<PAGE> 1
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the Fiscal year ended December 31, 1997
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)
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
CLASS A COMMON STOCK, PAR VALUE $.10 PER SHARE NEW YORK STOCK EXCHANGE
RIGHTS TO PURCHASE PREFERRED STOCK NEW YORK STOCK EXCHANGE
Securities registered pursuant to Section 12(g) of the Act: None
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
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K [ ].
The aggregate market value of Class A Common Stock, par value $.10 per
share ("Common Stock"), held by non-affiliates (based upon the closing sales
price on the New York Stock Exchange on February 27, 1998), was approximately
$510,000,000.
As of February 27, 1998, there were 24,680,936 shares of Common Stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Stockholders to
be held May 12, 1998 are incorporated herein by reference in Items 10, 11, 12,
and 13 of Part III of this report.
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PART I PAGE
<S> <C> <C>
ITEMS 1 AND 2 Business and Properties 2
ITEM 3 Legal Proceedings 16
ITEM 4 Submission of Matters to a Vote of Security Holders 16
Executive Officers of the Registrant 16
PART II
ITEM 5 Market for Registrant's Common Equity and Related Stockholder Matters 17
ITEM 6 Selected Historical Financial Data 18
ITEM 7 Management's Discussion and Analysis of Financial Condition and Results of Operations 19
ITEM 8 Financial Statements and Supplementary Data 29
ITEM 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 56
PART III
ITEM 10 Directors and Executive Officers of the Registrant 56
ITEM 11 Executive Compensation 56
ITEM 12 Security Ownership of Certain Beneficial Owners and Management 56
ITEM 13 Certain Relationships and Related Transactions 56
PART IV
ITEM 14 Exhibits, Financial Statement Schedules and Reports on Form 8-K 57
</TABLE>
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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," "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.
1
<PAGE> 3
PART I
ITEM 1. BUSINESS
GENERAL
Cabot Oil & Gas Corporation (the "Company") explores for, develops,
produces, stores, transports, purchases and markets natural gas and, to a lesser
extent, produces and sells crude oil. Substantially all of the Company's
operations are in the Appalachian Region of West Virginia and Pennsylvania and
in the Western Region, including the Anadarko Basin of southwestern Kansas,
Oklahoma and the Texas Panhandle, the Green River Basin of Wyoming, and South
Texas. At December 31, 1997, the Company had approximately 938.6 Bcfe of total
proved reserves, 96% of which was natural gas. A significant portion of the
Company's natural gas reserves is located in long-lived fields with extended
production histories.
The Company, a Delaware corporation, was organized in 1989 as the
successor to the oil and gas business of Cabot Corporation ("Cabot"), which was
begun in 1891. In 1990, the Company completed its initial public offering of
approximately 18% of the outstanding common stock held by Cabot. Cabot
distributed the remaining common stock of the Company to the shareholders of
Cabot in 1991. The Company has been publicly traded on the New York Stock
Exchange since its initial public offering.
Unless the context otherwise requires, all references herein to the
Company include Cabot Oil & Gas Corporation, its predecessors and subsidiaries.
Similarly, all references to Cabot include Cabot Corporation and its affiliates.
All references to wells are gross, unless otherwise stated.
The following table summarizes certain information, at December 31, 1997
regarding the Company's proved reserves, productive wells, developed and
undeveloped acreage and infrastructure.
SUMMARY OF RESERVES, PRODUCTION, ACREAGE AND OTHER INFORMATION BY
AREAS OF OPERATION (1)
<TABLE>
<CAPTION>
Total Appalachian Western
Company Region Region(2)
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
RESERVES/PRODUCTION:
Proved reserves
Developed (Bcfe) 767.9 346.4 421.5
Undeveloped (Bcfe) 170.7 71.5 99.2
--------- ------- -------
Total (Bcfe) 938.6 417.9 520.7
========= ======= =======
Daily production (Mmcfe) net 185.4 70.2 115.2
Gross productive wells 4,242.0 2,905.0 1,337.0
Net productive wells 3,441.4 2,696.4 745.0
Percent of wells operated 84.8% 96.7% 58.8%
ACREAGE:
Net acreage
Developed acreage 1,003,603 719,840 283,763
Undeveloped acreage 373,946 255,037 118,909
--------- ------- -------
Total 1,377,549 974,877 402,672
========= ======= =======
- --------------------------------------------------------------------------------
</TABLE>
(1) As of December 31, 1997. For additional information regarding the Company's
estimates of proved reserves and other data, see "Business--Reserves," and
the "Supplemental Oil and Gas Information" to the Consolidated Financial
Statements.
(2) Includes all properties outside the Appalachian Region, including
properties located in Anadarko, the Rocky Mountains and the Gulf Coast
areas.
2
<PAGE> 4
EXPLORATION, DEVELOPMENT AND PRODUCTION
The Company is one of the largest producers of natural gas in the
Appalachian basin, where it has conducted operations for more than a century.
The Company has had operations in the Anadarko basin for over 60 years. The
Company acquired its operations in the Rocky Mountains and the Gulf Coast
pursuant to the merger of Washington Energy Resources Company with the Company
which was completed in May 1994. Historically, the Company has maintained its
reserve base through low-risk development drilling and strategic acquisitions,
and recently has stepped up its emphasis on exploration. The Company continues
to focus its operations in the Appalachian and Western Regions through
development of undeveloped reserves and acreage, acquisition of oil and gas
producing properties and new exploration opportunities.
While continuing its strong development drilling program, the Company has
significantly expanded its exploration program in the last two years. Both the
Appalachian and Western Regions added more exploratory wells to their respective
drilling programs in 1997, increasing from 25 to 33 wells in Appalachia and from
5 to 13 wells in the West. Both regions had favorable results in the 1997
program with success rates of 76% and 46%, in the Appalachian and Western
Regions, respectively. A large part of the exploration activity in the Western
Region has been focused in the Gulf Coast area. In 1997, reserves in the Gulf
Coast area grew from 27.1 Bcfe to 56.5 Bcfe, or 108%, due primarily to the
Company's exploratory drilling strategy. The Company's 1998 exploration program
includes drilling expenditures of $17 million, which represents 24% of the
planned 1998 drilling program.
APPALACHIAN REGION
The Company's exploration, development and production activities in the
Appalachian Region are concentrated in Pennsylvania, Ohio, West Virginia, and
Virginia. Operations are managed by a regional office in Pittsburgh. At December
31, 1997, the Company had approximately 417.9 Bcfe of proved reserves
(substantially all natural gas) in the Appalachian Region, constituting 45% of
the Company's total proved reserves.
The Company has 2,905 productive wells (2,696.4 net), of which 2,810 wells
are operated by the Company. There are multiple producing intervals which
include the Upper Devonian, Oriskany, Berea, and Big Lime trend formations at
depths primarily ranging from 1,500 to 6,000 feet. Average net daily production
in 1997 was 70.0 Mmcfe. While natural gas production volumes from Appalachian
reservoirs are relatively low on a per-well basis compared to other areas of the
United States, the productive life of Appalachian reserves is relatively long.
In October 1997, the Company sold 912 wells primarily located in northwest
Pennsylvania (the "Meadville properties") which have been producing
approximately 15 Mmcfe per day from the Medina formation to Lomak Petroleum
Incorporated.
In 1997, the Company drilled 120 wells (96.8 net) in the Appalachian
Region, of which 87 were development wells (78.7 net). Capital and exploration
expenditures, including pipeline expenditures for the year were $38.0 million.
In the 1998 drilling program year, the Company has plans to drill 126 wells.
At December 31, 1997, the Company had 974,877 net acres in the region,
including 719,840 net developed acres. At year end, the Company had identified
205 proved undeveloped drilling locations.
The Company also owns and operates a brine treatment plant near Franklin,
Pennsylvania. The plant, which began operating in 1985, processes and treats
waste fluid generated during the drilling, completion and subsequent production
of oil and gas wells. The plant provides services to the Company and certain
other oil and gas producers in southwestern New York, eastern Ohio and western
Pennsylvania.
The Company believes that it gains operational efficiency in the
Appalachian Region because of its large acreage position, high concentration of
wells, natural gas gathering and pipeline systems and storage capacity.
3
<PAGE> 5
WESTERN REGION
The Company's exploration, development and production activities in the
Western Region are primarily focused in the Anadarko basin in Kansas, Oklahoma
and the Panhandle of Texas, in the Green River Basin of Wyoming and in South
Texas. Operations for the Western Region are managed from a regional office in
Denver and include the Anadarko, Rocky Mountain and Gulf Coast areas. At
December 31, 1997, the Company had approximately 520.7 Bcfe of proved reserves
(93.8% natural gas) in the Western Region, constituting 55% of the Company's
total proved reserves.
ANADARKO
The Company has 760 productive wells (502.2 net) in the Anadarko area of
which 556 wells are operated by the Company. Principal producing intervals in
Anadarko are in the Chase, Morrow and Chester formations at depths ranging from
1,500 to 11,000 feet. Average net daily production in 1997 was 46.5 Mmcfe.
In 1997, the Company drilled 35 wells (17.8 net) in Anadarko, including 32
development wells (16.2 net). Capital and exploration expenditures for the year
were $13.8 million. In the 1998 drilling program year, the Company has plans to
drill 45 wells.
At December 31, 1997, the Company had approximately 224,860 net acres,
including approximately 190,306 net developed acres. At year end, the Company
had identified 57 proved undeveloped drilling locations.
ROCKY MOUNTAINS
The Company has 420 productive wells (185.7 net) in the Rocky Mountain
area of which 196 wells are operated by the Company. Principal producing
intervals in Rocky Mountain are in the Frontier and Dakota formations at depths
ranging from 9,000 to 13,000 feet. Average net daily production in 1997 was 43.0
Mmcfe.
In October 1997, the Company acquired oil and gas producing properties
from Equitable Resources Energy Company in the Green River Basin of Wyoming (the
"Green River properties"). These properties included approximately 72 Bcfe of
reserves, interests in 63 wells with estimated daily net production of 10 Mmcfe,
and nearly 70 potential drilling locations. This acquisition increased the
Company's reserves in the area by 46%.
In 1997, the Company drilled 50 wells (26.6 net) in the Rocky Mountains
including 49 development wells (26.2 net). Capital and exploration expenditures
for the year were $61.9 million, including approximately $45 million for the
Green River property acquisition. In the 1998 drilling program year, the Company
has plans to drill 68 wells.
At December 31, 1997, the Company had approximately 150,421 net acres,
including approximately 76,507 net developed acres. At year end, the Company had
identified 75 proved undeveloped drilling locations.
GULF COAST
The Company has 157 productive wells (57.1 net) in the Gulf Coast area of
which 34 wells are operated by the Company. Principal producing intervals in
Gulf Coast are in the Frio, Wilcox and Vicksburg formations at depths ranging
from 6,000 to 14,000 feet. Average net daily production in 1997 was 25.3 Mmcfe.
In 1997, the Company drilled 20 wells (10.3 net) in the Gulf Coast
including 11 development wells (6.7 net). Capital and exploration expenditures
for the year were $25.4 million. In the 1998 drilling program year, the Company
has plans to drill 31 wells.
At December 31, 1997, the Company had approximately 27,391 net acres,
including approximately 16,950 net developed acres. At year end, the Company had
identified 5 proved undeveloped drilling locations.
4
<PAGE> 6
GAS MARKETING
The Company is engaged in a wide array of marketing activities designed to
offer its customers long-term, reliable supplies of natural gas. Utilizing its
pipeline and storage facilities, gas procurement ability and transportation and
natural gas risk management expertise, the Company provides a menu of services
that includes gas supply and transportation management, short and long-term
supply contracts, capacity brokering and risk management alternatives.
The marketing of natural gas has changed significantly as a result of FERC
Order 636 ("Order 636"), which was issued by the Federal Energy Regulatory
Commission in 1992. Order 636 required pipelines to unbundle their gas sales,
storage and transportation services. As a result, local distribution companies
and end-users will separately contract these services from gas marketers and
producers. Order 636 has had the effect of creating greater competition in the
industry while also providing the Company the opportunity to serve broader
markets. Since Order 636 was issued, there has been an increase in the number of
third-party producers that use the Company to market their gas. In addition, the
Company has experienced, as a result of Order 636, increased competition for
markets which has placed pressure on the premiums it has received.
APPALACHIAN REGION
The Company's principal markets for its Appalachian Region natural gas are
in the northeastern United States. The Company's marketing subsidiary purchases
the Company's natural gas production in the Appalachian Region as well as
production from local third-party producers and other suppliers to aggregate
larger volumes of natural gas for resale. This marketing subsidiary sells
natural gas to industrial customers, local distribution companies ("LDCs") and
gas marketers both on and off the Company's pipeline and gathering system.
A majority of the Company's natural gas sales volume in the Appalachian
Region is being sold at market -responsive prices under contracts with a term of
one year or less. Of these short-term sales, spot market sales are made under
month-to-month contracts while industrial and utility sales generally are made
under year-to-year contracts. Approximately 15% of the Appalachian production is
sold on fixed price contracts which typically renew annually.
The Company's Appalachian production is generally sold at a premium price
compared to production from other producing regions due to its close proximity
to eastern markets. However, that premium has been reduced from historic levels
due to increased competition in the market place resulting in part from changes
in transportation and sales arrangements due to the implementation of pipeline
open access tariffs and Order 636.
The Company operates a number of gas gathering and pipeline systems, made
up of approximately 2,800 miles of pipeline with interconnects to three
interstate pipeline systems and five LDCs. The Company's natural gas gathering
and pipeline systems enable the Company to connect new wells quickly and to
transport natural gas from the wellhead directly to interstate pipelines, LDCs
and industrial end-users. Control of its gathering and pipeline systems also
enables the Company to purchase, transport and sell natural gas produced by
third parties. In addition, the Company can undertake development drilling
operations without relying upon third parties to transport its natural gas while
incurring only the incremental costs of pipeline and compressor additions to its
system.
The Company has two natural gas storage fields located in West Virginia,
with a combined working capacity of approximately 4 Bcf of natural gas. The
Company uses these storage fields to take advantage of the seasonal variations
in the demand for natural gas and the higher prices typically associated with
winter natural gas sales, while maintaining production at a nearly constant rate
throughout the year. The storage fields also enable the Company to periodically
increase the volume of natural gas it can deliver by more than 40% above the
volume that it could deliver solely from its production in the Appalachian
Region. The pipeline systems and storage fields are fully integrated with the
Company's producing operations.
5
<PAGE> 7
WESTERN REGION
The Company's principal markets for Western Region natural gas are in the
northwestern, midwestern, and northeastern United States. The Company's
marketing subsidiary purchases all of the Company's natural gas production in
the Western Region. This marketing subsidiary sells the natural gas to
cogenerators, natural gas processors, LDCs, industrial customers and marketing
companies.
Currently, a majority of the Company's natural gas production in the
Western Region is being sold primarily under contracts with a term of one year
or less at market-responsive prices. Approximately 15% of the Western Region's
production is sold under a 15 year cogeneration contract with 11 years remaining
that escalates in price by 5% per year (See Item 3. Legal Proceedings). The
Western Region properties are connected to the majority of the Midwestern,
Northwestern, and Gulf Coast interstate and intrastate pipelines, affording the
Company access to multiple markets.
The Company also produces and markets approximately 1,400 barrels a day of
crude oil/condensate in the Western Region at market responsive prices.
RISK MANAGEMENT
In 1997, the Company entered into certain transactions to manage price
risks associated with its production and purchase commitments. The Company
utilized certain natural gas price swap agreements ("price swaps") to attempt to
manage price risk more effectively and improve the Company's realized natural
gas prices. These price swaps call for payments to (or to receive payments from)
counterparties based upon the differential between a fixed and a variable gas
price. The Company plans to continue to evaluate on an ongoing basis the benefit
of this strategy in the future. See the Overview section of Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations, or
Note 13 of the Notes to the Consolidated Financial Statements for further
discussion.
6
<PAGE> 8
RESERVES
CURRENT RESERVES
The following table sets forth information regarding the Company's
estimates of its net proved reserves at December 31, 1997.
<TABLE>
<CAPTION>
Natural Gas (Mmcf) Liquids(1) (Mbbl) Total(2) (Mmcfe)
- -----------------------------------------------------------------------------------------------------------------------
Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Appalachian 343,718 71,500 415,218 447 0 447 346,400 71,500 417,900
Western(3) 395,046 93,165 488,211 4,412 1,010 5,422 421,519 99,224 520,743
------- ------- ------- ----- ----- ----- ------- ------- -------
Total 738,764 164,665 903,429 4,859 1,010 5,869 767,919 170,724 938,643
======= ======= ======= ===== ===== ===== ======= ======= =======
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) Liquids include crude oil, condensate and natural gas liquids (Ngl).
(2) Natural Gas Equivalents are determined using the ratio of 6.0 Mcf of natural
gas to 1.0 Bbl of crude oil or condensate.
(3) Includes proved reserves attributable to Anadarko, Rocky Mountains and the
Gulf Coast Areas.
The proved reserve estimates presented herein were prepared by the
Company's petroleum engineering staff and reviewed by Miller and Lents, Ltd.,
independent petroleum engineers. For additional information regarding the
Company's estimates of proved reserves, the review of such estimates by Miller
and Lents, Ltd. and certain other information regarding the Company's oil and
gas reserves, see the Supplemental Oil and Gas Information to the Consolidated
Financial Statements included in Item 8 hereof. A copy of the review letter by
Miller and Lents, Ltd., has been filed as an exhibit to this Form 10-K. The
Company's estimates of proved reserves set forth in the foregoing table do not
differ materially from those filed by the Company with other federal agencies.
The Company's reserves are sensitive to natural gas sales prices and their
effect on economic producing rates. The Company's reserves are based on oil and
gas prices in effect at December 31, 1997.
There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond the control of the Company and,
therefore, the reserve information set forth in this Form 10-K represents only
estimates. Reserve engineering is a subjective process of estimating underground
accumulations of crude oil and natural gas that cannot be measured in an exact
manner, and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment. As
a result, estimates of different engineers often vary. In addition, results of
drilling, testing and production subsequent to the date of an estimate may
justify revision of such estimate. Accordingly, reserve estimates are often
different from the quantities of crude oil and natural gas that are ultimately
recovered. The meaningfulness of such estimates is highly dependent upon the
accuracy of the assumptions upon which they were based. In general, the volume
of production from oil and gas properties owned by the Company declines as
reserves are depleted. Except to the extent the Company acquires additional
properties containing proved reserves or conducts successful exploration and
development activities or both, the proved reserves of the Company will decline
as reserves are produced.
7
<PAGE> 9
HISTORICAL RESERVES
The following table sets forth certain information regarding the Company's
estimated proved reserves for the periods indicated.
<TABLE>
<CAPTION>
Oil, Condensate
Natural Gas (Mmcf) & NGLs (Mbbl) Total (Mmcfe)
- ----------------------------------------------------------------------------------------------------------------------------
APP WEST TOTAL APP WEST TOTAL APP WEST TOTAL
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
DECEMBER 31, 1994 560,494 392,589 953,083 167 7,869 8,036 561,496 439,803 1,001,299
Revisions of prior estimates 3,699 10,333 14,032 65 (713) (648) 4,086 6,061 10,147
Extensions, discoveries and
other additions 12,333 22,075 34,408 23 151 174 12,471 22,982 35,453
Production (27,530) (30,191) (57,721) (18) (722) (740) (27,637) (34,525) (62,162)
Purchases of reserves in place 576 840 1,416 0 15 15 576 929 1,505
Sales of reserves in place (34,016) (21,352) (55,368) (18) (1,509) (1,527) (34,123) (30,412) (64,535)
------- ------- ------- --- ----- ----- ------- ------- ---------
DECEMBER 31, 1995 515,556 374,294 889,850 219 5,091 5,310 516,869 404,838 921,707
------- ------- ------- --- ----- ----- ------- ------- ---------
Revisions of prior estimates (487) 3,261 2,774 (2) (130) (132) (501) 2,481 1,980
Extensions, discoveries and
other additions 40,703 29,005 69,708 137 249 386 41,526 30,500 72,026
Production (26,783) (31,979) (58,762) (21) (576) (597) (26,910) (35,435) (62,345)
Purchases of reserves in place 21,207 16,190 37,397 8 207 215 21,255 17,430 38,685
Sales of reserves in place (23,337) (2,013) (25,350) (7) (9) (16) (23,377) (2,065) (25,442)
------- ------- ------- --- ----- ----- ------- ------- ---------
DECEMBER 31, 1996 526,859 388,758 915,617 334 4,832 5,166 528,862 417,749 946,611
------- ------- ------- --- ----- ----- ------- ------- ---------
Revisions of prior estimates 2,929 3,815 6,744 67 32 99 3,327 4,009 7,336
Extensions, discoveries and
other additions 42,609 66,582 109,191 147 647 794 43,493 70,463 113,956
Production (25,340) (38,549) (63,889) (48) (581) (629) (25,628) (42,035) (67,663)
Purchases of reserves in place 5,355 68,481 73,836 2 592 594 5,366 72,035 77,401
Sales of reserves in place (137,194) (876) (138,070) (55) (100) (155) (137,520) (1,478) (138,998)
------- ------- ------- --- ----- ----- ------- ------- ---------
DECEMBER 31, 1997 415,218 488,211 903,429 447 5,422 5,869 417,900 520,743 938,643
======= ======= ======= === ===== ===== ======= ======= =========
PROVED DEVELOPED RESERVES:
December 31, 1994 474,574 331,339 805,913 167 7,537 7,704 475,576 376,561 852,137
December 31, 1995 430,165 317,070 747,235 219 4,751 4,970 431,477 345,579 777,056
December 31, 1996 434,558 333,540 768,097 334 4,351 4,685 436,560 359,646 796,206
December 31, 1997 343,718 395,046 738,764 447 4,412 4,859 346,400 421,519 767,919
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
APP = Appalachian Region
WEST = Western Region
Note: Natural gas equivalents are determined using the ratio of 6.0 Mcf of
natural gas to 1.0 Bbl of crude oil or condensate.
VOLUMES AND PRICES; PRODUCTION COSTS
The following table sets forth historical information regarding the
Company's sales and production volumes and average sales prices received for,
and average production costs associated with, its sales of natural gas and crude
oil, condensate and natural gas liquids (Ngl) for the periods indicated.
8
<PAGE> 10
<TABLE>
<CAPTION>
Year Ended December 31,
1997 1996 1995
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C>
NET WELLHEAD SALES VOLUME:
Natural Gas (Bcf)(1)
Appalachian Region 25.3 26.2 26.4
Western Region(2) 38.6 32.6 29.8
Crude/Condensate/Ngl (Mbbl)
Appalachian Region 48 21 18
Western Region 584 576 722
PRODUCED NATURAL GAS SALES PRICE $(/MCF)(3)
Appalachian Region $ 3.00 $ 2.72 $ 2.22
Western Region $ 2.22 $ 2.02 $ 1.33
Weighted Average $ 2.53 $ 2.34 $ 1.75
Crude/Condensate Sales Price ($/Bbl)(3) $20.13 $ 21.14 $ 17.95
Production Costs ($/Mcfe)(4) $ 0.58 $ 0.56 $ 0.55
- ---------------------------------------------------------------------------------------
</TABLE>
(1) Equal to the aggregate of production and the net changes in storage and
exchanges.
(2) Includes information regarding Anadarko, Rocky Mountains and Gulf Coast.
(3) Represents the average sales prices for all production volumes (including
royalty volumes) sold by the Company during the periods shown net of
related costs (principally purchased gas royalty, transportation and
storage).
(4) Production costs include direct lifting costs (labor, repairs and
maintenance, materials and supplies), and the costs of administration of
production offices, insurance and property and severance taxes but is
exclusive of depreciation and depletion applicable to capitalized lease
acquisition, exploration and development expenditures.
9
<PAGE> 11
ACREAGE
The following tables summarize the Company's gross and net developed and
undeveloped leasehold and mineral acreage at December 31, 1997. Acreage in which
the Company's interest is limited to royalty and overriding royalty interests is
excluded.
LEASEHOLD ACREAGE
<TABLE>
<CAPTION>
At December 31, 1997
Developed Undeveloped Total
- -----------------------------------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
STATE
Alabama -- -- 312 312 312 312
Arkansas 240 6 -- -- 240 6
Colorado 24,474 20,771 32,264 29,141 56,738 49,912
Indiana 739 369 53,485 26,457 54,224 26,826
Kansas 33,264 28,850 1,278 896 34,542 29,746
Kentucky 2,680 990 15,679 7,657 18,359 8,647
Louisiana 2,070 357 3,419 542 5,489 899
Michigan 809 178 6,228 1,362 7,037 1,540
Montana 157 52 680 303 837 355
New York 2,520 1,057 3,461 2,853 5,981 3,910
North Dakota 160 20 870 96 1,030 116
Ohio 5,088 1,905 41,060 28,223 46,148 30,128
Oklahoma 182,867 119,611 46,776 31,107 229,643 150,718
Pennsylvania 93,998 77,294 34,913 22,656 128,911 99,950
Texas 77,412 44,290 26,079 11,663 103,491 55,953
Utah 1,740 530 20,653 17,274 22,393 17,804
Virginia 22,091 20,045 24,849 12,279 46,940 32,324
West Virginia 567,650 524,600 119,838 96,088 687,488 620,688
Wyoming 113,729 55,094 59,805 27,019 173,534 82,113
--------- ------- ------- ------- --------- ---------
Total 1,131,688 896,019 491,649 315,928 1,623,337 1,211,947
========= ======= ======= ======= ========= =========
</TABLE>
MINERAL FEE ACREAGE
<TABLE>
<CAPTION>
At December 31, 1997
Developed Undeveloped Total
- -----------------------------------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
STATE
Colorado 279 40 160 6 439 46
Kansas 160 128 -- -- 160 128
Montana -- -- 589 75 589 75
New York -- -- 4,281 1,070 4,281 1,070
Oklahoma 16,889 13,987 240 49 17,129 14,036
Pennsylvania 86 86 1,573 502 1,659 588
Texas 27 27 857 426 884 453
Virginia 17,817 17,817 100 34 17,917 17,851
West Virginia 89,264 75,499 56,817 55,856 146,081 131,355
--------- --------- ------- ------- --------- ---------
Total 124,522 107,584 64,617 58,018 189,139 165,602
========= ========= ======= ======= ========= =========
Aggregate Total 1,256,210 1,003,603 556,266 373,946 1,812,476 1,377,549
========= ========= ======= ======= ========= =========
</TABLE>
10
<PAGE> 12
Total Net Acreage by Area of Operation
<TABLE>
<CAPTION>
At December 31, 1997
Developed Undeveloped Total
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Appalachian Region 719,840 255,037 974,877
Western Region 283,763 118,909 402,672
--------- ------- ---------
Total 1,003,603 373,946 1,377,549
========= ======= =========
</TABLE>
PRODUCTIVE WELL SUMMARY(1)
The following table reflects the Company's ownership at December 31, 1997
in natural gas and oil wells in the Appalachian Region (consisting of various
fields located in West Virginia, Pennsylvania, New York, Ohio, Virginia and
Kentucky), and in the Western Region (consisting of various fields located in
Louisiana, Oklahoma, Texas, Kansas, North Dakota, Utah, Colorado and Wyoming).
<TABLE>
<CAPTION>
Natural Gas Oil Total
Gross Net Gross Net Gross Net
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Appalachian Region 2,883 2,684.9 22 11.5 2,905 2,696.4
Western Region 1,134 659.8 203 85.2 1,337 745.0
----------------------------------------------------------------------------
Total 4,017 3,344.7 225 96.7 4,242 3,441.4
============================================================================
- ------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) "Productive" wells are producing wells and wells capable of production in
which the Company has a working interest.
DRILLING ACTIVITY
The Company drilled, participated in the drilling of, or acquired wells as
set forth in the table below for the periods indicated:
<TABLE>
<CAPTION>
Year Ended December 31,
1997 1996 1995
- ----------------------------------------------------------------------------------------------
GROSS NET Gross Net Gross Net
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
APPALACHIAN REGION:
Development Wells
Natural Gas 82 73.7 85 81.6 17 16.4
Oil 0 0.0 1 1.0 0 0.0
Dry 5 5.0 12 12.0 5 4.3
Extension Wells
Natural Gas 0 0.0 0 0.0 1 0.3
Oil 0 0.0 0 0.0 0 0.0
Dry 0 0.0 0 0.0 1 0.5
Exploratory Wells
Natural Gas 20 10.9 10 5.0 2 0.5
Oil 5 0.9 5 0.9 2 0.5
Dry 8 6.3 10 5.2 5 2.0
--- ---- --- ----- -- ----
Total 120 96.8 123 105.7 33 24.5
=== ==== === ===== == ====
Wells Acquired(1)
Natural Gas 1 40.0 15 11.8 3 3.7
Oil 0 0.0 0 0.0 0 0.0
--- ---- --- ----- -- ----
Total 1 40.0 15 11.8 3 3.7
=== ==== === ===== == ====
Wells in Progress at End
of Period 4 3.1 2 1.5 3 3.0
</TABLE>
11
<PAGE> 13
<TABLE>
<CAPTION>
Year Ended December 31,
1997 1996 1995
- -----------------------------------------------------------------------------------------------------------------
GROSS NET Gross Net Gross Net
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
WESTERN REGION:
Development Wells
Natural Gas 72 32.3 40 26.5 33 17.1
Oil 1 0.9 0 0.0 3 1.9
Dry 5 3.7 14 8.7 7 3.3
Extension Wells
Natural Gas 11 10.6 12 8.3 8 4.6
Oil 1 0.6 1 0.1 0 0.0
Dry 2 1.0 1 1.9 0 0.0
Exploratory Wells
Natural Gas 5 1.6 1 0.6 1 0.3
Oil 1 1.0 0 0 0 0.0
Dry 7 2.9 4 2.4 8 3.9
--- ---- -- ---- -- ----
Total 105 54.6 73 48.5 60 31.1
=== ==== == ==== == ====
Wells Acquired(1)
Natural Gas 63 18.5 25 11.9 0 2.7
Oil 2 0.2 3 0.4 0 0.1
--- ---- -- ---- -- ----
Total 65 18.7 28 12.3 0 2.8
=== ==== == ==== == ====
Wells in Progress at End
of Period 6 3.3 4 1.5 6 5.3
- -----------------------------------------------------------------------------------------------------------------
</TABLE>
(1)Includes the acquisition of net interest in certain wells in the Appalachian
Region and in the Western Region in 1997, 1996 and 1995 in which the Company
already held an ownership interest.
COMPETITION
Competition in the Company's primary producing areas is intense. The
Company believes that its competitive position is affected by price, contract
terms and quality of service, including pipeline connection times, distribution
efficiencies and reliable delivery record. The Company believes that its
extensive acreage position and existing natural gas gathering and pipeline
systems and storage fields give it a competitive advantage over certain other
producers in the Appalachian Region which do not have such systems or facilities
in place. The Company also believes that its competitive position in the
Appalachian Region is enhanced by the absence of significant competition from
major oil and gas companies. The Company also actively competes against some
companies with substantially larger financial and other resources, particularly
in the Western Region. The Company also believes that its competitive position
is enhanced by marketing its own gas through the operation of Cabot Oil & Gas
Marketing Corporation.
OTHER BUSINESS MATTERS
MAJOR CUSTOMER
The Company had no sales to any customer that exceeded 10% of the
Company's total gross revenues in 1997.
SEASONALITY
Demand for natural gas has historically been seasonal in nature, with peak
demand and typically higher prices occurring during the colder winter months.
12
<PAGE> 14
REGULATION OF OIL AND NATURAL GAS PRODUCTION
The Company's oil and gas production and transportation operations are
subject to various types of regulation by federal, state and local authorities.
The statutory law affecting the oil and natural gas industry is under constant
review for amendment or expansion. Further, numerous departments and agencies,
federal, state and local, have issued rules and regulations affecting the oil
and natural gas industry and its individual members, compliance with which is
often difficult and costly and some of which may carry substantial penalties for
non-compliance. The regulatory burden on the oil and natural gas industry
increases its cost of doing business and, consequently, affects its
profitability. Inasmuch as such laws and regulations are frequently expanded,
amended or reinterpreted, the Company is unable to predict the future cost or
impact of complying with such regulations. However, the Company does not believe
that under present regulations it is affected in a significantly different
manner by these regulations than others in the industry.
EXPLORATION AND PRODUCTION
The exploration and production operations of the Company are subject to
various types of regulation at the federal, state and local levels. Such
regulation includes requiring permits for the drilling of wells, maintaining
bonding requirements in order to drill or operate wells, and regulating the
location of wells, the method of drilling and casing wells, the surface use and
restoration of properties upon which wells are drilled and the plugging and
abandoning of wells. The Company's operations are also subject to various
conservation laws and regulations. These include the regulation of the size of
drilling and spacing units or proration units and the density of wells which may
be drilled in a given field and the unitization or pooling of oil and natural
gas properties. In this regard, some states allow the forced pooling or
integration of tracts to facilitate exploration while other states rely on
voluntary pooling of lands and leases. In addition, state conservation laws
establish maximum rates of production from oil and natural gas wells, generally
prohibit the venting or flaring of natural gas and impose certain requirements
regarding the ratability of production. In this regard, such states as Texas,
Oklahoma and Louisiana have in recent years reviewed and substantially revised
the methodologies previously used by them to gather the necessary information
and make monthly determinations of appropriate field and well production
allowables. The effect of these regulations is to limit the amounts of oil and
natural gas the Company can produce from its wells, and to limit the number of
wells or the locations at which the Company can drill.
NATURAL GAS MARKETING, GATHERING AND TRANSPORTATION
Federal legislation and regulatory controls have historically affected the
price of the natural gas produced by the Company and the manner in which such
production is transported and marketed. Under the Natural Gas Act of 1938, the
Federal Energy Regulatory Commission (the "FERC") regulates the interstate
transportation and the sale in interstate commerce for resale of natural gas.
The FERC's jurisdiction over interstate sales of natural gas was substantially
modified by the Natural Gas Policy Act, under which the FERC continued to
regulate the maximum selling prices of certain categories of gas sold in "first
sales" in interstate and intrastate commerce. Effective January 1, 1993,
however, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act")
deregulated natural gas prices for all "first sales" of natural gas, which
includes all sales by the Company of its own production. As a result, all of the
Company's domestically produced natural gas may now be sold at market prices,
subject to the terms of any private contracts which may be in effect. The FERC's
jurisdiction over natural gas transportation was unaffected by the Decontrol
Act.
The Company's natural gas sales are affected by the regulation of
intrastate and interstate gas transportation. In an attempt to restructure the
interstate pipeline industry with the goal of providing enhanced access to, and
competition among, alternative natural gas suppliers, the FERC, commencing in
April 1992, issued Order Nos. 636, 636-A and 636-B ("Order No. 636") which have
altered significantly the interstate transportation and sale of natural gas.
Previously, the interstate pipelines had acted primarily as wholesalers of
natural gas, purchasing the gas from producers in or within the vicinity of the
production areas and reselling the gas to large industrial customers and local
distribution companies. Among other things, Order No. 636 required interstate
pipelines to unbundle their wholesale merchant services into the various
constituent services, such as sales, transmission and storage, and to offer
these "unbundled" services individually to their customers. By requiring
interstate pipelines to "unbundle" their services and to provide their
13
<PAGE> 15
customers with direct access to pipeline capacity, Order No. 636 enabled
pipeline customers to choose the levels of transportation and storage service
they require, as well as to purchase natural gas directly from third-party
merchants other than the interstate pipelines and obtain transportation of such
gas on a nondiscriminatory basis. Through similar orders pertaining to
intrastate pipelines which provide certain interstate services, the FERC has
expanded the impact of these so-called "open access" regulations to intrastate
commerce. The effect of Order No. 636 and related orders has been to enable the
Company to market its natural gas production to a wider variety of potential
purchasers. The Company believes that these changes generally have improved the
Company's access to transportation and have enhanced the marketability of its
natural gas production. To date, Order No. 636 has not had any material adverse
effect on the Company's ability to market and transport its natural gas
production. However, even though Order No. 636 has been affirmed on appeal, with
minor exceptions, and individual interstate pipelines have had final open access
tariffs in place for several years, the FERC is continuing to review, assess and
modify its transportation regulations and the Company cannot predict what new or
different regulations may be adopted by the FERC and other regulatory
authorities, or what effect subsequent regulations may have on the Company's
activities.
