Cabot Oil & Gas Corporation
15375 Memorial Drive
Houston, Texas 77036
Telephone: 281/589-4600
Facsimile: 281/589-4912
November 11, 1998
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, 1998
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 June 30, 1998 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, 1998
( ) 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)
15375 Memorial Drive, Houston, Texas 77079
(Address of principal executive offices including Zip Code)
(281) 589-4600
(Registrant's telephone number)
No Change
(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 30, 1998, there were 24,928,480 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
Item 1. Financial Statements
Condensed Consolidated Statement of Operations for the
Three and Nine Months Ended September 30, 1998 and 1997................ 3
Condensed Consolidated Balance Sheet at September 30, 1998
and December 31, 1997.................................................. 4
Condensed Consolidated Statement of Cash Flows for the
Three and Nine Months Ended September 30, 1998 and 1997................ 5
Notes to Condensed Consolidated Financial Statements.................... 6
Independent Certified Public Accountants' 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................................. 19
Signature ................................................................. 20
</TABLE>
2
<PAGE>
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,
1998 1997 1998 1997
------- ------- ------- -------
<S> <C> <C> <C> <C>
NET OPERATING REVENUES
Natural Gas Production.....................$32,740 $35,416 $105,214 $115,901
Crude Oil & Condensate..................... 2,146 2,676 6,394 8,826
Brokered Natural Gas Margin................ 1,095 1,053 3,580 2,484
Other...................................... 1,405 1,628 4,656 5,761
------- ------- -------- --------
37,386 40,773 119,844 132,972
OPERATING EXPENSES
Direct Operations.......................... 7,529 7,154 22,026 21,587
Exploration................................ 7,195 2,966 13,574 9,873
Depreciation, Depletion and Amortization... 11,086 10,647 31,169 31,259
Impairment of Unproved Properties.......... 1,257 714 3,064 2,160
General and Administrative................. 4,919 5,011 16,244 13,867
Taxes Other Than Income.................... 3,776 3,450 11,610 11,017
------- ------- -------- --------
35,762 29,942 97,687 89,763
Gain/(Loss) on Sale of Assets............... 77 (1) 133 349
------- ------- -------- --------
INCOME FROM OPERATIONS...................... 1,701 10,830 22,290 43,558
Interest Expense............................ 4,423 4,614 13,256 13,533
------- ------- -------- --------
Income/(Loss) Before Income Taxes........... (2,722) 6,216 9,034 30,025
Income Tax Expense (Benefit)................ (1,049) 2,536 3,730 11,914
------- ------- -------- --------
NET INCOME/(LOSS)........................... (1,673) 3,680 5,304 18,111
Dividend Requirement on Preferred Stock..... 851 1,391 2,551 4,175
------- ------- -------- --------
Net Income/(Loss) Applicable to
Common Stockholders........................$(2,524) $ 2,289 $ 2,753 $ 13,936
======= ======= ======== ========
Basic Earnings/(Loss) Per Share
Applicable to Common.......................$ (0.10) $ 0.10 $ 0.11 $ 0.61
======= ======= ======== ========
Diluted Earnings/(Loss) Per Share
Applicable to Common.......................$ (0.10) $ 0.10 $ 0.11 $ 0.59
======= ======= ======== ========
Average Common Shares Outstanding........... 24,780 22,909 24,764 22,878
</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)
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1998 1997
------------- ------------
<S> <C> <C>
ASSETS
Current Assets
Cash and Cash Equivalents..........................$ 2,096 $ 1,784
Accounts Receivable................................ 45,917 59,672
Inventories........................................ 10,058 6,875
Other.............................................. 4,283 2,202
-------- --------
Total Current Assets............................. 62,354 70,533
Properties and Equipment (Successful
Efforts Method)..................................... 532,199 469,399
Other Assets......................................... 2,379 1,873
-------- --------
$596,932 $541,805
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current Portion of Long-Term Debt..................$ 16,000 $ 16,000
Accounts Payable................................... 50,192 52,348
Accrued Liabilities................................ 20,441 17,524
-------- --------
Total Current Liabilities........................ 86,633 85,872
Long-Term Debt....................................... 233,000 183,000
Deferred Income Taxes................................ 85,550 80,108
Other Liabilities.................................... 7,674 8,763
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 1998 and 1997................ 113 113
Common Stock:
Authorized--40,000,000 Shares of $.10 Par
Value Issued and Outstanding - 24,923,356
Shares and 24,667,262 Shares in 1998 and
1997, Respectively............................... 2,492 2,467
Additional Paid-in Capital...................... 251,559 247,033
Accumulated Deficit.................................. (65,780) (65,551)
Less Treasury Stock, at cost:
297,600 shares in 1998 and no shares in 1997....... (4,309) -
-------- --------
Total Stockholders' Equity....................... 184,075 184,062
-------- --------
$596,932 $541,805
======== ========
</TABLE>
The accompanying notes are an integral part of these
condensed consolidated financial statements.
