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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, 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 June 30, 2001.
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Item 1.
FINANCIAL INFORMATION
PANACO, Inc.
Condensed Balance Sheets
ASSETS
As of As of
June 30, 2001 December 31, 2000
---------------- ------------------
(Unaudited)
CURRENT ASSETS
Cash $ 1,458,000 $ 2,878,000
Accounts receivable, net of an allowance of
$303,000 and $554,000, respectively 15,465,000 17,680,000
Accounts receivable-related party - 300,000
Prepaid and other 1,938,000 907,000
-------------- ---------------
Total current assets 18,861,000 21,765,000
-------------- ---------------
OIL AND GAS PROPERTIES, AS DETERMINED BY THE
SUCCESSFUL EFFORTS METHOD OF ACCOUNTING
Oil and gas properties, proved 272,608,000 289,892,000
Less proved property accumulated depletion,
depreciation and amortization (166,137,000) (193,135,000)
Net unproved oil and gas properties 1,905,000 2,888,000
-------------- ---------------
Net oil and gas properties 108,376,000 99,645,000
-------------- ---------------
PIPELINES AND EQUIPMENT
Pipelines and equipment 26,523,000 26,409,000
Less accumulated depreciation (9,588,000) (8,256,000)
-------------- ---------------
Net pipelines and equipment 16,935,000 18,153,000
-------------- ---------------
OTHER ASSETS
Restricted deposits 9,926,000 8,625,000
Deferred debt costs, net 2,199,000 3,128,000
Deferred income taxes 22,230,000 22,763,000
-------------- ---------------
Total other assets 34,355,000 34,516,000
-------------- ---------------
TOTAL ASSETS $ 178,527,000 $ 174,079,000
============== ===============
(continued)
The accompanying notes are an integral part of this statement.
2
PANACO, Inc.
Condensed Balance Sheets
LIABILITIES AND STOCKHOLDERS' EQUITY
As of As of
June 30, 2001 December 31, 2000
--------------- ------------------
(Unaudited)
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 36,309,000 $ 31,963,000
Interest payable 2,809,000 2,917,000
Gas imbalance payable 1,007,000 2,860,000
Restricted cash payable - 629,000
Deferred income taxes 1,127,000 -
------------- -------------
Total current liabilities 41,252,000 38,369,000
------------- -------------
DEFERRED CREDITS 1,683,000 1,609,000
LONG-TERM DEBT 120,352,000 121,693,000
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
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 (55,941,000) (56,815,000)
Accumulated other comprehensive income 1,845,000 -
------------- -------------
Total stockholders' equity 15,240,000 12,408,000
------------- -------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 178,527,000 $ 174,079,000
============= =============
The accompanying notes are integral part of this statement.
3
PANACO, Inc.
Statements of Operations
For the Six Months Ended June 30,
(Unaudited)
2001 2000
---------- ----------
REVENUES
Oil and natural gas sales $ 46,373,000 $ 36,900,000
Gain on property sales 3,967,000 -
Lawsuit recovery - 990,000
------------ ------------
Total 50,340,000 37,890,000
COSTS AND EXPENSES
Lease operating expense 12,914,000 10,076,000
Depletion, depreciation & amortization 15,341,000 12,457,000
General and administrative expense 2,436,000 2,300,000
Production and ad valorem taxes 890,000 965,000
Exploratory dry hole expense 4,590,000 447,000
Geological and geophysical expense 599,000 852,000
Impairment of oil and gas properties 6,542,000 -
------------- ------------
Total 43,312,000 27,097,000
------------- ------------
OPERATING INCOME 7,028,000 10,793,000
OTHER INCOME (EXPENSE)
Interest income 301,000 74,000
Interest expense (6,459,000) (7,836,000)
Other income 656,000 -
------------- ------------
Total (5,502,000) (7,762,000)
------------- ------------
INCOME BEFORE INCOME TAXES 1,526,000 3,031,000
INCOME TAX EXPENSE (BENEFIT) 652,000 (27,824,000)
------------- ------------
NET INCOME $ 874,000 $ 30,855,000
============= ============
BASIC AND DILUTED NET INCOME PER SHARE $ 0.04 $ 1.28
============= ============
Basic Shares Outstanding 24,339,709 24,199,461
============= ============
Diluted Shares Outstanding 24,617,330 24,199,461
============= ============
The accompanying notes are integral part of this statement.
