- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
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, 2001
[ ] 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 _______.
24,359,695 shares of the registrant's $.01 par value Common Stock were
outstanding on September 30, 2001.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
PANACO, Inc.
Condensed Balance Sheets
ASSETS
As of As of
September 30, 2001 December 31, 2000
------------------ -----------------
CURRENT ASSETS (Unaudited)
Cash $ 9,313,000 $ 2,878,000
Accounts receivable, net of an allowance of
$303,000 and $554,000, respectively 13,020,000 17,680,000
Accounts receivable-related party - 300,000
Prepaid and other 1,459,000 907,000
----------------- ----------------
Total current assets 23,792,000 21,765,000
----------------- ----------------
OIL AND GAS PROPERTIES, AS DETERMINED BY THE
SUCCESSFUL EFFORTS METHOD OF ACCOUNTING
Oil and gas properties, proved 279,257,000 289,892,000
Less proved property accumulated depletion,
depreciation and amortization (174,081,000) (193,135,000)
Net unproved oil and gas properties 1,944,000 2,888,000
----------------- ----------------
Net oil and gas properties 107,120,000 99,645,000
----------------- ----------------
PIPELINES AND EQUIPMENT
Pipelines and equipment 26,535,000 26,409,000
Less accumulated depreciation (10,252,000) (8,256,000)
----------------- ----------------
Net pipelines and equipment 16,283,000 18,153,000
----------------- ----------------
HER ASSETS
Restricted deposits 10,460,000 8,625,000
Deferred debt costs, net 1,664,000 3,128,000
Deferred income taxes - 22,763,000
----------------- ----------------
Total other assets 12,124,000 34,516,000
----------------- ----------------
TOTAL ASSETS $ 159,319,000 $ 174,079,000
================= ================
(continued)
The accompanying notes are an integral part of this statement.
2
PANACO, Inc.
Condensed Balance Sheets
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
As of As of
September 30, 2001 December 31, 2000
--------------------- -----------------
CURRENT LIABILITIES (Unaudited)
Accounts payable and accrued liabilities $ 33,277,000 $ 31,963,000
Interest payable 5,480,000 2,917,000
Gas imbalance payable 979,000 2,860,000
Restricted cash payable - 629,000
Deferred income taxes - -
-------------- --------------
Total current liabilities 39,736,000 38,369,000
-------------- --------------
DEFERRED CREDITS 1,646,000 1,609,000
LONG-TERM DEBT 128,345,000 121,693,000
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;
24,359,695 and 24,323,521 shares
issued and outstanding, respectively 247,000 246,000
Additional paid-in capital 69,089,000 68,977,000
Accumulated deficit (82,549,000) (56,815,000)
Accumulated other comprehensive income 2,805,000 -
-------------- --------------
Total stockholders' equity (deficit) (10,408,000) 12,408,000
-------------- --------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 159,319,000 $ 174,079,000
============== ==============
The accompanying notes are an integral part of this statement.
3
PANACO, Inc.
Statements of Operations
For the Nine Months Ended September 30,
(Unaudited)
2001 2000
----------- ----------
REVENUES
Oil and natural gas sales $ 63,058,000 $ 61,811,000
Gain on property sales 3,967,000 -
Lawsuit recovery - 990,000
------------ ------------
Total 67,025,000 62,801,000
COSTS AND EXPENSES
Lease operating expense 20,454,000 16,359,000
Depletion, depreciation & amortization 24,153,000 20,227,000
General and administrative expense 3,356,000 3,474,000
Production and ad valorem taxes 1,284,000 1,454,000
Exploratory dry hole expense 4,590,000 794,000
Geological and geophysical expense 785,000 1,171,000
Severance expense - 746,000
Impairment of oil and gas properties 6,874,000 -
------------ ------------
Total 61,496,000 44,225,000
------------ ------------
OPERATING INCOME 5,529,000 18,576,000
OTHER INCOME (EXPENSE)
Interest income 522,000 113,000
Interest expense (9,696,000) (11,689,000)
Other income 798,000 -
------------ ------------
Total (8,376,000) (11,576,000)
------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES (2,847,000) 7,000,000
INCOME TAX EXPENSE (BENEFIT) 22,887,000 (26,317,000)
------------ ------------
NET INCOME (LOSS) $(25,734,000) $ 33,317,000
============ ============
BASIC AND DILUTED NET INCOME (LOSS) PER SHARE $ (1.06) $ 1.37
============ ============
Basic Shares Outstanding 24,346,444 24,241,116
============ ============
Diluted Shares Outstanding 24,346,444 24,241,116
============ ============
The accompanying notes are an integral part of this statement.
4
PANACO, Inc.
Consolidated Statements of Operations
For the Three Months Ended September 30,
(Unaudited)
2001 2000
---------- ----------
REVENUES
Oil and natural gas sales $ 16,685,000 $ 24,911,000
COSTS AND EXPENSES
Lease operating expense 7,540,000 6,283,000
Depletion, depreciation & amortization 8,811,000 7,769,000
General and administrative expense 920,000 1,174,000
Production and ad valorem taxes 394,000 489,000
Exploratory dry hole expense - 347,000
Geological and geophysical expense 186,000 319,000
Severance expense - 746,000
Impairment of oil and gas properties 332,000 -
------------ ------------
Total 18,183,000 17,127,000
------------ ------------
OPERATING INCOME (LOSS) (1,498,000) 7,784,000
OTHER INCOME (EXPENSE)
Interest income 220,000 39,000
Interest expense (3,237,000) (3,853,000)
Other income 142,000 -
------------ ------------
Total (2,875,000) (3,814,000)
------------ -------------
INCOME (LOSS) BEFORE INCOME TAXES (4,373,000) 3,970,000
INCOME TAX EXPENSE (BENEFIT) 22,235,000 1,508,000
------------ ------------
NET INCOME (LOSS) $(26,608,000) $ 2,462,000
============ ============
BASIC AND DILUTED NET INCOME (LOSS) PER SHARE $ (1.10) $ 0.10
============= ============
Basic Shares Outstanding 24,359,695 24,323,521
============= ============
Diluted Shares Outstanding 24,359,695 24,323,521
============= ============
The accompanying notes are an integral part of this statement.
