Cabot Oil & Gas Corporation
15375 Memorial Drive
Houston, Texas 77079
Telephone: 281/589-4600
Facsimile: 281/589-4912
August 11, 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 June 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 June 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 June 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)
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 July 30, 1999, there were 24,746,145 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 Six Months Ended June 30, 1999 and 1998...................... 3
Condensed Consolidated Balance Sheet at June 30, 1999
and December 31, 1998.................................................. 4
Condensed Consolidated Statement of Cash Flows for the
Three and Six Months Ended June 30, 1999 and 1998...................... 5
Notes to Condensed Consolidated Financial Statements.................... 6
Independent Accountant's Report on
Review of Interim Financial Information................................ 8
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations.................... 9
Part II. Other Information
Item 4. Submission of Matters to a Vote of Security Holders.............. 18
Item 6. Exhibits and Reports on Form 8-K................................. 18
Signature ................................................................. 19
</TABLE>
2
<PAGE>
CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
(In Thousands, Except Per Share Amounts)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
1999 1998 1999 1998
-------- -------- -------- --------
<S> <C> <C> <C> <C>
NET OPERATING REVENUES
Natural Gas Production...................... $ 35,339 $ 37,252 $ 65,958 $ 72,423
Crude Oil and Condensate.................... 3,842 1,911 6,492 4,248
Brokered Natural Gas Margin................. 1,056 1,143 1,939 2,536
Other....................................... 824 1,361 1,952 3,251
-------- -------- -------- --------
41,061 41,667 76,341 82,458
OPERATING EXPENSES
Direct Operations........................... 7,762 7,532 15,609 14,497
Exploration................................. 2,015 2,978 4,440 6,379
Depreciation, Depletion and Amortization.... 14,816 10,316 27,795 20,083
Impairment of Unproved Properties........... 696 1,110 1,953 1,806
General and Administrative.................. 4,426 5,824 8,717 11,325
Taxes Other Than Income..................... 4,165 4,036 7,803 7,834
-------- -------- -------- --------
33,880 31,796 66,317 61,924
Gain on Sale of Assets........................ 974 5 975 57
-------- -------- -------- --------
INCOME FROM OPERATIONS........................ 8,155 9,876 10,999 20,591
Interest Expense.............................. 6,450 4,579 13,168 8,834
-------- -------- -------- --------
Income/(Loss) Before Income Taxes............. 1,705 5,297 (2,169) 11,757
Income Tax Expense/(Benefit).................. 745 2,163 (687) 4,780
-------- -------- -------- --------
NET INCOME/(LOSS)............................. 960 3,134 (1,482) 6,977
Dividend Requirement on Preferred Stock....... 850 851 1,701 1,701
-------- -------- -------- --------
Net Income/(Loss) Applicable to
Common Stockholders......................... $ 110 $ 2,283 $ (3,183) $ 5,276
======== ======== ======== ========
Basic Earnings/(Loss) Per Share
Applicable to Common Stockholders........... $ -- $ 0.09 $ (0.13) $ 0.21
Diluted Earnings/(Loss) Per Share
Applicable to Common Stockholders........... $ -- $ 0.09 $ (0.13) $ 0.21
Average Common Shares Outstanding............. 24,702 24,828 24,684 24,756
</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>
JUNE 30, DECEMBER 31,
1999 1998
-------- --------
<S> <C> <C>
ASSETS
Current Assets
Cash and Cash Equivalents.............................. $ 1,904 $ 2,200
Accounts Receivable.................................... 43,518 55,799
Inventories............................................ 8,231 9,312
Other.................................................. 4,132 3,804
-------- --------
Total Current Assets................................ 57,785 71,115
Properties and Equipment (Successful Efforts Method).... 622,453 629,908
Other Assets............................................ 2,306 3,137
-------- --------
$682,544 $704,160
