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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 September 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 October 22, 2002, there were 31,795,548 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 Nine Months
Ended September 30, 2002 and 2001 .................................................... 3
Condensed Consolidated Balance Sheet at September 30, 2002 and December 31, 2001 ........ 4
Condensed Consolidated Statement of Cash Flows for the Three and Nine Months
Ended September 30, 2002 and 2001 .................................................... 5
Notes to Condensed Consolidated Financial Statements .................................... 6
Report of Independent Accountants ....................................................... 13
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations ............................................................. 14
Item 3A. Quantitative and Qualitative Disclosures about Market Risk ....................... 22
Item 4. Controls and Procedures ........................................................... 23
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K .................................................. 24
Signature ....................................................................................... 25
Certifications .................................................................................. 26
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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------------- --------------------------
2002 2001 2002 2001
---------- ---------- --------- ----------
NET OPERATING REVENUES
Natural Gas Production ................................. $52,029 $ 70,805 $152,684 $246,152
Brokered Natural Gas ................................... 10,838 18,447 40,223 81,142
Crude Oil and Condensate ............................... 20,754 12,712 51,792 35,232
Other .................................................. 1,928 2,262 5,508 4,198
------- -------- -------- -------
85,549 104,226 250,207 366,724
OPERATING EXPENSES
Brokered Natural Gas Cost .............................. 9,771 18,472 36,619 78,951
Direct Operations - Field & Pipeline ................... 11,652 11,745 35,808 29,615
Exploration ............................................ 9,803 14,441 27,683 39,754
Depreciation, Depletion and Amortization ............... 25,420 22,716 72,083 54,805
Impairment of Unproved Properties ...................... 2,337 2,232 7,011 5,196
Impairment of Long-Lived Assets ........................ -- 1,721 1,063 1,721
General and Administrative ............................. 5,966 6,520 21,277 18,158
Taxes Other Than Income ................................ 5,273 4,547 18,900 21,164
------- -------- -------- -------
70,222 82,394 220,444 249,364
Gain (Loss) on Sale of Assets ............................... (216) (231) 195 (258)
------- -------- -------- -------
INCOME FROM OPERATIONS ...................................... 15,111 21,601 29,958 117,102
Interest Expense ............................................ 6,314 5,140 18,871 14,549
------- -------- -------- -------
Income Before Income Taxes .................................. 8,797 16,461 11,087 102,553
Income Tax Expense .......................................... 2,672 6,430 3,638 39,868
------- -------- -------- -------
NET INCOME .................................................. $ 6,125 $ 10,031 $ 7,449 $ 62,685
======= ======== ======== ========
Basic Earnings Per Share .................................... $ 0.19 $ 0.33 $ 0.23 $ 2.10
Diluted Earnings Per Share .................................. $ 0.19 $ 0.32 $ 0.23 $ 2.07
Average Common Shares Outstanding ........................... 31,793 30,644 31,712 29,829
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)
SEPTEMBER 30, DECEMBER 31,
2002 2001
------------- -------------
ASSETS
Current Assets
Cash and Cash Equivalents ........................................ $ 4,668 $ 5,706
Accounts Receivable .............................................. 48,681 50,711
Inventories ...................................................... 19,459 17,560
Other ............................................................ 13,037 11,010
---------- ----------
Total Current Assets .......................................... 85,845 84,987
Properties and Equipment, Net (Successful Efforts Method) ............ 960,704 981,338
Other Assets ......................................................... 4,253 2,706
---------- ----------
$1,050,802 $1,069,031
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable ................................................. $ 52,480 $ 79,575
Accrued Liabilities .............................................. 31,504 30,665
---------- ----------
Total Current Liabilities ..................................... 83,984 110,240
Long-Term Debt ....................................................... 395,000 393,000
Deferred Income Taxes ................................................ 202,176 200,859
Other Liabilities .................................................... 15,235 18,380
Stockholders' Equity
Common Stock:
Authorized -- 40,000,000 Shares of $.10 Par Value
Issued and Outstanding - 32,096,448 Shares and
31,905,097 Shares in 2002 and 2001, Respectively .............. 3,210 3,191
Additional Paid-in Capital ....................................... 352,257 346,260
Retained Earnings ................................................ 4,291 650
Accumulated Other Comprehensive Income (Loss) (Note 9) ........... (967) 835
Less Treasury Stock, at Cost:
302,600 Shares in 2002 and 2001 ............................... (4,384) (4,384)
---------- ----------
Total Stockholders' Equity .................................... 354,407 346,552
---------- ----------
$1,050,802 $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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------- -----------------------
2002 2001 2002 2001
------- ------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income ............................................... $ 6,125 $ 10,031 $ 7,449 $ 62,685
Adjustment to Reconcile Net Income to
Cash Provided by Operating Activities:
Depletion, Depreciation and Amortization ............. 25,420 22,716 72,083 54,805
Impairment of Unproved Properties .................... 2,337 2,232 7,011 5,196
Impairment of Long-Lived Assets ...................... -- 1,721 1,063 1,721
Deferred Income Taxes ................................ 2,492 11,550 2,443 30,657
(Gain) Loss on Sale of Assets ........................ 216 231 (195) 258
Exploration Expense .................................. 9,803 14,441 27,683 39,754
Change in Derivative Fair Value ...................... (1,774) 422 (594) (789)
Other ................................................ 848 939 3,754 2,320
Changes in Assets and Liabilities:
Accounts Receivable .................................. 4,034 (3,090) 2,030 26,946
Inventories .......................................... (4,308) (6,072) (1,899) (9,229)
Other Current Assets ................................. (47) (5,914) (2,443) (6,448)
Other Assets ......................................... (1,525) (662) (1,547) (445)
Accounts Payable and Accrued Liabilities ............. (20,528) (5,814) (5,412) 3,577
Other Liabilities .................................... 2,159 4,974 (3,145) 3,790
-------- --------- --------- ---------
Net Cash Provided by Operating Activities .......... 25,252 47,705 108,281 214,798
-------- --------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures ..................................... (15,460) (213,041) (86,649) (276,795)
Proceeds from Sale of Assets ............................. 228 5,159 3,671 5,898
Exploration Expense ...................................... (9,803) (14,441) (27,683) (39,754)
-------- --------- --------- ---------
Net Cash Used by Investing Activities .................. (25,035) (222,323) (110,661) (310,651)
-------- --------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Sale of Common Stock ..................................... 13 372 3,150 7,748
Increase in Debt ......................................... 36,000 289,000 136,000 362,000
Decrease in Debt ......................................... (38,000) (109,000) (134,000) (264,000)
Dividends Paid ........................................... (1,272) (1,183) (3,808) (3,537)
-------- --------- --------- ---------
Net Cash Provided (Used) by Financing Activities ....... (3,259) 179,189 1,342 102,211
-------- --------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents ........ (3,042) 4,571 (1,038) 6,358
Cash and Cash Equivalents, Beginning of Period .............. 7,710 9,361 5,706 7,574
-------- --------- --------- ---------
Cash and Cash Equivalents, End of Period .................... $ 4,668 $ 13,932 $ 4,668 $ 13,932
======== ========= ========= =========
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, their 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 in January 2003. At this time, management is
continuing its analysis of this pronouncement and has laid out a schedule to
finalize the resulting impact, which will be disclosed in the 2002 Form 10-K.
