<PAGE>
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, 2000
( ) 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 20, 2000, there were 29,014,104 shares of Class A Common
Stock, Par Value $.10 Per Share, outstanding.
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<PAGE>
CABOT OIL & GAS CORPORATION
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Part I. Financial Information Page
----
<S> <C>
Item 1. Financial Statements
Condensed Consolidated Statement of Operations for the Three and Nine Months
Ended September 30, 2000 and 1999................................................................... 3
Condensed Consolidated Balance Sheet at September 30, 2000
and December 31, 1999............................................................................... 4
Condensed Consolidated Statement of Cash Flows for the Three and Nine Months
Ended September 30, 2000 and 1999................................................................... 5
Notes to Condensed Consolidated Financial Statements................................................. 6
Report of Independent Accountant's Review of
Interim Financial Information....................................................................... 9
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations.......................................................................... 10
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K............................................................... 20
Signature................................................................................................. 21
</TABLE>
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<PAGE>
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
------------------------------
CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
(In Thousands, Except Per Share Amounts)
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ ------------------------
2000 1999 2000 1999
------- ------- -------- --------
<S> <C> <C> <C> <C>
NET OPERATING REVENUES
Natural Gas Production.................... $45,099 $39,508 $123,088 $105,466
Crude Oil and Condensate.................. 7,593 4,805 16,567 11,297
Brokered Natural Gas Margin............... 1,230 905 3,782 2,844
Other..................................... 773 472 7,417 2,424
------- ------- -------- --------
54,695 45,690 150,854 122,031
OPERATING EXPENSES
Direct Operations - Field & Pipeline...... 8,718 8,502 26,292 24,111
Exploration............................... 4,691 2,993 12,086 7,433
Depreciation, Depletion and Amortization.. 13,216 13,797 38,329 41,592
Impairment of Unproved Properties......... 963 696 2,886 2,649
Impairment of Long-Lived Assets........... 0 0 9,143 0
General and Administrative................ 5,318 4,918 15,536 13,635
Taxes Other Than Income................... 6,016 4,767 15,570 12,570
------- ------- -------- --------
38,922 35,673 119,842 101,990
Gain (Loss) on Sale of Assets............... 26 4,044 (21) 5,019
------- ------- -------- --------
INCOME FROM OPERATIONS...................... 15,799 14,061 30,991 25,060
Interest Expense............................ 5,709 6,506 17,044 19,674
------- ------- -------- --------
Income Before Income Taxes.................. 10,090 7,555 13,947 5,386
Income Tax Expense.......................... 3,953 3,025 5,546 2,338
------- ------- -------- --------
NET INCOME.................................. 6,137 4,530 8,401 3,048
Dividend Requirement on Preferred Stock..... 0 851 (3,749) 2,552
------- ------- -------- --------
Net Income Available to
Common Stockholders...................... $ 6,137 $ 3,679 $ 12,150 $ 496
======= ======= ======== ========
Basic Earnings Per Share
Applicable to Common Stockholders........ $ 0.21 $ 0.15 $ 0.45 $ 0.02
Diluted Earnings Per Share
Applicable to Common Stockholders........ $ 0.21 $ 0.15 $ 0.45 $ 0.02
Weighted Average Common Shares Outstanding.. 28,976 24,757 26,830 24,709
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
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<PAGE>
CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET
(In Thousands, Except Per Share Amounts)
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
2000 1999
-------- --------
(Unaudited)
<S> <C> <C>
ASSETS
Current Assets
Cash and Cash Equivalents...................................... $ 2,022 $ 1,679
Accounts Receivable............................................ 62,165 50,391
Inventories.................................................... 14,602 10,929
Other.......................................................... 4,685 3,641
-------- --------
Total Current Assets........................................ 83,474 66,640
Properties and Equipment, Net (Successful Efforts Method).......... 611,949 590,301
Other Assets....................................................... 1,946 2,539
-------- --------
$697,369 $659,480
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current Portion of Long-Term Debt.............................. $ 16,000 $ 16,000
Accounts Payable............................................... 67,041 56,551
Accrued Liabilities............................................ 21,210 17,387
-------- --------
Total Current Liabilities................................... 104,251 89,938
Long-Term Debt..................................................... 260,000 277,000
Deferred Income Taxes.............................................. 99,187 95,012
Other Liabilities.................................................. 12,865 11,034
Stockholders' Equity
Preferred Stock:
Authorized -- 5,000,000 Shares of $.10 Par Value
