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, 1998
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 eahc 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 26, 1999), was approximately
$265,000,000.
As of February 26, 1999, there were 24,665,455 shares of Common Stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Stockholders to
be held May 11, 1999 are incorporated herein by reference in Items 10, 11, 12,
and 13 of Part III of this report.
1
TABLE OF CONTENTS
PART I PAGE
ITEMS 1 and 2 Business and Properties 3
ITEM 3 Legal Proceedings 17
ITEM 4 Submission of Matters to a Vote of Security Holders 17
Executive Officers of the Registrant 18
PART II
ITEM 5 Market for Registrant's Common Equity and
Related Stockholder Matters 19
ITEM 6 Selected Historical Financial Data 19
ITEM 7 Management's Discussion and Analysis of Financial
Condition and Results of Operations 20
ITEM 8 Financial Statements and Supplementary Data 33
ITEM 9 Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 58
PART III
ITEM 10 Directors and Executive Officers of the Registrant 58
ITEM 11 Executive Compensation 58
ITEM 12 Security Ownership of Certain Beneficial
Owners and Management 58
ITEM 13 Certain Relationships and Related Transactions 58
PART IV
ITEM 14 Exhibits, Financial Statement Schedules and
Reports on Form 8-K 59
--------------------------
The statements regarding future financial performance and results and
market prices and the other statements which are not historical facts contained
in this report are forward-looking statements. The words "expect," "project,"
"estimate," "believe," "anticipate," "intend," "budget," "plan," "forecast,"
"predict" and similar expressions are also intended to identify forward-looking
statements. These 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 in this
document and in the Company's other Securities and Exchange Commission filings.
If one or more of these risks or uncertainties materialize, or if underlying
assumptions prove incorrect, actual outcomes may vary materially from those
included in this document.
2
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, in
the Western Region, including the Anadarko Basin of southwestern Kansas,
Oklahoma and the Texas Panhandle and the Green River Basin of Wyoming, and in
the Gulf Coast Region, including South Texas and South Louisiana. At December
31, 1998, the Company had 1,042.8 Bcfe of total proved reserves, 96% of which
was natural gas. Most of the Company's natural gas reserves are located in
long-lived fields with extensive production histories.
The Company 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 its
outstanding Common Stock. Cabot distributed the remaining Common Stock of the
Company to Cabot shareholders in 1991. The Company is publicly traded on the New
York Stock Exchange.
Unless otherwise specified, all references to the Company include Cabot Oil
& Gas Corporation, its predecessors and subsidiaries. All references to wells
are gross, unless otherwise stated.
The following table summarizes certain information, at December 31, 1998,
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)
Total Appalachian Western Gulf Coast
Company Region Region Region
- --------------------------------------------------------------------------------
Reserves/Production:
Proved reserves
Developed (Bcfe) 823.3 364.1 381.7 77.5
Undeveloped (Bcfe) 219.5 72.3 99.2 48.0
-------- --------- ------- -------
Total (Bcfe) 1,042.8 436.4 480.9 125.5
======== ========= ======= =======
Daily production (Mmcfe) net 187.9 62.8 92.5 32.6
Gross productive wells 4,671 3,027 1,198 446
Net productive wells 3,795 2,831 695 269
Percent of wells operated 83.9% 96.5% 63.4% 53.6%
Acreage:
Net acreage
Developed acreage 1,100,112 776,843 267,944 55,325
Undeveloped acreage 516,618 366,364 100,176 50,078
--------- --------- -------- -------
Total 1,616,730 1,143,207 368,120 105,403
========= ========= ======== =======
- ----------
(1) As of December 31,1998. 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.
3
EXPLORATION, DEVELOPMENT AND PRODUCTION
The Company is one of the largest producers of natural gas in the
Appalachian Basin, where it has operated for more than a century. Cabot Oil &
Gas has operated in the Anadarko Basin for over 60 years. The Company acquired
its operations in the Rocky Mountains and the Gulf Coast after acquiring
Washington Energy Resources Company in May 1994. Historically, its reserve base
has been maintained through low-risk development drilling and strategic
acquisitions, and recently the Company has increased its emphasis on
exploration. The Company continues to focus its operations in the Appalachian,
Western and Gulf Coast Regions through development drilling, 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 three years. The
Company experienced a 69% gross success rate for its exploratory drilling
program in 1998, based on participation in 39 exploratory wells. A large part of
the exploration activity has been focused in the Gulf Coast Region, where the
1998 gross success rate was 88%. Also in 1998, reserves in the Gulf Coast Region
grew from 56.5 Bcfe to 125.5 Bcfe, an increase of 122%, due primarily to the
Company's exploratory drilling program combined with its acquisition strategy.
When combining the exploration and development programs, the overall gross
success rate for 1998 was 89%.
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, 1998, the Company had 436.4 Bcfe of proved reserves (substantially all
natural gas) in the Appalachian Region, constituting 42% of the Company's total
proved reserves.
The Company has 3,027 productive wells (2,831.1 net), of which 2,920 wells
are operated by the Company. There are multiple producing intervals that include
the Upper Devonian, Oriskany, Berea, and Big Lime trend formations at depths
primarily ranging from 1,500 to 9,000 feet. Average net daily production in 1998
was 62.8 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 1998, the Company drilled 109 wells (90.2 net) in the Appalachian
Region, of which 83 were development wells (74.2 net). Capital and exploration
expenditures, including pipeline expenditures, were $43.2 million for the year.
In the 1999 drilling program year, the Company has plans to drill 8 wells in the
region.
At December 31, 1998, the Company had 1,143,207 net acres in the region,
including 776,843 net developed acres. At year end, the Company had identified
218 proved undeveloped drilling locations.
The Company owns and operates two natural gas storage fields in West
Virginia with a combined working gas capacity of 4 Bcf.
Ancillary to its exploration and production operations, the Company owns
and operates two brine treatment plants that process and treat waste fluid
generated during the drilling, completion and subsequent production of oil and
gas wells. The first plant, near Franklin, Pennsylvania, which began operating
in 1985, provides services to the Company and certain other oil and gas
producers in southwestern New York, eastern Ohio and western Pennsylvania. In
April 1998, the Company acquired a second brine treatment plant in Indiana,
Pennsylvania that had been in existence since 1987.
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.
4
WESTERN REGION
The Company's exploration, development and production activities in the
Western Region are primarily focused in the Anadarko Basin in southwestern
Kansas, Oklahoma and the panhandle of Texas and in the Green River Basin of
Wyoming. Operations for the Western Region are managed from a regional office in
Denver. At December 31, 1998, the Company had 480.9 Bcfe of proved reserves
(96.1% natural gas) in the Western Region, constituting 46% of the Company's
total proved reserves.
ANADARKO
The Company has 743 productive wells (488.5 net) in the Anadarko area, of
which 543 wells are operated by the Company. Principal producing intervals in
Anadarko are in the Chase, Morrow, Red Fork and Chester formations at depths
ranging from 1,500 to 13,000 feet. Average net daily production in 1998 was 42.2
Mmcfe.
In 1998, the Company drilled 23 wells (13.5 net) in Anadarko, including 20
development and extension wells (11.4 net). Capital and exploration expenditures
for the year were $20.2 million. In the 1999 drilling program year, the Company
has plans to drill 3 wells in the area.
At December 31, 1998, the Company had approximately 230,256 net acres,
including approximately 194,130 net developed acres. At year end, the Company
had identified 65 proved undeveloped drilling locations.
ROCKY MOUNTAINS
The Company has 455 productive wells (206.1 net) in the Rocky Mountains
area, of which 216 wells are operated by the Company. Principal producing
intervals in the Rocky Mountains area are in the Frontier and Dakota formations
at depths ranging from 9,000 to 13,000 feet. Average net daily production in
1998 was 50.2 Mmcfe.
In 1998, the Company drilled 56 wells (30.4 net) in the Rocky Mountains,
including 54 development and extension wells (29.9 net). Capital and exploration
expenditures for the year were $32.3 million. In the 1999 drilling program year,
the Company has plans to drill 9 wells in the area.
At December 31, 1998, the Company had approximately 137,864 net acres,
including approximately 73,814 net developed acres. At year end, the Company had
identified 71 proved undeveloped drilling locations.
GULF COAST REGION
The Company's exploration, development and production activities in the
Gulf Coast Region are concentrated in South Louisiana and South Texas. A
regional office in Houston manages operations. At December 31, 1998, the Company
had 125.5 Bcfe of proved reserves (80.8% natural gas) in the Gulf Coast Region,
constituting 12% of the Company's total proved reserves.
The Company has 446 productive wells (269.0 net) in the Gulf Coast Region,
of which 239 wells are operated by the Company. The Company is in the process of
evaluating approximately 150 of the Southern Louisiana wells that were acquired
in December from Oryx Energy Company. Principal producing intervals in the Gulf
Coast are in the Wilcox and Vicksburg formations in Texas, and Miocene age
formations in Louisiana at depths ranging from 3,000 to 18,000 feet. Average net
daily production in 1998 was 32.6 Mmcfe.
In 1998, the Company drilled 17 wells (9.6 net) in the Gulf Coast Region,
including 9 development wells (4.0 net). Capital and exploration expenditures
for the year were $128.7 million, including $70.1 million for Southern Louisiana
properties acquired from Oryx Energy Company. (See further discussion in Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations.) In the 1999 drilling program year, the Company has plans to drill 9
wells in the region.
At December 31, 1998, the Company had approximately 105,403 net acres,
including approximately 55,325 net developed acres. At year end, the Company had
identified 20 proved undeveloped drilling locations.
5
GAS MARKETING
The Company is engaged in a wide array of marketing activities offering 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-term 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 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. Additionally, as
a result of Order 636, the Company has experienced 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, Cabot Oil
& Gas Marketing Corporation, 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.
Most 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 10% of Appalachian production is
sold on fixed price contracts which typically renew annually.
The Company's Appalachian natural gas production is generally sold at a
higher realized price (a "premium") compared to production from other producing
regions due to its close proximity to eastern markets. While year-to-year
fluctuations in that premium are normal due to changes in market conditions,
this premium has typically been in the range of $0.40 to $0.50 per Mmbtu above
the Henry Hub cash price throughout the 1990's. In 1998, the premium averaged
approximately $0.40 per Mmbtu.
Ancillary to its exploration and production operations, the Company
operates a number of gas gathering and transmission pipeline systems, made up of
approximately 2,850 miles of pipeline with interconnects to three interstate
pipeline systems and five LDCs. The majority of the Company's pipeline
infrastructure in West Virginia is regulated by the FERC. As such, the
transportation rates and terms of service of the Company's pipeline subsidiary,
Cranberry Pipeline Corporation, are subject to the rules and regulations of the
FERC. The Company's natural gas gathering and transmission 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 transmission pipeline systems also
enables the Company to purchase, transport and sell natural gas produced by
third parties. In addition, the Company can take part in 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 that 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.
6
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. The marketing subsidiary sells the natural gas to
cogenerators, natural gas processors, LDCs, industrial customers and marketing
companies.
Currently, most of the Company's natural gas production in the Western
Region is sold primarily under contracts with a term of one year or less at
market-responsive prices. Approximately 20% of the Western Region's production
is sold under a 15-year cogeneration contract with 9 1/2 years remaining that
escalates 5% in price per year. 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 1,200 barrels a day of
crude oil/condensate in the Western Region at market-responsive prices.
GULF COAST REGION
The Company's principal markets for Gulf Coast Region natural gas are in
the industrialized Gulf Coast areas and the northeastern United States. The
Company's marketing subsidiary purchases all of the Company's natural gas
production in the Gulf Coast Region. The marketing subsidiary sells the natural
gas to intrastate pipelines, natural gas processors and marketing companies.
Currently, all of the Company's natural gas sales volumes in the Gulf Coast
Region are being sold at market-responsive prices under contracts with terms of
one to three years. The Gulf Coast Region properties are connected to various
processing plants in Texas and Louisiana with multiple interstate and intrastate
deliveries, affording the Company access to multiple markets.
The Company also produces and markets approximately 1,500 barrels a day of
crude oil/condensate in the Gulf Coast Region at market-responsive prices. This
amount includes volumes attributable to the December acquisition of Southern
Louisiana properties from Oryx Energy Company.
RISK MANAGEMENT
In 1998, the Company used certain financial instruments, called
"derivatives", to manage price risks associated with its production and
brokering activities. The impact of these derivatives on the Company's financial
results was not material. While there are many different types of derivatives
available, the Company used 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 on the differential between a fixed and a
variable gas price. The Company will continue to evaluate 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, and
Note 11. of the Notes to the Consolidated Financial Statements for further
discussion.
7
RESERVES
CURRENT RESERVES
The following table sets forth information regarding the Company's
estimates of its net proved reserves at December 31, 1998.
Natural Gas (Mmcf) Liquids(1) (Mbbl) Total(2) (Mmcfe)
- ------------------------------------------------------------------------------------------------------------------
Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total
- ------------------------------------------------------------------------------------------------------------------
Appalachia 360,903 72,295 433,198 532 0 532 364,093 72,295 436,388
West 366,301 95,907 462,208 2,579 549 3,128 381,776 99,203 480,979
Gulf Coast 61,186 40,164 101,350 2,711 1,306 4,017 77,452 48,000 125,452
------- ------- ------- ----- ----- ----- ------- ------- ---------
Total 788,390 208,366 996,756 5,822 1,855 7,677 823,321 219,498 1,042,819
======= ======= ======= ===== ===== ===== ======= ======= =========
- ----------
(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, condensate or natural gas liquids.
The proved reserve estimates presented here 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 other information about the Company's oil and gas reserves, see the
Supplemental Oil and Gas Information to the Consolidated Financial Statements
included in Item 8. 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 in the table above 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 for December 1998.
There are a number of uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond the control of the Company and,
therefore, the reserve information 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. 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 revising the original 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 depends primarily on 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.
8
HISTORICAL RESERVES
The following table presents the Company's estimated proved reserves for
the periods indicated.
