SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2002
(_) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.
Commission file number 1-10447
CABOT OIL & GAS CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 04-3072771
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
1200 Enclave Parkway, Houston, Texas 77077
(Address of principal executive offices including Zip Code)
(281) 589-4600
(Registrant's telephone number)
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 and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No___
--
As of April 24, 2002, there were 31,965,705 shares of Class A Common
Stock, Par Value $.10 Per Share, outstanding.
CABOT OIL & GAS CORPORATION
INDEX TO FINANCIAL STATEMENTS
Part I. Financial Information Page
----
Item 1. Financial Statements
Condensed Consolidated Statement of Operations for the Three Months
Ended March 31, 2002 and 2001.................................................................. 3
Condensed Consolidated Balance Sheet at March 31, 2002 and December 31, 2001..................... 4
Condensed Consolidated Statement of Cash Flows for the Three Months
Ended March 31, 2002 and 2001.................................................................. 5
Notes to the Condensed Consolidated Financial Statements......................................... 6
Report of Independent Accountant's Review of Interim Financial Information....................... 12
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations...................................................................... 13
Item 3A. Quantitative and Qualitative Disclosures about Market Risk................................. 20
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K............................................................ 22
Signature................................................................................................. 23
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PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
------------------------------
CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
(In Thousands, Except Per Share Amounts)
THREE MONTHS ENDED
MARCH 31,
-------------------------------
2002 2001
---------- -----------
OPERATING REVENUES
Natural Gas Production........................................................ $ 46,506 $ 100,725
Brokered Natural Gas.......................................................... 13,698 35,422
Crude Oil & Condensate........................................................ 13,718 11,556
Change in Derivative Fair Value (Note 8)..................................... (616) 6,198
Other......................................................................... 1,767 990
---------- -----------
75,073 154,891
OPERATING EXPENSES
Brokered Natural Gas Cost..................................................... 12,267 34,155
Production and Pipeline Operations............................................ 12,235 8,220
Exploration................................................................... 7,056 10,773
Depreciation, Depletion and Amortization...................................... 23,210 15,891
Impairment of Unproved Properties............................................. 2,337 1,482
Impairment of Long-Lived Assets............................................... 1,063 --
General and Administrative.................................................... 5,739 5,946
Taxes Other than Income....................................................... 6,152 9,902
---------- -----------
70,059 86,369
Gain (Loss) on Sale of Assets..................................................... (18) 4
---------- -----------
INCOME FROM OPERATIONS............................................................ 4,996 68,526
Interest Expense and Other........................................................ 6,226 4,706
---------- -----------
Income (Loss) Before Income Taxes................................................. (1,230) 63,820
Income Tax Expense (Benefit)...................................................... (432) 24,758
---------- -----------
NET INCOME (LOSS)................................................................. $ (798) $ 39,062
========== ===========
Basic Earnings (Loss) Per Share................................................... $ (0.03) $ 1.33
Diluted Earnings (Loss) Per Share................................................. $ (0.03) $ 1.32
Average Common Shares Outstanding................................................. 31,604 29,318
The accompanying notes are an integral part of these condensed
consolidated financial statements.
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CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)
(In Thousands)
MARCH 31, DECEMBER 31,
2002 2001
------------- -------------
ASSETS
Current Assets
Cash and Cash Equivalents................................................ $ 4,976 $ 5,706
Accounts Receivable...................................................... 51,635 50,711
Inventories.............................................................. 12,065 17,560
Other.................................................................... 12,740 11,010
------------- -------------
Total Current Assets.................................................. 81,416 84,987
Properties and Equipment, Net (Successful Efforts Method).................... 982,146 981,338
Other Assets................................................................. 2,613 2,706
------------- -------------
$ 1,066,175 $ 1,069,031
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable......................................................... $ 64,028 $ 79,575
Accrued Liabilities...................................................... 41,114 30,665
------------- -------------
Total Current Liabilities............................................. 105,142 110,240
Long-Term Debt............................................................... 412,000 393,000
Deferred Income Taxes........................................................ 194,543 200,859
Other Liabilities............................................................ 18,798 18,380
Stockholders' Equity
Common Stock:
Authorized -- 40,000,000 Shares of $.10 Par Value
Issued and Outstanding - 31,911,685 Shares and
31,905,097 Shares in 2002 and 2001, Respectively...................... 3,191 3,191
Additional Paid-in Capital............................................... 346,885 346,260
Retained Earnings (Accumulated Deficit).................................. (1,412) 650
Other Comprehensive Income (Loss) (Note 9)............................... (8,588) 835
Less Treasury Stock, at Cost:
302,600 Shares in 2002 and 2001....................................... (4,384) (4,384)
------------- -------------
Total Stockholders' Equity............................................ 335,692 346,552
------------- -------------
$ 1,066,175 $ 1,069,031
============= =============
The accompanying notes are an integral part of these condensed
consolidated financial statements.
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CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
(In Thousands)
THREE MONTHS ENDED
MARCH 31,
------------------------------
2002 2001
----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)............................................................. $ (798) $ 39,062
Adjustment to Reconcile Net Income to Cash
Provided by Operating Activities:
Depletion, Depreciation and Amortization.................................. 23,210 15,891
Impairment of Undeveloped Leasehold....................................... 2,337 1,482
Impairment of Long-Lived Assets........................................... 1,063 --
Deferred Income Tax Expense............................................... (471) 13,788
(Gain) Loss on Sale of Assets............................................. 18 (4)
Exploration Expense....................................................... 7,056 10,773
Change in Derivative Fair Value........................................... 616 (6,198)
Other..................................................................... 1,364 777
Changes in Assets and Liabilities:
Accounts Receivable....................................................... (924) 14,533
Inventories............................................................... 5,495 3,461
Other Current Assets...................................................... (3,235) 1,759
Other Assets.............................................................. 93 144
Accounts Payable and Accrued Liabilities.................................. (6,100) 13,110
Other Liabilities......................................................... (175) 1,020
----------- -----------
Net Cash Provided by Operating Activities.............................. 29,549 109,598
----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures.......................................................... (41,062) (34,748)
Proceeds from Sale of Assets.................................................. (2) 438
Exploration Expense........................................................... (7,056) (10,773)
----------- -----------
Net Cash Used by Investing Activities.................................. (48,120) (45,083)
----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt.............................................................. 56,000 19,000
Decrease in Debt.............................................................. (37,000) (89,000)
Sale of Common Stock.......................................................... 105 4,194
Dividends Paid................................................................ (1,264) (1,172)
----------- -----------
Net Cash Provided (Used) by Financing Activities....................... 17,841 (66,978)
----------- -----------
Net Decrease in Cash and Cash Equivalents......................................... (730) (2,463)
Cash and Cash Equivalents, Beginning of Period.................................... 5,706 7,574
----------- -----------
Cash and Cash Equivalents, End of Period.......................................... $ 4,976 $ 5,111
=========== ===========
The accompanying notes are an integral part of these condensed
consolidated financial statements.
