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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, 2002
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
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 [__].
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).
Yes X No ____
---
The aggregate market value of 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, 2003), was approximately
$749,100,000. As of January 31, 2003, there were 32,133,975 shares of Common
Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Stockholders to
be held April 29, 2003 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 17
ITEM 4 Submission of Matters to a Vote of Security Holders 19
Executive Officers of the Registrant 20
PART II
ITEM 5 Market for Registrant's Common Equity and Related Stockholder Matters 21
ITEM 6 Selected Historical Financial Data 21
ITEM 7 Management's Discussion and Analysis of Financial Condition
and Results of Operations 22
ITEM 7A Quantitative and Qualitative Disclosures about Market Risk 36
ITEM 8 Financial Statements and Supplementary Data 41
ITEM 9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 76
PART III
ITEM 10 Directors and Executive Officers of the Registrant 76
ITEM 11 Executive Compensation 76
ITEM 12 Security Ownership of Certain Beneficial Owners and Management
and Equity Compensation Plan Information 76
ITEM 13 Certain Relationships and Related Transactions 77
ITEM 14 Controls and Procedures 77
PART IV
ITEM 15 Exhibits, Financial Statements, Schedules and Reports on Form 8-K 77
---------------------
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," "will" 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 Texas and Louisiana Gulf Coast
.. The Rocky Mountains
.. The Mid-Continent or Anadarko Basin
.. The Eastern area of the United States
Operationally, we have regional offices located in three regions - the Gulf
Coast region, the Western region, which is comprised of the Rocky Mountains and
Mid-Continent areas, and the Eastern region.
In 2002, our natural gas and oil production reached its highest annual
level in our history. We produced 91.1 Bcfe, or 249.7 Mmcfe per day this year.
This is a 12% improvement over 2001 when we produced 81.1 Bcfe, or 222.3 Mmcfe
per day. Of this 12% growth, 8% was associated with the full year impact of
properties acquired from Cody Company in August 2001. The remaining 4% was a
result of drilling during the past two years, primarily in south Louisiana.
Commodity prices were much softer in 2002, however, and despite the increases in
production, revenue and net income levels decreased in 2002 compared to 2001.
Our 2002 realized natural gas price was $3.02 per Mcf, down 31% from 2001 due to
a decline in natural gas prices. Our realized crude oil price was $23.79 per
Bbl, down 4% from 2001 primarily due to the impact of crude oil collars which
reduced our realized price by $1.81 per Bbl.
Net income of $16.1 million or $0.51 per share was under last year's record
of $47.1 million or $1.56 per share. Lower commodity prices were the primary
reason for this year's revenue decline. Prices have recovered somewhat during
the fourth quarter and into early 2003. In order to reduce the risk of price
declines in 2003, we have collar and swap arrangements in place on 51% of our
anticipated natural gas production and 42% (31% relates to oil range swaps) of
our anticipated oil production as of December 31, 2002.
In 2002, 93% of the wells that we drilled were successful. Drilling was
successful on 67% of our 2002 exploration wells, as we tested new ideas and
worked on building a foundation for the future. This was an improvement over an
87% overall success rate in 2001 and a 40% success rate on exploration wells.
Our 2002 capital and exploration spending was $126.3 million, including $19.6
million for seismic data and lease acquisition. This spending will support our
exploration and development drilling programs in 2003 and beyond. As we entered
2002, energy commodity prices softened from the unusually high level enjoyed in
2001. We concentrated our 2002 capital spending program on projects balancing
acceptable risk with the strongest economics. As in the past, we will use a
portion of the cash flow from our long-lived Eastern 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, through accretive reserve and production growth and higher rates of
return on equity. This strategy remains in place for 2003. In 2003, we plan to
spend $153.9 million and drill 180 gross wells.
Our proved reserves totaled approximately 1.2 Tcfe at December 31, 2002, of
which 91% was natural gas. This reserve level rose just slightly above the prior
year end in a year when production rose 12% while the level of total program
spending was 76% below 2001. Highlighting the success of the 2002 program was
Redfish Bay in the Gulf Coast and Double Eagle Field in Colorado.
3
The following table presents certain information as of December 31, 2002.
West
--------------------------------------
Gulf Rocky Mid- Total
Coast Mountains Continent West East Total
----- --------- --------- ---- ---- -----
Proved Reserves at Year End (Bcfe)
Developed 200.0 184.4 171.4 355.8 343.2 899.0
Undeveloped 85.4 48.6 26.1 74.7 112.2 272.3
------- ------- ------- ------- ------- ---------
Total 285.4 233.0 197.5 430.5 455.4 1,171.3
Average Daily Production (Mmcfe per day) 127.0 42.7 30.3 73.0 49.7 249.7
Reserve Life Index (in years)/(1)/ 6.2 15.0 17.8 16.2 25.1 12.9
Gross Wells 900 491 603 1,094 2,401 4,395
Net Wells/(2)/ 549.0 221.1 422.3 643.4 2,215.6 3,408.0
Percent Wells Operated 79.3% 51.3% 78.6% 66.4% 96.6% 85.5%
Net Acreage
Developed 100,861 85,332 182,340 267,672 741,652 1,110,185
Undeveloped 53,181 370,470 3,058 373,528 214,351 641,060
------- ------- ------- ------- ------- ---------
Total 154,042 455,802 185,398 641,200 956,003 1,751,245
- --------------------------------------------------------------------------------
/(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 the Gulf Coast
region are concentrated in south Louisiana and south Texas. A regional office in
Houston manages operations. Principal producing intervals are in the Frio,
Wilcox and Vicksburg formations in Texas and the Miocene and Frio age formations
in Louisiana at depths ranging from 3,000 to 20,500 feet. Capital and
exploration expenditures were $69.0 million for 2002 or 55% of our total 2002
capital and exploration expenditures, and $352.1 million for 2001. 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 (See "Limited Partnership" on page 29 for discussion
related to the Cody acquisition). 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 127.0 Mmcfe per day in 2002. Of this production rate, 35.8 Mmcfe per day was
associated with the Cody properties and the remaining primarily represents
production growth from our drilling activity. For 2003, we have budgeted $88.1
million (57% of our total 2003 budget) for capital and exploration expenditures
in the region. Our 2003 Gulf Coast drilling program will emphasize impact
exploration opportunities both on and off shore augmented by development
activity in our focus areas of south Texas and coastal Louisiana, including
properties acquired in the Cody acquisition.
We had 900 wells (549.0 net) in the Gulf Coast region as of December 31,
2002, of which 714 wells are operated by us. Average net daily production in
2002 was 127.0 Mmcfe, up from 97.9 Mmcfe in 2001 due both to drilling success in
south Louisiana and to the Cody acquisition. At December 31, 2002, we had 285.4
Bcfe of proved reserves (69% natural gas) in the Gulf Coast region, which
represented 24% of our total proved reserves.
In 2002, we drilled 24 wells (12 net) in the Gulf Coast region, of which 16
wells (8 net) were development wells. The south Louisiana Etouffee prospect and
our 2001 discoveries in the Augen field in south 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 43 wells in 2003.
At December 31, 2002, we had 154,042 net acres in the region, including
100,861 net developed, and we had identified 115 proved undeveloped drilling
locations.
4
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 60% 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 40% 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 currently produce and market approximately 7,900 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, 2002, we had 430.5 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 of
Wyoming and Paradox Basin in Colorado. 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 233.0 Bcfe at December 31, 2002. Capital and exploration
expenditures were $25.9 million for 2002, or 21% of our total 2002 capital and
exploration expenditures, and $42.9 million for 2001. In addition to drilling
activity, approximately $1.9 million was expended in 2002 for lease acquisition
and seismic data to provide exploration and development opportunities in the
future. For 2003, we have budgeted $20.0 million (13% of our total 2003 budget)
for capital and exploration expenditures in the area. The 2003 drilling program
consists of several new exploration plays complemented by development drilling.
We had 491 wells (221.1 net) in the Rocky Mountains area as of December 31,
2002, of which 252 wells are operated by us. Principal producing intervals in
the Rocky Mountains area are in the Almond, Frontier, Dakota, and Honaker Trail
formations at depths ranging from 9,000 to 13,500 feet. Average net daily
production in the Rocky Mountains during 2002 was 42.7 Mmcfe.
In 2002, we drilled 26 wells (10 net) in the Rocky Mountains, of which 25
wells (9 net) were development and extension wells. In 2003, we plan to drill 31
wells.
At December 31, 2002, we had 455,802 net acres in the area, including
85,332 net developed acres, and we had identified 75 proved undeveloped drilling
locations.
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 $8.2 million for 2002, or 6% of our total 2002
capital and exploration expenditures, and $11.5 million for 2001. For 2003, we
have budgeted $11.5 million (7% of our total 2003 budget) for capital and
exploration expenditures in the area.
As of December 31, 2002, we had 603 wells (422.3 net) in the Mid-Continent
area, of which 474 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 2002
was 30.3 Mmcfe. At December 31, 2002, we had 197.5 Bcfe of proved reserves (97%
natural gas) in the Mid-Continent area, 17% of our total proved reserves.
In 2002, we drilled 14 wells (12 net) in the Mid-Continent, all of which
were development and extension wells. In 2003, we plan to drill 24 wells.
5
At December 31, 2002, we had 185,398 net acres in the area, including
182,340 net developed acres, and we had identified 58 proved undeveloped
drilling locations.
Western Region Marketing
Our principal markets for Western region natural gas are in the
northwestern and Midwestern 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.
We currently also produce and market approximately 450 barrels of crude
oil/condensate per day in the Western region at market responsive prices.
EASTERN REGION
Our Eastern 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 $22.1
million for 2002, or 17% of our total 2002 capital spending, and $44.1 million
for 2001. For 2003, we have budgeted $27.7 million (18% of our total 2003
budget) for capital and exploration expenditures in the region.
At December 31, 2002, we had 2,401 wells (2,215.6 net), of which 2,319
wells are operated by us. There are multiple producing intervals that include
the Devonian Shale, Oriskany, Berea, Weir, and Big Lime formations at depths
primarily ranging from 1,500 to 9,000 feet. Average net daily production in 2002
was 49.7 Mmcfe. While natural gas production volumes from Eastern reservoirs are
relatively low on a per-well basis compared to other areas of the United States,
the productive life of Eastern reserves is relatively long. At December 31,
2002, we had 455.4 Bcfe of proved reserves (substantially all natural gas) in
the Eastern region, constituting 39% of our total proved reserves. This region
is managed from our office in Charleston, West Virginia.
In 2002, we drilled 44 wells (39 net) in the Eastern region, of which 43
wells (38 net) were development wells. In 2003, we plan to drill 82 wells.
At December 31, 2002, we had 956,003 net acres in the region, including
741,652 net developed, and we had identified 316 proved undeveloped drilling
locations.
Ancillary to our exploration, development 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 2002. 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.
6
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 Eastern 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.
Eastern Region Marketing
The principal markets for our Eastern region natural gas are in the
northeastern United States. Cabot Oil & Gas Marketing purchases our natural gas
production in the Eastern 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 Eastern 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 Eastern 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.
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 2002 we primarily employed natural
gas and oil price swap and 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 or crude oil for
the period is greater or less than the fixed price established for that period
when the swap is put in place. The 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.
We had certain costless collar arrangements on half of our natural gas
production for the months of February through October 2001. These financial
instruments resulted in a $0.50 per Mcf increase to our realized natural gas
price. In 2002, we employed both price swaps and collars for 57% of our natural
gas and 43% of our crude oil as part of our risk reduction strategy. These
financial instruments resulted in a $0.01 per Mcf decline to our realized
natural gas price and a $1.81 per Bbl decline to our realized crude oil price.
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.
7
RESERVES
Current Reserves
The following table presents our estimated proved reserves at December 31,
2002.
Natural Gas (Mmcf) Liquids/(1)/ (Mbbl) Total/(2)/ (Mmcfe)
- ----------------------------------------------------------------------------------------------------------------------
Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total
- ----------------------------------------------------------------------------------------------------------------------
Gulf Coast 137,531 58,203 195,734 10,415 4,541 14,956 200,022 85,445 285,467
Rocky Mountains 175,532 45,522 221,054 1,481 511 1,992 184,415 48,588 233,003
Mid-Continent 165,808 25,619 191,427 934 74 1,008 171,413 26,064 197,477
East 340,541 112,203 452,744 437 -- 437 343,166 112,203 455,369
------------------------------------------------------------------------------------------------------
Total 819,412 241,547 1,060,959 13,267 5,126 18,393 899,016 272,300 1,171,316
======================================================================================================
- --------------------------------------------------------------------------------
/(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 2002.
There are a number of uncertainties inherent in estimating quantities of
proved reserves, including many 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.
8
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, 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
------------------------------------------------------
Revision of Prior Estimates 14,405 1,871 25,631
Extensions, Discoveries and
Other Additions 64,945 851 70,053
Production (73,670) (2,909) (91,126)
Purchases of Reserves in Place 26,262 261 27,828
Sales of Reserves in Place (6,987) (1,365) (15,179)
------------------------------------------------------
December 31, 2002 1,060,959 18,393 1,171,316
======================================================
Proved Developed Reserves
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
December 31, 2002 819,412 13,267 899,016
- --------------------------------------------------------------------------------
/(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.
9
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,
2002 2001 2000
---------------------------------------------------------------------------
Net Wellhead Sales Volume
Natural Gas (Bcf)
Gulf Coast 30.4 25.6 14.1
West 25.3 26.2 29.0
East 18.0 17.4 17.8
Crude/Condensate/Ngl (Mbbl)
Gulf Coast 2,655 1,694 669
West 221 267 289
East 33 35 32
Produced Natural Gas Sales Price ($/Mcf)/(1)/
Gulf Coast $ 3.34 $ 4.44 $ 3.79
West 2.39 3.88 2.86
East 3.38 4.96 3.24
Weighted Average 3.02 4.36 3.19
Crude/Condensate Sales Price ($/Bbl)/(1)/ $23.79 $ 24.91 $26.81
Production Costs ($/Mcfe)/(2)/ $ 0.70 $ 0.72 $ 0.70
---------------------------------------------------------------------------
/(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.
10
Acreage
The following tables summarize our gross and net developed and undeveloped
leasehold and mineral acreage at December 31, 2002. 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
Arkansas 1,981 426 -- -- 1,981 426
Colorado 14,263 13,359 210,041 107,566 224,304 120,925
Kansas 29,067 27,745 -- -- 29,067 27,745
Kentucky 2,266 901 -- -- 2,266 901
Louisiana 51,281 41,428 30,152 20,547 81,433 61,975
Michigan 544 157 -- -- 544 157
Montana 397 210 35,609 27,791 36,006 28,001
New York 2,956 1,117 400 151 3,356 1,268
New Mexico 160 36 -- -- 160 36
North Dakota -- -- 870 96 870 96
Ohio 6,228 2,387 1,624 431 7,852 2,818
Oklahoma 162,942 113,304 2,784 2,528 165,726 115,832
Pennsylvania 131,975 81,852 19,741 17,650 151,716 99,502
Texas 149,273 85,852 80,697 32,762 229,970 118,614
Utah 1,740 529 169,425 101,387 171,165 101,916
Virginia 22,195 20,072 8,226 5,606 30,421 25,678
West Virginia 572,220 538,170 178,377 138,616 750,597 676,786
Wyoming 142,230 71,234 216,105 132,988 358,335 204,222
---------------------------------------------------------------------------
Total 1,291,718 998,779 954,051 588,119 2,245,769 1,586,898
===========================================================================
Mineral Fee Acreage
Developed Undeveloped Total
------------------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
------------------------------------------------------------------------------------------------
State
Colorado -- -- 2,899 567 2,899 567
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 61,746 52,941 194,499 164,347
===========================================================================
Aggregate Total 1,424,471 1,110,185 1,015,797 641,060 2,440,268 1,751,245
===========================================================================
11
Total Net Acreage by Region of Operation
Developed Undeveloped Total
-------------------------------------------------------------------------------------
Gulf Coast 100,861 53,181 154,042
West 267,672 373,528 641,200
East 741,652 214,351 956,003
-------------------------------------------------------------------------------------
Total 1,110,185 641,060 1,751,245
=========================================================
Well Summary
The following table presents our ownership at December 31, 2002, 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 Eastern 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 had a reversionary interest as in the case of certain
Section 29 tight sands and Devonian shale wells repurchased by us effective
December 31, 2002.
Natural Gas Oil Total /(1)/
Gross Net Gross Net Gross Net
-------------------------------------------------------------------------------------
Gulf Coast 579 361.7 321 187.3 900 549.0
West 1,039 609.9 55 33.5 1,094 643.4
East 2,377 2,204.5 24 11.1 2,401 2,215.6
-------------------------------------------------------------------------------------
Total 3,995 3,176.1 400 231.9 4,395 3,408.0
================================================================
--------------------------------------------------------------------------
/(1)/ Total does not include service wells of 99.0 (58.5 net).
