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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 June 30, 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 July 23, 2002, there were 31,792,901 shares of 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 and Six Months
Ended June 30, 2002 and 2001 ........................................................... 3
Condensed Consolidated Balance Sheet at June 30, 2002 and December 31, 2001 .............. 4
Condensed Consolidated Statement of Cash Flows for the Three and Six Months
Ended June 30, 2002 and 2001 ........................................................... 5
Notes to Condensed Consolidated Financial Statements ..................................... 6
Report of Independent Accountants ........................................................ 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 .......................... 21
Part II. Other Information
Item 2. Changes in Securities and Use of Proceeds ........................................... 23
Item 4. Submission of Matters to a Vote of Security Holders ................................. 23
Item 6. Exhibits and Reports on Form 8-K .................................................... 24
Signature ......................................................................................... 25
-2-
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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------- -------------------------
2002 2001 2002 2001
---------- ----------- ----------- -----------
NET OPERATING REVENUES
Natural Gas Production ............................ $ 55,300 $ 73,411 $ 101,806 $ 174,136
Brokered Natural Gas .............................. 15,687 27,273 29,385 62,695
Crude Oil and Condensate .......................... 17,348 10,964 31,066 22,520
Change in Derivative Fair Value (Note 8) ......... (564) (4,988) (1,180) 1,211
Other ............................................. 1,813 946 3,580 1,936
--------- ---------- ---------- ----------
89,584 107,606 164,657 262,498
OPERATING EXPENSES
Brokered Natural Gas Cost ......................... 14,581 26,323 26,848 60,479
Direct Operations - Field & Pipeline .............. 11,921 9,650 24,156 17,870
Exploration ....................................... 10,824 14,540 17,880 25,313
Depreciation, Depletion and Amortization .......... 23,453 16,198 46,663 32,089
Impairment of Unproved Properties ................. 2,337 1,482 4,674 2,964
Impairment of Long-Lived Assets ................... -- -- 1,063 --
General and Administrative ........................ 9,572 5,691 15,311 11,638
Taxes Other Than Income ........................... 7,475 6,715 13,627 16,617
--------- ---------- ---------- ----------
80,163 80,599 150,222 166,970
Gain (Loss) on Sale of Assets .......................... 429 (31) 411 (27)
--------- ---------- ---------- ----------
INCOME FROM OPERATIONS ................................. 9,850 26,976 14,846 95,501
Interest Expense ....................................... 6,331 4,704 12,557 9,409
--------- ---------- ---------- ----------
Income Before Income Taxes ............................. 3,519 22,272 2,289 86,092
Income Tax Expense ..................................... 1,398 8,679 966 33,438
--------- ---------- ---------- ----------
NET INCOME ............................................. $ 2,121 $ 13,593 $ 1,323 $ 52,654
========= ========== ========== ==========
Basic Earnings Per Share ............................... $ 0.07 $ 0.46 $ 0.04 $ 1.79
Diluted Earnings Per Share ............................. $ 0.07 $ 0.45 $ 0.04 $ 1.76
Average Common Shares Outstanding ...................... 31,737 29,509 31,671 29,414
The accompanying notes are an integral part of these condensed consolidated
financial statements.
-3-
CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)
(In Thousands)
JUNE 30, DECEMBER 31,
2002 2001
------------ ------------
Current Assets
Cash and Cash Equivalents ............................................ $ 7,710 $ 5,706
Accounts Receivable .................................................. 52,715 50,711
Inventories .......................................................... 15,151 17,560
Other ................................................................ 11,863 11,010
----------- -----------
Total Current Assets .............................................. 87,439 84,987
Properties and Equipment, Net (Successful Efforts Method) ................ 974,913 981,338
Other Assets ............................................................. 2,728 2,706
----------- -----------
$ 1,065,080 $ 1,069,031
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable ..................................................... $ 73,554 $ 79,575
Accrued Liabilities .................................................. 35,947 30,665
----------- -----------
Total Current Liabilities ......................................... 109,501 110,240
Long-Term Debt ........................................................... 397,000 393,000
Deferred Income Taxes .................................................... 198,522 200,859
Other Liabilities ........................................................ 13,076 18,380
Stockholders' Equity
Common Stock:
Authorized -- 40,000,000 Shares of $.10 Par Value
Issued and Outstanding - 32,094,768 Shares and
31,905,097 Shares in 2002 and 2001, Respectively .................. 3,210 3,191
Additional Paid-in Capital ........................................... 351,561 346,260
Retained Earnings (Accumulated Deficit) .............................. (562) 650
Accumulated Other Comprehensive Income (Loss) (Note 9) ............... (2,844) 835
Less Treasury Stock, at Cost:
302,600 Shares in 2002 and 2001 ................................... (4,384) (4,384)
---------- -----------
Total Stockholders' Equity ........................................ 346,981 346,552
---------- -----------
$ 1,065,080 $ 1,069,031
=========== ===========
The accompanying notes are an integral part of these condensed consolidated
financial statements.
