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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
For the fiscal year ended December 31, 2001
Commission file number 1-10447
CABOT OIL & GAS CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 04-3072771
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
1200 Enclave Parkway, Houston, Texas 77077
(Address of principal executive offices including ZIP code)
(281) 589-4600
(Registrant's telephone number)
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
Class A Common Stock, par value $.10 per share New York Stock Exchange
Rights to Purchase Preferred Stock New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No _______
-----
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K [__].
The aggregate market value of Class A Common Stock, par value $.10 per
share ("Common Stock"), held by non-affiliates (based upon the closing sales
price on the New York Stock Exchange on January 31, 2002), was approximately
$636,620,000. As of January 31, 2002, there were 31,905,097 shares of Common
Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Stockholders to
be held May 2, 2002, are incorporated herein by reference in Items 10, 11, 12
and 13 of Part III of this report.
TABLE OF CONTENTS
PART I PAGE
ITEMS 1 and 2 Business and Properties 3
ITEM 3 Legal Proceedings 19
ITEM 4 Submission of Matters to a Vote of Security Holders 21
Executive Officers of the Registrant 21
PART II
ITEM 5 Market for Registrant's Common Equity and Related Stockholder Matters 22
ITEM 6 Selected Historical Financial Data 22
ITEM 7 Management's Discussion and Analysis of Financial Condition
and Results of Operations 23
ITEM 7A Quantitative and Qualitative Disclosures about Market Risk 38
ITEM 8 Financial Statements and Supplementary Data 43
ITEM 9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 78
PART III
ITEM 10 Directors and Executive Officers of the Registrant 78
ITEM 11 Executive Compensation 78
ITEM 12 Security Ownership of Certain Beneficial Owners and Management 78
ITEM 13 Certain Relationships and Related Transactions 78
PART IV
ITEM 14 Exhibits, Financial Statements, Schedules and Reports on Form 8-K 79
_____________________
The statements regarding future financial and operating performance and
results, market prices, future hedging activities, and other statements that are
not historical facts contained in this report are forward-looking statements.
The words "expect," "project," "estimate," "believe," "anticipate," "intend,"
"budget," "plan," "forecast," "predict," "may," "should," "could" and similar
expressions are also intended to identify forward-looking statements. These
statements involve risks and uncertainties, including, but not limited to,
market factors, market prices (including regional basis differentials) of
natural gas and oil, results for future drilling and marketing activity, future
production and costs, and other factors detailed in this document and in our
other Securities and Exchange Commission filings. If one or more of these risks
or uncertainties materialize, or if underlying assumptions prove incorrect,
actual outcomes may vary materially from those included in this document.
2
PART I
ITEM 1. BUSINESS
OVERVIEW
Cabot Oil & Gas is an independent oil and gas company engaged in the
exploration, development, acquisition and exploitation of oil and gas properties
located in four principal areas of the United States:
. The onshore Texas and Louisiana Gulf Coast
. The Rocky Mountains
. The Mid-Continent or Anadarko Basin
. Appalachia
Administratively, we operate in three regions - the Gulf Coast region, the
Western region, which is comprised of the Rocky Mountains and Mid-Continent
areas, and the Appalachian region.
In 2001, we enjoyed a strong energy commodity price environment for most of
the year bolstered by gains realized on price hedges which were placed on about
44% of our production for the first nine months of 2001 natural gas production
near the peak of the market in December 2000. Drilling successes, most notably
in south Louisiana, over the past two years served to increase our 2001
production by 12% over 2000. While continuing to develop our existing fields
and exploring for new discoveries, we took advantage of our strong cash flow and
invested for the future. Most significantly, we acquired Cody Company in August
2001. With this transaction, we expanded and improved our development inventory
and added 11 exploration prospects. In addition, we expanded our acreage
position with a $12 million acquisition in the Rocky Mountains and added
significantly to our seismic database in both the Rocky Mountains and Gulf
Coast. The five months of production from the acquired Cody Company properties
increased our annual production by an additional 9% over 2000, for a combined
21% production increase year-over-year.
The purchase of Cody Company was the largest acquisition in our Company's
history. We paid $231.2 million in cash and common stock for all of the
outstanding common stock of Cody Company. Substantially all of the proved
reserves of Cody Company are located in the onshore Gulf Coast region, a
strategic growth area for us. As of December 31, 2001, these properties
contributed 39.1 Mmcfe of production per day and contained 92 proved undeveloped
drilling locations.
In 2001, 87% of the wells that we drilled were successful. Drilling was
successful on 40% of our 2001 exploration wells, as we tested new ideas and
worked on building a foundation for the future. Our 2001 capital and
exploration spending included $39.1 million for seismic data and lease
acquisition. This spending will support our exploration and development
drilling programs in 2002 and beyond. As we enter 2002 energy commodity prices
have softened. We will concentrate our 2002 capital spending program on
projects offering the prospect of acceptable risk and the strongest economics.
As in the past, we will use the cash flow from our long-lived Appalachian and
Mid-Continent natural gas reserves to fund our exploration and development
efforts in the Gulf Coast and Rocky Mountain areas. We believe these two core
producing areas offer more value, accretive reserve and production growth and
higher rates of return on equity.
Our proved reserves totaled approximately 1.2 Tcfe at December 31, 2001,
of which 90% was natural gas. This reserve level represents a 13% increase over
the prior year end. The increase is due primarily to the Cody acquisition, which
combined with drilling activities, replaced production by 268%. The Gulf Coast
region now represents 26% of our total proved reserves, up from 14% at the end
of 2000.
Net income of $47.1 million, or $1.56 per share, was the highest annual
level of earnings that we have ever achieved. Cash flow from operations in 2001
of $250.4 million was also a record, and represented a 110% increase over last
year. The strong commodity price environment combined with strategic price
collars were the main factors in this year's financial success. Production
improvements as discussed above also helped boost our earnings. Daily
production averaged 199 Mmcfe per day during the first seven months of the year
before increasing to approximately
3
255 Mmcfe per day in August with the acquisition of Cody Company. Overall,
including the Cody acquisition and additional successes in south Louisiana,
production averaged 222 Mmcfe per day in 2001. Development drilling on the
Etouffee field in south Louisiana has expanded producing wells to six, two of
which were drilled in 2001. This field, which is now fully developed, remains
our largest producer and at December 31, 2001 was producing 137 Mmcfe per day
(33 Mmcfe per day net to us).
The following table presents certain information as of December 31, 2001.
West
---------------------------------
Gulf Rocky Mid- Total
Coast Mountains Continent West Appalachia Total
-------- ---------- ---------- -------- ----------- ----------
Proved Reserves at Year End (Bcfe)
Developed 224.1 176.8 171.1 347.9 324.6 896.6
Undeveloped 76.2 50.6 28.0 78.6 102.7 257.5
------- ------- ------- ------- ------- ---------
Total 300.3 227.4 199.1 426.5 427.3 1,154.1
Average Daily Production (Mmcfe per day) 97.8 45.9 30.2 76.1 48.4 222.3
Reserve Life Index (in years) /(1)/ 8.4 13.6 18.1 15.4 24.2 14.2
Gross Wells 1,013 528 695 1,223 2,362 4,598
Net Wells /(2)/ 613.2 233.0 457.7 690.7 2,190.9 3,494.8
Percent Wells Operated 72.1% 49.1% 74.1% 63.3% 96.6% 82.3%
Net Acreage
Developed 103,836 85,058 180,981 266,039 743,204 1,113,079
Undeveloped 44,008 343,565 4,868 348,433 221,316 613,757
------- ------- ------- ------- ------- ---------
Total 147,844 428,623 185,849 614,472 964,520 1,726,836
- --------------------------------------------------------------------------------
/(1)/ Reserve Life Index is equal to year-end reserves divided by annual
production.
/(2)/ The term "net" as used in "net acreage" or "net production" throughout
this document refers to amounts that include only acreage or production
that is owned by Cabot Oil & Gas and produced to its interest, less
royalties and production due others. "Net wells" represents our working
interest share of each well.
GULF COAST REGION
Our exploration, development and production activities in Gulf Coast region
are concentrated in south Louisiana and south Texas. A regional office in
Houston manages operations. Principal producing intervals are in the Wilcox and
Vicksburg formations in Texas and the Miocene age formations in Louisiana at
depths ranging from 3,000 to 20,500 feet. Capital and exploration expenditures
made with cash and common stock were $352.1 million in 2001 or 78% of our total
2001 capital and exploration expenditures, and $66.0 million for 2000. The cash
and common stock portion of the August 2001 acquisition of Cody Company
accounted for $231.2 million of this amount, which did not include a non-cash
deferred tax gross-up of $78.0 million. Our drilling and acquisition program
has increased average daily production in the region from 15.6 Mmcfe per day in
1994, when we acquired our first Gulf Coast properties from Washington Energy,
to 131.6 Mmcfe per day in December 2001. Of this production rate, 39.1 Mmcfe
per day was associated with the newly acquired Cody properties and the remaining
primarily represents production growth from our drilling activity. For 2002, we
have budgeted $56.9 million (54% of our total 2002 capital budget) for capital
expenditures in the region. Our 2002 Gulf Coast drilling program will emphasize
our exploration opportunities and development drilling on the prospects acquired
in the Cody acquisition.
We had 1,013 wells (613.2 net) in the Gulf Coast region as of December 31,
2001, of which 730 wells are operated by us. Average net daily production in
2001 was 97.8 Mmcfe, up from 49.5 Mmcfe in 2000 due both to drilling success in
south Louisiana and to the Cody acquisition. At December 31, 2001, we had 300.3
Bcfe of proved reserves (67% natural gas) in the Gulf Coast region, which
represented 26% of our total proved reserves.