In recent years the FERC also has pursued a number of other important
policy initiatives which have significantly affected the marketing of natural
gas. Some of the more notable of these regulatory initiatives have included (i)
a series of orders in individual pipeline proceedings articulating a policy of
generally approving the voluntary divestiture of interstate pipeline-owned
gathering facilities either to non-affiliated companies (a "spin off") or to the
pipeline's nonregulated affiliate (a "spin down "), (ii) the completion of a
rulemaking proceeding involving the regulation of pipelines with marketing
affiliates under Order No. 497, (iii) FERC's ongoing efforts to promulgate
standards for pipeline electronic bulletin boards and electronic data exchange,
(iv) a generic inquiry into the pricing of interstate pipeline capacity, (v)
efforts to refine FERC's regulations controlling the operation of the secondary
market for released pipeline capacity, (vi) a policy statement and a series of
orders in individual pipeline dockets regarding market-based rates and other
non-cost-based rates for interstate pipeline transmission and storage capacity
and (vii) appropriate ratemaking procedures for pipeline expansions and
extensions. Several of these initiatives are intended to enhance competition in
natural gas markets, although some, such as the so-called "spin-down" of
previously regulated gathering facilities by interstate pipelines to their
affiliates, may have the adverse effect on some in the industry of increasing
the cost of doing business as a result of the potential for monopolization of
those facilities by their new, unregulated owners. FERC attempted to address
some of these concerns in its orders authorizing such "spin-downs," but one of
its principal devices, the use of "default" contracts to assure continuity of
gathering services for two years after spin down, was found unlawful on appeal.
It remains to be seen what effect the FERC's other activities will have on
access to markets and the cost to do business. In response to the FERC's policy
of authorizing the interstate pipeline industry's divestiture of these gathering
facilities, several states (most notably Oklahoma and Texas) enacted or are
considering laws and regulations enhancing state level oversight over gathering.
As to all of these recent FERC and state initiatives, the ongoing, or, in some
instances, preliminary evolving nature of these regulatory initiatives makes it
impossible to predict their ultimate impact upon the Company's activities.
The Company's pipeline systems and storage fields are regulated for safety
compliance by the U.S. Department of Transportation, the West Virginia Public
Service Commission, the Pennsylvania Department of Natural Resources and the New
York Department of Public Service. The Company's pipeline systems in each state
operate independently and are not interconnected.
ENVIRONMENTAL REGULATIONS
General. The Company's operations are subject to extensive federal, state
and local laws and regulations relating to the generation, storage, handling,
emission, transportation and discharge of materials into the environment.
Permits are required for the operation of various facilities of the Company, and
these permits are subject to revocation, modification and renewal by issuing
authorities. Governmental authorities have the power to enforce compliance with
their regulations, and violations are subject to fines, injunctions or both.
Such government regulation can increase the cost of planning, designing,
installing and operating oil and gas facilities. In most instances, the
regulatory requirements impose water and air pollution control measures.
Although the Company believes that compliance with environmental regulations
will not have a material adverse effect on the Company, risks of substantial
costs and liabilities related to environmental compliance issues are inherent in
oil and gas production operations, and no assurance can be given that
significant costs and liabilities will not be incurred. Moreover, it is possible
that other developments, such as stricter
14
<PAGE> 16
environmental laws and regulations, and claims for damages to property or
persons resulting from oil and gas production would result in substantial costs
and liabilities to the Company.
Solid and Hazardous Waste. The Company currently owns or leases, and has
in the past owned or leased, numerous properties that have been used for
production of oil and gas for many years. Although the Company has utilized
operating and disposal practices that were standard in the industry at the time,
hydrocarbons or other solid wastes may have been disposed or released on or
under the properties owned or leased by the Company. In addition, many of the
properties have been operated by third parties. The Company had no control over
such parties' treatment of hydrocarbons or other solid wastes and the manner in
which such substances may have been disposed or released. State and federal laws
applicable to oil and gas wastes and properties have gradually become stricter
over time. Under these new laws, the Company could be required to remove or
remediate previously disposed wastes (including wastes disposed or released by
prior owners and operators) or property contamination (including groundwater
contamination by prior owners or operators) or to perform remedial plugging
operations to prevent future contamination.
The Company generates some wastes that are subject to the Federal Resource
Conservation and Recovery Act ("RCRA") and comparable State statutes. The
Environmental Protection Agency ("EPA") has limited the disposal options for
certain "hazardous wastes." Furthermore, it is possible that certain wastes
currently exempt from treatment as "hazardous wastes" may in the future be
designated as "hazardous wastes" under RCRA or other applicable statues, and
therefore be subject to more rigorous and costly disposal requirements.
Superfund. The Comprehensive Environmental Response, Compensation, and
Liability Act ("CERCLA") , also known as the "Superfund" law, imposes liability,
without regard to fault or the legality of the original conduct, on certain
classes of persons with respect to the release of a "hazardous substance" into
the environment. These persons include the owner and operator of a site and any
party that disposed or arranged for the disposal of the hazardous substance
found at a site. CERCLA also authorizes the EPA, and in some cases, third
parties, to take actions in response to threats to the public health or the
environment and to seek to recover from the responsible parties the costs of
such action. In the course of the Company's operations, the Company has
generated and will generate wastes that may fall within CERCLA's definition of
"hazardous substances." The Company may also be an owner of sites on which
"hazardous substances" have been released. Therefore, the Company may be
responsible under CERCLA for all or part of the costs to clean up sites at which
such wastes have been disposed.
Oil Pollution Act. The Oil Pollution Act of 1990 (the "OPA") and
regulations thereunder impose a variety of regulations on "responsible parties"
related to the prevention of oil spills and liability for damages resulting from
such spills in "waters of the United States." The term "waters of the United
States" has been broadly defined to include inland waste bodies, including
wetlands and intermittent streams. The OPA assigns liability to each responsible
party for oil removal costs and a variety of public and private damages.
Air Emissions. The operations of the Company are subject to local, state
and federal laws and regulations for the control of emissions from sources of
air pollution. Administrative enforcement actions for failure to comply strictly
with air regulations or permits are generally resolved by payment of monetary
fines and correction of any identified deficiencies. Alternatively, regulatory
agencies could require the Company to cease construction or operation of certain
air emission sources. The Company believes that it is in substantial compliance
with the emission standards under local, state and federal laws and regulations.
EMPLOYEES
The Company had 342 active employees as of December 31, 1997. The Company
believes that its relations with its employees are satisfactory. The Company has
not entered into any collective bargaining agreements with its employees.
OTHER
The Company's profitability depends on certain factors that are beyond its
control, such as natural gas and crude oil prices. The nature of the oil and gas
business involves a variety of risks, including the risk of experiencing certain
15
<PAGE> 17
operating hazards such as fires, explosions, blowouts, cratering, oil spills and
encountering formations with abnormal pressures, the occurrence of any of which
could result in substantial losses to the Company. The operation of the
Company's natural gas gathering and pipeline systems also involves certain
risks, including the risk of explosions and environmental hazards caused by
pipeline leaks and ruptures. The proximity of pipelines to populated areas,
including residential areas, commercial business centers and industrial sites,
could exacerbate such risks. At December 31, 1997, the Company owned or operated
approximately 2,800 miles of natural gas gathering and pipeline systems. As part
of its normal maintenance program, the Company has identified certain segments
of its pipelines which it believes require repair, replacement or additional
maintenance. In accordance with customary industry practices, the Company
maintains insurance against some, but not all, of such risks.
ITEM 2. PROPERTIES
See Item 1. Business.
ITEM 3. LEGAL PROCEEDINGS
The Company and its subsidiaries are defendants or parties in numerous
lawsuits or other governmental proceedings arising in the ordinary course of
business. The Company is also involved in other gas contract issues. In the
opinion of the Company, final judgments or settlements, if any, which may be
awarded in connection with any one or more of these suits and claims could be
significant to the results of operations and cash flows of any period but would
not have a material adverse effect on the Company's financial position.
On February 10, 1997, Washington Energy Company and Puget Sound Power &
Light Company merged to form Puget Sound Energy, Inc. ("Puget"). As a result of
the merger, Puget is the holder of 2,133,000 shares of Common Stock and
1,134,000 shares of the Company's 6% Convertible Redeemable Preferred Stock
(convertible into 1,972,174 shares of Common Stock), all of which were
previously held by Washington Energy Company. Mr. William P. Vititoe, a member
of the Company's Board of Directors, is a consultant to Puget and was formerly
an officer and director of Washington Energy Company.
The Company sells approximately 20,000 Mmbtu of natural gas per day in the
Western Region to a cogeneration plant located in Bellingham, Washington and
owned by Encogen Northwest, L.P. ("Encogen") under a gas sales contract
containing a fixed price that escalates annually, a firm delivery arrangement
and a term continuing through June 30, 2008. Encogen sells all the electrical
power generated in the plant to Puget under an Agreement for Firm Power Purchase
("Power Agreement"). The Company is aware that a dispute has arisen between
Puget and Encogen over the appropriate interpretation of certain provisions of
the Power Agreement, which dispute is currently being litigated. Puget has
requested the court, among other matters, to declare that Encogen is in material
breach of the Power Agreement. A finding by the court that Encogen is in
material breach of the Power Agreement could lead to termination of the Power
Agreement. Any restructuring or termination of the Power Agreement may have a
negative impact on the Company's gas sales arrangement with Encogen. Encogen has
requested that the Company consider restructuring its gas sales arrangement with
Encogen. To date the Company has been unwilling to restructure its gas sales
agreement without being fully compensated for the agreement's value.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the
period from October 1, 1997 to December 31, 1997.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information about the executive officers
of the Company as of March 1, 1998, as such term is defined in Rule 3b-7
promulgated under the Securities Exchange Act of 1934, and certain other
officers of the Company.
16
<PAGE> 18
<TABLE>
<CAPTION>
Name Age Position Officer Since
------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Charles P. Siess, Jr. 71 Chairman of the Board and 1995
Chief Executive Officer
Ray R. Seegmiller 62 President, Chief Operating
Officer and Director 1995
James M. Trimble 49 Senior Vice President, Exploration and 1987
Production
Jim L. Batt 62 Vice President, Land 1988
Jeff W. Hutton 42 Vice President, Marketing 1995
Gerald F. Reiger 46 Vice President and Regional
Manager 1995
H. Baird Whitehead 47 Vice President and Regional
Manager 1987
Paul F. Boling 44 Controller 1996
Lisa A. Machesney 42 Corporate Secretary and Managing
Counsel 1995
Scott C. Schroeder 35 Treasurer 1997
</TABLE>
All officers are elected annually by the Company's Board of Directors.
With the exception of the following, all executive officers of the Company have
been employed by the Company for at least the last five years.
Charles P. Siess, Jr. has been Chairman of the Board and Chief Executive
Officer of the Company since May 1995. From February 1993 until January 1994,
Mr. Siess served as Acting General Manager of Bridas S.A.P.I.C. (oil exploration
in Argentina). Prior thereto, Mr. Siess served as Chairman of the Board, Chief
Executive Officer and President of the Company from December 1989 to December
1992.
Gerald F. Reiger has been Vice President, Regional Manager of the Company
since February 1995. From May 1994 until February 1995, Mr. Reiger served as
Regional Manager of the Company. Prior thereto, Mr. Reiger was associated with
Washington Energy Resources Company, a subsidiary of Washington Energy Company,
from 1992 to 1994. Prior thereto, Mr. Reiger served as U.S. Operations Manager
of DeKalb Energy Company.
Ray R. Seegmiller joined the Company as Vice President, Chief Financial
Officer and Treasurer in August 1995. Mr. Seegmiller served in this position
until March 1997 when he was promoted to Executive Vice President, Chief
Operating Officer. In September 1997, Mr. Seegmiller was promoted to his current
position of President, Chief Operating Officer and Director. Mr. Seegmiller has
been designated to replace Charles Siess as Chief Executive Officer upon the
expected retirement of Mr. Siess in 1998. From May 1988 until 1993, Mr.
Seegmiller served as President and Chief Executive of Terry Petroleum Company.
Prior thereto, Mr. Seegmiller held various officer positions with Marathon
Manufacturing Company.
Scott C. Schroeder has been Treasurer since May 1997. From October 1995 to
May 1997, Mr. Schroeder served as Assistant Treasurer. Prior to joining the
Company, Mr. Schroeder held various managerial positions with Pride Petroleum
Services (now known as Pride International). Prior thereto, Mr. Schroeder server
as Manager, Treasury Operations and Planning of DeKalb Energy Company.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Common Stock is listed and principally traded on the New York Stock
Exchange under the ticker symbol "COG". The following table sets forth for the
periods indicated the high and low sales prices per share of the Common Stock,
as reported in the consolidated transaction reporting system, and the cash
dividends paid per share of the Common Stock:
17
<PAGE> 19
<TABLE>
<CAPTION>
Cash
High Low Dividends
- ------------------------------------------------------------------------
<S> <C> <C> <C>
1997
FIRST QUARTER $ 19.75 $ 15.88 $ 0.04
SECOND QUARTER 18.88 15.50 0.04
THIRD QUARTER 23.69 17.38 0.04
FOURTH QUARTER 25.06 16.50 0.04
1996
First Quarter $ 16.88 $ 13.13 $ 0.04
Second Quarter 17.63 13.75 0.04
Third Quarter 18.38 13.75 0.04
Fourth Quarter 18.38 14.38 0.04
</TABLE>
As of January 31, 1998, there were 1,397 registered holders of the Common
Stock. Shareholders include individuals, brokers, nominees, custodians, trustees
and institutions such as banks, insurance companies and pension funds. Many of
these hold large blocks of stock on behalf of other individuals or firms.
ITEM 6. SELECTED HISTORICAL FINANCIAL DATA
The following table sets forth a summary of selected consolidated
financial data for the Company for the periods indicated. This information
should be read in conjunction with Management's Discussion and Analysis of
Financial Condition and Results of Operations and the Consolidated Financial
Statements and related Notes thereto.
<TABLE>
<CAPTION>
Year Ended December 31,
(In thousands, except per share amounts) 1997 1996 1995 1994 1993
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Net Operating Revenues $ 185,127 $ 163,061 $ 121,083 $ 140,295 $ 115,816
Income (Loss) from Operations 63,852 48,787 (116,758) 15,013 20,007
Net Income (Loss) Applicable to
Common Stockholders 23,231 15,258 (92,171) (5,444) 2,088
BASIC EARNINGS (LOSS) PER SHARE
APPLICABLE TO COMMON
STOCKHOLDERS(1) $ 1.00 $ 0.67 $ (4.05) $ (0.25) $ 0.10
DIVIDENDS PER COMMON SHARE $ 0.16 $ 0.16 $ 0.16 $ 0.16 $ 0.16
BALANCE SHEET DATA:
Properties and Equipment, Net $ 469,399 $ 480,511 $ 474,371 $ 634,934 $ 400,270
Total Assets 541,805 561,341 528,155 688,352 445,001
Long-Term Debt 183,000 248,000 249,000 268,363 169,000
Stockholders' Equity 184,062 160,704 147,856 243,082 153,529
- -----------------------------------------------------------------------------------------------------------
</TABLE>
(1) See "Earnings (Loss) Per Common Share" under Note 20 of the Notes to the
Consolidated Financial Statements.
18
<PAGE> 20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following review of operations should be read in conjunction with the
Consolidated Financial Statements and the Notes thereto included elsewhere.
OVERVIEW
The initial upswing in gas prices early in the year, coupled with a 8.5%
increase in natural gas production, played an important part in the Company's
performance in 1997 with record earnings and operating cash flows. Operating
results for 1997 included the benefit of the following:
o The average produced natural gas price was $2.53 per Mcf, up 8%
compared to 1996, while equivalent production was up 5.4 Bcfe, or
8.5%, compared to 1996.
o Under its continued asset rationalization program, involving the
divestiture of non-strategic properties, and synergistic growth
through new acquisitions, the Company completed a like-kind
exchange transaction in October 1997 which matched properties
purchased, including 63 wells and 74 potential drilling
locations, in the Green River Basin of Wyoming with a portion of
the properties divested in the Meadville district of the
Appalachian Region, including 912 wells and related assets. This
transaction generated net proceeds of $47.7 million.
o Net interest costs were down $1.1 million, or 6%, excluding the
benefit of the non-recurring $1.7 million of interest income
received in 1996 that related to an income tax refund for tax
periods prior to 1990. This reduction in interest cost was a
result of debt reductions made possible by strong operating cash
flow in 1997.
o Depreciation, depletion and amortization ("DD&A") expenses were
down $1.9 million or $0.09 per Mcfe of production. This
improvement was primarily the result of the reduction in high
cost depreciable assets due to the disposition of the Meadville
properties in September 1997.
Operating cash flows reached a record level of $95.0 million, increasing
$19.6 million, or 26%, from 1996. Cash flows from operations, along with the
$47.7 million of net proceeds from the Meadville/Green River property
transaction noted above, predominantly funded (1) $73.5 million of capital and
exploration expenditures, (excluding the Green River property acquisition) $12.8
million higher than 1996, (2) $49 million of net debt reductions and (3) $9.4
million of preferred and common stock dividend payments.
The Company drilled 151.4 net wells with a net success rate of 88%
compared to 154.2 net wells and a net 80% success rate in 1996. Along with the
higher success rate in 1997, the Company replaced 179% of production through
drilling additions and revisions, versus a 119% production replacement in 1996.
In 1998 the Company plans to drill 270 gross wells (173.2 net) and spend $111.0
million in capital and exploration expenditures, 17% higher than 1997
expenditures.
Natural gas production equivalent was 67.7 Bcf, an increase of 8.5% over
1996. The 1997 production growth resulted from the Company's expanded drilling
programs in 1996 and 1997. Additionally, the underperforming properties sold in
the Meadville district, effective September 1, 1997, which would have produced
an estimated 1.7 Bcfe in the remaining four months of 1997, were more than
offset by the acquired Green River properties which added 1.9 Bcfe to 1997
production.
19
<PAGE> 21
The Company's strategic pursuits are sensitive to energy commodity
prices, particularly the price of natural gas. Gas prices rose to near record
levels in November and December 1996. Although prices rose still further in
January 1997, the gas market demonstrated significant price volatility in the
spring months. Prices in most regions rose sharply in October and November 1997,
but due to the unseasonably warm winter, softened in December and January 1998
to levels significantly below the prices realized in the corresponding months of
the prior year.
The Company remains focused on its strategies to grow through the drill
bit, through synergistic acquisitions and through greater emphasis on marketing.
The Company believes that these strategies are appropriate in the current
industry environment and establish a firm base which will enable the Company to
create shareholder value over the long term.
The success of these strategies is measured by the achievement of three
goals. The first of these goals is to increase cash flow from both increased
production and reduced costs. The Company has made significant progress in this
area. During 1997, production increased 8.5% while direct operating cost per
Mcfe declined $0.02, contributing to the 26% increase in operational cash flow.
The second goal is to maintain reserves per share while increasing
production to protect long-term shareholder value. Reserve additions from the
1997 drilling program replaced 168% of 1997 production. In total, reserve levels
decreased slightly due to actions taken as part of the asset rationalization
program. The Company plans to drill 270 gross wells in 1998 and increase
exploratory drilling, lease acquisition and geophysical expenditures.
Finally, the Company strives to reduce debt as a percentage of total
capitalization without diluting shareholder value. This ratio was 60.7% at the
end of 1996 and has improved to 51.9% in 1997 due mainly to a $49 million
reduction in total borrowings, made possible from the net proceeds generated
from the sale of the Meadville properties.
In October 1997, the Company exercised the option to convert all of the
$3.125 cumulative preferred stock into approximately 1,649,000 shares of Common
Stock. By eliminating the dividends on the $3.125 cumulative preferred shares,
an additional $2.2 million of annual earnings will be made available to common
shareholders in future years.
The preceding paragraphs, discussing the Company's strategic pursuits and
goals, contain forward-looking information. See FORWARD-LOOKING INFORMATION on
page 25.
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 gas has historically been subject to seasonal
influences characterized by peak demand and higher prices in the winter heating
season. Natural gas prices were up in 1997 over 1996, resulting in higher cash
flows.
The primary sources of cash for the Company during 1997 were from funds
generated from operations and net cash proceeds from the sale of the Meadville
properties and acquisition of the Green River properties. Primary uses of cash
were funds used in operations, exploration and development expenditures,
acquisitions, dividends on preferred and common stock and repayment of debt.
The Company had a net cash inflow of $0.4 million in 1997. Net cash
inflow from operating and financing activities totaled $38.9 million, funding
the capital and exploration expenditures of $38.4 million, net of the $48.9
million in net proceeds from the sale of assets.
<TABLE>
<CAPTION>
(In millions) 1997 1996 1995
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash Flows Provided by Operating Activities $ 95.0 $ 75.5 $ 41.5
------- ------- -------
</TABLE>
20
<PAGE> 22
Cash flows provided by operating activities in 1997 were substantially
higher, increasing $19.5 million over 1996, due primarily to higher natural gas
prices and production, and a significant reduction in trade receivables.
Cash flows provided by operating activities in 1996 were higher by $34
million compared with 1995 due predominantly to higher natural gas prices.
<TABLE>
<CAPTION>
(In millions) 1997 1996 1995
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Cash Flows Used by Investing Activities $(38.4) $ (67.6) $ (14.0)
------ ------- -------
</TABLE>
Cash flows used by investing activities in 1997 were $29.2 million lower
than in 1996 due to net proceeds of $47.7 million received from the
Meadville/Green River property transaction, partially offset by the expenses of
the stronger 1997 drilling program.
Cash flows used by investing activities in 1996 were $53.5 million higher
than in 1995 due primarily to $40.6 million of increased capital and exploration
expenditures over 1995. The Company's 1995 drilling program was scaled down,
drilling only 55.4 net wells, compared to an average of 135 net wells per year
over the previous five years. The 1996 capital expenditures were offset in part
by proceeds of $5.7 million from the sale of assets.
<TABLE>
<CAPTION>
(In millions) 1997 1996 1995
- ----------------------------------------------------------------------------
<S> <C> <C> <C>
Cash Flows Used by Financing Activities $ (56.2) $ (9.6) $ (28.2)
-------- ------- -------
</TABLE>
Cash flows used by financing activities from 1997 consist primarily of the
$49.0 million net reduction in borrowings on the revolving credit facility as
well as dividend payments. The 1996 activity was mostly attributable to dividend
payments, but also included a $1.0 reduction in debt under the credit facility.
Cash flows used by financing activities from 1995 were primarily net
payments on the Company's revolving credit facility, reducing the debt under
this facility by $19.0 million.
The Company's available credit line under the revolving credit facility
was $235 million from June 1995 until November 1997. In November 1997, the
Company issued $100 million in 7.19% Notes (See Note 5 of the Notes to the
Consolidated Financial Statements for further discussion) and reduced the
available credit line to $135 million. The available credit line is subject to
adjustment on the basis of the projected present value of estimated future net
cash flows from proved oil and gas reserves (as determined by an independent
petroleum engineer's report incorporating certain assumptions provided by the
lender) and other assets. The Company's outstanding indebtedness under the
revolving credit facility was $19 million at December 31, 1997.
The Company's 1998 interest expense is projected to be approximately $17
million. A principal payment of $16 million on the 10.18% private placement of
senior notes is due in the second quarter of 1998.
The Company has begun making necessary changes to its computer software in
preparation for the year 2000. These projects are on schedule and the Company
believes that the related costs will not be material to its results of
operations or financial condition.
Capitalization information on the Company is as follows:
<TABLE>
<CAPTION>
(In millions) 1997 1996 1995
- ----------------------------------------------------------
<S> <C> <C> <C>
Long-Term Debt $183.0 $248.0 $249.0
Current Portion of
Long-Term Debt 16.0 -- --
------ ------ ------
Total Debt 199.0 248.0 249.0
Stockholders' Equity
Common Stock 127.4 69.4 56.6
Preferred Stock 56.7 91.3 91.3
------ ------ ------
Total Equity 184.1 160.7 147.9
------ ------ ------
Total Capitalization $383.1 $408.7 $396.9
====== ====== ======
Debt to Capitalization 51.9% 60.7% 62.7%
------ ------ ------
</TABLE>
21
<PAGE> 23
The Company's capitalization reflects the non-cash impact to equity of the
$69.2 million SFAS 121 impairment of long-lived assets recorded in 1995. (See
Note 15 of the Notes to the Consolidated Financial Statements for further
discussion.)
CAPITAL AND EXPLORATION EXPENDITURES
The following table presents major components of capital and exploration
expenditures for the three years ended December 31, 1997.
<TABLE>
<CAPTION>
(In millions) 1997 1996 1995
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Capital Expenditures:
Drilling and Facilities $ 68.2 $ 42.7 $ 19.3
Leasehold Acquisitions 4.3 4.3 2.0
Pipeline and Gathering 6.1 6.3 2.2
Other 2.0 0.7 1.2
------- ------- -------
80.6 54.0 24.7
------- ------- -------
Proved Property Acquisitions(3) 45.6 6.6 --
WERCO Acquisition -- (5.3)(1) (8.4)(2)
------- ------- -------
45.6 1.3 (8.4)
------- ------- -------
Exploration Expenses 13.9 12.6 8.0
------- ------- -------
Total $ 140.1 $ 67.9 $ 24.3
======= ======= =======
- --------------------------------------------------------------------------------
</TABLE>
(1) An adjustment to the $40.2 million non-cash component relating to deferred
taxes for the difference between the tax and book bases of the acquired
properties, as required by SFAS 109, "Accounting for Income Taxes", of the
WERCO acquisition as a result of the $8.4 million valuation adjustment
received in 1995.
(2) A net cash payment received in connection with a valuation adjustment on the
1994 WERCO acquisition.
(3) Includes $45.2 million in assets acquired from Equitable Resources Energy
Company in a like-kind exchange transaction with a portion of the assets
sold in the Meadville properties sale.
The substantially reduced level of capital and exploration expenditures in
1995 resulted from the downsized capital expenditures program resulting from
depressed gas prices and the absence of a major acquisition.
The Company generally funds 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, exclusive of acquisitions.
Planned expenditures for 1998 have been increased 17% compared with 1997,
excluding proved property acquisitions. Depending on the level of future natural
gas prices, the Company intends to review and adjust the capital and exploration
expenditures planned for 1998 as industry conditions dictate. Presently, the
Company projects $111 million in capital and exploration expenditures for 1998
including $88.5 million for the drilling and exploration program. The Company
plans to drill 270 wells (173.2 net), compared with 225 wells (151.4 net)
drilled in 1997.
In addition to the drilling and exploration program, other 1998 capital
expenditures are planned primarily for producing property and lease acquisitions
and for gathering and pipeline infrastructure maintenance and construction.
During 1997, dividends were paid on the Company's common stock totaling
$3.7 million, on the $3.125 convertible preferred stock totaling $1.7 million,
and on the 6% convertible redeemable preferred stock totaling $3.4 million. The
Company has paid quarterly common stock dividends of $0.04 per share since
becoming publicly traded
22
<PAGE> 24
in 1990. The amount of future dividends is determined by the Board of Directors
and is dependent upon a number of factors, including future earnings, financial
condition, and capital requirements.
OTHER ISSUES AND CONTINGENCIES
Encogen Gas Contract. See Item 3. Legal Proceedings on page 16 for a
discussion of this matter.
Corporate Income Tax. The Company generates tax credits for the production
of certain qualified fuels, including natural gas produced from tight formations
and Devonian Shale. The credit for natural gas from a tight formation ("tight
gas sands") amounts to $0.52 per Mmbtu for natural gas sold prior to 2003 from
qualified wells drilled in 1991 and 1992. A number of wells drilled in the
Appalachian Region during 1991 and 1992 qualified for the tight gas sands tax
credit. The credit for natural gas produced from Devonian Shale is approximately
$1.05 per Mmbtu in 1997. In 1995 and 1996, the Company completed three
transactions to monetize the value of these tax credits, resulting in revenues
of $3.6 million in 1997 and approximately $16.4 million over the remaining five
years (See Note 18 of the Notes to the Consolidated Financial Statements for
further discussion).
The Company has benefited in the past and may benefit in the future from
the alternative minimum tax ("AMT") relief granted under the Comprehensive
National Energy Policy Act of 1992. The Act repealed provisions of the AMT
requiring a taxpayer's alternative minimum taxable income to be increased on
account of certain intangible drilling costs ("IDC") and percentage depletion
deductions. The repeal of these provisions generally applies to taxable years
beginning after 1992. The repeal of the excess IDC preference cannot reduce a
taxpayer's alternative minimum taxable income by more than 40% of the amount of
such income determined without regard to the repeal of such preference.
Regulations. The Company's operations are subject to various types of
regulation by federal, state and local authorities. See "Regulation of Oil and
Natural Gas Production and Transportation" and "Environmental Regulations" in
the Other Business Matters section of Item 1. Business for a discussion of these
regulations.
Restrictive Covenants. The Company's ability to incur debt, to pay
dividends on its common and preferred stock, and to make certain types of
investments is dependent upon certain restrictive covenants in the Company's
various debt instruments. Among other requirements, the Company's 10.18% and
7.19% Notes specify a minimum annual coverage ratio of operating cash flow to
interest expense for the trailing four quarters of 2.8 to 1.0. At December 31,
1997 the calculated ratio for 1997 was 5.3 to 1.
CONCLUSION
The Company's financial results depend upon many factors, particularly the
price of natural gas and its ability to market its production on economically
attractive terms. The Company's average 1997 produced natural gas sales price
increased 8% compared to 1996, while production volumes increased 8.5%. As a
result, the Company experienced its highest level of earnings and operating cash
flow since becoming a public company in 1990. While prices in most regions of
the U.S. moved up sharply in November and December 1996 and January 1997, price
volatility in the gas market has remained prevalent in the last few years, as
demonstrated most recently in December 1997 and January 1998, with natural gas
prices dropping to levels substantially below the prices of the corresponding
months of the prior year. Given this continued price volatility, management
cannot predict with certainty what pricing levels will be for the rest of 1998
and beyond. Because future cash flows and earnings are subject to such
variables, there can be no assurance that the Company's operations will provide
cash sufficient to fully fund its capital requirements if prices should return
to the depressed levels of 1995.
While the Company's 1998 plans include an increase in capital spending,
the Company will periodically assess industry conditions and will adjust its
1998 spending plan to ensure the adequate funding of its capital requirements,
including, among other things, reductions in capital expenditures or common
stock dividends.
The Company believes its capital resources, supplemented, if necessary,
with external financing, are adequate to meet its capital requirements.
23
<PAGE> 25
The preceding paragraphs contain forward-looking information. See
Forward-Looking Information below.
* * *
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," "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.
24
<PAGE> 26
RESULTS OF OPERATIONS
For the purpose of reviewing the Company's results of operations, "Net
Income (Loss)" is defined as net income (loss) applicable to common
stockholders. The Company's Western Region includes operations located in the
Anadarko area, the onshore Gulf Coast, and in the Rocky Mountains.
SELECTED FINANCIAL AND OPERATING DATA
<TABLE>
<CAPTION>
(In millions except where specified) 1997 1996 1995
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Net Operating Revenues $ 185.1 $ 163.1 $ 121.1
Operating Expenses 121.3 116.0 237.2
Interest Expense 18.0 17.4 24.9
Net Income (Loss) 23.2 15.3 (92.2)
Earnings (Loss) Per Share - Basic $ 1.00 $ 0.67 $ (4.05)
Natural Gas Production (Bcf)
Appalachia 25.3 26.8 27.5
West 38.6 32.0 30.2
-------- ------- --------
Total Company 63.9 58.8 57.7
======== ======= ========
Produced Natural Gas Sales Price ($/Mcf)
Appalachia $ 3.00 $ 2.72 $ 2.22
West $ 2.22 $ 2.02 $ 1.33
Total Company $ 2.53 $ 2.34 $ 1.75
Crude/Condensate
Volume (Mbbl) 574 520 618
Price ($/Bbl) $ 20.13 $ 21.14 $ 17.95
</TABLE>
The table below presents the after-tax effects of certain selected items
("selected items") on the Company's results of operations for the three years
ended December 31, 1997.
<TABLE>
<CAPTION>
(In millions) 1997 1996 1995
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Net Income (Loss) Before Selected Items $ 23.2 $ 12.5 $(17.3)
Income tax refund 2.8
SFAS 121 impairment (69.2)
Cost reduction program (4.7)
Columbia settlement 2.6
Decoupled gas price hedges (2.0)
Terminated interest rate swaps (1.6)
-------- ------ ------
Net Income (Loss) $ 23.2 $ 15.3 $(92.2)
======== ====== ======
</TABLE>
1997 AND 1996 COMPARED
Net Income and Revenues. The Company reported net income in 1997 of $23.2
million, or $1.00 per share, up $10.7 million, or $0.45 per share, compared to
1996, excluding the impact of the selected items. The $2.8 million special item,
or $0.12 per share, in 1996 related to a $1.8 million tax refund for percentage
depletion claimed for certain periods prior to 1990 and $1.7 million of interest
income ($1.0 million after tax) earned on the refund amount. Excluding these
pre-tax effects of the selected items, 1997 operating income and net operating
revenues increased $15.1 million and $22.1 million, respectively. Natural gas
sales comprised 87%, or $161.7 million, of net operating revenue in 1997. The
increase in net operating revenue was a result of both an 8% increase in the
produced natural gas sales price and an 8.5% increase in equivalent production.
Operating income and net income were similarly impacted by the
25
<PAGE> 27
increases in natural gas prices and equivalent production along with lower
depreciation, depletion and amortization expense and interest expense.
Effective September 1, 1997, the Company sold proved reserves and acreage
located primarily in Northwest Pennsylvania (the "Meadville properties") for
$92.9 million to Lomak Petroleum Incorporated. The properties sold included 912
wells, producing approximately 15 Mmcfe net per day primarily from the Medina
formation. A portion of these assets were replaced, in a like-kind exchange
transaction, with oil and gas producing properties located in the Green River
Basin of Wyoming (the "Green River properties") purchased for $45.2 million in a
transaction with Equitable Resources Energy Company which closed on October 3,
1997. The purchased properties added an estimated 72 Bcfe of reserves, interests
in 63 wells with estimated daily net production of 10 Mmcfe and 74 potential
drilling locations to the Western Region. This acquisition increased the
Company's presence in the Rocky Mountains area by 46%.
Natural gas production volumes were down 1.5 Bcf, or 6%, to 25.3 Bcf in
the Appalachian Region as a result of the September sale of the Meadville
properties which were estimated to have produced 1.7 Bcfe in 1997 after the
sale. Natural gas production volumes were up 6.6 Bcf, or 21%, to 38.6 Bcf in the
Western Region due largely to new production from wells drilled and put on line
in the Rocky Mountains and Gulf Coast areas during the last half of 1996 and in
1997 and from the acquired Green River properties which produced 1.9 Bcfe.
In the Appalachian Region, the average natural gas production sales price
increased $0.28 per Mcf, or 10%, to $3.00, increasing net operating revenues by
approximately $7.1 million on 25.3 Bcf of production. The average Western Region
natural gas production sales price increased $0.20 per Mcf, or 10%, to $2.22,
increasing net operating revenues by approximately $7.7 million on 38.6 Bcf of
production. The overall weighted average natural gas production sales price
increased $0.19 per Mcf, or 8%, to $2.53.
Crude oil and condensate sales increased by 54 Mbbl, or 10%, primarily due
to new production brought on by the higher rate of drilling activity in 1996 and
1997 compared to 1995 levels.
Brokered natural gas margin was down $1.5 million to $4.1 million due
primarily to a $0.03 per Mcf decrease in the net margin to $0.12 per Mcf and in
part to a brokered volume decrease of 8% from 1996.
Operating Expense. The total operating expenses increased $5.3 million,
or 5%, to $77.9 million. The significant changes are explained as follows:
o Direct operation expense increased $1.0 million, or 4%, due to office
consolidation costs in the Western Region and the 8.5% increase in
equivalent production. Direct operating costs per Mcfe declined,
however, from $0.45 to $0.43 due in part to the sale of the higher
cost Meadville properties and the addition of new lower cost
production.
o Exploration expense increased $1.3 million primarily due to a $0.9
million rise in geological and geophysical expenses and a $0.3 million
increase in contract labor services related to the increased drilling
and exploration program in 1997.
o Depreciation, depletion, amortization and impairment expense decreased
$1.9 million, or 4%. due to the benefit of the Meadville/Green River
like-kind exchange transaction in the third quarter and due to the
decline in the Western Region DD &A rate related to the addition of
new lower cost production to existing fields.
o Taxes other than income increased $2.0 million, or 16%, due to the
increase in natural gas production revenues.
o General and administrative expense increased $2.9 million, or 17%,
due primarily to higher incentive and stock compensation expenses
related to the Company's marked improvement in earnings performance.
