Cabot Oil & Gas Corporation
1200 Enclave Parkway
Houston, Texas 77077
Telephone: 281/589-4600
Facsimile: 281/589-4912
November 15, 1999
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, 1999
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, 1999 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
<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, 1999
( ) 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, there were 25,073,016 shares of Class A Common
Stock, Par Value $.10 Per Share, outstanding.
================================================================================
<PAGE>
CABOT OIL & GAS CORPORATION
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Part I. Financial Information Page
Condensed Consolidated Statement of Operations for the
Three and Nine Months Ended September 30, 1999 and 1998................ 3
Condensed Consolidated Balance Sheet at September 30, 1999
and December 31, 1998.................................................. 4
Condensed Consolidated Statement of Cash Flows for the
Three and Nine Months Ended September 30, 1999 and 1998................ 5
Notes to Condensed Consolidated Financial Statements.................... 6
Independent Accountant's Report on
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>
2
<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,
1999 1998 1999 1998
-------- -------- -------- --------
<S> <C> <C> <C> <C>
NET OPERATING REVENUES
Natural Gas Production...................... $ 39,508 $ 32,740 $105,466 $105,214
Crude Oil and Condensate.................... 4,805 2,146 11,297 6,394
Brokered Natural Gas Margin................. 905 1,095 2,844 3,580
Other....................................... 472 1,405 2,424 4,656
-------- -------- -------- --------
45,690 37,386 122,031 119,844
OPERATING EXPENSES
Direct Operations........................... 8,502 7,529 24,111 22,026
Exploration................................. 2,993 7,195 7,433 13,574
Depreciation, Depletion and Amortization.... 13,797 11,086 41,592 31,169
Impairment of Unproved Properties........... 696 1,257 2,649 3,064
General and Administrative.................. 4,918 4,919 13,635 16,244
Taxes Other Than Income..................... 4,767 3,776 12,570 11,610
-------- -------- -------- --------
35,673 35,762 101,990 97,687
Gain on Sale of Assets........................ 4,044 77 5,019 133
-------- -------- -------- --------
INCOME FROM OPERATIONS........................ 14,061 1,701 25,060 22,290
Interest Expense.............................. 6,506 4,423 19,674 13,256
-------- -------- -------- --------
Income/(Loss) Before Income Taxes............. 7,555 (2,722) 5,386 9,034
Income Tax Expense/(Benefit).................. 3,025 (1,049) 2,338 3,730
-------- -------- -------- --------
NET INCOME/(LOSS)............................. 4,530 (1,673) 3,048 5,304
Dividend Requirement on Preferred Stock....... 851 851 2,552 2,551
-------- -------- -------- --------
Net Income/(Loss) Applicable to
Common Stockholders......................... $ 3,679 $ (2,524) $ 496 $ 2,753
======== ======== ======== ========
Basic Earnings/(Loss) Per Share
Applicable to Common Stockholders........... $ 0.15 $ (0.10) $ 0.02 $ 0.11
Diluted Earnings/(Loss) Per Share
Applicable to Common Stockholders........... $ 0.15 $ (0.10) $ 0.02 $ 0.11
Average Common Shares Outstanding............. 24,757 24,780 24,709 24,764
</TABLE>
The accompanying notes are an integral part of these
condensed consolidated financial statements.