In 2001, we drilled 35 wells (14.7 net) in the Gulf Coast region, of which
20 wells (7.76 net) were development wells. The south Louisiana Etouffee
prospect and our new discoveries in the Augen field in south
4
Louisiana and Red Fish Bay prospects in south Texas, together with the Cody
acquisition, contributed to the significant growth in net proved reserves. In
the Gulf Coast region, we plan to drill 19 wells in 2002 of which seven are on
prospects acquired from Cody.
At December 31, 2001, we had 147,844 net acres in the region, including
103,836 net developed, and we had identified 97 proved undeveloped drilling
locations of which 92 were part of the Cody acquisition.
Our principal markets for Gulf Coast region natural gas are in the
industrialized Gulf Coast area and the northeastern United States. Our marketing
subsidiary, Cabot Oil & Gas Marketing Corporation, purchases all of our natural
gas production in the Gulf Coast region. The marketing subsidiary sells the
natural gas to intrastate pipelines, natural gas processors and marketing
companies.
Currently, approximately 75% of our natural gas sales volumes in the Gulf
Coast region are sold at index-based prices under contracts with terms of one to
three years. The remaining 25% of our sales volumes are sold at index-based
prices under short-term agreements. From time to time when we believe market
conditions are favorable, we may implement financial hedges on a portion of our
production in an attempt to reduce our exposure to price volatility. The Gulf
Coast properties are connected to various processing plants in Texas and
Louisiana with multiple interstate and intrastate deliveries, affording us
access to multiple markets.
We also produce and market approximately 6,500 barrels per day of crude
oil/condensate in the Gulf Coast region at market responsive prices.
WESTERN REGION
Our activities in the Western region are managed by a regional office in
Denver. At December 31, 2001, we had 426.5 Bcfe of proved reserves (96% natural
gas) in the Western region, constituting 37% of our total proved reserves.
Rocky Mountains
Our Rocky Mountains activities are concentrated in the Green River Basin
and Washakie Basin of Wyoming. Since our initial acquisition in the area in 1994
from Washington Energy, we have increased reserves from 171.6 Bcfe at December
31, 1994, to 227.4 Bcfe at December 31, 2001. Capital and exploration
expenditures were $42.9 million for 2001, or 9% of our total 2001 capital and
exploration expenditures, and $23.9 million for 2000. In addition to drilling
activity, approximately $15.4 million was expended in 2001 for lease acquisition
and seismic data to provide exploration and development opportunities in the
future. For 2002, we have budgeted $19.4 million (19% of our total 2002 capital
budget) for capital expenditures in the area. The 2002 drilling program consists
of several new exploration plays complemented by development drilling.
We had 528 wells (233.0 net) in the Rocky Mountains area as of December 31,
2001, of which 259 wells are operated by us. Principal producing intervals in
the Rocky Mountains area are in the Almond, Frontier and Dakota formations at
depths ranging from 9,000 to 13,500 feet. Average net daily production in the
Rocky Mountains during 2001 was 45.9 Mmcfe.
In 2001, we drilled 31 wells (15.4 net) in the Rocky Mountains, of which 26
wells (11.5 net) were development and extension wells. In 2002, we plan to drill
41 wells.
At December 31, 2001, we had 428,623 net acres in the area, including
85,058 net developed acres, and we had identified 82 proved undeveloped drilling
locations.
5
Mid-Continent
Our Mid-Continent activities are concentrated in the Anadarko Basin in
southwestern Kansas, Oklahoma and the panhandle of Texas. Capital and
exploration expenditures were $11.5 million for 2001, or 3% of our total 2001
capital and exploration expenditures, and $7.6 million for 2000. For 2002, we
have budgeted $8.2 million (8% of our total 2002 capital budget) for capital
expenditures in the area.
As of December 31, 2001, we had 695 wells (457.7 net) in the Mid-Continent
area, of which 515 wells are operated by us. Principal producing intervals in
the Mid-Continent are in the Chase, Morrow, Red Fork and Chester formations at
depths ranging from 1,500 to 14,000 feet. Average net daily production in 2001
was 30.2 Mmcfe. At December 31, 2001, we had 199.1 Bcfe of proved reserves (97%
natural gas) in the Mid-Continent area, 17% of our total proved reserves.
In 2001, we drilled 25 wells (17.2 net) in the Mid-Continent, all of which
were development and extension wells. In 2002, we plan to drill 17 wells.
At December 31, 2001, we had 185,849 net acres in the area, including
180,981 net developed acres, and we had identified 62 proved undeveloped
drilling locations.
Western Region Marketing
Our principal markets for Western region natural gas are in the
northwestern, midwestern and northeastern United States. Cabot Oil & Gas
Marketing purchases all of our natural gas production in the Western region.
This marketing subsidiary sells the natural gas to power generators, natural gas
processors, local distribution companies, industrial customers and marketing
companies.
Currently, approximately 86% of our natural gas production in the Western
region is sold primarily under contracts with a term of one to three years at
index-based prices. Another 12% of the natural gas production is sold under
short-term arrangements at index-based prices and the remaining 2% is sold under
certain fixed-price contracts. From time to time when we believe market
conditions are favorable, we may implement financial hedges on a portion of our
production in an attempt to reduce our exposure to price volatility.. The
Western region properties are connected to the majority of the midwestern and
northwestern interstate and intrastate pipelines, affording us access to
multiple markets.
In December 1999, we negotiated the buyout of a long-term, fixed price
sales contract that covered approximately 20% of the Western region natural gas
production and was due to expire in June 2008. We received a payment of $12
million as part of this contract buyout agreement. This contract was then
replaced with a fixed price sales contract that expired in April 2001. The fixed
natural gas sales price in both the original natural gas sales contract and the
replacement sales contract was below the market price at year end 2000. After
April 2001, this production was sold at market responsive prices.
We currently also produce and market approximately 600 barrels of crude
oil/condensate per day in the Western region at market responsive prices.
APPALACHIAN REGION
Our Appalachian activities are concentrated in West Virginia, Pennsylvania,
Ohio and Virginia. In this region, our assets include a large undeveloped
acreage position, a high concentration of wells, natural gas gathering and
pipeline systems, and storage capacity. We have achieved a drilling success rate
of 89% in the region since 1991. Capital and exploration expenditures were $44.1
million for 2001, or 10% of our total 2001 capital spending, and $21.5 million
for 2000. For 2002, we have budgeted $18.5 million (18% of our total 2002
capital budget) for capital expenditures in the region.
At December 31, 2001, we had 2,362 wells (2,190.9 net), of which 2,281
wells are operated by us. There are multiple producing intervals that include
the Devonian Shale, Oriskany, Berea and Big Lime formations at depths
6
primarily ranging from 1,500 to 9,000 feet. Average net daily production in 2001
was 48.4 Mmcfe. While natural gas production volumes from Appalachian reservoirs
are relatively low on a per-well basis compared to other areas of the United
States, the productive life of Appalachian reserves is relatively long. At
December 31, 2001, we had 427.3 Bcfe of proved reserves (substantially all
natural gas) in the Appalachian region, constituting 37% of our total proved
reserves. This region is managed from our office in Charleston, West Virginia.
In 2001, we drilled 117 wells (106.3 net) in the Appalachian region, of
which 107 wells (97.0 net) were development wells. In 2002, we plan to drill 44
wells.
At December 31, 2001, we had 964,520 net acres in the region, including
743,204 net developed, and we had identified 292 proved undeveloped drilling
locations.
Ancillary to our exploration and production operations, we operate a number
of gas gathering and transmission pipeline systems, made up of approximately
2,500 miles of pipeline with interconnects to three interstate transmission
systems, seven local distribution companies and numerous end users as of the end
of 2001. The majority of our pipeline infrastructure in West Virginia is
regulated by the Federal Energy Regulatory Commission (FERC). As such, the
transportation rates and terms of service of our pipeline subsidiary, Cranberry
Pipeline Corporation, are subject to the rules and regulations of the FERC. Our
natural gas gathering and transmission pipeline systems enable us to connect new
wells quickly and to transport natural gas from the wellhead directly to
interstate pipelines, local distribution companies and industrial end users.
Control of our gathering and transmission pipeline systems also enables us to
purchase, transport and sell natural gas produced by third parties. In addition,
we can engage in development drilling without relying upon third parties to
transport our natural gas and incur only the incremental costs of pipeline and
compressor additions to our system.
We have two natural gas storage fields located in West Virginia with a
combined working capacity of approximately 4 Bcf. We use these storage fields to
take advantage of the seasonal variations in the demand for natural gas and the
higher prices typically associated with winter natural gas sales, while
maintaining production at a nearly constant rate throughout the year. The
storage fields also enable us to periodically increase the volume of natural gas
that we can deliver by more than 40% above the volume that we could deliver
solely from our production in the Appalachian region. The pipeline systems and
storage fields are fully integrated with our operations.
In addition, we own and operate two brine treatment plants that process and
treat waste fluid generated during the drilling, completion and production of
oil and gas wells. The first plant, near Franklin, Pennsylvania, began operating
in 1985. It provides services primarily to other oil and gas producers in
southwestern New York, eastern Ohio and western Pennsylvania. In April 1998, we
acquired a second brine treatment plant in Indiana, Pennsylvania that had been
in existence since 1987.
Appalachian Region Marketing
The principal markets for our Appalachian region natural gas are in the
northeastern United States. Cabot Oil & Gas Marketing purchases our natural gas
production in the Appalachian region as well as production from local third-
party producers and other suppliers to aggregate larger volumes of natural gas
for resale. This marketing subsidiary sells natural gas to industrial customers,
local distribution companies and gas marketers both on and off our pipeline and
gathering system.
Approximately 65% of our natural gas sales volume in the Appalachian region
is sold at index-based prices under contracts with a term of one to two years.
In addition, spot market sales are made under month-to-month contracts, while
industrial and utility sales generally are made under year-to-year contracts.
