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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: March 31, 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 May 9, 2003, there were 42,852,394 shares of the registrant's
common stock, par value $.001 per share, outstanding.
PETROQUEST ENERGY, INC.
Table of Contents
Part I. Financial Information Page No.
Item 1. Financial Statements
Consolidated Balance Sheets as of
March 31, 2003 and December 31, 2002.................................................... 1
Consolidated Statements of Operations for the
Three Months Ended March 31, 2003 and 2002.............................................. 2
Consolidated Statements of Cash Flows for the
Three Months Ended March 31, 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.................................................................... 13
Part II. Other Information
Item 1. Legal Proceedings........................................................................... 14
Item 2. Changes in Securities and Use of Proceeds................................................... 14
Item 3. Defaults upon Senior Securities............................................................. 14
Item 4. Submission of Matters to a Vote of Security Holders........................................ 14
Item 5. Other Information........................................................................... 14
Item 6. Exhibits and Reports on Form 8-K............................................................ 14
PETROQUEST ENERGY, INC.
Consolidated Balance Sheets
(Amounts in Thousands)
March 31, December 31,
2003 2002
--------- ---------
(unaudited) (Note 1)
ASSETS
Current assets:
Cash and cash equivalents $ 1,255 $ 1,137
Oil and gas revenue receivable 6,787 6,500
Joint interest billing receivable 2,441 2,165
Other current assets 1,472 310
--------- ---------
Total current assets 11,955 10,112
--------- ---------
Oil and gas properties:
Oil and gas properties, full cost method 232,405 214,543
Unevaluated oil and gas properties 11,738 15,653
Accumulated depreciation, depletion and amortization (115,194) (109,450)
--------- ---------
Oil and gas properties, net 128,949 120,746
--------- ---------
Other assets, net of accumulated depreciation and amortization
of $3,003 and $2,851, respectively 1,103 1,205
--------- ---------
Total assets $ 142,007 $ 132,063
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 11,919 $ 18,337
Advances from co-owners 2,808 940
Current portion of long-term debt 10,000 6,600
--------- ---------
Total current liabilities 24,727 25,877
--------- ---------
Long-term debt -- 2,400
Asset retirement obligation 9,607 --
Deferred income taxes 6,826 5,461
Other liabilities 555 555
Commitments and contingencies -- --
Stockholders' equity:
Common stock, $.001 par value; authorized 75,000
shares; issued and outstanding 42,852 and 42,852
shares, respectively 43 43
Paid-in capital 106,134 106,173
Other comprehensive income (1,715) (1,197)
Unearned deferred compensation (251) (337)
Accumulated deficit (3,919) (6,912)
--------- ---------
Total stockholders' equity 100,292 97,770
--------- ---------
Total liabilities and stockholders' equity $ 142,007 $ 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
-----------------------
March 31,
-----------------------
2003 2002
-------- --------
Revenues:
Oil and gas sales $ 16,154 $ 10,509
Interest and other income (24) (12)
-------- --------
16,130 10,497
-------- --------
Expenses:
Lease operating expenses 2,762 2,349
Production taxes 210 202
Depreciation, depletion and amortization 8,473 7,094
General and administrative 1,223 1,200
Accretion of asset retirement obligation 140 --
Interest expense 23 211
-------- --------
12,831 11,056
-------- --------
Income from operations 3,299 (559)
Income tax expense (benefit) 1,155 (195)
-------- --------
Income (loss) before cumulative effect of
change in accounting principle $ 2,144 $ (364)
Cumulative effect of change in accounting principle $ 849 $ --
-------- --------
Net income (loss) $ 2,993 $ (364)
======== ========
Earnings (loss) per common share:
Basic
Income (loss) before cumulative effect of
change in accounting principle $ 0.05 $ (0.01)
Cumulative effect of change in
accounting principle $ 0.02 $ --
-------- --------
Net income (loss) $ 0.07 $ (0.01)
======== ========
Diluted
Income (loss) before cumulative effect of
change in accounting principle $ 0.05 $ (0.01)
Cumulative effect of change in
accounting principle $ 0.02 $ --
-------- --------
Net income (loss) $ 0.07 $ (0.01)
======== ========
Weighted average number of common shares:
Basic 42,852 34,724
======== ========
Diluted 44,168 34,724
======== ========
See accompanying Notes to Consolidated Financial Statements.
2
PETROQUEST ENERGY, INC.
