Cabot Oil & Gas Corporation
1200 Enclave Parkway
Houston, Texas 77077
Telephone: 281/589-4600
Facsimile: 281/589-4912
August 9, 2000
Securities & Exchange Commission
450 Fifth Street, N.W.
Washington, D.C. 20549
RE: Cabot Oil & Gas Corporation Form 10-Q
for the Quarter Ended June 30, 2000
Ladies and Gentlemen:
On behalf of Cabot Oil & Gas Corporation, transmitted herewith for filing
under the Securities and Exchange Act of 1934, as amended, is a copy of the
Company's June 30, 2000 Form 10-Q. Pursuant to Rule 302 of Regulation S-T, the
Form 10-Q has been executed by typing the name of the signature.
This filing has been effected through the Securities and Exchange
Commission's EDGAR electronic filing system.
Please contact the undersigned at (281) 589-4642 with any questions or
statements you may have regarding this filing.
Sincerely,
JILL RIBBECK
Manager, Financial Reporting
<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, 2000
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.
Commission file number 1-10447
CABOT OIL & GAS CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 04-3072771
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
1200 Enclave Parkway, Houston, Texas 77077-1607
(Address of principal executive offices including Zip Code)
(281) 589-4600
(Registrant's telephone number)
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 31, 2000, there were 28,946,070 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
Item 1. Financial Statements
Condensed Consolidated Statement of Operations for the
Three and Six Months Ended June 30, 2000 and 1999................... 3
Condensed Consolidated Balance Sheet at June 30, 2000
and December 31, 1999............................................... 4
Condensed Consolidated Statement of Cash Flows for the
Three and Six Months Ended June 30, 2000 and 1999................... 5
Notes to Condensed Consolidated Financial Statements................. 6
Report of Independent Accountant's Review
of Interim Financial Information.................................... 9
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations................... 10
Part II. Other Information
Item 4. Submission of Matters to a Vote of Security Holders............. 20
Item 6. Exhibits and Reports on Form 8-K................................ 20
Signature ................................................................ 21
</TABLE>
2
<PAGE>
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
(In Thousands, Except Per Share Amounts)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------ ------------------
2000 1999 2000 1999
-------- -------- -------- --------
<S> <C> <C> <C> <C>
NET OPERATING REVENUES
Natural Gas Production..................... $ 38,903 $ 35,339 $ 77,989 $ 65,958
Crude Oil and Condensate................... 4,649 3,842 8,974 6,492
Brokered Natural Gas Margin................ 1,101 1,056 2,552 1,939
Other...................................... 1,872 824 6,644 1,952
-------- -------- -------- --------
46,525 41,061 96,159 76,341
OPERATING EXPENSES
Direct Operations - Field & Pipeline ...... 9,062 7,762 17,573 15,609
Exploration................................ 4,162 2,015 7,395 4,440
Depreciation, Depletion and Amortization... 12,464 14,816 25,112 27,795
Impairment of Unproved Properties.......... 963 696 1,923 1,953
Impairment of Long-Lived Assets............ 9,143 0 9,143 0
General and Administrative................. 5,331 4,426 10,218 8,717
Taxes Other Than Income.................... 4,954 4,165 9,555 7,803
-------- -------- -------- --------
46,079 33,880 80,919 66,317
Gain (Loss) on Sale of Assets................ (26) 974 (47) 975
-------- -------- -------- --------
INCOME FROM OPERATIONS....................... 420 8,155 15,193 10,999
Interest Expense............................. 5,365 6,450 11,336 13,168
-------- -------- -------- --------
Income (Loss) Before Income Taxes............ (4,945) 1,705 3,857 (2,169)
Income Tax Expense (Benefit)................. (1,863) 745 1,594 (687)
-------- -------- -------- --------
NET INCOME (LOSS)............................ (3,082) 960 2,263 (1,482)
Dividend Requirement on Preferred Stock...... (4,600) 850 (3,749) 1,701
-------- -------- -------- --------
Net Income (Loss) Applicable to
Common Stockholders........................ $ 1,518 $ 110 $ 6,012 $ (3,183)
======== ======== ======== ========
Basic Earnings (Loss) Per Share
Applicable to Common Stockholders.......... $ 0.05 $ -- $ 0.23 $ (0.13)
Diluted Earnings (Loss) Per Share
Applicable to Common Stockholders.......... $ 0.05 $ -- $ 0.23 $ (0.13)
Average Common Shares Outstanding............. 26,694 24,702 25,746 24,684
</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,
2000 1999
--------- ---------
<S> <C> <C>
ASSETS
Current Assets
Cash and Cash Equivalents............................. $ 1,429 $ 1,679
Accounts Receivable................................... 58,167 50,391
Inventories........................................... 8,312 10,929
Other................................................. 4,431 3,641
--------- ---------
Total Current Assets................................ 72,339 66,640
Properties and Equipment,
Net (Successful Efforts Method)...................... 600,689 590,301
Other Assets........................................... 2,199 2,539
--------- ---------
$ 675,227 $ 659,480
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current Portion of Long-Term Debt..................... $ 16,000 $ 16,000
Accounts Payable...................................... 71,208 56,551
Accrued Liabilities................................... 16,391 17,387
--------- ---------
Total Current Liabilities........................... 103,599 89,938
Long-Term Debt......................................... 249,000 277,000
Deferred Income Taxes.................................. 95,619 95,012
Other Liabilities...................................... 12,721 11,034
Stockholders' Equity
Preferred Stock:
Authorized -- 5,000,000 Shares of $.10 Par Value
Issued and Outstanding - 6% Convertible Redeemable
Preferred; $50 Stated Value; No Shares in 2000 and
1,134,000 Shares in 1999............................ 0 113
Common Stock:
Authorized -- 40,000,000 Shares of $.10 Par Value
Issued and Outstanding - 29,207,170 Shares and
25,073,660 Shares in 2000 and 1999, Respectively.... 2,921 2,507
Additional Paid-in Capital............................. 278,272 254,763
Accumulated Deficit.................................... (62,521) (66,503)
Less Treasury Stock, at Cost:
302,600 Shares in 2000 and 1999..................... (4,384) (4,384)
--------- ---------
Total Stockholders' Equity.......................... 214,288 186,496
--------- ---------
$ 675,227 $ 659,480
========= =========
</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,
------------------ ------------------
2000 1999 2000 1999
-------- -------- -------- --------
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)................................. $ (3,082) $ 960 $ 2,263 $ (1,482)
Adjustment to Reconcile Net Income (Loss) to
Cash Provided by Operating Activities:
Depletion, Depreciation and Amortization...... 12,464 14,816 25,112 27,795
Impairment of Undeveloped Leasehold........... 963 696 1,923 1,953
Impairment of Long-Lived Assets............... 9,143 0 9,143 0
