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 September 30, 2003
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) (I.R.S. Employer Identification No.)
1660 Lincoln Street, Suite 2700, Denver, Colorado 80264-2701
(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 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 November 14, 2003: 7,093,150
PART I - FINANCIAL INFORMATION
Consolidated Balance Sheet
(in thousands)
September 30, December 31,
2003 2002*
--------- -----------
ASSETS
Current assets:
Cash and cash equivalents $ 4,220 $ 1,647
Accounts receivable-
Oil and gas sales 569 680
Well operations 306 146
------ ------
Total current assets 5,095 2,473
------ ------
Oil and gas properties, at cost (successful efforts):
Unproved properties 364 247
Proved properties 26,047 25,058
Less - accumulated depreciation,
depletion, amortization and impairment (19,556) (18,836)
------ ------
6,855 6,469
------ ------
Oil and gas operator bonds 507 417
Investment in Catalytic Solutions 164 164
Other assets 34 38
------ ------
$12,655 $ 9,561
====== ======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 2,508 $ 527
Oil and gas sales payable 266 185
------ ------
Total current liabilities 2,774 712
------ ------
Bank debt 251
------
Key employee bonus plan 236 209
------ ------
Future site restoration-South Cuyama Field 974 653
------ ------
Minority interest 5,043 4,763
------ ------
Commitments and contingencies
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 (14,504) (15,159)
------ ------
3,628 2,973
------ ------
$12,655 $ 9,561
====== ======
*Derived from the Form 10-KSB.
See accompanying notes.
Consolidated Statement of Operations
(in thousands)
Nine months ended Three months ended
September 30, September 30,
2003 2002 2003 2002
------ ------ ------ ------
Revenue:
Oil $5,686 $4,813 $1,858 $1,933
Gas 1,296 858 461 298
Crude oil class action settlement 153 153
Interest and other 117 35 8 10
----- ----- ----- -----
7,252 5,706 2,480 2,241
----- ----- ----- -----
Costs and expenses:
Lease operating 3,963 3,474 1,232 1,208
Exploration costs -
Geological and geophysical 64 1,031 1,031
Dry hole 223 223
Plug and abandonment 42 42
Delay rentals 106 55 44 9
Unproved properties 19
Impairments -
Fulton Fuller gas well 79
S.E. Bonus Field 840
Unproved properties 18 18
Depreciation, depletion and amortization 868 1,918 306 572
General and administrative 850 640 265 190
----- ----- ----- -----
6,135 8,055 2,112 3,028
----- ----- ----- -----
Income (loss) before cumulative effect of
change in accounting principle 1,117 (2,349) 368 (787)
Cumulative effect of change in
accounting principle (181)
----- ----- ----- -----
Income (loss) before minority interest 936 (2,349) 368 (787)
Minority interest (281) 705 (110) 236
----- ----- ----- -----
Net income (loss) $ 655 $(1,644) $ 258 $ (551)
===== ===== ===== =====
Income (loss) per share-basic and diluted:
Before cumulative effect of change in
accounting principle $ .11 $ (.23) $ .04 $ (.08)
Cumulative effect of change in
accounting principle (.02)
----- ----- ----- -----
Net income (loss) $ .09 $ (.23) $ .04 $ (.08)
===== ===== ===== =====
Weighted average shares outstanding-
basic 7,093 7,093 7,093 7,093
===== ===== ===== =====
See accompanying notes.
Consolidated Statement of Cash Flows
(in thousands)
Nine months ended September 30,
2003 2002
------ ------
Net cash provided by operating activities $2,893 $1,206
------ -----
Cash flows from investing activities:
Properties (945) (993)
Operator bonds (91) (53)
------ -----
Net cash used in investing activities (1,036) (1,046)
------ -----
Cash flows from financing activites:
Debt retirement (251)
Cash calls from joint interest owners 967
------
Net cash from financing activities 716
------
Net increase in cash and cash equivalents 2,573 160
Cash and cash equivalents, beginning of period 1,647 2,078
------ -----
Cash and cash equivalents, end of period $ 4,220 $2,238
====== =====
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; accordingly, certain information and
footnote disclosures normally included in GAAP financial statements have
been condensed or omitted.