Consolidated Statements of Cash Flows
(unaudited)
(Amounts in Thousands)
Three Months Ended
----------------------
March 31,
----------------------
2003 2002
------- --------
Cash flows from operating activities:
Net income (loss) $ 2,993 $ (364)
Adjustments to reconcile net income to net cash provided by
operating activities:
Deferred tax expense (benefit) 1,155 (195)
Depreciation, depletion and amortization 8,473 7,094
Cumulative effect of change in accounting principle (849) --
Accretion of asset retirement obligation 140 --
Amortization of debt issuance costs 45 118
Compensation expense 86 86
Derivative mark to market (41) 6
Changes in working capital accounts:
Accounts receivable (286) 193
Joint interest billing receivable (275) 3,642
Other assets (51) (241)
Accounts payable and accrued liabilities (5,679) (3,788)
Advances from co-owners 2,139 (1,624)
Plugging and abandonment escrow -- 349
Other (1,162) (1,209)
------- --------
Net cash provided by operating activities 6,688 4,067
------- --------
Cash flows from investing activities:
Investment in oil and gas properties (7,564) (12,777)
Sale of oil and gas properties, net -- 17,320
------- --------
Net cash (used in) provided by investing activities (7,564) 4,543
------- --------
Cash flows from investing activities:
Exercise of options and warrants -- 137
Proceeds from borrowings 3,000 --
Repayment of debt (2,000) (31,329)
Issuance of common stock, net of expenses (6) 21,834
------- --------
Net cash provided by (used in) financing activities 994 (9,358)
------- --------
Net increase (decrease) in cash and cash equivalents 118 (748)
Cash balance and cash equivalents, beginning of period 1,137 1,063
------- --------
Cash balance and cash equivalents, end of period $ 1,255 $ 315
======= ========
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest $ 76 $ 370
======= ========
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-month periods
ended March 31, 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 March 31, 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).
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 1,325,587 shares of common stock were outstanding
during the three-month period ended March 31, 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 $3.13-$7.65 and expire in
2010-2012. For the three months ended March 31, 2002, 3,391,665 of the Company's
options and warrants were not included in the computation of diluted loss per
share because the effect of the assumed exercise of these stock options as of
the beginning of the year would have an antidilutive effect.
NOTE 3 LONG-TERM DEBT
The Company entered into a new bank credit facility on May 14, 2003
with a group of two banks, which replaces the current credit facility. The
Company will expense approximately $200,000 of deferred financing costs during
the quarter ended June 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 January 1 and July 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. The initial borrowing base
under this credit facility is $15.5 million and is subject to monthly reductions
of $1.25 million beginning June 1, 2003. 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%)
4
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 May 14, 2003,
the Company had $9 million of borrowings and a $2.6 million letter 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. The credit
facility matures during May 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 other income in the
Company's income statement. At March 31, 2003, the Company recognized a
liability of $435,000 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 quarter ended March 31, 2002 would have increased net income
by $90,000.
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:
Quarter Ended
March 31, 2003
--------------
Asset retirement obligation at beginning of year $ --
Liability recognized in transition 9,467,000
Accretion expense 140,000
----------
Asset retirement obligation at end of period $9,607,000
==========
If the new accounting rules had been adopted on January 1, 2002, the
asset retirement obligation would have approximated $7.3 million.
5
NOTE 5 EQUITY
Other Comprehensive Income
The following table presents a recap of the Company's comprehensive
income for the three-month periods ended March 31, 2003 and 2002 (in thousands):
Three Months Ended
March 31,
2003 2002
------- -----
Net income (loss) $ 2,993 $(364)
Change in fair value of derivative instrument,
accounted for as hedges, net of taxes (337) (376)
------- -----
Comprehensive income (loss) $ 2,656 $(740)
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 March 31, 2003, the Company had fixed price swap
contracts with third parties, whereby a fixed price has been established for a
certain period. At March 31, 2003 and 2002, the effect of derivative financial
instruments is net of deferred income tax benefit of $181,000 and $203,000,
respectively.
Unearned Deferred Compensation
In April 2001, the original owners, (the "Original Owners") of American
Explorer L.L.C. entered into an agreement with an officer of the Company whereby
the Original Owners granted to the officer an option to acquire, at a fixed
price, certain of the shares the Original Owners were issued in the September 1,
1998 merger and reorganization (the "Merger"). As the fixed price of the April
grant was below the market price as of the date of grant, the Company is
recognizing non-cash compensation expense over the three-year vesting period of
the option. In addition, the Original Owners granted to the officer an interest
in a portion of the 1,667,001 shares of common stock issuable pursuant to the
Contingent Stock Issue Rights (the "CSIRs") issued to the Original Owners in the
Merger, if any, that might be issued. This agreement is similar to agreements
previously entered into with two other officers of the Company. Non-cash
compensation expense is being recognized for the common stock issuable pursuant
to the CSIRs granted to the three officers over the three-year vesting period
based on the fair value of the common stock issuable pursuant to the CSIRs in
May 2001, when the common stock issuable pursuant to the CSIRs was issued to the
Original Owners. The Company has recorded the effects of the transactions as
deferred compensation until fully amortized. The Company recorded non-cash
compensation expense of $86,000 during the quarters ended March 31, 2003 and
2002, respectively, which is included in general and administrative expense.