Issued and Outstanding - 6% Convertible Redeemable
Preferred; $50 Stated Value; No Shares Outstanding in 2000
and 1,134,000 Shares Outstanding in 1999..................... 0 113
Common Stock:
Authorized -- 40,000,000 Shares of $.10 Par Value
Issued and Outstanding - 29,313,704 Shares and
25,073,660 Shares in 2000 and 1999, Respectively............ 2,931 2,507
Additional Paid-in Capital..................................... 280,063 254,763
Accumulated Deficit............................................ (57,544) (66,503)
Less Treasury Stock, at Cost:
302,600 Shares in 2000 and 1999............................. (4,384) (4,384)
-------- --------
Total Stockholders' Equity.................................. 221,066 186,496
-------- --------
$697,369 $659,480
======== ========
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
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<PAGE>
CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
(In Thousands)
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------- ---------------------
2000 1999 2000 1999
-------- -------- --------- --------
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income........................................... $ 6,137 $ 4,530 $ 8,401 $ 3,048
Adjustment to Reconcile Net Income to
Cash Provided by Operating Activities:
Depletion, Depreciation and Amortization........... 13,216 13,797 38,329 41,592
Impairment of Undeveloped Leasehold................ 963 696 2,886 2,649
Impairment of Long-Lived Assets.................... 0 0 9,143 0
Deferred Income Taxes.............................. 3,567 7,233 4,175 6,431
(Gain) Loss on Sale of Assets...................... (26) (4,044) 21 (5,019)
Exploration Expense................................ 4,691 2,993 12,086 7,433
Other.............................................. 823 415 1,077 1,672
Changes in Assets and Liabilities:
Accounts Receivable................................ (3,997) (7,896) (11,774) 4,385
Inventories........................................ (6,289) (3,219) (3,673) (2,138)
Other Current Assets............................... (255) 623 (1,060) 296
Other Assets....................................... 253 (55) 593 776
Accounts Payable and Accrued Liabilities........... 3,398 12,167 11,799 (2,386)
Other Liabilities.................................. 146 532 1,831 935
-------- -------- --------- --------
Net Cash Provided by Operating Activities........ 22,627 27,772 73,834 59,674
-------- -------- --------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures................................. (29,614) (19,617) (71,674) (60,980)
Proceeds from Sale of Assets......................... 882 47,597 2,663 56,973
Restricted Cash...................................... 0 (36,812) 0 (36,812)
Exploration Expense.................................. (4,691) (2,993) (12,086) (7,433)
-------- -------- --------- --------
Net Cash Used by Investing Activities............... (33,423) (11,825) (81,097) (48,252)
-------- -------- --------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Sale of Common Stock................................. 1,549 467 81,597 1,384
Retirement of Preferred Stock........................ 0 0 (51,600) 0
Increase in Debt..................................... 39,000 24,000 95,000 90,000
Decrease in Debt..................................... (28,000) (39,000) (112,000) (98,000)
Dividends Paid....................................... (1,160) (1,853) (5,391) (5,541)
-------- -------- --------- --------
Net Cash Provided (Used) by Financing Activities.... 11,389 (16,386) 7,606 (12,157)
-------- -------- --------- --------
Net Increase (Decrease) in Cash and Cash Equivalents.. 593 (439) 343 (735)
Cash and Cash Equivalents, Beginning of Period........ 1,429 1,904 1,679 2,200
-------- -------- --------- --------
Cash and Cash Equivalents, End of Period.............. $ 2,022 $ 1,465 $ 2,022 $ 1,465
======== ======== ========= ========
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
-5-
<PAGE>
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, consisting only of normal recurring
adjustments, necessary for a fair presentation.
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). SFAS 133 requires all
derivatives to be recognized in the statement of financial position as either
assets or liabilities and measured at fair value. In addition, all hedging
relationships must be designated, reassessed and documented according to the
provisions of SFAS 133. This statement was initially effective for financial
statements for fiscal years beginning after June 15, 1999. However, in June
1999, the FASB issued SFAS 137, "Accounting for Derivative Instruments and
Hedging Activities - Deferral of Effective Date of SFAS 133," which delayed the
effective date of SFAS 133 to fiscal years beginning after June 15, 2000. In
June 2000, the FASB issued SFAS 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities". This pronouncement amended portions
of SFAS 133 and will be applied with SFAS 133 effective January 1, 2001.
Since the issuance of SFAS 133 and SFAS 138, the Company has been modeling
the impact on our financial statements. Currently, one cash flow hedge is in
place that will remain open as of January 1, 2001 when SFAS 133 becomes
effective. Based on the current index price strip, the impact of this hedge at
adoption would be to record a Hedge Loss of $0.2 million and a charge to Other
Comprehensive Income of $1.7 million. Correspondingly, a Hedge Liability for
$1.9 million would be established. These amounts may change as a result in
changes in the index prices between now and January 1, 2001.