Deferred Income Taxes......................... (1,994) 670 607 (802)
(Gain) Loss on Sale of Assets................. 26 (974) 47 (975)
Exploration Expense........................... 4,162 2,015 7,395 4,440
Other......................................... (262) 516 239 1,257
Changes in Assets and Liabilities:
Accounts Receivable........................... (8,811) 3,700 (7,776) 12,281
Inventories................................... (3,385) (257) 2,617 1,081
Other Current Assets.......................... (2,142) (528) (790) (327)
Other Assets.................................. 240 206 340 831
Accounts Payable and Accrued Liabilities...... 7,962 978 8,400 (14,553)
Other Liabilities............................. 488 (962) 1,687 403
-------- -------- -------- --------
Net Cash Provided by Operating Activities... 15,772 21,836 51,207 31,902
-------- -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures.............................. (23,115) (14,850) (42,060) (41,363)
Proceeds from Sale of Assets...................... 258 9,375 1,781 9,376
Exploration Expense............................... (4,162) (2,015) (7,395) (4,440)
-------- -------- -------- --------
Net Cash Used by Investing Activities....... (27,019) (7,490) (47,674) (36,427)
-------- -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Sale of Common Stock.............................. 78,817 729 80,048 916
Retirement of Preferred Stock..................... (51,600) 0 (51,600) 0
Increase in Debt.................................. 29,000 25,000 56,000 66,000
Decrease in Debt.................................. (42,000) (38,000) (84,000) (59,000)
Dividends Paid.................................... (2,377) (1,850) (4,231) (3,687)
-------- -------- -------- --------
Net Cash Provided (Used) by
Financing Activities...................... 11,840 (14,121) (3,783) 4,229
-------- -------- -------- --------
Net Increase (Decrease) in Cash
and Cash Equivalents.............................. 593 225 (250) (296)
Cash and Cash Equivalents,
Beginning of Period............................... 836 1,679 1,679 2,200
-------- -------- -------- --------
Cash and Cash Equivalents,
End of Period..................................... $ 1,429 $ 1,904 $ 1,429 $ 1,904
======== ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these
condensed consolidated financial statements.
5
<PAGE>
CABOT OIL & GAS CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
1. FINANCIAL STATEMENT PRESENTATION
During interim periods, Cabot Oil & Gas Corporation follows the same
accounting policies used in its Annual Report to Stockholders and its Report on
Form 10-K filed with the Securities and Exchange Commission. People using
financial information produced for interim periods are encouraged to refer to
the footnotes in the Annual Report to Stockholders when reviewing interim
financial results. In management's opinion, the accompanying interim financial
statements contain all material adjustments, consisting only of normal recurring
adjustments, necessary for a fair presentation.
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). SFAS 133 requires all
derivatives to be recognized in the statement of financial position as either
assets or liabilities and measured at fair value. In addition, all hedging
relationships must be designated, reassessed and documented according to the
provisions of SFAS 133. This statement was initially effective for financial
statements for fiscal years beginning after June 15, 1999. However, in June
1999, the FASB issued SFAS 137, "Accounting for Derivative Instruments and
Hedging Activities - Deferral of Effective date of SFAS 133," which delayed the
effective date of SFAS 133 to fiscal years beginning after June 15, 2000. The
Company has not yet completed its evaluation of the impact that the provisions
of SFAS 133 will have on its earnings, statements of financial position or cash
flows.
In June 2000, the FASB issued SFAS 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities". This pronouncement amended portions
of SFAS 133 and will be applied as necessary with SFAS 133 effective January 1,
2001.
2. PROPERTIES AND EQUIPMENT
Properties and equipment are comprised of the following:
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
2000 1999
---------- ----------
(In thousands)
<S> <C> <C>
Unproved Oil and Gas Properties......................... $ 35,185 $ 32,262
Proved Oil and Gas Properties........................... 941,153 906,852
Gathering and Pipeline Systems.......................... 126,487 124,708
Land, Building and Improvements......................... 4,352 4,359
Other................................................... 23,825 23,206
---------- ----------
1,131,002 1,091,387
Accumulated Depreciation, Depletion and Amortization.... (530,313) (501,086)
---------- ----------
$ 600,689 $ 590,301
========== ==========
</TABLE>
6
<PAGE>
3. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
2000 1999
---------- ----------
(In thousands)
<S> <C> <C>
Accounts Receivable
Trade Accounts......................................... $ 49,479 $ 44,739
Joint Interest Accounts................................ 6,395 4,395
Insurance Recoveries................................... 1,913 1,177
Current Income Tax Receivable.......................... 111 111
Other Accounts......................................... 563 263
-------- --------
58,461 50,685
Allowance for Doubtful Accounts......................... (294) (294)
-------- --------
$ 58,167 $ 50,391
======== ========
Accounts Payable
Trade Accounts......................................... $ 10,390 $ 12,195
Natural Gas Purchases.................................. 21,126 14,918
Royalty and Other Owners............................... 15,284 11,316
Capital Costs.......................................... 16,361 10,103
Taxes Other Than Income................................ 1,433 1,279
Drilling Advances...................................... 1,323 614
Dividends Payable...................................... 0 851
Wellhead Gas Imbalances................................ 2,256 2,177
Other Accounts......................................... 3,035 3,098
-------- --------
$ 71,208 $ 56,551
======== ========
Accrued Liabilities
Employee Benefits...................................... $ 2,976 $ 5,203
Taxes Other Than Income................................ 9,691 8,471
Interest Payable....................................... 2,806 2,780
Other Accrued.......................................... 918 933
-------- --------
$ 16,391 $ 17,387
======== ========
Other Liabilities
Postretirement Benefits Other Than Pension............. $ 1,009 $ 799
Accrued Pension Cost................................... 6,675 6,290
Taxes Other Than Income and Other...................... 5,037 3,945
-------- --------
$ 12,721 $ 11,034
======== ========
</TABLE>
4. LONG-TERM DEBT
At June 30, 2000, the Company had $133 million outstanding under its credit
facility, which provides for an available credit line of $250 million. The
available credit line is subject to adjustment from time-to-time on the basis of
the projected present value (as determined by the banks' petroleum engineer
incorporating certain assumptions provided by the lender) of estimated future
net cash flows from proved oil and gas reserves and other assets of the Company.
