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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, 2003
[_] 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 ___
---
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Act).
Yes X No ___
---
As of April 28, 2003, there were 32,188,413 shares of Common Stock, Par
Value $.10 Per Share, outstanding.
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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, 2003, and 2002 ............................................................. 3
Condensed Consolidated Balance Sheet at March 31, 2003, and December 31, 2002 ................ 4
Condensed Consolidated Statement of Cash Flows for the Three Months
Ended March 31, 2003, and 2002 ............................................................. 5
Notes to the Condensed Consolidated Financial Statements ..................................... 6
Report of Independent Accountant's Review of Interim Financial Information ................... 17
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations .................................................................. 18
Item 3A. Quantitative and Qualitative Disclosures about Market Risk .............................. 26
Item 4. Controls and Procedures ................................................................. 28
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K ........................................................ 29
Signature ............................................................................................. 30
Certifications ........................................................................................ 31
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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,
---------------------------------------
2003 2002
--------------- ----------------
NET OPERATING REVENUES
Natural Gas Production ................................................... $ 78,173 $ 46,506
Brokered Natural Gas ..................................................... 31,850 13,698
Crude Oil and Condensate ................................................. 23,174 13,718
Change in Derivative Fair Value (Note 8) ................................. (544) (616)
Other .................................................................... 3,263 1,767
--------------- ----------------
135,916 75,073
OPERATING EXPENSES
Brokered Natural Gas Cost ................................................ 28,261 12,267
Direct Operations - Field and Pipeline ................................... 10,926 12,235
Exploration .............................................................. 13,391 7,056
Depreciation, Depletion and Amortization ................................. 23,507 23,210
Impairment of Unproved Properties ........................................ 2,337 2,337
Impairment of Long-Lived Assets (Note 11) ................................ 87,926 1,063
General and Administrative ............................................... 6,595 5,739
Taxes Other Than Income .................................................. 10,224 6,152
--------------- ----------------
183,167 70,059
Gain (Loss) on Sale of Assets ............................................. 560 (18)
--------------- ----------------
INCOME (LOSS) FROM OPERATIONS ............................................. (46,691) 4,996
Interest Expense and Other ................................................ 5,625 6,226
--------------- ----------------
Loss Before Income Taxes .................................................. (52,316) (1,230)
Income Tax Benefit ........................................................ (19,940) (432)
--------------- ----------------
NET LOSS BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE .................... (32,376) (798)
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (Note 12) .......................... (6,847) -
--------------- ----------------
NET LOSS .................................................................. $ (39,223) $ (798)
=============== ================
Basic Loss Per Share - Before Cumulative Effect of Accounting Change ...... $ (1.02) $ (0.03)
Diluted Loss Per Share - Before Cumulative Effect of Accounting Change .... $ (1.02) $ (0.03)
Basic Loss Per Share - Cumulative Effect of Accounting Change............. $ (0.21) $ -
Diluted Loss Per Share - Cumulative Effect of Accounting Change............ $ (0.21) $ -
Basic Loss Per Share ...................................................... $ (1.23) $ (0.03)
Diluted Loss Per Share .................................................... $ (1.23) $ (0.03)
Average Common Shares Outstanding ......................................... 31,837 31,604
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, except share amounts)
MARCH 31, DECEMBER 31,
-------------- --------------
2003 2002
-------------- --------------
ASSETS
Current Assets
Cash and Cash Equivalents .................................... $ 1,223 $ 2,561
Accounts Receivable .......................................... 108,470 70,028
Inventories .................................................. 9,656 15,252
Other ........................................................ 5,480 5,280
-------------- --------------
Total Current Assets ...................................... 124,829 93,121
Properties and Equipment, Net (Successful Efforts Method) ........ 881,783 971,754
Other Assets ..................................................... 7,214 7,013
-------------- --------------
$ 1,013,826 $ 1,071,888
============== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable ............................................. $ 88,910 $ 73,578
Accrued Liabilities .......................................... 70,785 48,312
-------------- --------------
Total Current Liabilities ................................. 159,695 121,890
Long-Term Debt ................................................... 338,000 365,000
Deferred Income Taxes ............................................ 161,641 200,207
Other Liabilities ................................................ 55,452 34,134
Stockholders' Equity
Common Stock:
Authorized -- 80,000,000 Shares of $.10 Par Value
Issued and Outstanding -- 32,160,913 Shares and
32,133,118 Shares in 2003 and 2002, Respectively .......... 3,216 3,213
Additional Paid-in Capital ................................... 353,963 353,093
Retained Earnings (Accumulated Deficit) ...................... (28,822) 11,674
Accumulated Comprehensive Loss (Note 9) ...................... (24,935) (12,939)
Less Treasury Stock, at Cost:
302,600 Shares in 2003 and 2002 ........................... (4,384) (4,384)
-------------- --------------
Total Stockholders' Equity ................................ 299,038 350,657
-------------- --------------
$ 1,013,826 $ 1,071,888
============== ==============
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,
---------------------------------------
2003 2002
-------------- --------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss ..................................................... $ (39,223) $ (798)
Adjustment to Reconcile Net Income to Cash
Provided by Operating Activities:
Cumulative Effect of Accounting Change ................. 6,847 -
Depletion, Depreciation and Amortization ............... 23,507 23,210
Impairment of Undeveloped Leasehold .................... 2,337 2,337
Impairment of Long-Lived Assets ........................ 87,926 1,063
Deferred Income Tax Expense ............................ (27,010) (471)
(Gain) Loss on Sale of Assets .......................... (560) 18
Exploration Expense .................................... 13,391 7,056
Change in Derivative Fair Value ........................ 544 616
Other .................................................. (139) 1,364
Changes in Assets and Liabilities:
Accounts Receivable .................................... (38,442) (924)
Inventories ............................................ 5,596 5,495
Other Current Assets ................................... (621) (3,235)
Other Assets ........................................... (201) 93
Accounts Payable and Accrued Liabilities ............... 22,988 (6,100)
Other Liabilities ...................................... 2,607 (175)
-------------- --------------
Net Cash Provided by Operating Activities ........... 59,547 29,549
-------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures ......................................... (21,321) (41,062)
Proceeds from Sale of Assets ................................. 1,602 (2)
Exploration Expense .......................................... (13,391) (7,056)
-------------- --------------
Net Cash Used by Investing Activities ............... (33,110) (48,120)
-------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt ............................................. 64,000 56,000
Decrease in Debt ............................................. (91,000) (37,000)
Sale of Common Stock ......................................... 498 105
Dividends Paid ............................................... (1,273) (1,264)
-------------- --------------
Net Cash Provided (Used) by Financing Activities .... (27,775) 17,841
-------------- --------------
Net Decrease in Cash and Cash Equivalents ........................ (1,338) (730)
Cash and Cash Equivalents, Beginning of Period ................... 2,561 5,706
-------------- --------------
Cash and Cash Equivalents, End of Period ......................... $ 1,223 $ 4,976
============== ==============
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 (the Company)
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
condensed consolidated 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 Sections 7 and 11 of the Act.
