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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 June 30, 2000
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number 0-26662
PANACO, Inc.
(Exact name of registrant as specified in its charter)
Delaware 43 - 1593374
(State or other jurisdiction of (I.R.S. Employer Identification
incorporation or organization) Number)
1100 Louisiana Street, Suite 5100
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 970 - 3100
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 _______.
24,323,521 shares of the registrant's $.01 par value Common Stock were
outstanding on June 30, 2000.
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE>
PANACO, Inc.
Consolidated Condensed Balance Sheets
ASSETS
<TABLE>
<CAPTION>
As of As of
June 30, 2000 December 31, 1999
------------- -----------------
<S> <C> <C>
CURRENT ASSETS (Unaudited)
Cash and cash equivalents $ 1,506,000 $ 5,575,000
Accounts receivable 16,607,000 9,675,000
Accounts receivable-employee 27,000 16,000
Prepaid and other 1,415,000 729,000
--------------- ---------------
Total current assets 19,555,000 15,995,000
--------------- ---------------
OIL AND GAS PROPERTIES, AS DETERMINED BY THE
SUCCESSFUL EFFORTS METHOD OF ACCOUNTING
Oil and gas properties, proved 273,991,000 262,043,000
Less proved property accumulated depletion,
depreciation and amortization (185,317,000) (175,048,000)
Net unproved oil and gas properties 1,887,000 1,893,000
--------------- ---------------
Net oil and gas properties 90,561,000 88,888,000
--------------- ---------------
PIPELINES AND EQUIPMENT
Pipelines and equipment 26,348,000 26,327,000
Less accumulated depreciation (7,454,000) (6,130,000)
--------------- ---------------
Net pipelines and equipment 18,894,000 20,197,000
--------------- ---------------
OTHER ASSETS
Deferred income taxes 27,602,000 -
Deferred debt costs, net 3,962,000 4,456,000
Employee note receivable 300,000 300,000
Restricted deposits 7,102,000 5,602,000
--------------- ---------------
Total other assets 38,966,000 10,358,000
--------------- ---------------
TOTAL ASSETS $ 167,976,000 $ 135,438,000
=============== ===============
(continued)
</TABLE>
The accompanying notes are an integral part of this statement.
2
<PAGE>
PANACO, Inc.
Consolidated Condensed Balance Sheets
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
<TABLE>
<CAPTION>
As of As of
June 30, 2000 December 31, 1999
------------- -----------------
CURRENT LIABILITIES (Unaudited)
<S> <C> <C>
Accounts payable $ 21,569,000 $ 20,408,000
Interest payable 3,059,000 3,003,000
---------------- ------------------
Total current liabilities 24,628,000 23,411,000
---------------- ------------------
DEFERRED CREDITS 625,000 -
LONG-TERM DEBT 138,251,000 138,902,000
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY (DEFICIT)
Preferred Shares, $.01 par value,
5,000,000 shares authorized; no
shares issued and outstanding - -
Common Shares, $.01 par value,
100,000,000 shares authorized;
24,323,521 and 23,986,521 shares
issued and outstanding, respectively 246,000 243,000
Additional paid-in capital 68,976,000 68,852,000
Accumulated deficit (64,750,000) (95,970,000)
---------------- -----------------
Total stockholders' equity (deficit) 4,472,000 (26,875,000)
---------------- -----------------
TOTAL LIABILITIES AND
STOCKHOLDERS' EQUITY (DEFICIT) $ 167,976,000 $ 135,438,000
================ =================
</TABLE>
The accompanying notes are an integral part of this statement.
3
<PAGE>
PANACO, Inc.
Consolidated Statements of Operations
For the Six Months Ended June 30,
(Unaudited)
<TABLE>
<CAPTION>
2000 1999
-------------- --------------
<S> <C> <C>
REVENUES
Oil and natural gas sales $ 37,581,000 $ 20,126,000
COSTS AND EXPENSES
Lease operating expense 10,076,000 8,405,000
Depletion, depreciation & amortization 12,552,000 12,339,000
General and administrative expense 2,300,000 2,068,000
Production and ad valorem taxes 965,000 371,000
Geological and geophysical expense 852,000 564,000
Exploratory dry hole expense 447,000 845,000
Lawsuit recovery (990,000) -
--------------- ---------------
Total 26,202,000 24,592,000
--------------- ---------------
OPERATING INCOME (LOSS) 11,379,000 (4,466,000)
OTHER INCOME (EXPENSE)
Interest income 74,000 35,000
Interest expense (7,836,000) (5,443,000)
--------------- ---------------
Total (7,762,000) (5,408,000)
--------------- ---------------
INCOME (LOSS) BEFORE INCOME TAXES 3,617,000 (9,874,000)
INCOME TAX EXPENSE (BENEFIT) (27,602,000) -
--------------- ---------------
NET INCOME (LOSS) $ 31,219,000 $ (9,874,000)
=============== ===============
Net income (loss) per share $ 1.29 $ (0.41)
=============== ===============
Basic Shares Outstanding 24,199,461 23,894,339
=============== ===============
Diluted Shares Outstanding 24,199,461 23,894,339
=============== ===============
</TABLE>
The accompanying notes are an integral part of this statement.