The revolving term under this credit facility presently ends in December 2003
and is subject to renewal.
7
<PAGE>
5. EARNINGS (LOSS) PER SHARE
Basic earnings (loss) per share for the second quarter and six months of
the year were based on the year-to-date weighted average shares outstanding of
25,746,134 in 2000 and 24,702,075 in 1999. Diluted earnings (loss) per share
were the same as basic earnings per share in all periods presented. The diluted
earnings (loss) per share amounts are based on weighted average shares
outstanding plus common stock equivalents. Common stock equivalents include both
stock awards and stock options, and totaled 328,425 in 2000 and 271,367 in 1999.
6. ENVIRONMENTAL LIABILITY
The EPA notified the Company in February 2000 that it might have potential
liability for waste material disposed of at the Casmalia Superfund Site
("Site"), located on a 252-acre parcel in Santa Barbara County, California. Over
10,000 separate parties disposed of waste at the Site while it was operational
from 1973 to 1989. The EPA stated that federal, state and local governmental
agencies along with the numerous private entities that used the Site for waste
disposal will be expected to pay for the clean-up costs which could total as
much as several hundred million dollars. The EPA is also pursuing the owner(s) /
operator(s) of the Site to pay for remediation. Documents received with the
notification from the EPA indicate that the Company used the Site principally to
dispose of salt water from two wells over a period from 1976 to 1979. A group of
potentially responsible parties, including the Company, are in negotiations with
the EPA and have presented the EPA with a counter offer to its settlement offer.
The Company has a reserve that it believes to be adequate to cover this
potential environmental liability based on its assessment of the most likely
outcome of this matter. While the potential impact to the Company may materially
affect quarterly or annual financial results, management does not believe it
would materially impact the Company's financial position. The Company will
continue to monitor the facts and its assessment of its liability related to
this claim.
7. WYOMING ROYALTY LITIGATION
In June 2000, two overriding royalty owners sued the Company in Wyoming
State court. The plaintiffs have requested class certification under the Wyoming
rules of civil procedure and allege that the Company has deducted impermissible
costs of production from royalty payments, which have been made to the
plaintiffs and other similarly situated persons. Additionally, the suit claims
that the Company has failed to properly inform the plaintiffs and other
similarly situated persons of the deductions taken from royalties.
The Company believes that it has substantial defenses to this claim and
intends to vigorously assert such defenses. However, the investigation into this
claim has only just begun and the Company can not presently determine the
likelihood or range of any potential loss.
8. RETIREMENT OF PREFERRED STOCK
In May 2000, the Company repurchased all of the then-outstanding shares of
preferred stock from the holder for $51.6 million. Since this stock had been
recorded at a stated value of $56.7 million on the Company's balance sheet, a
$5.1 million negative dividend to preferred stockholders was realized. After
this repurchase transaction, the Company retired all shares of preferred stock.
This transaction was funded by the sale of common stock in a public
offering. The Company sold 3.4 million shares to the public at $21.50 per share.
After deducting the costs of this transaction, the Company received net proceeds
of $71.5 million. After repurchasing the preferred stock, the excess proceeds
from this transaction were used to reduce debt on the Company's revolving credit
facility.
8
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders
Cabot Oil & Gas Corporation:
We have reviewed the accompanying condensed consolidated balance sheet of
Cabot Oil & Gas Corporation (the "Company") as of June 30, 2000 and the related
condensed consolidated statements of operations and cash flows for the three and
six month periods ended June 30, 2000 and June 30, 1999. These financial
statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established by the
American Institute of Certified Public Accountants. A review of interim
financial information consists principally of applying analytical procedures to
financial data and making inquiries of persons responsible for financial and
accounting matters. It is substantially less in scope than an audit conducted in
accordance with generally accepted auditing standards, the objective of which is
the expression of an opinion regarding the financial statements taken as a
whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that
should be made to the accompanying condensed consolidated financial statements
for them to be in conformity with accounting principles with generally accepted
in the United States.
We previously audited in accordance with generally accepted auditing
standards, the consolidated balance sheet as of December 31, 1999, and the
related consolidated statements of operations, stockholders' equity, and cash
flows for the year then ended (not presented herein) and in our report dated
February 11, 2000 we expressed an unqualified opinion on those consolidated
financial statements. In our opinion, the information set forth in the
accompanying condensed consolidated balance sheet as of December 31, 1999, is
fairly stated, in all material respects in relation to the consolidated balance
sheet from which it has been derived.
PricewaterhouseCoopers LLP
Houston, Texas
July 24, 2000
9
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following review of operations for the first six months of 2000 and
1999 should be read in conjunction with our Condensed Consolidated Financial
Statements and the Notes included in this Form 10-Q and with the Consolidated
Financial Statements, Notes and Management's Discussion and Analysis included in
the Cabot Oil & Gas Form 10-K for the year ended December 31, 1999.
OVERVIEW
Prices for both natural gas and oil continued to be strong during the
second quarter of 2000. Our realized natural gas price for the first half of
2000 was 31% higher than in 1999, and oil prices rose 61% over the same period.