In August 2001, the FASB also approved SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 144 replaces
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." The new accounting model for long-lived assets to be
disposed of by sale applies to all long-lived assets, including discontinued
operations, and replaces the provisions of APB Opinion No. 30, "Reporting
Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business", for the disposal of segments of a business. SFAS 144 requires that
those long-lived assets be measured at the lower of carrying amount or fair
value less cost to sell, whether reported in continuing operations or in
discontinued operations. Therefore, discontinued operations will no longer be
measured at net realizable value or include amounts for operating losses that
have not yet occurred. SFAS 144 also broadens the reporting of discontinued
operations to include all components of an entity with operations that can be
distinguished from the rest of the entity and that will be eliminated from the
ongoing operations of the entity in a disposal transaction. The provisions of
SFAS 144 are effective for financial statements issued for fiscal years
beginning after December 15, 2001 and, were adoption by the Company in 2002. The
adoption of this statement did not impact the Company's financial position,
results of operations, or cash flows.
In April 2002, the FASB issued Statement of Financial Accounting Standards
No. 145, Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB
Statement No. 13 and Technical Corrections ("SFAS 145"). SFAS 145, which is
effective for fiscal years beginning after May 15, 2002, provides guidance for
income statement classification of gains and losses on extinguishment of debt
and accounting for certain lease modifications that have economic effects that
are similar to sale-leaseback transactions. The Company does not believe that
the adoption of this statement will impact its financial position, results of
operations, or cash flows.
6
In June 2002, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 146 ("SFAS 146"), "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS 146 nullifies the guidance of
the Emerging Issues Task Force (EITF) Issue No. 94-3, Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring). SFAS 146 requires that a
liability for a cost that is associated with an exit or disposal activity be
recognized when the liability is incurred. SFAS 146 also establishes that fair
value is the objective for the initial measurement of the liability. The
provisions of SFAS 146 are required for exit or disposal activities that are
initiated after December 31, 2002. The provisions of SFAS 146 are not expected
to have a material impact on the Company's consolidated financial statements.
2. PROPERTIES AND EQUIPMENT
Properties and equipment are comprised of the following:
SEPTEMBER 30, DECEMBER 31,
2002 2001
------------- -------------
(In thousands)
Unproved Oil and Gas Properties ........................... $ 74,454 $ 70,709
Proved Oil and Gas Properties ............................. 1,445,158 1,400,341
Gathering and Pipeline Systems ............................ 135,373 131,768
Land, Building and Improvements ........................... 4,873 4,674
Other ..................................................... 28,826 27,513
---------- ----------
1,688,684 1,635,005
Accumulated Depreciation, Depletion and Amortization ...... (727,980) (653,667)
---------- ----------
$ 960,704 $ 981,338
========== ==========
3. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
SEPTEMBER 30, DECEMBER 31,
2002 2001
------------- -------------
(In thousands)
Accounts Receivable
Trade Accounts ............................................ $47,260 $39,570
Joint Interest Accounts ................................... 4,789 12,889
Current Income Tax Receivable ............................. 1,363 2,662
Other Accounts ............................................ 524 986
------- -------
53,936 56,107
Allowance for Doubtful Accounts ............................. (5,255) (5,396)
------- -------
$48,681 $50,711
======= =======
Other Current Assets
Commodity Hedging Contracts ............................... $ 1,971 $ 2,387
Drilling Advances ......................................... 2,812 2,111
Prepaid Balances .......................................... 3,201 2,114
Restricted Cash and Other Accounts ........................ 5,053 4,398
------- -------
$13,037 $11,010
======= =======
7
SEPTEMBER 30, DECEMBER 31,
2002 2001
------------- -------------
(In thousands)
Accounts Payable
Trade Accounts ................................................ $11,396 $19,914
Natural Gas Purchases ......................................... 4,758 4,559
Royalty and Other Owners ...................................... 16,618 11,041
Capital Costs ................................................. 7,161 30,923
Taxes Other Than Income ....................................... 1,272 2,686
Drilling Advances ............................................. 1,827 2,627
Wellhead Gas Imbalances ....................................... 2,855 2,353
Other Accounts ................................................ 6,593 5,472
------- -------
$52,480 $79,575
======= =======
Accrued Liabilities
Employee Benefits ............................................. $ 7,666 $ 7,151
Taxes Other Than Income ....................................... 13,797 13,623
Interest Payable .............................................. 5,590 6,996
Commodity Hedging Contracts ................................... 1,918 --
Income Taxes Payable .......................................... 880 45
Other Accrued ................................................. 1,653 2,850
------- -------
$31,504 $30,665
======= =======
Other Liabilities
Postretirement Benefits Other Than Pension .................... $ 1,750 $ 1,689
Accrued Pension Cost .......................................... 4,775 7,280
Taxes Other Than Income and Other ............................. 8,710 9,411
------- -------
$15,235 $18,380
======= =======
4. LONG-TERM DEBT
At September 30, 2002, the Company had $125 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 September 30, 2002, excess capacity
totaled $125 million, or 50% of the total available credit line.