4
<PAGE>
CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
(In Thousands)
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
1998 1997 1998 1997
------ ------ ------ ------
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income/(Loss)......................$ (1,673) $ 3,680 $ 5,304 $ 18,111
Adjustment to Reconcile Net
Income/(Loss) To Cash Provided by
Operating Activities:
Depletion, Depreciation
and Amortization.................... 11,086 10,647 31,169 31,259
Impairment of Undeveloped Leasehold.. 1,257 714 3,064 2,160
Deferred Income Taxes................ 864 3,000 5,442 11,183
(Gain) Loss on Sale of Assets........ (77) 1 (133) (349)
Exploration Expense.................. 7,195 2,966 13,574 9,873
Other................................ 105 399 1,383 683
Changes in Assets and Liabilities:
Accounts Receivable.................. (2,527) (2,675) 13,756 30,929
Inventories.......................... (1,311) (3,420) (3,183) (307)
Other Current Assets................. 50 (144) (2,082) (684)
Other Assets......................... (665) (105) (506 ) 275
Accounts Payable and Accrued
Liabilities........................ 3,191 12,054 (3,135) (9,029)
Other Liabilities.................... (68) 123 (748) (658)
-------- -------- -------- --------
Net Cash Provided by
Operating Activities.............. 17,427 27,240 63,905 93,446
-------- -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures................... (25,921) (32,018) (94,032) (63,823)
Proceeds from Sale of Assets........... 283 468 953 1,251
Exploration Expense.................... (7,195) (2,966) (13,574) (9,873)
-------- -------- -------- --------
Net Cash Used by Investing
Activities........................ (32,833) (34,516) (106,653) (72,445)
-------- -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Sale of Common Stock................... 762 936 2,896 1,347
Treasury Stock Transactions............ (4,309) - (4,309) -
Increase in Debt....................... 36,000 16,000 101,000 17,000
Decrease in Debt....................... (17,000) (6,000) (51,000) (32,000)
Dividends Paid......................... (1,845) (2,308) (5,527) (6,920)
-------- -------- -------- --------
Net Cash Provided (Used) by
Financing Activities.............. 13,608 8,628 43,060 (20,573)
-------- -------- -------- --------
Net Increase (Decrease) in Cash and
Cash Equivalents....................... (1,798) 1,352 312 428
Cash and Cash Equivalents,
Beginning of Period.................... 3,894 443 1,784 1,367
-------- -------- -------- --------
Cash and Cash Equivalents,
End of Period............ .............$ 2,096 $ 1,795 $ 2,096 $ 1,795
======== ======== ======== ========
</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, the Company follows the accounting policies set
forth in its Annual Report to Stockholders and its Report on Form 10-K filed
with the Securities and Exchange Commission. Users of financial information
produced for interim periods are encouraged to refer to the footnotes contained
in the Annual Report to Stockholders when reviewing interim financial results.
In the opinion of management, the accompanying interim financial statements
contain all material adjustments, consisting only of normal recurring
adjustments, necessary for a fair presentation.
Effective January 1, 1998, the Company adopted Statement of Financial
Accounting Standards No. 130, Reporting of Comprehensive Income ("SFAS 130").
Comprehensive income is defined as the change in net assets of the Company
during a period from transactions and other events and circumstances from
nonowner sources. It includes all changes in equity during a period except those
resulting from investments by owners (sale of stock by the Company) and
distributions to owners (dividends). Since the Company has no such changes in
equity other than net income, comprehensive income is equal to Net Income
Available to Common Shareholders as presented in the Consolidated Statement of
Operations.
In June 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 131, Disclosures about Segments of an
Enterprise and Related Information ("SFAS 131"). The Company plans to adopt this
statement effective December 31, 1998. SFAS 131 requires that the Company make
certain disclosures about each operating segment of its business. This is a
presentation requirement only and will not have an effect on reporting or
presentation of the financial position or operating results of the Company when
adopted. Since the Company operates in one segment, natural gas and oil
exploration and exploitation, no additional disclosure requirements are
anticipated by management.
In February 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 132, Employers' Disclosures about Pensions
and Other Postretirement Benefits ("SFAS 132"). The Company plans to adopt this
statement effective December 31, 1998. SFAS 132 standardizes the disclosure
requirements for pensions and other postretirement benefits in the Form 10-K
Annual Report to Shareholders. This is a presentation requirement only and will
not have an effect on the financial position or operating results of the Company
when adopted.
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 pursuant to the provisions of SFAS
133. This statement is effective for financial statements for fiscal years
beginning after June 15, 1999. The Company has not yet completed its evaluation
of the impact of the provisions of SFAS 133 on its financial position or
operations.