Natural Gas (Mmcf) Total (Mmcfe)(1)
- ------------------------------------------------------------------------------------------------------------------------
APP WEST GULF TOTAL APP WEST GULF TOTAL
- ------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1995 515,556 350,873 23,420 889,849 516,869 377,806 27,032 921,707
Revisions of prior estimates (487) 2,110 1,151 2,774 (501) 1,139 1,342 1,980
Extensions, discoveries and
other additions 40,703 25,786 3,219 69,708 41,526 27,269 3,231 72,026
Production (26,783) (27,041) (4,938) (58,762) (26,910) (29,768) (5,667) (62,345)
Purchases of reserves in place 21,207 15,494 696 37,397 21,255 15,980 1,450 38,685
Sales of reserves in place (23,337) (1,732) (281) (25,350) (23,377) (1,758) (307) (25,442)
------- ------- ------- ------- ------- ------- ------- ---------
DECEMBER 31, 1996 526,859 365,490 23,267 915,616 528,862 390,668 27,081 946,611
------- ------- ------- ------- ------- ------- ------- ---------
Revisions of prior estimates 2,929 (1,419) 5,234 6,744 3,327 (2,392) 6,401 7,336
Extensions, discoveries and
other additions 42,609 36,062 30,520 109,191 43,493 37,384 33,079 113,956
Production (25,340) (30,104) (8,445) (63,889) (25,628) (32,780) (9,255) (67,663)
Purchases of reserves in place 5,355 68,480 1 73,836 5,366 72,034 1 77,401
Sales of reserves in place (137,194) (457) (419) (138,070) (137,520) (680) (798) (138,998)
------- ------- ------- ------- ------- ------- ------- ---------
DECEMBER 31, 1997 415,218 438,052 50,158 903,428 417,900 464,234 56,509 938,643
------- ------- ------- ------- ------- ------- ------- ---------
Revisions of prior estimates(2) (3,279) (2,273) (7,545) (13,097) (3,578) (10,167) (9,218) (22,963)
Extensions, discoveries and
other additions 42,310 36,058 16,524 94,892 43,164 38,869 17,871 99,904
Production (22,684) (30,863) (10,620) (64,167) (22,918) (33,755) (11,911) (68,584)
Purchases of reserves in place 2,167 21,234 52,833 76,234 2,354 21,798 72,201 96,353
Sales of reserves in place (534) 0 0 (534) (534) 0 0 (534)
------- ------- ------- ------- ------- ------- ------- ---------
DECEMBER 31, 1998 433,198 462,208 101,350 996,756 436,388 480,979 125,452 1,042,819
======= ======= ======= ======= ======= ======= ======= =========
Proved Developed Reserves:
December 31, 1995 430,165 298,768 18,302 747,235 431,477 324,115 21,464 777,056
December 31, 1996 434,558 311,585 21,955 768,098 436,560 334,069 25,577 796,206
December 31, 1997 343,718 354,030 41,016 738,764 346,400 375,606 45,913 767,919
December 31, 1998 360,903 366,301 61,186 788,390 364,093 381,776 77,452 823,321
- ----------
APP = Appalachian Region
WEST = Western Region
GULF = Gulf Coast Region
(1) Includes natural gas and natural gas equivalents determined by using the
ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil, condensate or
natural gas liquids.
(2) The total revision of 22,963 Mmcfe includes a 14,309 Mmcfe revision due to
lower year-end pricing in 1998 compared to 1997.
9
VOLUMES AND PRICES; PRODUCTION COSTS
The following table presents 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.
Year Ended December 31,
1998 1997 1996
- --------------------------------------------------------------------------------
Net Wellhead Sales Volume:
Natural Gas (Bcf)(1)
Appalachian Region (2) 22.7 25.3 26.2
Western Region 30.9 30.2 27.7
Gulf Coast Region 10.6 8.4 4.9
Crude/Condensate/Ngl (Mbbl)
Appalachian Region 39 48 21
Western Region 482 447 463
Gulf Coast Region 215 135 113
Produced Natural Gas Sales Price ($/Mcf)(3)
Appalachian Region $ 2.53 $ 3.00 $ 2.72
Western Region $ 1.90 $ 2.14 $ 1.96
Gulf Coast Region $ 2.15 $ 2.52 $ 2.34
Weighted Average $ 2.16 $ 2.53 $ 2.34
Crude/Condensate Sales Price ($/Bbl)(3) $13.06 $20.13 $21.14
Production Costs ($/Mcfe)(4) $ 0.57 $ 0.58 $ 0.56
- ----------
(1) Equal to the aggregate of production and the net changes in storage and
exchanges.
(2) The decline in the Appalachian Region natural gas sales volume is
attributed to the sale of the Meadville properties sold effective September
1, 1997. Prior to the sale, these properties produced 3.6 Bcf, or 14.7 Mmcf
per day, during the eight-month period ending August 31, 1997.
(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.
ACREAGE
The following tables summarize the Company's gross and net developed and
undeveloped leasehold and mineral acreage at December 31, 1998. Acreage in which
the Company's interest is limited to royalty and overriding royalty interests is
excluded.
10
LEASEHOLD ACREAGE
At December 31, 1998
Developed Undeveloped Total
- --------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
- --------------------------------------------------------------------------------
State
Alabama -- -- 312 312 312 312
Arkansas -- -- 240 6 240 6
Colorado 20,911 19,120 20,219 19,011 41,130 38,131
Indiana 739 369 49,307 24,427 50,046 24,796
Kansas 31,467 28,850 798 798 32,265 29,648
Kentucky 2,680 990 10,630 5,180 13,310 6,170
Louisiana 45,987 34,679 98,096 32,681 144,083 67,360
Michigan 784 176 2,877 712 3,661 888
Montana 397 210 680 303 1,077 513
New York 2,737 1,098 37,812 19,222 40,549 20,320
North Dakota 160 20 870 96 1,030 116
Ohio 5,372 2,027 33,618 26,723 38,990 28,750
Oklahoma 177,742 123,646 48,348 29,883 226,090 153,529
Pennsylvania 136,282 85,888 52,233 38,600 188,515 124,488
Texas 81,420 48,138 62,467 21,788 143,887 69,926
Utah 1,740 530 20,653 17,274 22,393 17,804
Virginia 22,189 20,079 13,852 6,900 36,041 26,979
West Virginia 607,775 572,501 227,467 186,584 835,242 759,085
Wyoming 104,126 53,934 53,712 27,291 157,838 81,225
--------- ------- ------- ------- --------- ---------
Total 1,242,508 992,255 734,191 457,791 1,976,699 1,450,046
========= ======= ======= ======= ========= =========
MINERAL FEE ACREAGE
At December 31, 1998
Developed Undeveloped Total
- --------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
- --------------------------------------------------------------------------------
State
Colorado -- -- 160 6 160 6
Kansas 160 128 -- -- 160 128
Montana -- -- 589 75 589 75
New York -- -- 4,281 1,070 4,281 1,070
Oklahoma 16,888 13,987 400 76 17,288 14,063
Pennsylvania 86 86 2,367 1,296 2,453 1,382
Texas 27 27 662 654 689 681
Virginia 17,817 17,817 100 34 17,917 17,851
West Virginia 93,906 75,812 56,577 55,616 150,483 131,428
--------- -------- ------- ------- --------- ---------
Total 128,884 107,857 65,136 58,827 194,020 166,684
========= ======== ======= ======= ========= =========
Aggregate Total 1,371,392 1,100,112 799,327 516,618 2,170,719 1,616,730
========= ======== ======= ======= ========= =========
11
TOTAL NET ACREAGE BY AREA OF OPERATION
At December 31, 1998
Developed Undeveloped Total
- ----------------------------------------------------------------------------
Appalachian Region 776,843 366,364 1,143,207
Western Region 267,944 100,176 368,120
Gulf Coast Region 55,325 50,078 105,403
--------- ------- ---------
Total 1,100,112 516,618 1,616,730
========= ======= =========
PRODUCTIVE WELL SUMMARY(1)
The following table reflects the Company's ownership at December 31, 1998
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), in the Western Region (consisting of various fields located in
Oklahoma, Kansas, Colorado and Wyoming), and in the Gulf Coast Region
(consisting of various fields located in Louisiana and Texas).
Natural Gas Oil Total
Gross Net Gross Net Gross Net
- -------------------------------------------------------------------------------
Appalachian Region 3,006.0 2,821.5 21.0 9.6 3,027.0 2,831.1
Western Region 1,101.5 640.9 96.5 53.7 1,198.0 694.6
Gulf Coast Region 260.0 211.5 186.0 57.5 446.0 269.0
------- ------- ----- ----- ------- -------
Total 4,367.5 3,673.9 303.5 120.8 4,671.0 3,794.7
======= ======= ===== ===== ======= =======
- ----------
(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
presented in the table below for the periods indicated:
Year Ended December 31,
1998 1997 1996
Gross Net Gross Net Gross Net
- -----------------------------------------------------------------------------
Appalachian Region:
Development Wells
Successful 77 69.4 82 73.7 86 82.6
Dry 6 4.8 5 5.0 12 12.0
Extension Wells
Successful 0 0.0 0 0.0 0 0.0
Dry 0 0.0 0 0.0 0 0.0
Exploratory Wells
Successful 18 11.0 25 11.8 15 5.9
Dry 8 5.0 8 6.3 10 5.2
--- ---- --- ---- --- -----
Total 109 90.2 120 96.8 123 105.7
=== ==== === ==== === =====
Wells Acquired(1) 5 4.2 1 40.0 15 11.8
Wells in Progress at End
of Period 1 0.5 4 3.1 2 1.5
12
Year Ended December 31,
1998 1997 1996
Gross Net Gross Net Gross Net
- -----------------------------------------------------------------------------
Western Region:
Development Wells
Successful 64 36.2 66 29.7 33 26.5
Dry 4 1.9 4 3.1 13 8.7
Extension Wells
Successful 5 2.2 9 8.6 13 8.4
Dry 1 0.9 2 1.0 1 1.9
Exploratory Wells
Successful 2 0.7 1 1.0 0 0.6
Dry 3 2.0 3 0.9 3 2.4
-- ---- -- ---- -- ----
Total 79 43.9 85 44.3 63 48.5
== ==== == ==== == ====
Wells Acquired(1) 13 3.9 65 18.7 27 11.7
Wells in Progress at End
of Period 4 1.8 6 3.3 4 1.5
Year Ended December 31,
1998 1997 1996
Gross Net Gross Net Gross Net
- -----------------------------------------------------------------------------
Gulf Coast Region:
Development Wells
Successful 9 4.0 7 3.5 7 4.2
Dry 0 0.0 1 0.6 1 0.6
Extension Wells
Successful 0 0.0 3 2.6 0 0.0
Dry 0 0.0 0 0.0 0 0.0
Exploratory Wells
Successful 7 4.6 5 1.6 1 0.6
Dry 1 1.0 4 2.0 1 0.0
-- --- -- ---- -- ---
Total 17 9.6 20 10.3 10 5.4
== === == ==== == ===
Wells Acquired(1) 219 204.2 0 0.0 1 0.6
Wells in Progress at End
of Period 5 4.2 0 0.0 0 0.0
- ----------
(1) Includes the acquisition of net interest in certain wells in 1998, 1997 and
1996 in which the Company already held an ownership interest.
COMPETITION
Competition in the Company's primary producing areas is intense.
Competition 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 believes that
its competitive position in the Appalachian Region is enhanced by the lack of
significant competition from major oil and gas companies. The Company also
actively competes against other companies with substantially larger financial
and other resources, particularly in the Western and Gulf Coast Regions. The
Company believes that marketing its own gas through the operation of Cabot Oil &
Gas Marketing Corporation enhances its competitive position.
13
OTHER BUSINESS MATTERS
MAJOR CUSTOMER
The Company had no sales to any customer that exceeded 10% of the Company's
total gross revenues in 1998 or 1997.
SEASONALITY
Demand for natural gas has historically been seasonal, with peak demand and
typically higher prices during the colder winter months.
REGULATION OF OIL AND NATURAL GAS PRODUCTION
The Company's oil and gas production and transportation activities are
subject to federal, state and local regulations. These regulations are not only
statutory, but include rules and regulations issued by numerous governmental
departments and agencies. Because these statutes, rules and regulations undergo
constant review and often are amended, expanded and reinterpreted, the Company
is unable to predict the future cost or impact of regulatory compliance. The
regulatory burden on the oil and gas industry increases its cost of doing
business and, consequently, affects its profitability. The Company, however,
does not believe it is affected materially differently 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 to drill wells, maintaining bonding
requirements 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 on 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.
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. 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 regulates the interstate transportation and
the sale in interstate commerce for resale of natural gas. The FERC's
jurisdiction over interstate natural gas sales 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, including all sales by the Company of its own
production. As a result, all of the Company's 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 not
affected by the Decontrol Act.
14
The Company's natural gas sales are affected by intrastate and interstate
gas transportation regulation. Beginning in 1985, the FERC adopted regulatory
changes that have significantly altered the transportation and marketing of
natural gas. These changes were intended by the FERC to foster competition by,
among other things, transforming the role of interstate pipeline companies from
wholesaler marketers of gas to the primary role of gas transporters. All gas
marketing by the pipelines was required to be divested to a marketing affiliate,
which operates separately from the transporter and in direct competition with
all other merchants. As a result of the various omnibus rulemaking proceedings
in the late 1980s and the individual pipeline restructuring proceedings of the
early to mid-1990s, the interstate pipelines are now required to provide open
and nondiscriminatory transportation and transportation-related services to all
producers, gas marketing companies, local distribution companies, industrial end
users and other customers seeking service. Through similar orders affecting
intrastate pipelines that provide similar interstate services, the FERC expanded
the impact of open access regulations to intrastate commerce.
More recently, the FERC has pursued other policy initiatives that have
affected natural gas marketing. Most notable are (i) the large-scale divestiture
of interstate pipeline-owned gas gathering facilities to affiliated or
non-affiliated companies, (ii) further development of rules governing the
relationship of the pipelines with their marketing affiliates, (iii) the
publication of standards relating to the use of electronic bulletin boards and
electronic data exchange by the pipelines to make available transportation
information on a timely basis and to enable transactions to occur on a purely
electronic basis, (iv) further review of the role of the secondary market for
released pipeline capacity and its relationship to open access service in the
primary market and (v) development of policy and promulgation of orders
pertaining to its authorization of market-based rates (rather than traditional
cost-of-service based rates) for transportation or transportation-related
services upon the pipeline's demonstration of lack of market control in the
relevant service market. It remains to be seen what effect the FERC's other
activities will have on access to markets, the fostering of competition and the
cost of doing business.
As a result of these changes, sellers and buyers of gas have gained direct
access to the particular pipeline services they need and are better able to
conduct business with a larger number of counterparties. The Company believes
these changes generally have improved the Company's access to markets while, at
the same time, substantially increasing competition in the natural gas
marketplace. The Company cannot predict what new or different regulations the
FERC and other regulatory agencies may adopt, or what effect subsequent
regulations may have on the Company's activities.
In the past, Congress has been very active in the area of gas regulation.
However, as discussed above, the more recent trend has been in favor of
deregulation and the promotion of competition in the gas industry. Thus, in
addition to "first sale" deregulation, Congress also repealed incremental
pricing requirements and gas use restraints previously applicable. There are
other legislative proposals pending in the Federal and state legislatures which,
if enacted, would significantly affect the petroleum industry. At the present
time, it is impossible to predict what proposals, if any, might actually be
enacted by Congress or the various state legislatures and what effect, if any,
such proposals might have on the Company. Similarly, and despite the trend
toward federal deregulation of the natural gas industry, whether or to what
extent that trend will continue, or what the ultimate effect will be on the
Company's sales of gas, cannot be predicted.