On October 28, 2002, the Company entered into a new revolving credit
facility with a group of nine banks including seven that participated in the
previous facility and two new banks. The new facility has a term of four years
and expires in October 2006. The terms and conditions are similar to the
previous facility with adjustments for current market pricing. Both the LIBOR
and base rate pricing options increased in response to existing bank market
conditions. LIBOR spreads are now 125 to 175 basis points versus the previous 75
to 125 basis points. The base rate, which previously had no spread, now adds 25
to 75 basis points depending on the level of indebtedness. The new facility
remains unsecured.
In addition to the credit facility, the Company has the following debt
outstanding:
o $100 million of 12-year 7.19% Notes to be repaid in five annual
installments of $20 million beginning in November 2005
o $75 million of 10-year 7.26% Notes due in July 2011
o $75 million of 12-year 7.36% Notes due in July 2013
o $20 million of 15-year 7.46% Notes due in July 2016
8
5. EARNINGS PER SHARE
Basic earnings per share for the third quarter were based on the quarterly
weighted average shares outstanding of 31,793,342 in 2002 and 30,644,481 in
2001. Basic earnings per share for the first nine months of the year were based
on the year-to-date weighted average shares outstanding of 31,712,145 in 2002
and 29,828,850 in 2001. The diluted earnings per share amounts are based on
weighted average shares outstanding plus common stock equivalents. Third quarter
common stock equivalents, which include both stock awards and stock options,
totaled 342,675 in 2002 and 354,300 in 2001. For the year-to-date period ended
September 30, the common stock equivalents were 367,471 in 2002 and 434,244 in
2001. Stock awards and stock options excluded from the calculation of diluted
earnings per share because the effect was antidilutive were 1,231,132 and
975,004 for the third quarter of 2002 and 2001, respectively, and 1,206,336 and
895,060 for the year-to-date periods ended September 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 entered into a consent
decree, which will require the CNC to pay approximately $27 million toward Site
clean up in return for a release from liability. On January 30, 2002, the
Company placed $1,283,283 in an escrow account, representing the Company's
volumetric share of the CNC/United States settlement. This cash settlement, once
released from escrow and paid to the federal government after the consent decree
is entered by the court, will resolve all federal claims against the Company for
response costs and will release the Company from all response costs related to
the Site, except for future claims against the Company for natural resource
damage, unknown conditions, transshipment risks and claims by third parties,
nearly all of which are expected to be covered by insurance to be purchased by
participating CNC members. 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 and related legal costs.
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 improperly deducted costs of production from royalty payments to the
plaintiffs and other similarly situated persons. Additionally, the suit claims
that the Company has failed to properly inform the plaintiffs and other
similarly situated persons of the deductions taken from royalties. In December
2001, thirteen overriding royalty owners sued the Company in Wyoming federal
district court. The plaintiffs in the federal case have made the same general
claims pertaining to deductions from their overriding royalty as the plaintiffs
in the Wyoming state court case but have not asked for class certification.
9
Although the Company believes that a number of the its defenses are
supported by Wyoming case law, a recent letter decision handed down by a state
district court in another case does not support certain of the defenses. The
decision has not been reduced to a formal order and it is not known what effect,
if any, the decision will have on the pending cases.
The Company is vigorously defending both the cases. 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 these matters. Should
circumstances change, the potential impact to the Company may materially affect
quarterly or annual results of operations and cash flows. However management
does not believe it would materially impact the Company's financial position.
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 1/8th royalty share of the gas sales
contract settlement the Company reached with Columbia in the 1995 Columbia
bankruptcy proceeding.
The Company has removed the suit to federal court. At a recent status
conference, the court set up a schedule for the procedural handling of the
plaintiffs' allegations that the case should proceed as a class action. Under
this procedure, all discovery and pleadings necessary to place class
certification issue before the court are expected to be completed by November 1,
2002.
The investigation into this claim continues and it is in the discovery
phase. The Company is vigorously defending 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. Should circumstances
change, the potential impact to the Company may materially affect quarterly or
annual results of operations and cash flows. However management does not believe
it would materially impact the Company's financial position.
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 September 30, 2002, the Company had three cash flow hedges open:
a series of natural gas price swaps, and two crude oil price collar
arrangements. Additionally, the Company had one crude oil price range swap open
at September 30, 2002 that did not qualify for hedge accounting under SFAS 133.
At September 30, 2002, a $1.6 million pre-tax unrealized loss was recorded to
Other Comprehensive Income along with a $1.9 million derivative liability, a
$2.0 million derivative asset, and a non-cash gain of approximately $0.6
million. The ineffective portion of the cash flow hedges, a $1.0 million
year-to-date loss, and the mark-to-market gain on the crude oil price range swap
of $1.6 million were recorded as a component of Natural Gas Production and Crude
Oil and Condensate revenue, as appropriate. This classification is a
modification of prior period disclosures that segregated the ineffective portion
of the cash flow hedges as the Change in Derivative Fair Value on the Statement
of Operations. Prior period amounts including a loss of $0.4 million for the
quarter and a gain of $0.8 million year-to-date have been reclassified to
reflect the new presentation method. If commodity prices remain at the current
level over the next twelve months, the Company would recognize a loss of
approximately $1.0 million ($1.6 million pre-tax) to earnings which was deferred
in Accumulated Other Comprehensive Income at September 30, 2002.
