because it is too early to judge the success of this
recompletion, we have not booked any new reserves for this well.
We participated in an exploratory gas well during April 2001. The well is
currently in the testing phase. The cost to drill and complete this well to
the 100% was about $200,000. We have a 14% WI (11% NRI) in this well.
San Juan Basin
--------------
This gas field is located in the NW corner of New Mexico in San Juan County.
Three development gas wells were drilled in early spring 2000. We have an
interest in twenty wells and are the operator. These wells have an estimated
remaining life of twenty years. Our WI in this field ranges from 5%-10% with
NRI between 4%-8%.
Nine additional development wells have been identified and we plan to drill two
or three of them in the third and fourth quarter of 2001. The cost to the 100%
to drill and complete these wells are about $400,000 each.
East Texas
----------
This is a new prospect for us located about 150 miles southeast of Dallas in
Nacogdoches County. We participated in an exploratory gas well (the Fulton -
Fuller 1H), which was completed in April 2001. Sales of 1,000 MCF per day are
estimated to begin in June 2001 at a selling price of about $4.00 per MCF. The
cost to drill and complete this well to the 100% was about $2,000,000. We have
a 25% WI (20% NRI) in this well. Hallwood Energy of Denver is the operator.
A second exploratory gas well is planned to be drilled in the summer of 2001 in
Shelby County, Texas, about 20 miles east from the Fulton - Fuller 1H. El Paso
Energy will be the operator. We have a 7% WI (6% NRI). The cost to drill and
complete this well to the 100% is about $2,000,000, our share would be about
$150,000.
Environmental and Regulation
- ----------------------------
We are directly affected by changing environmental rules and regulations.
Although we believe our operations and facilities are in compliance with
applicable environmental regulations, risk of substantial cost and liabilities
resulting from an unintentional breach of environmental regulations are
inherent to oil and gas operations. It is possible that other developments,
such as increasingly strict environmental laws, regulations, and enforcement
policies or claims for damages could result in significant costs and liability
in the future.
In January 1999, the California legislature passed a bill, which increased our
operator's bond from $100,000 to $250,000 over a five-year period. In
addition, an idle well bill was passed to ensure that funds would be available
to properly plug and abandon (P&A) California wells upon their depletion. Over
the next ten years, we as the SC Field's operator, are required to place in an
interest-bearing escrow account $500 per year for each idle well in the SC
Field until such well is plugged and abandoned or until $5,000 has been
deposited. Installments of $60,000 and $68,000 were paid in June 1999 and
2000, respectively. We estimate that after ten annual installments we will
have met the current funding obligation of $700,000 considering the interest
to be earned. As the SC Field depletes, and more wells move from the
producing category to the idle-well category we will have to make additional
annual payments. Presently, there are 280 wells in the SC Field, 140 of which
are classified as "idle".
During 1999, we began amortizing, using the units-of-production method, our
share of the estimated future costs ($1,207,000) to P&A the SC Field's 280
wells. Included in the DD&A expense for the first quarter 2000 and 2001 was
$28,000 and $30,000, respectively, associated with these estimated future costs.
Washington County, Colorado Gas Plant
- -------------------------------------
In late February 2001, we were notified by the Colorado Oil and Gas
Conservation Commission that we must conduct a site investigation of a gas
plant that our predecessor operated forty years ago. It is our understanding
that the plant has not been in operation for at least thirty years and that
the plant was dismantled in 1961.
During May 2001, our consulting environmental engineer made a site visit and
performed a water test. The results were satisfactory; accordingly, we
estimate the cleanup cost for this site will not have a material effect on our
cash flows, results of operations or financial condition.
PART II. Other Information
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits - None.
(b) No reports on Form 8-K were filed during the quarter.
SIGNATURE
In accordance with the requirements of the Exchange Act, the registrant caused
this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
HALLADOR PETROLEUM COMPANY
Date: May 14, 2001 By: /s/VICTOR P. STABIO
Victor P. Stabio
Chief Executive Officer and
Chief Financial Officer
Signing on behalf of registrant
and as principal financial officer.