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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
--------------------
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended: September 30, 2003
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from: to:
Commission file number: 019020
--------------------
PETROQUEST ENERGY, INC.
(Exact name of registrant as specified in its charter)
DELAWARE 72-1440714
(State of Incorporation) (I.R.S. Employer Identification No.)
400 E. KALISTE SALOOM RD., SUITE 6000
LAFAYETTE, LOUISIANA 70508
(Address of principal executive offices) (Zip code)
--------------------
Registrant's telephone number, including area code: (337) 232-7028
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 [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Exchange Act).
Yes [X] No [ ]
As of November 12, 2003, there were 44,535,694 shares of the
registrant's common stock, par value $.001 per share, outstanding.
PETROQUEST ENERGY, INC.
Table of Contents
Page No.
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Part I. Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets as of
September 30, 2003 and December 31, 2002...................................... 1
Consolidated Statements of Operations for the
Three and Nine Months Ended September 30, 2003 and 2002....................... 2
Consolidated Statements of Cash Flows for the
Nine Months Ended September 30, 2003 and 2002................................. 3
Notes to Consolidated Financial Statements........................................ 4
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations................................. 8
Item 3. Quantitative and Qualitative Disclosures About Market Risk........................ 13
Item 4. Controls and Procedures........................................................... 14
Part II. Other Information
Item 1. Legal Proceedings................................................................. 15
Item 2. Changes in Securities and Use of Proceeds......................................... 15
Item 3. Defaults upon Senior Securities................................................... 15
Item 4. Submission of Matters to a Vote of Security Holders............................... 15
Item 5. Other Information................................................................. 15
Item 6. Exhibits and Reports on Form 8-K.................................................. 15
PETROQUEST ENERGY, INC.
Consolidated Balance Sheets
(Amounts in Thousands)
September 30, December 31,
2003 2002
---- ----
(unaudited) (Note 1)
ASSETS
Current assets:
Cash and cash equivalents $ 831 $ 1,137
Oil and gas revenue receivable 4,839 6,500
Joint interest billing receivable 3,527 2,165
Other current assets 765 310
------------ ------------
Total current assets 9,962 10,112
------------ ------------
Oil and gas properties:
Oil and gas properties, full cost method 246,785 214,543
Unevaluated oil and gas properties 11,029 15,653
Accumulated depreciation, depletion and amortization (127,047) (109,450)
------------ ------------
Oil and gas properties, net 130,767 120,746
------------ ------------
Other assets, net of accumulated depreciation and amortization
of $3,503 and $2,851, respectively 1,303 1,205
------------ ------------
Total assets $ 142,032 $ 132,063
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 9,026 $ 18,337
Advances from co-owners 2,845 940
Current portion of long-term debt 6,500 6,600
------------ ------------
Total current liabilities 18,371 25,877
------------ ------------
Long-term debt 2,000 2,400
Asset retirement obligation 11,650 -
Deferred income taxes 6,896 5,461
Other liabilities 555 555
Commitments and contingencies - -
Stockholders' equity:
Common stock, $.001 par value; authorized 75,000
shares; issued and outstanding 44,306 and 42,852
shares, respectively 44 43
Paid-in capital 108,229 106,173
Other comprehensive income (201) (1,197)
Unearned deferred compensation (125) (337)
Accumulated deficit (5,387) (6,912)
------------ ------------
Total stockholders' equity 102,560 97,770
------------ ------------
Total liabilities and stockholders' equity $ 142,032 $ 132,063
============ ============
See accompanying Notes to Consolidated Financial Statements.
1
PETROQUEST ENERGY, INC.
Consolidated Statements of Operations
(unaudited)
(Amounts in Thousands, Except Per Share Data)
Three Months Ended Nine Months Ended
September 30, September 30,
------------- -------------
2003 2002 2003 2002
---- ---- ---- ----
Revenues:
Oil and gas sales $ 9,800 $ 11,220 $ 35,014 $ 33,085
Interest and other income 57 30 108 68
---------- ---------- ---------- ----------
9,857 11,250 35,122 33,153
---------- ---------- ---------- ----------
Expenses:
Lease operating expenses 2,235 2,487 7,501 7,240
Production taxes 289 119 623 441
Depreciation, depletion and amortization 6,197 5,916 20,549 19,638
General and administrative 1,171 1,016 3,519 3,758
Accretion of asset retirement obligation 169 - 445 -
Interest expense 30 25 283 252
Derivative expense (586) 226 1,163 530
---------- ---------- ---------- ----------
9,505 9,789 34,083 31,859
---------- ---------- ---------- ----------
Income from operations 352 1,461 1,039 1,294
Income tax expense 123 511 364 453
---------- ---------- ---------- ----------
Income before cumulative effect of
change in accounting principle $ 229 $ 950 $ 675 $ 841
Cumulative effect of change in accounting principle - - 849 -
---------- ---------- ---------- ----------
Net income $ 229 $ 950 $ 1,524 $ 841
========== ========== ========== ==========
Earnings per common share:
Basic
Income before cumulative effect of
change in accounting principle $ 0.01 $ 0.03 $ 0.02 $ 0.02
Cumulative effect of change in
accounting principle - - 0.02 -
---------- ---------- ---------- ----------
Net income $ 0.01 $ 0.03 $ 0.04 $ 0.02
========== ========== ========== ==========
Diluted
Income before cumulative effect of
change in accounting principle $ 0.01 $ 0.02 $ 0.01 $ 0.02
Cumulative effect of change in
accounting principle - - 0.02 -
---------- ---------- ---------- ----------
Net income $ 0.01 $ 0.02 $ 0.03 $ 0.02
========== ========== ========== ==========
Weighted average number of common shares:
Basic 44,333 37,852 43,366 36,815
========== ========== ========== ==========
Diluted 44,729 39,820 44,167 38,575
========== ========== ========== ==========
See accompanying Notes to Consolidated Financial Statements.
2
PETROQUEST ENERGY, INC.