2. PROPERTIES AND EQUIPMENT
Properties and equipment are comprised of the following:
<TABLE>
<CAPTION>
September 30, December 31,
1998 1997
------------ ------------
(in thousands)
<S> <C> <C>
Unproved oil and gas properties......................$ 26,323 $ 24,618
Proved oil and gas properties........................ 832,591 744,381
Gathering and pipeline systems....................... 119,928 116,360
Land, building and improvements...................... 4,278 3,896
Other................................................ 19,665 17,525
---------- ---------
1,002,785 906,780
Accumulated depreciation, depletion
and amortization.................................... (470,586) (437,381)
---------- ---------
$ 532,199 $ 469,399
========== =========
</TABLE>
6
<PAGE>
3. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
<TABLE>
<CAPTION>
September 30, December 31,
1998 1997
------------ -----------
(in thousands)
<S> <C> <C>
Accounts Receivable
Trade accounts.................................. $30,824 $49,315
Joint interest accounts......................... 6,313 4,843
Insurance recoveries............................ 7,242 3,043
Current income tax receivable................... 819 1,291
Other accounts.................................. 1,267 1,719
------- -------
46,465 60,211
Allowance for doubtful accounts.................. (548) (539)
------- -------
$45,917 $59,672
======= =======
Accounts Payable
Trade accounts................................. $ 8,449 $ 6,209
Natural gas purchases.......................... 13,230 13,991
Royalty and other owners....................... 7,911 11,995
Capital costs.................................. 16,526 12,936
Dividends payable.............................. 851 851
Taxes other than income........................ 954 1,478
Drilling advances.............................. 768 2,333
Other accounts................................. 1,503 2,555
------- -------
$50,192 $52,348
======= =======
Accrued Liabilities
Employee benefits............................... $ 4,671 $ 6,067
Taxes other than income......................... 8,682 8,314
Interest payable................................ 6,009 2,147
Other accrued................................... 1,079 996
------- -------
$20,441 $17,524
======= =======
Other Liabilities
Postretirement benefits other than pension...... $ 651 $ 992
Accrued pension cost............................ 4,079 3,742
Taxes other than income and other............... 2,944 4,029
------- -------
$ 7,674 $ 8,763
======= =======
</TABLE>
4. LONG-TERM DEBT
At September 30, 1998, the Company had $85 million outstanding under its
facility which provides for an available credit line of $135 million. The
available credit line is subject to adjustment from time-to-time on the basis of
the projected present value (as determined by a petroleum engineer's report
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 June 2000 and is subject to
renewal.
5. EARNINGS PER SHARE
The Company adopted Statement of Financial Accounting Standards No. 128,
"Earnings per Share" ("SFAS 128") on December 31, 1997. SFAS 128 simplifies the
calculation of earnings per share for companies with complex capital structures
by replacing primary and fully diluted earnings per share with the new basic and
diluted computations. Under the previous guidelines, the Company disclosed only
primary earnings per share since its capital structure was considered simple.
The new disclosure of basic earnings per share is the same as the previously
disclosed primary earnings per share. In periods prior to the fourth quarter of
1997, the Company, with its then simple capital structure, was not required to
disclose fully diluted earnings per share. However, SFAS 128 requires all
companies with any number of common stock equivalents outstanding to disclose
diluted earnings per share unless such equivalents are antidilutive. Basic
earnings per share amounts are based on the weighted average shares outstanding
(24,764,177 in 1998 and 22,878,344 in 1997). The dilutive effect of outstanding
stock awards of 321,169 in 1998 and 649,632 in 1997 resulted in diluted earnings
per share for the third quarter of $(0.10) and $0.10 in 1998 and 1997,
respectively. Year-to-date diluted earnings per share was $0.11 and $0.59 in
1998 and 1997, respectively. No adjustments were made to reported net income in
the computation of earnings per share.
7
<PAGE>
6. STOCK REPURCHASE
In August 1998, the Board of Directors authorized the Company to repurchase
up to two million shares of outstanding common stock at market prices. The
timing and amount of these stock purchases are determined at the discretion of
management. As of September 30, 1998, the Company has repurchased 297,600
shares, or 15% of the total authorized number of shares, for a total cost of
approximately $4.3 million. No treasury shares were issued or sold by the
Company during the quarter.
7. YEAR 2000
To date, the Company has incurred expenses of $0.1 million as part of its
efforts to make all computer software, hardware and embedded microprocessors
Year 2000 compliant. Total project costs are estimated to be $2.1 million,
including $1.8 million in capital expenditures, when the project is complete in
1999. See Item 2, Management's Discussion and Analysis of Financial Condition
and Results of Operations - Year 2000.
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 as of September 30, 1998, 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, 1997, 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
March 6, 1998, 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, 1997, is
fairly stated, in all material respects, in relation to the consolidated balance
sheet from which it has been derived.