3
<PAGE>
CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)
(In Thousands, Except Share Data)
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1999 1998
-------- --------
<S> <C> <C>
ASSETS
Current Assets
Cash and Cash Equivalents.............................. $ 1,465 $ 2,200
Restricted Cash (Note 3).............................. 36,812 --
Accounts Receivable.................................... 51,414 55,799
Inventories............................................ 11,450 9,312
Other.................................................. 3,508 3,804
-------- --------
Total Current Assets................................ 104,649 71,115
Properties and Equipment (Successful Efforts Method).... 587,707 629,908
Other Assets............................................ 2,361 3,137
-------- --------
$694,717 $704,160
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current Portion of Long-Term Debt...................... $ 16,000 $ 16,000
Accounts Payable....................................... 55,890 66,628
Accrued Liabilities.................................... 18,700 16,406
-------- --------
Total Current Liabilities........................... 90,590 99,034
Long-Term Debt.......................................... 319,000 327,000
Deferred Income Taxes................................... 92,383 85,952
Other Liabilities....................................... 10,440 9,506
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 1999 and 1998 (Note 7)........................... 113 113
Common Stock:
Authorized - 40,000,000 Shares of $.10 Par Value
Issued and Outstanding - 25,068,870 Shares and
24,959,897 Shares in 1999 and 1998, Respectively.... 2,507 2,496
Additional Paid-in Capital............................. 254,191 252,073
Accumulated Deficit.................................... (70,123) (67,630)
Less Treasury Stock, at Cost:
302,600 Shares in 1999 and 1998..................... (4,384) (4,384)
-------- --------
Total Stockholders' Equity.......................... 182,304 182,668
-------- --------
$694,717 $704,160
======== ========
</TABLE>
The accompanying notes are an integral part of these
condensed consolidated financial statements.
4
<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,
1999 1998 1999 1998
-------- -------- -------- --------
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income/(Loss)................................ $ 4,530 $(1,673) $ 3,048 $ 5,304
Adjustment to Reconcile Net Income/(Loss) to
Cash Provided by Operating Activities
Depletion, Depreciation and Amortization..... 13,797 11,086 41,592 31,169
Impairment of Undeveloped Leasehold.......... 696 1,257 2,649 3,064
Deferred Income Taxes........................ 7,233 864 6,431 5,442
Gain on Sale of Assets....................... (4,044) (77) (5,019) (133)
Exploration Expense.......................... 2,993 7,195 7,433 13,574
Other........................................ 415 105 1,672 1,383
Changes in Assets and Liabilities
Accounts Receivable.......................... (7,896) (2,527) 4,385 13,756
Inventories.................................. (3,219) (1,311) (2,138) (3,183)
Other Current Assets......................... 623 50 296 (2,082)
Other Assets................................. (55) (665) 776 (506)
Accounts Payable and Accrued Liabilities..... 12,167 3,191 (2,386) (3,135)
Other Liabilities............................ 532 (68) 935 (748)
------- ------- ------- --------
Net Cash Provided by
Operating Activities...................... 27,772 17,427 59,674 63,905
------- ------- ------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures............................. (19,617) (25,921) (60,980) (94,032)
Proceeds from Sale of Assets..................... 47,597 283 56,973 953
Restricted Cash.................................. (36,812) -- (36,812) --
Exploration Expense.............................. (2,993) (7,195) (7,433) (13,574)
------- ------- ------- --------
Net Cash Used by Investing Activities.......... (11,825) (32,833) (48,252) (106,653)
------- ------- ------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Sale of Common Stock............................. 467 762 1,384 2,896
Treasury Stock Transactions...................... -- (4,309) -- (4,309)
Increase in Debt................................. 24,000 36,000 90,000 101,000
Decrease in Debt................................. (39,000) (17,000) (98,000) (51,000)
Dividends Paid................................... (1,853) (1,845) (5,541) (5,527)
------- ------- ------- --------
Net Cash Provided/(Used) by
Financing Activities.......................... (16,386) 13,608 (12,157) 43,060
------- ------- ------- --------
Net Increase/(Decrease) in Cash
and Cash Equivalents.............................. (439) (1,798) (735) 312
Cash and Cash Equivalents,
Beginning of Period............................... 1,904 3,894 2,200 1,784
------- ------- ------- --------
Cash and Cash Equivalents,
End of Period..................................... $ 1,465 $ 2,096 $ 1,465 $ 2,096
======= ======= ======= ========
</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 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 have not yet completed our evaluation of the impact of the
provisions of SFAS 133.