Approximately 5% of Appalachian production is sold on fixed price contracts that
typically renew annually. From time to time, we may also use financial hedges on
a portion of our production to reduce the potential risk of falling prices when
we believe market conditions are favorable.
Our Appalachian natural gas production has historically sold at a higher
realized price, or premium, compared to production from other producing regions
due to its proximity to northeastern markets. While year-to-year fluctuations in
that premium are normal due to changes in market conditions, throughout the
1990's this
7
premium has typically been in the range of $0.40 to $0.50 per Mmbtu above the
Henry Hub index spot price as published by Inside FERC's Gas Market Report for
gas delivered to this point. This index is the basis for sales price in our
standard natural gas sales contract. In 1999, however, the average premium
declined to $0.27 per Mmbtu due to increases in supply in the eastern market.
This decline continued into early 2000. However, late in 2000 and into 2001, the
premium began to increase again due to strengthening of demand and perceived
market shortages. The average 2001 premium was approximately $0.34 per Mmbtu.
Due to this continued volatility, we are not able to predict the level of this
premium for the future.
RISK MANAGEMENT
From time to time, when we believe that market conditions are favorable, we
use certain financial instruments called derivatives to manage price risks
associated with our production and brokering activities. While there are many
different types of derivatives available, in 2001 we primarily employed natural
gas and oil price swap and costless collar agreements to attempt to manage price
risk more effectively. The price swaps call for payments to, or receipts from,
counterparties based on whether the market price of natural gas for the period
is greater or less than the fixed price established for that period when the
swap is put in place. The costless collar arrangements are put and call options
used to establish floor and ceiling commodity prices for a fixed volume of
production during a certain time period. They provide for payments to
counterparties if the index price exceeds the ceiling and payments from the
counterparties if the index price is below the floor.
In December 2000, we entered into certain costless collar arrangements on
half of our natural gas production for the months of February through October
2001. We realized revenue of $34.6 million under these arrangements. In December
2001, we again entered into price collar arrangements for 60% of our anticipated
natural gas production for the months of January through April 2002. We will
continue to evaluate the benefit of employing derivatives in the future. Please
read Management's Discussion and Analysis of Financial Condition and Results of
Operations - Commodity Price Swaps and Options for further discussion concerning
our use of derivatives.
RESERVES
Current Reserves
The following table presents our estimated proved reserves at December 31,
2001.
Natural Gas (Mmcf) Liquids/(1)/ (Mbbl) Total/(2)/(Mmcfe)
- -----------------------------------------------------------------------------------------------------------------------
Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total
- -----------------------------------------------------------------------------------------------------------------------
Gulf Coast 148,692 53,734 202,426 12,567 3,744 16,311 224,096 76,198 300,294
Rocky Mountains 167,067 47,717 214,784 1,618 482 2,100 176,774 50,610 227,384
Mid-Continent 166,198 27,236 193,434 817 130 947 171,098 28,018 199,116
Appalachia 322,689 102,671 425,360 326 -- 326 324,644 102,671 427,315
----------------------------------------------------------------------------------------------------
Total 804,646 231,358 1,036,004 15,328 4,356 19,684 896,612 257,497 1,154,109
====================================================================================================
- --------------------------------------------------------------------------------
/(1)/ Liquids include crude oil, condensate and natural gas liquids (Ngl).
/(2)/ Natural gas equivalents are determined using the ratio of 6 Mcf of natural
gas to 1 Bbl of crude oil, condensate or natural gas liquids.
The proved reserve estimates presented here were prepared by our petroleum
engineering staff and reviewed by Miller and Lents, Ltd., independent petroleum
engineers. For additional information regarding estimates of proved reserves,
the review of such estimates by Miller and Lents, Ltd., and other information
about our oil and gas reserves, see the Supplemental Oil and Gas Information to
the Consolidated Financial Statements included in Item 8. A copy of the review
letter by Miller and Lents, Ltd. has been filed as an exhibit to this Form 10-K.
Our estimates of proved reserves in the table above are consistent with those
filed by us with other federal agencies. Our reserves are sensitive to natural
gas and crude oil sales prices and their effect on economic producing rates. Our
reserves are based on oil and gas index prices in effect on the last day of
December 2001.
There are a number of uncertainties inherent in estimating quantities of
proved reserves, including many
8
factors beyond our control such as commodity pricing. Therefore, the reserve
information in this Form 10-K represents only estimates. Reserve engineering is
a subjective process of estimating underground accumulations of crude oil and
natural gas that can not be measured in an exact manner. The accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. As a result, estimates
of different engineers often vary. In addition, results of drilling, testing and
production subsequent to the date of an estimate may justify revising the
original estimate. Accordingly, initial reserve estimates are often different
from the quantities of crude oil and natural gas that are ultimately recovered.
The meaningfulness of such estimates depends primarily on the accuracy of the
assumptions upon which they were based. In general, the volume of production
from oil and gas properties declines as reserves are depleted. Except to the
extent we acquire additional properties containing proved reserves or conduct
successful exploration and development activities or both, our proved reserves
will decline as reserves are produced.
9
Historical Reserves
The following table presents our estimated proved reserves for the periods
indicated.
Natural Gas Oil & Liquids Total
(Mmcf) (Mbbl) (Mmcfe)/(1)/
--------------------------------------------------------------
December 31, 1998 996,756 7,677 1,042,819
--------------------------------------------------------------
Revision of Prior Estimates (1,555) 128 (787)
Extensions, Discoveries and
Other Additions 52,781 1,292 60,535
Production (65,502) (963) (71,279)
Purchases of Reserves in Place 26,515 361 28,685
Sales of Reserves in Place (79,393) (306) (81,232)
--------------------------------------------------------------
December 31, 1999 929,602 8,189 978,741
--------------------------------------------------------------
Revision of Prior Estimates (14,796) 562 (11,423)
Extensions, Discoveries and
Other Additions 103,600 2,032 115,792
Production (60,934) (988) (66,872)
Purchases of Reserves in Place 5,118 120 5,838
Sales of Reserves in Place (3,368) (1) (3,373)
--------------------------------------------------------------
December 31, 2000 959,222 9,914 1,018,703
--------------------------------------------------------------
Revision of Prior Estimates (44,266) 254 (42,737)
Extensions, Discoveries and
Other Additions 99,911 2,257 113,456
Production (69,162) (1,996) (81,139)
Purchases of Reserves in Place 91,290 9,255 146,819
Sales of Reserves in Place (991) -- (993)
--------------------------------------------------------------
December 31, 2001 1,036,004 19,684 1,154,109
==============================================================
Proved Developed Reserves
December 31, 1998 788,390 5,822 823,321
December 31, 1999 720,670 5,546 753,944
December 31, 2000 754,962 8,438 805,590
December 31, 2001 804,646 15,328 896,612
________________________________________________________________________________
/(1)/ Includes natural gas and natural gas equivalents determined by using the
ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural
gas liquids.
10
Volumes and Prices; Production Costs
The following table presents regional historical information about our net
wellhead sales volume for natural gas and oil (including condensate and natural
gas liquids), produced natural gas and oil sales prices, and production costs
per equivalent.
Year Ended December 31,
2001 2000 1999
-------------------------------------------------------------------------
Net Wellhead Sales Volume
Natural Gas (Bcf)
Gulf Coast 25.6 14.1 15.5
West 26.2 29.0 29.3
Appalachia 17.4 17.8 20.7
Crude/Condensate/Ngl (Mbbl)
Gulf Coast 1,694 669 579
West 267 289 341
Appalachia 35 32 43
Produced Natural Gas Sales Price ($/Mcf)/(1)/
Gulf Coast $ 4.44 $ 3.79 $ 2.29
West 3.88 2.86 1.96
Appalachia 4.96 3.24 2.53
Weighted Average 4.36 3.19 2.22
Crude/Condensate Sales Price ($/Bbl)/(1)/ $24.91 $26.81 $17.22
Production Costs ($/Mcfe)/(2)/ $ 0.72 $ 0.70 $ 0.59
________________________________________________________________________________
/(1)/ Represents the average sales prices (net of hedge activity) for all
production volumes (including royalty volumes) sold by Cabot Oil & Gas
during the periods shown net of related costs (principally purchased gas
royalty, transportation and storage).
/(2)/ Production costs include direct lifting costs (labor, repairs and
maintenance, materials and supplies), and the costs of administration of
production offices, insurance and property and severance taxes, but is
exclusive of depreciation and depletion applicable to capitalized lease
acquisition, exploration and development expenditures.
11
Acreage
The following tables summarize our gross and net developed and undeveloped
leasehold and mineral acreage at December 31, 2001. Acreage in which our
interest is limited to royalty and overriding royalty interests is excluded.