In June 2001, the FASB approved for issuance Statement of Financial
Accounting Standard (SFAS) 143, "Accounting for 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 adoption of SFAS 143 resulted in (1) an increase of total
liabilities, because more retirement obligations are required to be recognized,
(2) an increase in the recognized cost of assets, because the retirement costs
are added to the carrying amount of the long-lived asset, and (3) an increase in
operating expense, because of the accretion of the retirement obligation and
additional depreciation and depletion. The majority of the asset retirement
obligations recorded by the Company relate to the plugging and abandonment of
oil and gas wells. The Company adopted the statement on January 1, 2003. The
transition adjustment resulting from the adoption of SFAS 143 has been reported
as a cumulative effect of a change in accounting principle in January 2003. The
impact on the financial statements of adopting SFAS 143 is disclosed in Note 12,
"Adoption of SFAS 143, Accounting for Asset Retirement Obligations," to the
financial statements.
In December 2002, the FASB issued SFAS 148, "Accounting for
Stock-Based Compensation - Transition and Disclosure." SFAS 148 amends FASB
Statement 123, "Accounting for Stock-Based Compensation," to provide
alternative methods of transition for a voluntary change to the fair value based
method of accounting for stock-based employee compensation. In addition, this
Statement amends the disclosure requirements of Statement 123 to require
prominent disclosures in both annual and interim financial statements about the
method of accounting for stock-based employee compensation and the effect of the
method used on the reported results. The provisions of SFAS 148 are effective
for financial statements for fiscal years ending after December 15, 2002. The
adoption of this statement did not impact the Company's financial position,
results of operations or cash flows. See Note 13, "Stock Based Compensation," to
the financial statements.
In January 2003, the FASB issued Financial Interpretation 46,
"Consolidation of Variable Interest Entities - An Interpretation of Accounting
Research Bulletin (ARB) 51" (FIN 46 or Interpretation). FIN 46 is an
interpretation of ARB 51, "Consolidated Financial Statements," and addresses
consolidation by business enterprises of variable interest entities (VIEs). The
primary objective of the Interpretation is to provide guidance on the
identification of, and financial reporting for, entities over which control is
achieved through means other than voting rights; such entities are known as
VIEs. The Interpretation requires an enterprise to consolidate a VIE if that
enterprise has a variable interest that will absorb a majority of the entity's
expected losses if they occur, receive a majority of the entity's expected
residual returns if they occur or both. An enterprise shall consider the rights
and obligations conveyed by its variable interests in making this determination.
This guidance applies immediately to VIEs created after January 31, 2003,
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and to VIEs in which an enterprise obtains an interest after that date. It
applies in the first fiscal year or interim period beginning after June 15,
2003, to VIEs in which an enterprise holds a variable interest that it acquired
before February 1, 2003. At this time there is only one entity that could
potentially be a VIE. The Company is evaluating this potential VIE, in which it
has a one percent general partner interest and that holds an interest in the
Kurten field, to determine if it is a VIE. However, pursuant to the partnership
agreement, the limited partner has elected to liquidate the partnership; it is
anticipated that this liquidation will be completed prior to the effective date
of the Interpretation. See Note 11 for additional information related to the
partnership.
2. PROPERTIES AND EQUIPMENT
Properties and equipment are comprised of the following:
MARCH 31, DECEMBER 31,
2003 2002
-------------- --------------
(In Thousands)
Unproved Oil and Gas Properties .................................. $ 78,940 $ 76,959
Proved Oil and Gas Properties .................................... 1,494,855 1,459,240
Gathering and Pipeline Systems ................................... 137,546 137,137
Land, Building and Improvements .................................. 4,884 4,884
Other ............................................................ 29,450 29,457
-------------- --------------
1,745,675 1,707,677
Accumulated Depreciation, Depletion and Amortization ............. (863,892) (735,923)
-------------- --------------
$ 881,783 $ 971,754
============== ==============
Prior to the adoption of SFAS 143 on January 1, 2003, future estimated
plug and abandonment costs were accrued over the productive life of certain oil
and gas properties when the residual value of well equipment was not sufficient
to cover the plug and abandonment liability. The accrued liability for plug and
abandonment costs was included in Accumulated Depreciation, Depletion and
Amortization.
Total future plug and abandonment costs of $17.1 million and $1.1
million have been reclassified from Accumulated Depreciation, Depletion and
Amortization and Other Accrued Liabilities, respectively, at December 31, 2002,
to Other Long-Term Liabilities due to the adoption of SFAS 143 (see Note 12).
These reclassifications were made to conform to the current period presentation.
See Note 11 for information regarding the impairment on the Kurten
Field.
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3. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
MARCH 31, DECEMBER 31,
2003 2002
-------------- --------------
(In Thousands)
Accounts Receivable
Trade Accounts ............................................... $ 106,905 $ 65,796
Joint Interest Accounts ...................................... 4,436 6,601
Current Income Tax Receivable ................................ 2,481 2,479
Other Accounts ............................................... 115 619
-------------- --------------
113,937 75,495
Allowance for Doubtful Accounts .................................. (5,467) (5,467)
-------------- --------------
$ 108,470 $ 70,028
============== ==============
Other Current Assets
Commodity Hedging Contracts .................................. $ 213 $ 634
Drilling Advances ............................................ 1,545 558
Prepaid Balances ............................................. 1,867 2,131
Restricted Cash and Other Accounts ........................... 1,855 1,957
-------------- --------------
$ 5,480 $ 5,280
============== ==============
Accounts Payable
Trade Accounts ............................................... $ 16,236 $ 13,317
Natural Gas Purchases ........................................ 15,856 6,058
Royalty and Other Owners ..................................... 30,070 20,254
Capital Costs ................................................ 10,928 13,900
Taxes Other Than Income ...................................... 3,760 3,076
Drilling Advances ............................................ 3,336 7,254
Wellhead Gas Imbalances ...................................... 2,280 2,817
Other Accounts ............................................... 6,444 6,902
-------------- --------------
$ 88,910 $ 73,578
============== ==============
Accrued Liabilities
Employee Benefits ............................................ $ 5,001 $ 8,751
Taxes Other Than Income ...................................... 13,224 9,887
Interest Payable ............................................. 5,153 7,076
Commodity Hedging Contracts - Short-Term ..................... 37,847 20,680
Other Accrued ................................................ 9,560 1,918
-------------- --------------
$ 70,785 $ 48,312
============== ==============
Other Liabilities
Postretirement Benefits Other Than Pension ................... $ 1,900 $ 1,843
Accrued Pension Cost ......................................... 9,055 8,486
Commodity Hedging Contracts - Long-Term ...................... 2,789 -
Accrued Plugging and Abandonment Liability ................... 35,687 18,151
Taxes Other Than Income and Other ............................ 6,021 5,654
-------------- --------------
$ 55,452 $ 34,134
============== ==============
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4. LONG-TERM DEBT
At March 31, 2003, the Company had $68 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 bank's petroleum
engineer) of estimated future net cash flows from certain proved oil and gas
reserves and other assets of the Company. The revolving term under this credit
facility presently ends in October 2006 and is subject to renewal. At March 31,
2003, excess capacity totaled $182 million, or 73% 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 31,836,505 in
2003 and 31,603,717 in 2002. The diluted earnings per share amounts are based on
weighted average shares outstanding plus common stock equivalents. The
computation of diluted earnings per share to determine common stock equivalents
includes both stock awards and stock options and did not assume conversion of
these instruments due to the antidilutive effect on loss per share. Stock awards
and stock options excluded from the calculation of diluted loss per share
because the effect was antidilutive were 1,561,973 and 1,755,223 for the first
quarter of 2003 and 2002, respectively.