2. PROPERTIES AND EQUIPMENT
Properties and equipment are comprised of the following:
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1999 1998
---------- ----------
(In thousands)
<S> <C> <C>
Unproved Oil and Gas Properties......................... $ 41,422 $ 42,426
Proved Oil and Gas Properties........................... 877,970 921,463
Gathering and Pipeline Systems.......................... 123,927 121,999
Land, Building and Improvements......................... 4,176 4,200
Other................................................... 22,589 20,468
---------- ----------
1,070,084 1,110,556
Accumulated Depreciation, Depletion and Amortization.... (482,377) (480,648)
---------- ----------
$ 587,707 $ 629,908
========== ==========
</TABLE>
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
<PAGE>
4. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1999 1998
-------- --------
(In thousands)
<S> <C> <C>
Accounts Receivable
Trade Accounts.................................. $ 42,097 $ 41,397
Joint Interest Accounts......................... 2,268 6,712
Insurance Recoveries............................ 1,242 5,539
Current Income Tax Receivables.................. 4,513 502
Other Accounts.................................. 1,571 2,123
-------- --------
51,691 56,273
Allowance for Doubtful Accounts.................. (277) (474)
-------- --------
$ 51,414 $ 55,799
======== ========
Accounts Payable
Trade Accounts.................................. $ 10,535 $ 13,229
Natural Gas Purchases........................... 16,410 17,031
Wellhead Gas Imbalances......................... 2,169 1,945
Royalty and Other Owners........................ 13,083 8,987
Capital Costs................................... 8,214 20,165
Dividends Payable............................... 851 851
Taxes Other Than Income......................... 1,534 1,017
Drilling Advances............................... 925 900
Other Accounts.................................. 2,169 2,503
-------- --------
$ 55,890 $ 66,628
======== ========
Accrued Liabilities
Employee Benefits............................... $ 3,155 $ 4,479
Taxes Other Than Income......................... 8,956 7,357
Interest Payable................................ 5,242 2,406
Other Accrued................................... 1,347 2,164
-------- --------
$ 18,700 $ 16,406
======== ========
Other Liabilities
Postretirement Benefits Other Than Pension...... $ 644 $ 316
Accrued Pension Cost............................ 6,000 4,941
Taxes Other Than Income and Other............... 3,796 4,249
-------- --------
$ 10,440 $ 9,506
======== ========
</TABLE>
5. LONG-TERM DEBT
At September 30, 1999, Cabot Oil & Gas Corporation had $187 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. The revolving term under this credit facility presently ends in
December 2003 and is subject to renewal.
7
<PAGE>
6. EARNINGS PER SHARE
Basic earnings per share for the first nine months of the year were based
on the year-to-date weighted average shares outstanding of 24,708,807 in 1999
and 24,764,177 in 1998. Diluted earnings/(loss) 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, and totaled 352,132 in 1999 and 321,169 in 1998.
7. PREFERRED STOCK
In October 1999, we entered into an agreement to repurchase the 1,134,000
shares of our 6% convertible redeemable preferred stock outstanding. The
purchase price 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 take the form of an exchange of the preferred stock for a mutually
agreed upon number of Cabot Oil & Gas Corporation common shares. The value of
this preferred stock as recorded on our balance sheet is $56.7 million.
According to the agreement, this transaction is to be closed by November 1,
2000. Upon repurchase, we intend to retire the preferred stock.
8
<PAGE>
INDEPENDENT ACCOUNTANT'S REPORT
To the Board of Directors and Shareholders
Cabot Oil & Gas Corporation:
We have reviewed the accompanying condensed consolidated balance sheet 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-month and nine-month periods then ended. 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 generally accepted accounting principles.
We have previously audited, in accordance with generally accepted auditing
standards, the consolidated balance sheet as of December 31, 1998, 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, 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, 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, 1999
9
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OEPRATIONS
The following review of operations for the first nine months of 1999 and
1998 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.
