Cabot Oil & Gas Corporation
1200 Enclave Parkway
Houston, Texas 77077
Telephone: 281/589-4600
Facsimile: 281/589-4912
November 15, 1999May 2, 2000
Securities & Exchange Commission
450 Fifth Street, N.W.
Washington, D.C. 20549
RE: Cabot Oil & Gas Corporation Form 10-Q
for the quarter ending September 30, 1999Quarter Ended March 31, 2000
Ladies and Gentlemen:
On behalf of Cabot Oil & Gas Corporation, transmitted herewith for filing
under the Securities and Exchange Act of 1934, as amended, is a copy of the
Company's September 30, 1999March 31, 2000 Form 10-Q. Pursuant to Rule 302 of Regulation S-T, the
Form 10-Q has been executed by typing the name of the signature.
This filing has been effected through the Securities and Exchange
Commission's EDGAR electronic filing system.
Please contact the undersigned at (281) 589-4642 with any questions or
statements you may have regarding this filing.
Sincerely,
JILL RIBBECK
Manager, Financial Reporting
================================================================================
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, 1999March 31, 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 77077-1607
(Address of principal executive offices including Zip Code)
(281) 589-4600
(Registrant's telephone number)
15375 Memorial Drive, Houston, Texas 77079
(Former name, former address and former fiscal year,
if changed since last report)
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 29, 1999,April 28, 2000, there were 25,073,01624,981,394 shares of Class A Common Stock,
Par Value $.10 Per Share, outstanding.
================================================================================
CABOT OIL & GAS CORPORATION
INDEX TO FINANCIAL STATEMENTS
Page
----
Part I. Financial Information
PageItem 1. Financial Statements
Condensed Consolidated Statement of Operations for the
Three and Nine Months Ended September 30, 1999March 31, 2000 and 1998................1999.......................... 3
Condensed Consolidated Balance Sheet at September 30, 1999March 31, 2000
and December 31, 1998..................................................1999............................................... 4
Condensed Consolidated Statement of Cash Flows for the
Three and Nine Months Ended September 30, 1999March 31, 2000 and 1998................1999.......................... 5
Notes to Condensed Consolidated Financial Statements....................Statements................. 6
Report of Independent Accountant's Report on Review
of Interim Financial Information................................Information.................................... 9
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations....................Operations................... 10
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K................................. 208-K................................ 18
Signature ................................................................. 21................................................................ 19
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,MARCH 31,
2000 1999 1998 1999 1998
-------- --------
-------- --------
NET OPERATING REVENUES
Natural Gas Production......................Production........................ $ 39,50839,086 $ 32,740 $105,466 $105,21430,619
Crude Oil and Condensate.................... 4,805 2,146 11,297 6,394& Condensate........................ 4,325 2,650
Brokered Natural Gas Margin................. 905 1,095 2,844 3,580
Other....................................... 472 1,405 2,424 4,656Margin................... 1,451 883
Other......................................... 4,772 1,128
-------- --------
-------- --------
45,690 37,386 122,031 119,84449,634 35,280
OPERATING EXPENSES
Direct Operations........................... 8,502 7,529 24,111 22,026
Exploration................................. 2,993 7,195 7,433 13,574Operations............................. 8,511 7,847
Exploration................................... 3,233 2,425
Depreciation, Depletion and Amortization.... 13,797 11,086 41,592 31,169Amortization...... 12,648 12,979
Impairment of Unproved Properties........... 696Properties............. 960 1,257 2,649 3,064
General and Administrative.................. 4,918 4,919 13,635 16,244Administrative.................... 4,887 4,291
Taxes Other Than Income..................... 4,767 3,776 12,570 11,610than Income....................... 4,601 3,638
-------- --------
-------- --------
35,673 35,762 101,990 97,68734,840 32,437
Gain (Loss) on Sale of Assets........................ 4,044 77 5,019 133
-------- --------Assets................... (21) 1
-------- --------
INCOME FROM OPERATIONS........................ 14,061 1,701 25,060 22,290OPERATIONS.......................... 14,773 2,844
Interest Expense.............................. 6,506 4,423 19,674 13,256Expense................................ 5,971 6,718
-------- --------
-------- --------
Income/Income (Loss) Before Income Taxes............. 7,555 (2,722) 5,386 9,034Taxes............... 8,802 (3,874)
Income Tax Expense/Expense (Benefit).................. 3,025 (1,049) 2,338 3,730
-------- --------.................... 3,457 (1,432)
-------- --------
NET INCOME/INCOME (LOSS)............................. 4,530 (1,673) 3,048 5,304............................... 5,345 (2,442)
-------- --------
Dividend Requirement on Preferred Stock.......Stock......... 851 851 2,552 2,551
-------- --------
-------- --------
Net Income/Income (Loss) Applicable to
Common Stockholders.........................Stockholders........................... $ 3,6794,494 $ (2,524) $ 496 $ 2,753
======== ========(3,293)
======== ========
Basic Earnings/Earnings (Loss) Per Share
Applicable to Common Stockholders...........Common.......................... $ 0.150.18 $ (0.10) $ 0.02 $ 0.11(0.13)
Diluted Earnings/Earnings (Loss) Per Share
Applicable to Common Stockholders...........Common.......................... $ 0.150.18 $ (0.10) $ 0.02 $ 0.11(0.13)
Average Common Shares Outstanding............. 24,757 24,780 24,709 24,764Outstanding............... 24,798 24,666
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
Except Share Data)
SEPTEMBER 30,MARCH 31, DECEMBER 31,
2000 1999
1998
-------- ----------------- ---------
ASSETS
Current Assets
Cash and Cash Equivalents..............................Equivalents............................. $ 1,465836 $ 2,200
Restricted Cash (Note 3).............................. 36,812 --1,679
Accounts Receivable.................................... 51,414 55,799
Inventories............................................ 11,450 9,312
Other.................................................. 3,508 3,804
-------- --------Receivable................................... 49,356 50,391
Inventories........................................... 4,928 10,929
Other................................................. 2,289 3,641
--------- ---------
Total Current Assets................................ 104,649 71,11557,409 66,640
Properties and Equipment,
Net (Successful Efforts Method).... 587,707 629,908...................... 592,244 590,301
Other Assets............................................ 2,361 3,137
-------- --------
$694,717 $704,160
======== ========Assets........................................... 2,439 2,539
--------- ---------
$ 652,092 $ 659,480
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current Portion of Long-Term Debt......................Debt..................... $ 16,000 $ 16,000
Accounts Payable....................................... 55,890 66,628Payable...................................... 52,478 56,551
Accrued Liabilities.................................... 18,700 16,406
-------- --------Liabilities................................... 20,321 17,387