5
PANACO, Inc.
Statement of Cash Flows
For the Nine Months Ended September 30,
(Unaudited)
2001 2000
---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $(25,734,000) $ 33,317,000
Adjustments to reconcile net income to net cash
provided by operating activities:
Deferred income taxes 22,763,000 (26,317,000)
Depletion, depreciation and amortization 24,152,000 20,227,000
Impairment of oil and gas properties 6,874,000 -
Exploratory dry hole expense 4,590,000 794,000
Gain on property sales (3,967,000) -
Plug and abandoning of wells and platforms (5,203,000) -
Changes in assets and liabilities:
Accounts receivable 8,504,000 (7,546,000)
Accounts payable 2,152,000 8,210,000
Gas imbalance payable (518,000) 1,581,000
Deferred credits 37,000 1,697,000
Interest payable 2,563,000 2,570,000
Accounts receivable-related party 300,000 -
Changes relating to derivative instruments (1,071,000) -
Prepaid and other (1,068,000) (488,000)
------------ ------------
Net cash provided by operating activities 34,374,000 34,045,000
------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the sale of oil and gas properties 2,843,000 -
Capital expenditures and acquisitions (35,529,000) (22,009,000)
Increase in restricted deposits (1,835,000) (1,518,000)
------------ ------------
Net cash used in investing activities (34,521,000) (23,527,000)
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Long-term debt borrowings 17,993,000 11,415,000
Repayment of long-term debt (11,341,000) (25,000,000)
Additional deferred financing costs (70,000) (354,000)
------------ ------------
Net cash used in financing activities 6,582,000 (13,939,000)
------------ ------------
NET INCREASE (DECREASE) IN CASH 6,435,000 (3,421,000)
CASH AT BEGINNING OF YEAR 2,878,000 5,575,000
------------ ------------
CASH AT SEPTEMBER 30 $ 9,313,000 $ 2,154,000
============ ============
The accompanying notes are an integral part of this statement.
6
PANACO, Inc.
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
Note 1 - BASIS OF PRESENTATION
In the opinion of management, the accompanying unaudited condensed
financial statements contain all adjustments necessary to present fairly the
Company's financial position as of September 30, 2001 and December 31, 2000 and
the results of its operations and cash flows for the periods ended September 30,
2001 and 2000. 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, 2000. These financial statements should be read in
conjunction with the financial statements and notes included in the Form 10-K.
The Company restated its financial results for the first three quarters of
2000. The adjustments reflect an increase in the Company's gas imbalance payable
and associated reduction of revenues in the quarters to which the imbalance
relates. The changes reflect adjustments to natural gas production and revenues,
depletion, income before income taxes and net income. The adjustments to the
first nine months of 2000 revenues, depletion, depreciation and amortization and
net income were $(1,688,000), $(387,000) and $(808,000), respectively. The
adjustments to the third quarter of 2000 revenues, depletion, depreciation and
amortization and net income were $(1,007,000), $(293,000) and $(444,000),
respectively.
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 are expensed. All development costs are capitalized.
Non-drilling exploratory costs, including geological and geophysical costs and
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 costs estimated to
ultimately prove nonproductive, based on experience, 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 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.
7
PANACO, Inc.
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
The Company recognized asset impairments during the first nine months of
2001 totaling $6.9 million, relating to both proved and unproved properties.
Based on the decision by the Company to discontinue development of proved
reserves, discovered in 1998, the Company recorded an impairment of $1.1 million
for the capital incurred in initially discovering those reserves. In addition,
in connection with the Company's regular review of the recoverability of proved
reserves carrying values, an impairment of $5.8 million was recorded based on
reserve and price reductions for several properties which the Company considers
non-core.
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.
During the second quarter of 2001, the Company sold its interest in the
High Island 309 and 310 Fields to the operator of the property. The
consideration received by the Company included cash, before adjustment, of $3.8
million and the forgiveness of a $1.4 million gas imbalance payable by the
Company. The sale closed on June 29, 2001 and the proceeds from the buyer were
adjusted to the effective date of the sale, January 1, 2001, and reduced by
amounts owed by the Company to the buyer. Both the Company and the buyer also
agreed to dismiss lawsuits filed by each party against the other as part of the
purchase and sale agreement. The sale resulted in a gain of $4.0 million during
the second quarter of 2001.
Note 3 - CASH FLOW INFORMATION
Cash payments for interest totaled $7.2 million and $9.3 million for the
first nine months of 2001 and 2000, respectively. Cash payments for income taxes
totaled $26,000 and $50,000 for the first nine months of 2001 and 2000,
respectively.