2. PROPERTIES AND EQUIPMENT
Properties and equipment are comprised of the following:
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
2000 1999
---------- ----------
(In thousands)
<S> <C> <C>
Unproved Oil and Gas Properties....................... $ 38,660 $ 32,262
Proved Oil and Gas Properties......................... 962,039 906,852
Gathering and Pipeline Systems........................ 127,228 124,708
Land, Building and Improvements....................... 4,410 4,359
Other................................................. 24,311 23,206
---------- ----------
1,156,648 1,091,387
Accumulated Depreciation, Depletion and Amortization.. (544,699) (501,086)
---------- ----------
$ 611,949 $ 590,301
========== ==========
</TABLE>
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<PAGE>
3. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
2000 1999
------- -------
(In thousands)
<S> <C> <C>
Accounts Receivable
Trade Accounts.............................. $55,690 $44,739
Joint Interest Accounts..................... 5,021 4,395
Insurance Recoveries........................ 1,571 1,177
Current Income Tax Receivable............... 111 111
Other Accounts.............................. 92 263
------- -------
62,485 50,685
Allowance for Doubtful Accounts.............. (320) (294)
------- -------
$62,165 $50,391
======= =======
Accounts Payable
Trade Accounts.............................. $14,139 $12,195
Natural Gas Purchases....................... 11,747 14,918
Royalty and Other Owners.................... 19,862 11,316
Capital Costs............................... 12,997 10,103
Taxes Other Than Income..................... 2,117 1,279
Drilling Advances........................... 888 614
Dividends Payable........................... 0 851
Wellhead Gas Imbalances..................... 2,459 2,177
Other Accounts.............................. 2,832 3,098
------- -------
$67,041 $56,551
======= =======
Accrued Liabilities
Employee Benefits........................... $ 3,387 $ 5,203
Taxes Other Than Income..................... 11,005 8,471
Interest Payable............................ 5,410 2,780
Other Accrued............................... 1,408 933
------- -------
$21,210 $17,387
======= =======
Other Liabilities
Postretirement Benefits Other Than Pension.. $ 1,223 $ 799
Accrued Pension Cost........................ 6,655 6,290
Taxes Other Than Income and Other........... 4,987 3,945
------- -------
$12,865 $11,034
======= =======
</TABLE>
4. LONG-TERM DEBT
At September 30, 2000, the Company had $144 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.
-7-
<PAGE>
5. EARNINGS PER SHARE
Basic earnings per share for the third quarter were based on the weighted
average shares outstanding of 28,975,578 in 2000 and 24,756,920 in 1999. Basic
earnings per share for the nine months of the year were based on the weighted
average shares outstanding of 26,830,473 in 2000 and 24,708,807 in 1999.
Diluted earnings per share were the same as basic earnings per share in all
periods presented. The diluted earnings per share amounts are based on weighted
average shares outstanding plus common stock equivalents. Common stock
equivalents include both stock awards and stock options. In the third quarter,
common stock equivalents were 246,400 in 2000 and 352,132 in 1999. Full the
first nine months, common stock equivalents were 262,783 in 2000 and 326,240 in
1999.
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 for the clean-up costs which
could total as much as several hundred million dollars. The EPA is also
pursuing the owner(s) / operator(s) 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, are in negotiations with the EPA and have
presented the EPA with a counter offer to its settlement offer.
The Company has a reserve that it believes to be adequate to cover this
potential environmental liability based on its assessment of the most likely
outcome of this matter. While the potential impact to the Company may
materially affect quarterly or annual financial results, management does not
believe it would materially impact the Company's financial position or cash
flows. 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.
While the Company believes that it has substantial defenses to this claim
and intends to vigorously assert such defenses, however, the investigation into
this claim has only just begun and, accordingly, the Company can not presently
determine the likelihood or range of any potential loss.
8. RETIREMENT OF PREFERRED STOCK
In May 2000, the Company repurchased all of the then-outstanding shares of
preferred stock from the holder for $51.6 million. Since this stock had been
recorded at a stated value of $56.7 million on the Company's balance sheet, the
benefit from a $5.1 million negative dividend to preferred stockholders was
included in net income available to common shareholders. After this repurchase
transaction, the Company retired all shares of preferred stock.
This transaction was funded by the sale of common stock in a public
offering. The Company sold 3.4 million shares to the public at $21.50 per
share. After deducting the costs of this transaction, the Company received net
proceeds of $71.5 million. After repurchasing the preferred stock, the excess
proceeds from this transaction were used to reduce debt on the Company's
revolving credit facility.
-8-
<PAGE>
Report of Independent Accountants
To the Board of Directors and Shareholders
Cabot Oil & Gas Corporation:
We have reviewed the accompanying condensed consolidated balance sheet of Cabot
Oil & Gas Corporation (the "Company") as of September 30, 2000 and the related
condensed consolidated statements of operations and cash flows for each of the
three month and nine month periods ended September 30, 2000 and September 30,
1999. 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, 1999, and the related consolidated statements of operations, stockholders'
equity, and cash flows for the year then ended (not presented herein), and in
our report dated February 11, 2000 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, 1999,
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 24, 2000
-9-
<PAGE>
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 2000 and 1999
should be read in conjunction 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, 1999.
Overview
Market prices for both natural gas and oil continued to strengthen during the
third quarter of 2000. Our realized natural gas price for the first nine months
of 2000 was 29% higher than in 1999, and oil prices rose 57% over the same
period. Our net revenues for the nine-month period increased $28.8 million, or
24%, and net income increased $11.7 million, mainly as a result of this improved
price environment and, to a lesser extent, the benefit of the repurchase of the
outstanding preferred stock reflected as a negative dividend. Operating cash
flows were similarly impacted, improving by $14.2 million over last year.