Leasehold Acreage
Developed Undeveloped Total
-------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
-------------------------------------------------------------------------------------
State
Alabama 1,976 374 -- -- 1,976 374
Colorado 14,263 13,359 190,529 92,799 204,792 106,158
Kansas 29,067 27,765 -- -- 29,067 27,765
Kentucky 2,266 901 -- -- 2,266 901
Louisiana 53,408 41,468 24,314 12,983 77,722 54,451
Michigan 739 205 6,823 6,773 7,562 6,978
Montana 397 210 44,288 33,552 44,685 33,762
New York 2,956 1,117 436 155 3,392 1,272
New Mexico 480 96 -- -- 480 96
North Dakota -- -- 870 96 870 96
Ohio 6,288 2,389 9,225 7,361 15,513 9,750
Oklahoma 161,665 111,923 6,642 3,489 168,307 115,412
Pennsylvania 128,862 78,772 40,916 36,908 169,778 115,680
Texas 153,385 88,781 69,974 32,002 223,359 120,783
Utah 1,740 530 129,044 88,125 130,784 88,655
Virginia 22,195 20,072 7,606 4,981 29,801 25,053
West Virginia 577,372 542,752 170,168 113,241 747,540 655,993
Wyoming 141,733 70,959 197,622 128,912 339,355 199,871
--------------------------------------------------------------
Total 1,298,792 1,001,673 898,457 561,377 2,197,249 1,563,050
==============================================================
Mineral Fee Acreage
Developed Undeveloped Total
-------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
-------------------------------------------------------------------------------------
State
Colorado -- -- 160 6 160 6
Kansas 160 128 -- -- 160 128
Louisiana 628 276 -- -- 628 276
Montana -- -- 589 75 589 75
New York -- -- 4,281 1,070 4,281 1,070
Oklahoma 16,580 13,979 400 76 16,980 14,055
Pennsylvania 86 86 2,367 1,296 2,453 1,382
Texas 27 27 652 326 679 353
Virginia 17,817 17,817 100 34 17,917 17,851
West Virginia 97,455 79,093 50,458 49,497 147,913 128,590
--------------------------------------------------------------
Total 132,753 111,406 59,007 52,380 191,760 163,786
==============================================================
Aggregate Total 1,431,545 1,113,079 957,464 613,757 2,389,009 1,726,836
==============================================================
12
Total Net Acreage by Region of Operation
Developed Undeveloped Total
--------------------------------------------------------------------
Gulf Coast 103,836 44,008 147,844
West 266,039 348,433 614,472
Appalachia 743,204 221,316 964,520
-------------------------------------------
Total 1,113,079 613,757 1,726,836
===========================================
Well Summary
The following table presents our ownership at December 31, 2001, in natural
gas and oil wells in the Gulf Coast region (consisting of various fields located
in Louisiana and Texas), in the Western region (consisting of various fields
located in Oklahoma, Kansas, Colorado and Wyoming) and in the Appalachian region
(consisting of various fields located in West Virginia, Pennsylvania, Virginia
and Ohio). This summary includes natural gas and oil wells in which we have a
working interest or a reversionary interest as in the case of certain Section 29
tight sands and Devonian shale wells.
Natural Gas Oil Total
Gross Net Gross Net Gross Net
----------------------------------------------------------
Gulf Coast 613 375.6 400 237.6 1,013 613.2
West 1,152 652.4 71 38.3 1,223 690.7
Appalachia 2,339 2,180.0 23 10.9 2,362 2,190.9
--------------------------------------------
Total 4,104 3,208.0 494 286.8 4,598 3,494.8
============================================
Drilling Activity
We drilled wells, participated in the drilling of wells, or acquired wells
as indicated in the regional tables below.
Year Ended December 31,
2001 2000 1999
--------------------------------------------------------------------
Gross Net Gross Net Gross Net
--------------------------------------------------------------------
Gulf Coast
Development Wells
Successful 18 7.0 14 6.3 10 6.2
Dry 1 0.6 3 1.7 3 3.0
Extension Wells
Successful 1 0.1 -- -- -- --
Dry -- -- -- -- -- --
Exploratory Wells
Successful 8 4.6 4 2.2 2 0.6
Dry 7 2.4 2 1.0 1 0.5
----------------------------------------
Total 35 14.7 23 11.2 16 10.3
========================================
Wells Acquired/(1)/ 600 334.0 1 0.6 2 0.6
Wells in Progress at End
of Period 5 3.6 2 1.1 1 0.3
13
Year Ended December 31,
2001 2000 1999
------------------------------------------------------------------------
Gross Net Gross Net Gross Net
------------------------------------------------------------------------
West
Development Wells
Successful 43 24.9 33 22.7 19 9.0
Dry 3 1.5 3 1.0 1 1.0
Extension Wells
Successful 5 2.4 7 3.9 1 0.3
Dry -- -- -- -- -- --
Exploratory Wells
Successful 1 0.8 1 0.3 -- --
Dry 4 3.0 1 0.5 2 1.3
--------------------------------------------
Total 56 32.6 45 28.4 23 11.6
============================================
Wells Acquired/(1)/ 10 0.1 1 0.4 27 10.7
Wells in Progress at End
of Period -- -- 4 2.7 5 2.3
Year Ended December 31,
2001 2000 1999
------------------------------------------------------------------------
Gross Net Gross Net Gross Net
------------------------------------------------------------------------
Appalachia
Development Wells
Successful 102 93.0 47 41.5 26 19.0
Dry 5 4.0 5 4.2 1 0.5
Extension Wells
Successful -- -- -- -- -- --
Dry -- -- -- -- -- --
Exploratory Wells
Successful 3 3.0 5 3.8 3 2.0
Dry 7 6.3 4 2.5 4 2.0
--------------------------------------------
Total 117 106.3 61 52.0 34 23.5
============================================
Wells Acquired/(1)/ 19 19.0 -- -- -- --
Wells in Progress at End
of Period -- -- 3 3.0 1 0.3
---------------------------------------------------------------------------
/(1)/ Includes the acquisition of net interest in certain wells in which we
already held an ownership interest. Does not include certain
interests in Section 29 tight sands and Devonian shale wells
purchased and then resold during 1999.
Competition
Competition in our primary producing areas is intense. Price, contract
terms and quality of service, including pipeline connection times, distribution
efficiencies and reliable delivery records, affect competition. We believe that
our extensive acreage position, existing natural gas gathering and pipeline
systems and storage fields enhance our competitive position over other producers
in the Appalachian region who do not have similar systems or facilities in
place. We also believe that our competitive position in the Appalachian region
is enhanced by the lack of significant competition from major oil and gas
companies. We also actively compete against other companies with substantially
larger financial and other resources, particularly in the Western and Gulf Coast
regions.
14
OTHER BUSINESS MATTERS
Major Customer
We had no sales to any customer that exceeded 10% of our total gross
revenues in 2001, 2000 or 1999.
Seasonality
Demand for natural gas has historically been seasonal, with peak demand and
typically higher prices occurring during the colder winter months.
Regulation of Oil and Natural Gas Exploration and Production
Exploration and production operations are subject to various types of
regulation at the federal, state and local levels. Such regulation includes
requiring permits to drill wells, maintaining bonding requirements to drill or
operate wells, and regulating the location of wells, the method of drilling and
casing wells, the surface use and restoration of properties on which wells are
drilled, and the plugging and abandoning of wells. Our operations are also
subject to various conservation laws and regulations. These include the
regulation of the size of drilling and spacing units or proration units, the
density of wells which may be drilled in a given field, and the unitization or
pooling of oil and natural gas properties. Some states allow the forced pooling
or integration of tracts to facilitate exploration while other states rely on
voluntary pooling of lands and leases. In addition, state conservation laws
establish maximum rates of production from oil and natural gas wells, generally
prohibiting the venting or flaring of natural gas, and imposing certain
requirements regarding the ratability of production. The effect of these
regulations is to limit the amounts of oil and natural gas we can produce from
our wells, and to limit the number of wells or the locations where we can drill.
Because these statutes, rules and regulations undergo constant review and often
are amended, expanded and reinterpreted, we are unable to predict the future
cost or impact of regulatory compliance. The regulatory burden on the oil and
gas industry increases its cost of doing business and, consequently, affects its
profitability. We do not believe, however, we are affected materially
differently by these regulations than others in the industry.
Natural Gas Marketing, Gathering and Transportation
Federal legislation and regulatory controls have historically affected the
price of the natural gas produced and the manner in which such production is
transported and marketed. Under the Natural Gas Act of 1938, the FERC regulates
the interstate sale and transportation of natural gas for resale. The FERC's
jurisdiction over interstate natural gas sales was substantially modified by the
Natural Gas Policy Act of 1978 (NGPA), under which the FERC continued to
regulate the maximum selling prices of certain categories of gas sold in "first
sales" in interstate and intrastate commerce. Effective January 1, 1993,
however, the Natural Gas Wellhead Decontrol Act (Decontrol Act) deregulated
natural gas prices for all "first sales" of natural gas, including all sales of
our own production. As a result, all of our produced natural gas may now be
sold at market prices, subject to the terms of any private contracts that may be
in effect. The FERC's jurisdiction over natural gas transportation and the sale
for resale of natural gas in interstate commerce was not affected by the
Decontrol Act.
Natural gas sales are affected by intrastate and interstate gas
transportation regulation. Beginning with Order No. 436 in 1985 and continuing
through Order No. 636 in 1992, the FERC adopted regulatory changes that have
significantly altered the transportation and marketing of natural gas. These
changes were intended by the FERC to foster competition by, among other things,
transforming the role of interstate pipeline companies from wholesale marketers
of gas to the primary role of gas transporters. Order No. 636 required that
interstate pipelines generally cease making sales of natural gas. At the same
time, FERC retained its statutory jurisdiction over the sale for resale of
natural gas in interstate commerce, but issued to all entities (except
interstate pipelines) a blanket certificate to make sales for resale of natural
gas in interstate commerce at market based prices. As a result, pipelines
divested their gas sales functions to marketing affiliates, which operate
separately from the transporter and in direct competition with all other
merchants. Interstate pipelines are now required to provide open and
nondiscriminatory transportation and transportation-related services to all
producers, gas marketing companies, local distribution companies, industrial end
users and other customers seeking service. The FERC expanded the impact of open
access
15
regulations to intrastate commerce through its implementation of the NGPA
provisions allowing intrastate pipelines to provide service in intrastate
commerce on behalf of interstate pipelines.
More recently, the FERC has pursued other policy initiatives that have
affected natural gas marketing. Most notable are (1) the large-scale
divestiture of interstate pipeline-owned gas gathering facilities to affiliated
or non-affiliated companies, which is a result of the FERC's requirement in
Order No. 636 that interstate pipelines unbundle gathering services from
transportation services, (2) further development of rules governing the
relationship of the pipelines with their marketing affiliates, (3) the
publication of standards relating to the use of electronic bulletin boards and
electronic data exchange by the pipelines to make available transportation
information on a timely basis and to enable transactions to occur on a purely
electronic basis, and (4) development of policy and promulgation of orders
pertaining to its authorization of market-based rates (rather than traditional
cost-of-service based rates) for transportation or transportation-related
services upon a showing of lack of market control in the relevant service
market.