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,
2002 2001 2000
-------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
-------------------------------------------------------------------------------------
Gulf Coast
Development Wells
Successful 15 7.3 18 7.0 14 6.3
Dry 1 0.3 1 0.6 3 1.7
Extension Wells
Successful -- -- 1 0.1 -- --
Dry 1 0.3 -- -- -- --
Exploratory Wells
Successful 5 3.3 8 4.6 4 2.2
Dry 2 0.9 7 2.4 2 1.0
--------------------------------------------------------
Total 24 12.1 35 14.7 23 11.2
========================================================
Wells Acquired /(1)/ -- 2.4 600 334.0 1 0.6
Wells in Progress at End
of Period 5 2.5 5 3.6 2 1.1
12
Year Ended December 31,
2002 2001 2000
-------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
-------------------------------------------------------------------------------------
West
Development Wells
Successful 38 19.8 43 24.9 33 22.7
Dry 1 0.8 3 1.5 3 1.0
Extension Wells
Successful -- -- 5 2.4 7 3.9
Dry -- -- -- -- -- --
Exploratory Wells
Successful -- -- 1 0.8 1 0.3
Dry 1 0.7 4 3.0 1 0.5
--------------------------------------------------------
Total 40 21.3 56 32.6 45 28.4
========================================================
Wells Acquired /(1)/ -- -- 10 0.1 1 0.4
Wells in Progress at End
of Period 1 0.2 -- -- 4 2.7
Year Ended December 31,
2002 2001 2000
-------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
-------------------------------------------------------------------------------------
East
Development Wells
Successful 41 37.2 102 93.0 47 41.5
Dry 2 0.6 5 4.0 5 4.2
Extension Wells
Successful -- -- -- -- -- --
Dry -- -- -- -- -- --
Exploratory Wells
Successful 1 1.0 3 3.0 5 3.8
Dry -- -- 7 6.3 4 2.5
--------------------------------------------------------
Total 44 38.8 117 106.3 61 52.0
========================================================
Wells Acquired /(1)/ -- -- 19 19.0 -- --
Wells in Progress at End
of Period -- -- -- -- 3 3.0
--------------------------------------------------------------------------
/(1)/ Includes the acquisition of net interest in certain wells in which
we already held an ownership interest. Does not include certain
interest in Section 29 tight sands and Devonian shale wells
repurchased by us effective December 31, 2002.
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 Eastern region who do not have similar systems or facilities in place. We
also believe that our competitive position in the Eastern 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.
13
OTHER BUSINESS MATTERS
Major Customer
In 2002, approximately 14% of our total sales were made to one customer.
This customer operates certain properties in which we have interests in the Gulf
Coast and purchases all of the production from these wells. This customer is
currently reselling the natural gas and oil to third parties with whom we would
deal directly if the customer either ceased to exist or stopped buying our
portion of the production. In 2001 and 2000 we had no sales to any customer that
exceeded 10% of our total gross revenues.
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. This 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 that 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 we produce and the manner in which our production is
transported and marketed. Under the Natural Gas Act of 1938, the FERC regulates
the interstate sale for resale of natural gas and the transportation of natural
gas in interstate commerce, although facilities used in the production or
gathering of natural gas in interstate commerce are exempted from FERC
jurisdiction. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act
deregulated natural gas prices for all "first sales" of natural gas, which
includes all sales of our own production. In addition, as part of the broad
industry restructuring initiatives described below, the FERC has granted to all
producers such as us a "blanket certificate of public convenience and necessity"
authorizing the sale of gas for resale without further FERC approvals. 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.
Our natural gas sales prices nevertheless continue to be affected by
intrastate and interstate gas transportation regulation, because the prices we
receive for our production are affected by the cost of transporting the gas to
the consuming market. Through a series of comprehensive rulemakings, beginning
with Order No. 436 in 1985 and continuing through Order No. 636 in 1992 and
Order No. 637 in 2000, the FERC has 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. 436 generally required
interstate pipelines to become "open access" transporters of natural gas,
thereby requiring pipelines to transport gas supplies owned by others in
competition with their own supplies. Order No. 636 further required that
interstate pipelines cease making "bundled" sales of natural gas, i.e., gas
sales at a single price that includes both the cost of the gas and the cost of
its delivery, and further required that pipelines "unbundle" their gathering and
14
transmission services. Order No. 637 has implemented additional requirements to
increase the transparency of pricing for pipeline services, including requiring
pipelines to implement imbalance management services for shippers; restricting
the ability of pipelines to impose penalties for imbalances, overruns, and
non-compliance with operational flow orders; and implementing a number of new
reporting requirements. The FERC has also developed rules governing the
relationship of the pipelines with their marketing affiliates, and implemented
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.
In light of these statutory and regulatory changes, most pipelines have
divested their gas sales functions to marketing affiliates, which operate
separately from the transporter and in direct competition with all other
merchants, and most pipelines have also implemented the large-scale divestiture
of their gas gathering facilities to affiliated or non-affiliated companies.
Interstate pipelines thus now generally provide unbundled, open and
nondiscriminatory transportation and transportation-related services to
producers, gas marketing companies, local distribution companies, industrial end
users and other customers seeking such services. 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.
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. In 2002, Congress enacted the Pipeline Safety
Improvement Act of 2002, which contains a number of provisions intended to
increase pipeline operating safety. Among other provisions, this act will
require that pipeline operators implement a pipeline integrity management
program that must at a minimum include an inspection of pipeline facilities
within the next ten years, and at least every seven years thereafter.
We cannot 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 recent trend toward
federal deregulation (or "lighter-handed" regulation) 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, cannot be predicted.
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 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
15
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 substantially comply with the Clean Water Act and
related federal and state regulations.
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, 2002, Cabot Oil & Gas had 347 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. In January 2003, we released 10 employees and
will record associated expenses of $0.6 million during the first quarter of
2003.
16
Website Access to Company Reports
We make available free of charge through our website, www.cabotog.com, our
annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on
form 8-K, and all amendments to those reports as soon as reasonably practicable
after such material is electronically filed with the Securities and Exchange
Commission. Information on our website is not a part of this report.
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 the East. At December 31,
2002, we owned or operated approximately 3,200 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.
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.
17
We received documents with the notification from the EPA indicating 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 entered into a consent decree, which
will require the CNC to pay approximately $27 million toward Site clean up in
return for a release from liability. On January 30, 2002, we placed $1,283,283
in an escrow account, representing our volumetric share of the CNC/United States
settlement. This cash settlement, once released from escrow and paid to the
federal government after the consent decree is entered by the court, 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. Most of the CNC, including us, have purchased insurance
designed to protect us from these liabilities not covered by the consent decree.
The State of California, a third party, has asserted a claim against the
CNC and other companies alleged to have waste at Casmalia for costs the State
incurred and will incur at the site. The CNC has presented the claim to its
insurer. The ultimate disposition of this claim is unknown. However, given the
size of the State's claim, and the number of parties allegedly responsible, the
Company's share of this claim is expected to be immaterial.
We have established a reserve we believe to be adequate to provide for this
environmental liability and related legal costs.
Wyoming Royalty Litigation
In June 2000, we were sued by two overriding royalty owners 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
improperly deducted 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 January 2002, thirteen overriding
royalty owners sued us in Wyoming federal district 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.
Although we believe that a number of the our defenses are supported by
Wyoming case law, a recent letter decision handed down by a state district court
in another case does not support certain of the defenses. The decision has not
been reduced to a formal order and it is not known what effect, if any, the
decision will have on the pending cases.
In our federal case, the judge recently agreed to certify two questions of
state law for decision by the Wyoming State Supreme Court. The Wyoming State
Supreme Court has agreed to decide both questions, and these decisions should
dispose of important issues in these cases. The federal judge refused, however,
to certify one question on check stub reporting that had been decided adversely
to the Company's position in the state district court letter decision. After the
federal judge's refusal to certify this issue, the plaintiffs reduced the
damages they were claiming. The plaintiffs in the federal case currently claim
$5.5 million in damages for the deductions and related issues and $12.9 million
in damages for violation of the check stub reporting statute. In the opinion of
our outside counsel, Brown, Drew & Massey, LLP the likelihood of the plaintiffs
recovering the stated damages for violation of the check stub reporting statute
is remote.
We are vigorously defending both cases. We have a reserve that we believe
is adequate to provide for these potential liabilities based on our estimate of
the probable outcome of these matters. Should circumstances change, the
potential impact could materially affect quarterly or annual results of
operations and cash flows. However, management does not believe it would
materially impact our financial position.
West Virginia Royalty Litigation
In December 2001, we were sued by two royalty owners 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 have
failed to properly inform the plaintiffs and other similarly situated persons of
deductions taken from the royalty. The plaintiffs have also claimed that they
are entitled to a 1/8/th/ royalty share of the gas sales contract settlement
that we reached with Columbia in the 1995 Columbia bankruptcy proceeding.
We had removed the lawsuit to federal court, however in February 2003 we
received an order remanding the lawsuit back to state court. Discovery and
pleadings necessary to place the
18
class certification issue before the court have been ongoing. No trial or
dispositive motions dates have been set and limited factual discovery is
ongoing.
The investigation into this claim continues and it is in the discovery
phase. We are vigorously defending the case. We have a reserve that we believe
is adequate to provide for these potential liabilities based on its estimate of
the probable outcome of this matter. Should circumstances change, the potential
impact may materially affect quarterly or annual results of operations and cash
flows. However, management does not believe it would materially impact our
financial position.
Texas Title Litigation
On January 6, 2003, we were served with Plaintiffs' Second Amended Original
Petition in Romeo Longoria, et al. v. Exxon Mobil Corporation, et al. in the
79th Judicial District Court of Brooks County, Texas. The plaintiffs allege that
they are the rightful owners of a one-half undivided mineral interest in and to
certain lands in Brooks County, Texas. As Cody Energy, Inc. we acquired certain
leases and wells from Wynn-Crosby 1996, Ltd. in 1997 and 1998 and as Cabot Oil &
Gas Corporation we subsequently acquired a 320 acre lease from Hector and Gloria
Lopez in 2001. The plaintiffs allege that they are entitled to be declared the
rightful owners of an undivided interest in the surface and minerals and all
improvements on the lands on which we acquired these leases. The plaintiffs also
assert claims for trespass to try title, action to remove a cloud on the title,
failure to properly account for royalty, fraud, trespass, conversion, all for
unspecified actual and exemplary damages. There is a trial date of May 19, 2003.
However, the recent addition of the Company as defendant, as well as others, is
expected to lead to a continuance of that trial date. We have not had the
opportunity to conduct discovery in this matter. The Company estimates that
production revenue from this field since its predecessor, Cody Energy, acquired
title and since the Company acquired its lease is approximately $12 million. The
carrying value of this property is approximately $35 million.
Although the investigation into this claim has just begun, we intend to
vigorously defend the case. Management cannot currently determine the likelihood
or range of any potential outcome.
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, 2002 to December 31, 2002.
19
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information about our executive officers
as of February 15, 2003, 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
-----------------------------------------------------------------------------------------------------
Dan O. Dinges 49 Chairman of the Board, Chief Executive Officer
and President 2001
Michael B. Walen 54 Senior Vice President, Exploration and Production 1998
J. Scott Arnold 49 Vice President, Land and Associate General Counsel 1998
R. Scott Butler 48 Vice President, Regional Manager, Western Region 2001
Robert G. Drake 55 Vice President, Information Services and
Operational Accounting 1998
Abraham D. Garza 56 Vice President, Human Resources 1998
Jeffrey W. Hutton 47 Vice President, Marketing 1995
Lisa A. Machesney 47 Vice President, Managing Counsel and
Corporate Secretary 1995
A. F. (Tony) Pelletier 50 Vice President, Regional Manager, Gulf Coast Region 2001
Scott C. Schroeder 40 Vice President and Chief Financial Officer 1997
Henry C. Smyth 56 Vice President, Controller and Treasurer 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.
He was promoted to his current position of Chairman of the Board, Chief
Executive Officer and President in May 2002. 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.
20
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
------------------------------------------------------
2002
First Quarter $ 24.95 $ 18.78 $ 0.04
Second Quarter 25.82 21.01 0.04
Third Quarter 23.68 18.40 0.04
Fourth Quarter 26.20 20.22 0.04
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
As of January 31, 2003, there were 853 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) 2002 2001 2000 1999 1998
- -------------------------------------------------------------------------------------------------------------
Income Statement Data
Operating Revenues $ 353,756 $ 447,042 $ 368,651 $ 294,037 $ 251,340
Income from Operations 49,088 95,366 64,817 39,498 27,403
Net Income Available to
Common Stockholders 16,103 47,084 29,221 5,117 1,902
Basic Earnings per Share
Available to Common
Stockholders /(1)/ $ 0.51 $ 1.56 $ 1.07 $ 0.21 $ 0.08
Dividends per Common Share $ 0.16 $ 0.16 $ 0.16 $ 0.16 $ 0.16
Balance Sheet Data
Properties and Equipment, Net $ 954,737 $ 981,338 $ 623,174 $ 590,301 $ 629,908
Total Assets 1,054,871 1,069,031 735,634 659,480 704,160
Long-Term Debt 365,000 393,000 253,000 277,000 327,000
Stockholders' Equity 350,657 346,552 242,505 186,496 182,668
- -------------------------------------------------------------------------------
/(1)/ See Earnings per Common Share under Note 15 of the Notes to the
Consolidated Financial Statements.
21
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 31.
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 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. (See the Commodity Price Swaps and Options discussion about
hedging on page 36.) These price collar arrangements boosted 2001 revenue by
$34.6 million, increasing the average realized natural gas price by $0.50 per
Mcf. In 2002, natural gas prices rose throughout the year beginning with a $2.60
per Mcf price in January and ending with a December realized price of $4.17 per
Mcf. This pattern is contrary to the pattern of prices declining throughout the
year as seen in 2001.
The tables below illustrate how natural gas prices have fluctuated over
the course of 2001 and 2002. "Index" represents the Henry Hub index price per
Mmbtu. The "2001" and "2002" price is the natural gas price per Mcf realized by
us and it includes the impact of the natural gas price collar or swap
arrangements:
Natural Gas Prices by Month - 2002
- -------------------------------------------------------------------------------------------------------------------
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
--- --- --- --- --- --- --- --- --- --- --- ---
Index 2.61 2.03 2.39 3.40 3.36 3.37 3.26 2.95 3.27 3.72 4.13 4.13
2002 2.60 2.55 2.44 3.25 2.86 2.86 2.74 2.74 2.83 3.41 3.89 4.17
Natural Gas Prices by Month - 2001
- -------------------------------------------------------------------------------------------------------------------
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 and rose during 2002. The tables below contain the West
Texas Intermediate index price (Index) and our realized per Bbl crude oil prices
by month for 2001 and 2002.
(in $ per Bbl) Crude Oil Prices by Month - 2002
- --------------------------------------------------------------------------------------------------------------------
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
--- --- --- --- --- --- --- --- --- --- --- ---
Index 19.43 20.54 24.15 26.02 26.73 25.34 26.73 28.09 29.53 28.71 25.97 29.33
2002 18.56 20.11 22.93 24.27 24.40 23.92 24.14 24.70 26.03 25.57 24.19 25.79
(in $ per Bbl) Crude Oil Prices by Month - 2001
- --------------------------------------------------------------------------------------------------------------------
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 $0.51 per share, or $16.1 million, for 2002.
This is down from the $1.56 per share, or $47.1 million, reported in 2001. The
weaker price environment coupled with the impact of our hedge arrangements were
the driving factors in this decline. Prices, including the impact of the hedge
arrangements, fell
22
31% for natural gas and 4% for oil. Partially offsetting this negative price
impact, natural gas production was up 7% and crude oil sales volumes were up 50%
from last year. Overall, on a Mcfe basis, our production grew more than 12% over
2001. An 8% production increase was a result of the full year impact of the
acquisition of Cody Company, which was effective August 1, 2001, and the
remaining 4% resulted from our drilling activities.
We drilled 108 gross wells with a success rate of 93% in 2002 compared to
208 gross wells and an 87% success rate in 2001. Total capital expenditures were
$126.3 million in 2002 compared to $453.4 million for 2001, which included
$181.3 million in cash and $49.9 million in common stock paid for Cody Company.
