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, 2001
( ) 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 24, 2001, there were 29,601,604 shares of Class A Common Stock,
Par Value $.10 Per Share, outstanding.
-1-
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, 2001 and 2000........................................................... 3
Condensed Consolidated Balance Sheet at June 30, 2001 and December 31, 2000............. 4
Condensed Consolidated Statement of Cash Flows for the Three and Six Months
Ended June 30, 2001 and 2000........................................................... 5
Notes to Condensed Consolidated Financial Statements.................................... 6
Report of Independent Accountant's Review of
Interim Financial Information.......................................................... 11
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations................................................................ 12
Item 3A. Quantitative and Qualitative Disclosures about Market Risk...................... 20
Part II. Other Information
Item 4. Submission of Matters to a Vote of Security Holders.............................. 22
Item 6. Exhibits and Reports on Form 8-K................................................. 22
Signature.................................................................................... 23
-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,
-------------------- --------------------
2001 2000 2001 2000
-------- ------- -------- --------
NET OPERATING REVENUES
Natural Gas Production.............................. $ 73,411 $38,903 $174,136 $ 77,989
Brokered Natural Gas................................ 27,273 37,024 62,695 73,960
Crude Oil and Condensate............................ 10,964 4,649 22,520 8,974
Change in Derivative Fair Value (Note 8)........... (4,988) -- 1,211 --
Other............................................... 946 1,872 1,936 6,644
-------- ------- -------- --------
107,606 82,448 262,498 167,567
OPERATING EXPENSES
Brokered Natural Gas Cost........................... 26,323 35,923 60,479 71,408
Direct Operations - Field & Pipeline................ 9,650 9,062 17,870 17,573
Exploration......................................... 14,540 4,162 25,313 7,395
Depreciation, Depletion and Amortization............ 16,198 12,464 32,089 25,112
Impairment of Unproved Properties................... 1,482 963 2,964 1,923
Impairment of Long-Lived Assets..................... -- 9,143 -- 9,143
General and Administrative.......................... 5,691 5,331 11,638 10,218
Taxes Other Than Income............................. 6,715 4,954 16,617 9,555
-------- ------- -------- --------
80,599 82,002 166,970 152,327
Loss on Sale of Assets................................ (31) (26) (27) (47)
-------- ------- -------- --------
INCOME FROM OPERATIONS................................ 26,976 420 95,501 15,193
Interest Expense...................................... 4,704 5,365 9,409 11,336
-------- ------- -------- --------
Income (Loss) Before Income Taxes..................... 22,272 (4,945) 86,092 3,857
Income Tax Expense (Benefit).......................... 8,679 (1,863) 33,438 1,594
-------- ------- -------- --------
NET INCOME (LOSS)..................................... 13,593 (3,082) 52,654 2,263
Dividend Requirement on Preferred Stock............... -- (4,600) -- (3,749)
-------- ------- -------- --------
Net Income Applicable to
Common Stockholders................................. $ 13,593 $ 1,518 $ 52,654 $ 6,012
======== ======= ======== ========
Basic Earnings Per Share
Applicable to Common Stockholders................... $ 0.46 $ 0.05 $ 1.79 $ 0.23
Diluted Earnings Per Share
Applicable to Common Stockholders................... $ 0.45 $ 0.05 $ 1.76 $ 0.23
Average Common Shares Outstanding..................... 29,509 26,694 29,414 25,746
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,
2001 2000
-------- ------------
ASSETS
Current Assets
Cash and Cash Equivalents.............................. $ 9,361 $ 7,574
Accounts Receivable.................................... 55,641 85,677
Inventories............................................ 14,194 11,037
Other.................................................. 30,028 5,981
-------- --------
Total Current Assets................................ 109,224 110,269
Properties and Equipment, Net (Successful Efforts Method).. 661,732 623,174
Other Assets............................................... 1,974 2,191
-------- --------
$772,930 $735,634
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current Portion of Long-Term Debt...................... $ -- $ 16,000
Accounts Payable....................................... 95,050 81,566
Accrued Liabilities.................................... 27,334 20,542
-------- --------
Total Current Liabilities........................... 122,384 118,108
Long-Term Debt............................................. 187,000 253,000
Deferred Income Taxes...................................... 135,626 108,174
Other Liabilities.......................................... 13,837 13,847
Stockholders' Equity
Common Stock:
Authorized -- 40,000,000 Shares of $.10 Par Value
Issued and Outstanding - 29,892,603 Shares and
29,494,411 Shares in 2001 and 2000, Respectively.... 2,989 2,949
Additional Paid-in Capital............................. 293,591 285,572
Retained Earnings/(Accumulated Deficit)................ 8,669 (41,632)
Accumulated Other Comprehensive Income (Note 9)........ 13,218 --
Less Treasury Stock, at Cost:
302,600 Shares in 2001 and 2000..................... (4,384) (4,384)
-------- --------
Total Stockholders' Equity.......................... 314,083 242,505
-------- --------
$772,930 $735,634
======== ========
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,
------------------- ------------------
2001 2000 2001 2000
-------- -------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss).................................... $ 13,593 $ (3,082) $ 52,654 $ 2,263
Adjustment to Reconcile Net Income (Loss) to
Cash Provided by Operating Activities:
Depletion, Depreciation and Amortization........... 16,198 12,464 32,089 25,112
Impairment of Undeveloped Leasehold................ 1,482 963 2,964 1,923
Impairment of Long-Lived Assets.................... -- 9,143 -- 9,143
Deferred Income Taxes.............................. 5,319 (1,994) 19,107 607
Loss on Sale of Assets............................. 31 26 27 47
Exploration Expense................................ 14,540 4,162 25,313 7,395
Change in Derivative Fair Value.................... 4,988 -- (1,211) --
Other.............................................. 602 (262) 1,381 239
Changes in Assets and Liabilities:
Accounts Receivable................................ 15,503 (8,811) 30,036 (7,776)
Inventories........................................ (6,618) (3,385) (3,157) 2,617
Other Current Assets............................... 4,575 (2,142) (534) (790)
Other Assets....................................... 73 240 217 340
Accounts Payable and Accrued Liabilities........... (11,194) 7,962 8,785 8,400
Other Liabilities.................................. (1,597) 488 (578) 1,687