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, and the Pennsylvania Department of Natural Resources. The
Company's pipeline systems in each state operate independently and are not
interconnected.
15
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 Company facilities. These
permits can be revoked, modified or renewed by issuing authorities. Governmental
authorities enforce compliance with their regulations, with violations 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
cases, 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
part of oil and gas production operations. No assurance can be given that
significant costs and liabilities will not be incurred. Also, it is possible
that other developments, such as stricter 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 used for the production of oil and
gas for many years. Although the Company utilized operating and disposal
practices that were standard in the industry at the time, hydrocarbons or other
solid wastes may have been disposed of or released on or under the properties
owned or leased by the Company. In addition, many of the properties were
operated by third parties. The Company had no control over other parties'
treatment of hydrocarbons or other solid wastes and the way 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." 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 statutes, 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 of 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 respond to threats to the public health or the environment. The EPA
and third parties are also authorized to try to recover the costs of such action
from the responsible parties. In the course of business, the Company has
generated and will continue to 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. As a result, the Company may
be responsible under CERCLA for all or part of the costs to clean up sites where
such wastes have been disposed.
Oil Pollution Act. The Oil Pollution Act of 1990 (the "OPA") and resulting
regulations impose a variety of terms 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 water 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.
Clean Water Act. The Federal Water Pollution Control Act ("FWPCA" or "Clean
Water Act") and resulting regulations also govern discharge of certain
contaminants to "waters of the United States." Sanctions for failure to comply
strictly with the Clean Water Act requirements are generally resolved by payment
of fines and correction of any identified deficiencies, but regulatory agencies
could require the Company to cease construction or operation of certain sources
of water discharges. The Company believes that it complies with the Clean Water
Act and implementing federal and state regulations in all material respects.
16
Air Emissions. The Company's operations are subject to local, state and
federal laws and regulations to control emissions from sources of air pollution.
Payment of fines and correction of any identified deficiencies generally resolve
penalties for failure to comply strictly with air regulations or permits.
Regulatory agencies could also require the Company to cease construction or
operation of certain air emission sources. The Company believes that it
substantially complies with the emission standards under local, state, and
federal laws and regulations.
EMPLOYEES
The Company had 365 active employees as of December 31, 1998. The Company
believes that its relations with its employees are satisfactory. The Company has
not entered into any collective bargaining agreements with its employees. In
January 1999, the Company instituted a reorganization plan that resulted in a 6%
reduction in the number of active 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
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 Company conducts
operations in shallow offshore areas, which are subject to additional hazards of
marine operations, such as capsizing, collision and damage from severe weather.
The Company's operation of 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, 1998, the Company
owned or operated approximately 2,850 miles of natural gas gathering and
transmission pipeline systems. As part of its normal maintenance program, the
Company has identified certain segments of its pipelines which may require
repair, replacement or additional maintenance. According to customary industry
practices, the Company maintains insurance against some, but not all, of these
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 various 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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the period
from October 1, 1998 to December 31, 1998.
17
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information about the executive officers
of the Company as of March 1, 1999, as such term is defined in Rule 3b-7 of the
Securities Exchange Act of 1934, and certain other officers of the Company.
Officer
Name Age Position Since
- --------------------------------------------------------------------------------
Ray R. Seegmiller 63 President and Chief Executive Officer 1995
James M. Trimble 50 Senior Vice President 1987
H. Baird Whitehead 48 Senior Vice President 1987
J. Scott Arnold 45 Vice President, Land and
Associate General Counsel 1998
Paul F. Boling 45 Vice President, Finance 1996
Robert G. Drake 50 Vice President, Information Systems 1998
Abraham D. Garza 51 Vice President, Human Resources 1998
Jeff W. Hutton 43 Vice President, Marketing 1995
Lisa A. Machesney 43 Vice President, Managing Counsel and
Corporate Secretary 1995
Scott C. Schroeder 36 Vice President and Treasurer 1997
Michael B. Walen 50 Vice President and Regional Manager 1998
Henry C. Smyth 52 Controller 1998
All officers are elected annually by the Company's Board of Directors.
Except for the following, all executive officers of the Company have been
employed by the Company for at least the last five years.
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 President
and Chief Operating Officer and was elected as a Director. Mr. Seegmiller
replaced Charles Siess as Chief Executive Officer upon the retirement of Mr.
Siess in May 1998. From May 1988 until 1993, Mr. Seegmiller served as President
and Chief Executive of Terry Petroleum Company. Prior to that, Mr. Seegmiller
held various officer positions with Marathon Manufacturing Company.
Abraham D. Garza joined the Company in August 1995 as Director, Human
Resources. He was named to his current position as Vice President, Human
Resources in May 1998. Prior to joining the Company, Mr. Garza served as Human
Resources Director at Texfield, Inc., and in various management positions of
increasing responsibility at Marathon Manufacturing Company.
Scott C. Schroeder has been Vice President and Treasurer since April 1998.
From May 1997 to that time he served as Treasurer. 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 to that, Mr. Schroeder served as
Manager, Treasury Operations and Planning of DeKalb Energy Company.
Henry C. Smyth has been Controller of the Company since September 1998.
From November 1996 to that time, he served as Manager of Business Analysis. From
January 1996 to November 1996, Mr. Smyth acted in an analytical role evaluating
business opportunities. From September 1994 to December 1995, Mr. Smyth served
as Director of Internal Audit for the Company. Prior to that, Mr. Smyth was
associated with Mark Resources Corporation, where he served in various positions
including Vice President of Operations and Controller.
18
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 presents the high
and low sales prices per share of the Common Stock during certain periods, as
reported in the consolidated transaction reporting system. Cash dividends paid
per share of the Common Stock are also shown:
Cash
High Low Dividends
- -----------------------------------------------------
1998
First Quarter $22.63 $17.06 $0.04
Second Quarter 23.88 18.06 0.04
Third Quarter 20.44 12.75 0.04
Fourth Quarter 18.13 13.38 0.04
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
As of January 31, 1999, there were 1,267 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 summarizes 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.
Year Ended December 31,
(In thousands, except per share amounts) 1998 1997 1996 1995 1994
- -----------------------------------------------------------------------------------------
INCOME STATEMENT DATA:
Net Operating Revenues $159,606 $185,127 $163,061 $121,083 $140,295
Income (Loss) from Operations 27,403 63,852 48,787 (116,758) 15,013
Net Income (Loss) Applicable to
Common Stockholders 1,902 23,231 15,258 (92,171) (5,444)
BASIC EARNINGS (LOSS) PER SHARE
APPLICABLE TO COMMON STOCKHOLDERS(1) $0.08 $1.00 $0.67 $(4.05) $(0.25)
DIVIDENDS PER COMMON SHARE $0.16 $0.16 $0.16 $ 0.16 $ 0.16
BALANCE SHEET DATA:
Properties and Equipment, Net $629,908 $469,399 $480,511 $474,371 $634,934
Total Assets 704,160 541,805 561,341 528,155 688,352
Long-Term Debt 327,000 183,000 248,000 249,000 268,363
Stockholders' Equity 182,668 184,062 160,704 147,856 243,082
- ----------
(1) See "Earnings per Common Share" under Note 15 of the Notes to the
Consolidated Financial Statements.
19
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 0the
Consolidated Financial Statements and the accompanying Notes included elsewhere.
The Company operates in one segment, natural gas and oil exploration and
exploitation. In previous years, the Company operated as two regions: the
Appalachian Region and the Western Region, which included the Anadarko, Rocky
Mountains and Gulf Coast areas. Beginning in 1998, a third region was created
with the formation of the Gulf Coast Region, leaving the Anadarko and Rocky
Mountains areas in the Western Region. For purposes of the comparisons below,
prior period results have been restated to conform to the new three-region
structure.
OVERVIEW
Despite the low commodity prices realized throughout the energy industry
this year, the Company reported earnings of $0.08 per share, or $1.9 million.
The decline in results from the record earnings and operating cash flow reported
in 1997 was due largely to a $0.37 per Mcf decline in realized natural gas
prices caused mainly by unseasonably warm temperatures for much of the United
States in 1998. Operating results for 1998 included the following:
o The average produced natural gas price was $2.16 per Mcf, down 15%
compared to 1997, resulting in a $23.5 million decrease in produced
natural gas revenue. Natural gas production was up 0.3 Bcf, or 0.4%,
compared to 1997, resulting in a $0.7 million increase to revenue. In
addition, the average realized oil price was $13.06 per Bbl, down 35%
from 1997, resulting in a $4.5 million reduction to oil revenue. The
volume of oil sales was up 76 Mbbls, resulting in an increase to oil
revenue of $1.5 million from 1997.
o Brokered natural gas margin increased $1.4 million as a result of an
increase in volume of 9 Bcf.
o In an effort to provide future growth opportunities, the Company
increased its exploration spending by $5.7 million, or 41%, over 1997.
The Company expanded its seismic program and added to its exploration
staff. Higher dry hole cost also contributed to this increase.
o In December 1998, the Company recognized a $0.9 million reorganization
charge. The reorganization involved the reduction of employment levels
by 6%, and is expected to result in future annual savings of $1.5
million. The 1998 income statement reflects the components of this
charge in the line items that will show the benefit in future years.
Direct operating expense related to the reorganization charge was $0.4
million, the exploration charge was $0.3 million, and $0.2 million was
recognized in general and administrative.
o In December 1998, the Company purchased producing oil and gas
properties and other assets located in Southern Louisiana from Oryx
Energy Company for $70.1 million (the "Southern Louisiana
properties"). These Southern Louisiana properties include interests in
ten fields covering 34,345 net acres with 68 producing wells. The
acquisition also included a 3-D seismic inventory. Proved reserves
acquired were approximately 72 Bcfe. Due to the timing of the
purchase, the impact on 1998 production was not significant, adding
11.5 Mmcfe to December's daily production rate. The Company plans to
increase production by reworking certain non-producing wells, and
commencing an exploratory and development drilling program.
Operating cash flows were $87.2 million, down $7.8 million, or 8%, from
1997's record level. The significant reduction in commodity prices was the
primary factor in the lower net cash flow level realized in 1998. Operating cash
flows, in combination with the increase in borrowings from the revolving credit
facility, funded the $223.2 million capital and expenditure program, including
the $70.1 million acquisition of oil and gas properties located in Southern
Louisiana from Oryx Energy Company in December 1998.
20
The Company drilled 143.7 net wells with a net success rate of 89% compared
to 151.4 net wells and a net 88% success rate in 1997. The Company replaced 112%
of production through drilling additions and revisions, versus a 179% production
replacement in 1997. Reserve replacement from all sources in 1998 was 253%,
compared to 294% in 1997. In 1999, the Company plans to drill 29 gross wells
(15.3 net) and spend $44.9 million in capital and exploration expenditures, down
from 1998 spending in reaction to continued low energy commodity price
expectations. Price volatility in the gas market remains prevalent as it has
over the past few years and management cannot predict natural gas price levels
for the remainder of 1999 and beyond. Consequently, the Company will adjust,
when necessary, its 1999 spending plan in accordance with material changes in,
among other things, realized natural gas prices and discretionary cash flows.
Total equivalent production was 68.6 Bcfe, an increase of 1.3% over 1997.
The Company's 1998 drilling program in the Gulf Coast Region experienced some
mechanical failures resulting in redrills as well as drilling difficulties
causing 1998 production to be 1.9 Bcfe lower than expected. Certain of these
wells commenced production later than anticipated in 1998 or will come on line
in 1999.
The Company's strategic pursuits are sensitive to energy commodity prices,
particularly the price of natural gas. The unseasonably lower natural gas prices
that were seen at the close of 1997 have remained soft through most of the 1998
winter period. Despite a spring that brought improved seasonal prices, the
balance of 1998 saw prices well below those of the most recent preceding years.
The unseasonably mild winter throughout much of the country has kept prices low
into 1999.
The Company remains focused on its strategies to grow through the drill
bit, through acquisitions and through greater emphasis on marketing.
Additionally, the Company will continue to capitalize on the opportunities its
expanded exploration efforts have provided. The Company believes that these
strategies remain appropriate in the current industry environment and establish
a firm base that 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. Although 1998 production increased only slightly
from 1997, the newly acquired Gulf Coast properties are expected to boost 1999
production by approximately 5 Bcfe. The benefits of the 1998 reorganization will
help to lower costs in 1999 and beyond.
The second goal is to maintain reserves per share while increasing
production to protect long-term shareholder value. Excluding revisions, reserve
additions from the 1998 drilling program replaced 146% of production.
Additionally, the Company acquired reserves during the year through asset
purchases. Most significantly, the Company purchased approximately 72 Bcfe of
proved reserves from Oryx Energy Company in December 1998. As a result, the
total proved reserve levels increased in 1998 to 1.04 Tcfe, the highest level in
the Company's history.
Finally, the Company strives to reduce debt as a percentage of total
capitalization ("debt-to-capital percentage") without diluting shareholder
value. However, the acquisition of growth-oriented opportunities such as the
December 1998 Southern Louisiana properties acquisition, along with the partial
funding of the 1998 drilling program, increased the Company's debt, resulting in
an increase in the debt-to-capital percentage from 51.9% in 1997 to 65.2% in
1998. While the debt-to-capital percentage has increased, the Company's debt to
discretionary cash flow ratio is 3.7x compared to the reserve life index (14.2
years, calculated as year-end reserves divided by annual production). These debt
to discretionary cash flow and reserve life index amounts have been normalized
to exclude the impact of the Southern Louisiana properties acquisition since the
$65.6 million of related debt incurred is disproportionate to the one month of
discretionary cash flows from these acquired properties. Excluding the
normalization, debt to discretionary cash flow is 4.6x and the reserve life
ratio is 15.2. For a three-year comparison, refer to the table on page 24.
The preceding paragraphs, discussing the Company's strategic pursuits and
goals, contain forward-looking information. See Forward-Looking Information on
page 28.
21
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. However, unseasonably warm temperatures remained into the winter of
1998/1999, bringing with it the continuation of lower energy commodity prices.
Natural gas prices were generally down in 1998 compared to 1997, resulting in
lower operating cash flows than in the previous year.
The primary sources of cash for the Company during 1998 were from funds
generated from operations and increased borrowings on the revolving line of
credit. Primary uses of cash were funds used in operations, exploration and
development expenditures, acquisitions (including $70.1 million for the purchase
of the Southern Louisiana properties from Oryx Energy Company), dividends on
preferred and common stock and repayment of debt.
The Company had a net cash inflow of $0.4 million in 1998. Net cash inflow
from operating and financing activities totaled $222.5 million, funding the
capital and exploration expenditures of $222.1 million, net of the $1.1 million
in net proceeds from the sale of assets.