Capital spent in drilling activity decreased $52.5 million from 2001, which
remains our largest capital program to date. In previous years, our capital
spending, excluding major acquisitions, used substantially all of our operating
cash flow. In 2002, our capital and exploration expenditures were under this
level, allowing us the reduce debt by $28.0 million. Our strategy in 2003 is
anticipated to remain consistent with 2002. We believe our operating cash flow
in 2003 will be sufficient to fund our capital and exploration budgeted spending
of $154 million and again provide excess cash flow to reduce debt.
At the end of 2002, our debt-to-total capitalization ratio was 51.0%, an
improvement from 53.1% at the end of 2001. This improvement was primarily the
result of the decrease in debt levels and occurred despite a $13.8 million
reduction in the Other Comprehensive Income portion of equity. 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,
balancing the higher risk higher reward exploration opportunities with an
extensive development program, and from synergistic acquisitions. We plan to
remain disciplined in our capital program while providing for growth potential.
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 31.
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 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. In 2002, commodity prices rose throughout the year, with
December's realized natural gas price up 60% from the January price. A mild
winter and the economic recession may have been contributing factors in the 2001
pricing volatility, while a colder winter and the threat of potential military
activity in the Middle East may have contributed to rising prices in 2002.
The primary sources of cash during 2002 were funds generated from
operations and, to a lesser extent, proceeds from the sale of non-strategic
assets and the sale of stock. Funds were used primarily for exploration and
development expenditures, reductions to the level of borrowing on the revolving
credit facility, and dividend payments.
23
We had a net cash outflow of $3.1 million during 2002. The net cash inflow
from operating activities of $165.1 million was sufficient to fund the $143.4
million of cash used for capital and exploration expenditures and $21.7 million
of the reduction to debt. Cash proceeds from the sales of non-strategic assets
and the sale of stock combined to provide an additional $8.1 million of cash
flow.
(In millions) 2002 2001 2000
-------------------------------------------------------------------------------------------------
Cash Flows Provided by Operating Activities $ 165.1 $250.4 $ 119.0
------------------------------------------
Cash flows provided by operating activities in 2002 were $85.3 million
lower than in 2001. This decrease was the result of lower realized commodity
prices combined with both an increase in accounts receivable and a decrease in
accounts payable. Cash flows provided by operating activities in 2001 were
$131.4 million higher than in 2000. This improvement was 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) 2002 2001 2000
------------------------------------------------------------------------------------------------
Cash Flows Used by Investing Activities $(138.6) $(379.2) $(116.1)
------------------------------------------
Cash flows used by investing activities in 2002 were attributable to
capital and exploration expenditures of $143.3 million, offset by the receipt of
$4.7 million in proceeds received from the sale of non-strategic oil and gas
properties.
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 2001 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.
(In millions) 2002 2001 2000
------------------------------------------------------------------------------------------------
Cash Flows Provided (Used) by Financing Activities $(29.6) $126.9 $ 3.0
------------------------------------------
Cash flows used by financing activities in 2002 included $28 million used
to reduce the year-end debt balance to $365 million from $393 million in 2001
and cash used to pay cash dividends to stockholders.
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.
We have a revolving credit facility with a group of banks, the revolving
term of which runs to October 2006. 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 $155 million, or 62% 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.
24
In the event that the available credit line is adjusted below the
outstanding level of borrowings, we have a period of three months to reduce our
outstanding debt to the adjusted credit line with a requirement to provide
additional borrowing base assets or pay down one-third of the excess during each
of the three months.
Our 2003 interest expense is expected to be approximately $23.6 million,
including interest on the $170 million 7.33% weighted average fixed rate notes
used to partially fund the acquisition of Cody Company.
Capitalization
Our capitalization information is as follows:
As of December 31,
(In millions) 2002 2001 2000
------------------------------------------------------------------------
Long-Term Debt $ 365.0 $ 393.0 $ 253.0
Current Portion of Long-Term Debt -- -- 16.0
---------------------------
Total Debt $ 365.0 $ 393.0 $ 269.0
===========================
Stockholders' Equity
Common Stock (net of Treasury Stock) $ 350.7 $ 346.6 $ 242.5
---------------------------
Total Equity $ 350.7 $ 346.6 $ 242.5
---------------------------
Total Capitalization $ 715.7 $ 739.6 $ 511.5
===========================
Debt to Capitalization 51.0% 53.1% 52.6%
---------------------------
During 2002, dividends were paid on our common stock totaling $5.1
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.
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, 2002.
(In millions) 2002 2001 2000
------------------------------------------------------------------------
Capital Expenditures
Drilling and Facilities $ 67.0 $ 119.5 $ 80.0
Leasehold Acquisitions 4.8 12.9 10.9
Pipeline and Gathering 4.1 3.8 3.2
Other 1.4 1.9 2.6
----------------------------------
77.3 138.1 96.7
----------------------------------
Proved Property Acquisitions 8.8 244.1/(1)/ 6.0
Exploration Expenses 40.2 71.2 19.9
----------------------------------
Total $ 126.3 $ 453.4 $ 122.6
==================================
-------------------------------------------------------------------------
(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.
25
Total capital and exploration expenditures for 2002 decreased $327.1
million compared to 2001. The spending in 2001 included the $231.2 million Cody
acquisition. The remaining $95.9 million of the decrease was due to smaller
drilling and geological and geophysical programs for 2002. In 2002, we drilled
108 gross wells compared to 208 gross wells drilled in 2001 representing a 48%
decline in drilling activity. Also, the 2001 drilling program included a $15.3
million increase in geological and geophysical expenses over 2000, including
costs of obtaining seismic data that supports future drilling programs.
We plan to drill 180 gross wells in 2003 compared with 108 gross wells
drilled in 2002. This 2003 drilling program includes $153.9 million in total
capital and exploration expenditures, up from $126.3 million in 2002. Expected
spending in 2003 includes $88.9 million for drilling and dry hole exposure,
$10.8 million for lease acquisition and $12.9 million in geological and
geophysical expenses. In addition to the drilling and exploration program, other
2003 capital expenditures are planned primarily for production equipment and for
gathering and pipeline infrastructure maintenance and construction. We will
continue to assess the commodity price environment and may increase or decrease
the capital and exploration expenditures accordingly so as to not jeopardize our
economic returns.
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, 2002.
Payments Due by Year
2004 2006 2008 &
(in thousands) Total 2003 to 2005 to 2007 Beyond
-----------------------------------------------------------------------------------------
Long-Term Debt /(1)/ $365,000 $ -- $20,000 $135,000 $210,000
Operating Leases /(2)/ 27,153 5,590 9,224 7,220 5,119
-------- ------ ------- -------- --------
Total Contractual Cash Obligations $392,153 $5,590 $29,224 $142,220 $215,119
---------------------------------------------------------------------------
/1)/ $95 million of the amount shown as scheduled for payment in 2006
represents the December 31, 2002 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". 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 our 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 with the
26
use of financial instruments. Most recently, we have used financial instruments
such as price collar and swap arrangements to reduce the impact of declining
prices on our revenue. Under both arrangements, there is also risk that the
movement of the index prices will result in the Company not being able to
realize the full benefit of a 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. During 2002, we hedged 57% of our natural
gas production with a combination of price swaps and collars. The impact of
these hedges reduced our 2002 realized natural gas price by $0.01 per Mcf. Also
in 2002, 43% of our crude oil production was hedged with a series of price
collars. The impact of these hedges reduced our realized crude oil price by
$1.81 per Bbl in 2002.
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
2002, we drilled nine exploratory wells and three of them were unsuccessful,
adding $6.9 million to exploration expense. Additionally, we abandoned certain
sections of exploration well bores that were not economical, in the amount of
$3.9 million. This 67% success rate for exploratory wells is higher than our
historical rate, 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. For the year-ended December 31, 2002, 2001 and 2000 we had
impairment of long-lived asset expense of $2.7 million, $6.9 million, and $9.1
million, respectively.
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
27
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.
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 the East.
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 Eastern 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 $1.10 per Mmbtu in 2002. In 1995 and 1996, we
completed three transactions to monetize the value of these tax credits,
resulting in revenues of $2.0 million in 2002. The tax credit wells were
repurchased in December 2002 and therefore, no monetization revenue will be
realized in 2003. 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.
28
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, 2002, the calculated ratio for 2002 was 7.9 to 1.0 on both the
Revolving Credit Agreement and the Notes. 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.
Limited Partnership. As part of the Cody acquisition, we acquired a
interest in certain oil and gas properties in the Kurten field, as general
partner of a partnership and as an operator. Our current interest in Kurten is
approximately 25%, including a one percent interest in the partnership. Under
the partnership agreement, we have the right to a reversionary working interest
that would bring our ultimate interest to 50% upon the limited partner reaching
payout. Under the partnership agreement, the limited partner has the sole option
to trigger a liquidation of the partnership. Effective February 13, 2003, the
Kurten partnership commenced liquidation at the limited partner's election. In
connection with the liquidation, an appraisal has been obtained to allocate the
interest in the partnership assets. Based on the receipt of the appraisal in
February 2003, we would not receive the reversionary interest as part of the
liquidation. Due to the impact of the loss of the reversionary interest on
future estimated net cash flows of the Kurten field, the limited partners
decision and our decision to proceed with the liquidation, we performed an
impairment review which resulted in an after-tax charge of approximately $55
million. This impairment charge will be reflected in the first quarter of 2003
as an operating expense but will not impact the Company's cash flows. In
addition, we will record a downward reserve revision of approximately 16 Bcfe
as a result of the loss of the reversionary interest.
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, including
the impact of derivatives, has changed from year-to-year as follows:
2002: decreased 31% from 2001 to $3.02 per Mcf
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
2003 with wide price swings in day-to-day trading on the NYMEX futures market.
Given this continued price volatility, we can not predict 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. For these reasons, we periodically use
derivative instruments to manage some of the price volatility.
While our 2003 plan now includes $153.9 million in capital and
exploration spending, we will periodically assess industry conditions and adjust
our 2003 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 plan on remaining disciplined in our
capital program. 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 31.
Recently Issued Accounting Pronouncements
In June 2001, the FASB approved for issuance SFAS 143, "Accounting for
Asset Retirement Obligations". SFAS 143 establishes accounting requirements for
retirement obligations associated with tangible long-lived assets,
29
including (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 adoption of SFAS 143 resulted in (1)
an increase of total liabilities, because more retirement obligations are
required to be recognized, (2) an increase in the recognized cost of assets,
because the retirement costs are added to the carrying amount of the long-lived
asset and (3) an increase in operating expense, because of the accretion of the
retirement obligation and additional depreciation and depletion. The majority of
the asset retirement obligations recorded by the Company relate to the plugging
and abandonment of oil and gas wells. The Company adopted the statement on
January 1, 2003. The transition adjustment resulting from the adoption of SFAS
143 will be reported as a cumulative effect of a change in accounting principle
in January 2003. The impact on the financial statements of adopting SFAS 143 is
disclosed in Note 12, "Adoption of SFAS 143, Accounting for Asset Retirement
Obligations", to the financial statements.
In August 2001, the FASB also approved SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets". 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, were adopted by the Company in 2002. The adoption of this statement did not
impact the Company's financial position, results of operations, or cash flows.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections".
SFAS 145, which is effective for fiscal years beginning after May 15, 2002,
provides guidance for income statement classification of gains and losses on
extinguishment of debt and accounting for certain lease modifications that have
economic effects that are similar to sale-leaseback transactions. The adoption
of this statement did not impact the Company's financial position, results of
operations, or cash flows.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS 146 nullifies the guidance of
the Emerging Issues Task Force (EITF) Issue No. 94-3, "Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)." SFAS 146 requires that a
liability for a cost that is associated with an exit or disposal activity be
recognized when the liability is incurred. SFAS 146 also establishes that fair
value is the objective for the initial measurement of the liability. The
provisions of SFAS 146 are required for exit or disposal activities that are
initiated after December 31, 2002. The adoption of this statement did not impact
the Company's financial position, results of operations, or cash flows.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure". SFAS 148 amends FASB Statement No.
123, "Accounting for Stock-Based Compensation", to provide alternative methods
of transition for a voluntary change to the fair value based method of
accounting for stock-based employee compensation. In addition, this Statement
amends the disclosure requirements of Statement 123 to require prominent
disclosures in both annual and interim financial statements about the method of
accounting for stock-based employee compensation and the effect of the method
used on the reported results. The provisions of SFAS 148 are effective for
financial statements for fiscal years ending after December 15, 2002. The
adoption of this statement did not impact the Company's financial position,
results of operations, or cash flows. See Note 10, "Capital Stock", to the
financial statements.
30
In January 2003, the FASB issued Financial Interpretation No. 46,
"Consolidation of Variable Interest Entities - an interpretation of ARB No. 51"
(FIN 46 or Interpretation). FIN 46 is an interpretation of Accounting Research
Bulletin 51, "Consolidated Financial Statements", and addresses consolidation by
business enterprises of variable interest entities (VIE's). The primary
objective of the Interpretation is to provide guidance on the identification of,
and financial reporting for, entities over which control is achieved through
means other than voting rights; such entities are known as VIE's. The
Interpretation requires an enterprise to consolidate a VIE if that enterprise
has a variable interest that will absorb a majority of the entity's expected
losses if they occur, receive a majority of the entity's expected residual
returns if they occur, or both. An enterprise shall consider the rights and
obligations conveyed by its variable interests in making this determination.
This guidance applies immediately to variable interest entities created after
January 31, 2003, and to variable interest entities in which an enterprise
obtains an interest after that date. It applies in the first fiscal year or
interim period beginning after June 15, 2003, to variable interest entities in
which an enterprise holds a variable interest that it acquired before February
1, 2003. At this time we have only one entity that could potentially be a VIE.
We are evaluating this potential VIE, in which we have a one percent general
partner interest and that holds an interest in the Kurten field, to determine if
it is a VIE. However, pursuant to the Partnership agreement, the limited partner
has elected to liquidate the Partnership. It is anticipated that this
liquidation will be completed prior to the effective date of the Interpretation.
See "Limited Partnership" on page 29 for discussion related to the Cody
acquisition.
* * *
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," "will" 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.
31
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) 2002 2001 2000
-------------------------------------------------------------------
Operating Revenues $ 353.8 $ 447.0 $ 368.7
Operating Expenses 304.9 351.7 303.8
Operating Income 49.1 95.4 64.8
Interest Expense 25.2 20.8 22.9
Net Income 16.1 47.1 29.2
Earnings Per Share - Basic $ 0.51 $ 1.56 $ 1.07
Earnings Per Share - Diluted $ 0.50 $ 1.53 $ 1.06
Natural Gas Production (Bcf)
Gulf Coast 30.4 25.6 14.1
West 25.3 26.2 29.0
East 18.0 17.4 17.8
-------------------------
Total Company 73.7 69.2 60.9
Produced Natural Gas Sales Price ($/Mcf)
Gulf Coast $ 3.34 $ 4.44 $ 3.79
West 2.39 3.88 2.86
East 3.38 4.96 3.24
Total Company $ 3.02 $ 4.36 $ 3.19
Crude/Condensate
Volume (Mbbl) 2,869 1,908 953
Price ($/Bbl) $ 23.79 $ 24.91 $ 26.81
2002 and 2001 Compared
Net Income and Revenues. During 2002, we reported net income of $16.1
million, or $0.51 per share. Operating income decreased $46.3 million, or 49%,
and operating revenues decreased $93.3 million, or 21%, in 2002. The decrease in
operating revenues was mainly a result of the $80.6 million decline in natural
gas sales due to the 31% decrease in natural gas prices and the $32.0 million
decrease in brokered natural gas sales revenue, which was also a result of lower
prices. Natural gas revenue and our realized price were reduced by $0.6 million
due to hedges in place during 2002. See further discussion in Item 7A. These
decreases were partially offset by an increase in crude oil revenue of $20.0
million due to a 50% increase in the volume of crude oil produced. Operating
income was similarly impacted by these revenue changes.
The average Gulf Coast natural gas production sales price declined
$1.10 per Mcf, or 25%, to $3.34, decreasing operating revenues by approximately
$33.4 million. In the Western region, the average natural gas production sales
price decreased $1.49 per Mcf, or 38%, to $2.39, decreasing operating revenues
by approximately $37.7 million. The average Eastern natural gas production sales
price decreased $1.58 per Mcf, or 32%, to $3.38, decreasing operating revenues
by approximately $28.4 million. The overall weighted average natural gas
production sales price decreased $1.34 per Mcf, or 31%, to $3.02 per Mcf in
2002.
Natural gas production volume in the Gulf Coast region was up 4.8 Bcf,
or 19%, to 30.4 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 0.9 Bcf, or
3%, to 25.3 Bcf due primarily to a 29% decline in drilling activity, offset
slightly by a 7% increase in the success rate. Natural gas production volume in
the Eastern region was up 0.6 Bcf, or 3%, to 18.0 Bcf, as a result increased
drilling activity in the region over the past year. Total natural gas production
was up 4.5 Bcf, or 7%, in 2002.