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current Portion of Long-Term Debt...................... $ 16,000 $ 16,000
Accounts Payable....................................... 43,979 66,628
Accrued Liabilities.................................... 14,580 16,406
-------- --------
Total Current Liabilities........................... 74,559 99,034
Long-Term Debt.......................................... 334,000 327,000
Deferred Income Taxes................................... 85,150 85,952
Other Liabilities....................................... 9,908 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..................................... 113 113
Common Stock:
Authorized - 40,000,000 Shares of $.10 Par Value
Issued and Outstanding - 25,040,135 Shares and
24,959,897 Shares in 1999 and 1998, Respectively..... 2,504 2,496
Additional Paid-in Capital............................. 253,492 252,073
Accumulated Deficit.................................... (72,798) (67,630)
Less Treasury Stock, At Cost:
302,600 Shares in 1999 and 1998...................... (4,384) (4,384)
-------- --------
Total Stockholders' Equity........................... 178,927 182,668
-------- --------
$682,544 $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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
1999 1998 1999 1998
-------- -------- -------- --------
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income/(Loss)................................ $ 960 $ 3,134 $ (1,482) $ 6,977
Adjustment to Reconcile Net Income/(Loss) to
Cash Provided by Operating Activities:
Depletion, Depreciation and Amortization..... 14,816 10,316 27,795 20,083
Impairment of Undeveloped Leasehold.......... 696 1,110 1,953 1,806
Deferred Income Taxes........................ 670 2,289 (802) 4,577
Gain on Sale of Assets....................... (974) (5) (975) (57)
Exploration Expense.......................... 2,015 2,978 4,440 6,379
Other........................................ 516 791 1,257 1,280
Changes in Assets and Liabilities:
Accounts Receivable.......................... 3,700 3,587 12,281 16,283
Inventories.................................. (257) (2,498) 1,081 (1,872)
Other Current Assets......................... (528) (2,113) (327) (2,132)
Other Assets................................. 206 158 831 159
Accounts Payable and Accrued Liabilities..... 978 (1,657) (14,553) (6,325)
Other Liabilities............................ (962) (564) 403 (680)
-------- -------- -------- --------
Net Cash Provided by
Operating Activities...................... 21,836 17,526 31,902 46,478
-------- -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures............................. (14,850) (36,727) (41,363) (68,111)
Proceeds from Sale of Assets..................... 9,375 159 9,376 669
Exploration Expense.............................. (2,015) (2,978) (4,440) (6,379)
-------- -------- -------- --------
Net Cash Used by Investing Activities.......... (7,490) (39,546) (36,427) (73,821)
-------- -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Sale of Common Stock............................. 729 1,238 916 2,134
Increase in Debt................................. 25,000 39,000 66,000 65,000
Decrease in Debt................................. (38,000) (16,000) (59,000) (34,000)
Dividends Paid................................... (1,850) (1,845) (3,687) (3,682)
-------- -------- -------- --------
Net Cash Provided/(Used) by
Financing Activities.......................... (14,121) 22,393 4,229 29,452
-------- -------- -------- --------
Net Increase/(Decrease) in Cash
and Cash Equivalents.............................. 225 373 (296) 2,109
Cash and Cash Equivalents,
Beginning of Period............................... 1,679 3,520 2,200 1,784
-------- -------- -------- --------
Cash and Cash Equivalents,
End of Period..................................... $ 1,904 $ 3,893 $ 1,904 $ 3,893
======== ======== ======== ========
</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.
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" ("SFAS No. 133"). SFAS No. 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 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. The Company has not yet completed its evaluation of the impact of
the provisions of SFAS No. 133.