(In millions) 1998 1997 1996
- ------------------------------------------------------------------------------
Cash Flows Provided by Operating Activities $ 87.2 $ 95.0 $ 75.5
Cash flows provided by operating activities in 1998 were $7.8 million lower
than in 1997 due predominantly to lower natural gas and oil prices, partially
offset by a significant increase in the accounts payable balance resulting
mainly from higher fourth quarter drilling expenditures.
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.
(In millions) 1998 1997 1996
- ------------------------------------------------------------------------------
Cash Flows Used by Investing Activities $(222.1) $(38.4) $(67.6)
Cash flows used by investing activities in 1998 were $183.7 million higher
than in 1997 due primarily to the capital and exploration expenditures that
increased $135.8 million over 1997, and in part to $47.7 million in net proceeds
from the Meadville sale in 1997. These 1998 expenditures included (1) the $70.1
million purchase of the Southern Louisiana properties from Oryx Energy Company
in December, (2) the $6.6 million spent as part of the joint exploration
agreement with Union Pacific Resources Group, Inc. ("UPR"), and (3) the $12.0
million used to acquire 21.8 Bcfe of proved reserves in the Anadarko and Rocky
Mountains areas of the Western Region.
22
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.
(In millions) 1998 1997 1996
- ------------------------------------------------------------------------------
Cash Flows Provided (Used) by Financing Activities $ 135.3 $(56.2) $ (9.6)
Cash flows provided by financing activities in 1998 were increases in
borrowings on the revolving credit facility related to the 1998 drilling program
and $83.6 million in property acquisitions. Financing activities in 1998 also
included the payment of stock dividends and the purchase of treasury stock.
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.
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. In December 1998, the revolving credit facility was
increased to include five additional banks. The new agreement gives the Company
the ability to borrow up to $250 million in addition to its other long-term
debt. The Company's outstanding indebtedness under the revolving credit facility
was $179 million at December 31, 1998.
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 the banks' petroleum engineer) and other assets.
Accordingly, oil and gas prices are an important part of this computation. Oil
and gas prices also effect the calculation of the financial ratios for debt
covenant compliance. While the Company does not currently believe that its
credit availability is likely to be significantly reduced, management cannot
predict how current price levels may change the banks' long-term price outlook
and, therefore, can give no assurance that the Company's available credit line
will not be adversely impacted in 1999 or as to the amount of credit that will
continue to be available under this facility. To reduce the impact of such a
redetermination, the Company strives to manage its debt at a level below the
available credit line in order to maintain excess borrowing capacity. At year
end, this excess capacity totaled $57 million, or 14% of the total available
credit line. See Note 5. Debt and Credit Agreements for further discussion.
In the event that the available credit line is adjusted below the
outstanding level of borrowings, the Company has a period of 180 days to reduce
its outstanding debt to the adjusted credit line. The Revolving Credit Agreement
also includes a requirement to pay down half of the debt in excess of the
adjusted credit line within the first 90 days of such an adjustment.
The Company's 1999 interest expense is projected to be approximately $27
million. A principal payment of $16 million on the 10.18% private placement of
senior notes is due in the second quarter of 1999.
23
Capitalization information on the Company is as follows:
(In millions) 1998 1997 1996
-------------------------------------------------------------------
Long-Term Debt $327.0 $183.0 $248.0
Current Portion of Long-Term Debt 16.0 16.0 --
------ ------ ------
Total Debt 343.0 199.0 248.0
------ ------ ------
Stockholders' Equity
Common Stock (net of Treasury) 126.0 127.4 69.4
Preferred Stock 56.7 56.7 91.3
------ ------ ------
Total Equity 182.7 184.1 160.7
------ ------ ------
Total Capitalization $525.7 $383.1 $408.7
====== ====== ======
Debt to Capitalization 65.2% 51.9% 60.7%
------ ------ ------
The Company's debt, discretionary cash flow and reserve life index are comprised
as follows:
(In millions) 1998 1997 1996
-------------------------------------------------------------------
Total Debt $343.0 $199.0 $248.0
Discretionary Cash Flow ("DCF") (1) $ 74.3 $ 98.4 $ 83.7
Debt to DCF Coverage 3.7x(3) 2.0x 3.0x
Reserve Life Index (in years) (2) 14.2(4) 13.9 15.2
----------
(1) Discretionary cash flow is defined as net income plus non-cash charges
and exploration expense less preferred dividends. Excludes net
proceeds on property sales.
(2) Reserve life index is year-end reserves divided by annual production.
(3) The Debt to DCF Coverage ratio was normalized to exclude the impact of
the December 1998 Southern Louisiana properties acquisition since the
ratio was disproportionately impacted by the full inclusion of the
$65.6 million in related debt incurred compared to the one month of
discretionary cash flows from these acquired properties. Before the
normalization,Debt to DCF coverage is 4.6x.
(4) Amount normalized to exclude the reserves purchased in the December
1998 Southern Louisiana properties acquisition. Including these
reserves, the reserve life index is 15.2.
GAS PRICE SWAPS
From time to time, the Company enters into natural gas swap agreements
("price swaps"), a type of derivative instrument, with counterparties to hedge
price risk associated with a portion of the Company's production. Under these
price swaps, the Company receives a fixed price ("fixed price swaps") on a
notional quantity of natural gas in exchange for paying a variable price based
on a market-based index, such as the Nymex gas futures. Notional quantities of
natural gas are used in each price swap, since no physical exchange or delivery
of natural gas is involved. During 1998 and 1997, the Company entered into no
fixed price swaps to hedge natural gas prices on its production. In 1996, the
prices received on fixed price swaps ranged from $1.02 to $2.54 per Mmbtu on
total notional quantities of 17,600,000 Mmbtu, representing 27% of 1996
production.
24
In addition, the Company uses price swaps to hedge the natural gas price
risk on brokered transactions. Typically, the Company enters into contracts to
broker natural gas at a variable price based on the market index price. However,
in some circumstances, some of the Company's customers or suppliers request that
a fixed price be stated in the contract. After entering into these fixed price
contracts to meet the needs of its customers or suppliers, the Company may use
price swaps to effectively convert these fixed price contracts to
market-sensitive price contracts. These price swaps are held by the Company to
their maturity and are not held for trading purposes. During 1998, the Company
entered into price swaps with total notional quantities of 2,226,000 Mmbtu
related to its brokered activities, representing less than 5% of the Company's
total volume of brokered natural gas sold. A pre-tax loss of $0.3 million was
recorded from these price swaps in 1998. In 1997 and 1996, these price swaps had
total notional quantities of 1,416,000 Mmbtu and 1,002,000 Mmbtu related to
brokered transactions, and represented approximately 4% and 3%, respectively, of
the Company's total volume of brokered natural gas sold. At December 31, 1998,
the Company had open price swaps with notional quantities of 1,730,000 Mmbtu and
an unrealized loss of $0.2 million on these open contracts. See Note 11.
Financial Instruments for further discussion.
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.
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" ("SFAS 133"). SFAS 133 requires all derivatives to be
recognized in the statement of financial position as either assets or
liabilities and measured at fair value. In addition, all hedging relationships
must be designated, reassessed and documented pursuant to the provisions of SFAS
133. This statement is effective for financial statements for fiscal years
beginning after June 15, 1999. The Company has not yet completed its evaluation
of the impact of the provisions from SFAS 133 on its financial position or
operations.
At December 31, 1998, the Company had entered into natural gas price swap
contracts that remain open at year end as follows:
Swap Purchases
Volume in Weighted Average
Period MMBtu Contract Price
------------------------------------------------------------
Full Year 1999 1,280,000 $2.03
1st Quarter 2000 450,000 2.13
YEAR 2000
Many computer systems have been built using software that processes
transactions using two digits to represent the year. This type of software will
generally require modifications to function properly with dates after December
31, 1999. The same issue applies to microprocessors embedded in machinery and
equipment, such as gas compressors and pipeline meters. The impact of failing to
identify and correct this problem could be significant to the Company's ability
to operate and report results, as well as potentially exposing the Company to
third-party liability.
The Company has begun making necessary modifications to its computer
systems and embedded microprocessors in preparation for the Year 2000. These
projects are on schedule and the Company believes that the total related costs
will be approximately $2.1 million, funded by cash from operations or short-term
borrowings, when completed in 1999. Of the total cost, $1.8 million is
attributable to the purchase of new software and equipment which will be
capitalized. The remaining $0.3 million is being expensed over 1998 and 1999,
and will not have a material impact on the Company's financial position or
operating results. Actual costs through 1998 were $0.6 million, $0.4 million of
which has been capitalized and $0.2 million of which has been expensed.
25
The Company has begun reviewing the compliance of field equipment including
compressor stations, gas control systems and data logging equipment. Most
equipment reviewed was found to be compliant, and, where necessary,
microprocessor chip replacements are scheduled to be complete in the first
quarter of 1999 at a cost less than $0.1 million.
Additionally, the Company is in the process of contacting its significant
customers and suppliers in order to determine the Company's exposure to their
potential failure to become Year 2000 compliant. Although the Company is not
aware of any Year 2000 compliance problems with any of its customers or
suppliers, there can be no guarantee that the systems of these companies will
operate without interruption in the new millennium.
The Company has formed an internal committee to not only identify and
respond to these issues, but also to develop a contingency plan in the event
that a problem arises after the turn of the century. Management expects the
contingency plan to be substantially complete by mid 1999. Additionally, the
Company has engaged outside consultants to review the Company's plans and
periodically update the status of the plan implementation. At this time, the
Company does not anticipate that the arrival of the Year 2000 will materially
impact its financial position or results of operations.
The project costs and timetable for Year 2000 compliance are based on
management's best estimates. In developing these estimates, assumptions were
made regarding future events including, among other things, the availability of
certain resources and the continued cooperation of the Company's customers and
suppliers. Actual costs and timing may differ from management's estimates due to
unexpected difficulties in obtaining trained personnel, locating and correcting
relevant computer code and other factors.
CAPITAL AND EXPLORATION EXPENDITURES
The following table lists capital and exploration expenditures for the
three years ended December 31, 1998.
(In millions) 1998 1997 1996
---------------------------------------------------------------------
Capital Expenditures:
Drilling and Facilities $ 99.0 $ 68.2 $ 42.7
Leasehold Acquisitions 15.6 4.3 4.3
Pipeline and Gathering 5.3 6.1 6.3
Other 2.8 2.0 0.7
------ ------ ------
122.7 80.6 54.0
------ ------ ------
Proved Property Acquisitions 83.6 (3) 45.6 (2) 6.6
WERCO Acquisition -- -- (5.3) (1)
------ ------ ------
83.6 45.6 1.3
------ ------ ------
Exploration Expenses 19.6 13.9 12.6
------ ------ ------
Total $225.9 $140.1 $ 67.9
====== ====== ======
- ----------
(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 Washington Energy Resources Company ("WERCO")
acquisition as a result of the $8.4 million valuation adjustment
received in 1995.
(2) Includes $45.2 million in oil and gas properties acquired from
Equitable Resources Energy Company in a like-kind exchange transaction
with a portion of the assets sold in the Meadville property sale.
(3) Includes $70.1 million in oil and gas properties acquired from Oryx
Energy Company in December 1998.
26
The Company generally funds its capital and exploration activities,
excluding major oil and gas property acquisitions, with cash generated from
operations. The Company budgets such capital expenditures based upon projected
cash flows, exclusive of acquisitions.
Planned expenditures for 1999 have been reduced 68% compared with 1998,
excluding proved property acquisitions. The Company intends to review and adjust
the capital and exploration expenditures planned for 1999 as industry conditions
dictate. Currently, the Company projects $44.9 million in capital and
exploration expenditures for 1999, including $33.4 million for the drilling and
exploration program. The Company plans to drill 29 wells (15.3 net), compared
with 205 wells (143.7 net) drilled in 1998.
In addition to the drilling and exploration program, other 1999 capital
expenditures are planned primarily for lease acquisitions and for gathering and
pipeline infrastructure maintenance and construction.
During 1998, dividends were paid on the Company's Common Stock totaling
$4.0 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 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
Corporate Income Tax. The Company generates tax credits for the production
of certain qualified fuels, including natural gas produced from tight sands
formations and Devonian Shale. The credit for natural gas from a tight sands
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 $1.07 per Mmbtu in 1998. In 1995 and 1996, the Company completed
three transactions to monetize the value of these tax credits, resulting in
revenues of $2.7 million in 1998 and approximately $11.1 million over the
remaining four years. See Note 13 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 subject to certain restrictive covenants in the Company's various
debt instruments. Among other requirements, the Company's Revolving Credit
Agreement 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, 1998, the calculated ratio for 1998 was 5.4 to 1. In the unforeseen
event that the Company fails to comply with these covenants, it may apply for a
temporary waiver with the bank, which, if granted, would allow the Company a
period of time to remedy the situation. See further discussion in Item 7.
Capital Resources and Liquidity and Note 5. Debt and Credit Agreements.
27
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 realized natural gas sales price decreased 15% compared to
1997, while production volumes increased less than 1%. As a result, the Company
experienced a lower level of earnings and operating cash flow than its record
highs in 1997. Price volatility in the gas market has remained prevalent in the
last few years, as demonstrated most recently in the first and last quarters of
1998 and the beginning of 1999, with monthly 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 1999 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 commodity prices should become substantially
more depressed.
While the Company's 1999 plans include approximately $45 million in capital
spending, the Company will periodically assess industry conditions and will
adjust its 1999 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 current capital requirements.
The preceding paragraphs contain forward-looking information. See
Forward-Looking Information on the following page.
* * *
FORWARD-LOOKING INFORMATION
The statements regarding future financial performance and results and
market prices and the other statements which are not historical facts contained
in this report are forward-looking statements. The words "expect," "project,"
"estimate," "believe," "anticipate," "intend," "budget," "plan," "forecast,"
"predict" and similar expressions are also intended to identify forward-looking
statements. Such statements involve risks and uncertainties, including, but not
limited to, market factors, market prices (including regional basis
differentials) of natural gas and oil, results for future drilling and marketing
activity, future production and costs and other factors detailed herein and in
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.
RESULTS OF OPERATIONS
For the purpose of reviewing the Company's results of operations, "Net
Income" is defined as net income available to common stockholders.