--------- ---------
Total Current Liabilities........................... 90,590 99,03488,799 89,938
Long-Term Debt.......................................... 319,000 327,000Debt......................................... 262,000 277,000
Deferred Income Taxes................................... 92,383 85,952Taxes.................................. 97,613 95,012
Other Liabilities....................................... 10,440 9,506Liabilities...................................... 12,232 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; 1,134,000 Shares
in 19992000 and 1998 (Note 7)...........................1999.................................... 113 113
Common Stock:
Authorized --- 40,000,000 Shares of $.10 Par Value
Issued and Outstanding - 25,068,87025,175,596 Shares and
24,959,89725,073,660 Shares in 2000 and 1999, and 1998, Respectively.... 2,518 2,507 2,496
Additional Paid-in Capital............................. 254,191 252,073256,215 254,763
Accumulated Deficit.................................... (70,123) (67,630)(63,014) (66,503)
Less Treasury Stock, at Cost:
302,600 Shares in 19992000 and 1998.....................1999..................... (4,384) (4,384)
-------- ----------------- ---------
Total Stockholders' Equity.......................... 182,304 182,668
-------- --------
$694,717 $704,160
======== ========191,448 186,496
--------- ---------
$ 652,092 $ 659,480
========= =========
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,MARCH 31,
2000 1999
1998 1999 1998
-------- -------- -------- ----------------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income/(Loss).................................................................. $ 4,530 $(1,673)5,345 $ 3,048 $ 5,304(2,442)
Adjustment to Reconcile Net Income/Income (Loss) to Cash
Provided by Operating ActivitiesActivities:
Depletion, Depreciation and Amortization..... 13,797 11,086 41,592 31,169Amortization....... 12,648 12,979
Impairment of Undeveloped Leasehold.......... 696Leasehold............ 960 1,257 2,649 3,064
Deferred Income Taxes........................ 7,233 864 6,431 5,442
GainTaxes.......................... 2,601 (1,472)
(Gain) Loss on Sale of Assets....................... (4,044) (77) (5,019) (133)Assets.................. 21 (1)
Exploration Expense.......................... 2,993 7,195 7,433 13,574
Other........................................ 415 105 1,672 1,383Expense............................ 3,233 2,425
Other.......................................... 517 741
Changes in Assets and LiabilitiesLiabilities:
Accounts Receivable.......................... (7,896) (2,527) 4,385 13,756
Inventories.................................. (3,219) (1,311) (2,138) (3,183)Receivable............................ 1,035 8,581
Inventories.................................... 6,002 1,338
Other Current Assets......................... 623 50 296 (2,082)Assets........................... 1,352 201
Other Assets................................. (55) (665) 776 (506)Assets................................... 100 626
Accounts Payable and Accrued Liabilities..... 12,167 3,191 (2,386) (3,135)Liabilities....... 443 (15,532)
Other Liabilities............................ 532 (68) 935 (748)
------- ------- ------- --------Liabilities.............................. 1,178 1,365
--------- ---------
Net Cash Provided by Operating Activities...................... 27,772 17,427 59,674 63,905
------- ------- ------- --------Activities... 35,435 10,066
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures............................. (19,617) (25,921) (60,980) (94,032)Expenditures............................... (18,945) (26,513)
Proceeds from Sale of Assets..................... 47,597 283 56,973 953
Restricted Cash.................................. (36,812) -- (36,812) --Assets....................... 1,523 1
Exploration Expense.............................. (2,993) (7,195) (7,433) (13,574)
------- ------- ------- --------Expense................................ (3,233) (2,425)
--------- ---------
Net Cash Used by Investing Activities.......... (11,825) (32,833) (48,252) (106,653)
------- ------- ------- --------Activities....... (20,655) (28,937)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Sale of Common Stock............................. 467 762 1,384 2,896
Treasury Stock Transactions...................... -- (4,309) -- (4,309)Stock............................... 1,231 187
Increase in Debt................................. 24,000 36,000 90,000 101,000Debt................................... 27,000 41,000
Decrease in Debt................................. (39,000) (17,000) (98,000) (51,000)Debt................................... (42,000) (21,000)
Dividends Paid................................... (1,853) (1,845) (5,541) (5,527)
------- ------- ------- --------Paid..................................... (1,854) (1,837)
--------- ---------
Net Cash Provided/Provided (Used) by
Financing Activities.......................... (16,386) 13,608 (12,157) 43,060
------- ------- ------- --------Activities....................... (15,623) 18,350
--------- ---------
Net Increase/(Decrease)Decrease in Cash
and Cash Equivalents.............................. (439) (1,798) (735) 312Equivalents................................ (843) (521)
Cash and Cash Equivalents,
Beginning of Period............................... 1,904 3,894Period................................. 1,679 2,200
1,784
------- ------- ------- ----------------- ---------
Cash and Cash Equivalents,
End of Period.....................................Period....................................... $ 1,465836 $ 2,096 $ 1,465 $ 2,096
======= ======= ======= ========1,679
========= =========
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, consisting only of normal recurring
adjustments, necessary for a fair presentation.
In June 1998, the Financial Accounting Standards Board 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 Financial
Accounting Standards Board 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. We haveThe Company has not yet completed ourits evaluation of the impact of
the provisions of SFAS 133.
2. PROPERTIES AND EQUIPMENT
Properties and equipment are comprised of the following:
SEPTEMBER 30,MARCH 31, DECEMBER 31,
2000 1999 1998
---------- ----------
(In thousands)
Unproved Oil and Gas Properties......................... $ 41,42235,038 $ 42,42632,262
Proved Oil and Gas Properties........................... 877,970 921,463912,631 906,852
Gathering and Pipeline Systems.......................... 123,927 121,999125,163 124,708
Land, Building and Improvements......................... 4,176 4,2004,349 4,359
Other................................................... 22,589 20,46823,658 23,206
---------- ----------
1,070,084 1,110,5561,100,839 1,091,387
Accumulated Depreciation, Depletion and Amortization.... (482,377) (480,648)(508,595) (501,086)
---------- ----------
$ 587,707592,244 $ 629,908590,301
========== ==========
3. RESTRICTED CASH
Restricted cash consists of cash held in an escrow account as a provision
of the tax-deferred exchange transaction in which we sold certain producing
assets in the Appalachian Region and purchased certain oil and gas properties in
the Rocky Mountains area of the Western Region. In November 1999, after the end
of the required waiting period, $28.6 million was withdrawn from this escrow
account and used to reduce the balance on our revolving credit facility. We
intend to use $8.3 million of the escrowed cash to complete a purchase that we
are currently negotiating. This transaction involves oil and gas properties
located in the Rocky Mountains area. We expect to close this transaction and
terminate the escrow account before year-end.
