- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
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 March 31, 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 _______.
24,323,521 shares of the registrant's $.01 par value Common Stock were
outstanding on March 31, 2001.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
PART I. Item 1.
FINANCIAL INFORMATION
PANACO, Inc.
Condensed Balance Sheets
ASSETS
As of As of
March 31, 2001 December 31, 2000
------------------- --------------------
CURRENT ASSETS (Unaudited)
Cash $ 5,427,000 $ 2,878,000
Accounts receivable, net of an allowance of
$110,000 and $554,000, respectively 13,276,000 17,680,000
Accounts receivable-related party - 300,000
Prepaid and other 535,000 907,000
Deferred income taxes 1,276,000 -
------------------- ------------------
Total current assets 20,514,000 21,765,000
------------------- ------------------
OIL AND GAS PROPERTIES, AS DETERMINED BY THE
SUCCESSFUL EFFORTS METHOD OF ACCOUNTING
Oil and gas properties, proved 296,746,000 289,892,000
Less proved property accumulated depletion,
depreciation and amortization (199,009,000) (193,135,000)
Net unproved oil and gas properties 2,930,000 2,888,000
------------------- ------------------
Net oil and gas properties 100,667,000 99,645,000
------------------- ------------------
PIPELINES AND EQUIPMENT
Pipelines and equipment 26,507,000 26,409,000
Less accumulated depreciation (8,926,000) (8,256,000)
------------------- ------------------
Net pipelines and equipment 17,581,000 18,153,000
-------------------- ------------------
OTHER ASSETS
Restricted deposits 9,548,000 8,625,000
Deferred debt costs, net 2,660,000 3,128,000
Deferred income taxes 20,596,000 22,763,000
------------------- ------------------
Total other assets 32,804,000 34,516,000
------------------- ------------------
TOTAL ASSETS $ 171,566,000 $ 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
March 31, 2001 December 31, 2000
------------------- --------------------
CURRENT LIABILITIES (Unaudited)
Accounts payable and accrued liabilities $ 30,829,000 $ 31,963,000
Interest payable 5,442,000 2,917,000
Gas imbalance payable 3,485,000 2,860,000
Restricted cash payable - 629,000
------------------ -------------------
Total current liabilities 39,756,000 38,369,000
------------------ -------------------
DEFERRED CREDITS 1,771,000 1,609,000
LONG-TERM DEBT 116,355,000 121,693,000
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;
24,323,521 shares issued and outstanding 246,000 246,000
Additional paid-in capital 68,977,000 68,977,000
Accumulated deficit (53,449,000) (56,815,000)
Accumulated other comprehensive loss (2,090,000) -
------------------ ------------------
Total stockholders' equity 13,684,000 12,408,000
------------------ ------------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 171,566,000 $ 174,079,000
================== ==================
The accompanying notes are integral part of this statement.
3
PANACO, Inc.
Statements of Operations
For the Three Months Ended March 31,
(Unaudited)
2001 2000
------------ ------------
REVENUES
Oil and natural gas sales $ 26,316,000 $ 15,619,000
COSTS AND EXPENSES
Lease operating expense 5,305,000 4,191,000
Depletion, depreciation & amortization 7,032,000 5,711,000
General and administrative expense 1,071,000 984,000
Production and ad valorem taxes 481,000 259,000
Exploratory dry hole expense 3,858,000 320,000
Geological and geophysical expense 297,000 301,000
----------------- -----------------
Total 18,044,000 11,766,000
----------------- -----------------
OPERATING INCOME 8,272,000 3,853,000
OTHER INCOME (EXPENSE)
Interest income 226,000 54,000
Interest expense (3,344,000) (3,654,000)
Other income 379,000 -
----------------- -----------------
Total (2,739,000) (3,600,000)
----------------- -----------------
INCOME BEFORE INCOME TAXES 5,533,000 253,000
INCOME TAX EXPENSE 2,167,000 -
----------------- -----------------
NET INCOME $ 3,366,000 $ 253,000
================= =================
BASIC AND DILUTED NET INCOME PER SHARE $ 0.14 $ 0.01
================= =================
Basic Shares Outstanding 24,323,521 24,075,400
================= =================
Diluted Shares Outstanding 24,473,625 24,075,400
================= =================
The accompanying notes are integral part of this statement.