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CABOT OIL & GAS CORPORATION
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
1. FINANCIAL STATEMENT PRESENTATION
During interim periods, Cabot Oil & Gas Corporation follows the same
accounting policies used in its Annual Report to Stockholders and its Report on
Form 10-K filed with the Securities and Exchange Commission. People using
financial information produced for interim periods are encouraged to refer to
the footnotes in the Annual Report to Stockholders when reviewing interim
financial results. In management's opinion, the accompanying interim financial
statements contain all material adjustments, consisting only of normal recurring
adjustments, necessary for a fair presentation. The results of operations for
any interim period are not necessarily indicative of the results of operations
for the entire year.
Our independent accountants have performed a review of these condensed
consolidated interim financial statements in accordance with standards
established by the American Institute of Certified Public Accountants. Pursuant
to Rule 436(c) under the Securities Act of 1933, this report should not be
considered a part of a registration statement prepared or certified by
PricewaterhouseCoopers LLP within the meanings of Section 7 and 11 of the Act.
In June 2001, the Financial Accounting Standards Board ("FASB") approved
for issuance Statement of Financial Accounting Standards 143, "Asset Retirement
Obligations" ("SFAS 143"). SFAS 143 establishes accounting requirements for
retirement obligations associated with tangible long-lived assets, including (1)
the timing of the liability recognition, (2) initial measurement of the
liability, (3) allocation of asset retirement cost to expense, (4) subsequent
measurement of the liability and (5) financial statement disclosures. SFAS 143
requires that an asset retirement cost should be capitalized as part of the cost
of the related long-lived asset and subsequently allocated to expense using a
systematic and rational method. The Company will adopt the statement effective
no later than January 1, 2003, as required. The transition adjustment resulting
from the adoption of SFAS 143 will be reported as a cumulative effect of a
change in accounting principle. At this time, the Company cannot reasonably
estimate the effect of the adoption of this statement on its financial position,
results of operations, or cash flows.
2. PROPERTIES AND EQUIPMENT
Properties and equipment are comprised of the following:
MARCH 31, DECEMBER 31,
2002 2001
----------- ------------
(In thousands)
Unproved Oil and Gas Properties........................................ $ 70,014 $ 70,709
Proved Oil and Gas Properties.......................................... 1,426,317 1,400,341
Gathering and Pipeline Systems......................................... 132,201 131,768
Land, Building and Improvements........................................ 4,767 4,674
Other.................................................................. 27,844 27,513
----------- ------------
1,661,143 1,635,005
Accumulated Depreciation, Depletion and Amortization................... (678,997) (653,667)
----------- ------------
$ 982,146 $ 981,338
=========== ============
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3. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
MARCH 31, DECEMBER 31,
2002 2001
---------- ------------
(In thousands)
Accounts Receivable
Trade Accounts.......................................................... $ 41,976 $ 39,570
Joint Interest Accounts................................................. 11,274 12,889
Current Income Tax Receivable........................................... 2,662 2,662
Other Accounts.......................................................... 990 986
---------- ----------
56,902 56,107
Allowance for Doubtful Accounts........................................... (5,267) (5,396)
---------- ----------
$ 51,635 $ 50,711
========== ==========
Other Current Assets
Commodity Hedging Contracts............................................. $ -- $ 2,387
Drilling Advances....................................................... 4,544 2,111
Prepaid Balances........................................................ 1,508 2,114
Restricted Cash and Other Accounts...................................... 6,688 4,398
---------- ----------
$ 12,740 $ 11,010
========== ==========
Accounts Payable
Trade Accounts.......................................................... $ 20,457 $ 19,914
Natural Gas Purchases................................................... 3,828 4,559
Royalty and Other Owners................................................ 12,581 11,041
Capital Costs........................................................... 17,304 30,923
Taxes Other Than Income................................................. 1,835 2,686
Drilling Advances....................................................... 2,405 2,627
Wellhead Gas Imbalances................................................. 2,634 2,353
Other Accounts.......................................................... 2,984 5,472
---------- ----------
$ 64,028 $ 79,575
========== ==========
Accrued Liabilities
Employee Benefits....................................................... $ 3,894 $ 7,151
Taxes Other Than Income................................................. 14,354 13,623
Interest Payable........................................................ 5,789 6,996
Commodity Hedging Contracts - Short-Term................................ 14,380 --
Other Accrued........................................................... 2,697 2,895
---------- ----------
$ 41,114 $ 30,665
========== ==========
Other Liabilities
Postretirement Benefits Other Than Pension.............................. $ 1,693 $ 1,689
Accrued Pension Cost.................................................... 7,715 7,280
Taxes Other Than Income and Other....................................... 9,390 9,411
---------- ----------
$ 18,798 $ 18,380
========== ==========
4. LONG-TERM DEBT
At March 31, 2002, the Company had $142 million outstanding under its
credit facility, which provides for an available credit line of $250 million.
The available credit line is subject to adjustment from time-to-time on the
basis of the projected present value (as determined by the banks' petroleum
engineer incorporating certain assumptions provided by the lender) of estimated
future net cash flows from proved oil and gas reserves and other assets of the
Company. The revolving term under this credit facility
-7-
presently ends in December 2003 and is subject to renewal. At March 31, 2002,
excess capacity totaled $108 million, or 43% of the total available credit line.