6
4. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
SEPTEMBER 30,MARCH 31, DECEMBER 31,
2000 1999
1998
-------- ------------------ ----------
(In thousands)
Accounts Receivable
Trade Accounts..................................Accounts......................................... $ 42,09744,769 $ 41,39744,739
Joint Interest Accounts......................... 2,268 6,712Accounts................................ 3,552 4,395
Insurance Recoveries............................ 1,242 5,539Recoveries................................... -- 1,177
Current Income Tax Receivables.................. 4,513 502Receivable.......................... 111 111
Other Accounts.................................. 1,571 2,123Accounts......................................... 1,218 263
-------- --------
51,691 56,27349,650 50,685
Allowance for Doubtful Accounts.................. (277) (474)Accounts......................... (294) (294)
-------- --------
$ 51,41449,356 $ 55,79950,391
======== ========
6
MARCH 31, DECEMBER 31,
2000 1999
---------- ----------
(In thousands)
Accounts Payable
Trade Accounts..................................Accounts......................................... $ 10,5359,736 $ 13,22912,195
Natural Gas Purchases........................... 16,410 17,031Purchases.................................. 14,481 14,918
Wellhead Gas Imbalances......................... 2,169 1,945Imbalances................................ 2,199 2,177
Royalty and Other Owners........................ 13,083 8,987Owners............................... 11,740 11,316
Capital Costs................................... 8,214 20,165Costs.......................................... 8,230 10,103
Dividends Payable...............................Payable...................................... 851 851
Taxes Other Than Income......................... 1,534 1,017Income................................ 1,126 1,279
Drilling Advances............................... 925 900Advances...................................... 1,290 614
Other Accounts.................................. 2,169 2,503Accounts......................................... 2,825 3,098
-------- --------
$ 55,89052,478 $ 66,62856,551
======== ========
Accrued Liabilities
Employee Benefits...............................Benefits...................................... $ 3,1553,611 $ 4,4795,203
Taxes Other Than Income......................... 8,956 7,357Income................................ 8,927 8,471
Interest Payable................................ 5,242 2,406Payable....................................... 6,040 2,780
Other Accrued................................... 1,347 2,164Accrued.......................................... 1,743 933
-------- --------
$ 18,70020,321 $ 16,40617,387
======== ========
Other Liabilities
Postretirement Benefits Other Than Pension......Pension............. $ 644868 $ 316799
Accrued Pension Cost............................ 6,000 4,941Cost................................... 6,422 6,290
Taxes Other Than Income and Other............... 3,796 4,249Other...................... 4,942 3,945
-------- --------
$ 10,44012,232 $ 9,50611,034
======== ========
5.4. LONG-TERM DEBT
At September 30, 1999, Cabot Oil & Gas CorporationMarch 31, 2000, the Company had $187$130 million outstanding under its revolving
credit facility, which provides for an available credit line of $250 million. In November 1999, $28.6 million was withdrawn from
the restricted cash account to be used to reduce the outstanding balance. See
further discussion in Note 3.
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.assets of the
Company. The revolving term under this credit facility presently ends in
December 2003 and is subject to renewal.
7
6.5. EARNINGS (LOSS) PER SHARE
Basic earnings (loss) per share for the first ninethree months of the year were
based on the year-to-date weighted average shares outstanding of 24,708,80724,797,986 in
19992000 and 24,764,17724,666,431 in 1998.1999. Diluted earnings/earnings (loss) per share were the same as
basic earnings per share in all periods presented. The diluted earnings (loss)
per share amounts are based on weighted average shares outstanding plus common
stock equivalents. Common stock equivalents include both stock awards and stock
options, and totaled 352,132213,525 in 19992000 and 321,169171,586 in 1998.
7. PREFERRED STOCK
In October 1999, we entered into an agreement1999.
7
6. ENVIRONMENTAL LIABILITY
The EPA notified the Company in February 2000 that it might have potential
liability for waste material disposed of at the Casmalia Superfund Site
("Site"), located on a 252-acre parcel in Santa Barbara County, California. Over
10,000 separate parties disposed of waste at the Site while it was operational
from 1973 to repurchase1989. The EPA stated that federal, state and local governmental
agencies along with the 1,134,000
shares of our 6% convertible redeemable preferred stock outstanding.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 purchase priceEPA is $51.6 million plus accrued dividends. We are evaluating a
variety of sources from which to fund this transaction. We may sell common stock
or use other instruments under our universal shelf registration. The transaction
may also takepursuing the form of an exchangeowner(s) /
operator(s) of the preferred stockSite 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 mutually
agreed upon numberperiod from 1976 to 1979.
The Company has a reserve that it believes to be adequate to cover this
potential environmental liability based on its assessment of Cabot Oil & Gas Corporation common shares. The valuethe most likely
outcome of this preferred stock as recorded on our balance sheet is $56.7 million.
Accordingmatter. While the potential impact to the agreement,Company may materially
affect the quarterly or annual financial results, management does not believe it
would materially impact the Company's financial position. The Company will
continue to monitor the facts and its assessment of its liability related to
this transaction is to be closed by November 1,
2000. Upon repurchase, we intend to retire the preferred stock.claim.
8
INDEPENDENT ACCOUNTANT'S REPORTReport 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 March 31, 2000, and the
related condensed consolidated statements of operations and cash flows of Cabot
Oil & Gas Corporation (the "Company") as of September 30, 1999, and for the
three-monththree month periods ended March 31, 2000 and nine-month periods then ended.March 31, 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 financial statements
for them to be in conformity with accounting principles generally accepted accounting principles.in
the United States.
We have previously audited in accordance with generally accepted auditing
standards, the consolidated balance sheet as of December 31, 1998,1999, 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 26, 1999,11, 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, 1998,1999, 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 21, 1999April 25, 2000
9
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OEPRATIONSOPERATIONS
The following review of operations for the first nine monthsquarter of 19992000 and 19981999
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, 1998.1999.
OVERVIEW
Despite an improvement in realized natural gas prices duringIn the thirdfirst quarter of 1999, our average price2000, we realized higher prices for the first nine months of the year
remained below the 1998 level. However, an increase inboth natural
gas and oil
production, along with higher oil prices, resulted in a $2.2oil. Our net revenues for the quarter increased $14.4 million, increase in
net revenues. The rise in depreciation, depletionor 41%,
and amortization (DD&A) and
interest expense, partially offset by the gain on the sale of non-strategic
assets, largely contributed to the reduction in net income increased $7.8 million, mainly as a result of $2.3 million from
1998. Operating cashthis improved price
environment. Cash flows were similarly impacted, declining $4.2improving by $25.4 million due
largely to higher interest expenses and changesover
last year.
Our first quarter net income was $4.5 million, or $0.18 per share,
including the net benefit resulting primarily from a contract settlement. This
selected item increased net income by $1.7 million, or $0.07 per share, in working capital.
Cabot Oil & Gasthe
first quarter of 2000. Excluding this selected item, our first quarter 2000 net
income was $2.8 million, or $0.11 per share.
We drilled 4925 gross wells with a success rate of 86% in the
first nine months of 199988% compared to 15115 gross
wells and an 88%80% success rate in the first nine months of 1998. Total capital expenditures were $61.0 million for
the first nine months of 1999, compared to $111.2 million for the comparable
period in 1998. We reduced the 1999 capital and exploration expenditures in
response to the weak energy price environment in the fourth quarter of 1998 and
in early 1999. However, we front-end loaded the 1999 development and exploration
plan to maximize production from this year's drilling program and to provide
more flexibility to drill more wells should cash flows improve later in the
year. Accordingly, we have increased our 1999 capital and exploration
expenditure budget by approximately $35 million in response to the improving
natural gas prices during the third quarter. For the full year,
Cabot Oil & Gas
now planswe plan to drill approximately 78110 gross wells and spend approximately $80.5$88.9
million in capital and exploration expenditures. This isexpenditures compared to 20573 gross wells and
$225.9$88.1 million of capital and exploration expenditures in 1998,
including $70.11999. Total
expenditures were $20.3 million for the southern Louisiana properties acquired from Oryx
Energy Company (the Oryx Acquisition).first quarter of 2000, compared to $18.3
million for the comparable period in 1999.