Our net income for the first nine months of 2000 was $12.2 million, or $0.45
per share. These results include the impact of non-recurring items. These
selected items includes a contract settlement ($1.7 million benefit after tax),
an impairment of long-lived assets ($5.6 million after tax), a negative
preferred stock dividend resulting from the repurchase of the preferred stock
($5.1 million benefit after tax), and the costs incurred as a result of closing
our Pittsburgh office ($0.6 million after tax). Excluding these selected items,
our net income for the first nine months of 2000 was $11.5 million, or $0.43 per
share.
We drilled 85 gross wells with a success rate of 88% in the first nine months
of 2000 compared to 49 gross wells and an 86% success rate in the first nine
months of 1999. We have increased our 2000 capital and exploration expenditure
budget by approximately $29 million in response to the improving commodity
prices during the year. For the full year, Cabot Oil & Gas now plans to drill
137 gross wells and spend $117.6 million in capital and exploration expenditures
compared to 73 gross wells and $88.1 million of capital and exploration
expenditures in 1999. Total expenditures were $86.7 million for the first nine
months of 2000, compared to $61.0 million for the comparable period in 1999.
Natural gas production was 45.4 Bcf, down 4.7 Bcf compared to the first nine
months of 1999. This production decline was due equally to the sale of non-
strategic producing assets in the Appalachian region during the third quarter of
1999, natural production declines, and delays in bringing on new production in
the Gulf Coast region, including the Etouffee wells in south Louisiana.
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 nine months of 2000 of $2.71/Mcf
was the highest we have ever realized. However, during the first nine months of
1999, our realized gas price ($2.10/Mcf) was the lowest nine-month price since
1995. 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, synergistic
acquisitions and the exploitation of our marketing abilities. 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.
Our level of earnings and cash flows depend on many factors, including the price
of oil and natural gas and our ability to control and reduce costs. Demand for
oil and natural gas has historically been subject to seasonal influences
characterized by peak demand and higher prices in the winter heating season.
During 2000, the commodity market has not followed this historical trend and we
have experienced higher than normal summer and fall prices.
-10-
<PAGE>
Our primary sources of cash during the first nine months of 2000 were from
funds generated from operations and the sale of common stock, primarily from a
block trade along with stock option exercises. Cash was primarily used to fund
exploration and development expenditures, to repurchase preferred stock, to
reduce debt and to pay dividends.
We had a net cash inflow of $0.3 million in the first nine months of 2000.
Net cash inflow from operating activities totaled $73.8 million in the period.
When combined with the net proceeds from stock activity of $30 million, this
cash inflow funded both the $17 million debt reduction and the $83.8 million of
capital and exploration expenditures.
<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30,
2000 1999
---- ----
(In millions)
<S> <C> <C>
Cash Flows Provided by Operating Activities......................................... $73.8 $59.7
===== =====
</TABLE>
Cash flows from operating activities in the 2000 first nine months were
$14.1 million higher than the corresponding period of 1999 primarily due to
higher commodity prices and the cash received on the settlement of a gas
contract dispute.
<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30,
2000 1999
---- ----
(In millions)
<S> <C> <C>
Cash Flows Used by Investing Activities............................................. $81.1 $48.3
===== =====
</TABLE>
Cash flows used by investing activities in the first nine months of 2000
and 1999 were substantially attributable to capital and exploration expenditures
of $83.8 million and $68.4 million, respectively. Proceeds from the sale of
certain oil and gas properties in the first nine months of 2000 were $2.7
million, and $57.0 million in 1999. Although we had recorded proceeds from the
sale of non-strategic properties of $57 million as of September 30, 1999, $36.8
million was placed in escrow as a requirement of a tax-deferred exchange
transaction. In this transaction, we sold all of our producing assets in the
Clarksburg area of the Appalachian Region. Certain of these sold properties
were matched with certain producing assets purchased in the Rocky Mountains area
of the Western Region. At September 30, 1999, the escrowed cash is recorded as
"Restricted Cash" on our balance sheet. During the fourth quarter of 1999,
after meeting the requirements of the tax-deferred exchange, $28.6 million was
withdrawn from this escrow account and used to reduce the outstanding balance on
our revolving credit agreement. The remaining $8.3 million was withdrawn from
the escrow account to fund the purchase of certain oil and gas properties during
the fourth quarter of 1999.
<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30,
2000 1999
---- ----
(In millions)
<S> <C> <C>
Cash Flows Provided (Used) by Financing Activities.................................. $7.6 $(12.2)
==== =======
</TABLE>
In the first nine months of 2000, we raised $81.6 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 nine months of 2000 also included $17 million used to reduce borrowings on
our revolving credit facility, and $5.4 million for the payment of dividends,
including the final dividend payment on the preferred stock. In the same period
of 1999, cash flows used by financing activities were primarily reductions to
borrowings on our revolving credit facility and the payment of dividends.
The available credit line under our revolving credit facility, currently $250
million, is subject to adjustment on the basis of the present value (as
determined by the banks' petroleum engineer) of estimated future net cash flows
from proved oil and gas reserves and other assets. The revolving term of the
credit
-11-
<PAGE>
facility ends in December 2003. Management believes that we have the ability to
finance, if necessary, our capital requirements, including acquisitions.