6. ENVIRONMENTAL LIABILITY
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.
The Company received documents with the notification from the EPA
indicating 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 entered into a consent
decree, which will require the CNC to pay approximately $27 million toward Site
clean up in return for a release from liability. On January 30, 2002, the
Company placed $1,283,283 in an escrow account, representing its volumetric
share of the CNC/United States settlement. This cash settlement, once released
from escrow and paid to the federal government after the consent decree is
entered by the court, 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.
Most of the CNC, including the Company, have purchased insurance designed to
protect the Company from these liabilities not covered by the consent decree.
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The State of California, a third party, has asserted a claim against
the CNC and other companies alleged to have waste at Casmalia for costs the
State incurred and will incur at the site. The CNC has presented the claim to
its insurer. The ultimate disposition of this claim is unknown. However, given
the size of the State's claim and the number of parties allegedly responsible,
the Company's share of this claim is expected to be immaterial.
The Company has established a reserve that management believes to be
adequate to provide for this environmental liability and related legal costs.
7. COMMITMENTS AND CONTINGENCIES
Wyoming Royalty Litigation
In June 2000, the Company was sued by two overriding royalty owners 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 improperly deducted 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. At a
mediation held in April 2003, the plaintiffs in this case claimed total damages
of $9.5 million plus attorney fees.
In January 2002, 13 overriding royalty owners sued the Company in
Wyoming federal district 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.
Although management believes that a number of the Company's defenses
are supported by Wyoming case law, a recent letter decision handed down by a
state district court in another case does not support certain of the defenses.
The decision has not been reduced to a formal order and it is not known what
effect, if any, the decision will have on the pending cases.
In the Company's federal case, the judge recently agreed to certify two
questions of state law for decision by the Wyoming State Supreme Court. The
Wyoming State Supreme Court has agreed to decide both questions, and these
decisions should dispose of important issues in these cases. The federal judge
refused, however, to certify one question on check stub reporting that had been
decided adversely to the Company's position in the state district court letter
decision. After the federal judge's refusal to certify this issue, the
plaintiffs reduced the damages they were claiming. Based upon the plaintiffs
expert witness report filed in March 2003, the plaintiffs are now claiming $21
million in total damages which can be broken down into $15.7 million for alleged
violations of the check stub reporting statute and the remainder for all other
damages. In the opinion of our outside counsel, Brown, Drew & Massey, LLP the
likelihood of the plaintiffs recovering the stated damages for violation of the
check stub reporting statute is remote.
The Company is vigorously defending both cases. The Company has a
reserve that management believes is adequate to provide for these potential
liabilities based on its estimate of the probable outcome of these matters.
Should circumstances change, the potential impact may materially affect
quarterly or annual results of operations and cash flows. However, management
does not believe it would materially impact our financial position.
West Virginia Royalty Litigation
In December 2001, the Company was sued by two royalty owners 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 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 have 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
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gas sales contract settlement that the Company reached with Columbia in the 1995
Columbia bankruptcy proceeding.
The Company had removed the lawsuit to federal court; however, in February
2003, we received an order remanding the lawsuit back to state court. Discovery
and pleadings necessary to place the class certification issue before the court
have been ongoing. No trial or dispositive motions dates have been set and
limited factual discovery is ongoing.
The investigation into this claim continues and it is in the discovery
phase. The Company is vigorously defending the case. The Company has reserves it
believes are adequate to provide for these potential liabilities based on its
estimate of the probable outcome of this matter. Should circumstances change,
the potential impact may materially affect quarterly or annual results of
operations and cash flows. However, management does not believe it would
materially impact the Company's financial position.
Texas Title Litigation
On January 6, 2003, the Company was served with Plaintiffs' Second Amended
Original Petition in Romeo Longoria, et al. v. Exxon Mobil Corporation, et al.
in the 79th Judicial District Court of Brooks County, Texas. The plaintiffs
allege that they are the rightful owners of a one-half undivided mineral
interest in and to certain lands in Brooks County, Texas. As Cody Energy, LLC,
the Company acquired certain leases and wells from Wynn-Crosby 1996, Ltd. in
1997 and 1998 and the Company subsequently acquired a 320 acre lease from Hector
and Gloria Lopez in 2001. The plaintiffs allege that they are entitled to be
declared the rightful owners of an undivided interest in the surface and
minerals and all improvements on the lands on which the Company acquired these
leases. The plaintiffs also assert claims for trespass to try title, action to
remove a cloud on the title, failure to properly account for royalty, fraud,
trespass, conversion, all for unspecified actual and exemplary damages. The
trial date of May 19, 2003 has been cancelled and a new trial date has not been
set. The Company has not had the opportunity to conduct discovery in this
matter. The Company estimates that production revenue from this field since its
predecessor, Cody Energy, LLC, acquired title and since the Company acquired its
lease is approximately $12 million. The carrying value of this property is
approximately $35 million.
Although the investigation into this claim has just begun, the Company
intends to vigorously defend the case. Management cannot currently determine the
likelihood or range of any potential outcome.
-11-
Lease Commitments
The Company leases certain transportation vehicles, warehouse facilities,
office space, and machinery and equipment under cancelable and non-cancelable
leases. Leases for the Company's offices in Houston and Denver each run for
approximately seven more years. Rent expense under such arrangements totaled
$1.9 million and $2.1 million for the three months ended March 31, 2003, and
2002, respectively. Most of the other leases expire within five years and may be
renewed.
Future minimum rental commitments under non-cancelable leases in effect at
March 31, 2003, are as follows:
(In thousands)
------------------------------------------
2003 $ 4,193
2004 4,805
2005 4,419
2006 3,732
2007 3,488
Thereafter 5,119
--------
$ 25,756
========
Minimum rental commitments are not reduced by an insignificant amount of
minimum sublease rental income due in the future under non-cancelable subleases.