-4-
CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
(In Thousands)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------ -------------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income ............................................. $ 2,121 $ 13,593 $ 1,323 $ 52,654
Adjustment to Reconcile Net Income to
Cash Provided by Operating Activities:
Depletion, Depreciation and Amortization ........... 23,453 16,198 46,663 32,089
Impairment of Unproved Properties .................. 2,337 1,482 4,674 2,964
Impairment of Long-Lived Assets .................... -- -- 1,063 --
Deferred Income Taxes .............................. 422 5,319 (49) 19,107
(Gain) Loss on Sale of Assets ...................... (429) 31 (411) 27
Exploration Expense ................................ 10,824 14,540 17,880 25,313
Change in Derivative Fair Value .................... 564 4,988 1,180 (1,211)
Other .............................................. 1,542 602 2,907 1,381
Changes in Assets and Liabilities:
Accounts Receivable ................................ (1,080) 15,503 (2,004) 30,036
Inventories ........................................ (3,086) (6,618) 2,409 (3,157)
Other Current Assets ............................... 839 4,575 (2,396) (534)
Other Assets ....................................... (115) 73 (22) 217
Accounts Payable and Accrued Liabilities ........... 21,216 (11,194) 15,116 8,785
Other Liabilities .................................. (5,129) (1,597) (5,304) (578)
---------- ---------- ---------- ----------
Net Cash Provided by Operating Activities ........ 53,479 57,495 83,029 167,093
---------- ---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures ................................... (30,126) (29,008) (71,188) (63,754)
Proceeds from Sale of Assets ........................... 3,445 302 3,443 739
Exploration Expense .................................... (10,824) (14,540) (17,880) (25,313)
---------- ---------- ---------- ----------
Net Cash Used by Investing Activities ................ (37,505) (43,246) (85,625) (88,328)
---------- ---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Sale of Common Stock ................................... 3,031 3,182 3,136 7,376
Increase in Debt ....................................... 44,000 54,000 100,000 73,000
Decrease in Debt ....................................... (59,000) (66,000) (96,000) (155,000)
Dividends Paid ......................................... (1,271) (1,181) (2,536) (2,354)
---------- ---------- ---------- ----------
Net Cash Provided (Used) by Financing Activities ..... (13,240) (9,999) 4,600 (76,978)
---------- ---------- ---------- ----------
Net Increase in Cash and Cash Equivalents ................. 2,734 4,250 2,004 1,787
Cash and Cash Equivalents, Beginning of Period ............ 4,976 5,111 5,706 7,574
---------- ---------- ---------- ----------
Cash and Cash Equivalents, End of Period .................. $ 7,710 $ 9,361 $ 7,710 $ 9,361
========== ========== ========== ==========
The accompanying notes are an integral part of these condensed
consolidated financial statements.
-5-
CABOT OIL & GAS CORPORATION
NOTES TO 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 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:
JUNE 30, DECEMBER 31,
2002 2001
------------- -------------
(In thousands)
Unproved Oil and Gas Properties ........................ $ 74,829 $ 70,709
Proved Oil and Gas Properties .......................... 1,434,070 1,400,341
Gathering and Pipeline Systems ......................... 133,901 131,768
Land, Building and Improvements ........................ 4,805 4,674
Other .................................................. 28,458 27,513
------------ ------------
1,676,063 1,635,005
Accumulated Depreciation, Depletion and Amortization ... (701,150) (653,667)
------------ ------------
$ 974,913 $ 981,338
============ ============
-6-
3. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
JUNE 30, DECEMBER 31,
2002 2001
----------- -------------
(In thousands)
Accounts Receivable
Trade Accounts ............................................ $ 50,171 $ 39,570
Joint Interest Accounts ................................... 5,687 12,889
Current Income Tax Receivable ............................. 1,413 2,662
Other Accounts ............................................ 691 986
---------- ----------
57,962 56,107
Allowance for Doubtful Accounts ............................. (5,247) (5,396)
---------- ----------
$ 52,715 $ 50,711
========== ==========
Other Current Assets
Commodity Hedging Contracts ............................... $ 844 $ 2,387
Drilling Advances ......................................... 1,951 2,111
Prepaid Balances .......................................... 4,044 2,114
Restricted Cash and Other Accounts ........................ 5,024 4,398
---------- ----------
$ 11,863 $ 11,010
========== ==========
Accounts Payable
Trade Accounts ............................................ $ 23,526 $ 19,914
Natural Gas Purchases ..................................... 7,210 4,559
Royalty and Other Owners .................................. 18,033 11,041
Capital Costs ............................................. 8,630 30,923
Taxes Other Than Income ................................... 2,812 2,686
Drilling Advances ......................................... 4,429 2,627
Wellhead Gas Imbalances ................................... 2,690 2,353
Other Accounts ............................................ 6,224 5,472
---------- ----------
$ 73,554 $ 79,575
========== ==========
Accrued Liabilities
Employee Benefits ......................................... $ 7,465 $ 7,151
Taxes Other Than Income ................................... 13,066 13,623
Interest Payable .......................................... 6,971 6,996
Commodity Hedging Contracts ............................... 5,604 --
Income Taxes Payable ...................................... 882 45
Other Accrued ............................................. 1,959 2,850
---------- ----------
$ 35,947 $ 30,665
========== ==========
Other Liabilities
Postretirement Benefits Other Than Pension ................ $ 1,802 $ 1,689
Accrued Pension Cost ...................................... 2,722 7,280
Taxes Other Than Income and Other ......................... 8,552 9,411
---------- ----------
$ 13,076 $ 18,380
========== ==========
4. LONG-TERM DEBT
At June 30, 2002, the Company had $127 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 presently ends in December 2003
and is subject to renewal. At June 30, 2002, excess capacity totaled $123
million, or 49% of the total available credit line.
