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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, 2001
Commission file number 1-10447
CABOT OIL & GAS CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 04-3072771
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
1200 Enclave Parkway, Houston, Texas 77077
(Address of principal executive offices including ZIP code)
(281) 589-4600
(Registrant's telephone number)
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
Class A Common Stock, par value $.10 per share New York Stock Exchange
Rights to Purchase Preferred Stock New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No _______
-----
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K [__].
The aggregate market value of Class A Common Stock, par value $.10 per
share ("Common Stock"), held by non-affiliates (based upon the closing sales
price on the New York Stock Exchange on January 31, 2002), was approximately
$636,620,000. As of January 31, 2002, there were 31,905,097 shares of Common
Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Stockholders to
be held May 2, 2002, are incorporated herein by reference in Items 10, 11, 12
and 13 of Part III of this report.
TABLE OF CONTENTS
PART I PAGE
ITEMS 1 and 2 Business and Properties 3
ITEM 3 Legal Proceedings 19
ITEM 4 Submission of Matters to a Vote of Security Holders 21
Executive Officers of the Registrant 21
PART II
ITEM 5 Market for Registrant's Common Equity and Related Stockholder Matters 22
ITEM 6 Selected Historical Financial Data 22
ITEM 7 Management's Discussion and Analysis of Financial Condition
and Results of Operations 23
ITEM 7A Quantitative and Qualitative Disclosures about Market Risk 38
ITEM 8 Financial Statements and Supplementary Data 43
ITEM 9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 78
PART III
ITEM 10 Directors and Executive Officers of the Registrant 78
ITEM 11 Executive Compensation 78
ITEM 12 Security Ownership of Certain Beneficial Owners and Management 78
ITEM 13 Certain Relationships and Related Transactions 78
PART IV
ITEM 14 Exhibits, Financial Statements, Schedules and Reports on Form 8-K 79
_____________________
The statements regarding future financial and operating performance and
results, market prices, future hedging activities, and other statements that are
not historical facts contained in this report are forward-looking statements.
The words "expect," "project," "estimate," "believe," "anticipate," "intend,"
"budget," "plan," "forecast," "predict," "may," "should," "could" 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 our
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
OVERVIEW
Cabot Oil & Gas is an independent oil and gas company engaged in the
exploration, development, acquisition and exploitation of oil and gas properties
located in four principal areas of the United States:
. The onshore Texas and Louisiana Gulf Coast
. The Rocky Mountains
. The Mid-Continent or Anadarko Basin
. Appalachia
Administratively, we operate in three regions - the Gulf Coast region, the
Western region, which is comprised of the Rocky Mountains and Mid-Continent
areas, and the Appalachian region.
In 2001, we enjoyed a strong energy commodity price environment for most of
the year bolstered by gains realized on price hedges which were placed on about
44% of our production for the first nine months of 2001 natural gas production
near the peak of the market in December 2000. Drilling successes, most notably
in south Louisiana, over the past two years served to increase our 2001
production by 12% over 2000. While continuing to develop our existing fields
and exploring for new discoveries, we took advantage of our strong cash flow and
invested for the future. Most significantly, we acquired Cody Company in August
2001. With this transaction, we expanded and improved our development inventory
and added 11 exploration prospects. In addition, we expanded our acreage
position with a $12 million acquisition in the Rocky Mountains and added
significantly to our seismic database in both the Rocky Mountains and Gulf
Coast. The five months of production from the acquired Cody Company properties
increased our annual production by an additional 9% over 2000, for a combined
21% production increase year-over-year.
The purchase of Cody Company was the largest acquisition in our Company's
history. We paid $231.2 million in cash and common stock for all of the
outstanding common stock of Cody Company. Substantially all of the proved
reserves of Cody Company are located in the onshore Gulf Coast region, a
strategic growth area for us. As of December 31, 2001, these properties
contributed 39.1 Mmcfe of production per day and contained 92 proved undeveloped
drilling locations.
In 2001, 87% of the wells that we drilled were successful. Drilling was
successful on 40% of our 2001 exploration wells, as we tested new ideas and
worked on building a foundation for the future. Our 2001 capital and
exploration spending included $39.1 million for seismic data and lease
acquisition. This spending will support our exploration and development
drilling programs in 2002 and beyond. As we enter 2002 energy commodity prices
have softened. We will concentrate our 2002 capital spending program on
projects offering the prospect of acceptable risk and the strongest economics.
As in the past, we will use the cash flow from our long-lived Appalachian and
Mid-Continent natural gas reserves to fund our exploration and development
efforts in the Gulf Coast and Rocky Mountain areas. We believe these two core
producing areas offer more value, accretive reserve and production growth and
higher rates of return on equity.
Our proved reserves totaled approximately 1.2 Tcfe at December 31, 2001,
of which 90% was natural gas. This reserve level represents a 13% increase over
the prior year end. The increase is due primarily to the Cody acquisition, which
combined with drilling activities, replaced production by 268%. The Gulf Coast
region now represents 26% of our total proved reserves, up from 14% at the end
of 2000.
Net income of $47.1 million, or $1.56 per share, was the highest annual
level of earnings that we have ever achieved. Cash flow from operations in 2001
of $250.4 million was also a record, and represented a 110% increase over last
year. The strong commodity price environment combined with strategic price
collars were the main factors in this year's financial success. Production
improvements as discussed above also helped boost our earnings. Daily
production averaged 199 Mmcfe per day during the first seven months of the year
before increasing to approximately
3
255 Mmcfe per day in August with the acquisition of Cody Company. Overall,
including the Cody acquisition and additional successes in south Louisiana,
production averaged 222 Mmcfe per day in 2001. Development drilling on the
Etouffee field in south Louisiana has expanded producing wells to six, two of
which were drilled in 2001. This field, which is now fully developed, remains
our largest producer and at December 31, 2001 was producing 137 Mmcfe per day
(33 Mmcfe per day net to us).
The following table presents certain information as of December 31, 2001.
West
---------------------------------
Gulf Rocky Mid- Total
Coast Mountains Continent West Appalachia Total
-------- ---------- ---------- -------- ----------- ----------
Proved Reserves at Year End (Bcfe)
Developed 224.1 176.8 171.1 347.9 324.6 896.6
Undeveloped 76.2 50.6 28.0 78.6 102.7 257.5
------- ------- ------- ------- ------- ---------
Total 300.3 227.4 199.1 426.5 427.3 1,154.1
Average Daily Production (Mmcfe per day) 97.8 45.9 30.2 76.1 48.4 222.3
Reserve Life Index (in years) /(1)/ 8.4 13.6 18.1 15.4 24.2 14.2
Gross Wells 1,013 528 695 1,223 2,362 4,598
Net Wells /(2)/ 613.2 233.0 457.7 690.7 2,190.9 3,494.8
Percent Wells Operated 72.1% 49.1% 74.1% 63.3% 96.6% 82.3%
Net Acreage
Developed 103,836 85,058 180,981 266,039 743,204 1,113,079
Undeveloped 44,008 343,565 4,868 348,433 221,316 613,757
------- ------- ------- ------- ------- ---------
Total 147,844 428,623 185,849 614,472 964,520 1,726,836
- --------------------------------------------------------------------------------
/(1)/ Reserve Life Index is equal to year-end reserves divided by annual
production.
/(2)/ The term "net" as used in "net acreage" or "net production" throughout
this document refers to amounts that include only acreage or production
that is owned by Cabot Oil & Gas and produced to its interest, less
royalties and production due others. "Net wells" represents our working
interest share of each well.
GULF COAST REGION
Our exploration, development and production activities in Gulf Coast region
are concentrated in south Louisiana and south Texas. A regional office in
Houston manages operations. Principal producing intervals are in the Wilcox and
Vicksburg formations in Texas and the Miocene age formations in Louisiana at
depths ranging from 3,000 to 20,500 feet. Capital and exploration expenditures
made with cash and common stock were $352.1 million in 2001 or 78% of our total
2001 capital and exploration expenditures, and $66.0 million for 2000. The cash
and common stock portion of the August 2001 acquisition of Cody Company
accounted for $231.2 million of this amount, which did not include a non-cash
deferred tax gross-up of $78.0 million. Our drilling and acquisition program
has increased average daily production in the region from 15.6 Mmcfe per day in
1994, when we acquired our first Gulf Coast properties from Washington Energy,
to 131.6 Mmcfe per day in December 2001. Of this production rate, 39.1 Mmcfe
per day was associated with the newly acquired Cody properties and the remaining
primarily represents production growth from our drilling activity. For 2002, we
have budgeted $56.9 million (54% of our total 2002 capital budget) for capital
expenditures in the region. Our 2002 Gulf Coast drilling program will emphasize
our exploration opportunities and development drilling on the prospects acquired
in the Cody acquisition.
We had 1,013 wells (613.2 net) in the Gulf Coast region as of December 31,
2001, of which 730 wells are operated by us. Average net daily production in
2001 was 97.8 Mmcfe, up from 49.5 Mmcfe in 2000 due both to drilling success in
south Louisiana and to the Cody acquisition. At December 31, 2001, we had 300.3
Bcfe of proved reserves (67% natural gas) in the Gulf Coast region, which
represented 26% of our total proved reserves.
In 2001, we drilled 35 wells (14.7 net) in the Gulf Coast region, of which
20 wells (7.76 net) were development wells. The south Louisiana Etouffee
prospect and our new discoveries in the Augen field in south
4
Louisiana and Red Fish Bay prospects in south Texas, together with the Cody
acquisition, contributed to the significant growth in net proved reserves. In
the Gulf Coast region, we plan to drill 19 wells in 2002 of which seven are on
prospects acquired from Cody.
At December 31, 2001, we had 147,844 net acres in the region, including
103,836 net developed, and we had identified 97 proved undeveloped drilling
locations of which 92 were part of the Cody acquisition.
Our principal markets for Gulf Coast region natural gas are in the
industrialized Gulf Coast area and the northeastern United States. Our marketing
subsidiary, Cabot Oil & Gas Marketing Corporation, purchases all of our 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, approximately 75% of our natural gas sales volumes in the Gulf
Coast region are sold at index-based prices under contracts with terms of one to
three years. The remaining 25% of our sales volumes are sold at index-based
prices under short-term agreements. From time to time when we believe market
conditions are favorable, we may implement financial hedges on a portion of our
production in an attempt to reduce our exposure to price volatility. The Gulf
Coast properties are connected to various processing plants in Texas and
Louisiana with multiple interstate and intrastate deliveries, affording us
access to multiple markets.
We also produce and market approximately 6,500 barrels per day of crude
oil/condensate in the Gulf Coast region at market responsive prices.
WESTERN REGION
Our activities in the Western region are managed by a regional office in
Denver. At December 31, 2001, we had 426.5 Bcfe of proved reserves (96% natural
gas) in the Western region, constituting 37% of our total proved reserves.
Rocky Mountains
Our Rocky Mountains activities are concentrated in the Green River Basin
and Washakie Basin of Wyoming. Since our initial acquisition in the area in 1994
from Washington Energy, we have increased reserves from 171.6 Bcfe at December
31, 1994, to 227.4 Bcfe at December 31, 2001. Capital and exploration
expenditures were $42.9 million for 2001, or 9% of our total 2001 capital and
exploration expenditures, and $23.9 million for 2000. In addition to drilling
activity, approximately $15.4 million was expended in 2001 for lease acquisition
and seismic data to provide exploration and development opportunities in the
future. For 2002, we have budgeted $19.4 million (19% of our total 2002 capital
budget) for capital expenditures in the area. The 2002 drilling program consists
of several new exploration plays complemented by development drilling.
We had 528 wells (233.0 net) in the Rocky Mountains area as of December 31,
2001, of which 259 wells are operated by us. Principal producing intervals in
the Rocky Mountains area are in the Almond, Frontier and Dakota formations at
depths ranging from 9,000 to 13,500 feet. Average net daily production in the
Rocky Mountains during 2001 was 45.9 Mmcfe.
In 2001, we drilled 31 wells (15.4 net) in the Rocky Mountains, of which 26
wells (11.5 net) were development and extension wells. In 2002, we plan to drill
41 wells.
At December 31, 2001, we had 428,623 net acres in the area, including
85,058 net developed acres, and we had identified 82 proved undeveloped drilling
locations.
5
Mid-Continent
Our Mid-Continent activities are concentrated in the Anadarko Basin in
southwestern Kansas, Oklahoma and the panhandle of Texas. Capital and
exploration expenditures were $11.5 million for 2001, or 3% of our total 2001
capital and exploration expenditures, and $7.6 million for 2000. For 2002, we
have budgeted $8.2 million (8% of our total 2002 capital budget) for capital
expenditures in the area.
As of December 31, 2001, we had 695 wells (457.7 net) in the Mid-Continent
area, of which 515 wells are operated by us. Principal producing intervals in
the Mid-Continent are in the Chase, Morrow, Red Fork and Chester formations at
depths ranging from 1,500 to 14,000 feet. Average net daily production in 2001
was 30.2 Mmcfe. At December 31, 2001, we had 199.1 Bcfe of proved reserves (97%
natural gas) in the Mid-Continent area, 17% of our total proved reserves.
In 2001, we drilled 25 wells (17.2 net) in the Mid-Continent, all of which
were development and extension wells. In 2002, we plan to drill 17 wells.
At December 31, 2001, we had 185,849 net acres in the area, including
180,981 net developed acres, and we had identified 62 proved undeveloped
drilling locations.
Western Region Marketing
Our principal markets for Western region natural gas are in the
northwestern, midwestern and northeastern United States. Cabot Oil & Gas
Marketing purchases all of our natural gas production in the Western region.
This marketing subsidiary sells the natural gas to power generators, natural gas
processors, local distribution companies, industrial customers and marketing
companies.
Currently, approximately 86% of our natural gas production in the Western
region is sold primarily under contracts with a term of one to three years at
index-based prices. Another 12% of the natural gas production is sold under
short-term arrangements at index-based prices and the remaining 2% is sold under
certain fixed-price contracts. From time to time when we believe market
conditions are favorable, we may implement financial hedges on a portion of our
production in an attempt to reduce our exposure to price volatility.. The
Western region properties are connected to the majority of the midwestern and
northwestern interstate and intrastate pipelines, affording us access to
multiple markets.
In December 1999, we negotiated the buyout of a long-term, fixed price
sales contract that covered approximately 20% of the Western region natural gas
production and was due to expire in June 2008. We received a payment of $12
million as part of this contract buyout agreement. This contract was then
replaced with a fixed price sales contract that expired in April 2001. The fixed
natural gas sales price in both the original natural gas sales contract and the
replacement sales contract was below the market price at year end 2000. After
April 2001, this production was sold at market responsive prices.
We currently also produce and market approximately 600 barrels of crude
oil/condensate per day in the Western region at market responsive prices.
APPALACHIAN REGION
Our Appalachian activities are concentrated in West Virginia, Pennsylvania,
Ohio and Virginia. In this region, our assets include a large undeveloped
acreage position, a high concentration of wells, natural gas gathering and
pipeline systems, and storage capacity. We have achieved a drilling success rate
of 89% in the region since 1991. Capital and exploration expenditures were $44.1
million for 2001, or 10% of our total 2001 capital spending, and $21.5 million
for 2000. For 2002, we have budgeted $18.5 million (18% of our total 2002
capital budget) for capital expenditures in the region.
At December 31, 2001, we had 2,362 wells (2,190.9 net), of which 2,281
wells are operated by us. There are multiple producing intervals that include
the Devonian Shale, Oriskany, Berea and Big Lime formations at depths
6
primarily ranging from 1,500 to 9,000 feet. Average net daily production in 2001
was 48.4 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. At
December 31, 2001, we had 427.3 Bcfe of proved reserves (substantially all
natural gas) in the Appalachian region, constituting 37% of our total proved
reserves. This region is managed from our office in Charleston, West Virginia.
In 2001, we drilled 117 wells (106.3 net) in the Appalachian region, of
which 107 wells (97.0 net) were development wells. In 2002, we plan to drill 44
wells.
At December 31, 2001, we had 964,520 net acres in the region, including
743,204 net developed, and we had identified 292 proved undeveloped drilling
locations.
Ancillary to our exploration and production operations, we operate a number
of gas gathering and transmission pipeline systems, made up of approximately
2,500 miles of pipeline with interconnects to three interstate transmission
systems, seven local distribution companies and numerous end users as of the end
of 2001. The majority of our pipeline infrastructure in West Virginia is
regulated by the Federal Energy Regulatory Commission (FERC). As such, the
transportation rates and terms of service of our pipeline subsidiary, Cranberry
Pipeline Corporation, are subject to the rules and regulations of the FERC. Our
natural gas gathering and transmission pipeline systems enable us to connect new
wells quickly and to transport natural gas from the wellhead directly to
interstate pipelines, local distribution companies and industrial end users.
Control of our gathering and transmission pipeline systems also enables us to
purchase, transport and sell natural gas produced by third parties. In addition,
we can engage in development drilling without relying upon third parties to
transport our natural gas and incur only the incremental costs of pipeline and
compressor additions to our system.
We have two natural gas storage fields located in West Virginia with a
combined working capacity of approximately 4 Bcf. We use 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 us to periodically increase the volume of natural gas
that we can deliver by more than 40% above the volume that we could deliver
solely from our production in the Appalachian region. The pipeline systems and
storage fields are fully integrated with our operations.
In addition, we own and operate two brine treatment plants that process and
treat waste fluid generated during the drilling, completion and production of
oil and gas wells. The first plant, near Franklin, Pennsylvania, began operating
in 1985. It provides services primarily to other oil and gas producers in
southwestern New York, eastern Ohio and western Pennsylvania. In April 1998, we
acquired a second brine treatment plant in Indiana, Pennsylvania that had been
in existence since 1987.
Appalachian Region Marketing
The principal markets for our Appalachian region natural gas are in the
northeastern United States. Cabot Oil & Gas Marketing purchases our 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 and gas marketers both on and off our pipeline and
gathering system.
Approximately 65% of our natural gas sales volume in the Appalachian region
is sold at index-based prices under contracts with a term of one to two years.
In addition, spot market sales are made under month-to-month contracts, while
industrial and utility sales generally are made under year-to-year contracts.
Approximately 5% of Appalachian production is sold on fixed price contracts that
typically renew annually. From time to time, we may also use financial hedges on
a portion of our production to reduce the potential risk of falling prices when
we believe market conditions are favorable.
Our Appalachian natural gas production has historically sold at a higher
realized price, or premium, compared to production from other producing regions
due to its proximity to northeastern markets. While year-to-year fluctuations in
that premium are normal due to changes in market conditions, throughout the
1990's this
7
premium has typically been in the range of $0.40 to $0.50 per Mmbtu above the
Henry Hub index spot price as published by Inside FERC's Gas Market Report for
gas delivered to this point. This index is the basis for sales price in our
standard natural gas sales contract. In 1999, however, the average premium
declined to $0.27 per Mmbtu due to increases in supply in the eastern market.
This decline continued into early 2000. However, late in 2000 and into 2001, the
premium began to increase again due to strengthening of demand and perceived
market shortages. The average 2001 premium was approximately $0.34 per Mmbtu.
Due to this continued volatility, we are not able to predict the level of this
premium for the future.
RISK MANAGEMENT
From time to time, when we believe that market conditions are favorable, we
use certain financial instruments called derivatives to manage price risks
associated with our production and brokering activities. While there are many
different types of derivatives available, in 2001 we primarily employed natural
gas and oil price swap and costless collar agreements to attempt to manage price
risk more effectively. The price swaps call for payments to, or receipts from,
counterparties based on whether the market price of natural gas for the period
is greater or less than the fixed price established for that period when the
swap is put in place. The costless collar arrangements are put and call options
used to establish floor and ceiling commodity prices for a fixed volume of
production during a certain time period. They provide for payments to
counterparties if the index price exceeds the ceiling and payments from the
counterparties if the index price is below the floor.
In December 2000, we entered into certain costless collar arrangements on
half of our natural gas production for the months of February through October
2001. We realized revenue of $34.6 million under these arrangements. In December
2001, we again entered into price collar arrangements for 60% of our anticipated
natural gas production for the months of January through April 2002. We will
continue to evaluate the benefit of employing derivatives in the future. Please
read Management's Discussion and Analysis of Financial Condition and Results of
Operations - Commodity Price Swaps and Options for further discussion concerning
our use of derivatives.
RESERVES
Current Reserves
The following table presents our estimated proved reserves at December 31,
2001.
Natural Gas (Mmcf) Liquids/(1)/ (Mbbl) Total/(2)/(Mmcfe)
- -----------------------------------------------------------------------------------------------------------------------
Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total
- -----------------------------------------------------------------------------------------------------------------------
Gulf Coast 148,692 53,734 202,426 12,567 3,744 16,311 224,096 76,198 300,294
Rocky Mountains 167,067 47,717 214,784 1,618 482 2,100 176,774 50,610 227,384
Mid-Continent 166,198 27,236 193,434 817 130 947 171,098 28,018 199,116
Appalachia 322,689 102,671 425,360 326 -- 326 324,644 102,671 427,315
----------------------------------------------------------------------------------------------------
Total 804,646 231,358 1,036,004 15,328 4,356 19,684 896,612 257,497 1,154,109
====================================================================================================
- --------------------------------------------------------------------------------
/(1)/ Liquids include crude oil, condensate and natural gas liquids (Ngl).
/(2)/ Natural gas equivalents are determined using the ratio of 6 Mcf of natural
gas to 1 Bbl of crude oil, condensate or natural gas liquids.
The proved reserve estimates presented here were prepared by our petroleum
engineering staff and reviewed by Miller and Lents, Ltd., independent petroleum
engineers. For additional information regarding estimates of proved reserves,
the review of such estimates by Miller and Lents, Ltd., and other information
about our 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.
Our estimates of proved reserves in the table above are consistent with those
filed by us with other federal agencies. Our reserves are sensitive to natural
gas and crude oil sales prices and their effect on economic producing rates. Our
reserves are based on oil and gas index prices in effect on the last day of
December 2001.
There are a number of uncertainties inherent in estimating quantities of
proved reserves, including many
8
factors beyond our control such as commodity pricing. 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 can not 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, initial 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 declines as reserves are depleted. Except to the
extent we acquire additional properties containing proved reserves or conduct
successful exploration and development activities or both, our proved reserves
will decline as reserves are produced.
9
Historical Reserves
The following table presents our estimated proved reserves for the periods
indicated.
Natural Gas Oil & Liquids Total
(Mmcf) (Mbbl) (Mmcfe)/(1)/
--------------------------------------------------------------
December 31, 1998 996,756 7,677 1,042,819
--------------------------------------------------------------
Revision of Prior Estimates (1,555) 128 (787)
Extensions, Discoveries and
Other Additions 52,781 1,292 60,535
Production (65,502) (963) (71,279)
Purchases of Reserves in Place 26,515 361 28,685
Sales of Reserves in Place (79,393) (306) (81,232)
--------------------------------------------------------------
December 31, 1999 929,602 8,189 978,741
--------------------------------------------------------------
Revision of Prior Estimates (14,796) 562 (11,423)
Extensions, Discoveries and
Other Additions 103,600 2,032 115,792
Production (60,934) (988) (66,872)
Purchases of Reserves in Place 5,118 120 5,838
Sales of Reserves in Place (3,368) (1) (3,373)
--------------------------------------------------------------
December 31, 2000 959,222 9,914 1,018,703
--------------------------------------------------------------
Revision of Prior Estimates (44,266) 254 (42,737)
Extensions, Discoveries and
Other Additions 99,911 2,257 113,456
Production (69,162) (1,996) (81,139)
Purchases of Reserves in Place 91,290 9,255 146,819
Sales of Reserves in Place (991) -- (993)
--------------------------------------------------------------
December 31, 2001 1,036,004 19,684 1,154,109
==============================================================
Proved Developed Reserves
December 31, 1998 788,390 5,822 823,321
December 31, 1999 720,670 5,546 753,944
December 31, 2000 754,962 8,438 805,590
December 31, 2001 804,646 15,328 896,612
________________________________________________________________________________
/(1)/ Includes natural gas and natural gas equivalents determined by using the
ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural
gas liquids.