Consolidated Statements of Cash Flows
(unaudited)
(Amounts in Thousands)
Nine Months Ended
September 30,
-------------
2003 2002
---- ----
Cash flows from operating activities:
Net income $ 1,524 $ 841
Adjustments to reconcile net income to net cash provided by
operating activities:
Deferred tax expense 364 453
Depreciation, depletion and amortization 20,549 19,638
Cumulative effect of change in accounting principle (849) -
Accretion of asset retirement obligation 445 -
Amortization of debt issuance costs 323 209
Compensation expense 294 259
Derivative mark to market 186 429
Changes in working capital accounts:
Accounts receivable 1,661 1,370
Joint interest billing receivable (1,362) (2,213)
Other assets (750) (673)
Accounts payable and accrued liabilities (6,967) 4,695
Advances from co-owners 1,905 1,877
Plugging and abandonment escrow - 268
Other (455) (428)
---------- ----------
Net cash provided by operating activities 16,868 26,725
---------- ----------
Cash flows from investing activities:
Investment in oil and gas properties (18,727) (49,169)
Sale of oil and gas properties, net - 17,321
---------- ----------
Net cash used in investing activities (18,727) (31,848)
---------- ----------
Cash flows from investing activities:
Exercise of options and warrants 2,059 178
Proceeds from borrowings 16,100 15,000
Repayment of debt (16,600) (32,329)
Issuance of common stock, net of expenses (6) 21,827
---------- ----------
Net cash provided by financing activities 1,553 4,676
---------- ----------
Net decrease in cash and cash equivalents (306) (447)
Cash balance and cash equivalents, beginning of period 1,137 1,063
---------- ----------
Cash balance and cash equivalents, end of period $ 831 $ 616
========== ==========
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest $ 251 $ 554
========== ==========
Income taxes $ - $ -
========== ==========
See accompanying Notes to Consolidated Financial Statements.
3
PETROQUEST ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 BASIS OF PRESENTATION
The consolidated financial information for the three- and nine-month
periods ended September 30, 2003 and 2002, respectively, have been prepared by
the Company and was not audited by its independent public accountants. In the
opinion of management, all normal and recurring adjustments have been made to
present fairly the financial position, results of operations, and cash flows of
the Company at September 30, 2003 and for all reported periods. Results of
operations for the interim periods presented are not necessarily indicative of
the operating results for the full year or any future periods.
The balance sheet at December 31, 2002 has been derived from the
audited financial statements at that date. Certain information and footnote
disclosures normally included in financial statements prepared in accordance
with accounting principles generally accepted in the United States have been
condensed or omitted. These consolidated financial statements should be read in
conjunction with the financial statements and related notes thereto included in
the Company's Annual Report on Form 10-K for the year ended December 31, 2002.
Unless the context otherwise indicates, any references in this
Quarterly Report on Form 10-Q to "PetroQuest" or the "Company" refer to
PetroQuest Energy, Inc. (Delaware) and its wholly-owned consolidated
subsidiaries, PetroQuest Energy, L.L.C. (a single member Louisiana limited
liability company) and PetroQuest Oil & Gas, L.L.C. (a single member Louisiana
limited liability company).
Certain reclassifications of prior year amounts have been made to
conform with the current year presentation.
NOTE 2 EARNINGS PER SHARE
Basic earnings or loss per common share was computed by dividing net
income or loss by the weighted average number of shares of common stock
outstanding during the relevant periods. Diluted earnings or loss per common
share is determined on a weighted average basis using common shares issued and
outstanding adjusted for the effect of stock options considered dilutive
computed using the treasury stock method.
Options to purchase 1,197,002 shares of common stock were outstanding
during the three- and nine-month periods ended September 30, 2003, but were not
included in the computation of diluted earnings per share because the options'
exercise prices were greater than the average market prices of the common shares
during the periods. These options' exercise prices were between $2.18-$7.65,
respectively, and expire in 2010-2013. Options to purchase 572,751 and 273,667
shares of common stock were outstanding during the three- and nine-month periods
ended September 30, 2002, but were not included in the computation of diluted
earnings per share because the options' exercise prices were greater than the
average market prices of the common shares during the periods. These options'
exercise prices were between $4.95-$7.65 and between $5.56-$7.65, respectively,
and expire in 2011-2012.
NOTE 3 LONG-TERM DEBT
The Company entered into a bank credit facility on May 14, 2003 with a
group of two banks. The Company expensed $203,000 of deferred financing costs,
which is included in interest expense, during the nine-month period ended
September 30, 2003 relating to the previous credit facility.
Pursuant to the new credit facility agreement, PetroQuest and our
subsidiary PetroQuest Energy, L.L.C. (the "Borrower") have a $75 million
revolving credit facility with a group of two banks which permits the Borrower
to borrow amounts from time to time based on its available borrowing base as
determined in the credit facility. The credit facility is secured by a mortgage
on substantially all of the Borrower's oil and gas properties, a pledge of the
membership interest of the Borrower and PetroQuest's corporate guarantee of the
indebtedness of the Borrower. The borrowing base under this credit facility is
based upon the valuation as of April 1 and October 1 of each year of the
Borrower's mortgaged properties, projected oil and gas prices, and any other
factors deemed relevant by the lenders. The Company or the lenders may also
request additional borrowing base redeterminations. As of September 30, 2003,
the borrowing base under this credit facility was $12 million and is subject to
monthly reductions of $1 million commencing December 1, 2003. The Company is
currently undergoing a borrowing base
4
redetermination. The banks will determine future monthly reductions in
connection with each borrowing base redetermination.
Outstanding balances on the revolving credit facility bear interest at
either the bank's prime rate plus a margin (based on a sliding scale of 0.75% to
1.25% based on borrowing base usage but never less than the Federal Funds
Effective Rate plus 0.5%) or the Eurodollar rate plus a margin (based on a
sliding scale of 2.0% to 2.5% depending on borrowing base usage). The credit
facility also allows the Company to use up to $5 million of the borrowing base
for letters of credit for fees equal to the applicable margin rate for
Eurodollar advances. At November 7, 2003, the Company had $9.5 million of
borrowings and no letters of credit issued pursuant to the credit facility.