4
PANACO, Inc.
Statement of Cash Flows
For the Three Months Ended March 31,
(Unaudited)
2001 2000
----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 3,366,000 $ 253,000
Adjustments to reconcile net income to net cash
provided by operating activities:
Deferred income taxes 2,167,000 -
Depletion, depreciation and amortization 7,032,000 5,711,000
Exploratory dry hole expense 3,858,000 320,000
Changes in assets and liabilities:
Accounts receivable 4,404,000 (4,319,000)
Accounts payable (4,038,000) (721,000)
Gas imbalance payable 625,000 -
Deferred credits 162,000 -
Interest payable 2,525,000 2,662,000
Accounts receivable-related party 300,000 -
Change relating to derivative instruments (462,000) -
Prepaid and other (232,000) 46,000
------------- -------------
Net cash provided by operating activities 19,707,000 3,952,000
------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures and acquisitions (10,852,000) (7,998,000)
Increase in restricted deposits (923,000) (500,000)
------------- -------------
Net cash used in investing activities (11,775,000) (8,498,000)
------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of common shares - 129,000
Long-term debt borrowings 6,000,000 8,538,000
Repayment of long-term debt (11,338,000) (3,500,000)
Additional deferred financing costs (45,000) (51,000)
------------- -------------
Net cash provided by (used in) financing activities (5,383,000) 5,116,000
------------- -------------
NET INCREASE IN CASH 2,549,000 570,000
CASH AT BEGINNING OF YEAR 2,878,000 5,575,000
------------- -------------
CASH AT MARCH 31 $ 5,427,000 $ 6,145,000
============= =============
The accompanying notes are integral part of this statement.
5
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 March 31, 2001 and December 31, 2000 and the
results of its operations and cash flows for the periods ended March 31, 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.
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.
6
PANACO, Inc.
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
Property and equipment are carried at cost. Oil and natural gas pipelines
and equipment are depreciated on the straight-line method over their estimated
lives, primarily fifteen years. Other property is also depreciated on the
straight-line method over their estimated lives, ranging from three to ten
years. Fees for processing oil and natural gas for others are treated as a
reduction of lease operating expense related to the facilities and
infrastructure.
Note 3 - CASH FLOW INFORMATION
Cash payments for interest totaled $860,000 and $1,044,000 during the first
three months of 2001 and 2000, respectively. The Company did not make any cash
payments for income taxes during the first three months of 2001 or 2000.
Note 4 - EARNINGS PER SHARE CALCULATIONS
Basic earnings per share for the first three months of each year were based
on the year-to-date weighted average share outstanding of 24,323,521 in 2001 and
24,075,400 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 150,104 in 2001 and 0 in
2000. The Company had stock options outstanding during the first three months of
2000, which were out of the money during the entire quarter 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.
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 $4.4 million at
March 31, 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 March 31, 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 March 31, 2001.
7
PANACO, Inc.
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
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 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.
In August 2000, an action was filed against the Company by Coastal Oil and
Gas Corporation (now El Paso Corporation) for nonpayment of joint interest
billing invoices. The suit seeks to recover unpaid costs from a well drilled on
a property operated by El Paso. PANACO counter sued alleging, among other
things, gross misconduct and negligence in drilling the well. The case is still
in discovery and it is not possible to evaluate the likelihood of an unfavorable
outcome or to estimate the amount or range of potential loss in addition to what
has already been accrued.
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 March 31, 2001
was $60 million, with availability of $44.6 million, of which, $5.5 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 reviewing its alternatives regarding this
facility, including extension of this facility or replacing it with a bank
facility.
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.
8
PANACO, Inc.
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
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 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 our deferred tax assets due to higher commodity
prices and reserve additions, therefore the valuation allowance was removed.