4
<PAGE>
PANACO, Inc.
Consolidated Statements of Operations
For the Three Months Ended June 30,
(Unaudited)
<TABLE>
<CAPTION>
2000 1999
-------------- ------------
<S> <C> <C>
REVENUES
Oil and natural gas sales $ 22,024,000 $ 10,627,000
COSTS AND EXPENSES
Lease operating expense 5,885,000 4,285,000
Depletion, depreciation & amortization 6,806,000 5,709,000
General and administrative expense 1,316,000 946,000
Production and ad valorem taxes 706,000 217,000
Geological and geophysical expense 551,000 177,000
Exploratory dry hole expense 127,000 845,000
Lawsuit recovery (990,000) -
-------------- -------------
Total 14,401,000 12,179,000
-------------- -------------
OPERATING INCOME (LOSS) 7,623,000 (1,552,000)
OTHER INCOME (EXPENSE)
Interest income 21,000 23,000
Interest expense (4,182,000) (2,720,000)
-------------- -------------
Total (4,161,000) (2,697,000)
-------------- -------------
INCOME (LOSS) BEFORE INCOME TAXES 3,462,000 (4,249,000)
INCOME TAX EXPENSE (BENEFIT) (27,602,000) -
-------------- -------------
NET INCOME (LOSS) $ 31,064,000 $ (4,249,000)
============== =============
Net income (loss) per share $ 1.28 $ (0.18)
============== =============
Basic Shares Outstanding 24,323,521 23,985,927
============== =============
Diluted Shares Outstanding 24,323,521 23,985,927
============== =============
</TABLE>
The accompanying notes are an integral part of this statement.
5
<PAGE>
PANACO, Inc.
Consolidated Statement of Cash Flows
For the Six Months Ended June 30,
(Unaudited)
<TABLE>
<CAPTION>
2000 1999
-------------- -------------
<S> <C> <C>
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES
Net income (loss) $ 31,219,000 $(9,874,000)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Deferred income taxes (27,602,000) -
Depletion, depreciation and amortization 12,552,000 12,339,000
Exploratory dry hole expense 447,000 845,000
ESOP stock contribution 127,000 250,000
Changes in assets and liabilities:
Accounts receivable (6,932,000) 501,000
Accounts payable 1,161,000 2,196,000
Deferred credits 625,000 -
Interest payable 56,000 (44,000)
Prepaid and other (697,000) (175,000)
--------------- ---------------
Net cash provided by operating activities 10,956,000 6,038,000
--------------- ---------------
CASH FLOWS USED IN INVESTING ACTIVITIES
Capital expenditures and acquisitions (12,520,000) (14,490,000)
Increase in restricted deposits (1,500,000) (1,250,000)
--------------- ---------------
Net cash used in investing activities (14,020,000) (15,740,000)
--------------- ---------------
CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES
Long-term debt borrowings 10,349,000 10,500,000
Repayment of long-term debt (11,000,000) -
Additional deferred financing costs (354,000) -
--------------- ---------------
Net cash provided by (used in) financing activities (1,005,000) 10,500,000
--------------- ---------------
NET INCREASE (DECREASE) IN CASH (4,069,000) 798,000
CASH AT BEGINNING OF YEAR 5,575,000 3,452,000
--------------- ---------------
CASH AT JUNE 30 $ 1,506,000 $ 4,250,000
=============== ===============
</TABLE>
The accompanying notes are an integral part of this statement.
6
<PAGE>
PANACO, Inc.
Consolidated Statement of Changes in Stockholders' Equity (Deficit)
(Unaudited)
<TABLE>
<CAPTION>
Amount ($)
----------------------------------------------------
Number of Additional Total
Common Common Paid-in Accumulated Stockholders'
Shares Stock Capital Deficit Equity (Deficit)
-------------- -------------- -------------- -------------- -----------------
<S> <C> <C> <C> <C> <C>
Balances, December 31, 1999 23,986,521 $ 243,000 $ 68,852,000 $ (95,969,000) $ (26,874,000)
Net Income - - - 31,219,000 31,219,000
Common shares issued to the ESOP 337,000 3,000 124,000 - 127,000
-------------- --------------- --------------- ----------------- ---------------
Balances, June 30, 2000 24,323,521 $ 246,000 $ 68,976,000 $ (64,750,000) $ 4,472,000
============== =============== =============== ================= ===============
</TABLE>
The accompanying notes are an integral part of this statement.