10
Volumes and Prices; Production Costs
The following table presents regional historical information about our net
wellhead sales volume for natural gas and oil (including condensate and natural
gas liquids), produced natural gas and oil sales prices, and production costs
per equivalent.
Year Ended December 31,
2001 2000 1999
-------------------------------------------------------------------------
Net Wellhead Sales Volume
Natural Gas (Bcf)
Gulf Coast 25.6 14.1 15.5
West 26.2 29.0 29.3
Appalachia 17.4 17.8 20.7
Crude/Condensate/Ngl (Mbbl)
Gulf Coast 1,694 669 579
West 267 289 341
Appalachia 35 32 43
Produced Natural Gas Sales Price ($/Mcf)/(1)/
Gulf Coast $ 4.44 $ 3.79 $ 2.29
West 3.88 2.86 1.96
Appalachia 4.96 3.24 2.53
Weighted Average 4.36 3.19 2.22
Crude/Condensate Sales Price ($/Bbl)/(1)/ $24.91 $26.81 $17.22
Production Costs ($/Mcfe)/(2)/ $ 0.72 $ 0.70 $ 0.59
________________________________________________________________________________
/(1)/ Represents the average sales prices (net of hedge activity) for all
production volumes (including royalty volumes) sold by Cabot Oil & Gas
during the periods shown net of related costs (principally purchased gas
royalty, transportation and storage).
/(2)/ 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.
11
Acreage
The following tables summarize our gross and net developed and undeveloped
leasehold and mineral acreage at December 31, 2001. Acreage in which our
interest is limited to royalty and overriding royalty interests is excluded.
Leasehold Acreage
Developed Undeveloped Total
-------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
-------------------------------------------------------------------------------------
State
Alabama 1,976 374 -- -- 1,976 374
Colorado 14,263 13,359 190,529 92,799 204,792 106,158
Kansas 29,067 27,765 -- -- 29,067 27,765
Kentucky 2,266 901 -- -- 2,266 901
Louisiana 53,408 41,468 24,314 12,983 77,722 54,451
Michigan 739 205 6,823 6,773 7,562 6,978
Montana 397 210 44,288 33,552 44,685 33,762
New York 2,956 1,117 436 155 3,392 1,272
New Mexico 480 96 -- -- 480 96
North Dakota -- -- 870 96 870 96
Ohio 6,288 2,389 9,225 7,361 15,513 9,750
Oklahoma 161,665 111,923 6,642 3,489 168,307 115,412
Pennsylvania 128,862 78,772 40,916 36,908 169,778 115,680
Texas 153,385 88,781 69,974 32,002 223,359 120,783
Utah 1,740 530 129,044 88,125 130,784 88,655
Virginia 22,195 20,072 7,606 4,981 29,801 25,053
West Virginia 577,372 542,752 170,168 113,241 747,540 655,993
Wyoming 141,733 70,959 197,622 128,912 339,355 199,871
--------------------------------------------------------------
Total 1,298,792 1,001,673 898,457 561,377 2,197,249 1,563,050
==============================================================
Mineral Fee Acreage
Developed Undeveloped Total
-------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
-------------------------------------------------------------------------------------
State
Colorado -- -- 160 6 160 6
Kansas 160 128 -- -- 160 128
Louisiana 628 276 -- -- 628 276
Montana -- -- 589 75 589 75
New York -- -- 4,281 1,070 4,281 1,070
Oklahoma 16,580 13,979 400 76 16,980 14,055
Pennsylvania 86 86 2,367 1,296 2,453 1,382
Texas 27 27 652 326 679 353
Virginia 17,817 17,817 100 34 17,917 17,851
West Virginia 97,455 79,093 50,458 49,497 147,913 128,590
--------------------------------------------------------------
Total 132,753 111,406 59,007 52,380 191,760 163,786
==============================================================
Aggregate Total 1,431,545 1,113,079 957,464 613,757 2,389,009 1,726,836
==============================================================
12
Total Net Acreage by Region of Operation
Developed Undeveloped Total
--------------------------------------------------------------------
Gulf Coast 103,836 44,008 147,844
West 266,039 348,433 614,472
Appalachia 743,204 221,316 964,520
-------------------------------------------
Total 1,113,079 613,757 1,726,836
===========================================
Well Summary
The following table presents our ownership at December 31, 2001, in natural
gas and oil wells in the Gulf Coast region (consisting of various fields located
in Louisiana and Texas), in the Western region (consisting of various fields
located in Oklahoma, Kansas, Colorado and Wyoming) and in the Appalachian region
(consisting of various fields located in West Virginia, Pennsylvania, Virginia
and Ohio). This summary includes natural gas and oil wells in which we have a
working interest or a reversionary interest as in the case of certain Section 29
tight sands and Devonian shale wells.
Natural Gas Oil Total
Gross Net Gross Net Gross Net
----------------------------------------------------------
Gulf Coast 613 375.6 400 237.6 1,013 613.2
West 1,152 652.4 71 38.3 1,223 690.7
Appalachia 2,339 2,180.0 23 10.9 2,362 2,190.9
--------------------------------------------
Total 4,104 3,208.0 494 286.8 4,598 3,494.8
============================================
Drilling Activity
We drilled wells, participated in the drilling of wells, or acquired wells
as indicated in the regional tables below.
Year Ended December 31,
2001 2000 1999
--------------------------------------------------------------------
Gross Net Gross Net Gross Net
--------------------------------------------------------------------
Gulf Coast
Development Wells
Successful 18 7.0 14 6.3 10 6.2
Dry 1 0.6 3 1.7 3 3.0
Extension Wells
Successful 1 0.1 -- -- -- --
Dry -- -- -- -- -- --
Exploratory Wells
Successful 8 4.6 4 2.2 2 0.6
Dry 7 2.4 2 1.0 1 0.5
----------------------------------------
Total 35 14.7 23 11.2 16 10.3
========================================
Wells Acquired/(1)/ 600 334.0 1 0.6 2 0.6
Wells in Progress at End
of Period 5 3.6 2 1.1 1 0.3
13
Year Ended December 31,
2001 2000 1999
------------------------------------------------------------------------
Gross Net Gross Net Gross Net
------------------------------------------------------------------------
West
Development Wells
Successful 43 24.9 33 22.7 19 9.0
Dry 3 1.5 3 1.0 1 1.0
Extension Wells
Successful 5 2.4 7 3.9 1 0.3
Dry -- -- -- -- -- --
Exploratory Wells
Successful 1 0.8 1 0.3 -- --
Dry 4 3.0 1 0.5 2 1.3
--------------------------------------------
Total 56 32.6 45 28.4 23 11.6
============================================
Wells Acquired/(1)/ 10 0.1 1 0.4 27 10.7
Wells in Progress at End
of Period -- -- 4 2.7 5 2.3
Year Ended December 31,
2001 2000 1999
------------------------------------------------------------------------
Gross Net Gross Net Gross Net
------------------------------------------------------------------------
Appalachia
Development Wells
Successful 102 93.0 47 41.5 26 19.0
Dry 5 4.0 5 4.2 1 0.5
Extension Wells
Successful -- -- -- -- -- --
Dry -- -- -- -- -- --
Exploratory Wells
Successful 3 3.0 5 3.8 3 2.0
Dry 7 6.3 4 2.5 4 2.0
--------------------------------------------
Total 117 106.3 61 52.0 34 23.5
============================================
Wells Acquired/(1)/ 19 19.0 -- -- -- --
Wells in Progress at End
of Period -- -- 3 3.0 1 0.3
---------------------------------------------------------------------------
/(1)/ Includes the acquisition of net interest in certain wells in which we
already held an ownership interest. Does not include certain
interests in Section 29 tight sands and Devonian shale wells
purchased and then resold during 1999.
Competition
Competition in our primary producing areas is intense. Price, contract
terms and quality of service, including pipeline connection times, distribution
efficiencies and reliable delivery records, affect competition. We believe that
our extensive acreage position, existing natural gas gathering and pipeline
systems and storage fields enhance our competitive position over other producers
in the Appalachian region who do not have similar systems or facilities in
place. We also believe that our competitive position in the Appalachian region
is enhanced by the lack of significant competition from major oil and gas
companies. We also actively compete against other companies with substantially
larger financial and other resources, particularly in the Western and Gulf Coast
regions.
14
OTHER BUSINESS MATTERS
Major Customer
We had no sales to any customer that exceeded 10% of our total gross
revenues in 2001, 2000 or 1999.
Seasonality
Demand for natural gas has historically been seasonal, with peak demand and
typically higher prices occurring during the colder winter months.
Regulation of Oil and Natural Gas Exploration and Production
Exploration and production operations 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. Our 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, 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
prohibiting the venting or flaring of natural gas, and imposing certain
requirements regarding the ratability of production. The effect of these
regulations is to limit the amounts of oil and natural gas we can produce from
our wells, and to limit the number of wells or the locations where we can drill.
Because these statutes, rules and regulations undergo constant review and often
are amended, expanded and reinterpreted, we are 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. We do not believe, however, we are affected materially
differently by these regulations than others in the industry.
Natural Gas Marketing, Gathering and Transportation
Federal legislation and regulatory controls have historically affected the
price of the natural gas produced and the manner in which such production is
transported and marketed. Under the Natural Gas Act of 1938, the FERC regulates
the interstate sale and transportation of natural gas for resale. The FERC's
jurisdiction over interstate natural gas sales was substantially modified by the
Natural Gas Policy Act of 1978 (NGPA), 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 (Decontrol Act) deregulated
natural gas prices for all "first sales" of natural gas, including all sales of
our own production. As a result, all of our produced natural gas may now be
sold at market prices, subject to the terms of any private contracts that may be
in effect. The FERC's jurisdiction over natural gas transportation and the sale
for resale of natural gas in interstate commerce was not affected by the
Decontrol Act.
Natural gas sales are affected by intrastate and interstate gas
transportation regulation. Beginning with Order No. 436 in 1985 and continuing
through Order No. 636 in 1992, 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 wholesale marketers
of gas to the primary role of gas transporters. Order No. 636 required that
interstate pipelines generally cease making sales of natural gas. At the same
time, FERC retained its statutory jurisdiction over the sale for resale of
natural gas in interstate commerce, but issued to all entities (except
interstate pipelines) a blanket certificate to make sales for resale of natural
gas in interstate commerce at market based prices. As a result, pipelines
divested their gas sales functions to marketing affiliates, which operate
separately from the transporter and in direct competition with all other
merchants. 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. The FERC expanded the impact of open
access
15
regulations to intrastate commerce through its implementation of the NGPA
provisions allowing intrastate pipelines to provide service in intrastate
commerce on behalf of interstate pipelines.
More recently, the FERC has pursued other policy initiatives that have
affected natural gas marketing. Most notable are (1) the large-scale
divestiture of interstate pipeline-owned gas gathering facilities to affiliated
or non-affiliated companies, which is a result of the FERC's requirement in
Order No. 636 that interstate pipelines unbundle gathering services from
transportation services, (2) further development of rules governing the
relationship of the pipelines with their marketing affiliates, (3) 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, and (4) 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 a showing of lack of market control in the relevant service
market.
The FERC continued its efforts to develop a competitive natural gas market
with Order No. 637, issued in 2000. Order No. 637 modifies FERC regulations to:
(1) lift the cost-based cap on pipeline transportation rates in the capacity
release market until September 30, 2002, for releases of pipeline capacity for
periods less than one year; (2) permit pipelines to file for authority to charge
different maximum cost-based rates for peak and off-peak periods; (3) encourage
auctions for pipeline capacity; (4) require that pipelines implement imbalance
management services for shippers; (5) restrict the ability of pipelines to
impose penalties for imbalances, overruns, and non-compliance with operational
flow orders; and (6) implement a number of new pipeline reporting requirements
to enhance market transparency. These Order No. 637 requirements are being
implemented by pipelines through individual tariff reform filings. Order No.
637 also requires the FERC Staff to analyze whether the FERC should develop
additional fundamental policy changes, including whether to pursue performance-
based or other non-cost based ratemaking methods and whether the FERC should
mandate greater standardization in terms and conditions of service across the
interstate pipeline grid.
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. We believe these
changes generally have improved our access to markets while, at the same time,
substantially increasing competition in the natural gas marketplace.
We can not predict what new or different regulations the FERC and other
regulatory agencies may adopt, or what effect subsequent regulations may have on
our activities. Similarly, it is impossible to predict what proposals, if any,
that affect the oil and natural gas_industry might actually be enacted by
Congress or the various state legislatures and what effect, if any, such
proposals might have on us. 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 our sales of gas, can not
be predicted.
Our pipeline systems and storage fields in West Virginia are regulated for
safety compliance by the U.S. Department of Transportation and the West Virginia
Public Service Commission.
Federal Regulation of Petroleum
Our sales of oil and natural gas liquids are not regulated and are at
market prices. The price received from the sale of these products is affected
by the cost of transporting the products to market. Much of that transportation
is through interstate common carrier pipelines. Effective January 1, 1995, the
FERC implemented regulations generally grandfathering all previously approved
interstate transportation rates and establishing an indexing system for those
rates by which adjustments are made annually based on the rate of inflation,
subject to certain conditions and limitations. These regulations may tend to
increase the cost of transporting oil and natural gas liquids by interstate
pipeline, although the annual adjustments may result in decreased rates in a
given year. These regulations have generally been approved on judicial review.
Every five years, the FERC must examine the relationship between the annual
change in the applicable index and the actual cost changes experienced in the
oil pipeline industry. The first such review has been completed and on December
14, 2000, the FERC reaffirmed the current index. We are not able to predict
with certainty the effect upon us of these relatively new federal regulations or
of the periodic
16
review by the FERC of the index.
Environmental Regulations
General. Our 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 our various facilities. These permits can be
revoked, modified or renewed by issuing authorities. Governmental authorities
enforce compliance with their regulations through fines, injunctions or both.
Government regulations can increase the cost of planning, designing, installing
and operating oil and gas facilities. Although we believe that compliance with
environmental regulations will not have a material adverse effect on us, 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 could result in substantial costs and liabilities to us.
Solid and Hazardous Waste. We currently own or lease, and have in the past
owned or leased, numerous properties that were used for the production of oil
and gas for many years. Although operating and disposal practices that were
standard in the industry at the time may have been utilized, it is possible that
hydrocarbons or other solid wastes may have been disposed of or released on or
under the properties currently owned or leased by us. State and federal laws
applicable to oil and gas wastes and properties have become more strict over
time. Under these increasingly stringent requirements, we could be required to
remove or remediate previously disposed wastes (including wastes disposed or
released by prior owners and operators) or clean up property contamination
(including groundwater contamination by prior owners or operators) or to perform
plugging operations to prevent future contamination.
We generate some hazardous wastes that are already 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. We could, therefore, be subject
to more rigorous and costly disposal requirements in the future than we
encounter today.
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
persons with respect to the release of hazardous substances 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 hazardous substances
found at a site. CERCLA also authorizes the EPA, and in some cases, private
parties, to undertake actions to clean up such hazardous substances, or to
recover the costs of such actions from the responsible parties. In the course
of business, we have generated and will continue to generate wastes that may
fall within CERCLA's definition of hazardous substances. We may also be an
owner or operator of sites on which hazardous substances have been released. As
a result, we may be responsible under CERCLA for all or part of the costs to
clean up sites where such wastes have been disposed. See Item 3 Legal
Proceedings for a discussion of the Casmalia Superfund Site.
Oil Pollution Act. The federal Oil Pollution Act of 1990 (OPA) and
resulting regulations impose a variety of obligations 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, which are implemented through a system of
permits, also govern the discharge of certain contaminants into waters of the
United States. Sanctions for failure to comply strictly with the Clean Water
Act are generally resolved by payment of fines and correction of any identified
deficiencies. However, regulatory agencies could require us to cease
construction or operation of certain facilities that are the source of water
discharges. We believe that we comply with the Clean Water Act and related
federal and state regulations in all material respects.
17
Clean Air Act. Our 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 us to cease construction or operation of certain
facilities that are air emission sources. We believe that we substantially
comply with the emission standards under local, state, and federal laws and
regulations.
Employees
As of December 31, 2001, Cabot Oil & Gas had 366 active employees. We
recognize that our success is significantly influenced by the relationship we
maintain with our employees. Overall, we believe that our relations with our
employees are satisfactory. The Company and its employees are not represented
by a collective bargaining agreement.
Other
Our profitability depends on certain factors that are beyond our control,
such as natural gas and crude oil prices. Please see Items 7 and 7A. We face a
variety of hazards and risks that could cause substantial financial losses. Our
business involves a variety of operating risks, including blowouts, cratering,
explosions and fires, mechanical problems, uncontrolled flows of oil, natural
gas or well fluids, formations with abnormal pressures, pollution and other
environmental risks, and natural disasters. We conduct operations in shallow
offshore areas, which are subject to additional hazards of marine operations,
such as capsizing, collision and damage from severe weather.
Our operation of natural gas gathering and pipeline systems also involves
various risks, including the risk of explosions and environmental hazards caused
by pipeline leaks and ruptures. Any of these events could result in loss of
human life, significant damage to property, environmental pollution, impairment
of our operations and substantial losses to us. The location of pipelines near
populated areas, including residential areas, commercial business centers and
industrial sites, could increase these risks. In accordance with customary
industry practice, we maintain insurance against some, but not all, of these
risks and losses. The occurrence of any of these events not fully covered by
insurance could have a material adverse effect on our financial position and
results of operations. The costs of these insurance policies are somewhat
dependent on our historical claims experience and also the areas in which we
choose to operate. During the past few years, we have drilled a higher
percentage of our wells in the Gulf Coast, where insurance rates are
significantly higher than in other regions such as Appalachia. At December 31,
2001, we owned or operated approximately 2,900 miles of natural gas gathering
and transmission pipeline systems throughout the United States. As part of our
normal maintenance program, we have identified certain segments of our pipelines
that we believe may require repair, replacement or additional maintenance and we
schedule this maintenance as appropriate.
The sale of our oil and gas production depends on a number of factors
beyond our control. The factors include the availability and capacity of
transportation and processing facilities. Our failure to access these facilities
and obtain these services on acceptable terms could materially harm our
business.
ITEM 2. PROPERTIES
See Item 1. Business.
18
ITEM 3. LEGAL PROCEEDINGS
We are a party to various legal proceedings arising in the normal course of
our business. All known liabilities are fully accrued based on management's
best estimate of the potential loss. In management's opinion, final judgments
or settlements, if any, which may be awarded in connection with any one or more
of these suits and claims would not have a significant impact on the results of
operations, financial position or cash flows of any period.
Environmental Liability
The EPA notified us in February 2000 of our potential liability for waste
material disposed of at the Casmalia Superfund Site ("Site"), located on a 252-
acre parcel in Santa Barbara County, California. Over 10,000 separate parties
disposed of waste at the Site while it was operational from 1973 to 1992. The
EPA stated that federal, state and local governmental agencies along with the
numerous private entities that used the Site for disposal of approximately 4.5
billion pounds of waste would be expected to pay the clean-up costs, which are
estimated by the EPA to be $271.9 million. The EPA is also pursuing the
owners/operators of the Site to pay for remediation.
Documents received by us with the notification from the EPA indicate that
we used the Site principally to dispose of salt water from two wells over a
period from 1976 to 1979. There is no allegation that we violated any laws in
the disposal of material at the Site. The EPA's actions stem from the fact that
the owners/operators of the Site do not have the financial means to implement a
closure plan for the Site.
A group of potentially responsible parties, including us, formed a group
called the Casmalia Negotiating Committee ("CNC"). The CNC has had extensive
settlement discussions with the EPA and has reached a settlement in principal to
pay approximately $27 million toward Site clean up in return for a release from
liability. The CNC is currently negotiating a consent decree to memorialize the
settlement. On January 30, 2002, we placed $1,283,283 in an escrow account. This
amount approximates our volumetric share of EPA's cost estimate, plus a 5%
premium and is our settlement amount. The escrow account is being funded by us
and many other CNC members to maximize the likelihood that there will be
sufficient funds to fund the settlement agreement upon its completion, which is
expected later in 2002. This cash settlement, once released from escrow and paid
to the federal government, will resolve all federal claims against us for
response costs and will release us from all response costs related to the Site,
except for future claims against us for natural resource damage, unknown
conditions, transshipment risks and claims by third parties, all of which are
expected to be covered by insurance to be purchased by participating CNC
members. Responsibility for certain State of California oversight and response
costs, while not covered by the settlement or insurance, are not expected to be
material. No determination has been made as to whether any insurance arrangement
will allow us to recover our contribution to the settlement.
We have established a reserve that management believes to be adequate to
provide for this environmental liability based on its estimate of the probable
outcome of this matter and estimated legal costs.
Wyoming Royalty Litigation
In June 2000, two overriding royalty owners sued us in Wyoming State court
for unspecified damages. The plaintiffs have requested class certification
under the Wyoming Rules of Civil Procedure and allege that we have deducted
improper costs of production from royalty payments to the plaintiffs and other
similarly situated persons. Additionally, the suit claims that we have failed
to properly inform the plaintiffs and other similarly situated persons of the
deductions taken from royalties. In December 2001, fourteen overriding royalty
owners sued us in Wyoming federal court. The plaintiffs in the federal case
have made the same general claims pertaining to deductions from their overriding
royalty as the plaintiffs in the Wyoming state court case but have not asked for
class certification.
Management believes that we have substantial defenses to these claims and
intends to vigorously assert such defenses. We have a reserve that we believe
is adequate to provide for these potential liabilities based on our estimate of
the probable outcome of this matter. While the potential impact to us may
materially affect quarterly or annual financial results including cash flows,
management does not believe it would materially impact our financial position or
results of operations.
19
West Virginia Royalty Litigation
In late December 2001, two royalty owners sued us in West Virginia State
court for an unspecified amount of damages. The plaintiffs have requested class
certification under the West Virginia Rules of Civil Procedure and allege that
we have failed to pay royalty based upon the wholesale market value of the gas
produced, that we have taken improper deductions from the royalty and that we
have failed to properly inform the plaintiffs and other similarly situated
persons of deductions taken from the royalty.
Although the investigation into this claim has just begun, we intend to
vigorously defend the case. We cannot currently determine the likelihood or
range of any potential outcome.
20
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, 2001 to December 31, 2001.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information about our executive officers
as of February 15, 2002, as such term is defined in Rule 3b-7 of the Securities
Exchange Act of 1934, and certain of our other officers.