Our 2000 interest expense is projected to be approximately $23.3 million. In
May 2001, a $16 million principal payment is due on the 10.18% Notes. This
amount is reflected as "Current Portion of Long-Term Debt" on the balance sheet.
This payment is expected to be made with cash from operations and, if necessary,
from increased borrowings on the revolving credit facility.
Capitalization
Our capitalization information is as follows:
SEPTEMBER 30, DECEMBER 31,
2000 1999
------ ------
(In millions)
Long-Term Debt.................................... $260.0 $277.0
Current Portion of Long-Term Debt................. 16.0 16.0
------ ------
Total Debt....................................... 276.0 293.0
------ ------
Stockholders' Equity
Common Stock (net of Treasury Stock)............. 221.1 129.8
Preferred Stock.................................. 0.0 56.7
------ ------
Total............................................ 221.1 186.5
------ ------
Total Capitalization.............................. $497.1 $479.5
====== ======
Debt to Capitalization............................ 55.5% 61.1%
During the first nine months of 2000, we paid dividends of $3.2 million on the
common stock and $2.2 million on the 6% convertible redeemable preferred stock.
A regular dividend of $0.04 per share of common stock was declared for the
quarter ending September 30, 2000, to be paid November 24, 2000 to shareholders
of record as of November 10, 2000.
In May 2000, we bought back all of the shares of preferred stock from the
holder for $51.6 million. Since this stock had been recorded at a stated value
of $56.7 million on our balance sheet, we realized a negative dividend to
preferred stockholders of $5.1 million. We received net proceeds of $71.5
million from the sale of 3.4 million shares of common stock in a public offering
primarily to fund this transaction. After repurchasing the preferred stock, the
excess proceeds were used to reduce debt.
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 SEPTEMBER 30,
2000 1999
----- -----
(In millions)
Capital Expenditures
Drilling and Facilities........................ $58.8 $32.1
Leasehold Acquisitions......................... 8.2 6.0
Pipeline and Gathering......................... 2.2 3.0
Other.......................................... 1.2 2.6
----- -----
70.4 43.7
----- -----
Proved Property Acquisitions.................... 4.2 9.9
Exploration Expenses............................ 12.1 7.4
----- -----
Total.......................................... $86.7 $61.0
===== =====
-12-
<PAGE>
Total capital and exploration expenditures in the first nine months of 2000
increased $25.7 million compared to the same period of 1999, primarily as a
result of increased drilling activity.
We have increased our 2000 capital and exploration expenditure budget by
approximately $29 million in response to the improving commodity prices during
the year. We now plan to drill 137 gross wells in 2000 compared with 73 gross
wells drilled in 1999. This increased 2000 drilling program includes $117.6
million in total capital and exploration expenditures, up 33% from the $88.1
million spent in 1999. Expected spending in 2000 includes $94.5 million for
drilling, facilities and exploration. In addition to the drilling and
exploration program, other 2000 capital expenditures are planned primarily for
lease acquisitions 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.
Commodity Price 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. We did not enter into any natural
gas price swaps on our production for the first nine months of 2000.
Subsequent to September 30, 2000, we had open natural gas price swap
contracts on our production as follows:
<TABLE>
<CAPTION>
Natural Gas Price Swaps
------------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Mmcf Contract Price (in $ millions)
----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Natural Gas Price Swap on Our Production
----------------------------------------
Fourth Quarter 2000 315 $4.03 $(0.3)
2001 918 $3.55 $(0.9)
2002 678 $3.41 $(0.8)
2003 423 $3.24 $ 0.1
</TABLE>
The notional volume of the crude oil swap transactions was 364,000 Bbls at an
average price of $22.67 per Bbl, which represents 56% of our total oil
production for the nine months ended September 30, 2000. Financial derivatives
related to crude oil reduced revenue by $2.2 million during the first nine
months of 2000. We had no open oil price swap contracts on our production at
September 30, 2000. There were no crude oil price swaps in place for the first
nine months of 1999.
Currently, we also have a series of price collars in place on a portion of our
natural gas production. There are seven collar arrangements that are based on
separate regional price indexes which have a weighted average price floor of
$2.74/Mcf and a weighted average price ceiling of $3.38/Mcf. If the index rises
above the ceiling price, we pay the counterparty. If the index falls below the
floor price, the counterparty will pay us. These collars are in place during
the months of April through October 2000. During the second and third quarters
of 2000, these collars covered a total quantity of 8,473 Mmcf, or 28% of our
total production for the period. In April and May 2000, the index prices all
fell within the price collar and no settlements were made. In June 2000, all of
the indexes rose above the ceiling prices, resulting in a $1.8 million reduction
to our realized revenue in the second quarter. The indexes remained above the
ceiling during the third quarter, resulting in a $5.0 million reduction to the
quarter's revenue. If these hedges had not been in place for the third quarter,
our realized natural gas price would have been $0.32 per Mcf higher. There were
no commodity price collars in place during 1999.