2. PROPERTIES AND EQUIPMENT
Properties and equipment are comprised of the following:
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
---------- ----------
(In thousands)
<S> <C> <C>
Unproved Oil and Gas Properties.........................$ 42,083 $ 42,426
Proved Oil and Gas Properties........................... 934,498 921,463
Gathering and Pipeline Systems.......................... 126,289 121,999
Land, Building and Improvements......................... 4,355 4,200
Other................................................... 22,537 20,468
---------- ----------
1,129,762 1,110,556
Accumulated Depreciation, Depletion and Amortization.... (507,309) (480,648)
---------- ----------
$ 622,453 $ 629,908
========== ==========
</TABLE>
3. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
-------- --------
(In thousands)
<S> <C> <C>
Accounts Receivable
Trade Accounts.................................. $ 38,020 $ 41,397
Joint Interest Accounts......................... 3,561 6,712
Insurance Recoveries............................ 1,242 5,539
Current Income Tax Receivable................... -- 502
Other Accounts.................................. 1,052 2,123
-------- --------
43,875 56,273
Allowance for Doubtful Accounts.................. (357) (474)
-------- --------
$ 43,518 $ 55,799
======== ========
</TABLE>
6
<PAGE>
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
-------- --------
(In thousands)
<S> <C> <C>
Accounts Payable
Trade Accounts.................................. $ 10,027 $ 13,229
Natural Gas Purchases........................... 11,506 17,031
Wellhead Gas Imbalances......................... 2,087 1,945
Royalty and Other Owners........................ 11,869 8,987
Capital Costs................................... 4,616 20,165
Dividends Payable............................... 851 851
Taxes Other Than Income......................... 1,463 1,017
Drilling Advances............................... -- 900
Other Accounts.................................. 1,560 2,503
-------- --------
$ 43,979 $ 66,628
======== ========
Accrued Liabilities
Employee Benefits............................... $ 3,107 $ 4,479
Taxes Other Than Income......................... 8,002 7,357
Interest Payable................................ 2,486 2,406
Other Accrued................................... 985 2,164
-------- --------
$ 14,580 $ 16,406
======== ========
Other Liabilities
Postretirement Benefits Other Than Pension...... $ 532 $ 316
Accrued Pension Cost............................ 5,639 4,941
Taxes Other Than Income and Other............... 3,737 4,249
-------- --------
$ 9,908 $ 9,506
======== ========
</TABLE>
4. LONG-TERM DEBT
At June 30, 1999, the Company had $202 million outstanding under its
facility, which provides for an available credit line of $250 million. The
available credit line is subject to adjustment from time-to-time on the basis of
the projected present value (as determined by the banks' petroleum engineer
incorporating certain assumptions provided by the lender) of estimated future
net cash flows from proved oil and gas reserves and other assets of the Company.
The revolving term under this credit facility presently ends in December 2003
and is subject to renewal.
5. EARNINGS PER SHARE
Basic earnings per share for the second quarter were $0.00 and $0.09 in
1999 and 1998, respectively, and were based on the weighted average shares
outstanding of 24,702,075 in 1999 and 24,828,099 in 1998. Basic earnings/(loss)
per share for the first six months of the year were $(0.13) and $0.21 in 1999
and 1998, respectively. Diluted earnings/(loss) per share were $0.00 and $0.09
in the second quarter, and $(0.13) and $0.21 for the first six months in 1999
and 1998, respectively. 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 271,367 and
549,249 in 1999 and 1998, respectively. The Company reported a loss for the six
months ended June 30, 1999, and accordingly the potential effect of dilutive
stock options were not included in the computation of diluted earnings per
share.
7
<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 June 30, 1999, and for the
three-month and six-month periods ended June 30, 1999 and 1998. 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
August 6, 1999
8
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following review of operations for the first six months of 1999 and
1998 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, 1998.
OVERVIEW
As a result of unseasonably mild temperatures, natural gas prices for the
first half of 1999 were substantially below those of the same period last year.
This decline in gas price was the primary cause of the $6.1 million reduction in
net revenues and, along with increased depreciation, depletion and amortization
(DD&A) and higher interest expense, largely contributed to the net loss
available to common shareholders of $3.2 million, an $8.5 million decline from
1998. Operating cash flows were similarly impacted, declining $14.6 million due
to lower natural gas prices, higher interest expenses and changes in working
capital.
The Company drilled 26 gross wells with a success rate of 85% compared to
84 gross wells and an 86% success rate in the first six months of 1998. Total
capital and exploration expenditures were $34.8 million for the first six months
of 1999, compared to $75.1 million for the comparable period in 1998. The
Company reduced the 1999 capital and exploration expenditures in response to the
weak energy price environment in 1999 and in the fourth quarter of 1998.
However, the Company 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, the Company has increased its capital and exploration expenditures
budget by approximately $23 million due to the improving natural gas prices in
July and August. For the full year, the Company now plans to drill approximately
76 gross wells and spend approximately $68.1 million in capital and exploration
expenditures compared to 205 gross wells and $225.9 million in 1998.
Natural gas production was 33.1 Bcf, up 1.0 Bcf compared to the first half
of 1998. This production increase was due primarily to production from the
Southern Louisiana properties acquired from Oryx Energy Company in the fourth
quarter of 1998 (the "Oryx Acquisition"), as well as new production brought on
by the 1998 drilling program of 205 gross (143.7 net) wells.