7
<PAGE>
PANACO, Inc.
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Unaudited)
Note 1 - BASIS OF PRESENTATION
In the opinion of management, the accompanying unaudited condensed
consolidated financial statements contain all adjustments necessary to present
fairly the financial position as of June 30, 2000 and December 31, 1999 and the
results of operations and cash flows for the periods ended June 30, 2000 and
1999. Most adjustments made to the financial statements are of a normal,
recurring nature. Although the Company believes that the disclosures are
adequate to make the information presented not misleading, certain information
and footnote disclosures, including significant accounting policies, normally
included in financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted pursuant to the rules and
regulations of the Securities and Exchange Commission (the "SEC"). A more
complete description of the accounting policies followed by the Company are set
forth in Note 1 to the Company's financial statements in Form 10-K for the year
ended December 31, 1999. These financial statements should be read in
conjunction with the financial statements and notes included in the Form 10-K.
Certain reclassifications of prior period statements have been made to
conform with current reporting practices.
Weighted average options to purchase 1,150,000 shares of common stock at
$4.45 per share were outstanding during the second quarter of 2000 but were not
included in the computation of diluted earnings per share because the options'
exercise prices were greater than the average market price of the common shares.
These options were issued in 1997 to officers and directors and expired June 20,
2000.
Note 2 - OIL AND GAS PROPERTIES AND PIPELINES AND EQUIPMENT
The Company utilizes the successful efforts method of accounting for its
oil and gas properties. Under the successful efforts method, lease acquisition
costs are initially capitalized. Exploratory drilling costs are also capitalized
pending determination of proved reserves. If proved reserves are not discovered,
the exploratory costs and associated lease acquisition costs are expensed. All
development costs are capitalized. Non-drilling exploratory costs, including
geological and geophysical costs and delay rentals, are expensed. Unproved
leaseholds with significant acquisition costs are assessed periodically, on a
property-by-property basis, and a loss is recognized to the extent, if any, that
the cost of the property has been impaired. Unproved leaseholds whose
acquisition costs are not individually significant are aggregated, and the
portion of such are amortized over an average holding period. As unproved
leaseholds are determined to be productive, the related costs are transferred to
proved leaseholds. Provision for depreciation and depletion is determined on a
depletable unit basis using the unit-of-production method. Estimated future
abandonment costs are recorded by charges to depreciation and depletion expense
over the lives of the proved reserves of the properties.
The Company performs a review for impairment of proved oil and gas
properties on a depletable unit basis when circumstances suggest there is a need
for such a review. For each depletable unit determined to be impaired, an
impairment loss equal to the difference between the carrying value and the fair
value of the depletable unit will be recognized. Fair value, on a depletable
unit basis, is estimated to be the present value of expected future cash flows
computed by applying estimated future oil and gas prices, as determined by
management, to estimated future production of oil and gas reserves over the
economic lives of the reserves. Future cash flows are based upon the Company's
estimate of proved reserves.
8
<PAGE>
PANACO, Inc.
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Unaudited)
Property and equipment are carried at cost. Oil and natural gas pipelines
and equipment are depreciated on the straight-line method over their estimated
lives, primarily fifteen years. Other property is also depreciated on the
straight-line method over their estimated lives, ranging from three to ten
years. Fees for processing oil and natural gas for others are treated as a
reduction of lease operating expense related to the facilities and
infrastructure.
Note 3 - CASH FLOW INFORMATION
For purposes of the consolidated statement of cash flows, the Company
considers all cash investments purchased with original maturities of three
months or less to be cash equivalents. Cash payments for interest totaled
$7,884,000 and $5,868,000 during the first six months of 2000 and 1999,
respectively. Cash payments for income taxes totaled $0 during the first six
months of 2000 and 1999, respectively.
Note 4 - RESTRICTED DEPOSITS
Pursuant to existing agreements the Company is required to deposit funds in
bank trust and escrow accounts to provide a reserve against satisfaction of its
eventual responsibility to plug and abandon wells and remove structures when
certain fields no longer produce oil and gas. Through November 30, 1997 the
Company funded $900,000 into an escrow account with respect to the West Delta
Fields. At that time, the Company completed its obligation for the funding under
West Delta agreement. The Company has entered into an escrow agreement with
Amoco Production Company under which the Company deposits, for the life of the
fields, in a bank escrow account ten percent (10%) of the net cash flow, as
defined in the agreement, from the Amoco properties. The Company has established
the "PANACO East Breaks 110 Platform Trust" in favor of RLI, Underwriter's
Indemnity. This trust required an initial funding of $846,720 in December 1996,
and remaining deposits of $250,000 due at the end of each quarter until the
balance in the account reaches $5.4 million. In connection with the BP
Acquisition, the Company deposited $1.0 million into an escrow account on July
1, 1998. On the first day of each quarter thereafter, the Company deposits
$250,000 into the escrow account until the balance in the escrow account reaches
$6.5 million.