Natural gas production was 50.115.2 Bcf, for the first nine months of 1999, up
1.5down 0.9 Bcf compared to the 1999
first nine months of 1998.quarter. This production increasedecline was due primarily to production from Oryx Acquisition, as well as new production
brought on by the 1998 drilling programsale of
205 gross (143.7 net) wells.
During 1999, we entered into several property sales intended to high grade
our reserve base. Most recently,non-strategic producing assets in September 1999, we sold Appalachia
properties with reservesthe Appalachian region during the third
quarter of 58.8 Bcfe for $46.3 million to Enervest Management
Company. Of the proceeds from the divestiture of these non-strategic properties,
we used $8.8 million to purchase of proved reserves adjacent to our existing
properties in Wyoming's Green River Basin and we withdrew $28.6 million to
reduce debt in November 1999. By year-end, we expect to use $8.3 million to fund
a purchase of oil and gas assets that we are currently negotiating. However, we
have not yet signed a purchase and sale agreement and therefore, it is possible
that the transaction may not occur. Additionally, we sold other non-strategic
properties in several smaller transactions. In total, the 1999 asset sales
resulted in a gain of $5 million. These actions eliminated approximately 22% of
our total well count but reduced our production by only 6%, or 13 MMcfe/d.
Despite this reduction in well count, we expect the full year production for
1999 to be 5% higher than in 1998.
Our strategic pursuits are sensitive to energy commodity prices,
particularly the price of natural gas. As a result of unseasonably warm weather
during the winter of 1999, our realized gas price for the first quarter of 1999
($1.91 per 1.91/Mcf) was the lowest quarterly price since 1995. DuringHowever, in the secondfirst
quarter gas prices began to
recover with an averageof 2000, market conditions had improved significantly and our realized
gas price of $2.08 per $2.56/Mcf forwas the secondhighest first quarter and rose to $2.32 per Mcf in the third quarter. Asprice since 1997. Based on
this history of September 30,
1999, the year-to-date average price was $2.10 per Mcf, down 3% from last year.
With the continued pricemarket volatility, experienced in the past several years, there is considerable uncertainty about the
future level of natural gas prices.
10
prices for the remainder of this year and beyond.
We remain focused on our strategies to grow throughof growth from the drill bit,
from
synergistic acquisitions and fromthe exploitation of our marketing abilities.
We
believeManagement believes that these strategies are appropriate in the current
industry environment, enabling usCabot Oil & Gas to add shareholder value over the
long term.long-term.
The preceding paragraphs, discussing Cabot Oil & Gas Corporation'sour strategic pursuits and goals,
contain forward-looking information. See Forward-Looking Information on page 19.17.
FINANCIAL CONDITION
CAPITAL RESOURCES AND LIQUIDITY
Our capital resources consist primarily of cash flows from our oil and gas
properties and asset-based borrowingborrowings supported by our oil and gas reserves. OurThe
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.
Natural gas prices were unseasonably low during muchOur primary source of 1998 and into the first
four months of 1999.
The primary sources of cash for Cabot Oil & Gas Corporation during the first nine monthsquarter of 1999 were2000 was from funds
generated from operations andoperations. Other sources of cash included proceeds from asset
sales and the saleexercise of non-strategic oil and gas properties. Primary uses of cash were
fundsstock options. Cash was primarily used forto fund
exploration and development expenditures, to reduce debt and to pay dividends.
We had a net cash outflowsoutflow of $0.7$0.8 million in the nine months ended September
30, 1999.first quarter of 2000. Net
cash inflow from operating activities was $59.7totaled $35.4 million through
September 1999,in the current
quarter, substantially funding substantially all ofboth the $61.0$15 million debt reduction and the $22.2
million of capital and exploration expenditures.
The year-to-date cash proceeds from asset sales of
$20.2 million provided funds used to reduce debt and pay dividends. Although we
recorded proceeds from the sale of non-strategic properties of $57 million,
$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. In November 1999, after meeting the
requirements of the tax-deferred exchange, $28.6 million was withdrawn from this
escrow account to be used to reduce the outstanding balance on our revolving
credit agreement. We intend to use the remaining $8.3 million from the escrow
account to fund a purchase of certain oil and gas properties by year-end subject
to the completion of a purchase and sale agreement.10
NINETHREE MONTHS ENDED SEPTEMBER 30,MARCH 31,
2000 1999 1998
------ ------
(In millions)
Cash Flows Provided by Operating Activities..............Activities............ $ 59.735.4 $ 63.910.1
====== ======
Cash flows from operating activities in the 2000 first nine monthsquarter were $25.3
million higher than the corresponding quarter of 1999 were
lower by $4.2 million compared to the corresponding period of 1998 primarily due to lowerhigher
natural gas prices, higher interest expense andfavorable changes in working capital.capital and the cash received
on the settlement of a gas contract dispute.
NINETHREE MONTHS ENDED SEPTEMBER 30,MARCH 31,
2000 1999 1998
------ ------
(In millions)
Cash Flows Used by Investing Activities..................Activities................ $ 48.3 $106.720.7 $ 28.9
====== ======
Cash flows used by investing activities in the first nine monthsquarters of 1999
were attributable to capital2000 and
exploration expenditures of $68.4 million,
offset by the receipt of $20.2 million in net cash proceeds received from the
sale of non-strategic oil and gas properties. Of the $36.8 million in proceeds
that remained in escrow at September 30, 1999 $28.6 million was withdrawn in
11
November to reduce debt, and $8.3 million is intended to be used to purchase
certain oil and gas properties in the fourth quarter. Cash flows used by
investing activities in the first nine months of 1998 were substantially attributable to capital and exploration expenditures of
$107.6$22.2 million offset
by the receipt of $1.0and $28.9 million, in proceedsrespectively. Proceeds from the sale of certain
oil and gas properties.properties in the first quarter of 2000 were $1.5 million.
NINETHREE MONTHS ENDED SEPTEMBER 30,MARCH 31,
2000 1999 1998
------ ------
(In millions)
Cash Flows Provided (Used) by Financing Activities....... $(12.2)Activities..... $(15.6) $ 43.118.3
====== ======
Cash flows used by financing activities in the first nine monthsquarter of 1999
were attributable2000
included $15 million used to a decrease inreduce borrowings on our revolving credit facility,
combined withfacility.
In the paymentsame period of $5.6 million in dividends during the period. In
1998,1999, cash flows provided by financing activities were
primarily increases in borrowings on our revolving credit facility, andfacility. These funds
were used largely to partially fund capital and exploration expenditures. During the first nine months of 1998,
these expenditures included $5 million for leasehold acquisitions as part of
Cabot Oil & Gas Corporation's joint exploration program with Union Pacific
Resources Group, Inc. as well as $6.6 million for the purchase of 9.3 Bcfe of
proved reserves in the Mid-Continent during the second quarter.1999.
The available credit line under our revolving credit facility, with a group
of banks is currently
$250 million. This amountmillion, 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 banks'bank's petroleum engineer) and other assets. The revolving term of the
credit facility runs to December 2003. We
believeManagement believes that we have the
ability to finance, if necessary, our capital requirements, including
acquisitions.
Our 2000 interest expense for 1999 is projected to be approximately $25.7$23.3 million.
In May 2000, a $16 million principal payment is due on the 10.18% Notes. This
amount is reflected as "Current Portion of Long-Term Debt" on ourthe balance sheet.