28
SELECTED FINANCIAL AND OPERATING DATA
(In millions except wehre specified) 1998 1997 1996
- -------------------------------------------------------------------------
Net Operating Revenues $159.6 $185.1 $163.1
Operating Expenses 132.7 121.3 116.0
Interest Expense 18.6 18.0 17.4
Net Income 1.9 23.2 15.3
Earnings Per Share - Basic $ 0.08 $ 1.00 $ 0.67
Earnings Per Share - Diluted $ 0.08 $ 0.97 $ 0.66
Natural Gas Production (Bcf)
Appalachia 22.7 25.3 26.8
West 30.9 30.2 27.1
Gulf Coast 10.6 8.4 4.9
------ ------ ------
Total Company 64.2 63.9 58.8
====== ====== ======
Produced Natural Gas Sales Price ($/Mcf)
Appalachia $ 2.53 $ 3.00 $ 2.72
West $ 1.90 $ 2.14 $ 1.96
Gulf Coast $ 2.15 $ 2.52 $ 2.34
Total Company $ 2.16 $ 2.53 $ 2.34
Crude/Condensate
Volume (Mbbl) 650 574 520
Price ($/Bbl) $13.06 $20.13 $21.14
1998 AND 1997 COMPARED
Net Income and Revenues. The Company reported net income in 1998 of $1.9
million, or $0.08 per share, down $21.3 million, or $0.92 per share, compared to
1997. Net operating revenue of $159.6 million was down $25.5 million, or 14%
from 1997. Natural gas sales of $138.9 million accounted for 87% of net
operating revenue in 1998. The decrease in net operating revenue was a result of
a 15% decline in realized natural gas prices and a 35% reduction in realized oil
prices. Operating income and net income were similarly impacted by the decrease
in energy commodity prices along with higher expenses attributable to the
Company's increased exploration program.
Natural gas production volumes were down 2.6 Bcf, or 10%, to 22.7 Bcf in
the Appalachian Region due to the September 1997 sale of producing properties
located in Northwest Pennsylvania (the "Meadville properties"). Natural gas
production volumes in the Western Region were up 0.7 Bcf, or 2%, to 30.9 Bcf due
to increases in Rocky Mountains area production. This increase was a result of
both the 1997 purchase of oil and gas producing properties located in the Green
River Basin of Wyoming (the "Green River properties") and new wells brought on
line. In the Gulf Coast Region, natural gas production volumes were up 2.2 Bcf,
or 26%, to 10.6 Bcf due to results of the 1997 and 1998 drilling programs and in
part to the December 1998 purchase of the Southern Louisiana properties. While
production increased over 1997 levels, the region did experience drilling delays
and mechanical failures in a significant field that deferred production into
1999, but left the field's total reserves substantially unchanged.
The average natural gas sales price decreased $0.47 per Mcf, or 16%, to
$2.53 in the Appalachian Region, decreasing net operating revenues by
approximately $10.7 million on 22.7 Bcf of production. In the Western Region,
the average natural gas sales price decreased $0.24 per Mcf, or 11%, to $1.90,
decreasing net operating revenues by $7.4 million on 30.9 Bcf of production. The
average natural gas sales price in the Gulf Coast Region decreased $0.37 per
Mcf, or 15%, to $2.15, reducing net operating revenue by $3.9 million on 10.6
Bcf of production. The overall weighted average natural gas production sales
price decreased $0.37 per Mcf, or 15%, to $2.16.
Crude oil and condensate sales increased by 76 Mbbl, or 13%, increasing
revenue by $1.5 million over 1997. This increase was due to new production
brought on line, combined with the December production of the newly acquired
Southern Louisiana properties. However, the 1998 average crude oil price
declined 35%, reducing oil revenue by $4.5 million.
29
Brokered natural gas margin was up $1.4 million to $5.5 million due to a
26% volume increase over 1997, combined with a $0.01 per Mcf increase in the net
margin to $0.13 per Mcf.
Operating Expenses. Total operating expenses increased $11.3 million, or
9%, to $132.7 million. In December 1998, the Company recognized a $0.9 million
reorganization charge designed to reduce future operating expenses. The
reorganization charge was comprised of $0.4 million in direct operating expense,
$0.3 million in exploration expense and $0.2 million in general and
administrative expense. The reorganization reduced the number of Company
employees by 6%. The significant changes in operating expenses are explained as
follows:
o Direct operations expense increased $0.9 million, or 3%, due primarily
to the $0.4 million direct operations component of the reorganization
charge in the fourth quarter and $0.5 million in higher workover costs
incurred primarily in the Gulf Coast Region.
o Exploration expense increased $5.7 million, or 41%, due to (1) a $1.5
million increase in geological and geophysical activity including
seismic data purchases and consulting fees, (2) a $2.3 million
increase in dry hole cost, resulting from the Company's expanded
drilling efforts in the Gulf Coast where wells are generally drilled
at higher costs, (3) a $1.4 million increase in exploration personnel-
related expenses such as salaries, benefits, and relocation associated
with the increase in the exploration program, and (4) $0.3 million for
the exploration expense component of the reorganization that was
expensed in December 1998.
o Depreciation, depletion, amortization and impairment expense increased
$2.1 million, or 5%, primarily due to the amortization of a lease
option purchased in the second quarter of 1998 related to a joint
venture with UPR in the Gulf Coast Region. Additionally, this expense
increased in part due to higher units of production expense in
connection with increased production.
o General and administrative expense increased $2.2 million primarily
due to (1) $0.5 million due to staffing increases in the third and
fourth quarters of 1997, (2) $0.7 million for non-cash stock
compensation for stock awards, (3) $0.5 million for certain executive
retirement and severance packages accrued in 1998, (4) $0.3 million
due to higher relocation and travel expenses, and (5) $0.2 million
that was recorded for the general and administrative component of the
reorganization in December 1998.
Interest expense increased $0.6 million, or 4%, due to higher levels of
debt outstanding on the revolving credit facility.
Income tax expense was down $14.1 million due to the comparable decrease in
earnings before income tax. Included in income tax expense is the interest
charged by the Internal Revenue Service on a deferred tax gain related to the
monetization of the Section 29 credits. This interest amount was $0.3 million in
1998 and $0.5 million in 1997.
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 an income tax refund. The $2.8 million income tax
refund, 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 income tax refund, 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 increases in natural gas prices and equivalent production along
with lower depreciation, depletion and amortization expense and interest
expense.
30
Effective September 1, 1997, the Company sold the Meadville properties for
$92.9 million to Lomak Petroleum Incorporated (now known as Range Resources
Corporation). 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 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 3.1Bcf, or 11%, to 30.2 Bcf in the Western Region
due largely to new production from wells drilled and put on line in the Rocky
Mountains area during the last half of 1996 and in 1997, and from the acquired
Green River properties which produced 1.9 Bcfe. Natural gas production volumes
were up 3.5 Bcf, or 71%, to 8.4 Bcf in the Gulf Coast Region due largely to new
production from wells drilled and put on line during the last half of 1996 and
in 1997.
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 $0.18 per Mcf, or 9%, to $2.14,
increasing net operating revenues by approximately $5.4 million on 30.2 Bcf of
production. In the Gulf Coast Region, the average natural gas production sales
price increased $0.18 per Mcf, or 8%, to $2.52, increasing net operating
revenues by approximately $1.5 million on 8.4 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 Expenses. 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.
Interest expense, excluding the 1996 income tax refund, declined $1.1
million, or 6%, due to a reduction in the Company's long-term debt level.
31
Income tax expense, excluding the $2.8 million refund, 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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
- ---------------------------------------------------------------
Report of Independent Accountants 33
Consolidated Statement of Operations 34
Consolidated Balance Sheet 35
Consolidated Statement of Cash Flows 36
Consolidated Statement of Stockholders' Equity 37
Notes to Consolidated Financial Statements 38
Supplemental Oil & Gas Information (Unaudited) 56
Quarterly Financial Information (Unaudited) 58
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.
Ray Seegmiller
President and Chief Executive Officer
March 3, 1999
32
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE STOCKHOLDERS AND BOARD OF DIRECTORS OF CABOT OIL & GAS CORPORATION:
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of operations and stockholders' equity and of cash flows
present fairly, in all material respects, the financial position of Cabot Oil &
Gas Corporation and its subsidiaries at December 31, 1998 and 1997, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1998, in conformity with generally accepted
accounting principles. 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 of these
statements in accordance with generally accepted auditing standards which
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, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Houston, Texas
February 26, 1999
33
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
Year Ended December 31,
(In thousands, except per share amounts) 1998 1997 1996
- -------------------------------------------------------------------------------
NET OPERATING REVENUES
Natural Gas Production $138,903 $161,737 $137,482
Crude Oil and Condensate 8,486 11,443 10,992
Brokered Natural Gas Margin 5,547 4,113 5,619
Other 6,670 7,834 8,968
-------- -------- --------
159,606 185,127 163,061
OPERATING EXPENSES
Direct Operations 30,250 29,380 28,361
Exploration 19,564 13,884 12,559
Depreciation, Depletion and Amortization 41,186 40,598 42,689
Impairment of Unproved Properties 4,402 2,856 2,701
General and Administrative 21,950 19,744 16,823
Taxes Other Than Income 15,324 14,874 12,826
-------- -------- --------
132,676 121,336 115,959
Gain on Sale of Assets 473 61 1,685
-------- -------- --------
INCOME FROM OPERATIONS 27,403 63,852 48,787
Interest Expense 18,598 17,961 17,409
-------- -------- --------
Income Before Income Tax Expense 8,805 45,891 31,378
Income Tax Expense 3,501 17,557 10,554
-------- -------- --------
NET INCOME 5,304 28,334 20,824
Dividend Requirement on Preferred Stock 3,402 5,103 5,566
-------- -------- --------
Net Income Available to
Common Stockholders $ 1,902 $ 23,231 $ 15,258
======== ======== ========
Basic Earnings per Share Available
to Common Stockholders $ 0.08 $ 1.00 $ 0.67
======== ======== ========
Diluted Earnings per Share Available
to Common Stockholders $ 0.08 $ 0.97 $ 0.66
======== ======== ========
Average Common Shares Outstanding 24,733 23,272 22,807
======== ======== ========
- ----------
The accompanying notes are an integral part of these consolidated
financial statements.
34
CABOT OIL & GAS CORPORATION
CONSOLIDATED BALANCE SHEET
December 31,
(In thousands) 1998 1997
- -------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 2,200 $ 1,784
Accounts Receivable 55,799 59,672
Inventories 9,312 6,875
Other 3,804 2,202
-------- --------
Total Current Assets 71,115 70,533
PROPERTIES AND EQUIPMENT (Successful Efforts Method) 629,908 469,399
OTHER ASSETS 3,137 1,873
-------- --------
$704,160 $541,805
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current Portion of Long-Term Debt $ 16,000 $ 16,000
Accounts Payable 66,628 52,348
Accrued Liabilities 16,406 17,524
-------- --------
Total Current Liabilities 99,034 85,872
LONG-TERM DEBT 327,000 183,000
DEFERRED INCOME TAXES 85,952 80,108
OTHER LIABILITIES 9,506 8,763
COMMITMENTS AND CONTINGENCIES (Note 8)
STOCKHOLDERS' EQUITY
Preferred Stock:
Authorized -- 5,000,000 Shares of $0.10 Par Value
-- 6% Convertible Redeemable Preferred; $50
Stated Value; 1,134,000 Shares Outstanding in
1998 and 1997 113 113
Common Stock:
Authorized -- 40,000,000 Shares of $0.10 Par Value
Issued and Outstanding -- 24,959,897 Shares and
24,667,262 Shares at December 31, 1998 and 1997,
respectively 2,496 2,467
Class B Common Stock:
Authorized -- 800,000 Shares of $0.10 Par Value
No Shares Issued -- --
Additional Paid-in Capital 252,073 247,033
Accumulated Deficit (67,630) (65,551)
Less Treasury Stock, at cost:
302,600 Shares in 1998, No Shares in 1997 (4,384) --
-------- --------
Total Stockholders' Equity 182,668 184,062
-------- --------
$704,160 $541,805
======== ========
- ----------
The accompanying notes are an integral part of these consolidated
financial statements.
35
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended December 31,
(In thousands) 1998 1997 1996
- --------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 5,304 $ 28,334 $ 20,824
Adjustments to Reconcile Net Income
to Cash Provided by Operations:
Depletion, Depreciation and Amortization 41,186 40,598 42,689
Impairment of Long-Lived Assets -- -- --
Impairment of Unproved Properties 4,402 2,856 2,701
Deferred Income Tax Expense 5,844 10,681 12,017
Gain on Sale of Assets (473) (61) (1,685)
Exploration Expense 19,564 13,884 12,559
Other 1,834 1,419 176
Changes in Assets and Liabilities:
Accounts Receivable 3,873 8,137 (25,796)
Inventories (2,437) 1,922 (3,201)
Other Current Assets (1,602) (539) 46
Other Assets (1,264) (680) 243
Accounts Payable and Accrued Liabilities 10,263 (10,541) 11,199
Other Liabilities 743 (970) 3,713
-------- -------- --------
Net Cash Provided by Operations 87,237 95,040 75,485
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (203,632) (73,476) (60,719)
Proceeds from Sale of Assets 1,054 48,916 5,725
Exploration Expense (19,564) (13,884) (12,559)
-------- -------- --------
Net Cash Used by Investing (222,142) (38,444) (67,553)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt 217,000 11,000 6,000
Decrease in Debt (73,000) (60,000) (7,000)
Exercise of Stock Options 3,589 2,197 613
Treasury Stock Purchases (4,384) -- --
Preferred Dividends Paid (3,402) (5,644) (5,566)
Common Dividends Paid (3,974) (3,732) (3,649)
Increase in Debt Issuance Cost and Other (508) -- 8
-------- -------- --------
Net Cash Provided/(Used) by Financing 135,321 (56,179) (9,594)
-------- -------- --------
Net Increase (Decrease) in Cash and
Cash Equivalents 416 417 (1,662)
Cash and Cash Equivalents, Beginning of Year 1,784 1,367 3,029
-------- -------- --------
Cash and Cash Equivalents, End of Year $ 2,200 $ 1,784 $ 1,367
======== ======== ========
- ----------
The accompanying notes are an integral part of these consolidated
financial statements.
36
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
Retained
Common Preferred Treasury Paid-In Earnings
(In thousands) Stock Stock Stock Capital (Deficit) Total
- -----------------------------------------------------------------------------------------
Balance at December 31, 1995 $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, 1996 $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
at $0.16 Per Share (3,732) (3,732)
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
=========================================================
Net Income 5,304 5,304
Exercise of Stock Options 21 3,568 3,589
Preferred Stock Dividends (3,402) (3,402)
Common Stock Dividends
at $0.16 Per Share (3,974) (3,974)
Stock Grant Vesting 8 1,472 1,480
Treasury Stock Repurchase $(4,384) (4,384)
Other (7) (7)
---------------------------------------------------------
Balance at December 31, 1998 $2,496 $113 $(4,384) $252,073 $(67,630) $182,668
=========================================================
- ----------
The accompanying notes are an integral part of these consolidated
financial statements.