The Company is subject to certain restrictive financial and
non-financial covenants under the credit facility, including a minimum current
ratio, a minimum tangible net worth, maximum debt to EBITDA ratio, maximum G&A
expenses, and limiting authorization for expenditures on dry hole costs, all as
defined in the credit facility. The credit facility also requires the Borrower
to establish and maintain commodity hedges covering at least 50% of its proved
developed producing reserves on a rolling twelve-month basis. As of September
30, 2003, the Company was in compliance with all of the covenants in the credit
facility. The credit facility matures on May 14, 2006.
The Company currently has two interest rate swaps covering $5 million
of our floating rate debt. The swaps, which expire in November 2003 and 2004,
have fixed interest rates of 4.56% and 4.25%-5.665%, respectively. The swaps are
stated at their fair value and are marked-to-market through derivative expense
in the Company's income statement. At September 30, 2003, the Company recognized
a liability of $306,000 related to these derivative instruments.
NOTE 4 NEW ACCOUNTING STANDARDS
In June 2001, the Financial Accounting Standards Board issued SFAS 143,
"Accounting for Asset Retirement Obligations," which requires recording the fair
value of an asset retirement obligation associated with tangible long-lived
assets in the period incurred. Retirement obligations associated with long-lived
assets included within the scope of SFAS 143 are those for which there is a
legal obligation to settle under existing or enacted law, statute, written or
oral contract or by legal construction under the doctrine of promissory
estoppel.
The Company adopted SFAS 143 effective January 1, 2003. The net
difference between the Company's previously recorded abandonment liability and
the amounts estimated under SFAS 143, after taxes, totaled a gain of $849,000,
which has been recognized as a cumulative effect of a change in accounting
principle. The gain is due to the effect on the historical depletion as a result
of the retirement obligation being recorded at fair value. On a pro forma basis,
the impact for the nine months ended September 30, 2002 would have increased net
income by $270,000.
The Company has legal obligations to plug, abandon and dismantle
existing wells and facilities that it has acquired and constructed during its
existence. As of January 1, 2003, the Company recognized a $9,467,000 liability
for its asset retirement obligations and recorded the related additional assets
that will be depreciated using the units-of-production method. The following
table describes all changes to the Company's asset retirement obligation
liability:
5
Nine Months Ended
September 30, 2003
------------------
Asset retirement obligation at beginning of year $ -
Liability recognized in transition 9,467,000
Liabilities incurred during 2003 74,000
Liabilities settled during 2003 (389,000)
Accretion expense 445,000
Revisions in estimated cash flows 2,053,000
------------
Asset retirement obligation at end of period $ 11,650,000
============
In January 2003, the Financial Accounting Standards Board issued
Interpretation No. 46, Consolidation of Variable Interest Entities (FIN 46),
which requires companies to evaluate variable interest entities to determine
whether to apply the consolidation provisions of FIN 46 to those entities. The
consolidation provisions of FIN 46, if applicable, would apply to variable
interest entities created after January 31, 2003 immediately, and to variable
interest entities created before February 1, 2003 in the Company's interim
period beginning October 1, 2003. The Company believes that it has no interests
in these types of entities.
NOTE 5 EQUITY
Other Comprehensive Income and Derivative Instruments
The following table presents a recap of the Company's comprehensive
income for the three- and nine-month periods ended September 30, 2003 and 2002
(in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
------------- -------------
2003 2002 2003 2002
---- ---- ---- ----
Net income $ 229 $ 950 $1,524 $ 841
Change in fair value of derivative instrument,
accounted for as hedges, net of taxes 534 (134) 996 (134)
------ ------ ------ ------
Comprehensive income $ 763 $ 816 $2,520 $ 707
The Company accounts for derivatives in accordance with Statement of
Financial Accounting Standards No. 133, as amended (SFAS 133). When the
conditions specified in SFAS 133 are met, the Company may designate these
derivatives as hedges. As of September 30, 2003, the Company had five derivative
contracts with third parties designated as hedges, whereby a fixed price has
been established for a certain period. For the three and nine months ended
September 30, 2003, the effect of derivative financial instruments is net of
deferred income tax liability of $287,000 and $536,000, respectively. For the
three and nine months ended September 30, 2002, the effect of derivative
financial instruments is net of deferred income tax benefit of $72,000. The cash
settlements of these hedges are recorded in oil and gas revenues. Oil and gas
sales include reductions related to gas hedges of $171,000 and zero and oil
hedges of $412,000 and $61,000 for the three months ended September 30, 2003 and
2002, respectively. Oil and gas sales include reductions related to gas hedges
of $2,440,000 and $729,000 and oil hedges of $1,423,000 and $61,000 for the nine
months ended September 30, 2003 and 2002, respectively.
As of September 30, 2003, the Company had open fixed price swap
contracts with third parties, whereby a fixed price has been established for a
certain period. These agreements in effect for the remainder of 2003 are for oil
volume of 1,000 barrels per day at a weighted average price of $25.75, and gas
volume of 7,000Mmbtu per day at a weighted average price of $4.02. Additionally,
the Company entered into a costless collar contract for 2004 for 2,500Mmbtu per
day with a floor price of $4.00 and ceiling price of $7.03. At September 30,
2003, the Company recognized a liability of $665,000 related to these derivative
instruments, of which four have been designated as
6
cash flow hedges and one has been deemed ineffective and recorded through
derivative expense on the income statement. These changes in fair value of the
derivative are recorded on the income statement because of a decline in
production in the specific field to which the derivative was designated.
Public Offering
During February and March 2002, the Company completed the offering of
5,193,600 shares of its common stock. The shares were sold to the public for
$4.40 per share. After underwriting discounts, the Company realized proceeds of
approximately $21.9 million.
During October and November 2002, the Company completed the offering of
5,000,000 shares of its common stock. The shares were sold to the public for
$4.25 per share. After underwriting discounts, the Company realized proceeds of
approximately $20.4 million.