Crude oil prices fell $1.12 per Bbl, or 4%, to $23.79, resulting in a
decrease to operating revenues of
32
approximately $3.2 million. The volume of crude oil sold in the year rose by 50%
to 2,869 Mbbls, increasing operating revenues by $23.9 million. This production
increase was a result of our 2000 and 2001 drilling success in south Louisiana
(60% of the increase) and the acquisition of Cody Company (40% of the increase).
Brokered natural gas revenue decreased $32.0 million, or 35%, from the
prior year. The sales price of brokered natural gas declined 35%, resulting in a
decrease in revenue of $31.3 million. The volume of natural gas brokered this
year declined by 1%, reducing revenues by $0.7 million. 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. After including the related brokered natural gas costs, we
realized a brokered gas margin of $5.7 million in 2002 compared to a brokered
gas margin of $2.9 million in 2001.
Other operating revenues decreased $0.7 million to $6.4 million. In
2002, we provided for payout liabilities on certain properties not operated by
us and certain estimated potential legal settlements.
Costs and Expenses. Total costs and expenses from operations decreased
$46.8 million, or 13%, from 2001 due primarily to the following:
. Brokered natural gas cost decreased $34.8 million, or 40%, primarily
due to the $34.1 million impact of decreased natural gas costs per Mcf.
Volumes of brokered gas purchases decreased slightly contributing
further to a reduction in the amount of $0.7 million.
. Production and pipeline expense increased $8.8 million, or 21%,
primarily as a result of a full year of costs associated with operating
the Cody Company properties acquired in August 2001. Additionally,
increased insurance costs and increased drilling activity in the Gulf
Coast and Rockies contributed to the rise in expense. On a
units-of-production basis, our company-wide production and pipeline
expense was $0.55 per Mcfe in 2002 versus $0.51 per Mcfe in 2001.
. Exploration expense decreased $31.0 million, or 44%, primarily as a
result of the following:
. An $8.9 million decrease in geological and geophysical expenses
over last year due to the unusually high 2001 acquisition of
seismic data for future evaluation.
. A $21.0 million decrease in dry hole costs. In 2002, we drilled
nine exploratory wells compared to 27 in 2001. Our success rate on
these wells improved from 44% in 2001 to 67% in 2002. The $16.9
million in dry hole cost recognized in 2002 includes expenditures
related to three wells from the 2001 drilling program determined to
be dry in 2002, in the amount of $6.9 million, as well as costs of
abandoning certain sections of exploration well bores that were not
economical, in the amount of $3.9 million.
. A $0.8 million increase for salaries, wages and related benefits
largely attributable to increased staffing in the Gulf Coast region
during 2001 to support that year's expanded drilling program and
assimilating Cody.
. Depreciation, depletion, amortization and impairment of unproved
properties expense increased $17.4 million, or 20%, over 2001. Natural
gas equivalent production increased 12%, increasing DD&A expense by
$11.4 million. The 6% increase in the per unit expense from $1.09 per
Mcfe to $1.16 per Mcfe was a result of increased production in the
higher cost Gulf Coast region (including a full year impact of the
newly acquired Cody properties) and resulted in an $5.6 million
increase to DD&A expense for 2001.
. Impairment of Long-Lived Assets decreased by $4.1 million this year.
This year we recorded impairments on four small fields, three of which
were in the Gulf Coast and one in the Rocky Mountains. For each of
these fields, the capitalized cost exceeded the future undiscounted
cash flows. A pipeline in the Eastern region was written down to fair
market value. Last year, two fields in the Gulf Coast region were
impaired since the cost capitalized exceeded the future undiscounted
cash flows. Also in 2001, one natural gas processing plant in the Rocky
Mountains area was written down to fair market value. In the fourth
quarter of 2001, the Starpath prospect in the Gulf Coast region was
impaired.
. General and administrative expenses increased $2.7 million due to the
costs associated with the retirement of the chief executive officer in
May 2002.
. Taxes other than income decreased $3.6 million as a result of lower
natural gas and oil revenues.
Interest expense increased $4.4 million due to the full year impact of
the incremental debt used to partially fund the Cody acquisition in August 2001.
Interest expense on the credit facility was down slightly due both to lower
33
levels of borrowings and lower interest rates.
Income tax expense was down $19.8 million due to the comparable
decrease in earnings before income tax. Our effective tax rate decreased
slightly in 2002 reflecting a shift of activity between states.
2001 and 2000 Compared
Net Income and Revenues. We reported net income in 2001 of $47.1
million, or $1.56 per share. During 2000, we reported net income of $29.2
million, or $1.07 per share. Operating income increased $30.5 million, or 47%,
and operating revenues increased $78.4 million, or 21%, 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. In 2001 our natural gas
revenue and our realized price were bolstered by the use of collar arrangements
resulting in a $0.50 per Mcf increase to our realized natural gas price. 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.
Other operating revenues decreased $0.7 million to $7.1 million. In
2001, we received a $0.8 million settlement as a result of a lawsuit. In 2000,
we realized miscellaneous net revenue of approximately $2.2 million primarily
from the settlement of a natural gas sales contract.
34
Costs and Expenses. Total costs and expenses from operations increased
$47.9million, or 16%, 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 $5.5 million, or 15%,
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. The 2000 expense includes $0.5 million related to the
closure of the region office in Pittsburgh. 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.
. Exploration expense increased $51.3 million, or 258%, 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 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.
. Impairment of long-lived assets decreased $2.3 million from 2000. In
2001, two fields in the Gulf Coast region were impaired since the cost
capitalized exceeded the future undiscounted cash flows. Also in 2001,
one natural gas processing plant in the Rocky Mountains area was
written down to fair market value. In the fourth quarter of 2001, the
Starpath prospect in the Gulf Coast region was impaired. During 2000,
we recorded a $9.1 million impairment on one field in the Gulf Coast
due to casing collapse in two of the field's wells.
. General and administrative expenses increased $5.4 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 $5.3 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 $11.0 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.
35
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.
Prices continued to decline for the remainder of 2001. From the end of 2001
through half of 2002 oil and gas prices were constant with an increase in prices
during the fourth quarter. 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. 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. Under our Revolving Credit
Agreement, the aggregate level of commodity hedging must not exceed 80% of the
anticipated future production during the period covered by the hedges. We did
not have crude oil swap arrangements covering our production in 2000, 2001, or
2002. During 2002, we fixed the price at an average of $4.44 per Mcf on
quantities totaling 7,870 Bcf, representing 11% of our 2002 natural gas
production. During 2001, we fixed the price at an average of $3.75 per Mcf on
quantities totaling 918 Mmcf, representing approximately 1% of our 2001 natural
gas production. During 2000, we fixed the price at an average of $4.54 per Mcf
on quantities totaling 315 Mmcf, representing less than 1% of our 2000 natural
gas production.
36
As of the years ended December 31, 2002, and 2001, we had no crude oil
swap contracts that qualified as hedges outstanding. We had open natural gas
price swap contracts on our production as follows:
Natural Gas Price Swaps
---------------------------------------
Volume Weighted Unrealized
in Average Loss
Contract Period Mmcf Contract Price (In $ millions)
-----------------------------------------------------------------------------
As of December 31, 2002
-----------------------
Natural Gas Price Swaps on Production in:
-----------------------------------------
First Quarter of 2003 8,333 $ 4.44
Second Quarter of 2003 7,107 4.24
Third Quarter of 2003 7,186 4.24
Fourth Quarter of 2003 7,186 4.24
----- ----
Full Year of 2003 29,812 4.29 $ 15,062
First Quarter of 2004 2,089 $ 4.42
Second Quarter of 2004 2,089 4.42
Third Quarter of 2004 2,112 4.42
Fourth Quarter of 2004 2,112 4.42
----- ----
Full Year of 2004 8,402 4.42 $ 1,753
As of December 31, 2001
-----------------------
None
Natural gas price swaps increased revenue by $0.9 million in 2002 and
reduced revenue by $0.8 million in 2001.
From time to time we enter into crude oil range swaps with
counterparties. These derivatives do not qualify for hedge accounting under SFAS
133 and are recorded at fair value at the balance sheet date. We entered into
two crude oil range swap arrangements as follows:
. A fixed price swap at $28.15 per barrel, unless the NYMEX West Texas
Intermediate monthly average price falls below $21.00 per barrel. If
the NYMEX West Texas Intermediate monthly average price falls below
$21.00 per barrel for any month, the swap is cancelled for that month.
This instrument covers 730 Mbbls of production over the period January
2003 through December 2003.
. A fixed price swap at $27.75 per barrel, unless the NYMEX West Texas
Intermediate monthly average price falls below $21.00 per barrel. If
the NYMEX West Texas Intermediate monthly average price falls below
$21.00 per barrel for any month, the swap is cancelled for that month.
This instrument covers 276 Mbbls of production over the period July
2003 through December 2003.
The crude oil range swaps at December 31, 2002 had a pre-tax unrealized
loss in the amount of $0.7 million, which is reflected in crude oil operating
revenue, and covered approximately 31% of our anticipated crude oil production
during this period. We had no crude oil range swap contracts outstanding during
2001.
In January 2003, we entered into a natural gas swap arrangement to
reduce the price risk on an additional portion of our 2003 production. The swap
arrangement is in place for the months of February through December 2003 with a
fixed price of $5.39 per Mcf. This hedge covers 1,597 Mmcf of our anticipated
natural gas production for the year.
Hedges on Production - Options
In December 2001 and March 2002, we believed that the pricing
environment provided a strategic opportunity to significantly reduce the price
risk on a portion of our 2002 production through the use of a series of collars.
Under the 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 2002 natural gas price hedges include several collar
arrangements based on nine price indexes. The first series of natural gas price
collars were in place for the months of January through April 2002 with a
weighted average price floor of $2.68 per Mcf and a weighted average price
ceiling of $3.53 per Mcf. These hedges covered 16,145 Mmcf, or 22% of our
natural gas production for the
37
year. The second series of natural gas price collars were in place for the
months of May through August 2002 with a weighted average price floor of $2.54
per Mcf and a weighted average price ceiling of $3.17 per Mcf. These hedges
covered 18,284 Mmcf, or 25% of our natural gas production for the year.
All indexes were within the collars during the month of January, all
were below the floor for February through March, and most were above the ceiling
in April through August, resulting in a cash expenditure of $1.4 million for the
year. Overall, the natural gas collar and swap arrangements resulted in a
reduction of $0.01 per Mcf to our average realized natural gas price for 2002.
During 2001, we used several costless collar arrangements to hedge a
portion of our 2001 natural gas production. 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.
Again in August 2002, we believed that the pricing environment provided
a strategic opportunity to significantly reduce the price risk on a portion of
our 2003 production through the use of natural gas price collar arrangements. As
of the years ended December 31, 2002, and 2001, we had open natural gas price
collar contracts on our production as follows:
Natural Gas Price Collars
-----------------------------------------------------
Volume Weighted Unrealized
in Average Loss
Contract Period Mmcf Ceiling / Floor (In $ millions)
-------------------------------------------------------------------------------------------
As of December 31, 2002
-----------------------
Natural Gas Collars on Production in:
-------------------------------------
First Quarter of 2003 2,066 $5.03/$4.36
Second Quarter of 2003 2,089 $5.03/$4.36
Third Quarter of 2003 2,112 $5.03/$4.36
Fourth Quarter of 2003 2,112 $5.03/$4.36
----- -----------
Full Year of 2003 8,379 $5.03/$4.36 $ 2,090
As of December 31, 2001
-----------------------
Natural Gas Costless Collars on Production in:
----------------------------------------------
First Quarter of 2002 12,082 $3.54/$2.68
Second Quarter of 2002 4,027 $3.54/$2.68
------ -----------
Full Year of 2002 16,109 $3.54/$2.68 --
The natural gas price collars open at December 31, 2002, noted above,
included several collar arrangements based on two price indexes at which we sell
a portion of our production. These hedges are in place for the full year of 2003
and cover approximately 11% of our anticipated natural gas production during
this period. We also have crude oil collars open at December 31, 2002. These
hedges are in place for the months of January through June 2003 with a weighted
average price floor of $24.75 and a weighted average price ceiling of $28.86.
These hedges cover approximately 11% of our anticipated crude oil production
during this period. Crude oil collars reduced revenue by $5.2 million during
2002, but had no impact on 2001 results.
Subsequent to year end we entered into a series of natural gas costless
collar and natural gas and crude oil price swap arrangements to significantly
reduce the price risk on a portion of our 2003 and 2004 production. These
arrangements are as follows:
. A natural gas costless collar in place for the months of February
through December 2003 with a weighted average price floor of $4.71 per
Mcf and a weighted average price ceiling of $5.98 per Mcf. This hedge
covers 6,386 Mmcf of our anticipated natural gas production for the
year.
38
. A natural gas costless collar in place for the full year of 2004 with
a weighted average price floor of $4.33 per Mcf and a weighted average
price ceiling of $5.42 per Mcf. This hedge covers 5,041 Mmcf of our
anticipated natural gas production for the year.
. A natural gas costless collar in place for the full year of 2004 with
a weighted average price floor of $4.16 per Mcf and a weighted average
price ceiling of $5.25 per Mcf. This hedge covers 3,346 Mmcf of our
anticipated natural gas production for the year.
. A natural gas costless collar in place for the months of March
through December 2003 with a weighted average price floor of $3.91 per
Mcf and a weighted average price ceiling of $5.08 per Mcf. This hedge
covers 1,371 Mmcf of our anticipated natural gas production for the
year.
. A natural gas price swap in place for the months of March through
December 2003 with a fixed price of $4.46 per Mcf. This hedge covers
1,371 Mmcf of our anticipated natural gas production for the year.
. A fixed price swap at $30.00 per barrel, unless the NYMEX West Texas
Intermediate monthly average price falls below $22.00 per barrel. If
the NYMEX West Texas Intermediate monthly average price falls below
$22.00 per barrel for any month, the swap is cancelled for that month.
This instrument covers 92 Mbbls of production over the period July 2003
through December 2003.
Adoption of SFAS 133
We adopted SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities", 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
were 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.
39
As of December 31, 2001, we had a series of nine natural gas price
collar arrangements outstanding. As of December 31, 2002 we had a series of 16
natural gas price swap arrangements, two natural gas price collar arrangements,
two crude oil price collar arrangements, and two crude oil swap arrangements
outstanding. 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, 2002, we had recorded $18.8
million of Other Comprehensive Income ($11.6 million net of deferred taxes), a
$0.6 million Unrealized Hedge Loss in revenue, a $0.6 million Hedge Asset, and a
$20.0 million Hedge Liability, exclusive of the crude oil range swaps. As of
December 31, 2001, we had recorded $1.4 million of Other Comprehensive Income
($0.8 million net of deferred taxes), a $0.1 million Unrealized Hedge Gain in
revenue and a $1.5 million Hedge Asset.
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. This disclosure is presented in accordance with
SFAS 107, "Disclosures about Fair Value of Financial Instruments" and does not
impact our financial position, results of operations or cash flows.
Long-Term Debt
December 31, 2002 December 31, 2001
Carrying Estimated Carrying Estimated
(In thousands) Amount Fair Value Amount Fair Value
-----------------------------------------------------------------------
Debt
7.19% Notes $ 100,000 $ 113,591 $ 100,000 $ 104,961
7.26% Notes 75,000 84,231 75,000 79,187
7.36% Notes 75,000 86,461 75,000 79,225
7.46% Notes 20,000 23,322 20,000 21,097
Credit Facility 95,000 95,000 123,000 123,000
--------------------------------------------------
$ 365,000 $ 402,605 $ 393,000 $ 407,470
==================================================
40
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
-------------------------------------------------------------------------------------------------------------
Report of Independent Accountants 42
Consolidated Statement of Operations for the Years Ended December 31, 2002, 2001 and 2000 43
Consolidated Balance Sheet at December 31, 2002 and 2001 44
Consolidated Statement of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000 45
Consolidated Statement of Stockholders' Equity for the Years Ended December 31, 2002, 2001 and 2000 46
Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2002, 2001 and 2000 47
Notes to the Consolidated Financial Statements 48
Supplemental Oil and Gas Information (Unaudited) 72
Quarterly Financial Information (Unaudited) 76
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.
Dan O. Dinges
Chairman of the Board, Chief Executive Officer and President
February 21, 2003
41
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,
2002 and 2001, and the results of their operations, their cash flows and their
comprehensive income for each of the three years in the period ended December
31, 2002 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, on January 1, 2001.