37
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 its 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 Company
operates in one segment, natural gas and oil exploration and exploitation.
The consolidated financial statements contain the accounts of the Company
after eliminating 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 to locate proved reserves, are capitalized.
The impairment of unamortized capital costs is measured at a lease level
and is reduced to fair value if it is determined that the sum of expected future
net cash flows is less than the net book value. The Company determines if an
impairment has occurred through either adverse changes or a 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. The costs of unproved
oil and gas properties are generally combined 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 on a units of production basis. The accrued
liability for plug and abandonment cost is included in accumulated depreciation,
depletion and amortization.
Costs of retired, sold or abandoned properties, which make up a part of an
amortization base, are charged to accumulated depreciation, depletion and
amortization. Accordingly, a gain or loss, if any, is recognized only when a
group of proved properties (or field), that make up the amortization base, has
been retired, abandoned or sold.
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. Production volume 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 these properties.
38
INCOME TAXES
The Company follows the asset and liability method of 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 $9.1 million and $5.5 million at
December 31, 1998 and 1997, respectively.
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
as on offset to the specific hedged item. 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 a hedge
are recognized currently in the results of operations.
A derivative instrument qualifies as a hedge if: (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 the 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 11. Financial Instruments for further discussion.
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" ("SFAS 133"). SFAS 133 requires all derivatives to be
recognized in the statement of financial position as either assets or
liabilities and measured at fair value. In addition, all hedging relationships
must be designated, reassessed and documented pursuant to the provisions of SFAS
133. This statement is effective for financial statements for fiscal years
beginning after June 15, 1999. The Company has not yet completed its evaluation
of the impact of the provisions from SFAS 133 on its financial position or
operations.
39
CASH EQUIVALENTS
The Company considers all highly liquid short-term investments with
original maturities of three months or less to be cash equivalents. At December
31, 1998 and 1997, the majority of cash and cash equivalents is concentrated in
one financial institution. The Company periodically assesses the financial
condition of the institution and believes that any possible credit risk is
minimal.
USE OF ESTIMATES
Preparing financial statements that conform 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 the remaining proved
oil and gas reserves (see Supplemental Oil and Gas Information). Actual results
could differ from those estimates.
2. PROPERTIES AND EQUIPMENT
Properties and equipment are comprised of the following:
December 31,
(In thousands) 1998 1997
- --------------------------------------------------------------------
Proved Oil and Gas Properties $ 921,463 $744,381
Unproved Oil and Gas Properties 42,426 24,618
Gathering and Pipeline Systems 121,999 116,360
Land, Building and Improvements 4,200 3,896
Other 20,468 17,525
---------- --------
1,110,556 906,780
Accumulated Depreciation,
Depletion and Amortization (480,648) (437,381)
---------- --------
$ 629,908 $469,399
========== ========
As a component of accumulated depreciation, depletion and amortization,
total future plug and abandonment cost, accrued on a units of production basis,
was $11.6 million and $13.1 million at December 31, 1998 and 1997, respectively.
The Company believes that this accrual method adequately provides for its
estimated future plug and abandonment cost over the reserve life of the oil and
gas properties.
40
3. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
December 31,
(In thousands) 1998 1997
- --------------------------------------------------------------------------
Accounts Receivable
Trade Accounts $41,397 $49,315
Joint Interest Accounts 6,712 4,843
Insurance Recoveries 5,539 3,043
Current Income Tax Receivable 502 1,291
Other Accounts 2,123 1,719
------- -------
56,273 60,211
Allowance for Doubtful Accounts (474) (539)
------- -------
$55,799 $59,672
======= =======
Accounts Payable
Trade Accounts $13,229 $ 6,209
Natural Gas Purchases 17,031 12,120
Wellhead Gas Imbalances 1,945 1,871
Royalty and Other Owners 8,987 11,995
Capital Costs 20,165 12,936
Dividends Payable 851 851
Taxes Other Than Income 1,017 1,478
Drilling Advances 900 2,333
Other Accounts 2,503 2,555
------- -------
$66,628 $52,348
======= =======
Accrued Liabilities
Employee Benefits $ 4,479 $ 6,067
Taxes Other Than Income 7,357 8,314
Interest Payable 2,406 2,147
Other Accrued 2,164 996
------- -------
$16,406 $17,524
======= =======
Other Liabilities
Postretirement Benefits Other Than Pension $ 316 $ 992
Accrued Pension Cost 4,941 3,742
Taxes Other Than Income and Other 4,249 4,029
------- -------
$ 9,506 $ 8,763
======= =======
4. INVENTORIES
Inventories are comprised of the following:
December 31,
(In thousands) 1998 1997
- --------------------------------------------------------------------------
Natural Gas in Storage $ 7,524 $ 6,322
Tubular Goods and Well Equipment 1,714 1,663
Pipeline Exchange Balances 74 (1,110)
------- -------
$ 9,312 $ 6,875
======= =======
41
5. DEBT AND CREDIT AGREEMENTS
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 each May starting in 1998.
The payment due in May 1999, classified as "Current Portion of Long-Term Debt",
is a current liability on the Company's Consolidated Balance Sheet. The Company
may prepay all or any portion of the debt at any time with a prepayment penalty.
The 10.18% Notes contain restrictions on the merger of the Company or any
subsidiary with a third party except under certain limited conditions. There are
also 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 penalty. 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. There are also 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
In November 1998, the Company replaced its $135 million Revolving Credit
Agreement that utilized five banks with a new $250 million Revolving Credit
Agreement (the "Credit Facility") with ten banks. The term of the credit
facility is five years and expires on December 17, 2003. The available credit
line is subject to adjustment from time-to-time on the basis of the projected
present value (as determined by the banks' petroleum engineer) of estimated
future net cash flows from certain proved oil and gas reserves and other assets
of the Company. While the Company does not expect a change in the available
credit line, in the event that it is adjusted below the outstanding level of
borrowings, the Company has a period of 180 days to reduce its outstanding debt
to the adjusted credit line. The Revolving Credit Agreement also includes a
requirement to pay down half of the debt in excess of the adjusted credit line
within the first 90 days of such an adjustment. 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. For CD rate and LIBOR
borrowings, interest rates are subject to increase if the indebtedness under the
Credit Facility is either greater than 60% or 80% of the Company's debt limit of
$400 million, as shown below.
Debt Percentage
Lower than 60% 60% - 80% Higher than 80%
- ----------------------------------------------------------------------------
LIBOR margin 0.750% 1.00% 1.250%
CD margin 0.875% 1.125% 1.375%
Commitment fee rate 0.250% 0.3750% 0.3750%
The Credit Facility provides for a commitment fee on the unused available
balance at an annual rate 1/4 of 1% and 3/8 of 1% depending on the level of
indebtedness as indicated above. The Company's effective interest rates for the
Credit Facility in the years ended December 31, 1998, 1997 and 1996 were 6.8%,
6.6% and 6.6%, respectively. The Credit Facility contains various customary
restrictions, including (i) prohibiting the merger of the Company or any
subsidiary with a third party except 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.
42
6. EMPLOYEE BENEFIT PLANS
PENSION PLAN
The Company has a non-contributory, defined benefit pension plan for all
full-time employees. Plan benefits are based primarily on years of service and
salary level near retirement. Plan assets are mainly fixed income investments
and equity securities. The Company complies with the Employee Retirement Income
Security Act of 1974 and Internal Revenue Code limitations when funding the
plan.
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,
1998, 1997 and 1996 are comprised of the following:
(In thousands) 1998 1997 1996
- --------------------------------------------------------------------------
Qualified:
Current Year Service Cost $ 853 $ 753 $ 737
Interest Accrued on Pension Obligation 945 810 744
Actual Return on Plan Assets (1,434) (1,129) (948)
Net Amortization and Deferral 706 491 448
Recognized Gain (20) -- --
------ ------ ------
Net Periodic Pension Cost $1,050 $ 925 $ 981
====== ====== ======
Non-Qualified:
Current Year Service Cost $ 81 $ 28 $ 90
Interest Accrued on Pension Obligation 45 6 6
Net Amortization 54 27 34
Recognized Loss 20 -- --
Settlement Charge 213 -- --
------ ------ ------
Net Periodic Pension Cost $ 413 $ 61 $ 130
====== ====== ======
The following table illustrates the funded status of the Company's pension
plans at December 31, 1998 and 1997, respectively:
1998 1997
Non- Non-
(In thousands) Qualified Qualified Qualified Qualified
- --------------------------------------------------------------------------------
Actuarial Present Value of:
Accumulated Benefit Obligation $10,552 $438 $ 8,669 $363
Projected Benefit Obligation $15,491 $959 $12,772 $668
Plan Assets at Fair Value 10,344 -- 8,890 --
------- ---- ------- ----
Projected Benefit Obligation in
Excess of Plan Assets 5,147 959 3,882 668
Unrecognized Net Gain (Loss) 657 (537) 1,527 (436)
Unrecognized Prior Service Cost (774) (784) (862) (349)
Adjustment to Recognize Minimum
Liability -- 801 -- 480
------- ---- ------- ----
Accrued Pension Cost $ 5,030 $439 $ 4,547 $363
======= ==== ======= ====
43
In February 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 132, Employers' Disclosures about Pensions
and Other Postretirement Benefits ("SFAS 132"). The Company has adopted this
statement effective December 31, 1998. SFAS 132 standardizes the disclosure
requirements for pensions and other postretirement benefits as contained below.
This is a presentation requirement only and does not have an effect on the
financial position or operating results of the Company.
The change in the combined projected benefit obligation of the Company's
qualified and non-qualified pension plans during the last three years is
explained as follows:
(In thousands) 1998 1997 1996
- ------------------------------------------------------------------------------
Beginning of Year $13,441 $11,041 $10,153
Service Cost 935 781 827
Interest Cost 990 817 750
Plan Amendments 488 - -
Actuarial Loss (Gain) 1,803 1,192 (256)
Benefits Paid (1,208) (390) (433)
------- ------- -------
End of Year $16,449 $13,441 $11,041
======= ======= =======
The change in the combined plan assets at fair value of the Company's
qualified and non-qualified pension plans during the last three years is
explained as follows:
(In thousands) 1998 1997 1996
- ------------------------------------------------------------------------------
Beginning of Year $ 8,890 $ 7,074 $ 6,417
Actual Return on Plan Assets 1,608 1,305 1,113
Employer Contribution 1,227 1,077 142
Benefits Paid (1,208) (390) (433)
Expenses Paid (173) (176) (165)
------- ------- -------
End of Year $10,344 $ 8,890 $ 7,074
======= ======= =======
The reconciliation of the combined funded status of the Company's qualified
and non-qualified pension plans at the end of the last three years is explained
as follows:
(In thousands) 1998 1997 1996
- ------------------------------------------------------------------------------
Funded Status $ 6,105 $ 4,550 $ 3,967
Unrecognized Gain 121 1,091 1,890
Unrecognized Prior Service Cost (1,558) (1,211) (1,336)
------- ------- -------
Net Amount Recognized $ 4,668 $ 4,430 $ 4,521
======= ======= =======
Accrued Benefit Liability - Qualified Plan $ 5,030 $ 4,547 $ 4,686
Accrued Benefit Liability - Non-Qualified Plan 439 363 81
Intangible Asset (801) (480) (246)
------- ------- -------
Net Amount Recognized $ 4,668 $ 4,430 $ 4,521
======= ======= =======
44
Assumptions used to determine benefit obligations and pension costs are as
follows:
1998 1997 1996
- -------------------------------------------------------------------------------
Discount Rate 7.00%(1) 7.50% 7.50%
Rate of Increase in Compensation Levels 4.00% 4.50% 4.50%
Long-Term Rate of Return on Plan Assets 9.00% 9.00% 9.00%
- ----------
(1) Represents the rate used to determine the benefit obligation. A 7.5%
discount rate was 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 $0.8 million, $0.6 million and $0.6 million in 1998, 1997 and 1996,
respectively. The Company's Common Stock is an investment option within the SIP.
DEFERRED COMPENSATION PLAN
In 1998, the Company established a deferred compensation plan. This plan is
available to officers of the Company and acts as a supplement to the savings
investment plan. The Company matches a portion of the employee's contribution
and those assets are invested in instruments selected by the employee. Unlike
the SIP, the deferred compensation plan does not have dollar limits on tax
deferred contributions. However, the assets of this plan are held in a rabbi
trust and are subject to additional risk of loss in the event of bankruptcy or
insolvency of the Company. At December 31, 1998, the balance in deferred
compensation plan's rabbi trust was $0.9 million.
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"). Most employees become eligible for these benefits if they meet
certain age and service requirements at retirement. The Company was providing
postretirement benefits to 251 retirees and 259 retirees at the end of 1998 and
1997, respectively.
When the Company adopted SFAS 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions", in 1992, it began amortizing the
$16.9 million accumulated postretirement benefit (the "Transition Obligation")
over a period of 20 years.
The amortization benefit of the unrecognized Transition Obligation in 1998,
1997 and 1996, 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 was amortized
over a 5.75 year period beginning in 1993 and ending in 1998.
Postretirement benefit costs recognized in the years ended December 31,
1998, 1997 and 1996 are as follows:
(In thousands) 1998 1997 1996
- --------------------------------------------------------------------------------
Service Cost of Benefits Earned During the Year $ 190 $ 168 $ 99
Interest Cost on the Accumulated Postretirement
Benefit Obligation 525 519 522
Amortization Benefit of the Unrecognized Gain (165) (181) (163)
Amortization Benefit of the Unrecognized
Transition Obligation (435) (808) (807)
----- ----- -----
Total Postretirement Benefit Cost (Benefit) $ 115 $(302) $(349)
===== ===== =====
45
The health care cost trend rate used to measure the expected cost in 1998
for medical benefits to retirees over age 65 was 8.1%, graded down to a trend
rate of 0% in 2001. The health care cost trend rate used to measure the expected
cost in 1998 for retirees under age 65 was 8.2%, 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 to determine the actuarial present
value of the benefit obligation was 7.0% at December 31, 1998 and 7.5% at
December 31, 1997.
A one-percentage-point increase in health care cost trend rates for future
periods would increase the accumulated net postretirement benefit obligation by
approximately $105 thousand and, accordingly, the total postretirement benefit
cost recognized in 1998 would have also increased by approximately $12 thousand.
Similarly, a one-percentage-point decrease in health care cost trend rates for
future periods would decrease the accumulated net postretirement benefit
obligation by approximately $144 thousand and, accordingly, the total
postretirement benefit cost recognized in 1998 would have also decreased by
approximately $13 thousand.