Our net revenues for the period increased $19.9 million, or 26%, and net income
increased $9.2 million, mainly as a result of this improved price environment
and a gain on the repurchase of the outstanding preferred stock reflected as a
negative dividend. Operating cash flows were similarly impacted, improving by
$19.3 million over last year.
Our net income for the first half of 2000 was $6.0 million, or $0.23 per
share, including the impact of selected, non-recurring items. The after-tax
impact of certain of these items includes a contract settlement ($1.7 million
benefit), an impairment of long-lived assets ($5.6 million), a negative
preferred stock dividend resulting from the repurchase of the preferred stock
($5.1 million benefit), and the costs incurred as a result of closing our
Pittsburgh office ($0.6 million). Excluding these selected items, our net income
for the first half of 2000 was $5.4 million, or $0.21 per share.
We drilled 60 gross wells with a success rate of 92% compared to 26 gross
wells and an 85% success rate in the first half of 1999. For the full year, we
plan to drill 110 gross wells and spend $88.9 million in capital and exploration
expenditures compared to 73 gross wells and $88.1 million of capital and
exploration expenditures in 1999. Total expenditures were $55.7 million for the
first six months of 2000, compared to $34.8 million for the comparable period in
1999.
Natural gas production was 29.9 Bcf, down 3.2 Bcf compared to the 1999
first half. This production decline was due primarily to the sale of
non-strategic producing assets in the Appalachian region during the third
quarter of 1999, natural production declines, and delays in bringing on new
production in the Gulf Coast region, including the Etouffee wells in south
Louisiana.
Our strategic pursuits are sensitive to energy commodity prices,
particularly the price of natural gas. Market conditions have improved
significantly this year and our realized gas price for the first half of 2000 of
$2.66/Mcf was the highest we have ever realized. However, during the first half
of 1999, our realized gas price ($1.99/Mcf) was the lowest first half price
since 1995. Based on this history of market volatility, there is considerable
uncertainty about the level of natural gas prices for the remainder of this year
and beyond.
We remain focused on our strategies of growth from the drill bit,
synergistic acquisitions and the exploitation of our marketing abilities.
Management believes that these strategies are appropriate in the current
industry environment, enabling Cabot Oil & Gas to add shareholder value over the
long term.
The preceding paragraphs, discussing our strategic pursuits and goals,
contain forward-looking information. See Forward-Looking Information on page 19.
FINANCIAL CONDITION
CAPITAL RESOURCES AND LIQUIDITY
Our capital resources consist primarily of cash flows from our oil and gas
properties and asset-based borrowings supported by our oil and gas reserves. Our
level of earnings and cash flows depend on many factors, including the price of
oil and natural gas and our ability to control and reduce costs. Demand for oil
and natural gas has historically been subject to seasonal influences
characterized by peak demand and higher prices in the winter heating season.
During 2000, the commodity market has not followed this historical trend and we
have experienced higher than normal summer prices.
Our primary sources of cash during the first half of 2000 were from funds
generated from operations and the sale of common stock, both in a block trade
and through stock option exercises. Cash was primarily used to fund exploration
and development expenditures, to repurchase preferred stock, to reduce debt and
to pay dividends.
10
<PAGE>
We had a net cash outflow of $0.3 million in the first half of 2000. Net
cash inflow from operating activities totaled $51.2 million in the period. When
combined with the net proceeds from stock activity of $28.4 million, this cash
inflow funded both the $28 million debt reduction and the $49.5 million of
capital and exploration expenditures.
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
2000 1999
------ ------
(In millions)
<S> <C> <C>
Cash Flows Provided by Operating Activities............ $ 51.2 $ 31.9
====== ======
</TABLE>
Cash flows from operating activities in the 2000 first half were $19.3
million higher than the corresponding period of 1999 primarily due to higher
natural gas prices, favorable changes in working capital and the cash received
on the settlement of a gas contract dispute.
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
2000 1999
------ ------
(In millions)
<S> <C> <C>
Cash Flows Used by Investing Activities................ $ 47.7 $ 36.4
====== ======
</TABLE>
Cash flows used by investing activities in the first six months of 2000 and
1999 were substantially attributable to capital and exploration expenditures of
$49.5 million and $45.8 million, respectively. Proceeds from the sale of certain
oil and gas properties in the first half of 2000 were $1.8 million, and $9.4
million in 1999.
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
2000 1999
------ ------
(In millions)
<S> <C> <C>
Cash Flows Provided (Used) by Financing Activities..... $ (3.8) $ 4.2
====== ======
</TABLE>
In the first half of 2000, we raised $80 million from the sale of common
stock through a public offering and through stock option exercises. Of the
proceeds, $51.6 million was used to repurchase all of the then-outstanding
shares of our preferred stock. Cash flows used by financing activities in the
first half of 2000 also included $28 million used to reduce borrowings on our
revolving credit facility, and $4.2 million for the payment of dividends,
including the final dividend payment on the preferred stock. In the same period
of 1999, cash flows provided by financing activities were primarily increases in
borrowings on our revolving credit facility. These funds were used to partially
fund capital and exploration expenditures in 1999 and to pay dividends.
The available credit line under our revolving credit facility, currently
$250 million, is subject to adjustment on the basis of the present value (as
determined by the banks' petroleum engineer) of estimated future net cash flows
from proved oil and gas reserves and other assets. The revolving term of the
credit facility ends in December 2003. Management believes that we have the
ability to finance, if necessary, our capital requirements, including
acquisitions.
Our 2000 interest expense is projected to be approximately $23.3 million.
In May 2001, a $16 million principal payment is due on the 10.18% Notes. This
amount is reflected as "Current Portion of Long-Term Debt" on the balance sheet.
This payment is expected to be made with cash from operations and, if necessary,
from increased borrowings on the revolving credit facility.