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 (loss), 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 Company is recognizing compensation expense as a result of
the Original Owners granting options to three officers as discussed in Note 5.
The following table illustrates the effect on net income (loss) and earnings
(loss) per share if the Company had applied the fair value recognition
provisions of SFAS No. 123, "Accounting for Stock Based Compensation"
6
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
-------------------------
March 31,
-------------------------
2003 2002
--------- ---------
Net income (loss) 2,993 (364)
Stock-based compensation:
Add expense included in reported results, net of tax 56 56
Deduct fair value based method, net of tax (112) (226)
--------- ---------
Pro forma net income (loss) 2,937 (534)
Earnings (loss) per common share:
Basic - as reported $ 0.07 ($0.01)
Basic - pro forma $ 0.07 ($0.02)
Diluted - as reported $ 0.07 ($0.01)
Diluted - pro forma $ 0.07 ($0.02)
NOTE 7 DISPOSITION OF PROPERTY
On March 1, 2002, the Company closed the sale of its interest in
Valentine Field for $18.6 million. The transaction had an effective date of
January 1, 2002. At December 31, 2001, the Company's independent reservoir
engineering firm attributed 7.3 Bcfe of proved reserves net to the Company's
interest in this field. Consistent with the full cost method of accounting, the
Company 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 through an increase
in accumulated depreciation, depletion and amortization.
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 March 31, 2003, the Company operated
approximately 95% of all of its proved reserves. For the three months ended
March 31, 2003, approximately 47% of the Company's equivalent production was oil
and 53% 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.
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. 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.
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
--------------------------
March 31,
--------------------------
2003 2002
---------- ----------
Production:
Oil (Bbls) 234,830 234,508
Gas (Mcf) 1,606,318 2,384,964
Total Production (Mcfe) 3,015,298 3,792,012
Sales:
Total oil sales $7,235,119 $4,853,441
Total gas sales 8,918,569 5,655,498
Average sales prices:
Oil (per Bbl) $ 30.81 $ 20.70
Gas (per Mcf) 5.55 2.37
Per Mcfe 5.36 2.77
The above sales include reductions related to gas hedges of $1,644,000 and
$138,000 and oil hedges of $725,000 and zero for the three months ended March
31, 2003 and 2002, respectively.
Net income totaled $2,993,000 for the quarter ended March 31, 2003. The Company
incurred a net loss of $364,000 for the quarter ended March 31, 2002. The
results are attributable to the following components:
PRODUCTION. Oil production in 2003 remained relatively flat as compared to the
quarter ended March 31, 2002. Natural gas production in 2003 decreased 33% over
the quarter ended March 31, 2002. On a Mcfe basis, production for the first
quarter decreased 20% over the same period in 2002. The decrease in production
for the quarter ended March 31, 2003 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. The average oil price per Bbl for the quarter ended March 31, 2003 was
$30.81, as compared to $20.70 for the same period in 2002. Average gas price per
Mcf was $5.55 for the quarter ended March 31, 2003, as compared to $2.37 for the
same period in 2002. Stated on a Mcfe basis, unit prices received during the
first quarter 2003 were 94% higher than the prices received during the
comparable 2002 period.
REVENUE. Oil and gas sales during the quarter ended March 31, 2003 increased to
$16,154,000 as compared to sales of $10,509,000 for the same period in 2002. The
increase in commodity prices partially offset by a decrease in production
volumes, resulted in an increase in revenue.
EXPENSES. Lease operating expenses for the quarter ended March 31, 2003
increased to $2,762,000 as compared to $2,349,000 for the quarter ended March
31, 2002. On a Mcfe basis, lease operating expenses for the quarter ended March
31, 2003 increased to $0.92 as compared to $0.62 for the same period in 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 quarter ended March 31, 2003
totaled $1,223,000 as compared to expenses of $1,200,000 during the 2002 period.
The Company capitalized $978,000 and $925,000, respectively, of general and
administrative costs during the quarters ended March 31, 2003 and 2002. We
recognized $86,000 of non-cash compensation expense during the quarters ended
March 31, 2003 and 2002.