-7-
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 second quarter were based on the quarterly
weighted average shares outstanding of 31,737,292 in 2002 and 29,509,047 in
2001. Basic earnings per share for the first six months of the year were based
on the year-to-date weighted average shares outstanding of 31,670,874 in 2002
and 29,414,275 in 2001. The diluted earnings per share amounts are based on
weighted average shares outstanding plus common stock equivalents. Second
quarter common stock equivalents, which include both stock awards and stock
options, totaled 457,720 in 2002 and 444,011 in 2001. For the year to date
period ended June 30, the common stock equivalents were 429,007 in 2002 and
439,767 in 2001. Stock awards and stock options excluded from the calculation of
diluted earnings per share because the effect was antidilutive were 1,168,871
and 781,360 for the second quarter of 2002 and 2001, respectively and 1,197,584
and 785,604 for the year to date periods ended June 30, 2002 and 2001,
respectively.
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 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.
West Virginia Royalty Litigation
In 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 1/8/th/ 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 fluctuations on natural gas and crude oil
production. At June 30, 2002, the Company had two cash flow hedges open: a
series of ten natural gas costless collar arrangements and one crude oil price
collar arrangement. At June 30, 2002, a $4.6 million pre-tax unrealized loss was
recorded to Other Comprehensive Income along with a $5.6 million derivative
liability, a $0.8 million derivative asset, and a non-cash loss of approximately
$0.2 million. The ineffective portion of the cash flow hedges was recorded as a
component of the Change in Derivative Fair Value on the statement of operations.
If commodity prices remain at the current level over the next twelve months, the
Company would recognize a loss of approximately $2.8 million ($4.6 million
pre-tax) to earnings which was deferred in Accumulated Other Comprehensive
Income at June 30, 2002.
-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
six-month periods ended June 30:
SIX MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2002 JUNE 30, 2001
---------------------- ----------------------
(In thousands)
Accumulated Other Comprehensive Income -
Beginning of Period ................................ $ 835 $ --
Net Income .............................................. $ 1,323 $ 52,654
Other Comprehensive Income (net of tax)
Cumulative effect of change in accounting
principle - January 1, 2001 ..................... -- (2,617)
Reclassification adjustment for
settled contracts ............................... (1,420) 2,267
Changes in fair value of outstanding
hedge positions ................................. (2,259) 13,568
--------- ---------
Other Comprehensive Income (Loss) $ (3,679) $ (3,679) $ 13,218 $ 13,218
--------- --------- --------- ----------
Comprehensive Income (Loss) ............................. $ (2,356) $ 65,872
========= =========
Accumulated Other Comprehensive
Income (Loss) - End of Period ...................... $ (2,844) $ 13,218
========= ==========
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.
-10-
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 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.
PERIOD ENDING JUNE 30, 2001
QUARTER SIX MONTHS
------------- -------------
(Unaudited)
(In thousands)
Revenues ......................................... $ 128,557 $ 315,865
Net Income ....................................... $ 15,674 $ 62,792
Per share - Basic ........................... $ 0.50 $ 2.00
Per share - Diluted ......................... $ 0.49 $ 1.97
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 June 30, 2002,
and the related condensed consolidated statements of operations and of cash
flows for each of the three and six-month periods ended June 30, 2002 and June
30, 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
July 26, 2002
-12-
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following review of operations for the first six months 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 half of 2002, we produced 45.3 Bcfe, an increase of 27% over
the 2001 first half. Natural gas production was 36.9 Bcf, up 6.3 Bcf compared to
the 2001 first half. Oil production was up 587 Mbbls, or 74% over the comparable
period of last year. Production from the properties acquired with Cody Company
contributed 6.6 Bcfe, or 68% of the total 9.7 Bcfe increase in equivalent
production, and drilling successes in the Gulf Coast and Eastern regions have
contributed the other 3.1 Bcfe, or 32%.
Commodity prices were unusually high during the first half of 2001, and our
financial results reflected their impact during that period. However, in the
first half of 2002, natural gas prices were 51% lower and crude oil prices were
20% lower than in 2001. This lower commodity price environment impacted our
financial results. Operating revenues decreased $97.8 million, or 37%, and net
income decreased $51.4 million, mainly as a result of this weakened price
environment. Operating cash flows were similarly impacted, declining by $84.1
million over last year.