PricewaterhouseCoopers LLP
Houston, Texas
February 17, 2003
42
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
Year Ended December 31,
(In thousands, except per share amounts) 2002 2001 2000
-----------------------------------------------------------------------------------------------
OPERATING REVENUES
Natural Gas Production $ 221,101 $ 301,671 $ 194,185
Brokered Natural Gas 58,729 90,710 141,085
Crude Oil and Condensate 67,548 47,544 25,544
Other (Note 13) 6,378 7,117 7,837
----------------------------------------------
353,756 447,042 368,651
OPERATING EXPENSES
Brokered Natural Gas Cost 53,007 87,785 135,700
Direct Operations - Field and Pipeline 50,047 41,217 35,727
Exploration 40,167 71,165 19,858
Depreciation, Depletion and Amortization 96,512 80,619 53,441
Impairment of Unproved Properties 9,348 7,803 4,368
Impairment of Long-Lived Assets 2,720 6,852 9,143
General and Administrative 28,377 25,650 20,421
Bad Debt Expense (Note 3) -- 2,270 2,096
Taxes Other Than Income 24,734 28,341 23,041
----------------------------------------------
304,912 351,702 303,795
Gain (Loss) on Sale of Assets 244 26 (39)
----------------------------------------------
INCOME FROM OPERATIONS 49,088 95,366 64,817
Interest Expense and Other 25,311 20,817 22,878
----------------------------------------------
Income Before Income Tax Expense 23,777 74,549 41,939
Income Tax Expense 7,674 27,465 16,467
----------------------------------------------
NET INCOME 16,103 47,084 25,472
Preferred Stock Dividend (Note 10) -- -- (3,749)
----------------------------------------------
Net Income Available to
Common Stockholders $ 16,103 $ 47,084 $ 29,221
==============================================
Basic Earnings per Share Available
to Common Stockholders $ 0.51 $ 1.56 $ 1.07
Diluted Earnings per Share Available
to Common Stockholders $ 0.50 $ 1.53 $ 1.06
Average Common Shares Outstanding 31,737 30,276 27,384
The accompanying notes are an integral part of these consolidated
financial statements.
43
CABOT OIL & GAS CORPORATION
CONSOLIDATED BALANCE SHEET
December 31,
(In thousands, except share amounts) 2002 2001
-------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 2,561 $ 5,706
Accounts Receivable 70,028 50,711
Inventories 15,252 17,560
Other 5,280 11,010
----------------------------
Total Current Assets 93,121 84,987
PROPERTIES AND EQUIPMENT (Successful Efforts Method) 954,737 981,338
OTHER ASSETS 7,013 2,706
----------------------------
$ 1,054,871 $ 1,069,031
============================
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable $ 73,578 $ 79,575
Accrued Liabilities 49,446 30,665
----------------------------
Total Current Liabilities 123,024 110,240
LONG-TERM DEBT 365,000 393,000
DEFERRED INCOME TAXES 200,207 200,859
OTHER LIABILITIES 15,983 18,380
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 2002 and 2001 (Note 10) -- --
Common Stock
Authorized - 80,000,000 Shares of $0.10 Par Value
Issued and Outstanding -
32,133,118 Shares in 2002 and
31,905,097 Shares in 2001 3,213 3,191
Additional Paid-in Capital 353,093 346,260
Retained Earnings 11,674 650
Accumulated Comprehensive (Loss) Income (12,939) 835
Less Treasury Stock, at Cost
302,600 Shares in 2002 and 2001 (4,384) (4,384)
----------------------------
Total Stockholders' Equity 350,657 346,552
----------------------------
$ 1,054,871 $ 1,069,031
============================
The accompanying notes are an integral part of these consolidated
financial statements.
44
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended December 31,
(In thousands) 2002 2001 2000
-----------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 16,103 $ 47,084 $ 25,472
Adjustments to Reconcile Net Income
to Cash Provided by Operations
Depletion, Depreciation and Amortization 96,512 80,619 53,441
Impairment of Unproved Properties 9,348 7,803 4,368
Impairment of Long-Lived Assets 2,720 6,852 9,143
Deferred Income Tax Expense 7,882 14,157 13,162
(Gain) Loss on Sale of Assets (244) (26) 39
Exploration Expense 40,167 71,165 19,858
Change in Derivative Fair Value 2,301 (142) --
Other 3,963 2,995 1,141
Changes in Assets and Liabilities
Accounts Receivable (19,317) 34,966 (35,286)
Inventories 2,308 (6,523) (108)
Other Current Assets 3,976 (3,524) (2,357)
Other Assets (4,307) (515) 348
Accounts Payable and Accrued Liabilities 8,301 (7,859) 26,976
Other Liabilities (4,572) 3,383 2,813
-----------------------------------------
Net Cash Provided by Operations 165,141 250,435 119,010
-----------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (103,189) (127,129) (99,359)
Acquisition of Cody Company /(1)/ -- (187,785) --
Proceeds from Sale of Assets 4,688 6,829 3,150
Exploration Expense (40,167) (71,165) (19,858)
-----------------------------------------
Net Cash Used by Investing (138,668) (379,250) (116,067)
-----------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt 180,000 435,000 135,000
Decrease in Debt (208,000) (311,000) (159,000)
Sale of Common Stock 3,461 7,749 85,104
Common Dividends Paid (5,079) (4,802) (4,350)
Preferred Dividends Paid -- -- (2,202)
Retirement of Preferred Stock -- -- (51,600)
-----------------------------------------
Net Cash Provided (Used) by Financing (29,618) 126,947 2,952
-----------------------------------------
Net Increase (Decrease) in Cash and
Cash Equivalents (3,145) (1,868) 5,895
Cash and Cash Equivalents, Beginning of Year 5,706 7,574 1,679
-----------------------------------------
Cash and Cash Equivalents, End of Year $ 2,561 $ 5,706 $ 7,574
=========================================
/(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.
45
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
Accumulated
Compre-
hensive Retained
Common Stock Preferred Treasury Paid-In Income Earnings
(In thousands) Shares Par Stock Stock Capital /(Loss) (Deficit) Total
- ---------------------------------------------------------------------------------------------------------------------
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
=====================================================================================
Net Income 16,103 16,103
Exercise of Stock Options 228 22 3,845 3,867
Common Stock Dividends
at $0.16 per Share (5,079) (5,079)
Other Comprehensive Loss (13,774) (13,774)
Stock Grant Vesting 2,988 2,988
-------------------------------------------------------------------------------------
Balance at December 31, 2002 32,133 $ 3,213 $ -- $ (4,384) $ 353,093 $(12,939) $ 11,674 $ 350,657
=====================================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
46
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Year Ended December 31,
(In thousands) 2002 2001 2000
------------------------------------------------------------------------------------------------------
Net Income Available to Common Stockholders $ 16,103 $ 47,084 $29,221
------------------------------------
Other Comprehensive (Loss) Income
---------------------------------
Cumulative Effect of Change in Accounting Principle
on January 1, 2001 -- (4,269) --
Reclassification Adjustments for Settled Contracts (6,423) 33,762 --
Changes in Fair Value of Outstanding Hedge Positions (13,708) (28,131) --
Adjustment to Recognize Minimum Pension Liability (2,177) -- --
Deferred Income Tax 8,534 (527) --
------------------------------------
Total Other Comprehensive (Loss) Income (13,774) 835 --
------------------------------------
Comprehensive Income $ 2,329 $ 47,919 $29,221
====================================
The accompanying notes are an integral part of these consolidated
financial statements.
47
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) approved
for issuance Statement of Financial Accounting Standard (SFAS) No. 143,
"Accounting for Asset Retirement Obligations." SFAS 143 establishes accounting
requirements for retirement obligations associated with tangible long-lived
assets, including (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 adoption of
SFAS 143 resulted in (1) an increase of total liabilities, because more
retirement obligations are required to be recognized, (2) an increase in the
recognized cost of assets, because the retirement costs are added to the
carrying amount of the long-lived asset and (3) an increase in operating expense
because of the accretion of the retirement obligation and additional
depreciation and depletion. The majority of the asset retirement obligations
recorded by the Company relate to the plugging and abandonment of oil and gas
wells. The Company adopted the statement on January 1, 2003. The transition
adjustment resulting from the adoption of SFAS 143 will be reported as a
cumulative effect of a change in accounting principle in January 2003. The
impact on the consolidated financial statements of adopting SFAS 143 is
disclosed in Note 12, "Adoption of SFAS 143, Accounting for Asset Retirement
Obligations".
In August 2001, the FASB approved SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets". 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 therefore were adopted by the Company in 2002. The adoption of this
statement did not impact the Company's financial position, results of
operations, or cash flows.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical
Corrections". SFAS 145, which is effective for fiscal years beginning after May
15, 2002, provides guidance for income statement classification of gains and
losses on extinguishment of debt and accounting for certain lease modifications
that have economic effects that are similar to sale-leaseback transactions. The
adoption of this statement did not impact the Company's financial position,
results of operations, or cash flows.
48
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS 146 nullifies the guidance of
the Emerging Issues Task Force (EITF) Issue No. 94-3, "Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)." SFAS 146 requires that a
liability for a cost that is associated with an exit or disposal activity be
recognized when the liability is incurred. SFAS 146 also establishes that fair
value is the objective for the initial measurement of the liability. The
provisions of SFAS 146 are required for exit or disposal activities that are
initiated after December 31, 2002. The adoption of this statement did not impact
the Company's financial position, results of operations, or cash flows.
In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation - Transition and Disclosure." SFAS 148 amends FASB
Statement No. 123, "Accounting for Stock-Based Compensation" to provide
alternative methods of transition for a voluntary change to the fair value based
method of accounting for stock-based employee compensation. In addition, this
Statement amends the disclosure requirements of Statement 123 to require
prominent disclosures in both annual and interim financial statements about the
method of accounting for stock-based employee compensation and the effect of the
method used on the reported results. The provisions of SFAS 148 are effective
for financial statements for fiscal years ending after December 15, 2002. The
adoption of this statement did not impact the Company's financial position,
results of operations, or cash flows. See Note 10, "Capital Stock".
In January 2003, the FASB issued Financial Interpretation No. 46,
"Consolidation of Variable Interest Entities - an interpretation of ARB No. 51"
(FIN 46 or Interpretation). FIN 46 is an interpretation of Accounting Research
Bulletin 51, "Consolidated Financial Statements", and addresses consolidation by
business enterprises of variable interest entities (VIE's). The primary
objective of the Interpretation is to provide guidance on the identification of,
and financial reporting for, entities over which control is achieved through
means other than voting rights; such entities are known as VIE's. The
Interpretation requires an enterprise to consolidate a variable interest entity
if that enterprise has a variable interest that will absorb a majority of the
entity's expected losses if they occur, receive a majority of the entity's
expected residual returns if they occur, or both. An enterprise shall consider
the rights and obligations conveyed by its variable interests in making this
determination. This guidance applies immediately to variable interest entities
created after January 31, 2003, and to variable interest entities in which an
enterprise obtains an interest after that date. It applies in the first fiscal
year or interim period beginning after June 15, 2003, to variable interest
entities in which an enterprise holds a variable interest that it acquired
before February 1, 2003. At this time, the Company has only one entity that
could potentially be a VIE. The Company is evaluating this potential VIE, in
which it has a one percent general partner interest (Partnership) and that holds
an interest in the Kurten field, to determine if it is a VIE. However, pursuant
to the Partnership agreement, the limited partner has elected to liquidate the
Partnership. It is anticipated that this liquidation will be completed prior to
the effective date of the Interpretation. See "Limited Partnership" on page 29
for discussion related to the Cody acquisition.
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 2002, the Company recorded total impairments
of $2.7 million. In 2002, the Company recorded impairments on four small fields,
three of which were in the Gulf Coast and one in the Rocky Mountains. For each
49
of these fields, the capitalized cost exceeded the future undiscounted cash
flows. In addition, a pipeline in the Eastern region was written down to fair
market value. 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. 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.
Prior to the adoption of SFAS 143 on January 1, 2003, future estimated
plug and abandonment costs were accrued over the productive life of certain oil
and gas properties when the residual value of well equipment was not sufficient
to cover the plug and abandonment liability. The accrued liability for plug and
abandonment costs was included in accumulated depreciation, depletion and
amortization. As a component of accumulated depreciation, depletion and
amortization, future plug and abandonment costs were $17.1 million at December
31, 2002 and $14.4 million at December 31, 2001. The Company believed that this
accrual method adequately provided for its estimated future plug and abandonment
costs of certain properties over the reserve life of the wells. The total
estimated liability to plug and abandon all wells was $53.0 million at December
31, 2002 and $50.8 million at December 31, 2001, excluding the residual value of
well equipment. See Note 12, "Adoption of SFAS 143, Accounting for Asset
Retirement Obligations", for additional information.
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.
The Company realizes brokered margin as a result of buying and selling
natural gas in back-to-back transactions. The Company realized $5.7 million,
$2.9 million, and $5.4 million of brokered natural gas margin in 2002, 2001, and
2000, 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.
50
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
$1.0 million at December 31, 2002, and $9.7 million at December 31, 2001.
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 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 SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities", and SFAS No. 138, "Accounting
for Certain Derivative Instruments and Certain Hedging Activities". 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
51
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.
Stock Based Compensation
The Company accounts for stock-based compensation in accordance with
the intrinsic value based method recommended by Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees." Under the intrinsic
value based method, compensation cost is the excess, if any, of the quoted
market price of the stock at grant date over the amount an employee must pay to
acquire the stock. The impact on the financial statements of using this method
is disclosed in Note 10, "Capital Stock", to the financial statements.
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, 2002, and 2001, the cash and cash equivalents are primarily concentrated in
one and two financial institutions, respectively. 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.
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) 2002 2001
-------------------------------------------------------------------------
Proved Oil and Gas Properties $ 1,459,240 $ 1,400,341
Unproved Oil and Gas Properties 76,959 70,709
Gathering and Pipeline Systems 137,137 131,768
Land, Building and Improvements 4,884 4,674
Other 29,457 27,513
-----------------------------
1,707,677 1,635,005
Accumulated Depreciation,
Depletion, Amortization and Impairments (752,940) (653,667)
------------------------------
$ 954,737 $ 981,338
==============================
As a component of accumulated depreciation, depletion and amortization,
total future plug and abandonment costs were $17.1 million at December 31, 2002
and $14.4 million at December 31, 2001. See further discussion in Note 1.
52
3. Additional Balance Sheet Information
Certain balance sheet amounts are comprised of the following:
December 31,
(In thousands) 2002 2001
----------------------------------------------------------------------
Accounts Receivable
Trade Accounts $ 65,796 $ 39,570
Joint Interest Accounts 6,601 12,889
Current Income Tax Receivable 2,479 2,662
Other Accounts 619 986
----------------------
75,495 56,107
Allowance for Doubtful Accounts /(1)/ (5,467) (5,396)
----------------------
$ 70,028 $ 50,711
======================
Other Current Assets
Derivative Instrument Asset - SFAS 133 $ 634 $ 2,387
Drilling Advances 558 2,111
Prepaid Balances 2,131 2,114
Restricted Cash and Other Accounts /(2)/ 1,957 4,398
----------------------
$ 5,280 $ 11,010
======================
Accounts Payable
Trade Accounts $ 13,317 $ 19,914
Natural Gas Purchases 6,058 4,559
Wellhead Gas Imbalances 2,817 2,353
Royalty and Other Owners 20,254 11,041
Capital Costs 13,900 30,923
Taxes Other than Income 3,076 2,686
Drilling Advances 7,254 2,627
Other Accounts 6,902 5,472
----------------------
$ 73,578 $ 79,575
======================
Accrued Liabilities
Employee Benefits $ 8,751 $ 7,151
Taxes Other than Income 9,887 13,623
Interest Payable 7,076 6,996
Derivative Instrument Payable - FAS 133 20,680 --
Other Accrued 3,052 2,895
----------------------
$ 49,446 $ 30,665
======================
Other Liabilities
Postretirement Benefits Other than Pension $ 1,843 $ 1,689
Accrued Pension Cost 8,486 7,280
Taxes Other than Income and Other 5,654 9,411
----------------------
$ 15,983 $ 18,380
======================
----------------------------------------------------------------------
/(1)/ Includes a $2.3 million addition in 2001 in connection with the
Enron Corp. bankruptcy.
/(2)/ Primarily represents cash in escrow for assumed Cody Company
liabilities.
4. Inventories
Inventories are comprised of the following:
December 31,
(In thousands) 2002 2001
----------------------------------------------------------------------
Natural Gas and Oil in Storage $ 11,519 $ 12,622
Tubular Goods and Well Equipment 3,334 4,059
Pipeline Exchange Balances 399 879
-------------------------
$ 15,252 $ 17,560
=========================
Natural gas and oil in storage is valued at average cost. Tubular
goods and well equipment is valued at historical cost. All inventory balances
are carried at the lower of cost or market.