-13-
<PAGE>
As of September 30, 2000, we had open natural gas price collars on our
production as follows:
<TABLE>
<CAPTION>
Natural Gas Price Collars
-------------------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Mmcf Ceiling/Floor Price (in $ millions)
---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Natural Gas Price Collars on Our Production
-------------------------------------------
Fourth Quarter 2000 1,435 $3.38/$2.74 $(3.3)
(open for October only)
</TABLE>
We also use price swaps to hedge the natural gas price risk on some 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 these 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.
During the first nine months of 2000 and 1999 we entered into price swaps with
total notional quantities of 1,295 and 2,470 Mmcf, respectively, related to our
brokered activities representing 4% and 7%, respectively, of our total volume of
brokered natural gas sold.
As of September 30, 2000, we had no open commodity price swap contracts on
our brokered activity. Financial derivatives related to brokered natural gas
reduced revenue by $16,000 in the first nine months of 2000 and reduced revenue
by $58,000 in the same period of 1999.
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.
Since its issuance, we have been modeling the impact of Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" (SFAS 133). Currently, we have one cash flow hedge in place that
will be remain open as of January 1, 2001 when SFAS 133 becomes effective.
Based on the current index price strip, the impact of this hedge at adoption
would be to record a Hedge Loss of $0.2 million and a charge to Other
Comprehensive Income of $1.7 million. Correspondingly, a Hedge Liability for
$1.9 million would be established. These amounts may change as a result in
changes in the index prices between now and January 1, 2001.
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 2000 was up 29% over 1999, after declining 3% from the first nine
months of 1998 to 1999. The volatility of natural gas prices in recent years
remains prevalent in 2000 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 on page 19.
-14-
<PAGE>
Results of Operations
For the purpose of reviewing our results of operations, "Net Income" is
defined as net income available to common shareholders.
<TABLE>
<CAPTION>
Selected Financial and Operating Data
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ -----------------
2000 1999 2000 1999
------ ------ ------ ------
(In millions, except where noted)
<S> <C> <C> <C> <C>
Net Operating Revenues............................. $ 54.7 $ 45.7 $150.9 $122.0
Operating Expenses................................. 38.9 35.7 119.8 102.0
Operating Income................................... 15.8 14.1 31.0 25.1
Interest Expense................................... 5.7 6.5 17.0 19.7
Net Income......................................... 6.1 3.7 12.2 0.5
Earnings Per Share - Basic......................... $ 0.21 $ 0.15 $ 0.45 $ 0.02
Earnings Per Share - Diluted....................... $ 0.21 $ 0.15 $ 0.45 $ 0.02
Natural Gas Production (Bcf)
Gulf Coast....................................... 3.5 4.2 9.9 11.7
West............................................. 7.4 7.6 22.0 22.3
Appalachia....................................... 4.6 5.3 13.5 16.1
------ ------ ------ ------
Total Company.................................... 15.5 17.1 45.4 50.1
Natural Gas Production Sales Prices ($/Mcf)
Gulf Coast...................................... $ 3.72 $ 2.49 $ 3.12 $ 2.17
West............................................ $ 2.62 $ 2.14 $ 2.46 $ 1.91
Appalachia...................................... $ 2.73 $ 2.43 $ 2.81 $ 2.33
Total Company................................... $ 2.90 $ 2.32 $ 2.71 $ 2.10
Crude/Condensate
Volume (MBbl)................................... 255 237 656 705
Price ($/Bbl)................................... $29.72 $20.23 $25.26 $16.04
Brokered Natural Gas Margin
Volume (Bcf).................................... 8.2 13.8 33.5 36.7
Margin ($/Mcf).................................. $ 0.15 $ 0.07 $ 0.11 $ 0.08
</TABLE>
The table below presents the after-tax effect of certain selected items on
our results of operations for the three- and nine-month periods ended September
30, 2000.
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------- -------------------
Amount per share Amount per share
-------- ---------- ------- ----------
(In millions, except per share amounts)
<S> <C> <C> <C> <C>
Net Income Before Selected Items................. $6.1 $0.21 $11.5 $ 0.43
Benefit from miscellaneous net revenue /(1)/..... 0.0 0.00 1.7 0.07
Impairment of long-lived assets.................. 0.0 0.00 (5.6) (0.22)
Closure of Pittsburgh office..................... 0.0 0.00 (0.6) (0.03)
Negative preferred stock dividend................ 0.0 0.00 5.1 0.20
---- ----- ----- ------
Net Income Available to Common Shareholders...... $6.1 $0.21 $12.1 $ 0.45
==== ===== ===== ======
</TABLE>
/(1)/ Represents net benefit, primarily from a contract settlement.
-15-
<PAGE>
These selected items impacted our financial results in 2000. 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 ($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.
In the third quarter of 1999, a $4.0 million gain was recorded on the sale
of non-strategic assets. Excluding this item, net income for the third quarter
of 1999 was $1.2 million, or $0.05 per share. In the first nine months of 1999,
a $5.0 million gain was recorded on the sale of non-strategic assets. Excluding
this item, the net loss for the first nine months of 1999 was $2.6 million, or
$0.10 per share. The discussion below excludes the impact of all of these
selected items.