The FERC continued its efforts to develop a competitive natural gas market
with Order No. 637, issued in 2000. Order No. 637 modifies FERC regulations to:
(1) lift the cost-based cap on pipeline transportation rates in the capacity
release market until September 30, 2002, for releases of pipeline capacity for
periods less than one year; (2) permit pipelines to file for authority to charge
different maximum cost-based rates for peak and off-peak periods; (3) encourage
auctions for pipeline capacity; (4) require that pipelines implement imbalance
management services for shippers; (5) restrict the ability of pipelines to
impose penalties for imbalances, overruns, and non-compliance with operational
flow orders; and (6) implement a number of new pipeline reporting requirements
to enhance market transparency. These Order No. 637 requirements are being
implemented by pipelines through individual tariff reform filings. Order No.
637 also requires the FERC Staff to analyze whether the FERC should develop
additional fundamental policy changes, including whether to pursue performance-
based or other non-cost based ratemaking methods and whether the FERC should
mandate greater standardization in terms and conditions of service across the
interstate pipeline grid.
As a result of these changes, sellers and buyers of gas have gained direct
access to the particular pipeline services they need and are better able to
conduct business with a larger number of counterparties. We believe these
changes generally have improved our access to markets while, at the same time,
substantially increasing competition in the natural gas marketplace.
We can not predict what new or different regulations the FERC and other
regulatory agencies may adopt, or what effect subsequent regulations may have on
our activities. Similarly, it is impossible to predict what proposals, if any,
that affect the oil and natural gas_industry might actually be enacted by
Congress or the various state legislatures and what effect, if any, such
proposals might have on us. Similarly, and despite the trend toward federal
deregulation of the natural gas industry, whether or to what extent that trend
will continue, or what the ultimate effect will be on our sales of gas, can not
be predicted.
Our pipeline systems and storage fields in West Virginia are regulated for
safety compliance by the U.S. Department of Transportation and the West Virginia
Public Service Commission.
Federal Regulation of Petroleum
Our sales of oil and natural gas liquids are not regulated and are at
market prices. The price received from the sale of these products is affected
by the cost of transporting the products to market. Much of that transportation
is through interstate common carrier pipelines. Effective January 1, 1995, the
FERC implemented regulations generally grandfathering all previously approved
interstate transportation rates and establishing an indexing system for those
rates by which adjustments are made annually based on the rate of inflation,
subject to certain conditions and limitations. These regulations may tend to
increase the cost of transporting oil and natural gas liquids by interstate
pipeline, although the annual adjustments may result in decreased rates in a
given year. These regulations have generally been approved on judicial review.
Every five years, the FERC must examine the relationship between the annual
change in the applicable index and the actual cost changes experienced in the
oil pipeline industry. The first such review has been completed and on December
14, 2000, the FERC reaffirmed the current index. We are not able to predict
with certainty the effect upon us of these relatively new federal regulations or
of the periodic
16
review by the FERC of the index.
Environmental Regulations
General. Our operations are subject to extensive federal, state and local
laws and regulations relating to the generation, storage, handling, emission,
transportation and discharge of materials into the environment. Permits are
required for the operation of our various facilities. These permits can be
revoked, modified or renewed by issuing authorities. Governmental authorities
enforce compliance with their regulations through fines, injunctions or both.
Government regulations can increase the cost of planning, designing, installing
and operating oil and gas facilities. Although we believe that compliance with
environmental regulations will not have a material adverse effect on us, risks
of substantial costs and liabilities related to environmental compliance issues
are part of oil and gas production operations. No assurance can be given that
significant costs and liabilities will not be incurred. Also, it is possible
that other developments, such as stricter environmental laws and regulations,
and claims for damages to property or persons resulting from oil and gas
production could result in substantial costs and liabilities to us.
Solid and Hazardous Waste. We currently own or lease, and have in the past
owned or leased, numerous properties that were used for the production of oil
and gas for many years. Although operating and disposal practices that were
standard in the industry at the time may have been utilized, it is possible that
hydrocarbons or other solid wastes may have been disposed of or released on or
under the properties currently owned or leased by us. State and federal laws
applicable to oil and gas wastes and properties have become more strict over
time. Under these increasingly stringent requirements, we could be required to
remove or remediate previously disposed wastes (including wastes disposed or
released by prior owners and operators) or clean up property contamination
(including groundwater contamination by prior owners or operators) or to perform
plugging operations to prevent future contamination.
We generate some hazardous wastes that are already subject to the Federal
Resource Conservation and Recovery Act (RCRA) and comparable state statutes.
The Environmental Protection Agency (EPA) has limited the disposal options for
certain hazardous wastes. It is possible that certain wastes currently exempt
from treatment as hazardous wastes may in the future be designated as hazardous
wastes under RCRA or other applicable statutes. We could, therefore, be subject
to more rigorous and costly disposal requirements in the future than we
encounter today.
Superfund. The Comprehensive Environmental Response, Compensation, and
Liability Act (CERCLA), also known as the "Superfund" law, imposes liability,
without regard to fault or the legality of the original conduct, on certain
persons with respect to the release of hazardous substances into the
environment. These persons include the owner and operator of a site and any
party that disposed of or arranged for the disposal of hazardous substances
found at a site. CERCLA also authorizes the EPA, and in some cases, private
parties, to undertake actions to clean up such hazardous substances, or to
recover the costs of such actions from the responsible parties. In the course
of business, we have generated and will continue to generate wastes that may
fall within CERCLA's definition of hazardous substances. We may also be an
owner or operator of sites on which hazardous substances have been released. As
a result, we may be responsible under CERCLA for all or part of the costs to
clean up sites where such wastes have been disposed. See Item 3 Legal
Proceedings for a discussion of the Casmalia Superfund Site.
Oil Pollution Act. The federal Oil Pollution Act of 1990 (OPA) and
resulting regulations impose a variety of obligations on responsible parties
related to the prevention of oil spills and liability for damages resulting from
such spills in waters of the United States. The term "waters of the United
States" has been broadly defined to include inland water bodies, including
wetlands and intermittent streams. The OPA assigns liability to each
responsible party for oil removal costs and a variety of public and private
damages.
Clean Water Act. The Federal Water Pollution Control Act (FWPCA or Clean
Water Act) and resulting regulations, which are implemented through a system of
permits, also govern the discharge of certain contaminants into waters of the
United States. Sanctions for failure to comply strictly with the Clean Water
Act are generally resolved by payment of fines and correction of any identified
deficiencies. However, regulatory agencies could require us to cease
construction or operation of certain facilities that are the source of water
discharges. We believe that we comply with the Clean Water Act and related
federal and state regulations in all material respects.
17
Clean Air Act. Our operations are subject to local, state and federal laws
and regulations to control emissions from sources of air pollution. Payment of
fines and correction of any identified deficiencies generally resolve penalties
for failure to comply strictly with air regulations or permits. Regulatory
agencies could also require us to cease construction or operation of certain
facilities that are air emission sources. We believe that we substantially
comply with the emission standards under local, state, and federal laws and
regulations.
Employees
As of December 31, 2001, Cabot Oil & Gas had 366 active employees. We
recognize that our success is significantly influenced by the relationship we
maintain with our employees. Overall, we believe that our relations with our
employees are satisfactory. The Company and its employees are not represented
by a collective bargaining agreement.
Other
Our profitability depends on certain factors that are beyond our control,
such as natural gas and crude oil prices. Please see Items 7 and 7A. We face a
variety of hazards and risks that could cause substantial financial losses. Our
business involves a variety of operating risks, including blowouts, cratering,
explosions and fires, mechanical problems, uncontrolled flows of oil, natural
gas or well fluids, formations with abnormal pressures, pollution and other
environmental risks, and natural disasters. We conduct operations in shallow
offshore areas, which are subject to additional hazards of marine operations,
such as capsizing, collision and damage from severe weather.
Our operation of natural gas gathering and pipeline systems also involves
various risks, including the risk of explosions and environmental hazards caused
by pipeline leaks and ruptures. Any of these events could result in loss of
human life, significant damage to property, environmental pollution, impairment
of our operations and substantial losses to us. The location of pipelines near
populated areas, including residential areas, commercial business centers and
industrial sites, could increase these risks. In accordance with customary
industry practice, we maintain insurance against some, but not all, of these
risks and losses. The occurrence of any of these events not fully covered by
insurance could have a material adverse effect on our financial position and
results of operations. The costs of these insurance policies are somewhat
dependent on our historical claims experience and also the areas in which we
choose to operate. During the past few years, we have drilled a higher
percentage of our wells in the Gulf Coast, where insurance rates are
significantly higher than in other regions such as Appalachia. At December 31,
2001, we owned or operated approximately 2,900 miles of natural gas gathering
and transmission pipeline systems throughout the United States. As part of our
normal maintenance program, we have identified certain segments of our pipelines
that we believe may require repair, replacement or additional maintenance and we
schedule this maintenance as appropriate.
The sale of our oil and gas production depends on a number of factors
beyond our control. The factors include the availability and capacity of
transportation and processing facilities. Our failure to access these facilities
and obtain these services on acceptable terms could materially harm our
business.
ITEM 2. PROPERTIES
See Item 1. Business.
18
ITEM 3. LEGAL PROCEEDINGS
We are a party to various legal proceedings arising in the normal course of
our business. All known liabilities are fully accrued based on management's
best estimate of the potential loss. In management's opinion, final judgments
or settlements, if any, which may be awarded in connection with any one or more
of these suits and claims would not have a significant impact on the results of
operations, financial position or cash flows of any period.