In addition to the credit facility, the Company has the following debt
outstanding:
.. $100 million of 12-year 7.19% Notes to be repaid in five annual
installments of $20 million beginning in November 2005
.. $75 million of 10-year 7.26% Notes due in July 2011
.. $75 million of 12-year 7.36% Notes due in July 2013
.. $20 million of 15-year 7.46% Notes due in July 2016
5. EARNINGS PER SHARE
Basic earnings per share for the first three months of the year were based
on the year-to-date weighted average shares outstanding of 31,603,717 in 2002
and 29,318,262 in 2001. The diluted earnings per share amounts are based on
weighted average shares outstanding plus common stock equivalents. Common stock
equivalents include both stock awards and stock options, and totaled 471,719 in
2002 and 396,431 in 2001.
6. ENVIRONMENTAL LIABILITY
The EPA notified the Company in February 2000 of its potential liability
for waste material disposed of at the Casmalia Superfund Site ("Site"), located
on a 252-acre parcel in Santa Barbara County, California. Over 10,000 separate
parties disposed of waste at the Site while it was operational from 1973 to
1992. The EPA stated that federal, state and local governmental agencies along
with the numerous private entities that used the Site for disposal of
approximately 4.5 billion pounds of waste would be expected to pay the clean-up
costs, which are estimated by the EPA to be $271.9 million. The EPA is also
pursuing the owners/operators of the Site to pay for remediation.
Documents received by the Company with the notification from the EPA
indicate that the Company used the Site principally to dispose of salt water
from two wells over a period from 1976 to 1979. There is no allegation that the
Company violated any laws in the disposal of material at the Site. The EPA's
actions stem from the fact that the owners/operators of the Site do not have the
financial means to implement a closure plan for the Site.
A group of potentially responsible parties, including the Company, formed a
group, called the Casmalia Negotiating Committee ("CNC"). The CNC has had
extensive settlement discussions with the EPA and has reached a settlement in
principal to pay approximately $27 million toward Site clean up in return for a
release from liability. The CNC is currently negotiating a consent decree to
memorialize the settlement. On January 30, 2002, the Company placed $1,283,283
in an escrow account. This amount approximates the Company's volumetric share of
EPA's cost estimate, plus a 5% premium and is the Company's settlement amount.
The escrow account is being funded by the Company and many other CNC members to
maximize the likelihood that there will be sufficient funds to fund the
settlement agreement upon its completion, which is expected later in 2002. This
cash settlement, once released from escrow and paid to the federal government,
will resolve all federal claims against the Company for response costs and will
release the Company from all response costs related to the Site, except for
future claims against the Company for natural resource damage, unknown
conditions, transshipment risks and claims by third parties, all of which are
expected to be covered by insurance to be purchased by participating CNC
members. Responsibility for certain State of California oversight and response
costs, while not covered by the settlement or insurance, are not expected to be
material. No determination has been made as to whether any insurance arrangement
will allow the Company to recover its contribution to the settlement.
The Company has established a reserve that management believes to be
adequate to provide for this environmental liability based on its estimate of
the probable outcome of this matter and estimated legal costs.
-8-
7. LITIGATION
Wyoming Royalty Litigation
In June 2000, two overriding royalty owners sued the Company in Wyoming
State court for unspecified damages. The plaintiffs have requested class
certification under the Wyoming Rules of Civil Procedure and allege that the
Company has deducted improper costs of production from royalty payments to the
plaintiffs and other similarly situated persons. Additionally, the suit claims
that the Company has failed to properly inform the plaintiffs and other
similarly situated persons of the deductions taken from royalties. In December
2001, fourteen overriding royalty owners sued the Company in Wyoming federal
court. The plaintiffs in the federal case have made the same general claims
pertaining to deductions from their overriding royalty as the plaintiffs in the
Wyoming state court case but have not asked for class certification.
The Company believes that it has substantial defenses to these claims and
intends to vigorously assert such defenses. The Company has a reserve that it
believes is adequate to provide for these potential liabilities based on its
estimate of the probable outcome of this matter. While the potential impact to
the Company may materially affect quarterly or annual financial results
including cash flows, management does not believe it would materially impact the
Company's financial position.
West Virginia Royalty Litigation
In late December 2001, two royalty owners sued the Company in West Virginia
State court for an unspecified amount of damages. The plaintiffs have requested
class certification under the West Virginia Rules of Civil Procedure and allege
that the Company has failed to pay royalty based upon the wholesale market value
of the gas produced, that the Company has taken improper deductions from the
royalty and has failed to properly inform the plaintiffs and other similarly
situated persons of deductions taken from the royalty. The plaintiffs have also
claimed that they are entitled to a 1/8th royalty share of the gas sales
contract settlement the Company reached with Columbia in the 1995 Columbia
bankruptcy proceeding.
The Company has removed the suit to Federal court. At a recent status
conference, the Court set up a schedule for the procedural handling of the
plaintiffs' allegations that the case should proceed as a class action. Under
this procedure, all discovery and pleadings necessary to place class
certification issue before the Court are expected to be completed by November 1,
2002.
The investigation into this claim continues and it is in the discovery
phase. The Company intends to vigorously defend the case. The Company has a
reserve that it believes is adequate to provide for these potential liabilities
based on its estimate of the probable outcome of this matter. While the
potential impact to the Company may materially affect quarterly or annual
financial results including cash flows, management does not believe it would
materially impact the Company's financial position.
8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY
The Company periodically enters into derivative commodity instruments to
hedge its exposure to price fluctuation on natural gas and crude oil production.