26
<PAGE> 28
Interest expense, excluding the 1996 selected item, declined $1.1 million,
or 6%, due to a reduction in the Company's long-term debt level.
Income tax expense, excluding the selected item, was up $5.2 million due
to the comparable increase in earnings before income tax. The Company's
effective tax rate declined slightly due to a 0.2% reduction in the effective
state tax rate combined with a $0.2 million refund received on the prior year
percentage depletion claim.
1996 AND 1995 COMPARED
Net Income (Loss) and Revenues. The Company reported net income in 1996 of
$12.5 million, or $0.55 per share, up $29.8 million, or $1.31 per share,
compared with 1995, excluding the impact of the selected items. The $2.8 million
special item, or $0.12 per share, in 1996 related to a $1.8 million tax refund
for percentage depletion claimed for certain periods prior to 1990 and $1.7
million of interest income ($1.0 million after tax) earned on the refund amount.
The $74.9 million from special items, or $3.29 per share, in 1995 consisted of a
$113.8 million charge ($69.2 million after tax) related to the adoption of SFAS
121, $7.7 million ($4.7 million after tax) for the cost reduction program and
other severance costs, $3.2 million ($2.0 million after tax) loss related to
uncovered gas price hedges and a $2.6 million charge ($1.6 million after tax) to
interest expense to close interest rate swap contracts, offset in part by other
revenue of $4.3 million ($2.6 million after tax) in connection with the sale of
a Columbia bankruptcy claim. Excluding the pre-tax effects of the selected
items, operating income and net operating revenues increased $39 million and
$43.1 million, respectively. Natural gas sales comprised 84%, or $137.5 million,
of net operating revenue in 1996. The increase in net operating revenues was
driven primarily by a 34% increase in the produced natural gas sales price. Net
income (loss) and operating income (loss), excluding selected items, were
similarly impacted by the increase in the produced natural gas sales price, as
well as lower depreciation, depletion & amortization and interest expenses.
Natural gas production volumes were down 0.7 Bcf, or 3%, to 26.8 Bcf in
the Appalachian Region, a result from the low level of drilling activity in 1995
and the sale of non-strategic properties. Natural gas production volumes were up
1.8 Bcf, or 6%, to 32.0 Bcf in the Western Region due primarily to Rocky
Mountains and Gulf Coast area wells drilled and put on line in the second and
third quarters of 1996.
The average Appalachian natural gas production sales price increased $0.50
per Mcf, or 23%, to $2.72, increasing net operating revenues by approximately
$13.6 million on 26.8 Bcf of production. In the Western Region, the average
natural gas production sales price increased $0.69 per Mcf, or 52%, to $2.02,
increasing net operating revenues by approximately $22.3 million on 32.0 Bcf of
production. The overall weighted average natural gas production sales price
increased $0.59 per Mcf, or 34%, to $2.34.
Crude oil and condensate sales decreased 98 Mbbl, or 16%, due primarily to
the low drilling activity in 1995 and the sale of various non-strategic oil
properties in 1995.
Brokered natural gas margin was up $3.1 million to $5.6 million due
primarily to a $0.08 per Mcf increase in the net margin to $0.15 per Mcf, a
result of the higher prices environment in 1996. Brokered volume was comparable
to 1995.
Operating Expenses. Total operating expenses, excluding the selected
items, were virtually unchanged, increasing $0.4 million. The significant
changes are explained as follows:
o Exploration expense increased $4.5 million due to the $4.1 million
increase in dry hole expense and the $0.4 million increase in
geological and geophysical expenses, a direct result of the increased
capital expenditure program in 1996.
o Depreciation, depletion, amortization and impairment expense
decreased $6.9 million, or 13%, due to a $0.11 per Mcfe decline in the
DD&A rate caused by the 1995 impairment of long-lived assets which
reduced depreciable basis by $113.8 million.
27
<PAGE> 29
o Taxes other than income increased $1.6 million, or 14%, due primarily
to the increase in natural gas production revenues.
o The cost reduction program in 1995 consisted primarily of a 23% staff
reduction, achieved through early retirement and involuntary
termination programs. The pre-tax charges, a selected item, related to
this action totaled $6.8 million, comprised of $3.8 million in salary
and other severance related expense and a $3.0 million non-cash charge
for curtailments to the pension and postretirement benefits plans.
Interest expense, excluding selected items, declined $3.1 million, or 14%,
due primarily to the absence of the interest rate swaps which effectively
increased interest expense in 1995.
Income tax expense, excluding the selected item, was up $67.4 million due
to the comparable increase in earnings before income tax. The Company's
effective tax rate was virtually unchanged.
28
<PAGE> 30
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
- ---------------------------------------------------------------------------
Report of Independent Accountants 31
Consolidated Statement of Operations 32
Consolidated Balance Sheet 33
Consolidated Statement of Cash Flows 34
Consolidated Statement of Stockholders' Equity 35
Notes to Consolidated Financial Statements 36
Supplemental Oil & Gas Information (Unaudited) 55
Quarterly Financial Information (Unaudited) 59
REPORT OF MANAGEMENT
The management of Cabot Oil & Gas Corporation is responsible for the
preparation and integrity of all information contained in the annual report. The
consolidated financial statements and other financial information are prepared
in conformity with generally accepted accounting principles and, accordingly,
include certain informed judgments and estimates of management.
Management maintains a system of internal accounting and managerial
controls and engages internal audit representatives who monitor and test the
operation of these controls. Although no system can ensure the elimination of
all errors and irregularities, the system is designed to provide reasonable
assurance that assets are safeguarded, transactions are executed in accordance
with management's authorization and accounting records are reliable for
financial statement preparation.
An Audit Committee of the Board of Directors, consisting of directors who
are not employees of the Company, meets periodically with management, the
independent accountants and internal audit representatives to obtain assurances
to the integrity of the Company's accounting and financial reporting and to
affirm the adequacy of the system of accounting and managerial controls in
place. The independent accountants and internal audit representatives have full
and free access to the Audit Committee to discuss all appropriate matters.
We believe that the Company's policies and system of accounting and
managerial controls reasonably assure the integrity of the information in the
consolidated financial statements and in the other sections of the annual
report.
Charles P. Siess, Jr. Ray Seegmiller
Chairman of the Board and President and
Chief Executive Officer Chief Operating Officer
March 6, 1998
29
<PAGE> 31
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE STOCKHOLDERS AND BOARD OF DIRECTORS OF CABOT OIL & GAS CORPORATION:
We have audited the accompanying consolidated balance sheet of Cabot Oil &
Gas Corporation as of December 31, 1997 and 1996, and the related consolidated
statements of operations, stockholders' equity, and cash flows for each of the
three years in the period ended December 31, 1997. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Cabot Oil & Gas
Corporation as of December 31, 1997 and 1996, and the consolidated results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1997, in conformity with generally accepted accounting
principles.
As discussed in Notes 14 and 15 to the consolidated financial statements,
in 1995 the Company changed its method of applying the unit-of-production method
to calculate depreciation and depletion on producing oil and gas properties, and
accounting for the impairment of long-lived assets.
COOPERS & LYBRAND L.L.P.
Houston, Texas
March 6, 1998
30
<PAGE> 32
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
<TABLE>
<CAPTION>
Year Ended December 31,
(In thousands, except per share amounts) 1997 1996 1995
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C>
NET OPERATING REVENUES
Natural Gas Production $ 161,737 $ 137,482 $ 101,260
Crude Oil and Condensate 11,443 10,992 11,089
Brokered Natural Gas Margin 4,113 5,619 2,509
Other 7,834 8,968 6,225
--------- --------- ---------
185,127 163,061 121,083
OPERATING EXPENSES
Direct Operations 29,380 28,361 28,328
Exploration 13,884 12,559 8,031
Depreciation, Depletion and Amortization 40,598 42,689 47,206
Impairment of Long-Lived Assets (Note 15) -- -- 113,795
Impairment of Unproved Properties 2,856 2,701 5,047
General and Administrative 19,744 16,823 16,785
Cost Reduction Program (Note 12) -- -- 6,820
Taxes Other Than Income 14,874 12,826 11,215
--------- --------- ---------
121,336 115,959 237,227
Gain (Loss) on Sale of Assets 61 1,685 (614)
--------- --------- ---------
INCOME (LOSS) FROM OPERATIONS 63,852 48,787 (116,758)
Interest Expense 17,961 17,409 24,885
--------- --------- ---------
Income (Loss) Before Income Tax Expense 45,891 31,378 (141,643)
Income Tax Expense (Benefit) 17,557 10,554 (55,025)
--------- --------- ---------
NET INCOME (LOSS) 28,334 20,824 (86,618)
Dividend Requirement on Preferred Stock 5,103 5,566 5,553
--------- --------- ---------
Net Income (Loss) Applicable to
Common Stockholders $ 23,231 $ 15,258 $ (92,171)
========= ========= =========
Basic Earnings (Loss) Per Share Applicable
to Common Stockholders (Note 20) $ 1.00 $ 0.67 $ (4.05)
========= ========= =========
Diluted Earnings (Loss) Per Share Applicable
to Common Stockholders (Note 20) $ 0.97 $ 0.66$ (4.05)
========= ========= =========
Average Common Shares Outstanding 23,272 22,807 22,775
========= ========= =========
- ----------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
31
<PAGE> 33
CABOT OIL & GAS CORPORATION
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
December 31,
(In thousands) 1997 1996
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 1,784 $ 1,367
Accounts Receivable 59,672 67,810
Inventories 6,875 8,797
Other 2,202 1,663
--------- ---------
Total Current Assets 70,533 79,637
PROPERTIES AND EQUIPMENT (Successful Efforts Method) 469,399 480,511
OTHER ASSETS 1,873 1,193
--------- ---------
$ 541,805 $ 561,341
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current Portion of Long-Term Debt $ 16,000 --
Accounts Payable 52,348 $ 56,338
Accrued Liabilities 17,524 16,279
--------- ---------
Total Current Liabilities 85,872 72,617
LONG-TERM DEBT 183,000 248,000
DEFERRED INCOME TAXES 80,108 69,427
OTHER LIABILITIES 8,763 10,593
COMMITMENTS AND CONTINGENCIES (Note 8)
STOCKHOLDERS' EQUITY
Preferred Stock:
Authorized -- 5,000,000 Shares of $0.10 Par Value Issued and Outstanding --
$3.125 Cumulative Convertible Preferred; $50 Stated Value; 0 Shares in
1997 and 692,439 Shares 1996 -- 6% Convertible Redeemable Preferred; $50
Stated Value; 1,134,000 Shares in 1997 and 1996 113 183
Common Stock:
Authorized -- 40,000,000 Shares of $0.10 Par Value Issued and Outstanding
-- 24,667,262 Shares and 22,847,345 Shares at December 31, 1997 and 1996,
respectively 2,467 2,284
Class B Common Stock:
Authorized -- 800,000 Shares of $0.10 Par Value
No Shares Issued -- --
Additional Paid-in Capital 247,033 243,283
Accumulated Deficit (65,551) (85,046)
--------- ---------
Total Stockholders' Equity 184,062 160,704
--------- ---------
$ 541,805 $ 561,341
========= =========
- ---------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
32
<PAGE> 34
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
Year Ended December 31,
(In thousands) 1997 1996 1995
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss) $ 28,334 $20,824 $ (86,618)
Adjustments to Reconcile Net Income (Loss)
to Cash Provided by Operations:
Depletion, Depreciation, and Amortization 40,598 42,689 47,206
Impairment of Long-Lived Assets -- -- 113,795
Impairment of Unproved Properties 2,856 2,701 5,047
Deferred Income Tax Expense (Benefit) 10,681 12,017 (55,055)
Loss (Gain) on Sale of Assets (61) (1,685) 614
Exploration Expense 13,884 12,559 8,031
Other, Net 1,419 176 3,178
Changes in Assets and Liabilities:
Accounts Receivable 8,137 (25,796) (3,848)
Inventories 1,922 (3,201) 2,788
Other Current Assets (539) 46 (13)
Other Assets (680) 243 (37)
Accounts Payable and Accrued Liabilities (10,541) 11,199 5,838
Other Liabilities (970) 3,713 565
---------- ------- -------
Net Cash Provided by Operations 95,040 75,485 41,491
---------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (73,476) (60,719) (24,672)
Cost of Major Acquisition -- -- 8,402
Proceeds from Sale of Assets 48,916 5,725 10,291
Exploration Expense (13,884) (12,559) (8,031)
---------- ------- -------
Net Cash Used by Investing (38,444) (67,553) (14,010)
---------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt 11,000 6,000 16,000
Decrease in Debt (60,000) (7,000) (35,363)
Exercise of Stock Options 2,197 613 348
Preferred Dividends Paid (5,644) (5,566) (5,566)
Common Dividends Paid and Other, Net (3,732) (3,641) (3,644)
---------- ------- -------
Net Cash Used by Financing (56,179) (9,594) (28,225)
---------- ------- -------
Net Increase (Decrease) in Cash and
Cash Equivalents 417 (1,662) (744)
Cash and Cash Equivalents, Beginning of Year 1,367 3,029 3,773
---------- ------- -------
Cash and Cash Equivalents, End of Year $ 1,784 $ 1,367 $ 3,029
========== ======= =======
- ----------------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
33
<PAGE> 35
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
Retained
Common Preferred Paid-In Earnings
(In thousands) Stock Stock Capital (Deficit) Total
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Balance at December 31, 1995 $ 2,275 $ 183 $241,471 $ (847) $ 243,082
------- ----- -------- -------- ---------
Net Loss (86,618) (86,618)
Exercise of Stock Options 3 345 348
Preferred Stock Dividends (5,566) (5,566)
Common Stock Dividends
at $0.16 Per Share (3,631) (3,631)
Stock Grant Vesting 242 242
Other (1) (1)
------- ----- -------- -------- ---------
Balance at December 31, 1996 $ 2,278 $ 183 $242,058 $(96,663) $ 147,856
======= ===== ======== ======== =========
Net Income 20,824 20,824
Exercise of Stock Options 6 607 613
Preferred Stock Dividends (5,566) (5,566)
Common Stock Dividends
at $0.16 Per Share (3,649) (3,649)
Stock Grant Vesting 618 618
Other 8 8
------- ----- -------- -------- ---------
Balance at December 31, 1997 $ 2,284 $ 183 $243,283 $(85,046) $ 160,704
======= ===== ======== ======== =========
Net Income 28,334 28,334
Exercise of Stock Options 14 2,183 2,197
Preferred Stock Dividends (5,103) (5,103)
Common Stock Dividends (3,732) (3,732)
at $0.16 Per Share
Stock Grant Vesting 1,662 1,662
Conversion of $3.125 Preferred
Stock to Common Stock 165 (70) (95) 0
Other 4 (4) 0
------- ----- -------- -------- ---------
BALANCE AT DECEMBER 31, 1997 $ 2,467 $ 113 $247,033 $(65,551) $ 184,062
======= ===== ======== ======== =========
- ---------------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
34
<PAGE> 36
CABOT OIL & GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION
Cabot Oil & Gas Corporation and subsidiaries (the "Company") are engaged
in the exploration, development, production and marketing of natural gas and, to
a lesser extent, crude oil and natural gas liquids. The Company also transports,
stores, gathers and purchases natural gas for resale.
The consolidated financial statements contain the accounts of the Company
after elimination of all significant intercompany balances and transactions.
PIPELINE EXCHANGES
Natural gas gathering and pipeline operations normally include exchange
arrangements with customers and suppliers. The volumes of natural gas due to or
from the Company under exchange agreements are recorded at average selling or
purchase prices, as the case may be, and are adjusted monthly to reflect market
changes. The net value of exchanged natural gas is included in inventories in
the consolidated balance sheet.
PROPERTIES AND EQUIPMENT
The Company uses the successful efforts method of accounting for oil and
gas producing activities. Under this method, acquisition costs for proved and
unproved properties are capitalized when incurred. Exploration costs, including
geological and geophysical costs, the costs of carrying and retaining unproved
properties and exploratory dry hole drilling costs, are expensed. Development
costs, including the costs to drill and equip development wells, and successful
exploratory drilling costs that locate proved reserves, are capitalized
Before the Company adopted Statement of Financial Accounting Standard
("SFAS") No. 121 on September 1, 1995, the Company limited the total amount of
unamortized capitalized costs to the value of future net revenues, based on
current prices and costs. Under SFAS 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of", the unamortized
capital costs at a lease level are reduced to fair value if it is determined
that the sum of expected future net cash flows is less than the net book value
(See Note 15 Accounting For Long-Lived Assets). The Company makes a
determination of an impairment event through either adverse changes or a
periodic review of all fields each year.
Capitalized costs of proved oil and gas properties, after considering
estimated dismantlement, restoration and abandonment costs, net of estimated
salvage values, are depreciated and depleted on a field basis by the
unit-of-production method using proved developed reserves (See Note 14
Accounting Change). The costs of unproved oil and gas properties are generally
aggregated and amortized over a period that is based on the average holding
period for such properties and the Company's experience of successful drilling.
Properties related to gathering and pipeline systems and equipment are
depreciated using the straight-line method based on estimated useful lives
ranging from 10 to 25 years. Certain other assets are also depreciated on a
straight-line basis.
Future estimated plug and abandonment cost is accrued over the productive
life of the oil and gas properties. The accrued liability for plug and
abandonment cost is included in accumulated depreciation, depletion and
amortization.
Costs of retired, sold or abandoned properties, constituting a part of an
amortization base, are charged to accumulated depreciation, depletion, and
amortization. Accordingly, gain or loss, if any, is recognized only when a group
of proved properties (or field), constituting the amortization base, has been
retired, abandoned or sold.
35
<PAGE> 37
REVENUE RECOGNITION AND GAS IMBALANCES
The Company applies the sales method of accounting for natural gas
revenue. Under this method, revenues are recognized based on the actual volume
of natural gas sold to purchasers. Natural gas production operations may include
joint owners who take more or less than the production volumes entitled to them
on certain properties. Volumetric production is monitored to minimize these
natural gas imbalances. A natural gas imbalance liability is recorded in other
liabilities in the consolidated balance sheet if the Company's excess takes of
natural gas exceed its estimated remaining recoverable reserves for such
properties.
INCOME TAXES
The Company follows the asset and liability method in accounting for
income taxes. Under this method, deferred tax assets and liabilities are
recorded for the estimated future tax consequences attributable to the
differences between the financial carrying amounts of existing assets and
liabilities and their respective tax bases. Deferred tax assets and liabilities
are measured using the tax rate in effect for the year in which those temporary
differences are expected to turn around. The effect of a change in tax rates on
deferred tax assets and liabilities is recognized in the year of the enacted
rate change.
NATURAL GAS MEASUREMENT
The Company records estimated amounts for natural gas revenues and natural
gas purchase costs based on volumetric calculations under its natural gas sales
and purchase contracts. Variances or imbalances resulting from such calculations
are inherent in natural gas sales, production, operation, measurement, and
administration. Management does not believe that differences between actual and
estimated natural gas revenues or purchase costs attributable to the unresolved
variances or imbalances are material.
ACCOUNTS PAYABLE
This account includes credit balances to the extent that checks issued
have not been presented to the Company's bank for payment. These credit balances
included in accounts payable were approximately $5.5 million and $10.4 million
at December 31, 1997 and 1996, respectively.
EARNINGS (LOSS) PER COMMON SHARE
In February 1997, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 128, Earnings per Share ("SFAS
128"). The Company has adopted this statement effective December 31, 1997. SFAS
128 simplifies the computation of earnings per share for companies with complex
capital structure by replacing primary and fully diluted presentations with the
new basic and diluted disclosures. It has not impacted the Company's previously
disclosed earnings per share since the Company had a simple capital structure
and because earnings per share in prior years was calculated in the same manner
that the new "Basic" earnings per share is presented. Basic earnings per share
amounts are based on the weighted average of shares outstanding ( 23,272,432 in
1997 and 22,806,516 in 1996). See Note 20 Earnings (Loss) Per Common Share for
further discussion.
RISK MANAGEMENT ACTIVITIES
From time to time, the Company enters into derivative contracts, such as
natural gas price swaps, as a hedging strategy to manage commodity price risk
associated with its inventories, production or other contractual commitments.
Gains or losses on these hedging activities are generally recognized over the
period that the inventory, production or other underlying commitment is hedged.
The cash flows related to any recognized gains or losses associated with these
hedges are reported as cash flows from operations. If the hedge is terminated
prior to expected maturity, gains or losses are deferred and included in income
in the same period that the underlying production or other contractual
commitment is delivered. Unrealized gains or losses associated with any
derivative contracts not considered to be a hedge are recognized currently in
the results of operations.
36
<PAGE> 38
The conditions to be met for a derivative instrument to qualify as a hedge
are as follows: (1) the item to be hedged exposes the Company to price risk; (2)
the derivative reduces the risk exposure and is designated as a hedge at the
time the derivative contract is entered into; and (3) at the inception of the
hedge and throughout the hedge period there is a high correlation of the changes
in the market value of the derivative instrument and the fair value of the
underlying item being hedged.
When the designated item associated with a derivative instrument matures,
is sold, extinguished or terminated, derivative gains or losses are recognized
as part of the gain or loss on sale or settlement of the underlying item. When a
derivative instrument is associated with an anticipated transaction that is no
longer expected to occur or if correlation no longer exists, the gain or loss on
the derivative is recognized currently in the results of operations to the
extent the market value changes in the derivative have not been offset by the
effects of the price changes on the hedged item since the inception of the
hedge. See Note 13 Financial Instruments for further discussion.
CASH EQUIVALENTS
The Company considers all highly liquid short-term investments with
original maturities of three months or less to be cash equivalents.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. The Company's most significant financial estimates are based
on remaining proved oil and gas reserves (see Supplemental Oil and Gas
Information). Actual results could differ from those estimates.
RECLASSIFICATIONS
Certain items within the Consolidated Statement of Operations for the year
ended 1995 have been reclassified to conform with the 1996 and 1997
presentation. Under the new presentation, the Company presents gas revenues from
its equity production net of related costs (principally transportation and
storage costs) in a new revenue item called "Natural Gas Production". Similarly,
the procurement costs related to the purchase and resale (brokered) activity are
netted against the gas revenues and presented in a new item called "Brokered
Natural Gas Margin" in the net operating revenues section.
2. PROPERTIES AND EQUIPMENT
Properties and equipment are comprised of the following:
<TABLE>
<CAPTION>
December 31,
(In thousands) 1997 1996
- ------------------------------------------------------------
<S> <C> <C>
Unproved Oil and Gas Properties $ 24,618 $ 15,746
Proved Oil and Gas Properties 744,381 811,726
Gathering and Pipeline Systems 116,360 150,910
Land, Building and Improvements 3,896 5,221
Other 17,525 16,028
--------- ---------
906,780 999,631
Accumulated Depreciation,
Depletion and Amortization (437,381) (519,120)
--------- ---------
$ 469,399 $ 480,511
========= =========
</TABLE>
As a component of accumulated depreciation, depletion and amortization,
total accrued future plug and abandonment cost was $13.1 million and $14.8
million at December 31, 1997 and 1996, respectively. The Company believes that
this accrual adequately provides for its estimated future plug and abandonment
cost.
37
<PAGE> 39
3. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
<TABLE>
<CAPTION>
December 31,
(In thousands) 1997 1996
- ------------------------------------------------------------------------
<S> <C> <C>
Accounts Receivable
Trade Accounts $ 49,315 $ 63,458
Insurance Recoveries 3,043 --
Current Income Tax Receivable 1,291 --
Other Accounts 6,562 5,021
-------- --------
60,211 68,479
Allowance for Doubtful Accounts (539) (669)
-------- --------
$ 59,672 $ 67,810
======== ========
Accounts Payable
Trade Accounts $ 6,209 $ 12,277
Natural Gas Purchases 13,991 20,726
Royalty and Other Owners 11,995 13,469
Capital Costs 12,936 5,409
Dividends Payable 851 1,391
Taxes Other Than Income 1,478 1,170
Drilling Advances 2,333 111
Other Accounts 2,555 1,785
-------- --------
$ 52,348 $ 56,338
======== ========
Accrued Liabilities
Employee Benefits $ 6,067 $ 4,432
Taxes Other Than Income 8,314 8,407
Interest Payable 2,147 2,188
Other Accrued 996 1,252
-------- --------
$ 17,524 $ 16,279
======== ========
Other Liabilities
Postretirement Benefits Other Than Pension $ 992 $ 1,853
Accrued Pension Cost 3,742 4,022
Taxes Other Than Income and Other 4,029 4,718
-------- --------
$ 8,763 $ 10,593
======== ========
</TABLE>
4. INVENTORIES
Inventories are comprised of the following:
<TABLE>
<CAPTION>
December 31,
(In thousands) 1997 1996
- --------------------------------------------------------------------------------
<S> <C> <C>
Natural Gas in Storage $ 6,322 $ 7,312
Tubular Goods and Well Equipment 1,663 1,677
Pipeline Exchange Balances (1,110) (192)
---------- ---------
$ 6,875 $ 8,797
========== =========
</TABLE>
5. DEBT AND CREDIT AGREEMENTS
SHORT-TERM DEBT
The Company has a $5.0 million unsecured short-term line of credit with a
bank which it uses as part of its cash management program. The interest rate on
the line of credit is at the bank's prime rate minus 1%. The debt agreement was
established in February 1996, replacing the previous $5 million short-term line
with another bank. Aside from a
38
<PAGE> 40
more favorable rate, prime rate minus 1% versus prime rate, the terms of the new
line of credit are comparable to the previous line of credit. At December 31,
1997 and 1996, no debt was outstanding under the respective lines.
10.18% NOTES
In May 1990, the Company issued an aggregate principal amount of $80
million of its 12-year 10.18% Notes (the "10.18% Notes") to a group of nine
institutional investors in a private placement offering. The 10.18% Notes
require five annual $16 million principal payments starting in May 1998. The
payment due in May 1998 is classified as "Current Portion of Long-Term Debt", a
current liability on the Company's Consolidated Balance Sheet. The Company may
prepay all or any portion of the indebtedness on any date with a prepayment
premium. Due to the impact of the interest rate swap instruments obtained in
1993 (see "Interest Rate Swap Agreements" under Note 13 Financial Instruments),
the Company's effective interest rate for the 10.18% Notes in the year ended
December 31, 1995 was 12.6%. This effective rate excluded the $2.6 million
charge in December 1995 to terminate the remaining interest rate swaps. Without
the impact of the interest rate swaps, closed in 1995, the effective interest
rate returned to 10.18% in 1996 and 1997. The 10.18% Notes contain restrictions
on the merger of the Company or any subsidiary with a third party other than
under certain limited conditions, as well as various other restrictive covenants
customarily found in such debt instruments, including a restriction on the
payment of dividends and a required asset coverage ratio (present value of
proved reserves to debt and other liabilities) that must be at least 1.5 to 1.0.
7.19% NOTES
In November 1997, the Company issued an aggregate principal amount of
$100 million of its 12-year 7.19% Notes (the "7.19% Notes") to a group of six
institutional investors in a private placement offering. The 7.19% Notes require
five annual $20 million principal payments starting in November 2005. The
Company may prepay all or any portion of the indebtedness on any date with a
prepayment premium. The 7.19% Notes contain restrictions on the merger of the
Company or any subsidiary with a third party other than under certain limited
conditions, as well as various other restrictive covenants customarily found in
such debt instruments, including a required asset coverage ratio (present value
of proved reserves to debt and other liabilities) that must be at least 1.5 to
1.0; and a minimum annual coverage ratio of operating cash flow to interest
expense for the trailing four quarters of 2.8 to 1.0.
REVOLVING CREDIT AGREEMENT
The Company has a $135 million Revolving Credit Agreement (the "Credit
Facility") with five banks. During 1997, the Company elected to reduce its
availability under the Credit Facility to the existing $135 million level from
$235 million in connection with the issuance of the 7.19% Notes. The available
credit line is subject to adjustment from time-to-time on the basis of the
projected present value (as determined by a petroleum engineer's report
incorporating certain assumptions provided by the lender) of estimated future
net cash flows from certain proved oil and gas reserves and other assets of the
Company. In May 1997, the revolving term under the Credit Facility was extended
one year to June 1999. Interest rates are principally based on a reference rate
of either the rate for certificates of deposit ("CD rate") or LIBOR, plus a
margin, or the prime rate. The margin above the reference rate is presently
equal to 3/4 of 1% for the LIBOR based rate, or 7/8 of 1% for the CD based rate.
The Credit Facility provides for a commitment fee on the unused available
balance at an annual rate of 3/8 of 1% and a commitment fee on the unavailable
balance of the credit line at an annual rate of 1/4 of 1%. The Company's
effective interest rates for the Credit Facility in the years ended December 31,
1997, 1996 and 1995 were 6.6%, 6.6% and 6.8%, respectively. Although the
revolving term of the Credit Facility expires in June 1999, it may be extended
with the banks' approval. If such term is not extended, the indebtedness
outstanding will be payable in 24 quarterly installments. Interest rates are
subject to increase if the indebtedness under the Credit Facility is greater
than 80% of the Company's debt limit of $315 million, as noted below. The Credit
Facility contains various restrictive covenants customarily found in such
facilities, including restrictions (i) prohibiting the merger of the Company or
any subsidiary with a third party other than under certain limited conditions,
(ii) prohibiting the sale of all or substantially all of the Company's or any
subsidiary's assets to a third party, and (iii) requiring a minimum annual
coverage ratio of operating cash flow to interest expense for the trailing four
quarters of 2.8 to 1.0.
39
<PAGE> 41
6. EMPLOYEE BENEFIT PLANS
PENSION PLAN
The Company has a non-contributory, defined benefit pension plan covering
all full-time employees. The benefits for this plan are based primarily on years
of service and pay near retirement. Plan assets consist principally of fixed
income investments and equity securities. The Company funds the plan in
accordance with the Employee Retirement Income Security Act of 1974 and Internal
Revenue Code limitations.
The Company has a non-qualified equalization plan to ensure payments to
certain executive officers of amounts to which they are already entitled under
the provisions of the pension plan, but which are subject to limitations imposed
by federal tax laws. This plan is unfunded.
Net periodic pension cost of the Company for the years ended December 31,
1997, 1996 and 1995 are comprised of the following:
<TABLE>
<CAPTION>
(In thousands) 1997 1996 1995
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C>
QUALIFIED:
Current Year Service Cost $ 753 $ 737 $ 722
Interest Accrued on Pension Obligation 810 744 742
Actual Return on Plan Assets (1,129) (948) (1,327)
Net Amortization 491 448 934
Curtailment Gain -- -- (376)
Special Termination Benefit -- -- 766
------- -------- ---------
Net Periodic Pension Cost $ 925 $ 981 $ 1,461
======= ======== =========
NON-QUALIFIED:
Current Year Service Cost $ 28 $ 90 $ 63
Interest Accrued on Pension Obligation 6 6 23
Net Amortization 27 34 39
Curtailment Loss -- -- 37
Settlement Charge -- -- 174
------- -------- ---------
Net Periodic Pension Cost $ 61 $ 130 $ 336
======= ======== =========
</TABLE>
The following table sets forth the funded status of the Company's pension
plans at December 31, 1997 and 1996, respectively:
<TABLE>
<CAPTION>
1997 1996
(In thousands) QUALIFIED NON-QUALIFIED QUALIFIED NON-QUALIFIED
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Actuarial Present Value of:
Vested Benefit Obligation $ 7,838 $ 246 $ 6,946 $ 31
Accumulated Benefit Obligation 8,669 363 7,621 81
Projected Benefit Obligation $ 12,772 $ 668 $ 10,960 $ 81
Plan Assets at Fair Value 8,890 -- 7,074 --
-------- -------- --------- ---------
Projected Benefit Obligation in Excess
of Plan Assets 3,882 668 3,886 81
Unrecognized Net Gain (Loss) 1,527 (436) 1,750 140
Adjustment to Recognize Minimum
Liability 480
Unrecognized Prior Service Cost (862) (349) (950) (386)
-------- -------- --------- --------
Accrued (Prepaid) Pension Cost $ 4,547 $ 363 $ 4,686 $ (165)
======== ======== ========= ========
</TABLE>
40
<PAGE> 42
Assumptions used to determine benefit obligations and pension costs are as
follows:
<TABLE>
<CAPTION>
1997 1996 1995
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Discount Rate 7.50% 7.50% 7.50%(1)
Rate of Increase in Compensation Levels 4.50% 4.50% 4.50%(1)
Long-Term Rate of Return on Plan Assets 9.00% 9.00% 9.00%
- --------------------------------------------------------------------------------
</TABLE>
(1) Represents the rates used to determine the benefit obligation. An 8.5%
discount rate and 5.5% rate of increase in compensation levels were used to
compute pension costs.
SAVINGS INVESTMENT PLAN
The Company has a Savings Investment Plan (the "SIP") which is a defined
contribution plan. The Company matches a portion of employees' contributions.
Participation in the SIP is voluntary and all regular employees of the Company
are eligible to participate. The Company charged to expense plan contributions
of $0.6 million, $0.6 million and $0.8 million in 1997, 1996 and 1995,
respectively. Effective February 1, 1994, the Company's common stock was added
as an investment option within the SIP.
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits ("postretirement benefits") for retired
employees, including their spouses, eligible dependents and surviving spouses
("retirees"). Substantially all employees become eligible for these benefits if
they meet certain age and service requirements at retirement. The Company was
providing postretirement benefits to 259 retirees and 295 retirees at the end of
1997 and 1996, respectively.
The Company adopted SFAS 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions", in 1992 and elected to amortize the accumulated
postretirement benefit obligation at January 1, 1992 (the "Transition
Obligation") over 20 years.
The amortization benefit of the unrecognized Transition Obligation in
1997, 1996 and 1995, presented in the table below, is due to a cost-cutting
amendment to the postretirement medical benefits in 1993. The amendment
prospectively reduced the unrecognized Transition Obligation by $9.8 million and
is amortized over a 5.75 year period beginning in 1993.
Postretirement benefit costs recognized in the years ended December 31,
1997, 1996 and 1995 are comprised of the following:
<TABLE>
<CAPTION>
(In thousands) 1997 1996 1995
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service Cost of Benefits Earned During the Year $ 168 $ 99 $ 140
Interest Cost on the Accumulated Postretirement
Benefit Obligation 519 522 517
Amortization Benefit of the Unrecognized Gain (181) (163) (249)
Amortization Cost (Benefit) of the Unrecognized
Transition Obligation (808) (807) (821)
Curtailment Loss -- -- 2,074
Special Termination -- -- 503
------- ------- -------
Total Postretirement Benefit Cost (Benefit) $ (302) $ (349) $ 2,164
======= ======= =======
</TABLE>
41
<PAGE> 43
The health care cost trend rate used to measure the expected cost in 1997
for medical benefits to retirees over age 65 was 8.2%, graded down to a trend
rate of 0% in 2001. The health care cost trend rate used to measure the expected
cost in 1997 for retirees under age 65 was 8.5%, graded down to a trend rate of
0% in 2001. Provisions of the plan should prevent further increases in employer
cost after 2001.
The weighted average discount rate used in determining the actuarial
present value of the benefit obligation at December 31, 1997 and 1996 was 7.5%.
A one-percentage-point increase in health care cost trend rates for future
periods would increase the accumulated net postretirement benefit obligation by
approximately $167 thousand and, accordingly, the total postretirement benefit
cost recognized in 1996 would have also increased by approximately $17 thousand.