These projections of future taxable income are management's best estimates,
using current reserve estimates, estimates of future commodity prices and other
information currently available. While the Company believes that the assumptions
used in these projections are reasonable, unfavorable future events such as a
decrease in commodity prices could result in a reduction in some or all of the
deferred tax assets in a future period.
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
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 March 31, 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
9
PANACO, Inc.
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
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.
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 March 31,
2001 the Company recognized a $0.3 million decrease in earnings, pre-tax,
related to the decrease in time 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 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 quarter of 2001, the
Company realized after tax losses of $1.3 million on hedging activity incurred
in the first quarter 2001, which were transferred from Other Comprehensive Loss
to natural gas revenues for the production months the hedge related. The Company
also recognized Other Income of $0.3 million, after tax, for the ineffective
portion of the natural gas swap. At March 31, 2001 $2.1 million, net of tax, of
deferred net losses on derivative instruments recorded in Other Comprehensive
Loss are expected to be reclassified to earnings during the remainder of 2001.
All hedge transactions are subject to the Company's risk management policy,
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
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 quarter ended March 31, 2001:
10
PANACO, Inc.
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
Accumulated Other Comprehensive Income, December 31, 2000 $ --
Net Income $ 3,366,000
Accumulated Other Comprehensive Loss (net of tax)
Cumulative effect of change in accounting principle - January 1, 2001 (6,134,000)
Changes in fair value of outstanding hedging positions 2,990,000
Financial derivative settlements transferred from
Accumulated Other Comprehensive Loss 1,054,000
-------------
Accumulated Other Comprehensive Loss $ (2,090,000)
-------------
Comprehensive Income $ 1,276,000
=============
There were no other items in Comprehensive Income/Loss during 2001.
11
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
three months of 2001, net cash provided by operating activities totaled $19.7
million, which, along with cash on hand, was used to fund capital expenditures
of $10.9 million, for required restricted deposit increases of $0.9 million and
to reduce debt by $5.4 million. Capital expenditures of $10.9 million for the
first three months of 2001 represents a 36% increase over capital expenditures
totaling $8.0 million for the comparable period of 2000. For the year 2001, our
Board of Directors has approved a $37.1 million capital budget. We believe that
cash flows from operations will fund this level of capital expenditures in
addition to reducing outstanding debt when compared to December 31, 2000.
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 March 31, 2001 this working capital deficit totaled $19.2 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
12
properties that we own and for acquiring additional oil and natural gas
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 March 31, 2001, $14.1 was outstanding under the Credit Facility, a
decrease of $5.4 million during the first quarter of 2001. We are reviewing 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 March 31, 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 March 31, 2001 the fair value of these hedges was a loss of $3.1
million, pre-tax.
13
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 quarter 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
Capital expenditures totaled $10.9 million for the first three months of
2001, representing a 36% increase over the $8.0 million of capital expenditures
incurred in the comparable period of 2000. The capital expenditures incurred in
2001 were primarily in two fields that we operate.
In late June 2000, we began a new 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 quarter of 2001 we spent $9.6 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 in spudding the #A-13 well which is
currently drilling and the completion of the #A-7 well which was completed and
began production in late January 2001.
During the first quarter of 2001 we spent $0.6 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. During the second quarter
of 2001, we purchased an adjacent block, West Delta 52 for $4 million, before
adjustment, which will provide additional capital projects for the remainder of
2001.
The remaining capital expenditures were incurred on several properties in
which we own smaller interests.
14
Results of Operations
For the three months ended March 31, 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. The average realized price, net of hedges, has increased 147% for
natural gas and 2% for oil from the first quarter of 2000 to the first quarter
of 2001.
Revenues
Oil and natural gas sales totaled $26.3 million during the first quarter of
2001, an increase of $10.7 million, or 69% when compared to the first quarter of
2000. While both oil and natural gas production decreased during the first
quarter of 2001, improved market prices have offset lower production.