Name Age Position Officer Since
---------------------------------------------------------------------------------------------------
Ray R. Seegmiller 66 Chairman of the Board and Chief Executive Officer 1995
Dan O. Dinges 48 President and Chief Operating Officer 2001
Michael B. Walen 53 Senior Vice President, Exploration and Production 1998
J. Scott Arnold 48 Vice President, Land and Associate General Counsel 1998
R. Scott Butler 47 Vice President, Regional Manager, Western Region 2001
Robert G. Drake 54 Vice President, Management Information Systems 1998
Abraham D. Garza 55 Vice President, Human Resources 1998
Jeffrey W. Hutton 46 Vice President, Marketing 1995
Lisa A. Machesney 46 Vice President, Managing Counsel and
Corporate Secretary 1995
A. F. (Tony) Pelletier 49 Vice President, Regional Manager, Gulf Coast Region 2001
Scott C. Schroeder 39 Vice President, Chief Financial Officer and Treasurer 1997
Henry C. Smyth 55 Vice President and Controller 1998
All officers are elected annually by our Board of Directors. Except for
the following, all of the executive officers have been employed by Cabot Oil &
Gas Corporation for at least the last five years.
Dan O. Dinges joined Cabot Oil & Gas Corporation as President and Chief
Operating Officer and as a member of the Board of Directors in September 2001.
Mr. Dinges came to Cabot after a 20-year career with Samedan Oil Corporation, a
subsidiary of Noble Affiliates, Inc. The last three years, Mr. Dinges served as
Samedan's Senior Vice President, as well as Division General Manager for the
Offshore Division, a position he held since August 1996. He also served as a
member of the Executive Operating Committee for Samedan. Mr. Dinges started his
career as a Landman for Mobil Oil Corporation covering Louisiana, Arkansas and
the central Gulf of Mexico. After four years of expanding responsibilities at
Mobil he joined Samedan as a Division Landman - Offshore. Over the years, Mr.
Dinges held positions of increasing responsibility at Samedan including Division
Manager, Vice President and ultimately Senior Vice President. Mr. Dinges
received his BBA degree in Petroleum Land Management from The University of
Texas.
R. Scott Butler has been Vice President, Regional Manager, Western Region since
October 2001. Mr. Butler joined Cabot in 1998 as Director of Exploration and
was named Regional Manager, Western Region, in February 2001. He came to Cabot
following a 19-year career with Chevron where he served in roles of increasing
responsibility focusing on exploration in the lower 48 states. Mr. Butler holds
a bachelor's degree from Stanford University and a master's from the University
of Nevada at Reno, both in geology. He is a member of the American Association
of Petroleum Geologists and serves as a director-at-large for the Independent
Petroleum Association of Mountain States.
A. F. (Tony) Pelletier has been Vice President, Regional Manager, Gulf Coast
Region since October 2001. Mr. Pelletier joined the Company in April 2001 as
Regional Manager, Gulf Coast. Before coming to Cabot, he held positions of
increasing responsibility at PetroCorp Incorporated, most recently as Executive
Vice President and Chief Operating Officer. Prior to that, he worked at Exxon
Company USA in a variety of engineering and supervisory capacities. Mr.
Pelletier holds a B.S. in Mechanical Engineering and a master's in Civil
Engineering, both from Texas A&M University. He is a registered professional
engineer in the state of Texas.
21
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 closing 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
------------------------------------------------
2001
First Quarter $32.00 $25.88 $0.04
Second Quarter 34.20 24.22 0.04
Third Quarter 26.33 16.70 0.04
Fourth Quarter 24.99 18.35 0.04
2000
First Quarter $18.06 $14.19 $0.04
Second Quarter 24.94 16.75 0.04
Third Quarter 21.25 17.38 0.04
Fourth Quarter 31.75 19.00 0.04
As of January 31, 2002, there were 849 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
Cabot Oil & Gas 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) 2001 2000 1999 1998 1997
- ----------------------------------------------------------------------------------------------
Income Statement Data
Operating Revenues $ 447,042 $368,651 $294,037 $251,340 $269,771
Income from Operations 95,366 64,817 39,498 27,403 63,852
Net Income Available to
Common Stockholders 47,084 29,221 5,117 1,902 23,231
Basic Earnings per Share
Available to Common
Stockholders/(1)/ $ 1.56 $ 1.07 $ 0.21 $ 0.08 $ 1.00
Dividends per Common Share $ 0.16 $ 0.16 $ 0.16 $ 0.16 $ 0.16
Balance Sheet Data
Properties and Equipment, Net $ 981,338 $623,174 $590,301 $629,908 $469,399
Total Assets 1,069,031 735,634 659,480 704,160 541,805
Long-Term Debt 393,000 253,000 277,000 327,000 183,000
Stockholders' Equity 346,552 242,505 186,496 182,668 184,062
- ----------------------------------------------------------------------------------------------
/(1)/See Earnings per Common Share under Note 15 of the Notes to the Consolidated Financial Statements.
22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion is intended to assist you in understanding our
results of operations and our present financial condition. Our Consolidated
Financial Statements and the accompanying notes included elsewhere in this Form
10-K contain additional information that should be referred to when reviewing
this material.
Statements in this discussion may be forward-looking. These forward-looking
statements involve risks and uncertainties, including those discussed below,
which could cause actual results to differ from those expressed. Please read
Forward-Looking Information on page 32.
We operate in one segment, natural gas and oil exploration and development.
OVERVIEW
Our financial results depend upon many factors, particularly the price of
natural gas and our ability to market our production on economically attractive
terms. Price volatility in the natural gas market has remained prevalent in the
last few years. In the first quarter of 1999, we experienced a decline in energy
commodity prices, resulting in lower revenues and net income during this period.
However, in the summer of 1999 and continuing through 2000, prices improved. For
the months of April through October 2000, we had certain natural gas hedges in
place that prevented us from realizing the full impact of this price
environment. (See the Commodity Price Swaps and Options discussion about hedging
on page 38.) Despite this limitation, our realized natural gas price for each
month in the year 2000 was higher than the same month of any previous year. In
the final months of 2000 and into early 2001, the NYMEX futures market reported
unprecedented natural gas contract prices. We benefited from this market with
our realized natural gas price reaching $5.66 per Mcf in December and $8.46 per
Mcf in January 2001. When the NYMEX futures market was near its high on the last
day of December 2000, we entered into a series of price collars that protected
us from the subsequent price decline until their expiration in October 2001.
These price collar arrangements boosted 2001 revenue by $34.6 million,
increasing the average realized natural gas price by $0.50 per Mcf. The table
below illustrates how natural gas prices have fluctuated over the course of
2001. "Index" represents the Henry Hub index price. The "2001" price is the
natural gas price realized by us and it includes the impact of the natural gas
price collar arrangements:
(in $ per Mcf) Natural Gas Prices by Month
- --------------------------------------------------------------------------------
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
Index 9.91 6.22 5.03 5.35 4.87 3.73 3.16 3.19 2.34 1.86 3.16 2.28
2001 8.46 6.28 4.91 5.05 5.08 4.25 3.96 3.79 3.57 3.24 3.06 2.32
Prices for crude oil have followed a similar path as the commodity market
fell through 2001. The table below contains the West Texas Intermediate index
price ("Index") and our realized crude oil prices by month for 2001.
(in $ per Bbl) Crude Oil Prices by Month
- --------------------------------------------------------------------------------
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Index 28.66 27.40 26.30 28.46 28.37 26.26 26.35 27.20 23.43 21.18 19.44 19.84
2001 30.32 29.20 26.44 26.31 29.12 27.85 24.72 25.71 24.50 22.85 19.05 19.85
We reported earnings of $1.56 per share, or $47.1 million, for 2001. This
is up from the $1.07 per share, or $29.2 million, reported in 2000. The
improvement is a result of the stronger commodity price environment during the
year 2001 and the impact of the natural gas price collar arrangements, which
combined to push our realized natural gas price up 37% to $4.36 per Mcf.
Additionally, natural gas production was up 14% and crude oil sales volumes were
up 100% from last year. Overall, on a Mcf equivalent basis, our production grew
more than 21% over 2000. A 12% production increase was a result of our drilling
successes in 2000 and 2001, and the remaining 9% increase resulted from the
acquisition of Cody Company, which was effective August 1, 2001.
23
A discussion of our results from recurring operations can be found in the
Results of Operations section, beginning on page 33. Before taking into account
selected items, net income for 2001 was $51.9 million, or $1.71 per share, and
$30.2 million, or $1.10 per share for 2000.
In August 2001, we acquired the stock of Cody Company, the parent of Cody
Energy LLC ("Cody acquisition") for $231.2 million consisting of $181.3 million
of cash and 1,999,993 shares of common stock valued at $49.9 million.
Substantially all of the proved reserves of Cody Company are located in the
onshore Gulf Coast region. The acquisition was recorded using the purchase
method of accounting. As such, the Company reflected the assets and liabilities
acquired at fair value in the Company's balance sheet effective August 1, 2001
and the results of operations of Cody Company beginning August 1, 2001. In 2001,
these acquired properties contributed 6.2 Bcfe of production, $17.0 million of
operating revenue and $19.2 million of operating expenses including $11.6
million of DD&A expense. Additional 2001 costs included $5.3 million of interest
expense. These properties contributed $10.3 million in operating cash flow to
2001. The purchase price totaling approximately $315.6 million was allocated to
specific assets and liabilities based on certain estimates of fair values,
resulting in approximately $302.4 million allocated to property and $13.2
million allocated to working capital items. This $315.6 million was comprised of
non-cash common stock consideration of $49.9 million and a non-cash deferred tax
gross-up of $78.0 million and acquisition related fees and costs of $6.4
million. The deferred tax gross-up pertains to the deferred income taxes
attributable to the differences between the tax basis and the estimated fair
value of the acquired oil and gas properties.
We drilled 208 gross wells with a success rate of 87% in 2001 compared to
129 gross wells and an 86% success rate in 2000. Total capital expenditures were
$453.4 million for 2001, including $181.3 million in cash and $49.9 million in
common stock paid for Cody Company, compared to $122.6 million in 2000. Capital
spent in drilling activity increased $39.5 million, with the largest activity
increase coming in the Gulf Coast region, where we continued to develop the
Etouffee, Augen and Lake Pelto prospects in south Louisiana and initiated new
exploration in south Texas. We increased our spending for seismic data, both 2-D
and 3-D, and lease acquisition costs both in the Gulf Coast and Rocky Mountains
in order to evaluate and expand our drilling opportunities for 2001 and beyond.
The largest portion of this spending occurred in December 2001.
Total equivalent production for 2001 was 81.1 Bcfe, an increase of 21% over
2000. Of this increase, 12% resulted from drilling activity and the remaining 9%
was a result of the production from the acquired Cody Company properties.
At the end of 2001, our debt-to-total capitalization ratio was 53.1%, up
slightly from the end of 2000. This result was achieved despite expending $181.3
million as cash consideration in the Cody acquisition which was sourced
primarily by the issuance of $170 million in private placement Notes. During
2000, we improved our debt-to-total capitalization ratio from 61.1% at the end
of 1999 to 52.6% at the close of 2000. This improvement was a result of several
significant accomplishments. We sold 3.4 million shares of common stock in May
2000 for net proceeds of $71.5 million, of which $51.6 million was used to
repurchase all of our preferred stock. The remaining proceeds, along with
another $14.8 million from employee stock option exercises, were used to reduce
debt and pay dividends. From year end 1999 to year end 2000, we reduced debt by
$24 million.
We remain focused on our strategies to grow through the drill bit,
concentrating on the highest expected_return opportunities, and from synergistic
acquisitions. We believe these strategies are appropriate in the current
industry environment, enabling us to add shareholder value over the long term.
The preceding paragraphs, discussing our strategic pursuits and goals,
contain forward-looking information. Please read Forward-Looking Information on
page 32.
FINANCIAL CONDITION
Capital Resources and Liquidity
Our capital resources consist primarily of cash flows from our oil and gas
properties and asset-based borrowing supported by oil and gas reserves. Our
level of earnings and cash flows depends on many factors, including the price of
natural gas and oil, our ability to find and produce hydrocarbons and our
ability to control and reduce costs. Demand for
24
natural gas has historically been subject to seasonal influences characterized
by peak demand and higher prices in the winter heating season. However, in the
summer of 2000, our realized gas prices began to climb to unseasonably high
levels and by January 2001, we realized the highest prices in the Company's
history. Then in 2001, our realized natural gas price declined throughout the
year to a low of $2.32 per Mcf in December. A mild winter and the economic
recession may be contributing factors in the 2001 pricing volatility.
The primary sources of cash during 2001 were funds generated from
operations, proceeds from the issuance of Notes (see Note 5 of the Notes to the
Consolidated Financial Statements) and, to a lesser extent, proceeds from the
sale of stock. Funds were used primarily for exploration and development
expenditures, including the acquisition of Cody Company in August 2001, and
dividend payments.
We had a net cash outflow of $1.9 million during 2001. The net cash inflow
from operating activities of $250.4 million combined with the increase in debt
of $124.0 million to substantially fund the $386.1 million of cash used for
capital and exploration expenditures. Cash proceeds from the sales of non-
strategic assets and the sale of stock combined to provide an additional $14.6
million of cash flow.
(In millions) 2001 2000 1999
------------------------------------------------------------------------
Cash Flows Provided by Operating Activities $250.4 $119.0 $92.5
-------------------------
Cash flows provided by operating activities in 2001 were $131.4 million
higher than in 2000 and cash flows provided by operating activities in 2000 were
$26.5 million higher than in 1999. These improvements were primarily a result of
increased revenues from higher realized commodity prices and to a lesser extent
to increased natural gas and oil production.
(In millions) 2001 2000 1999
------------------------------------------------------------------------
Cash Flows Used by Investing Activities $(379.2) $(116.1) $(37.4)
--------------------------
Cash flows used by investing activities in 2001 included the $181.3 million
cash portion of the Cody Company acquisition. Additionally, capital spending for
drilling and facilities increased $39.5 million, or 49%, from last year to
$119.5 million. We drilled 208 gross wells, which represents a 61% increase over
2000.
Cash flows used by investing activities in 2000 were attributable to
capital and exploration expenditures of $119.2 million, offset by the receipt of
$3.1 million in proceeds received from the sale of non-strategic oil and gas
properties.
Cash flows used by investing activities in 1999 were attributable to
capital and exploration expenditures of $93.7 million, offset by the receipt of
$56.3 million in proceeds received from the sale of non-strategic oil and gas
properties.
(In millions) 2001 2000 1999
------------------------------------------------------------------------
Cash Flows Provided (Used) by Financing Activities $126.9 $3.0 $(55.6)
--------------------
Cash flows provided by financing activities in 2001 included the impact of
issuing $170 million in a private placement of Notes in July 2001 used to
partially fund the Cody Company acquisition. Partially offsetting this debt
increase was the reduction to the balance outstanding on the revolving credit
facility and the May 2001 prepayment of $16 million in debt that was due in May
2002.
Cash flows provided by financing activities in 2000 included $85.1 million
in proceeds received from the sale of common stock, both in a block trade and
through the exercise of employee stock options. Of the proceeds, $51.6 million
was used to repurchase all of the outstanding shares of preferred stock.
Additional cash used in financing activities included $24 million used to reduce
the year-end debt balance to $269 million from $293 million in 1999 and cash
used to pay dividends to stockholders.
Cash flows used by financing activities in 1999 included $50 million used
to reduce the year-end debt balance to $293 million from $343 million in 1998
and cash used to pay cash dividends to stockholders.
25
We have a revolving credit facility with a group of banks, the revolving
term of which runs to December 2003. The available credit line under this
facility, currently $250 million, is subject to adjustment on the basis of the
present value of estimated future net cash flows from proved oil and gas
reserves (as determined by the banks' petroleum engineer) and other assets.
Accordingly, oil and gas prices are an important part of this computation. Since
the current price environment remains volatile, management can not predict how
future price levels may change the banks' long-term price outlook. To reduce the
impact of any redetermination, we strive to manage our debt at a level below the
available credit line in order to maintain excess borrowing capacity. At year
end, this excess capacity totaled $127 million, or 51% of the total available
credit line. Management believes it has the ability to finance, if necessary,
our capital requirements, including acquisitions. Oil and gas prices also affect
the calculation of the financial ratios for debt covenant compliance. Please
read Note 5 of the Notes to the Consolidated Financial Statements for a more
detailed discussion of our revolving credit facility.
In the event that the available credit line is adjusted below the
outstanding level of borrowings, we have a period of 180 days to reduce our
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 any adjustment.
Our 2002 interest expense is expected to be approximately $29.2 million,
including interest on the $170 million 7.33% weighted average fixed rate notes
used to partially fund the acquisition of Cody Company. In May 2001, a $16
million principal payment was made on the 10.18% Notes. This amount had been
reflected as "Current Portion of Long-Term Debt" on the balance sheet.
Additionally, the final $16 million payment on these notes that was due in May
2002 was paid in May 2001 using existing capacity on the revolving credit
agreement.
Capitalization
Our capitalization information is as follows:
As of December 31,
(In millions) 2001 2000 1999
- ----------------------------------------------------------------------------
Long-Term Debt $393.0 $253.0 $277.0
Current Portion of Long-Term Debt -- 16.0 16.0
----------------------
Total Debt $393.0 $269.0 $293.0
======================
Stockholders' Equity
Common Stock (net of Treasury Stock) $346.6 $242.5 $129.8
Preferred Stock -- -- 56.7
----------------------
Total Equity 346.6 242.5 186.5
----------------------
Total Capitalization $739.6 $511.5 $479.5
======================
Debt to Capitalization 53.1% 52.6% 61.1%
----------------------
During 2001, dividends were paid on our common stock totaling $4.8 million.
We have paid quarterly common stock dividends of $0.04 per share since becoming
publicly traded in 1990. The amount of future dividends is determined by our
Board of Directors and is dependent upon a number of factors, including future
earnings, financial condition and capital requirements.
In May 2000, we bought back all of the shares of preferred stock from the
holder for $51.6 million. Since this stock had been recorded at a stated value
of $56.7 million on our balance sheet, we realized a negative dividend to
preferred stockholders of $5.1 million. We received net proceeds of $71.5
million from the sale of 3.4 million shares of common stock in a public offering
primarily to fund this transaction. After repurchasing the preferred stock, the
excess proceeds were used to reduce debt.
26
Capital and Exploration Expenditures
On an annual basis, we generally fund most of our capital and exploration
activities, excluding major oil and gas property acquisitions, with cash
generated from operations. We budget these capital expenditures based on our
projected cash flows for the year.
The following table presents major components of our capital and
exploration expenditures for the three years ended December 31, 2001.
(In millions) 2001 2000 1999
----------------------------------------------------------------------
Capital Expenditures
Drilling and Facilities $119.5 $ 80.0 $43.9
Leasehold Acquisitions 12.9 10.9 7.2
Pipeline and Gathering 3.8 3.2 3.8
Other 1.9 2.6 3.3
-------------------------------
138.1 96.7 58.2
-------------------------------
Proved Property Acquisitions 244.1/(1)/ 6.0 18.4
Exploration Expenses 71.2 19.9 11.5
-------------------------------
Total $453.4 $122.6 $88.1
===============================
----------------------------------------------------------------------
/(1)/ The 2001 amount includes the $49.9 million common stock component
of the Cody acquisition and excludes the $78.0 million deferred
tax gross-up. See Note 14, Cody Acquisition.
Total capital and exploration expenditures for 2001 increased $330.8
million compared to 2000, primarily as a result of the $231.2 million Cody
acquisition. The remaining increase of $99.6 million was due primarily to
increased drilling activity as well as increases in leasehold acquisitions costs
consistent with our future drilling plans. The 2001 drilling program included an
over 68% increase in net wells drilled and a $15.3 million increase in
geological and geophysical expenses, including costs of obtaining seismic data
that supports future drilling programs.
We plan to drill 121 gross wells in 2002 compared with 208 gross wells
drilled in 2001. This 2002 drilling program includes $104.6 million in total
capital and exploration expenditures, down from $453.4 million in 2001, which
was our largest capital program to date. Expected spending in 2002 includes
$62.6 million for drilling and dry hole exposure, $7.8 million for lease
acquisition and $9.9 million in geological and geophysical expenses. In
addition to the drilling and exploration program, other 2002 capital
expenditures are planned primarily for production equipment and for gathering
and pipeline infrastructure maintenance and construction. We will continue to
assess the natural gas price environment and may increase or decrease the
capital and exploration expenditures accordingly.
27
Contractual Obligations
We are committed to making cash payments in the future on two types on
contracts: Note agreements and leases. We have no off-balance sheet debt or
other such unrecorded obligations and we have not guaranteed the debt of any
other party. Below is a schedule of the future payments that we were obligated
to make based on agreements in place as of December 31, 2001.
Payments Due by Year
2003 2005 2007 &
(in thousands) Total 2002 to 2004 to 2006 Beyond
--------------------------------------------------------------------------------------------------------------
Long-Term Debt /(1)/ $393,000 $ -- $123,000 $40,000 $230,000
Operating Leases /(2)/ 29,843 5,194 8,555 7,474 8,620
-------- ------ -------- ------- --------
Total Contractual Cash Obligations $422,843 $5,194 $131,555 $47,474 $238,620
--------------------------------------------------------------------------------------------------------------
/(1)/ The $123 million shown as scheduled for payment in 2003 represents
the December 31, 2001 balance outstanding on the revolving credit
facility. Typically, we are able to replace this credit agreement
with a new one as this comes due. See discussion in Note 5 of the
Notes to the Consolidated Financial Statements.
/(2)/ A discussion of operating leases can be found in Note 8 of the
Notes to the Consolidated Financial Statements. We have no capital
leases.
Potential Impact of Our Critical Accounting Policies
Readers of this document and users of the information contained in it
should be aware of how certain events may impact our financial results based on
the accounting policies in place. The three most significant policies are
discussed below.
Commodity Pricing and Risk Management Activities
Our revenues, operating results, financial condition and ability to borrow
funds or obtain additional capital depend substantially on prevailing prices for
natural gas and, to a lesser extent, oil. Declines in oil and gas prices may
materially adversely affect our financial condition, liquidity, ability to
obtain financing and operating results. Lower oil and gas prices also may reduce
the amount of oil and gas that we can produce economically. Historically, oil
and gas prices and markets have been volatile, with prices fluctuating widely,
and they are likely to continue to be volatile. Depressed prices in the future
would have a negative impact on our future financial results. In particular,
substantially lower prices would significantly reduce revenue and could
potentially impact the outcome of our annual impairment test under SFAS 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets" when adopted.
Because our reserves are predominantly natural gas, changes in natural gas
prices may have a particularly large impact on our financial results.
The majority of production is sold at market responsive prices. Generally,
if the commodity indexes fall, the price that we receive for our production will
also decline. Therefore, the amount of revenue that we realize is partially
determined by factors beyond our control. However, management may mitigate this
price risk in a number of ways. Most recently, we have used financial
instruments such as natural gas price collar arrangements to reduce the impact
of declining pricing on our revenue. Under a price collar arrangement, there is
also risk that the index prices will rise above the ceiling price and the
Company will not be able to realize the full benefit of the market improvement.
We covered 16% of our production in 2000 with natural gas price collar
arrangements and prices rose above the ceiling during some months. If we had not
had these collars in place in 2000, our realized natural gas price would have
been $0.17 per Mcf higher. In 2001, we covered 35% of our natural gas production
with price collar arrangements and prices were below the floor for several
months. The gains from the 2001 price collars improved our annual realized
natural gas price by $0.50 per Mcf.