The funded status of the Company's postretirement benefit obligation at
December 31, 1997 and 1996 is comprised of the following:
<TABLE>
<CAPTION>
(In thousands) 1997 1996
- ------------------------------------------------------------------------------------------
<S> <C> <C>
Plan Assets at Fair Value $ -- $ --
Accumulated Postretirement Benefits Other Than Pensions
Retirees 5,626 5,681
Active Participants 1,677 1,526
-------- -------
7,303 7,207
Unrecognized Cumulative Net Gain 2,429 2,614
Unrecognized Transition Obligation (8,395) (7,587)
-------- -------
Accrued Postretirement Benefit Liability $ 1,337 $ 2,234
======== =======
</TABLE>
7. INCOME TAXES
Income tax expense (benefit) is summarized as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
(In thousands) 1997 1996 1995
- ------------------------------------------------------------------------------------
<S> <C> <C> <C>
CURRENT:
Federal $ 5,210 $ (1,229) $ --
State 1,089 316 30
---------- ---------- -----------
Total 6,299 (913) 30
---------- ---------- -----------
DEFERRED:
Federal 9,382 9,756 (46,430)
State 1,876 1,711 (8,625)
---------- ---------- ----------
Total 11,258 11,467 (55,055)
---------- ---------- ----------
Total Income Tax Expense (Benefit) $ 17,557 $ 10,554 $ (55,025)
========== ========== ==========
</TABLE>
Total income taxes were different than the amounts computed by applying
the statutory federal income tax rate as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
(In thousands) 1997 1996 1995
- -----------------------------------------------------------------------------------------
<S> <C> <C> <C>
Statutory Federal Income Tax Rate 35% 35% 35%
Computed "Expected" Federal Income Tax $ 16,062 $ 10,982 $(49,575)
State Income Tax, Net of Federal Income Tax 1,927 1,317 (5,586)
Other, Net (432) (1,745) 136
-------- -------- --------
Total Income Tax Expense (Benefit) $ 17,557 $ 10,554 $(55,025)
======== ======== ========
</TABLE>
42
<PAGE> 44
Income taxes for the year ended December 31, 1996 were decreased by $1.8
million due to a federal income tax refund in connection with percentage
depletion claimed in certain periods prior to the Company's IPO in 1990. The
Company also received $1.7 million of interest income in connection with the
income tax refund.
The tax effects of temporary differences that gave rise to significant
portions of the deferred tax liabilities and deferred tax assets as of December
31, 1997 and 1996 were as follows:
<TABLE>
<CAPTION>
(In thousands) 1997 1996
- ----------------------------------------------------------------------------
<S> <C> <C>
DEFERRED TAX LIABILITIES:
Property, Plant and Equipment $115,808 $115,099
-------- --------
DEFERRED TAX ASSETS:
Alternative Minimum Tax Credit Carryforwards 9,674 3,786
Net Operating Loss Carryforwards 6,749 17,708
Note Receivable on Section 29 Monetization(1) 13,933 18,347
Items Accrued for Financial Reporting Purposes 5,344 5,831
-------- --------
35,700 45,672
-------- --------
Net Deferred Tax Liabilities $ 80,108 $ 69,427
======== ========
- ----------------------------------------------------------------------------
</TABLE>
(1) As a result of the monetization of Section 29 tax credits in 1997 and 1996,
the Company recorded an asset sale for tax purposes in exchange for a
long-term note receivable which will be repaid through 100% working and
royalty interest in the production from the sold properties.
At December 31, 1997, the Company has a net operating loss carryforward
for regular income tax reporting purposes of $18.2 million which will begin
expiring in 2009. In addition, the Company has an alternative minimum tax credit
carryforward of $9.7 million which does not expire and is available to offset
regular income taxes in future years to the extent that regular income taxes
exceed the alternative minimum tax in any such year. In 1996, the Company
recorded a $5.3 million adjustment reducing deferred tax liabilities for the
reversal of temporary differences associated with the $8.4 million valuation
adjustment received in 1995 on the 1994 WERCO acquisition (See Note 11 WERCO
Acquisition).
8. COMMITMENTS AND CONTINGENCIES
LEASE COMMITMENTS
The Company leases certain transportation vehicles, warehouse facilities,
office space and machinery and equipment under cancelable and non-cancelable
leases, most of which expire within five years and may be renewed by the
Company. Rent expense under such arrangements totaled $4.1 million, $4.8 million
and $4.9 million for the years ended December 31, 1997, 1996 and 1995,
respectively. Future minimum rental commitments under non-cancelable leases in
effect at December 31, 1997 are as follows:
<TABLE>
<CAPTION>
(In thousands)
- ----------------------------------------------
<S> <C>
1998 $ 2,932
1999 2,146
2000 1,422
2001 1,039
2002 906
Thereafter 430
--------
$ 8,875
========
</TABLE>
Minimum rental commitments are not reduced by minimum sublease rental
income of $1.4 million due in the future under non-cancelable subleases.
43
<PAGE> 45
CONTINGENCIES
The Company is a defendant in various lawsuits and is involved in other
gas contract issues. In the opinion of the Company, final judgments or
settlements, if any, which may be awarded in connection with any one or more of
these suits and claims could be significant to the results of operations and
cash flows of any period but would not have a material adverse effect on the
Company's financial position.
The Company sells approximately 20,000 Mmbtu of its natural gas per day in
the Western Region to a cogeneration plant owned by Encogen Northwest, L.P.
("Encogen") under a contract containing a fixed price that escalates annually, a
firm delivery arrangement and a term continuing through June 30, 2008. Encogen
has requested that the Company consider restructuring this agreement. Thus far
the Company has been unwilling to restructure the agreement without full
compensation for the agreements value. See Item 3. Legal Proceedings for further
discussion of this matter.
9. CASH FLOW INFORMATION
Cash paid for interest and income taxes is as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
(In thousands) 1997 1996 1995
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Interest $18,001 $17,105 $24,744
Income Taxes $ 8,980 $ 873 $ 197
</TABLE>
At December 31, 1997 and 1996, the majority of cash and cash equivalents
is concentrated in one financial institution. Additionally, the Company has
accounts receivable that are subject to credit risk.
At December 31, 1997 and 1996, the Accounts Payable balance on the
Consolidated Balance Sheet included payables for capital expenditures of $12.9
million and $5.4 million, respectively.
10. CAPITAL STOCK
INCENTIVE PLANS
On May 20, 1994, the 1994 Long-Term Incentive Plan and the 1994
Non-Employee Director Stock Option Plan were approved by the shareholders. The
Company has two other stock option plans - the Incentive Stock Option Plan,
adopted in 1990, and the 1990 Non-Employee Director Stock Option Plan. Under
these four plans (the "Incentive Plans"), incentive and non-statutory stock
options, stock appreciation rights ("SARs") and stock awards may be granted to
key employees and officers of the Company, and non-statutory stock options may
be granted to non-employee directors of the Company. A maximum of 2,660,000
shares of Common Stock, par value $0.10 per share, are subject to issuance under
the Incentive Plans. All stock options have a maximum term of five or ten years
from the date of grant and most vest over time. The options are issued at market
value on the date of grant. The minimum exercise period for stock options is six
months from the date of grant. No SARs have been granted under the Incentive
Plans. Information regarding the Company's Incentive Plans is summarized below:
44
<PAGE> 46
<TABLE>
<CAPTION>
December 31,
1997 1996 1995
- --------------------------------------------------------------------------------------
<S> <C> <C> <C>
Shares Under Option at
Beginning of Period 1,532,353 1,310,318 953,775
Granted 82,500 311,750 565,750
Exercised 139,836 41,094 2,400
Surrendered or Expired 70,140 48,621 206,807
---------- ---------- ----------
Shares Under Option at
End of Period 1,404,877 1,532,353 1,310,318
========== ========== ==========
Option Price Range per Share $ 13.25 - $ 13.25 - $ 13.25 -
26.00 26.00 26.00
Options Exercisable at End
of Period 1,071,923 1,021,362 852,692
========== =========== ==========
</TABLE>
Under the 1994 Long-Term Incentive plan, the Compensation Committee of the
Board of Directors may grant awards of performance shares of stock to members of
the executive management group. Each grant of performance shares has a
three-year performance period, measured as the change from July 1 of the initial
year of the performance period to June 30 of the third succeeding year. The
number of shares of common stock received at the end of the performance period
is based principally on the relative stock price growth between the two
measurement dates of the Company's common stock as compared to that of a list of
company peers. The performance shares which were granted on July 1, 1994,
expired on June 1, 1997 without the issuance of any common stock of the Company.
Performance shares granted in July of 1995 and 1996 may be converted to shares
of common stock, depending upon the Company's relative performance to the peer
group measured on June 1st of 1998 and 1999, respectively.
Management has reviewed Statement of Financial Accounting Standards
("SFAS") No. 123, "Accounting for Stock-Based Compensation", which outlines a
fair value based method of accounting for stock options or similar equity
instruments and has opted to continue using the intrinsic value based method, as
prescribed by Accounting Principles Board ("APB") Opinion No. 25, to measure
compensation cost for its stock option plans.
The pro forma results of operations, had the Company adopted SFAS 123,
were net income of $22.9 million and $14.8 million, or $0.98 and $0.65 per
share, in 1997 and 1996, respectively, and a net loss of $92.9 million, or $4.08
per share, in 1995. Under the fair value based method, the weighted average fair
values of options granted during 1997, 1996 and 1995 were $4.26, $5.51 and
$4.52, respectively. The fair value of stock options was calculated using a
Black-Scholes stock option valuation model with the following weighted average
assumptions for grants in 1997, 1996 and 1995: stock price volatility of 25.8
percent; risk free rate of return ranging from 6.20 percent to 6.46 percent;
dividend rate of $0.16 per year; and an expected term of 5 years. The fair value
of stock options included in the pro forma results for each of the three years
is not necessarily indicative of future effects on net income and earnings per
share.
DIVIDEND RESTRICTIONS
The determination of the amount of future cash dividends, if any, to be
declared and paid on the Common Stock will be subject to the discretion of the
Board of Directors of the Company and will depend upon, among other things, the
Company's financial condition, funds from operations, the level of its capital
and exploration expenditures, and its future business prospects. The Company's
10.18% note agreement restricts certain payments ("Restricted Payments," as
defined in the note agreement) associated with (i) purchasing, redeeming,
retiring or otherwise acquiring any capital stock of the Company or any option,
warrant or other right to acquire such capital stock or (ii) declaring any
dividend, if immediately prior to or after giving effect to such payments, the
dividend exceeds consolidated net cash flows, as defined, and the ratio of
proved reserves to debt is less than 1.7 to 1, or an event of default has
occurred under the note agreement. As of December 31, 1997, such restrictions
had no adverse impact on the Company's ability to pay regular dividends. The
agreement related to 7.19% Notes issued in 1997 contains no restricted payment
provision.
PURCHASE RIGHTS
On January 21, 1991, the Board of Directors adopted the Preferred Stock
Purchase Rights Plan and declared a dividend distribution of one right for each
outstanding share of Common Stock. Each right becomes exercisable, at a price of
$55, when any person or group has acquired, obtained the right to acquire or
made a tender or exchange offer for beneficial ownership of 15 percent or more
of the Company's outstanding Common Stock, except pursuant to a
45
<PAGE> 47
tender or exchange offer for all outstanding shares of Common Stock deemed to be
fair and in the best interests of the Company and its stockholders by a majority
of the independent Continuing Directors (as defined in the plan). Each right
entitles the holder, other than the acquiring person or group, to purchase one
one-hundredth of a share of Series A Junior Participating Preferred Stock
("Junior Preferred Stock"), or to receive, after certain triggering events,
Common Stock or other property having a market value (as defined in the plan) of
twice the exercise price of each right. After the rights become exercisable, if
the Company is acquired in a merger or other business combination in which it is
not the survivor or 50 percent or more of the Company's assets or earning power
are sold or transferred, each right entitles the holder to purchase common stock
of the acquiring company with a market value (as defined in the plan) equal to
twice the exercise price of each right. At December 31, 1997, there were no
shares of Junior Preferred Stock issued.
The rights, which expire on January 21, 2001, and the exercise price are
subject to adjustment and may be redeemed by the Company for $0.01 per right at
any time before they become exercisable. Under certain circumstances, the
Continuing Directors may opt to exchange one share of Common Stock for each
exercisable right.
PREFERRED STOCK
At December 31, 1996, 692,439 shares of the Company's $3.125 cumulative
convertible preferred stock ("$3.125 preferred stock") were issued and
outstanding. Each share had a stated value of $50 and was convertible any time
by the holder into Common Stock at a conversion price of $21 per share. These
shares were also redeemable under certain provisions and fixed redemption
prices. The Company had the option to convert the $3.125 preferred stock into
shares of Common Stock valued at the conversion price if the closing price of
the Common Stock was at least equal to the conversion price for 20 consecutive
trading days. In October 1997, the Company exercised this right and converted
all of the 692,439 shares of $3.125 preferred stock into 1,648,664 shares of
Common Stock.
At December 31, 1996 and 1995, 1,134,000 shares of 6% convertible
redeemable preferred stock ("6% preferred stock") were issued and outstanding
(See Note 11 WERCO Acquisition). Each share has voting rights equal to
approximately 1.7 shares of Common Stock, a stated value of $50 and is
convertible by the holder, at any time at least five days prior to the date
fixed for redemption by the Company's Board of Directors, into Common Stock at a
conversion price of $28.75 per share, subject to adjustment. Starting on May 2,
1998, the 6% preferred stock is redeemable, in whole or in part, at the
Company's option price of $50 per share. Commencing May 2, 1998 and continuing
until May 2, 1999, the Company may redeem the 6% preferred stock at $50 per
share, payable in Common Stock, using the market price of the Common Stock on
the date redeemed, plus a cash payment for the accrued dividends due on the
shares redeemed. On or after May 2, 1999, the $50 per share redemption price is
payable in cash, plus a cash payment for accrued dividends due on the shares
redeemed.
11. WERCO ACQUISITION
On May 2, 1994, the Company completed the merger between a Company
subsidiary and Washington Energy Resources Company ("WERCO"), a wholly-owned
subsidiary of Washington Energy Company. The Company acquired the stock of WERCO
in a tax-free exchange. Total capitalized costs related to the acquisition were
$202.5 million, comprised of cash and stock consideration of $167.6 million (net
of an $8.4 million post-closing adjustment in 1995) and a $34.9 million non-cash
component (net of a $5.3 million reduction in 1996 related to the 1995
post-closing adjustment) in connection with the deferred income taxes
attributable to the differences between the tax and book bases of the acquired
properties, as required by SFAS 109, "Accounting for Income Taxes". The
acquisition was recorded using the purchase method. The oil and gas properties
are located in the Green River Basin of Wyoming and in the Gulf Coast.
The Company issued 2,133,000 shares of Common Stock and 1,134,000 shares
of 6% convertible redeemable preferred stock ($50 per share stated value) to
Washington Energy Company in exchange for the capital stock of WERCO.
46
<PAGE> 48
The $8.4 million post-closing adjustment was a net cash payment received
in 1995 related to a valuation adjustment and was recorded as a reduction to the
net book value of certain of the oil and gas properties acquired. In 1996, the
net book value of certain oil and gas properties was further reduced by a $5.3
million non-cash adjustment. This adjustment was to record the reversal of the
differences between the tax and book basis related to the 1995 post-closing
adjustment.
12. COST REDUCTION PROGRAM
In January 1995, the Company announced a cost reduction program which
included a voluntary early retirement program, a 15% targeted reduction in work
force and a consolidation of management in the Rocky Mountain, Anadarko and
onshore Gulf Coast areas into a single Western Region. Accordingly, the Company
recognized a liability and charged to expense $6.8 million in termination
benefits for 115 employees, or 23% of the total work force, including 24
employees who elected early retirement. The employee terminations were made in
virtually all departments both at the Company's corporate headquarters and each
of the operating region/area offices. The termination benefits included $3.8
million for severance and related costs, which were paid out by year end and a
$3.0 million non-cash charge for curtailments to the Company's pension ($0.4
million) and postretirement ($2.6 million) benefits plans.
13. FINANCIAL INSTRUMENTS
The following disclosures on the estimated fair value of financial
instruments are presented in accordance with SFAS 107, "Disclosures about Fair
Value of Financial Instruments". Fair value, as defined in SFAS 107, is the
amount at which the instrument could be exchanged currently between willing
parties. The Company uses available marketing data and valuation methodologies
to estimate fair value of debt.
<TABLE>
<CAPTION>
DECEMBER 31, 1997 DECEMBER 31, 1996
CARRYING ESTIMATED CARRYING ESTIMATED
(IN THOUSANDS) AMOUNT FAIR VALUE AMOUNT FAIR VALUE
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
DEBT:
10.18% Notes $ 80,000 $ 86,555 $ 80,000 $ 86,433
7.19% Notes 100,000 102,693 -- --
Credit Facility 19,000 19,000 168,000 168,000
---------- ---------- --------- ----------
$ 199,000 $ 208,248 $ 248,000 $ 254,433
========== ========== ========= ==========
OTHER FINANCIAL INSTRUMENTS:
Gas Price Swaps -- $ (350) -- $ 763
</TABLE>
LONG-TERM DEBT
The fair value of long-term debt is the estimated cost to acquire the
debt, including a premium or discount for the differential between the issue
rate and the year-end market rate. The fair value of the 10.18% Notes and the
7.19% Notes is based upon interest rates available to the Company. The Credit
Facility and the short-term line approximate fair value because these
instruments bear interest at rates based on current market rates.
47
<PAGE> 49
INTEREST RATE SWAP AGREEMENTS
In November 1993, the Company executed reverse interest rate swap
agreements with four banks that effectively converted the Company's $80 million
fixed rate notes into variable rate notes. Under the swap agreements, the
Company paid a variable rate of interest that was based on the six-month LIBOR.
The banks paid the Company fixed rates of interest that average 5.00%. The four
agreements had notional principal of $20 million each with terms of two, three,
four and five years. The fair value was determined by obtaining termination
values from third parties.
In January 1995, the Company entered into four additional swap agreements
which effectively fixed interest payments on the original interest rate swaps
until May 1997. In 1995, the Company recorded $4.5 million of interest expense
related to these swap agreements.
GAS PRICE SWAPS
The Company has entered into several price swap agreements with
counterparties. In a majority of the natural gas price swap agreements in 1996,
the Company received a fixed price ("fixed price swap contracts") for a notional
quantity of natural gas in exchange for its paying a variable price based on a
market based index, such as the NYMEX gas futures. The fixed price swap
contracts are used to hedge price risk associated with the Company's production.
During 1996, the fixed prices received on closed contracts ranged from $1.02 to
$2.54 per Mmbtu on total notional quantities of 17,600,000 Mmbtu. There were no
fixed price swap contracts open at December 31, 1996. During 1997, the Company
entered into no fixed price swap contracts to hedge prices on its production.
Typically, the Company enters into contracts to sell its natural gas at a
variable price based on the market index price. However, in some circumstances,
some of the Company's customers request that a fixed price be stated in the
contract. After entering into these certain fixed price sales contracts to meet
the needs of its customers, the Company typically opens gas swap agreements to
convert these fixed price contracts to market-sensitive price contracts. These
agreements had total notional quantities of 2,683,000 Mmbtu and 1,002,000 Mmbtu
in closed contracts in 1997 and 1996, respectively. In 1997 and 1996, this
represented approximately 7% and 3%, respectively, of the Company's total volume
of brokered gas sold. Additional agreements which remained open at year end had
notional quantities of 248,000 Mmbtu and 744,000 Mmbtu in 1997 and 1996,
respectively.
The estimated fair value of price swaps in the table above are for hedged
transactions in which gains or losses are recognized in results of operations
over the periods that production or purchased gas is hedged (see "Risk
Management Activities" under Note 1).
Certain of the fixed price swap contracts, open at December 31, 1995,
became 'uncovered' due to an unprecedented decoupling of the NYMEX gas prices
from realizable sales prices in the physical markets. These 'uncovered' hedge
contracts had notional quantities totaling 5,480,000 Mmbtu and covered the
contract months of January to April 1996. Accordingly, the Company recorded a
$3.2 million unrealized loss at December 31, 1995.
The Company is exposed to market risk on these open contracts to the
extent of changes in market prices for natural gas. However, the market risk
exposure on these hedged contracts is generally offset by the gain or loss
recognized upon the ultimate sale of the natural gas that is hedged.
CREDIT RISK
Although notional contract amounts are used to express the volume of gas
price and interest rate swap agreements, the amounts potentially subject to
credit risk in the event of non-performance by third parties are substantially
smaller. The Company does not anticipate any material impact to its financial
results due to non-performance by the third parties.
14. ACCOUNTING CHANGE
Effective January 1, 1995, the Company changed from the
property-by-property basis to the field basis of applying the unit-of-production
method to calculate depreciation and depletion on producing oil and gas
properties.
48
<PAGE> 50
The field basis provides for the aggregation of wells that have a common
geological reservoir or field. The field basis provides a better matching of
expenses with revenues over the productive life of the properties, and,
therefore, the Company believes the new method is preferable to the
property-by-property basis. Because the cumulative effect of the change in
method from prior periods was insignificant, a pre-tax charge of $303 thousand,
such amount ("pre-1995 amount") was included with depreciation, depletion and
amortization ("DD&A") expense in 1995. The net effect of the change in method
resulted in a $3,967 thousand decrease in DD&A expense and a $2,428 thousand
increase in net earnings in 1995, including the impact of the pre-1995 amount.
The pro forma impact on the results of operations in 1994, had the change in
method been implemented at the beginning of 1994, would have been a decrease in
DD&A expense of approximately $2,378 thousand and a $1,446 thousand increase in
net earnings. The reduction in DD&A expense for 1995 due to the change in method
was offset by higher levels of DD&A expense primarily due to reserve revisions.
15. ACCOUNTING FOR LONG-LIVED ASSETS
Effective September 30, 1995, the Company adopted SFAS No. 121 "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of". SFAS 121 requires that an impairment loss be recognized when the carrying
amount of an asset exceeds the sum of the undiscounted estimated future cash
flow of the asset. Under SFAS 121, the Company reviewed the impairment of oil
and gas properties and related assets on an economic unit basis. For each
economic unit determined to be impaired, an impairment loss equal to the
difference between the carrying value and the fair value of the economic unit
was recognized. Fair value, on an economic unit basis, was estimated to be the
present value of expected future net cash flows over the economic lives of the
reserves. As a result of the adoption of SFAS 121, the Company recognized a
non-cash charge during the third quarter of 1995 of $113.8 million ($69.2
million after tax).
16. OIL AND GAS PROPERTY TRANSACTIONS
The Company sold various non-core oil and gas properties in the
Appalachian Region, receiving proceeds of $4.6 million, in 1996 and in the
Western Region, obtaining proceeds of $7.6 million, in 1995.
In the fourth quarter of 1997, the Company closed two notable asset
transactions. Properties in northwest Pennsylvania (the "Meadville properties"),
including 912 wells and 15 Mmcfed of production, were sold to Lomak Petroleum
Incorporated for $92.9 million. In a like-kind exchange transaction, the Company
matched a portion of the Meadville properties sold with approximately $45
million in oil and gas producing properties acquired from Equitable Resources
Energy Company, including 63 wells and 10 Mmcfed of production.
17. OTHER REVENUE
The Company recorded $4.6 million ($4.3 million net of severance taxes) in
1995 in other revenue in connection with the sale of certain Columbia Gas
Transmission Corporation ("Columbia") bankruptcy claims. The claims related to
the remaining value of gas sales in contracts terminated by Columbia as part of
its bankruptcy filing in 1991.
18. MONETIZATION OF SECTION 29 TAX CREDITS
The Company completed two transactions in September and November 1995 and
a third transaction in August 1996 to monetize the value of Section 29 tax
credits from most of its qualifying Appalachian and Rocky Mountain properties.
The transactions provided up-front cash of $2.8 million in 1995 and $0.6 million
in 1996 which was recorded as a reduction to the net book value of natural gas
properties, and will generate additional revenues through 2002 estimated at $23
million ($3.6 million in 1997 and $3.4 million in 1996) related to the value of
future Section 29 tax credits attributable to these properties. Employing a
volumetric production payment structure, the production, revenues, expenses and
proved reserves related to these properties will continue to be reported by the
Company as Other Revenue until the production payment is satisfied.
49
<PAGE> 51
19. SUPPLEMENTAL FULL COST ACCOUNTING INFORMATION
U.S. oil and gas producing entities may utilize one of two methods of
financial accounting: successful efforts or full cost. Given the current
composition of the Company's properties, management considers the successful
efforts method to be more appropriate than the full cost method primarily
because the successful efforts method results in moderately better matching of
costs and revenues. It has come to management's attention that certain users of
the Company's financial statements believe that information about the Company
prepared under the full cost method would be useful. As a result, management has
presented the following supplemental full cost information.
Successful efforts methodology is explained in Note 1. Summary of
Significant Accounting Policies.
Under the full cost method of accounting, all costs incurred in the
acquisition, exploration and development of oil and gas properties are
capitalized. Such capitalized costs and estimated future development and
dismantlement costs are amortized on a unit-of-production method based on proved
reserves. Net capitalized costs of oil and gas properties are limited to the
lower of unamortized cost or the cost center ceiling, defined as: (1) the
present value (10% discount rate) of estimated unescalated future net revenues
from proved reserves, plus (2) the cost of properties not being amortized, plus
(3) the lower of cost or estimated fair value of unproved properties included in
the costs being amortized, minus (4) the deferred tax liabilities for the
temporary differences between the book and tax basis of oil and gas properties.
Proceeds from the sale of oil and gas properties are applied to reduce the costs
in the cost center unless the sale involves a significant quantity of reserves
in relation to the cost center, in which case a gain or loss is recognized.
Unevaluated properties and associated costs not currently being amortized and
included in oil and gas properties totaled $24.6 million, $15.7 million, and
$12.5 million at December 31, 1997, 1996, and 1995, respectively.
Because of the capital cost limitations, described above, full cost
entities are not subject to the impairment test prescribed by SFAS 121 (see Note
15. Accounting for Long-Lived Assets).
<TABLE>
<CAPTION>
1997 1996 1995
-------------------- ------------------- --------------------------
SUCCESSFUL FULL SUCCESSFUL FULL SUCCESSFUL FULL
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) EFFORTS COST EFFORTS COST EFFORTS COST
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
BALANCE SHEET:
Properties and Equipment, Net $ 469,399 $ 651,739 $ 480,511 $ 657,957 $ 474,371 $ 646,322
Stockholders' Equity 184,062 296,201 160,704 269,833 147,856 253,606
INCOME STATEMENT:
Depreciation, Depletion, Amortization
and Unproved Property Impairment $ 43,454 $ 52,383 $ 45,390 $ 50,769 $ 52,253 $ 51,922
Impairment of Long-Lived Assets -- -- -- -- 113,795 --
Impairment - Full Cost Ceiling -- -- -- -- -- --
Net Income (Loss) Applicable
to Common Stockholders 23,231 26,240 15,258 18,637 (92,171) (17,481)
Basic Earnings (Loss) Per Share $ 1.00 $ 1.13 $ 0.67 $ 0.82 $ (4.05 $ (0.77)
</TABLE>
20. EARNINGS (LOSS) PER COMMON SHARE
The adoption of SFAS 128 effective December 31, 1997, requires the
restatement of Earnings (Loss) Per Share of each year presented in the
Consolidated Statement of Operations. Since the Company has a simple capital
structure, previously disclosed Earnings (Loss) Per Share represents Basic
Earnings (Loss) Per Share. Diluted Earnings (Loss) Per Share reflects the
assumed conversion of outstanding stock options and stock grants.
Both the $3.125 cumulative convertible preferred stock and the 6%
convertible redeemable preferred stock ("preferred stock"), issued May 1994 and
May 1995, respectively, had an antidilutive effect on earnings per common share.
The preferred stock was determined not to be a common stock equivalent at the
time of issuance.
During 1997, 1,648,664 common shares were issued upon conversion of all of
the 692,439 shares of $3.125 Cumulative Convertible Preferred stock. The
preferred stock became convertible at the Company's option when the
50
<PAGE> 52
Company's common shares closed at or above the $21.00 conversion price of the
$3.125 cumulative convertible preferred stock for twenty consecutive days.
Earnings per share, basic and diluted, are calculated as follows:
<TABLE>
<CAPTION>
(in thousands, except per share data) 1997 1996 1995
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
BASIC EARNINGS (LOSS) PER COMMON SHARE:
Income before cumulative effect of changes $ 23,231 $ 15,258 $(22,984)
in accounting principles
Cumulative effect of changes in accounting principles -- -- (69,187)
-------- -------- --------
Net Income - Basic EPS $ 23,231 $ 15,258 $(92,171)
Weighted average common shares outstanding 23,272 22,807 22,775
Basic earnings (loss) per common share $ 1.00 $ 0.67 $ (4.05)
=================================================================================================
DILUTED EARNINGS (LOSS) PER COMMON SHARE:
Income before cumulative effect of changes $ 23,231 $ 15,258 $(22,984)
in accounting principles
Cumulative effect of changes in accounting principles -- -- (69,187)
-------- -------- --------
Net Income - Diluted EPS $ 23,231 $ 15,258 $(92,171)
Diluted earnings (loss) per common share $ 0.97 $ 0.66 $ (4.05)
Weighted average common shares outstanding 23,272 22,807 22,775
Dilutive effect of:
Stock Options(1) 275 70 --
Stock Grants(1) 375 116 --
Weighted average shares outstanding - Diluted 23,922 22,993 22,775
=====================================================================================================
</TABLE>
(1) In 1995, the stock options and stock grants are anti-dilutive and,
therefore, excluded from the calculation of Diluted Earnings (Loss) Per Share.
51
<PAGE> 53
CABOT OIL & GAS CORPORATION
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
OIL AND GAS RESERVES
Users of this information should be aware that the process of estimating
quantities of "proved" and "proved developed" natural gas and crude oil reserves
is very complex, requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each reservoir. The
data for a given reservoir may also change substantially over time as a result
of numerous factors including, but not limited to, additional development
activity, evolving production history and continual reassessment of the
viability of production under varying economic conditions. Consequently,
material revisions to existing reserve estimates may occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the significance of
the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with financial statement disclosures.
Proved reserves represent estimated quantities of natural gas, crude oil
and condensate that geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under
economic and operating conditions existing at the time the estimates were made.
Proved developed reserves are proved reserves expected to be recovered
through wells and equipment in place and under operating methods being utilized
at the time the estimates were made.
Estimates of proved and proved developed reserves at December 31, 1997,
1996 and 1995 were based on studies performed by the Company's petroleum
engineering staff. The estimates prepared by the Company's engineering staff
were reviewed by Miller and Lents, Ltd., who indicated in their recent letter
dated February 9,1998 that, based on their investigation and subject to the
limitations described in such letter, it was their judgment that the results of
those estimates and projections for 1997 were reasonable in the aggregate.
No major discovery or other favorable or adverse event subsequent to
December 31, 1997 is believed to have caused a material change in the estimates
of proved or proved developed reserves as of that date.
The following table sets forth the Company's net proved reserves,
including changes therein, and proved developed reserves for the periods
indicated, as estimated by the Company's engineering staff. All reserves are
located in the United States.
<TABLE>
<CAPTION>
Natural Gas
---------------------------------------------
December 31,
(Millions of cubic feet) 1997 1996 1995
- ------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
PROVED RESERVES
Beginning of Year 915,617 889,850 953,083
Revisions of Prior Estimates 6,744 2,774 14,032
Extensions, Discoveries and Other Additions 109,191 69,708 34,408
Production (63,889) (58,762) (57,721)
Purchases of Reserves in Place 73,836 37,397 1,416
Sales of Reserves in Place (138,070) (25,350) (55,368)
-------- ------- -------
End of Year 903,429 915,617 889,850
======= ======= =======
PROVED DEVELOPED RESERVES 738,764 768,097 747,235
======= ======= =======
</TABLE>
52
<PAGE> 54
<TABLE>
<CAPTION>
Liquids
----------------------------------
December 31,
(Thousands of barrels) 1997 1996 1995
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C>
PROVED RESERVES
Beginning of Year 5,166 5,310 8,036
Revisions of Prior Estimates 99 (132) (648)
Extensions, Discoveries and Other Additions 794 386 174
Production (629) (597) (740)
Purchases of Reserves in Place 594 215 15
Sales of Reserves in Place (155) (16) (1,527)
----- ----- -----
End of Year 5,869 5,166 5,310
===== ===== =====
PROVED DEVELOPED RESERVES 4,859 4,685 4,970
===== ===== =====
</TABLE>
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
The following table sets forth the aggregate amount of capitalized costs
relating to natural gas and crude oil producing activities and the aggregate
amount of related accumulated depreciation, depletion and amortization.
<TABLE>
<CAPTION>
Year Ended December 31,
(In thousands) 1997 1996 1995
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Aggregate Capitalized Costs Relating
to Oil and Gas Producing Activities $ 904,669 $ 997,531 $ 977,885
Aggregate Accumulated Depreciation,
Depletion and Amortization $ 435,502 $ 517,249 $ 503,757
</TABLE>
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES
Costs incurred in property acquisition, exploration and development
activities were as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
(In thousands) 1997 1996 1995
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Property Acquisition Costs - Proved $ 45,573 $ 6,637 $ 33
Property Acquisition Costs - Unproved 4,302 4,355 2,006
Exploration and Extension Well Costs 28,633 14,192 8,670
Development Costs 53,441 41,036 18,610
-------- -------- --------
Total Costs $131,949 $ 66,220 $ 29,319
======== ======== ========
</TABLE>
53
<PAGE> 55
HISTORICAL RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES
The results of operations for the Company's oil and gas producing
activities were as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
(In thousands) 1997 1996 1995
- ----------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues $ 173,865 $ 150,096 $ 110,418
Costs and Expenses
Production 39,068 35,161 34,062
Other Operating 18,017 15,155 22,783
Exploration 13,884 12,559 8,031
Depreciation, Depletion and
Amortization 39,485 40,810 161,886
--------- --------- ---------
Total Cost and Expenses 110,454 103,685 226,762
--------- --------- ---------
Income (Loss) Before Income Taxes 63,411 46,411 (116,344)
Provision for Income Taxes
Expense (Benefit) 22,194 16,244 (40,720)
--------- --------- ---------
Results of Operations $ 41,217 $ 30,167 $ (75,624)
========= ========= =========
</TABLE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES
The following information has been developed utilizing procedures
prescribed by SFAS 69 and based on natural gas and crude oil reserve and
production volumes estimated by the Company's engineering staff. It may be
useful for certain comparison purposes, but should not be solely relied upon in
evaluating the Company or its performance. Further, information contained in the
following table should not be considered as representative of realistic
assessments of future cash flows, nor should the Standardized Measure of
Discounted Future Net Cash Flows be viewed as representative of the current
value of the Company.
The Company believes that the following factors should be taken into
account in reviewing the following information: (i) future costs and selling
prices will probably differ from those required to be used in these
calculations; (ii) due to future market conditions and governmental regulations,
actual rates of production achieved in future years may vary significantly from
the rate of production assumed in the calculations; (iii) selection of a 10%
discount rate is arbitrary and may not be reasonable as a measure of the
relative risk inherent in realizing future net oil and gas revenues; and (iv)
future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by
applying year-end oil and gas prices adjusted for fixed and determinable
escalations, to the estimated future production of year-end proved reserves.
The average prices related to proved reserves at December 31, 1997, 1996
and 1995 were for oil ($/Bbl) $19.02, $22.86 and $17.06, respectively, and for
natural gas ($/Mcf) $2.44, $3.55 and $2.06, respectively. Future cash inflows
were reduced by estimated future development and production costs based on
year-end costs in order to arrive at net cash flow before tax. Future income tax
expense has been computed by applying year-end statutory tax rates to future
pretax net cash flows, reduced by the tax basis of the properties involved. Use
of a 10% discount rate is required by SFAS 69.
Management does not rely solely upon the following information in making
investment and operating decisions. Such decisions are based upon a wide range
of factors, including estimates of probable as well as proved reserves, and
varying price and cost assumptions considered more representative of a range of
possible economic conditions that may be anticipated.
54
<PAGE> 56
Standardized Measure is as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
(In thousands) 1997(1) 1996(1) 1995
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Future Cash Inflows $2,539,287 $ 3,528,558 $ 2,194,751
Future Production and
Development Costs (686,689) (773,631) (644,586)
---------- ----------- -----------
Future Net Cash Flows Before
Income Taxes 1,852,598 2,754,927 1,550,165
10% Annual Discount for
Estimated Timing of Cash Flows (1,013,837) (1,589,290) (884,861)
---------- ----------- -----------
Standardized Measure of
Discounted Future Net Cash Flows
Before Income Taxes 838,761 1,165,637 665,304
Future Income Tax Expenses,
Net of 10% Annual Discount(2) (227,796) (331,331) (152,356)
---------- ----------- -----------
Standardized Measure of Discounted
Future Net Cash Flows (3) $ 610,965 $ 834,306 $ 512,948
========== =========== ===========
</TABLE>
(1) Includes the future cash inflows, production costs and development costs,
as well as the tax basis, relating to the properties included in the
transactions to monetize the value of Section 29 tax credits. See Note 18
of the Notes to the Consolidated Financial Statements.