4
PANACO, Inc.
Consolidated Statements of Operations
For the Three Months Ended June 30,
(Unaudited)
2001 2000
--------- ---------
REVENUES
Oil and natural gas sales $ 20,057,000 $ 21,280,000
Gain on property sales 3,967,000 -
Lawsuit recovery - 990,000
------------ ------------
24,024,000 22,270,000
COSTS AND EXPENSES
Lease operating expense 7,609,000 5,885,000
Depletion, depreciation & amortization 8,310,000 6,746,000
General and administrative expense 1,365,000 1,316,000
Production and ad valorem taxes 408,000 706,000
Exploratory dry hole expense 733,000 127,000
Geological and geophysical expense 302,000 551,000
Impairment of oil and gas properties 6,542,000 -
------------ ------------
Total 25,269,000 15,331,000
------------ ------------
OPERATING INCOME (LOSS) (1,245,000) 6,939,000
OTHER INCOME (EXPENSE)
Interest income 76,000 21,000
Interest expense (3,115,000) (4,182,000)
Other income 277,000 -
------------ ------------
Total (2,762,000) (4,161,000)
------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES (4,007,000) 2,778,000
INCOME TAX EXPENSE (BENEFIT) (1,515,000) (27,861,000)
------------ ------------
NET INCOME (LOSS) $ (2,492,000) $ 30,639,000
============ ============
BASIC AND DILUTED NET INCOME (LOSS) PER SHARE $ (0.10) $ 1.26
============ ============
Basic Shares Outstanding 24,355,720 24,323,521
============ ============
Diluted Shares Outstanding 24,355,720 24,323,521
============ ============
The accompanying notes are integral part of this statement.
5
PANACO, Inc.
Statement of Cash Flows
For the Six Months Ended June 30,
(Unaudited)
2001 2000
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 874,000 $ 30,855,000
Adjustments to reconcile net income to net cash
provided by operating activities:
Deferred income taxes 533,000 (27,824,000)
Depletion, depreciation and amortization 15,341,000 12,457,000
Impairment of oil and gas properties 6,542,000 -
Exploratory dry hole expense 4,590,000 447,000
Gain on property sales (3,967,000) -
Plug and abandoning of wells and platforms (3,676,000) -
Changes in assets and liabilities:
Accounts receivable 6,018,000 (6,932,000)
Accounts payable 5,184,000 1,161,000
Gas imbalance payable (490,000) 681,000
Deferred credits 74,000 625,000
Interest payable (108,000) 56,000
Accounts receivable-related party 300,000 -
Changes relating to derivative instruments (863,000) -
Prepaid and other (1,547,000) (570,000)
------------- -------------
Net cash provided by operating activities 28,805,000 10,956,000
------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the sale of oil and gas properties 2,843,000 -
Capital expenditures and acquisitions (30,357,000) (12,520,000)
Increase in restricted deposits (1,301,000) (1,500,000)
------------- -------------
Net cash used in investing activities (28,815,000) (14,020,000)
------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES
Long-term debt borrowings 10,000,000 10,349,000
Repayment of long-term debt (11,341,000) (11,000,000)
Additional deferred financing costs (70,000) (354,000)
------------- -------------
Net cash used in financing activities (1,411,000) (1,005,000)
------------- -------------
NET DECREASE IN CASH (1,420,000) (4,069,000)
CASH AT BEGINNING OF YEAR 2,878,000 5,575,000
------------- -------------
CASH AT JUNE 30 $ 1,458,000 $ 1,506,000
============= =============
The accompanying notes are 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 June 30, 2001 and December 31, 2000 and the
results of its operations and cash flows for the periods ended June 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 has 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 quarter of 2000 revenues, depletion, depreciation and amortization
and net income were $63,000, $(35,000) and $98,000, respectively. The
adjustments to the second quarter of 2000 revenues, depletion, depreciation and
amortization and net income were $(744,000), $(60,000) and $(425,000),
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 an asset impairment during the second quarter of
2001 totaling $6.5 million, relating to both proved and unproved properties.