28
Successful Efforts Method of Accounting
We use 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
seismic purchases and processing, exploratory dry hole drilling costs and costs
of carrying and retaining unproved properties are expensed as incurred. During
2001, we drilled 30 exploratory wells and 18 of them were unsuccessful, adding
$37.9 million to exploration expense. This 40% success rate for exploratory
wells is not unusual, and as we focus more on our exploration program, we are
exposed to the risk of dry hole expense. Development costs, including the costs
to drill and equip development wells, and successful exploratory drilling costs
to locate proved reserves are capitalized.
We are also exposed to potential impairments if the book value of our
assets exceeds their future expected cash flows. This may occur if a field
discovers lower than anticipated reserves or if commodity prices fall below a
level that significantly effects anticipated future cash flows on the field. We
determine if an impairment has occurred through either adverse changes or as a
result of the annual review of all fields. 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.
Oil and Gas Reserves
The process of estimating quantities of proved reserves is inherently
uncertain, and the reserve data included in this document are only estimates.
Reserve engineering is a subjective process of estimating underground
accumulations of natural gas and crude oil that cannot be measured in an exact
manner. The process relies on interpretations of available geologic, geophysic,
engineering and production data. The extent, quality and reliability of this
technical data can vary. The process also requires certain economic assumptions,
some of which are mandated by the SEC, such as oil and gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds. The
accuracy of a reserve estimate is a function of:
. the quality and quantity of available data;
. the interpretation of that data;
. the accuracy of various mandated economic assumptions; and
. the judgment of the persons preparing the estimate.
Our proved reserve information included in this document is based on
estimates we prepared. Estimates prepared by others may be higher or lower than
our estimates.
Because these estimates depend on many assumptions, all of which may
substantially differ from actual results, reserve estimates may be different
from the quantities of natural gas and crude oil that are ultimately recovered.
In addition, results of drilling, testing and production after the date of an
estimate may justify material revisions to the estimate.
You should not assume that the present value of future net cash flows is
the current market value of our estimated proved natural gas and oil reserves.
In accordance with SEC requirements, we base the estimated discounted future net
cash flows from proved reserves on prices and costs on the date of the estimate.
Actual future prices and costs may be materially higher or lower than the prices
and costs as of the date of the estimate.
Our rate of recording depreciation, depletion and amortization expense
(DD&A) is dependent upon our estimate of proved reserves. If the estimates of
proved reserves declines, the rate at which we record DD&A expense increases,
reducing net income. Such a decline may result from lower market prices, which
may make it non-economic to drill for and produce higher cost fields. In
addition, the decline in proved reserve estimates may impact the outcome of our
annual impairment test under SFAS 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" when adopted.
29
Operating Risks and Insurance Coverage
Our business involves a variety of operating risks, including:
. blowouts, cratering and explosions;
. mechanical problems;
. uncontrolled flows of oil, natural gas or well fluids;
. fires;
. formations with abnormal pressures;
. pollution and other environmental risks; and
. natural disasters.
The operation of our natural gas gathering and pipeline systems also
involves various risks, including the risk of explosions and environmental
hazards caused by pipeline leaks and ruptures. The location of pipelines near
populated areas, including residential areas, commercial business centers and
industrial sites, could increase these risks. Any of these events could result
in loss of human life, significant damage to property, environmental pollution,
impairment of our operations and substantial losses to us. In accordance with
customary industry practice, we maintain insurance against some, but not all, of
these risks and losses. The occurrence of any of these events not fully covered
by insurance could have a material adverse effect on our financial position and
results of operations. The costs of these insurance policies are somewhat
dependent on our historical claims experience and also the areas in which we
choose to operate. During the past few years, we have drilled a higher
percentage of our wells in the Gulf Coast, where insurance rates are
significantly higher than in other regions such as Appalachia.
OTHER ISSUES AND CONTINGENCIES
Corporate Income Tax. We generate 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 sand 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 and Rocky Mountains during 1991 and 1992 qualified for the
tight gas sands tax credit. The credit for natural gas produced from Devonian
Shale is estimated to be $1.08 per Mmbtu in 2001. In 1995 and 1996, we completed
three transactions to monetize the value of these tax credits, resulting in
revenues of $2.0 million in 2001 and an estimated $2.1 million in 2002. See Note
13 of the Notes to the Consolidated Financial Statements for further discussion.
We have 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). 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 can not 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. Our 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. Our ability to incur debt and to make certain types
of investments is subject to certain restrictive covenants in the Company's
various debt instruments. Among other requirements, our Revolving Credit
Agreement and the Notes (see Note 5 of the Notes to the Consolidated Financial
Statements) 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,
2001, the calculated ratio for 2001 was 10.0 to 1.0. In the unforeseen event
that we fail to comply with these covenants, the Company may apply for a
temporary waiver with the bank, which, if granted, would allow us a period of
time to remedy the situation. See further discussion in Capital Resources and
Liquidity and Note 5 of the Notes to the Consolidated Financial Statements for
further discussion.
30
CONCLUSION
Our financial results depend upon many factors, particularly the price of
natural gas and oil and our ability to market gas on economically attractive
terms. The average produced natural gas sales price received by us has changed
from year-to-year as follows:
2001: increased 37% over 2000 to $4.36 per Mcf
2000: increased 44% over 1999 to $3.19 per Mcf
1999: increased 3% over 1998 to $2.22 per Mcf
1998: decreased 15% from 1997 to $2.16 per Mcf
1997: increased 8% over 1996 to $2.53 per Mcf
The volatility of natural gas prices in recent years remains prevalent in 2002
with wide price swings in day-to-day trading on the NYMEX futures market. Given
this continued price volatility, we can not predict with certainty what pricing
levels will be in the future. Because future cash flows are subject to these
variables, there is no assurance that our operations will provide cash
sufficient to fully fund our planned capital expenditures.
While our 2002 plan now includes $104.6 million in capital and exploration
spending, we will periodically assess industry conditions and adjust our 2002
spending plan to ensure the adequate funding of our capital requirements,
including, if necessary, reductions in capital and exploration expenditures or
common stock dividends. We believe our capital resources, supplemented with
external financing if necessary, are adequate to meet our capital requirements.
The preceding paragraphs contain forward-looking information. See Forward-
Looking Information on page 32.
Recently Issued Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statements of Financial Accounting Standards No. 141 "Business Combinations"
("SFAS 141") and No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142").
SFAS 141 requires all business combinations initiated after June 30, 2001 to be
accounted for under the purchase method. For all business combinations for which
the date of acquisition is after June 30, 2001, SFAS 141 also establishes
specific criteria for the recognition of intangible assets separately from
goodwill. SFAS 141 also requires unallocated negative goodwill (in a case where
the purchase price is less than fair market value of the acquired assets) to be
written off immediately as an extraordinary gain, rather than deferred and
amortized. SFAS 142 changes the accounting for goodwill and other intangible
assets after an acquisition. The most significant changes made by SFAS 142 are:
1) goodwill and intangible assets with indefinite lives will no longer be
amortized; 2) goodwill and intangible assets with indefinite lives must be
tested for impairment at least annually; and 3) the amortization period for
intangible assets with finite lives will no longer be limited to forty years.
The Company does not believe that the adoption of these statements will have a
material effect on its financial position, results of operations, or cash flows.
In June 2001, the FASB also approved for issuance SFAS 143 "Asset
Retirement Obligations." SFAS 143 establishes accounting requirements for
retirement obligations associated with tangible long-lived assets such as wells
and production facilities. SFAS 143 guidance covers (1) the timing of the
liability recognition, (2) initial measurement of the liability, (3) allocation
of asset retirement cost to expense, (4) subsequent measurement of the liability
and (5) financial statement disclosures. SFAS 143 requires that an asset
retirement cost should be capitalized as part of the cost of the related long-
lived asset and subsequently allocated to expense using a systematic and
rational method. The Company will adopt the statement effective no later than
January 1, 2003, as required. The transition adjustment resulting from the
adoption of SFAS 143 will be reported as a cumulative effect of a change in
accounting principle. At this time, the Company cannot reasonably estimate the
effect of the adoption of this statement on its financial position, results of
operations, or cash flows.
In August 2001, the FASB also approved SFAS 144, "Accounting for the
Impairment or Disposal of Long-
31
Lived Assets" ("SFAS 144"). SFAS 144 replaces SFAS 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of."
The new accounting model for long-lived assets to be disposed of by sale applies
to all long-lived assets, including discontinued operations, and replaces the
provisions of APB Opinion No. 30, "Reporting Results of Operations-Reporting the
Effects of Disposal of a Segment of a Business", for the disposal of segments of
a business. SFAS 144 requires that those long-lived assets be measured at the
lower of carrying amount or fair value less cost to sell, whether reported in
continuing operations or in discontinued operations. Therefore, discontinued
operations will no longer be measured at net realizable value or include amounts
for operating losses that have not yet occurred. SFAS 144 also broadens the
reporting of discontinued operations to include all components of an entity with
operations that can be distinguished from the rest of the entity and that will
be eliminated from the ongoing operations of the entity in a disposal
transaction. The provisions of SFAS 144 are effective for financial statements
issued for fiscal years beginning after December 15, 2001 and, generally are to
be applied prospectively. At this time, the Company cannot estimate the effect
of this statement on its financial position, results of operations, or cash
flows.
* * *
Forward-Looking Information
The statements regarding future financial and operating performance and
results, market prices, future hedging activities, and other statements that are
not historical facts contained in this report are forward-looking statements.
The words "expect," "project," "estimate," "believe," "anticipate," "intend,"
"budget," "plan," "forecast," "predict," "may," "should," "could" and similar
expressions are also intended to identify forward-looking statements. Such
statements involve risks and uncertainties, including, but not limited to,
market factors, market prices (including regional basis differentials) of
natural gas and oil, results for future drilling and marketing activity, future
production and costs and other factors detailed herein and in our other
Securities and Exchange Commission filings. Should one or more of these risks or
uncertainties materialize, or should underlying assumptions prove incorrect,
actual outcomes may vary materially from those indicated.
32
RESULTS OF OPERATIONS
For the purpose of reviewing our results of operations, "Net Income" is
defined as net income available to common stockholders.
Selected Financial and Operating Data
(In millions except where specified) 2001 2000 1999
------------------------------------------------------------------
Operating Revenues $447.0 $368.7 $294.0
Operating Expenses 351.7 303.8 258.5
Operating Income 95.4 64.8 39.5
Interest Expense 20.8 22.9 25.8
Net Income 47.1 29.2 5.1
Earnings Per Share - Basic $ 1.56 $ 1.07 $ 0.21
Earnings Per Share - Diluted $ 1.53 $ 1.06 $ 0.21
Natural Gas Production (Bcf)
Gulf Coast 25.6 14.1 15.5
West 26.2 29.0 29.3
Appalachia 17.4 17.8 20.7
----------------------
Total Company 69.2 60.9 65.5
Produced Natural Gas Sales Price ($/Mcf)
Gulf Coast $ 4.44 $ 3.79 $ 2.29
West 3.88 2.86 1.96
Appalachia 4.96 3.24 2.53
Total Company $ 4.36 $ 3.19 $ 2.22
Crude/Condensate
Volume (Mbbl) 1,908 953 929
Price ($/Bbl) $24.91 $26.81 $17.22
The table below presents the after-tax effects of certain selected items on
our results of operations for the three years ended December 31, 2001.
(In millions) 2001 2000 1999
----------------------------------------------------------------
Net Income Before Selected Items $ 51.9 $ 30.2 $ 0.4
Change in Derivative Fair Value 0.1
Severance Tax Refund 0.7
Buyout of Gas Sales Contract 7.3
Impairment of Long-Lived Assets (4.2) (5.6) (4.3)
Gain on Sale of Assets 2.4
Section 29 Tax Credit Provision (0.7)
Negative Preferred Stock Dividend 5.1
Contract Settlements 1.4
Bad Debt Expense (1.4) (1.3)
Severance Costs (0.6)
----------------------
Net Income $ 47.1 $ 29.2 $ 5.1
======================
These selected items impacted our financial results. Because they are not a
part of our normal business, we have isolated their effects in the table above.
These selected items for 2001 were as follows:
. The change in derivative fair value 2001 related to the adoption of SFAS
133 on January 1, 2001. See Note 11 of the Notes to the Consolidated
Financial Statements for further discussion.
. A severance tax refund of $0.7 million ($1.1 million pre-tax) was received
in the third quarter for taxes
33
previously paid in Louisiana that recently qualified for the Severance
Tax Relief Program as deep wells.
. A total impairment of $4.2 million ($6.9 million pre-tax) recorded in
2001. Two fields in the Gulf Coast region were impaired in the third
quarter since the cost capitalized exceeded the future undiscounted
cash flows. Also, one natural gas processing plant in the Rocky
Mountains area was written down to fair market value. In the fourth
quarter, the Starpath prospect in the Gulf Coast region was impaired.
. As a result of the Enron bankruptcy, we recorded $1.4 million ($2.3
million pre-tax) of bad debt expense primarily related to physical
natural gas sales made to Enron in November 2001.
These selected items for 2000 were as follows:
. A $9.1 million impairment ($5.6 million after tax) was recorded on the
Beaurline field in south Texas as a result of a casing collapse in two
of the field's wells.
. As a result of repurchasing all of the preferred stock at less than
the book value, we recorded a $5.1 million negative stock dividend in
May 2000.
. Miscellaneous net revenue, primarily from the settlement of a natural
gas sales contract, was recorded in the first quarter ($1.4 million
after tax). See Note 13 of the Notes to the Consolidated Financial
Statements for further discussion.
. As a result of bankruptcy proceedings of two of our customers, we
recorded $2.1 million in bad debt expense in the fourth quarter ($1.3
million after tax).
. We announced the closure of the regional office in Pittsburgh in May
2000 and recorded costs of $1.0 million ($0.6 million after tax).
These costs were recorded in the income statement categories that will
receive the future savings benefit ($0.6 million in operations, $0.1
million in exploration and $0.3 million in administration).
These selected items for 1999 were as follows:
. We had a 15-year cogeneration contract under which we sold
approximately 20% of our Western region natural gas per year. The
contract was due to expire in 2008, but during 1999 we reached an
agreement with the counterparty under which the counterparty bought
out the remainder of the contract for $12 million. This transaction,
completed in December 1999, accelerated the realization of any future
price premium that may have been associated with the contract and
added $12 million of pre-tax other revenue ($7.3 million after tax).
We simultaneously sold forward a similar quantity of Western region
gas production through April 2001 at similar prices to those in the
old contract. The natural gas sales price stated in this new contract
was significantly below year-end 2000 market prices in the region. See
Note 13 of the Notes to the Consolidated Financial Statements for
further discussion.
. In the fourth quarter of 1999, we recorded impairments totaling $7
million on two of our producing fields in the Gulf Coast region ($4.3
million after tax). The Chimney Bayou field was impaired by $6.6
million due to a significant reserve revision on the Broussard-
Middleton #1R well in connection with a decline in its natural gas
production accompanied by a marked increase in water production. The
Broussard-Middleton #1R was the only producing well in this field. The
Lawson field was impaired by $0.4 million due to an unsuccessful
workover on one of its wells.
. We recorded a $4 million gain on the sale of certain non-strategic oil
and gas assets, most notably the Clarksburg properties in the
Appalachian region sold to EnerVest effective October 1999 ($2.4
million after tax).
. We recorded a $1.2 million reserve against other revenue for certain
wells no longer deemed to be eligible for the Section 29 tight gas
sands credit following an industry tax court ruling ($0.7 million
after tax). Late in 1999, the FERC issued a rule proposal that may
ultimately restore the eligibility for some or all of the wells in
question. For an update on the FERC's actions, please read Note 13 of
the Notes to the Consolidated Financial Statements.
34
2001 and 2000 Compared
The following discussion is based on our results before taking into
account the selected items discussed above.
Net Income and Revenues. We reported net income in 2001 of $51.9
million, or $1.71 per share. During 2000, we reported net income of $30.2
million, or $1.10 per share. Operating income increased $28.5 million, or 38%,
and operating revenues increased $80.6 million, or 22%, in 2001. The improvement
in operating revenues was mainly a result of the $107.3 million rise in natural
gas sales due to the increases in both natural gas prices and production, and
the $22.0 million increase in crude oil sales revenue. Natural gas revenue and
our realized price were bolstered by a $34.6 million gain on natural gas price
collar arrangements used during 2001. See further discussion in Item 7A. These
improvements were partially offset by a decline in brokered natural gas volume
that reduced operating revenues by $50.4 million. Operating income was similarly
impacted by these revenue changes.
The average Gulf Coast natural gas production sales price rose $0.65
per Mcf, or 17%, to $4.44, increasing operating revenues by approximately $16.6
million. In the Western region, the average natural gas production sales price
increased $1.02 per Mcf, or 36%, to $3.88, increasing operating revenues by
approximately $26.7 million. The average Appalachian natural gas production
sales price increased $1.72 per Mcf, or 53%, to $4.96, increasing operating
revenues by approximately $29.9 million. The overall weighted average natural
gas production sales price increased $1.17 per Mcf, or 37%, to $4.36 per Mcf in
2001.
Natural gas production volume in the Gulf Coast region was up 11.5
Bcf, or 82%, to 25.6 Bcf primarily due to production from our discoveries in
south Louisiana and production from the Cody Company properties acquired in
August 2001. Natural gas production volume in the Western region was down 2.8
Bcf, or 10%, to 26.2 Bcf due primarily to lower levels of drilling activity in
the Mid-Continent area during the past three years. Natural gas production
volume in the Appalachian region was down 0.4 Bcf, or 2%, to 17.4 Bcf, as a
result of lower than anticipated success of the Oriskany drilling program in the
region in late 2000 and into 2001. Total natural gas production was up 8.3 Bcf,
or 14%, in 2001.
Crude oil prices fell $1.90 per Bbl, or 7%, to $24.91, resulting in a
decrease to operating revenues of approximately $3.6 million. The volume of
crude oil sold in the year doubled to 1,908 Mbbls, increasing operating revenues
by $25.6 million. This production increase was a result of our 2000 drilling
success in south Louisiana (80% increase) and the acquisition of Cody Company
(20% increase).
Brokered natural gas revenue decreased $50.4 million, or 36%, from the
prior year. The sales price of brokered natural gas rose 37%, resulting in an
increase in revenue of $24.5 million. The volume of natural gas brokered this
year declined by 53%, reducing revenues by $74.9 million. After including the
related brokered natural gas costs, we realized a net margin of $2.9 million in
2001 compared to a net margin of $5.4 million in 2000.
Excluding the selected items regarding the contract settlements in
2000, other operating revenues increased $1.6 million to $7.1 million. This
increase in 2001 is primarily the result of a settlement received as a result of
a lawsuit and increased revenue from the sale of natural gas liquids.
Costs and Expenses. Total costs and expenses from operations,
excluding the selected items related to the impairment of long-lived assets and
bad debt in each year and the costs associated with closing the regional office
in Pittsburgh during 2000, increased $52.1 million, or 18%, from 2000 due
primarily to the following:
. Brokered natural gas cost decreased $47.9 million, or 35%, primarily
due to the $73.0 million impact of the lower volume of brokered sales
in 2001. This was partially offset by a $25.1 million increase due to
higher natural gas costs compared to the prior year.
. Production and pipeline expense increased $6.0 million, or 17%,
primarily as a result of costs associated with operating the Cody
Company properties acquired in August 2001. Additionally, increased
staffing and insurance costs were incurred to support the expanded
2001 drilling program. On a units-of-production basis, our company-
wide production and pipeline expense was $0.51 per Mcfe in 2001 versus
$0.53 per Mcfe in 2000 as a result of the increased production
discussed above.
35
. Exploration expense increased $51.4 million, or 261%, primarily as a
result of the following:
. A $15.3 million increase in geological and geophysical expenses
over last year due to the acquisition of seismic data for future
evaluation and increased drilling activity in all regions.
. A $34.9 million increase in dry hole costs. Although the drilling
success rate improved from 86% in 2000 to 87% in 2001, we drilled
a total of 208 gross wells in 2001, a 61% increase over 2000. We
recorded seven exploratory dry holes in the higher cost Gulf
Coast region versus only two in 2000. We also recorded four
exploratory dry holes in the Rocky Mountains area and seven in
the Appalachian region for a total of 18, up from a Company total
of seven in 2000.
. A $0.8 million increase for salaries, wages and incentive
compensation largely attributable to increased staffing in the
Gulf Coast region to support the expanded drilling program.
. Depreciation, depletion, amortization and impairment expense,
excluding the selected item related to the SFAS 121 impairment in each
year, increased $30.6 million, or 53%, over 2000. Natural gas
equivalent production increased 21%, increasing DD&A expense by $12.3
million. The 27% increase in the per unit expense from $0.86 per Mcfe
to $1.09 per Mcfe was a result of increased production in the higher
cost Gulf Coast region (including the newly acquired Cody properties)
and resulted in an $18.3 million increase to DD&A expense for 2001.
. General and administrative expenses increased $5.5 million, primarily
as a result of increased staffing during the transition period
following the Cody Company acquisition and other staffing increases
that support our larger operations. Additional cost increases were
realized in incentive compensation programs as well as technology
updates and related software maintenance.
. Taxes other than income increased $6.4 million as a result of higher
natural gas and oil revenues.
Interest expense decreased $2.1 million due to a lower weighted
average interest rate realized in 2001. This was despite the new Notes issued to
partially fund the acquisition of Cody Company in August 2001.
Income tax expense was up $10.2 million due to the comparable increase
in earnings before income tax. Our effective tax rate decreased in 2001
reflecting a shift of activity between states.
2000 and 1999 Compared
The following discussion is based on our results before taking into
account the selected items discussed above.
Net Income and Revenues. We reported net income in 2000 of $30.2
million, or $1.10 per share. During 1999, we reported net income of $0.4
million, or $0.02 per share. Operating income increased $42.9 million, or 135%,
and operating revenues increased $83.1 million, or 29%, in 2000. The improvement
in operating revenues was mainly a result of the $48.7 million rise in natural
gas sales due to the increase in gas prices, and the $24.5 million increase in
brokered natural gas sales revenue. Operating revenues were reduced by a $10
million loss on natural gas price collar arrangements used during 2000. See
further discussion in Item 7A. Price and production volume increases in crude
oil also contributed to the higher operating revenues. Operating income was
similarly impacted by these revenue changes.
The average Gulf Coast natural gas production sales price rose $1.50
per Mcf, or 66%, to $3.79, increasing operating revenues by approximately $21.2
million. In the Western region, the average natural gas production sales price
increased $0.90 per Mcf, or 46%, to $2.86, increasing operating revenues by
approximately $24.9 million. The average Appalachian natural gas production
sales price increased $0.71 per Mcf, or 28%, to $3.24, increasing operating
revenues by approximately $12.7 million. The overall weighted average natural
gas production sales price increased $0.97 per Mcf, or 44%, to $3.19, increasing
revenues by $58.8 million.
Natural gas production volume in the Gulf Coast region was down 1.4
Bcf, or 9%, to 14.1 Bcf primarily due to production difficulties in the
Beaurline field and delays in bringing new production on-line in south
Louisiana. Natural gas production volume in the Western region was down 0.3 Bcf
to 29.0 Bcf due primarily to lower levels of drilling activity in the Mid-
Continent area during 1999 and 2000. Natural gas production volume in the
Appalachian
36
region was down 2.9 Bcf to 17.8 Bcf, as a result of the sale of certain non-
strategic assets in the Appalachian region effective October 1, 1999, and a
decrease in drilling activity in the region. Total natural gas production was
down 4.6 Bcf, or 7%, generating a revenue decrease of $10.1 million in 2000.