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 2002 Form 10-KSB. This quarterly report should be read in
conjunction with that annual report.
3. In July 2001, the Financial Accounting Standards Board issued SFAS No. 143,
"Accounting for Asset Retirement Obligations." SFAS No. 143 requires
entities to record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred and a corresponding
increase in the carrying amount of the related long-lived asset and is
effective for fiscal years beginning after June 15, 2002. We adopted
SFAS No. 143 on January 1, 2003 and increased our liability for asset
retirement obligations by $264,000 (using an 8% discount rate) and
recorded a cumulative effect of change in accounting principle of $181,000.
For the nine months ended September 30, 2003, we recognized $56,000 of
accretion on the liability as a component of depletion expense.
Had SFAS No. 143 been adopted on January 1, 2002, the pro forma net loss
would have been $1,725,000 and the pro forma net loss per share would have
been $(.24) for the nine months ended September 30, 2002 and the pro forma
asset retirement obligation at January 1, 2002 would have been $850,000.
4. As allowed in SFAS No. 123, "Accounting for Stock-Based Compensation," we
continue to apply Accounting Principles Board Opinion (APB) No. 25,
"Accounting for Stock Issued to Employees," and related interpretations in
recording compensation related to our plan. The pro forma effect on our
net income (loss) was not material for any of the periods presented. No
grants were issued during the first nine months of 2003.
5. As discussed in previous filings, the SC Field was purchased from ARCO
(Atlantic Richfield which is now part of BP p.l.c.) in May 1990. As part
of the Purchase and Sale Agreement, ARCO agreed to indemnify us for certain
environmental liabilities connected with their 40-year ownership of the
field and gas plant ("ARCO Indemnity"). Part of the gas plant has not been
operational during the past twenty-five years. There is evidence of
asbestos in the non-operational part of the gas plant. It is our position,
and the opinion of our legal counsel, that the ARCO Indemnity covers future
abandonment and clean-up costs associated with this gas plant. We have had
several discussions with BP regarding this matter and have retained a San
Francisco law firm to assert our rights under the ARCO Indemnity. BP
continues to deny any responsibility.
The costs to abandon and clean up the gas plant area and other oil and gas
areas at the field will be significant. There is a chance, depending on
the negotiations and legal proceedings with BP, that some or all of the
costs could be borne by us. At this time we are unable to estimate what
these costs could ultimately be but we expect that such costs could have a
material adverse effect on our financial condition, results of operations
and cash flows.
HALLADOR PETROLEUM COMPANY
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.
2003 2002
------------------------ ----------------------
Sales Average Sales Average
Volume Price Revenue Volume Price Revenue
------- ------- ------ ------ ----- -------
Oil - barrels
South Cuyama field 194 $28.66 $5,560 210 $22.34 $4,692
Other 6 21.00 126 7 17.31 121
Gas - mcf
South Cuyama field 135 5.39 728 80 3.14 251
San Juan-New Mexico 43 4.51 194 38 2.00 76
Other 63 5.93 374 181 2.93 531
Oil revenue increased primarily due to higher prices as set forth in the table
above. Gas revenue increased due to higher prices and production, even though
there was a significant production decline in our South Texas - Bonus field.
As previously disclosed, we took an impairment charge of $840,000 in the second
quarter of 2002 for this field.
During 1999 we agreed to participate in a class action suit against
certain purchasers of crude oil in the state of California covering
1986 through 1998. The case was settled during the third quarter of 2003
and our share of the judgment, after contingent legal fees, was
approximately $153,000.
Current prices for the South Cuyama field are about $27.40 for oil and $4.74
for gas and San Juan gas is about $4.60.
The table below (in thousands) shows lease operating expenses (LOE) for
our two primary fields.
2003 2002
---- ----
South Cuyama field:
LOE excluding electricity $2,761 $2,054
Electricity 1,152 1,221
Electricity refund (115)
----- -----
3,798 3,275
San Juan-New Mexico 87 49
Other 78 150
----- -----
$3,963 $3,474
===== =====
LOE in the field increased due to higher operating expenses relating to the
new equipment we had to install in the first quarter of 2003 in order to
remove CO2 from our gas stream. Furthermore, when oil prices are high,
we perform more repair and maintenance in the field compared to when prices
are low (see the table above for 2003 and 2002 average oil prices.)