11
<PAGE>
CAPITALIZATION
Our capitalization information is as follows:
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
2000 1999
-------- --------
(In millions)
<S> <C> <C>
Long-Term Debt...................................... $ 249.0 $ 277.0
Current Portion of Long-Term Debt................... 16.0 16.0
------- -------
Total Debt........................................ 265.0 293.0
------- -------
Stockholders' Equity
Common Stock (net of Treasury Stock)............... 214.3 129.8
Preferred Stock.................................... 0.0 56.7
------- -------
Total............................................. 214.3 186.5
------- -------
Total Capitalization................................ $ 479.3 $ 479.5
======= =======
Debt to Capitalization.............................. 55.3% 61.1%
</TABLE>
During the first half of 2000, we paid dividends of $2.0 million on the
common stock and $2.2 million on the 6% convertible redeemable preferred stock.
A regular dividend of $0.04 per share of common stock was declared for the
quarter ending June 30, 2000, to be paid August 25, 2000 to shareholders of
record as of August 11, 2000.
In May 2000, we bought back all of the shares of preferred stock from the
holder for $51.6 million. Since this stock had been recorded at a stated value
of $56.7 million on our balance sheet, we realized a negative dividend to
preferred stockholders of $5.1 million. We received net proceeds of $71.5
million from the sale of 3.4 million shares of common stock in a public offering
primarily to fund this transaction. After repurchasing the preferred stock, the
excess proceeds were used to reduce debt.
CAPITAL AND EXPLORATION EXPENDITURES
On an annual basis, we generally fund most of our capital and exploration
activities, excluding major oil and gas property acquisitions, with cash
generated from operations, and budget such capital expenditures based upon
projected cash flows for the year.
The following table presents major components of capital and exploration
expenditures:
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
2000 1999
------ ------
(In millions)
<S> <C> <C>
Capital Expenditures
Drilling and Facilities.......................... $ 37.8 $ 20.8
Leasehold Acquisitions........................... 3.6 4.7
Pipeline and Gathering .......................... 1.8 2.0
Other............................................ 0.8 2.3
------ ------
44.0 29.8
------ ------
Proved Property Acquisitions....................... 4.3 0.6
Exploration Expenses............................... 7.4 4.4
------ ------
Total............................................ $ 55.7 $ 34.8
====== ======
</TABLE>
Total capital and exploration expenditures in the first six months of 2000
increased $20.9 million compared to the same period of 1999, primarily as a
result of increased drilling activity.
We plan to drill 110 gross wells in 2000 compared with 73 gross wells
drilled in 1999. This 2000 drilling program includes $88.9 million in total
capital and exploration expenditures, slightly up from $88.1 million in 1999.
Expected spending in 2000 includes $74.3 million for drilling, facilities and
12
<PAGE>
exploration. In addition to the drilling and exploration program, other 2000
capital expenditures are planned primarily for lease acquisitions and for
gathering and pipeline infrastructure maintenance and construction. We will
continue to assess the natural gas price environment and may increase or
decrease the capital and exploration expenditures accordingly.
COMMODITY PRICE SWAPS
From time to time, we enter into natural gas and crude oil swap agreements
with counterparties to hedge price risk associated with a portion of our
production. These derivatives are not held for trading purposes. Under these
price swaps, we receive a fixed price on a notional quantity of natural gas and
crude oil in exchange for paying a variable price based on a market-based index,
such as the NYMEX gas and crude oil futures. We did not enter into any natural
gas price swaps on our production for the first half of 2000.
As of June 30, 2000, we had open natural gas price swap contracts on our
production as follows:
<TABLE>
<CAPTION>
Natural Gas Price Swaps
---------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Mmbtu Contract Price (in $ millions)
--------------------------------------------------------------------------------
<S> <C> <C> <C>
Natural Gas Price Swap on Our Production
---------------------------------------
Fourth Quarter 2000.................. 325,070 $3.91 $(0.1)
2001................................. 946,205 $3.45 $(0.0)
2002................................. 698,362 $3.31 $ 0.3
2003................................. 436,105 $3.14 $ 0.3
</TABLE>
The notional volume of the crude oil swap transactions was 364,000 Bbls at
an average price of $22.67 per Bbl, which represents most of our total oil
production for the six months ended June 30, 2000. Financial derivatives related
to crude oil reduced revenue by $2.2 million during the first six months of
2000. We had no open oil price swap contracts on our production at June 30,
2000. There were no crude oil price swaps in place for the first half of 1999.
Currently, we also have a series of price collars in place on a portion of
our natural gas production. There are seven collar arrangements that are based
on separate regional price indexes. If the index rises above the ceiling price,
we pay the counterparty. If the index falls below the floor price, the
counterparty will pay us. These collars are in place during the months of April
through October 2000. During the second quarter of 2000, these collars covered a
total quantity of 4,550,000 Mmbtu, or 28% of our total production for the
period. In April and May 2000, the index prices all fell within the price collar
and no settlements were made. In June 2000, all of the indexes rose above the
ceiling prices, resulting in a $1.8 million reduction to our realized revenue.
As of June 30, 2000, we had open natural gas price collars on our
production as follows:
<TABLE>
<CAPTION>
Natural Gas Price Collars
----------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Mmbtu Ceiling/Floor Price (in $ millions)
---------------------------------------------------------------------------------
<S> <C> <C> <C>
Natural Gas Price Collars on Our Production
-------------------------------------------
Third Quarter 2000................... 4,600,000 $3.13/$2.54 $(4.7)
Fourth Quarter 2000.................. 1,550,000 $3.13/$2.54 $(1.5)
</TABLE>
We also use price swaps to hedge the natural gas price risk on some
brokered transactions. Typically, we enter into contracts to broker natural gas
at a variable price based on the market index price. However, in some
circumstances, some of our customers or suppliers request that a fixed price be
stated in the contract. After entering into these fixed price contracts to meet
13
<PAGE>
the needs of our customers or suppliers, we may use price swaps to effectively
convert these fixed price contracts to market-sensitive price contracts. These
price swaps are held by us to their maturity and are not held for trading
purposes.
During the first six months of 2000 and 1999 we entered into price swaps
with total notional quantities of 1,464,800 and 2,180,000 Mmbtu, respectively,
related to our brokered activities representing 5% and 10%, respectively, of our
total volume of brokered natural gas sold.
As of June 30, 2000, we had no open commodity price swap contracts on our
brokered activity. Financial derivatives related to brokered natural gas reduced
revenue by $16,000 in the first half of 2000 and reduced revenue by $37,000 in
the same period of 1999.