10
The Company has entered into the following derivative arrangements:
o 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.
o 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.
o 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.
o A series of natural gas price swaps covering 1.3 Bcf of production in
October 2002 with a weighted average fixed price of $4.12 per Mcf.
o Subsequent to the end of the third quarter, we entered into a series of
natural gas price swaps covering 1.7 Bcf of production in November 2002
with a weighted average fixed price of $4.63 per Mcf.
o Subsequent to the end of the third quarter, we entered into a series of
natural gas price swaps covering 9.9 Bcf of production during the period
November 2002 through December 2003 at a fixed price of $4.30 per Mcf.
o A crude oil price collar arrangement covering 272 Mbbls of production over
the period of January through June 2003 with a $24.00 per barrel floor
price and a $28.50 per barrel ceiling price.
o A crude oil range swap arrangement covering 730 Mbbls of production over
the period January through December 2003. This derivative provides for a
fixed price swap at $28.15 per barrel, unless the Nymex West Texas
Intermediate monthly average price falls below $21.00/barrel. If the Nymex
West Texas Intermediate monthly average price falls below $21.00/barrel for
any month, the swap is cancelled for that month. The derivative does not
qualify for hedge accounting under SFAS 133.
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
nine-month periods ended September 30:
NINE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2002 SEPTEMBER 30, 2001
--------------------------- --------------------------
(In thousands)
Accumulated Other Comprehensive Income -
Beginning of Period $ 835 $ --
Net Income .............................................. $ 7,449 $ 62,685
Other Comprehensive Income (net of tax)
Cumulative effect of change in accounting
principle - January 1, 2001 ..................... -- (2,617)
Reclassification adjustment for
settled contracts ............................... (2,933) 14,543
Changes in fair value of outstanding
hedge positions ................................. 1,131 (5,980)
------- ----------
Other Comprehensive Income (Loss)........................ $(1,802) $ (1,802) $ 5,946 $ 5,946
------- ---------- ---------- ----------
Comprehensive Income .................................... $ 5,647 $ 68,631
======= ==========
Accumulated Other Comprehensive
Income (Loss) - End of Period ...................... $ (967) $ 5,946
========== ===========
Comprehensive income for the third quarter 2002 was $8.0 million, including
net income of $6.1 million, a negative reclassification adjustment for settled
contracts of $1.5 million and a positive change in fair value of open hedges of
$3.4 million. For the comparable period of 2001, comprehensive income was $2.8
million, including net income of $10.0 million, a positive reclassification
adjustment for settled contracts of $12.3 million and a negative change in fair
value of open hedges of $19.5 million.
11
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.
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 for consideration 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 Company recorded a purchase price of approximately $315.6 million;
which was allocated to specific assets and liabilities based on certain
estimates of fair values resulting in approximately $302.4 million allocated to
property and $13.2 million allocated to working capital items. The remaining
$78.0 million of the recorded purchase price reflected a non-cash item
pertaining to the deferred income taxes attributable to the differences between
the tax basis and the fair value of the acquired oil and gas properties, and
acquisition related fees and costs of $6.4 million.
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 SEPTEMBER 30, 2001
QUARTER NINE MONTHS
------------- ----------------
(Unaudited)
(In thousands)
Revenues ................................ $109,345 $425,210
Net Income .............................. $ 10,708 $ 72,681
Per share - Basic .................. $ 0.34 $ 2.31
Per share - Diluted ................ $ 0.34 $ 2.28
The results of operations for Cody Company are consolidated with Cabot Oil & Gas
Corporation as of August 1, 2001.
12
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 September 30,
2002, and the related condensed consolidated statements of operations and of
cash flows for each of the three and nine-month periods ended September 30, 2002
and September 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
October 25, 2002
13
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following review of operations for the first nine 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 nine months of 2002, we produced 68.7 Bcfe, an increase of
10.9 Bcfe, or 19% over the comparable period of 2001. Natural gas production was
55.6 Bcf, up 6.0 Bcf compared to the first nine months of 2001. Oil production
was up 844 Mbbls, or 65% over the comparable period of last year. Production
from the properties acquired with Cody Company contributed 7.3 Bcfe, or 67% of
the total 10.9 Bcfe increase in equivalent production, and drilling successes in
the Gulf Coast and Eastern regions have contributed the other 3.6 Bcfe, or 33%.
Commodity prices were unusually high during the first nine months of 2001,
and our financial results reflected their impact during that period. However, in
the first nine months of 2002, natural gas prices were 44% lower and crude oil
prices were 13% lower than in 2001. This lower commodity price environment
effected our financial results. Operating revenues decreased $116.5 million, or
32%, and net income decreased $55.2 million, mainly as a result of this weakened
price environment. Operating cash flows were similarly impacted, declining by
$106.5 million over last year. Our net income for the first nine months of 2002
was $7.4 million or $0.23 per share, down from $62.7 million or $2.10 per share,
in the comparable period of 2001.
We drilled 85 gross wells (79 development and 6 exploratory wells) with a
success rate of 93% compared to 154 gross wells (132 development and 22
exploratory wells) and an 88% success rate in the first nine months of 2001. For
the full year, we plan to drill 115 gross wells and spend $126.3 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 $90.6 million for
the first nine months of 2002, compared to $379.6 million (including $231.2 for
the acquisition of Cody Company) 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 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. Natural gas prices then recovered somewhat
during the second and third quarters of 2002. Crude oil prices have risen
consistently throughout 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 nine months of 2002 were from
funds generated from operations, 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.
14
We had a net cash outflow of $1.0 million in the first nine months of 2002.
Cash inflows from operating activities totaled $108.3 million in the period. The
$114.3 million of capital and exploration expenditures were funded with a
combination of the operating cash flows, $3.7 million in proceeds from the sale
of non-strategic assets, $3.2 million in proceeds from stock option exercises
and $2.0 million of increased borrowing on the revolving credit facility.