(2) Future income taxes before discount were $582,639, $887,583 and $462,058
for the years ended December 31, 1997, 1996 and 1995, respectively.
(3) The change in discounted future cash flows from 1996 to 1997 is primarily a
result of the $1.11 per Mcf decrease in average natural gas price.
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO
PROVED OIL AND GAS RESERVES
The following is an analysis of the changes in the Standardized Measure:
<TABLE>
<CAPTION>
Year Ended December 31,
(In thousands) 1997 1996 1995
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Beginning of Year $ 834,306 $ 512,948 $ 490,495
Discoveries and Extensions,
Net of Related Future Costs 113,032 99,983 21,881
Net Changes in Prices and
Production Costs (367,112) 416,042 57,057
Accretion of Discount 116,564 66,530 61,566
Revisions of Previous Quantity
Estimates, Timing and Other (10,798) (7,874) 1,707
Development Costs Incurred 17,435 10,294 5,665
Sales and Transfers, Net of
Production Costs (138,274) (114,935) (76,356)
Net Purchases (Sales) of
Reserves in Place (57,723) 30,293 (21,878)
Net Change in Income Taxes 103,535 (178,975) (27,189)
---------- ----------- -----------
End of Year $ 610,965 $ 834,306 $ 512,948
========== ========== ==========
</TABLE>
55
<PAGE> 57
CABOT OIL & GAS CORPORATION
SELECTED DATA (UNAUDITED)
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>
(In thousands except per share amounts) First Second Third Fourth Total
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1997
NET OPERATING REVENUES $ 52,792 $ 39,407 $ 40,773 $ 52,155 $185,127
OPERATING INCOME 22,715 10,013 10,830 20,294 63,852
NET INCOME 9,692 1,955 2,289 9,295 23,231
BASIC EARNINGS PER SHARE $ 0.42 $ 0.09 $ 0.10 $ 0.39 $ 1.00
1996
Net Operating Revenues $ 41,198 $ 37,346 $ 35,497 $ 49,020 $163,061
Operating Income 15,929 8,615 7,577 16,666 48,787
Net Income 5,258 853 2,974 6,173 15,258
Basic Earnings Per Share $ 0.23 $ 0.04 $ 0.13 $ 0.27 $ 0.67
- -------------------------------------------------------------------------------------------------------
</TABLE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information to be set forth under the caption "Election of Directors"
in the Company's definitive proxy statement ("Proxy Statement") in connection
with the 1998 annual stockholders meeting is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information appearing under the caption "Executive Compensation" in
the Proxy Statement is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information appearing under the captions "Beneficial Ownership of Over
Five Percent of Common Stock" and "Beneficial Ownership of Directors and
Executive Officers" in the Proxy Statement is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
56
<PAGE> 58
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES AND REPORTS ON FORM 8-K
A. INDEX
1. CONSOLIDATED FINANCIAL STATEMENTS
See Index on page 30.
2. FINANCIAL STATEMENT SCHEDULES
None
3. EXHIBITS
The following instruments are included as exhibits to this report. Those
exhibits below incorporated by reference herein are indicated as such by the
information supplied in the parenthetical thereafter. If no parenthetical
appears after an exhibit, copies of the instrument have been included herewith.
Exhibit
Number Description
- -------- -----------
3.1 Certificate of Incorporation of the Company (Registration Statement
No. 33-32553).
3.2 Amended and Restated Bylaws of the Company adopted August 5, 1994.
4.1 Form of Certificate of Common Stock of the Company (Registration
Statement No. 33-32553).
4.2 Certificate of Designation for Series A Junior Participating Preferred
Stock (Form 10-K for 1994).
4.3 Rights Agreement dated as of March 28, 1991 between the Company and
The First National Bank of Boston, as Rights Agent, which includes as
Exhibit A the form of Certificate of Designation of Series A Junior
Participating Preferred Stock (Form 8-A, File No. 1-10477).
(a) Amendment No. 1 to the Rights Agreement dated February 24, 1994
(Form 10-K for 1994).
4.4 Certificate of Designation for 6% Convertible Redeemable Preferred
Stock (Form 10-K for 1994).
4.5 Amended and Restated Credit Agreement dated as of May 30, 1995 among
the Company, Morgan Guaranty Trust Company, as agent and the banks
named therein.
(a) Amendment No. 1 to Credit Agreement dated September 15, 1995
(Form 10-K for 1995).
(b) Amendment No. 2 to Credit Agreement dated December 24, 1996
(Form 10-K for 1996).
4.6 Note Purchase Agreement dated May 11, 1990 among the Company and
certain insurance companies parties thereto (Form 10-Q for the quarter
ended June 30, 1990).
(a) First Amendment dated June 28, 1991 (Form 10-K for 1994).
(b) Second Amendment dated July 6, 1994 (Form 10-K for 1994).
4.7 Note Purchase Agreement dated November 14, 1997 among the Company and
the purchasers named therein.
10.1 Supplemental Executive Retirement Agreement between the Company and
Charles P. Siess, Jr. (Form 10-K for 1995).
10.2 Form of Change in Control Agreement between the Company and Certain
Officers (Form 10-K for 1995).
10.3 Letter Agreement dated January 11, 1990 between Morgan Guaranty Trust
Company of New York and the Company (Registration Statement No.
33-32553).
10.4 Form of Annual Target Cash Incentive Plan of the Company (Registration
Statement No. 33-32553).
10.5 Form of Incentive Stock Option Plan of the Company (Registration
Statement No. 33-32553).
(a) First Amendment to the Incentive Stock Option Plan
(Post-Effective Amendment No. 1 to S-8 dated April 26, 1993).
10.6 Form of Stock Subscription Agreement between the Company and certain
executive officers and directors of the Company (Registration
Statement No. 33-32553).
57
<PAGE> 59
10.7 Transaction Agreement between Cabot Corporation and the Company dated
February 1, 1991 (Registration Statement No. 33-37455).
10.8 Tax Sharing Agreement between Cabot Corporation and the Company dated
February 1, 1991 (Registration Statement No. 33-37455).
10.9 Amendment Agreement (amending the Transaction Agreement and the Tax
Sharing Agreement) dated March 25, 1991. (incorp. by ref. from Cabot
Corporation's Schedule 13E-4, Am. No. 6, File No. 5-30636).
10.10 Savings Investment Plan & Trust Agreement of the Company (Form 10-K
for 1991).
(a) First Amendment to the Savings Investment Plan dated May 21, 1993
(Form S-8 dated November 1, 1993).
(b) Second Amendment to the Savings Investment Plan dated May 21,
1993 (Form S-8 dated November 1, 1993).
(c) First through Fifth Amendments to the Trust Agreement (Form 10-K
for 1995).
(d) Third through Fifth Amendments to the Savings Investment Plan
(Form 10-K for 1996).
10.11 Supplemental Executive Retirement Agreements of the Company (Form 10-K
for 1991).
10.12 Settlement Agreement and Mutual Release (Tax Issues) between Cabot
Corporation and the Company dated July 7, 1992 (Form 10-Q for the
quarter ended June 30, 1992).
10.13 Agreement of Merger dated February 25, 1994 among Washington Energy
Company, Washington Energy Resources Company, the Company and COG
Acquisition Company (Form 10-K for 1993).
10.14 1990 Nonemployee Director Stock Option Plan of the Company (Form S-8
dated June 23, 1990)
(a) First Amendment to 1990 Nonemployee Director Stock Option Plan
(Post-Effective Amendment No. 2 to Form S-8 dated March 7, 1994).
(b) Second Amendment to 1990 Nonemployee Director Stock Option Plan
(Form 10-K for 1995).
10.15 1994 Long-Term Incentive Plan of the Company (Form S-8 dated May 20,
1994 - Registration Statement No. 33-53723).
10.16 1994 Nonemployee Director Stock Option Plan (Form S-8 dated May 20,
1994 - Registration Statement No. 33-53723).
10.17 Employment Agreement between the Company and Ray R. Seegmiller dated
September 25, 1995 (Form 10-K for 1995).
10.18 Form of Indemnity Agreement between the Company and Certain Officers.
21.1 Subsidiaries of Cabot Oil & Gas Corporation.
23.1 Consent of Coopers & Lybrand L.L.P.
23.2 Consent of Miller and Lents, Ltd.
27 Financial Data Schedule.
28.1 Miller and Lents, Ltd. Review Letter dated February 9, 1998.
B. REPORTS ON FORM 8-K
None
58
<PAGE> 60
SIGNATURES
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, in the City of Houston, State of Texas,
on the 10th of March 1998.
CABOT OIL & GAS CORPORATION
By: /s/ Charles P. Siess, Jr.
---------------------------------
Charles P. Siess, Jr.
Chairman of the Board and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons in the capacities and on
the dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
/s/ Charles P. Siess, Jr. Chairman of the Board and March 10, 1998
- -------------------------------- Chief Executive Officer
Charles P. Siess, Jr (Principal Executive Officer)
/s/ Ray R. Seegmiller President, Chief Operating March 10, 1998
- -------------------------------- Officer and Director
Ray R. Seegmiller (Principal Financial Officer)
/s/ Paul F. Boling Controller March 10, 1998
- -------------------------------- (Principal Accounting Officer)
Paul F. Boling
/s/ Robert F. Bailey Director March 10, 1998
- --------------------------------
Robert F. Bailey
/s/ Samuel W. Bodman Director March 10, 1998
- --------------------------------
Samuel W. Bodman
/s/ Henry O. Boswell Director March 10, 1998
- --------------------------------
Henry O. Boswell
/s/ John G. L. Cabot Director March 10, 1998
- --------------------------------
John G. L. Cabot
/s/ William R. Esler Director March 10, 1998
- --------------------------------
William R. Esler
/s/ William H. Knoell Director March 10, 1998
- --------------------------------
William H. Knoell
/s/ C. Wayne Nance Director March 10, 1998
- --------------------------------
C. Wayne Nance
/s/ William P. Vititoe Director March 10, 1998
- --------------------------------
William P. Vititoe
</TABLE>
59
<PAGE> 61
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit
Number Description
- -------- -----------
<S> <C>
3.1 Certificate of Incorporation of the Company (Registration Statement
No. 33-32553).
3.2 Amended and Restated Bylaws of the Company adopted August 5, 1994.
4.1 Form of Certificate of Common Stock of the Company (Registration
Statement No. 33-32553).
4.2 Certificate of Designation for Series A Junior Participating Preferred
Stock (Form 10-K for 1994).
4.3 Rights Agreement dated as of March 28, 1991 between the Company and
The First National Bank of Boston, as Rights Agent, which includes as
Exhibit A the form of Certificate of Designation of Series A Junior
Participating Preferred Stock (Form 8-A, File No. 1-10477).
(a) Amendment No. 1 to the Rights Agreement dated February 24, 1994
(Form 10-K for 1994).
4.4 Certificate of Designation for 6% Convertible Redeemable Preferred
Stock (Form 10-K for 1994).
4.5 Amended and Restated Credit Agreement dated as of May 30, 1995 among
the Company, Morgan Guaranty Trust Company, as agent and the banks
named therein.
(a) Amendment No. 1 to Credit Agreement dated September 15, 1995
(Form 10-K for 1995).
(b) Amendment No. 2 to Credit Agreement dated December 24, 1996
(Form 10-K for 1996).
4.6 Note Purchase Agreement dated May 11, 1990 among the Company and
certain insurance companies parties thereto (Form 10-Q for the quarter
ended June 30, 1990).
(a) First Amendment dated June 28, 1991 (Form 10-K for 1994).
(b) Second Amendment dated July 6, 1994 (Form 10-K for 1994).
4.7 Note Purchase Agreement dated November 14, 1997 amoung the Company and
the purchasers named therein.
10.1 Supplemental Executive Retirement Agreement between the Company and
Charles P. Siess, Jr. (Form 10-K for 1995).
10.2 Form of Change in Control Agreement between the Company and Certain
Officers (Form 10-K for 1995).
10.3 Letter Agreement dated January 11, 1990 between Morgan Guaranty Trust
Company of New York and the Company (Registration Statement No.
33-32553).
10.4 Form of Annual Target Cash Incentive Plan of the Company (Registration
Statement No. 33-32553).
10.5 Form of Incentive Stock Option Plan of the Company (Registration
Statement No. 33-32553).
(a) First Amendment to the Incentive Stock Option Plan
(Post-Effective Amendment No. 1 to S-8 dated April 26, 1993).
10.6 Form of Stock Subscription Agreement between the Company and certain
executive officers and directors of the Company (Registration
Statement No. 33-32553).
</TABLE>
<PAGE> 62
<TABLE>
<S> <C>
10.7 Transaction Agreement between Cabot Corporation and the Company dated
February 1, 1991 (Registration Statement No. 33-37455).
10.8 Tax Sharing Agreement between Cabot Corporation and the Company dated
February 1, 1991 (Registration Statement No. 33-37455).
10.9 Amendment Agreement (amending the Transaction Agreement and the Tax
Sharing Agreement) dated March 25, 1991. (incorp. by ref. from Cabot
Corporation's Schedule 13E-4, Am. No. 6, File No. 5-30636).
10.10 Savings Investment Plan & Trust Agreement of the Company (Form 10-K
for 1991).
(a) First Amendment to the Savings Investment Plan dated May 21, 1993
(Form S-8 dated November 1, 1993).
(b) Second Amendment to the Savings Investment Plan dated May 21,
1993 (Form S-8 dated November 1, 1993).
(c) First through Fifth Amendments to the Trust Agreement (Form 10-K
for 1995).
(d) Third through Fifth Amendments to the Savings Investment Plan
(Form 10-K for 1996).
10.11 Supplemental Executive Retirement Agreements of the Company (Form 10-K
for 1991).
10.12 Settlement Agreement and Mutual Release (Tax Issues) between Cabot
Corporation and the Company dated July 7, 1992 (Form 10-Q for the
quarter ended June 30, 1992).
10.13 Agreement of Merger dated February 25, 1994 among Washington Energy
Company, Washington Energy Resources Company, the Company and COG
Acquisition Company (Form 10-K for 1993).
10.14 1990 Nonemployee Director Stock Option Plan of the Company (Form S-8
dated June 23, 1990)
(a) First Amendment to 1990 Nonemployee Director Stock Option Plan
(Post-Effective Amendment No. 2 to Form S-8 dated March 7, 1994).
(b) Second Amendment to 1990 Nonemployee Director Stock Option Plan
(Form 10-K for 1995).
10.15 1994 Long-Term Incentive Plan of the Company (Form S-8 dated May 20,
1994 - Registration Statement No. 33-53723).
10.16 1994 Nonemployee Director Stock Option Plan (Form S-8 dated May 20,
1994 - Registration Statement No. 33-53723).
10.17 Employment Agreement between the Company and Ray R. Seegmiller dated
September 25, 1995 (Form 10-K for 1995).
10.18 Form of Indemnity Agreement between the Company and Certain Officers.
21.1 Subsidiaries of Cabot Oil & Gas Corporation.
23.1 Consent of Coopers & Lybrand L.L.P.
23.2 Consent of Miller and Lents, Ltd.
27 Financial Data Schedule.
28.1 Miller and Lents, Ltd. Review Letter dated February 9, 1998.
</TABLE>
<PAGE> 1
Exhibit 4.7
NOTE PURCHASE AGREEMENT
dated as of
November 14, 1997
among
CABOT OIL & GAS CORPORATION
and
THE PURCHASERS LISTED HEREIN
-------------------
$100,000,000 7.19% Notes due 2009
<PAGE> 2
TABLE OF CONTENTS*
<TABLE>
<S> <C> <C>
ARTICLE I
DEFINITIONS 1
SECTION 1.01. Definitions 1
SECTION 1.02. Accounting Terms and Definitions 8
ARTICLE II
THE NOTES 8
SECTION 2.01. Sale and Purchase of Notes 8
SECTION 2.02. Closing 9
SECTION 2.03. Prepayments 9
SECTION 2.04. Maximum Interest Rate 11
ARTICLE III
CONDITIONS TO PURCHASE OF NOTES 12
SECTION 3.01. Conditions to Purchase 12
ARTICLE IV
REPRESENTATIONS AND WARRANTIES 13
SECTION 4.01. Corporate Existence and Power 13
SECTION 4.02. Corporate and Governmental Authorization;
No Contravention 13
SECTION 4.03. Binding Effect 14
SECTION 4.04. Financial Information 14
SECTION 4.05. Full Disclosure 14
SECTION 4.06. Litigation 15
SECTION 4.07. Compliance with ERISA 15
SECTION 4.08. Environmental Matters 15
SECTION 4.09. Taxes 16
SECTION 4.10. Titles, etc 16
SECTION 4.11. Casualties; Taking of Properties 16
SECTION 4.12. Gas Imbalances 16
SECTION 4.13. Use of Proceeds 17
SECTION 4.14. Offering of the Notes 17
SECTION 4.15. Ownership of Subsidiaries 17
ARTICLE V
COVENANTS 17
SECTION 5.01. Information 17
SECTION 5.02. Payment of Obligations 19
SECTION 5.03. Maintenance of Property 19
SECTION 5.04. Conduct of Business and Maintenance of Existence 19
SECTION 5.05. Compliance with Laws 20
SECTION 5.06. Inspection of Property, Books and Records 20
SECTION 5.07. Insurance 20
SECTION 5.08. Engineering Reports 20
</TABLE>
- ----------------------
* The Table of Contents is not a part of this Agreement.
<PAGE> 3
<TABLE>
<S> <C> <C>
SECTION 5.09. Asset Coverage Ratio 20
SECTION 5.10. Liens 21
SECTION 5.11. Transactions with Affiliates 21
SECTION 5.12. Annual Coverage Ratio 22
SECTION 5.13. Consolidations, Mergers and Sales of Assets 22
SECTION 5.14. Subsidiary Debt 23
SECTION 5.15. Sale and Leasebacks 23
ARTICLE VI
DEFAULTS 23
SECTION 6.01. Events of Default 23
SECTION 6.02. Rescission of Acceleration 26
ARTICLE VII
PURCHASE FOR INVESTMENT; SOURCE OF FUNDS 26
SECTION 7.01. Purchase for Investment 26
SECTION 7.02. Source of Funds 26
SECTION 7.03. Securities Act; Legend 28
ARTICLE VIII
MISCELLANEOUS
SECTION 8.01. Notices 28
SECTION 8.02. No Waiver 28
SECTION 8.03. Expenses; Documentary Taxes; Indemnification
for Litigation 29
SECTION 8.04. Amendments and Waivers 29
SECTION 8.05. New York Law 30
SECTION 8.06. Successors and Assigns 30
SECTION 8.07. Form, Registration, Transfer and Exchange of the Notes;
Transferees 30
SECTION 8.08. Persons Deemed Owners 31
SECTION 8.09. Home Office Payment 31
SECTION 8.10. Substitution 31
SECTION 8.11. Credit Decision 32
SECTION 8.12. Counterparts; Integration; Effectiveness;
Severability 32
SECTION 8.13. Submission to Jurisdiction 32
SECTION 8.14. Confidentiality 32
</TABLE>
Schedule A -- Information Relating To Purchasers
Schedule 4.05 -- Certain Disclosure
Schedule 4.06 -- Litigation
Schedule 4.15 -- Subsidiaries
Schedule 5.10 -- Liens
Exhibit A -- Form of Note
Exhibit B -- Form of Opinion of Counsel for the Issuer
Exhibit C -- Form of Opinion of Managing Counsel for the Issuer
Exhibit D -- Form of Opinion of Special Counsel for the Purchasers
<PAGE> 4
NOTE PURCHASE AGREEMENT
AGREEMENT dated as of November 14, 1997 among CABOT OIL & GAS
CORPORATION, a Delaware corporation (the "Issuer"), and the PURCHASERS listed on
the signature pages hereof (the "Purchasers").
The parties hereto agree as follows:
ARTICLE I
DEFINITIONS
SECTION 1.01. Definitions. The following terms, as used
herein, have the following meanings:
"Adjusted Cash" means, as of any date, the lesser of (i) the
amount by which cash and short-term investments of the Issuer and its
Subsidiaries exceed $5,000,000 and (ii) the amount, if any, by which (a) current
assets of the Issuer and its Subsidiaries exceed (b) current liabilities of such
Persons (excluding the aggregate outstanding principal amount of Debt included
in such current liabilities), in each case determined on a consolidated basis as
of such date. If such current liabilities exceed such current assets, Adjusted
Cash shall be zero.
"Affiliate" means each Person who controls, is controlled by
or is under common control with the Issuer. For purposes of this definition, the
term "control" means possession, directly or indirectly, of the power to direct
or cause the direction of the management or policies of a Person, whether
through the ownership of voting securities, by contract or otherwise.
"Asset Disposition" means any sale, lease, transfer or other
disposition of shares of capital stock of a Subsidiary, property or other assets
by the Issuer or a Subsidiary, other than any such sales, leases, transfers or
other dispositions of assets made in the ordinary course of business.
"Attributable Debt" means, as to any particular lease and at
any date, the total net amount of rent required to be paid by such Person under
such lease during the remaining primary term thereof (or any renewal terms for
which the lease may be extended at the option of the lessor), discounted from
the respective due dates thereof to such date at a rate of 7.19% per annum. The
net amount of rent required to be paid under any such lease for any such period
shall be the aggregate amount of rent payable by the lessee with respect to such
period after excluding amounts required to be paid on account of insurance,
taxes, assessments, utility, operating and labor costs and similar charges. In
the case of any lease which is terminable by the lessee upon the payment of a
penalty, such net amount shall also include the amount of such penalty, but no
rent shall be considered as required to be paid under such lease subsequent to
the first date upon which it may be so terminated.
"Business Day" means any day except a Saturday, Sunday or
other day on which commercial banks in Houston, Texas are authorized by law to
close.
"Change of Control" shall have occurred if (i) any Person or
related Persons constituting a "group" for purposes of Section 13(d) of the
Exchange Act shall have acquired "beneficial ownership" of a majority of the
voting stock of the Issuer, or (ii) during any period of 24 consecutive months,
individuals who were directors of the Issuer at the beginning of the period and
Qualifying Directors, in the aggregate, shall cease to constitute a majority of
the Board of Directors of the Issuer.
<PAGE> 5
"Closing Date" means November 18, 1997.
"Credit Agreement" means the Amended and Restated Credit
Agreement dated May 30, 1995 among the Issuer, the banks party thereto, and
Morgan Guaranty Trust Company of New York, as Agent, as amended from time to
time.
"Debt" of any Person means at any date, without duplication,
(i) all obligations of such Person for borrowed money; (ii) all obligations of
such Person evidenced by bonds, debentures, notes or other similar instruments;
(iii) all long-term obligations of such Person to pay the deferred purchase
price of property or services, except trade accounts payable arising in the
ordinary course of business; (iv) all obligations of such Person as lessee under
capital leases; (v) all Debt of others secured by a Lien on any asset of such
Person, whether or not such Debt is assumed by such Person, provided that to the
extent such Debt is not assumed by such Person the amount of such Debt for
purposes of the provisions of this Agreement shall be equal to the lesser of (a)
the amount of Debt secured by such Lien or (b) the value of the asset which
secures such Debt and to the extent such Debt is assumed by such Person the
amount of such Debt for purposes of the provisions of this Agreement shall equal
the amount of such Debt assumed; and (vi) all Debt of others described in (i)
through (v) above directly or indirectly guaranteed by such Person or in respect
of which such Person is otherwise liable, contingently or otherwise; provided,
that the amount of such Debt for the purposes of this Agreement shall be equal
to the amount of Debt guaranteed by such Person or in respect of which such
Person is otherwise liable, contingently or otherwise.
"Debt and Other Liabilities" means, at any date, the sum of,
without duplication, (i) Debt of the Issuer and its Subsidiaries at such date
plus (ii) the amount, if any, by which Negative Adjusted Working Capital at such
date exceeds 6% of the Present Value of Proved Reserves minus (iii) Non-Recourse
Debt of the Issuer and its Subsidiaries at such date.
"Default" means the occurrence of any of the events specified
in Section 6.01, whether or not any requirement for notice or lapse of time or
other condition precedent has been satisfied.
"Environmental Laws" means any and all federal, state, local
and foreign statutes, laws, regulations, ordinances, rules, judgments, orders,
decrees, permits, concessions, grants, franchises, licenses, agreements or other
governmental restrictions relating to the environment or to emissions,
discharges or releases of pollutants contaminants, petroleum or petroleum
products, chemicals or industrial, toxic or hazardous substances or wastes into
the environment including, without limitation, ambient air, surface water,
ground water, or land, or otherwise relating to the manufacture, processing,
distribution, use, treatment, storage, disposal, transport or handling of
pollutants, contaminants, petroleum or petroleum products (including natural
gas), chemicals or industrial, toxic or hazardous substances or wastes or the
clean-up or other remediation thereof.
"ERISA" means the Employee Retirement Income Security Act of
1974, as amended, or any successor statute.
"ERISA Group" means the Issuer and all members of a controlled
group of corporations and all trades or businesses (whether or not incorporated)
under common control which, together with the Issuer, are treated as a single
employer under Section 414 of the Internal Revenue Code.
"Event of Default" means any of the events specified in
Section 6.01.
<PAGE> 6
"Excepted Liens" means: (i) Liens for taxes, assessments or
other governmental charges or levies not yet due or which are being contested in
good faith by appropriate action; (ii) Liens in connection with workers'
compensation, unemployment insurance or other social security, old age pension
or public liability obligations but not resulting from the failure of the Issuer
to meet or comply with such obligations; (iii) attachment or judgment Liens
arising in connection with legal proceedings, provided that (A) the execution or
enforcement of such Lien is effectively stayed and the claims secured thereby
are being actively contested in good faith by appropriate proceedings and (B)
such reserve or other appropriate provision, if any, as shall be required by
generally accepted accounting principles shall have been made therefor on the
books of the Issuer and its Subsidiaries; (iv) vendors', carriers',
warehousemen's, repairmen's, mechanics', workmen's, materialmen's, construction
or other like Liens (including, without limitation, Liens arising in favor of
sellers of hydrocarbons) arising by operation of law in the ordinary course of
business incident to obligations which are not yet due or which are being
contested in good faith by appropriate proceedings by or on behalf of the Issuer
or a Subsidiary and for which appropriate provisions, if any, as required by
generally accepted accounting principles shall have been made on the books of
the Issuer and its Subsidiaries; (v) Liens arising in the ordinary course of
business under farm-out agreements, gas sales contracts, operating agreements,
unitization and pooling agreements, and such other documents as are customarily
found in connection with comparable drilling and producing operations; (vi)
letters of credit, pledges or deposits, including bonds, required in the
ordinary course of business to secure public or statutory obligations or to
secure performance in connection with bids or contracts related to the
exploration or development of Petroleum Properties, to the extent that payment
of the underlying obligations is not yet due or is being contested in good faith
by appropriate proceedings by or on behalf of the Issuer or a Subsidiary and
with respect to which appropriate reserves have been established; and (vii)
minor irregularities in title which do not materially interfere with the
occupation, use and enjoyment by the Issuer and its Subsidiaries of their
respective Properties in the normal course of business as presently conducted or
materially impair the value thereof for such business.
"Exchange Act" means the Securities Exchange Act of 1934, as
amended, or any successor statute. For purposes of the definitions of "Change of
Control" and "Qualifying Director", unless otherwise defined in such Sections,
the terms enclosed in quotation marks as used therein have the meanings ascribed
to such terms under the Exchange Act and the rules and regulations promulgated
by the Securities and Exchange Commission thereunder.
"Executive Officer" means, with respect to any Person, the
chairman and chief executive officer, the president, any vice president, the
treasurer, the chief financial officer, the chief accounting officer, the
controller or the general counsel or any other person performing similar
functions.
"Holder" means a registered holder from time to time of any
Note.
"Institutional Investor" means (a) any original purchaser of a
Note, (b) any holder of a Note holding more than 5% of the aggregate principal
amount of the Notes then outstanding, and (c) any bank, trust company, savings
and loan association or other financial institution, any pension plan, any
investment company, any insurance company, any broker or dealer, or any other
similar financial institution or entity, regardless of legal form.
"Internal Revenue Code" means the Internal Revenue Code of
1986, as amended, or any successor statute.
<PAGE> 7
"Investment" means with respect to any Person (the
"Investor"), any investment by the Investor in any other Person, whether by
means of share purchase, capital contribution, loan, purchase of Debt, guarantee
of Debt, time deposit or otherwise.
"Issuer" means Cabot Oil & Gas Corporation, a Delaware
corporation, and its successors.
"Lien" means, with respect to any asset, any mortgage, lien,
pledge, charge, security interest or encumbrance of any kind in respect of such
asset (including without limitation any Production Payment, advance payment, gas
imbalances or similar arrangement with respect to minerals in place) or any
other arrangement the economic effect of which is to give a creditor
preferential access to such asset to satisfy its claim, whether or not filed,
recorded or otherwise perfected under applicable law. For the purposes of this
Agreement, the Issuer or any Subsidiary shall be deemed to own subject to a Lien
(i) any asset that it has acquired or holds subject to the interest of a vendor
or lessor under any conditional sale agreement, capital lease or other title
retention agreement relating to such asset or any capitalized lease obligation
or (ii) any account receivable transferred by it with credit recourse (including
any such transfer subject to a holdback or similar arrangement which effectively
imposes the risk of collectibility upon the transferor).
"Majority Lenders" means Holders of a majority in principal
amount of the Outstanding Notes.
"Make Whole Amount" has the meaning set forth in Section 2.03
and, as used in Section 6.01 with respect to the acceleration of any Note, means
an amount equal to the Make Whole Amount that would be payable with respect to
such Note if the Issuer had elected to prepay the Notes in full pursuant to
Section 2.03(b) on the date of the applicable acceleration..
"Material Debt" means Debt (other than Non-Recourse Debt) of
the Issuer or one or more of its Subsidiaries, arising in one or more related or
unrelated transactions, in an aggregate principal amount exceeding $15,000,000.
"Material Plan" means at any time a Plan or Plans having
aggregate Unfunded Liabilities in excess of $5,000,000.
"Multiemployer Plan" means at any time an employee pension
benefit plan within the meaning of Section 4001(a)(3) of ERISA to which any
member of the ERISA Group is then making or accruing an obligation to make
contributions or has within the preceding five plan years made contributions,
including for these purposes any Person which ceased to be a member of the ERISA
Group during such five year period.
"Negative Adjusted Working Capital" means, at any date, the
amount, if any, by which current liabilities other than Debt of the Issuer and
its Subsidiaries exceeds current assets of such Persons, determined on a
consolidated basis as of such date.
"Non-Recourse Debt" of any Person means Debt of such Person in
respect of which (i) the recourse of the holder of such Debt, whether direct or
indirect and whether contingent or otherwise, is effectively limited to the
assets directly securing such Debt; (ii) such holder may not collect by levy of
execution against assets of such Person generally (other than the assets
directly securing such Debt) if such Person fails to pay such Debt when due and
the holder obtains a judgment with respect thereto; and (iii) such holder has
waived, to the extent such holder may effectively do so, such holder's right to
elect recourse treatment under 11 U.S.C. S 1111(b).
<PAGE> 8
"Notes" means the promissory notes of the Issuer,
substantially in the form of Exhibit A hereto, in an original aggregate
principal amount equal to $100,000,000, evidencing the obligations of the Issuer
hereunder and "Note" means any one of such promissory notes issued hereunder.
"Offering Memorandum" means the Private Placement Memorandum
dated October 1997 provided by the Issuer to the Purchasers in connection with
this Agreement, together with all amendments, supplements, exhibits and
schedules thereto delivered to the Purchasers prior to the execution of this
Agreement.
"Outstanding" means, with respect to the Notes, all Notes
issued pursuant to this Agreement except (i) Notes delivered to the Issuer in
substitution or exchange for which new Notes have been issued, (ii) Notes
delivered to the Issuer for payment upon maturity, prepayment or repurchase and
(iii) Notes held by the Issuer or any of its Affiliates.
"PBGC" means the Pension Benefit Guaranty Corporation or any
entity succeeding to any or all of its functions under ERISA.
"Person" means an individual, a corporation, a partnership, an
association, a trust or any other entity or organization, including a government
or political subdivision or an agency or instrumentality thereof.
"Petroleum Property" means any interest of the Issuer or any
Subsidiary in oil and gas reserves and assets consisting primarily of gas
gathering, processing and storage facilities and transmission pipelines.
"Plan" means at any time an employee pension benefit plan
(other than a Multiemployer Plan) which is covered by Title IV of ERISA or
subject to the minimum funding standards under Section 412 of the Internal
Revenue Code and either (i) is maintained, or contributed to, by any member of
the ERISA Group for employees of any member of the ERISA Group or (ii) has at
any time within the preceding five years been maintained, or contributed to, by
any Person which was at such time a member of the ERISA Group for employees of
any Person which was at such time a member of the ERISA Group.
"Present Value of Proved Reserves" means at any time the
standardized measure of discounted after-tax future net cash flows, calculated
in accordance with the methods prescribed at such time by Item 302(b) of
Regulation S-K or any successor provision promulgated by the Securities and
Exchange Commission (or if no such methods shall then be prescribed, then on a
basis consistent with those most recently so prescribed), of the Issuer's and
its Subsidiaries' Proved Reserves, excluding reserves subject to any
Non-Recourse Debt. In calculating the Present Value of Proved Reserves, Proved
Undeveloped Reserves shall not be taken into account to the extent that more
than 30% of the Present Value of Proved Reserves is attributable to Proved
Undeveloped Reserves.
"Prime Rate" means the rate of interest publicly announced by
Morgan Guaranty Trust Company of New York from time to time as its Prime Rate.
"Production Payment" means an interest in a Petroleum Property
that (i) is not subject to the costs of production and (ii) terminates at such
time as the interest holder has realized a specified sum from the sale of oil or
gas attributable to such interest.
<PAGE> 9
"Property" means any interest in any kind of property or
asset, whether real, personal or mixed, or tangible or intangible.
"Proved Developed Producing Reserves" has the meaning assigned
to that term by the Society of Petroleum Engineers, as it may be amended from
time to time, but generally shall mean the subcategory of "Proved Developed
Reserves" (as defined by the Society of Petroleum Engineers) which are
recoverable by natural reservoir energies (including pumping) from the
completion intervals currently open and producing to market. Additional oil and
gas expected to be obtained through the application of fluid injection or other
improved recovery techniques for supplementing the natural forces and mechanisms
of primary recovery will be included as "Proved Developed Producing Reserves"
only after testing by a pilot project or after the operation of an installed
program has confirmed through production response through existing completions
producing to market that increased recovery will be achieved. Proved Developed
Producing Reserves shall not include any Proved Developed Non-Producing
Reserves.
"Proved Developed Non-Producing Reserves" has the meaning
assigned to that term by the Society of Petroleum Engineers, as it may be
amended from time to time, but generally shall mean the subcategory of "Proved
Developed Reserves" (as defined by the Society of Petroleum Engineers) which
will become "Proved Developed Producing Reserves" upon minor capital
expenditures being made with respect to existing wells which will cause formerly
non-producing completions or intervals to become open and producing to market.
"Proved Reserves" means and includes Proved Developed
Producing Reserves, Proved Developed Non-Producing Reserves and Proved
Undeveloped Reserves.
"Proved Undeveloped Reserves" has the meaning assigned to that
term by the Society of Petroleum Engineers, as it may be amended from time to
time, but generally shall mean those reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion. Proved Undeveloped Reserves on
undrilled acreage shall be limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled. Proved Undeveloped
Reserves for other undrilled units can be claimed only where it can be
demonstrated with certainty that there is continuity of production from the
existing productive formation. Under no circumstances should estimates for
Proved Undeveloped Reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual tests
in the area and in the same reservoir.
"QPAM Exemption" means Prohibited Transaction Class Exemption
84-14 issued by the United States Department of Labor.
"Qualifying Director" means any director who (a) is elected by
a majority of the members of the board of directors of the Issuer who were
directors immediately prior to the event that caused the change in directorships
and (b) is not a "person" or member of a "group" of persons, or an "affiliate"
or "associate" of any "person" or "group" member, or an "associate" of an
"affiliate" of any such "person" or "group" member, which "person" or "group" of
persons, together with all of their respective "affiliates" and "associates" and
all "associates" of their respective "affiliates" (other than a "person" or
"group" of persons or an "affiliate" or "associate" of such "person" or "group"
of persons or an "associate" of such "affiliate" in each case which is
affiliated with the Issuer or any Subsidiary) comprise a majority of the board
of directors of the Issuer.