We are exposed to market risk on these open contracts, to the extent of
changes in market prices of natural gas and oil. However, the market risk
exposure on these hedged contracts is generally offset by the gain or loss
recognized upon the ultimate sale of the commodity that is hedged.
CONCLUSION
Our financial results depend upon many factors, particularly the price of
natural gas and oil and our ability to market gas on economically attractive
terms. The average produced natural gas sales price received in the first half
of 2000 was up 31% over 1999, after declining 12% from the first half of 1998 to
1999. The volatility of natural gas prices in recent years remains prevalent in
2000 with wide price swings in day-to-day trading on the NYMEX futures market.
Given this continued price volatility, we cannot predict with certainty what
pricing levels will be in the future. Because future cash flows are subject to
these variables, we cannot assure you that our operations will provide cash
sufficient to fully fund our planned capital expenditures.
We believe our capital resources, supplemented with external financing, if
necessary, are adequate to meet our capital requirements.
The preceding paragraph contains forward-looking information. See
Forward-Looking Information on page 19.
14
<PAGE>
RESULTS OF OPERATIONS
For the purpose of reviewing our results of operations, "Net Income (Loss)"
is defined as net income or loss available to common shareholders.
SELECTED FINANCIAL AND OPERATING DATA
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------- ----------------
2000 1999 2000 1999
------ ------ ------ ------
(In millions, except where noted)
<S> <C> <C> <C> <C>
Net Operating Revenues................. $ 46.5 $ 41.1 $ 96.2 $ 76.3
Operating Expenses..................... 46.1 33.9 80.9 66.3
Operating Income....................... 0.4 8.2 15.2 11.0
Interest Expense....................... 5.4 6.5 11.3 13.2
Net Income (Loss)...................... 1.5 0.1 6.0 (3.2)
Earnings (Loss) Per Share - Basic...... $ 0.05 $ 0.00 $ 0.23 $(0.13)
Earnings (Loss) Per Share - Diluted.... $ 0.05 $ 0.00 $ 0.23 $(0.13)
Natural Gas Production (Bcf)
Gulf Coast........................... 3.0 4.4 6.4 7.5
West................................. 7.2 7.4 14.5 14.8
Appalachia........................... 4.5 5.2 9.0 10.8
------ ------ ------ ------
Total Company...................... 14.7 17.0 29.9 33.1
Natural Gas Production Sales Prices ($/Mcf)
Gulf Coast........................... $ 3.05 $ 2.16 $ 2.78 $ 1.99
West................................. $ 2.51 $ 1.86 $ 2.38 $ 1.79
Appalachia........................... $ 2.63 $ 2.31 $ 2.85 $ 2.28
Total Company...................... $ 2.66 $ 2.08 $ 2.61 $ 1.99
Crude/Condensate
Volume (MBbl)........................ 205 237 400 467
Price ($/Bbl)........................ $22.66 $16.20 $22.42 $13.90
Brokered Natural Gas Margin
Volume (Bcf)......................... 11.4 10.2 25.2 22.9
Margin ($/Mcf)....................... $ 0.10 $ 0.10 $ 0.10 $ 0.08
</TABLE>
The table below presents the after-tax effect of certain selected items on
our results of operations for the three- and six-month periods ended June 30,
2000.
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------- -------------------
Amount Per Share Amount Per Share
------ --------- ------ ---------
(In millions, except per share amounts)
<S> <C> <C> <C> <C>
NET INCOME BEFORE SELECTED ITEMS............... $ 2.6 $ 0.10 $ 5.4 $ 0.21
Benefit from miscellaneous net revenue(1)...... 0.0 0.00 1.7 0.07
Impairment of long-lived assets ............... (5.6) (0.22) (5.6) 0.22)
Closure of Pittsburgh office .................. (0.6) (0.03) (0.6) (0.03)
Negative preferred stock dividend.............. 5.1 0.20 5.1 0.20
----- ------ ----- ------
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS.... $ 1.5 $ 0.05 $ 6.0 $ 0.23
===== ====== ===== ======
</TABLE>
(1) REPRESENTS NET BENEFIT, PRIMARILY FROM A CONTRACT SETTLEMENT.
15
<PAGE>
These selected items impacted our financial results. Because they are not a
part of our normal business, we have isolated their effect in the table above.
These selected items are as follows:
- Miscellaneous net revenue, primarily from the settlement of a natural gas
sales contract, was recorded in the first quarter ($1.7 million after tax).
- A $9.1 million impairment ($5.6 million after tax) was recorded on the
Beaurline field in south Texas as a result of a casing collapse in two of
the field's wells.
- We announced the closure of the regional office in Pittsburgh in May 2000
and recorded costs of $1.0 million ($0.6 million after tax). These costs
were recorded in the income statement categories that will receive the
future savings benefit ($0.6 million in operations, $0.1 million in
exploration and $0.3 million in administration).
- As a result of repurchasing all of the preferred stock at less than the
book value, we recorded a $5.1 million negative stock dividend in May 2000.
In the first quarter of 1999, a $1.0 million gain was recorded on the sale of
non-strategic assets. Excluding this item, the net loss for the first half of
1999 was $3.8 million, or $0.15 per share. The discussion below excludes the
impact of these selected items.
SECOND QUARTERS OF 2000 AND 1999 COMPARED
NET INCOME AND REVENUES. We reported net income before the selected items
in the second quarter of 2000 of $2.6 million, or $0.10 per share. During the
corresponding quarter of 1999, we recorded a net loss excluding the selected
item of $0.5 million, or $0.02 per share. Operating revenues increased by $5.4
million and operating income increased by $2.3 million. Natural gas made up 84%,
or $38.9 million, of net operating revenue. The increase in net operating
revenues was driven primarily by a 28% improvement in the average natural gas
price, offset slightly by a 14% decrease in natural gas production as discussed
below. Net income and operating income were similarly impacted by the increase
in the average natural gas price.