Third Quarters of 2000 and 1999 Compared
Net Income and Revenues. We reported net income in the third quarter of
-----------------------
2000 of $6.1 million, or $0.21 per share. During the corresponding quarter of
1999, we recorded net income excluding the selected item of $1.2 million, or
$0.05 per share. Operating revenues increased by $9.0 million and operating
income increased by $1.7 million. Natural gas made up 82%, or $45.1 million, of
net operating revenue. The increase in net operating revenues was driven
primarily by improvements in realized commodity prices. The average natural gas
price was 25% higher than the third quarter of 1999, offset slightly by a 9%
decrease in natural gas production as discussed below. We also realized oil
prices that were 47% higher than the 1999 third quarter. Net income and
operating income were similarly impacted by the increase in the average natural
gas price.
Natural gas production volume in the Gulf Coast region was down 0.7 Bcf, or
17%, to 3.5 Bcf primarily due to delays in bringing on new production, including
the Etouffee wells in south Louisiana, and the collapse of casing in two wells
in the Beaurline field. Natural gas production volume in the Western region was
down 0.2 Bcf, or 3%, to 7.4 Bcf primarily due to a decrease in drilling activity
in the Mid-Continent area during 1999. Natural gas production volume in the
Appalachian region was down 0.7 Bcf, or 13%, to 4.6 Bcf, as a result of the sale
of certain non-strategic assets effective October 1, 1999, and a decrease in
drilling activity in the region in 1999. The decline in total natural gas
production of 1.6 Bcf, or 9%, reduced revenue by $3.5 million in the third
quarter of 2000.
The average Gulf Coast natural gas production sales price rose $1.23 per
Mcf, or 49%, to $3.72, increasing net operating revenues by approximately $4.3
million. In the Western region, the average natural gas production sales price
increased $0.48 per Mcf, or 22%, to $2.62, increasing net operating revenues by
approximately $3.5 million. The average Appalachian natural gas production sales
price increased $0.30 per Mcf, or 12%, to $2.73, increasing net operating
revenues by approximately $1.3 million. The overall weighted average natural gas
production sales price increased $0.58 per Mcf, or 25%, to $2.90, increasing
revenues by $9.1 million. Early in the second quarter, we entered into certain
natural gas price collars that limited the benefit we received when natural gas
price indexes rose later in the middle of the year. If these hedges had not been
in place for the third quarter, our realized natural gas price would have been
$0.32 per Mcf higher. Additionally, we had entered into certain fixed price
contracts starting early in the second quarter that fixed the price on 47% of
our third quarter production at an average price of $2.70/Mcf.
Crude oil prices rose $9.49 per Bbl, or 47%, to $29.72, resulting in an
increase to net operating revenues of approximately $2.4 million. In addition,
the volume of crude oil sold in the quarter increased by 18 Mbbls, or 8%, to 255
Mbbls, increasing net operating revenues by $0.4 million.
-16-
<PAGE>
Other net operating revenues increased $0.3 million to $0.8 million.
Section 29 revenues were increased by $0.3 million, as we are no longer
deferring revenue from non-certified wells. A recent FERC ruling will allow us
to certify these wells and take advantage of the related tax credits.
Costs and Expenses. Total costs and expenses from operations increased
------------------
$3.2 million, or 9%, in the third quarter of 2000 compared to the same period of
1999. The primary reasons for this fluctuation are as follows:
. Direct operating expense increased $0.2 million, or 3%, primarily as a result
of costs associated with the expansion of the Gulf Coast regional office,
both in staffing and office facilities.
. Exploration expense increased $1.7 million, or 57%, primarily as a result of
$0.5 million in higher geological and geophysical costs that were incurred in
the Rocky Mountains area, and $0.4 million due to increased dry hole expense
resulting from a more active drilling program in 2000. Additionally, we
incurred $0.3 million for increased staffing in the Gulf Coast region, and
$0.2 million for higher employee related expenses including travel and
relocation costs.
. Depreciation, depletion, amortization and impairment expense (DD&A) decreased
$0.3 million, or 2% as a result of the decrease in natural gas and oil
production this quarter.
. General and administrative costs rose $0.4 million, or 8%, primarily as a
result of legal costs related to certain litigation which was settled in the
quarter as well as the increased cost associated with our new corporate
office space.
. Taxes other than income rose $1.2 million, or 26%, as a result of higher
commodity prices realized this quarter.
Interest expense decreased $0.8 million as a result of a lower average
level of outstanding debt during the third quarter of 2000 when compared to the
third quarter of 1999.
Income tax expense increased $0.9 million due to the comparable increase in
earnings before income tax excluding the income tax impact of the selected
items.
Nine Months of 2000 and 1999 Compared
Net Income and Revenues. Excluding the selected items, we reported net
-----------------------
income in the first nine months of 2000 of $11.5 million, or $0.43 per share.
During the corresponding period of 1999 after excluding selected items, we had a
net loss of $2.6 million, or $0.10 per share. Operating revenues and operating
income increased $26.0 million and $13.2 million, respectively. Natural gas made
up 83%, or $123.1 million, of net operating revenue. The increase in net
operating revenues was driven primarily by a 29% increase in the average natural
gas price, partially offset by a 9% decrease in natural gas production as
discussed below. The 57% increase in realized oil prices also contributed to
this improvement. Net income and operating income were similarly impacted by the
increase in commodity prices, but reduced by increases in operating expenses as
discussed below.