PricewaterhouseCoopers LLP
Houston, Texas
November 6, 1998
10
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following review of operations for the first nine months of 1998 and
1997 should be read in conjunction with the Condensed Consolidated Financial
Statements of the Company and the Notes thereto included elsewhere in this Form
10-Q and with the Consolidated Financial Statements, Notes and Management's
Discussion and Analysis included in the Company's Form 10-K for the year ended
December 31, 1997.
In previous years, the Company operated as two regions: the Appalachian
Region and the Western Region, which included the Anadarko, Rocky Mountains and
Gulf Coast areas. Beginning in 1998, a third region was created with the
formation of the Gulf Coast Region, leaving the Anadarko and Rocky Mountains
areas in the Western Region. For purposes of the comparisons below, prior period
results have been restated to conform to the new structure. In all periods
reported, the Company has operated in one segment, natural gas and oil
exploration and exploitation.
OVERVIEW
Along with unseasonably warm temperatures, the first three quarters of 1998
brought natural gas prices substantially below 1997 levels. This decline in
price was the primary cause of the $13.1 million reduction in net revenues. Net
income available to common stockholders declined $11.2 million as a result of
lower prices and increased exploration and general and administrative expenses.
The Company drilled 151 gross wells with a success rate of 88% in the first
nine months of 1998 compared to 168 gross wells and a 90% success rate for the
comparable period of 1997. In 1998, the Company plans to drill 220 gross wells
and spend $149.1 million in capital and exploration expenditures compared to 225
gross wells and $87.4 million of capital and exploration expenditures in 1997.
The plan includes acquisitions to date of $6.6 million as part of the joint
exploration agreement with Union Pacific Resources Group, Inc. ("UPR") and $6.6
million to acquire 9.3 Bcfe of proved reserves in the Anadarko area of the
Western Region. The 1998 drilling program includes an increase in activity in
the Gulf Coast Region. Typically, wells in this area require higher levels of
capital expenditure, including more frequently required workovers and
recompletions.
Natural gas production was 48.6 Bcf, up 0.8 Bcf compared to the first three
quarters of 1997. This production increase was due primarily to new production
brought on by the expanded drilling program of 225 gross (151 net) wells in 1997
along with the 1997 acquisition of producing properties in the Green River Basin
from Equitable Energy Resources. Production for 1997 includes approximately 3.6
Bcf attributable to certain properties in the Appalachian Region that were sold
effective September 1, 1997.
The Company's strategic pursuits are sensitive to energy commodity prices,
particularly the price of natural gas. To date, 1998 prices have demonstrated a
great deal of volatility. Due to the mild winter of 1997, January prices were
significantly lower than the prior year. Prices dropped dramatically in
February, but rebounded to the highest level of the year in March. Since the
beginning of the second quarter, prices have been declining at a slow, but
steady rate. Consequently, there is considerable uncertainty about the level of
natural gas prices for the remainder of the year and beyond.
The Company remains focused on its strategies to grow through the drill
bit, from synergistic acquisitions and from exploitation of its marketing
abilities. Management believes that these strategies are appropriate in the
current industry environment, enabling the Company to add shareholder value over
the long term.
The preceding paragraphs, discussing the Company's strategic pursuits and
goals, contain forward-looking information. See Forward-Looking Information on
page 18.
FINANCIAL CONDITION
Capital Resources and Liquidity
The Company's capital resources consist primarily of cash flows from its
oil and gas properties and asset-based borrowing supported by its oil and gas
reserves. The Company's level of earnings and cash flows depend on many factors,
including the price of oil and natural gas and its ability to control and reduce
costs. Demand for oil and natural gas has historically been subject to seasonal
influences generally characterized by peak demand and higher prices in the
winter heating season. Due to mild winter conditions, natural gas prices
softened significantly in January and remained well below 1997 prices until
March. While temperatures for much of the U.S. were unseasonably warm during the
second quarter and the natural gas price in the second quarter was up $0.16 per
Mcf over 1997, prices softened significantly in the third quarter, with the
quarter prices down $0.14 per Mcf over last year. Natural gas prices for the
first nine months of 1998 are $0.26 per Mcf, or 11%, below the 1997 prices.
The primary sources of cash for the Company during the first nine months of
1998 were from funds generated from operations and increased borrowings on the
revolving credit facility. Primary uses of cash were funds used in exploration
and development expenditures and in the repayment of debt and dividends, as well
as the repurchase of common stock in the third quarter.