NOTE 6 STOCK BASED COMPENSATION
The Company accounts for its stock-based compensation plans under the
principles prescribed by the Accounting Principles Board's Opinion No. 25,
"Accounting for Stock Issued to Employees." No stock option compensation cost is
reflected in net income, as all options granted under the plan had an exercise
price equal to the market value of the underlying common stock on the date of
grant. The following table illustrates the effect on net income and earnings per
share if the Company had applied the fair value recognition provisions of SFAS
No. 123, "Accounting for Stock Based Compensation" pursuant to the disclosure
requirements of SFAS No. 148, "Accounting for Stock-Based Compensation -
Transition and Disclosure" (in thousands, except per share data):
Three Months Ended Nine Months Ended
September 30, September 30,
------------- -------------
2003 2002 2003 2002
---- ---- ---- ----
Net income 229 950 1,524 841
Stock-based compensation:
Add expense included in reported results, net of tax 90 56 191 168
Deduct fair value based method, net of tax (157) (226) (391) (678)
------- ------- --------- -------
Pro forma net income 162 780 1,324 331
Earnings per common share:
Basic - as reported $ 0.01 $ 0.03 $ 0.04 $ 0.02
Basic - pro forma $ 0.00 $ 0.02 $ 0.03 $ 0.01
Diluted - as reported $ 0.01 $ 0.02 $ 0.03 $ 0.02
Diluted - pro forma $ 0.00 $ 0.02 $ 0.03 $ 0.01
7
Item 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
PetroQuest Energy, Inc. is an independent oil and gas company engaged
in the exploration, development, acquisition and operation of oil and gas
properties onshore and offshore in the Gulf Coast Region. The Company and its
predecessors have been active in this area since 1986, which gives the Company
extensive geophysical, technical and operational expertise in this area.
The Company's business strategy is to increase production, cash flow
and reserves through exploration, development and acquisition of properties
located in the Gulf Coast Region. At September 30, 2003, the Company operated
approximately 90% of all of its proved reserves. For the nine months ended
September 30, 2003, approximately 50% of the Company's equivalent production was
oil and 50% was natural gas.
CRITICAL ACCOUNTING POLICIES
Full Cost Method of Accounting
We use the full cost method of accounting for our investments in oil
and gas properties. Under this method, all acquisition, exploration and
development costs, including certain related employee costs, incurred for the
purpose of exploring for and developing and oil and natural gas are capitalized.
Acquisition costs include costs incurred to purchase, lease or otherwise acquire
property. Exploration costs include the costs of drilling exploratory wells,
including those in progress and geological and geophysical service costs in
exploration activities. Development costs include the costs of drilling
development wells and costs of completions, platforms, facilities and pipelines.
Costs associated with production and general corporate activities are expensed
in the period incurred. Sales of oil and gas properties, whether or not being
amortized currently, are accounted for as adjustments of capitalized costs, with
no gain or loss recognized, unless such adjustments would significantly alter
the relationship between capitalized costs and proved reserves of oil and gas.
The costs associated with unevaluated properties are not initially
included in the amortization base and relate to unevaluated leasehold acreage
and delay rentals, seismic data and capitalized interest. These costs are either
transferred to the amortization base with the costs of drilling the related well
or are assessed quarterly for possible impairment or reduction in value.
We compute the provision for depletion of oil and gas properties using
the unit-of-production method based upon production and estimates of proved
reserve quantities. Unevaluated costs and related carrying costs are excluded
from the amortization base until the properties associated with these costs are
evaluated. In addition to costs associated with evaluated properties, the
amortization base includes estimated future development costs and dismantlement,
restoration and abandonment costs, net of estimated salvage values. Our
depletion expense is affected by the estimates of future development costs,
unevaluated costs and proved reserves, and changes in these estimates could have
an impact on our future earnings.
We capitalize certain internal costs that are directly identified with
the acquisition, exploration and development activities. The capitalized
internal costs include salaries, employee benefits, costs of consulting services
and other related expenses and do not include costs related to production,
general corporate overhead or similar activities. We also capitalize a portion
of the interest costs incurred on our debt. Capitalized interest is calculated
using the amount of our unevaluated property and our effective borrowing rate.
Capitalized costs of oil and gas properties, net of accumulated DD&A
and related deferred taxes, are limited to the estimated future net cash flows
from proved oil and gas reserves, discounted at 10 percent, plus the lower of
cost or fair value of unproved properties, as adjusted for related income tax
effects (the full cost ceiling). If capitalized costs exceed the full cost
ceiling, the excess is charged to write-down of oil and gas properties in the
quarter in which the excess occurs. Declines in prices or reserves could result
in a future write-down of oil and gas properties.
8
Given the volatility of oil and gas prices, it is probable that our
estimate of discounted future net cash flows from proved oil and gas reserves
will change in the near term. If oil or gas prices decline, even for only a
short period of time, or if we have downward revisions to our estimated proved
reserves, it is possible that write-downs of oil and gas properties could occur
in the future.
Future Abandonment Costs
Future abandonment costs include costs to dismantle and relocate or
dispose of our production platforms, gathering systems, wells and related
structures and restoration costs of land and seabed. We develop estimates of
these costs for each of our properties based upon the type of production
structure, depth of water, reservoir characteristics, depth of the reservoir,
market demand for equipment, currently available procedures and consultations
with construction and engineering consultants. Because these costs typically
extend many years into the future, estimating these future costs is difficult
and requires management to make estimates and judgments that are subject to
future revisions based upon numerous factors, including changing technology and
the political and regulatory environment. The accounting for future abandonment
costs changed on January 1, 2003, with the adoption of Statement of Financial
Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." See
New Accounting Standards in the Notes to Consolidated Financial Statements for a
further discussion of this accounting standard.