Crude oil prices rose $9.59 per Bbl, or 56%, to $26.81, resulting in
an increase to operating revenues of approximately $9.2 million. The volume of
crude oil sold in the year increased slightly to 953 Mbbls, increasing operating
revenues by $0.4 million.
Brokered natural gas revenue increased $24.5 million, or 21%, over the
prior year. The sales price of brokered natural gas rose 52%, resulting in an
increase in revenue of $48.5 million. The volume of natural gas brokered this
year declined by 21%, reducing revenues by $24.0 million. After including the
related brokered natural gas costs, we realized a net margin of $5.4 million in
2000.
Excluding the selected items regarding the contract settlements in
2000, and the sales contract buyout and the Section 29 tax credit provision in
1999, other operating revenues increased $0.2 million to $5.5 million.
Costs and Expenses. Total costs and expenses from operations,
excluding the selected items related to the impairment of long-lived assets in
each year and the costs associated with closing the regional office in
Pittsburgh during 2000, increased $40.2 million, or 16%, from 1999 due primarily
to the following:
. Brokered natural gas cost increased $23.5 million, or 21%, primarily
due to the $46.5 million impact of higher purchased natural gas
prices. This was partially offset by a $23.0 million reduction to
purchased natural cost, the result of fewer brokered sales this year
compared to the prior year.
. Production and pipeline expense increased $1.9 million, or 6%,
primarily as a result of costs associated with the expansion of the
Gulf Coast regional office, both in staffing and office facilities.
Additionally, operational costs for surface equipment and compressor
maintenance were up in the Rocky Mountains area where we drilled 50%
more net wells in 2000 compared to 1999. On a units-of-production
basis, our company-wide production and pipeline expense was $0.53 per
Mcfe in 2000 versus $0.47 per Mcfe in 1999.
. Exploration expense increased $8.3 million, or 72%, primarily as a
result of the following:
. A $3.5 million increase in geological and geophysical expenses
over last year due to increased drilling activity in all regions.
. A $1.3 million increase in delay rental costs over last year
largely due to delays in scheduled drilling projects in the Gulf
Coast region.
. A $2.1 million increase for salaries, wages and incentive
compensation largely attributable to increased staffing in the
Gulf Coast region to support the expanded drilling program.
. A $0.5 million increase in dry hole costs. Although the drilling
success rate improved from 84% in 1999 to 86% in 2000, we
recorded two exploratory dry holes in the higher cost Gulf Coast
region versus only one in 1999.
. Depreciation, depletion, amortization and impairment expense,
excluding the selected item related to the SFAS 121 impairment in each
year, increased $0.5 million, or 1%, over 1999. A 6% decrease in total
natural gas equivalent production caused the expense to remain just
slightly above last year's level, despite the 7% increase in the per
unit expense to $0.86 per Mcfe.
. General and administrative expenses remained at the same level as in
1999.
. Taxes other than income increased $6.1 million as a result of higher
natural gas and oil revenues.
Interest expense decreased $2.9 million primarily due to lower average
levels of borrowing on the revolving credit facility.
Income tax expense was up $18.1 million due to the comparable increase
in earnings before income tax.
No significant asset sale activity occurred in 2000. Gain on the sale
of assets was $4 million for 1999. These gains are the result of the non-
strategic asset divestitures, primarily the sale of the Clarksburg properties in
the
37
Appalachian region to EnerVest effective October 1999.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Oil and gas prices fluctuate widely, and low prices for an extended period of
time are likely to have a material adverse impact on our business.
Our revenues, operating results, financial condition and ability to
borrow funds or obtain additional capital depend substantially on prevailing
prices for natural gas and, to a lesser extent, oil. Declines in oil and
natural gas prices may materially adversely affect our financial condition,
liquidity, ability to obtain financing and operating results. Lower oil and gas
prices also may reduce the amount of oil and gas that we can produce
economically. Historically, oil and gas prices and markets have been volatile,
with prices fluctuating widely, and they are likely to continue to be volatile.
Oil and gas prices declined substantially in 1998 and early 1999, moved higher
through 2000 and into 2001 before declining back to year-end 1998 levels in
October 2001. Because our reserves are predominantly natural gas, changes in
natural gas prices may have a particularly significant impact on our financial
results.
Prices for oil and natural gas are subject to wide fluctuations in
response to relatively minor changes in the supply of and demand for oil and
gas, market uncertainty and a variety of additional factors that are beyond our
control. These factors include:
. The domestic and foreign supply of oil and natural gas.
. The level of consumer product demand.
. Weather conditions.
. Political conditions in oil producing regions, including the Middle
East.
. The ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls.
. The price of foreign imports.
. Actions of governmental authorities.
. Domestic and foreign governmental regulations.
. The price, availability and acceptance of alternative fuels.
. Overall economic conditions.
These factors make it impossible to predict with any certainty the future prices
of oil and gas.
Our hedging policy is designed to reduce the risk of price volatility
for our production in the natural gas, natural gas liquids and crude oil
markets. Currently we are focusing on protection from natural gas price
declines, particularly in light of our capital spending plans. A hedging
committee that consists of members of senior management overseas our hedging
activity. Our hedging arrangements apply to only a portion of our production and
provide only partial price protection against declines in oil and gas prices.
These hedging arrangements may expose us to risk of financial loss and limit the
benefit to us of increases in prices. Please read the discussion below related
to commodity price swaps and Note 11 of the Notes to the Consolidated Financial
Statements for a more detailed discussion of our hedging arrangements.
Commodity Price Swaps and Options
Hedges on Production - Swaps
From time to time, we enter into natural gas and crude oil swap
agreements with counterparties to hedge price risk associated with a portion of
our production. These derivatives are not held for trading purposes. Under these
price swaps, we receive a fixed price on a notional quantity of natural gas and
crude oil in exchange for paying a variable price based on a market-based index,
such as the NYMEX gas and crude oil futures. During 2001, we fixed the price at
an average of $3.75 per Mcf on quantities totaling 918 Mmcf, representing 1% of
the Company's 2001 natural gas production. We did not have crude oil swap
arrangements covering our production in 2001. During 2000, we fixed the price at
an average of $4.54 per Mcf on quantities totaling 315 Mmcf, representing less
38
than 1% of the Company's 2000 natural gas production. The notional volume of the
crude oil swap transactions was 364 Mbbls at a price of $22.67 per Bbl, which
represented approximately 38% of our total oil production for 2000. During 1999,
we fixed the price at an average of $2.88 per Mcf on quantities totaling 3,237
Mmcf, representing 5% of the Company's 1999 natural gas production. The notional
volume of the crude oil swap transactions was 306 Mbbls at a price of $20.65 per
Bbl, which represented approximately one-third of our total oil production for
1999.
The natural gas price swap arrangement that we entered into during the
third quarter of 2000 covered a portion of production over the period of October
2000 through September 2003. However, the counterparty declared bankruptcy in
December 2001. Based on the terms of the natural gas swap contract, this action
resulted in the cancellation of the contract. At the time of cancellation, the
contract's value was less than $0.2 million. As of the years ending December 31,
2001, and 2000, we had open natural gas price swap contracts on our production
as follows:
Natural Gas Price Swaps
------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Mmcf Contract Price (in $ millions)
-----------------------------------------------------------------------------------------
As of December 31, 2001
-----------------------
None
As of December 31, 2000
-----------------------
Natural Gas Price Swaps on Production in:
----------------------------------------
Full Year 2001 918 $3.75 $(2.8)
Full Year 2002 678 3.11 (1.0)
Full Year 2003 423 2.81 (0.5)
Financial derivatives related to natural gas production reduced
revenues by $0.8 million in 2001 and $0.3 million in 2000.
We had no open oil price swap contracts outstanding on our production
at December 31/st/ of 2001 or 2000. Financial derivatives related to crude oil
reduced revenue by $2.2 million during 2000, but had no impact on 2001 results.
Hedges on Production - Options
In December 2000, we believed that the pricing environment provided a
strategic opportunity to significantly reduce the price risk on a portion of our
production through the use of costless collars. Under the costless collar
arrangements, if the index rises above the ceiling price, we pay the
counterparty. If the applicable index falls below the floor, the counterparty
pays us. The 2001 natural gas price hedges include several costless collar
arrangements based on eight price indexes at which we sell a portion of our
production. These hedges were in place for the months of February through
October 2001 and covered 24,404 Mmcf, or 35%, of our natural gas production for
the year. All indexes were within the collars during February and April, some
fell below the floor during the period of March, and all indexes were below the
floor from June through October, resulting in a $34.6 million cash revenue for
the year. These gains contributed $0.50 per Mcf to our average realized natural
gas price for 2001.
During 2000, we used several costless collar arrangements to hedge a
portion of our natural gas production. There were seven collar arrangements
based on separate regional price indexes with a weighted average price floor of
$2.74 per Mcf and a weighted average price ceiling of $3.38 per Mcf. These
collars were in place during the months of April through October 2000. During
this period, if the index rose above the ceiling price, we paid the
counterparty. If the applicable index fell below the floor price, the
counterparty paid us. These collars covered a total quantity of 9,909 Mmcf, or
16% of our annual production. In April and May 2000, the index prices all fell
within the price collar and no settlements were made. In June 2000, all of the
indexes rose above the ceiling prices and remained above the ceiling for the
duration of the transaction resulting in a $10 million reduction to our realized
revenue for the year. If these hedges had not been in place, our average
realized natural gas price for 2000 would have been $0.17 per Mcf higher.
39
Again in December of 2001, we believed that the pricing environment
provided a strategic opportunity to significantly reduce the price risk on a
portion of our future production through the use of natural gas price collar
arrangements. As of December 31, 2001, we had open natural gas price collar
arrangements to hedge our production as follows:
Natural Gas Price Collars
---------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Mmcf Ceiling / Floor (in $ millions)
---------------------------------------------------------------------------------------------------
As of December 31, 2001
-----------------------
Natural Gas Collars on Production in:
------------------------------------
First Quarter of 2002 12,082 $3.54/$2.68 --
Second Quarter of 2002 4,027 $3.54/$2.68 --
As of December 31, 2000
-----------------------
Natural Gas Costless Collars on Production in:
---------------------------------------------
First Quarter of 2001 5,274 $9.68/$5.59 --
Second Quarter of 2001 8,135 $9.68/$5.59 --
Third Quarter of 2001 8,224 $9.68/$5.59 --
Fourth Quarter of 2001 2,771 $9.68/$5.59 --
The natural gas price hedges open at December 31, 2001, noted above,
included several collar arrangements based on nine price indexes at which we
sell a portion of our production. These hedges are in place for the months of
January through April 2002 and cover approximately 60% of our anticipated
natural gas production during this period. A premium totaling $0.9 million was
paid to purchase these collar arrangements.
Hedges on Brokered Transactions
We use price swaps to hedge the natural gas price risk on brokered
transactions. Typically, we enter into contracts to broker natural gas at a
variable price based on the market index price. However, in some circumstances,
some of our customers or suppliers request that a fixed price be stated in the
contract. After entering into these fixed price contracts to meet the needs of
our customers or suppliers, we may use price swaps to effectively convert these
fixed price contracts to market-sensitive price contracts. These price swaps are
held by us to their maturity and are not held for trading purposes.
We entered into price swaps with total notional quantities of 1,295
Mmcf in 2000 and 3,572 Mmcf in 1999 related to our brokered activities,
representing 3% and 7% respectively, of our total volume of brokered natural gas
sold. We did not use price swaps on brokered transactions in 2001.
As of the years ending December 31, 2000 and 2001, we had no open
natural gas price swap contracts on brokered transactions. Financial derivatives
related to natural gas reduced revenues by less than $0.1 million in 2000 and
had no impact on revenue in 2001.
We are exposed to market risk on these open contracts, to the extent
of changes in market prices of natural gas and oil. However, the market risk
exposure on these hedged contracts is generally offset by the gain or loss
recognized upon the ultimate sale of the commodity that is hedged.
Adoption of SFAS 133
We adopted Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) on
January 1, 2001. Under SFAS 133, the fair value of each derivative instrument is
recorded as either an asset or liability on the balance sheet. At the end of
each period, these instruments are marked-to-market. The gain or loss on the
change in fair value is recorded as Other Comprehensive Income, a component of
equity, to the extent that the derivative instrument is an effective hedge.
Under SFAS 133, effectiveness is a measurement of how closely correlated the
hedge instrument is with the underlying physical sale. For example, a natural
gas price swap that converts Henry Hub index to a fixed price would be perfectly
correlated,
40
and 100% effective, if the underlying gas was sold at the Henry Hub index. Any
portion of the gains or losses that are considered ineffective under the SFAS
133 test are recorded immediately as a component of operating revenue on the
statement of operations.
When we adopted SFAS 133, we had two types of hedges in place. The
first type was a cash flow hedge that set the price of a certain monthly
quantity of natural gas sold in the Gulf Coast region through September 2003.
Based on the index price strip, the impact of this hedge on January 1, 2001 was
to record a Hedge Loss of $0.1 million and a charge to Other Comprehensive
Income of $4.2 million. Correspondingly, a Hedge Liability for $4.3 million was
established. This instrument was cancelled in December 2001 with the bankruptcy
of the counterparty. No balance related to this hedge remains in Other
Comprehensive Income.
The second type of hedge outstanding at January 1, 2001 was a natural
gas price costless collar agreement. We had entered into eight of these collars
for a portion of our production at regional indexes for the months of February
through October 2001. The collars had two components of value: intrinsic value
and time value. Under SFAS 133, both components were valued at the end of each
reporting period. Intrinsic value arises when the index price is either above
the ceiling or below the floor for any period covered by the collar. If the
index is above the ceiling for any month covered by the collar, the intrinsic
value would be the difference between the index and the ceiling prices
multiplied by the notional volume. In accordance with the initial SFAS 133
guidance, intrinsic value related to the current month would be recorded as a
hedge loss (if the index is above the ceiling) or gain (if the index is below
the floor). Starting in 2001 under amended guidance on SFAS 133, any changes in
the intrinsic value component related to future months were recorded in Other
Comprehensive Income, a component of stockholders' equity on the balance sheet,
rather than to the income statement to the extent that the hedge was proven to
be effective. These natural gas price collars were considered to be highly
effective with respect to the intrinsic value calculation, since they were
tied to the same indexes at which our natural gas is sold. Also under SFAS 133,
the time value component, a market premium/discount, was marked-to-market
through the income statement each period. Since these collar arrangements were
executed on the last business day of 2000, the net premium value at adoption on
January 1, 2001 was zero.
As of December 31, 2001, we had a series of nine natural gas price
collar arrangements in place. In accordance with the latest guidance from the
FASB's Derivative Implementation Group, we test the effectiveness of the
combined intrinsic and time values and the effective portion of each will be
recorded as a component of Other Comprehensive Income. Any ineffective portion
will be recorded as a gain or loss in the current period. As of December 31,
2001, we have recorded $1.4 million of Other Comprehensive Income, a $0.1
million Unrealized Hedge Gain and a $1.5 million Hedge Asset.
41
Fair Market Value of 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.
Long-Term Debt
December 31, 2001 December 31, 2000
Carrying Estimated Carrying Estimated
(In thousands) Amount Fair Value Amount Fair Value
--------------------------------------------------------------------------
Debt
10.18% Notes $ -- $ -- $ 32,000 $ 33,162
7.19% Notes 100,000 104,961 100,000 97,033
7.26% Notes 75,000 79,187 -- --
7.36% Notes 75,000 79,225 -- --
7.46% Notes 20,000 21,097 -- --
Credit Facility 123,000 123,000 137,000 137,000
-------------------------------------------
$393,000 $407,470 $269,000 $267,195
===========================================
42
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
-----------------------------------------------------------------------------------------------------------
Report of Independent Accountants 44
Consolidated Statement of Operations for the Years Ended December 31, 2001, 2000 and 1999 45
Consolidated Balance Sheet at December 31, 2001 and 2000 46
Consolidated Statement of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999 47
Consolidated Statement of Stockholders' Equity for the Years Ended December 31, 2001, 2000 and 1999 48
Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2001, 2000 and 1999 49
Notes to the Consolidated Financial Statements 50
Supplemental Oil and Gas Information (Unaudited) 74
Quarterly Financial Information (Unaudited) 78
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 are prepared in conformity with accounting
principles generally accepted in the United States of America 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
Chairman of the Board and Chief Executive Officer
February 22, 2002
43
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors of Cabot Oil & Gas Corporation:
In our opinion, the consolidated financial statements listed in the
accompanying index present fairly, in all material respects, the financial
position of Cabot Oil & Gas Corporation and its subsidiaries at December 31,
2001 and 2000, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 2001 in conformity with
accounting principles generally accepted in the United States of America. 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
auditing standards generally accepted in the United States of America, 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 our opinion.
As discussed in Note 11 to the Notes to the Consolidated Financial
Statements, the Company changed its method of accounting for its derivative
instruments and hedging activities in connection with its adoption of Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities", as amended.
PricewaterhouseCoopers LLP
Houston, Texas
February 15, 2002
44
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
Year Ended December 31,
(In thousands, except per share amounts) 2001 2000 1999
----------------------------------------------------------------------------
OPERATING REVENUES
Natural Gas Production $301,529 $194,185 $145,495
Brokered Natural Gas 90,710 141,085 116,554
Crude Oil and Condensate 47,544 25,544 15,909
Change in Derivative Fair Value (Note 11) 142 -- --
Other (Note 13) 7,117 7,837 16,079
-----------------------------
447,042 368,651 294,037
OPERATING EXPENSES
Brokered Natural Gas Cost 87,785 135,700 112,164
Production and Pipeline Operations 41,217 35,727 33,357
Exploration 71,165 19,858 11,490
Depreciation, Depletion and Amortization 80,619 53,441 53,357
Impairment of Unproved Properties 7,803 4,368 3,950
Impairment of Long-Lived Assets 6,852 9,143 7,047
General and Administrative 25,650 20,421 20,136
Bad Debt Expense (Note 3) 2,270 2,096 --
Taxes Other Than Income 28,341 23,041 16,988
-----------------------------
351,702 303,795 258,489
Gain (Loss) on Sale of Assets 26 (39) 3,950
-----------------------------
INCOME FROM OPERATIONS 95,366 64,817 39,498
Interest Expense and Other 20,817 22,878 25,818
-----------------------------
Income Before Income Tax Expense 74,549 41,939 13,680
Income Tax Expense 27,465 16,467 5,161
-----------------------------
NET INCOME 47,084 25,472 8,519
Preferred Stock Dividend (Note 10) -- (3,749) 3,402
-----------------------------
Net Income Available to
Common Stockholders $ 47,084 $ 29,221 $ 5,117
=============================
Basic Earnings per Share Available
to Common Stockholders $ 1.56 $ 1.07 $ 0.21
Diluted Earnings per Share Available
to Common Stockholders $ 1.53 $ 1.06 $ 0.21
Average Common Shares Outstanding 30,276 27,384 24,726
The accompanying notes are an integral part of these consolidated financial
statements.
45
CABOT OIL & GAS CORPORATION
CONSOLIDATED BALANCE SHEET
December 31,
(In thousands, except share amounts) 2001 2000
----------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 5,706 $ 7,574
Accounts Receivable 50,711 85,677
Inventories 17,560 11,037
Other 11,010 5,981
---------------------
Total Current Assets 84,987 110,269
PROPERTIES AND EQUIPMENT (Successful Efforts Method) 981,338 623,174
OTHER ASSETS 2,706 2,191
---------------------
$1,069,031 $735,634
=====================
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current Portion of Long-Term Debt $ -- $ 16,000
Accounts Payable 79,575 81,566
Accrued Liabilities 30,665 20,542
---------------------
Total Current Liabilities 110,240 118,108
LONG-TERM DEBT 393,000 253,000
DEFERRED INCOME TAXES 200,859 108,174
OTHER LIABILITIES 18,380 13,847
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;
No Shares Outstanding in 2001 and 2000 (Note 10) -- --
Common Stock
Authorized - 40,000,000 Shares of $0.10 Par Value
Issued and Outstanding -
31,905,097 Shares in 2001 and
29,494,411 Shares in 2000 3,191 2,949
Class B Common Stock
Authorized - 800,000 Shares of $0.10 Par Value
No Shares Issued -- --
Additional Paid-in Capital 346,260 285,572
Retained Earnings (Accumulated Deficit) 650 (41,632)
Other Comprehensive Income 835 --
Less Treasury Stock, at Cost
302,600 Shares in 2001 and 2000 (4,384) (4,384)
---------------------
Total Stockholders' Equity 346,552 242,505
---------------------
$1,069,031 $735,634
=====================
The accompanying notes are an integral part of these consolidated financial
statements.
46
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended December 31,
(In thousands) 2001 2000 1999
---------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 47,084 $ 25,472 $ 8,519
Adjustments to Reconcile Net Income
to Cash Provided by Operations
Depletion, Depreciation and Amortization 80,619 53,441 53,357
Impairment of Unproved Properties 7,803 4,368 3,950
Impairment of Long-Lived Assets 6,852 9,143 7,047
Deferred Income Tax Expense 14,157 13,162 9,060
(Gain) Loss on Sale of Assets (26) 39 (3,950)
Exploration Expense 71,165 19,858 11,490
Change in Derivative Fair Value (142) -- --
Other 2,995 1,141 2,439
Changes in Assets and Liabilities
Accounts Receivable 34,966 (35,286) 5,408
Inventories (6,523) (108) (1,617)
Other Current Assets (3,524) (2,357) 164
Other Assets (515) 348 598
Accounts Payable and Accrued Liabilities (7,859) 26,976 (5,505)
Other Liabilities 3,383 2,813 1,528
---------------------------------
Net Cash Provided by Operations 250,435 119,010 92,488
---------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (127,129) (99,359) (82,191)
Acquisition of Cody Company /(1)/ (187,785) -- --
Proceeds from Sale of Assets 6,829 3,150 56,328
Exploration Expense (71,165) (19,858) (11,490)
---------------------------------
Net Cash Used by Investing (379,250) (116,067) (37,353)
---------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt 435,000 135,000 125,000
Decrease in Debt (311,000) (159,000) (175,000)
Sale of Common Stock 7,749 85,104 1,738
Common Dividends Paid (4,802) (4,350) (3,992)
Preferred Dividends Paid -- (2,202) (3,402)
Retirement of Preferred Stock -- (51,600) --
---------------------------------
Net Cash Provided (Used) by Financing 126,947 2,952 (55,656)
---------------------------------
Net Increase (Decrease) in Cash and
Cash Equivalents (1,868) 5,895 (521)
Cash and Cash Equivalents, Beginning of Year 7,574 1,679 2,200
---------------------------------
Cash and Cash Equivalents, End of Year $ 5,706 $ 7,574 $ 1,679
=================================
/1/ The amount excludes non-cash consideration of $49.9 million in common
stock issued in connection with the acquisition of Cody Company in
August 2001. This amount also excludes the $78.0 million deferred
taxes pertaining to the difference between the fair value of the
assets acquired and the related tax basis. The amount includes the
$181.3 million in cash consideration plus $6.4 million in capitalized
acquisition costs. See Note 14, Acquisition of Cody Company.
The accompanying notes are an integral part of these consolidated financial
statements.