<PAGE> 10
"Required Lenders" means Holders of at least 66 2/3% in
principal amount of the Outstanding Notes.
"Reserve Report" means the Reserve Summary contained in the
Offering Memorandum and, subsequently, a report delivered by the Issuer pursuant
to Section 5.08(a).
"Subsidiary" means any corporation or other entity of which
securities or other ownership interests having ordinary voting power to elect a
majority of the board of directors or other persons performing similar functions
are at the time directly or indirectly owned by the Issuer.
"Unfunded Liabilities" means, with respect to any Plan at any
time, the amount (if any) by which (i) the present value of all benefits under
such Plan exceeds (ii) the fair market value of all Plan assets allocable to
such benefits (excluding any accrued but unpaid contributions), all determined
as of the then most recent valuation date for such Plan, but only to the extent
that such excess represents a potential liability of the Issuer or any
Subsidiary (whether direct or joint and several with one or more affiliates) to
the PBGC or any other Person under Title IV of ERISA.
"Wholly-Owned Subsidiary" means any Subsidiary all of the
shares of capital stock or other ownership interests of which (except directors'
qualifying shares) are at the time directly or indirectly owned by the Issuer.
SECTION 1.02. Accounting Terms and Definitions. Unless
otherwise specified herein, all accounting terms used in this Agreement shall be
interpreted, all accounting determinations hereunder shall be made and all
financial statements required to be delivered hereunder shall be prepared in
accordance with generally accepted accounting principles as in effect from time
to time, applied on a basis consistent (except for changes concurred by the
Issuer's independent public accountants) with the most recent audited
consolidated financial statements of the Issuer delivered to the Holders.
ARTICLE II
THE NOTES
SECTION 2.01. Sale and Purchase of Notes. The Issuer agrees to
issue and sell to each Purchaser, and subject to the terms and conditions of
this Agreement, each Purchaser, severally and not jointly, agrees to purchase
from the Issuer, at the Closing provided for in Section 2.02, Notes in the
principal amounts specified opposite such Purchaser's name on Schedule A
attached hereto. The purchase price of the Notes to be purchased by each
Purchaser shall be 100% of the principal amount thereof. The Notes to be
purchased by each Purchaser will be dated the date of issue thereof, will mature
on the date set forth therein and will bear interest on the unpaid balance
thereof from the date of issue until the principal thereof shall become due and
payable, at the rate of 7.19% per annum. Interest on the Notes shall be computed
on the basis of a year of 360 days, consisting of 12 30-day months, and accrued
and unpaid interest on the unpaid balance thereof shall be payable semi-annually
on May 15 and November 15 of each year, commencing May 15, 1998, and at
maturity. Any overdue principal of, prepayment charge on, and, to the extent
permitted by law, overdue interest on any Note shall bear interest, payable on
demand, for each day from and including the date payment thereof is due to but
excluding the date of actual payment, at a rate per annum equal to the higher of
(i) 9.19% and (ii) the Prime Rate for such day plus 2%. Whenever any payment of
principal of, or interest on, a Note shall be due on a day which is not a
Business Day, the date for payment thereof shall be extended to the next
succeeding Business Day. If the date for any payment of principal is extended by
operation of law or otherwise, interest thereon will be payable for such
extended time. The Notes will be in registered form substantially in the form of
Exhibit A attached hereto.
<PAGE> 11
SECTION 2.02. CLOSING. The sale and purchase of the Notes
shall take place- at the offices of Milbank, Tweed, Hadley & McCloy, 1 Chase
Manhattan Plaza, New York, New York 10005, at 10:00 a.m., New York City time, on
November 18, 1997 or at such other time on such day as may be agreed upon by the
Issuer and the Purchasers (the "Closing"). At the Closing, the Issuer will
deliver to each Purchaser the Note or Notes to be purchased by such Purchaser,
dated the date of the Closing and registered in such Purchaser's name (or in the
name of such Purchaser's nominee), against delivery by such Purchaser to the
Issuer or its order of immediately available funds in the amount of the purchase
price thereof. If at the Closing the Issuer shall fail to tender such Note or
Notes to such Purchaser as provided above, or any of the conditions specified in
Article III shall not have been satisfied or waived, such Purchaser shall, at
its election, be relieved of all further obligations under this Agreement,
without thereby waiving any other rights such Purchaser may have by reason of
such failure or such nonfulfillment.
SECTION 2.03. Prepayments. (a) Subject to the provisions of
Section 2.03(e), the Issuer shall pay $20,000,000 of the outstanding principal
amount of the Notes on November 15 of each of the years 2005 through 2008,
inclusive, and shall pay the remaining outstanding principal amount of the Notes
together with all accrued but unpaid interest thereon, and the Notes shall
finally mature, on November 15, 2009.
(b) On any date (but in any event not more than four times in
any fiscal year), the Issuer may prepay all or any portion of the Notes,
provided that, simultaneously with any such prepayment, the Issuer shall pay
accrued but unpaid interest and a prepayment charge with respect to Notes being
prepaid equal to the amount (the "Make Whole Amount") not less than zero that is
the excess of:
(1) the sum of the Present Values of (i) the aggregate
principal amount of the Notes being prepaid (assuming the principal
balance of such Notes payable upon maturity and the required
prepayments pursuant to Section 2.03(a) are paid when due, without
regard to the prepayment in respect of which the Make Whole Amount is
being calculated) and (ii) the amount of interest which would have been
payable on the principal amount of such Notes (assuming the principal
balance of such Notes payable upon maturity, the required prepayments
pursuant to Section 2.03(a) and interest payments pursuant to the terms
of such Notes are paid when due); over
(2) the aggregate principal amount of the Notes being prepaid.
For purposes of the definition of Make Whole Amount, "Present Value" shall be
computed in accordance with generally accepted accounting principles on a
semiannual basis at a discount rate equal to the sum of the Treasury Yield plus
0.50%; and the "Treasury Yield" shall be the yield to maturity implied by (i)
the yields reported, as of 10:00 A.M. (New York City time) on the second
Business Day prior to the date fixed for prepayment, on the display designated
as Bloomberg Financial Markets "Page USD" (or such other display as may replace
Bloomberg Financial Markets "Page USD") for actively traded United States
Treasury securities adjusted to a constant maturity equal to the then remaining
weighted average life of the Notes being prepaid (the "Remaining Life"), or (ii)
if such yields are not reported as of such time or the yields reported as of
such time are not ascertainable, the Treasury Constant Maturity Series Yields
reported, for the latest day for which such yields have been so reported as of
the second Business Day prior to the date fixed for prepayment in Federal
Reserve Statistical Release H.15 (519) (or any comparable successor publication)
for actively traded United States Treasury securities adjusted to a constant
maturity equal to the Remaining Life; provided that if the Remaining Life of the
Notes is not equal to the constant maturity of a United States Treasury
<PAGE> 12
security for which a weekly average yield is given, the Treasury Yield shall be
obtained by linear interpolation (calculated to the nearest one-twelfth of a
year) from the most recent weekly average yield of United States Treasury
securities for which such yields are given having a maturity as close as
possible to the Remaining Life.
Prepayments of Notes in accordance with this subsection (b)
shall be made in minimum amounts of $5,000,000 principal amount of Notes and
increments of $1,000,000.
(c) The Issuer shall give each Holder at least 20 Business
Days'(but not more than 60 days') notice of any anticipated prepayment of Notes
pursuant to paragraph (b) of this Section 2.03, which notice shall set forth the
date of the prepayment and the anticipated amount of the prepayment applicable
to such Holder's Notes. Any such notice given by the Issuer hereunder shall be
irrevocable. The Issuer shall, at least one Business Day prior to the date of
the prepayment, give immediate notice to each Holder of the Make Whole Amount
applicable to such prepayment, showing the components of the calculation
thereof.
(d) In the event of a Change of Control, the Issuer shall
prepay the aggregate principal amount of the Notes of any Holder electing
prepayment, together with accrued and unpaid interest thereon and the Make Whole
Amount with respect thereto. The Issuer shall give notice (the "Change of
Control Notice") to each Holder of a Change of Control within 5 Business Days of
knowledge of such event. The Change of Control Notice shall include a statement
of the date of occurrence of such Change of Control and a description of the
facts known to the Issuer underlying such Change of Control and shall state that
the Issuer is obligated, pursuant to this Section 2.03(d), to purchase Notes in
respect of which a Holder shall elect prepayment. Each Holder electing
prepayment shall notify the Issuer in writing of its election of prepayment (the
"Election Notice") within 30-days of the date of the Change of Control Notice.
The Issuer shall promptly upon receipt of an Election Notice from any Holder
forward a copy of such Election Notice to all other Holders. In the event that a
Change of Control occurs but no Change of Control Notice is given by the Issuer,
a Holder may deliver a notice to the Issuer (a "Purchase Notice") stating that
it is electing to exercise its right to require the Issuer to purchase its
Notes. The Issuer shall forthwith upon receipt of any Purchase Notice give
notice of the receipt of such Purchase Notice (and enclose a copy of such
Purchase Notice) to all other Holders, stating that other Holders may give a
similar notice to the Issuer within 30 days of the date of transmission of the
copy of such Purchase Notice by the Issuer. Prepayments required to be made by
this paragraph (d) shall be made on a date specified by the Issuer by at least 5
Business Days notice to the Holders electing prepayment, which date shall be no
later than 15 days after the earlier of (i) the last day for submission of the
Election Notice or Purchase Notice by any Holder and (ii) the date of receipt by
the Issuer of an Election Notice or Purchase Notice from a Holder such that all
Holders of Outstanding Notes have delivered such Notice to the Issuer.
(e) The Issuer will not make any payment of any Note under
this Section 2.03 unless a simultaneous payment is made to all Holders (or in
the case of prepayment under subsection (d) to all Holders electing prepayment)
so as to reduce ratably the obligation of the Issuer under each of the
Outstanding Notes (or, in the case of prepayment under subsection (d), under
each of the Outstanding Notes as to which the Holder has elected prepayment).
The amount of each payment required by subsection (a) shall be reduced ratably
by the aggregate principal amount of Notes prepaid in accordance with subsection
(b) or (d).
(f) The Issuer will not, and will not permit any of its
Affiliates to, acquire directly or indirectly by purchase or prepayment or
otherwise any of the Outstanding Notes except by way of payment or prepayment in
accordance with the provisions of the Notes and of this
<PAGE> 13
Agreement. Notes paid or prepaid in full in accordance with this Section 2.03
shall not be deemed Outstanding for any purpose under this Agreement.
SECTION 2.04. Maximum Interest Rate. The Issuer, the
Purchasers and all other Holders of the Notes specifically intend and agree to
limit contractually the amount of interest, and all amounts which shall be
deemed to constitute interest under applicable law, payable under this
Agreement, the Notes and all other instruments and agreements related hereto and
thereto to the maximum amount of interest lawfully permitted to be charged under
applicable law. Therefore, none of the terms of this Agreement, the Notes or any
instrument pertaining to or relating to this Agreement or the Notes shall ever
be construed to create a contract to pay interest at a rate in excess of the
maximum rate permitted to be charged under applicable law, and neither the
Issuer nor any other party liable or to become liable hereunder, under the Notes
or under any other instruments and agreements related hereto and thereto shall
ever be liable for interest in excess of the amount determined at such maximum
rate, and the provisions of this Section 2.04 shall control over all other
provisions of this Agreement, the Notes, or any other instrument pertaining to
or relating to the transactions herein contemplated. If any amount of interest
taken or received by any Holder of a Note shall be in excess of said maximum
amount of interest which, under applicable law, could lawfully have been
collected by such Holder incident to such transactions, then such excess shall
be deemed to have been the result of a mathematical error by all parties hereto
and the amount of interest which would otherwise be payable hereunder or under
the Notes shall be automatically reduced to the amount allowed under applicable
law, and such excess shall be credited ratably against and to the extent of the
unpaid principal amount of the Note or Notes held by such Holder, with the
excess, if any, being refunded to the Issuer. All amounts paid or agreed to be
paid in connection with such transactions which would under applicable law be
deemed "interest" shall, to the extent permitted by such applicable law, be
amortized, prorated, allocated and spread throughout the full stated term of
this Agreement. "Maximum rate" as used in this paragraph means, with respect to
each of the Notes, the maximum lawful, nonusurious rates of interest which under
applicable law may be charged to the Issuer from time to time with respect to
such Notes.
ARTICLE III
CONDITIONS TO PURCHASE OF NOTES
SECTION 3.01. Conditions to Purchase. The obligation of each
Purchaser to purchase a Note or Notes at the Closing is subject to the
satisfaction of such of the following conditions as shall not have been
expressly waived by such Purchaser:
(a) the fact that, immediately before and after such purchase,
no Default shall have occurred and be continuing;
(b) the fact that the representations and warranties of the
Issuer contained in this Agreement shall be true and correct on and as
of the date of such purchase and before and after giving effect to the
issuance and purchase of the Notes;
(c) receipt by such Purchaser of a Note duly executed on
behalf of the Issuer and dated the date of such purchase, substantially
in the form of Exhibit A hereto;
(d) receipt by such Purchaser of an opinion of Baker & Botts,
counsel for the Issuer, substantially in the form of Exhibit B hereto;
<PAGE> 14
(e) receipt by such Purchaser of an opinion of Lisa A.
Machesney, Managing Counsel for the Issuer, substantially in the form
Of Exhibit C hereto;
(f) receipt by such Purchaser of an opinion of Milbank, Tweed,
Hadley & McCloy, special counsel for the Purchasers, substantially in
the form of Exhibit D hereto;
(g) receipt by such Purchaser of a certificate signed by the
chief financial officer or the treasurer of the Issuer, to the effect
set forth in clauses (a) and (b) of Section 3.01;
(h) on the Closing Date, the purchase of Notes by such
Purchaser shall (i) be permitted by the laws and regulations of each
jurisdiction to which such Purchaser is subject, without recourse to
provisions (such as Section 1405(a)(8) of the New York Insurance Law)
permitting limited investments by insurance companies without
restriction as to the character of the particular investment, (ii) not
violate any applicable law or regulation (including, without
limitation, Regulation G, T or X of the Board of Governors of the
Federal Reserve System) and (iii) not subject such Purchaser to any
tax, penalty or liability under or pursuant to any applicable law or
regulation, which law or regulation was not in effect on the date
hereof; and, if requested by any Purchaser, such Purchaser shall have
received a certificate of the chief financial officer, principal
accounting officer, treasurer or comptroller of the Issuer or of any
other officer of the Issuer whose responsibilities extend to the
subject matter of such certificate, certifying as to such matters of
fact (but in no event as to a legal conclusion with respect thereto) as
such Purchaser may reasonably specify in a form to be provided by such
Purchaser, to enable such Purchaser to determine whether such purchase
is so permitted;
(i) without limiting the provisions of Section 8.03, the
Issuer shall have paid on or before the Closing Date the fees, charges
and disbursements of special counsel for the Purchasers referred to in
paragraph (f) above to the extent reflected in a statement of such
counsel rendered to the Issuer at least one Business Day prior to the
Closing Date;
(j) evidence satisfactory to such Purchaser of the receipt of
a Private Placement Number for the Notes from the CUSIP Bureau of
Standard & Poor's;
(k) the fact that the Issuer shall have issued and sold
$100,000,000 in aggregate principal amount of Notes hereunder (taking
into account the Notes to be purchased by such Purchaser); and
(l) receipt by such Purchaser of all documents it or its
special counsel may reasonably request relating to the existence of the
Issuer, the corporate authority for and the validity of the Notes and
this Agreement, and any other matters relevant hereto, all in form and
substance satisfactory to special counsel for the Purchasers.
The documents and opinions referred to in this Article III shall be delivered to
each Purchaser no later than the Closing Date. The certificate and opinions
referred to above shall be dated the Closing Date.
<PAGE> 15
ARTICLE IV
REPRESENTATIONS AND WARRANTIES
The Issuer represents and warrants to each Purchaser that:
SECTION 4.01. Corporate Existence and Power. The Issuer and
each Subsidiary is a corporation duly incorporated, validly existing and in good
standing under the laws of its jurisdiction of incorporation, and has all
corporate powers and all governmental licenses, authorizations, consents and
approvals required to own its assets and to carry on its business as now
conducted and is duly qualified as a foreign corporation in good standing in
each jurisdiction where the nature of its business or the ownership or leasing
of its Properties requires such qualification, except where the failure to
qualify would not materially and adversely affect the conduct of its business or
the enforceability of contractual obligations of the Issuer. Neither the Issuer
nor any Affiliate is subject to regulation under the Public Utility Holding
Company Act of 1935, the Investment Company Act of 1940, the Transportation Act
(49 U.S.C.), as amended, the Federal Power Act, as amended, or any other law or
regulation the application of which limits the incurrence by the Issuer of Debt
hereunder, including, but not limited to, laws relating to common or contract
carriers or the sale of electricity, gas, steam, water or other public utility
services.
SECTION 4.02. Corporate and Governmental Authorization; No
Contravention. The execution, delivery and performance by the Issuer of this
Agreement and the Notes are within the Issuer's corporate powers, have been duly
authorized by all necessary corporate action, require no action by or in respect
of, or filing with, any governmental body, agency or official and do not
contravene, or constitute a default under, any provision of applicable law or
regulation or of the certificate of incorporation or bylaws of the Issuer or of
any agreement or instrument evidencing or governing Debt of the Issuer or any
Affiliate or any other agreement, instrument, judgment, injunction, order or
decree binding upon the Issuer or any Subsidiary or result in the creation or
imposition of any Lien on any asset of the Issuer pursuant to any such
agreement, instrument, judgment, injunction, order or decree.
SECTION 4.03. Binding Effect. The Notes and this Agreement
constitute legal, valid and binding obligations of the Issuer enforceable in
accordance with their terms, except as the enforceability thereof may be limited
by (i) bankruptcy, insolvency or similar laws affecting creditors' rights
generally and (ii) equitable principles of general applicability.
SECTION 4.04. Financial Information
(a) Audited Financial Statements. The consolidated balance
sheets of the Issuer and its Subsidiaries as of the fiscal years ended December
31, 1994 to 1996 and the related consolidated statements of operations, cash
flows and stockholders' equity for the fiscal years then ended, reported on by
Coopers & Lybrand and set forth in the Offering Memorandum, a copy of which has
been delivered to each of the Purchasers, fairly present, in conformity with
generally accepted accounting principles, the consolidated financial position of
the Issuer and its Subsidiaries as of such dates and their consolidated results
of operations and cash flows for such fiscal years.
(b) Reserve Data. There are no statements or conclusions in
the reserve report included in the Offering Memorandum provided to Purchasers
regarding reserves which are based upon or include misleading information or
fail to take into account material information known to the Issuer regarding the
matters reported therein, it being understood that such statements and
conclusions are necessarily based upon professional opinions, estimates and
forecasts, and the Issuer
<PAGE> 16
does not warrant that such opinions, estimates and forecasts will ultimately
prove to have been accurate. Such reserve data has, in the judgment of the
Issuer, been properly compiled from engineering tests conducted in accordance
with prevailing industry standards.
(c) The financial projections and estimates and the pro forma
financial statements included in the Offering Memorandum or otherwise furnished
by the Issuer in connection with the Notes and this Agreement have been prepared
by the Issuer in good faith on the basis of information and assumptions that the
Issuer believed to be reasonable as of the date of such information, and no
material assumptions have been omitted as basis for such financial projections
and estimates and pro forma financial statements.
(d) Since December 31, 1996, there has been no material
adverse change in the business, Properties, financial position, results of
operations or prospects of the Issuer or the Issuer and its Subsidiaries,
considered as a whole.
SECTION 4.05. Full Disclosure. None of the financial
statements and other financial or factual information included in the Offering
Memorandum (excluding estimates, financial projections and pro forma financial
statements) contains any untrue statement of material fact or omits to state a
material fact necessary in order to make the statements contained therein not
misleading. All other financial and reserve information, financial statements
and other documents (excluding estimates, projections and pro forma financial
information) furnished by the Issuer to the Purchasers in connection with the
Notes and this Agreement and set forth on Schedule 4.05 do not and will not
contain any untrue statement of material fact or omit to state a material fact
necessary in order to make the statements contained therein not misleading. The
Issuer has disclosed to the Purchasers in writing any and all facts known to the
Issuer which materially, and adversely affect the business, properties,
operations or condition, financial or otherwise, of the Issuer or the Issuer and
its Subsidiaries, considered as a whole or the Issuer's ability to perform its
obligations under the Notes and this Agreement.
SECTION 4.06. Litigation. Except as disclosed on
Schedule 4.06 there is no action, suit or proceeding pending against, or to the
knowledge of the Issuer threatened against or affecting, the Issuer or any of
its Affiliates before any court or arbitrator or any governmental body, agency
or official in which there is a reasonable possibility of an adverse decision
which could individually or in the aggregate materially adversely affect the
financial position of the Issuer or the Issuer and its Subsidiaries, considered
as a whole or which in any manner draws into question the validity of the Notes
and this Agreement.
SECTION 4.07. Compliance with ERISA. (a) Each member of the
ERISA Group has fulfilled its obligations under the minimum funding standards of
ERISA and the Internal Revenue Code with respect to each Plan and is in
compliance in all material respects with the presently applicable provisions of
ERISA and the Internal Revenue Code with respect to each Plan. No member of the
ERISA Group has (i) sought a waiver of the minimum funding standard under
Section 412 of the Internal Revenue Code in respect of any Plan, (ii) failed to
make any contribution or payment to any Plan or Multiemployer Plan, or made any
amendment to any Plan, which, in either case, has resulted or could result in
the imposition of a Lien on Property of the Issuer or any Subsidiary or the
posting of a bond or other security by the Issuer or any Subsidiary under ERISA
or the Internal Revenue Code or (iii) incurred any liability under Title IV of
ERISA (other than a liability to the PBGC for premiums under Section 4007 of
ERISA) which could cause the Issuer or any Subsidiary (whether directly or
jointly and severally with one or more affiliates) to incur any liability.
<PAGE> 17
(b) The execution and delivery of this Agreement and the
issuance and sale of the Notes hereunder will not involve any transaction that
is subject to the prohibitions of section 406(a) of ERISA or in connection with
which a tax could be imposed pursuant to section 4975(c)(1)(A)-(D) of the
Internal Revenue Code. The representation by the Issuer in the immediately
preceding sentence is made in reliance upon and subject to the accuracy of the
representation of each Purchaser in Section 7.02 as to the sources of the funds
used to pay the purchase price of the Notes to be purchased by such Purchaser.
SECTION 4.08. Environmental Matters. In the ordinary course of
its business, the Issuer considers effects of all existing and applicable
Environmental Laws on the business, operations and properties of the Issuer and
its Subsidiaries, in the course of which it identifies and evaluates associated
liabilities and costs (including, without limitation, any capital or operating
expenditures required for cleanup or closure of properties currently or
previously owned, any capital or operating expenditures required to achieve or
maintain compliance with environmental protection standards imposed by law or as
a condition of any license, permit or contract, any related constraints on
operating activities, including any periodic or permanent shutdown of any
facility or reduction in the level of or change in the nature of operations
conducted thereat and any actual or potential liabilities to third parties,
including employees, and any related costs and expenses). The Issuer has
reasonably concluded that existing and applicable Environmental Laws are
unlikely to have a material adverse effect on the business, Properties,
financial condition, results of operations or prospects of the Issuer or the
Issuer and its Subsidiaries, considered as a whole. The Issuer and its
Subsidiaries have conducted and are conducting their respective businesses in
compliance with all applicable Environmental Laws, except where the failure to
so comply would not have a material adverse effect on the Issuer or the Issuer
and its Subsidiaries, considered as a whole.
SECTION 4.09. Taxes. The Issuer and its Subsidiaries have
filed all United States Federal income tax returns and all other material tax
returns which are required to be filed by them and have paid all taxes due
pursuant to such returns or pursuant to any assessment received by the Issuer or
any Subsidiary. The charges, accruals and reserves on the books of the Issuer
and its Subsidiaries in respect of taxes or other governmental charges are
adequate.
SECTION 4.10. Titles, ect. The Issuer and each Subsidiary has
valid and defensible title to its material (individually or in the aggregate)
Petroleum Properties and good, valid, defensible and marketable title to its
other real and personal property, in each case free and clear of all Liens
except Liens expressly permitted by Section 5.10. Each lease under which the
Issuer or any of its Subsidiaries is the lessee which is material to the
business or operations of the Issuer or the Issuer and its Subsidiaries
considered as a whole is valid and subsisting and is in full force and effect.
SECTION 4.11. Casualities; Taking of Properties. Since the
date of the reserve data included in the Offering Memorandum, neither the
business nor the Petroleum Properties of the Issuer or any of its Subsidiaries
have been affected as a result of any fire, explosion, earthquake, flood,
drought, windstorm, accident, strike or other labor disturbance, embargo,
requisition or taking of Property or cancellation of contract, permits or
concessions by any domestic or foreign government or any agency thereof, riot,
activities of armed forces or acts of God or of any public enemy, or any other
event the occurrence of which, would have a material adverse effect on the
business, Properties, financial condition, results of operations or prospects of
the Issuer or the Issuer and its Subsidiaries, considered as a whole.
SECTION 4.12. Gas Imbalances. There exists no gas imbalances,
take or pay or other prepayments with respect to any Petroleum Properties which
would require the Issuer or any Subsidiary to deliver hydrocarbons produced from
any Petroleum Properties at some future time
<PAGE> 18
without then or thereafter receiving full payment therefor which would be
reasonably likely to have a material adverse effect on the business, Properties,
financial condition, results of operations or prospects of the Issuer or the
Issuer and its Subsidiaries, considered as a whole.
SECTION 4.13. Use of Proceeds. The proceeds from the sale of
the Notes pursuant to this Agreement will be used by the Issuer to repay
indebtedness under the Credit Agreement and for general corporate purposes. No
part of the proceeds from the sale of the Notes hereunder will be used, directly
or indirectly, for the purpose of buying or carrying any margin stock within the
meaning of Regulation G of the Board of Governors of the Federal Reserve System
(12 CFR 207), or for the purpose of buying or carrying or trading in any
securities under such circumstances as to involve the Issuer in a violation of
Regulation X of said Board (12 CFR 224) or to involve any broker or dealer in a
violation of Regulation T of said Board (12 CFR 220). Margin stock does not
constitute more than 5% of the value of the consolidated assets of the Issuer
and its Subsidiaries and the Issuer does not have any present intention that
margin stock will constitute more than 5% of the value of such assets. As used
in this Section, the terms "margin stock" and "purpose of buying or carrying"
shall have the meanings assigned to them in said Regulation G.
SECTION 4.14. Offering of the Notes. Neither the Issuer nor
any Person acting on behalf of the Issuer has, directly or indirectly, offered
any of the Notes or any similar security of the Issuer for sale to, or solicited
any offers to buy any thereof from, or otherwise approached or negotiated with
respect thereto with, anyone other than the Purchasers and not more than 75
other institutional investors, each of whom were offered a portion of the Notes
for purposes of investment and not for distribution. Neither the Issuer nor any
Person acting on behalf of the Issuer has taken or will take any action which
would cause the offer, issuance or sale of any Note to any Purchaser to violate
the provisions of the Securities Act of 1933, as amended, or any other
securities or blue sky laws of any applicable jurisdiction or subject the
issuance or sale of the Notes to the registration requirements of Section 5 of
said Securities Act.
SECTION 4.15. Ownership of Subsidiaries. Schedule 4.15 sets
forth a list of each Subsidiary of the Issuer and its jurisdiction of
incorporation. All of the issued shares of capital stock of such Subsidiary have
been duly and validly authorized and issued, are fully paid and nonassessable,
and are owned directly or indirectly by the Issuer, free and clear of all Liens
and restrictions on transferability or voting.
ARTICLE V
COVENANTS
The Issuer agrees that, so long as any amount payable under
any Note or this Agreement remains unpaid, it will, and will cause each of its
Subsidiaries to, perform and comply with each of the following covenants, unless
such performance and compliance shall have been specifically waived in writing
by the Required Lenders:
<PAGE> 19
SECTION 5.01. Information. The Issuer will deliver to each of
the Holders:
(a) as soon as available and in any event within 100 days
after the end of each fiscal year of the Issuer, a consolidated balance
sheet of the Issuer and its Subsidiaries as of the end of such fiscal
year and the related consolidated statements of operations, cash flows
and stockholders' equity for such fiscal year, setting forth in each
case in comparative form the figures for the previous fiscal year, all
reported on in a manner acceptable to the Securities and Exchange
Commission by Coopers & Lybrand or other independent public accountants
of nationally recognized standing;
(b) as soon as available and in any event within 60 days after
the end of each of the first three quarters of each fiscal year of the
Issuer, a consolidated balance sheet of the Issuer and its Subsidiaries
as of the end of such quarter and the related consolidated statements
of operations and cash flows for such quarter and for the portion of
the Issuer's fiscal year ended at the end of such quarter, setting
forth in each case in comparative form the figures for the
corresponding quarter and the corresponding portion of the Issuer's
previous fiscal year, all certified (subject to normal year-end
adjustments) as to fairness of presentation, generally accepted
accounting principles and consistency by the chief financial officer or
the chief accounting officer or treasurer of the Issuer;
(c) simultaneously with the delivery of each set of financial
statements referred to in clauses (a) and (b) above, a certificate of
the chief financial officer or the chief accounting officer or
treasurer of the Issuer (i) setting forth in reasonable detail the
calculations required to establish whether the Issuer was in compliance
with the financial covenants contained herein on the date of such
financial statements, and (ii) stating whether any Default then exists,
setting forth the details thereof and the action which the Issuer is
taking or proposes to take with respect thereto;
(d) within five days after any Executive Officer of the Issuer
obtains knowledge of any Default, if such Default is then continuing, a
certificate of the chief financial officer or the chief accounting
officer or treasurer of the Issuer setting forth the details thereof
and the action which the Issuer is taking or proposes to take with
respect thereto;
(e) promptly upon the mailing thereof to the shareholders of
the Issuer generally, copies of all financial statements, reports and
proxy statements so mailed;
(f) promptly upon the filing thereof, copies of all
registration statements (other than the exhibits thereto and any
registration statements on Form S-8, or its equivalent) and reports on
Forms 10K, 10Q and 8K (or their equivalents) which the Issuer shall
have filed with the Securities and Exchange Commission;
(g) if and when any member of the ERISA Group (i) gives or is
required to give notice to the PBGC of any "reportable event" (as
defined in Section 4043 of ERISA and the regulations thereunder) with
respect to any Plan which might constitute grounds for a termination of
such Plan under Title IV of ERISA, or any Executive Officer of the
Issuer or any Subsidiary knows that the plan administrator of any Plan
has given or is required to give notice of any such reportable event, a
copy of the notice of such reportable event given or required to be
given to the PBGC; (ii) receives notice of complete or partial
withdrawal liability under Title IV of ERISA or notice that any
Multiemployer Plan is in reorganization, is insolvent or has been
terminated, a copy of such notice; (iii) receives notice from the PBGC
under Title IV of ERISA of an intent to terminate, impose liability
(other than for premiums
<PAGE> 20
under Section 4007 of ERISA) in respect of, or appoint a trustee to
administer any Plan, a copy of such notice; (iv) applies for a waiver
of the minimum funding standard under Section 412 of the Internal
Revenue Code, a copy of such application; (v) gives notice of intent to
terminate any Plan under Section 4041(c) of ERISA, a copy of such
notice and other information filed with the PBGC; (vi) gives notice of
withdrawal from any Plan pursuant to Section 4063 of ERISA, a copy of
such notice; or (vii) fails to make any required payment or
contribution to any Plan or Multiemployer Plan, or makes any amendment
to any Plan which has resulted or could result in the imposition of a
Lien on Property of the Issuer or any Subsidiary or the posting of a
bond or other security by the Issuer or any Subsidiary, a certificate
of the chief financial officer or the chief accounting officer or
treasurer of the Issuer setting forth details as to such occurrence and
action, if any, which the Issuer or applicable member of the ERISA
Group is required or proposes to take; and
(h) from time to time such additional information regarding
the financial position, reserves or business of the Issuer and its
Subsidiaries as any Holder may reasonably request.
SECTION 5.02. Payment of Obligations. The Issuer will pay and
discharge, and will cause each Subsidiary to pay and discharge, at or before
maturity, all their respective material obligations and liabilities, including,
without limitation, tax liabilities, except where, the same may be contested in
good faith by appropriate proceedings, and will maintain, and will cause each
Subsidiary to maintain, in accordance with generally accepted accounting
principles, appropriate reserves for the accrual of any of the same.
SECTION 5.03. Maintenance of Property. The Issuer will keep,
and will cause each Subsidiary to keep, all property useful and necessary in its
business in good working order and condition, ordinary wear and tear excepted.
The Issuer will operate, or will use its best efforts to cause a third party
operator to operate, all Petroleum Properties in a prudent manner, and will
market or will cause to be marketed the production therefrom at the best price
reasonably obtainable at the time the applicable sales contract is executed.
SECTION 5.04. Conduct of Business and Maintenance of
Existence. The Issuer (a) will, and will cause each Subsidiary to continue to,
engage in business of the same general type as now conducted by the Issuer and
its Subsidiaries, and (b) will preserve, renew and keep in full force and
effect, and will cause each Subsidiary to preserve, renew and keep in full force
and effect, their respective corporate existence and their respective rights,
privileges and franchises necessary or desirable in the normal conduct of
business; provided that nothing in this Section 5.04 shall prohibit (i) the
merger of a Wholly-Owned Subsidiary into the Issuer or the merger or
consolidation of a Wholly-Owned Subsidiary with or into another Person if the
corporation surviving such consolidation or merger is a Wholly-Owned Subsidiary
and if, in each case, after giving effect thereto, no Default shall have
occurred and be continuing or (ii) the termination of the corporate existence of
any Subsidiary if the Issuer in good faith determines that such termination is
in the best interest of the Issuer and is not materially disadvantageous to the
Holders.
SECTION 5.05. Compliance with Laws. The Issuer will comply,
and will cause each Subsidiary to comply, in all material respects with all
applicable laws, ordinances, rules, regulations, and requirements of
governmental authorities (including, without limitation, Environmental Laws and
ERISA and the rules and regulations thereunder) except for laws the violation of
which could not have a material adverse effect on the Issuer or any Subsidiary
and where the necessity of compliance therewith is contested in good faith by
appropriate proceedings.
<PAGE> 21
SECTION 5.06. Inspection of Property, Books and Records. The
Issuer will keep, and will cause each Subsidiary to keep, proper books of record
and account in which full, true and correct entries shall be made of all
dealings and transactions in relation to its business and activities; and will
permit, and will cause each Subsidiary to permit, representatives of any Holder
at such Holder's expense (except during the continuance of any Default, in which
case at the expense of the Issuer) to visit and inspect any of their respective
Properties, to examine and make copies of any of their respective books and
records and to discuss their respective affairs, finances and accounts with
their respective officers, employees and independent public accountants, all at
such reasonable times and as often as may reasonably be desired.
SECTION 5.07. Insurance. The Issuer and each Subsidiary now
maintains and will cause to be maintained with insurers which the Issuer
believes to be financially sound and reputable, insurance with respect to its
Properties and business against such liabilities, casualties, risks and
contingencies and in such types and amounts as is customary in the case of
Persons engaged in the same or similar businesses and similarly situated.
SECTION 5.08. Engineering Reports
(a) On or before April 10, 1998, and thereafter by April 10th
of each subsequent year, the Issuer shall furnish to each of the Holders a
report in form and substance reasonably satisfactory to the Required Lenders
prepared by or under the supervision of a petroleum engineer who may be an
employee of the Issuer, which shall evaluate all net Proved Reserves owned by
the Issuer and its Subsidiaries as of the preceding December 31 and which shall
set forth the information necessary to determine the Present Value of Proved
Reserves as of such date.
(b) Together with the Reserve Report furnished pursuant to
subsection (a), the Issuer shall furnish to each of the Holders a review report
thereon in form and substance reasonably satisfactory to the Required Lenders by
Miller & Lents, Ltd. or other independent petroleum engineers of nationally
recognized standing.