Note 5 - COMMITMENTS AND CONTINGENCIES
An action was filed against the Company in Louisiana, along with Exxon
Pipeline Company ("Exxon"), National Energy Group, Inc. ("NEG"), Mendoza Marine,
Inc., Shell Western Exploration & Production, Inc. ("Shell"), and the Louisiana
Department of Transportation and Development. The petition was filed in August
1998, and alleges that, in 1997 and perhaps earlier, leaks from a buried crude
oil pipeline contaminated the plaintiff's property.
Pursuant to the purchase and sales agreement between the Company and NEG,
NEG is required to indemnify the Company from any damages attributable to NEG's
operations on the property after the sale. However, NEG is in Chapter 11
bankruptcy proceedings, and so any action by the Company to assert indemnity
rights against NEG is currently stayed. The Company's Counsel has prepared and
may file a motion to lift the stay so that the Company may assert its
indemnification rights against NEG. But even if the Company is successful in
proving its right to indemnity, NEG's ability to satisfy the judgement is
questionable because of the bankruptcy.
9
<PAGE>
PANACO, Inc.
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Unaudited)
Pursuant to another purchase and sale agreement, the Company may owe
indemnity to Shell and Exxon, from whom it acquired the property prior to
selling same to NEG. The Company may have insurance coverage for the claims
asserted in the petition, and has notified all insurance carriers that might
provide coverage under its policies. Some discovery has occurred in the case,
but discovery is not yet complete. Therefore, at this point it is not possible
to evaluate the likelihood of an unfavorable outcome, or to estimate the amount
or range of potential loss.
The Company is subject to various legal proceedings and claims which arise
in the ordinary course of business. In the opinion of management, the amount of
liability, if any, with the respect to these actions would not materially affect
the financial position of the Company or its results of operation.
Note 6 - LONG-TERM DEBT
In October 1999 the Company put in place a new credit facility. The loan is
a reducing revolver which will provide the Company with up to $60 million,
depending on the borrowing base. The Company's borrowing base at June 30, 2000
was $60.0 million, with availability of $21.8 million. The principal amount of
the loan is due September 30, 2001, and may be extended for an additional year
at the option of the Company. Interest on the loan is computed at Wells Fargo's
prime rate plus .5% to 3.0%, depending on the percentage of the facility being
used. The Credit Facility is collateralized by a first mortgage on most of the
Company's properties. The loan agreement contains certain covenants including an
EBITDA (as defined in the agreement) to interest expense ratio of at least 1.5
to 1.0 and a working capital ratio (as defined in the agreement) of at least .25
to 1.0. The loan agreement also contains limitations on additional debt,
dividends, mergers and sales of assets. At June 30, 2000 the Company was in
compliance with all of the requirements of it long-term debt.
Note 7 - NEW ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for
Derivative Instruments and Hedging Activities, and in June 2000, the FASB issued
SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging
Activities, an amendment of FASB Statement No. 133. These statements establish
standards of accounting for and disclosures of derivative instruments and
hedging activities. These statements are effective for fiscal years beginning
after June 15, 2000. While the Company has not yet completed its evaluation of
the impact of these statements, the Company does not believe the statements will
have a significant impact on its results of operations as it expects its current
derivative activities would continue to qualify under hedge accounting.
Note 8 - INCOME TAXES
At December 31, 1999 the Company had a tax valuation allowance of
approximately $29 million against its deferred tax assets. As of June 30, 2000,
the Company determined that it was more likely than not that the deferred tax
assets would be realized. This determination was based on current projections of
future taxable income in addition to recent reserve additions. Current
projections of future taxable income are sufficient to utilize our deferred tax
assets due to higher commodity prices and reserve additions, therefore the
valuation allowance was removed.
10
<PAGE>
PANACO, Inc.
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Unaudited)
These projections of future taxable income are management's best estimates,
using current reserve estimates, estimates of future commodity prices and other
information currently available. While the Company believes that the assumptions
used in these projections are reasonable, unfavorable future events such as a
decrease in commodity prices could result in a reduction in some or all of the
deferred tax assets in a future period. The $29 million benefit recorded for the
removal of the valuation allowance was offset by a $1.4 million deferred tax
liability that was generated during the six months ended June 30, 2000,
resulting in an overall tax benefit of $27.6 million.
11
<PAGE>
PART I
Item 2.