Note 4 - EARNINGS PER SHARE CALCULATIONS
Basic and diluted earnings per share for the first nine months of each year
were based on the year-to-date weighted average share outstanding of 24,346,444
in 2001 and 24,241,116 for 2000. The Company did have potential common shares
outstanding during 2001 in the form of stock options, however, the potential
common shares are excluded from the diluted earnings per share calculation
because the Company had a net loss for both the nine months and quarter ended
September 30, 2001 and the potential common shares would have been
anti-dilutive. The Company also had stock options outstanding during 2000,
however, these stock options were out of the money during the period prior to
their expiration in June 2000.
Note 5 - RESTRICTED DEPOSITS
Pursuant to existing agreements with former property owners and in
accordance with requirements of the U.S. Department of Interior's Minerals
Management Service ("MMS"), the Company has put in place surety bonds and/or
escrow agreements to provide satisfaction of its eventual responsibility to plug
and abandon wells and remove structures when certain fields are no longer in
use. As part of its agreement with the underwriter of the surety bonds, the
Company has established bank trust and escrow accounts in favor of either the
surety bond underwriter or the former owners of the particular fields.
8
PANACO, Inc.
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
In the West Delta Fields and the East Breaks 109 and 110 Fields, the
Company established an escrow for both Fields in favor of the surety bond
underwriter, who provides a surety bond to the former owners of the West Delta
Fields and to the MMS. The balance in this escrow account was $5.2 million at
September 30, 2001 and requires quarterly deposits of $375,000 until June 2003,
decreasing to $125,000 until the account balance reaches $7.8 million.
In the East Breaks 165 and 209 Fields the Company established an escrow
account in favor of the surety bond underwriter, who provides surety bonds to
both the MMS and the former owner of the Fields. The balance in this escrow
account was $4.6 million at September 30, 2001 and requires quarterly deposits
of $250,000 until the account balance reaches $6.5 million.
The Company has also established an escrow account in favor of BP under
which the Company will deposit 10% of the net cash flows from the properties, as
defined in the agreement, from the properties acquired from BP. This escrow
account balance was $0.7 million at September 30, 2001.
Note 6 - 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 plaintiffs' property. Pursuant to the purchase and
sale agreement between PANACO and NEG, NEG is required to indemnify the Company
from any damages attributable to NEG's operations on the property after the
sale.
Pursuant to another purchase and sale agreement, the Company may owe
indemnity to Shell and Exxon, from whom the property was acquired prior to
selling same to NEG. The Company believes that it has insurance coverage for the
claims asserted in the petition, and has notified all insurance carriers that
might provide coverage under its policies. In 1999 NEG filed chapter 11
bankruptcy and emerged in late 2000. Some discovery has occurred in the case,
but 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 other 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 7 - LONG-TERM DEBT
The Company maintains a Credit Facility that is a reducing, revolving loan
and is collateralized by a first mortgage on the Company's properties. The
amount available to the Company under the Credit Facility is determined by a
borrowing base typically based on the estimated value of the properties under
mortgage to the lender, less any amounts borrowed under the Credit Facility. In
October 1999 the Company put in place a new, $60 million Credit Facility with
Foothill Capital Corp. ("Foothill") as the Agent for the lenders. The Foothill
facility had an initial term of two years with two six-month extension options
available at the sole option of the Company. The borrowing base under the
Foothill facility at the expiration of the initial term was $60 million.
9
PANACO, Inc.
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
In November 2001, the Company amended the Foothill facility to, among other
changes, extend the expiration date an additional two years. The new Credit
Facility is a $40 million facility with a borrowing base of $40 million. At
September 30, 2001, $26.1 million was outstanding under the facility, with
availability of $12.7 million, of which $1.3 million was reserved under a letter
of credit. The borrowing base is subject to monthly determinations made using
internally prepared engineering reports, using a two-year average of NYMEX
future commodity prices 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.
The amendment also reduced the interest rates, administrative fees and
servicing fees charged the Company. Interest on the loan is computed at Wells
Fargo's prime rate plus 0.25% to 0.75% or LIBOR plus 2.25% to 2.75%, depending
on the percentage of the facility being used and the pricing option is the
choice of the Company. The loan agreement contains certain covenants including
an EBITDA (as defined in the agreement) to interest expense ratio of at least
2.0 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.
Note 8 - INCOME TAXES
During the second quarter of 2000, the Company determined that it was more
likely than not that its deferred tax assets would be realized. This valuation
was based on several factors, including estimates for future oil and natural gas
prices. Projections of future taxable income were sufficient to utilize all of
the deferred tax assets due to higher commodity prices and reserve additions,
therefore the valuation allowance was removed. The Company performs a review of
the deferred tax asset including the associated utilization estimates for the
asset. The factors considered in the review include historical utilization, tax
planning strategies that may improve the utilization and market conditions at
the time of review. The Company has and is continuing to evaluate tax planning
strategies for utilizing its deferred tax asset including the sale of assets,
when appropriate.
Based on its review during the third quarter of 2001, the Company
determined that it was more likely than not that its deferred tax asset would
not be utilized and reestablished a valuation allowance against the deferred tax
asset. This valuation was due to, among other factors, the significant decrease
in oil and natural gas prices and reduced reserve estimates from the second
quarter of 2000, losses in the prior years, excluding 2000, and current
estimates of results for 2001. 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,
future events, including changes in commodity prices, could result in a
reduction in some or all of the deferred tax asset valuation allowance in future
periods.