-------- -------- --------- --------
Net Cash Provided by Operating Activities........ 57,495 15,772 167,093 51,207
-------- -------- --------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures................................. (29,008) (23,115) (63,754) (42,060)
Proceeds from Sale of Assets......................... 302 258 739 1,781
Exploration Expense.................................. (14,540) (4,162) (25,313) (7,395)
-------- -------- --------- --------
Net Cash Used by Investing Activities............... (43,246) (27,019) (88,328) (47,674)
-------- -------- --------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Sale of Common Stock................................. 3,182 78,817 7,376 80,048
Retirement of Preferred Stock........................ -- (51,600) -- (51,600)
Increase in Debt..................................... 54,000 29,000 73,000 56,000
Decrease in Debt..................................... (66,000) (42,000) (155,000) (84,000)
Dividends Paid....................................... (1,181) (2,377) (2,354) (4,231)
-------- -------- --------- --------
Net Cash Provided (Used) by Financing Activities.... (9,999) 11,840 (76,978) (3,783)
-------- -------- --------- --------
Net Increase (Decrease) in Cash and Cash Equivalents.. 4,250 593 1,787 (250)
Cash and Cash Equivalents, Beginning of Period........ 5,111 836 7,574 1,679
-------- -------- --------- --------
Cash and Cash Equivalents, End of Period.............. $ 9,361 $ 1,429 $ 9,361 $ 1,429
======== ======== ========= ========
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 (with the addition
of SFAS 133, which was adopted on January 1, 2001 - see Note 8). People using
financial information produced for interim periods are encouraged to refer to
the footnotes in the Annual Report to Stockholders when reviewing interim
financial results. In management's opinion, the accompanying interim financial
statements contain all material adjustments, consisting only of normal recurring
adjustments, necessary for a fair presentation. The results of operations for
any interim period are not necessarily indicative of the results of operations
for the entire year.
Our independent accountants have performed a review of these condensed
consolidated interim financial statements in accordance with standards
established by the American Institute of Certified Public Accountants. Pursuant
to Rule 436(c) under the Securities Act of 1933, this report should not be
considered a part of a registration statement prepared or certified by
PricewaterhouseCoopers LLP within the meanings of Section 7 and 11 of the Act.
2. PROPERTIES AND EQUIPMENT
Properties and equipment are comprised of the following:
JUNE 30, DECEMBER 31,
2001 2000
---------- -----------
(In thousands)
Unproved Oil and Gas Properties....................... $ 41,450 $ 31,780
Proved Oil and Gas Properties......................... 1,053,453 993,397
Gathering and Pipeline Systems........................ 129,654 128,257
Land, Building and Improvements....................... 4,563 4,538
Other................................................. 25,745 25,601
---------- ----------
1,254,865 1,183,573
Accumulated Depreciation, Depletion and Amortization.. (593,133) (560,399)
---------- ----------
$ 661,732 $ 623,174
========== ==========
3. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
JUNE 30, DECEMBER 31,
2001 2000
-------- ------------
(In thousands)
Accounts Receivable
Trade Accounts........................................ $ 52,018 $ 79,773
Joint Interest Accounts............................... 5,822 4,074
Current Income Tax Receivable......................... 37 37
Other Accounts........................................ 722 4,347
---------- ----------
58,599 88,231
Allowance for Doubtful Accounts........................ (2,958) (2,554)
--------- ----------
$ 55,641 $ 85,677
========= ==========
-6-
JUNE 30, DECEMBER 31,
2001 2000
------- -------
(In thousands)
Other Current Assets
Derivative Instrument Asset - SFAS 133................. $23,514 $ --
Drilling Advances...................................... 3,542 2,459
Prepaid Balances....................................... 1,040 1,101
Other Accounts......................................... 1,932 2,421
------- -------
$30,028 $ 5,981
======= =======
Accounts Payable
Trade Accounts......................................... $17,898 $20,855
Natural Gas Purchases.................................. 13,457 12,525
Royalty and Other Owners............................... 18,597 22,858
Capital Costs.......................................... 24,041 13,486
Taxes Other Than Income................................ 3,354 2,654
Drilling Advances...................................... 2,804 456
Wellhead Gas Imbalances................................ 2,433 2,185
Other Accounts......................................... 12,466 6,547
------- -------
$95,050 $81,566
======= =======
Accrued Liabilities
Employee Benefits...................................... $ 5,536 $ 5,441
Taxes Other Than Income................................ 14,033 11,363
Interest Payable....................................... 1,298 2,478
Income Taxes Payable................................... 4,617 --
Short-Term Derivative Instrument Liability - SFAS 133.. 172 --
Other Accrued.......................................... 1,678 1,260
------- -------
$27,334 $20,542
======= =======
Other Liabilities
Postretirement Benefits Other Than Pension............. $ 1,657 $ 1,497
Accrued Pension Cost................................... 6,862 6,743
Long-Term Derivative Instrument Liability - SFAS 133... 568 --
Taxes Other Than Income and Other...................... 4,750 5,607
------- -------
$13,837 $13,847
======= =======
4. LONG-TERM DEBT
At June 30, 2001, the Company had $87 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.
In July 2001, the Company issued $170 million of notes in a private
placement transaction for the purpose of funding the acquisition of Cody
Company. See discussion in Note 10.
5. EARNINGS PER SHARE
Basic earnings per share for the second quarter and six months of the year
were based on the year-to-date weighted average shares outstanding of 29,414,275
in 2001 and 25,746,134 in 2000. The diluted earnings per share amounts are based
on weighted average shares outstanding plus common stock equivalents. Common
stock equivalents, which include both stock awards and stock options, totaled
439,767 in 2001 and 328,425 in 2000.
-7-
6. ENVIRONMENTAL LIABILITY
The EPA notified the Company in February 2000 that it might have 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 1989. The EPA stated that federal, state and local
governmental agencies along with the numerous private entities that used the
Site for waste disposal will be expected to pay the clean-up costs which could
total as much as several hundred million dollars. The EPA is also pursuing the
owners/operators of the Site to pay for remediation.
Documents received 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 stemmed 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, has had extensive settlement discussions with
the EPA. However, the parties have yet to reach an agreement.