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Forward-looking Statements
With the exception of historical information, the matters discussed in this
Form 10-Q contain forward-looking statements. The forward-looking statements we
make, not only in this Form 10-Q, but also in press releases, oral statements
and other reports that we file with the Securities and Exchange Commission
("SEC") are intended to be subject to the safe harbor provisions of the Private
Securities Litigation Reform Act of 1995. These statements relate to future
results of operations, the ability to satisfy future capital requirements, the
growth of our Company and other matters. You are cautioned that all
forward-looking statements involve risks and uncertainties. The words
"estimate," "anticipate," "expect," "predict," "believe" and similar expressions
are intended to qualify these forward-looking statements. We believe that the
forward-looking statements that we make are based on reasonable expectations.
However, due to the nature of the business we are in and other factors, we can
not assure you that the actual results of our Company will not differ from those
expectations.
General
The oil and natural gas industry has experienced significant volatility in
recent years because of the fluctuatory relationship of the supply of most
fossil fuels relative to the demand for those products and other uncertainties
in the world energy markets. You should consider the volatility of this industry
when reading the following.
Liquidity and Capital Resources
In implementing our business strategy of increasing our reserve base and
cash flows from operations, we have reinvested our cash flows from operations as
capital expenditures. During the first six months of 2000, our net cash provided
by operating activities totaled $11.0 million, which, along with cash on hand,
was used to fund our capital expenditures of $12.5 million, and our required
restricted deposit increases of $1.5 million. Our capital expenditures of $12.5
million for the first six months of 2000 were down from $14.5 million during the
first six months of 1999.
For the year 2000, our Board of Directors has approved a $30 million
capital budget. This budget is based primarily on the resources available to us
at this time. We believe that our cash flows from operations and borrowings
under our Credit Facility will fund this level of capital expenditures and that
we will have sufficient availability under our Credit Facility.
Credit Facility
Our primary source of capital beyond discretionary cash flows is our Credit
Facility. Our Credit Facility is secured by a first mortgage on most of our oil
and natural gas properties, and is used primarily as development capital on
properties that we own. We may also use the Credit Facility for working capital
support, to provide letters of credit and general corporate purposes.
In October 1999 we put in place a new Credit Facility, with Foothill
Capital Corp. as the Agent, and includes Foothill Partners, L.P. and Ableco
Finance, a subsidiary of Cereberus Capital Management, L.P. This Credit Facility
12
<PAGE>
is a $60 million line, with a term of two years, and extendable for an
additional year at our option. Borrowings under this Facility bear interest at
rates ranging from prime plus .5% up to prime plus 3.0% depending on the amount
borrowed. We had $36 million outstanding at June 30, 2000, a decrease of $5.7
million during the second quarter of 2000. We will continue to use this Facility
in 2000 to fund part of our $30 million capital budget.
The Credit Facility is a revolving credit agreement subject to monthly
borrowing base determinations. These determinations are made based on internally
prepared engineering reports, using a two year average of NYMEX future commodity
process and are based on our semi-annual third party reserve reports.
Indebtedness under this Credit Facility constitutes senior indebtedness with
respect to the Senior Notes.
Under the terms of this Credit Facility, we must maintain a ratio of
trailing twelve-month EBITDA to net interest expense of not less than 1.5 to 1.0
throughout the term of the Facility. We must also maintain a working capital
ratio, as defined in the agreement, of not less than .25 to 1.0. Also, the
Credit Facility contains certain limitations on mergers, additional indebtedness
and pledging or selling assets. We were in compliance with all covenants on June
30, 2000 and anticipate compliance throughout the term of the loan.
Senior Note offering
On October 9, 1997, we issued $100 million principal amount of 10 5/8%
Senior Notes due October 1, 2004. Interest on the Notes is payable semi-annually
in arrears on each April 1 and October 1, commencing April 1, 1998.
Commodity price hedges
We follow a hedging strategy designed to protect against the possibility of
severe price declines due to market volatility. We usually make hedging
decisions to assure a payout of a specific acquisition or development project.
For the year 2000, we have options to put oil and natural gas produced to a
purchaser at an agreed upon price. The natural gas put option is for 10,000
MMbtu per day at a NYMEX price of $2.04 per MMbtu. The cost of the natural gas
put option was $366,000, which is being amortized over the period the hedge item
is produced, fiscal year 2000. We also have an oil put option for 1,000 barrels
of oil per day beginning March 1, 2000 and continuing through December 31, 2000
at NYMEX price of $20.00 per barrel. The oil put option cost $275,000 and is
also being amortized over the period the hedge item is produced, fiscal year
2000. In addition we have a swap in place on an average of 232 barrels of oil
for each day at $17.00 per barrel. This swap was assumed with the acquisition of
Goldking in 1997.
On June 30, 2000 this open hedge position had a fair value of estimated
future losses totaling $506,000. A 10% adverse change in prices would cause
these estimated future losses to increase to $539,000.