Based on the decision by the Company to discontinue development of potential
reserves, discovered in 1998, the Company recorded an impairment of $1.1 million
for the capital incurred in discovering those reserves. In addition, in
connection with the Company's regular review of the recoverability of its proved
reserves' carrying values, an impairment was recorded based on reserve and price
reductions for three properties which the Company considers non-core. The proved
property impairment totaled $5.4 million and was also recognized during the
second quarter of 2001.
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 $6.6 million and $7.9 million during the
first six months of 2001 and 2000, respectively. The Company did not make any
cash payments for income taxes during the first six months of 2001 or 2000.
Note 4 - EARNINGS PER SHARE CALCULATIONS
Basic earnings per share for the first six months of each year were based
on the year-to-date weighted average share outstanding of 24,339,709 in 2001 and
24,199,461 for 2000. The diluted earnings per share amounts are based on
weighted average share outstanding plus in the money common stock equivalents,
which consists of stock options outstanding and totaled 277,621 in 2001 and 0 in
2000. The Company had stock options outstanding during the first six months of
2000, which were out of the money during all of 2000 and expired 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 $4.8 million at
June 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 $4.4 million at June 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 June 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
In October 1999 the Company put in place a new Credit Facility. The loan is
a reducing revolver, which provides the Company with up to $60 million,
depending on the borrowing base. The Company's borrowing base at June 30, 2001
was $60 million, with availability of $32.5 million, of which, $1.8 million was
reserved by a letter of credit. The principal amount of the loan is due October
1, 2001, and may be extended for two additional six-month periods, at the sole
option of the Company. The Company is evaluating its alternatives regarding this
facility, including extension of this facility or replacing it with a bank
facility.
9
PANACO, Inc.
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
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 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.
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
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. 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. While utilization estimates are important, they are not the sole factor.
The Company is evaluating several tax planning strategies that would potentially
provide utilization of its deferred tax assets including the sale of properties,
which would result in potentially significant gains.
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 events, including a
decrease in commodity prices, could result in a reduction in some or all of the
deferred tax assets in a future period.
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
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, 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
10
PANACO, Inc.
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
hedged forecast 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 June 30, 2001, the Company had two derivative instruments: an option to put
oil to a purchaser and a natural gas swap. For 2001, the Company has 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 had entered into a natural gas price swap covering 6.6 Bcf
of production for 2001 at an average price of $4.91 per MMBtu. For the period of
July 1 through December 31, 2001 the Company's average price for its natural gas
swap is $4.54 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 on June 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 an after-tax loss of
$6.1 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 six months
of 2001, the Company realized after tax losses of $1.5 million on hedging
activity incurred in the first six 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 $0.5
million, after tax, for the ineffective portion of the natural gas swap. At June
30, 2001 $1.8 million, net of tax, 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
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
11
PANACO, Inc.
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
SFAS 133, the Company recorded an after-tax charge to Accumulated Other
Comprehensive Loss of $6.1 million for the fair value of the Company's cash flow
hedges. The following table illustrates the calculation of comprehensive income
for the six months ended June 30, 2001:
Accumulated Other Comprehensive Income, December 31, 2000 $ --
Net Income 874,000
Accumulated Other Comprehensive Income (net of tax)
Cumulative effect of change in accounting principle - January 1, 2001 (6,134,000)
Changes in fair value of outstanding hedging positions 7,017,000
Financial derivative settlements transferred from
Accumulated Other Comprehensive Income 962,000
------------
Accumulated Other Comprehensive Income 1,845,000
------------
Comprehensive Income $ 2,719,000
============
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 six
months of 2001, net cash provided by operating activities totaled $28.8 million,
which, along with cash on hand, was used to fund capital expenditures, net of
property sales, of $26.1 million, for required restricted deposit increases of
$1.3 million and to reduce debt by $1.4 million. Net capital expenditures of
$26.1 million for the first six months of 2001 represents a 109% increase over
capital expenditures totaling $12.5 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 June 30, 2001 this working capital deficit totaled $22.4 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 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
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. On June 30, 2001, $18.1 was outstanding under the Credit Facility, a
decrease of $1.3 million during the first six months of 2001. We are evaluating
the alternatives available regarding the Credit Facility, including extension of
this facility or replacing it with a bank facility.