Natural gas production volume in the Gulf Coast region was down 1.4 Bcf, or
32%, to 3.0 Bcf primarily due to delays in bringing on new production, including
the Etouffee wells in south Louisiana. Natural gas production volume in the
Western region was down 0.2 Bcf, or 3%, to 7.2 Bcf primarily due to a decrease
in drilling activity in the Mid-Continent area during 1999. Natural gas
production volume in the Appalachian region was down 0.7 Bcf, or 16%, to 4.5
Bcf, as a result of the sale of certain non-strategic assets effective October
1, 1999, and a decrease in drilling activity in the region in 1999. The decline
in total natural gas production of 2.3 Bcf, or 14%, reduced revenue by $4.9
million in the second quarter of 2000.
The average Gulf Coast natural gas production sales price rose $0.89 per
Mcf, or 41%, to $3.05, increasing net operating revenues by approximately $2.6
million. In the Western region, the average natural gas production sales price
increased $0.65 per Mcf, or 35%, to $2.51, increasing net operating revenues by
approximately $4.5 million. The average Appalachian natural gas production sales
price increased $0.32 per Mcf, or 14%, to $2.63, increasing net operating
revenues by approximately $1.4 million. The overall weighted average natural gas
production sales price increased $0.58 per Mcf, or 28%, to $2.66, increasing
revenues by $8.5 million. Early in the second quarter, we entered into certain
natural gas price collars that limited the benefit we received when natural gas
price indexes rose later in the quarter. If these hedges had not been in place
for the second quarter, our realized natural gas price would have been $0.12 per
Mcf higher.
Crude oil prices rose $6.46 per Bbl, or 40%, to $22.66, resulting in an
increase to net operating revenues of approximately $1.3 million. Our realized
oil price was impacted by the $1.0 million revenue reduction that resulted from
price swap activity as discussed in the Commodity Price Swaps section of this
document. In addition, the volume of crude oil sold in the quarter decreased by
32 Mbbls, or 13%, to 205 Mbbls, reducing net operating revenues by $0.5 million.
This decline in volume is largely due to the Gulf Coast, which has been impacted
by the delays in new production similar to those for natural gas discussed
above.
16
<PAGE>
Other net operating revenues increased $1.1 million to $1.9 million. This
improvement was a result of changes in activity in the following areas:
- A natural gas liquids plant in the Gulf Coast contributed an additional
$0.6 million.
- Section 29 revenues were increased by $0.3 million, as we are no longer
deferring revenue from non-certified wells. A recent FERC ruling may allow
us to certify these wells and take advantage of the related tax credits.
- Revenue from our brine treatment plant in the Appalachian region increased
$0.2 million.
COSTS AND EXPENSES. Excluding the costs incurred in connection with the
closure of our Pittsburgh office and the impairment of long-lived assets of $9.1
million, total costs and expenses from operations increased $2.1 million, or 6%,
in the second quarter of 2000 compared to the same period of 1999. The primary
reasons for this fluctuation are as follows:
- Direct operating expense increased $0.8 million, or 10%, primarily as a
result of costs associated with the expansion of the Gulf Coast regional
office, both in staffing and office facilities. Additionally, we accrued
approximately $0.3 million for incentive compensation this quarter. In
1999, incentive compensation was accrued largely in the fourth quarter.
- Exploration expense increased $2.0 million, or 100%, primarily as a result
of a $1.0 million dry hole recorded in June 2000 in the Gulf Coast, $0.3
million in delay rentals incurred as a result of drilling delays in the
Gulf Coast and $0.2 for staffing increases in this region. Additionally,
$0.3 million in higher geological and geophysical costs were incurred in
the Appalachian region.
- Depreciation, depletion, amortization and impairment expense decreased $2.1
million, or 13%, due to the decrease in natural gas and oil production this
quarter.
- General and administrative costs rose $0.6 million, or 14%, primarily as a
result of legal costs related to certain routine litigation as well as the
increased cost associated with our new corporate office space. - Taxes
other than income rose $0.8 million, or 19%, as a result of higher
commodity prices realized this quarter.
Interest expense decreased $1.1 million as a result of a lower average
level of outstanding debt during the second quarter of 2000 when compared to the
second quarter of 1999.
Income tax expense increased $1.3 million due to the comparable increase in
earnings before income tax excluding the selected items.
SIX MONTHS OF 2000 AND 1999 COMPARED
NET INCOME AND REVENUES. Excluding the selected items, we reported net
income in the first half of 2000 of $5.4 million, or $0.21 per share. During the
corresponding half of 1999, we had a net loss of $3.8 million, or $0.15 per
share. Operating revenues and operating income increased $17.0 million and $12.4
million, respectively. Natural gas made up 84%, or $78.0 million, of net
operating revenue. The increase in net operating revenues was driven primarily
by a 31% increase in the average natural gas price, partially offset by a 10%
decrease in natural gas production as discussed below. Net income and operating
income were similarly impacted by the increase in natural gas prices, but
reduced by increases in operating expenses as discussed below.
Natural gas production volume in the Gulf Coast region was down 1.1 Bcf, or
15%, to 6.4 Bcf primarily due to delays in bringing on new production, including
the Etouffee wells in south Louisiana. Natural gas production volume in the
Western region was down 0.3 Bcf, or 2%, to 14.5 Bcf primarily due to a decrease
in drilling activity in the Mid-Continent area during 1999. Natural gas
production volume in the Appalachian region was down 1.8 Bcf, or 17%, to 9.0
17
<PAGE>
Bcf, as a result of the sale of certain non-strategic assets effective October
1, 1999, and a decrease in drilling activity in the region in 1999 and 2000. The
decline in total natural gas production of 3.2 Bcf, or 10%, reduced revenue by
$6.4 million in the first half of 2000.
The average Gulf Coast natural gas production sales price rose $0.79 per
Mcf, or 40%, to $2.78, increasing net operating revenues by approximately $5.0
million. In the Western region, the average natural gas production sales price
increased $0.59 per Mcf, or 33%, to $2.38, increasing net operating revenues by
approximately $8.4 million. The average Appalachian natural gas production sales
price increased $0.57 per Mcf, or 25%, to $2.85, increasing net operating
revenues by approximately $5.0 million. The overall weighted average natural gas
production sales price increased $0.62 per Mcf, or 31%, to $2.61, increasing
revenues by $18.4 million.