The Company's strategic pursuits are sensitive to energy commodity prices,
particularly the price of natural gas. As a result of unseasonably warm weather,
the Company's realized gas price for the first quarter ($1.91 per Mcf) was the
lowest quarterly price since 1995. In the second quarter, gas prices recovered
somewhat to $2.08 per Mcf, bringing the year-to-date average price to $1.99 per
Mcf. As the third quarter begins, gas prices continue to strengthen. However,
there is considerable uncertainty about the level of natural gas prices for the
remainder of this 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 17.
9
<PAGE>
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 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. In late spring and into the summer, prices began
to show improvement bringing the second quarter realized gas price up $0.17 per
Mcf to $2.08 compared to the first quarter price of $1.91, but this second
quarter price was down $0.16 per Mcf compared to $2.24 from the comparable 1998
period.
The primary sources of cash for the Company during the first half of 1999
were from funds generated from operations, increased borrowings on the revolving
credit facility, and proceeds from the sale of non-strategic oil and gas
properties. Primary uses of cash were funds used in exploration and development
expenditures and dividends.
The Company had a net cash outflow of $0.3 million in the first half of
1999. Net cash inflow from operating and financing activities totaled $36.1
million through June 1999, sufficiently funding the $45.8 million of capital and
exploration expenditures when combined with the $9.4 million of cash proceeds
from the sale of non-strategic oil and gas properties.
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
1999 1998
------ ------
(In millions)
<S> <C> <C>
Cash Flows Provided by Operating Activities.............. $ 31.9 $ 46.5
====== ======
</TABLE>
Cash flows from operating activities in the 1999 first half were lower by
$14.6 million compared to the corresponding half of 1998 primarily due to lower
natural gas prices, higher interest expense and changes in working capital.
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
1999 1998
------ ------
(In millions)
<S> <C> <C>
Cash Flows Used by Investing Activities.................. $ 36.4 $ 73.8
====== ======
</TABLE>
Cash flows used by investing activities in the first half of 1999 were
attributable to capital and exploration expenditures of $45.8 million, offset by
the receipt of $9.4 million in proceeds received from the sale of non-strategic
oil and gas properties. Cash flows used by investing activities in the first six
months of 1998 were substantially attributable to capital and exploration
expenditures of $74.5 million, offset by the receipt of $0.7 million in proceeds
from the sale of certain oil and gas properties.
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
1999 1998
------ ------
(In millions)
<S> <C> <C>
Cash Flows Provided by Financing Activities.............. $ 4.2 $ 29.5
====== ======
</TABLE>
Cash flows provided by financing activities in the first half of 1999 were
attributable to increases in borrowings on the Company's revolving credit
facility, offset by the payment of $3.7 million in dividends during the period.
In 1998, cash flows provided by financing activities were primarily increases in
borrowings on the Company's revolving credit facility. The cash from the
increased borrowings was used primarily to fund capital and exploration
expenditures. During the first six months of 1998, these expenditures included
$5 million for leasehold acquisitions as part of the Company'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.
10
<PAGE>
Under the Company's revolving credit facility, the available credit line,
currently $250 million, is subject to adjustment on the basis of the present
value of estimated future net cash flows from proved oil and gas reserves (as
determined by the bank's petroleum engineer) and other assets. The revolving
term of the credit facility runs to December 2003. Management believes that the
Company has the ability to finance, if necessary, its capital requirements,
including acquisitions.
The Company's 1999 interest expense is projected to be approximately $27
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 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.
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. This
project is 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 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 the Company's financial position or
operating results. To date, the Company has incurred $0.2 million of expense,
all recorded in 1998, and $1.6 million in capital cost, $1.4 million of which
was incurred this year.
The Company has 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, the Company has contacted 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 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. Management expects the
contingency plan to be substantially complete in the third quarter of 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.
11
<PAGE>
CAPITALIZATION
Capitalization information on the Company is as follows:
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
------- -------
(In millions)
<S> <C> <C>
Long-Term Debt................................. $ 334.0 $ 327.0
Current Portion of Long-Term Debt.............. 16.0 16.0
------- -------
Total Debt................................... 350.0 343.0
------- -------
Stockholders' Equity
Common Stock (net of Treasury Stock).......... 122.2 126.0
Preferred Stock............................... 56.7 56.7
------- -------
Total........................................ 178.9 182.7
------- -------
Total Capitalization........................... $ 528.9 $ 525.7
======= =======
Debt to Capitalization......................... 66.2% 65.2%
</TABLE>
During the first half of 1999, the Company paid dividends of $2.0 million
on the Common Stock and $1.7 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 June 30, 1999, to be paid August 27, 1999, to shareholders of
record as of August 13, 1999.