This payment is expected to be made with cash from operations and, if necessary,
from increased borrowings under our revolving credit
facility.
YEAR 2000 (Y2K)
Many computer systems have been built using software that processes
transactions using two digits to represent the year. This type of software will
generally require modifications to function properly with dates after December
31, 1999 or to become Y2K Compliant. The same issue applies to microprocessors
embedded in machinery and equipment, such as gas compressors and pipeline
meters. The impact of failing to identify those computer systems (operated
either by us or by our business partners) that are not Y2K compliant and correct
the problem could be significant to our ability to operate and report results,
as well as potentially expose us to third-party liability.
We have begun making the necessary modifications to our computer systems
and embedded microprocessors in preparation for the year 2000. This project is
on schedule and we believe that the total related costs will be approximately
$2.1 million, funded by cash from operations or borrowings on the revolving credit facility, when completed in 1999. Of the total project cost, $1.8 million
is attributable to the purchase of new software and equipment that will be
capitalized. The remaining $0.3 million is being expensed and is not expected to
have a material impact on our financial position or operating results. To date,
we have incurred $0.2 million of expense which was all recorded in 1998, and
$1.8 million in capital cost, $1.6 million of which was incurred this year.
We have reviewed the compliance of field equipment including compressor
stations, gas control systems and data logging equipment. Most equipment
reviewed was found to be compliant, and, where necessary, microprocessor chips
were replaced at a total cost of less than $0.1 million.
Additionally, we have contacted our significant customers and suppliers in
order to determine our exposure to their potential failure to become Y2K
compliant. Although we are not aware of any Y2K compliance problems with any of
our customers or suppliers, there can be no guarantee that the systems of these
companies will operate without interruption in the new millennium.
13facility.
11
Cabot Oil & Gas has an internal committee that not only identifies and
responds to these issues, but also is developing a contingency plan in the event
that a significant problem arises after the turn of the century. Contingency
plans for key operational areas have been established and will continue to be
reviewed during the fourth quarter. Additionally, we have engaged outside
consultants to review our plans and provide feedback relating to the status of
the plan implementation. At this time, we do not anticipate that the arrival of
the year 2000 will materially impact our financial position or results of
operations.
The project costs and timetable for Y2K compliance are based on our best
estimates. In developing these estimates, assumptions were made regarding future
events including, among other things, the availability of certain resources and
the continued cooperation of our customers and suppliers. Actual costs and
timing may differ from our estimates due to unexpected difficulties in obtaining
trained personnel, locating and correcting relevant computer code and other
factors.
CAPITALIZATION
Capitalization information on Cabot Oil & Gas is as follows:
SEPTEMBER 30,MARCH 31, DECEMBER 31,
2000 1999
1998
------- --------------- --------
(In millions)
Long-Term Debt.................................Debt...................................... $ 319.0262.0 $ 327.0277.0
Current Portion of Long-Term Debt..............Debt................... 16.0 16.0
------- -------
Total Debt.................................. 335.0 343.0Debt........................................ 278.0 293.0
------- -------
Stockholders' Equity
Common Stock (Net(net of Treasury Stock).......... 125.6 126.0............... 134.7 129.8
Preferred Stock...............................Stock.................................... 56.7 56.7
------- -------
Total....................................... 182.3 182.7Total............................................. 191.4 186.5
------- -------
Total Capitalization...........................Capitalization................................ $ 517.3469.4 $ 525.7479.5
======= =======
Debt to Capitalization......................... 64.8% 65.2%Capitalization.............................. 59.2% 61.1%
During the first nine monthsquarter of 1999,2000, we paid dividends of $3.0$1.0 million on the
Common Stock and $2.6$0.9 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, 1999,March 31, 2000, to be paid NovemberMay 26, 1999,2000 to shareholders of record
as of November 12, 1999.May 19, 2000.
We have entered into an agreement with the holdersholder of our preferred stock to
repurchase theirits preferred shares by November 1, 2000. As outlined in the
agreement, the preferred shares, thatwhich are recorded on our balance sheet for
$56.7 million, will be repurchased for $51.6 million. Cash flow from operations,
additional borrowings or proceeds from the sale of equity may be used to fund
this transaction. If both parties agree, the transaction could also be settled
by exchanging a mutually agreed upon number of shares of our common stock for
theirits preferred shares.
See Note 7 toDuring the financial statements.first quarter of 2000, we reduced the balance on our revolving
credit facility by $15 million. The decrease in debt was largely attributable to the fact thatincreased cash flow from operations substantially coveredin the
first quarter of 2000 provided the necessary cash required for capital expenditures.
Therefore, cash proceeds from assets sales were available to reduce the level ofthis debt outstanding.reduction.
CAPITAL AND EXPLORATION EXPENDITURES
On an annual basis, we generally fund most of our capital and exploration
activities, excluding major oil and gas property acquisitions, with cash
generated from operations. Weoperations, and budget such capital expenditures based upon
our
projected cash flows for the year.
13
The following table presents major components of capital and exploration
expenditures:
NINETHREE MONTHS ENDED SEPTEMBER 30,MARCH 31,
2000 1999 1998
------ ------
(In millions)
Capital Expenditures
Drilling and Facilities.....................Facilities.......................... $ 32.115.1 $ 72.011.6
Leasehold Acquisitions...................... 6.0 12.7Acquisitions........................... 0.9 2.2
Pipeline and Gathering ..................... 3.0 3.3
Other....................................... 2.6.......................... 0.4 0.4
Other............................................ 0.7 1.7
------ ------
43.7 89.717.1 15.9
Exploration Expenses............................... 3.2 2.4
------ ------
Proved Property Acquisitions................ 9.9 7.9
Exploration Expenses.......................... 7.4 13.6
------ ------
Total.......................................Total............................................ $ 61.0 $111.220.3 $ 18.3
====== ======
12
Total capital and exploration expenditures in the first nine monthsquarter of 1999
decreased $50.22000
increased $2.0 million compared to the same periodquarter of 1998,1999, primarily as a
result of this year's reducedincreased drilling program. In the third quarter of 1999, we
purchased oil and gas propertiesactivity.
We plan to drill 110 gross wells in the Blue Forest Unit of the Moxa Arch2000 compared with 73 gross wells
drilled in the
Rocky Mountains area. These properties included 18 wells and 10.3 Bcfe of proved
reserves. Additionally,1999. This 2000 drilling program includes $88.9 million in the first quarter of 1998, we made an initial
expenditure of $5 million for leasehold acquisitions as part of our joint
exploration program with Union Pacific Resources Group, Inc. In the second
quarter of 1998, we also purchased 9.3 Bcfe of proved reserves in the
Mid-Continent for $6.6 million.
In reaction to lower energy commodity prices, the 1999 budgetedtotal
capital and exploration expenditures, are down 53% compared to 1998 expenditures after
excluding proved property acquisitions. Since March 31, 1999, our Board of
Directors has approved increasesup from $88.1 million in the 1999 capital and exploration
expenditures budget from $44.9 million to $80.5 million. This new plan1999. Expected
spending in 2000 includes $43.5$49.1 million for drilling and facilities $12.2and $25.2
million in exploration expenses. In addition to the drilling and exploration
program, other 2000 capital expenditures are planned primarily for exploration
expenses,lease
acquisitions and $4.2 million for pipelines. Cabot Oil & Gas plans to drill 78
gross wells in 1999 compared with 205 gross wells drilled in 1998.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.