Note 9 - ADOPTION OF SFAS 133
On January 1, 2001, the Company adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138. Under
SFAS 133, all derivative instruments are recorded on the balance sheet at fair
value. If the derivative does not qualify as a hedge or is not designated as a
hedge, the gain or loss on the derivative is recognized currently in earnings.
To qualify for hedge accounting, the derivative must qualify either as a fair
value hedge, cash flow hedge or foreign currency hedge. Currently, the Company
10
PANACO, Inc.
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
uses only cash flow hedges and the remaining discussion will relate exclusively
to this type of derivative instrument. If the derivative qualifies for hedge
accounting, the gain or loss on the derivative is deferred in Accumulated Other
Comprehensive Income/Loss, a component of Stockholders' Equity (Deficit), to the
extent the hedge is effective.
The relationship between the hedging instrument and the hedged item must be
highly effective in achieving the offset of changes in cash flows attributable
to the hedged risk both at the inception of the contract and on an ongoing
basis. The Company measures effectiveness on a quarterly basis. Hedge accounting
is discontinued prospectively when a hedge instrument becomes ineffective. Gains
and losses deferred in Accumulated Other Comprehensive Income/Loss related to
cash flow hedges that become ineffective remain unchanged until the related
production is delivered. If the Company determines that it is probable that a
hedged forecasted transaction will not occur, deferred gains or losses on the
hedging instrument are recognized in earnings immediately.
Gains and losses on hedging instruments related to Accumulated Other
Comprehensive Income/Loss and adjustments to carrying amounts on hedged
production are included in natural gas or crude oil production revenues in the
period that the related production is delivered. Gains and losses of hedging
instruments, which represent hedge ineffectiveness and changes in the time value
component of options, are included in Other Income/Loss in the period in which
they occur.
The Company periodically enters into derivative commodity instruments to
hedge its exposure to price fluctuation on natural gas and crude oil production.
At September 30, 2001, the Company had one derivative instrument outstanding, a
natural gas swap. For 2001, the Company entered into an option to put 1,000
barrels of oil per day at $25.00 per barrel to a purchaser through September 30,
2001 for a total of 273,000 barrels. In addition, the Company entered into a
natural gas price swap covering 6.6 Bcf of production for the entire twelve
months of 2001 at an average price of $4.91 per MMBtu. For the period of October
1 through December 31, 2001 the Company's average price for its natural gas swap
is $4.56 per MMBtu.
The Company recognized a $0.3 million increase in earnings, pre-tax, for
the cumulative effect of adopting SFAS 133 on January 1, 2001 and for the nine
months ended September 30, 2001 the Company recognized a $0.3 million decrease
in earnings, pre-tax, related to the decrease in the value of the put option.
For the Company's natural gas swap, on January 1, 2001, in accordance with
the transition provisions of SFAS 133, the Company recorded a loss of $9.9
million in Other Comprehensive Income/Loss representing the cumulative effect of
an accounting change to recognize the fair value of the natural gas swap. The
Company also recorded cash flow hedge derivative liabilities of $9.9 million in
accounts payable and accrued liabilities. During the first nine months of 2001,
the Company realized pre-tax income of $0.1 million on hedging activity incurred
in the first nine months 2001, which were transferred from Other Comprehensive
Income/Loss to natural gas revenues for the production months the hedge related.
The Company also recognized Other Income of $1.1 million, pre-tax, for the
ineffective portion of the natural gas swap. At September 30, 2001 $2.8 million
of deferred net gains on derivative instruments recorded in Other Comprehensive
Income/Loss are expected to be reclassified to earnings during the next twelve
months.
All hedge transactions are subject to the Company's risk management policy
and are approved by the Board of Directors, which does not permit speculative
positions. The Company formally documents all relationships between hedging
instruments and hedged items, as well as its risk management objectives and
11
PANACO, Inc.
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
strategy for undertaking the hedge. This process includes specific
identification of the hedging instrument and the hedge transaction, the nature
of the risk being hedged and how the hedging instrument's effectiveness will be
assessed. Both at the inception of the hedge and on an ongoing basis, the
Company assesses whether the derivatives that are used in hedging transactions
are highly effective in offsetting changes in cash flows of hedged items.
Note 10 - COMPREHENSIVE INCOME
Comprehensive income includes net income and certain items recorded
directly to shareholders' equity and classified as Accumulated Other
Comprehensive Loss. The Company recorded Other Comprehensive Income for the
first time in the first quarter of 2001. On January 1, 2001, upon adoption of
SFAS 133, the Company recorded a charge to Accumulated Other Comprehensive Loss
of $9.9 million for the fair value of the Company's cash flow hedges. The
following table illustrates the calculation of comprehensive income for the nine
months ended September 30, 2001:
Accumulated Other Comprehensive Income (Loss), December 31, 2000 $ --
Net Loss (25,734,000)
Accumulated Other Comprehensive Income
Cumulative effect of change in accounting principle - January 1, 2001 (9,881,000)
Changes in fair value of outstanding hedging positions 13,862,000
Financial derivative settlements transferred from
Accumulated Other Comprehensive Income (1,176,000)
------------
Accumulated Other Comprehensive Income 2,805,000
------------
Comprehensive Income (Loss) $(22,929,000)
============
There were no other items in Comprehensive Income (Loss) during 2001.