SECTION 5.09. Asset Coverage Ratio. (a) The ratio of (i)
Present Value of Proved Reserves plus Adjusted Cash to (ii) Debt and Other
Liabilities shall at all times be not less than 1.5:1;
(b) The Present Value of Proved Reserves will be determined
and adjusted periodically as follows:
(i) The calculation of Present Value of Proved Reserves will
be determined from the most recent Reserve Report.
(ii) Upon any sale by the Issuer or any Subsidiary of any
Petroleum Property including but not limited to a sale of a lesser
interest such as a royalty or a net profit interest to the extent the
sale of such lesser interest is not considered to create a Lien (other
than the sale of hydrocarbons after severance occurring in the ordinary
course of the Issuer's business), the calculation of Present Value of
Proved Reserves shall be reduced, effective on the date of consummation
of such sale, by an amount equal to the Present Value of Proved
Reserves attributable to Proved Reserves included in such sale.
(iii) Immediately upon acquisition or development by the
Issuer or any Subsidiary of any Petroleum Property owned directly by
the Issuer or any Subsidiary and not reflected in the most recent
Reserve Report, the calculation of Present Value
<PAGE> 22
of Proved Reserves shall be increased in an amount equal to the Present
Value of Proved Reserves attributable to such Petroleum Property.
SECTION 5.10. Liens. The Issuer will not, and will not permit
any Subsidiary to, create, incur, assume or suffer to exist any Lien on any of
its Properties (now owned or hereafter acquired), except:
(a) Excepted Liens;
(b) Liens existing on the Closing Date and listed on Schedule
5.10, but not any renewals and extensions thereof;
(c) a Lien existing on any asset prior to the acquisition
thereof by the Issuer or any of its Subsidiaries but not created in
contemplation of such acquisition;
(d) a Lien on any asset not previously owned by the Issuer or
any Subsidiary securing Debt incurred or assumed for the purpose of
financing any part of the cost of acquiring such asset, provided that
such Lien attaches to such asset concurrently with or within 90 days
after the acquisition thereof;
(e) Liens in respect of gas imbalances in the ordinary course
of business not exceeding 2% of the Present Value of Proved Reserves in
the aggregate at any time; and
(f) Liens securing other Debt of the Issuer or any Subsidiary
the aggregate principal amount of which, when taken together with the
amount of Attributable Debt in respect of sale and leaseback
transactions otherwise restricted by Section 5.15, does not exceed
$5,000,000 at any time.
SECTION 5.11. Transactions with Affiliates. The Issuer will
not, and will not permit any Subsidiary to, directly or indirectly, pay any
funds to or for the account of, make any Investment in, lease, sell, transfer or
otherwise dispose of any assets, tangible or intangible, to, or participate in,
or effect any transaction in connection with any joint enterprise or other joint
arrangement with, any Affiliate; provided, however, that the foregoing
provisions of this Section shall not prohibit (a) the Issuer or any Subsidiary
from making sales to or purchases from any Affiliates and, in connection
therewith, extending credit or making payments, or from making payments for
services rendered by any Affiliates, if such sales or purchases are made or such
services are rendered in the ordinary course of business and on terms and
conditions at least as favorable to it as the terms and conditions which would
apply in a similar transaction with a Person not an Affiliate, (b) the Issuer
from making payments of principal, interest and premium on any Debt of the
Issuer held by an Affiliate if the terms of such Debt are substantially as
favorable to the Issuer as the terms which could have been obtained at the time
of the creation of such Debt from a lender which was not an Affiliate and are
otherwise in accordance with this Agreement, (c) the Issuer or any Subsidiary
from participating in, or effecting any transaction in connection with, any
joint enterprise or other joint arrangement with any Affiliate if it
participates or effects any such transaction in the ordinary course of its
business and on a basis no less advantageous than the basis on which such
Affiliate participates or (d) the Issuer or any Wholly-Owned Subsidiary from
engaging in any of the above listed activities with any other Wholly-Owned
Subsidiary or any Wholly-Owned Subsidiary with the Issuer.
<PAGE> 23
SECTION 5.12. Annual Coverage Ratio. (a) The Company will not
permit as of the last day of any fiscal quarter the Annual Coverage Ratio to be
less than 2.8:1. For this purpose:
(i) "Annual Coverage Ratio" means at any date the ratio of
Consolidated Cash Flow to Consolidated Interest Expense for the period
of four consecutive fiscal quarters ending on such date.
(ii) "Consolidated Cash Flow" means, for any period, the net
cash from operating activities of the Issuer and its Consolidated
Subsidiaries for such period, as the same is, or would in accordance
with generally accepted accounting principles be set forth in a
statement of cash flows for such period, plus to the extent deducted in
determining such net cash from operating activities, the sum of (x)
Consolidated Interest Expense for such period and (y) income tax
expense.
(iii) "Consolidated Interest Expense" means, for any period,
the interest expense of the Issuer and its Consolidated Subsidiaries
determined on a consolidated basis for such period in accordance with
generally accepted accounting principles.
(iv) "Consolidated Subsidiaries" means at any date any
Subsidiary or other entity the accounts of which would in accordance
with generally accepted accounting principles be consolidated with
those of the Issuer in its consolidated financial statements if such
statements were prepared as of such date.
SECTION 5.13. Consolidations, Mergers and Sales of Asset. (a)
Without limiting the applicability of Section 2.03(d), the Issuer will not
consolidate or merge with or into any other Person or sell, lease or otherwise
transfer, directly or indirectly, all or substantially all of its assets to any
other Person unless (i) immediately after giving effect to such consolidation,
merger, sale, lease or other transfer, no Default shall exist and the Issuer
would be in compliance with the provisions of Section 5.12 (assuming that the
date of any determination hereunder were the end of a fiscal quarter of the
Issuer), (ii) such Person shall be a corporation organized and existing under
the laws of the United States of America or any state therein or the District of
Columbia and (iii) all of the obligations of the Issuer under the Notes and this
Agreement shall have been expressly assumed in writing by the Person formed by
such consolidation, or into which the Issuer shall have been merged, or which
shall have acquired such assets.
(b) The Issuer will not, and will not permit any Subsidiary
to, make any Asset Disposition to any Person unless such Asset Disposition is
upon fair and reasonable terms no less favorable to the Issuer or such
Subsidiary than would obtain in a comparable arm's-length transaction with a
Person which is not an Affiliate; provided that, this Section 5.13(b) shall not
limit the transactions permitted with Affiliates provided under Section 5.11
hereof.
SECTION 5.14. Subsidiary Debt. The Issuer will not permit any
Subsidiary to incur, create, assume, guarantee or in any other manner become
liable with respect to, or extend the maturity of or become responsible for the
payment of any Debt other than (i) Debt owing to the Issuer or a Wholly-Owned
Subsidiary, (ii) Non-Recourse Debt in an aggregate principal amount (together
with any such Non-Recourse Debt incurred by the Issuer) not to exceed
$150,000,000 at any time incurred to finance the acquisition of assets, and
(iii) other Debt in an aggregate principal amount not to exceed 5% of the
Present Value of Proved Reserves as reflected in the most recent Reserve Report.
<PAGE> 24
SECTION 5.15. Sale and Leasebacks. The Issuer shall not, and
shall not permit any of its Subsidiaries to, enter into any arrangement with any
lender or investor (other than the Issuer or any Subsidiary of the Issuer) or to
which such lender or investor is a party providing for the leasing by the Issuer
or any of its Subsidiaries for a period of more than three years (including all
renewals and extensions) of real or personal property that has been or is to be
sold or transferred by the Issuer or any of its Subsidiaries to such lender or
investor or to any Person to whom funds have been or are to be advanced by such
lender or investor on the security of such property or rental obligations of the
Issuer or any of its Subsidiaries, unless the Issuer or such Subsidiary would be
entitled, pursuant to Section 5.10(f), to incur Debt in a principal amount equal
to or exceeding the Attributable Debt in respect of such arrangement, secured by
a Lien on the property to be leased, without any violation of Section 5.09 or
5.14.
ARTICLE VI
DEFAULTS
SECTION 6.01. Events of Default. If one or more of the
following events shall have occurred and be continuing:
(a) the Issuer shall fail to pay when due any principal on the
Notes or shall fail to pay within five Business Days of the due date
thereof any interest or other amount payable under any of the Notes or
this Agreement;
(b) the Issuer shall fail to observe or perform any covenant
or agreement contained in Section 5.14 for 10 days after it shall have
become aware of such failure;
(c) the Issuer shall fail to observe or perform any covenant
or agreement contained in Sections 5.04(a), 5.09, 5.10, 5.11, 5.12,
5.13 and 5.15;
(d) the Issuer shall fail to observe or perform any of its
covenants or agreements contained in any of the Notes or this Agreement
(other than those covered by clause (a), (b) or (c) above) for 30 days
after it shall have become aware of such failure;
(e) any representation, warranty, certification or statement
made by the Issuer in any of the Notes or this Agreement or in any
certificate, financial statement or other document delivered pursuant
to any of the Notes or this Agreement shall prove to have been
incorrect in any material respect when made;
(f) the Issuer or any Subsidiary shall fail to make any
payment in respect of any Material Debt (other than the Notes) when due
or within any applicable grace period and such default has not been
effectively waived by the holders of such Debt;
(g) any event or condition shall occur which, after the
expiration of any applicable grace period with respect thereto, results
in the acceleration of the maturity of any Material Debt (other than
the Notes) or enables the holder of such Debt or any Person acting on
such holder's behalf to accelerate the maturity thereof and such
default has not been effectively waived by the holders of such Debt
(provided, that prior to the expiration of such grace period, the
occurrence of such event or condition shall constitute a Default
hereunder);
<PAGE> 25
(h) the Issuer or any Subsidiary shall commence a voluntary
case or other proceeding seeking liquidation, reorganization or other
relief with respect to itself or its debts under any bankruptcy,
insolvency or other similar law now or hereafter in effect or seeking
the appointment of a trustee, receiver, liquidator, custodian or other
similar official of it or any substantial part of its property, or
shall consent to any such relief or to the appointment of or taking
possession by any such official in an involuntary case or other
proceeding commenced against it, or shall make a general assignment for
the benefit of creditors, or shall fail generally to pay its debts as
they become due, or shall take any corporate action to authorize any of
the foregoing;
(i) an involuntary case or other proceeding shall be commenced
against the Issuer or any Subsidiary seeking liquidation,
reorganization or other relief with respect to it or its debts under
any bankruptcy, insolvency or other similar law now or hereafter in
effect or seeking the appointment of a trustee, receiver, liquidator,
custodian or other similar official of it or any substantial part of
its property, and such involuntary case or other proceeding shall
remain undismissed and unstayed for a period of 60 days; or an order
for relief shall be entered against the Issuer or any Subsidiary under
the federal bankruptcy laws as now or hereafter in effect;
(j) any member of the ERISA Group shall fail to pay when due
an amount or amounts aggregating in excess of $1,000,000 which it shall
have become liable to pay under Title IV of ERISA which failure to pay
could cause the Issuer or any Subsidiary (whether directly or jointly
and severally with one or more affiliates) to incur a liability in
respect of such amount or amounts, except for any such failure which is
being contested in good faith through appropriate proceedings, so long
as such proceedings are diligently prosecuted and no Lien has been
imposed on any Property of the Issuer or any Subsidiary as a
consequence of such failure; or notice of intent to terminate a
Material Plan shall be filed under Title IV of ERISA by any member of
the ERISA Group, any plan administrator or any combination of the
foregoing; or the PBGC shall institute proceedings under Title IV of
ERISA to terminate, to impose liability (other than for premiums under
Section 4007 of ERISA) in respect of, or to cause a trustee to be
appointed to administer any Material Plan; or a condition shall exist
by reason of which the PBGC would be entitled to obtain a decree
adjudicating that any Material Plan must be terminated; or there shall
occur a complete or partial withdrawal from, or a default, within the
meaning of Section 4219(c)(5) of ERISA, with respect to, one or more
Multi-employer Plans which could cause the Issuer or any Subsidiary
(whether directly or indirectly or jointly and severally with one or
more affiliates) of the ERISA Group to incur a current payment
obligation in excess of $1,000,000; or
(k) a judgment or order for the payment of money in excess of
$5,000,000 shall be rendered against the Issuer or any Subsidiary and
such judgment or order shall continue unsatisfied and unstayed pending
appeal for a period of 30 days; then
(i) in the event of any Event of Default specified
in subsection (a) of this Section 6.01, each Holder may, by notice to the Issuer
declare the principal amount of all Notes held by such Holder (together with
accrued interest thereon) and, to the extent permitted under applicable law, the
Make Whole Amount with respect thereto and all other amounts payable by the
Issuer hereunder to such Holder to be, and such Notes and amounts shall
thereupon become, immediately due and payable without presentment, demand,
protest or other notice of any kind, all of which are hereby waived by the
Issuer;
<PAGE> 26
(ii) in the event of any Event of Default specified
in subsections (h)or (i) of this Section 6.01, without any notice to the Issuer
or any other act by any Holder or the Majority Lenders, the Notes (together with
accrued interest thereon and all other amounts payable by the Issuer hereunder)
and, to the extent permitted under applicable law, the Make Whole Amount with
respect thereto shall become immediately due and payable without presentment,
demand, protest, notice of intent to accelerate, notice of acceleration, or
other notice of any kind, all of which are hereby waived by the Issuer; and
(iii) in the event of any Event of Default specified
in any other subsection of this Section 6.01, the Majority Lenders may, by
notice to the Issuer, declare the Notes (together with accrued interest thereon)
and, to the extent permitted under applicable law, the Make Whole Amount with
respect thereto and all other amounts payable by the Issuer hereunder to be, and
such Notes and amounts shall thereupon become, immediately due and payable
without presentment, demand, protest or other notice of any kind, all of which
are hereby waived by the Issuer.
SECTION 6.02. Rescission of Acceleration. At any time after
the principal of, and interest accrued on and the Make Whole Amount on, any or
all of the Notes are declared due and payable, the Required Lenders, by written
notice to the Issuer, may rescind and annul any such declaration and its
consequences if (a) the Issuer has paid all overdue interest on the Notes, the
principal of and Make Whole Amount, if any, on any Notes which have become due
otherwise than by reason of such declaration, and interest on such overdue
principal and Make Whole Amount, (to the extent permitted by applicable law) any
overdue interest in respect of the Notes, (b) all Events of Default, other than
non-payment of amounts which have become due solely by reason of such
declaration, and all conditions and events which constitute a Default have been
cured or waived pursuant to Section 8.04, and (c) no judgment or decree has been
entered for the payment of any monies due pursuant to the Notes or this
Agreement; but no such rescission and annulment shall extend to or affect any
subsequent Default or Event of Default or impair any right consequent thereon.
ARTICLE VII
PURCHASE FOR INVESTMENT; SOURCE OF FUNDS
SECTION 7.01. Purchase for Investment. Each Purchaser
represents that it is purchasing Notes for its own account or for one or more
separate accounts maintained by it or for the account of one or more pension or
trust funds, in each case for investment and not with a view to the distribution
thereof or with any present intention of distributing or selling any of the
Notes, but subject to any requirement of law, the disposition of its or their
property shall at all times be within its or their control.
SECTION 7.02. Source of Funds. Each Purchaser represents that
at least one of the following statements is an accurate representation as to
each source of funds (a "Source") to be used by it to pay the purchase price of
the Notes purchased by it hereunder:
(a) the Source is an "insurance company general account" (as
the term is defined in Prohibited Transaction Exemption ("PTE") 95-60
(issued July 12, 1995)) in respect of which the reserves and
liabilities (as defined by the annual statement for life insurance
companies approved by the National Association of Insurance
Commissioners (the "NAIC Annual Statement")) for the general account
contract(s) held by or on behalf of any employee benefit plan together
with the amount of the reserves and liabilities for the general account
contract(s) held by or on behalf of any other employee benefit plans
maintained by the same employer
<PAGE> 27
(or affiliate thereof as defined in PTE 95-60) or by the same employee
organization in the general account do not exceed 10% of the total
reserves and liabilities of the general account (exclusive of separate
account liabilities) plus surplus as set forth in the NAIC Annual
Statement filed with such Purchaser's state of domicile; or
(b) the Source is a separate account that is maintained solely
in connection with such Purchaser's fixed contractual obligations under
which the amounts payable, or credited, to any employee benefit plan
(or its related trust) that has any interest in such separate account
(or to any participant or beneficiary of such plan (including any
annuitant)) are not affected in any manner by the investment
performance of the separate account; or
(c) the Source is either (i) an insurance company pooled
separate account, within the meaning of PTE 90-1 (issued January 29,
1990), or (ii) a bank collective investment fund, within the meaning of
the PTE 91-38 (issued July 12, 1991) and, except as disclosed by such
Purchaser to the Issuer in writing pursuant to this paragraph (c), no
employee benefit plan or group of plans maintained by the same employer
or employee organization beneficially owns more than 10% of all assets
allocated to such pooled separate account or collective investment
fund; or
(d) the Source constitutes assets of an "investment fund"
(within the meaning of Part V of the QPAM Exemption) managed by a
"qualified professional asset manager" or "QPAM" (within the meaning of
Part V of the QPAM Exemption), no employee benefit plan's assets that
are included in such investment fund, when combined with the assets of
all other employee benefit plans established or maintained by the same
employer or by an affiliate (within the meaning of Section V(c) of the
QPAM Exemption) of such employer or by the same employee organization
and managed by such QPAM, exceed 20% of the total client assets managed
by such QPAM, the conditions of Part I(c) and (g) of the QPAM Exemption
are satisfied, neither the QPAM nor a person controlling or controlled
by the QPAM (applying the definition of "control" in Section V(e) of
the QPAM Exemption) owns a 5% or more interest in the Issuer and (i)
the identity of such QPAM and (ii) the names of all employee benefit
plans whose assets are included in such investment fund have been
disclosed to the Issuer in writing pursuant to this paragraph (d); or
(e) the Source is a governmental plan; or
(f) the Source is one or more employee benefit plans, or a
separate account or trust fund comprised of one or more employee
benefit plans, each of which has been identified to the Issuer in
writing pursuant to this paragraph (f); or
(g) the Source does not include assets of any employee benefit
plan, other than a plan exempt from the coverage of ERISA.
As used in this Section 7.02, the terms "employee benefit plan", "governmental
plan", "party in interest" and "separate account" shall have the respective
meanings assigned to such terms in Section 3 of ERISA.
<PAGE> 28
SECTION 7.03. Securities Act; Legend. Each Purchaser
represents that it is an accredited investor (as defined in Regulation D of the
Rules and Regulations of the Securities and Exchange Commission under the
Securities Act of 1933, as amended) and that it understands the Notes have not
been registered under the Securities Act of 1933. Each Purchaser acknowledges
that upon issuance of the Notes, and until such time, if any, as the same is no
longer required under applicable securities laws, the Notes shall bear the
following legend:
THIS NOTE HAS NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF
1933, AS AMENDED, AND MAY NOT BE TRANSFERRED, SOLD OR
OTHERWISE DISPOSED OF EXCEPT WHILE REGISTRATION UNDER SAID ACT
IS IN EFFECT OR PURSUANT TO AN EXEMPTION FROM REGISTRATION
UNDER SAID ACT OR IF SAID ACT DOES NOT APPLY.
Any Holder of a Note may upon surrender of its Note to the
Issuer together with an opinion of counsel to the effect that the foregoing
legend is no longer required under applicable securities laws obtain a like Note
in exchange for its Note without such legend.
ARTICLE VIII
MISCELLANEOUS
SECTION 8.01. Notices. Unless otherwise specified herein, all
notices, requests and other communications to any party hereunder shall be in
writing (including bank wire, facsimile copy or similar writing) and shall be
given (i) if to the Issuer, at its address or facsimile number set forth on its
signature page hereto and to the attention of the Person therein specified, (ii)
if to any Purchaser, at the address or facsimile number specified for such
communication in Schedule A and to the Person therein specified, if any, or
(iii) if to any other Holder, at such address or facsimile number and to such
Person as such other Holder shall have specified to the Issuer in writing, or,
in any case, to such other address or facsimile number or to the attention of
such other Person as such party may hereafter specify for the purpose by notice
in the case of the Issuer to each Holder and in the case of any Holder to the
Issuer; provided, however, that no Holder shall be required to give notice to
any other Holder of any matter under this Agreement. Each such notice, request
or other communication shall be addressed to the attention of the Person
specified pursuant to this Section and shall be effective (i) if given by mail,
ten days after such communication is deposited in the mails with prepaid
certified mail, return receipt requested, addressed as aforesaid or (ii) if
given by courier, facsimile or any other means, when delivered to the Person
specified, if any, at the address or sent to the facsimile number specified
pursuant to this Section 8.01 with confirmation from the addressee of receipt.
SECTION 8.02. No Waiver. No failure or delay by any Holder in
exercising any right, power or privilege under any Note or this Agreement shall
operate as a waiver thereof nor shall any single or partial exercise thereof
preclude any other or further exercise thereof or the exercise of any other
right, power or privilege. The rights and remedies provided in the Notes or this
Agreement shall be cumulative and not exclusive of any rights or remedies
provided by law.
SECTION 8.03. Expenses; Documentary Taxes; Indemnification for
Litigation. (a) The Issuer shall pay on demand (i) all reasonable fees and
out-of-pocket expenses of the Purchasers and the Holders (including, without
limitation, reasonable fees and disbursements of the law firm acting as special
counsel for the Purchasers or the Holders and such local counsel as may be
retained on behalf of the Purchasers or the Holders) in connection with the
preparation, closing and administration of the Notes and this Agreement, any
waiver, consent or amendment of any provision thereof (whether
<PAGE> 29
or not any such waiver, consent or amendment becomes effective), or any Default
or alleged Default thereunder, and (ii) if any Event of Default occurs, all
reasonable out-of-pocket expenses incurred by any Holder, including reasonable
fees and disbursements of counsel and funding losses, in connection with such
Event of Default and collection and other enforcement proceedings resulting
therefrom. The Issuer agrees to indemnify each Holder from and hold it harmless
against any transfer taxes, documentary taxes, or other similar assessments or
charges made by any governmental authority by reason of the execution and
delivery of the Notes and this Agreement. The Issuer shall bear the costs of
obtaining a Private Placement Number for the Notes.
(b) The Issuer shall indemnify each Holder and hold each
Holder harmless from and against any and all liabilities, losses, damages, costs
and expenses of any kind (including, without limitation, the reasonable fees and
disbursements of counsel for any Holder in connection with any investigative,
administrative or judicial proceeding, whether or not such Holder shall be
designated a party thereto) which may be incurred by any Holder, relating to or
arising out of the Notes and this Agreement or any actual or proposed use of the
proceeds of the sale of the Notes hereunder, provided that no Holder shall have
the right to be indemnified hereunder for its own gross negligence or willful
misconduct as determined by a court of competent jurisdiction.
SECTION 8.04. Amendments and Waivers. (a) Any provision of
this Agreement or the Notes may be amended or waived if, and only if, such
amendment or waiver is in writing and is signed by the Issuer and the Required
Lenders; provided that no such amendment or waiver shall, unless signed by all
Holders of Outstanding Notes, (i) change the principal of or rate of interest on
any Note, the Make Whole Amount or any other amount payable hereunder, (ii)
waive or change the date fixed for any payment of principal of or interest on
any Note or the Make Whole Amount hereunder, or (iii) change the percentage of
Holders that shall be required for the Holders to take any action under this
Section or any other provision of this Agreement; and provided further that no
such amendment will change the principal amount of Notes to be purchased by any
Purchaser hereunder without the consent of such Purchaser.
(b) The Issuer will provide each Holder (irrespective of the
amount of Notes then owned by it) with sufficient information, sufficiently far
in advance of the date a decision is required, to enable such Holder to make an
informed and considered decision with respect to any proposed amendment, waiver
or consent in respect of any of the provisions hereof or of the Notes. The
Issuer will deliver executed or true and correct copies of each amendment,
waiver or consent effected pursuant to the provisions of this Section 8.04 to
each Holder promptly following the date on which it is executed and delivered
by, or receives the consent or approval of, the requisite Holders.
(c) The Issuer will not directly or indirectly pay or cause to
be paid any remuneration, whether by way of supplemental or additional interest,
fee or otherwise, or grant any security, to any Holder as consideration for or
as an inducement to the entering into by any Holder or any waiver or amendment
of any of the terms and provisions hereof unless such remuneration is
concurrently paid, or security is concurrently granted, on the same terms,
ratably to each Holder even if such Holder did not consent to such waiver or
amendment.
SECTION 8.05. New York Law. This Agreement and each Note shall
be construed in accordance with and governed by the law of the State of New
York.
SECTION 8.06. Successors and Assigns. This Agreement shall be
binding upon and inure to the benefit of the parties hereto and their respective
successors and assigns, except that the Issuer may not assign or transfer any of
its rights or obligations under this Agreement.
<PAGE> 30
SECTION 8.07. Form, Registration, Transfer and Exchange of the
Notes; Transferees. (a) The Notes issuable under this Agreement shall be
registered notes substantially in the form of Exhibit A hereto and shall be
issued in denominations of $1,000,000 and any larger multiple of $50,000 (except
as may otherwise be required as a result of prepayments of portions of Notes
pursuant to Section 2.03). The Issuer shall keep at its principal office a
register in which the Issuer shall provide for the registration of the transfers
of Notes. The Issuer's principal office for such purposes shall be maintained in
the continental United States and, until further notice, will be maintained at
the address specified pursuant to Section 8.01. Upon surrender of any Note at
such office for registration of transfer, the Issuer shall execute and deliver,
at its expense, one or more new Notes of a like aggregate unpaid principal
amount. Each such new Note shall be registered in the name of the designated
transferee or transferees (or its nominee or nominees). At the option of the
Holder of any Note such Note may be exchanged for other Notes of any authorized
denominations, of a like aggregate unpaid principal amount upon surrender of the
Note to be exchanged at the principal office of the Issuer. Whenever any Notes
are so surrendered for exchange, the Issuer shall execute and deliver, at its
expense, the Notes which the Holder thereof making the exchange is entitled to
receive. Every Note presented or surrendered for registration of transfer shall
be duly endorsed, or be accompanied by a written instrument of transfer duly
executed by the registered Holder or his attorney duly authorized in writing.
Any Note or Notes issued in exchange for any Note or upon transfer thereof shall
carry the rights to unpaid interest and interest to accrue which were carried by
the Note so exchanged or transferred, and neither gain nor loss of interest
shall result from any such transfer or exchange. Upon the written request of any
Holder, the Issuer shall promptly forward to such Holder the names and addresses
of all other Holders and the principal amount of Notes held by such Holders.
Upon receipt by the Issuer of evidence reasonably satisfactory to it of the
ownership of and loss, theft, destruction or mutilation of any Note and (i) in
case of loss, theft, or destruction, of indemnity reasonably satisfactory to it
(provided that, with respect to Institutional Investors and their nominees, such
Person's agreement of indemnity shall be deemed to be satisfactory) or (ii) in
the case of mutilation, upon surrender and cancellation thereof, the Issuer, at
its expense, will execute and deliver, in lieu thereof, a new Note of like tenor
and dated and bearing interest from the date to which interest has been paid on
such lost, stolen, destroyed or mutilated Note.
SECTION 8.08. Persons Deemed Owners. Prior to due presentment
for registration of transfer, the Issuer may treat the Person in whose name any
Note is registered as the owner and holder of such Note for the purpose of
receiving payment of principal of and interest and premium on such Note and for
all other purposes whatsoever, whether or not such Note is or shall be overdue,
and the Issuer shall not be affected by notice to the contrary.
SECTION 8.09. Home Office Payment. The Issuer agrees that, so
long as a Purchaser listed on the signature pages hereof or its nominee shall
hold any of the Notes, it will make payments of principal of and interest and
Make Whole Amounts (if any) on such Notes not later than 12:00 noon, New York
City time, on the date such payment is due, in immediately available funds, at
the address specified for such purpose on Schedule A or such other account or
address (in the United States of America) as such Purchaser may designate in
writing, notwithstanding any contrary provisions contained herein or in the
Notes and without any requirement of surrendering the Notes (except that, upon
the written request of the Issuer, any Note that has been paid or prepaid in
full shall be surrendered for cancellation to the Issuer at its principal office
maintained by the Issuer pursuant to Section 8.07). Each Purchaser agrees that,
before selling or otherwise transferring any Note, it will make a notation
thereon of all principal payments previously made thereon and of the date to
which interest thereon has been paid. As to any subsequent Holder, the Issuer
will make payments of principal of and interest on the Notes held by such Holder
not later than 12:00 noon, local time, to a place within the United States on
the date such payment is due, in immediately
<PAGE> 31
available funds, by credit to the account designated by such Holder or at the
option of such Holder by a check mailed or delivered to the address designated
by such Holder.
SECTION 8.10. Substitution. Each Purchaser may by notice to
the Issuer substitute any of its wholly-owned subsidiaries as a Purchaser
hereunder. Such notice shall be signed by such Purchaser and such wholly-owned
subsidiary, shall contain such wholly-owned subsidiary's agreement to be bound
by this Agreement and shall contain confirmation by such wholly-owned subsidiary
of the accuracy with respect to it of the representations set forth in Article
VII (subject to any exception necessary to reflect the intention, if any, of
such wholly-owned subsidiary to transfer to such Purchaser at a subsequent date
all or any of the Notes to be acquired by such wholly-owned subsidiary). The
Issuer agrees that, upon receipt of such notice, all references to "Purchaser"
hereunder (other than this Section 8.10) shall include a reference to such
wholly-owned subsidiary and that such wholly-owned subsidiary shall have the
right to transfer the Notes acquired by it hereunder to a Purchaser subsequent
to such purchase. In the event that a wholly-owned subsidiary is substituted for
a Purchaser in accordance with this Section 8.10 and thereafter transfers its
Notes or any portion thereof to such Purchaser, the term "Purchaser" shall be
deemed to refer to such wholly-owned subsidiary only if it retains any portion
of the Notes, and shall refer to such Purchaser to the extent such Purchaser
owns all or any portion of the Notes, and such Purchaser and such wholly-owned
subsidiary (if it retains any Notes) shall each have all the rights which an
original purchaser of Notes has under this Agreement.
SECTION 8.11. Credit Decision. Each Purchaser acknowledges
that it has, independently and without reliance upon any other Purchaser, and
based on such documents and information as it has deemed appropriate, made its
own credit analysis and decision to enter into this Agreement. Each Purchaser
also acknowledges that it will, independently and without reliance upon any
other Purchaser, and based on such documents and information as it shall deem
appropriate at the time, continue to make its own credit decisions in taking or
not taking any action under the Notes and this Agreement.
SECTION 8.12. Counterparts; Integration; Effectiveness;
Severability. (a) This Agreement may be signed in any number to counterparts,
each of which shall be an original, and all of which taken together shall
constitute a single agreement, with the same effect as if the signatures thereto
and hereto were upon the same instrument. This Agreement constitutes the entire
agreement and understanding among the parties hereto and supersedes any and all
prior agreements and understandings, oral or written, relating to the subject
matter hereof. This Agreement shall become effective when the Issuer shall have
received counterparts hereof signed by all of the parties hereto (or, in the
case of any Purchaser as to which an original executed counterpart shall not
have been received, the Issuer shall have received from such Purchaser an
executed counterpart hereof by facsimile by such Purchaser).
(b) In case any provision in this Agreement or any Note shall
be invalid, illegal or unenforceable, the validity, legality and enforceability
of the remaining provisions shall not in any way be affected or impaired thereby
and such provision shall be ineffective only to the extent of such invalidity,
illegality or unenforceability.
SECTION 8.13. SUBMISSION TO JURISDICTION. THE ISSUER HEREBY
SUBMITS TO THE NON-EXCLUSIVE JURISDICTION OF THE UNITED STATES DISTRICT COURT
FOR THE SOUTHERN DISTRICT OF NEW YORK AND OF ANY NEW YORK STATE COURT SITTING IN
THE CITY OF NEW YORK FOR PURPOSES OF ALL LEGAL PROCEEDINGS WHICH MAY ARISE
HEREUNDER OR UNDER THE NOTES. THE ISSUER IRREVOCABLY WAIVES TO THE FULLEST
EXTENT PERMITTED BY LAW,
<PAGE> 32
ANY OBJECTION WHICH IT MAY HAVE OR HEREAFTER HAVE TO THE LAYING OF THE VENUE OF
ANY SUCH PROCEEDINGS BROUGHT IN SUCH A COURT AND ANY CLAIM THAT ANY SUCH
PROCEEDING BROUGHT IN SUCH A COURT HAS BEEN BROUGHT IN AN INCONVENIENT FORUM.
THE ISSUER HEREBY CONSENTS TO PROCESS BEING SERVED IN ANY SUCH PROCEEDING BY THE
MAILING OF A COPY THEREOF BY REGISTERED OR CERTIFIED MAIL, POSTAGE PREPAID, TO
ITS ADDRESS SPECIFIED PURSUANT TO SECTION 8.01 OR IN ANY OTHER MANNER PERMITTED
BY LAW.
SECTION 8.14. Confidentiality. For the purposes of this
Section 8.14, "Confidential Information" means information delivered to a Holder
by or on behalf of the Issuer or any Subsidiary in connection with the
transactions contemplated by or otherwise pursuant to this Agreement that is
proprietary in nature and that was clearly marked or labeled or otherwise
adequately identified when received by such Holder as being confidential
information of the Issuer or such Subsidiary, provided that such term does not
include information that (a) was publicly known or otherwise known to such
Holder prior to the time of such disclosure, (b) subsequently becomes publicly
known through no act or omission by such Holder or any person acting on its
behalf, (c) otherwise becomes known to such Holder other than through disclosure
by the Issuer or any Subsidiary or (d) constitutes financial statements
delivered to such Holder under Section 5.01 that are otherwise publicly
available. Each Holder will maintain the confidentiality of such Confidential
Information in accordance with procedures adopted by such Holder in good faith
to protect confidential information of third parties delivered to it, provided
that such Holder may deliver or disclose Confidential Information to (i) its
directors, trustees, officers, employees, agents, attorneys and affiliates (to
the extent such disclosure reasonably relates to the administration of the
investment represented by Notes held by it), (ii) its financial advisors and
other professional advisors who agree to hold confidential the Confidential
Information substantially in accordance with the terms of this Section 8.14,
(iii) any other holder of any Note, (iv) any Institutional Investor to which
such Holder sells or offers to sell such Note or any part thereof or any
participation therein (if such Person has agreed in writing prior to its receipt
of such Confidential Information to be bound by the provisions of this Section
8.14), (v) any federal or state regulatory authority having jurisdiction over
such Holder, (vi) the National Association of Insurance Commissioners or any
similar organization, or any nationally recognized rating agency that requires
access to information about such Holder's investment portfolio, or (vii) any
other Person to which such delivery or disclosure may be necessary or
appropriate (w) to effect compliance with any law, rule, regulation or order
applicable to such Holder, (x) in response to any subpoena or other legal
process, (y) in connection with any litigation to which such Holder is a party
or (z) if an Event of Default has occurred and is continuing, to the extent such
Holder may reasonably determine such delivery and disclosure to be necessary or
appropriate in the enforcement or for the protection of the rights and remedies
under its Notes and this Agreement. Each holder of a Note, by its acceptance of
a Note, will be deemed to have agreed to be bound by and to be entitled to the
benefits of this Section 8.14 as though it were a party to this Agreement. On
reasonable request by the Issuer in connection with the delivery to any holder
of a Note of information required to be delivered to such holder under this
Agreement or requested by such holder (other than a holder that is a party to
this Agreement or its nominee), such holder will enter into an agreement with
the Issuer embodying the provisions of this Section 8.14.
<PAGE> 33
IN WITNESS WHEREOF, the parties hereto have caused this
Agreement to be duly executed by their respective authorized officers as of the
date first above written.