The $64,000 in G&G costs relate to a late billing for the 3-D work performed
in the fourth quarter of 2002. The $223,000 in dry hole expense relates to
the dry hole drilled in the SC Field in the third quarter of this year. In
addition we spent $42,000 to properly plug and abandon a well in southern
Colorado, which was drilled by our predecessor over 20 years ago. Delay
rentals increased due to exploration activity we are planning next year on
leases we acquired near the SC Field. These sites were identified by the
3-D project we performed last year.
The increase in G&A was due to higher 2002 audit and tax fees - $35,000,
accruals for 2003 audit and tax fees - $25,000, state taxes - $43,000, higher
employee costs - $50,000, higher legal fees associated with the ARCO Indemnity
and SOCAL negotiations - $24,000, donations - $13,000, and other minor
increases of $20,000.
DD&A decreased due to higher reserve estimates at September 30, 2003
compared to September 30, 2002. The increase in reserves was due to higher
oil prices.
QUARTER-TO-DATE COMPARISON
--------------------------
The table below (in thousands) provides sales data and average prices for
the period.
2003 2002
------------------------ ----------------------
Sales Average Sales Average
Volume Price Revenue Volume Price Revenue
------- ------- ------ ------ ----- -------
Oil - barrels
South Cuyama field 65 $27.90 $1,814 75 $25.29 $1,897
Other 2 22.00 44 1.6 22.50 36
Gas - mcf
South Cuyama field 56 5.16 289 30 3.53 106
San Juan-New Mexico 17 4.41 75 11 2.36 26
Other 18 5.38 97 54 3.07 166
The table below (in thousands) shows lease operating expenses (LOE) for
our primary fields.
2003 2002
---- ----
South Cuyama field:
LOE excluding electricity $ 860 $ 637
Electricity 458 504
Electricity refund (115)
----- -----
1,203 1,141
San Juan-New Mexico 8 18
Other 21 49
----- -----
Total $1,232 $1,208
===== =====
For the most part, the explanations above for the year-to-date comparisons
also apply to the quarter-to-date comparisons.
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.
Bank Debt
---------
The SC Field, our principal asset, is pledged to U. S. Bank National
Association under a $2,200,000 revolving line of credit which was renewed
on March 31, 2002. At March 31, 2003 we owed $244,000 under this line.
On April 28, 2003 the loan was paid off.
THE FOLLOWING DISCUSSION UPDATES THE MD&A CONTAINED IN ITEM 6 OF THE 2002
FORM 10-KSB AND THE TWO DISCUSSIONS SHOULD BE READ TOGETHER.
PROSPECT DEVELOPMENT AND EXPLORATION ACTIVITY
---------------------------------------------
South Cuyama Field
-------------------
Based on the results of our 2002 3-D project we have identified four
wildcat sites located outside the field boundaries. Also, we have
identified six developmental drilling opportunities within the boundaries
of the field. During July 2003 we drilled three gas wells; one was a
dry hole, one was successful and the other was marginal. It is too
early to assign reserves to these wells, but the results are encouraging.
The wildcat wells outside the field will not be drilled until sometime
next year and no further development drilling is planned for this year.
Of the 63 oil wells in the field, five account for 60% of the oil
production. Two gas wells account for 90% of the gas production. Due
to air quality regulations in Santa Barbara County we began a project to
electrify the field. This project began seven years ago, and all but one
oil and gas well is electrified. Although we have higher electricity
costs, the repairs and maintenance expenses are lower because electrical
engines are much cheaper to maintain than combustion engines.
SOCAL
-----
Currently gas sales in the SC Field are 1,000 MCF per day. Southern
California Gas Company (SOCAL), the pipeline company and our only outlet
to sell gas has imposed a 1,000 MCF per day maximum limit. If it weren't
for this limit, we believe we could sell 2,500 MCF per day. If we are
unable to sell more gas, we will have to curtail our exploration and
development plans. We have been negotiating with SOCAL to increase the
capacity from 1,000 MCF per day to 3,000 MCF per day. Recent negotiations
with SOCAL have proved fruitless, and we don't know when and if our
capacity will increase. Our gas reserves should last for at least 8 years
producing at this low rate of 1,000 MCF per day. Considering the
time value of money, we would much rather be producing at a much higher rate.