Reserve Estimates
Our estimates of oil and gas reserves are, by necessity, projections
based on geologic and engineering data, and there are uncertainties inherent in
the interpretation of such data as well as the projection of future rates of
production and the timing of development expenditures. Reserve engineering is a
subjective process of estimating underground accumulations of oil and gas that
are difficult to measure. The accuracy of any reserve estimate is a function of
the quality of available data, engineering and geological interpretation and
judgment. Estimates of economically recoverable oil and gas reserves and future
net cash flows necessarily depend upon a number of variable factors and
assumptions, such as historical production from the area compared with
production from other producing areas, the assumed effect of regulations by
governmental agencies, and assumptions governing future oil and gas prices,
future operating costs, severance taxes, development costs and workover costs,
all of which may in fact vary considerably from actual results. The future
drilling costs associated with reserves assigned to proved undeveloped locations
may ultimately increase to the extent that these reserves may be later
determined to be uneconomic. For these reasons, estimates of the economically
recoverable quantities of expected oil and gas attributable to any particular
group of properties, classifications of such reserves based on risk of recovery,
and estimates of the future net cash flows may vary substantially. Any
significant variance in the assumptions could materially affect the estimated
quantity and value of the reserves, which could affect the carrying value of our
oil and gas properties and/or the rate of depletion of such oil and gas
properties. Actual production, revenues and expenditures with respect to our
reserves will likely vary from estimates, and such variance may be material.
Derivative Instruments
The estimated fair values of our commodity derivative instruments are
recorded in the consolidated balance sheet. At inception, all of our commodity
derivative instruments represent hedges of the price of future oil and gas
production. The changes in fair value of those derivative instruments that
qualify for treatment due to being highly effective are recorded to Other
Comprehensive Income until the hedged oil or natural gas quantities are
produced. If a hedge becomes ineffective because the expected event does not
occur, the fair value of the derivative is recorded on the income statement.
Estimating the fair values of hedging derivatives requires complex
calculations incorporating estimates of future prices, discount rates and price
movements. Instead, we choose to obtain the fair value of our commodity
derivatives from the counter parties to those contracts. Since the counter
parties are market makers, they are able to provide us with a literal market
value, or what they would be willing to settle such contracts for as of the
given date.
9
RESULTS OF OPERATIONS
The following table (unaudited) sets forth certain operating
information with respect to our oil and gas operations for the periods noted:
Three Months Ended Nine Months Ended
September 30, September 30,
------------- -------------
2003 2002 2003 2002
---- ---- ---- ----
Production:
Oil (Bbls) 166,385 237,167 584,249 688,801
Gas (Mcf) 1,031,679 1,461,924 3,483,927 5,763,714
Total Production (Mcfe) 2,029,989 2,884,923 6,989,421 9,896,520
Sales:
Total oil sales $ 4,552,094 $ 6,339,813 $ 16,801,189 $ 16,732,483
Total gas sales 5,247,711 4,879,750 18,212,501 16,352,614
Average sales prices:
Oil (per Bbl) $ 27.36 $ 26.73 $ 28.76 $ 24.29
Gas (per Mcf) 5.09 3.34 5.23 2.84
Per Mcfe 4.83 3.89 5.01 3.36
The above sales include reductions related to gas hedges of $171,000 and zero
and oil hedges of $412,000 and $61,000 for the three months ended September 30,
2003 and 2002, respectively. The above sales include reductions related to gas
hedges of $2,440,000 and $729,000 and oil hedges of $1,423,000 and $61,000 for
the nine months ended September 30, 2003 and 2002, respectively.
Net income totaled $229,000 and $950,000 for the quarters ended September 30,
2003 and 2002, respectively. Net income totaled $1,524,000 and $841,000 for the
nine-month periods ended September 30, 2003 and 2002, respectively. The results
are attributable to the following components:
PRODUCTION. Oil production in 2003 decreased 30% and 15% from the third quarter
and nine months ended September 30, 2002, respectively. Natural gas production
in 2003 decreased 29% and 40% from the third quarter and nine months ended
September 30, 2002, respectively. On a Mcfe basis, production for the quarter
and nine months ended September 30, 2003 decreased 30% and 29% over the same
periods in 2002, respectively. The decrease in current year production as
compared to 2002 was due to well performance at our Bordeaux and Berry Lake
wells, the consistent decline of our Gulf Coast production and the absence of
the addition of a significant amount of new discoveries.
PRICES. Average oil prices per Bbl for the quarter and nine months ended
September 30, 2003 were $27.36 and $28.76, as compared to $26.73 and $24.29,
respectively, for the same periods in 2002. Average gas prices per Mcf were
$5.09 and $5.23 for the quarter and nine months ended September 30, 2003, as
compared to $3.34 and $2.84, respectively, for the same periods in 2002. Stated
on a Mcfe basis, unit prices received during the third quarter and nine months
ended September 30, 2003 were 24% and 49% higher, respectively, than the prices
received during the comparable 2002 periods.
REVENUE. Oil and gas sales during the third quarter ended September 30, 2003
decreased to $9,800,000 as compared to sales of $11,220,000 for the same period
in 2002. The decrease in production volumes resulted in a decrease in revenue.
Oil and gas sales during the nine months ended September 30, 2003 increased to
$35,014,000 as compared to sales of $33,085,000 for the same period in 2002. The
increase in commodity prices partially offset by a decrease in production
volumes, resulted in a decrease in revenue for the quarter. The increase in
commodity prices resulted in the increase in revenue for the nine months ended
September 30, 2003.
EXPENSES. Lease operating expenses for the quarter and nine months ended
September 30, 2003 decreased and increased to $2,235,000 and $7,501,000,
respectively as compared to $2,487,000 and $7,240,000, respectively, for the
same periods in 2002. On a Mcfe basis, lease operating expenses for the quarter
and nine months ended September 30, 2003 increased to $1.10 and $1.07,
respectively, as compared to $0.86 and $0.73 for the same periods
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during 2002. The increase is primarily due to the decrease in production volumes
without a comparable reduction of the fixed costs in our major fields.