8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY
The Company periodically enters into derivative commodity instruments to
hedge its exposure to price fluctuations on natural gas and crude oil
production. At March 31, 2003, the Company had 24 cash flow hedges open: eight
natural gas price collar arrangements, 14 natural gas price swap arrangements
and two crude oil price collar arrangements. Additionally, the Company had three
crude oil price range swaps open at March 31, 2003, that did not qualify for
hedge accounting under SFAS 133. At March 31, 2003, a $38.1 million ($23.6
million net of tax) unrealized loss was recorded to Other Comprehensive Income,
along with a $40.6 million derivative liability and a $0.7 million derivative
receivable. A charge related to the change in fair value of derivative
instruments of $0.5 million is reflected in Operating Income and is comprised of
$0.4 million and $0.1 million for gas derivative instruments and oil derivative
instruments, respectively, inclusive of the range swaps described below.
From time to time the Company enters into crude oil range swaps with
counterparties. These derivatives do not qualify for hedge accounting under SFAS
133 and are recorded at fair value at the balance sheet date. At March 31, 2003,
the Company had three open crude oil range swap arrangements with an unrealized
net loss of $0.8 million reflected in Operating Revenue.
-12-
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
-----------------------------------------------------
MARCH 31, 2003 MARCH 31, 2002
------------------------- -----------------------
(In Thousands)
Accumulated Other Comprehensive Income (Loss) -
Beginning of Period ......................... $ (12,939) $ 835
Net Loss ........................................ $ (39,223) $ (798)
Other Comprehensive Loss (Net of Tax)
Reclassification Adjustments for
Settled Contracts ........................ (16,131) (1,592)
Changes in Fair Value of Outstanding
Hedge Positions .......................... 4,135 (7,831)
---------- ---------- ---------- ---------
Total Other Comprehensive Loss .................. $ (11,996) $ (11,996) $ (9,423) $ (9,423)
---------- ---------- ---------- ---------
Comprehensive Loss .............................. $ (51,219) $ (10,221)
========== ==========
Accumulated Comprehensive Loss -
End of Period ............................... $ (24,935) $ (8,588)
========== =========
10. RETIREMENT OF EXECUTIVE OFFICER
In May 2002, Ray Seegmiller retired as the Company's Chairman and Chief
Executive Officer. The Company recorded a charge of approximately $3.6 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 was expensed as part
of his supplemental executive retirement plan benefits. Mr. Seegmiller's
previously awarded stock grants and options vested upon retirement, resulting in
compensation expense of approximately $1.7 million.
-13-
11. ACQUISITION OF CODY COMPANY
In August 2001, the Company acquired the stock of Cody Company, the parent
of Cody Energy LLC ("Cody acquisition") for $231.2 million, consisting of $181.3
million 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
Company recorded a purchase price of approximately $315.6 million, which 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. The remaining $78.0 million of
the recorded purchase price reflected a 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.
As part of the Cody acquisition, the Company acquired an interest in
certain oil and gas properties in the Kurten field, as general partner of a
partnership and as an operator. The Company's current interest in Kurten is
approximately 25%, including a one percent interest in the partnership. Under
the partnership agreement, the Company has the right to a reversionary working
interest that would bring its ultimate interest to 50% upon the limited partner
reaching payout. Under the partnership agreement, the limited partner has the
sole option to trigger a liquidation of the partnership. Effective February 13,
2003, the Kurten partnership commenced liquidation at the limited partner's
election. In connection with the liquidation, an appraisal was obtained to
allocate the interest in the partnership assets. Based on the receipt of the
appraisal in February 2003, the Company would not receive the reversionary
interest as part of the liquidation. Due to the impact of the loss of the
reversionary interest on future estimated net cash flows of the Kurten field,
the limited partners' decision and our decision to proceed with the liquidation,
the Company performed an impairment review that resulted in an after-tax charge
of $54 million. This impairment charge is reflected in the first quarter of 2003
as an operating expense but does not impact the Company's cash flows. In
addition, the Company recorded a downward reserve revision of approximately 16
Bcfe as a result of the loss of the reversionary interest.
12. ADOPTION OF SFAS 143, "ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS"
Effective January 1, 2003, the Company adopted SFAS 143, "Accounting for
Asset Retirement Obligations." SFAS 143 requires that the fair value of a
liability for an asset retirement obligation be recognized in the period in
which it is incurred if a reasonable estimate of fair value can be made. The
associated asset retirement cost is capitalized as part of the carrying amount
of the long-lived asset. Subsequently, the asset retirement cost is allocated to
expense using a systematic and rational method over the assets useful life. The
adoption of SFAS 143 resulted in an increase of total liabilities because more
retirement obligations are required to be recognized, an increase in the
recognized cost of assets because the retirement costs are added to the carrying
amount of the long-lived asset and an increase in operating expense because of
the accretion of the retirement obligation and additional depreciation and
depletion. The majority of the asset retirement obligations recorded by the
Company relate to the plugging and abandonment of oil and gas wells. However,
liabilities will also be recorded for meter stations, pipelines, processing
plants and compressors. At January 1, 2003, there are no assets legally
restricted for purposes of settling asset retirement obligations. The Company
recorded a net-of-tax cumulative effect of change in accounting principle loss
in January 2003 of $6.8 million and recorded a retirement obligation of $35.2
million. There was no impact on the Company's cash flows as a result of adopting
SFAS 143. See Note 2 for additional information on plugging and abandonment
costs.
-14-
Subsequent to the adoption of SFAS 143, there has been no significant
current period activity with respect to additional retirement liabilities,
settled liabilities, accretion expense and revisions of estimated cash flows.
The following unaudited pro forma information has been prepared to give
effect to the adoption of SFAS 143 as if it had been adopted on January 1, 2002.
QUARTER ENDED
MARCH 31, 2002
--------------------------
(In Thousands)
(Except Per Share Amounts)
Net Loss $ (1,409)
--------------
Per Share - Basic ....... $ (0.04)
Per Share - Diluted ..... $ (0.04)
13. STOCK BASED COMPENSATION
SFAS 123, "Accounting for Stock-Based Compensation", as amended by SFAS
148, "Accounting for Stock-Based Compensation - Transition and Disclosure,"
outlines a fair value based method of accounting for stock options or similar
equity instruments. The Company has opted to continue using the intrinsic value
based method, as recommended by Accounting Principles Board (APB) Opinion 25,
to measure compensation cost for its stock option plans.
The following table illustrates the effect on Net Income and Earnings Per
Share if the Company had applied the fair value recognition provisions of SFAS
123 to stock-based employee compensation.
QUARTER ENDED MARCH 31,
-----------------------
(In Thousands, Except Per Share Amounts) 2003 2002
- -------------------------------------------------------------------------------
Net Loss, as reported $ (39,223) $ (798)
Deduct: Total stock-based employee compensation
expense determined under fair value based
method for all awards, net of tax (1,802) (1,469)
--------- ----------
Pro forma net loss $ (41,025) $ (2,267)
========= ==========
Earnings per share:
Basic - as reported $ (1.23) $ (0.03)
Basic - pro forma $ (1.29) $ (0.07)
Diluted - as reported $ (1.23) $ (0.03)
Diluted - pro forma $ (1.29) $ (0.07)
-15-
The assumptions used in the fair value method calculation as well as
additional stock based compensation information are disclosed in the following
table.