Our net income for the first six months of 2002 was $1.3 million, or $0.04
per share, including a $1.2 million non-cash loss realized from the change in
the fair value of our derivatives under SFAS 133 (see Note 8), $3.6 million in
charges related to the retirement of the Chief Executive officer in May 2002
(see Note 10), and a first quarter $1.1 million property impairment. These
selected items decreased after-tax net income by $3.6 million, or $0.12 per
share, in the first half of 2002. Excluding these selected items, our 2002 net
income was $4.9 million, or $0.16 per share.
We drilled 54 gross wells (49 development and 5 exploratory wells) with a
success rate of 94% compared to 96 gross wells (83 development and 13
exploratory wells) and an 88% success rate in the first half 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 $66.8 million for the
first half of 2002, compared to $99.6 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 20.
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. Prices then recovered
somewhat during the second quarter of 2002. This is a variation from the
cyclical nature of demand that we had seen previously in the market and may be a
result of increases in commodity storage levels.
Our primary sources of cash during the first six months of 2002 were from
funds generated from operations and increased borrowing on our revolving credit
facility, as well as proceeds from a sale on non-strategic assets and exercises
of stock options. Cash was primarily used to fund exploration and development
expenditures and to pay dividends.
-13-
We had a net cash inflow of $2.0 million in the first six months of 2002.
Cash inflows from operating activities totaled $83.0 million in the period. The
$89.0 million of capital and exploration expenditures were funded with a
combination of the operating cash flows, $4.0 million of increased borrowing on
the revolving credit facility, $3.4 million in proceeds from the sale of
non-strategic assets, and $3.1 million in proceeds from stock option exercises.
SIX MONTHS ENDED JUNE 30,
2002 2001
---------- -----------
(In millions)
Cash Flows Provided by Operating Activities ............$ 83.0 $ 167.1
======== ========
Cash flows from operating activities in the 2002 first half were $84.1
million lower than the corresponding period of 2001 primarily due to lower
natural gas and oil prices and less favorable changes in working capital.
SIX MONTHS ENDED JUNE 30,
2002 2001
--------- -----------
(In millions)
Cash Flows Used by Investing Activities ................$ (85.6) $ (88.3)
======== ========
Cash flows used by investing activities in the first half of 2002 were
primarily a result of capital and exploration expenditures of $89.0 million.
This amount was partially offset by $3.4 million in proceeds from the sale of
non-strategic assets. A portion of the 2002 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 half of 2001 were
substantially attributable to capital and exploration expenditures of $89.0
million, partially offset by proceeds from the sale of certain oil and gas
properties of $0.7 million.
SIX MONTHS ENDED JUNE 30,
2002 2001
--------- -----------
(In millions)
Cash Flows Provided (Used) by Financing Activities .....$ 4.6 $ (77.0)
======== ========
Cash flows provided by financing activities in the first six months of 2002
consist primarily of $4.0 million in increased borrowings on the revolving
credit facility and $3.1 million in proceeds from stock option exercises. Cash
flows used by financing activities in the first half of 2001 included $82.0
million used to reduce borrowings on our revolving credit facility, partially
offset by $7.4 million in proceeds from stock option exercises.
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 $24.9 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 $16 million payment on these notes that was due in May
2002 was paid in May 2001 using existing capacity on the revolving credit
agreement.
-14-
Capitalization
Our capitalization information is as follows:
JUNE 30, DECEMBER 31,
2002 2001
------------ ------------
(In millions)
Debt ..................................$ 397.0 $ 393.0
Stockholders' Equity (1) .............. 347.0 346.6
-------- --------
Total Capitalization ..................$ 744.0 $ 739.6
======== ========
Debt to Capitalization ................ 53.4% 53.1%
/(1)/ Includes common stock, net of treasury stock.
During the first six months of 2002, we paid dividends of $2.5 million
on the Common Stock. A regular dividend of $0.04 per share of Common Stock has
been declared for each quarter since we became a public company.
Capital and Exploration Expenditures
On an annual basis, we generally fund most of our capital and
exploration activities, excluding major oil and gas property acquisitions, with
cash generated from operations, and budget such capital expenditures based upon
projected cash flows for the year.
The following table presents major components of capital and
exploration expenditures:
SIX MONTHS ENDED JUNE 30,
2002 2001
---------- -----------
(In millions)
Capital Expenditures
Drilling and Facilities ............$ 42.1 $ 52.7
Leasehold Acquisitions ............. 2.5 14.0
Pipeline and Gathering ............. 1.2 1.3
Other .............................. 0.3 0.1
-------- --------
46.1 68.1
-------- --------
Proved Property Acquisitions ........... 2.8 6.2
Exploration Expenses ................... 17.9 25.3
-------- --------
Total ..............................$ 66.8 $ 99.6
======== ========
Total capital and exploration expenditures in the first six months of
2002 decreased $32.8 million compared to the same period of 2001, primarily as a
result of planned decreases in drilling, leasehold acquisition costs and other
capital projects in response to lower commodity prices.