The Company had a net cash inflow of $0.3 million in the first three
quarters of 1998. Net cash inflow from operating and financing activities
totaled $107 million year to date through September 1998, funding the $107.6
million of capital and exploration expenditures.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
1998 1997
------ ------
(in millions)
<S> <C> <C>
Cash Flows Provided by Operating Activities............$ 63.9 $ 93.4
====== ======
</TABLE>
Cash flows from operating activities in the first three quarters of 1998
were lower by $29.5 million compared to the corresponding period of 1997
primarily due to lower natural gas prices and smaller favorable changes in
working capital. Accounts receivable increased in part due to outstanding
insurance claims on well blowouts in the Gulf Coast.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
1998 1997
------ ------
(in millions)
<S> <C> <C>
Cash Flows Used in Investing Activities................$106.7 $ 72.4
====== ======
</TABLE>
Cash flows used by investing activities in both the first nine months of
1998 and 1997 were substantially attributable to capital and exploration
expenditures of $107.6 million and $73.7 million, respectively. Proceeds from
the sale of certain oil and gas properties in the first nine months of 1998 and
1997 were $1.0 million and $1.3 million, respectively.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
1998 1997
------ ------
(in millions)
<S> <C> <C>
Cash Flows Provided (Used) by Financing Activities.....$ 43.1 $(20.6)
====== =======
</TABLE>
Cash flows provided by financing activities were primarily increases in
borrowings on the Company's revolving credit facility in 1998. The cash from the
increased borrowings was used to fund acquisitions ($13.2 million), a stock
repurchase program ($4.3 million), and to partially fund other capital and
exploration expenditures. Cash flows used by financing activities in 1997 were
primarily debt reductions under the Company's revolving credit facility and
dividend payments.
Under the Company's revolving credit facility, the available credit line,
currently $135 million, is subject to adjustment on the basis of the projected
present value of estimated future net cash flows from proved oil and gas
reserves and other assets. The revolving term of the credit facility runs to
June 2000. Management believes that the Company has the ability to finance, if
necessary, its capital requirements, including acquisitions from existing
operating cash flows and the available credit facility.
The Company's 1998 interest expense is projected to be approximately $19.0
million. In May 1999, a $16 million principal payment is due on the 10.18%
Notes. This amount is reflected as "Current Portion of Long-Term Debt" on the
Company's balance sheet. This payment is expected to be made with cash from
operations and, if necessary, from increased borrowings on the revolving credit
facility.
The Company is subject to legal proceeding and claims which arise in the
ordinary course of its business. In the opinion of management, the amount of
ultimate liability with respect to these matters will not materially affect the
financial position and operating results of the Company.
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 by the Company or its business partners) that are not Y2K compliant
and correct the problem could be significant to the Company's ability to operate
and report results, as well as potentially expose the Company to third-party
liability.
The Company has begun making the necessary modifications to its computer
systems and embedded microprocessors in preparation for the Year 2000. These
projects are on schedule and the Company believes 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 cost,
$1.8 million is attributable to the purchase of new software and equipment which
will be capitalized. The remaining $0.3 million will be expensed over the next
five quarters and is not expected to have a material impact on the Company's
financial position or operating results. Actual costs to date are approximately
$0.1 million, all of which has been expensed.
The Company has begun reviewing 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 chip replacements are scheduled to be completed by the end of the
first quarter of 1999 at a cost of less than $0.1 million.
Additionally, the Company is in the process of contacting its significant
customers and suppliers in order to determine the Company's exposure to their
potential failure to become Y2K compliant. Although the Company is not aware of
any Y2K compliance problems with any of its customers or suppliers, there can be
no guarantee that the systems of these companies will operate without
interruption in the new millennium.
The Company has formed an internal committee to not only identify and
respond to these issues, but also to develop a contingency plan in the event
that a problem arises after the turn of the century. Management expects the
contingency plan to be substantially complete by mid 1999. Additionally, the
Company has engaged outside consultants to review the Company's plans and
provide feedback relating to the status of the plan implementation. At this
time, the Company does not anticipate that the arrival of the Year 2000 will
materially impact its financial position or results of operations.
The project costs and timetable for Y2K compliance are based on
management's 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 the Company's customers and
suppliers. Actual costs and timing may differ from management's estimates due to
unexpected difficulties in obtaining trained personnel, locating and correcting
relevant computer code and other factors.
CAPITALIZATION
Capitalization information on the Company is as follows:
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1998 1997
------ ------
(in millions)
<S> <C> <C>
Long-Term Debt................................... $233.0 $183.0
Current Portion of Long-Term Debt................ 16.0 16.0
------ ------
Total Debt.................................. 249.0 199.0
------ ------
Stockholders' Equity
Common Stock................................ 131.7 127.4
Treasury Stock.............................. (4.3) -
Preferred Stock............................. 56.7 56.7
------ ------
Total....................................... 184.1 184.1
------ ------
Total Capitalization............................. $433.1 $383.1
====== ======
Debt to Capitalization........................... 57.5% 51.9%
</TABLE>
During the first nine months of 1998, the Company paid dividends of $3.0
million on the Common Stock and $2.5 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, 1998, to be paid November 27, 1998
to shareholders of record as of November 13, 1998.
During the first three quarters of 1998, debt has increased $50 million.
The primary reasons for this increase are the expanded capital spending program,
the stock repurchase program as well as the reduction to income resulting from
lower natural gas prices.