The Company has a reserve that it believes is adequate to provide for this
potential environmental liability 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 or cash flows, management does not believe
it would materially impact the Company's financial position. The Company will
continue to monitor the facts and its assessment of its liability related to
this claim.
7. WYOMING ROYALTY LITIGATION
In June 2000, two overriding royalty owners sued the Company in Wyoming
State court. The plaintiffs have requested class certification under the
Wyoming Rules of Civil Procedure and allege that the Company has deducted
impermissible 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.
The Company believes that it has substantial defenses to this claim and
intends to vigorously assert such defenses. The Company has a reserve that it
believes is adequate to provide for this potential liability 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 or cash
flows, management does not believe it would materially impact the Company's
financial position.
8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY
On January 1, 2001, the Company adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138. Under
SFAS 133, all derivative instruments are recorded on the balance sheet at fair
value. If the derivative does not qualify as a hedge or is not designated as a
hedge, the gain or loss on the derivative is recognized currently in earnings.
To qualify for hedge accounting, the derivative must qualify either as a fair
value hedge, cash flow hedge or foreign currency hedge. Currently, the Company
uses only cash flow hedges and the remaining discussion will relate exclusively
to this type of derivative instrument. If the derivative qualifies for hedge
accounting, the gain or loss on the derivative is deferred in Other
Comprehensive Income/Loss, a component of Stockholders' Equity, to the extent
the hedge is effective.
The relationship between the hedging instrument and the hedged item must be
highly effective in achieving the offset of changes in cash flows attributable
to the hedged risk both at the inception of the contract and on an ongoing
basis. The Company measures effectiveness on a monthly basis. Hedge accounting
is discontinued prospectively when a hedge instrument becomes ineffective.
Gains and losses deferred in accumulated Other Comprehensive Income related to
cash flow hedges that become ineffective remain unchanged until the related
production is delivered. If the Company determines that it is probable that a
hedged forecasted transaction will not occur, deferred gains or losses on the
hedging instrument are recognized in earnings immediately.
-8-
Gains and losses on hedging instruments related to accumulated Other
Comprehensive Income and adjustments to carrying amounts on hedged production
are included in natural gas or crude oil production revenues in the period that
the related production is delivered. Gains and losses of hedging instruments,
which represent hedge ineffectiveness and changes in the time value component of
the fair value, are included in Change in Derivative Fair Value on the income
statement in the period in which they occur.
The Company periodically enters into derivative commodity instruments to
hedge its exposure to price fluctuation on natural gas and crude oil production.
At June 30, 2001, the Company had two types of cash flow hedges open: a series
of eight costless collar arrangements and one natural gas price swap. At June
30, 2001, a $21.6 million pre-tax unrealized gain was recorded to Other
Comprehensive Income along with a $0.7 million derivative liability, a
derivative asset of $23.5 million and a non-cash gain of $1.2 million. The
ineffective portion of the cash flow hedges, a $1.0 million gain at June 30,
2001, was recorded as a component of the Change in Derivative Fair Value on the
income statement. The remainder of the Change in Derivative Fair Value was a
$0.2 million gain at June 30, 2001, representing the time value component of the
costless collar arrangement. Based on commodity prices and other circumstances
as of June 30, 2001, the Company expects to reclass a deferred gain of $13.2
million ($21.6 million pre-tax) to earnings from Accumulated Other Comprehensive
Income during the next twelve months.
For 2001, the Company has entered into costless collar arrangements for 24.4
Bcf of its natural gas production with weighted average floor and ceiling prices
of $5.59/Mcf and $9.68/Mcf. In addition, the Company had entered into a natural
gas price swap covering 0.9 Bcf of production for 2001 at a weighted average
price of $3.75/Mcf. This swap also covers 0.7 Bcf of production in 2002 at
$3.11/Mcf, and 0.4 Bcf in 2003 at $2.81/Mcf.
On January 1, 2001, in accordance with the transition provisions of SFAS
133, the Company recorded an after-tax loss of $2.6 million in Other
Comprehensive Loss representing the cumulative effect of an accounting change to
recognize at fair value all cash flow derivatives. The Company recorded cash
flow hedge derivative liabilities of $4.3 million and an after-tax, non-cash
loss of less than $0.1 million was recorded in earnings as a component of the
Change in Derivative Fair Value.
During the first six months of 2001, gains of $3.7 million ($2.3 million
after tax) were transferred to Other Comprehensive Income and the Derivative
Instrument Asset on the balance sheet increased $22.1 million ($13.6 million
after tax).
All hedge transactions are subject to the Company's risk management policy,
approved by the Board of Directors, which does not permit speculative positions.
The Company formally documents all relationships between hedging instruments and
hedged items, as well as its risk management objectives and strategy for
undertaking the hedge. This process includes specific identification of the
hedging instrument and the hedge transaction, the nature of the risk being
hedged and how the hedging instrument's effectiveness will be assessed. Both at
the inception of the hedge and on an ongoing basis, the Company assesses whether
the derivatives that are used in hedging transactions are highly effective in
offsetting changes in cash flows of hedged items.
-9-
9. COMPREHENSIVE INCOME
Comprehensive income includes net income and certain items recorded directly
to shareholders' equity and classified as Other Comprehensive Income. The
Company recorded Other Comprehensive Income for the first time in January of
2001. Following the adoption of SFAS 133, the Company recorded an after-tax
credit to Other Comprehensive Income of $13.2 million in the first six months of
2001 related to the change in fair value of certain derivative financial
instruments that has qualified for cash flow hedge accounting. The following
table illustrates the calculation of comprehensive income for the six-month
period ended June 30, 2001:
(In thousands)
--------------
Accumulated Other Comprehensive Income - December 31, 2000.. $ --
Net Income.................................................. $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 2,267
Changes in fair value of outstanding hedging positions 13,568
-------
Other Comprehensive Income.................................. $13,218 $13,218
------- -------
Comprehensive Income........................................ $65,872
=======
Accumulated Other Comprehensive Income...................... $13,218
=======
There were no items in Other Comprehensive Income during 2000.