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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------- ------------------------
2002 2001 2002 2001
-------- -------- --------- --------
(In millions, except where noted)
Net Operating Revenues ................................ $ 89.6 $ 107.6 $ 164.7 $ 262.5
Operating Expenses .................................... 80.2 80.6 150.2 167.0
Operating Income ...................................... 9.9 27.0 14.8 95.5
Interest Expense ...................................... 6.3 4.7 12.6 9.4
Net Income ............................................ 2.1 13.6 1.3 52.7
Earnings Per Share - Basic ............................ $ 0.07 $ 0.46 $ 0.04 $ 1.79
Earnings Per Share - Diluted .......................... $ 0.07 $ 0.45 $ 0.04 $ 1.76
Natural Gas Production (Bcf)
Gulf Coast ....................................... 7.7 4.7 15.2 9.5
West ............................................. 6.4 6.4 12.8 12.8
Appalachia ....................................... 4.4 4.2 8.9 8.3
------- ------- -------- -------
Total Company .................................... 18.5 15.3 36.9 30.6
Natural Gas Production Sales Prices ($/Mcf)
Gulf Coast ....................................... $ 3.35 $ 5.16 $ 2.99 $ 6.26
West ............................................. $ 2.40 $ 4.11 $ 2.27 $ 5.10
Appalachia ....................................... $ 3.31 $ 5.44 $ 3.08 $ 5.94
Total Company .................................... $ 2.99 $ 4.79 $ 2.76 $ 5.68
Crude/Condensate
Volume (MBbl) .................................... 717 394 1,385 798
Price ($/Bbl) .................................... $ 24.19 $ 27.86 $ 22.43 $ 28.21
Brokered Natural Gas Margin
Volume (Bcf) ..................................... 5.9 5.6 9.1 10.4
Margin ($/Mcf) ................................... $ 0.19 $ 0.17 $ 0.28 $ 0.21
The table below presents the after-tax effect of certain selected items
on our results of operations for the three- and six-month periods ended June 30,
2002.
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2002 JUNE 30, 2002
------------------------- -------------------------
Amount per share Amount per share
---------- --------- ----------- ---------
(In millions, except per share amounts)
Net Income Before Selected Items ....................... $ 4.7 $ 0.15 $ 4.9 $ 0.16
Retirement of Chief Executive Officer ................. (2.2) (0.07) (2.2) (0.07)
Impairment of Long-Lived Assets ....................... -- -- (0.7) (0.03)
Change in Derivative Fair Value ....................... (0.4) (0.01) (0.7) (0.02)
------- -------- -------- --------
Net Income (as reported) ............................... $ 2.1 $ 0.07 $ 1.3 $ 0.04
======= ======== ======== ========
The selected items in 2002 include the change in derivative fair value
during the six months ended June 30, 2002 (Note 9), charges related to the
retirement of the Chief Executive Officer (Note 10) and an impairment taken
during the first quarter.
-16-
The table below presents the after-tax effect of certain selected items
on our results of operations for the three- and six-month periods ended June 30,
2001.
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2001 JUNE 30, 2001
------------------------ -----------------------
Amount per share Amount per share
--------- --------- --------- ---------
(In millions, except per share amounts)
Net Income Before Selected Items .............. $ 16.7 $ 0.56 $ 51.9 $ 1.76
Change in Derivative Fair Value .............. (3.1) (0.10) 0.8 0.03
------- -------- -------- --------
Net Income (as reported) ...................... $ 13.6 $ 0.46 $ 52.7 $ 1.79
======= ======== ======== ========
The selected item in 2001 is the change in derivative fair value during
the six months ended June 30, 2001 related to the adoption SFAS 133 on January
1, 2001. See Note 9 for further discussion.
The discussion below excludes the impact of these selected items.
Second Quarters of 2002 and 2001 Compared
Net Income and Revenues. We reported net income before the selected
items in the second quarter of 2002 of $4.7 million, or $0.15 per share. During
the corresponding quarter of 2001, we recorded net income excluding selected
items of $16.7 million, or $0.56 per share. Operating revenues decreased by
$22.4 million and operating income decreased by $18.0 million. Natural gas made
up 61%, or $55.3 million, of net operating revenue in 2002. The decrease in net
operating revenues was driven by declines in realized commodity prices of 38%
for natural gas and 13% for oil. Net income and operating income were similarly
impacted by the reduction in commodity prices.
The average Gulf Coast natural gas production sales price decreased
$1.81 per Mcf, or 35%, to $3.35, decreasing net operating revenues by
approximately $13.9 million. In the Western region, the average natural gas
production sales price decreased $1.71 per Mcf, or 42%, to $2.40, decreasing net
operating revenues by approximately $10.9 million. The average Appalachian
natural gas production sales price decreased $2.13 per Mcf, or 39%, to $3.31,
decreasing net operating revenues by approximately $9.4 million. The overall
weighted average natural gas production sales price decreased $1.80 per Mcf, or
38%, to $2.99, decreasing revenues by $34.2 million. Sales of approximately 70%
of our natural gas production for the quarter were covered by a series of
natural gas price collars that limited our exposure to movements in commodity
prices. However, index prices rose above the ceiling of most of these collars
for April through June of 2002. The resulting $3.3 million hedge loss decreased
our realized natural gas price for the quarter by $0.18 per Mcf. These collar
arrangements cover 149 Mcf of natural gas production per day and remain in place
through August 2002.