Environmental Liability
The EPA notified us in February 2000 of our potential liability for waste
material disposed of at the Casmalia Superfund Site ("Site"), located on a 252-
acre parcel in Santa Barbara County, California. Over 10,000 separate parties
disposed of waste at the Site while it was operational from 1973 to 1992. The
EPA stated that federal, state and local governmental agencies along with the
numerous private entities that used the Site for disposal of approximately 4.5
billion pounds of waste would be expected to pay the clean-up costs, which are
estimated by the EPA to be $271.9 million. The EPA is also pursuing the
owners/operators of the Site to pay for remediation.
Documents received by us with the notification from the EPA indicate that
we used the Site principally to dispose of salt water from two wells over a
period from 1976 to 1979. There is no allegation that we violated any laws in
the disposal of material at the Site. The EPA's actions stem from the fact that
the owners/operators of the Site do not have the financial means to implement a
closure plan for the Site.
A group of potentially responsible parties, including us, formed a group
called the Casmalia Negotiating Committee ("CNC"). The CNC has had extensive
settlement discussions with the EPA and has reached a settlement in principal to
pay approximately $27 million toward Site clean up in return for a release from
liability. The CNC is currently negotiating a consent decree to memorialize the
settlement. On January 30, 2002, we placed $1,283,283 in an escrow account. This
amount approximates our volumetric share of EPA's cost estimate, plus a 5%
premium and is our settlement amount. The escrow account is being funded by us
and many other CNC members to maximize the likelihood that there will be
sufficient funds to fund the settlement agreement upon its completion, which is
expected later in 2002. This cash settlement, once released from escrow and paid
to the federal government, will resolve all federal claims against us for
response costs and will release us from all response costs related to the Site,
except for future claims against us for natural resource damage, unknown
conditions, transshipment risks and claims by third parties, all of which are
expected to be covered by insurance to be purchased by participating CNC
members. Responsibility for certain State of California oversight and response
costs, while not covered by the settlement or insurance, are not expected to be
material. No determination has been made as to whether any insurance arrangement
will allow us to recover our contribution to the settlement.
We have established a reserve that management believes to be adequate to
provide for this environmental liability based on its estimate of the probable
outcome of this matter and estimated legal costs.
Wyoming Royalty Litigation
In June 2000, two overriding royalty owners sued us in Wyoming State court
for unspecified damages. The plaintiffs have requested class certification
under the Wyoming Rules of Civil Procedure and allege that we have deducted
improper costs of production from royalty payments to the plaintiffs and other
similarly situated persons. Additionally, the suit claims that we have failed
to properly inform the plaintiffs and other similarly situated persons of the
deductions taken from royalties. In December 2001, fourteen overriding royalty
owners sued us in Wyoming federal court. The plaintiffs in the federal case
have made the same general claims pertaining to deductions from their overriding
royalty as the plaintiffs in the Wyoming state court case but have not asked for
class certification.
Management believes that we have substantial defenses to these claims and
intends to vigorously assert such defenses. We have a reserve that we believe
is adequate to provide for these potential liabilities based on our estimate of
the probable outcome of this matter. While the potential impact to us may
materially affect quarterly or annual financial results including cash flows,
management does not believe it would materially impact our financial position or
results of operations.
19
West Virginia Royalty Litigation
In late December 2001, two royalty owners sued us in West Virginia State
court for an unspecified amount of damages. The plaintiffs have requested class
certification under the West Virginia Rules of Civil Procedure and allege that
we have failed to pay royalty based upon the wholesale market value of the gas
produced, that we have taken improper deductions from the royalty and that we
have failed to properly inform the plaintiffs and other similarly situated
persons of deductions taken from the royalty.
Although the investigation into this claim has just begun, we intend to
vigorously defend the case. We cannot currently determine the likelihood or
range of any potential outcome.
20
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the period
from October 1, 2001 to December 31, 2001.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information about our executive officers
as of February 15, 2002, as such term is defined in Rule 3b-7 of the Securities
Exchange Act of 1934, and certain of our other officers.
Name Age Position Officer Since
---------------------------------------------------------------------------------------------------
Ray R. Seegmiller 66 Chairman of the Board and Chief Executive Officer 1995
Dan O. Dinges 48 President and Chief Operating Officer 2001
Michael B. Walen 53 Senior Vice President, Exploration and Production 1998
J. Scott Arnold 48 Vice President, Land and Associate General Counsel 1998
R. Scott Butler 47 Vice President, Regional Manager, Western Region 2001
Robert G. Drake 54 Vice President, Management Information Systems 1998
Abraham D. Garza 55 Vice President, Human Resources 1998
Jeffrey W. Hutton 46 Vice President, Marketing 1995
Lisa A. Machesney 46 Vice President, Managing Counsel and
Corporate Secretary 1995
A. F. (Tony) Pelletier 49 Vice President, Regional Manager, Gulf Coast Region 2001
Scott C. Schroeder 39 Vice President, Chief Financial Officer and Treasurer 1997
Henry C. Smyth 55 Vice President and Controller 1998
All officers are elected annually by our Board of Directors. Except for
the following, all of the executive officers have been employed by Cabot Oil &
Gas Corporation for at least the last five years.
Dan O. Dinges joined Cabot Oil & Gas Corporation as President and Chief
Operating Officer and as a member of the Board of Directors in September 2001.
Mr. Dinges came to Cabot after a 20-year career with Samedan Oil Corporation, a
subsidiary of Noble Affiliates, Inc. The last three years, Mr. Dinges served as
Samedan's Senior Vice President, as well as Division General Manager for the
Offshore Division, a position he held since August 1996. He also served as a
member of the Executive Operating Committee for Samedan. Mr. Dinges started his
career as a Landman for Mobil Oil Corporation covering Louisiana, Arkansas and
the central Gulf of Mexico. After four years of expanding responsibilities at
Mobil he joined Samedan as a Division Landman - Offshore. Over the years, Mr.
Dinges held positions of increasing responsibility at Samedan including Division
Manager, Vice President and ultimately Senior Vice President. Mr. Dinges
received his BBA degree in Petroleum Land Management from The University of
Texas.
R. Scott Butler has been Vice President, Regional Manager, Western Region since
October 2001. Mr. Butler joined Cabot in 1998 as Director of Exploration and
was named Regional Manager, Western Region, in February 2001. He came to Cabot
following a 19-year career with Chevron where he served in roles of increasing
responsibility focusing on exploration in the lower 48 states. Mr. Butler holds
a bachelor's degree from Stanford University and a master's from the University
of Nevada at Reno, both in geology. He is a member of the American Association
of Petroleum Geologists and serves as a director-at-large for the Independent
Petroleum Association of Mountain States.
A. F. (Tony) Pelletier has been Vice President, Regional Manager, Gulf Coast
Region since October 2001. Mr. Pelletier joined the Company in April 2001 as
Regional Manager, Gulf Coast. Before coming to Cabot, he held positions of
increasing responsibility at PetroCorp Incorporated, most recently as Executive
Vice President and Chief Operating Officer. Prior to that, he worked at Exxon
Company USA in a variety of engineering and supervisory capacities. Mr.
Pelletier holds a B.S. in Mechanical Engineering and a master's in Civil
Engineering, both from Texas A&M University. He is a registered professional
engineer in the state of Texas.
21
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Common Stock is listed and principally traded on the New York Stock
Exchange under the ticker symbol "COG." The following table presents the high
and low closing sales prices per share of the Common Stock during certain
periods, as reported in the consolidated transaction reporting system. Cash
dividends paid per share of the Common Stock are also shown.
Cash
High Low Dividends
------------------------------------------------
2001
First Quarter $32.00 $25.88 $0.04
Second Quarter 34.20 24.22 0.04
Third Quarter 26.33 16.70 0.04
Fourth Quarter 24.99 18.35 0.04
2000
First Quarter $18.06 $14.19 $0.04
Second Quarter 24.94 16.75 0.04
Third Quarter 21.25 17.38 0.04
Fourth Quarter 31.75 19.00 0.04
As of January 31, 2002, there were 849 registered holders of the Common
Stock. Shareholders include individuals, brokers, nominees, custodians,
trustees, and institutions such as banks, insurance companies and pension funds.
Many of these hold large blocks of stock on behalf of other individuals or
firms.
ITEM 6. SELECTED HISTORICAL FINANCIAL DATA
The following table summarizes selected consolidated financial data for
Cabot Oil & Gas for the periods indicated. This information should be read in
conjunction with Management's Discussion and Analysis of Financial Condition and
Results of Operations, and the Consolidated Financial Statements and related
Notes.
Year Ended December 31,
(In thousands, except per share amounts) 2001 2000 1999 1998 1997
- ----------------------------------------------------------------------------------------------
Income Statement Data
Operating Revenues $ 447,042 $368,651 $294,037 $251,340 $269,771
Income from Operations 95,366 64,817 39,498 27,403 63,852
Net Income Available to
Common Stockholders 47,084 29,221 5,117 1,902 23,231
Basic Earnings per Share
Available to Common
Stockholders/(1)/ $ 1.56 $ 1.07 $ 0.21 $ 0.08 $ 1.00
Dividends per Common Share $ 0.16 $ 0.16 $ 0.16 $ 0.16 $ 0.16
Balance Sheet Data
Properties and Equipment, Net $ 981,338 $623,174 $590,301 $629,908 $469,399
Total Assets 1,069,031 735,634 659,480 704,160 541,805
Long-Term Debt 393,000 253,000 277,000 327,000 183,000
Stockholders' Equity 346,552 242,505 186,496 182,668 184,062
- ----------------------------------------------------------------------------------------------
/(1)/See Earnings per Common Share under Note 15 of the Notes to the Consolidated Financial Statements.