10. ACQUISITION OF CODY COMPANY
In June 2001, the Company entered into a definitive merger agreement to
acquire the stock of Cody Company, the parent of Cody Energy LLC for $230
million. Cody shareholders will receive approximately $168 million in cash and
$62 million in stock, or cash and stock, at the Company's election. The Cody
Company acquisition is expected to close prior to August 17, 2001. Cody Company
is based in Denver, Colorado, with substantially all of its exploration and
production reserves located in the onshore Gulf Coast region.
To fund the cash portion of this acquisition, the Company issued $170
million in Notes in a private placement transaction that closed on July 26,
2001. Prior to the determination of the Note's interest rates, the Company
entered into a treasury lock in order to reduce the risk of rising interest
rates. Interest rates rose during the pricing period, resulting in a $0.7
million gain that will be amortized over the life of the Notes, and thereby
reducing the effective interest rate by 5.5 basis points. The Notes are in
three series with maturity dates and interest rates as follows:
$75 million with a coupon rate of 7.26% (7.2% effective interest rate) due
in July 2011
$75 million with a coupon rate of 7.36% (7.3% effective interest rate) due
in July 2013
$20 million with a coupon rate of 7.46% (7.4% effective interest rate) due
in July 2016
Any incremental cash used in the Cody acquisition will come from the Company's
revolving credit facility.
-10-
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, 2001,
and the related condensed consolidated statements of operations and cash flows
for each of the three and six-month periods ended June 30, 2001 and June 30,
2000. 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, 2000, 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 16, 2001 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, 2000,
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, 2001
-11-
ITEM 2. Management's Discussion and Analysis of Financial Condition and
- ----------------------------------------------------------------------------
Results of Operations
- ---------------------
The following review of operations for the second quarter of 2001 and 2000
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, 2000.
Overview
During the second quarter of 2001, we realized the second highest quarterly
natural gas prices in our history, exceeded only by prices realized in the first
quarter of this year. For the first half of 2001 realized natural gas prices
were 118% higher than the same period of last year. Oil prices were up 26% and
oil production doubled from the second quarter of last year. The improvement in
oil production was primarily driven by the Company's discoveries in south
Louisiana. Operating revenues increased $94.9 million, or 57%, and net income
increased $46.6 million, mainly as a result of this improved price environment
and increased production. Operating cash flows were similarly impacted,
improving by $115.9 million over last year, contributing to a $82 million
reduction in debt and a $39.6 million increase in capital and exploration
spending.
Net income for the first half of 2001 was $52.7 million, or $1.79 per share,
including a $1.2 million non-cash gain realized from the change in the fair
value of our derivatives under the newly adopted SFAS 133 (see Note 8). This
selected item increased after-tax net income by $0.8 million, or $0.03 per
share, in the first half of 2001. Excluding this selected item, our year-to-
date 2001 net income was $51.9 million, or $1.76 per share.
We drilled 96 gross wells with a success rate of 88% compared to 60 gross
wells and a 92% success rate in the first half of 2000. For the full year, we
plan to drill approximately 206 gross wells and spend approximately $189.2
million in capital and exploration expenditures compared to 129 gross wells and
$122.6 million of capital and exploration expenditures in 2000. Total
expenditures were $99.6 million for the first half of 2001, compared to $55.7
million for the comparable period in 2000.
Natural gas production was 30.6 Bcf, up 0.7 Bcf compared to the 2000 first
half. Production from our recent discoveries in the Gulf Coast helped boost
production in that region by 3.1 Bcfe for the first six months of 2001.
However, anticipated declines in the other regions offset 2.4 Bcf of this
production.
Our strategic pursuits are sensitive to energy commodity prices,
particularly the price of natural gas. Market conditions have improved
significantly this year and our realized gas price for the first half of 2001 of
$5.68/Mcf was the highest we have ever realized. Although second quarter 2001
realized natural gas prices rose 80% over the prior year, prices were 27% lower
then those realized in the first quarter of this year. Prices of natural gas for
Henry Hub have declined from a high of $9.19 per Mmbtu in January 2001 to $3.16
per Mmbtu in July 2001. Based on this history of market volatility, there is
considerable uncertainty about the level of natural gas prices for the remainder
of this year and beyond.
We remain focused on our strategies of growth from the drill bit and
synergistic acquisitions. Management believes that these strategies are
appropriate in the current industry environment, enabling Cabot Oil & Gas to add
shareholder value over the long term.
The preceding paragraphs, discussing our strategic pursuits and goals,
contain forward-looking information. See Forward-Looking Information on page 19.
Financial Condition
Capital Resources and Liquidity
Our capital resources consist primarily of cash flows from our oil and gas
properties and asset-based borrowings supported by our oil and gas reserves.
The level of earnings and cash flows depend on many factors, including the price
of crude oil and natural gas and our ability to control and reduce costs.
Demand for crude oil and natural gas has historically been subject to seasonal
influences characterized by peak demand and higher prices in the winter heating
season. However, demand and prices have both remained
-12-
strong through the summer of 2000 and the spring of 2001, reducing the cyclical
nature of demand that we had seen previously in the market.
In August 2001, we expect to complete the acquisition of the stock of Cody
Company for $230 million in cash and stock. In July 2001, $170 million in Notes
were issued in a private placement transaction to fund a portion of this
transaction. We expect that this acquisition and the related issuance of debt
will result in increases to operating revenues, operating expenses, production
and interest expense. Increases to the capital spending program are also
planned.
Our primary source of cash during the first half of 2001 was from funds
generated from operations. Another source of cash was the exercise of stock
options. Cash was primarily used to reduce debt, fund exploration and
development expenditures, and pay dividends.
We had a net cash inflow of $1.8 million in the first half of 2001. Cash
inflows from operating activities totaled $167.1 million in the period,
substantially funding both the $82 million debt reduction and the $89.1 million
of capital and exploration expenditures.
SIX MONTHS ENDED JUNE 30,
2001 2000
---- ----
(In millions)
Cash Flows Provided by Operating Activities............ $167.1 $51.2
====== =====
Cash flows from operating activities in the 2001 first half were $115.9
million higher than the corresponding period of 2000 primarily due to higher
natural gas and oil prices and favorable changes in working capital.