The increase in debt was largely attributable to the partial funding of the
accelerated drilling program and working capital requirements.
CAPITAL AND EXPLORATION EXPENDITURES
On an annual basis, 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 for the year.
The following table presents major components of capital and exploration
expenditures:
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
1999 1998
------ ------
(In millions)
<S> <C> <C>
Capital Expenditures
Drilling and Facilities..................... $ 20.8 $ 50.0
Leasehold Acquisitions...................... 4.7 9.3
Pipeline and Gathering ..................... 2.0 2.0
Other....................................... 2.3 1.1
------ ------
29.8 62.4
------ ------
Proved Property Acquisitions................ 0.6 6.3
Exploration Expenses.......................... 4.4 6.4
------ ------
Total....................................... $ 34.8 $ 75.1
====== ======
</TABLE>
Total capital and exploration expenditures in the first half of 1999
decreased $40.3 million compared to the same period of 1998, primarily as a
result of the reduced 1999 drilling program. Additionally, in the first quarter
of 1998, the Company made an initial expenditure of $5 million for leasehold
acquisitions as part of its joint exploration program with Union Pacific
Resources Group, Inc. In the second quarter of 1998, the Company also purchased
9.3 Bcfe of proved reserves in the Mid-Continent for $6.6 million.
12
<PAGE>
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. Following the recent improvements in oil
and gas prices, the Company's Board of Directors approved increases in the 1999
capital and exploration expenditures budget from $44.9 million to $68.1 million.
This new budget includes $39.5 million for drilling and facilities, $11.6
million for exploration expenses, and $4.7 million for pipelines. The Company
plans to drill 76 gross wells in 1999 compared with 205 gross wells drilled in
1998. The Company will continue to assess the natural gas price environment and
may increase or decrease the capital and exploration expenditures accordingly.
GAS PRICE SWAPS
The Company has entered into limited natural gas swap agreements since
December 31, 1998, and, accordingly, there have been no material changes in the
Company's open natural gas price swap positions.
At June 30, 1999, the Company had open natural gas price swap contracts as
follows:
<TABLE>
<CAPTION>
Swap Purchases
--------------------------------------------
Volume Weighted Unrealized
in Average Gain (Loss)
Period MMBtu Contract Price ($ Millions)
- ----------------------------------------------------------------------------
<S> <C> <C> <C>
1999 2,155,000 $2.01 $ 0.5
1st Quarter 2000 450,000 2.13 (0.1)
</TABLE>
CONCLUSION
The Company's financial results depend upon many factors, particularly the
price of natural gas and oil, and its ability to market gas on economically
attractive terms. The average produced natural gas sales price received in the
first half of 1999 was down 12% over the first half of 1998, however, natural
gas prices for July and August have improved significantly. Accordingly, 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, management cannot predict with certainty what
pricing levels will be for the remainder of 1999. Because future cash flows are
subject to such variables, there can be no assurance that the Company's
operations will provide cash sufficient to fully fund its planned capital
expenditures.
The Company believes its capital resources, supplemented, if necessary,
with external financing, are adequate to meet its capital requirements.
The preceding paragraphs contains forward-looking information. See
Forward-Looking Information on page 17.
13
<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 applicable to common
shareholders.