12
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
cannot assure you that the actual results 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,
increasing cash flows from operations and to reduce debt, we reinvest cash flows
from operations as capital expenditures or to reduce debt. During the first nine
months of 2001, net cash provided by operating activities totaled $34.3 million,
which, along with cash on hand, was used to fund capital expenditures, net of
property sales, of $32.6 million and for required restricted deposit increases
of $1.8 million. Net capital expenditures of $32.6 million for the first nine
months of 2001 represents a 48% increase over capital expenditures totaling
$22.0 million for the comparable period of 2000. For the year 2001, our Board of
Directors has approved a $45 million capital budget. We believe that cash flows
from operations and availability under our Credit Facility will fund this level
of capital expenditures.
In an attempt to reduce interest costs, we keep as little cash on hand as
possible and apply available cash to our Credit Facility balance. The timing of
receipt of monies due us and the payment of amounts due others also affects our
working capital. These two factors cause us to typically have a working capital
deficit. On September 30, 2001 this working capital deficit totaled $15.9
million. We believe that cash flows from operations and borrowing availability
under our Credit Facility will be sufficient to fund this working capital
deficit in addition to ongoing operations and capital expenditures.
Credit Facility
The primary source of capital beyond discretionary cash flows is our Credit
Facility. The 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 and for acquiring additional oil and natural gas
13
reserves. 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 $60 million Credit Facility with Foothill
Capital Corp. ("Foothill") as the Agent for the lenders. The Foothill facility
had an initial term of two years with two six-month extension options available
at the sole option of the Company. The borrowing base under the Foothill
facility at the expiration of the initial term was $60 million.
In November 2001, we amended the Foothill facility to, among other changes,
extend the expiration date an additional two years. The new Foothill facility is
a $40 million facility with a borrowing base of $40 million. The borrowing base
is subject to monthly determinations made using internally prepared engineering
reports, using a two-year average of NYMEX future commodity prices 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. At
September 30, 2001, $26.1 million was outstanding under the facility, with
availability of $12.7 million, of which $1.3 million was reserved under a letter
of credit. The reduction in the Credit Facility was part of management's focus
on controlling costs and reduces the amount of unused line fees charged by the
lender. Management believes that the $40 million provides the liquidity and
flexibility needed to continue its capital expenditure program and implement our
business strategy.
The amendment also reduced the interest rates, administrative fees and
servicing fees charged the Company. Interest on the loan is computed at Wells
Fargo's prime rate plus 0.25% to 0.75% or LIBOR plus 2.25% to 2.75%, depending
on the percentage of the facility being used and the pricing option is the
choice of the Company. The loan agreement contains certain covenants including
an EBITDA (as defined in the agreement) to interest expense ratio of at least
2.0 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. We were in compliance with the terms of
the Foothill facility on September 30, 2001 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 may also make hedging
decisions to assure a payout of a specific acquisition or development project.
For 2001, we have hedged 18,000 MMBtu per day of natural gas for the entire
year. The hedge is a swap, based on the NYMEX closing prices when the swap was
put in place in November 2000. The swap prices range from a high of $6.415 per
MMBtu in January to a low of $4.485 per MMBtu in October and average $4.914 per
MMBtu for the year. The corresponding settlement prices are based on the last
three trading days on the NYMEX for the month to which the swap prices relate.
If the swap prices are higher than the settlement prices, the counterparty will
pay us the price difference for the total MMBtu hedged for that month. If the
swap prices are less than the settlement prices, we will pay the counterparty
the price difference for the total MMBtu hedged for that month.
14
The Company also purchased an option to put oil to a purchaser at an agreed
upon price. The put option was for 1,000 barrels of oil per day from January 1
through September 30 at a NYMEX price of $25.00 per barrel. The cost of the put
option was $1.00 per barrel, or $365,000.
At September 30, 2001 the fair value of the remaining hedges was a gain of
$3.9 million, pre-tax.
The fair value of commodity hedging instruments is the estimated amount
that we would receive or pay to settle the applicable commodity hedging
instrument at the reporting date, taking into account the difference between
NYMEX prices or index prices at year-end and the contract price of the commodity
hedging instrument. On January 1, 2001, the Company adopted SFAS 133 "Accounting
for Derivative Instruments and Hedging Activities" as amended by SFAS 137 and
SFAS 138. Under SFAS 133, all derivative instruments are recorded on the balance
sheet at fair value. See Note 9 to the Company's Condensed Financial Statements
for a discussion of activities involving derivative financial instruments during
the first nine months of 2001.
We produce and sell natural gas, oil and natural gas liquids. As a result,
our financial results are 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 gains from increases in the
market price of natural gas and oil.
Capital expenditures
Net capital expenditures totaled $32.6 million for the first nine months of
2001, representing a 48% increase over the $22.0 million of capital expenditures
incurred in the comparable period of 2000. The capital expenditures incurred in
2001 were concentrated primarily in four fields in the Gulf of Mexico, as
follows.
In late June 2000, we began a development program in the East Breaks 109
and 110 Fields, with the aid of 3-D seismic, which we purchased in late 1998.
These Fields are in approximately 700 feet of water in the Gulf of Mexico. We
own a 100% working interest in these Fields and are the operator. During the
first nine months of 2001 we spent $14.1 million in continuing the drilling
program in these Fields, $3.8 million of which related to the #A-4 well, an
exploratory well that was not completed and accounted for as exploratory dry
hole expense. The remaining capital was primarily incurred on the #A-13 well
which was completed and began production during the second quarter, in addition
to the #A-7 well, which was completed and began production in late January 2001.
On April 13, 2001 PANACO acquired 100% of West Delta Block 52 for $4
million, before purchase price adjustments to the effective date of the
acquisition, January 1, 2001. The acquisition included approximately 1.1 million
barrels of proved reserves and is contiguous to our existing West Delta Fields.