OVERVIEW
Despite an improvement in realized natural gas prices during the third
quarter of 1999, our average price for the first nine months of the year
remained below the 1998 level. However, an increase in natural gas and oil
production, along with higher oil prices, resulted in a $2.2 million increase in
net revenues. The rise in depreciation, depletion 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 of $2.3 million from
1998. Operating cash flows were similarly impacted, declining $4.2 million due
largely to higher interest expenses and changes in working capital.
Cabot Oil & Gas drilled 49 gross wells with a success rate of 86% in the
first nine months of 1999 compared to 151 gross wells and an 88% 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 plans to drill approximately 78 gross wells and spend approximately $80.5
million in capital and exploration expenditures. This is compared to 205 gross
wells and $225.9 million of capital and exploration expenditures in 1998,
including $70.1 million for the southern Louisiana properties acquired from Oryx
Energy Company (the Oryx Acquisition).
Natural gas production was 50.1 Bcf for the first nine months of 1999, up
1.5 Bcf compared to the first nine months of 1998. This production increase was
due primarily to production from Oryx Acquisition, as well as new production
brought on by the 1998 drilling program of 205 gross (143.7 net) wells.
During 1999, we entered into several property sales intended to high grade
our reserve base. Most recently, in September 1999, we sold Appalachia
properties with reserves 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,
our realized gas price for the first quarter ($1.91 per Mcf) was the lowest
quarterly price since 1995. During the second quarter, gas prices began to
recover with an average realized gas price of $2.08 per Mcf for the second
quarter and rose to $2.32 per Mcf in the third quarter. As of September 30,
1999, the year-to-date average price was $2.10 per Mcf, down 3% from last year.
With the continued price volatility experienced in the past several years, there
is considerable uncertainty about the future level of natural gas prices.
10
<PAGE>
We remain focused on our strategies to grow through the drill bit, from
synergistic acquisitions and from exploitation of our marketing abilities. We
believe these strategies are appropriate in the current industry environment,
enabling us to add shareholder value over the long term.
The preceding paragraphs, discussing Cabot Oil & Gas Corporation's
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 borrowing 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.
Natural gas prices were unseasonably low during much of 1998 and into the first
four months of 1999.
The primary sources of cash for Cabot Oil & Gas Corporation during the
first nine months of 1999 were from funds generated from operations and proceeds
from the sale of non-strategic oil and gas properties. Primary uses of cash were
funds used for exploration and development expenditures and dividends.
We had net cash outflows of $0.7 million in the nine months ended September
30, 1999. Net cash inflow from operating activities was $59.7 million through
September 1999, funding substantially all of the $61.0 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.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
1999 1998
------ ------
(In millions)
<S> <C> <C>
Cash Flows Provided by Operating Activities.............. $ 59.7 $ 63.9
====== ======
</TABLE>
Cash flows from operating activities in the first nine months of 1999 were
lower by $4.2 million compared to the corresponding period of 1998 primarily due
to lower natural gas prices, higher interest expense and changes in working
capital.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
1999 1998
------ ------
(In millions)
<S> <C> <C>
Cash Flows Used by Investing Activities.................. $ 48.3 $106.7
====== ======
</TABLE>
Cash flows used by investing activities in the first nine months of 1999
were attributable to capital 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
<PAGE>
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 million, offset
by the receipt of $1.0 million in proceeds from the sale of certain oil and gas
properties.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
1999 1998
------ ------
(In millions)
<S> <C> <C>
Cash Flows Provided (Used) by Financing Activities....... $(12.2) $ 43.1
====== ======
</TABLE>
Cash flows used by financing activities in the first nine months of 1999
were attributable to a decrease in borrowings on our revolving credit facility,
combined with the payment of $5.6 million in dividends during the period. In
1998, cash flows provided by financing activities were primarily increases in
borrowings on our revolving credit facility, and were used largely to 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.