22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion is intended to assist you in understanding our
results of operations and our present financial condition. Our Consolidated
Financial Statements and the accompanying notes included elsewhere in this Form
10-K contain additional information that should be referred to when reviewing
this material.
Statements in this discussion may be forward-looking. These forward-looking
statements involve risks and uncertainties, including those discussed below,
which could cause actual results to differ from those expressed. Please read
Forward-Looking Information on page 32.
We operate in one segment, natural gas and oil exploration and development.
OVERVIEW
Our financial results depend upon many factors, particularly the price of
natural gas and our ability to market our production on economically attractive
terms. Price volatility in the natural gas market has remained prevalent in the
last few years. In the first quarter of 1999, we experienced a decline in energy
commodity prices, resulting in lower revenues and net income during this period.
However, in the summer of 1999 and continuing through 2000, prices improved. For
the months of April through October 2000, we had certain natural gas hedges in
place that prevented us from realizing the full impact of this price
environment. (See the Commodity Price Swaps and Options discussion about hedging
on page 38.) Despite this limitation, our realized natural gas price for each
month in the year 2000 was higher than the same month of any previous year. In
the final months of 2000 and into early 2001, the NYMEX futures market reported
unprecedented natural gas contract prices. We benefited from this market with
our realized natural gas price reaching $5.66 per Mcf in December and $8.46 per
Mcf in January 2001. When the NYMEX futures market was near its high on the last
day of December 2000, we entered into a series of price collars that protected
us from the subsequent price decline until their expiration in October 2001.
These price collar arrangements boosted 2001 revenue by $34.6 million,
increasing the average realized natural gas price by $0.50 per Mcf. The table
below illustrates how natural gas prices have fluctuated over the course of
2001. "Index" represents the Henry Hub index price. The "2001" price is the
natural gas price realized by us and it includes the impact of the natural gas
price collar arrangements:
(in $ per Mcf) Natural Gas Prices by Month
- --------------------------------------------------------------------------------
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
Index 9.91 6.22 5.03 5.35 4.87 3.73 3.16 3.19 2.34 1.86 3.16 2.28
2001 8.46 6.28 4.91 5.05 5.08 4.25 3.96 3.79 3.57 3.24 3.06 2.32
Prices for crude oil have followed a similar path as the commodity market
fell through 2001. The table below contains the West Texas Intermediate index
price ("Index") and our realized crude oil prices by month for 2001.
(in $ per Bbl) Crude Oil Prices by Month
- --------------------------------------------------------------------------------
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Index 28.66 27.40 26.30 28.46 28.37 26.26 26.35 27.20 23.43 21.18 19.44 19.84
2001 30.32 29.20 26.44 26.31 29.12 27.85 24.72 25.71 24.50 22.85 19.05 19.85
We reported earnings of $1.56 per share, or $47.1 million, for 2001. This
is up from the $1.07 per share, or $29.2 million, reported in 2000. The
improvement is a result of the stronger commodity price environment during the
year 2001 and the impact of the natural gas price collar arrangements, which
combined to push our realized natural gas price up 37% to $4.36 per Mcf.
Additionally, natural gas production was up 14% and crude oil sales volumes were
up 100% from last year. Overall, on a Mcf equivalent basis, our production grew
more than 21% over 2000. A 12% production increase was a result of our drilling
successes in 2000 and 2001, and the remaining 9% increase resulted from the
acquisition of Cody Company, which was effective August 1, 2001.
23
A discussion of our results from recurring operations can be found in the
Results of Operations section, beginning on page 33. Before taking into account
selected items, net income for 2001 was $51.9 million, or $1.71 per share, and
$30.2 million, or $1.10 per share for 2000.
In August 2001, we acquired the stock of Cody Company, the parent of Cody
Energy LLC ("Cody acquisition") for $231.2 million consisting of $181.3 million
of cash and 1,999,993 shares of common stock valued at $49.9 million.
Substantially all of the proved reserves of Cody Company are located in the
onshore Gulf Coast region. The acquisition was recorded using the purchase
method of accounting. As such, the Company reflected the assets and liabilities
acquired at fair value in the Company's balance sheet effective August 1, 2001
and the results of operations of Cody Company beginning August 1, 2001. In 2001,
these acquired properties contributed 6.2 Bcfe of production, $17.0 million of
operating revenue and $19.2 million of operating expenses including $11.6
million of DD&A expense. Additional 2001 costs included $5.3 million of interest
expense. These properties contributed $10.3 million in operating cash flow to
2001. The purchase price totaling approximately $315.6 million was allocated to
specific assets and liabilities based on certain estimates of fair values,
resulting in approximately $302.4 million allocated to property and $13.2
million allocated to working capital items. This $315.6 million was comprised of
non-cash common stock consideration of $49.9 million and a non-cash deferred tax
gross-up of $78.0 million and acquisition related fees and costs of $6.4
million. The deferred tax gross-up pertains to the deferred income taxes
attributable to the differences between the tax basis and the estimated fair
value of the acquired oil and gas properties.
We drilled 208 gross wells with a success rate of 87% in 2001 compared to
129 gross wells and an 86% success rate in 2000. Total capital expenditures were
$453.4 million for 2001, including $181.3 million in cash and $49.9 million in
common stock paid for Cody Company, compared to $122.6 million in 2000. Capital
spent in drilling activity increased $39.5 million, with the largest activity
increase coming in the Gulf Coast region, where we continued to develop the
Etouffee, Augen and Lake Pelto prospects in south Louisiana and initiated new
exploration in south Texas. We increased our spending for seismic data, both 2-D
and 3-D, and lease acquisition costs both in the Gulf Coast and Rocky Mountains
in order to evaluate and expand our drilling opportunities for 2001 and beyond.
The largest portion of this spending occurred in December 2001.
Total equivalent production for 2001 was 81.1 Bcfe, an increase of 21% over
2000. Of this increase, 12% resulted from drilling activity and the remaining 9%
was a result of the production from the acquired Cody Company properties.
At the end of 2001, our debt-to-total capitalization ratio was 53.1%, up
slightly from the end of 2000. This result was achieved despite expending $181.3
million as cash consideration in the Cody acquisition which was sourced
primarily by the issuance of $170 million in private placement Notes. During
2000, we improved our debt-to-total capitalization ratio from 61.1% at the end
of 1999 to 52.6% at the close of 2000. This improvement was a result of several
significant accomplishments. We sold 3.4 million shares of common stock in May
2000 for net proceeds of $71.5 million, of which $51.6 million was used to
repurchase all of our preferred stock. The remaining proceeds, along with
another $14.8 million from employee stock option exercises, were used to reduce
debt and pay dividends. From year end 1999 to year end 2000, we reduced debt by
$24 million.
We remain focused on our strategies to grow through the drill bit,
concentrating on the highest expected_return opportunities, and from synergistic
acquisitions. We believe these strategies are appropriate in the current
industry environment, enabling us to add shareholder value over the long term.
The preceding paragraphs, discussing our strategic pursuits and goals,
contain forward-looking information. Please read Forward-Looking Information on
page 32.
FINANCIAL CONDITION
Capital Resources and Liquidity
Our capital resources consist primarily of cash flows from our oil and gas
properties and asset-based borrowing supported by oil and gas reserves. Our
level of earnings and cash flows depends on many factors, including the price of
natural gas and oil, our ability to find and produce hydrocarbons and our
ability to control and reduce costs. Demand for
24
natural gas has historically been subject to seasonal influences characterized
by peak demand and higher prices in the winter heating season. However, in the
summer of 2000, our realized gas prices began to climb to unseasonably high
levels and by January 2001, we realized the highest prices in the Company's
history. Then in 2001, our realized natural gas price declined throughout the
year to a low of $2.32 per Mcf in December. A mild winter and the economic
recession may be contributing factors in the 2001 pricing volatility.
The primary sources of cash during 2001 were funds generated from
operations, proceeds from the issuance of Notes (see Note 5 of the Notes to the
Consolidated Financial Statements) and, to a lesser extent, proceeds from the
sale of stock. Funds were used primarily for exploration and development
expenditures, including the acquisition of Cody Company in August 2001, and
dividend payments.
We had a net cash outflow of $1.9 million during 2001. The net cash inflow
from operating activities of $250.4 million combined with the increase in debt
of $124.0 million to substantially fund the $386.1 million of cash used for
capital and exploration expenditures. Cash proceeds from the sales of non-
strategic assets and the sale of stock combined to provide an additional $14.6
million of cash flow.
(In millions) 2001 2000 1999
------------------------------------------------------------------------
Cash Flows Provided by Operating Activities $250.4 $119.0 $92.5
-------------------------
Cash flows provided by operating activities in 2001 were $131.4 million
higher than in 2000 and cash flows provided by operating activities in 2000 were
$26.5 million higher than in 1999. These improvements were primarily a result of
increased revenues from higher realized commodity prices and to a lesser extent
to increased natural gas and oil production.
(In millions) 2001 2000 1999
------------------------------------------------------------------------
Cash Flows Used by Investing Activities $(379.2) $(116.1) $(37.4)
--------------------------
Cash flows used by investing activities in 2001 included the $181.3 million
cash portion of the Cody Company acquisition. Additionally, capital spending for
drilling and facilities increased $39.5 million, or 49%, from last year to
$119.5 million. We drilled 208 gross wells, which represents a 61% increase over
2000.
Cash flows used by investing activities in 2000 were attributable to
capital and exploration expenditures of $119.2 million, offset by the receipt of
$3.1 million in proceeds received from the sale of non-strategic oil and gas
properties.
Cash flows used by investing activities in 1999 were attributable to
capital and exploration expenditures of $93.7 million, offset by the receipt of
$56.3 million in proceeds received from the sale of non-strategic oil and gas
properties.