CAPITAL AND EXPLORATION EXPENDITURES
The Company generally funds most of its capital and exploration activities,
excluding major oil and gas property acquisitions, with cash generated from
operations, and budgets such capital expenditures based upon projected cash
flows.
The following table presents major components of capital and exploration
expenditures:
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
1998 1997
------ ------
(in millions)
<S> <C> <C>
Capital Expenditures
Drilling and Facilities...................... $ 72.0 $ 50.0
Leasehold Acquisitions....................... 12.7 3.3
Pipeline and Gathering....................... 3.3 3.4
Other........................................ 1.7 1.5
------ ------
89.7 58.2
------ ------
Proved Property Acquisitions................. 7.9 5.6
Exploration Expenses.......................... 13.6 9.9
------ ------
Total........................................ $111.2 $ 73.7
====== ======
</TABLE>
Total capital and exploration expenditures in the first nine months of 1998
increased $37.5 million compared to the same period of 1997, primarily as a
result of increased expenditures attributable to its 1998 drilling program, the
acquisition of proved properties and its participation in the UPR exploration
joint venture. In the first quarter of 1998, the Company invested $6.6 million
as part of its joint exploration program with UPR. In the second quarter of
1998, the Company also purchased 9.3 Bcfe of proved reserves in the Anadarko
area of the Western Region for $6.6 million.
The Company has a $149.1 million capital and exploration expenditures plan
for 1998 which includes $92.5 million for drilling and facilities, $18.9 million
for exploration expenses, $6.8 million for pipelines and $12.7 million for
proved property acquisitions. Compared to 1997 capital and exploration
expenditures of $87.4 million, the 1998 planned expenditures are up 71%. The
Company expects to drill 220 gross (150.5 net) wells in 1998 compared with 225
gross (151.4 net) wells drilled in 1997.
CONCLUSION
The Company's financial results depend upon many factors, particularly the
price of natural gas, and its ability to market gas on economically attractive
terms. The volatility of natural gas prices in recent years remains prevalent in
1998 with wide price swings in day-to-day trading on the Nymex futures market.
Given this continued price volatility, management cannot predict with certainty
what pricing levels will be for the remainder of 1998. Because future cash flows
are subject to such variables, there can be no assurance that the Company's
operations, combined with short-term borrowings on the revolving credit
facility, will provide cash sufficient to fully fund its planned capital
expenditures if prices should remain low through the rest of 1998.
While the Company's 1998 plan includes a significant increase over 1997
spending, potentially negative changes in industry conditions might require the
Company to adjust its 1998 spending plan to ensure the availability of capital,
including, among other things, reductions in capital expenditures or common
stock dividends.
The Company believes its capital resources, supplemented, if necessary,
with external financing, are adequate to meet its capital requirements.
The preceding paragraphs contain forward-looking information. See
Forward-Looking Information on page 18.
<PAGE>
RESULTS OF OPERATIONS
For the purpose of reviewing the Company's results of operations, "Net
Income/Loss " is defined as net income or loss available to common shareholders.
Selected Financial and Operating Data
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
1998 1997 1998 1997
------ ------ ------ ------
(in millions, except where noted)
<S> <C> <C> <C> <C>
Net Operating Revenues...................$ 37.4 $ 40.8 $119.8 $133.0
Operating Expenses....................... 35.8 29.9 97.7 89.8
Operating Income......................... 1.7 10.8 22.3 43.6
Interest Expense......................... 4.4 4.6 13.3 13.5
Net Income/(Loss)........................ (2.5) 2.3 2.8 13.9
Earnings/(Loss) Per Share - Basic........$(0.10) $ 0.10 $ 0.11 $ 0.61
Earnings/(Loss) Per Share - Diluted......$(0.10) $ 0.10 $ 0.11 $ 0.59
Natural Gas Production (Bcf)
Appalachia.............................. 5.9 6.5 16.6 19.9
West.................................... 7.9 8.1 23.0 21.9
Gulf Coast.............................. 2.7 2.1 9.0 6.0
------ ------ ------ ------
Total Company........................... 16.5 16.7 48.6 47.8
====== ====== ====== ======
Natural Gas Production Sales Prices ($/Mcf)
Appalachia..............................$ 2.19 $ 2.57 $ 2.51 $ 2.88
West....................................$ 1.79 $ 1.77 $ 1.90 $ 2.06
Gulf Coast..............................$ 2.07 $ 2.34 $ 2.21 $ 2.36
Total Company...........................$ 1.98 $ 2.12 $ 2.16 $ 2.42
Crude/Condensate
Volume ((Bbbl).......................... 174 139 471 434
Price $/Bbl.............................$12.35 $19.57 $13.58 $20.45
Brokered Natural Gas Margin
Volume (Bcf)............................ 10.4 9.2 29.8 24.8
Margin $/Mcf............................$ 0.10 $ 0.11 $ 0.12 $ 0.10
</TABLE>
THIRD QUARTERS OF 1998 AND 1997 COMPARED
Net Income and Revenues. The Company reported a net loss in the third
quarter 1998 of $2.5 million, or $0.10 per share. During the corresponding
quarter of 1997, the Company reported net income of $2.3 million, or $0.10 per
share. Operating revenues decreased by $3.4 million while operating income
decreased by $9.1 million. Natural gas made up 88%, or $32.7 million, of net
operating revenue. The decrease in net operating revenues was driven by a 7%
decrease in the average natural gas price. Natural gas production volumes were
comparable with the same period last year. Net income and operating income were
similarly impacted by this drop in average natural gas price, along with a
significant increase in exploration expense as discussed below. This impact was
somewhat softened by decreases in both interest expense and preferred stock
dividends in 1998.