53
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
required five annual $16 million principal payments each May starting in 1998.
The Company paid the outstanding principal balance of $32 million, together with
accrued interest and a $0.9 million prepayment penalty (which was recorded as a
component of interest expense) in May 2001.
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 in
October 2006. 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 reduction in the available credit line, in the event that it is
adjusted below the outstanding level of borrowings, the Company has a period of
three months to reduce its outstanding debt to the adjusted credit line
available with a requirement to provide additional borrowing base assets or pay
down one-third of the excess during each of the three months.
Interest rates under the Credit Facility are based on Euro-Dollars
(LIBOR) or Base Rate (Prime) indications, plus a margin. These associated
margins 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%
------------------------------------------
Euro-Dollar margin 1.250% 1.500% 1.750%
Base Rate margin 0.250% 0.500% 0.750%
54
The Company's effective interest rates for the Credit Facility in the
years ended December 31, 2002, 2001, and 2000 were 3.4%, 7.6%, and 7.8%,
respectively. The Credit Facility provides for a commitment fee on the unused
available balance at an annual rate of three-eighths of 1%. The Credit Facility
also contains various customary restrictions, which include the following:
(a) Maintenance of a minimum asset coverage ratio (present value of proved
reserves to debt and other liabilities) that must be at least 1.5 to
1.0,
(b) 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.
(c) Prohibition on the merger or sale of all, or substantially all, of the
Company's or any subsidiary's assets to a third party, except under
certain limited conditions.
(d) The aggregate level of commodity hedging must not exceed 80% of the
anticipated future production during the period covered by the hedges.
The Company was in compliance with all covenants at December 31, 2002 and 2001.
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, 2002, 2001 and 2000 are comprised of the following:
(In thousands) 2002 2001 2000
--------------------------------------------------------------------------------------
Qualified
Current Year Service Cost $ 1,056 $ 914 $ 832
Interest Accrued on Pension Obligation 1,362 1,198 1,070
Expected Return on Plan Assets (991) (1,064) (1,123)
Net Amortization and Deferral 88 88 88
Recognized Loss (Gain) 21 (28) (282)
--------------------------------
Net Periodic Pension Cost $ 1,536 $ 1,108 $ 585
================================
(In thousands) 2002 2001 2000
--------------------------------------------------------------------------------------
Non-Qualified
Current Year Service Cost $ 78 $ 88 $ 60
Interest Accrued on Pension Obligation 29 72 42
Net Amortization 77 77 77
Loss Recognized from Settlement 963 -- --
Recognized (Gain) Loss 7 21 (5)
--------------------------------
Net Periodic Pension Cost $ 1,154 $ 258 $ 174
================================
55
The following table illustrates the funded status of the Company's
pension plans at December 31, 2002, and 2001, respectively:
2002 2001
(In thousands) Qualified Non-Qualified Qualified Non-Qualified
--------------------------------------------------------------------------------------------------
Actuarial Present Value of:
Accumulated Benefit Obligation $ 18,136 $ 338 $ 14,279 $ 816
Projected Benefit Obligation $ 23,530 $2,511 $ 18,996 $ 898
Plan Assets at Fair Value 10,279 -- 9,909 --
---------------------------------------------------
Projected Benefit Obligation in Excess
of Plan Assets 13,251 2,511 9,087 898
Unrecognized Net Loss (7,283) (2,462) (2,153) (260)
Unrecognized Prior Service Cost (424) (475) (511) (553)
Adjustment to Recognize Minimum
Liability 2,313 764 -- 731
---------------------------------------------------
Accrued Pension Cost $ 7,857 $ 338 $ 6,423 $ 816
===================================================
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) 2002 2001 2000
--------------------------------------------------------------------------------------------
Beginning of Year $ 19,894 $ 17,151 $ 14,546
Service Cost 1,134 1,002 892
Interest Cost 1,391 1,270 1,112
Actuarial Loss 5,860 1,166 1,328
Benefits Paid (2,237) (695) (727)
--------------------------------------
End of Year $ 26,042 $ 19,894 $ 17,151
======================================
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) 2002 2001 2000
--------------------------------------------------------------------------------------------
Beginning of Year $ 9,908 $ 11,801 $ 12,092
Actual Return on Plan Assets (1,280) (1,527) (440)
Employer Contribution 4,080 584 1,172
Benefits Paid (2,237) (695) (727)
Expenses Paid (192) (254) (296)
--------------------------------------
End of Year $ 10,279 $ 9,909 $ 11,801
======================================
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) 2002 2001 2000
--------------------------------------------------------------------------------------------
Funded Status $ 15,762 $ 9,985 $ 5,350
Unrecognized Gain (Loss) (9,745) (2,413) 1,605
Unrecognized Prior Service Cost (899) (1,064) (1,229)
--------------------------------------
Net Amount Recognized $ 5,118 $ 6,508 $ 5,726
======================================
Accrued Benefit Liability - Qualified Plan $ 7,857 $ 6,423 $ 5,729
Accrued Benefit Liability - Non-Qualified Plan 338 816 753
Intangible Asset (3,077) (731) (756)
--------------------------------------
Net Amount Recognized $ 5,118 $ 6,508 $ 5,726
======================================
56
Assumptions used to determine projected post-retirement benefit
obligations and pension costs are as follows:
2002 2001 2000
--------------------------------------------------------------------------------------
Discount Rate/(1)/ 6.50% 7.25% 7.50%
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
7.25% discount rate was used to compute pension costs in 2002, a
rate of 7.50% in 2001, and a rate of 7.75% was used in 2000.
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 $1.3 million, $1.0 million, and $0.7 million in 2002, 2001, and
2000, respectively. The plan contribution rose in 2002 and 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, 2002, the balance in
the Deferred Compensation Plan's rabbi trust was $2.8 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 246 retirees at
the end of 2002 and 240 retirees at the end of 2001.
When the Company adopted SFAS 106, "Employers' Accounting for
Postretirement Benefits Other Than Pension", in 1992, it began amortizing the
$16.9 million accumulated postretirement benefit, known as the Transition
Obligation, over a period of 20 years.
57
Postretirement benefit costs recognized during the last three years
are as follows:
(In thousands) 2002 2001 2000
-------------------------------------------------------------------------------------
Service Cost of Benefits Earned During the Year $ 215 $ 175 $ 187
Interest Cost on the Accumulated Postretirement
Benefit Obligation 381 388 534
Amortization Benefit of the Unrecognized Gain (267) (291) (132)
Amortization Benefit of the Unrecognized
Transition Obligation 662 662 662
------------------------------
Total Postretirement Benefit Cost $ 991 $ 934 $1,251
==============================
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, 2002, and 2001 is comprised of the following:
(In thousands) 2002 2001
------------------------------------------------------------------------------------
Plan Assets at Fair Value $ -- $ --
Accumulated Postretirement Benefits Other Than Pensions 6,185 5,507
Unrecognized Cumulative Net Gain 2,113 3,292
Unrecognized Transition Obligation (5,955) (6,617)
---------------------
Accrued Postretirement Benefit Liability $ 2,343 $ 2,182
=====================
The change in the accumulated postretirement benefit obligation during
the last three years is presented as follows:
(In thousands) 2002 2001 2000
-------------------------------------------------------------------------------------
Beginning of Year $ 5,507 $ 5,429 $ 7,243
Service Cost 215 175 187
Interest Cost 381 388 534
Amendments -- -- --
Actuarial Loss (Gain) 912 265 (1,923)
Benefits Paid (830) (750) (612)
------------------------------------
End of Year $ 6,185 $ 5,507 $ 5,429
====================================
58
7. Income Taxes
Income tax expense is summarized as follows:
Year Ended December 31,
(In thousands) 2002 2001 2000
-------------------------------------------------------------------------------------------
Current
Federal $ (1,158)/(1)/ $ 10,984/(1)/ $ 3,089
State 869 496 216
--------------------------------------------
Total (289) 11,480 3,305
--------------------------------------------
Deferred
Federal 7,931 13,723 11,804
State 32 2,262 1,358
--------------------------------------------
Total 7,963 15,985 13,162
--------------------------------------------
Total Income Tax Expense $ 7,674 $ 27,465 $ 16,467
============================================
-----------------------------------------------------------------------
/(1)/ Federal Income Taxes Payable is zero at December 31, 2002 and
2001 primarily due to tax payments made during the current year
and prior year overpayments applied to the current year.
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) 2002 2001 2000
-------------------------------------------------------------------------------------------
Statutory Federal Income Tax Rate 35% 35% 35%
Computed "Expected" Federal Income Tax $ 8,322 $ 26,092 $14,679
State Income Tax, Net of Federal Income Tax 737 2,758 1,552
Other, Net (1,385)/(1)/ (1,385)/(2)/ 236
--------------------------------------------
Total Income Tax Expense $ 7,674 $ 27,465 $16,467
============================================
-----------------------------------------------------------------------
/(1)/ Other, Net includes credit adjustments totaling $0.8 million to
deferred taxes as a result of a reduction to the state effective
tax rate,$0.8 million to deferred taxes as a result of basis
adjustments related to the Cody acquisition, and 2001 estimate-
to-actual differences and non-provision additions.
/(2)/ Other, Net includes credit adjustments totaling $1.7 million to
deferred taxes as a result of a reduction to the state effective
tax rate.
The tax effects of temporary differences that resulted in significant
portions of the deferred tax liabilities and deferred tax assets as of December
31, 2002, and 2001 were as follows:
(In thousands) 2002 2001
-------------------------------------------------------------------------------------------
Deferred Tax Liabilities
Property, Plant and Equipment $ 229,583 $ 224,031
---------------------------
Deferred Tax Assets
Alternative Minimum Tax Credit Carryforwards 12,083 4,943
Net Operating Loss Carryforwards 746 1,715
Note Receivable on Section 29 Monetization (1) -- 4,928
Items Accrued for Financial Reporting Purposes 8,540 11,059
Other Comprehensive Income 8,007 527
---------------------------
29,376 23,172
---------------------------
Net Deferred Tax Liabilities $ 200,207 $ 200,859
===========================
-----------------------------------------------------------------------
/(1)/ In December 2002, the Company repurchased assets associated with
Section 29 credits sold in 1995 and 1996. Accordingly, the
remaining deferred gain from the installment sale and deferred
loss associated with unrealized receivables was recognized in
2002.
As of December 31, 2002, the Company had a net operating loss
carryforward of $11.6 million for state income tax reporting purposes, the
majority of which will expire between 2012 and 2018 and none available for
regular federal income tax purposes. The Company has alternative minimum tax
credit carryforwards of $12.1 million which does not expire and is available to
offset regular income taxes in future years to the extent that regular income
taxes exceed the alternative minimum tax in any such year.
59
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 seven 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 $8.8 million, $7.7 million, and $6.3
million for the years ended December 31, 2002, 2001, and 2000, respectively.
Future minimum rental commitments under non-cancelable leases in effect at
December 31, 2002 are as follows:
(In thousands)
------------------------------------------
2003 $ 5,590
2004 4,805
2005 4,419
2006 3,732
2007 3,488
Thereafter 5,119
--------
$ 27,153
Minimum rental commitments are not reduced by minimum sublease rental income of
$46.9 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 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.
The Company documents with the notification from the EPA indicating 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 entered into a consent
decree, which will require the CNC to pay approximately $27 million toward Site
clean up in return for a release from liability. On January 30, 2002, the
Company placed $1,283,283 in an escrow account, representing its volumetric
share of the CNC/United States settlement. This cash settlement, once released
from escrow and paid to the federal government after the consent decree is
entered by the court, 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 Most
of the CNC, including the Company, have purchased insurance designed to protect
the Company from these liabilities not covered by the consent decree.
60
The State of California, a third party, has asserted a claim against the
CNC and other companies alleged to have waste at Casmalia for costs the State
incurred and will incur at the site. The CNC has presented the claim to its
insurer. The ultimate disposition of this claim is unknown. However, given the
size of the State's claim, and the number of parties allegedly responsible, the
Company's share of this claim is expected to be immaterial.
The Company has established a reserve management believes to be adequate to
provide for this environmental liability and related legal costs.
Wyoming Royalty Litigation
In June 2000, the Company was sued by two overriding royalty owners 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 improperly deducted 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 January
2002, thirteen overriding royalty owners sued the Company in Wyoming federal
district 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.
Although management believes that a number of the Company's defenses are
supported by Wyoming case law, a recent letter decision handed down by a state
district court in another case does not support certain of the defenses. The
decision has not been reduced to a formal order and it is not known what effect,
if any, the decision will have on the pending cases.
In the Company's federal case, the judge recently agreed to certify two
questions of state law for decision by the Wyoming State Supreme Court. The
Wyoming State Supreme Court has agreed to decide both questions, and these
decisions should dispose of important issues in these cases. The federal judge
refused, however, to certify one question on check stub reporting that had been
decided adversely to the Company's position in the state district court letter
decision. After the federal judge's refusal to certify this issue, the
plaintiffs reduced the damages they were claiming. The plaintiffs in the federal
case currently claim $5.5 million in damages for the deductions and related
issues and $12.9 million in damages for violation of the check stub reporting
statute. In the opinion of our outside counsel, Brown, Drew & Massey, LLP the
likelihood of the plaintiffs recovering the stated damages for violation of the
check stub reporting statute is remote.
The Company is vigorously defending both cases. The Company has a reserve
that management believes is adequate to provide for these potential liabilities
based its estimate of the probable outcome of these matters. Should
circumstances change, the potential impact may materially affect quarterly or
annual results of operations and cash flows. However, management does not
believe it would materially impact our financial position.
West Virginia Royalty Litigation
In December 2001, the Company was sued by two royalty owners 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 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 have failed to properly inform the plaintiffs and other
similarly situated persons of deductions taken from the royalty. The plaintiffs
have also claimed that they are entitled to a 1/8th royalty share of the gas
sales contract settlement that the Company reached with Columbia in the 1995
Columbia bankruptcy proceeding.
The Company had removed the lawsuit to federal court, however in February
2003 the Company received an order remanding the lawsuit back to state court.
Discovery and pleadings necessary to place the class certification issue before
the court have been ongoing. No trial or dispositive motions dates have been set
and limited factual discovery is ongoing.
The investigation into this claim continues and it is in the discovery
phase. The Company is vigorously defending the case. The Company has reserves it
believes are adequate to provide for these potential liabilities based on its
estimate of the probable outcome of this matter. Should circumstances change,
the potential impact may materially affect quarterly or annual results of
operations and cash flows. However, management does not believe it would
materially impact the Company's financial position.
Texas Title Litigation
On January 6, 2003, the Company was served with Plaintiffs' Second Amended
Original Petition in Romeo Longoria, et al. v. Exxon Mobil Corporation, et al.
in the 79th Judicial District Court of Brooks County, Texas. The plaintiffs
allege that they are the rightful owners of a one-half
61
undivided mineral interest in and to certain lands in Brooks County, Texas. As
Cody Energy, Inc. the Company acquired certain leases and wells from Wynn-Crosby
1996, Ltd. in 1997 and 1998 and the Company subsequently acquired a 320 acre
lease from Hector and Gloria Lopez in 2001. The plaintiffs allege that they are
entitled to be declared the rightful owners of an undivided interest in the
surface and minerals and all improvements on the lands on which the Company
acquired these leases. The plaintiffs also assert claims for trespass to try
title, action to remove a cloud on the title, failure to properly account for
royalty, fraud, trespass, conversion, all for unspecified actual and exemplary
damages. There is a trial date of May 19, 2003. However, the recent addition of
the Company as defendant, as well as others, is expected to lead to a
continuance of that trial date. The Company has not had the opportunity to
conduct discovery in this matter. The Company estimates that production revenue
from this field since its predecessor, Cody Energy, acquired title and since the
Company acquired its lease is approximately $12 million. The carrying value of
this property is approximately $35 million.
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) 2002 2001 2000
------------------------------------------------------------------
Interest $ 25,112 $ 16,295 $ 23,180
Income Taxes $ 266 $ 14,395 $ 1,419
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. Under these two 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 4,200,000 shares of Common Stock may be issued under the
Incentive Plans. There are no shares available for award under any previous
equity plan. All stock options awarded under the Incentive Plans have a maximum
term of five years from the date of grant, vesting over time. The options are
issued at market value on 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,
2002 2001 2000
-------------------------------------------------------------------------------------
Shares Under Option at Beginning of Period 1,081,621 1,124,148 1,773,389
Granted 429,300 454,100 299,250
Exercised 181,027 408,949 896,081
Surrendered or Expired 42,065 87,678 52,410
----------------------------------------
Shares Under Option at End of Period 1,287,829 1,081,621 1,124,148
========================================
Options Exercisable at End of Period 570,406 355,778 474,599
========================================
62
For each of the three most recent years, the price range for outstanding
options was $15.25 to $27.30 per share. The following tables provide more
information about the options by exercise price and year.