During the second quarter we spent $3.2 million in capital expenditures, in
addition to the acquisition cost, primarily for the completion of previously
shut-in wells to new gas zones.
PANACO also incurred capital expenditures totaling $9.1 million in the East
Breaks 205 and 161 Fields during the first nine months of 2001. We own a 25%
working interest in the first well, the East Breaks 205 #1 well, which was
drilled and completed during the second quarter. The #1 well, which is operated
by Unocal, was successful and is expected to begin production during the fourth
quarter of 2001. The Block 161 #2 well was spudded during the second quarter and
completed during the third quarter of 2001. This well was also successful and is
expected to begin production during the fourth quarter of 2001. PANACO also owns
a 25% working interest in the Block 161 #2 well.
15
During the third quarter of 2001, we spudded a new well in the Umbrella
Point Field, the State Tract 76 #3 well in which we own a 40% working interest
and are the operator. The State Tract 76 #3 well is an exploratory well which
will test the prolific Deep Vicksburg formation at approximately 15,700 feet.
Based on current estimates, our net dry hole exposure for this well is
approximately $3 million. Through September 30, 2001 we had incurred $2.0
million in net costs in drilling this well. The costs are capitalized pending
determination of proved reserves once the well has reached the targeted depths.
The remaining capital expenditures were incurred primarily on several
properties in which we own smaller interests.
Results of Operations
For the nine months ended September 30, 2001 and 2000:
One of the most significant factors affecting our business is the market
price of oil and natural gas that we produce and sell. In late 1997 and
continuing through early 1999, both oil and natural gas prices were lower than
they had been in the proceeding years. A turnaround was seen in 1999 and through
the first quarter of 2001 where we benefited from a steady increase in realized
prices for both oil and natural gas. Since March 2001, both oil and natural gas
prices have decreased from their highs earlier in 2001.
Revenues
Oil and natural gas sales totaled $63.1 million during the first nine
months of 2001, an increase of $1.2 million, or 2% when compared to the first
nine months of 2000. While both oil and natural gas production decreased in
2001, improved natural gas prices have offset lower oil prices and lower
production.
Production and Prices:
% Increase
2001 2000 (Decrease)
---- ---- ----------
Natural gas production (MMcf) 8,595 10,299 (17%)
Average price per Mcf
excluding hedging $ 5.12 $ 3.71 38%
Average price per Mcf
including hedging $ 5.13 $ 3.68 39%
Oil Production (MBbl) 698 818 (15%)
Average price per Bbl
excluding hedging $ 27.16 $ 29.78 (9%)
Average price per Bbl
including hedging $ 27.16 $ 29.23 (7%)
Both oil and natural gas production decreased when comparing the first nine
months of 2001 to the comparable period of 2000.
The most significant decreases in natural gas production were in the
Umbrella Point Field (1,769 MMcf), East Breaks 160 and 161 Fields (898 MMcf )
and the East Breaks 165 Field (651 MMcf), which were due primarily to natural
declines in the production from those fields. In addition, naturally declining
production and the sale of the High Island 309 and 310 Fields (808 MMcf) during
the second quarter of 2001 contributed to the decreased production. Those
declines were somewhat offset by increases in the East Breaks 109 and 110 Fields
16
(2,192 MMcf) and the West Delta Fields (923 MMcf), a focal point for part of our
2001 capital expenditure program.
Likewise, oil production has decreased from the East Breaks 165 Field (124
Mbbl) and East Breaks 160 and 161 Fields (47 Mbbl) due to lower capital
expenditures in those fields and the rapid production declines from the wells in
those fields, which are inherent in the areas that we operate. The bulk of the
capital expenditures in 2001 are for projects that should produce natural gas,
rather than oil.
We also recognized a gain of $4.0 million on the sale of an oil and natural
gas property during the second quarter of 2001. We sold PANACO's entire interest
in High Island Blocks 309 and 310 to the operator of the fields for cash, the
assumption of a gas imbalance liability and the dismissal of a lawsuit the
operator had filed against us for non-payment of invoices. The property sale was
completed on June 29, 2001.
Cost and Expenses
Lease operating expenses increased $4.1 million, to $20.5 million, during
the first nine months of 2001 compared to $16.4 million in 2000. On an Mcf
equivalent ("Mcfe") basis, lease operating expenses also increased to $1.60 in
2001 from $1.08 in 2000. During 2001, we have spent a significant amount of
capital for repairs and maintenance of PANACO's offshore platforms, which, due
to the nature of the work, are expensed as incurred. Some of these expenses are
required by the regulatory agencies in the Gulf of Mexico. We expect this
program to continue throughout 2001, specifically in the East Breaks area of the
Gulf of Mexico, where we own 3 platforms. Total repair and workover expenses for
the first nine months of 2001 was $7.6 million, compared to $5.2 million during
2000. These projects include production equipment repairs and workover or
cleanout of productive zones in well bores. Excluding these amounts, lease
operating expenses per Mcfe were $1.01 and $0.73 for the first nine months of
2001 and 2000, respectively.
Depletion, depreciation and amortization ("DD&A") increased 19%, or $3.9
million primarily due to a 42% increase in DD&A per unit of production, which
was offset by a 16% decrease in total production. The higher cost per unit
relates primarily to an increase in the cost per Mcfe of production from the
East Breaks 109 and 110 Fields along with increased production from those
Fields.