CABOT OIL & GAS CORPORATION
By /s/ Edgar J. Milan
------------------------------
Title: Chief Financial Officer
15375 Memorial Drive
Houston, Texas 77079
Attention: Treasurer
Telecopier: (281) 589-4653
<PAGE> 34
PURCHASERS:
THE NORTHWESTERN MUTUAL
LIFE INSURANCE COMPANY
By: /s/Richard A. Strait
--------------------------------
Title: Vice President
THE GUARDIAN LIFE INSURANCE
COMPANY OF AMERICA
By: /s/Thomas M. Donohue
--------------------------------
Title: Vice President-Fixed Income
GREAT-WEST LIFE & ANNUITY
INSURANCE COMPANY
By: /s/ James G. Lowery
--------------------------------
Title: Assistant Vice President-
Investments
By: /s/ Julie Bock
--------------------------------
Title: Assistant Vice President
PACIFIC LIFE INSURANCE COMPANY
By: /s/ Diane W. Oales
--------------------------------
Title: Assistant Vice President
By: /s/ Peter S. Fiek
--------------------------------
Title: Assistant Secretary
KEYPORT LIFE INSURANCE COMPANY
by Stein Roe & Farnham
Incorporated, as agent
By: /s/ Richard A. Hedgwood
--------------------------------
Title: Senior Vice President
TRANSAMERICA LIFE INSURANCE AND
ANNUITY COMPANY
By: /s/ John M. Casparian
---------------------
Title: Investment Officer
<PAGE> 35
EXHIBIT A
[FORM OF NOTE]
[Add Legend as Appropriate]
CABOT OIL & GAS CORPORATION
7.19% NOTE DUE 2009
No. [_____] [Date]
$[________] PPN 127097 A@ 2
FOR VALUE RECEIVED, the undersigned, CABOT OIL & GAS
CORPORATION (herein called the "Issuer"), a corporation organized and existing
under the laws of the State of Delaware, hereby promises to pay to
[___________________________], or registered assigns, the principal sum of
[___________________________] DOLLARS on November 15, 2009, with interest
(computed on the basis of a 360-day year of twelve 30-day months) (a) on the
unpaid balance thereof at the rate of 7.19% per annum from the date hereof,
payable semiannually, on the 15th day of May and November in each year,
commencing May 15, 1998, until the principal hereof shall have become due and
payable, and (b) to the extent permitted by law on any overdue payment
(including any overdue prepayment) of principal, any overdue payment of interest
and any overdue payment of any Make Whole Amount (as defined in the Note
Purchase Agreement referred to below), payable semiannually as aforesaid (or, at
the option of the registered holder hereof, on demand), at a rate per annum from
time to time equal to the higher of (i) 9.19% or (ii) the Prime Rate (as defined
in said Note Purchase Agreement) for such day plus 2%.
Payments of principal of, interest on and any Make Whole
Amount with respect to this Note are to be made in lawful money of the United
States of America as provided in Section 8.09 of the Note Purchase Agreement
referred to below.
This Note is one of a series of Notes (herein called the
"Notes") issued pursuant to the Note Purchase Agreement, dated as of November
14, 1997 (as from time to time amended, the "Note Purchase Agreement"), between
the Issuer and the Purchasers named therein and is entitled to the benefits
thereof. Each holder of this Note will be deemed, by its acceptance hereof, (i)
to have agreed to the confidentiality provisions set forth in Section 8.14 of
the Note Purchase Agreement and (ii) to have made the representation set forth
in Article VII of the Note Purchase Agreement.
This Note is a registered Note and, as provided in the Note
Purchase Agreement, upon surrender of this Note for registration of transfer,
duly endorsed, or accompanied by a written instrument of transfer duly executed,
by the registered holder hereof or such holder's attorney duly authorized in
writing, a new Note for a like principal amount will be issued to, and
registered in the name of, the transferee. Prior to due presentment for
registration of transfer, the Issuer may treat the person in whose name this
Note is registered as the owner hereof for the purpose of receiving payment and
for all other purposes, and the Issuer will not be affected by any notice to the
contrary.
The Issuer will make required prepayments of principal on the
dates and in the amounts specified in the Note Purchase Agreement. This Note is
also subject to optional prepayment, in whole or from time to time in part, at
the times and on the terms specified in the Note Purchase Agreement, but not
otherwise.
<PAGE> 36
If an Event of Default, as defined in the Note Purchase
Agreement, occurs and is continuing, the principal of this Note may be declared
or otherwise become due and payable in the manner, at the price (including any
applicable Make Whole Amount) and with the effect provided in the Note Purchase
Agreement.
This Note shall be construed in accordance with and governed
by the law of the State of New York.
CABOT OIL & GAS CORPORATION
By
------------------------------
Title:
<PAGE> 1
Exhibit 10.18
CABOT OIL & GAS CORPORATION
AGREEMENT
This Agreement, made and entered into this 23rd day of August, 1994,
("Agreement"), by and between CABOT OIL & GAS CORPORATION, a Delaware
corporation ("Company"), and ("Indemnitee"):
WHEREAS, highly competent persons are becoming more reluctant to
continue to serve publicly-held corporations as directors or in other capacities
unless they are provided with adequate protection through insurance or adequate
indemnification against inordinate risks of claims and actions against them
arising out of their service to and activities on behalf of the corporation;
WHEREAS, it is reasonable, prudent and necessary for the Company
contractually to obligate itself to indemnify such persons to the fullest extent
permitted by applicable law so that they will serve or continue to serve the
Company free from undue concern that they will not be so indemnified; and
WHEREAS, Indemnitee is willing to serve, continue to serve and to take
on additional service for or on behalf of the Company on the condition that he
be so indemnified;
NOW THEREFORE, in consideration of the premises and the covenants
contained herein, the Company and Indemnitee do hereby covenant and agree as
follows:
Section 1. Services by Indemnitee. Indemnitee agrees to serve at the
request of the Company as a director, officer or employee. Indemnitee may at any
time and for any reason resign from such position (subject to any other
contractual obligation or any obligation imposed by operation of law), in which
event the Company shall have no obligation under this Agreement to continue
Indemnitee in any such position.
Section 2. Indemnification - General. The Company shall indemnify, and
advance Expenses (as hereinafter defined), to Indemnitee as provided in this
Agreement and to the fullest extent permitted by applicable law in effect on the
date hereof and to such greater extent as applicable law may thereafter from
time to time permit. The rights of Indemnitee provided under the preceding
sentence shall include, but shall not be limited to, the rights set forth in the
other Sections of this Agreement.
-1-
<PAGE> 2
Section 3. Proceedings Other Than Proceedings by or in the Right of the
Company. Indemnitee shall be entitled to the rights of indemnification provided
in this Section 3 if, by reason of his Corporate Status (as hereinafter
defined), he is, or is threatened to be made, a party to any threatened,
pending, or completed Proceeding (as hereinafter defined), other than a
Proceeding by or in the right of the Company. Pursuant to this Section 3,
Indemnitee shall be indemnified against Expenses, judgments, penalties, fines
and amounts paid in settlement actually and reasonably incurred by him or on his
behalf in connection with such Proceeding or any claim, issue or matter therein,
if he acted in good faith and in a manner he reasonably believed to be in or not
opposed to the best interests of the Company, and, with respect to any criminal
Proceeding, had no reasonable cause to believe his conduct was unlawful.
Section 4. Proceedings by or in the Right of the Company. Indemnitee
shall be entitled to the rights of indemnification provided in this Section 4
if, by reason of his Corporate Status, he is, or is threatened to be made, a
party to any threatened, pending or completed Proceeding brought by or in the
right of the Company to procure a judgment in its favor. Pursuant to this
Section, Indemnitee shall be indemnified against Expenses actually and
reasonably incurred by him or on his behalf in connection with such Proceeding
if he acted in good faith and in a manner he reasonably believed to be in or not
opposed to the best interests of the Company. Notwithstanding the foregoing, no
indemnification against such Expenses shall be made in respect of any claim,
issue or matter in such Proceeding as to which Indemnitee shall have been
adjudged to be liable to the Company if applicable law prohibits such
indemnification; provided, however, that if applicable law so permits,
indemnification against Expenses shall nevertheless be made by the Company in
such event if and only to the extent that the Court of Chancery of the State of
Delaware, or the court in which such Proceeding shall have been brought or is
pending, shall determine.
Section 5. Indemnification for Expenses of a Party Who is Wholly or
Partly Successful. Notwithstanding any other provision of this Agreement, to the
extent that Indemnitee is, by reason of his Corporate Status, a party to and is
successful, on the merits or otherwise, in any Proceeding, he shall be
indemnified against all Expenses actually and reasonably incurred by him or on
his behalf in connection therewith. If otherwise, as to one or more but less
than all claims, issues or matters in such Proceeding, the Company shall
indemnify Indemnitee against all Expenses actually and reasonably incurred by
him or on his behalf in connection with each successfully resolved claim, issue
or matter. For purposes of this Section and without limitation, the termination
of any claim, issue or matter in such a Proceeding by dismissal, with or without
prejudice, shall be deemed to be a successful result as to such claim, issue or
matter.
Section 6. Indemnification for Expenses of a Witness. Notwithstanding
any other provision of this Agreement, to the extent that Indemnitee is, by
reason of his Corporate Status, a witness in any Proceeding, he shall be
indemnified against all Expenses actually and reasonably incurred by him or on
his behalf in connection therewith.
-2-
<PAGE> 3
Section 7. Advancement of Expenses. The Company shall advance all
reasonable Expenses incurred by or on behalf of Indemnitee in connection with
any Proceeding within twenty days after the receipt by the Company of a
statement or statements from Indemnitee requesting such advance or advances from
time to time, whether prior to or after final disposition of such Proceeding.
Such statement or statements shall reasonably evidence the Expenses incurred by
Indemnitee and shall include or be preceded or accompanied by an undertaking by
or on behalf of Indemnitee to repay any Expenses advanced if it shall ultimately
be determined that Indemnitee is not entitled to be indemnified against such
Expenses.
Section 8. Procedure for Determination of Entitlement to
Indemnification.
(a) To obtain indemnification under this Agreement, Indemnitee
shall submit to the Company a written request, including therein or therewith
such documentation and information as is reasonably available to Indemnitee and
is reasonably necessary to determine whether and to what extent Indemnitee is
entitled to indemnification. The Secretary of the Company shall, promptly upon
receipt of such a request for indemnification, advise the Board of Directors in
writing that Indemnitee has requested indemnification.
(b) Upon written request by Indemnitee for indemnification
pursuant to the first sentence of Section 8(a) hereof, a determination, if
required by applicable law, with respect to Indemnitee's entitlement thereto
shall be made in the specific case: (i) if a Change in Control (as hereinafter
defined) shall have occurred, by Independent Counsel (as hereinafter defined)
(unless Indemnitee shall request that such determination be made by the Board of
Directors or the stockholders, in which case by the person or persons or in the
manner provided for in clauses (ii) or (iii) of this Section 8(b)) in a written
opinion to the Board of Directors, a copy of which shall be delivered to
Indemnitee; (ii) if a Change of Control shall not have occurred, (A) by the
Board of Directors by a majority vote of a quorum consisting of Disinterested
Directors (as hereinafter defined), or (B) if a quorum of the Board of Directors
consisting of Disinterested Directors so directs, by Independent Counsel in a
written opinion to the Board of Directors, a copy of which shall be delivered to
Indemnitee or (C) if so directed by the Board of Directors, by the stockholders
of the Company; or (iii) as provided in Section 9(b) of this Agreement; and, if
it is so determined that Indemnitee is entitled to indemnification, payment to
Indemnitee shall be made within ten (10) days after such determination.
Indemnitee shall cooperate with the person, persons or entity making such
determination with respect to Indemnitee's entitlement to indemnification,
including providing to such person, persons or entity upon reasonable advance
request any documentation or information which is not privileged or otherwise
protected from disclosure and which is reasonably available to Indemnitee and
reasonably necessary to such determination. Any costs or expenses (including
attorneys, fees and disbursements) incurred by Indemnitee in so cooperating with
the person, persons or entity making such determination shall be borne by the
Company (irrespective of the determination as to Indemnitee's entitlement to
indemnification) and the Company hereby indemnifies and agrees to hold
Indemnitee harmless therefrom.
-3-
<PAGE> 4
(c) In the event the determination of entitlement to
indemnification is to be made by Independent Counsel pursuant to Section 8(b)
hereof, the Independent Counsel shall be selected as provided in this Section
8(c). If a Change of Control shall not have occurred, the Independent Counsel
shall be selected by the Board of Directors, and the Company shall give written
notice to Indemnitee advising him of the identity of the Independent Counsel so
selected. If a Change of Control shall have occurred, the Independent Counsel
shall be selected by Indemnitee (unless Indemnitee shall request that such
selection be made by the Board of Directors, in which event the preceding
sentence shall apply), and Indemnitee shall give written notice to the Company
advising it of the identity of the Independent Counsel so selected. In either
event, Indemnitee or the Company, as the case may be, may, within 7 days after
such written notice of selection shall have been given, deliver to the Company
or to Indemnitee, as the case may be, a written objection to such selection.
Such objection may be asserted only on the ground that the Independent Counsel
so selected does not meet the requirements of "Independent Counsel" as defined
in Section 17 of this Agreement, and the objection shall set forth with
particularity the factual basis of such assertion. If such written objection is
made, the Independent Counsel so selected may not serve as Independent Counsel
unless and until a court has determined that such objection is without merit.
If, within 20 days after submission by Indemnitee of a written request for
indemnification pursuant to Section 8(a) hereof, no Independent Counsel shall
have been selected and not objected to, either the Company or Indemnitee may
petition the Court of Chancery of the State of Delaware or other court of
competent jurisdiction for resolution of any objection which shall have been
made by the Company or Indemnitee to the other's selection of Independent
Counsel and/or for the appointment as Independent Counsel of a person selected
by the Court or by such other person as the Court shall designate, and the
person with respect to whom an objection is so resolved or the person so
appointed shall act as Independent Counsel under Section 8(b) hereof. The
Company shall pay any and all reasonable fees and expenses of Independent
Counsel incurred by such Independent Counsel in connection with acting pursuant
to Section 8(b) hereof, and the Company shall pay all reasonable fees and
expenses incident to the procedures of this Section 8(c), regardless of the
manner in which such Independent Counsel was selected or appointed. Upon the due
commencement of any judicial proceeding or arbitration pursuant to Section
10(a)(iii) of this Agreement, Independent Counsel shall be discharged and
relieved of any further responsibility in such capacity (such to the applicable
standards of professional conduct then prevailing).
-4-
<PAGE> 5
Section 9. Presumptions and Effect of Certain Proceedings.
(a) If a Change of Control shall have occurred, in making a
determination with respect to entitlement to indemnification hereunder, the
person or persons or entity making such determination shall presume that
Indemnitee is entitled to indemnification under this Agreement if Indemnitee has
submitted a request for indemnification in accordance with Section 8(a) of this
Agreement, and the Company shall have the burden of proof to overcome that
presumption in connection with the making by any person, persons or entity of
any determination contrary to that presumption.
(b) If the person, persons or entity empowered or selected
under Section 8 of this Agreement to determine whether Indemnitee is entitled to
indemnification shall not have made a determination within 60 days after receipt
by the Company of the request therefor, the requisite determination of
entitlement to indemnification shall be deemed to have been made and Indemnitee
shall be entitled to such indemnification, absent (i) a misstatement by
Indemnitee of a material fact, or an omission of a material fact necessary to
make Indemnitee's statement not materially misleading, in connection with the
request for indemnification, or (ii) a prohibition of such indemnification under
applicable law; provided, however, that such 60-day period may be extended for a
reasonable time, not to exceed an additional 30 days, if the person, persons or
entity making the determination with respect to entitlement to indemnification
in good faith requires such additional time for the obtaining or evaluating of
documentation and/or information relating thereto; and provided, further, that
the foregoing provisions of this Section 9(b) shall not apply (i) if the
determination of entitlement to indemnification is to be made by the
stockholders pursuant to Section 8(b) of this Agreement and if (A) within 15
days after receipt by the Company of the request for such determination the
Board of Directors has resolved to submit such determination to the stockholders
for their consideration at an annual meeting thereof to be held within 75 days
after such receipt and such determination is made thereat, or (B) a special
meeting of stockholders is called within 15 days after such receipt for the
purpose of making such determination, such meeting is held for such purpose
within 60 days after having been so called and such determination is made
thereat, or (ii) if the determination of entitlement to indemnification is to be
made by Independent Counsel pursuant to Section 8(b) of this Agreement.
(c) The termination of any Proceeding or of any claim, issue
or matter therein, by judgment, order, settlement or conviction, or upon a plea
of nolo contendere or its equivalent, shall not (except as otherwise expressly
provided in this Agreement) of itself adversely affect the right of Indemnitee
to indemnification or create a presumption that Indemnitee did not act in good
faith and in a manner which he reasonably believed to be in or not opposed to
the best interests of the Company or, with respect to any criminal Proceeding,
that Indemnitee had reasonable cause to believe that his conduct was unlawful.
-5-
<PAGE> 6
Section 10. Remedies of Indemnitee.
(a) In the event that (i) a determination is made pursuant to
Section 8 of this Agreement that Indemnitee is not entitled to indemnification
under this Agreement, (ii) advancement of Expenses is not timely made pursuant
to Section 7 of this Agreement, (iii) the determination of entitlement to
indemnification is to be made by Independent Counsel pursuant to Section 8(b) of
this Agreement and such determination shall not have been made and delivered in
a written opinion within 90 days after receipt by the Company of the request for
indemnification, or (iv) payment of indemnification is not made pursuant to
Section 6 of this Agreement within ten (10) days after receipt by the Company of
a written request therefor, or (v) payment of indemnification is not made within
ten (10) days after a determination has been made that Indemnitee is entitled to
indemnification or such determination is deemed to have been made pursuant to
Section 8 or 9 of this Agreement, Indemnitee shall be entitled to an
adjudication in an appropriate court of the State of Delaware, or in any other
court of competent jurisdiction, of his entitlement to such indemnification or
advancement of Expenses. Alternatively, Indemnitee, at his option, may seek an
award in arbitration to be conducted by a single arbitrator pursuant to the
rules of the American Arbitration Association. Indemnitee shall commence such
proceeding seeking an adjudication or an award in arbitration within 180 days
following the date on which Indemnitee first has the right to commence such
proceeding pursuant to this Section 10(a); provided, however, that the foregoing
clause shall not apply in respect of a proceeding brought by an Indemnitee to
enforce his rights under Section 5 of the Agreement.
(b) In the event that a determination shall have been made
pursuant to Section 8 of this Agreement that Indemnitee is not entitled to
indemnification, any judicial proceeding or arbitration commenced pursuant to
this Section 10 shall be conducted in all respects as a de novo trial, or
arbitration, on the merits and Indemnitee shall not be prejudiced by reason of
that adverse determination. If a Change of Control shall have occurred, in any
judicial proceeding or arbitration commenced pursuant to this Section 10 the
Company shall have the burden of proving that Indemnitee is not entitled to
indemnification or advancement of Expenses, as the case may be.
(c) If a determination shall have been made or deemed to have
been made pursuant to Section 8 or 9 of this Agreement that Indemnitee is
entitled to indemnification, the Company shall be bound by such determination in
any judicial proceeding or arbitration commenced pursuant to this Section 10,
absent (i) a misstatement by Indemnitee of a material fact, or an omission of a
material fact necessary to make Indemnitee's statement not materially
misleading, in connection with the request for indemnification, or (ii) a
prohibition of such indemnification under applicable law.
-6-
<PAGE> 7
(d) The Company shall be precluded from asserting in any
judicial proceeding or arbitration commenced pursuant to this Section 10 that
the procedures and presumptions of this Agreement are not valid, binding and
enforceable and shall stipulate in any such court or before any such arbitrator
that the Company is bound by all the provisions of this Agreement.
(e) In the event that Indemnitee, pursuant to this Section 10,
seeks a judicial adjudication of an award in arbitration to enforce his rights
under, or to recover damages for breach of, this Agreement, Indemnitee shall be
entitled to recover from the Company, and shall be indemnified by the Company
against, any and all expenses (of the types described in the definition of
Expenses in Section 17 of this Agreement) actually and reasonably incurred by
him in such judicial adjudication or arbitration, but only if he prevails
therein. If it shall be determined in said judicial adjudication or arbitration
that Indemnitee is entitled to receive part but not all of the indemnification
or advancement of expenses sought, the expenses incurred by Indemnitee in
connection with such judicial adjudication or arbitration shall be appropriately
prorated.
Section 11. Non-Exclusivity; Survival of Rights; Insurance;
Subrogation.
(a) The rights of indemnification and to receive advancement
of Expenses as provided by this Agreement shall not be deemed exclusive of any
other rights to which Indemnitee may at any time be entitled under applicable
law, the Certificate of Incorporation, the By-Laws, any agreement, a vote of
stockholders or a resolution of directors, or otherwise. No amendment,
alteration or repeal of this Agreement or any provision hereof shall be
effective as to any Indemnitee with respect to any action taken or omitted by
such Indemnitee in his Corporate Status prior to such amendment, alteration or
repeal.
(b) To the extent that the Company maintains an insurance
policy or policies providing liability insurance for directors, officers or
employees of the Company or of any other corporation, partnership, joint
venture, trust employee benefit plan or other enterprise which such person
serves at the request of the Company, Indemnitee shall be covered by such policy
or policies in accordance with its or their terms to the maximum extent of the
coverage available for any such director, officer, employee or agent under such
policy or policies.
(c) In the event of any payment under this Agreement, the
Company shall be subrogated to the extent of such payment to all of the rights
of recovery of Indemnitee, who shall execute all papers required and take all
action necessary to secure such rights, including execution of such documents as
are necessary to enable the Company to bring suit to enforce such rights.
-7-
<PAGE> 8
(d) The Company shall not be liable under this Agreement to
make any payment of amounts otherwise indemnifiable hereunder if and to the
extent that Indemnitee has otherwise actually received such payment under any
insurance policy, contract, agreement or otherwise.
Section 12. Duration of Agreement. This Agreement shall continue for so
long as the Indemnitee may have any liability or potential liability by virtue
of serving as a director, officer or employee of the Company or of any other
corporation, partnership, joint venture, trust, employee benefit plan or other
enterprise which Indemnitee served at the request of the Company, including
without limitation, the final termination of all pending Proceedings in respect
of which Indemnitee is granted rights of indemnification or advancement of
expenses hereunder and of any proceeding commenced by Indemnitee pursuant to
Section 10 of this Agreement relating thereto. This Agreement shall be binding
upon the Company and its successors and assigns and shall insure to the benefit
of Indemnitee and his heirs, executors and administrators.
Section 13. Severability. If any provision or provisions of this
Agreement shall be held to be invalid, illegal or unenforceable for any reason
whatsoever: (a) the validity, legality and enforceability of the remaining
provisions of this agreement (including without limitation, each portion of any
Section of this Agreement containing any such provision held to be invalid,
illegal or unenforceable) shall not in any way be affected or impaired thereby;
and (b) to the fullest extent possible, the provisions of this Agreement
(including, without limitation, each portion of any Section of this Agreement
containing any such provision held to be invalid, illegal or unenforceable, that
is not itself invalid, illegal or unenforceable) shall be construed so as to
give effect to the intent manifested by the provision held invalid, illegal or
unenforceable.
Section 14. Exception to Right of Indemnification or Advancement of
Expenses. Notwithstanding any other provision of this Agreement, Indemnitee
shall not be entitled to indemnification or advancement of Expenses under this
Agreement with respect to any Proceeding, or any claim therein, brought or made
by him against the Company except for any claim or proceeding or in respect of
this Agreement and/or the Indemnitee's rights hereunder.
Section 15. Identical Counterparts. This Agreement may be executed in
one or more counterparts, each of which shall for all purposes be deemed to be
an original but all of which together shall constitute one and the same
Agreement. Only one such counterpart signed by the party against whom
enforceability is sought needs to be produced to evidence the existence of this
Agreement.
Section 16. Headings. The headings of the paragraphs of this Agreement
are inserted for convenience only and shall not be deemed to constitute part of
this Agreement or to affect the construction thereof.
-8-
<PAGE> 9
Section 17. Definitions. For purposes of this Agreement:
(a) "Change in Control" means a change in control of the
Company occurring after the Effective Date of a nature that would be required to
be reported in response to Item 6(e) of Schedule 14A of Regulation 14A (or in
response to any similar item on any similar schedule or form) promulgated under
the Securities Exchange Act of 1934 (the "Act"), whether or not the Company is
then subject to such reporting requirement; provided, however, that, without
limitation, such a Change in Control shall be deemed to have occurred if after
the Effective Date (i) any "person" (as such term is used in Section 13(d) and
14(d) of the Act) is or becomes the "beneficial owner" (as defined in Rule 13d-3
under the Act), directly or indirectly, of securities of the Company
representing 20% or more of the combined voting power of the Company's then
outstanding securities entitled to vote generally in the election of directors
without the prior approval of at least two-thirds of the members of the Board of
Directors in office immediately prior to such person attaining such percentage
interest; (ii) the Company is a party to a merger, consolidation, sale of assets
or other reorganization, or a proxy contest, as a consequence of which members
of the Board of Directors in office immediately prior to such transaction or
event constitute less than a majority of the Board of Directors thereafter; or
(iii) during any period of two consecutive years, individuals who at the
beginning of such period constituted the Board of Directors (including for this
purpose any new director whose election or nomination for election by the
Company's stockholders was approved by a vote of at least two-thirds of the
directors then still in office who were directors at the beginning of such
period) cease for any reason to constitute at least a majority of the Board of
Directors.
(b) "Corporate Status" describes the status of a person who is
or was a director, officer or employee of the Company or of any other
corporation, partnership, joint venture, trust, employee benefit plan or other
enterprise which such person is or was serving at the request of the Company.
(c) "Disinterested Director" means a director of the Company
who is not and was not a party to the Proceeding in respect of which
indemnification is sought by Indemnitee.
(d) "Effective Date" means August 5, 1994.
(e) "Expenses" shall include all reasonable attorneys fees,
retainers, court costs, transcript costs, fees of experts, witness fees, travel
expenses, duplicating costs, printing and binding costs, telephone charges,
postage, delivery service fees, and all other disbursements or expenses of the
types customarily incurred in connection with prosecuting, defending, preparing
to prosecute or defined, investigating, or being or preparing to be a witness in
a Proceeding.
-9-
<PAGE> 10
(f) "Independent Counsel" means a law firm, or a member of a
law firm, that is experience in matters of corporation law and neither presently
is, nor in the past five years has been, retained to represent: (i) the Company
or Indemnitee in any matter material to either such party, or (ii) any other
party to the Proceeding giving rise to a claim for indemnification hereunder.
Notwithstanding the foregoing, the term "Independent Counsel" shall not include
any person who, under the applicable standards of professional conduct then
prevailing, would have a conflict of interest in representing either the Company
or Indemnitee in an action to determine Indemnitee's rights under this
Agreement.
(g) "Proceeding" includes any action, suit, arbitration,
alternate dispute resolution mechanism, investigation, administrative hearing or
any other proceeding whether civil, criminal, administrative or investigative.
Section 18. Modification and Waiver. No supplement, modification or
amendment of this Agreement shall be binding unless executed in writing by both
of the parties hereto. No waiver of any of the provisions of this Agreement
shall be deemed or shall constitute a wavier of any other provisions hereof
(whether or not similar) nor shall such waiver constitute a continuing waiver.
Section 19. Notice by Indemnitee. Indemnitee agrees promptly to notify
the Company in writing upon being served with any summons, citation, subpoena,
complaint, indictment, information or other document relating to any Proceeding
or matter which may be subject to indemnification or advancement of Expenses
covered hereunder.
Section 20. Notices. All notices, requests, demands and other
communications hereunder shall be in writing and shall be deemed and shall be
deemed to have been duly given if (i) delivered by hand and receipted for by the
party to whom said notice or other communication shall have been directed, or
(ii) mailed by certified or registered mail with postage prepaid, on the third
business day after the date on which it is so mailed:
(a) If to Indemnitee, to:
15375 Memorial Drive
Houston, Texas 77079
(b) If to the Company to:
15375 Memorial Drive
Houston, Texas 77079
or to such other address as may have been furnished to Indemnitee by the Company
or to the Company by Indemnitee, as the case may be.
-10-
<PAGE> 11
Section 21. Governing Law. The parties agree that this Agreement
shall be governed by, and construed and enforced in accordance with, the laws of
the State of Delaware.
Section 22. Miscellaneous. Use of the masculine pronoun shall be
deemed to include usage of the feminine pronoun where appropriate.
IN WITNESS WHEREOF, the parties hereto have executed this Agreement on
the day and year first above written.
ATTEST: CABOT OIL & GAS CORPORATION
By: By:
------------------------ ---------------------------
INDEMNITEE
------------------------------
Address:
------------------------------
------------------------------
------------------------------
-11-
<PAGE> 1
Exhibit 21.1
SUBSIDIARIES OF CABOT OIL & GAS CORPORATION
Big Sandy Gas Company
Cabot Oil & Gas Marketing Corporation *
Cabot Oil & Gas U.K. Limited
Cabot Petroleum North Sea, Ltd.
Cranberry Pipeline Corporation *
Franklin Brine Treatment Corporation
* Denotes significant subsidiary.
<PAGE> 1
Exhibit 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration statement of
Cabot Oil & Gas Corporation on Form S-8 filed on June 23, 1991 and on October
29, 1993 of our report dated March 6, 1998, on our audits of the consolidated
financial statements of Cabot Oil & Gas Corporation as of December 31, 1997,
which report in included in this Annual Report on Form 10-K.
Our report refers to a change in 1995 in the method of applying the
unit-of-production method to calculate depreciation and depletion on producing
oil & gas properties, and accounting for the impairment of long-lived assets.
COOPERS & LYBRAND L.L.P.
Houston, Texas
March 6, 1998
<PAGE> 1
Exhibit 23.2
[Miller and Lents, Ltd. Letterhead]
March 11, 1998
Cabot Oil & Gas Corporation
15375 Memorial Drive
Houston, Texas 77079
Re: Securities and Exchange Commission
Form 10-K of Cabot Oil & Gas Corporation
Gentlemen:
The firm of Miller and Lents, Ltd. consents to the use of its name and
the use of its report dated February 9, 1998 regarding Cabot Oil & Gas
Corporation Proved Reserves and Future Net Revenues as of January 1, 1998, which
report is to be included by reference in Form 10-K to be filed by Cabot Oil &
Gas Corporation with the Securities and Exchange Commission.
Miller and Lents, Ltd. has no interests in Cabot Oil & Gas Corporation,
or in any of its affiliated companies or subsidiaries and is not to receive any
such interest as payment for such report and has no director, officer, or
employee employed or otherwise connected with Cabot Oil & Gas Corporation. We
are not employed by Cabot Oil & Gas Corporation on a contingent basis.
Very truly yours,
MILLER AND LENTS, LTD.
By: /s/ JAMES A. COLE
-----------------
James A. Cole
Senior Vice President
JAC/mk
<TABLE> <S> <C>
<ARTICLE> 5
<CIK> 0000858470
<NAME> CABOT OIL & GAS CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<CASH> 1,784
<SECURITIES> 0
<RECEIVABLES> 60,211
<ALLOWANCES> (529)
<INVENTORY> 6,875
<CURRENT-ASSETS> 70,533
<PP&E> 906,780
<DEPRECIATION> (437,381)
<TOTAL-ASSETS> 541,805
<CURRENT-LIABILITIES> 85,872
<BONDS> 199,000
0
56,700
<COMMON> 192,913
<OTHER-SE> (65,551)
<TOTAL-LIABILITY-AND-EQUITY> 541,805
<SALES> 177,293
<TOTAL-REVENUES> 185,127
<CGS> 121,336
<TOTAL-COSTS> 121,336
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 17,961
<INCOME-PRETAX> 45,891
<INCOME-TAX> 17,557
<INCOME-CONTINUING> 23,231
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 23,231
<EPS-PRIMARY> 1.00
<EPS-DILUTED> 0.97
</TABLE>
<PAGE> 1
Exhibit 28.1
[Miller and Lents, Ltd. Letterhead]
February 9, 1998
Cabot Oil & Gas Corporation
15375 Memorial Drive
Houston, TX 77079
Re: Review of Proved Reserves
And Future Net Revenues
As of January 1, 1998
Gentlemen:
At your request, we reviewed the estimates of proved reserves of oil,
natural gas liquids, and gas and the future net revenues associated with these
reserves that Cabot Oil & Gas Corporation, hereinafter Cabot, attributes to its
net interests in oil and gas properties as of January 1, 1998. Cabot's
estimates, shown below, are in accordance with the definitions contained in
Securities and Exchange Commission Regulation S-X, Rule 4-10(a).
<TABLE>
<CAPTION>
Proved Reserves
-----------------------------------------
Developed Undeveloped Total
-----------------------------------------
<S> <C> <C> <C>
Net Liquids, MBbls 4,859.1 1,009.9 5,869.0
Net Gas, MMcf 738,764.2 164,664.7 903,428.9
Future Net Revenues
Undiscounted, M$ 1,581,487.0 271,111.4 1,852,598.4
Discounted at 10 Percent, M$ 744,537.2 94,223.6 838,760.8
</TABLE>
Based on our investigations and subject to the limitations described
hereinafter, it is our judgment that (1) Cabot has an effective system for
gathering data and documenting information required to estimate its proved
reserves and to project its future net revenues, (2) in making its estimates and
<PAGE> 2
Cabot Oil & Gas Corporation February 9, 1998
Page 2
projections, Cabot used appropriate engineering, geologic, and evaluation
principles and techniques that are in accordance with practices generally
accepted in the petroleum industry, and (3) the results of those estimates and
projections are, in the aggregate, reasonable.
All reserves discussed herein are located within the continental United
States. Gas volumes were estimated at the appropriate pressure base and
temperature base that are established for each well or field by the applicable
sales contract or regulatory body. Total gas reserves were obtained by summing
the reserves for all the individual properties and are therefore stated herein
at a mixed pressure base.
Cabot represents that the future net revenues reported herein were
computed based on prices being received for oil, natural gas liquids, and gas as
of Cabot's fiscal year end, December 31, 1997, and are in accordance with
Securities and Exchange Commission guidelines. The present value of future net
revenues was computed by discounting the future net revenues at 10 per cent per
annum. Estimates of future net revenues and the present value of future net
revenues are not intended and should not be interpreted to represent fair market
values for the estimated reserves.
In conducting our investigations, we reviewed the pertinent available
engineering, geological, and accounting information for each well or designated
property to satisfy ourselves that Cabot's estimates of reserves and future
production forecasts and economic projections are, in the aggregate, reasonable.
We independently selected a sampling of properties in each region and reviewed
the direct operating expenses and product prices used in the economic
projections.
In its estimates of proved reserves and future net revenues associated
with its proved reserves, Cabot has considered that a portion of its facilities
associated with the movement of its gas in the Appalachian Region to its markets
are unusual in that the construction and operation of these facilities are
highly dependent on its producing operations. Cabot has deemed the portion of
the cost of these facilities associated with its revenue interest gas as costs
that are attributable to its oil and gas producing activities, and accordingly,
has included these costs in its computation of the future net revenues
associated with its proved reserves.
Reserve estimates were based on decline curve extrapolations, material
balance calculations, volumetric calculations, analogies, or combinations of
these methods for each well, reservoir, or field. Reserve estimates from
volumetric calculations and from analogies are often less certain than reserve
estimates based on well performance obtained over a period during which a
substantial portion of the reserves were produced.
In making its projections, Cabot estimated yearly well abandonment
costs except where salvage values were assumed to offset these expenses. Costs
for possible future environmental claims were not included. Cabot's estimates
include no adjustments for production prepayments, exchange agreements, gas
balancing, or similar arrangements. We were provided with no information
concerning these conditions, and we have made no investigations of these matters
as such was beyond the scope of this investigation.
<PAGE> 3
Cabot Oil & Gas Corporation February 9, 1998
Page 3
The evaluations presented in this report, with the exceptions of those
parameters specified by others, reflect our informed judgments based on accepted
standards of professional investigation but are subject to those generally
recognized uncertainties associated with interpretation of geological,
geophysical, and engineering information. Government policies and market
conditions different from those employed in this study may cause the total
quantity of oil, natural gas liquids, or gas to be recovered, actual production
rates, prices received, or operating and capital costs to vary from those
presented in this report.
In conducting these evaluations, we relied upon production histories,
accounting and cost data, and other financial, operating, engineering, and
geological data supplied by Cabot. To a lesser extent, nonproprietary data
existing in the files of Miller and Lents, Ltd., and data obtained from
commercial services were used. We also relied, without independent verification,
upon Cabot's representation of its ownership interests, payout balances and
reversionary interests, the current prices, and the transportation fees
applicable to each property.
Miller and Lents, Ltd. is an independent oil and gas consulting firm.
None of the principals of this firm have any financial interests in Cabot or any
of its affiliated companies. Our fee is not contingent upon the results of our
work or report, and we have not performed other services for Cabot that would
affect our objectivity.
Very truly yours,
MILLER AND LENTS, LTD.
By: /s/James A. Cole
-----------------------
James A. Cole
Senior Vice President
JAC/mk