GAS AND OILCOMMODITY PRICE SWAPS
From time to time, we enter into natural gas and crude oil swap agreements a type of
derivative instrument,
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 or
crude oil in exchange for paying a variable price based on a market-based index,
such as the NYMEX gas and crude oil futures. Notional quantities ofWe did not enter into any natural
gas are used in each price swap, since no physical exchange or delivery
of natural gas is involved. During the first nine months of 1999, we fixed the
price at an average of $2.32 per MMbtuswaps on quantities totaling 2,420,000 MMbtu,
representing 4% of the natural gasour production for the period. A lossfirst quarter of $0.4
million was recorded from these price swaps during the first nine months of
1999.
During the first nine months of 1999, we entered into an oil swap agreement
in order to hedge risk on a portion of our production.2000. The notional
volume of this transactionthe crude oil swap transactions was 62,000 barrels182,000 Bbls at aan average price
of $20.65$22.25 per Bbl, which represents less than 9%most of our total oil production for the
first nine months
1999. Additionally, we have an outstanding swap on 60,000 barrels of ourquarter. We did not enter into any fixed price swaps to hedge oil or natural gas
production for the monthfirst quarter of October at $20.65 per barrel. At September 30, 1999,
we had recorded a loss of less than $0.1 million on the closed contract and had
an unrealized loss on this open contract of $0.2 million.1999.
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.
14
During the first nine monthsquarters of 2000 and 1999 we entered into price swaps with
total notional quantities of 2,795,000 MMbtu1,164,800 and 670,000 Mmbtu, respectively, related
to our brokered activities representing approximately 7%8% and 4%, respectively, of our total
volume of brokered natural gas sold.
A gainAs of less than $0.1 million was recorded from these price swaps during the first nine months of 1999.
At September 30, 1999,period ended March 31, 2000, we had open natural gascommodity price swap
contracts on our brokered activity as follows:
Swap Purchases
--------------------------------------------Natural Gas Price Swaps
---------------------------------------------
Volume Weighted Unrealized
in Average Gain Gain/(Loss)
Period MMBtuMmbtu Contract Price ($ Millions)(in $ millions)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
1999 3,155,800 $2.59Natural Gas Price Swap on Brokered Transactions
- -----------------------------------------------
Second Quarter 2000.................. 300,000 $2.57 $ (0.2)
1st(0.0)
Financial derivatives related to natural gas added revenues of $20,000 in
the first quarter of 2000 and reduced revenue by $91,000 in the same period of
1999.
13
We had open oil price swap contracts on our production at March 31, 2000,
as follows:
Oil Price Swaps
------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Bbls Contract Price (in $ millions)
- --------------------------------------------------------------------------------
Oil Price Swaps on Our Production
- ---------------------------------
Second Quarter 2000 450,000 2.13 (0.2)2000............. 182,000 $23.08 $(0.6)
Financial derivatives related to crude oil reduced revenue by $1.2 million
during the first quarter of 2000. There were no crude oil price swaps
outstanding at March 31, 1999.
We are exposed to market risk on these open contracts, to the extent of
changes in market prices of natural gas.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 natural gascommodity that is hedged.
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
monthsquarter of 2000 was up 34% over 1999, was down 3% overafter declining 16% from the comparable periodfirst quarter
of 1998.1998 to 1999. The volatility of natural gas prices in recent years remains
prevalent in 19992000 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 suchthese variables, there
can be no assurancewe 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 paragraphsparagraph contains forward-looking information. See
Forward-Looking Information on page 19.
1517.
14
RESULTS OF OPERATIONS
For the purpose of reviewing Cabot Oil & Gas Corporation'sour results of operations, "Net Income/(Loss)"
is defined as net income or loss applicableavailable to common shareholders.
SELECTED FINANCIAL AND OPERATING DATA
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------- ----------------MARCH 31,
2000 1999 1998 1999 1998
------ ------
------ ------
(In millions, except where noted)
Net Operating Revenues.....................Revenues......................... $ 45.735.3 $ 37.4 $122.0 $119.840.8
Net Operating Expenses......................... 35.7 35.8 102.0 97.7Revenues......................... $ 49.6 $ 35.3
Operating Income........................... 14.1 1.7 25.1 22.3Expenses............................. 34.8 32.4
Operating Income............................... 14.8 2.8
Interest Expense........................... 6.5 4.4 19.7 13.3Expense............................... 6.0 6.7
Net Income/Income (Loss).......................... 3.7 (2.5) 0.5 2.8
Earnings/.............................. 4.5 (3.3)
Earnings (Loss) Per Share - Basic..........Basic.............. $ 0.15 $(0.10) $ 0.02 $ 0.11
Earnings/0.18 $(0.13)
Earnings (Loss) Per Share - Diluted........Diluted............ $ 0.15 $(0.10) $ 0.02 $ 0.110.18 $(0.13)
Natural Gas Production (Bcf)
Appalachia................................... 4.5 5.6
West......................................... 7.3 7.4
Gulf Coast............................ 4.2 2.7 11.7 9.0
West.................................. 7.6 7.9 22.3 23.0
Appalachia............................ 5.3 5.9 16.1 16.6
------ ------Coast................................... 3.4 3.1
------ ------
Total Company......................... 17.1 16.5 50.1 48.6Company................................ 15.2 16.1
====== ======
Natural Gas Production Sales Prices ($/Mcf)
Appalachia................................... $ 3.07 $ 2.25
West......................................... $ 2.26 $ 1.71
Gulf Coast............................Coast................................... $ 2.492.55 $ 2.071.75
Total Company................................ $ 2.17 $ 2.21
West.................................. $ 2.14 $ 1.792.56 $ 1.91
$ 1.90
Appalachia............................ $ 2.43 $ 2.19 $ 2.33 $ 2.51
Total Company......................... $ 2.32 $ 1.98 $ 2.10 $ 2.16
Crude/Condensate
Volume (MBbl)......................... 237 174 705 471(Mbbl)................................ 195 230
Price ($/Bbl)......................... $20.23 $12.35 $16.04 $13.58................................ $22.19 $11.53
Brokered Natural Gas Margin
Volume (Bcf).......................... 13.8 10.4 36.7 29.8................................. 13.9 12.7
Margin ($/Mcf)........................ $ 0.07............................... $ 0.10 $ 0.080.07
The table below presents the after-tax effect of a selected item on our
results of operations for the three months ended March 31, 2000.
(In millions, except per share amounts) Amount per share
- ------------------------------------------------------------------------
Net Income Before Selected Items.................... $ 0.122.8 $0.11
Benefit from miscellaneous net revenue (1)........ 1.7 0.07
-----------------
Net Income........................................ $ 4.5 $0.18
=================
(1) Represents net benefit, primarily from a contract settlement.
THIRDThis selected item impacted our first quarter financial results. Because it
is not a part of our normal business, we have isolated its effect in the table
above. This selected item represents miscellaneous net revenue, primarily from
the settlement of a natural gas sales contract. There were no selected items in
the first quarter of 1999. The discussion below excludes the impact of the
selected item.