We produce and sell natural gas, oil and natural gas liquids. As a result,
our financial results can be significantly affected by changes in these
commodity prices. We use derivative financial instruments to attempt to hedge
our exposure to changes in the market price of natural gas and oil. While
commodity financial instruments are intended to reduce exposure to declines in
these market prices, the commodity financial instruments may also limit the
gains from increases in the market price of natural gas and oil. Gains or losses
on these transactions are recognized in the production month to which a hedge
contract relates.
13
<PAGE>
Capital expenditures
Capital expenditures totaled $12.5 million for the first six months of
2000, which represents a 14% decrease from the $14.5 million of capital
expenditures incurred in the comparable period of 1999. The capital expenditures
incurred in 2000 were primarily for three new wells completed during the first
quarter, two acquisitions and developmental work in the East Breaks 165 Field,
which took place during the second quarter. The first development well was in
the Price Lake Field, the Sturlese #3 that was successfully completed in March
2000. We also drilled a new development well in the Umbrella Point Field, the ST
#87-12 well, which was also successfully completed in March 2000. A third new
development well was completed in the West Delta Fields in January.
In addition, we acquired minority, non-operating interests in our North
Coward's Gully Field and in the East Breaks 109 Fields, giving us essentially
100% ownership of both of these Fields. These expenditures were funded with cash
flows from operations in addition to cash on hand. Our total capital
expenditures during fiscal year 2000 are estimated to be $30 million.
Results of Operations
For the six months ended June 30, 2000 and 1999:
"Oil and natural gas sales"
Production and Prices:
<TABLE>
<CAPTION>
% Increase
2000 1999 (Decrease)
---- ---- -----------
<S> <C> <C> <C>
Natural gas production (MMcf) 6,833 6,304 8%
Average price per Mcf
excluding hedging $ 3.28 $ 1.88 74%
Average price per Mcf
including hedging $ 3.25 $ 1.85 76%
Oil Production (MBbl) 541 551 (2%)
Average price per Bbl
excluding hedging $ 28.92 $ 15.19 90%
Average price per Bbl
including hedging $ 28.42 $ 15.37 85%
</TABLE>
Natural gas production increased 8%, while oil production decreased 2%
during the first six of 2000 when compared to the first six months of 1999. The
resumption of capital spending during the fourth quarter of 1999 and continuing
in the first quarter of 2000 resulted in additional production in several fields
that we operate. This additional production resulted in offsetting production
declines that occur naturally on some of our other properties.
The fields that we experienced increased production from were the Price
Lake Field, which did not produce during the first six months of 1999. Initial
production from the Price Lake Field began in September 1999 and was increased
further with a second successful well completed in March 2000. We also increased
production with two successful projects in the Umbrella Point Field. A workover
of the ST #74-10 well in December 1999 was the primary factor in increasing
14
<PAGE>
natural gas production in the Umbrella Point Field. We also completed a
successful development well in this Field, the ST #87-12, which did not begin
production until March 2000.
"Lease operating expense" increased to $10.1 million during the first six
months of 2000 compared to $8.4 million in 1999. On an Mcf equivalent ("Mcfe")
basis, lease operating expenses also increased to $1.00 in 2000 compared to
$0.87 in 1999. Part of our increased capital and project spending in 2000
included a number of workover and repair expenditures, which are expensed as
they are incurred. The largest of which were incurred at our East Breaks 165
Field. We spent approximately $1.1 million for MMS mandated repairs of
production tubing on several wells.
"Depletion, depreciation and amortization" increased $.2 million primarily
due to a 5% increase in total production, which was offset slightly by a 3%
decrease in depletion per Mcfe. On an Mcfe basis, depletion, depreciation and
amortization decreased to $1.25 in 2000 from $1.28 in 1999. The primary reason
for the decrease was 35% lower production from the High Island 309 Fields for
the first six months of 2000. This was offset somewhat by a higher depletion
cost per Mcfe from the Price Lake Field, however, this production did not begin
to increase significantly until the second quarter of 2000.
"General and administrative expense" increased $.2 million during the first
six months of 2000 primarily due to higher salaries, wages and benefits.
"Production and ad valorem taxes" increased $.6 million, or 160%, during
the first six months of 2000 due to two factors. Production taxes on oil sales
are calculated based on the value of the oil being sold which increased
significantly with a 90% increase in our realized oil prices. Our production mix
during 2000 also changed to include more production from properties onshore, or
in state waters, which are subject to severance taxes.
"Geological and geophysical expense" increased $.3 million during the first
six months of 2000. The increase relates to an increase in drilling activity and
related required geological work over the first six months of 1999. We also
purchased 3-D seismic for further development of a field we operate.