SELECTED FINANCIAL AND OPERATING DATA
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
--------------- ----------------
1999 1998 1999 1998
------ ------ ------ ------
(In millions, except where noted)
<S> <C> <C> <C> <C>
Net Operating Revenues..................... $ 41.1 $ 41.7 $ 76.3 $ 82.5
Operating Expenses......................... 33.9 31.8 66.3 61.9
Operating Income........................... 8.2 9.9 11.0 20.6
Interest Expense........................... 6.5 4.6 13.2 8.8
Net Income/(Loss).......................... 0.1 2.3 (3.2) 5.3
Earnings/(Loss) Per Share - Basic.......... $ 0.00 $ 0.09 $ (0.13) $ 0.21
Earnings/(Loss) Per Share - Diluted........ $ 0.00 $ 0.09 $ (0.13) $ 0.21
Natural Gas Production (Bcf)
Appalachia............................... 5.2 5.6 10.8 10.7
West..................................... 7.4 7.6 14.8 15.1
Gulf Coast............................... 4.4 3.4 7.5 6.3
------ ------ ------ ------
Total Company............................ 17.0 16.6 33.1 32.1
Natural Gas Production Sales Prices ($/Mcf)
Appalachia............................... $ 2.31 $ 2.60 $ 2.28 $ 2.68
West..................................... $ 1.86 $ 1.96 $ 1.79 $ 1.95
Gulf Coast............................... $ 2.16 $ 2.29 $ 1.99 $ 2.27
Total Company............................ $ 2.08 $ 2.24 $ 1.99 $ 2.26
Crude/Condensate
Volume (MBbl)............................ 237 141 467 297
Price ($/Bbl)............................ $16.20 $13.55 $13.90 $14.30
Brokered Natural Gas Margin
Volume (Bcf)............................. 10.2 8.8 22.9 19.4
Margin ($/Mcf)........................... $ 0.10 $ 0.13 $ 0.08 $ 0.13
</TABLE>
SECOND QUARTERS OF 1999 AND 1998 COMPARED
Net Income and Revenues. The Company reported net income in the second
quarter 1999 of $0.1 million, or $0.00 per share. During the corresponding
quarter of 1998, the Company reported net income of $2.3 million, or $0.09 per
share. Operating revenues decreased by $0.6 million while operating income
decreased by $1.7 million. Natural gas made up 86%, or $35.3 million, of net
operating revenue. The decrease in net operating revenues was driven primarily
by a 7% decrease in the average natural gas price. Net income and operating
income were similarly impacted by the decrease in the average natural gas price,
along with increased depreciation, depletion and amortization expense as
discussed below. Net income was further affected by a $1.9 million increase in
interest expense related to increased debt as discussed below. These decreases
were partially offset by a net gain from the sale of non-strategic properties.
14
<PAGE>
Natural gas production volume in the Appalachian Region was down 0.4 Bcf to
5.2 Bcf, as a result of a decrease in drilling activity in the Region in 1999.
Natural gas production volume in the Western Region was down 0.2 Bcf to 7.4 Bcf,
primarily due to lower levels of drilling activity in the Anadarko area during
1998 and 1999. Natural gas production volume in the Gulf Coast Region was up 1.0
Bcf to 4.4 Bcf primarily due to production from the Southern Louisiana
properties acquired in December 1998 and recent discoveries in the Kacee field
in South Texas.
The average Appalachian natural gas production sales price decreased $0.29
per Mcf, or 11%, to $2.31, decreasing net operating revenues by $1.5 million on
5.2 Bcf of production. In the Western Region, the average natural gas production
sales price decreased $0.10 per Mcf, or 5%, to $1.86, decreasing net operating
revenues by $0.7 million on 7.4 Bcf of production. In the Gulf Coast Region, the
average natural gas production sales price decreased $0.13 per Mcf, or 6%, to
$2.16, decreasing net operating revenues by $0.6 million on 4.4 Bcf of
production. The overall weighted average natural gas production sales price
decreased $0.16 per Mcf, or 7%, to $2.08.
The volume of crude oil sold by the Company in the second quarter of the
year increased by 96 Mbbl, or 68%, to 237 Mbbl, increasing net operating
revenues by $1.3 million. The volume increase was largely due to production from
the Southern Louisiana properties acquired in the fourth quarter of 1998. Crude
oil prices increased $2.65 per Bbl, or 20%, to $16.20, resulting in an increase
to net operating revenues of approximately $0.6 million.
The brokered natural gas margin decreased $0.1 million to $1.1 million
primarily due to a $0.03 per Mcf decrease in the net margin to $0.10 per Mcf.
Offsetting this margin reduction, the quarterly volume of brokered gas increased
16%, or 1.4 Bcf, contributing $0.2 million to revenue.
Other net operating revenues decreased $0.5 million to $0.8 million due
primarily to a reduction in revenues from the monetized value of the Section 29
tax credits on certain tight sands wells, natural gas transportation and sales
of natural gas liquids.