General and administrative expenses during the third quarter and nine months
ended September 30, 2003 totaled $1,171,000 and $3,519,000, respectively, as
compared to expenses of $1,016,000 and $3,758,000, respectively, during the 2002
periods. The Company capitalized $974,000 and $2,869,000, respectively, of
general and administrative costs during the quarter and nine months ended
September 30, 2003 as compared to $784,000 and $2,752,000, respectively in the
comparable 2002 periods. We have recognized $139,000 and $294,000, respectively,
of non-cash compensation expense during the quarter and nine months ended
September 30, 2003. We recorded non-cash compensation expense of $86,000 and
$258,000, respectively, during the quarter and nine months ended September 30,
2002.
Depreciation, depletion and amortization ("DD&A") expense for the three- and
nine-month periods ended September 30, 2003 increased 5%, respectively, from the
2002 periods. On a Mcfe basis, which reflects the changes in production, the
DD&A rate for the third quarter of 2003 was $3.05 per Mcfe as compared to $2.05
per Mcfe for the same period in 2002. The DD&A rate for the nine months ended
September 30, 2003 was $2.94 per Mcfe compared to $1.98 per Mcfe for the same
period in 2002. The increase in 2003 as compared to 2002 is due primarily to the
significant capital expended during the previous twelve months without a
comparable increase in our reserve base.
Interest expense, net of amounts capitalized on unevaluated prospects, increased
$5,000 and $31,000 during the third quarter and nine months ended September 30,
2003, respectively, as compared to the same periods in 2002. The increases are
the result of fully expensing deferred financing costs from our previous credit
facility during the current year. We capitalized $111,000 and $150,000 of
interest during the three months ended September 30, 2003 and 2002,
respectively, and $343,000 and $457,000 during the nine months ended September
30, 2003 and 2002, respectively.
Derivative expense decreased and increased $812,000 and $633,000 during the
third quarter and nine months ended September 30, 2003, respectively, as
compared to the same periods in 2002. These fluctuations are primarily the
result of one of our gas derivatives being marked-to-market value on the income
statement. These changes in fair value of the derivative are recorded on the
income statement because of a decline in production in the specific field to
which the derivative was designated. Additionally, the monthly settlements
related to this derivative have been recorded to derivative expense effective
during June 2003.
Income tax expense of $123,000 and $364,000 was recognized during the third
quarter and nine months ended September 30, 2003, respectively, as compared to
expense of $511,000 and $453,000 during the same periods of 2002. The changes
are a result of fluctuations in the operating profit during the current year. We
provide for income taxes at a statutory rate of 35%.
LIQUIDITY AND CAPITAL RESOURCES
We have financed our exploration and development activities to date principally
through cash flow from operations, bank borrowings, private and public offerings
of common stock and sales of properties.
Source of Capital: Operations
Net cash flow from operations during the nine months ended September 30, 2003
decreased from $26,725,000 in 2002 to $16,868,000 in 2003. This decrease
resulted primarily from the decrease in production volumes during the current
year. Additionally, we utilized discretionary cash flow to reduce our vendor
payables and debt during the first nine months of 2003, which decreased our net
cash flow from operations. The working capital deficit was reduced from $(15.8)
million at December 31, 2002 to $(8.4) million at September 30, 2003. This
decrease was caused primarily by our effort to utilize cash flow to first reduce
our working capital deficit and second to drill prospects.
Source of Capital: Debt
We entered into a new bank credit facility on May 14, 2003 with a group of two
banks. Pursuant to the new credit facility agreement, PetroQuest and our
subsidiary PetroQuest Energy, L.L.C. (the "Borrower") have a $75 million
revolving credit facility with a group of two banks which permits us to borrow
amounts from time to time based on
11
our available borrowing base as determined in the credit facility. The credit
facility is secured by a mortgage on substantially all of the Borrower's oil and
gas properties, a pledge of the membership interest of the Borrower and
PetroQuest's corporate guarantee of the indebtedness of the Borrower. The
borrowing base under this credit facility is based upon the valuation as of
April 1 and October 1 of each year of the Borrower's mortgaged properties,
projected oil and gas prices, and any other factors deemed relevant by the
lenders. We or the lenders may also request additional borrowing base
redeterminations. As of September 30, 2003, the borrowing base under this credit
facility was $12 million and is subject to monthly reductions of $1 million
commencing December 1, 2003. We are currently undergoing a borrowing base
redetermination. The banks will determine future monthly reductions in
connection with each borrowing base redetermination.
Outstanding balances on the revolving credit facility bear interest at either
the bank's prime rate plus a margin (based on a sliding scale of 0.75% to 1.25%
based on borrowing base usage but never less than the Federal Funds Effective
Rate plus 0.5%) or the Eurodollar rate plus a margin (based on a sliding scale
of 2.0% to 2.5% depending on borrowing base usage). The credit facility also
allows us to use up to $5 million of the borrowing base for letters of credit
for fees equal to the applicable margin rate for Eurodollar advances. At
November 7, 2003, we had $9.5 million of borrowings and no letters of credit
issued pursuant to the credit facility.
We are subject to certain restrictive financial and non-financial covenants
under the credit facility, including a minimum current ratio, a minimum tangible
net worth, maximum debt to EBITDA ratio, maximum G&A expenses, and limiting
authorization for expenditures on dry hole costs, all as defined in the credit
facility. The credit facility also requires the Borrower to establish and
maintain commodity hedges covering at least 50% of its proved developed
producing reserves on a rolling twelve month basis. As of September 30, 2003, we
were in compliance with all of the covenants in the facility. The credit
facility matures on May 14, 2006.
On November 6, 2003, we obtained a $20 million subordinated term credit facility
from Macquarie Americas Corp. ("Macquarie"). The facility carries an interest
rate of prime plus 5.5%, is secured by a second mortgage on substantially all of
our oil and gas properties and matures November 30, 2006. The facility is
available for advances at any time until December 31, 2004 subject to the
restrictive covenants of the facility and Macquarie approval. At closing,
Macquarie received warrants to purchase 1,250,000 shares of our common stock at
an exercise price of $2.30 per share. When cumulative advances under the
facility exceed $5 million, $10 million and $15 million, Macquarie will receive
warrants to purchase an additional 250,000 shares, 500,000 shares and 250,000
shares of our common stock, respectively, at the same exercise price per share.