ARCO Indemnity
--------------
As discussed in previous filings, the SC Field was purchased from ARCO
(Atlantic Richfield which is now part of BP p.l.c.) in May 1990. As part
of the Purchase and Sale Agreement, ARCO agreed to indemnify us for certain
environmental liabilities connected with their 40-year ownership of the field
and gas plant ("ARCO Indemnity"). Part of the gas plant has not been
operational during the past twenty-five years. There is evidence of asbestos
in the non-operational part of the gas plant. It is our position, and the
opinion of our legal counsel, that the ARCO Indemnity covers future abandonment
and clean-up costs associated with this gas plant. We have had several
discussions with BP regarding this matter and have retained a San Francisco law
firm to assert our rights under the ARCO Indemnity. BP continues to deny any
responsibility.
The costs to abandon and clean up the gas plant area and other oil and gas
areas at the field will be significant. There is a chance, depending on the
negotiations and legal proceedings with BP, that some or all of the costs could
be borne by us. At this time we are unable to estimate what these costs could
ultimately be but we expect that such costs could have a material adverse
effect on our financial condition, results of operations and cash flows.
San Juan Basin - New Mexico
---------------------------
Two successful development gas wells were drilled during April. During the
third quarter we drilled four more successful development gas wells. These
six wells cost about $3.6 million to the 100%. We have an approximate 10%
WI in these six wells. We expect to assign proved developed gas reserves to
the 100% of between 1 BCF and 1.5 BCF per well. Our net revenue interest in
these wells is about 8%. No more drilling is planned for the near future.
Predecessor Entity
------------------
Over the past 12 years we have paid about $250,000 to properly plug and abandon
12 or so sites which were previously plugged and abandoned by Kimbark Oil & Gas
Company, our predecessor entity. For the quarter ended September 30, 2003, we
spent $42,000 to properly plug and abandon a well in southern Colorado, which
was drilled by our predecessor over 20 years ago. We do not expect any more
notices from state regulatory jurisdictions regarding improperly P&A wells, but
it is possible that there could be more.
SFAS No. 143 - "Accounting for Asset Retirement Obligations"
------------------------------------------------------------
In July 2001, the Financial Accounting Standards Board issued SFAS No. 143,
"Accounting for Asset Retirement Obligations." SFAS No. 143 requires
entities to record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred and a corresponding increase
in the carrying amount of the related long-lived asset and is effective for
fiscal years beginning after June 15, 2002. We adopted SFAS No. 143 on
January 1, 2003 and increased our liability for asset retirement obligations
by $264,000 (using an 8% discount rate) and recorded a cumulative effect of
change in accounting principle of $181,000. For the nine months ended
September 30, 2003, we recognized $56,000 of accretion on the liability as
a component of depletion expense.
There are no other significant changes or developments to report from what
we disclosed in the 2002 Form 10-KSB.
ITEM 3. CONTROLS AND PROCEDURES
We maintain a system of disclosure controls and procedures that are designed
for the purposes of ensuring that information required to be disclosed in our
SEC reports is recorded, processed, summarized and reported within the time
periods specified in the SEC's rules and forms, and that such information is
accumulated and communicated to our CEO as appropriate to allow timely
decisions regarding required disclosure.
As of the end of the period covered by this report, we have carried out an
evaluation, under the supervision and with the participation of our CEO of the
effectiveness of the design and operation of our disclosure controls and
procedures. Based upon that evaluation, our CEO, who is also our CFO,
concluded that our disclosure controls and procedures are effective for the
purposes discussed above. There have been no significant changes in our
internal controls or in other factors that could significantly affect these
controls subsequent to the date of the evaluation.
PART II-OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
31 - SOX 302 Certification
32 - SOX 906 Certification
Signature
In accordance with the requirements of the Exchange Act, the Registrant
has caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
HALLADOR PETROLEUM COMPANY
Dated: November 14, 2003 By: /S/VICTOR P. STABIO
Chief Executive Officer and
Chief Financial Officer
Signing on behalf of registrant
and as principal financial officer.