COSTS AND EXPENSES. Total costs and expenses from operations increased $2.1
million in the second quarter of 1999 compared to the same quarter of 1998. The
primary reasons for this fluctuation are as follows:
- Direct operating expense increased $0.2 million, or 3%, primarily as a
result of the incremental quarterly cost of operating the Southern
Louisiana properties acquired in December 1998 partially offset by
lower employee related expenses.
- Exploration expense decreased $1.0 million, or 32%, primarily as a
result of a reduction in dry hole costs from the 1998 second quarter,
or one dry hole in the second quarter of 1999 compared to six dry
holes in the second quarter of 1998.
- Depreciation, depletion, amortization and impairment expense increased
$4.1 million, or 36%, in part due to the costs associated with the
properties in 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 total Company
natural gas equivalent production, including a 44% production increase
in the higher cost Gulf Coast Region, was the other major component of
the DD&A increase.
- General and administrative expenses decreased $1.4 million, or 24%,
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.
- Gain on sale of assets increased $1.0 million due to the sale of
certain non-strategic properties in the Gulf Coast Region's Provident
City field.
15
<PAGE>
Interest expense increased $1.9 million as a result of a higher average
level of outstanding debt during the second quarter of 1999 when compared to the
second quarter of 1998, primarily due to the debt incurred for the Oryx
Acquisition.
Income tax expense was down $1.4 million due to the comparable decrease in
earnings before income tax.
SIX MONTHS OF 1999 AND 1998 COMPARED
Net Income and Revenues. The Company reported a net loss in the first half
of 1999 of $3.2 million, or $0.13 per share. During the corresponding half of
1998, the Company reported net income of $5.3 million, or $0.21 per share.
Operating income and operating revenues decreased $9.6 million and $6.1 million,
respectively. Natural gas made up 86%, or $66.0 million, of net operating
revenue. The decrease in net operating revenues was driven primarily by a 12%
decrease in the average natural gas price, partially offset by a 3% increase in
natural gas production as discussed below. Net income and operating income were
similarly impacted by the decrease in natural gas prices, and reduced further by
increases in operating expenses as discussed below. Net income was further
affected by a $4.3 million increase in interest expense related to increased
debt as discussed below. These decreases were partially offset by a net gain
from the sale of non-strategic properties.
Natural gas production volume in the Appalachian Region was up 0.1 Bcf to
10.8 Bcf. Natural gas production volume in the Western Region was down 0.3 Bcf
to 14.8 Bcf due primarily lower levels of drilling activity in the Anadarko area
during 1998 and into 1999. Natural gas production volume in the Gulf Coast
Region was up 1.2 Bcf, or 20%, to 7.5 Bcf primarily due to production from the
Oryx Acquisition and recent discoveries in the Kacee field in South Texas.
Production growth in the Gulf Coast Region was reduced as a result of drilling
and mechanical difficulties encountered in the Beaurline field in 1998. The
production from these wells, interrupted during the middle of the third and
fourth quarters due to mechanical failures, averaged 17.5 Mmcf per day for the
nine months ended September 30, 1998. Production from certain of the replacement
wells commenced in the first quarter with the final replacement well completed
late in the second quarter of 1999. The field's total proved reserves remained
substantially intact.
The average Appalachian natural gas production sales price decreased $0.40
per Mcf, or 15%, to $2.28, decreasing net operating revenues by approximately
$4.3 million on 10.8 Bcf of production. In the Western Region, the average
natural gas production sales price decreased $0.16 per Mcf, or 8%, to $1.79,
decreasing net operating revenues by approximately $2.4 million on 14.8 Bcf of
production. The average Gulf Coast natural gas production sales price decreased
$0.28 per Mcf, or 12%, to $1.99, decreasing net operating revenues by
approximately $2.1 million on 7.5 Bcf of production. The overall weighted
average natural gas production sales price decreased $0.27 per Mcf, or 12%, to
$1.99.
The volume of crude oil sold by the Company in the first six months of the
year increased by 170 Mbbl, or 57%, to 467 Mbbl, increasing net operating
revenues by $2.4 million. The volume increase was largely due to production from
the Oryx Acquisition. Crude oil prices decreased $0.40 per Bbl, or 3%, to
$13.90, resulting in a decrease to net operating revenues of approximately $0.2
million.