QUARTER ENDED MARCH 31,
--------------------------
(In Thousands, Except Per Share Amounts) 2003 2002
- -------------------------------------------------------------------------------
Compensation Expense in Net Income, as reported (1) $ 248 $ 339
Weighted Average Value of Options Granted
During the Quarter (2) $ 6.75 $ 6.02
Assumptions
Stock Price Volatility 35.4% 35.8%
Risk Free Rate of Return 2.5% 3.9%
Dividend Rate (per year) 0.16 0.16
Expected Term (in years) 4 4
- -------------------------------------------------------------------------------
(1) Compensation expense is defined as expense related to the vesting of stock
grants, net of tax.
(2) Calculated using the Black Sholes fair value based method.
The fair value of stock options included in the pro forma results for each
of the periods presented is not necessarily indicative of future effects on Net
Income and Earnings Per Share.
-16-
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, 2003,
and the related condensed consolidated statements of operations and cash flows
for each of the three-month periods ended March 31, 2003 and March 31, 2002.
These interim 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 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, 2002, 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 17, 2003 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, 2002,
is fairly stated in all material respects in relation to the consolidated
balance sheet from which it has been derived.
As discussed in Notes 1 and 12 to the condensed consolidated financial
statements, the Company adopted Statement of Financial Accounting Standards No.
143 "Accounting for Asset Retirement Obligations" effective January 1, 2003.
PricewaterhouseCoopers LLP
Houston, Texas
April 25, 2003
-17-
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following review of operations for the first quarter of 2003 and
2002 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, 2002.
Overview
In the first quarter of 2003, we produced 21.9 Bcfe, a decrease of 3%
over the 2002 first quarter. Natural gas production was 17.2 Bcf, down 1.2 Bcf,
or 7%, compared to the 2002 first quarter. Oil production was 750 Mbbls, up 82
Mbbls, or 12% over the comparable quarter of last year. Production in the
current period decreased slightly from the same period in 2002, which is when we
experienced the highest annual production levels in our history. Our current
production levels are attributable to drilling successes in the Gulf Coast and
Eastern regions.
Commodity prices were unusually high during the first quarter of 2003,
and our financial results reflected their impact. In the first quarter of 2003,
natural gas prices were 80% higher and crude oil prices were 50% higher than in
2002. Although our hedge positions limited the upside in the first quarter, the
strong commodity price environment resulted in an increase to gas revenue of
$31.7 million, or 68%, and an increase in oil revenue of $9.5 million, or 69%.
Operating cash flows were similarly impacted, increasing by $30.0 million, or
102%, over last year.
Despite the increase in commodity prices our first quarter resulted in
a net loss of $39.2 million, or $1.23 per share. This loss is substantially
attributable to an $87.9 million non-cash impairment related to the liquidation
of a limited partnership interest in the Kurten field (see Note 11) and a $6.8
million charge from the adoption of SFAS 143 (see Note 12).
In the first quarter of 2003, we drilled 25 gross wells (22 development
and three exploratory wells) with a success rate of 88% compared to 21 gross
wells (17 development and four exploratory wells) and a 95% success rate in the
first quarter of 2002. For the full year, we plan to drill 180 gross wells and
spend approximately $153.0 million in capital and exploration expenditures
compared to 108 gross wells and $126.3 million of capital and exploration
expenditures in 2002. Total capital and exploration expenditures were $31.7
million for the first quarter of 2003, compared to $34.5 million for the
comparable period in 2002.
We remain focused on our strategies of concentrating our capital
spending program on projects balancing acceptable risk with the strongest
economics. As in the past, we will use a portion of the cash flow from our
long-lived Eastern and Mid-Continent natural gas reserves to fund our
exploration and development efforts in the Gulf Coast and Rocky Mountain areas.
In addition, we have begun to expand our interest in the offshore Gulf of
Mexico. We believe 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 25.
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 first
quarter of 2002 into the summer and continued to strengthen through the first
quarter of 2003. Prices in the first quarter of 2003 were the result of a higher
demand associated with colder than normal winter temperatures, combined with
historical low inventory levels.
-18-
Our primary source of cash during the first quarter of 2003 was from
funds generated from operations. Cash was primarily used to fund exploration and
development expenditures, reduce debt and to pay dividends.
We had a net cash outflow of $1.3 million in the first quarter of 2003.
Cash inflows from operating activities totaled $59.5 million in the current
quarter. The $34.7 million of capital and exploration expenditures were funded
with our operating cash flows.
THREE MONTHS ENDED MARCH 31,
2003 2002
-------- --------
(In millions)
Cash Flows Provided by Operating Activities .. $ 59.5 $ 29.6
======== ========
Cash flows from operating activities in the 2003 first quarter were
$29.9 million higher than the corresponding quarter of 2002 primarily due to
higher natural gas and oil prices.
THREE MONTHS ENDED MARCH 31,
2003 2002
--------- ---------
(In millions)
Cash Flows Used by Investing Activities ..... $ (33.1) $ (48.1)
========= =========
Cash flows used by investing activities in the first quarter of 2003
were substantially attributable to capital and exploration expenditures of $34.7
million, partially offset by proceeds from the sale of certain oil and gas
properties of $1.6 million. Cash flows used by investing activities in the first
quarter of 2002 were entirely for capital and exploration expenditures of $48.1
million.
THREE MONTHS ENDED MARCH 31,
2003 2002
--------- -----------
(In millions)
Cash Flows Provided (Used) by Financing
Activities ...................................... $ (27.8) $ 17.8
========= ========
Cash flows used by financing activities in the first quarter of 2003
consist primarily of $27.0 million of borrowing repayments on the revolving
credit facility and $1.3 million of dividend payments. 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. Partially
offsetting the use of cash flow by financing activities were proceeds from the
exercise of stock options in the first quarter of $0.5 million in 2003 and
$0.1 million in 2002. Our 2003 interest expense is expected to be approximately
$23.6 million.
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 October 2006. 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 through new
debt or equity offerings, if necessary, our capital requirements, including
acquisitions.
Non-GAAP Financial Measures
From time to time management discloses discretionary cash flow and net
income and earnings per share, excluding selected items. These non-GAAP
financial measure calculations and reconciliations to the most comparable GAAP
financial measure for the period are presented with each earnings release of the
Company, furnished in Form 8-K to the Securities and Exchange Commission.
Discretionary cash flow is defined as Net Income plus non-cash charges
and Exploration Expense. Discretionary cash flow is widely accepted as a
financial indicator of an oil and gas company's ability to generate cash which
is used to internally fund exploration and development activities, pay dividends
and service debt. Discretionary cash flow is presented based on management's
belief that this non-GAAP measure is useful information to investors because it
is widely used by professional research analysts in
-19-
the valuation, comparison, rating and investment recommendations of companies
within the oil and gas exploration and production industry. Many investors use
the published research of these analysts in making their investment decisions.