Exploratory dry hole expense increased to $4.6 million primarily due to the
unsuccessful #A-4 well drilled during the first quarter of 2001 in the East
Breaks 109 and 110 Fields.
Geological and geophysical expense decreased $0.4 million primarily due to
3-D Seismic purchases and land rentals incurred during 2000 that were not
included in 2001 spending.
During the second and third quarters of 2001, PANACO recognized impairments
for both proved and unproved oil and natural gas properties. The unproved
property impairment was based on our decision to not further develop potential
reserves based on the significant capital required to develop the field and the
low potential to be realized based on numerous evaluations made by PANACO and
other partners in the field. Also, due to reductions in future reserve estimates
by our third party engineers, and the resulting lower future net cash flows from
certain fields, we were required to impair non-core proved properties.
Interest expense decreased $2.0 million due to lower weighted average
borrowing levels during 2001 in addition to lower interest rate for our Credit
Facility, which is based on the prime rate.
Other income increased $0.8 million and is made up of the adoption of SFAS
No. 133, including a gain on the ineffective portion of a natural gas swap and
the mark-to-market of an option to put oil to a purchaser.
17
Income Tax Expense (Benefit)
As oil and natural gas prices increased during 2000, we were able to
project future taxable income sufficient to utilize our net operating loss
carry-forwards. As such, during the second quarter of 2000 we recorded an income
tax benefit of $29 million by reversing a valuation allowance recorded against
these assets. From that point forward until the second quarter of 2001, income
tax expense has been recognized, at the effective rate, as a percentage of
pre-tax income.
The analysis of the deferred tax asset utilization made during the second
quarter of 2000 determined that it was more likely than not that the deferred
tax assets would be realized. This determination was based on several factors,
including current projections of future taxable income. This analysis also
included current estimates for future oil and natural gas prices in addition to
recent reserve additions. Projections of future taxable income were sufficient
to utilize all of the deferred tax assets due to higher commodity prices and
reserve additions, therefore the valuation allowance was removed. With the
decrease in oil and natural gas prices and reserve estimates since the second
quarter of 2000, management's estimates of future taxable income had decreased
to a point in which it was more likely than not that none of its deferred tax
asset would be utilized. Based on this analysis and all other evidence available
at the time, the valuation allowance was reestablished against the deferred tax
asset.
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, future events, including changes in commodity
prices, could result in a reduction in some or all of the deferred tax asset
valuation allowance in future periods. PANACO also evaluates tax planning
strategies and utilizes them when available in order to utilize our deferred tax
assets and minimize income taxes. During 2001 this evaluation included the
potential sales of assets which would have resulted in significant gains which
would have been offset by the deferred tax asset. While there is no sale
imminent, we are continually evaluating our options.
Net Income (Loss)
Although total revenues increased 7%, to $67.0 million, a property
impairment of $6.9 million, an increase in exploratory dry hole expense of $3.8
million and the increase in the deferred tax valuation allowance of $22.9
million during 2001 along with an income tax net benefit of $26.3 million
recognized during 2000, were the primary factors in a decrease of $59.1 million
in net income and a $2.43 per share decrease in net income per share.
18
Results of Operations
For the three months ended September 30, 2001 and 2000:
Revenues
Oil and natural gas sales totaled $16.7 million during the third quarter of
2001, a decrease of $8.2 million, or 33%, when compared to the third quarter of
2000.
Production and Prices:
% Increase
2001 2000 (Decrease)
---- ---- -----------
Natural gas production (MMcf) 2,576 3,635 (29%)
Average price per Mcf
excluding hedging $ 2.95 $ 4.53 (35%)
Average price per Mcf
including hedging $ 3.93 $ 4.51 (13%)
Oil Production (MBbl) 249 277 (10%)
Average price per Bbl
excluding hedging $ 26.43 $ 31.45 (16%)
Average price per Bbl
including hedging $ 26.43 $ 30.81 (14%)
Both oil and natural gas production decreased when comparing the third
quarter of 2001 to the comparable period of 2000.
The most significant decreases in natural gas production were in the
Umbrella Point Field (630 MMcf), the Price Lake Field (320 MMcf) East Breaks 160
and 161 Fields (316 MMcf ) and the East Breaks 165 Field (252 MMcf) were due
primarily to natural declines in the respective production from those fields.
Those declines were somewhat offset by increases in the East Breaks 109 and 110
Fields (849 MMcf) and the West Delta Fields (179 MMcf), both a primary focus of
our current capital expenditure program. Likewise, oil production has decreased
from the East Breaks 165 Field (31 Mbbl) and East Breaks 160 and 161 Fields (14
Mbbl) due to lower capital expenditures in those fields and the rapid production
declines from the wells in those fields, which are inherent in the areas that we
operate.
Cost and Expenses
Lease operating expenses increased $1.2 million, to $7.5 million, during
the third quarter of 2001 compared to $6.3 million in 2000. The West Delta Block
52 Field, which was purchased in April 2001, added $0.8 million of additional
lease operating expenses, when compared to the third quarter of 2000. On an Mcfe
basis, lease operating expenses also increased to $1.85 in 2001, from $1.19 in
2000.
Depletion, depreciation and amortization ("DD&A") increased 13%, or $1.0
million primarily due to a 48% increase in DD&A per unit of production and was
offset by a 23% decrease in total production. The higher cost per unit relates
primarily due to an increase in the cost per Mcfe of production from the East
Breaks 109 and 110 Fields along with increased production from those Fields.