15
FIRST QUARTERS OF 2000 AND 1999 AND 1998 COMPARED
NET INCOME AND REVENUES.Net Income and Revenues. We reported net income before the selected items
in the thirdfirst quarter 1999
of $3.72000 of $2.8 million, or $0.15$0.11 per share. During the
corresponding quarter of 1998,1999, we reported a net loss of $2.5$3.3 million, or $0.10$0.13
per share. Operating revenues increased by $8.3$11.5 million or 22%, whileand operating income
increased by $12.4$9.2 million. Natural gas production made up 86%84%, or $39.5$39.1 million, of net
operating revenue. A 17%The increase in net operating revenues was driven primarily
by a 34% improvement in the average natural gas price, offset slightly by a 6%
decrease in natural gas production as discussed below. Net income and operating
income were similarly impacted by the increase in the average natural gas price and a 64% increase in
our average oil price drove the increase in net operating revenues. The
improvements in commodity prices similarly impacted net income and operating
income as did the $4.0 million gain on the sale of non-strategic properties.
16
price.
Natural gas production volume in the Gulf Coast Regionregion was up 1.50.3 Bcf, or
10%, to 4.23.4 Bcf primarily due to production from the December 1998 Oryx Acquisitionacquisition, and
recent discoveries and development in the Kacee field in South Texas.south Texas in 1999. Natural
gas production volume in the Western Regionregion was down 0.30.1 Bcf to 7.67.3 Bcf
primarily due to lower
levels ofa decrease in drilling activity in the Mid-Continent area
during 1998 and 1999. Natural gas production volume in the Appalachian Regionregion was down
0.61.1 Bcf to 5.34.5 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. The decline in total natural gas production of 0.9 Bcf, or 6%, reduced
revenue by $1.5 million in the first quarter of 2000.
The average Gulf Coast natural gas production sales price rose $0.80 per
Mcf, or 46%, to $2.55, increasing net operating revenues by approximately $2.7
million. In the Gulf Coast Region,Western region, the average natural gas production sales price
increased $0.42$0.55 per Mcf, or 20%32%, to $2.49,$2.26, increasing net operating revenues by
$1.8 million on 4.2 Bcf of production. In the Western Region, the average
natural gas production sales price increased $0.35 per Mcf, or 20%, to $2.14,
increasing net operating revenues by $2.7 million on 7.6 Bcf of production.approximately $3.7 million. The average Appalachian natural gas production sales
price increased $0.24$0.82 per Mcf, or 11%36%, to $2.43,$3.07, increasing net operating
revenues by $1.3 million on 5.3 Bcf
of production.approximately $3.6 million. The overall weighted average natural gas
production sales price increased $0.34$0.65 per Mcf, or 17%34%, to $2.32.
The volume of crude oil sold in the third quarter of the year increased by
63 Mbbl, or 36%, to 237 Mbbl,$2.56, increasing net operating
revenues by $0.8$10.0 million.
The volume increase was largely due to production from the Oryx Acquisition.
Crude oil prices increased $7.88rose $10.66 per Bbl, or 64%92%, to $20.23,$22.19, resulting in an
increase to net operating revenues of approximately $1.9$2.1 million. Our realized
oil price was impacted by the $1.2 million revenue reduction that resulted from
price swap activity as discussed in the Commodity Price Swaps section of this
document. In addition, the volume of crude oil sold in the quarter decreased by
35 Mbbls, or 15%, to 195 Mbbls, reducing net operating revenues by $0.4 million.
The brokered natural gas margin decreased $0.2increased $0.6 million to $0.9 million
primarily due to$1.5 million. The
primary cause was a $0.03 per Mcf orimprovement to net margin that resulted in a
$0.5 million decreaserevenue increase. Additionally, we realized a 1.2 Bcf volume
improvement, resulting in a $0.1 million increase in brokered natural gas
margin.
Excluding the selected item regarding the net margin to
$0.07 per Mcf. Offsetting this margin reduction, the quarterly volume of
brokered gas increased 32%, or 3.4 Bcf, contributing $0.3 million to revenue.
Othersettlement on a contract
dispute, other net operating revenues decreased $0.9increased $0.8 million to $0.5 million due
primarily to$1.9 million.
This improvement was a reductionresult of changes in revenues fromactivity in the monetized value of thefollowing areas:
- Transportation revenue rose $0.6 million.
- A new natural gas liquids plant in Appalachia contributed an
additional $0.4 million.
- Section 29 tax credits on certain tight sands wells and lower sales of natural gas liquids.revenues decreased slightly due to normal production
decline.
Costs and Expenses. Total costs and expenses from operations decreased $0.1increased
$2.4 million in the thirdfirst quarter of 19992000 compared to the same quarter of 1998.1999.
The primary reasons for this fluctuation are as follows:
- Direct operating expense increased $1.0$0.7 million, or 13%, as a result
of the incremental cost of operating the properties from the December
1998 Oryx Acquisition.
- Exploration expense decreased $4.2 million, or 58%8%, primarily as a
result of a reduction in dry hole costs from the 1998 third quarter.
Although both the third quarters of 1998 and 1999 included three
exploratory dry holes, the costs associated with these wells were much
higher in 1998. The 1999 dry holes were lower-cost Appalachian wells,
while the 1998 wells included a $2.3 million Gulf Coast dry hole.
- Depreciation, depletion, amortization (DD&A) and impairment expense
increased $2.1 million, or 17%, due to the costs associated with the Oryx Acquisition,expansion of the Gulf Coast
regional office, both in staffing and space. Additionally, we accrued
approximately $0.3 million for incentive compensation this quarter. In
1999, incentive compensation was accrued largely in the fourth
quarter.
- Exploration expense increased $0.8 million, or 33%, primarily as well as higher finding costsa
result of increases in 1998 on certain
fieldsdelay rentals and geological and geophysical
expenses in the Gulf Coast Region, largely related to drilling and
mechanical difficulties. A 5% increase in our total natural gas
equivalent production, includingregion as a 74% production increase in the
higher cost Gulf Coast Region, is the other major componentresult of the DD&A increase.increased
activity this year on the Continental Land & Fur acreage.
16
- Taxes other than income increasedrose $1.0 million, or 26%, due largely to
severance tax increases related to bothas a result of
higher realized commodity prices realized this year.
- General and higher production levelsadministrative costs rose $0.6 million, or 14%, equally as
a result of the increased cost associated with our new corporate
office space and this period's incentive compensation accrual. In
1999, incentive compensation was accrued largely in the third quarter of 1999.fourth
quarter.
- Depreciation, depletion, amortization and impairment expense decreased
$0.6 million, or 4%, due to the decrease in natural gas and oil
production this quarter.
Interest expense increased $2.1decreased $0.7 million as a result of a higherlower average
level of outstanding debt during the thirdfirst quarter of 19992000 when compared to the
thirdfirst quarter of 1998, primarily due to debt incurred for the Oryx Acquisition.
17
1999.
Income tax expense was up $4.1$4.9 million due to the comparable increase in
earnings before income tax.
Gains on the sale of assets totaled $4.0 million in the third quarter of
1999 compared to $0.1 million in the third quarter of 1998. These gains were the
result of the non-strategic asset divestitures, primarily the sale of the
Clarksburg properties in the Appalachian Region to Enervest.