Discretionary cash flow is not a measure of financial performance under GAAP and
should not be considered as an alternative to cash flows from operating
activities, as defined by GAAP, or as a measure of liquidity, or an alternative
to Net Income.
Net Income excluding selected items and Earnings Per Share excluding
selected items is presented based on managements belief that these non-GAAP
measures enable a user of the financial information to understand the impact of
these items on reported results. Additionally, this presentation provides a
Beneficial Comparison to Similarly adjusted measurements of prior periods. Net
Income and Earnings Per Share excluding selected items is not a measure of
financial performance under GAAP and should not be considered as an alternative
to Net Income and Earnings Per Share, as defined by GAAP.
Capitalization
Our capitalization information is as follows:
MARCH 31, DECEMBER 31,
2003 2002
--------- ------------
(In millions)
Debt ........................ $ 338.0 $ 365.0
Stockholders' Equity /(1)/ .. 299.0 350.7
-------- --------
Total Capitalization ........ $ 637.0 $ 715.7
======== ========
Debt to Capitalization 53.1% 51.0%
/(1)/ Includes common stock, net of treasury stock. No shares of
preferred stock were outstanding.
During the first quarter of 2003, 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,
2003 2002
----------- -----------
(In millions)
Capital Expenditures
Drilling and Facilities ...... $ 14.5 $ 25.9
Leasehold Acquisitions ....... 2.8 1.0
Pipeline and Gathering ....... 1.0 0.2
Other ........................ 0.0 0.3
-------- --------
18.3 27.4
Exploration Expenses ............. 13.4 7.1
-------- --------
Total ........................ $ 31.7 $ 34.5
======== ========
Total capital and exploration expenditures in the first quarter of 2003
decreased $2.8 million compared to the same quarter of 2002, primarily as a
result of decreased drilling activity.
We plan to drill 180 gross wells in 2003 compared with 108 gross wells
drilled in 2002. This 2003 drilling program includes approximately $153.0
million in total capital and exploration expenditures, up
-20-
from $126.3 million in 2002. Budgeted spending in 2003 includes approximately
$89 million for drilling and dry hole exposure, $11 million for lease
acquisition and $13 million in geological and geophysical expenses. In addition
to the drilling and exploration program, other 2003 capital expenditures are
planned primarily for production equipment, workovers, 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.
-21-
Results of Operations
Selected Financial and Operating Data
THREE MONTHS ENDED MARCH 31,
--------------------------------
2003 2002
-------- --------
(In millions, except where noted)
Operating Revenues ....................................................... $ 135.9 $ 75.1
Operating Expenses ....................................................... 183.2 70.1
Operating Income (Loss) .................................................. (46.7) 5.0
Interest Expense ......................................................... 5.6 6.2
Net Loss, Before Accounting Change ....................................... (32.4) (0.8)
Net Loss ................................................................. (39.2) (0.8)
Loss Per Share - Basic, Before Accounting Change ......................... $ (1.02) $ (0.03)
Loss Per Share - Diluted, Before Accounting Change ....................... $ (1.02) $ (0.03)
Loss Per Share - Basic, Accounting Change................................. $ (0.21) $ 0.00
Loss Per Share - Diluted, Accounting Change............................... $ (0.21) $ 0.00
Loss Per Share - Basic ................................................... $ (1.23) $ (0.03)
Loss Per Share - Diluted ................................................. $ (1.23) $ (0.03)
Natural Gas Production (Bcf)
Gulf Coast .......................................................... 6.7 7.5
West ................................................................ 6.1 6.4
East ................................................................ 4.4 4.5
------- ------
Total Company ....................................................... 17.2 18.4
======= ======
Natural Gas Production Sales Prices ($/Mcf)
Gulf Coast .......................................................... $ 4.88 $ 2.67
West ................................................................ $ 3.61 $ 2.14
East ................................................................ $ 5.35 $ 2.85
Total Company ....................................................... $ 4.55 $ 2.53
Crude Oil Production (Mbbl)
Gulf Coast .......................................................... 696 610
West ................................................................ 48 50
East ................................................................ 6 8
------- -------
Total Company ....................................................... 750 668
======= =======
Crude Oil Production Sales Prices ($/Bbl)
Gulf Coast .......................................................... $ 30.84 $ 20.57
West ................................................................ $ 32.05 $ 20.97
East ................................................................ $ 25.79 $ 16.41
Total Company ....................................................... $ 30.88 $ 20.55
Brokered Natural Gas Margin
Volume (Bcf) ........................................................ 3.9 3.2
Margin ($/Mcf)/(1)/ ................................................. $ 0.92 $ 0.45
(1) Amount represents brokered natural gas revenue less brokered natural gas cost, divided by
brokered natural gas volumes.
First Quarters of 2003 and 2002 Compared
Net Income and Revenues. We reported a net loss in the first quarter of
2003 of $39.2 million, or $1.23 per share. During the corresponding quarter of
2002, we reported a net loss of $0.8 million, or $0.03 per share. Net operating
revenues increased by $60.8 million, or 81% and operating income decreased
by $51.7 million. The decrease in operating income was substantially due to the
impairment on the Kurten field (Note 11). Natural gas sales made up 58%, or
$78.2 million, of operating revenue. The 81% increase in
-22-
operating revenues was primarily due to an 80% and 50% increase in our realized
average natural gas price and crude oil price, respectively, compared to the
first quarter of 2002, as well as a 12% increase in crude oil production,
partially offset by a 7% decrease in natural gas production. Operating revenues
were also impacted by an increase in our brokered natural gas revenues.
The average realized total company natural gas production sales price
was $4.55 per Mcf for the first quarter of 2003. Due to certain derivative
instruments this price was reduced by $1.46 per Mcf. The average Gulf Coast
natural gas production sales price increased $2.21 per Mcf, or 83%, to $4.88,
increasing operating revenues by approximately $14.8 million. In the Western
region, the average natural gas production sales price increased $1.47 per Mcf,
or 69%, to $3.61, increasing operating revenues by approximately $9.0 million.
The average Eastern region natural gas production sales price increased $2.50
per Mcf, or 88%, to $5.35, increasing operating revenues by approximately $11.0
million. The overall weighted average natural gas production sales price
increased $2.02 per Mcf, or 80%, to $4.55, increasing revenues by $34.8 million.
Natural gas production volume in the Gulf Coast region was down 0.8
Bcf, or 11%, to 6.7 Bcf primarily due to the size and timing of the Gulf Coast
drilling program, along with the natural decline of existing production. Natural
gas production volume in the Western region decreased 0.3 Bcf, or 5%, to 6.1 Bcf
primarily due to natural declines and a small drilling program in 2002. Natural
gas production volume in the Eastern region was substantially the same as the
comparable quarter of 2002 at 4.4 Bcf. The decrease in total natural gas
production of 1.2 Bcf, or 7%, resulted in a decrease to natural gas revenue of
$3.0 million in the first quarter of 2003.