Natural gas production volume in the Gulf Coast region was up 3.0 Bcf,
or 64%, to 7.7 Bcf primarily due to the acquisition of Cody Company in August
2001 and new production brought on line in south Texas. Natural gas production
volume in the Western region remained at 6.4 Bcf. Natural gas production volume
in the Appalachian region was up 0.2 Bcf, or 5%, to 4.4 Bcf. The 3.2 Bcf, or
21%, improvement in total natural gas production increased revenue by $16.1
million in the second quarter of 2002.
Brokered natural gas revenue decreased $11.6 million, or 42%, over the
second quarter of last year. The sales price of brokered natural gas declined
46%, resulting in a decrease in revenue of $13.1 million, only partially offset
by a 6% rise in volume of natural gas brokered this quarter, improving revenues
by $1.5 million. After including the related brokered natural gas costs, we
realized a net margin of $1.1 million in the second quarter of 2002 and $1.0
million in the comparable quarter of 2001.
Crude oil prices decreased $3.67 per Bbl, or 13%, to $24.19, resulting
in a decrease to net operating revenues of approximately $2.6 million. In
addition, the volume of crude oil sold in the quarter increased by 323 Mbbls, or
82%, to 717 Mbbls, boosting net operating revenues by $9.0 million. This
improvement in volume is primarily in the Gulf Coast, which had the benefit of
both the August 2001 Cody acquisition and increased production resulting from
the 2001 drilling program.
-17-
Other net operating revenues increased $0.9 million to $1.8 million,
both as a result of transportation revenues from a new pipeline in the Rocky
Mountains area in 2002 and a decrease in revenue reductions related to payouts
on certain fields.
Costs and Expenses. Excluding the second quarter 2002 costs incurred
in connection with the retirement of the Chief Executive Officer in May 2002,
total costs and expenses from operations decreased $4.0 million, or 5%, in the
second quarter of 2002 compared to the same period of 2001. The primary reasons
for this fluctuation are as follows:
. Brokered natural gas cost decreased $11.7 million, or 45%, over the
second quarter of last year. The price per Mcf of brokered natural gas
decreased 48%, resulting in a decrease to expense of $13.2 million,
offset by a 6% increase in volume of natural gas brokered this
quarter, increasing costs by $1.5 million. After including the related
brokered natural gas revenues, we realized a net margin of $1.1
million in the second quarter of 2002 and $1.0 million in the
comparable quarter of 2001.
. Direct operating expense increased $2.3 million, or 24%, primarily as
a result of costs associated with operating the properties acquired in
the Cody acquisition 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 declined slightly
from $0.54 per Mcf in the second quarter of 2001 to $0.52 per Mcf in
2002.
. Exploration expense decreased $3.7 million, or 26%, primarily as a
result of a $4.9 million decline in dry hole expense from the
comparable quarter of 2001. However, geological and geophysical
expense, primarily related to the acquisition and processing of
seismic data, increased $1.6 million for the quarter. Delay rental
payments also declined slightly for the quarter. These changes are
consistent with the 2002 budget and the more active 2001 drilling
program.
. Depreciation, depletion, amortization and impairment expense increased
$8.1 million, or 46%, due to the increase in natural gas and oil
production in the quarter, as well as the stronger influence of the
higher cost Gulf Coast region. Equivalent production in this region
has increased 75% from last year's second quarter including amounts
attributable to the Cody Company properties. On a per unit basis, DD&A
for the second quarter was $1.00 per Mcf in 2001 and $1.13 per Mcf in
2002.
. General and administrative costs rose $0.3 million, or 5%, primarily
as a result of costs associated with certain non-cash compensation
programs.
. Taxes other than income rose $0.8 million, or 11%, as a result of
higher natural gas and oil production this quarter.
Interest expense increased $1.6 million as a result of a higher
average level of outstanding debt during the second quarter of 2002 when
compared to the second quarter of 2001. The new debt was primarily related to
the Cody Company acquisition.
Income tax expense decreased $7.6 million due to the comparable
decrease in earnings before income tax excluding the selected items.
Six Months of 2002 and 2001 Compared
Net Income and Revenues. Excluding the selected items, we reported
net income in the first half of 2002 of $4.9 million, or $0.16 per share. During
the corresponding half of 2001, we had net income excluding selected items of
$51.9 million, or $1.76 per share. Operating revenues and operating income
decreased $95.4 million and $73.6 million, respectively. Natural gas made up
62%, or $101.8 million, of net operating revenue in 2002. The decrease in net
operating revenues was driven primarily by a 51% decrease in the average natural
gas price and by a 20% decrease in the average oil price. Net income and
operating income were similarly impacted by the decline in commodity prices.
The average Gulf Coast natural gas production sales price decreased
$3.27 per Mcf, or 52%, to $2.99, decreasing net operating revenues by
approximately $49.7 million. In the Western region, the average natural gas
production sales price decreased $2.83 per Mcf, or 55%, to $2.27, decreasing net
operating revenues by approximately $36.2 million. The average Appalachian
natural gas production
-18-
sales price decreased $2.86 per Mcf, or 48%, to $3.08, decreasing net operating
revenues by approximately $25.5 million. The overall weighted average natural
gas production sales price decreased $2.92 per Mcf, or 51%, to $2.76, decreasing
revenues by $111.4 million.