NINE MONTHS ENDED SEPTEMBER 30,
2002 2001
----------- -----------
(In millions)
Cash Flows Provided by Operating Activities ........ $108.3 $214.8
====== ======
Cash flows from operating activities in the first nine months of 2002 were
$106.5 million lower than the corresponding period of 2001 primarily due to
lower natural gas and oil prices and less favorable changes in working capital.
NINE MONTHS ENDED SEPTEMBER 30,
2002 2001
----------- -----------
(In millions)
Cash Flows Used by Investing Activities ............ $(110.6) $(310.6)
======= =======
Cash flows used by investing activities in the first nine months of 2002
were primarily a result of capital and exploration expenditures of $114.3
million. This amount was partially offset by $3.7 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 nine
months of 2001 were substantially attributable to capital and exploration
expenditures of $316.5 million, partially offset by proceeds from the sale of
certain oil and gas properties of $5.9 million. The 2001 capital expenditures
included the August 2001 acquisition of Cody Company.
NINE MONTHS ENDED SEPTEMBER 30,
2002 2001
----------- -----------
(In millions)
Cash Flows Provided by Financing Activities ........ $ 1.3 $ 102.2
======== ========
Cash flows provided by financing activities in the first nine months of
2002 consist primarily of $2.0 million in increased borrowings on the revolving
credit facility and $3.2 million in proceeds from stock option exercises.
Dividends of $3.8 million were paid to date in 2002. Cash flows provided by
financing activities in the first nine months of 2001 included a $98 million net
increase in debt. We issued 7.3% weighted average fixed rate notes in July 2001
for $170 million. However, during 2001, we also reduced our level of borrowing
on our revolving credit facility and repaid the 10.18% Notes. Additionally, $3.5
million was used to pay dividends. Proceeds from the exercise of stock options
in the period were $7.7 million.
The available credit line under our revolving credit facility, currently
$250 million, is subject to adjustment on the basis of the present value of
estimated future net cash flows from proved oil and gas reserves (as determined
by the bank's petroleum engineer) and other assets. The revolving term of the
existing credit facility ends in December 2003. In October 2002, the Company
entered into a new credit facility agreement that runs through October 2006. It
is similar in terms to the facility that it replaces. We strive to manage our
debt at a level below the available credit line in order to maintain excess
borrowing capacity. Management believes that we have the ability to finance
through new debt or equity offerings, if necessary, our capital requirements,
including acquisitions.
Our 2002 interest expense is expected to be approximately $25 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.
The limited partner in a partnership that owns an interest in oil and gas
properties has notified the Company of its intent to dissolve the partnership.
The partnership interest was acquired as part of the Cody acquisition. The
Company is evaluating its options in connection with the notice, including
purchasing the
15
limited partner's interest, negotiating a preferential right to purchase the
limited partner's interest, and liquidating and terminating the partnership. The
Company can not predict with any degree of certainty the outcome of this matter
or its impact on the Company's financial position, cash flows or results of
operations.
Capitalization
Our capitalization information is as follows:
SEPTEMBER 30, DECEMBER 31,
2002 2001
------------ ------------
(In millions)
Debt $395.0 $393.0
Stockholders' Equity (1) .............. 354.4 346.6
------ ------
Total Capitalization .................. $749.4 $739.6
====== ======
Debt to Capitalization ................ 52.7% 53.1%
-------------
(1) Includes common stock, net of t reasury stock.
During the first nine months of 2002, w e paid dividends of $3.8 million on
the Common Stock. A regular dividend of $0.0 4 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:
NINE MONTHS ENDED SEPT. 30,
2002 2001
----------- -----------
(In millions)
Capital Expenditures
Drilling and Facilities ........... $ 55.6 $ 86.4
Leasehold Acquisitions ............ 2.0 14.7
Pipeline and Gathering ............ 2.4 2.4
Other ............................. 0.8 0.2
-------- --------
60.8 103.7
-------- --------
Proved Property Acquisitions .......... 2.1 236.1
Exploration Expenses .................. 27.7 39.8
-------- --------
Total ............................. $ 90.6 $ 379.6
======== ========
Excluding the $231.2 million Cody acquisition, total capital and
exploration expenditures in the first nine months of 2002 decreased $57.8
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 115 gross wells in 2002 compared with 208 gross wells
drilled in 2001. This 2002 drilling program includes $126.3 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 $77.7 million for drilling and dry
hole exposure, $8.2 million for lease acquisition and $11.6 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.
16
Results of Operations
Selected Financial and Operating Data
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------------- --------------------------
2002 2001 2002 2001
-------- --------- --------- ---------
(In millions, except where noted)
Net Operating Revenues .......................... $ 85.5 $104.2 $250.2 $366.7
Operating Expenses .............................. 70.2 82.4 220.4 249.4
Operating Income ................................ 15.1 21.6 30.0 117.1
Interest Expense ................................ 6.3 5.1 18.9 14.5
Net Income ...................................... 6.1 10.0 7.4 62.7
Earnings Per Share - Basic ...................... $ 0.19 $ 0.33 $ 0.23 $ 2.10
Earnings Per Share - Diluted .................... $ 0.19 $ 0.32 $ 0.23 $ 2.07
Natural Gas Production (Bcf)
Gulf Coast ................................. 8.0 7.9 23.2 17.3
West ....................................... 6.2 6.4 18.9 19.4
East ....................................... 4.5 4.6 13.5 12.9
------ ------ ------ ------
Total Company .............................. 18.7 18.9 55.6 49.6
Natural Gas Production Sales Prices ($/Mcf)
Gulf Coast ................................. $ 3.27 $ 3.91 $ 3.07 $ 5.19
West ....................................... $ 2.00 $ 3.10 $ 2.18 $ 4.43
East ....................................... $ 3.04 $ 4.56 $ 3.07 $ 5.45
Total Company .............................. $ 2.77 $ 3.77 $ 2.76 $ 4.95
Crude/Condensate
Volume (MBbl) .............................. 766 509 2,151 1,307
Price ($/Bbl) .............................. $24.97 $ 24.99 $23.34 $26.96
Brokered Natural Gas Margin
Volume (Bcf) ............................... 5.7 5.2 14.7 15.6
Margin ($/Mcf) ............................. $ 0.19 $(0.01) $ 0.25 $ 0.14
Third Quarters of 2002 and 2001 Compared
Net Income and Revenues. We reported net income in the third quarter of
2002 of $6.1 million, or $0.19 per share. During the corresponding quarter of
2001, we recorded net income of $10.0 million, or $0.33 per share. Operating
revenues decreased by $18.7 million and operating income decreased by $6.5
million. Natural gas made up 61%, or $52.0 million, of net operating revenue in
2002. The decrease in net operating revenues was driven by a 26% decline in
realized natural gas prices. Net income and operating income were similarly
impacted by the reduction in commodity prices.