The Credit Facility is a revolving credit agreement subject to monthly
borrowing base determinations. These determinations are 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.
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, paying dividends or repurchasing the Company's
stock. We were in compliance with all covenants on June 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.
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 June 30, 2001 the fair value of these hedges was a gain of $3.8 million,
pre-tax.
14
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 six 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 $26.1 million for the first six months of
2001, representing a 109% increase over the $12.5 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 six months of 2001 we spent $15.3 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 $3.3 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 $5.0 million in the East
Breaks 205 and 161 Fields during the second quarter 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.
During the first six months of 2001 we spent $1.5 million for continued
development and exploitation of the West Delta Fields, located offshore
Louisiana, in Plaquemines Parish. We operate the West Delta Fields and generally
own a 100% working interest in the wells. These capital expenditures were
incurred in completing two new wells in Block 54 in addition to spudding the
recompletion of a currently shut-in well to new zones.
15
The remaining capital expenditures were incurred primarily on several
properties in which we own smaller interests.
Results of Operations
For the six months ended June 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, natural gas prices have
decreased from their highs in January 2001.
Revenues
Oil and natural gas sales totaled $46.4 million during the first six months
of 2001, an increase of $9.5 million, or 26% when compared to the first six
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) 6,019 6,664 (10%)
Average price per Mcf
excluding hedging $ 6.05 $ 3.26 86%
Average price per Mcf
including hedging $ 5.65 $ 3.23 75%
Oil Production (MBbl) 449 541 (17%)
Average price per Bbl
excluding hedging $ 27.56 $ 28.92 (5%)
Average price per Bbl
including hedging $ 27.56 $ 28.42 (3%)
Both oil and natural gas production decreased when comparing the first six
months of 2001 to the comparable period of 2000.
The most significant decreases in natural gas production were in the
Umbrella Point Field (1,139 MMcf), High Island 309 and 310 Fields (566 MMcf) and
the East Breaks 160 and 161 Fields (583 MMcf), which were due primarily to
natural declines in the production from those fields. Those declines were
somewhat offset by increases in the East Breaks 109 and 110 Fields (1,343 MMcf)
and the West Delta Fields (745 MMcf), the primary focus of our current capital
expenditure program. Likewise, oil production has decreased from the East Breaks
165 Field (92 Mbbl) and East Breaks 160 and 161 Fields (32 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
16
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 $2.8 million, to $12.9 million, during
the first six months of 2001 compared to $10.1 million in 2000. On an Mcf
equivalent ("Mcfe") basis, lease operating expenses also increased to $1.48 in
2001 from $1.02 in 2000. During 2001, we have spent a large amount of capital
for repairs and maintenance of PANACO's offshore platforms, a large portion of
which has been 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 six months of 2001 was $5.1 million, compared to $2.4
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 $0.90 and $0.77 for the first six months
of 2001 and 2000, respectively.
Depletion, depreciation and amortization ("DD&A") increased 23%, or $2.9
million primarily due to a 37% increase in DD&A per unit of production, which
was offset slightly by a 12% 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.
Exploratory dry hole expense increased $4.1 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 $0.3 million primarily due to
3-D Seismic purchases and land rentals incurred during 2000 that were not
included in 2001 spending.
During the second quarter of 2001, PANACO recognized an impairment for an
unproved oil and natural gas property and three proved 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 three non-core proved properties.
Interest expense decreased $1.3 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 $0.7 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.
Income Tax Expense
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, income tax expense has been recognized,
at the effective rate, as a percentage of pre-tax income.
During the second quarter of 2000, we 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
17
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. We perform 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. While utilization
estimates are important, they are not the sole factor. We are evaluating several
tax planning strategies that would potentially provide utilization of the
deferred tax assets including the sale of properties, which would result in
potentially significant gains.
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 net
deferred tax assets in a future period.
Net Income
Although total revenues increased 33%, to $50.3 million, a property
impairment of $6.5 million recognized during the second quarter of 2001 and an
income tax benefit of $27.8 million recognized during the second quarter of 2000
were the primary factors in a decrease of $30 million in net income and a $1.24
per share decrease in net income per share.