The warrants are and will be exercisable at any time through the earlier of 36
months following the repayment in full of the facility or 30 days after daily
volume weighted average price of our common stock as published by Nasdaq is
equal to or greater than, for a period of 30 days, the exercise price multiplied
by three. In addition, we granted Macquarie piggy-back registration rights with
respect to the shares of common stock issuable upon exercise of the warrants.
We intend to use the proceeds borrowed under the Macquarie facility towards
funding our development plan, which is subject to prior approval by Macquarie
and includes completion and facility costs, the cost of drilling development
wells, and for other general corporate purposes. The facility contains certain
restrictive financial and non-financial covenants, including a minimum current
ratio, a minimum interest coverage ratio, a minimum adjusted present value ratio
and a maximum general and administrative expense ratio, all as defined in the
facility.
Natural gas and oil prices have a significant impact on our cash flows available
for capital expenditures and our ability to borrow and raise additional capital.
The amount we can borrow under our credit facility is subject to periodic
re-determination based in part on changing expectations of future prices. Lower
prices may also reduce the amount of natural gas and oil that we can
economically produce. Additionally, the production declines of certain producing
wells resulted in lower production in the nine months ended September 30, 2003.
Lower prices and/or lower production may decrease revenues, cash flows and the
borrowing base under the credit facility, thus reducing the amount of financial
resources available to meet our capital requirements.
Source of Capital: Issuance of Equity Securities
We have an effective universal shelf registration statement relating to the
potential public offer and sale by PetroQuest of any combination of debt
securities, common stock, preferred stock, depositary shares, and warrants from
time to time or when financing needs arise. The registration statement does not
provide assurance that we will or could sell any such securities.
12
During October and November 2002, we completed the offering of 5,000,000 shares
of our common stock. The shares were sold to the public for $4.25 per share.
After underwriting discounts, we realized proceeds of approximately $20.4
million.
During February and March 2002, we completed the offering of 5,193,600 shares of
our common stock. The shares were sold to the public for $4.40 per share. After
underwriting discounts, we realized proceeds of approximately $21.9 million.
Source of Capital: Sales of Properties
On March 1, 2002, we closed the sale of our interest in Valentine Field for
$18.6 million. The transaction had an effective date of January 1, 2002. At
December 31, 2001, our independent reservoir engineering firm attributed 7.3
Bcfe of proved reserves net to our interest in this field. Consistent with the
full cost method of accounting, we did not recognize any gain or loss as a
result of this sale. The proceeds were treated as a reduction of the full cost
pool.
Use of Capital: Exploration and Development
We have an exploration and development program budget for the year 2003 that
will require significant capital. Our capital budget for capital for new
projects in 2003 is approximately $30 million of which $18 million had been
incurred by September 30, 2003. We have completed the drilling of our Murphy
Castle, Knight, Trout, Pinot Grigio and Riesling prospects, and are currently
drilling our Eagle, Amberjack and Dolcetto prospects. Our management believes
that cash flows from operations will be sufficient to fund planned 2003
exploration and development activities. Although we have not determined our
budget for capital for new projects in 2004, we are currently planning on
spending approximately $35-40 million depending on drilling success and related
completion and facility costs. In the future, our exploration and development
activities could require additional financings, which may include sales of
additional equity or debt securities, additional bank borrowings, sales of
properties, or joint venture arrangements with industry partners. We cannot
assure you that such additional financings will be available on acceptable
terms, if at all. If we are unable to obtain additional financing, we could be
forced to delay or even abandon some of our exploration and development
opportunities or be forced to sell some of our assets on an untimely or
unfavorable basis.
DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS
This Form 10-Q contains "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended (the "Securities Act"),
and Section 21E of the Securities Exchange Act of 1934, as amended (the
"Exchange Act"). All statements other than statements of historical facts
included in and incorporated by reference into this Form 10-Q are
forward-looking statements. These forward-looking statements are subject to
certain risks, trends and uncertainties that could cause actual results to
differ materially from those projected. Among those risks, trends and
uncertainties are the Company's estimate of the sufficiency of its existing
capital sources, its ability to raise additional capital to fund cash
requirements for future operations, the uncertainties involved in estimating
quantities of proved oil and natural gas reserves, in prospect development and
property acquisitions and in projecting future rates of production, the timing
of development expenditures and drilling of wells, and the operating hazards
attendant to the oil and gas business. In particular, careful consideration
should be given to cautionary statements made in the various reports the Company
has filed with the Securities and Exchange Commission. The Company undertakes no
duty to update or revise these forward-looking statements.
When used in the Form 10-Q, the words, "expect," "anticipate," "intend," "plan,"
"believe," "seek," "estimate" and similar expressions are intended to identify
forward-looking statements, although not all forward-looking statements contain
these identifying words. Because these forward-looking statements involve risks
and uncertainties, actual results could differ materially from those expressed
or implied by these forward-looking statements for a number of important
reasons, including those discussed under "Management's Discussions and Analysis
of Financial Condition and Results of Operations" and elsewhere in this Form
10-Q.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company experiences market risks primarily in two areas: interest rates and
commodity prices. The Company believes that its business operations are not
exposed to significant market risks relating to foreign currency exchange risk.
13
The Company's revenues are derived from the sale of its crude oil and natural
gas production. Based on projected annual sales volumes for the remaining three
months of 2003, a 10% change in the prices the Company receives for its crude
oil and natural gas production would have an approximate $1 million impact on
the Company's revenues.