Production and Prices:
% Increase
2001 2000 (Decrease)
---- ---- ----------
Natural gas production (MMcf) 3,065 3,122 (2%)
Average price per Mcf
excluding hedging $ 7.19 $ 2.67 169%
Average price per Mcf
including hedging $ 6.49 $ 2.63 147%
Oil Production (MBbl) 226 266 (15%)
Average price per Bbl
excluding hedging $ 28.45 $ 28.16 1%
Average price per Bbl
including hedging $ 28.45 $ 27.87 2%
Both oil and natural gas production decreased slightly when comparing the
first quarter of 2001 to the comparable period of 2000.
Natural gas production decreases from the Umbrella Point Field (470 MMcf),
High Island 309 and 310 Fields (456 MMcf ) and the East Breaks 160 and 161
Fields (251 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 (631 MMcf) and the West Delta Fields (518
MMcf), the primary focus of our current capital expenditure program. Likewise,
oil production has decreased from the East Breaks 165 Field (51 Mbbl) and East
Breaks 160 and 161 Fields (14 Mbbl) due to lower capital expenditures in those
fields. The bulk of the capital expenditures in 2001 are for projects that
should produce natural gas, rather than oil.
Cost and Expenses
Lease operating expenses increased $1.1 million, to $5.3 million, during
the first quarter of 2001 compared to $4.2 million in 2000. On an Mcf equivalent
("Mcfe") basis, lease operating expenses also increased to $1.20 in 2001 from
$0.89 in 2000. Part of the capital spending in 2001 includes a number of
workover and repair expenditures included in lease operating expenses and
totaled approximately $1.2 million during the first quarter of 2001. This
15
compares to $0.8 million of similar expenditures during the first quarter of
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 $0.92 and $0.72 for the first quarter of 2001
and 2000, respectively.
Depletion, depreciation and amortization ("DD&A") increased 23.1 %, or $1.3
million primarily due to a 31% increase in DD&A per unit of production, which
was offset slightly by a 6% 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.
Production and ad valorem taxes increased $0.2 million, or 86%, during the
first three months of 2001 primarily due to our production mix during 2001.
Production from properties onshore, or in state waters, which are subject to
severance taxes became a higher percentage of total production as production
from offshore properties, as a percentage of the total, decreased.
Exploratory dry hole expense increased $3.5 million primarily due to the
unsuccessful #A-4 well drilled during the first quarter of 2001 in the East
Breaks 109 and 110 Fields.
Interest expense decreased $0.3 million due to lower borrowing levels
during 2001 in addition to lower interest rates for the Credit Facility, which
is based on the prime rate.
Other income increased $0.4 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.
The reduction of the valuation allowance during the second quarter of 2000
was based on the determination that it was more likely than not that the
deferred tax assets would be realized. This determination was based on our
current projections of future taxable income. This analysis also included
current estimates for future oil and natural gas prices in addition to recent
reserve additions. Our current projections of future taxable income are
sufficient to utilize our deferred tax assets due to higher commodity prices and
reserve additions, therefore the valuation allowance was removed.
These projections of future taxable income are management's best estimates,
using current reserve estimates, estimates of future commodity prices and other
information currently available. While we believe that the assumptions used in
these projections are reasonable, unfavorable future events such as a decrease
in commodity prices could result in a reduction in some or all of the net
deferred tax assets in a future period.
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
16
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.
For fiscal 2001, the Board of Directors has approved a $37.1 million
capital budget. This budget includes approximately $21.5 million of exploratory
projects, the majority of which will be spent at our 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.
In August 2000, an action was filed against the Company by Coastal Oil and
Gas Corporation (now El Paso Corporation) for nonpayment of joint interest
billing invoices. The suit seeks to recover unpaid costs from a well drilled on
a property operated by El Paso. PANACO counter sued alleging, among other
things, gross misconduct and negligence in drilling the well. The case is still
in discovery and it is not possible to evaluate the likelihood of an unfavorable
outcome or to estimate the amount or range of potential loss in addition to what
we have already accrued.
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
17
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 March 31, 2001 the fair value of these hedges was a loss of $3.1
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
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: May 14, 2001 /s/ Todd R. Bart
--------------------- -------------------------------------
Todd R. Bart, Chief Financial Officer
18