NINE MONTHS OF 1999 AND 1998 COMPARED
NET INCOME AND REVENUES. We reported net income in the first nine months of
1999 of $0.5 million, or $0.02 per share. During the corresponding period of
1998, we reported net income of $2.8 million, or $0.11 per share. Operating
income increased $2.8 million, or 12%, and operating revenues increased $2.2
million, or 2%, in 1999. Natural gas production made up 86%, or $105.5 million,
of net operating revenue. The primary cause of the improvement in operating
revenues was the $4.9 million rise in crude oil and condensate sales both due to
price improvements and production volume increases, partially offset by the
decline in other revenues. Operating income was similarly impacted by these
revenue changes as well as by the $5.0 million gain realized on the sale of
certain non-strategic properties and a $10.0 million increase in DD&A expense.
In addition, net income was further reduced by a $6.4 million increase in
interest expense.
Natural gas production volume in the Gulf Coast Region was up 2.7 Bcf, or
30%, to 11.7 Bcf primarily due to production from the Oryx Acquisition and
recent discoveries in the Kacee field in South Texas. Natural gas production
volume in the Western Region was down 0.7 Bcf to 22.3 Bcf due primarily lower
levels of drilling activity in the Mid-Continent area during 1998 and into 1999.
Natural gas production volume in the Appalachian Region was down 0.5 Bcf to 16.1
Bcf, as a result of a decrease in drilling activity in the region in 1999.
The average Gulf Coast natural gas production sales price decreased $0.04
per Mcf, or 2%, to $2.17, decreasing net operating revenues by approximately
$0.5 million. In the Western Region, the average natural gas production sales
price increased $0.01 per Mcf, or 1%, to $1.91, increasing net operating
revenues by approximately $0.2 million. The average Appalachian natural gas
production sales price decreased $0.18 per Mcf, or 7%, to $2.33, decreasing net
operating revenues by approximately $2.9 million. The overall weighted average
natural gas production sales price decreased $0.06 per Mcf, or 3%, to $2.10.
The volume of crude oil sold in the first nine months of the year increased
by 234 Mbbl, or 50%, to 705 Mbbl, increasing net operating revenues by $3.2
million. The volume increase was largely due to production from the Oryx
Acquisition. Crude oil prices increased $2.46 per Bbl, or 18%, to $16.04,
resulting in an increase to net operating revenues of approximately $1.7
million.
The brokered natural gas margin decreased $0.7 million to $2.8 million. The
primary cause was a $0.04 per Mcf reduction to net margin that resulted in a
$1.5 million revenue decrease. Offsetting the effect of the lower margin, was a
6.9 Bcf volume increase, which resulted in a $0.8 million increase in brokered
natural gas margin.
Other net operating revenues decreased $2.2 million to $2.4 million due
primarily to a $1.0 million reduction in revenues from the monetized value of
the Section 29 tax credits on certain tight sands wells. Additionally,
transportation revenue and natural gas liquids sales each declined $0.4 million
due to lower activity levels in the first nine months of 1999.
18
COSTS AND EXPENSES. Total costs and expenses from operations increased $4.3
million, or 4%, due primarily to the following:
- Direct operating expense increased $2.1 million, or 10%, as a result
of the incremental cost of operating the Oryx Acquisition properties.
- Exploration expense decreased $6.1 million, or 45%, primarily as a
result of a reduction in dry hole costs from the first nine months of
1998. We recorded five dry holes in the first nine months of 1999
compared to nine dry holes in the comparable period of 1998.
- Depreciation, depletion, amortization and impairment expense increased
$10.0 million, or 29%, due to the costs associated with the Oryx
Acquisition properties, as well as higher finding costs in 1998 on
certain fields in the Gulf Coast Region which were largely related to
drilling and mechanical difficulties. A 5% increase in our total
natural gas equivalent production, including a 46% production increase
in the higher finding cost Gulf Coast Region, is the other major
component of the DD&A increase.
- General and administrative expenses decreased $2.6 million, or 16%,
due to lower accruals on certain incentive plans and non-cash stock
awards, along with decreases in salaries and wages associated with
reduced headcount and in travel and related costs.
Interest expense increased $6.4 million as a result of a higher average
level of outstanding debt during the first nine months of 1999 when compared to
the first nine months of 1998. The debt increase was primarily due to the debt
incurred for the Oryx Acquisition in December 1998 and to partially fund the
1998 drilling program.
Income tax expense was down $1.4 million due to the comparable decrease in
earnings before income tax.
Gains on the sale of assets totaled $5.0 million for the first nine months
of 1999 compared to $0.1 million in the first nine months of 1998. These gains
were the result of the non-strategic asset divestitures, primarily the sale of
the Clarksburg properties in the Appalachian Region to Enervest in September
1999.
* * *
FORWARD-LOOKING INFORMATION
The statements regarding future financial performance and results and
market prices financing and capital activities, including drilling activities 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
Cabot Oil & Gas
Corporation'sour 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.
1917
PART II. OTHER INFORMATION
ITEMItem 6. EXHIBITS AND REPORTS ON FORMExhibits and Reports on Form 8-K
(a) Exhibits
15.1 - Awareness letter of independent accountantsaccountants.
27 - Article 5. Financial Data Schedule for
ThirdFirst Quarter 19992000 Form 10-Q
(b) Reports on Form 8-K
None
2018
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)
By: /s/ Ray R. Seegmiller
November 15, 1999 ---------------------------------------------
Ray R. Seegmiller, Chairman of the Board,
Chief Executive Officer and President
(Principal Executive Officer Duly Authorized
to Sign on Behalf of the Registrant)May 2, 2000 By: /s/ Paul F. Boling
-----------------------------------------------------------------------------------------
Paul F. Boling, Vice President - Finance
(Principal Financial Officer)Executive Officer Duly Authorized
to sign on Behalf of the Registrant)
By: /s/ Henry C. Smyth
-----------------------------------------------------------------------------------------
Henry C. Smyth, Controller
(Principal Accounting Officer)
2119
EXHIBIT 15.1
PricewaterhouseCoopers LLP Awareness Letter
Securities and Exchange Commission
450 Fifth Street, N.W.NW
Washington, D. C.D.C. 20549
Re: Cabot Oil & Gas Corporation
Registration Statements on Form S-8 and Form S-3
Commissioners:
We are aware that our report dated October 21, 1999April 25, 2000 on our review of the interim
condensed consolidated interim financial statementsinformation of Cabot Oil & Gas Corporation (the
"Company") as of September 30, 1999, and for the three-month
and nine-month periods thenthree month period ended March 31, 2000 and
included in the Company's quarterly report on Form 10-Q for the quarter then
ended is incorporated by reference in the Company's registration
statementsits Registration Statements on Form S-8
filed with the Securities and Exchange Commission on June 23, 1990, November 1,
1993 and May 20, 1994 and Form S-3 filed with the Securities and Exchange
Commission on July 27, 1999. Pursuant to Rule 436(c) under the Securities Act of
1933, this report should not be considered a part of the registration statement
prepared or certified by us within the meanings of Section 7 and 11 of the Act.
PricewaterhouseCoopers LLP
Houston, Texas
November 15, 1999
22May 2, 2000
20