The brokered natural gas margin decreased $0.6 million to $1.9 million. The
primary cause was a $0.05 per Mcf reduction to net margin that resulted in a
$1.1 million revenue decrease. Offsetting the effect of the lower margin, was a
3.5 Bcf volume increase, which resulted in a $0.5 million increase in brokered
natural gas margin.
Other net operating revenues decreased $1.3 million to $2.0 million due to
a $0.4 million reduction in revenues from the monetized value of the Section 29
tax credits on certain tight sands wells along with reductions in transportation
revenue and natural gas liquids sales of $0.3 million and $0.4 million,
respectively, due to lower activity levels in the first six months of 1999.
16
<PAGE>
COSTS AND EXPENSES. Total costs and expenses from operations increased $4.4
million, or 7%, due primarily to the following:
- Direct operating expense increased $1.1 million, or 8%, as a result of
the incremental cost of operating the Oryx Acquisition properties.
- Exploration expense decreased $1.9 million, or 30%, primarily as a
result of a reduction in dry hole costs from the first half of 1998,
or two dry holes in the first six months of 1999 compared to seven dry
holes in the comparable period of 1998.
- Depreciation, depletion, amortization and impairment expense increased
$7.9 million, or 36%, in part 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, largely related to
drilling and mechanical difficulties. A 5% increase in total Company
natural gas equivalent production, including a 34% production increase
in the higher cost Gulf Coast Region, was the other major component of
the DD&A increase.
- General and administrative expenses decreased $2.6 million, or 23%,
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.
- Gain on sale of assets increased $0.9 million due to the sale of
certain non-strategic properties in the Gulf Coast Region's Provident
City field.
Interest expense increased $4.3 million as a result of a higher average
level of outstanding debt during the first half of 1999 when compared to the
first half of 1998, 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 $5.5 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," "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 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.
17
<PAGE>
PART II. OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On May 11, 1999, the Company held its Annual Meeting of Stockholders. In
connection with this meeting, the Company's stockholders voted on two matters:
the election of three directors and the ratification of the appointment of
PricewaterhouseCoopers LLP as the Company's independent auditors. Of the total
outstanding shares, 23,093,907, or 92%, were voted.
Shareholders approved the re-election of three directors by the following
vote:
Samuel W. Bodman
--------------------------------
Votes cast in favor: 23,002,396
Votes withheld: 91,511
Ray R. Seegmiller
--------------------------------
Votes cast in favor: 23,008,643
Votes withheld: 85,264
William P. Vititoe
--------------------------------
Votes cast in favor: 23,003,850
Votes withheld: 90,057
The terms of office of directors Robert F. Bailey, Henry O. Boswell, John
G.L. Cabot, William R. Esler, William H. Knoell, C. Wayne Nance, P. Dexter
Peacock and Charles P. Siess continued beyond the meeting date.
The other item presented for a vote before the stockholders was the
ratification of the appointment of PricewaterhouseCoopers LLP as the Company's
independent certified public accountants. Of the votes received, 23,081,966 were
in favor of the ratification, 3,128 were against, and 8,813 abstained.
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
Second Quarter 1999 Form 10-Q
(b) Reports on Form 8-K
None
18
<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
August 11, 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)
19
<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 August 6, 1999 on our review of the condensed
consolidated interim financial statements of Cabot Oil & Gas Corporation (the
"Company") as of June 30, 1999, and for the three-month and six-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
August 6, 1999
20
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<CASH> 1,904
<SECURITIES> 0
<RECEIVABLES> 43,875
<ALLOWANCES> (357)
<INVENTORY> 8,231
<CURRENT-ASSETS> 57,785
<PP&E> 1,129,762
<DEPRECIATION> (507,309)
<TOTAL-ASSETS> 682,544
<CURRENT-LIABILITIES> 74,559
<BONDS> 350,000
<COMMON> 195,025
0
56,700
<OTHER-SE> (72,798)
<TOTAL-LIABILITY-AND-EQUITY> 682,544
<SALES> 74,389
<TOTAL-REVENUES> 76,341
<CGS> 66,317
<TOTAL-COSTS> 66,317
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 13,168
<INCOME-PRETAX> (2,169)
<INCOME-TAX> (687)
<INCOME-CONTINUING> (1,482)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (1,482)
<EPS-BASIC> (0.13)
<EPS-DILUTED> (0.13)
</TABLE>