The average realized total company crude oil sales price was $30.88 per
Bbl first quarter of 2003. Due to certain derivative instruments this price was
reduced by $2.54 per Bbl. The volume of crude oil sold in the quarter increased
by 82 Mbbls, or 12%, to 750 Mbbls, increasing operating revenues by $1.7
million. This increase in crude oil production was substantially due to
production increases in the Gulf Coast region. Additionally, crude oil prices
increased $10.33 per Bbl, or 50%, to $30.88, resulting in an increase to
operating revenues of $7.8 million. In total, revenue from crude oil sales
increased $9.5 million, or 69%, above the 2002 first quarter.
Brokered natural gas revenue increased $18.2 million, or 133%, over the
first quarter of last year. The sales price of brokered natural gas rose 89%,
resulting in an increase in revenue of $15.0 million, combined with a 24%
increase in volume of natural gas brokered this quarter, increasing revenues by
$3.2 million. After including the related brokered natural gas costs, we
realized a net margin of $3.6 million in the first quarter of 2003 and $1.4
million in the comparable quarter of 2002.
Other operating revenues increased $1.5 million to $3.3 million. This
change was primarily a result of:
. A $0.4 million increase in transportation revenue due to a substantial
increase in volumes, offset slightly by a decrease in price.
. A $0.8 million increase in natural gas liquids revenue as a result of
increased volumes in the current quarter.
. A $0.3 million increase in natural gas processing plant revenue.
-23-
Costs and Expenses. Total costs and expenses from operations increased
$113.1 million in the first quarter of 2003 compared to the same quarter of
2002. The primary reasons for this fluctuation are as follows:
. Brokered natural gas cost increased $16.0 million, or 130%, from the
first quarter of last year. The cost of brokered natural gas rose 86%,
resulting in an increase to expense of $13.1 million. Additionally, a
24% increase in volume of natural gas brokered this quarter increased
costs by $2.9 million.
. Direct operating expense decreased $1.3 million, or 11%. Operating
costs have decreased in the Gulf Coast, and to a lesser extent in the
Rocky Mountains. The decrease in the Gulf Coast is attributable to
timing of expenditures. The decrease in the Rocky Mountains is due to a
milder winter, which resulted in less required maintenance, and to a
lesser extent, timing of expenditures. On a per unit basis, operating
expense declined from $0.54 to $0.50 per Mcfe produced in the first
quarter of 2002 and 2003, respectively.
. Exploration expense increased $6.3 million, or 90%, primarily as a
result of increased spending on geological and geophysical expenses and
dry hole expense in 2003. During the first quarter of 2003, we spent an
additional $5.2 million on geological and geophysical activities and
incurred an additional $0.7 million in dry hole expense.
. Impairment of long-lived assets expense increased $86.9 million due to
the impairment on the Kurten field (see Note 11).
. General and administrative costs increased $0.9 million, or 15%, as a
result of an increase in employee fringe benefit expenses.
. Taxes other than income increased $4.1 million, or 66%, as a result of
higher commodity prices realized this quarter.
Interest expense decreased $0.6 million as a result of a lower average
level of outstanding debt during the first quarter of 2003 when compared to the
first quarter of 2002 and a decline in interest rates on the revolving credit
facility.
Income tax benefit increased from $0.4 million to $19.9 million in the
first quarter of 2002 and 2003, respectively. The increase is due to a
comparable increase in our net loss.
Recently Issued Accounting Pronouncements
In June 2001, the FASB approved for issuance Statement of Financial
Accounting Standard (SFAS) 143, "Accounting for 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 adoption of SFAS 143 resulted in (1) an increase of total
liabilities, because more retirement obligations are required to be recognized,
(2) an increase in the recognized cost of assets, because the retirement costs
are added to the carrying amount of the long-lived asset, and (3) an increase in
operating expense, because of the accretion of the retirement obligation and
additional depreciation and depletion. The majority of the asset retirement
obligations recorded by the Company relate to the plugging and abandonment of
oil and gas wells. The Company adopted the statement on January 1, 2003. The
transition adjustment resulting from the adoption of SFAS 143 has been reported
as a cumulative effect of a change in accounting principle in January 2003. The
impact on the financial statements of adopting SFAS 143 is disclosed in Note 12,
"Adoption of SFAS 143, Accounting for Asset Retirement Obligations," to the
financial statements.
In December 2002, the FASB issued SFAS 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure." SFAS 148 amends FASB Statement 123,
"Accounting for Stock-Based Compensation", to provide alternative methods of
transition for a voluntary change to the fair value based
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method of accounting for stock-based employee compensation. In addition, this
Statement amends the disclosure requirements of Statement 123 to require
prominent disclosures in both annual and interim financial statements about the
method of accounting for stock-based employee compensation and the effect of the
method used on the reported results. The provisions of SFAS 148 are effective
for financial statements for fiscal years ending after December 15, 2002. The
adoption of this statement did not impact the Company's financial position,
results of operations, or cash flows. See Note 13, "Stock Based Compensation,"
to the financial statements.
In January 2003, the FASB issued Financial Interpretation 46,
"Consolidation of Variable Interest Entities - An Interpretation of ARB 51" (FIN
46 or Interpretation). FIN 46 is an interpretation of Accounting Research
Bulletin 51, "Consolidated Financial Statements," and addresses consolidation by
business enterprises of variable interest entities (VIEs). The primary objective
of the Interpretation is to provide guidance on the identification of, and
financial reporting for, entities over which control is achieved through means
other than voting rights; such entities are known as VIEs. The Interpretation
requires an enterprise to consolidate a VIE if that enterprise has a variable
interest that will absorb a majority of the entity's expected losses if they
occur, receive a majority of the entity's expected residual returns if they
occur or both. An enterprise shall consider the rights and obligations conveyed
by its variable interests in making this determination. This guidance applies
immediately to VIEs created after January 31, 2003, and to VIEs in which an
enterprise obtains an interest after that date. It applies in the first fiscal
year or interim period beginning after June 15, 2003, to VIEs in which an
enterprise holds a variable interest that it acquired before February 1, 2003.
At this time we have only one entity that could potentially be a VIE. We are
evaluating this potential VIE, in which we have a one percent general partner
interest and that holds an interest in the Kurten field, to determine if it is a
VIE. However, pursuant to the partnership agreement, the limited partner has
elected to liquidate the partnership; it is anticipated that this liquidation
will be completed prior to the effective date of the Interpretation. See Note 11
for additional information related to this partnership.
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 and oil on economically
attractive terms. The average produced natural gas sales price received in the
first three months of 2003 was 80% higher than in 2002 and the average oil sales
price was 50% higher than in the comparable period of 2002. The volatility of
natural gas prices in recent years remains prevalent in 2003 with wide price
swings in day-to-day trading on the NYMEX futures market. Additionally, we have
natural gas price swaps and collars in place through December 2004 and oil price
collars and range swaps in place through June 2003 and December 2003,
respectively, which all offer some protection against price volatility. 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. See Item 3A., "Quantitative and
Qualitative Disclosures about Market Risk" for additional information regarding
these derivative instruments.