Options with exercise prices between $15.25 and $20.00 per share:
December 31,
2002 2001 2000
------------------------------------------------------------------------------------------
Options Outstanding
-------------------
Number of Options 737,385 480,561 866,498
Weighted Average Exercise Price $ 18.97 $ 17.79 $ 17.63
Weighted Average Contractual Term (in years) 3.0 1.50 2.60
Options Exercisable
-------------------
Number of Options 301,277 211,734 372,418
Weighted Average Exercise Price $ 18.39 $ 17.29 $ 16.27
Options with exercise prices between $20.01 and $27.30 per share:
December 31,
2002 2001 2000
------------------------------------------------------------------------------------------
Options Outstanding
-------------------
Number of Options 550,444 601,060 257,650
Weighted Average Exercise Price $ 25.81 $ 25.44 $ 22.46
Weighted Average Contractual Term (in years) 3.0 4.30 1.90
Options Exercisable
-------------------
Number of Options 269,129 144,044 102,181
Weighted Average Exercise Price $ 25.39 $ 22.45 $ 22.51
SFAS 123, "Accounting for Stock-Based Compensation", as amended by SFAS
148, "Accounting for Stock-Based Compensation - Transition and Disclosure",
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.
The following table illustrates the effect on net income and earnings per
share if the Company had applied the fair value recognition provisions of SFAS
123 to stock-based employee compensation.
Year Ended December 31
----------------------------------------------------
(In thousands, except per share amounts) 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------
Net Income, as reported $ 16,103 $ 47,084 $ 29,221
Deduct: Total stock-based employee compensation expense
determined under fair value based
method for all awards, net of tax 1,605 1,355 1,051
----------------------------------------------------
Pro forma net income $ 14,498 $ 45,729 $ 28,170
====================================================
Earnings per share:
Basic - as reported $ 0.51 $ 1.56 $ 1.07
Basic - pro forma $ 0.46 $ 1.51 $ 1.03
Diluted - as reported $ 0.50 $ 1.53 $ 1.06
Diluted - pro forma $ 0.45 $ 1.49 $ 1.02
63
The assumptions used in the fair value method calculation as well as
additional stock based compensation information are disclosed in the following
table.
Year Ended December 31
-----------------------
(In thousands, except per share amounts) 2002 2001 2000
--------------------------------------------------------------------------
Compensation Expense in Net Income,
as reported /1)/ $2,326 $1,078 $ 595
Weighted Average Value of
Options Granted During the Year /2)/ $ 6.23 $ 8.61 $6.63
Assumptions
Stock Price Volatility 35.8% 34.9% 34.5%
Risk Free Rate of Return 3.9% 4.7% 5.2%
Dividend Rate (per year) $ 0.16 $ 0.16 $0.16
Expected Term (in years) 4 4 4
--------------------------------------------------------------------------
/(1)/ Compensation expense is defined as expense related to the vesting of
stock grants, net of tax. Compensation expense in 2002 includes $1.7
million related to the acceleration of stock awards due to the
retirement of an executive.
/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.
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 have been repurchased. The stock repurchase plan
was funded from increased borrowings on the revolving credit facility. No
treasury shares have been delivered or sold by the Company subsequent to the
repurchase.
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% 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% 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, 2002, and 2001, there were
64
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, 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 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. This disclosure is presented in accordance with
SFAS 107, "Disclosures about Fair Value of Financial Instruments" and does not
impact the Company's financial position, results of operations or cash flows.
Long-Term Debt
December 31, 2002 December 31, 2001
Carrying Estimated Carrying Estimated
(In thousands) Amount Fair Value Amount Fair Value
---------------------------------------------------------------------------
Debt
7.19% Notes $ 100,000 $ 113,591 $ 100,000 $ 104,961
7.26% Notes 75,000 84,231 75,000 79,187
7.36% Notes 75,000 86,461 75,000 79,225
7.46% Notes 20,000 23,322 20,000 21,097
Credit Facility 95,000 95,000 123,000 123,000
---------------------------------------------------
$ 365,000 $ 402,605 $ 393,000 $ 407,470
===================================================
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 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 Credit Facility approximates fair value because
this instrument bears interest at rates based on current market rates.
65
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. Under the
Revolving Credit Agreement, the aggregate level of commodity hedging must not
exceed 80% of the anticipated future production during the period covered by the
hedges. During 2002, the Company fixed the price at an average of $4.44 per Mcf
on quantities totaling 7,870 Bcf, representing 11% of the Company's 2002 natural
gas production. The Company did not have crude oil swap arrangements covering
its production in 2002. During 2001, the Company fixed the price at an average
of $3.75 per Mcf on quantities totaling 918 Mmcf, representing approximately 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
Company did not have crude oil swap arrangements covering its production in
2000.
As of the years ended December 31, 2002, and 2001, the Company had no crude
oil swap contracts that qualified as hedges outstanding. The Company had open
natural gas price swap contracts on its production as follows:
Natural Gas Price Swaps
------------------------------------------------
Volume Weighted Unrealized
in Average Loss
Contract Period Mmcf Contract Price (In $ millions)
--------------------------------------------------------------------------------------
As of December 31, 2002
-----------------------
Natural Gas Price Swaps on Production in:
-----------------------------------------
First Quarter of 2003 8,333 $ 4.44
Second Quarter of 2003 7,107 4.24
Third Quarter of 2003 7,186 4.24
Fourth Quarter of 2003 7,186 4.24
----- ----
Full Year of 2003 29,812 4.29 $ 15,062
First Quarter of 2004 2,089 $ 4.42
Second Quarter of 2004 2,089 4.42
Third Quarter of 2004 2,112 4.42
Fourth Quarter of 2004 2,112 4.42
----- ----
Full Year of 2004 8,402 4.42 $ 1,753
As of December 31, 2001
-----------------------
None
Natural gas price swaps increased revenue by $0.9 million in 2002 and
reduced revenue by $0.8 million in 2001.
From time to time the Company enters into crude oil range swaps with
counterparties. These derivatives do not qualify for hedge accounting under SFAS
133 and are recorded at fair value at the balance sheet date. The Company
entered into two derivative arrangements as follows:
. A fixed price swap at $28.15 per barrel, unless the NYMEX West Texas
Intermediate monthly average price falls below $21.00 per barrel. If the
NYMEX West Texas Intermediate monthly average price falls below $21.00 per
barrel for any month, the swap is cancelled for that month. This instrument
covers 730 Mbbls of production over the period January 2003 through
December 2003.
. A fixed price swap at $27.75 per barrel, unless the NYMEX West Texas
Intermediate monthly average price falls below $21.00 per barrel. If the
NYMEX West Texas Intermediate monthly average price falls below $21.00 per
barrel for any month, the swap is cancelled for that month. This instrument
covers 276 Mbbls of production over the period July 2003 through December
2003.
66
The crude oil range swaps at December 31, 2002, had a pre-tax unrealized loss in
the amount of $0.7 million, which is reflected in crude oil operating revenue,
and covered approximately 31% of the Company's anticipated crude oil production
during this period. The Company had no crude oil range swap contracts
outstanding during 2001.
Hedges on Production - Options
In December 2001 and March 2002, management believed that the pricing
environment provided a strategic opportunity to significantly reduce the price
risk on a portion of the Company's 2002 production through the use of a series
of collars. Under the 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 2002 natural gas price hedges
include several collar arrangements based on nine price indexes. The first
series of natural gas price collars were in place for the months of January
through April 2002 with a weighted average price floor of $2.68 per Mcf and a
weighted average price ceiling of $3.53 per Mcf. These hedges covered 16,145
Mmcf, or 22% of the Company's natural gas production for the year. The second
series of natural gas price collars were in place for the months of May through
August 2002 with a weighted average price floor of $2.54 per Mcf and a weighted
average price ceiling of $3.17 per Mcf. These hedges covered 18,284 Mmcf, or 25%
of the Company's natural gas production for the year.
All indexes were within the collars during the month of January, all were
below the floor for February through March, and most were above the ceiling in
April through August, resulting in a cash expenditure of $1.4 million for the
year. Overall, the natural gas collar and swap arrangements resulted in a
reduction of $0.01 per Mcf to the Company's average realized natural gas price
for 2002.
During 2001, the Company used several costless collar arrangements to hedge
a portion of its 2001 natural gas production. The 2001 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 a $34.6 million cash revenue for the year. These gains contributed
$0.50 per Mcf to the Company's average realized natural gas price for 2001.
Again in August 2002, management believed that the pricing environment
provided a strategic opportunity to significantly reduce the price risk on a
portion of the Company's 2003 production through the use of natural gas price
collar arrangements. As of the years ended December 31, 2002, and 2001, the
Company had open natural gas price collar contracts on its production as
follows:
Natural Gas Price Collars
-----------------------------------------------------
Volume Weighted Unrealized
in Average Loss
Contract Period Mmcf Ceiling / Floor (In $ millions)
-------------------------------------------------------------------------------------------
As of December 31, 2002
-----------------------
Natural Gas Collars on Production in:
-------------------------------------
First Quarter of 2003 2,066 $5.03/$4.36
Second Quarter of 2003 2,089 $5.03/$4.36
Third Quarter of 2003 2,112 $5.03/$4.36
Fourth Quarter of 2003 2,112 $5.03/$4.36
----- -----------
Full Year of 2003 8,379 $5.03/$4.36 $ 2,090
As of December 31, 2001
-----------------------
Natural Gas Costless Collars on Production in:
----------------------------------------------
First Quarter of 2002 12,082 $3.54/$2.68
Second Quarter of 2002 4,027 $3.54/$2.68
------- -----------
Full Year of 2003 16,109 $3.54/$2.68 --
The natural gas price collars open at December 31, 2002 include collar
arrangements based on two price indexes at which the Company sells a portion of
its production. These hedges are in place for the full year of 2003 and cover
approximately 11% of the Company's anticipated natural gas production during
this period. The
67
Company also has crude oil collars open at December 31, 2002. These hedges are
in place for the months of January through June 2003 with a weighted average
price floor of $24.75 and a weighted average price ceiling of $28.86. These
hedges cover approximately 11% of the Company's anticipated crude oil production
during this period. Crude oil collars reduced revenue by $5.2 million during
2002, but had no impact on 2001 results.
Subsequent to year end the Company entered into a series of natural
gas costless collar and natural gas and crude oil price swap arrangements to
significantly reduce the price risk on a portion of its 2003 and 2004
production. These arrangements are as follows:
. A natural gas costless collar in place for the months of February
through December 2003 with a weighted average price floor of $4.71 per
Mcf and a weighted average price ceiling of $5.98 per Mcf. This hedge
covers 6,386 Mmcf of our anticipated natural gas production for the
year.
. A natural gas costless collar in place for the full year of 2004
with a weighted average price floor of $4.33 per Mcf and a weighted
average price ceiling of $5.42 per Mcf. This hedge covers 5,041 Mmcf
of our anticipated natural gas production for the year.
. A natural gas costless collar in place for the full year of 2004
with a weighted average price floor of $4.16 per Mcf and a weighted
average price ceiling of $5.25 per Mcf. This hedge covers 3,346 Mmcf
of our anticipated natural gas production for the year.
. A natural gas costless collar in place for the months of March
through December 2003 with a weighted average price floor of $3.91 per
Mcf and a weighted average price ceiling of $5.08 per Mcf. This hedge
covers 1,371 Mmcf of our anticipated natural gas production for the
.year.
. A natural gas price swap in place for the months of March through
December 2003 with a fixed price of $4.46 per Mcf. This hedge covers
1,371 Mmcf of our anticipated natural gas production for the year.
. A fixed price swap at $30.00 per barrel, unless the NYMEX West Texas
Intermediate monthly average price falls below $22.00 per barrel. If
the NYMEX West Texas Intermediate monthly average price falls below
$22.00 per barrel for any month, the swap is cancelled for that month.
This instrument covers 92 Mbbls of production over the period July
2003 through December 2003.
Adoption of SFAS 133
The Company adopted SFAS 133, "Accounting for Derivative Instruments
and Hedging Activities", 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 were 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, it 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. 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. In accordance with the initial SFAS
133 guidance,
68
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 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 outstanding. As of December 31, 2002 the Company had a
series of 16 natural gas price swap arrangements, two natural gas price collar
arrangements, two crude oil price collar arrangements, and two crude oil swap
arrangements outstanding. In accordance with the latest guidance from the FASB's
Derivative Implementation Group, the Company tests 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,
2002, the Company had recorded $18.8 million of Other Comprehensive Loss ($11.6
million net of deferred taxes), a $0.6 million Unrealized Hedge Loss in revenue,
a $0.6 million Hedge Asset, and a $20.0 million Hedge Liability, exclusive of
the crude oil range swaps. 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 in revenue 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. As of December 31, 2002, the Company
had recorded $22.3 million of Other Comprehensive Loss ($13.8 million net of
deferred taxes). Amounts recorded consisted of a $6.4 million loss for
Reclassification Adjustments for Settled Contracts ($4.0 million net of deferred
taxes), a $13.7 million loss for Changes in Fair Value of Outstanding Hedge
Positions ($8.5 million net of deferred taxes), and a $2.2 million loss for an
Adjustment to Recognize Minimum Pension Liability ($1.3 million net of deferred
taxes).
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.
In 2002, approximately 14% of the Company's total sales were made to one
customer. This customer operates certain properties in which the Company has
interests in the Gulf Coast and purchases all of the production from these
wells. This customer is currently reselling the natural gas and oil to third
parties with whom the Company would deal directly if the customer either ceased
to exist or stopped buying the Company's portion of the production. The Company
had no sales to any customer that exceeded 10% of its total gross revenues in
2001 or 2000.
69
12. Adoption of SFAS 143, "Accounting for Asset Retirement Obligations"
Effective January 1, 2003 the Company adopted SFAS 143, "Accounting for
Asset Retirement Obligations." SFAS 143 requires that the fair value of a
liability for an asset retirement obligation be recognized in the period in
which it is incurred if a reasonable estimate of fair value can be made. The
associated asset retirement cost is capitalized as part of the carrying amount
of the long-lived asset. Subsequently, the asset retirement cost is allocated to
expense using a systematic and rational method over the assets useful life. The
adoption of SFAS 143 resulted in an increase of total liabilities because more
retirement obligations are required to be recognized, an increase in the
recognized cost of assets because the retirement costs are added to the carrying
amount of the long-lived asset and an increase in operating expense because of
the accretion of the retirement obligation and additional depreciation and
depletion. The majority of the asset retirement obligations recorded by the
Company relate to the plugging and abandonment of oil and gas wells. However,
liabilities will also be recorded for meter stations, pipelines, processing
plants and compressors. At January 1, 2003 there are no assets legally
restricted for purposes of settling asset retirement obligations. The Company
will record a net-of-tax cumulative effect of change in accounting principle
loss, in January of 2003, of approximately $6.8 million and record a retirement
obligation of approximately $35.1 million. There will be no impact on the
Company's cash flows as a result of adopting SFAS 143.
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.
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 Eastern and Rocky Mountains properties. Revenue from these monetized
credits was $2.0 million in 2002, $2.0 million in 2001, and $2.2 million in
2000. The production, revenues, expenses and proved reserves for these
properties was reported by the Company as Other Revenue until the credits were
repurchased in December 2002. In this repurchase transaction, the Company
acquired 26 Bcfe for $7 million, or $0.27 Mcfe. The effective date of the
repurchase was December 31, 2002.
14. Acquisition of Cody Company
In August 2001, the Company 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 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
Company recorded a purchase price of approximately $315.6 million, which 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. The
70
remaining $78.0 million of the recorded purchase price reflected a 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 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, 2001. The information presented is not necessarily
indicative of the results of future operations of the Company.
Year Ended December 31,
(In thousands) 2002 2001
-----------------------------------------------------------------
Revenues $ 353,756 $ 505,528
Net Income $ 16,103 $ 54,513
per share - Basic $ 0.51 $ 1.75
per share - Diluted $ 0.50 $ 1.73
The decrease in revenues from 2001 to 2002 is primarily the result of
lower realized prices both for natural gas and crude oil. The Company's realized
natural gas price declined by 31% and crude oil prices declined by 4%. Partially
offsetting the decline in revenues were lower operating expenses, including
brokered gas cost and exploration expense, as well as a reduction to income tax
expense. The results of operations for Cody Company are consolidated with Cabot
Oil & Gas Corporation as of August 1, 2001.
