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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