Crude oil prices increased $8.52 per Bbl, or 61%, to $22.42, resulting in
an increase to net operating revenues of approximately $3.4 million. The volume
of crude oil sold in the first six months of the year decreased by 67 Mbbl, or
14%, to 400 Mbbl, decreasing net operating revenues by $0.9 million.
The brokered natural gas margin increased $0.6 million to $2.6 million. The
primary cause was a $0.02 per Mcf improvement in net margin that resulted in a
$0.4 million revenue increase. Additionally, we experienced a 2.3 Bcf volume
increase, which resulted in a $0.2 million increase in brokered natural gas
margin.
Excluding the selected items, other net operating revenues increased $1.9
million to $3.8 million. This improvement was a result of changes in activity in
the following areas:
- A natural gas liquids plant in the Gulf Coast contributed an additional
$0.6 million and the Appalachian region's plant contributed an additional
$0.4 million.
- Transportation revenue increased $0.6 million,
- Revenue from our brine treatment plant in the Appalachian region increased
$0.2 million.
COSTS AND EXPENSES. Excluding the selected items, total costs and expenses
from operations increased $4.5 million, or 7%, due primarily to the following:
- Direct operating expense increased $1.4 million, or 9%, primarily as a
result of costs associated with the expansion of the Gulf Coast regional
office, both in staffing and office facilities. Additionally, we accrued
approximately $0.5 million for incentive compensation during the first half
of 2000. In 1999, incentive compensation was accrued largely in the fourth
quarter.
- Exploration expense increased $2.8 million, or 64%, as a result of an
increase in dry hole costs primarily as a result of one high-cost dry hole
in the Gulf Coast this year ($1.0 million). Additionally, delay rental
costs increased mainly as a result of drilling delays in the Gulf Coast
($0.8 million), geological and geophysical costs were higher in both the
Appalachian and Gulf Coast regions ($0.5 million), and higher costs were
incurred as a result of increased staffing in the Gulf Coast region ($0.4
million).
- Depreciation, depletion and amortization expense decreased $2.7 million, or
9%, due to the decrease in natural gas and oil production this quarter.
- General and administrative expenses increased $1.2 million, or 14%,
primarily as a result of the increased costs associated with the new
corporate headquarters. Additionally, we accrued approximately $0.3 million
for incentive compensation during the first half of 2000.
- Taxes other than income rose $1.8 million, or 22%, as a result of higher
commodity prices realized this year.
Interest expense decreased $1.8 million as a result of a lower average
level of outstanding debt during the first half of 2000 when compared to the
first half of 1999.
Income tax expense increased $5.1 million due to the comparable increase in
earnings before income tax excluding the selected items.
18
<PAGE>
* * *
FORWARD-LOOKING INFORMATION
The statements regarding future financial performance and results and
market prices and the other statements which are not historical facts contained
in this report are forward-looking statements. The words "expect," "project,"
"estimate," "believe," "anticipate," "intend," "budget," "plan," "forecast,"
"predict" and similar expressions are also intended to identify forward-looking
statements. Such statements involve risks and uncertainties, including, but not
limited to, market factors, market prices (including regional basis
differentials) of natural gas and oil, results for future drilling and marketing
activity, future production and costs and other factors detailed herein and in
our other Securities and Exchange Commission filings. Should one or more of
these risks or uncertainties materialize, or should underlying assumptions prove
incorrect, actual outcomes may vary materially from those indicated.
19
<PAGE>
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders
On May 9, 2000, the Company held its Annual Meeting of Stockholders. In
connection with this meeting, the Company's stockholders voted on two matters:
the election of four directors and the ratification of the appointment of
PricewaterhouseCoopers LLP as the Company's independent auditors. Of the total
outstanding shares, 22,918,570, or 91%, were voted. There were no broker
nonvotes.
Shareholders voted to re-elect four directors by the following vote:
<TABLE>
<CAPTION>
<S> <C>
HENRY O. BOSWELL
Votes cast in favor: 22,743,262
Votes withheld: 175,308
WILLIAM R. ESLER
Votes cast in favor: 22,740,990
Votes withheld: 177,580
P. DEXTER PEACOCK
Votes cast in favor: 22,744,223
Votes withheld: 174,347
CHARLES P. SIESS, JR.
Votes cast in favor: 19,541,221
Votes withheld: 3,377,349
</TABLE>
The terms of office of directors Robert F. Bailey, John G.L. Cabot, C.
Wayne Nance, Ray R. Seegmiller, Arthur L. Smith and William P. Vititoe 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, 22,899,613 were
in favor of the ratification, 17,146 were against, and 1,811 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 2000 Form 10-Q.
(b) Reports on Form 8-K
None
20
<PAGE>
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CABOT OIL & GAS CORPORATION
(Registrant)
August 9, 2000 By: /s/ Paul F. Boling
--------------------------------------------
Paul F. Boling, Vice President - Finance
(Principal Executive Officer Duly Authorized
to sign on Behalf of the Registrant)
By: /s/ Henry C. Smyth
--------------------------------------------
Henry C. Smyth, Controller
(Principal Accounting Officer)
21
<PAGE>
EXHIBIT 15.1
PricewaterhouseCoopers LLP Awareness Letter
Securities and Exchange Commission
450 Fifth Street, NW
Washington, D.C. 20549
Re: Cabot Oil & Gas Corporation
Registration Statements on Form S-8 and Form S-3
Commissioners:
We are aware that our report dated July 24, 2000 on our review of the interim
condensed consolidated financial information of Cabot Oil & Gas Corporation (the
"Company") as of and for the three and six month periods ended June 30, 2000 and
included in the Company's quarterly report on Form 10-Q for the quarter then
ended is incorporated by reference in its Registration Statements on Form S-8
filed with the Securities and Exchange Commission on June 23, 1990, November 1,
1993, May 20, 1994 and May 23, 2000 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 9, 2000
22