SIX MONTHS ENDED JUNE 30,
2001 2000
---- ----
(In millions)
Cash Flows Used by Investing Activities................ $ 88.3 $47.7
====== =====
Cash flows used by investing activities in the first six months of 2001 and
2000 were substantially attributable to capital and exploration expenditures of
$89.1 million and $49.5 million, respectively. Proceeds from the sale of certain
oil and gas properties were $0.7 in 2001 and $1.8 million in 2000.
SIX MONTHS ENDED JUNE 30,
2001 2000
---- ----
(In millions)
Cash Flows Used by Financing Activities................ $ 77.0 $ 3.8
====== =====
Cash flows used by financing activities in the first half of 2001 included
$82 million used to reduce borrowings on our revolving credit facility and
10.18% Notes, and $2.4 million used to pay dividends. Proceeds from the exercise
of stock options in the period were $7.4 million. In the first half of 2000, we
raised $80 million from the sale of common stock through a public offering and
through stock option exercises. Of the proceeds, $51.6 million was used to
repurchase all of the then-outstanding shares of our preferred stock. Cash flows
used by financing activities in the first half of 2000 also included $28 million
used to reduce borrowings on our revolving credit facility, and $4.2 million for
the payment of dividends, including the final dividend payment on the preferred
stock.
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 runs to December 2003. Management believes that we have the
ability to finance, if necessary, our capital requirements, including
acquisitions.
-13-
Our 2001 interest expense is projected to be approximately $21.6 million,
including interest on the $170 million in Notes used to fund the acquisition of
Cody Company. 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.
Capitalization
Our capitalization information is as follows:
JUNE 30, DECEMBER 31,
2001 2000
------ ------
(In millions)
Long-Term Debt......................... $187.0 $253.0
Current Portion of Long-Term Debt...... -- 16.0
------ ------
Total Debt............................ 187.0 269.0
------ ------
Stockholders' Equity
Common Stock (net of Treasury Stock).. 314.1 242.5
------ ------
Total................................. 314.1 242.5
------ ------
Total Capitalization................... $501.1 $511.5
====== ======
Debt to Capitalization................. 37.3% 52.6%
During the first half of 2001, we paid dividends of $2.4 million on the
common stock. A regular dividend of $0.04 per share of common stock was
declared for the quarter ending June 30, 2001, to be paid August 24, 2001 to
shareholders of record as of August 10, 2001.
As a result of the requirements of SFAS 133 adopted January 1, 2001 (see
Note 9), our Stockholders' Equity includes $13.2 million, net of tax, in Other
Comprehensive Income for the six-months ended June 30, 2001.
In May 2001, we paid off our 10.18% Notes one year early utilizing existing
borrowing capacity under our revolving credit agreement. During the first half
of 2001, we reduced the total outstanding debt balance by $82 million. The
increased cash flow from operations in the period provided the necessary cash
for this debt reduction.
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,
2001 2000
----- -----
(In millions)
Capital Expenditures
Drilling and Facilities............ $52.7 $37.8
Leasehold Acquisitions............. 14.0 3.6
Pipeline and Gathering............. 1.3 1.8
Other.............................. 0.1 0.8
----- -----
68.1 44.0
----- -----
Proved Property Acquisitions........ 6.2 4.3
Exploration Expenses................ 25.3 7.4
----- -----
Total.............................. $99.6 $55.7
===== =====
-14-
Total capital and exploration expenditures in the first half of 2001
increased $43.9 million compared to the same period of 2000, primarily as a
result of increased drilling activity as well as increases in leasehold
acquisitions costs consistent with our future drilling plans.
We plan to drill 206 gross wells in 2001 compared with 129 gross wells
drilled in 2000. This 2001 drilling program includes $190.0 million in total
capital and exploration expenditures, up from $122.6 million in 2000. Expected
capital and exploration spending in 2001 includes $100.6 million for drilling,
$19.2 million for lease acquisition costs and $14.5 million for geological and
geophysical expenses including seismic data costs. Drilling of an additional 32
gross wells and capital and exploration expenditures of $22.3 million are
planned for the properties to be acquired from Cody Company in August 2001. In
addition to the drilling and exploration program, other 2001 capital
expenditures are planned primarily 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.
Results of Operations
For the purpose of reviewing our results of operations, "Net Income" is
defined as net income available to common shareholders.
Selected Financial and Operating Data
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------ ------------------
2001 2000 2001 2000
------ ------ ------ ------
(In millions, except where noted)
Net Operating Revenues....................... $107.6 $ 82.4 $262.5 $167.6
Operating Expenses........................... 80.6 82.0 167.0 152.3
Operating Income............................. 27.0 0.4 95.5 15.2
Interest Expense............................. 4.7 5.4 9.4 11.3
Net Income................................... 13.6 1.5 52.7 6.0
Earnings Per Share - Basic................... $ 0.46 $ 0.05 $ 1.79 $ 0.23
Earnings Per Share - Diluted................. $ 0.45 $ 0.05 $ 1.76 $ 0.23
Natural Gas Production (Bcf)
Gulf Coast.................................. 4.7 3.0 9.5 6.4
West........................................ 6.4 7.2 12.8 14.5
Appalachia.................................. 4.2 4.5 8.3 9.0
------ ------ ------ ------
Total Company............................... 15.3 14.7 30.6 29.9
Natural Gas Production Sales Prices ($/Mcf)
Gulf Coast.................................. $ 5.16 $ 3.05 $ 6.26 $ 2.78
West........................................ $ 4.11 $ 2.51 $ 5.10 $ 2.38
Appalachia.................................. $ 5.44 $ 2.63 $ 5.94 $ 2.85
Total Company............................... $ 4.79 $ 2.66 $ 5.68 $ 2.61
Crude/Condensate
Volume (MBbl)............................... 394 205 798 400
Price ($/Bbl)............................... $27.86 $22.66 $28.21 $22.42
Brokered Natural Gas Margin
Volume (Bcf)................................ 5.6 11.4 10.4 25.2
Margin ($/Mcf).............................. $ 0.17 $ 0.10 $0.21 $ 0.10
-15-
The table below presents the after-tax effect of certain selected
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 Available to Common Shareholders.. $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 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,
2000.