47
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
Accumulated
Compre- Retained
Common Stock Preferred Treasury Paid-In hensive Earnings
(In thousands) Shares Par Stock Stock Capital Income (Deficit) Total
- ----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 24,960 $2,496 $ 113 $(4,384) $252,073 $(67,630) $182,668
--------------------------------------------------------------------------------
Net Income 8,519 8,519
Exercise of Stock Options 72 7 1,492 1,499
Preferred Stock Dividends (3,402) (3,402)
Common Stock Dividends
at $0.16 per Share (3,992) (3,992)
Stock Grant Vesting 42 4 1,198 1,202
Other 2 2
--------------------------------------------------------------------------------
Balance at December 31, 1999 25,074 $2,507 $ 113 $(4,384) $254,763 $(66,503) $186,496
================================================================================
Net Income 25,472 25,472
Exercise of Stock Options 766 77 14,764 14,841
Preferred Stock Dividends 3,749 3,749
Common Stock Dividends
at $0.16 per Share (4,350) (4,350)
Stock Grant Vesting 254 25 1,412 1,437
Issuance of Common Stock 3,400 340 71,219 71,559
Retirement of Preferred Stock (113) (56,586) (56,699)
--------------------------------------------------------------------------------
Balance at December 31, 2000 29,494 $2,949 $ -- $(4,384) $285,572 $(41,632) $242,505
================================================================================
Net Income 47,084 47,084
Exercise of Stock Options 411 42 9,339 9,381
Common Stock Dividends
at $0.16 per Share (4,802) (4,802)
Other Comprehensive Income 835 835
Stock Grant Vesting 1,689 1,689
Issuance of Common Stock 2,000 200 49,660 49,860
--------------------------------------------------------------------------------
Balance at December 31, 2001 31,905 $3,191 $ -- $(4,384) $346,260 $ 835 $ 650 $346,552
================================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
48
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Year Ended December 31,
(In thousands) 2001 2000 1999
------------------------------------------------------------------------------------
Net Income Available to Common Stockholders $ 47,084 $29,221 $5,117
--------------------------
Other Comprehensive Income
--------------------------
Cumulative Effect of Change in Accounting Principle
on January 1, 2001 (4,269) -- --
Reclassification Adjustments for Settled Contracts 33,762 -- --
Changes in Fair Value of Outstanding Hedge Positions (28,131) -- --
Deferred Income Tax (527) -- --
--------------------------
Total Other Comprehensive Income 835 -- --
--------------------------
Comprehensive Income $ 47,919 $29,221 $5,117
==========================
The accompanying notes are an integral part of these consolidated financial
statements.
49
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
Cabot Oil & Gas Corporation and its subsidiaries 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 within the
continental United States.
The consolidated financial statements contain the accounts of the Company
after eliminating all significant intercompany balances and transactions.
Recently Issued Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statements of Financial Accounting Standards No. 141 "Business Combinations"
("SFAS 141") and No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142").
SFAS 141 requires all business combinations initiated after June 30, 2001 to be
accounted for under the purchase method. For all business combinations for
which the date of acquisition is after June 30, 2001, SFAS 141 also establishes
specific criteria for the recognition of intangible assets separately from
goodwill. SFAS 141 also requires unallocated negative goodwill (in a case where
the purchase price is less than fair market value of the acquired assets) to be
written off immediately as an extraordinary gain, rather than deferred and
amortized. SFAS 142 changes the accounting for goodwill and other intangible
assets after an acquisition. The most significant changes made by SFAS 142 are:
1) goodwill and intangible assets with indefinite lives will no longer be
amortized; 2) goodwill and intangible assets with indefinite lives must be
tested for impairment at least annually; and 3) the amortization period for
intangible assets with finite lives will no longer be limited to 40 years. The
Company does not believe that the adoption of these statements will have a
material effect on its financial position, results of operations or cash flows.
The Company did not record goodwill as part of the Cody acquisition.
In June 2001, the FASB also approved for issuance SFAS 143 "Asset
Retirement Obligations." SFAS 143 establishes accounting requirements for
retirement obligations associated with tangible long-lived assets such as wells
and production facilities. SFAS 143 guidance covers (1) the timing of the
liability recognition, (2) initial measurement of the liability, (3) allocation
of asset retirement cost to expense, (4) subsequent measurement of the liability
and (5) financial statement disclosures. SFAS 143 requires that an asset
retirement cost should be capitalized as part of the cost of the related long-
lived asset and subsequently allocated to expense using a systematic and
rational method. The Company will adopt the statement effective no later than
January 1, 2003, as required. The transition adjustment resulting from the
adoption of SFAS 143 will be reported as a cumulative effect of a change in
accounting principle. At this time, the Company cannot reasonably estimate the
effect of the adoption of this statement on its financial position, results of
operations or cash flows.
In August 2001, the FASB also approved SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 144 replaces
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." The new accounting model for long-lived assets to be
disposed of by sale applies to all long-lived assets, including discontinued
operations, and replaces the provisions of APB Opinion No. 30, "Reporting
Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business", for the disposal of segments of a business. SFAS 144 requires that
those long-lived assets be measured at the lower of carrying amount or fair
value less cost to sell, whether reported in continuing operations or in
discontinued operations. Therefore, discontinued operations will no longer be
measured at net realizable value or include amounts for operating losses that
have not yet occurred. SFAS 144 also broadens the reporting of discontinued
operations to include all components of an entity with operations that can be
distinguished from the rest of the entity and that will be eliminated from the
ongoing operations of the entity in a disposal transaction. The provisions of
SFAS 144 are
50
effective for financial statements issued for fiscal years beginning after
December 15, 2001 and, generally are to be applied prospectively. At this time,
the Company cannot estimate the effect of this statement on its financial
position, results of operations, or cash flows.
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 as a result of the
annual review of all fields. During 2001, the Company recorded a total
impairment of $6.9 million primarily related to three Gulf Coast fields for
which capitalized cost exceeded the future undiscounted cash flows.
Additionally, one natural gas processing plant in the Rocky Mountains was
written down to fair market value. During 2000, two wells in the Beaurline
field in south Texas experienced casing collapses. This situation resulted in
an impairment to this field of $9.1 million, recorded in the second quarter
financial results. During the fourth quarter of 1999, the Company experienced a
significant production decline from the Chimney Bayou field located in the Texas
Gulf Coast. This decline along with an unsuccessful workover in the Lawson
field in Louisiana resulted in a $7.0 million impairment of long-lived assets
during 1999. These impairments were measured based on discounted cash flows
utilizing a discount rate appropriate for risks associated with the related
properties.
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 units-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 costs are accrued over the productive
life of the oil and gas properties on a units-of-production basis. The accrued
liability for plug and abandonment costs is included in accumulated
depreciation, depletion and amortization. As a component of accumulated
depreciation, depletion and amortization, total future plug and abandonment
costs were $14.4 million at December 31, 2001, and $12.4 million at December 31,
2000. The Company believes that this accrual method adequately provides for its
estimated future plug and abandonment costs over the reserve life of the oil and
gas properties.
The Company estimated at December 31, 2001 that it would ultimately require
approximately $50.8 million to plug and abandon its properties at the end of
their economic life occurring over the next 50 years. These costs would include
plugging all wells, removing all equipment and returning all sites to the
original condition. The Company anticipates these plugging and abandoning
operations to occur throughout future years as each well is fully produced.
Under SFAS 143, the Company will record the discounted present value of this
amount as a component of the capitalized cost of proved oil and gas properties,
and increase the future estimated liability monthly by recording implied
interest. These costs will be expensed over the life of the reserves.
51
Costs of retired, sold or abandoned properties that make up a part of an
amortization base (partial field) are charged to accumulated depreciation,
depletion and amortization if the units-of-production rate is not significantly
affected. Accordingly, a gain or loss, if any, is recognized only when a group
of proved properties (entire 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 proved reserves for these properties.
Brokered Natural Gas Margin
In prior years, the revenues and expenses related to brokering natural gas
were reported net on the Consolidated Statement of Operations as Brokered
Natural Gas Margin. Beginning in 2000, these amounts are reported gross as part
of Operating Revenues and Operating Expenses. Prior year amounts have been
reclassified to conform to the current year presentation.
The Company realizes brokered margin as a result of buying and selling
natural gas in back-to-back transactions. The Company realized $2.9 million,
$5.4 million, and $4.4 million of brokered natural gas margin in 2001, 2000, and
1999, respectively.
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 basis. 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 from outstanding checks in zero
balance cash accounts. These credit balances included in accounts payable were
$9.7 million at December 31, 2001, and $12.7 million at December 31, 2000.
Risk Management Activities
From time to time, the Company enters into derivative contracts, such as
natural gas price swaps or costless price collars, as a hedging strategy to
manage commodity price risk associated with its inventories, production or other
contractual commitments. These transactions are executed for purposes other
than trading. Gains or losses on these hedging activities are generally
recognized over the period that the inventory, production or other underlying
52
commitment is hedged as an offset to the specific hedged item. Cash flows
related to any recognized gains or losses associated with these hedges are
reported as cash flows from operations. If a 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 contract
not considered a hedge would be recognized currently in the results of
operations.
A derivative instrument qualifies as a hedge if all of the following tests
are met:
. The item to be hedged exposes the Company to price risk.
. The derivative reduces the risk exposure and is designated as a hedge at the
time the Company enters into the contract.
. At the inception of the hedge and throughout the hedge period there is a high
correlation between 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.
For example, in the case of natural gas price hedges, the gain or loss is
reflected in natural gas revenue. 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.
On January 1, 2001, the Company adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" (SFAS 133) and Statement of Financial Accounting Standards No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities"
(SFAS 138). SFAS 133 requires all derivatives to be recognized in the statement
of financial position as either assets or liabilities and measured at fair
value. In addition, all hedging relationships must be designated, reassessed
and documented according to the provisions of SFAS 133. SFAS 138 amended
portions of SFAS 133 and was adopted with SFAS 133.
All hedge transactions are subject to the Company's risk management policy,
approved by the Board of Directors, which does not permit speculative positions.
The Company formally documents all relationships between hedging instruments and
hedged items, as well as its risk management objectives and strategy for
undertaking the hedge. This process includes specific identification of the
hedging instrument and the hedge transaction, the nature of the risk being
hedged and how the hedging instrument's effectiveness will be assessed. Both at
the inception of the hedge and on an quarterly basis going forward, the Company
assesses whether the derivatives that are used in hedging transactions are
highly effective in offsetting changes in cash flows of hedged items.
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, 2001, and 2000, the cash and cash equivalents are primarily concentrated in
two financial institutions. The Company periodically assesses the financial
condition of these institutions and believes that any possible credit risk is
minimal.
Environmental Matters
Environmental expenditures are expensed or capitalized, as appropriate,
depending on their future economic benefit. Expenditures that relate to an
existing condition caused by past operations, and that do not have future
economic benefit are expensed. Liabilities related to future costs are recorded
on an undiscounted basis when environmental assessments and/or remediation
activities are probable and the costs can be reasonably estimated. Any
insurance recoveries are recorded as assets when received.
53
Use of Estimates
In preparing financial statements, the Company follows generally accepted
accounting principles. These principles require management to make estimates
and assumptions that affect the reported amounts of assets and liabilities, the
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) 2001 2000
- ----------------------------------------------- ---------- ----------
Proved Oil and Gas Properties $1,400,341 $ 993,397
Unproved Oil and Gas Properties 70,709 31,780
Gathering and Pipeline Systems 131,768 128,257
Land, Building and Improvements 4,674 4,538
Other 27,513 25,601
---------- ----------
1,635,005 1,183,573
Accumulated Depreciation,
Depletion, Amortization and Impairments (653,667) (560,399)
---------- ----------
$ 981,338 $ 623,174
========== ==========
As a component of accumulated depreciation, depletion and amortization,
total future plug and abandonment costs were $14.4 million at December 31, 2001,
and $12.4 million at December 31, 2000. See further discussion in Note 1.
On February 14, 2002, the Company determined that two exploratory wells
(one in the Gulf Coast and one in Appalachia) were unsuccessful and would be
abandoned. As of December 31, 2001, costs of approximately $7.7 million had
been incurred on these wells and this amount is included as a component of
Exploration Expense in the Statement of Operations. The Company anticipates
recording additional pre-tax dry hole expense of $2.5 million in the first
quarter of 2002 associated with drilling and abandoning these wells.
3. Additional Balance Sheet Information
Certain balance sheet amounts are comprised of the following:
December 31,
(In thousands) 2001 2000
- ---------------------------------------------- ------- -------
Accounts Receivable
Trade Accounts $39,570 $79,773
Joint Interest Accounts 12,889 4,074
Current Income Tax Receivable 2,662 37
Other Accounts 986 4,347
------- -------
56,107 88,231
Allowance for Doubtful Accounts /(1)/ (5,396) (2,554)
------- -------
$50,711 $85,677
======= =======
--------------------------------------------------------------------------
(1) Includes a $2.3 million addition in 2001 in connection with the Enron
Corp. bankruptcy. Includes a $2.1 million addition in 2000 in
connection with two trade receivable accounts determined not to be
collectible due to bankruptcy filings of the customers.
54
December 31,
(In thousands) 2001 2000
-----------------------------------------------------------------------
Other Current Assets
Derivative Instrument Asset - SFAS 133 $ 2,387 $ --
Drilling Advances 2,111 2,459
Prepaid Balances 2,114 2,172
Restricted Cash and Other Accounts /(1)/ 4,398 1,350
------- -------
$11,010 $ 5,981
======= =======
Accounts Payable
Trade Accounts $19,914 $23,757
Natural Gas Purchases 4,559 12,525
Wellhead Gas Imbalances 2,353 2,185
Royalty and Other Owners 11,041 22,858
Capital Costs 30,923 13,486
Taxes Other than Income 2,686 2,654
Drilling Advances 2,627 456
Other Accounts 5,472 3,645
------- -------
$79,575 $81,566
======= =======
Accrued Liabilities
Employee Benefits $ 7,151 $ 5,441
Taxes Other than Income 13,623 11,363
Interest Payable 6,996 2,478
Other Accrued 2,895 1,260
------- -------
$30,665 $20,542
======= =======
Other Liabilities
Postretirement Benefits Other than Pension $ 1,689 $ 1,497
Accrued Pension Cost 7,280 6,743
Taxes Other than Income and Other 9,411 5,607
------- -------
$18,380 $13,847
======= =======
-----------------------------------------------------------------------
/(1)/ In 2001, primarily represents cash in escrow for assumed Cody
Company liabilities.
4. Inventories
Inventories are comprised of the following:
December 31,
(In thousands) 2001 2000
-----------------------------------------------------------------------
Natural Gas and Oil in Storage $12,622 $10,277
Tubular Goods and Well Equipment 4,059 2,122
Pipeline Exchange Balances 879 (1,362)
------- -------
$17,560 $11,037
======= =======
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 (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 fourth payment due in May 2001, classified as Current Portion of Long-Term
Debt, was a current liability on the Company's Consolidated Balance Sheet at
December 31, 2000. However, the Company prepaid the remaining $32 million in
May 2001 along with a $0.9 million prepayment penalty, which was recorded as a
component of interest expense.
55
7.19% Notes
In November 1997, the Company issued an aggregate principal amount of $100
million of its 12-year 7.19% Notes (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. These covenants include 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.
7.33% Weighted Average Fixed Rate Notes
To partially fund the cash portion of the acquisition of Cody Company in
August 2001, the Company issued $170 million of Notes to a group of seven
institutional investors in a private placement transaction in July 2001. Prior
to the determination of the Note's interest rates, the Company entered into a
treasury lock in order to reduce the risk of rising interest rates. Interest
rates rose during the pricing period, resulting in a $0.7 million gain that will
be amortized over the life of the Notes, and thereby reducing the effective
interest rate by 5.5 basis points. All of the Notes have bullet maturities and
were issued in three separate tranches as follows:
Principal Term Coupon
------------------------------------------
Tranche 1 $75,000,000 10-year 7.26%
Tranche 2 $75,000,000 12-year 7.36%
Tranche 3 $20,000,000 15-year 7.46%
The Notes were issued under the same Note Purchase Agreement as the 7.19%
Notes.
Revolving Credit Agreement
The Company has a $250 million Revolving Credit Agreement (Credit Facility)
that utilizes nine banks. The term of the Credit Facility 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 Credit Facility
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 total indebtedness is either greater than 60% or 80% of the Company's
debt limit of $520 million, as shown below.
Debt Percentage
---------------------------------------------
Lower than 60% 60% - 80% Higher than 80%
=============================================
LIBOR margin 0.750% 1.000% 1.250%
CD margin 0.875% 1.125% 1.375%
Commitment fee rate 0.250% 0.375% 0.375%
The Credit Facility provides for a commitment fee on the unused available
balance at an annual rate one-fourth of 1% or three-eighths 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, 2001, 2000 and
1999 were 7.6%, 7.8%, and 6.7%, respectively. The Credit Facility contains
various customary restrictions, which include the following:
56
(a) Prohibition of the merger of the Company or any subsidiary with a third
party except under certain limited conditions.
(b) Prohibition of the sale of all or substantially all of the Company's or
any subsidiary's assets to a third party.
(c) Maintenance of a minimum annual coverage ratio of operating cash flow to
interest expense for the trailing four quarters of 2.8 to 1.0.
The Company was in compliance with all covenants at December 31, 2001 and 2000.
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,
2001, 2000 and 1999 are comprised of the following:
(In thousands) 2001 2000 1999
----------------------------------------------------------------------
Qualified
Current Year Service Cost $ 914 $ 832 $1,012
Interest Accrued on Pension Obligation 1,198 1,070 1,072
Expected Return on Plan Assets (1,064) (1,123) (919)
Net Amortization and Deferral 88 88 88
Recognized Gain (28) (282) --
--------------------------
Net Periodic Pension Cost $ 1,108 $ 585 $1,253
==========================
(In thousands) 2001 2000 1999
----------------------------------------------------------------------
Non-Qualified
Current Year Service Cost $ 88 $ 60 $ 140
Interest Accrued on Pension Obligation 72 42 67
Net Amortization 77 77 77
Recognized (Gain) Loss 21 (5) 35
--------------------------
Net Periodic Pension Cost $ 258 $ 174 $ 319
==========================
57
The following table illustrates the funded status of the Company's pension
plans at December 31, 2001, and 2000, respectively:
2001 2000
(In thousands) Qualified Non-Qualified Qualified Non-Qualified
-----------------------------------------------------------------------------------------------
Actuarial Present Value of:
Accumulated Benefit Obligation $14,279 $ 816 $12,188 $ 753
Projected Benefit Obligation $18,996 $ 898 $16,173 $ 978
Plan Assets at Fair Value 9,909 -- 11,801 --
---------------------------------------------------
Projected Benefit Obligation in Excess
of Plan Assets 9,087 898 4,372 978
Unrecognized Net Gain (Loss) (2,153) (260) 1,956 (351)
Unrecognized Prior Service Cost (511) (553) (599) (630)
Adjustment to Recognize Minimum
Liability -- 731 -- 756
---------------------------------------------------
Accrued Pension Cost $ 6,423 $ 816 $ 5,729 $ 753
===================================================
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) 2001 2000 1999
-------------------------------------------------------------------------
Beginning of Year $17,151 $14,546 $16,449
Service Cost 1,002 892 1,152
Interest Cost 1,270 1,112 1,139
Actuarial Loss (Gain) 1,166 1,328 (3,657)
Benefits Paid (695) (727) (537)
-------------------------
End of Year $19,894 $17,151 $14,546
=========================
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) 2001 2000 1999
-------------------------------------------------------------------------
Beginning of Year $11,801 $12,092 $10,344
Actual Return on Plan Assets (1,527) (440) 2,428
Employer Contribution 584 1,172 101
Benefits Paid (695) (727) (537)
Expenses Paid (254) (296) (244)
-------------------------
End of Year $ 9,909 $11,801 $12,092
=========================
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) 2001 2000 1999
-------------------------------------------------------------------------
Funded Status $ 9,985 $ 5,350 $ 2,454
Unrecognized Gain (Loss) (2,413) 1,605 5,078
Unrecognized Prior Service Cost (1,064) (1,229) (1,394)
-------------------------
Net Amount Recognized $ 6,508 $ 5,726 $ 6,138
=========================
Accrued Benefit Liability - Qualified Plan $ 6,423 $ 5,729 $ 6,194
Accrued Benefit Liability - Non-Qualified Plan 816 753 504
Intangible Asset (731) (756) (560)
-------------------------
Net Amount Recognized $ 6,508 $ 5,726 $ 6,138
=========================
58
Assumptions used to determine projected post-retirement benefit obligations
and pension costs are as follows:
2001 2000 1999
-----------------------------------------------------------------------
Discount Rate /(1)/ 7.25% 7.50% 7.75%
Rate of Increase in Compensation Levels 4.00% 4.00% 4.00%
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 7.50%
discount rate was used to compute pension costs in 2001, a rate of
7.75% in 2000, and a rate of 7.0% was used in 1999.
Savings Investment Plan
The Company has a Savings Investment Plan (SIP) which is a defined
contribution plan. The Company matches a portion of employees' contributions in
cash. 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 $1.0 million, $0.7 million, and $0.7 million in 2001, 2000, and
1999, respectively. The plan contribution rose in 2001 due to an increase in
the Company's matching program. Effective July 1, 2001, the Company increased
its dollar-for-dollar matching limit from 4% to 6% of an employee's pretax
earnings. 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, 2001, the balance in the Deferred
Compensation Plan's rabbi trust was $1.0 million.
The employee participants guide the diversification of trust assets. The
trust assets are invested in 13 mutual funds that cover the investment spectrum
from equity to money market. These mutual funds are publicly quoted and
reported at market value. No shares of Cabot Oil & Gas stock are held by the
trust. Settlement payments are made to participants in cash, either in a lump
sum or in periodic installments. The market value of the trust assets is
recorded on the Company's balance sheet as a component of "Other Assets" and the
corresponding liability is recorded as a component of "Other Liabilities."
There is no impact on earnings or earnings per share from the changes in
market value of the deferred compensation plan assets for two reasons. First,
the changes in market value of the trust assets are offset completely by changes
in the value of the liability, which represents trust assets belonging to plan
participants. Second, no shares of Cabot Oil & Gas stock are held in the trust.
The Company charged to expense plan contributions of less than $20,000 in
each year presented.
Postretirement Benefits Other than Pensions
In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits for retired employees, including their
spouses, eligible dependents and surviving spouses (retirees). These benefits
are commonly called postretirement benefits. Most employees become eligible for
these benefits if they meet certain age and service requirements at retirement.
The Company was providing postretirement benefits to 240 retirees at the end of
2001 and 241 retirees at the end of 2000.
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, known as the Transition
Obligation, over a period of 20 years.
59
Postretirement benefit costs recognized during the last three years are as
follows:
(In thousands) 2001 2000 1999
- -------------------------------------------------------------------------------
Service Cost of Benefits Earned During the Year $ 175 $ 187 $ 225
Interest Cost on the Accumulated Postretirement
Benefit Obligation 388 534 515
Amortization Benefit of the Unrecognized Gain (291) (132) (131)
Amortization Benefit of the Unrecognized
Transition Obligation 662 662 690
----- ------ ------
Total Postretirement Benefit Cost $ 934 $1,251 $1,299
===== ====== ======
The health care cost trend rate used to measure the expected cost in 2000
for medical benefits to retirees was 8%. Provisions of the plan should prevent
further increases in employer cost after 2000.
A one-percentage-point increase or decrease in health care cost trend rates
for future periods would not impact the accumulated net postretirement benefit
obligation or the total postretirement benefit cost recognized. Company costs
are capped at 2000 levels and the retirees assume any future increases in costs.