As part of the Cody acquisition, the Company acquired a interest in
certain oil and gas properties in the Kurten field, as general partner of a
partnership and as an operator. The Company's current interest in Kurten is
approximately 25%, including a one percent interest in the partnership. Under
the partnership agreement, the Company has the right to a reversionary working
interest that would bring its ultimate interest to 50% upon the limited partner
reaching payout. Under the partnership agreement, the limited partner has the
sole option to trigger a liquidation of the partnership. Effective February 13,
2003, the Kurten partnership commenced liquidation at the limited partner's
election. In connection with the liquidation, an appraisal has been obtained to
allocate the interest in the partnership assets. Based on the receipt of the
appraisal in February 2003, the Company would not receive the reversionary
interest as part of the liquidation. Due to the impact of the loss of the
reversionary interest on future estimated net cash flows of the Kurten field,
the limited partners decision and our decision to proceed with the liquidation,
the Company performed an impairment review which resulted in an after-tax charge
of approximately $55 million. This impairment charge will be reflected in the
first quarter of 2003 as an operating expense but does not impact the Company's
cash flows. In addition, the Company will record a downward reserve revision of
approximately 16 Bcfe as a result of the loss of the reversionary interest.
15. Earnings per Common Share
Full year basic earnings per share for the Company were $0.51, $1.56,
and $1.07 in 2002, 2001, and 2000, respectively, and were based on the weighted
average shares outstanding of 31,736,975 in 2002, 30,275,906 in 2001, and
27,383,848 in 2000. Diluted earnings per share for the Company were $0.50,
$1.53, and $1.06 in 2002, 2001, and 2000, 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 338,972 in 2002, 408,361 in 2001, and 281,210 in 2000. Stock awards
and stock options excluded from the calculation of diluted earnings per share
because the effect was antidilutive were 1,174,507, 913,310, and 947,909 in
2002, 2001 and 2000, respectively.
No preferred stock was outstanding at the end of 2002, 2001 or 2000.
See Note 10, "Capital Stock" for further discussion.
71
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, 2002,
2001, and 2000 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 7, 2003, 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, 2002, 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) 2002 2001 2000
-----------------------------------------------------------------------------------------------------
Proved Reserves
Beginning of Year 1,036,004 959,222 929,602
Revisions of Prior Estimates 14,405 (44,266) (14,796)
Extensions, Discoveries and Other Additions 64,945 99,911 103,600
Production (73,670) (69,162) (60,934)
Purchases of Reserves in Place 26,262 91,290 5,118
Sales of Reserves in Place (6,987) (991) (3,368)
-------------------------------------------------
End of Year 1,060,959 1,036,004 959,222
=================================================
Proved Developed Reserves 819,412 804,646 754,962
=================================================
Percentage of Reserves Developed 77.2% 77.7% 78.7%
=================================================
72
Liquids
-------------------------------------------------
December 31,
(Thousands of barrels) 2002 2001 2000
-----------------------------------------------------------------------------------------------------
Proved Reserves
Beginning of Year 19,684 9,914 8,189
Revisions of Prior Estimates 1,871 254 562
Extensions, Discoveries and Other Additions 851 2,257 2,032
Production (2,909) (1,996) (988)
Purchases ofReserves in Place 261 9,255 120
Sales of Reserves in Place (1,365) -- (1)
-------------------------------------------------
End of Year 18,393 19,684 9,914
=================================================
Proved Developed Reserves 13,267 15,328 8,438
=================================================
Percentage of Reserves Developed 72.1% 77.9% 85.1%
=================================================
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) 2002 2001 2000
-----------------------------------------------------------------------------------------------------
Aggregate Capitalized Costs Relating
to Oil and Gas Producing Activities $ 1,704,746 $ 1,632,101 $ 1,180,692
Aggregate Accumulated Depreciation,
Depletion and Amortization $ 750,857 $ 651,657 $ 558,463
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) 2002 2001 2000
-----------------------------------------------------------------------------------------------------
Property Acquisition Costs, Proved /(1)/ $ 8,799 $ 245,079 $ 5,954
Property Acquisition Costs, Unproved /(1)/ 4,869 21,116 10,869
Exploration and Extension Well Costs /(2)/ 52,012 91,261 40,008
Development Costs 55,165 90,246 59,879
-----------------------------------------------
Total Costs $ 120,845 $ 447,702 $ 116,710
===============================================
-----------------------------------------------------------------------
/(1)/ Excludes the $78.0 million deferred tax gross-up on the Cody
acquisition.
/(2)/ Includes administrative exploration costs of $8,942, $9,831, and
$8,442 for the years ended December 31, 2002, 2001, and 2000,
respectively. These costs are excluded from the Company's
calculation of reserve replacement costs.
73
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) 2002 2001 2000
-----------------------------------------------------------------------------------------------------
Operating Revenues $ 280,379 $ 339,064 $ 214,116
Costs and Expenses
Production 63,823 58,382 46,721
Other Operating 21,731 22,656 17,249
Exploration /(1)/ 40,167 71,165 19,858
Depreciation, Depletion and Amortization 102,086 89,286 63,200
----------------------------------------------
Total Costs and Expenses 227,807 241,489 147,028
----------------------------------------------
Income Before Income Taxes 52,572 97,575 67,088
Provision for Income Taxes 18,400 34,151 23,481
----------------------------------------------
Results of Operations $ 34,172 $ 63,424 $ 43,607
==============================================
-----------------------------------------------------------------------
/(1)/ Includes administrative exploration costs of $8,942, $9,831, and
$8,442 for the years ended December 31, 2002, 2001, and 2000,
respectively. These costs are excluded from the Company's
calculation of reserve replacement costs.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves
The following information has been developed utilizing SFAS 69,
"Disclosures about Oil and Gas Producing Activities", procedures and based on
natural gas and crude oil reserve and production volumes estimated by the
Company's engineering staff. It can be used for some comparisons, but should not
be the only method used to evaluate the Company or its performance. Further, the
information in the following table may not represent realistic assessments of
future cash flows, nor should the Standardized Measure of Discounted Future Net
Cash Flows be viewed as representative of the current value of the Company.
The Company believes that the following factors should be taken into
account when reviewing the following information:
. Future costs and selling prices will probably differ from those
required to be used in these calculations.
. Due to future market conditions and governmental regulations, actual
rates of production in future years may vary significantly from the
rate of production assumed in the calculations.
. Selection of a 10% discount rate is arbitrary and may not be a
reasonable measure of the relative risk that is part of realizing
future net oil and gas revenues.
. Future net revenues may be subject to different rates of income
taxation.
Under the Standardized Measure, future cash inflows were estimated by
applying year-end oil and gas prices adjusted for fixed and determinable
escalations to the estimated future production of year-end proved reserves.
The average prices related to proved reserves at December 31, 2002,
2001, and 2000 for natural gas ($ per Mcf) were $4.41, $2.65, and $9.63,
respectively, and for oil ($ per Bbl) were $30.39, $18.56, and $26.18,
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.
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.
74
Standardized Measure is as follows:
Year Ended December 31,
(In thousands) 2002 /(1)/ 2001 /(1)/ 2000 /(1)/
-------------------------------------------------------------------------------------
Future Cash Inflows $ 5,236,349 $ 3,107,668 $ 9,497,181
Future Production Costs (1,137,615) (823,988) (1,435,489)
Future Development Costs (284,165) (266,833) (192,893)
----------------------------------------
Future Net Cash Flows Before Income Taxes 3,814,569 2,016,847 7,868,799
10% Annual Discount for Estimated
Timing of Cash Flows (2,098,669) (1,065,747) (4,332,551)
----------------------------------------
Standardized Measure of Discounted Future
Net Cash Flows Before Income Taxes 1,715,900 951,100 3,536,248
Future Income Tax Expenses,
Net of 10% Annual Discount /(2)/ (460,547) (185,074) (1,126,416)
----------------------------------------
Standardized Measure of Discounted
Future Net Cash Flows $ 1,255,353 $ 766,026 $ 2,409,832
========================================
-----------------------------------------------------------------------
/(1)/ Includes the future cash inflows, production costs and
development costs, as well as the tax basis, related to the
properties.
/(2)/ Future income taxes before discount were $1,195,082, $558,085,
and $2,642,810 for the years ended December 31, 2002, 2001, and
2000, 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) 2002 2001 2000
-----------------------------------------------------------------------------------------------------
Beginning of Year $ 766,026 $ 2,409,832 $ 587,557
Discoveries and Extensions,
Net of Related Future Costs 112,269 100,084 486,236
Net Changes in Prices and Production Costs /(1)/ 703,874 (2,545,349) 2,441,921
Accretion of Discount 95,110 353,625 73,782
Revisions of Previous Quantity
Estimates, Timing and Other 51,944 (358,134) (81,093)
Development Costs Incurred 20,516 26,158 28,540
Sales and Transfers, Net of Production Costs (216,555) (280,682) (167,395)
Net Purchases (Sales) of Reserves in Place (2,357) 119,149 16,440
Net Change in Income Taxes (275,474) 941,343 (976,156)
----------------------------------------------
End of Year $ 1,255,353 $ 766,026 $ 2,409,832
==============================================
-----------------------------------------------------------------------
/(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.
75
CABOT OIL & GAS CORPORATION
SELECTED DATA (UNAUDITED)
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
(In thousands, except per share amounts) First Second Third Fourth Total
------------------------------------------------------------------------------------------------------
2002
Operating Revenues $ 75,073 $ 89,584 $ 85,549 $ 103,550 $ 353,756
Impairment of Long-Lived Assets 1,063 -- -- 1,657 2,720
Operating Income 4,996 9,850 15,111 19,131 49,088
Net Income (Loss) (798) 2,121 6,125 8,655 16,103
Basic Earnings per Share $ (0.03) $ 0.07 $ 0.19 $ 0.27 $ 0.51
Diluted Earnings per Share $ (0.03) $ 0.07 $ 0.19 $ 0.27 $ 0.50
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
------------------------------------------------------------------------------------------------------
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 2002 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 AND
EQUITY COMPENSATION PLAN INFORMATION
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.
76
Equity Compensation Plan Information
The following table provides information as of December 31, 2002
regarding the number of shares of Common Stock that may be issued under the
Company's equity compensation plans. All of the Company's equity compensation
plans have been approved by the Company's stockholders.
-----------------------------------------------------------------------------------------------------
Plan Category Number of securities Weighted-average Number of securities
to be issued upon exercise price of remaining available
exercise of outstanding for future issuance
outstanding options, options, warrants and under equity
warrants and rights rights compensation plans
(excluding securities
reflected in
column (a))
-----------------------------------------------------------------------------------------------------
Equity compensation plans
approved by security 1,287,829 $21.89 1,169,979/(1)/
holders
-----------------------------------------------------------------------------------------------------
Equity compensation plans
not approved by security n/a n/a n/a
holders
-----------------------------------------------------------------------------------------------------
Total 1,287,829 $21.89 1,169,979/(1)/
-----------------------------------------------------------------------------------------------------
/(1)/ Includes 225,650 sharesof restricted stock awarded under the Second
Amended and Restated 1994 Long Term Incentive Plan, the restrictions on
which lapse over the period 2003, 2004 and 2005.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
ITEM 14. CONTROLS AND PROCEDURES
Within the 90-day period prior to the date of this report, the Company
carried out an evaluation, under the supervision and with the participation of
the Company's management, including the Company's Chief Executive Officer and
Chief Financial Officer, of the effectiveness of the design and operation of the
Company's disclosure controls and procedures pursuant to Rule 13a-14 of the
Securities Exchange Act of 1934 (the "Exchange Act"). Based upon that
evaluation, the Chief Executive Officer and Chief Financial Officer concluded
that the Company's disclosure controls and procedures are effective, in all
material respects, with respect to the recording, processing, summarizing and
reporting, within the time periods specified in the Commission's rules and
forms, of information required to be disclosed by the issuer in the reports that
it files or submits under the Exchange Act.
There have been no significant changes in the Company's internal
controls or in other factors that could significantly affect internal controls
subsequent to the date the Company carried out its evaluation.
PART IV
ITEM 15. 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.
77
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
(Form 10-K for 2001).
3.3 Certificate of Amendment of Certificate of Incorporation (Form 8-K for
July 2, 2002).
3.4 Certificate of Increase of Shares Designated Series A Junior
Participating Preferred Stock (Form 8-K for July 2, 2002).
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).
4.9 Credit Agreement dated as of October 28, 2002 among the Company, the
Banks Parties Hereto and Fleet National Bank, as administrative agent
(Form 10-Q for the quarter ended September 30, 2002).
10.1 Supplemental Executive Retirement Agreement between the Company and
Charles P. Siess, Jr. (Form 10-K for 1995).
10.2 Form of Change in Control Agreement between the Company and Certain
Officers (Form 10-K for 2001).
10.3 Letter Agreement dated January 11, 1990, between Morgan Guaranty Trust
Company of New York and the Company (Registration Statement No.
33-32553).
10.4 Form of Annual Target Cash Incentive Plan of the Company (Registration
Statement No. 33-32553).
10.5 Form of Incentive Stock Option Plan of the Company (Registration
Statement No. 33-32553).
(a) First Amendment to the Incentive Stock Option Plan
(Post-Effective Amendment No. 1 to S-8 dated April 26, 1993).
10.6 Form of Stock Subscription Agreement between the Company and certain
executive officers and directors of the Company (Registration
Statement No. 33-32553).
10.7 Transaction Agreement between Cabot Corporation and the Company dated
February 1, 1991 (Registration Statement No. 33-37455).
10.8 Tax Sharing Agreement between Cabot Corporation and the Company dated
February 1, 1991 (Registration Statement No. 33-37455).
10.9 Amendment Agreement (amending the Transaction Agreement and the Tax
Sharing Agreement) dated March 25, 1991 (incorporated by reference
from Cabot Corporation's Schedule 13E-4, Am. No. 6, File No. 5-30636).
78
Exhibit
Number Description
- --------------------------------------------------------------------------------
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 (Form 10-K for 2001).
10.16 Second Amended and Restated 1994 Non-Employee Director Stock Option
Plan (Form 10-K for 2001).
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
(Form 10-K for 2001).
10.20 Trust Agreement dated September 2000 between Harris Trust and Savings
Bank and the Company (Form 10-K for 2001).
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 (Form 10-K for 2001).
21.1 Subsidiaries of Cabot Oil & Gas Corporation.
23.1 Consent of PricewaterhouseCoopers LLP
23.2 Consent of Miller and Lents, Ltd.
23.3 Consent of Brown, Drew & Massey, LLP
28.1 Miller and Lents, Ltd. Review Letter dated February 7, 2003.
B. REPORTS ON FORM 8-K
None
79
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 18th of February 2003.
CABOT OIL & GAS CORPORATION
By: /s/ Dan O. Dinges
--------------------------------------------
Dan O. Dinges
Chairman of the Board, Chief Executive
Officer and President
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/ Dan O. Dinges Chairman of the Board, Chief Executive February 18, 2003
- -------------------------------- Officer and President
Dan O. Dinges (Principal Executive Officer)
/s/ Scott C. Schroeder Vice President, Chief Financial Officer February 18, 2003
- -------------------------------- (Principal Financial Officer)
Scott C. Schroeder
/s/ Henry C. Smyth Vice President, Controller and Treasurer February 18, 2003
- -------------------------------- (Principal Accounting Officer)
Henry C. Smyth
/s/ Robert F. Bailey Director February 18, 2003
- --------------------------------
Robert F. Bailey
/s/ Henry O. Boswell Director February 18, 2003
- --------------------------------
Henry O. Boswell
/s/ John G. L. Cabot Director February 18, 2003
- --------------------------------
John G. L. Cabot
/s/ James G. Floyd Director February 18, 2003
- --------------------------------
James G. Floyd
/s/ C. Wayne Nance Director February 18, 2003
- --------------------------------
C. Wayne Nance
/s/ P. Dexter Peacock Director February 18, 2003
- --------------------------------
P. Dexter Peacock
/s/ Arthur L. Smith Director February 18, 2003
- --------------------------------
Arthur L. Smith
/s/ William P. Vititoe Director February 18, 2003
- --------------------------------
William P. Vititoe
80
CERTIFICATIONS
I, Dan O. Dinges, certify that:
1. I have reviewed this annual report on Form 10-K of Cabot Oil & Gas
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit committee
of registrant's board of directors (or persons performing the equivalent
functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: February 21, 2003
/s/ Dan O. Dinges
----------------------------------
Dan O. Dinges
Chairman of the Board, Chief Executive
Officer and President
81
I, Scott C. Schroeder, certify that:
1. I have reviewed this annual report on Form 10-K of Cabot Oil & Gas
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit committee
of registrant's board of directors (or persons performing the equivalent
functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: February 21, 2003
/s/ Scott C. Schroeder
------------------------------------------
Scott C. Schroeder
Vice President and Chief Financial Officer
82