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.............. $ 2.6 $ 0.10 $ 5.4 $ 0.21
Benefit from miscellaneous net revenue (1).. -- -- 1.7 0.07
Impairment of long-lived assets............. (5.6) (0.22) (5.6) (0.22)
Closure of Pittsburgh office................ (0.6) (0.03) (0.6) (0.03)
Negative preferred stock dividend........... 5.1 0.20 5.1 0.20
----- ------ ----- ------
Net Income Available to Common Shareholders... $ 1.5 $ 0.05 $ 6.0 $ 0.23
===== ====== ===== ======
/(1)/ Represents net benefit, primarily from a contract settlement.
These selected items impacted our 2000 financial results. Because they are
not a part of our normal business, we have isolated their effect in the table
above. These selected items are as follows:
. Miscellaneous net revenue, primarily from the settlement of a natural gas
sales contract, was recorded in the first quarter of 2000 ($1.7 million after
tax).
. A $9.1 million impairment ($5.6 million after tax) was recorded on the
Beaurline field in south Texas as a result of a casing collapse in two of the
field's wells.
. We announced the closure of the regional office in Pittsburgh in May 2000 and
recorded costs of $1.0 million ($0.6 million after tax). These costs were
recorded in the income statement categories that will receive the future
savings benefit ($0.6 million in operations, $0.1 million in exploration and
$0.3 million in administration).
. As a result of repurchasing all of the preferred stock at less than the book
value, we recorded a $5.1 million negative stock dividend in May 2000.
Second Quarters of 2001 and 2000 Compared
Net Income and Revenues. We reported net income before the selected items
-----------------------
in the second quarter of 2001 of $16.7 million, or $0.56 per share. During the
corresponding quarter of 2000, we recorded net income excluding selected items
of $2.6 million, or $0.10 per share. Operating revenues increased by $30.1
million and operating income increased by $21.5 million. Natural gas made up
65%, or $73.4 million, of net operating revenue in 2001. The increase in net
operating revenues was driven primarily by realized price improvements of 80%
for natural gas and 23% for oil. Net income and operating income were similarly
impacted by the increase in commodity prices.
The average Gulf Coast natural gas production sales price rose $2.11 per Mcf,
or 69%, to $5.16, increasing net operating revenues by approximately $9.8
million. In the Western region, the average natural gas production sales price
increased $1.60 per Mcf, or 64%, to $4.11, increasing net operating revenues by
approximately $10.4 million. The average Appalachian natural gas production
sales price
-16-
increased $2.81 per Mcf, or 107%, to $5.44, increasing net operating revenues by
approximately $11.7 million. The overall weighted average natural gas production
sales price increased $2.13 per Mcf, or 80%, to $4.79, increasing revenues by
$31.9 million. On the last day of 2000, we entered into a series of natural gas
price collars that limited our exposure to the decline in commodity prices for
the months of February through October 2001. Index prices were below the floor
of these collars in May and June of 2001 resulting in a hedge gain of $4.7
million, which contributed a $0.28 per Mcf increase to our realized natural gas
price for the quarter. These collar arrangements covered approximately 55% of
our natural gas production during the second quarter of 2001and remain in place
through October 2001.
Natural gas production volume in the Gulf Coast region was up 1.7 Bcf, or
57%, to 4.7 Bcf primarily due to new production brought on line in south
Louisiana. Natural gas production volume in the Western region was down 0.8 Bcf,
or 11%, to 6.4 Bcf primarily due to a decrease in drilling activity in the Mid-
Continent area during 1999 and 2000. Natural gas production volume in the
Appalachian region was down 0.3 Bcf, or 7%, to 4.2 Bcf, as a result of a
decrease in drilling activity in the region in 1999 and 2000. The 0.6 Bcf, or
4%, improvement in total natural gas production increased revenue by $2.6
million in the second quarter of 2001.
Brokered natural gas revenue decreased $9.8 million, or 26%, over the
second quarter of last year. The sales price of brokered natural gas rose 50%,
resulting in an increase in revenue of $9.1 million, offset by a 51% decrease in
volume of natural gas brokered this quarter, reducing revenues by $18.9 million.
After including the related brokered natural gas costs, we realized a net margin
of $1.0 million in the second quarter of 2001 and $1.1 million in the comparable
quarter of 2000.
Crude oil prices rose $5.20 per Bbl, or 23%, to $27.86, resulting in an
increase to net operating revenues of approximately $2.0 million. In addition,
the volume of crude oil sold in the quarter increased by 189 Mbbls, or 92%, to
394 Mbbls, boosting net operating revenues by $4.3 million. This improvement in
volume is primarily in the Gulf Coast, which had been impacted by production
delays during the second quarter of last year.
Other net operating revenues decreased $0.9 million to $0.9 million, both
as a result of a decline in Section 29 tax credit revenues due to a one-time
adjustment made in the second quarter of 2000 and a decline on liquids plant
revenues due to a reduction in processed volumes.
Costs and Expenses. Excluding the second quarter 2000 costs incurred in
------------------
connection with the closure of our Pittsburgh office and the impairment of long-
lived assets, total costs and expenses from operations increased $8.7 million,
or 12%, in the second quarter of 2001 compared to the same period of 2000. The
primary reasons for this fluctuation are as follows:
. Brokered natural gas cost decreased $9.6 million, or 27%, over the second
quarter of last year. The cost of brokered natural gas rose 49%, resulting
in an increase to expense of $8.7 million, offset by a 51% decrease in
volume of natural gas brokered this quarter, reducing costs by $18.3
million. After including the related brokered natural gas revenues, we
realized a net margin of $1.0 million in the second quarter of 2001 and
$1.1 million in the comparable quarter of 2000.
. Direct operating expense increased $1.1 million, or 13%, as a result of
costs associated with the expansion of the Gulf Coast regional office,
including investments both in staffing and technology, and the cost of
operations for new wells brought on line primarily in south Louisiana.
. Exploration expense increased $10.5 million, or 260%, primarily as a result
of $8.3 million in dry hole expenses recorded in the second quarter of 2001
primarily in the Gulf Coast and Appalachian regions, an increase of $7.3
million from last year. Additionally, geological and geophysical expense,
primarily related to the acquisition and processing of seismic data, has
increased $2.4 million for the quarter. These increases are consistent with
the budget for the expanded 2001 drilling program.