19
As part of our regular review of proved property carrying values and
estimated recoverability of those values, during the third quarter of 2001,
PANACO recognized an impairment of two proved oil and natural gas properties.
The impairments were due primarily to reductions in estimated prices for oil and
natural gas production.
Interest expense decreased $0.6 million due to lower weighted average
borrowing levels during 2001 in addition to lower interest rate for our Credit
Facility, which is based on the prime rate.
Other income increased $0.1 million and is made up of the impact of SFAS
No. 133, including a gain on the ineffective portion of a natural gas swap and
the mark-to-market of an option to put oil to a purchaser.
Income Tax Expense (Benefit)
As oil and natural gas prices increased during 2000, we were able to
project future net income sufficient to utilize our net operating loss
carry-forwards. As such, during the second quarter of 2000 we recorded an income
tax benefit of $29 million by reversing a valuation allowance recorded against
these assets. From that point forward until the second quarter of 2001, income
tax expense has been recognized, at the effective rate, as a percentage of
pre-tax income.
The analysis of the deferred tax asset utilization made during the second
quarter of 2000 determined that it was more likely than not that the deferred
tax assets would be realized. This determination was based on several factors,
including current projections of future taxable income. This analysis also
included current estimates for future oil and natural gas prices in addition to
recent reserve additions. Projections of future taxable income were sufficient
to utilize all of the deferred tax assets due to higher commodity prices and
reserve additions, therefore the valuation allowance was removed. With the
decrease in oil and natural gas prices and reserve estimates since the second
quarter of 2000, management's estimates of future taxable income had decreased
to a point in which it was more likely than not that none of its deferred tax
asset would be utilized. Based on this analysis and all other evidence available
at the time, the valuation allowance was reestablished against the deferred tax
asset.
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, future events, including changes in commodity
prices, could result in a reduction in some or all of the deferred tax asset
valuation allowance in future periods. During 2001 this evaluation included the
potential sales of assets which would have resulted in significant gains which
would have been offset by the deferred tax asset. While there is no sale
imminent, we are continually evaluating our options.
Net Income (Loss)
A decrease in total revenues of $8.2 million, in addition to an increase in
income tax expense of $20.7 million, were the primary factors in a $29.1 million
decrease in net income and $1.20 decrease in net income per share from the third
quarter of 2000 to the third quarter of 2001.
Outlook
As a relatively small, leveraged oil and natural gas exploration and
production company, the success and outcome of our business are highly dependent
on oil and natural gas prices. Not only are our revenues, cash flows, results of
operations and liquidity impacted by commodity prices, our ability to obtain
financing for our business is also influenced by these prices. The nature of our
20
business is capital intensive, typically requiring an investment up front and a
resulting return on that investment. The resulting return and success of that
investment will vary depending on the prices we receive for the oil and natural
gas. Also, due to the geographic area that we operate in, the levels of capital
spending are significant and the lives of the reserves that we own are
relatively short. Historically, our reserves have a five to seven year life,
which tends to amplify oil and natural gas price fluctuations on our Company.
For fiscal 2001, the Board of Directors has approved a $45 million capital
budget. This budget includes approximately $21.5 million of exploratory
projects, the majority of which has been spent at the East Breaks 109 and 110
Fields. While this level of exploratory spending is higher than in previous
years, based on current seismic and drilling technology, we feel that these
projects are also lower risk than the exploratory projects we have historically
participated in.
Other 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 plaintiffs' property. Pursuant to the purchase and
sale agreement between PANACO and NEG, NEG is required to indemnify us from any
damages attributable to NEG's operations on the property after the sale.
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 that we have insurance coverage for the claims asserted in the
petition, and have notified all insurance carriers that might provide coverage
under our policies. In 1999 NEG filed for chapter 11 bankruptcy and emerged in
late 2000. 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.
PART I
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 may also make hedging
decisions to assure a payout of a specific acquisition or development project.
For 2001, we have hedged 18,000 MMBtu per day of natural gas for the entire
year. The hedge is a swap, based on the NYMEX closing prices when the swap was
put in place in November 2000. The swap prices range from a high of $6.415 per
MMBtu in January to a low of $4.485 per MMBtu in October and average $4.914 per
MMBtu for the year. The average price of this swap for July 1 through December
31, 2001 is $4.54 per MMBtu. The corresponding settlement prices are based on
the last three trading days on the NYMEX for the month to which the swap prices
relate. If the swap prices are higher than the settlement prices, the
counterparty will pay us the price difference for the total MMBtu hedged for
that month. If the swap prices are less than the settlement prices, we will pay
the counterparty the price difference for the total MMBtu hedged for that month.
21
We have also purchased an option to put oil to a purchaser at an agreed
upon price. The put option is for 1,000 barrels of oil per day from January 1
through September 30 at a NYMEX price of $25.00 per barrel. The cost of the put
option was $1.00 per barrel, or $365,000.
At September 30, 2001 the fair value of these hedges was a gain of $3.9
million, pre-tax.
The fair value of our commodity hedging instruments is the estimated amount
that we would receive or pay to settle the applicable commodity hedging
instrument at the reporting date, taking into account the difference between
NYMEX prices or index prices at year-end and the contract price of the commodity
hedging instrument.
PART II OTHER INFORMATION
Item 6.
EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
None.
(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: November 13, 2001 /s/ Todd R. Bart
------------------------ -------------------------------------
Todd R. Bart, Chief Financial Officer