Results of Operations
For the three months ended June 30, 2001 and 2000:
Revenues
Oil and natural gas sales totaled $20.1 million during the second quarter
of 2001, a decrease of $1.2 million, or 6%, when compared to the second quarter
of 2000.
Production and Prices:
% Increase
2001 2000 (Decrease)
---- ---- ----------
Natural gas production (MMcf) 2,955 3,541 (17%)
Average price per Mcf
excluding hedging $ 4.86 $ 3.78 29%
Average price per Mcf
including hedging $ 4.78 $ 3.76 27%
Oil Production (MBbl) 223 275 (19%)
Average price per Bbl
excluding hedging $ 26.65 $ 29.65 (10%)
Average price per Bbl
including hedging $ 26.65 $ 28.95 (8%)
Both oil and natural gas production decreased when comparing the second
quarter of 2001 to the comparable period of 2000.
18
The most significant decreases in natural gas production were in the
Umbrella Point Field (669 MMcf), the East Breaks 165 Field (216 MMcf ) and the
East Breaks 160 and 161 Fields (332 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 (711MMcf) and the West
Delta Fields (187 MMcf), the primary focus of our current capital expenditure
program. Likewise, oil production has decreased from the East Breaks 165 Field
(42 Mbbl) and East Breaks 160 and 161 Fields (19 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 $1.7 million, to $7.6 million, during
the second quarter of 2001 compared to $5.9 million in 2000. On an Mcf
equivalent ("Mcfe") basis, lease operating expenses also increased to $1.77 in
2001 from $1.13 in 2000. During 2001, we have spent a large amount of capital
for repairs and maintenance of PANACO's offshore platforms, a large portion of
which has been 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. Repair and workover
expenses for the second quarter of 2001 totaled $3.8 million, compared to $1.7
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 $0.88 and $0.80 for the second quarter of
2001 and 2000, respectively.
Depletion, depreciation and amortization ("DD&A") increased 23 %, or $1.6
million primarily due to a 49% increase in DD&A per unit of production, which
was offset slightly by a 17% 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.
Exploratory dry hole expense increased $0.6 million due to the bottom zones
of the #A-13 well at our East Breaks 110 Field. Although it was successful, the
costs associated with the bottom portion of the well were written off as they
did not contain hydrocarbons.
Geological and geophysical expense decreased $0.3 million primarily due to
3-D Seismic purchases and land rentals incurred during 2000 that were not
included in 2001 spending.
During the second quarter of 2001, PANACO recognized an impairment for an
unproved oil and natural gas property and three proved 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 the book values of three non-core proved properties.
19
Interest expense decreased $1.1 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 $0.3 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.
Income Tax Expense
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, income tax expense has been recognized,
at the effective rate, as a percentage of pre-tax income.
During the second quarter of 2000, we 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. We perform 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. While utilization
estimates are important, they are not the sole factor. We are evaluating several
tax planning strategies that would potentially provide utilization of the
deferred tax assets including the sale of properties, which would result in
potentially significant gains.
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 net
deferred tax assets in a future period.
Net Income (Loss)
Although total revenues increased 8%, to $24.0 million, a property
impairment of $6.5 million recognized during 2001 and an income tax benefit of
$27.9 million recognized during 2000 were the primary factors in a decrease of
$33.1 million in net income, to a loss of $2.5 million, and a $1.36 per share
decrease in net income per share, to a loss of $0.10 per share.
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
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.
20
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.
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 June 30, 2001 the fair value of these hedges was a gain of $3.8 million,
pre-tax.
21
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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On June 12, 2001, the Company held its 2001 Annual Meeting of Shareholders.
At such time the following items were submitted to a vote of security holders.
Such matters were submitted to the security holders through the solicitation of
proxies.
1. Election of Class III Directors.
The following persons were elected to serve on the Board of Directors until
the 2004 Annual Meeting of Shareholders or until their successors have been duly
elected and qualified. The Directors received the votes set forth opposite their
respective names:
Name For Withheld
James B. Kreamer 21,875,204 248,753
Robert G. Wonish 21,774,911 349,046
George W. Hebard, III 20,544,721 1,579,236
22
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: August 13, 2001 /s/ Todd R. Bart
--------------------- -------------------------------------
Todd R. Bart, Chief Financial Officer
23