. Depreciation, depletion, amortization and impairment expense increased $4.3
million, or 32%, 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 where equivalent production has increased 77% from last year's
second quarter.
-17-
. General and administrative costs rose $0.7 million, or 13%, primarily as a
result of costs associated with certain non-cash compensation programs.
. Taxes other than income rose $1.8 million, or 36%, as a result of higher
commodity prices realized this quarter.
Interest expense decreased $0.7 million as a result of a lower average
level of outstanding debt during the second quarter of 2001 when compared to the
second quarter of 2000.
Income tax expense increased $8.6 million due to the comparable increase in
earnings before income tax excluding the selected items.
Six Months of 2001 and 2000 Compared
Net Income and Revenues. Excluding the selected items, we reported net
-----------------------
income in the first half of 2001 of $51.9 million, or $1.76 per share. During
the corresponding half of 2000, we had net income excluding selected items of
$5.4 million, or $0.21 per share. Operating revenues and operating income
increased $96.6 million and $71.8 million, respectively. Natural gas made up
67%, or $174.1 million, of net operating revenue in 2001. The increase in net
operating revenues was driven primarily by a 118% increase in the average
natural gas price and by a 26% increase in the average oil price. Net income
and operating income were similarly impacted by the increase in commodity
prices.
The average Gulf Coast natural gas production sales price rose $3.48 per
Mcf, or 125%, to $6.26, increasing net operating revenues by approximately $32.8
million. In the Western region, the average natural gas production sales price
increased $2.72 per Mcf, or 114%, to $5.10, increasing net operating revenues by
approximately $35.0 million. The average Appalachian natural gas production
sales price increased $3.09 per Mcf, or 108%, to $5.94, increasing net operating
revenues by approximately $25.5 million. The overall weighted average natural
gas production sales price increased $3.07 per Mcf, or 118%, to $5.68,
increasing revenues by $93.3 million.
Natural gas production volume in the Gulf Coast region was up 3.1 Bcf, or
48%, to 9.5 Bcf primarily due to new production brought on line in south
Louisiana. Natural gas production volume in the Western region was down 1.7
Bcf, or 12%, to 12.8 Bcf primarily due to a decrease in drilling activity in the
Mid-Continent area since 1999. Natural gas production volume in the Appalachian
region was down 0.7 Bcf, or 8%, to 8.3 Bcf, as a result of a decrease in
drilling activity in the region since 1999. The 0.7 Bcf, or 2%, rise in total
natural gas production increased revenue by $2.8 million in the first half of
2001.
Crude oil prices increased $5.79 per Bbl, or 26%, to $28.21, resulting in
an increase to net operating revenues of approximately $4.6 million. The volume
of crude oil sold in the first six months of the year increased by 398 Mbbl, or
100%, to 798 Mbbl, increasing net operating revenues by $8.9 million.
Brokered natural gas revenue decreased $11.3 million, or 15%, over the
first half of last year. The sales price of brokered natural gas rose 105%,
resulting in an increase in revenue of $32.1 million, offset by a 59% decrease
in volume of natural gas brokered this period, reducing revenues by $43.4
million. After including the related brokered natural gas costs, we realized a
net margin of $2.2 million in the first half of 2001 and $2.6 million in the
comparable period of 2000.
Excluding the selected items, other operating revenues decreased $1.9
million to $1.9 million, both as a result of a decline in Section 29 tax credit
revenues due to a one-time adjustment made in the second quarter of 2000 and a
decline liquids plant revenues due to changes in activity levels.
Costs and Expenses. Excluding the selected items, total costs and expenses
-------------------
from operations increased $24.7 million, or 17%, due primarily to the following:
. Brokered natural gas cost decreased $10.9 million, or 15%, over the first
half of last year. The cost of brokered natural gas rose 105%, resulting in
an increase to expense of $31.0 million, offset by a 59% decrease in volume
of natural gas brokered this quarter, reducing costs by $41.9 million.
After including the related brokered natural gas revenues we realized a net
margin of $2.2 million in the first half of 2001 and $2.6 million in the
comparable period of 2000.
-18-
. Direct operating expense increased $0.8 million, or 5%, primarily as a
result of the cost of operations for new wells brought on line during the
past year primarily in the Gulf Coast and Rocky Mountains.
. Exploration expense increased $18.0 million, or 248%, as a result of
primarily as a result of $12.3 million in dry hole expense recorded in
2001, primarily in the Gulf Coast and Rocky Mountain regions, an increase
of $11.3 million from last year. Additionally, geological and geophysical
expense, primarily related to the acquisition and processing of seismic
data, has increased $5.0 million for the period. These increases are
consistent with the budget for the expanded 2001 drilling program.
. Depreciation, depletion and amortization expense increased $8.0 million, or
30%, due to the increase in natural gas and oil production and the stronger
influence of the higher cost Gulf Coast region where equivalent production
has increased 71% from the first six months of last year.
. General and administrative expenses increased $1.7 million, or 17%,
primarily as a result of higher compensation costs most of which is
associated with certain non-cash compensation programs. Increased
competition for experienced professionals in the energy industry has
resulted in increased salary and fringe benefit levels in order to retain
key employees. Additionally, our incentive compensation programs are based
on the Company's annual performance and result in higher expenses in years
of better financial performance.
. Taxes other than income rose $7.1 million, or 74%, as a result of higher
commodity prices realized this year.
Interest expense decreased $1.9 million as a result of a lower average
level of outstanding debt during the first half of 2001 when compared to the
first half of 2000.
Income tax expense increased $28.6 million due to the comparable increase
in earnings before income tax excluding the selected items.
Forward-Looking Information
The statements regarding future financial performance and results, market
prices, timing and impact of the Cody Company acquistion 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 half
of 2001 was two times higher than in 2000. The volatility of natural gas prices
in recent years remains prevalent in 2001 with wide price swings in day-to-day
trading on the NYMEX futures market. 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.
-19-
ITEM 3A. Quantitative and Qualitative Disclosures about Market Risk
- ---------------------------------------------------------------------
Commodity Price Swaps
Hedges on our Production
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 2001,
natural gas price swaps covered 498 Mmcf, fixing the sales price of this gas at
$3.97 per Mcf. During the first six months of 2000, we did not have any natural
gas price swaps covering our production. We entered into no oil price swaps
covering the first half of 2001. In the first half of 2000, the notional volume
of the crude oil swap transactions was 364 Mbbls at a price of $22.67 per Bbl,
which represented most of our oil production for the period.