Depreciation, depletion and amortization ("DD&A") expense in 2003 increased 19%
over the quarter ended March 31, 2002. On a Mcfe basis, which reflects the
changes in production, the DD&A rate for the first quarter of 2003 was $2.81 per
Mcfe as compared to $1.87 per Mcfe for the same period in 2002. The increase in
2003 as compared
10
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, decreased
$188,000 during the quarter ended March 31, 2003 as compared to same period in
2002. The decrease is the result of a decrease in the average debt levels and
interest rates during the current year. We capitalized $124,000 and $164,000 of
interest during the three months ended March 31, 2003 and 2002, respectively.
Income tax expense of $1,155,000 was recognized during quarter ended March 31,
2003. We recorded an income tax benefit of $195,000 during the quarter ended
March 31, 2002. The increase is a result of an increase 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 quarter increased from $4,067,000 in
2002 to $6,688,000 in 2003. This increase resulted primarily from an increase in
the average realized commodity prices. Additionally, we utilized discretionary
cash flow to reduce our vendor payables during the first quarter 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 $(12.8) million at March
31, 2003. This increase was caused primarily by our effort to utilize cash flow
to first reduce our working capital deficit and second to drill prospects. These
strategies were partially offset by an increase in the current portion of
long-term debt due to the borrowing base reductions as required by our credit
facility. In order to reduce expenses for the remainder of 2003, our management
team has voluntarily reduced salaries, and we have reduced our staff, which
should result in an aggregate annual savings of in excess of $1 million.
Source of Capital: Debt
We entered into a new bank credit facility on May 14, 2003 with a group of two
banks, which replaces our current credit facility. We will expense approximately
$200,000 of deferred financing costs during the quarter ended June 30, 2003
relating to our 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 us to borrow amounts from time
to time based on 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 January 1 and July 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. The initial borrowing base under this credit facility is $15.5
million and is subject to monthly reductions of $1.25 million beginning June 1,
2003. 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 May 14,
2003, we had $9 million of borrowings and a $2.6 million letter 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. The credit facility matures
during May 2006.
11
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 three months ended March 31, 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.
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 direct capital for new
projects in 2003 is approximately $25 million of which $4.7 million had been
incurred by March 31, 2003. Our management believes that cash flows from
operations will be sufficient to fund planned 2003 exploration and development
activities. We will actively seek industry partners for certain of our prospects
to provide further funding for our 2003 planned activities. 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.
12
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.
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 nine
months of 2003, a 10% change in the prices the Company receives for its crude
oil and natural gas production would have an approximate $3 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 March 31, 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. At March 31, 2003,
the Company recognized a liability of $2,639,000 related to these derivative
instruments, which have been designated as cash flow hedges.
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 other income in our income
statement. As of March 31, 2003, the fair value of the open interest rate swaps
was a liability of $435,000.
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 March 31, 2003. Based upon an analysis, utilizing the
actual interest rate in effect and balances outstanding as of March 31, 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 nine
months of 2003 is approximately $26,000.
Item 4. CONTROLS AND PROCEDURES
Within the 90-day period prior to the date of 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-14 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 controls or in
other factors that could significantly affect internal controls subsequent to
the date the Company carried out its evaluation.
13
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
NONE.
Item 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
Exhibit 99.1, Certification Pursuant To 18 U.S.C. Section
1350, As Adopted Pursuant To Section 906 Of The Sarbanes-Oxley Act Of
2002
Exhibit 99.2, 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 January 27, 2003, the Company filed a current report on
Form 8-K regarding drilling results.
On February 18, 2003, the Company filed a current report on
Form 8-K regarding its 2002 year-end proved oil and gas
reserves.
On February 26, 2003, the Company filed a current report on
Form 8-K regarding its 2002 year-end and fourth quarter
results.
14
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: May 15, 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)
15
CERTIFICATIONS
I, Charles T. Goodson, certify that:
1. I have reviewed this quarterly report on Form 10-Q of PetroQuest
Energy, Inc.;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly report
is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about
the effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability
to record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves
management or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: May 14, 2003 By: /s/ Charles T. Goodson
---------------------------------------
Charles T. Goodson
Chairman of the Board and Chief
Executive Officer (Principal Executive
Officer)
16
I, Michael O. Aldridge, certify that:
1. I have reviewed this quarterly report on Form 10-Q of PetroQuest
Energy, Inc.;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this quarterly report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: May 14, 2003 By: /s/ Michael O. Aldridge
----------------------------------------
Michael O. Aldridge
Senior Vice President, Chief Financial
Officer and Treasurer (Principal
Financial Officer)
17