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.
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ITEM 3A. Quantitative and Qualitative Disclosures about Market Risk
Commodity Price Swaps and Options
Our hedging policy is designed to reduce the risk of price volatility for
our production in the natural gas, natural gas liquids and crude oil markets. A
hedging committee that consists of members of senior management oversees our
hedging activity. Our hedging arrangements apply to only a portion of our
production and provide only partial price protection against declines in oil and
gas prices. These hedging arrangements may expose us to risk of financial loss
and limit the benefit to us of increases in prices. Please read the discussion
below related to commodity price swaps and Note 8 of the Notes to the Interim
Condensed Consolidated Financial Statements for a more detailed discussion of
our hedging arrangements.
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. Under our Revolving Credit
Agreement, the aggregate level of commodity hedging must not exceed 80% of the
anticipated future production during the period covered by the hedges. During
the first quarter of 2003, natural gas price swaps covered 8,754 Mmcf, or 51% of
our first quarter production, fixing the sales price of this gas at an average
of $4.47 per Mcf. During the first quarter of 2002, we did not have any natural
gas price swaps covering our production. During the first quarter of 2003 and
2002, we did not have any crude oil price swaps covering our production that
qualified for hedge accounting.
At March 31, 2003, we had open natural gas price swap contracts covering
our 2003 and 2004 production as follows:
Natural Gas Price Swaps
-----------------------------------------------
Volume Weighted Unrealized
in Average Loss
Contract Period Mmcf Contract Price (In Thousands)
- ----------------------------------------------------------------------------------------------------
As of March 31, 2003
Natural Gas Price Swaps on Production in:
Second Quarter 2003 7,950 $ 4.31
Third Quarter 2003 8,037 4.31
Fourth Quarter 2003 8,037 4.31
-----------------------------------------------
Nine Months Ended December 31, 2003 24,024 $ 4.31 $ 25,850
First Quarter 2004 2,089 $ 4.42
Second Quarter 2004 2,089 4.42
Third Quarter 2004 2,112 4.42
Fourth Quarter 2004 2,112 4.42
-----------------------------------------------
Full Year 2004 8,402 $ 4.42 $ 5,153
From time to time we enter into crude oil range swaps with counterparties.
These derivatives do not qualify for hedge accounting under SFAS 133 and are
recorded at fair value at the balance sheet date. At March 31, 2003, these
instruments resulted in an unrealized net loss of $0.8 million recognized in
operating revenue.
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Hedges on Production - Options
Throughout 2002 and the first quarter of 2003, 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 natural gas and crude oil
collars. Under the 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 2003 and 2004 natural gas price collar hedges included several collar
arrangements based on eight price indexes at which we sell a portion of our
production. During the first quarter of 2003, natural gas price collars covered
3,333 Mmcf, or 19% of our first quarter production, with a weighted average
floor of $4.46 per Mcf and a weighted average ceiling of $5.35 per Mcf. During
the first quarter of 2002, natural gas price collars covered 12,109 Mmcf, or 66%
of our production, with a weighted average price floor of $2.68 per Mcf and a
weighted average price ceiling of $3.53 per Mcf.
At March 31, 2003, we had open natural gas price collar contracts covering
our 2003 and 2004 production as follows:
Natural Gas Price Collars
-----------------------------------------------
Volume Weighted Unrealized
in Average Loss
Contract Period Mmcf Ceiling / Floor (In Thousands)
- ---------------------------------------------------------------------------------------------------
As of March 31, 2003
Natural Gas Price Collars on Production in:
Second Quarter 2003 4,237 $5.42 / $4.46
Third Quarter 2003 4,283 $5.42 / $4.46
Fourth Quarter 2003 4,283 $5.42 / $4.46
-----------------------------------------------
Nine Months Ended December 31, 2003 12,803 $5.42 / $4.46 $ 6,636
First Quarter 2004 2,955 $5.78 / $4.32
Second Quarter 2004 2,955 $5.78 / $4.32
Third Quarter 2004 2,988 $5.78 / $4.32
Fourth Quarter 2004 2,988 $5.78 / $4.32
-----------------------------------------------
Full Year 2004 11,886 $5.78 / $4.32 $ 1,420
We have 2003 crude oil price collars in place for the months of January
through June, covering 362 Mbbls of production with a weighted average price
floor of $24.75 per Mbbl and a weighted average price ceiling of $28.86 per
Mbbl. At March 31, 2003, we have no open crude oil price collar arrangements to
cover our 2004 production.
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 25.
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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 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.
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PART II. OTHER INFORMATION
ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibits
4.3 - Rights Agreement dated as of March 28, 1991, between the
Company and The First National Bank of Boston, as Rights Agent,
which includes as Exhibit A the form of Certificate of
Designation of Series A Junior Participating Preferred Stock
(Form 8-A, File No. 1-10477).
(a) Amendment No. 1 to the Rights Agreement dated February 24,
1994 (Form 10-K for 1994).
(b) Amendment No. 2 to the Rights Agreement dated December 8,
2000 (Form 8-K for December 21, 2000).
(c) Amendment No. 3 to the Rights Agreement dated January 1,
2003.
10.16 - Second Amended and Restated 1994 Non-Employee Director
Stock Option Plan (Form 10-K for 2001 ).
(a) First Amendment to the Cabot Oil & Gas Corporation Second
Amended and Restated 1994 Non-Employee Director Stock Option
Plan dated March 17, 2003.
15.1 - Awareness letter of PricewaterhouseCoopers LLP
15.2 - Consent of Brown, Drew & Massey, LLP
(b) Reports on Form 8-K
Item 5: Other Events filing made on February 13, 2003, includes
Item 7. Press Release dated February 13, 2003, and titled "Cabot
Oil & Gas Announces First Quarter Impairment and SFAS 143
Adoption."
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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, 2003 By: /s/ Dan O. Dinges
-------------------------------------------
Dan O. Dinges
Chairman of the Board,
Chief Executive Officer and President
(Principal Executive Officer)
April 30, 2003 By: /s/ Scott C. Schroeder
-------------------------------------------
Scott C. Schroeder
Vice President and Chief Financial Officer
(Principal Financial Officer)
April 30, 2003 By: /s/ Henry C. Smyth
-------------------------------------------
Henry C. Smyth
Vice President, Controller and Treasurer
(Principal Accounting Officer)
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CERTIFICATIONS
I, Dan O. Dinges, certify that:
1. I have reviewed this quarterly report on Form10-Q of Cabot Oil & Gas
Corporation;
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: April 30, 2003
/s/ Dan O. Dinges
--------------------------------------
Dan O. Dinges
Chairman of the Board,
Chief Executive Officer and President
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I, Scott C. Schroeder, certify that:
1. I have reviewed this quarterly report on Form10-Q of Cabot Oil & Gas
Corporation;
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: April 30, 2003
/s/ Scott C. Schroeder
------------------------------------------
Scott C. Schroeder
Vice President and Chief Financial Officer
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