The average Gulf Coast natural gas production sales price decreased $0.64
per Mcf, or 16%, to $3.27, decreasing net operating revenues by approximately
$4.6 million. In the Western region, the average natural gas production sales
price decreased $1.10 per Mcf, or 35%, to $2.00, decreasing net operating
revenues by approximately $7.2 million. The average natural gas production sales
price in the East region decreased $1.52 per Mcf, or 33%, to $3.04, decreasing
net operating revenues by approximately $6.8 million. The overall weighted
average natural gas production sales price decreased $1.00 per Mcf, or 26%, to
$2.77, decreasing revenues by $18.6 million. Sales of approximately 74% of our
natural gas production for the first two months of the quarter were covered by a
series of natural gas price collars that limited our exposure to movements in
commodity prices. Index prices rose above the ceiling of most of these collars
for July and August of 2002. The resulting $0.5 million hedge loss decreased our
realized natural gas price for the quarter by $0.03 per Mcf. These collar
arrangements covered 149 Mmcf of natural gas production per day and expired in
August 2002.
17
Natural gas production volume in the Gulf Coast region was up 0.1 Bcf, or
2%, to 8.0 Bcf primarily due to new production brought on line in south Texas
and also due somewhat to the full quarter impact of the acquisition of Cody
Company in August 2001. Natural gas production volume in the Western region was
down 0.2 Bcf, or 3%, to 6.2 Bcf. Natural gas production volume in the East
region was down 0.1 Bcf, or 2%, to 4.5 Bcf. The 0.2 Bcf, or 1%, decline in total
natural gas production decreased revenue by $0.7 million in the third quarter of
2002. Production declines in 2002 were the result of the reduced drilling
program for 2002.
Brokered natural gas revenue decreased $7.6 million, or 41%, over the third
quarter of last year. The sales price of brokered natural gas declined 46%,
resulting in a decrease in revenue of $9.4 million, only partially offset by a
10% rise in volume of natural gas brokered this quarter, improving revenues by
$1.8 million. After including the related brokered natural gas costs, we
realized a net margin of $1.1 million in the third quarter of 2002 and we
realized no margin in the comparable quarter of 2001.
Crude oil prices decreased $0.02 per Bbl to $24.97. The volume of crude oil
sold in the quarter increased by 257 Mbbls, or 50%, to 766 Mbbls, boosting net
operating revenues by $6.4 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. Additionally,
a $1.6 million unrealized gain on the change in derivative fair value was
recorded in the third quarter of 2002 primarily related to a crude oil price
range swap in place for 2003.
Other net operating revenues decreased $0.3 million to $1.9 million,
primarily as a result of lower natural gas liquids sales due to a lower volume
of transactions.
Costs and Expenses. Total costs and expenses from operations decreased
$12.2 million, or 15%, in the third quarter of 2002 compared to the same period
of 2001. The primary reasons for this fluctuation are as follows:
o Brokered natural gas cost decreased $8.7 million, or 47%, over the third
quarter of last year. The price per Mcf of brokered natural gas decreased
52%, resulting in a decrease to expense of $10.5 million, offset by a 10%
increase in volume of natural gas brokered this quarter, increasing costs
by $1.8 million. After including the related brokered natural gas revenues,
we realized a net margin of $1.1 million in the third quarter of 2002 and
we realized no margin in the comparable quarter of 2001.
o Direct operating expense decreased $0.1 million, or 1%. On a per unit
basis, operating expense declined from $0.53 per Mcf in the third quarter
of 2001 to $0.50 per Mcf in 2002.
o Exploration expense decreased $4.6 million, or 32%, primarily as a result
of a $6.8 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 $1.7 million for
the quarter. Delay rental payments were up $0.8 million for the quarter
primarily as the result of lower than normal costs in the third quarter of
2001. These changes are consistent with the 2002 budget and the more active
2001 drilling program.
o Depreciation, depletion, amortization and impairment expense increased $1.1
million, or 4%, 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 14% from
last year's third quarter including amounts attributable to the Cody
Company properties. On a per unit basis, DD&A for the third quarter was
$1.12 per Mcf in 2001 and $1.17 per Mcf in 2002.
o General and administrative costs declined $0.6 million, or 9%, primarily as
a result of reductions to salary costs and related expenses. During the
third quarter of 2001, payroll costs included the salaries of certain
employees of the acquired Cody Company assisting in the transition and who
were released by the end of 2001.
o Taxes other than income increased $0.7 million, or 16%, for the third
quarter 2002. A one-time severance tax refund of $1.1 million pre-tax was
received in the third quarter of 2001 for taxes
18
previously paid in Louisiana that recently qualified for the Severance Tax
Relief Program as deep wells. Slightly offsetting this change was the
reduction in taxes as a result of lower natural gas and oil prices this
quarter.
Interest expense increased $1.2 million as a result of a higher average
level of outstanding debt during the third quarter of 2002 when compared to the
third quarter of 2001. The new debt was primarily related to the Cody Company
acquisition in August 2001.