At March 31, 2002, the Company had three cash flow hedges open: a series of nine
natural gas collar arrangements, a series of ten natural gas costless collar
arrangements and one crude oil price collar arrangement. At March 31, 2002, a
$13.9 million pre-tax unrealized loss was recorded to Other Comprehensive Income
along with a $14.4 million derivative liability, and a non-cash loss of
approximately $0.5 million. The ineffective portion of the cash flow hedges was
recorded as a component of the Change in Derivative Fair Value on the income
statement. If commodity prices equal those as of March 31, 2002, the Company
would reclass a deferred loss of approximately $8.6 million ($13.9 million pre-
tax) to earnings from Accumulated Other Comprehensive Income during the next
twelve months.
-9-
For 2002, the Company has entered into the following derivative
arrangements:
.. A series of nine natural gas price collar arrangements covering 16.1 Bcf of
production over the period of January through April 2002 with weighted
average floor and ceiling prices of $2.68 per Mcf and $3.53 per Mcf.
.. A series of ten natural gas price costless collar arrangements covering 18.3
Bcf of production over the period of May through August 2002 with weighted
average floor and ceiling prices of $2.54 per Mcf and $3.17 per Mcf.
.. A crude oil price collar arrangement covering 1,224 Mbbls of production over
the period of March through December 2002 with a $20.00 per barrel floor price
and a $23.00 per barrel ceiling price.
9. COMPREHENSIVE INCOME
Comprehensive income includes net income and certain items recorded
directly to stockholders' equity and classified as Other Comprehensive Income.
The following table illustrates the calculation of comprehensive income for the
three-month periods ended March 31:
THREE MONTHS ENDED THREE MONTHS ENDED
MARCH 31, 2002 MARCH 31, 2001
--------------------------- --------------------------
(In thousands)
Accumulated Other Comprehensive Income -
Beginning of Period.................................. $ 835 $ --
Net Income (Loss)......................................... $ (798) $ 39,062
Other Comprehensive Income (net of tax)
Cumulative effect of change in accounting
principle - January 1, 2001....................... -- (2,617)
Reclassification adjustment for
settled contracts................................. (1,592) 487
Changes in fair value of outstanding
hedge positions................................... (7,831) 424
--------- ----------
Other Comprehensive Income................................ $ (9,423) $ (9,423) $ (1,706) $ (1,706)
--------- ---------- ---------- ----------
Comprehensive Income...................................... $ (10,221) $ 37,356
========= ==========
Accumulated Other Comprehensive Income -
End of Period........................................ $ (8,588) $ (1,706)
========== ===========
10. RETIREMENT OF EXECUTIVE OFFICER
In May 2002, Ray Seegmiller will retire as the Company's Chairman and
Chief Executive Officer. The Company expects to record a charge of approximately
$3.2 million in the second quarter of 2002 for expenses related to his
retirement. The costs include a lump sum cash payment of $0.9 million in
recognition of Mr. Seegmiller's employment agreement, his contributions to the
Company and in lieu of a 2002 long-term incentive award. Another $1.0 million
will be expensed as part of his supplemental executive retirement plan benefits.
Mr. Seegmiller's previously awarded stock grants and options will vest upon
retirement, resulting in estimated compensation expense of approximately $1.3
million. This amount related to the acceleration of the stock award vesting is
an estimate and will be based on the closing stock price on May 2, 2002.
-10-
11. ACQUISITION OF CODY COMPANY
Effective in August 2001, the Company acquired the stock of Cody Company,
the parent of Cody Energy LLC ("Cody acquisition") for $231.2 million comprised
of $181.3 million of cash and 1,999,993 shares of common stock valued at $49.9
million. Substantially all of the proved reserves of Cody Company are located in
the onshore Gulf Coast region. The acquisition was accounted for using the
purchase method of accounting. As such, the Company reflected the assets and
liabilities acquired at fair value in the Company's balance sheet effective
August 1, 2001 and the results of operations of Cody Company beginning August 1,
2001. The purchase price totaling approximately $315.6 million was allocated to
specific assets and liabilities based on certain estimates of fair values
resulting in approximately $302.4 million allocated to property and $13.2
million allocated to working capital items. This $315.6 million amount was
inclusive of a $78.0 million non-cash item pertaining to the deferred income
taxes attributable to the differences between the tax basis and the fair value
of the acquired oil and gas properties, and acquisition related fees and costs
of $6.4 million. The purchase price allocation is preliminary and subject to
change as additional information becomes available. Management does not expect
the final purchase price allocation to differ materially from the preliminary
allocation.
The following unaudited pro forma condensed income statement information
has been prepared to give effect to the Cody acquisition as if it had occurred
on January 1, 2001. The information presented is not necessarily indicative of
the results of future operations of the Company.
QUARTER ENDED
MARCH 31, 2001
--------------
(Unaudited)
(In thousands)
Revenues................................................... $ 187,307
----------
Net Income................................................. $ 47,145
-----------
per share - Basic....................................... $ 1.51
per share - Diluted..................................... $ 1.49
The results of operations for Cody Company are consolidated with Cabot Oil & Gas
Corporation as of August 1, 2001.
-11-
Report of Independent Accountants
To the Board of Directors and Shareholders of
Cabot Oil & Gas Corporation:
We have reviewed the accompanying condensed consolidated balance sheet of Cabot
Oil & Gas Corporation and its subsidiaries (the "Company") as of March 31, 2002,
and the related condensed consolidated statements of operations and cash flows
for each of the three-month periods ended March 31, 2002 and March 31, 2001.
These financial statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with generally accepted auditing standards, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the accompanying condensed consolidated interim financial statements
for them to be in conformity with accounting principles generally accepted in
the United States of America.
We previously audited in accordance with auditing standards generally accepted
in the United States of America, the consolidated balance sheet as of December
31, 2001, and the related consolidated statements of operations, stockholders'
equity, and of cash flows for the year then ended (not presented herein), and in
our report dated February 15, 2002 we expressed an unqualified opinion on those
consolidated financial statements. In our opinion, the information set forth in
the accompanying condensed consolidated balance sheet as of December 31, 2001,
is fairly stated in all material respects in relation to the consolidated
balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Houston, Texas
April 25, 2002
-12-
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results
--------------------------------------------------------------------------------
of Operations
-------------
The following review of operations for the first quarter of 2002 and 2001
should be read along with our Condensed Consolidated Financial Statements and
the Notes included in this Form 10-Q and with the Consolidated Financial
Statements, Notes and Management's Discussion and Analysis included in the Cabot
Oil & Gas Form 10-K for the year ended December 31, 2001.