Natural gas production volume in the Appalachian Region was down 0.6 Bcf to
5.9 Bcf due primarily to the sale of producing properties in September of 1997.
This was offset by natural gas production volume growth in the Gulf Coast
Region, up 0.6 Bcf to 2.7 Bcf primarily due to new production brought on by
drilling in 1997 and 1998. Natural gas production volume in the Western Region
was down 0.2 Bcf to 7.9 Bcf.
The average Appalachian natural gas production sales price decreased $0.38
per Mcf, or 15%, to $2.19, decreasing net operating revenues by approximately
$2.2 million on 5.9 Bcf of production. In the Gulf Coast Region, the average
natural gas production sales price decreased $0.27 per Mcf, or 12%, to $2.07,
decreasing net operating revenues by approximately $0.7 million on 2.7 Bcf of
production. In the Western Region, the average natural gas production sales
price was up $0.02 per Mcf, or 1%, to $1.79, increasing net operating revenues
by approximately $0.2 million on 7.9 Bcf of production. The overall weighted
average natural gas production sales price decreased $0.14 per Mcf, or 7%, to
$1.98.
Crude oil prices decreased $7.22 per Bbl, or 37%, to $12.35, resulting in a
decrease to net operating revenue of $1.3 million. A volume increase of 35 MBbl
due to a prior period interest adjustment on a well in the Rocky Mountains area
(25 MBbl) and to new production in that region, brought production up to 174
MBbls while adding $0.4 million to net operating revenue.
Costs and Expenses Total costs and expenses from recurring operations
increased $5.8 million in the third quarter of 1998 primarily due to the
following:
- Direct operating expense increased $0.4 million, or 5%, due primarily
to increased costs associated with outside operated properties in the
Rocky Mountains area combined with higher workover expenses in the
Gulf Coast Region and Anadarko area of the Western Region.
- Exploration expense increased by $4.2 million, or 143%, primarily due
to $3.7 million of higher dry hole costs associated with the increased
drilling activity in the Gulf Coast and Western Regions in 1998. Two
wells, which contributed to the majority of the third quarter costs,
were a $2.3 million exploratory well in the Gulf Coast Region and a
$1.1 million extension well in the Western Region. In addition, the
administrative costs related to this expanded exploration activity
increased $0.4 million including additions to our professional staff
and increased consulting expense.
- Depreciation, depletion, amortization and impairment expense increased
$1.0 million due largely to the amortization of unproved properties
associated with the UPR exploration joint venture and in part to an
increase in the overall units of production rate associated with the
higher percentage of total production attributable to the Gulf Coast
and Western Regions.
- Taxes other than income increased $0.3 million, or 9%, due to
increases in Ad Valorem taxes in West Virginia, brought about by
higher taxable values related to higher gas prices in prior years.
Interest expense decreased $0.2 million as a result of $0.4 million in
interest income received on a prior year income tax refund. This benefit was
partially offset by the effect of a higher average level of outstanding debt
during the third quarter of 1998 when compared to the third quarter of 1997.
Income tax expense was down $3.6 million due to the comparable decrease in
earnings before income tax.
Dividends on preferred stock were $0.5 million less than in the third
quarter of 1997 due to the conversion of all of the Company's $3.125 cumulative
convertible preferred stock into shares of common stock during the fourth
quarter of 1997.
NINE MONTHS OF 1998 AND 1997 COMPARED
Net Income and Revenues. The Company reported net income in the first nine
months of 1998 of $2.8 million, or $0.11 per share. During the corresponding
period of 1997, the Company reported net income of $13.9 million, or $0.61 per
share. Operating income and operating revenues decreased $21.3 million and $13.1
million, respectively. Natural gas made up 88%, or $105.2 million, of net
operating revenue. The decrease in net operating revenues was driven primarily
by a 11% decrease in the average natural gas price, partially offset by a 2%
increase in natural gas production as discussed below. Net income and operating
income were similarly impacted by the decrease in natural gas prices.