Natural gas production volume in the Gulf Coast region was up 5.7 Bcf,
or 60%, to 15.2 Bcf due both to the August 2001 Cody acquisition and to new
production brought on line in south Texas. Natural gas production volume in the
Western region remained at 12.8 Bcf. Natural gas production volume in the
Appalachian region was up 0.6 Bcf, or 7%, to 8.9 Bcf, as a result of an increase
in drilling activity in the region during 2001. The 6.3 Bcf, or 21%, rise in
total natural gas production increased revenue by $39.1 million in the first
half of 2002.
The volume of crude oil sold in the first six months of the year
increased by 587 Mbbl, or 74%, to 1,385 Mbbl, increasing net operating revenues
by $16.6 million. Our increased crude oil sales volumes were primarily from the
Gulf Coast region, which had the benefit of both the August 2001 Cody
acquisition and increased production resulting from the 2001 drilling program.
Crude oil prices decreased $5.78 per Bbl, or 20%, to $22.43, resulting in a
decrease to net operating revenues of approximately $8.0 million.
Brokered natural gas revenue decreased $33.3 million, or 53%, over the
first half of last year. The sales price of brokered natural gas declined 46%,
resulting in a decrease in revenue of $25.1 million, combined with a 13%
decrease in volume of natural gas brokered this period, which reduced revenues
by $8.2 million. After including the related brokered natural gas costs, we
realized a net margin of $2.5 million in the first half of 2002 and $2.2 million
in the comparable period of 2001.
Other operating revenues increased $1.6 million to $3.6 million, both
as a result of transportation revenues from a new pipeline in the Rocky
Mountains area in 2002 and a decrease in revenue reductions related to payouts
on certain fields.
Costs and Expenses. Excluding the selected items, total costs and
expenses from operations decreased $21.4 million, or 13%, due primarily to the
following:
. Brokered natural gas cost decreased $33.6 million, or 56%, over the
first half of last year. The cost of brokered natural gas dropped 49%,
resulting in a decrease to expense of $25.7 million, combined with a
13% decrease in volume of natural gas brokered this quarter, reducing
costs by $7.9 million. After including the related brokered natural gas
revenues we realized a net margin of $2.5 million in the first half of
2002 and $2.2 million in the comparable period of 2001.
. Direct operating expense increased $6.3 million, or 35%, primarily as
a result of costs associated with operating the properties acquired in
the Cody acquisition in August 2001. Additionally, operating costs
have increased in the Gulf Coast, and to a lesser extent in the Rocky
Mountains and East, where we are have more active properties than in
prior quarters. On a per unit basis, operating expense has increased
slightly from $0.50 per Mcf in the first half of 2001 to $0.53 per Mcf
in 2002.
. Exploration expense decreased $7.4 million, or 29%, primarily as a
result of a $5.4 million decline in dry hole expense from the
comparable period of 2001. Delay rental payments were $1.0 million
lower than in 2001 as wells have been drilled on certain Gulf Coast
leases, and due to the fact that certain leases have been released.
Geological and geophysical expense, primarily related to the
acquisition and processing of seismic data, has decreased $0.5 million
for the period. These changes are consistent with the 2002 budget and
the more active 2001 drilling program.
. Depreciation, depletion and amortization expense increased $16.3
million, or 46%, due to the increase in natural gas and oil production
and the stronger influence of the higher cost Gulf Coast region.
Equivalent production in this region has increased 69% from last year
including amounts attributable to the Cody Company properties. On a
per unit basis, DD&A for the first half of the year was $0.98 per Mcf
in 2001 and $1.13 per Mcf in 2002.
. General and administrative expenses were up slightly from the same
period of 2001 excluding the selected item related to the retirement of
the Chief Executive Officer in May 2002.
. Taxes other than income declined $3.0 million, or 18%, as a result of
lower commodity prices realized this year.
-19-
Interest expense increased $3.1 million as a result of a higher average
level of outstanding debt during the first half of 2002 when compared to 2001.
The new debt was primarily related to the Cody Company acquisition.
Income tax expense decreased $29.8 million due to the comparable
decrease in earnings before income tax excluding the selected items.
Forward-Looking Information
The statements regarding future financial performance and results,
market prices, impact of the Cody Company acquisition 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 six
months of 2002 was more than 50% 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 covering 149 Mcf per day in place through August 2002 and oil
price collars covering 4 Mbbls per day 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 paragraph contains forward-looking information. See
Forward-Looking Information above.
-20-
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 half of 2002, we
did not have any natural gas price swaps covering our production. During the
first half of 2001, natural gas price swaps covered 498 Mmcf, fixing the sales
price of this gas at $3.97 per Mcf. We entered into no oil price swaps covering
the first half 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 13,409 Mmcf, or 44%, of our natural gas production for
the first half of 2001. All indexes were within the collars during February,
however some fell below the floor during the period of March, and all indexes
were below the collars in May and June resulting in $4.8 million cash revenue
for the first six months of 2001. This gain improved our realized natural gas
price for the first half of 2001 by $0.16 per Mcf.