Income tax expense decreased $3.8 million due both to the comparable
decrease in earnings before income tax and due to a $0.8 million credit to
income tax expense from an adjustment to deferred taxes.
Nine Months of 2002 and 2001 Compared
Net Income and Revenues. We reported net income in the first nine months of
2002 of $7.4 million, or $0.23 per share. During the corresponding period of
2001, we had net income of $62.7 million, or $2.10 per share. Operating revenues
and operating income decreased $116.5 million and $87.1 million, respectively.
Natural gas made up 61%, or $152.7 million, of net operating revenue in 2002.
The decrease in net operating revenues was driven primarily by a 44% decrease in
the average natural gas price and by a 13% 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 $2.12
per Mcf, or 41%, to $3.07, decreasing net operating revenues by approximately
$46.5 million. In the Western region, the average natural gas production sales
price decreased $2.25 per Mcf, or 51%, to $2.18, decreasing net operating
revenues by approximately $43.1 million. The average East region natural gas
production sales price decreased $2.38 per Mcf, or 44%, to $3.07, decreasing net
operating revenues by approximately $32.0 million. The overall weighted average
natural gas production sales price decreased $2.19 per Mcf, or 44%, to $2.76,
decreasing revenues by $121.6 million. The impact of the change in derivative
fair value on year-to-date natural gas revenue was a $1.0 million reduction to
revenue in 2002, and a $0.8 million addition to revenue in 2001
Natural gas production volume in the Gulf Coast region was up 5.8 Bcf, or
34%, to 23.2 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 declined 0.5 Bcf, or 3%, to 18.9 Bcf due to a decline in net
wells drilled in the region during 2002. Natural gas production volume in the
East region was up 0.6 Bcf, or 5%, to 13.5 Bcf, as a result of an increase in
drilling activity in the region during 2001. The 6.0 Bcf, or 12%, rise in total
natural gas production increased revenue by $29.9 million in the first nine
months of 2002.
The volume of crude oil sold in the first nine months of the year increased
by 844 Mbbl, or 65%, to 2,151 Mbbl, increasing net operating revenues by $22.8
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 and 2002 drilling programs. Crude
oil prices decreased $3.62 per Bbl, or 13%, to $23.34, resulting in a decrease
to net operating revenues of approximately $7.8 million. Additionally, a $1.6
million unrealized gain on the change in derivative fair value was recorded in
2002 primarily related to a crude oil price range swap in place for 2003.
Brokered natural gas revenue decreased $40.9 million, or 50%, over the
first nine months of last year. The sales price of brokered natural gas declined
48%, resulting in a decrease in revenue of $36.4 million, combined with a 6%
decrease in volume of natural gas brokered this period, which reduced revenues
by $4.5 million. After including the related brokered natural gas costs, we
realized a net margin of $3.6 million in the first nine months of 2002 and $2.2
million in the comparable period of 2001.
Other operating revenues increased $1.3 million to $5.5 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.
19
Costs and Expenses. Total costs and expenses from operations decreased $28.9
million, or 12%, due primarily to the following:
o Brokered natural gas cost decreased $42.3 million, or 54%, over the first
nine months of last year. . The price per Mcf of brokered natural gas
dropped 51%, resulting in a decrease to expense of $37.9 million, combined
with a 6% decrease in volume of natural gas brokered this quarter, reducing
costs by $4.4 million. After including the related brokered natural gas
revenues we realized a net margin of $3.6 million in the first nine months
of 2002 and $2.2 million in the comparable period of 2001.
o Direct operating expense increased $6.2 million, or 21%, 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 remainder of 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 $0.51 per Mcf in the first nine months of 2001 to $0.52 per
Mcf in 2002.
o Exploration expense decreased $12.1 million, or 30%, as a result of a $12.1
million decline in dry hole expense from the comparable period of 2001.
Geological and geophysical expenses primarily related to the acquisition
and processing of seismic data has increased $1.1 million for the period,
offset by a decrease of $1.1 million in administrative costs. These changes
are consistent with the 2002 budget and the more active 2001 drilling
program.
o Depreciation, depletion and amortization expense increased $18.4 million,
or 30%, 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 45% from last year including
amounts attributable to the Cody Company properties. On a per unit basis,
DD&A for the first nine months of the year was $1.04 per Mcf in 2001 and
$1.14 per Mcf in 2002.
o General and administrative expenses increased $3.1 million, or 17%,
primarily due to costs related to the retirement of the Chief Executive
Officer in May 2002. Partially offsetting this increase was a $0.4 million
reduction due to additional bad debt expense recorded in the first quarter
of 2001 related to the fourth quarter 2000 bankruptcy of two customers.
o Taxes other than income declined $2.3 million, or 11%, primarily as a
result of lower commodity prices realized this year.
Interest expense increased $4.2 million as a result of a higher average
level of outstanding debt during the first nine months of 2002 when compared to
2001. The new debt was primarily related to the Cody Company acquisition.
Income tax expense decreased $36.2 million due to the comparable decrease
in earnings before income tax and due to a $0.8 million credit to income tax
expense from an adjustment to deferred taxes.
Forward-Looking Information
The statements regarding future financial performance and results, market
prices and the other statements which are not historical facts contained in this
report are forward-looking statements. The words "expect," "project,"
"estimate," "believe," "anticipate," "intend," "budget," "plan," "forecast,"
"predict" and similar expressions are also intended to identify forward-looking
statements. Such statements involve risks and uncertainties, including, but not
limited to, market factors, market prices (including regional basis
differentials) of natural gas and oil, results for future drilling and marketing
activity, future production and costs and other factors detailed herein and in
our other Securities and Exchange Commission filings. Should one or more of
these risks or uncertainties materialize, or should underlying assumptions prove
incorrect, actual outcomes may vary materially from those indicated.