The available credit line under our revolving credit facility with a group
of banks is currently $250 million. This amount 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' petroleum engineer) and other
assets. The revolving term of the credit facility runs to December 2003. We
believe that we have the ability to finance, if necessary, our capital
requirements, including acquisitions.
Our interest expense for 1999 is projected to be approximately $25.7
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 our
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.
13
<PAGE>
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:
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1999 1998
------- -------
(In millions)
<S> <C> <C>
Long-Term Debt................................. $ 319.0 $ 327.0
Current Portion of Long-Term Debt.............. 16.0 16.0
------- -------
Total Debt.................................. 335.0 343.0
------- -------
Stockholders' Equity
Common Stock (Net of Treasury Stock).......... 125.6 126.0
Preferred Stock............................... 56.7 56.7
------- -------
Total....................................... 182.3 182.7
------- -------
Total Capitalization........................... $ 517.3 $ 525.7
======= =======
Debt to Capitalization......................... 64.8% 65.2%
</TABLE>
During the first nine months of 1999, we paid dividends of $3.0 million on
the Common Stock and $2.6 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, to be paid November 26, 1999, to
shareholders of record as of November 12, 1999.
We have entered into an agreement with the holders of our preferred stock
to repurchase their preferred shares by November 1, 2000. As outlined in the
agreement, the preferred shares that are recorded on our balance sheet for $56.7
million will be repurchased for $51.6 million. If both parties agree, the
transaction could also be settled by exchanging a mutually agreed upon number of
shares of our common stock for their preferred shares. See Note 7 to the
financial statements.
The decrease in debt was largely attributable to the fact that cash from
operations substantially covered cash required for capital expenditures.
Therefore, cash proceeds from assets sales were available to reduce the level of
debt outstanding.
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. We budget such capital expenditures based upon our
projected cash flows for the year.
13
<PAGE>
The following table presents major components of capital and exploration
expenditures:
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
1999 1998
------ ------
(In millions)
<S> <C> <C>
Capital Expenditures
Drilling and Facilities..................... $ 32.1 $ 72.0
Leasehold Acquisitions...................... 6.0 12.7
Pipeline and Gathering ..................... 3.0 3.3
Other....................................... 2.6 1.7
------ ------
43.7 89.7
------ ------
Proved Property Acquisitions................ 9.9 7.9
Exploration Expenses.......................... 7.4 13.6
------ ------
Total....................................... $ 61.0 $111.2
====== ======
</TABLE>
Total capital and exploration expenditures in the first nine months of 1999
decreased $50.2 million compared to the same period of 1998, primarily as a
result of this year's reduced drilling program. In the third quarter of 1999, we
purchased oil and gas properties in the Blue Forest Unit of the Moxa Arch in the
Rocky Mountains area. These properties included 18 wells and 10.3 Bcfe of proved
reserves. Additionally, 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 budgeted 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 increases in the 1999 capital and exploration
expenditures budget from $44.9 million to $80.5 million. This new plan includes
$43.5 million for drilling and facilities, $12.2 million for exploration
expenses, 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. We will
continue to assess the natural gas price environment and may increase or
decrease the capital and exploration expenditures accordingly.
GAS AND OIL PRICE SWAPS
From time to time, we enter into natural gas swap agreements, a type of
derivative instrument, with counterparties to hedge price risk associated with a
portion of our production. Under these price swaps, we receive a fixed price on
a notional quantity of natural gas in exchange for paying a variable price based
on a market-based index, such as the NYMEX gas futures. Notional quantities of
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 MMbtu on quantities totaling 2,420,000 MMbtu,
representing 4% of the natural gas production for the period. A loss 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. The notional volume of
this transaction was 62,000 barrels at a price of $20.65 per Bbl, which
represents less than 9% of our total oil production for the first nine months
1999. Additionally, we have an outstanding swap on 60,000 barrels of our oil
production for the month 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.