"Exploratory dry hole expense" decreased $.4 million in 2000. These
exploration expenses incurred in 2000 primarily related to two successful wells
completed during the first quarter, the Umbrella Point Field ST#87-12 and the
Price Lake Field D.T. Sturlese #3. Although the wells were completed and are
producing, portions of the targeted zones in each well were exploratory and did
not encounter an economical quantity of reserves. The incremental costs for
drilling to these zones were expensed based on their proportional costs of the
entire well.
"Lawsuit recovery" relates to a lawsuit that we had filed in 1996, in
conjunction with our insurance carrier, related to a property that we operate.
Our part of the lawsuit was primarily for time value of delayed revenues from a
fire caused by a third party service company. The judgement against the service
companies' insurance carrier was appealed on April 7, 2000 and was subsequently
settled for which we received $990,000.
"Income tax benefit" reflects a reduction of our deferred income taxes
valuation allowance. At December 31, 1999 we had a tax valuation allowance of
approximately $29 million against our deferred tax assets. As of June 30, 2000,
we determined that it was more likely than not that the deferred tax assets
would be realized. This determination was based on our current projections of
future taxable income in addition to recent reserve additions. Our current
projections of future taxable income are sufficient to utilize our deferred tax
15
<PAGE>
assets due to higher commodity prices and reserve additions, therefore the
valuation allowance was removed.
These projections of future taxable income are management's best estimates,
using current reserve estimates, estimates of future commodity prices and other
information currently available. While we believe that the assumptions used in
these projections are reasonable, unfavorable future events such as a decrease
in commodity prices could result in a reduction in some or all of the deferred
tax assets in a future period. The $29 million benefit recorded for the removal
of the valuation allowance was offset by a $1.4 million deferred tax liability
that was generated during the six months ended June 30, 2000, resulting in an
overall tax benefit of $27.6 million.
"Interest expense" increased due to a combination of higher average
borrowings and an increase in the prime rate, upon which our Credit Facility
interest rate is based on.
For the three months ended June 30, 2000 and 1999:
"Oil and natural gas sales"
Production and Prices:
<TABLE>
<CAPTION>
% Increase
2000 1999 (Decrease
---- ---- ---------
<S> <C> <C> <C>
Natural gas production (MMcf) 3,585 2,945 22%
Average price per Mcf
excluding hedging $ 3.92 $ 2.07 89%
Average price per Mcf
including hedging $ 3.90 $ 1.93 102%
Oil Production (MBbl) 275 289 (5%)
Average price per Bbl
excluding hedging $ 29.88 $ 16.86 77%
Average price per Bbl
including hedging $ 29.18 $ 17.06 71%
</TABLE>
The resumption of capital spending during the fourth quarter of 1999 and
continuing in the first quarter of 2000 resulted in increased natural gas
production in several fields that we operate. This additional production more
than offset production declines that occur naturally on other properties.
The fields that we experienced increased production from were the Price
Lake Field, which did not produce during the second quarter of 1999. Initial
production from the Price Lake Field began in September 1999 and was increased
further with a second successful well completed in March 2000. We also increased
production with two successful projects in the Umbrella Point Field. A workover
of the ST #74-10 well in December 1999 was the primary factor in increasing
natural gas production in the Umbrella Point Field. We also completed a
successful development well in this Field, the ST #87-12, which began production
in March 2000.
"Lease operating expense" increased $1.6 million during the second quarter
of 2000 compared to the comparable period in 1999. On an Mcf equivalent ("Mcfe")
16
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basis, lease operating expenses also increased to $1.12 in 2000 compared to
$0.92 in 1999. Part of our increased capital and project spending in 2000
included a number of workover and repair expenditures during the second quarter
of 2000, which are expensed as they are incurred. The largest of which were
incurred at our East Breaks 165 Field. We spent approximately $1.1 million for
MMS mandated repairs of production tubing on several wells in that Field.
"Depletion, depreciation and amortization" increased $1.1 million, or 19%,
primarily due to a 12% increase in total production. On an Mcfe basis,
depletion, depreciation and amortization increased to $1.30 in 2000 from $1.22
in 1999. Although production from the High Island 309 Fields, which had a higher
cost per Mcfe of production, had decreased during the second quarter of 2000.
Offsetting increased production from the Price Lake Field, which also had a
relatively higher cost per Mcfe, had begun to increase to meaningful levels
during the second quarter.
"General and administrative expense" increased $.4 million during 2000
primarily due to higher salaries, wages and benefits.
"Production and ad valorem taxes" increased $.5 million, or 226%, during
the second quarter of 2000 due to two factors. Production taxes on oil sales are
calculated based on the value of the oil being sold which increased
significantly with a 77% increase in our realized oil prices. Our production mix
during 2000 also changed to include more production from properties onshore, or
in state waters, which are subject to severance taxes.
"Geological and geophysical expense" increased $.4 million during the
second quarter of 2000. The increase relates to an increase in drilling activity
and related required geological work over the second quarter of 1999. During
2000, we also purchased 3-D seismic for further development of a field we
operate.