Natural gas production volume in the Gulf Coast region was down 1.8 Bcf, or
15%, to 9.9 Bcf primarily due to delays in bringing on new production, including
the Etouffee wells in south Louisiana, and the collapse of casing in two wells
in the Beaurline field. Natural gas production volume in the Western region was
down 0.3 Bcf, or 1%, to 22.0 Bcf primarily due to a decrease in drilling
activity in the Mid-Continent area during 1999. Natural gas production volume
in the Appalachian region was down 2.6 Bcf, or 16%, to 13.5 Bcf, as a result of
the sale of certain non-strategic assets effective October 1, 1999, and a
decrease in drilling activity in the region in 1999 and 2000. The decline in
total natural gas production of 4.7 Bcf, or 9%, reduced revenue by $9.9 million
in the first nine months of 2000.
The average Gulf Coast natural gas production sales price rose $0.95 per
Mcf, or 44%, to $3.12, increasing net operating revenues by approximately $9.4
million. In the Western region, the average
-17-
<PAGE>
natural gas production sales price increased $0.55 per Mcf, or 29%, to $2.46,
increasing net operating revenues by approximately $12.1 million. The average
Appalachian natural gas production sales price increased $0.48 per Mcf, or 21%,
to $2.81, increasing net operating revenues by approximately $6.5 million. The
overall weighted average natural gas production sales price increased $0.61 per
Mcf, or 29%, to $2.71, increasing revenues by $27.5 million.
Crude oil prices increased $9.22 per Bbl, or 57%, to $25.26, resulting in
an increase to net operating revenues of approximately $6.0 million. The volume
of crude oil sold in the first nine months of the year decreased by 49 Mbbl, or
7%, to 656 Mbbl, decreasing net operating revenues by $0.7 million.
The brokered natural gas margin increased $0.9 million to $3.8 million. The
primary cause was a $0.03 per Mcf improvement in net margin that resulted in a
$1.2 million revenue increase. Partially offsetting this increase was a 3.3 Bcf
volume decrease, which resulted in a $0.3 million decrease in brokered natural
gas margin.
Excluding the selected items, other net operating revenues increased $2.2
million to $4.6 million. This improvement was a result of changes in activity in
the following areas:
. A natural gas liquids plant in the Gulf Coast contributed an additional
$0.7 million and the Appalachian region's plant contributed an additional
$0.4 million.
. Transportation revenue increased $0.7 million,
. Revenue from our brine treatment plants in the Appalachian region increased
$0.3 million.
Costs and Expenses. Excluding the selected items, total costs and expenses
-------------------
from operations increased $10.8 million, or 19%, due primarily to the following:
. Direct operating expense increased $1.7 million, or 7%, primarily as a
result of costs associated with the expansion of the Gulf Coast regional
office, both in staffing and office facilities. Additionally, we accrued
approximately $0.5 million more for incentive compensation during the first
nine months of 2000. In 1999, incentive compensation was accrued largely in
the fourth quarter.
. Exploration expense increased $4.5 million, or 61%, as a result of an
increase in dry hole costs primarily related to one high-cost dry hole in
the Gulf Coast this year ($1.4 million). Additionally, delay rental costs
increased mainly as a result of drilling delays in the Gulf Coast ($0.8
million), geological and geophysical costs were higher in both the
Appalachian and Western regions ($1.2 million), and higher costs were
incurred as a result of increased staffing in the Gulf Coast and Western
regions ($0.9 million).
. Depreciation, depletion and amortization expense decreased $3.0 million, or
7%, as a result of the decrease in natural gas and oil production.
. General and administrative expenses increased $1.6 million, or 12%,
primarily as a result of the increased costs associated with the new
corporate headquarters and as a result of legal costs related to certain
litigation settled in the third quarter.
. Taxes other than income rose $3.0 million, or 24%, as a result of higher
commodity prices realized this year.
Interest expense decreased $2.6 million as a result of a lower average
level of outstanding debt during the first nine months of 2000 when compared to
the first nine months of 1999.
Income tax expense increased $6.0 million due to the comparable increase in
earnings before income tax excluding the selected items.
-18-
<PAGE>
* * *
Forward-Looking Information
The statements regarding future financial performance and results and
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.
-19-
<PAGE>
PART II. OTHER INFORMATION
ITEM 6. Exhibits and Reports on Form 8-K
-----------------------------------------
(a) Exhibits
15.1 - Awareness letter of independent accountants.
27 - Article 5. Financial Data Schedule for Third Quarter 2000
Form 10-Q
(b) Reports on Form 8-K
None
-20-
<PAGE>
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 27, 2000 By: /s/ Paul F. Boling
--------------------
Paul F. Boling, Vice President - Finance
(Principal Executive Officer Duly Authorized
to Sign on Behalf of the Registrant)
By: /s/ Henry C. Smyth
--------------------
Henry C. Smyth, Controller
(Principal Accounting Officer)
-21-