Overview
In the first quarter of 2002, we produced 22.5 Bcfe, an increase of 26%
over the 2001 first quarter, and the highest first quarter in Company history.
Natural gas production was 18.4 Bcf, up 3.1 Bcf compared to the 2001 first
quarter. Oil production was up 263 Mbbls, or 65% over the comparable quarter of
last year. Production from the properties acquired with Cody Company contributed
most of the increase, but drilling successes in the Gulf Coast and Eastern
regions have also served to improve production rates.
Commodity prices were unusually high during the first quarter of 2001, and
our financial results reflected their impact during that period. However, in the
first quarter of 2002, natural gas prices were 61% lower and crude oil prices
were 28% lower than in 2001. This softer commodity price environment impacted
our financial results. Operating revenues decreased $79.8 million, or 52%, and
net income decreased $39.9 million, mainly as a result of this weakened price
environment. Operating cash flows were similarly impacted, declining by $80.0
million over last year.
Our first quarter net loss was $0.8 million, or $0.03 per share, including
a $0.6 million non-cash loss realized from the change in the fair value of our
derivatives under SFAS 133 (see Note 8) and a $1.1 million impairment recorded
on two small fields. The impairments occurred since it was determined that the
reserves on these two small fields were not commercially viable. These selected
items decreased after-tax net income by $1.0 million, or $0.04 per share, in the
first quarter of 2002. Excluding these selected items, our first quarter 2002
net income was $0.2 million, or $0.01 per share.
We drilled 21 gross wells (17 development and 4 exploratory wells) with a
success rate of 95% compared to 43 gross wells (39 development and 4 exploratory
wells) and a 91% success rate in the first quarter of 2001. For the full year,
we plan to drill 111 gross wells and spend $104.7 million in capital and
exploration expenditures compared to 208 gross wells and $453.4 million of
capital and exploration expenditures in 2001, including the $231.2 million
August 2001 Cody acquisition. Total expenditures were $34.5 million for the
first quarter of 2002, compared to $53.5 million for the comparable period in
2001.
We remain focused on our strategies of growth from the drill bit and
synergistic acquisitions. Management believes that these strategies are
appropriate in the current industry environment, enabling Cabot Oil & Gas to add
shareholder value over the long-term.
The preceding paragraphs, discussing our strategic pursuits and goals,
contain forward-looking information. See Forward-Looking Information on page 19.
Financial Condition
Capital Resources and Liquidity
Our capital resources consist primarily of cash flows from our oil and gas
properties and asset-based borrowings supported by our oil and gas reserves. The
level of earnings and cash flows depend on many factors, including the price of
crude oil and natural gas and our ability to control and reduce costs. Demand
for crude oil and natural gas has historically been subject to seasonal
influences characterized by peak demand and higher prices in the winter heating
season. However, demand and prices moved higher strengthening from the summer of
2000 to the spring of 2001 until they began to decline in the late summer and
early fall of 2001 and remained low to start 2002. This is a variation from the
cyclical nature of demand that we had seen previously in the market.
-13-
Our primary source of cash during the first quarter of 2002 was from funds
generated from operations and increased borrowing on our revolving credit
facility. Cash was primarily used to fund exploration and development
expenditures and to pay dividends.
We had a net cash outflow of $0.7 million in the first quarter of 2002.
Cash inflows from operating activities totaled $29.6 million in the current
quarter. The $48.1 million of capital and exploration expenditures were funded
with a combination of the operating cash flows and $19.0 million of increased
borrowing on the revolving credit facility.
THREE MONTHS ENDED MARCH 31,
2002 2001
-------- --------
(In millions)
Cash Flows Provided by Operating Activities..................................$ 29.6 $ 109.6
======== ========
Cash flows from operating activities in the 2002 first quarter were $80.0
million lower than the corresponding quarter of 2001 primarily due to lower
natural gas and oil prices and less favorable changes in working capital.
THREE MONTHS ENDED MARCH 31,
2002 2001
-------- --------
(In millions)
Cash Flows Used by Investing Activities......................................$ (48.1) $ (45.1)
======== ========
Cash flows used by investing activities in the first quarter of 2002 were
entirely for capital and exploration expenditures of $48.1 million. A portion of
this cash spending related to the 2001 capital program as certain 2001 projects
were completed in the first quarter of 2002. Cash flows used by investing
activities in the first quarter of 2001 were substantially attributable to
capital and exploration expenditures of $45.5 million, partially offset by
proceeds from the sale of certain oil and gas properties of $0.4 million.
THREE MONTHS ENDED MARCH 31,
2002 2001
-------- --------
(In millions)
Cash Flows Provided (Used) by Financing Activities...........................$ 17.8 $ (67.0)
======== ========
Cash flows provided by financing activities in the first quarter of 2002
consist primarily of $19.0 million in increased borrowings on the revolving
credit facility. Cash flows used by financing activities in the first quarter of
2001 included $70 million used to reduce borrowings on our revolving credit
facility. Proceeds from the exercise of stock options in the first quarter were
$0.1 million in 2002 and $4.2 million in 2001.
The available credit line under our revolving credit facility, currently
$250 million, is subject to adjustment on the basis of the present value of
estimated future net cash flows from proved oil and gas reserves (as determined
by the bank's petroleum engineer) and other assets. The revolving term of the
credit facility ends in December 2003. We strive to manage our debt at a level
below the available credit line in order to maintain excess borrowing capacity.
Management believes that we have the ability to finance, if necessary, our
capital requirements, including acquisitions.
Our 2002 interest expense is expected to be approximately $29.2 million,
including interest on the $170 million 7.33% weighted average fixed rate notes
used to partially fund the acquisition of Cody Company in 2001. In May 2001, a
$16 million principal payment was made on the 10.18% Notes. This amount had been
reflected as "Current Portion of Long-Term Debt" on the balance sheet.