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. The natural gas price hedges
include several costless collar arrangements based on eight price indexes at
which we sell a portion of our production. These hedges are in place for the
months of February through October 2001 and cover approximately half of our
anticipated natural gas production during this period. For the first half of
2001, these collars covered 8,135 Mmcf of production. All indexes were within
the collars during February, but some fell below the floor during the period of
March through June, resulting in a $4.8 million cash gain for the first six
months.
A series of costless collars were in place during the months of April
through October 2000. During the first six months of 2000, these collars
covered 4,214 Mmcf, or 14%, of our production. During the months of April and
May, the indexes remained within the collars, but rose above the ceiling in June
2000, resulting in a $1.8 million cash loss for the first six months.
Hedges on Brokered Transactions
Occasionally, we use price swaps to hedge the natural gas price risk on
brokered transactions. Typically, we enter into contracts to broker natural gas
at a variable price based on the market index price. However, in some
circumstances, some of our customers or suppliers request that a fixed price be
stated in the contract. After entering into fixed price contracts to meet the
needs of our customers or suppliers, we may use price swaps to effectively
convert these fixed price contracts to market-sensitive price contracts. These
price swaps are held by us to their maturity and are not held for trading
purposes.
In the first half of 2001, we had no price swaps on brokered transactions.
For the first half of 2000, we entered into price swaps with total notional
quantities of 1,295 Mmcf related to our brokered activities, representing 6% of
our total volume of brokered natural gas sold.
We are exposed to market risk on these open contracts, to the extent of
changes in market prices of natural gas and oil.
Adoption of SFAS 133
On January 1, 2001, the Company adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138. Under
SFAS 133, all derivative instruments are recorded on the balance sheet at fair
value. This new pronouncement impacts the accounting for the Company's natural
gas costless collar arrangements and natural gas price swap.
The Company uses derivative instruments to reduce the impact of changing
commodity prices on its financial results. At June 30, 2001, the Company had
two types of cash flow hedges open: a series of eight costless collar
arrangements and one natural gas price swap. The Company has recorded these
items at their fair market value on the balance sheet. The related unrealized
gains and losses were recorded as Other Comprehensive Income, a component of
Stockholders' Equity on the balance sheet, rather than to the income statement
to the extent that the derivative instrument was proven to be effective. For
the first half of 2001, a $13.2 million ($21.6 million pre-tax) unrealized gain
was recorded to Other
-20-
Comprehensive Income. Ineffectiveness arises when the change in fair value of
the cash flow hedge does not perfectly offset the change in the underlying
anticipated natural gas sale. The ineffective portion of the cash flow hedges, a
$1.0 million gain in the first half of 2001, was recorded directly to the income
statement as a Change in Derivative Fair Value. Additionally, the time value
component of the market value, a $0.2 million gain in the first half of 2001,
was recognized entirely as part of the Change in Derivative Fair Value.
The preceding paragraphs contain forward-looking information concerning
future production and projected gains and losses, which may be impacted both by
production and by changes in the future market prices of energy commodities.
See Forward-Looking Information on page 19.
-21-
PART II. OTHER INFORMATION
ITEM 4. Submission of Matters to a Vote of Security Holders
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On May 3, 2001, the Company held its Annual Meeting of Stockholders.
At this meeting, the Company's stockholders voted on four matters:
. the election of three directors,
. approval of the second amendment and restatement of the 1994 Long-Term
Incentive Plan,
. approval of the second amendment and restatement of the 1994 Non-Employee
Director Stock Option Plan, and
. the ratification of the appointment of PricewaterhouseCoopers LLP as the
Company's independent auditors.
Of the total outstanding shares, 26,971,660, or 92%, were voted. There were no
broker nonvotes.
Shareholders voted to re-elect three directors by the following vote:
Robert F. Bailey
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Votes cast in favor: 26,069,199
Votes withheld: 902,461
John G.L. Cabot
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Votes cast in favor: 26,080,249
Votes withheld: 891,411
C. Wayne Nance
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Votes cast in favor: 26,068,641
Votes withheld: 903,019
The terms of office of directors Henry O. Boswell, P. Dexter Peacock, Ray
R. Seegmiller, Charles P. Siess, Arthur L. Smith and William P. Vititoe
continued beyond the meeting date. William R. Esler retired from the Board of
Directors immediately following the 2001 Annual Meeting of Stockholders in
accordance with the Board's mandatory retirement policy.
The second item presented for a vote before the stockholders was the
approval of the second amendment and restatement of the 1994 Long-Term Incentive
Plan. Of the votes received, 23,491,425 were in favor of the approval,
3,470,804 were against, and 9,431 abstained.
The next item presented for a vote before the stockholders was the approval
of the second amendment and restatement of the 1994 Non-Employee Director Stock
Option Plan. Of the votes received, 21,963,152 were in favor of the approval,
4,990,356 were against, and 18,152 abstained.
The last item presented for a vote before the stockholders was the
ratification of the appointment of PricewaterhouseCoopers LLP as the Company's
independent certified public accountants. Of the votes received, 26,838,541
were in favor of the ratification, 132,059 were against, and 1,060 abstained.
ITEM 6. Exhibits and Reports on Form 8-K
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(a) Exhibits
2.1 -Agreement and Plan of Merger, dated as of June 20, 2001, among
Cabot Oil & Gas Corporation, COG Colorado Corporation, Cody
Company and the shareholders of Cody Company. (Form 8-K dated
June 28, 2001).
15.1 -Awareness letter of independent accountants.
(b) Reports on Form 8-K
Item 5: Other Events filing made on June 28, 2001 to disclose the
merger agreement between Cabot Oil & Gas Corporation and Cody Company.
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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 27, 2001 By: /s/ Scott C. Schroeder
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Scott C. Schroeder, Vice President, Chief
Financial Officer and Treasurer
(Principal Executive Officer Duly Authorized
to Sign on Behalf of the Registrant)
By: /s/ Henry C. Smyth
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Henry C. Smyth, Vice President and Controller
(Principal Accounting Officer)
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