In a typical hedge transaction, the Company will have the right to receive from
the counterparts to the hedge, the excess of the fixed price specified in the
hedge over a floating price based on a market index, multiplied by the quantity
hedged. If the floating price exceeds the fixed price, the Company is required
to pay the counterparts this difference multiplied by the quantity hedged. The
Company is required to pay the difference between the floating price and the
fixed price (when the floating price exceeds the fixed price) regardless of
whether the Company has sufficient production to cover the quantities specified
in the hedge. Significant reductions in production at times when the floating
price exceeds the fixed price could require the Company to make payments under
the hedge agreements even though such payments are not offset by sales of
production. Hedging will also prevent the Company from receiving the full
advantage of increases in oil or gas prices above the fixed amount specified in
the hedge. As of September 30, 2003, the Company had open fixed price swap
contracts with third parties, whereby a fixed price has been established for a
certain period. These agreements in effect for the remainder of 2003 are for oil
volume of 1,000 barrels per day at a weighted average price of $25.75, and gas
volume of 7,000 Mmbtu per day at a weighted average price of $4.02.
Additionally, the Company entered into a costless collar contract for 2004 for
2,500 Mmbtu per day with a floor price of $4.00 and ceiling price of $7.03. At
September 30, 2003, the Company recognized a liability of $665,000 related to
these derivative instruments, of which four have been designated as cash flow
hedges and one has been deemed ineffective, under accounting regulations, and
recorded through derivative expense on the income statement.
We currently have two interest rate swaps covering $5 million of our floating
rate debt. The swaps, which expire in November 2003 and 2004, have fixed
interest rates of 4.56% and 4.25%-5.665%, respectively. The swaps are stated at
their fair value and are marked-to-market through derivative expense in our
income statement. As of September 30, 2003, the fair value of the open interest
rate swaps was a liability of $306,000.
The Company also evaluated the potential effect that reasonably possible near
term changes may have on the Company's credit facility. Debt outstanding under
the facility is subject to a floating interest rate and represents 100% of the
Company's total debt as of September 30, 2003. Based upon an analysis, utilizing
the actual interest rate in effect and balances outstanding as of September 30,
2003 and assuming a 10% increase in interest rates and no changes in the amount
of debt outstanding, the potential effect on interest expense for the remaining
three months of 2003 is approximately $8,000.
Item 4. CONTROLS AND PROCEDURES
As of the end of the period covered by this report, the Company carried out an
evaluation, under the supervision and with the participation of the Company's
management, including the Company's Chief Executive Officer and Chief Financial
Officer, of the effectiveness of the design and operation of the Company's
disclosure controls and procedures pursuant to Rule 13a-15 of the Securities
Exchange Act of 1934 (the "Exchange Act"). Based upon that evaluation, the Chief
Executive Officer and Chief Financial Officer concluded that the Company's
disclosure controls and procedures are effective, in all material respects, with
respect to the recording, processing, summarizing and reporting, within the time
periods specified in the Securities and Exchange Commission's rules and forms,
of information required to be disclosed by the issuer in the reports that it
files or submits under the Exchange Act.
There have been no significant changes in the Company's internal control over
financial reporting during the period covered by this report that have
materially affected, or are reasonably likely to materially affect, the
Company's internal control over financial reporting.
14
PART II
Item 1. LEGAL PROCEEDINGS
NONE.
Item 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
NONE.
Item 3. DEFAULTS UPON SENIOR SECURITIES
NONE.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
NONE.
Item 5. OTHER INFORMATION
The Company announced the appointment of Michael L. Finch, age
48, as an independent member of the Company's Board of Directors. Mr.
Finch served as Chief Financial Officer and a member of the Board of
Directors of Stone Energy Corporation from 1993 until his retirement in
1999. He was affiliated with Stone in a variety of capacities for
nineteen years. Prior to his service with Stone, he was employed by an
international public accounting firm in New Orleans, Louisiana. Mr.
Finch has been a private investor since 1999. He was licensed as a
certified public accountant in 1978, and received a Bachelor of Science
in Accounting from the University of South Alabama in 1976.
The Company also announced the retirement of Alfred J. Thomas,
II as President and the resignation of Mr. Thomas and Jay B. Langner
from the Company's Board of Directors to devote more time to other
commitments. Mr. Thomas' retirement and resignation was effective on
September 5, 2003, and Mr. Langner's resignation was effective November
7, 2003.
Item 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
Exhibit 4.1, Warrant to Purchase Common Shares of PetroQuest
Energy, Inc.
Exhibit 10.1, Senior Second Lien Secured Credit Agreement
dated November 6, 2003, between PetroQuest Energy, L.L.C., PetroQuest
Energy, Inc., each of the Lenders from time to time party thereto; and
Macquarie Americas Corp., as administrative agent for the Lenders.
Exhibit 10.2, Unconditional Guaranty Agreement dated November
6, 2003, by PetroQuest Energy, Inc. to Macquarie Americas Corp., as
administrative agent for the benefit of the Lenders under the Credit
Agreement.
Exhibit 10.3, Employment agreement dated July 28, 2003,
between PetroQuest Energy, Inc. and Stephen H. Green
Exhibit 10.4, First Amendment to Amended and Restated Credit
Agreement dated as of November 6, 2003, by and among PetroQuest Energy,
L.L.C., PetroQuest Energy, Inc.; Bank One, N.A., and Union Bank of
California, N.A.
Exhibit 31.1, Certification of Chief Executive Officer
pursuant to Rule 13-a-14(a) / Rule 15d-14(a), promulgated under the
Securities Exchange Act of 1934, as amended.
15
Exhibit 31.2, Certification of Chief Financial Officer
pursuant to Rule 13-a-14(a) / Rule 15d-14(a), promulgated under the
Securities Exchange Act of 1934, as amended.
Exhibit 32.1, Certification Pursuant To 18 U.S.C. Section
1350, As Adopted Pursuant To Section 906 Of The Sarbanes-Oxley Act Of
2002
Exhibit 32.2, Certification Pursuant to 18 U.S.C. Section
1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
(b) Reports on Form 8-K:
On July 30, 2003, the Company filed a current report on Form
8-K regarding its 2003 second quarter results.
16
SIGNATURE
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.
PETROQUEST ENERGY, INC.
Date: November 13, 2003 By: /s/ Michael O. Aldridge
--------------------------------------
Michael O. Aldridge
Senior Vice President, Chief
Financial Officer and Treasurer
(Authorized Officer and Principal
Financial and Accounting Officer)
17