Additionally, the final $16 million payment on these notes that was due in May
2002 was paid in May 2001 using existing capacity on the revolving credit
agreement.
-14-
Capitalization
Our capitalization information is as follows:
MARCH 31, DECEMBER 31,
2002 2001
-------- -----------
(In millions)
Debt..................................................................... $ 412.0 $ 393.0
Stockholders' Equity/(1)/................................................ 335.7 346.6
-------- --------
Total Capitalization..................................................... $ 747.7 $ 739.6
======== ========
Debt to Capitalization................................................... 55.1% 53.1%
/(1)/ Includes common stock, net of treasury stock. No shares of preferred
stock were outstanding.
During the first quarter of 2002, we paid dividends of $1.3 million on the
Common Stock. A regular dividend of $0.04 per share of Common Stock has been
declared for each quarter since we became a public company.
Capital and Exploration Expenditures
On an annual basis, we generally fund most of our capital and exploration
activities, excluding major oil and gas property acquisitions, with cash
generated from operations, and budget such capital expenditures while
considering projected cash flows for the year.
The following table presents major components of capital and exploration
expenditures:
THREE MONTHS ENDED MARCH 31,
----------------------------
2002 2001
-------- --------
(In millions)
Capital Expenditures
Drilling and Facilities......................................... $ 25.9 $ 26.2
Leasehold Acquisitions.......................................... 1.0 12.7
Pipeline and Gathering ......................................... 0.2 0.5
Other........................................................... 0.3 3.3
-------- --------
27.4 42.7
Exploration Expenses................................................ 7.1 10.8
-------- --------
Total........................................................... $ 34.5 $ 53.5
======== ========
Total capital and exploration expenditures in the first quarter of 2002
decreased $19.0 million compared to the same quarter of 2001, primarily as a
result of planned decreases in leasehold acquisition costs and other capital
projects.
We plan to drill 111 gross wells in 2002 compared with 208 gross wells
drilled in 2001. This 2002 drilling program includes $104.7 million in total
capital and exploration expenditures, down from $453.4 million in 2001, which
was our largest capital program to date and included the acquisition of Cody
Company. Expected spending in 2002 includes $62.6 million for drilling and dry
hole exposure, $7.8 million for lease acquisition and $9.9 million in geological
and geophysical expenses. In addition to the drilling and exploration program,
other 2002 capital expenditures are planned primarily for production equipment
and for gathering and pipeline infrastructure maintenance and construction. We
will continue to assess the natural gas price environment and may increase or
decrease the capital and exploration expenditures accordingly.
-15-
Results of Operations
Selected Financial and Operating Data
THREE MONTHS ENDED MARCH 31,
----------------------------
2002 2001
----------- -----------
(In millions, except where noted)
Operating Revenues.......................................................... $ 75.1 $ 154.9
Operating Expenses.......................................................... 70.1 86.4
Operating Income............................................................ 5.0 68.5
Interest Expense............................................................ 6.2 4.7
Net Income (Loss)........................................................... (0.8) 39.1
Earnings (Loss) Per Share - Basic........................................... $ (0.03) $ 1.33
Earnings (Loss) Per Share - Diluted......................................... $ (0.03) $ 1.32
Natural Gas Production (Bcf)
Gulf Coast............................................................. 7.5 4.8
West................................................................... 6.4 6.4
East................................................................... 4.5 4.1
--------- ---------
Total Company.......................................................... 18.4 15.3
========= =========
Natural Gas Production Sales Prices ($/Mcf)
Gulf Coast............................................................. $ 2.67 $ 7.34
West................................................................... $ 2.14 $ 6.10
East................................................................... $ 2.85 $ 6.44
Total Company.......................................................... $ 2.53 $ 6.57
Crude Oil Production (Mbbl)
Gulf Coast............................................................. 610 328
West................................................................... 50 68
East................................................................... 8 9
--------- ---------
Total Company.......................................................... 668 405
========= =========
Crude Oil Production Sales Prices ($/Bbl)
Gulf Coast............................................................. $ 20.57 $ 28.83
West................................................................... $ 20.97 $ 27.36
East................................................................... $ 16.41 $ 27.21
Total Company.......................................................... $ 20.55 $ 28.55
Brokered Natural Gas Margin
Volume (Bcf)........................................................... 3.2 4.8
Margin ($/Mcf)......................................................... $ 0.45 $ 0.26
The table below presents the after-tax effect of certain selected items on
our results of operations for the three months ended March 31, 2002 and 2001.
(In millions) 2002 2001
--------------------------------------------------------------------
Net Income Before Selected Items $ 0.2 $ 35.3
Change in derivative fair value/(1)/ (0.4) 3.8
Impairment of Long-Lived Assets (0.6)
----------------------
Net Income (Loss) $ (0.8) $ 39.1
======================
/(1)/ See discussion in Note 8 of the Notes to the Condensed
Consolidated Financial Statements.
-16-
For the first quarter of 2002, we reported a net loss of $0.8 million or
$0.03 per share. In the comparable quarter of 2001, we reported $39.1 million of
$1.33 per share. Selected items related to the change in derivative valuation
and impairment of long-lived assets impacted our first quarter financial
results. Because these items are not a part of our business operations or
because they are unrealized gains or losses on future transactions, we have
isolated the effect in the table above. The discussion below excludes the impact
of these selected items.
First Quarters of 2002 and 2001 Compared
Net Income and Revenues. We reported net income before the selected items
-----------------------
in the first quarter of 2002 of $0.2 million, or $0.01 per share. During the
corresponding quarter of 2001, we reported net income before the selected item
of $35.3 million, or $1.20 per share. Operating revenues decreased by $73.0
million and operating income decreased by $55.7 million. Natural gas sales
related to our production made up 61%, or $46.5 million, of operating revenue.
The 49% decrease in operating revenues was primarily due to a 61% decline in our
realized average natural gas price compared to the first quarter of 2001. This
decline was partially offset by a 20% increase in natural gas production. Net
income and operating income were similarly impacted by the decline in the
average natural gas price.