We use price swaps to hedge the natural gas price risk on brokered
transactions. Typically, we enter into contracts to broker natural gas at a
variable price based on the market index price. However, in some circumstances,
some of our customers or suppliers request that a fixed price be stated in the
contract. After entering into 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
<PAGE>
During the first nine months of 1999, we entered into price swaps with
total notional quantities of 2,795,000 MMbtu related to our brokered activities,
representing approximately 7% of our total volume of brokered natural gas sold.
A gain of less than $0.1 million was recorded from these price swaps during the
first nine months of 1999.
At September 30, 1999, we had open natural gas price swap contracts as
follows:
<TABLE>
<CAPTION>
Swap Purchases
--------------------------------------------
Volume Weighted Unrealized
in Average Gain (Loss)
Period MMBtu Contract Price ($ Millions)
- ----------------------------------------------------------------------------
<S> <C> <C> <C>
1999 3,155,800 $2.59 $ (0.2)
1st Quarter 2000 450,000 2.13 (0.2)
</TABLE>
We are exposed to market risk on these open contracts, to the extent of
changes in market prices of natural gas. 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 gas 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
months of 1999 was down 3% over the comparable period of 1998. The volatility of
natural gas prices in recent years remains prevalent in 1999 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 such variables, there
can be no assurance 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 paragraphs contains forward-looking information. See
Forward-Looking Information on page 19.
15
<PAGE>
RESULTS OF OPERATIONS
For the purpose of reviewing Cabot Oil & Gas Corporation's results of
operations, "Net Income/(Loss)" is defined as net income or loss applicable to
common shareholders.
SELECTED FINANCIAL AND OPERATING DATA
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------- ----------------
1999 1998 1999 1998
------ ------ ------ ------
(In millions, except where noted)
<S> <C> <C> <C> <C>
Net Operating Revenues..................... $ 45.7 $ 37.4 $122.0 $119.8
Operating Expenses......................... 35.7 35.8 102.0 97.7
Operating Income........................... 14.1 1.7 25.1 22.3
Interest Expense........................... 6.5 4.4 19.7 13.3
Net Income/(Loss).......................... 3.7 (2.5) 0.5 2.8
Earnings/(Loss) Per Share - Basic.......... $ 0.15 $(0.10) $ 0.02 $ 0.11
Earnings/(Loss) Per Share - Diluted........ $ 0.15 $(0.10) $ 0.02 $ 0.11
Natural Gas Production (Bcf)
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
------ ------ ------ ------
Total Company......................... 17.1 16.5 50.1 48.6
Natural Gas Production Sales Prices ($/Mcf)
Gulf Coast............................ $ 2.49 $ 2.07 $ 2.17 $ 2.21
West.................................. $ 2.14 $ 1.79 $ 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
Price ($/Bbl)......................... $20.23 $12.35 $16.04 $13.58
Brokered Natural Gas Margin
Volume (Bcf).......................... 13.8 10.4 36.7 29.8
Margin ($/Mcf)........................ $ 0.07 $ 0.10 $ 0.08 $ 0.12
</TABLE>
THIRD QUARTERS OF 1999 AND 1998 COMPARED
NET INCOME AND REVENUES. We reported net income in the third quarter 1999
of $3.7 million, or $0.15 per share. During the corresponding quarter of 1998,
we reported a net loss of $2.5 million, or $0.10 per share. Operating revenues
increased by $8.3 million, or 22%, while operating income increased by $12.4
million. Natural gas production made up 86%, or $39.5 million, of net operating
revenue. A 17% 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
<PAGE>
Natural gas production volume in the Gulf Coast Region was up 1.5 Bcf to
4.2 Bcf primarily due to production from the December 1998 Oryx Acquisition and
recent discoveries in the Kacee field in South Texas. Natural gas production
volume in the Western Region was down 0.3 Bcf to 7.6 Bcf, primarily due to lower
levels of drilling activity in the Mid-Continent area during 1998 and 1999.
Natural gas production volume in the Appalachian Region was down 0.6 Bcf to 5.3
Bcf, as a result of a decrease in drilling activity in the region in 1999.