The funded status of the Company's postretirement benefit obligation at
December 31, 2001, and 2000 is comprised of the following:
(In thousands) 2001 2000
---------------------------------------------------------------------------------------------------
Plan Assets at Fair Value $ -- $ --
Accumulated Postretirement Benefits Other Than Pensions 5,507 5,429
Unrecognized Cumulative Net Gain 3,292 3,847
Unrecognized Transition Obligation (6,617) (7,279)
------- -------
Accrued Postretirement Benefit Liability $ 2,182 $ 1,997
======= =======
The change in the accumulated postretirement benefit obligation during the
last three years is presented as follows:
(In thousands) 2001 2000 1999
--------------------------------------------------------------------------
Beginning of Year $5,429 $ 7,243 $ 7,693
Service Cost 175 187 225
Interest Cost 388 534 515
Amendments -- -- (253)
Actuarial Loss (Gain) 265 (1,923) (102)
Benefits Paid (750) (612) (835)
------ ------- -------
End of Year $5,507 $ 5,429 $ 7,243
====== ======= =======
60
7. Income Taxes
Income tax expense is summarized as follows:
Year Ended December 31,
(In thousands) 2001 2000 1999
---------------------------------------------------------------------
Current
Federal $10,984 /(1)/ $ 3,089/(2)/ $(3,899)
State 496 216 --
------------------------------------
Total 11,480 3,305 (3,899)
------------------------------------
Deferred
Federal 13,723 11,804 8,910
State 2,262 1,358 150
------------------------------------
Total 15,985 13,162 9,060
------------------------------------
Total Income Tax Expense $27,465 $16,467 $ 5,161
====================================
---------------------------------------------------------------------------
/(1)/ The Federal Income Taxes Payable is zero at December 31, 2001
primarily as a result of tax payments made during the year, a 2000
overpayment applied to 2001, and a $1.8 million tax benefit related
to stock option exercises during 2001.
/(2)/ The Federal Income Taxes Payable is zero at December 31, 2000
primarily as a result of tax payments made during the year and a $1.8
million tax benefit related to stock option exercises during 2000.
In the table above, the $4.5 million refund received in 1999 that applied
to a net operating loss carryback to 1997 is reflected in "Current -Federal."
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) 2001 2000 1999
----------------------------------------------------------------------------------------
Statutory Federal Income Tax Rate 35% 35% 35%
Computed "Expected" Federal Income Tax $ 26,092 $14,679 $4,788
State Income Tax, Net of Federal Income Tax 2,758 1,552 506
Other, Net (1,385) /(1)/ 236 (133)
---------------------------------
Total Income Tax Expense $ 27,465 $16,467 $5,161
=================================
---------------------------------------------------------------------------
/(1)/ Other, Net includes credit adjustments totaling $1.7 million to
deferred taxes as a result of a reduction to the state effective tax
rate.
61
The tax effects of temporary differences that resulted in significant
portions of the deferred tax liabilities and deferred tax assets as of December
31, 2001, and 2000 were as follows:
(In thousands) 2001 2000
-----------------------------------------------------------------------
Deferred Tax Liabilities
Property, Plant and Equipment $224,031 $142,935
------------------
Deferred Tax Assets
Alternative Minimum Tax Credit Carryforwards 4,943 5,817
Net Operating Loss Carryforwards 1,715 13,904
Note Receivable on Section 29 Monetization/ (1)/ 4,928 6,397
Items Accrued for Financial Reporting Purposes 11,586 8,643
------------------
23,172 34,761
------------------
Net Deferred Tax Liabilities $200,859 $108,174
==================
---------------------------------------------------------------------------
/(1)/ 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.
As of December 31, 2001, the Company had a net operating loss carryforward
of $1.7 million for state income tax reporting purposes and none available for
regular federal income tax purposes. The Company has alternative minimum tax
credit carryforwards of $4.9 million which do 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 such 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. Leases for the Company's offices in Houston and Denver each run for
approximately eight more years. With the acquisition of Cody Company in August
2001, the Company assumed certain lease agreements, most of which expire in
2004. Most of the other leases expire within five years and may be renewed.
Rent expense under such arrangements totaled $7.7 million, $6.3 million, and
$5.0 million for the years ended December 31, 2001, 2000, and 1999,
respectively.
Future minimum rental commitments under non-cancelable leases in effect at
December 31, 2001 are as follows:
(In thousands)
-----------------------------
2002 $ 5,194
2003 4,602
2004 3,953
2005 3,855
2006 3,619
Thereafter 8,620
-------
$29,843
=======
Minimum rental commitments are not reduced by minimum sublease rental income of
$0.3 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. All known liabilities are fully accrued based on management's
best estimate of the potential loss. In management's opinion, final judgments
or settlements, if any, which may be awarded in connection with any one or more
of these suits and claims would not have a significant impact on the results of
operations, financial position or cash flows of any
62
period.
Environmental Liability
The EPA notified the Company in February 2000 of its potential liability
for waste material disposed of at the Casmalia Superfund Site ("Site"), located
on a 252-acre parcel in Santa Barbara County, California. Over 10,000 separate
parties disposed of waste at the Site while it was operational from 1973 to
1992. The EPA stated that federal, state and local governmental agencies along
with the numerous private entities that used the Site for disposal of
approximately 4.5 billion pounds of waste would be expected to pay the clean-up
costs, which are estimated by the EPA to be $271.9 million. The EPA is also
pursuing the owners/operators of the Site to pay for remediation.
Documents received by the Company with the notification from the EPA
indicate that the Company used the Site principally to dispose of salt water
from two wells over a period from 1976 to 1979. There is no allegation that the
Company violated any laws in the disposal of material at the Site. The EPA's
actions stem from the fact that the owners/operators of the Site do not have the
financial means to implement a closure plan for the Site.
A group of potentially responsible parties, including the Company, formed a
group, called the Casmalia Negotiating Committee ("CNC"). The CNC has had
extensive settlement discussions with the EPA and has reached a settlement in
principal to pay approximately $27 million toward Site clean up in return for a
release from liability. The CNC is currently negotiating a consent decree to
memorialize the settlement. On January 30, 2002, the Company placed $1,283,283
in an escrow account. This amount approximates the Company's volumetric share of
EPA's cost estimate, plus a 5% premium and is the Company's settlement amount.
The escrow account is being funded by the Company and many other CNC members to
maximize the likelihood that there will be sufficient funds to fund the
settlement agreement upon its completion, which is expected later in 2002. This
cash settlement, once released from escrow and paid to the federal government,
will resolve all federal claims against the Company for response costs and will
release the Company from all response costs related to the Site, except for
future claims against the Company for natural resource damage, unknown
conditions, transshipment risks and claims by third parties, all of which are
expected to be covered by insurance to be purchased by participating CNC
members. Responsibility for certain State of California oversight and response
costs, while not covered by the settlement or insurance, are not expected to be
material. No determination has been made as to whether any insurance arrangement
will allow the Company to recover its contribution to the settlement.
The Company has established a reserve that management believes to be
adequate to provide for this environmental liability based on its estimate of
the probable outcome of this matter and estimated legal costs.
Wyoming Royalty Litigation
In June 2000, two overriding royalty owners sued the Company in Wyoming
State court for unspecified damages. The plaintiffs have requested class
certification under the Wyoming Rules of Civil Procedure and allege that the
Company has deducted improper costs of production from royalty payments to the
plaintiffs and other similarly situated persons. Additionally, the suit claims
that the Company has failed to properly inform the plaintiffs and other
similarly situated persons of the deductions taken from royalties. In December
2001, fourteen overriding royalty owners sued the Company in Wyoming federal
court. The plaintiffs in the federal case have made the same general claims
pertaining to deductions from their overriding royalty as the plaintiffs in the
Wyoming state court case but have not asked for class certification.
The Company believes that it has substantial defenses to these claims and
intends to vigorously assert such defenses. The Company has a reserve that it
believes is adequate to provide for these potential liabilities based on its
estimate of the probable outcome of this matter. While the potential impact to
the Company may materially affect quarterly or annual financial results
including cash flows, management does not believe it would materially impact the
Company's financial position.
63
West Virginia Royalty Litigation
In late December 2001, two royalty owners sued the Company in West Virginia
State court for an unspecified amount of damages. The plaintiffs have requested
class certification under the West Virginia Rules of Civil Procedure and allege
that the Company has failed to pay royalty based upon the wholesale market value
of the gas produced, that the Company has taken improper deductions from the
royalty and that the Company has failed to properly inform the plaintiffs and
other similarly situated persons of deductions taken from the royalty.
Although the investigation into this claim has just begun, the Company
intends to vigorously defend the case. Management cannot currently determine
the likelihood or range of any potential outcome.
9. Cash Flow Information
Cash paid for interest and income taxes is as follows:
Year Ended December 31,
(In thousands) 2001 2000 1999
-------------------------------------------------
Interest $16,295 $23,180 $25,445
Income Taxes $14,395 $ 1,419 $ 652
At December 31, 2001, and 2000, the Accounts Payable balance on the
Consolidated Balance Sheet included payables for capital expenditures of $30.9
million and $13.5 million, respectively.
10. Capital Stock
Incentive Plans
On May 3, 2001, the Second Amended and Restated 1994 Long-Term Incentive
Plan and the Second 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 (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
5,260,000 shares of Common Stock may be issued under the Incentive Plans. All
stock options have a maximum term of five or 10 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,
2001 2000 1999
-----------------------------------------------------------------------------------
Shares Under Option at Beginning of Period 1,124,148 1,773,389 1,557,936
Granted 454,100 299,250 454,100
Exercised 408,949 896,081 55,032
Surrendered or Expired 87,678 52,410 183,615
-------------------------------------
Shares Under Option at End of Period 1,081,621 1,124,148 1,773,389
=====================================
Options Exercisable at End of Period 355,778 474,599 1,108,637
=====================================
For each of the three most recent years, the price range for outstanding
options was $14.69 to $27.30 per share. The following tables provide more
information about the options by exercise price and year.
64
Options with exercise prices between $14.69 and $20.00 per share:
December 31,
2001 2000 1999
----------------------------------------------------------------------------------------------------------
Options Outstanding
-------------------
Number of Options 480,561 866,498 1,412,072
Weighted Average Exercise Price $ 17.79 $ 17.63 $ 16.07
Weighted Average Contractual Term (in years) 1.50 2.60 2.40
Options Exercisable
-------------------
Number of Options 211,734 372,418 953,640
Weighted Average Exercise Price $ 17.29 $ 16.27 $ 15.44
Options with exercise prices between $20.01 and $27.30 per share:
December 31,
2001 2000 1999
----------------------------------------------------------------------------------------------------------
Options Outstanding
-------------------
Number of Options 601,060 257,650 361,317
Weighted Average Exercise Price $ 25.44 $ 22.46 $ 22.50
Weighted Average Contractual Term (in years) 4.30 1.90 3.37
Options Exercisable
-------------------
Number of Options 144,044 102,181 154,997
Weighted Average Exercise Price $ 22.45 $ 22.51 $ 22.55
Under the Second Amended and Restated 1994 Long-Term Incentive Plan,
the Compensation Sub-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 granted in July 1996 were converted to 19,090
shares of the Company's Common Stock in 1999. The Board of Directors has not
issued performance shares since July 1996, and currently, there are no
performance shares outstanding.
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 as follows:
2001 2000 1999
-------------------------------------------------------------------------------------------------------------
Net Income/(1)/ $45.7 million $28.2 million $ 4.3 million
Net Income per Share $1.51 $1.03 $0.20
Weighted Average Value of
Options Granted During the Year/(2)/ $8.61 $6.63 $4.78
Assumptions
Stock Price Volatility 34.9% 34.5% 27.4%
Risk Free Rate of Return 4.7% 5.21% 5.21%
Dividend Rate (per year) $0.16 $0.16 $0.16
Expected Term (in years) 4 4 4
-------------------------------------------------------------------------------------------------------------
/(1)/ Net income is defined as Net Income Available to Common
Shareholders.
/(2)/ Calculated using the fair value based method.
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.
65
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. None of the note or credit agreements in place 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. No additional shares were repurchased during 1999, 2000 or 2001. The
stock repurchase plan was funded 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. On December 8, 2000, the rights agreement for
the plan was amended and restated to extend the term of the plan to 2010 and to
make other changes. Each right becomes exercisable, at a price of $55, when any
person or group has acquired or made a tender or exchange offer for beneficial
ownership of 15 percent or more of the Company's outstanding Common Stock. 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). After a person or group acquires beneficial ownership
of 15% of the Common Stock, each right entitles the holder to purchase Common
Stock or other property having a market value (as defined in the plan) of twice
the exercise price of the right. An exception to this triggering event applies
in the case of 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 directors. Under certain
circumstances, the Board of Directors may opt to exchange one share of Common
Stock for each exercisable right. If there is a 15% holder and the Company is
acquired in a merger or other business combination in which it is not the
survivor, or 50 percent or more of the Company's assets or earning power are
sold or transferred, each right entitles the holder to purchase common stock of
the acquiring company with a market value (as defined in the plan) equal to
twice the exercise price of each right. At December 31, 2001, and 2000, there
were no shares of Junior Preferred Stock issued or outstanding.
The rights expire on January 21, 2010, and may be redeemed by the Company
for $0.01 per right at any time before a person or group acquires beneficial
ownership of 15% of the Common Stock.
Preferred Stock
At December 31, 1999 and 1998, 1,134,000 shares of 6% convertible
redeemable preferred stock (6% preferred stock) were issued and outstanding.
The shares of 6% preferred stock were issued in May 1994 to the seller in
connection with Cabot Oil & Gas' acquisition of a subsidiary of the seller. The
6% preferred stock had a liquidation preference of $50 per share, provided for
quarterly cash dividends at the rate of 6% per annum, was convertible into Cabot
Oil & Gas Class A common stock at the holder's option at a conversion price of
$28.75, and was entitled to 1.739 votes per share, generally voting together
with the Class A common stock. The 6% preferred stock was not redeemable at the
holder's option, but was redeemable at the option of Cabot Oil & Gas commencing
in May 1998 at a price of $50 per share, payable in shares of Class A common
stock until May 1999 and in cash thereafter, plus cash in an amount equal to
accrued and unpaid dividends.
In October 1999, Cabot Oil & Gas agreed with the holder of the 6% preferred
stock that the Company would repurchase all the 6% preferred stock for $51.6
million in cash or Class A common stock. During the second
66
quarter of 2000, the Company completed this repurchase and paid the holder of
the preferred stock $51.6 million in cash. The cash payment was funded using a
portion of the proceeds from the issuance of 3,400,000 shares of Class A common
stock in a registered offering at a price of $21.50 per share (yielding net
proceeds of $71.5 million, after expenses). The remaining proceeds of this
offering of Class A common stock were used to reduce borrowings under the
revolving credit facility.
The difference between the payment to the holder of the 6% preferred stock
($51.6 million) and the carrying amount of the 6% preferred stock on the
Company's balance sheet ($56.7 million) was added to net earnings available to
common shareholders in the calculation of earnings per share. This difference
represents a forgone return to the preferred shareholder and is treated similar
to a dividend; accordingly, a negative dividend of $5.1 million was recognized
upon the repurchase.
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.
Long-Term Debt
December 31, 2001 December 31, 2000
Carrying Estimated Carrying Estimated
(In thousands) Amount Fair Value Amount Fair Value
----------------------------------------------------------------
Debt
10.18% Notes $ -- $ -- $ 32,000 $ 33,162
7.19% Notes 100,000 104,961 100,000 97,033
7.26% Notes 75,000 79,187 -- --
7.36% Notes 75,000 79,225 -- --
7.46% Notes 20,000 21,097 -- --
Credit Facility 123,000 123,000 137,000 137,000
-------------------------------------------
$393,000 $407,470 $269,000 $267,195
===========================================
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, the 7.19% Notes,
the 7.26% Notes, the 7.36% Notes and the 7.46% Notes is based on interest rates
currently available to the Company. The 10.18% Notes were repaid in May 2001.
The Credit Facility approximates fair value because this instrument bears
interest at rates based on current market rates.
Commodity Price Swaps and Options
Hedges on Production - Swaps
From time to time, the Company enters into natural gas and crude oil swap
agreements with counterparties to hedge price risk associated with a portion of
its production. These derivatives are not held for trading purposes. Under these
price swaps, the Company receives a fixed price on a notional quantity of
natural gas and crude oil in exchange for paying a variable price based on a
market-based index, such as the NYMEX gas and crude oil futures. During 2001,
the Company fixed the price at an average of $3.75 per Mcf on quantities
totaling 918 Mmcf, representing 1% of the Company's 2001 natural gas production.
The Company did not have crude oil swap arrangements covering its production in
2001. During 2000, the Company fixed the price at an average of $4.54 per Mcf on
quantities totaling 315 Mmcf, representing less than 1% of the Company's 2000
natural gas production. The notional volume of the crude oil swap transactions
was 364 Mbbls at a price of $22.67 per Bbl, which represents approximately 38%
of the Company's total oil production for 2000. During 1999, the Company fixed
the price at an average of $2.88 per Mcf on quantities totaling 3,237 Mmcf,
representing 5% of the Company's 1999 natural gas production. The notional
volume of the crude oil swap transactions was 306 Mbbls at a price of $20.65 per
Bbl, which represents approximately one-third of the Company's total oil
production for 1999.
67
The natural gas price swap arrangement that the Company entered into during
the third quarter of 2000 covered a portion of production over the period of
October 2000 through September 2003. However, the counterparty declared
bankruptcy in December 2001. Based on the terms of the natural gas swap
contract, this action results in the cancellation of the contract. As of the
years ending December 31, 2001, and 2000, the Company had open natural gas price
swap contracts on its production as follows:
Natural Gas Price Swaps
----------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Mmcf Contract Price (in $ millions)
--------------------------------------------------------------------------------------
As of December 31, 2001
-----------------------
None
As of December 31, 2000
-----------------------
Natural Gas Price Swaps on Production in:
----------------------------------------
Full Year 2001 918 $3.75 $(2.8)
Full Year 2002 678 3.11 (1.0)
Full Year 2003 423 2.81 (0.5)
Financial derivatives related to natural gas production reduced revenues by
$0.8 million in 2001 and $0.3 million in 2000.
The Company had no open oil price swap contracts outstanding on its
production at December 31/st/ of 2001 or 2000. Financial derivatives related to
crude oil reduced revenue by $2.2 million during 2000, but had no impact on 2001
results.
Hedges on Production - Options
In December 2000, management believed that the pricing environment provided
a strategic opportunity to significantly reduce the price risk on a portion of
the Company's production through the use of costless collars. Under the costless
collar arrangements, if the index rises above the ceiling price, the Company
pays the counterparty. If the applicable index falls below the floor, the
counterparty pays the Company. The natural gas price hedges include several
costless collar arrangements based on eight price indexes at which the Company
sells a portion of its production. These hedges were in place for the months of
February through October 2001 and covered 24,404 Mmcf, or 35%, of the Company's
natural gas production for the year. All indexes were within the collars during
February and April, some fell below the floor during the period of March, and
all indexes were below the floor from June through October, resulting in $34.6
million cash revenue for the year. This revenue contributed $0.50 per Mcf to the
Company's average realized natural gas price for 2001.
During 2000, the Company used several costless collar arrangements to hedge
a portion of its natural gas production. There were seven collar arrangements
based on separate regional price indexes with a weighted average price floor of
$2.74 per Mcf and a weighted average price ceiling of $3.38 per Mcf. These
collars were in place during the months of April through October 2000. These
collars covered a total quantity of 9,909 Mmcf, or 16% of the Company's annual
production. In April and May 2000, the index prices all fell within the price
collar and no settlements were made. In June 2000, all of the indexes rose above
the ceiling prices and remained above the ceiling for the duration of the
transaction resulting in a $10 million reduction to the Company's realized
revenue for the year. If these hedges had not been in place, the Company's
average realized natural gas price for 2000 would have been $0.17 per Mcf
higher.
Again in December of 2001, management believed that the pricing environment
provided a strategic opportunity to significantly reduce the price risk on a
portion of the Company's future production through the use of natural gas price
collar arrangements. A premium totaling $0.9 million was paid to purchase these
collar arrangements. This cost will be expensed as the instruments are marked-
to-market each quarter. As of December 31, 2001, the Company had open natural
gas price collar arrangements to hedge production as follows:
68
Natural Gas Price Collars
-----------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Mmcf Ceiling / Floor (in $ millions)
-----------------------------------------------------------------------------------------------
As of December 31, 2001
-----------------------
Natural Gas Collars on Production in:
------------------------------------
First Quarter of 2002 12,082 $3.54/$2.68 --
Second Quarter of 2002 4,027 $3.54/$2.68 --
As of December 31, 2000
-----------------------
Natural Gas Costless Collars on Production in:
---------------------------------------------
First Quarter of 2001 5,274 $9.68/$5.59 --
Second Quarter of 2001 8,135 $9.68/$5.59 --
Third Quarter of 2001 8,224 $9.68/$5.59 --
Fourth Quarter of 2001 2,771 $9.68/$5.59 --
The natural gas price hedges open at December 31, 2001, noted above,
include several collar arrangements based on nine price indexes at which the
Company sells a portion of its production. These hedges are in place for the
months of January through April 2002 and cover approximately 60% of the
Company's anticipated natural gas production during this period. A premium
totaling $0.9 million was paid to purchase these collar arrangements.
Hedges on Brokered Transactions
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 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 the customers or suppliers, the Company may use price swaps
to effectively convert these fixed price contracts to market-sensitive price
contracts. These price swaps were held by the Company to their maturity and are
not held for trading purposes.
The Company entered into price swaps with total notional quantities of
1,295 Mmcf in 2000, and 3,572 Mmcf in 1999 related to its brokered activities,
representing 3% and 7% respectively, of its total volume of brokered natural gas
sold. The Company did not use price swaps on brokered transactions in 2001.
As of the years ending December 31, 2000 and 2001, the Company had no open
natural gas price swap contracts on brokered transactions. Financial
derivatives related to natural gas reduced revenues by less than $0.1 million in
2000 and had no impact on revenue in 2001.
The Company is exposed to market risk on these open contracts, to the
extent of changes in market prices of natural gas and oil. However, the market
risk exposure on these hedged contracts is generally offset by the gain or loss
recognized upon the ultimate sale of the commodity that is hedged.
Adoption of SFAS 133
The Company adopted Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) on
January 1, 2001. Under SFAS 133, the fair value of each derivative instrument is
recorded as either an asset or liability on the balance sheet. At the end of
each period, these instruments are marked-to-market. The gain or loss on the
change in fair value is recorded as Other Comprehensive Income, a component of
equity, to the extent that the derivative instrument is an effective hedge.
Under SFAS 133, effectiveness is a measurement of how closely correlated the
hedge instrument is with the underlying physical sale. For example, a natural
gas price swap that converts Henry Hub index to a fixed price would be perfectly
correlated, and 100% effective, if the underlying gas was sold at the Henry Hub
index. Any portion of the gains or losses that are considered ineffective under
the SFAS 133 test are recorded immediately as a component of operating revenue
on the statement of operations.
When the Company adopted SFAS 133, two types of hedges were in place. The
first type was a cash flow hedge that sets the price of a certain monthly
quantity of natural gas sold in the Gulf Coast region through September
69
2003. Based on the index price strip, the impact of this hedge on January 1,
2001 was to record a Hedge Loss of $0.1 million and a charge to Other
Comprehensive Income of $4.2 million. Correspondingly, a Hedge Liability for
$4.3 million was established. This instrument was cancelled in the December 2001
with the bankruptcy of the counterparty. No balance related to this hedge
remains in Other Comprehensive Income.