The average Gulf Coast natural gas production sales price decreased $4.67
per Mcf, or 64%, to $2.67, decreasing operating revenues by approximately $32.7
million. In the Western region, the average natural gas production sales price
decreased $3.96 per Mcf, or 65%, to $2.14, decreasing operating revenues by
approximately $25.6 million. The average Eastern region natural gas production
sales price decreased $3.59 per Mcf, or 56%, to $2.85, decreasing operating
revenues by approximately $16.1 million. The overall weighted average natural
gas production sales price decreased $4.04 per Mcf, or 61%, to $2.53, decreasing
revenues by $74.4 million.
Natural gas production volume in the Gulf Coast region was up 2.7 Bcf, or
56%, to 7.5 Bcf primarily due to production from properties acquired with the
Cody Company acquisition in August 2001. Natural gas production volume in the
Western region was the same as the comparable quarter of 2001 at 6.4 Bcf.
Natural gas production volume in the Eastern region was up 0.4 Bcf to 4.5 Bcf,
as a result of an increase in drilling activity in the region in 2001. The
improvement in total natural gas production of 3.1 Bcf, or 20%, increased
revenue by $20.2 million in the first quarter of 2002.
The volume of crude oil sold in the quarter increased by 263 Mbbls, or 65%,
to 668 Mbbls, increasing operating revenues by $7.5 million. This increase in
crude oil production was due both to production from properties acquired with
Cody Company in August 2001, and production increases in south Louisiana due to
2001 drilling activity. However, crude oil prices fell $8.00 per Bbl, or 28%, to
$20.55, resulting in a decrease to operating revenues of approximately $5.3
million. In total, revenue from crude oil sales was $2.2 million, or 19%, above
the 2001 first quarter.
Brokered natural gas revenue decreased $21.7 million, or 61%, over the
first quarter of last year. The sales price of brokered natural gas fell 41%,
resulting in a decrease in revenue of $9.4 million, combined with a 35% decrease
in volume of natural gas brokered this quarter, reducing revenues by $12.3
million. After including the related brokered natural gas costs, we realized a
net margin of $1.4 million in the first quarter of 2002 and $1.3 million in the
comparable quarter of 2001.
Other operating revenues increased $0.8 million to $1.8 million. This
change was primarily a result of:
.. A $0.4 million increase in transportation revenue as operations commenced on a
new gathering system in the Western region.
.. A $0.9 million increase due to a decrease in payout and gas balancing costs.
In the first quarter of 2001, we had recorded the impact of resolving several
payout and gas balancing issues.
.. A $0.8 million decrease in natural gas liquids revenue as a result of a
downward revision to accrued revenue from the prior quarter.
.. A $0.2 million increase in natural gas processing plant revenue.
-17-
Costs and Expenses. Total costs and expenses from operations decreased
------------------
$17.4 million in the first quarter of 2002 compared to the same quarter of 2001.
The primary reasons for this fluctuation are as follows:
. Brokered natural gas cost decreased $21.9 million, or 64%, from the first
quarter of last year. The cost of brokered natural gas fell 45%, resulting
in a decrease to expense of $10.0 million. Additionally, a 35% decrease in
volume of natural gas brokered this quarter reduced costs by $11.9 million.
. Direct operating expense increased $4.0 million, or 49%, primarily as a
result of costs associated with operating the Gulf Coast properties
acquired with Cody Company in August 2001. Additionally, operating costs
have increased in the Gulf Coast, and to a lesser extent in the Rocky
Mountains, where we are have more active properties than in prior quarters.
On a per unit basis, operating expense has risen from $0.46 per Mcf in the
first quarter of 2001 to $0.54 per Mcf in 2002.
. Exploration expense decreased $3.7 million, or 34%, primarily as a result
of lower spending on geological and geophysical expenses and delay rentals
in 2002. During the first quarter of 2001, we spent more than $3.7 million
in these areas in preparation for drilling which would occur later in 2001
and in 2002. These categories of costs were $1.2 million during the first
quarter of 2002. Certain other employee compensation costs recorded only in
2001 accounted for the remainder of the decrease.
. Depreciation, depletion, amortization and impairment expense increased $8.2
million, or 47%, due to the increase in natural gas and oil production this
quarter and the higher influence of the Gulf Coast rate (including amounts
attributable to the Cody Company properties) on the weighted average due to
the higher production contribution of this region. On a per unit basis, DDA
for the first quarter was $0.97 per Mcf in 2001 and $1.14 per Mcf in 2002.
. General and administrative costs declined $0.2 million, or 3%, as a result
of additional bad debt expense recorded in the first quarter of 2001
related to the fourth quarter 2000 bankruptcy of two customers.
. Taxes other than income declined $3.8 million, or 38%, as a result of lower
commodity prices realized this quarter.
Interest expense increased $1.5 million as a result of a higher average
level of outstanding debt during the first quarter of 2002 when compared to the
first quarter of 2001. The new debt was primarily related to the Cody Company
acquisition.
Income tax expense was down $22.2 million due to the comparable
decrease in earnings before income tax.
Recently Issued Accounting Pronouncements
In June 2001, the FASB also approved for issuance SFAS 143 "Asset
Retirement Obligations." SFAS 143 establishes accounting requirements for
retirement obligations associated with tangible long-lived assets, including (1)
the timing of the liability recognition, (2) initial measurement of the
liability, (3) allocation of asset retirement cost to expense, (4) subsequent
measurement of the liability and (5) financial statement disclosures. SFAS 143
requires that an asset retirement cost should be capitalized as part of the cost
of the related long-lived asset and subsequently allocated to expense using a
systematic and rational method. The Company will adopt the statement effective
no later than January 1, 2003, as required. The transition adjustment resulting
from the adoption of SFAS 143 will be reported as a cumulative effect of a
change in accounting principle. At this time, the Company cannot reasonably
estimate the effect of the adoption of this statement on its financial position,
results of operations, or cash flows.