"Exploratory dry hole expense" decreased $.7 million during the second
quarter of 2000. The unsuccessful results in 2000 were from a non-operated well
drilled in Alabama, in which we owned a 12.5% interest.
"Lawsuit recovery" relates to a lawsuit that we had filed in 1996, in
conjunction with our insurance carrier, related to a property that we operate.
Our part of the lawsuit was primarily for time value of delayed revenues from a
fire caused by a third party service company. The judgement against the service
companies' insurance carrier was appealed on April 7, 2000 and was subsequently
settled for which we received $990,000.
"Income tax benefit" reflects a reduction of our deferred income taxes
valuation allowance. At December 31, 1999 we had a tax valuation allowance of
approximately $29 million against our deferred tax assets. As of June 30, 2000,
we determined that it was more likely than not that the deferred tax assets
would be realized. This determination was based on our current projections of
future taxable income in addition to recent reserve additions. Our current
projections of future taxable income are sufficient to utilize our deferred tax
assets due to higher commodity prices and reserve additions, therefore the
valuation allowance was removed.
These projections of future taxable income are management's best estimates,
using current reserve estimates, estimates of future commodity prices and other
information currently available. While we believe that the assumptions used in
these projections are reasonable, unfavorable future events such as a decrease
in commodity prices could result in a reduction in some or all of the deferred
tax assets in a future period. The $29 million benefit recorded for the removal
of the valuation allowance was offset by a $1.4 million deferred tax liability
that was generated during the six months ended June 30, 2000, resulting in an
overall tax benefit of $27.6 million.
17
<PAGE>
"Interest expense" increased due to a combination of higher average
borrowings and an increase in the prime rate, upon which our Credit Facility
interest rate is based on.
Other Contingencies
We are subject to various legal proceedings and claims that arise in the
ordinary course of business. We believe, based on the information available to
us, that the amount of liability, if any, with the respect to these actions
would not materially affect the financial position of the Company or its results
of operation.
An action was filed against the Company, Exxon Pipeline Company ("Exxon"),
National Energy Group, Inc. ("NEG"), Mendoza Marine, Inc., Shell Western
Exploration & Production, Inc. ("Shell") and the Louisiana Department of
Transportation and Development. The petition was filed in August 1998, and
alleges that, in 1997 and perhaps earlier, leaks from a buried crude oil
pipeline contaminated the plaintiff's property.
Pursuant to the purchase and sale agreement between the Company and NEG,
NEG is required to indemnify us from any damages attributable to NEG's
operations on the property after the sale. However, NEG is in Chapter 11
bankruptcy proceedings, and so any action we take to assert our indemnity rights
against NEG is currently stayed. Our Counsel has prepared and may file a motion
to lift the stay so that we may assert our indemnification rights against NEG.
But even if we are successful in proving our right to indemnity, NEG's
judgementworthiness is questionable because of the bankruptcy.
Pursuant to another purchase and sale agreement, we may owe indemnity to
Shell and Exxon, from whom we acquired the property prior to selling same to
NEG. We believe we have insurance coverage for the claims asserted in the
petition, and have notified all insurance carriers that might provide coverage
under our policies. Some discovery has occurred in the case, but discovery is
not yet complete. Therefore, at this point it is not possible to evaluate the
likelihood of an unfavorable outcome, or to estimate the amount or range of
potential loss.
Item 3a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity price hedges
We follow a hedging strategy designed to protect against the possibility of
severe price declines due to market volatility. We usually make hedging
decisions to assure a payout of a specific acquisition or development project.
For the year 2000, we have options to put oil and natural gas produced to a
purchaser at an agreed upon price. The natural gas put option is for 10,000
MMbtu per day at a NYMEX price of $2.04 per MMbtu. The cost of the natural gas
put option was $366,000, which is being amortized over the period the hedge item
is produced, fiscal year 2000. We also have an oil put option for 1,000 barrels
of oil per day beginning March 1, 2000 and continuing through December 31, 2000
at NYMEX price of $20.00 per barrel. The oil put option cost $275,000 and is
also being amortized over the period the hedge item is produced, fiscal year
2000. In addition we have a swap in place on an average of 232 barrels of oil
for each day at $17.00 per barrel. This swap was assumed with the acquisition of
Goldking in 1997.
On June 30, 2000 this open hedge position had a fair value of estimated
future losses totaling $506,000. A 10% adverse change in prices would cause
these estimated future losses to increase to $539,000.
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PART II OTHER INFORMATION
Item 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
27 Financial Date Schedule
(b) Reports on Form 8-K
None
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PANACO, Inc.
Date: August 9, 2000 /s/ Todd R. Bart
----------------------- -------------------------------------
Todd R. Bart, Chief Financial Officer
<PAGE>