In the Gulf Coast Region, the average natural gas production sales price
increased $0.42 per Mcf, or 20%, to $2.49, 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. The
average Appalachian natural gas production sales price increased $0.24 per Mcf,
or 11%, to $2.43, increasing net operating revenues by $1.3 million on 5.3 Bcf
of production. The overall weighted average natural gas production sales price
increased $0.34 per Mcf, or 17%, 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, increasing net operating revenues by $0.8 million.
The volume increase was largely due to production from the Oryx Acquisition.
Crude oil prices increased $7.88 per Bbl, or 64%, to $20.23, resulting in an
increase to net operating revenues of approximately $1.9 million.
The brokered natural gas margin decreased $0.2 million to $0.9 million
primarily due to a $0.03 per Mcf, or $0.5 million, decrease in 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.
Other net operating revenues decreased $0.9 million to $0.5 million due
primarily to a reduction in revenues from the monetized value of the Section 29
tax credits on certain tight sands wells and lower sales of natural gas liquids.
Costs and Expenses. Total costs and expenses from operations decreased $0.1
million in the third quarter of 1999 compared to the same quarter of 1998. The
primary reasons for this fluctuation are as follows:
- Direct operating expense increased $1.0 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%, 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, as well as higher finding costs in 1998 on certain
fields in the Gulf Coast Region, largely related to drilling and
mechanical difficulties. A 5% increase in our total natural gas
equivalent production, including a 74% production increase in the
higher cost Gulf Coast Region, is the other major component of the
DD&A increase.
- Taxes other than income increased $1.0 million, or 26%, due largely to
severance tax increases related to both higher realized commodity
prices and higher production levels in the third quarter of 1999.
Interest expense increased $2.1 million as a result of a higher average
level of outstanding debt during the third quarter of 1999 when compared to the
third quarter of 1998, primarily due to debt incurred for the Oryx Acquisition.
17
<PAGE>
Income tax expense was up $4.1 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
<PAGE>
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, 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's 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 1999 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)
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)
By: /s/ Paul F. Boling
---------------------------------------------
Paul F. Boling, Vice President - Finance
(Principal Financial Officer)
By: /s/ Henry C. Smyth
---------------------------------------------
Henry C. Smyth, Controller
(Principal Accounting Officer)
21
<PAGE>
EXHIBIT 15.1
PricewaterhouseCoopers LLP Awareness Letter
Securities and Exchange Commission
450 Fifth Street, N.W.
Washington, D. C. 20549
Re: Cabot Oil & Gas Corporation
Registration Statements on Form S-8
Commissioners:
We are aware that our report dated October 21, 1999 on our review of the
condensed consolidated interim financial statements of Cabot Oil & Gas
Corporation (the "Company") as of September 30, 1999, and for the three-month
and nine-month periods then ended, and included in the Company's quarterly
report on Form 10-Q is incorporated by reference in the Company's 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
22
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> SEP-30-1999
<CASH> 1,465
<SECURITIES> 0
<RECEIVABLES> 51,691
<ALLOWANCES> (277)
<INVENTORY> 11,450
<CURRENT-ASSETS> 104,649
<PP&E> 1,070,084
<DEPRECIATION> (482,377)
<TOTAL-ASSETS> 694,717
<CURRENT-LIABILITIES> 90,590
<BONDS> 319,000
<COMMON> 195,728
0
56,700
<OTHER-SE> (70,123)
<TOTAL-LIABILITY-AND-EQUITY> 694,717
<SALES> 119,607
<TOTAL-REVENUES> 122,031
<CGS> 101,990
<TOTAL-COSTS> 101,990
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 19,674
<INCOME-PRETAX> 5,386
<INCOME-TAX> 2,338
<INCOME-CONTINUING> 3,048
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 3,048
<EPS-BASIC> 0.02
<EPS-DILUTED> 0.02
</TABLE>