Natural gas production volume in the Appalachian Region was down 3.3 Bcf to
16.6 Bcf due primarily to the sale of producing properties in September 1997.
Natural gas production volume in the Western Region was up 1.1 Bcf to 23.0 Bcf
due primarily to the acquisition of producing properties in the Green River
Basin of Wyoming effective in the third quarter of 1997 and in part to new
production brought on by drilling in 1997 and 1998. Natural gas production
volume in the Gulf Coast Region was up 3.0 Bcf, or 50%, to 9.0 Bcf primarily due
to new production brought on by drilling in 1997 and 1998.
The average Appalachian natural gas production sales price decreased $0.37
per Mcf, or 13%, to $2.51, decreasing net operating revenues by approximately
$6.1 million on 16.6 Bcf of production. In the Western Region, the average
natural gas production sales price decreased $0.16 per Mcf, or 8%, to $1.90,
decreasing net operating revenues by approximately $3.7 million on 23.0 Bcf of
production. The average Gulf Coast natural gas production sales price decreased
$0.15 per Mcf, or 6%, to $2.21, decreasing net operating revenues by
approximately $1.3 million on 9.0 Bcf of production. The overall weighted
average natural gas production sales price decreased $0.26 per Mcf, or 11%, to
$2.16.
Crude oil and condensate sales volumes were up 37 MBbl, or 9%, to 471 MBbl
while crude oil prices decreased $6.87 per Bbl, or 34%, to $13.58, decreasing
net operating revenues by approximately $3.2 million. The volume increase was
due to a prior period interest adjustment on a well in the Rocky Mountains area
(25 MBbl) and to new production in that region.
The brokered natural gas margin increased $1.1 million to $3.6 million
primarily due to a 5.0 Bcf increase in volume, combined with a $0.02 per Mcf
improvement in net margin to $0.12 per Mcf.
Other net operating revenues decreased $1.1 million to $4.7 million due
primarily to net miscellaneous revenues in the first nine months of 1997 related
primarily to contract settlements.
Costs and Expenses Total costs and expenses from operations increased $7.9
million, or 9%, due primarily to the following:
- Exploration expense increased $3.7 million, or 37%, due to the higher
dry hole expenses related to the exploration activity during the first
nine months of 1998. In addition, the administrative cost related to
this expanded exploration activity increased $0.8 million, including
additions to our professional staff and increased consulting expense.
- Depreciation, depletion, amortization and impairment expense increased
$0.8 million due primarily to the amortization of unproved properties
associated with the UPR exploration joint venture.
- General and administrative expenses increased $2.4 million, or 17%,
largely due to staffing increases in the third and fourth quarters of
1997 ($0.4 million), non-cash stock compensation from stock awards in
the second quarter of 1997 ($0.8 million), certain executive
retirement and severance packages accrued in 1998 ($0.5 million), and
relocation and other travel expenses ($0.4 million).
- Taxes other than income increased $0.6 million, or 5%, due to the
increase in Ad Valorem taxes in West Virginia, brought about by higher
taxable values related to higher natural gas prices in prior years.
Income tax expense was down $8.2 million due to the comparable decrease in
earnings before income tax.
* * *
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," "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 the Company'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.
<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
1998 Form 10-Q
(b) Reports on Form 8-K
None
<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/ Paul F. Boling
-------------------------------------------
November 12, 1998 Paul F. Boling, Vice President - Finance
(Executive Officer Duly Authorized
to Sign on Behalf of the Registrant)
By: /s/ Henry C. Smyth
-------------------------------------------
Henry C. Smyth, Controller
(Principal Accounting Officer)
<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
We are aware that our report dated November 6, 1998 on our review of the
condensed consolidated financial statements of Cabot Oil & Gas Corporation as of
September 30, 1998, and for the three-month and nine-month periods then ended
and included in the Company's quarterly report on Form 10-Q for the quarter
ended, 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. 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 6, 1998
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> SEP-30-1998
<CASH> 27
<SECURITIES> 2,069
<RECEIVABLES> 46,465
<ALLOWANCES> (548)
<INVENTORY> 10,058
<CURRENT-ASSETS> 62,354
<PP&E> 1,002,785
<DEPRECIATION> (470,586)
<TOTAL-ASSETS> 596,932
<CURRENT-LIABILITIES> 86,633
<BONDS> 249,000
<COMMON> 127,373
0
56,700
<OTHER-SE> (65,780)
<TOTAL-LIABILITY-AND-EQUITY> 596,932
<SALES> 115,188
<TOTAL-REVENUES> 119,844
<CGS> 97,687
<TOTAL-COSTS> 97,687
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 13,256
<INCOME-PRETAX> 9,034
<INCOME-TAX> 3,730
<INCOME-CONTINUING> 5,304
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 5,304
<EPS-PRIMARY> 0.11
<EPS-DILUTED> 0.11
</TABLE>