The second type of hedge outstanding at January 1, 2001 was a natural gas
price costless collar agreement. The Company had entered into eight of these
collars for a portion of its production at regional indexes for the months of
February through October 2001. The collars had two components of value:
intrinsic value and time value. Under SFAS 133, both components were valued at
the end of each reporting period. Intrinsic value arises when the index price is
either above the ceiling or below the floor for any period covered by the
collar. If the index is above the ceiling for any month covered by the collar,
the intrinsic value would be the difference between the index and the ceiling
prices multiplied by the notional volume. Similar to the current accounting
treatment, intrinsic value related to the current month would be recorded as a
hedge loss (if the index is above the ceiling) or gain (if the index is below
the floor). Starting in 2001 under SFAS 133, any changes in the intrinsic value
component related to future months were recorded in Other Comprehensive Income,
a component of stockholders' equity on the balance sheet, rather than to the
income statement to the extent that the hedge was proven to be effective. These
natural gas price collars were considered to be highly effective with
respect to the intrinsic value calculation since they were tied to the same
indexes at which the Company's natural gas is sold. Also under SFAS 133, the
time value component, a market premium/discount, was marked-to-market through
the income statement each period. Since these collar arrangements were executed
on the last business day of 2000, the net premium value at adoption on January
1, 2001 was zero.
As of December 31, 2001, the Company had a series of nine natural gas price
collar arrangements in place. In accordance with the latest guidance from the
FASB's Derivative Implementation Group, the Company determines the effectiveness
of the combined intrinsic and time values, and the effective portion of each
will be recorded as a component of Other Comprehensive Income. Any ineffective
portion will be recorded as a gain or loss in the current period. As of December
31, 2001, the Company had recorded $1.4 million of Other Comprehensive Income
($0.8 million net of deferred taxes), a $0.1 million Unrealized Hedge Gain and a
$1.5 million Hedge Asset.
Other Comprehensive Income
Comprehensive income includes net income and certain items recorded
directly to stockholders' equity and classified as Other Comprehensive Income.
The Company recorded Other Comprehensive Income for the first time in January of
2001. Following the adoption of SFAS 133, the Company recorded an after-tax
credit to Other Comprehensive Income of $0.8 million in 2001 related to the
change in fair value of certain derivative financial instruments that has
qualified for cash flow hedge accounting.
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. The Company had no sales to any customer
that exceeded 10% of total gross revenues in 2001, 2000 or 1999.
70
12. Oil and Gas Property Transactions
In September and December 1999, the Company purchased oil and gas producing
properties in the Moxa Arch of the Green River Basin in southwest Wyoming for
$8.9 and $8.5 million, respectively. The assets included approximately 16 Bcfe
of proved reserves, approximately 43,000 undeveloped net acres, and 27 wells
producing a net 3.8 Mmcfe per day at the time of the acquisition.
Also in September 1999, the Company sold non-strategic oil and gas
properties located in Pennsylvania and West Virginia to EnerVest for
approximately $46 million. These properties represented 716 wells and 62.2 Bcfe
of proved reserves.
The property transactions in September and December 1999 qualified in part
for Section 1031 exchange treatment for tax purposes. This treatment resulted in
the $8.9 million deferred gain for tax purposes. For tax purposes, the assets
acquired in the exchange were recorded at the value (tax basis) of the assets
given up. The "gain" is deferred and recognized through lower tax depreciation
on these assets and/or by inclusion in the taxable gain/loss calculation should
these assets be subsequently sold.
For financial statement purposes, these transactions were treated as a
purchase and a sale, as opposed to a deferred transaction. The asset sale
resulted in a $4.1 million gain for financial statement purposes, which was
recorded in September 1999.
In the second quarter of 1999, the Company sold certain non-strategic
properties in the Gulf Coast region's Provident City field. These properties
were producing 3.5 Mmcfe per day from eight wells. The sales price was $9.1
million, and the transaction contributed to a gain of approximately $1.0 million
on the Company's second quarter income statement.
13. Other Revenue
Settlement of Contract Dispute
During 2000, the Company reached settlement on a natural gas contract
dispute. As a result, the Company recorded net revenue of approximately $2.3
million to Other Revenue during 2000.
The dispute involved a contract under which the customer was obligated to
take-or-pay a daily base quantity of natural gas over a 10-year period ending in
2003. The customer also agreed to pay a reservation charge in exchange for the
right to purchase optional quantities of natural gas from the Company. The sales
price of the natural gas sold under this contract increased over time.
In 1997, the customer's parent company decided to close the facility that
was purchasing the gas from the Company. The Company agreed to market the gas
that had been committed to the customer and the customer agreed to pay the
difference between the price the Company received and an agreed upon price until
December 31, 1998. Starting on January 1, 1999, the customer again became
responsible for purchasing the gas under the original contract terms. The
Company invoiced the customer for the contractual sales quantities during 1999,
but received no payment. The unpaid balance was included in accounts receivable.
When the Company reached the contract settlement with this customer in the
first quarter of 2000, a portion of the settlement was used to satisfy the
accounts receivable account. The remainder represented a contract buy-out and
was recorded in Other Revenue. No reserve had been recorded for this dispute.
Sales Contract
The Company had a 15-year natural gas sales contract under which
approximately 20% of the Western region natural gas was sold per year to an
independent third-party cogeneration facility. The contract was a standard long-
term, natural gas sales contract under which the Company sold gas to the
facility for a fixed price, which escalated annually. Revenue from the sale of
natural gas is included in "Natural Gas Production" on the Consolidated
Statement of Operations. The contract was due to expire in 2008. The customer
requested to be released from the contract, and during 1999, the Company reached
an agreement with the customer under which the
71
customer bought out the remainder of the contract for a $12 million cash payment
to the Company in exchange for a release from future obligations under the
contract. This transaction was completed in December 1999, and the $12 million
payment was recorded as other revenue. Simultaneously, the Company sold forward
a similar monthly volume of Western region gas through April 2001 at prices
similar to those in the monetized contract.
Section 29 Tax Credits
Other revenue includes income generated from the monetization of the value
of Section 29 tax credits (monetized credits) from most of the Company's
qualifying Appalachian and Rocky Mountains properties. Revenue from these
monetized credits was $2.0 million in 2001, $2.2 million in 2000, and $1.3
million in 1999. These monetized credits are expected to generate future
revenues in 2002 of $2.1 million. 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.
During 1999, an industry tax court ruling concluded that the Section 29
tight sands tax credits (Section 29 credits) would not be available on wells not
certified by the FERC. Because the FERC discontinued the certification process
for qualifying wells in 1992, there was no avenue to obtain the well
certifications. Accordingly, the Company stopped recording revenue on non-
certified wells and established a reserve related to previously recorded amounts
on these wells. This resulted in a $1.2 million reduction to other revenue in
1999. Subsequent to 1999, the certification process has been reinstated by FERC,
and the Company has begun applying for the well certificates and accruing
Section 29 credit revenues related to these wells.
14. Acquisition of Cody Company
Effective in August 2001, the Company acquired the stock of Cody Company,
the parent of Cody Energy LLC ("Cody acquisition") for $231.2 million comprised
of $181.3 million of cash and 1,999,993 shares of common stock valued at $49.9
million. Substantially all of the proved reserves of Cody Company are located in
the onshore Gulf Coast region. The acquisition was accounted for using the
purchase method of accounting. As such, the Company reflected the assets and
liabilities acquired at fair value in the Company's balance sheet effective
August 1, 2001 and the results of operations of Cody Company beginning August 1,
2001. The purchase price totaling approximately $315.6 million was allocated to
specific assets and liabilities based on certain estimates of fair values
resulting in approximately $302.4 million allocated to property and $13.2
million allocated to working capital items. This $315.6 million amount was
inclusive of a $78.0 million non-cash item pertaining to the deferred income
taxes attributable to the differences between the tax basis and the fair value
of the acquired oil and gas properties, and acquisition related fees and costs
of $6.4 million. The purchase price allocation is preliminary and subject to
change as additional information becomes available. Management does not expect
the final purchase price allocation to differ materially from the preliminary
allocation.
The following unaudited pro forma condensed income statement information
has been prepared to give effect to the Cody acquisition as if it had occurred
on January 1, 2000. The information presented is not necessarily indicative of
the results of future operations of the Company.
Year Ended December 31,
(In thousands) 2001 2000
--------------------------------------------------------------------------
Revenues $505,528 $444,793
Net Income $ 54,513 $ 25,997
per share - Basic $ 1.75 $ 0.90
per share - Diluted $ 1.73 $ 0.89
The results of operations for Cody Company are consolidated with Cabot Oil & Gas
Corporation as of August 1, 2001.
15. Earnings per Common Share
72
Full year basic earnings per share for the Company were $1.56, $1.07, and
$0.21 in 2001, 2000, and 1999, respectively, and were based on the weighted
average shares outstanding of 30,275,906 in 2001, 27,383,848 in 2000, and
24,726,030 in 1999. Diluted earnings per share for the Company were $1.53,
$1.06, and $0.21 in 2001, 2000, and 1999, respectively. The diluted earnings per
share amounts are based on weighted average shares outstanding plus common stock
equivalents. Common stock equivalents include stock awards and stock options,
and totaled 408,361 in 2001, 281,210 in 2000, and 225,177 in 1999.
The 6% convertible redeemable preferred stock issued May 1994 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 net income in the computation of earnings per share for
1999. No preferred stock was outstanding at the end of 2000 or 2001. See Note 10
Capital Stock for further discussion.
73
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,
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, 2001,
2000, and 1999 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 8, 2002, that based on their
investigation and subject to the limitations described in their letter, they
believe the results of those estimates and projections were reasonable in the
aggregate.
No major discovery or other favorable or unfavorable event after December
31, 2001, 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.
Natural Gas
-----------------------------------
December 31,
(Millions of cubic feet) 2001 2000 1999
------------------------------------------------------------------------------------
Proved Reserves
Beginning of Year 959,222 929,602 996,756
Revisions of Prior Estimates (44,266) (14,796) (1,555)
Extensions, Discoveries and Other Additions 99,911 103,600 52,781
Production (69,162) (60,934) (65,502)
Purchases of Reserves in Place 91,290 5,118 26,515
Sales of Reserves in Place (991) (3,368) (79,393)
-----------------------------------
End of Year 1,036,004 959,222 929,602
===================================
Proved Developed Reserves 804,646 754,962 720,670
===================================
Percentage of Reserves Developed 77.7% 78.7% 77.5%
===================================
74
Liquids
----------------------------------
December 31,
(Thousands of barrels) 2001 2000 1999
-----------------------------------------------------------------------------------
Proved Reserves
Beginning of Year 9,914 8,189 7,677
Revisions of Prior Estimates 254 562 128
Extensions, Discoveries and Other Additions 2,257 2,032 1,292
Production (1,996) (988) (963)
Purchases of Reserves in Place 9,255 120 362
Sales of Reserves in Place -- (1) (307)
----------------------------------
End of Year 19,684 9,914 8,189
==================================
Proved Developed Reserves 15,328 8,438 5,546
==================================
Percentage of Reserves Developed 77.9% 85.1% 67.7%
==================================
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) 2001 2000 1999
-------------------------------------------------------------------------------------
Aggregate Capitalized Costs Relating
to Oil and Gas Producing Activities $1,632,101 $1,180,692 $1,088,640
Aggregate Accumulated Depreciation,
Depletion and Amortization $ 651,657 $ 558,463 $ 499,201
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development
Activities
Costs incurred in property acquisition, exploration and development
activities were as follows:
Year Ended December 31,
(In thousands) 2001 2000 1999
-------------------------------------------------------------------------------------
Property Acquisition Costs, Proved /(1)/ $245,079 $ 5,954 $18,395
Property Acquisition Costs, Unproved /(1)/ 21,116 10,869 7,163
Exploration and Extension Well Costs /(2)/ 91,261 40,008 16,117
Development Costs 90,246 59,879 39,239
------------------------------------
Total Costs $447,702 $116,710 $80,914
====================================
___________________________________________________________________________
/(1)/ Excludes the $78.0 million deferred tax gross-up on the Cody
acquisition.
/(2)/ Includes administrative exploration costs of $9,831, $8,442, and
$5,633 for the years ended December 31, 2001, 2000, and 1999,
respectively. These costs are excluded from the Company's calculation
of finding costs.
75
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) 2001 2000 1999
-------------------------------------------------------------------------------------
Operating Revenues $339,064 $214,116 $156,018
Costs and Expenses
Production 58,382 46,721 41,942
Other Operating 22,656 17,249 17,009
Exploration /(1)/ 71,165 19,858 11,490
Depreciation, Depletion and Amortization 89,286 63,200 62,446
------------------------------------
Total Costs and Expenses 241,489 147,028 132,887
------------------------------------
Income Before Income Taxes 97,575 67,088 23,131
Provision for Income Taxes 34,151 23,481 8,096
------------------------------------
Results of Operations $ 63,424 $ 43,607 $ 15,035
====================================
___________________________________________________________________________
/(1)/ Includes administrative exploration costs of $9,831, $8,442, and
$5,633 for the years ended December 31, 2001, 2000, and 1999,
respectively. These costs are excluded from the Company's calculation
of finding costs.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves
The following information has been developed utilizing SFAS 69 procedures
and based on natural gas and crude oil reserve and production volumes estimated
by the Company's engineering staff. It can be used for some comparisons, but
should not be the only method used to evaluate the Company or its performance.
Further, the information in the following table may not represent realistic
assessments of future cash flows, nor should the Standardized Measure of
Discounted Future Net Cash Flows be viewed as representative of the current
value of the Company.
The Company believes that the following factors should be taken into
account when reviewing the following information:
. Future costs and selling prices will probably differ from those required to
be used in these calculations.
. Due to future market conditions and governmental regulations, actual rates
of production in future years may vary significantly from the rate of
production assumed in the calculations.
. Selection of a 10% discount rate is arbitrary and may not be a reasonable
measure of the relative risk that is part of realizing future net oil and
gas revenues.
. Future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by
applying year-end oil and gas prices adjusted for fixed and determinable
escalations to the estimated future production of year-end proved reserves.
The average prices related to proved reserves at December 31, 2001, 2000,
and 1999 for natural gas ($ per Mcf) were $2.65, $9.63, and $2.36, respectively,
and for oil ($ per Bbl) were $18.56, $26.18, and $24.15, 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.
76
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) 2001 /(1)/ 2000 /(1)/ 1999 /(1)/
------------------------------------------------------------------------------------
Future Cash Inflows $ 3,107,668 $ 9,497,181 $ 2,401,349
Future Production Costs (823,988) (1,435,489) (622,025)
Future Development Costs (266,833) (192,893) (164,377)
----------- ----------- -----------
Future Net Cash Flows Before Income Taxes 2,016,847 7,868,799 1,614,947
10% Annual Discount for Estimated
Timing of Cash Flows (1,065,747) (4,332,551) (877,129)
----------- ----------- -----------
Standardized Measure of Discounted Future
Net Cash Flows Before Income Taxes 951,100 3,536,248 737,818
Future Income Tax Expenses,
Net of 10% Annual Discount /(2)/ (185,074) (1,126,416) (150,261)
---------------------------------------
Standardized Measure of Discounted
Future Net Cash Flows $ 766,026 $ 2,409,832 $ 587,557
=======================================
---------------------------------------------------------------------------
/(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 $558,085, $2,642,810, and
$457,256 for the years ended December 31, 2001, 2000 and 1999,
respectively.
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) 2001 2000 1999
- ---------------------------------------------------------------------------------------------
Beginning of Year $ 2,409,832 $ 587,557 $ 594,078
Discoveries and Extensions,
Net of Related Future Costs 100,084 486,236 65,210
Net Changes in Prices and Production Costs /(1)/ (2,545,349) 2,441,921 1,354
Accretion of Discount 353,625 73,782 73,893
Revisions of Previous Quantity
Estimates, Timing and Other (358,134) (81,093) (20,162)
Development Costs Incurred 26,158 28,540 19,586
Sales and Transfers, Net of Production Costs (280,682) (167,395) (114,076)
Net Purchases (Sales) of Reserves in Place 119,149 16,440 (26,916)
Net Change in Income Taxes 941,343 (976,156) (5,410)
------------------------------------
End of Year $ 766,026 $2,409,832 $ 587,557
====================================
---------------------------------------------------------------------------
(1) For 2000, the prices for natural gas used in this calculation were
regional cash price quotes on the last day of the year. These prices
were higher than the Company actually realized in December 2000.
Further, based on market conditions in February 2001, the prices are
not indicative of those that the Company expects to realize
consistently in the future. For 2001, year-end pricing returned to the
range that management considers typical.
77
CABOT OIL & GAS CORPORATION
SELECTED DATA (UNAUDITED)
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
(In thousands, except per share amounts) First Second Third Fourth Total
---------------------------------------------------------------------------------------------
2001
Operating Revenues $154,891 $107,606 $104,226 $ 80,319 $447,042
Impairment of Long-Lived Assets -- -- 1,721 5,131 6,852
Operating Income (Loss) 68,526 26,976 21,601 (21,737) 95,366
Net Income (Loss) 39,062 13,593 10,031 (15,602) 47,084
Basic Earnings per Share $ 1.33 $ 0.46 $ 0.33 $ (0.49) $ 1.56
Diluted Earnings per Share $ 1.32 $ 0.45 $ 0.32 $ (0.49) $ 1.53
2000
Operating Revenues $ 85,120 $ 82,447 $ 86,237 $114,847 $368,651
Impairment of Long-Lived Assets -- 9,143 -- -- 9,143
Operating Income 14,773 420 15,799 33,825 64,817
Net Income 4,494 1,518 6,137 17,072 29,221
Basic Earnings per Share $ 0.18 $ 0.05 $ 0.21 $ 0.59 $ 1.07
Diluted Earnings per Share $ 0.18 $ 0.05 $ 0.21 $ 0.58 $ 1.06
---------------------------------------------------------------------------------------------
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 in connection with the 2001 annual stockholders'
meeting is incorporated by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information under the caption "Executive Compensation" in the
definitive 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 definitive Proxy Statement is incorporated by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
78
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES AND REPORTS ON FORM 8-K
A. INDEX
1. Consolidated Financial Statements
See Index on page 41.
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 amended September 6, 2001.
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).
(b) Amendment No. 2 to the Rights Agreement dated December 8, 2000 (Form
8-K for December 21, 2000).
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).
4.8 Note Purchase Agreement dated as of July 26, 2001 among Cabot Oil & Gas
Corporation and the Purchasers listed therein (Form 8-K for August 30,
2001).
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.
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).
79
Exhibit
Number Description
- --------------------------------------------------------------------------------
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 (incorporated by reference 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 Non-employee Director Stock Option Plan of the Company (Form S-8
dated June 23, 1990).
(a) First Amendment to 1990 Non-employee Director Stock Option Plan
(Post-Effective Amendment No. 2 to Form S-8 dated March 7, 1994).
(b) Second Amendment to 1990 Non-employee Director Stock Option Plan
(Form 10-K for 1995).
10.15 Second Amended and Restated 1994 Long-Term Incentive Plan of the
Company.
10.16 Second 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 as Amended September 1, 2001.
10.20 Trust Agreement dated September 2000 between Harris Trust and Savings
Bank and the Company.
10.21 Lease Agreement between the Company and DNA COG, Ltd. dated April 24,
1998 (Form 10-K for 1998).
10.22 Credit Agreement dated as of December 17, 1998, between the Company and
the banks named therein (Form 10-K for 1998).
10.23 Letter Agreement with Puget Sound Energy Company dated September 21,
1999 (Form 10-K for 1999).
10.24 Agreement and Plan of Merger, dated June 20, 2001, among Cabot Oil & Gas
Corporation, COG Colorado Corporation, Cody Company and the shareholders
of Cody Company (Form 8-K for June 28, 2001).
(a) Amendment to Agreement and Plan of Merger dated as of July 10, 2001
to the Agreement and plan of Merger, dated June 20, 2001, among
Cabot Oil & Gas Corporation, COG Colorado Corporation, Cody Company
and the shareholders of Cody Company (Form 8-K for August 30, 2001).
(b) Closing Agreement dated August 16, 2001 (Form 8-K for August 30,
2001).
10.25 Employment Agreement between the Company and Dan O. Dinges dated August
29, 2001.
21.1 Subsidiaries of Cabot Oil & Gas Corporation.
23.1 Consent of PricewaterhouseCoopers LLP.
23.2 Consent of Miller and Lents, Ltd.
28.1 Miller and Lents, Ltd. Review Letter dated February 8, 2002.
80
B. REPORTS ON FORM 8-K
Item 2: Acquisition or Disposition of Assets filing made on October 30, 2001 as
an amendment to the August 30, 2001 Form 8-K. This amendment includes Item 7.
Financial Statements and Exhibits.
Item 5: Other Events filing made on January 8, 2002 includes Item 7. Press
Release dated December 14, 2001 and titled "Cabot Oil & Gas Announces Natural
Gas Hedges."
Item 5: Other Events filing made on January 28, 2002 includes Item 7. Press
Release dated January 22, 2002 and titled "Cabot Oil & Gas Provides 2001 Capital
Program Update", and Item 7. Press Release dated January 24, 2002 and titled
"Cabot Oil & Gas Announces Full Year and Fourth Quarter Results."
Item 5: Other Events filing made on February 20, 2002 includes Item 7. Press
Release dated February 14, 2002 and titled "Cabot Oil & Gas Finalizes Year-End
Reserves", and Item 7. Press Release dated February 19, 2002 and titled "Cabot
Oil & Gas Chairman & CEO to Retire."
81
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/th/ of February 2002.
CABOT OIL & GAS CORPORATION
By: /s/ Ray R. Seegmiller
------------------------------------
Ray R. Seegmiller
Chairman of the Board and
Chief Exective 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 Chairman of the Board and Chief February 19, 2002
- -------------------------
Ray R. Seegmiller Executive Officer
(Principal Executive Officer)
/s/ Dan O. Dinges President and Chief Operating February 19, 2002
- -------------------------
Dan O. Dinges Officer
/s/ Scott C. Schroeder Vice President, Chief Financial Officer February 19, 2002
- -------------------------
Scott C. Schroeder and Treasurer
(Principal Financial Officer)
/s/ Henry C. Smyth Vice President and Controller February 19, 2002
- -------------------------
Henry C. Smyth (Principal Accounting Officer)
/s/ Robert F. Bailey Director February 19, 2002
- -------------------------
Robert F. Bailey
/s/ Henry O. Boswell Director February 19, 2002
- -------------------------
Henry O. Boswell
/s/ John G. L. Cabot Director February 19, 2002
- -------------------------
John G. L. Cabot
/s/ James G. Floyd Director February 19, 2002
- -------------------------
James G. Floyd
/s/ C. Wayne Nance Director February 19, 2002
- -------------------------
C. Wayne Nance
82
/s/ P. Dexter Peacock Director February 19, 2002
- ---------------------------
P. Dexter Peacock
/s/ Charles P. Siess, Jr. Director February 19, 2002
- ---------------------------
Charles P. Siess, Jr.
/s/ Arthur L. Smith Director February 19, 2002
- ---------------------------
Arthur L. Smith
/s/ William P. Vititoe Director February 19, 2002
- ---------------------------
William P. Vititoe
83