-18-
Forward-Looking Information
The statements regarding future financial performance and results, market
prices, and the other statements, which are not historical facts contained in
this report are forward-looking statements. The words "expect," "project,"
"estimate," "believe," "anticipate," "intend," "budget," "plan," "forecast,"
"predict" and similar expressions are also intended to identify forward-looking
statements. Such statements involve risks and uncertainties, including, but not
limited to, market factors, market prices (including regional basis
differentials) of natural gas and oil, results for future drilling and marketing
activity, future production and costs and other factors detailed herein and in
our other Securities and Exchange Commission filings. Should one or more of
these risks or uncertainties materialize, or should underlying assumptions prove
incorrect, actual outcomes may vary materially from those indicated.
Conclusion
Our financial results depend upon many factors, particularly the price of
natural gas and oil and our ability to market gas on economically attractive
terms. The average produced natural gas sales price received in the first three
months of 2002 was more than 60% lower than in 2001. The volatility of natural
gas prices in recent years remains prevalent in 2002 with wide price swings in
day-to-day trading on the NYMEX futures market. Additionally, we have natural
gas price collars in place through August 2002 and oil price collars in place
through December 2002, which both offer some protection against falling prices
and remove some benefit of rising prices. Given this continued price volatility,
we cannot predict with certainty what pricing levels will be in the future.
Because future cash flows are subject to these variables, we cannot assure you
that our operations will provide cash sufficient to fully fund our planned
capital expenditures.
We believe our capital resources, supplemented with external financing, if
necessary, are adequate to meet our capital requirements.
The preceding paragraphs contain forward-looking information. See Forward-
Looking Information above.
-19-
ITEM 3A. Quantitative and Qualitative Disclosures about Market Risk
---------------------------------------------------------------------
Commodity Price Swaps and Options
Hedges on Production - Swaps
From time to time, we enter into natural gas and crude oil swap agreements
with counterparties to hedge price risk associated with a portion of our
production. These derivatives are not held for trading purposes. Under these
price swaps, we receive a fixed price on a notional quantity of natural gas and
crude oil in exchange for paying a variable price based on a market-based index,
such as the NYMEX gas and crude oil futures. During the first quarter of 2002,
we did not have any natural gas price swaps covering our production. During the
first quarter of 2001, natural gas price swaps covered 261 Mmcf, fixing the
sales price of this gas at $4.31 per Mcf. We entered into no oil price swaps
covering the first quarter of 2002 or 2001.
The natural gas price swap arrangement that we entered into during the
third quarter of 2000 covered a portion of production over the period of October
2000 through September 2003. However, the counterparty declared bankruptcy in
December 2001. Based on the terms of the natural gas swap contract, this action
resulted in the cancellation of the contract. At the time of cancellation, the
contract's value was less than $0.2 million.
Hedges on Production - Options
In December 2000, we believed that the pricing environment provided a
strategic opportunity to significantly reduce the price risk on a portion of our
production through the use of costless collars. Under the costless collar
arrangements, if the index rises above the ceiling price, we pay the
counterparty. If the applicable index falls below the floor, the counterparty
pays us. The 2001 natural gas price hedges included several costless collar
arrangements based on eight price indexes at which we sold a portion of our
production. These hedges were in place for the months of February through
October 2001 and covered 5,274 Mmcf, or 34%, of our natural gas production for
the first quarter of 2001. All indexes were within the collars during February,
however some fell below the floor during the period of March resulting in $0.1
million cash revenue for the quarter.
Again in December of 2001, we believed that the pricing environment
provided a strategic opportunity to significantly reduce the price risk on a
portion of our 2002 production through the use of natural gas price collar
arrangements. The natural gas price hedges included several collar arrangements
based on nine price indexes at which we sell a portion of our production. These
hedges are in place for the months of January through April 2002 and cover 68%
of our anticipated natural gas production during this period. These collars have
a ceiling of $3.53 per Mcf and a floor of $2.68 per Mcf. A premium totaling $0.9
million was paid to purchase these collar arrangements.
In March 2002, we entered into another series of natural gas collars that
cover approximately 77% of our anticipated production during the months of May
through August 2002. These collars have a ceiling of $3.17 per Mcf and a floor
of $2.54 per Mcf. These natural gas price hedges are similar to those in place
during the first four months of 2002, but no premium was paid to enter into
these collars.
Also in the first quarter of 2002, we entered into a crude oil price collar
arrangement that covers approximately 46% of our production during the period
from March through December 2002. This collar is based on NYMEX settlements, and
has a ceiling of $23.00 per barrel and a floor of $20.00 per barrel.
In accordance with the latest guidance from the FASB's Derivative
Implementation Group, we test the effectiveness of the combined intrinsic and
time values and the effective portion of each will be recorded as a component of
Other Comprehensive Income. Any ineffective portion will be recorded as a gain
or loss in the current period. As of March 31, 2002, we have recorded $15.3
million of Other Comprehensive Loss, a $0.6 million Unrealized Hedge Loss, the
reversal of a $1.5 million Hedge Assets and a $14.4 million Hedge Liability.
-20-
We are exposed to market risk on these open contracts, to the extent of
changes in market prices of natural gas and oil. However, the market risk
exposure on these hedged contracts is generally offset by the gain or loss
recognized upon the ultimate sale of the commodity that is hedged.
The preceding paragraphs contain forward-looking information concerning
future production and projected gains and losses, which may be impacted both by
production and by changes in the future market prices of energy commodities. See
Forward-Looking Information on page 19.
-21-
PART II. OTHER INFORMATION
ITEM 6. Exhibits and Reports on Form 8-K
-----------------------------------------
(a) Exhibits
15.1 - Awareness letter of independent accountants.
(b) Reports on Form 8-K
None
-22-
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.
CABOT OIL & GAS CORPORATION
(Registrant)
April 30, 2002 By: /s/ Scott C. Schroeder
---------------------------------------------
Scott C. Schroeder, Vice President, Chief
Financial Officer and Treasurer
(Principal Executive Officer Duly Authorized
to Sign on Behalf of the Registrant)
By: /s/ Henry C. Smyth
---------------------------------------------
Henry C. Smyth, Vice President and Controller
(Principal Accounting Officer)
-23-