The funded status of the Company's postretirement benefit obligation at
December 31, 1998 and 1997 is comprised of the following:
(In thousands) 1998 1997
- ------------------------------------------------------------------------------
Plan Assets at Fair Value $ -- $ --
Accumulated Postretirement Benefits Other Than Pensions 7,693 7,303
Unrecognized Cumulative Net Gain 2,086 2,429
Unrecognized Transition Obligation (8,883) (8,395)
------- -------
Accrued Postretirement Benefit Liability $ 896 $ 1,337
======= =======
The change in the accumulated postretirement benefit obligation during the
last three years is explained as follows:
(In thousands) 1998 1997 1996
- -----------------------------------------------------------------------------
Beginning of Year $7,303 $7,207 $7,234
Service Cost 190 168 99
Interest Cost 526 519 522
Amendments 0 0 0
Actuarial Loss/(Gain) 230 3 (231)
Benefits Paid (556) (594) (417)
------ ------ ------
End of Year $7,693 $7,303 $7,207
====== ====== ======
46
7. INCOME TAXES
Income tax expense (benefit) is summarized as follows:
Year Ended December 31,
(In thousands) 1998 1997 1996
- -------------------------------------------------------------------
Current:
Federal $ 317 $ 5,210 $(1,229)
State 65 1,089 316
------- ------- -------
Total 382 6,299 (913)
------- ------- -------
Deferred:
Federal 2,856 9,382 9,756
State 263 1,876 1,711
------- ------- -------
Total 3,119 11,258 11,467
------- ------- -------
Total Income Tax Expense $ 3,501 $17,557 $10,554
======= ======= =======
Total income taxes were different than the amounts computed by applying the
statutory federal income tax rate as follows:
Year Ended December 31,
(In thousands) 1998 1997 1996
- -----------------------------------------------------------------------------
Statutory Federal Income Tax Rate 35% 35% 35%
Computed "Expected" Federal Income Tax $ 3,081 $16,062 $10,982
State Income Tax, Net of Federal Income Tax 352 1,927 1,317
Other, Net 68 (432) (1,745)
------- ------- -------
Total Income Tax Expense $ 3,501 $17,557 $10,554
======= ======= =======
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 resulted in significant
portions of the deferred tax liabilities and deferred tax assets as of December
31, 1998 and 1997 were as follows:
(In thousands) 1998 1997
- ----------------------------------------------------------------------------
Deferred Tax Liabilities:
Property, Plant and Equipment $137,061 $115,808
-------- --------
Deferred Tax Assets:
Alternative Minimum Tax Credit Carryforwards 7,241 9,674
Net Operating Loss Carryforwards(1) 25,663 6,749
Note Receivable on Section 29 Monetization(2) 12,320 13,933
Items Accrued for Financial Reporting Purposes 5,885 5,344
-------- --------
51,109 35,700
-------- --------
Net Deferred Tax Liabilities $ 85,952 $ 80,108
======== ========
- ----------
(1) The 1998 amount includes the effect of $2.7 million in income tax refunds
received in 1998 that applied to a net operating loss carryback to 1992 and
an overpayment of 1997 federal income tax.
(2) As a result of the monetization of Section 29 tax credits in 1996 and 1995,
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.
47
At December 31, 1998, the Company has a net operating loss carryforward for
regular income tax reporting purposes of $64.2 million that will begin expiring
in 2011. In addition, the Company has an alternative minimum tax credit
carryforward of $7.2 million which does not expire and can be used to offset
regular income taxes in future years to the extent that regular income taxes
exceed the alternative minimum tax in any year.
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 the leases expire within five years and may be renewed. Rent
expense under such arrangements totaled $4.3 million, $4.1 million and $4.8
million for the years ended December 31, 1998, 1997 and 1996, respectively. In
1998, the Company entered into a ten-year lease agreement for office space in
Houston, Texas intended to house the corporate offices and the Gulf Coast Region
offices. This new office space is currently under construction and the Company
expects to begin leasing the space in mid to late 1999. The lease for the
existing office space will expire in the fourth quarter of 1999.
Future minimum rental commitments under non-cancelable leases in effect at
December 31, 1998 are as follows:
(In thousands)
-----------------------------------
1999 $ 3,440
2000 3,890
2001 3,784
2002 3,679
2003 2,468
Thereafter 12,327
-------
$29,588
=======
Minimum rental commitments are not reduced by minimum sublease rental income of
$1.4 million due in the future under non-cancelable subleases.
CONTINGENCIES
The Company is a defendant in various lawsuits and is involved in other gas
contract issues. In the Company's opinion, final judgments or settlements, if
any, which may be awarded in connection with any one or more of these suits and
claims could have a significant impact on the results of operations and cash
flows of any period. However, there would not be a material adverse effect on
the Company's financial position.
9. CASH FLOW INFORMATION
Cash paid for interest and income taxes is as follows:
Year Ended December 31,
(In thousands) 1998 1997 1996
---------------------------------------------------------------
Interest $18,341 $18,001 $17,105
Income Taxes $ 827 $ 8,980 $ 873
At December 31, 1998 and 1997, the Accounts Payable balance on the
Consolidated Balance Sheet included payables for capital expenditures of $20.2
million and $12.9 million, respectively.
48
10. CAPITAL STOCK
INCENTIVE PLANS
On May 12, 1998, the Amended and Restated 1994 Long-Term Incentive Plan and
the Amended and Restated 1994 Non-Employee Director Stock Option Plan were
approved by the shareholders. The Company has two other stock option plans - the
1990 Incentive Stock Option Plan 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 3,860,000 shares of Common Stock, par value $0.10 per share, may be issued
under the Incentive Plans. All stock options have a maximum term of five or ten
years from the date of grant, with most vesting 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:
December 31,
1998 1997 1996
- --------------------------------------------------------------------------------
Shares Under Option at Beginning of Period 1,404,877 1,532,353 1,310,318
Granted 355,000 82,500 311,750
Exercised 152,917 139,836 41,094
Surrendered or Expired 49,024 70,140 48,621
--------- --------- ---------
Shares Under Option at End of Period 1,557,936 1,404,877 1,532,353
========= ========= =========
Weighted Average Option Price $ 13.25 - $ 13.25 - $ 13.25 -
22.75 26.00 26.00
Options Exercisable at End of Period 1,092,295 1,071,923 1,021,362
========= ========= =========
Under the Amended and Restated 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 year. The number of shares of Common Stock received at the end of the
performance period is based mainly on the relative stock price growth between
the two measurement dates of Common Stock compared to that of a group of peer
companies. The performance shares that were granted on July 1, 1994 expired on
June 30, 1997 without issuing any Common Stock of the Company. Performance
shares granted in July 1995 were converted to 21,692 shares of the Company's
Common Stock in 1998. Performance shares granted in July 1996 may be converted
to shares of Common Stock, depending upon the Company's relative performance to
the peer group measured on June 30, 1999.
Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting
for Stock-Based Compensation", outlines a fair value based method of accounting
for stock options or similar equity instruments. The Company has opted to
continue using the intrinsic value based method, as recommended by Accounting
Principles Board ("APB") Opinion No. 25, to measure compensation cost for its
stock option plans.
If the Company had adopted SFAS 123, the pro forma results of operations
would be net income of $1.6 million, $22.9 million and $14.8 million, or $0.06 ,
$0.98 and $0.65 per share, in 1998, 1997 and 1996, respectively. Under the fair
value based method, the weighted average fair values of options granted during
1998, 1997 and 1996 were $6.21, $4.26 and $5.51, 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 1998, 1997 and
1996: stock price volatility of 26.1, 27.8 and 25.9 percent, respectively; risk
free rate of return of 5.63, 6.34 and 6.24 percent, respectively; dividend rate
of $0.16 per year; and an expected term of three to four 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.
49
DIVIDEND RESTRICTIONS
The Board of Directors of the Company determines the amount of future cash
dividends, if any, to be declared and paid on the Common Stock depending on,
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 making payments,
the dividend exceeds consolidated net cash flow (as defined) and the ratio of
proved reserves to debt is less than 1.7 to 1, or there has been an event of
default under the Note Agreement. As of December 31, 1998, these restrictions
did not impact on the Company's ability to pay regular dividends. The 7.19% Note
Agreement issued in 1997 does not have a restricted payment provision.
TREASURY STOCK
In August 1998, the Board of Directors authorized the Company to repurchase
up to two million shares of outstanding Common Stock at market prices. The
timing and amount of these stock purchases are determined at the discretion of
management. The Company may use the repurchased shares to fund stock
compensation programs presently in existence, or for other corporate purposes.
As of December 31, 1998, the Company had repurchased 302,600 shares, or 15% of
the total authorized number of shares, for a total cost of approximately $4.4
million. The stock repurchase plan was funded with cash from increased
borrowings on the revolving credit facility. No treasury shares were delivered
or sold by the Company during the year.
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. An exception to the right occurs
following a tender or exchange offer for all outstanding shares of Common Stock
determined 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. 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. Once it becomes
exercisable, 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, 1998 and 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, 1998 and 1997, 1,134,000 shares of 6% convertible
redeemable preferred stock ("6% preferred stock") were issued and outstanding.
Each share has voting rights equal to approximately 1.7 shares of Common Stock
and a stated value of $50. At any time, the stock is convertible by the holder
into Common Stock at a conversion price of $28.75 per share. While the 6%
preferred stock does not have a mandatory redemption requirement, it is
redeemable, starting after May 1, 1998, at the Company's option ("redemption
option"). During the first year of the redemption option, the Company may redeem
the 6% preferred stock at $50 per share, payable in Common Stock, using an
average market price of the Common Stock for a 30 day period as defined in the
agreement, plus a cash payment for the accrued dividends due on the shares
redeemed. After the first year of the redemption option, the $50 per share
redemption price is payable in cash, plus a cash payment for accrued dividends
due on the shares redeemed.
50
Prior to the Company converting these shares into 1,648,664 shares of
Common Stock in October 1997, 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 could be converted any
time by the holder into Common Stock at a conversion price of $21 per share.
While there was no mandatory requirement, these shares could also be redeemed
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.
11. FINANCIAL INSTRUMENTS
The estimated fair value of financial instruments is the amount at which
the instrument could be exchanged currently between willing parties. The
carrying amounts reported in the consolidated balance sheet for cash and cash
equivalents, accounts receivable, and accounts payable approximate fair value.
The Company uses available marketing data and valuation methodologies to
estimate fair value of debt.
December 31, 1998 December 31, 1997
Carrying Estimated Carrying Estimated
(In thousands) Amount Fair Value Amount Fair Value
- --------------------------------------------------------------------------------
Debt:
10.18% Notes $ 64,000 $ 68,185 $ 80,000 $ 86,555
7.19% Notes 100,000 93,145 100,000 102,693
Credit Facility 179,000 179,000 19,000 19,000
-------- -------- -------- --------
$343,000 $340,330 $199,000 $208,248
======== ======== ======== ========
Other Financial Instruments:
Gas Price Swaps -- $(231) -- $(350)
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 difference 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 on interest rates currently available to the Company. The Credit
Facility approximates fair value because this instrument bears interest at rates
based on current market rates.
GAS PRICE SWAPS
From time to time, the Company enters into natural gas swap agreements
("price swaps"), a type of derivative instrument, with counterparties to hedge
price risk associated with a portion of the Company's production. Under these
price swaps, the Company receives a fixed price ("fixed price swaps") on a
notional quantity of natural gas in exchange for paying a variable price based
on a market-based index, such as the Nymex gas futures. Notional quantities of
natural gas are used in each price swap, since no physical exchange or delivery
of natural gas is involved. During 1998 and 1997, the Company entered into no
fixed price swaps to hedge natural gas prices on its production. In 1996, the
prices received on fixed price swaps ranged from $1.02 to $2.54 per Mmbtu on
total notional quantities of 17,600,000 Mmbtu, representing 27% of 1996
production.
51
In addition, the Company uses price swaps to hedge the natural gas price
risk on brokered transactions. Typically, the Company enters into contracts to
broker natural gas at a variable price based on the market index price. However,
in some circumstances, some of the Company's customers or suppliers request that
a fixed price be stated in the contract. After entering into these fixed price
contracts to meet the needs of its customers or suppliers, the Company may use
price swaps to effectively convert these fixed price contracts to
market-sensitive price contracts. These price swaps are held by the Company to
their maturity and are not held for trading purposes. During 1998, the Company
entered into price swaps with total notional quantities of 2,226,000 Mmbtu
related to its brokered activities, representing less than 5% of the Company's
total volume of brokered natural gas sold. A pre-tax loss of $0.3 million was
recorded from these price swaps in 1998. In 1997 and 1996, these price swaps had
total notional quantities of 1,416,000 Mmbtu and 1,002,000 Mmbtu related to
brokered transactions, and represented approximately 4% and 3%, respectively, of
the Company's total volume of brokered natural gas sold. At December 31, 1998,
the Company had open price swaps with notional quantities of 1,730,000 Mmbtu and
an unrealized loss of $0.2 million on these open contracts.
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 and the Capital Resources and Liquidity section of Item
7.
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
natural gas price agreements, the amounts that can be subject to credit risk in
the event of non-performance by third parties are substantially smaller. The
Company does not anticipate any material impact on its financial results due to
non-performance by the third parties.
12. OIL AND GAS PROPERTY TRANSACTIONS
The Company acquired oil and gas producing properties in Oklahoma during
the second quarter of 1998 for $6.6 million. Included in the purchase were 9.3
Bcfe of proved reserves, ten wells and undeveloped acreage.
In the fourth quarter of 1998, the Company purchased oil and gas producing
properties in the Lookout Wash Unit of Wyoming from Oxy USA, Inc. for $5.2
million. The properties acquired included 11.2 Bcfe of proved reserves and more
than ten potential drilling locations.
Effective December 1, 1998, the Company purchased onshore Southern
Louisiana properties and 3-D seismic inventory from Oryx Energy Company for
approximately $70.1 million. The purchased assets included ten fields covering
over 34,000 net acres with 68 producing wells. Total proved reserves are
approximately 72 Bcfe. This transaction was funded by the Company's newly
expanded revolving line of credit. See discussion in Note 5. Debt and Credit
Agreements.
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 (now known as Range Resources Corporation) 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.
The Company sold various non-core oil and gas properties in the Appalachian
Region for $4.6 million in 1996.
52
13. OTHER REVENUE
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. This income was recorded as a reduction to the net book value of natural
gas properties. Revenue from these transactions was $2.7 million in 1998, $3.6
million in 1997 and $3.4 million in 1996. These transactions are expected to
generate additional future revenues through 2002 of $11.1 million related to the
value of future Section 29 tax credits attributable to these properties. Using a
volumetric production payment structure, the production, revenues, expenses and
proved reserves for these properties will continue to be reported by the Company
as Other Revenue until the production payment is satisfied.
14. 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 also be useful. As a result, the
following supplemental full cost information is also included.
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. These 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 this case, a gain or loss is recognized.