20
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 nine
months of 2002 was 44% 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
swaps covering 37 Mmcf per day in place for October 2002, oil price collars
covering 4 Mbbls per day in place through December 2002, oil price collars for
1.5 Mbbls per day for the first half of 2003, natural gas price swaps in place
for November 2002 through December 2003 for 23 Mmcf per day, and an oil price
range swap in place for 2003 covering 2 Mbbls per day, which all 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 on page 20.
21
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 nine months of
2002, we did not have any natural gas price swaps covering our production.
During the first nine months of 2001, natural gas price swaps covered 918 Mmcf,
fixing the sales price of this gas at $3.75 per Mcf. We entered into no oil
price swaps covering the first nine months 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.
As part of the Cody acquisition, we assumed a derivative contract that Cody
had intended previously. This derivative was a natural gas price floor entered
into to reduce the risk of declining prices in the Gulf Coast region. It was in
place through December 2001. During the third quarter of 2001, this natural gas
price floor covered 533 Mmcf of Gulf Coast production, fixing the floor at $2.81
per Mcf. In September 2001, prices fell below the floor and we realized a cash
gain of $84,000. The natural gas price floor obtained in the merger with Cody
Company valued at $205,300 upon acquisition does not qualify for hedge treatment
under SFAS 133. At September 30, 2001, this derivative has been recorded at
market value on the balance sheet and the resulting gain of $0.5 million,
representing the movement of gas prices since the Cody acquisition (August 1,
2001), is included in the period's operating revenue.
We have entered into a series of four natural gas price swaps that cover 41
Mmcf of production per day for the month of October 2002. These swaps are each
based on price indexes at which we sell a portion of our production and have an
average fixed price of $4.11 per Mcf.
Subsequent to September 30, 2002, we have entered into a series of two
natural gas price swaps for the period of November 2002 through December 2003.
These hedges cover 12% of our estimated production for that period. These cash
flow hedges have an average fixed price of $4.30 per Mcf and are based on two
indexes in the Gulf Coast region at which we typically sell our production.
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 21.6 Bcf, or 44%, of our natural gas production for the
first nine months 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 through the end of the quarter resulting in a
$24.7 million cash gain for the first nine months of 2001. This gain improved
our realized natural gas price for the first nine months of 2001 by $0.50 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
22
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 nine months of
2002 by $0.03 per Mcf.
In March 2002, we entered into another series of natural gas collars that
covered 74% of our anticipated production during the months of May through
August 2002. These collars had a ceiling of $3.17 per Mcf and a floor of $2.54
per Mcf. These natural gas price hedges were 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 nine months of 2002, these collars covered 18.3 Bcf of
production. Most of the indexes were above the ceiling during the duration of
the collar and the resulting $3.3 million cash loss reduced our realized gas
price for the first nine months of 2002 by $0.06 per Mcf.
Also in the first quarter of 2002, we entered into a crude oil price collar
arrangement that covered approximately 40% of our production during the first
nine months of 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 September 2002. The resulting
$3.3 million cash loss reduced our realized oil price by $1.53 per barrel.
Additionally, in August 2003, we entered into a crude oil price collar
covering the first six months of 2003. This collar is based on NYMEX
settlements, and has a ceiling of $28.50 per barrel and a floor of $24.00 per
barrel. This collar covers 9% of our projected oil production during that
period.
Also in August 2003, we have entered into a crude oil price range swap
covering a 2.0 Mbbls per day of production for each month of 2003. Under this
range swap, we receive the fixed price of $28.15 per barrel unless the crude oil
NYMEX is less than $21.00 per barrel for any single month. If the price is below
this range, no settlement is made on this instrument. This range swap does not
qualify for hedge accounting treatment under SFAS 133 and will be
marked-to-market at the end of each period.
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.
ITEM 4. Controls and Procedures
Within the 90-day period prior to the date of this report, the Company
carried out an evaluation, under the supervision and with the participation of
the Company's management, including the Company's Chief Executive Officer and
Chief Financial Officer, of the effectiveness of the design and operation of the
Company's disclosure controls and procedures pursuant to Rule 13a-14 of the
Securities Exchange Act of 1934 (the "Exchange Act"). Based upon that
evaluation, the Chief Executive Officer and Chief Financial Officer concluded
that the Company's disclosure controls and procedures are effective, in all
material respects, with respect to the recording, processing, summarizing and
reporting, within the time periods specified in the Commission's rules and
forms, of information required to be disclosed by the issuer in the reports that
it files or submits under the Exchange Act.
There have been no significant changes in the Company's internal
controls or in other factors that could significantly affect internal controls
subsequent to the date the Company carried out its evaluation.
23
PART II. OTHER INFORMATION
ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibits
4.9 - Credit Agreement dated as of October 28, 2002
among the Company, the Banks Parties Hereto and
Fleet National Bank, as administrative agent.
15.1 - Awareness letter of independent accountants.
(b) Reports on Form 8-K
None
24
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)
October 29, 2002 By: /s/ Dan O. Dinges
-----------------------------------
Dan O. Dinges
President, Chief Executive Officer and
Chairman of the Board
October 29, 2002 By: /s/ Scott C. Schroeder
----------------------------------------
Scott C. Schroeder
Vice President, Chief Financial Officer
and Treasurer
October 29, 2002 By: /s/ Henry C. Smyth
----------------------------------------
Henry C. Smyth
Vice President and Controller
(Principal Accounting Officer)
25
CERTIFICATIONS
I, Scott C. Schroeder, certify that:
1. I have reviewed this quarterly report on Form10-Q of Cabot Oil & Gas
Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: October 29, 2002
/s/ Scott C. Schroeder
----------------------------------------------
Scott C. Schroeder
Vice President, Chief Financial Officer and
Treasurer
I, Dan O. Dinges, certify that:
1. I have reviewed this quarterly report on Form10-Q of Cabot Oil & Gas
Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: October 29, 2002
/s/ Dan O. Dinges
---------------------------------------------
Dan O. Dinges
President, Chief Executive Officer
and Chairman of the Board