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 were in place for the months of January through April 2002 and covered
66% of our natural gas production during this period. These collars had 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. The indexes were below
the floor during February and March during which time we realized a $2.4 million
cash gain. However, the indexes rose above the ceiling for April 2002, resulting
in a $0.5 million cash loss. The $1.9 million net gain increased our realized
gas price for the first six months of 2002 by $0.05 per Mcf.
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. During the first half of 2002, these collars covered 9,067
Mcf of production. The indexes were above the ceiling during May and June and
the resulting $2.8 million cash loss reduced our realized gas price for the
first six months of 2002 by $0.08 per Mcf.
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. The index was above the ceiling for each month March through June 2002.
The resulting $1.4 million cash loss reduced our realized oil price by $0.98 per
barrel.
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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.
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 20.
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PART II. OTHER INFORMATION
ITEM 2. Changes in Securities and Use of Proceeds
On July 1, 2002, the Company filed with the Secretary of State of the
State of Delaware (i) an amendment to its Certificate of Incorporation and (ii)
a Certificate of Increase of Shares Designated Series A Junior Participating
Preferred Stock. These filings (i) eliminated the Company's Class B Common Stock
from the Company's Certificate of Incorporation and changed the name of the
Company's Class A Common Stock to simply "Common Stock" and (ii) increased the
authorized Common Stock from the 40,000,000 shares of Class A Common Stock
previously authorized to 80,000,000 shares of Common Stock, par value $.10 per
share. Each issued share of Class A Common Stock prior to the filing of the
amendment to the Certificate of Incorporation is now a share of Common Stock.
ITEM 4. Submission of Matters to a Vote of Security Holders
On May 2, 2002, the Company held its Annual Meeting of Stockholders. At
this meeting, the Company's stockholders voted on three matters:
.. the election of three directors,
.. the approval of the an amendment to the Company's Certificate of
Incorporation to eliminate the Class B Common Stock from the Certificate of
Incorporation and change the name of the Class A Common Stock to simply
"Common Stock" and increase the authorized Common Stock from the 40,000,000
shares of Class A Common Stock currently authorized to 80,000,000 shares of
Common Stock, and
.. the ratification of the appointment of PricewaterhouseCoopers LLP,
independent certified public accountants, as auditors of the Company for
its 2002 fiscal year.
Of the total outstanding shares, 28,984,156, or 92%, were voted. There were no
broker nonvotes.
Shareholders voted to re-elect three directors by the following vote:
Dan O. Dinges
-------------
Votes cast in favor: 28,798,183
Votes withheld: 185,973
Arthur L. Smith
---------------
Votes cast in favor: 28,708,781
Votes withheld: 275,375
William P. Vititoe
------------------
Votes cast in favor: 28,795,939
Votes withheld: 188,217
The terms of office of directors Robert F. Bailey, Henry O. Boswell,
John G.L Cabot, James G. Floyd, C. Wayne Nance, and P. Dexter Peacock continued
beyond the meeting date. Charles P. Siess retired from the Board of Directors
immediately following the 2002 Annual Meeting of Stockholders in accordance with
the Board's mandatory retirement policy. Ray R. Seegmiller retired from the
Board of Directors immediately following the 2002 Annual Meeting of Stockholders
in connection with his retirement as Chief Executive Officer.
The second item presented for a vote before the stockholders was
approval of an amendment to the Company's Certificate of Incorporation with
respect to the Common Stock, as described above. Of the votes received,
26,903,764 were in favor of the approval, 2,072,467 were against, and 7,925
abstained.
The last item presented for a vote before the stockholders was the
ratification of the appointment of PricewaterhouseCoopers LLP, independent
certified public accountants, as auditors of the Company for its 2002 fiscal
year. Of the votes received, 28,296,119 were in favor of the ratification,
683,910 were against, and 4,127 abstained.
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ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibits
3.1 -- Certificate of Amendment of Certificate of
Incorporation (Form 8-K July 2, 2002 Exhibit 3.1).
3.2 -- Certificate of Increase of Shares Designated Series A
Junior Participating Preferred Stock (Form 8-K July 2,
2002 Exhibit 3.2).
15.1 -- Awareness letter of independent accountants.
(b) Reports on Form 8-K
. A Form 8-K Item 5 was filed on July 2, 2002. The Form 8-K
reported that the Company had filed documents with the
Secretary of State of the State of Delaware that eliminated
the Class B Common Stock from the Certificate of
Incorporation and changed the name of the Class A Common
Stock to simply "Common Stock" and increased the authorized
Common Stock from the 40,000,000 shares of Class A Common
Stock previously authorized to 80,000,000 shares of Common
Stock.
. An 8-K/A was filed on July 3, 2002 to complete a date left
blank in the July 2nd Form 8-K.
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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)
July 26, 2002 By: /s/ Scott C. Schroeder
------------------------------------
Scott C. Schroeder
Vice President, Chief Financial
Officer and Treasurer
(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)
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