Unevaluated properties and associated costs not currently being amortized and
included in oil and gas properties totaled $42.4 million, $24.6 million, and
$15.7 million at December 31, 1998, 1997, and 1996, respectively.
Because of the capital cost limitations, described above, full cost
entities are not subject to the impairment test prescribed by SFAS 121.
1998 1997 1996
------------------ ------------------ -----------------
Successful Full Successful Full Successful Full
(In thousands, except per share amounts) Efforts Cost Efforts Cost Efforts Cost
- -------------------------------------------------------------------------------------------------------
BALANCE SHEET:
Properties and Equipment, Net $629,907 $816,759 $469,399 $651,739 $480,511 $657,957
Stockholders' Equity 182,668 297,583 184,062 296,201 160,704 269,833
INCOME STATEMENT:
Depreciation, Depletion, Amortization
and Unproved Property Impairment $ 45,588 $ 60,165 $ 43,454 $ 52,383 $ 45,390 $ 50,769
Net Income Available to
Common Stockholders 1,902 4,676(1) 23,231 26,240(1) 15,258 18,637(1)
Basic Earnings Per Share $ 0.08 $ 0.19 $ 1.00 $ 1.13 $ 0.67 $ 0.82
- ----------
(1) Supplementary full cost information does not include the effect of
allowable capitalization of general and administrative, region office and
interest expense. Pretax capitalizable administrative expenses were $4.6
million in 1998, $4.2 million in 1997, and $3.7 million in 1996. Pretax
capitalizable interest expense was $2.0 million in 1998, $1.4 million in
1997 and $1.1 million in 1996.
53
15. EARNINGS PER COMMON SHARE
Basic earnings per share for the Company were $0.08, $1.00, and $0.67 in
1998, 1997 and 1996, respectively, and were based on the weighted average shares
outstanding of 24,733,465 in 1998, 23,272,432 in 1997, and 22,806,516 in 1996.
Diluted earnings per share for the Company were $0.08, $0.97, and $0.66 in 1998,
1997 and 1996, respectively. The diluted earnings per share amounts are based on
weighted average shares outstanding plus common stock equivalents. Common stock
equivalents include both stock awards and stock options, and totaled 372,937 in
1998, 649,632 in 1997, and 186,000 in 1996.
Both the $3.125 cumulative convertible preferred stock and the 6%
convertible redeemable preferred stock ("preferred stock") issued May 1993 and
May 1994, respectively, had an antidilutive effect on earnings per common share.
The preferred stock was determined not to be a common stock equivalent when it
was issued. As such, no adjustments were made to reported net income in the
computation of earnings per share. The Company, under the provisions of the
stock, converted the $3.125 cumulative convertible preferred stock to Common
Stock in October 1997. See Note 10. Capital Stock for further discussion.
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. As a result, 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 subjective decisions and
variances in available data for various reservoirs make these estimates
generally less precise than other estimates included in the 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 in effect when the estimates were made.
Proved developed reserves are proved reserves expected to be recovered
through wells and equipment in place and under operating methods used when the
estimates were made.
Estimates of proved and proved developed reserves at December 31, 1998,
1997 and 1996 were based on studies performed by the Company's petroleum
engineering staff. The estimates were reviewed by Miller and Lents, Ltd., who
indicated in their letter dated February 9, 1999 that, based on their
investigation and subject to the limitations described in their letter, they
believe that the results of those estimates and projections were reasonable in
the aggregate.
No major discovery or other favorable or unfavorable event after December
31, 1998 is believed to have caused a material change in the estimates of proved
or proved developed reserves as of that date.
The following table illustrates the Company's net proved reserves,
including changes, and proved developed reserves for the periods indicated, as
estimated by the Company's engineering staff. All reserves are located in the
United States.
54
Natural Gas
-----------------------------
December 31,
(Millions of cubic feet) 1998 1997 1996
- -------------------------------------------------------------------------------
PROVED RESERVES
Beginning of Year 903,429 915,617 889,850
Revisions of Prior Estimates (13,097) 6,744 2,774
Extensions, Discoveries and Other Additions 94,891 109,191 69,708
Production (64,167) (63,889) (58,762)
Purchases of Reserves in Place 76,234 73,836 37,397
Sales of Reserves in Place (534) (138,070) (25,350)
------- ------- -------
End of Year 996,756 903,429 915,617
======= ======= =======
PROVED DEVELOPED RESERVES 788,390 738,764 768,097
======= ======= =======
Liquids
-----------------------------
December 31,
(Thousands of barrels) 1998 1997 1996
- -------------------------------------------------------------------------------
PROVED RESERVES
Beginning of Year 5,869 5,166 5,310
Revisions of Prior Estimates (1,644) 99 (132)
Extensions, Discoveries and Other Additions 835 794 386
Production (736) (629) (597)
Purchases of Reserves in Place 3,353 594 215
Sales of Reserves in Place -- (155) (16)
----- ----- -----
End of Year 7,677 5,869 5,166
===== ===== =====
PROVED DEVELOPED RESERVES 5,822 4,859 4,685
===== ===== =====
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
The following table illustrates the total amount of capitalized costs
relating to natural gas and crude oil producing activities and the total amount
of related accumulated depreciation, depletion and amortization.
Year Ended December 31,
(In thousands) 1998 1997 1996
- -------------------------------------------------------------------------------
Aggregate Capitalized Costs Relating
to Oil and Gas Producing Activities $1,107,877 $904,669 $997,531
Aggregate Accumulated Depreciation,
Depletion and Amortization $ 478,766 $435,502 $517,249
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND
DEVELOPMENT ACTIVITIES
Costs incurred in property acquisition, exploration and development
activities were as follows:
55
Year Ended December 31,
(In thousands) 1998 1997 1996
- --------------------------------------------------------------------------
Property Acquisition Costs - Proved $ 83,584 $ 45,573 $ 6,637
Property Acquisition Costs - Unproved 15,587 4,302 4,355
Exploration and Extension Well Costs 36,310 28,633 14,192
Development Costs 82,235 53,441 41,036
-------- -------- --------
Total Costs $217,716 $131,949 $ 66,220
======== ======== ========
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:
Year Ended December 31,
(In thousands) 1998 1997 1996
- -----------------------------------------------------------------------------
Operating Revenues $147,856 $173,865 $150,096
Costs and Expenses
Production 38,802 39,068 35,161
Other Operating 20,070 18,017 15,155
Exploration 19,564 13,884 12,559
Depreciation, Depletion and Amortization 43,127 39,485 40,810
-------- -------- --------
Total Cost and Expenses 121,563 110,454 103,685
-------- -------- --------
Income Before Income Taxes 26,293 63,411 46,411
Provision for Income Taxes Expense 9,203 22,194 16,244
-------- -------- --------
Results of Operations $ 17,090 $ 41,217 $ 30,167
======== ======== ========
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO
PROVED OIL AND GAS RESERVES
The following information has been developed utilizing SFAS 69 procedures
and based on natural gas and crude oil reserve and production volumes estimated
by the Company's engineering staff. It can be used for some comparisons, but
should not be the only method used to evaluate the Company or its performance.
Further, the information in the following table may not represent 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 when 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 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 a reasonable measure of the relative risk that
is part of 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, 1998, 1997
and 1996 were for natural gas ($/Mcf) $2.26, $2.62 and $3.77, respectively, and
for oil ($/Bbl) $10.23, $19.02 and $22.86, respectively. Future cash inflows
were reduced by estimated future development and production costs based on
year-end costs to arrive at net cash flow before tax. Future income tax expense
was computed by applying year-end statutory tax rates to future pretax net cash
flows, less the tax basis of the properties involved. SFAS 69 requires the use
of a 10% discount rate.
56
Management does not use only the following information when making
investment and operating decisions. These decisions are based on a number of
factors, including estimates of probable as well as proved reserves, and varying
price and cost assumptions considered more representative of a range of
anticipated economic conditions.
Standardized Measure is as follows:
Year Ended December 31,
(In thousands) 1998(1) 1997(1) 1996(1)
- -------------------------------------------------------------------------------
Future Cash Inflows $2,382,860 $2,539,287 $3,528,558
Future Production and
Development Costs (780,705) (686,689) (773,631)
---------- ---------- ----------
Future Net Cash Flows Before
Income Taxes 1,602,155 1,852,598 2,754,927
10% Annual Discount for
Estimated Timing of Cash Flows (863,226) (1,013,837) (1,589,290)
---------- ---------- ----------
Standardized Measure of
Discounted Future Net Cash Flows
Before Income Taxes 738,929 838,761 1,165,637
Future Income Tax Expenses,
Net of 10% Annual Discount (2) (144,851)(4) (227,796) (331,331)
---------- ---------- ----------
Standardized Measure of Discounted
Future Net Cash Flows(3) $ 594,078 $ 610,965 $ 834,306
========== ========== ==========
- ----------
(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 13.
of the Notes to the Consolidated Financial Statements.
(2) Future income taxes before discount were $446,980, $582,639 and $887,583
for the years ended December 31, 1998, 1997 and 1996, respectively.
(3) The change in discounted future cash flows from 1996 to 1997 is primarily a
result of the $1.15 per Mcf decrease in average natural gas price.
(4) Future income tax expense decreased as a result of tax benefits realized on
property acquisitions and drilling activity late in 1998.
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:
Year Ended December 31,
(In thousands) 1998 1997 1996
- ------------------------------------------------------------------------------
Beginning of Year $610,965 $834,306 $512,948
Discoveries and Extensions,
Net of Related Future Costs 72,275 113,032 99,983
Net Changes in Prices and Production Costs (195,554) (367,112) 416,042
Accretion of Discount 83,876 116,564 66,530
Revisions of Previous Quantity
Estimates, Timing and Other (1) (36,522) (10,798) (7,874)
Development Costs Incurred 20,236 17,435 10,294
Sales and Transfers, Net of Production Costs (109,054) (138,274) (114,935)
Net Purchases (Sales) of Reserves in Place 64,911 (57,723) 30,293
Net Change in Income Taxes 82,945 103,535 (178,975)
-------- -------- --------
End of Year $594,078 $610,965 $834,306
======== ======== ========
- ----------
(1) Includes the effect of a 14.3 Bcfe downward revision in 1998 due to lower
year-end pricing.
57
CABOT OIL & GAS CORPORATION
SELECTED DATA (UNAUDITED)
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
(In thousands except
per share amounts) First Second Third Fourth Total
- --------------------------------------------------------------------------------
1998
Net Operating Revenues $40,791 $41,667 $37,386 $39,762 $159,606
Operating Income 10,714 9,876 1,701 5,112 27,403
Net Income/(Loss) 2,993 2,283 (2,524) (850) 1,902
Basic Earnings/(Loss) Per Share $ 0.12 $ 0.09 $ (0.10) $ (0.03) $ 0.08
Diluted Earnings/(Loss) Per Share $ 0.12 $ 0.09 $ (0.10) $ (0.03) $ 0.08
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
Diluted Earnings Per Share $ 0.41 $ 0.08 $ 0.10 $ 0.38 $ 0.97
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 under the caption "Election of Directors" in the Company's
definitive proxy statement ("Proxy Statement") in connection with the 1999
annual stockholders meeting is incorporated by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information under the caption "Executive Compensation" in the Proxy
Statement is incorporated by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information 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 by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
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 33.
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 (Form 10-K for 1997).
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).
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).
59
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 Amended and Restated 1994 Long-Term Incentive Plan of the Company.
10.16 Amended and Restated 1994 Non-Employee Director Stock Option Plan.
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.
(Form 10-K for 1997) 10.19 Deferred Compensation Plan of the Company.
10.20 Trust Agreement dated August 1998 between Bankers Trust Company and the
Company.
10.21 Lease Agreement between the Company and DNA COG, Ltd. dated April 24,
1998.
10.22 Credit Agreement dated as of December 17, 1998 between the Company and
the banks named therein.
21.1 Subsidiaries of Cabot Oil & Gas Corporation.
23.1 Consent of PricewaterhouseCoopers LLP.
23.2 Consent of Miller and Lents, Ltd.
27 Financial Data Schedule.
28.1 Miller and Lents, Ltd. Review Letter dated February 9, 1999.
B. REPORTS ON FORM Form 8-K
Item 5 Form 8-K filed on January 27, 1999.
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 19 of March 1999.
CABOT OIL & GAS CORPORATION
By: /s/ Ray Seegmiller
---------------------------------
Ray Seegmiller
President 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.
Signature Title Date
- --------------------------------------------------------------------------------
/s/ Ray R. Seegmiller President, Chief Executive March 19, 1999
- --------------------------- Officer and Director
Ray R. Seegmiller (Principal Executive Officer)
/s/ Paul F. Boling Vice President, Finance March 19, 1999
- --------------------------- (Principal Financial Officer)
Paul F. Boling
/s/ Henry C. Smyth Controller March 19, 1999
- --------------------------- (Principal Accounting Officer)
Henry C. Smyth
/s/ Charles P. Siess, Jr. Chairman of the Board March 19, 1999
- ---------------------------
Charles P. Siess, Jr.
/s/ Robert F. Bailey Director March 19, 1999
- ---------------------------
Robert F. Bailey
/s/ Samuel W. Bodman Director March 19, 1999
- ---------------------------
Samuel W. Bodman
/s/ Henry O. Boswell Director March 19, 1999
- ---------------------------
Henry O. Boswell
/s/ John G. L. Cabot Director March 19, 1999
- ---------------------------
John G. L. Cabot
/s/ William R. Esler Director March 19, 1999
- ---------------------------
William R. Esler
/s/ William H. Knoell Director March 19, 1999
- ---------------------------
William H. Knoell
61
/s/ C. Wayne Nance Director March 19, 1999
- ---------------------------
C. Wayne Nance
/s/ P. Dexter Peacock Director March 19, 1999
- ---------------------------
P. Dexter Peacock
/s/ William P. Vititoe Director March 19, 1999
- ---------------------------
William P. Vititoe
62
INDEX TO EXHIBITS
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 (Form 10-K for 1997).
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).
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).
63
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 Amended and Restated 1994 Long-Term Incentive Plan of the Company.
10.16 Amended and Restated 1994 Non-Employee Director Stock Option Plan.
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.
(Form 10-K for 1997) 10.19 Deferred Compensation Plan of the Company.
10.20 Trust Agreement dated August 1998 between Bankers Trust Company and the
Company.
10.21 Lease Agreement between the Company and DNA COG, Ltd. dated April 24,
1998.
10.22 Credit Agreement dated as of December 17, 1998 between the Company and
the banks named therein.
21.1 Subsidiaries of Cabot Oil & Gas Corporation.
23.1 Consent of PricewaterhouseCoopers LLP.
23.2 Consent of Miller and Lents, Ltd.
27 Financial Data Schedule.
28.1 Miller and Lents, Ltd. Review Letter dated February 9, 1999.
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