(In millions) 2001 2000 1999
------------------------------------------------------------------------
Cash Flows Provided (Used) by Financing Activities $126.9 $3.0 $(55.6)
--------------------
Cash flows provided by financing activities in 2001 included the impact of
issuing $170 million in a private placement of Notes in July 2001 used to
partially fund the Cody Company acquisition. Partially offsetting this debt
increase was the reduction to the balance outstanding on the revolving credit
facility and the May 2001 prepayment of $16 million in debt that was due in May
2002.
Cash flows provided by financing activities in 2000 included $85.1 million
in proceeds received from the sale of common stock, both in a block trade and
through the exercise of employee stock options. Of the proceeds, $51.6 million
was used to repurchase all of the outstanding shares of preferred stock.
Additional cash used in financing activities included $24 million used to reduce
the year-end debt balance to $269 million from $293 million in 1999 and cash
used to pay dividends to stockholders.
Cash flows used by financing activities in 1999 included $50 million used
to reduce the year-end debt balance to $293 million from $343 million in 1998
and cash used to pay cash dividends to stockholders.
25
We have a revolving credit facility with a group of banks, the revolving
term of which runs to December 2003. The available credit line under this
facility, currently $250 million, is subject to adjustment on the basis of the
present value of estimated future net cash flows from proved oil and gas
reserves (as determined by the banks' petroleum engineer) and other assets.
Accordingly, oil and gas prices are an important part of this computation. Since
the current price environment remains volatile, management can not predict how
future price levels may change the banks' long-term price outlook. To reduce the
impact of any redetermination, we strive to manage our debt at a level below the
available credit line in order to maintain excess borrowing capacity. At year
end, this excess capacity totaled $127 million, or 51% of the total available
credit line. Management believes it has the ability to finance, if necessary,
our capital requirements, including acquisitions. Oil and gas prices also affect
the calculation of the financial ratios for debt covenant compliance. Please
read Note 5 of the Notes to the Consolidated Financial Statements for a more
detailed discussion of our revolving credit facility.
In the event that the available credit line is adjusted below the
outstanding level of borrowings, we have a period of 180 days to reduce our
outstanding debt to the adjusted credit line. The revolving credit agreement
also includes a requirement to pay down half of the debt in excess of the
adjusted credit line within the first 90 days of any adjustment.
Our 2002 interest expense is expected to be approximately $29.2 million,
including interest on the $170 million 7.33% weighted average fixed rate notes
used to partially fund the acquisition of Cody Company. In May 2001, a $16
million principal payment was made on the 10.18% Notes. This amount had been
reflected as "Current Portion of Long-Term Debt" on the balance sheet.
Additionally, the final $16 million payment on these notes that was due in May
2002 was paid in May 2001 using existing capacity on the revolving credit
agreement.
Capitalization
Our capitalization information is as follows:
As of December 31,
(In millions) 2001 2000 1999
- ----------------------------------------------------------------------------
Long-Term Debt $393.0 $253.0 $277.0
Current Portion of Long-Term Debt -- 16.0 16.0
----------------------
Total Debt $393.0 $269.0 $293.0
======================
Stockholders' Equity
Common Stock (net of Treasury Stock) $346.6 $242.5 $129.8
Preferred Stock -- -- 56.7
----------------------
Total Equity 346.6 242.5 186.5
----------------------
Total Capitalization $739.6 $511.5 $479.5
======================
Debt to Capitalization 53.1% 52.6% 61.1%
----------------------
During 2001, dividends were paid on our common stock totaling $4.8 million.
We have paid quarterly common stock dividends of $0.04 per share since becoming
publicly traded in 1990. The amount of future dividends is determined by our
Board of Directors and is dependent upon a number of factors, including future
earnings, financial condition and capital requirements.
In May 2000, we bought back all of the shares of preferred stock from the
holder for $51.6 million. Since this stock had been recorded at a stated value
of $56.7 million on our balance sheet, we realized a negative dividend to
preferred stockholders of $5.1 million. We received net proceeds of $71.5
million from the sale of 3.4 million shares of common stock in a public offering
primarily to fund this transaction. After repurchasing the preferred stock, the
excess proceeds were used to reduce debt.
26
Capital and Exploration Expenditures
On an annual basis, we generally fund most of our capital and exploration
activities, excluding major oil and gas property acquisitions, with cash
generated from operations. We budget these capital expenditures based on our
projected cash flows for the year.
The following table presents major components of our capital and
exploration expenditures for the three years ended December 31, 2001.
(In millions) 2001 2000 1999
----------------------------------------------------------------------
Capital Expenditures
Drilling and Facilities $119.5 $ 80.0 $43.9
Leasehold Acquisitions 12.9 10.9 7.2
Pipeline and Gathering 3.8 3.2 3.8
Other 1.9 2.6 3.3
-------------------------------
138.1 96.7 58.2
-------------------------------
Proved Property Acquisitions 244.1/(1)/ 6.0 18.4
Exploration Expenses 71.2 19.9 11.5
-------------------------------
Total $453.4 $122.6 $88.1
===============================
----------------------------------------------------------------------
/(1)/ The 2001 amount includes the $49.9 million common stock component
of the Cody acquisition and excludes the $78.0 million deferred
tax gross-up. See Note 14, Cody Acquisition.
Total capital and exploration expenditures for 2001 increased $330.8
million compared to 2000, primarily as a result of the $231.2 million Cody
acquisition. The remaining increase of $99.6 million was due primarily to
increased drilling activity as well as increases in leasehold acquisitions costs
consistent with our future drilling plans. The 2001 drilling program included an
over 68% increase in net wells drilled and a $15.3 million increase in
geological and geophysical expenses, including costs of obtaining seismic data
that supports future drilling programs.
We plan to drill 121 gross wells in 2002 compared with 208 gross wells
drilled in 2001. This 2002 drilling program includes $104.6 million in total
capital and exploration expenditures, down from $453.4 million in 2001, which
was our largest capital program to date. Expected spending in 2002 includes
$62.6 million for drilling and dry hole exposure, $7.8 million for lease
acquisition and $9.9 million in geological and geophysical expenses. In
addition to the drilling and exploration program, other 2002 capital
expenditures are planned primarily for production equipment and for gathering
and pipeline infrastructure maintenance and construction. We will continue to
assess the natural gas price environment and may increase or decrease the
capital and exploration expenditures accordingly.
27
Contractual Obligations
We are committed to making cash payments in the future on two types on
contracts: Note agreements and leases. We have no off-balance sheet debt or
other such unrecorded obligations and we have not guaranteed the debt of any
other party. Below is a schedule of the future payments that we were obligated
to make based on agreements in place as of December 31, 2001.
Payments Due by Year
2003 2005 2007 &
(in thousands) Total 2002 to 2004 to 2006 Beyond
--------------------------------------------------------------------------------------------------------------
Long-Term Debt /(1)/ $393,000 $ -- $123,000 $40,000 $230,000
Operating Leases /(2)/ 29,843 5,194 8,555 7,474 8,620
-------- ------ -------- ------- --------
Total Contractual Cash Obligations $422,843 $5,194 $131,555 $47,474 $238,620
--------------------------------------------------------------------------------------------------------------
/(1)/ The $123 million shown as scheduled for payment in 2003 represents
the December 31, 2001 balance outstanding on the revolving credit
facility. Typically, we are able to replace this credit agreement
with a new one as this comes due. See discussion in Note 5 of the
Notes to the Consolidated Financial Statements.
/(2)/ A discussion of operating leases can be found in Note 8 of the
Notes to the Consolidated Financial Statements. We have no capital
leases.
Potential Impact of Our Critical Accounting Policies
Readers of this document and users of the information contained in it
should be aware of how certain events may impact our financial results based on
the accounting policies in place. The three most significant policies are
discussed below.
Commodity Pricing and Risk Management Activities
Our revenues, operating results, financial condition and ability to borrow
funds or obtain additional capital depend substantially on prevailing prices for
natural gas and, to a lesser extent, oil. Declines in oil and gas prices may
materially adversely affect our financial condition, liquidity, ability to
obtain financing and operating results. Lower oil and gas prices also may reduce
the amount of oil and gas that we can produce economically. Historically, oil
and gas prices and markets have been volatile, with prices fluctuating widely,
and they are likely to continue to be volatile. Depressed prices in the future
would have a negative impact on our future financial results. In particular,
substantially lower prices would significantly reduce revenue and could
potentially impact the outcome of our annual impairment test under SFAS 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets" when adopted.
Because our reserves are predominantly natural gas, changes in natural gas
prices may have a particularly large impact on our financial results.
The majority of production is sold at market responsive prices. Generally,
if the commodity indexes fall, the price that we receive for our production will
also decline. Therefore, the amount of revenue that we realize is partially
determined by factors beyond our control. However, management may mitigate this
price risk in a number of ways. Most recently, we have used financial
instruments such as natural gas price collar arrangements to reduce the impact
of declining pricing on our revenue. Under a price collar arrangement, there is
also risk that the index prices will rise above the ceiling price and the
Company will not be able to realize the full benefit of the market improvement.
We covered 16% of our production in 2000 with natural gas price collar
arrangements and prices rose above the ceiling during some months. If we had not
had these collars in place in 2000, our realized natural gas price would have
been $0.17 per Mcf higher. In 2001, we covered 35% of our natural gas production
with price collar arrangements and prices were below the floor for several
months. The gains from the 2001 price collars improved our annual realized
natural gas price by $0.50 per Mcf.
28
Successful Efforts Method of Accounting
We use the successful efforts method of accounting for oil and gas
producing activities. Under this method, acquisition costs for proved and
unproved properties are capitalized when incurred. Exploration costs, including
seismic purchases and processing, exploratory dry hole drilling costs and costs
of carrying and retaining unproved properties are expensed as incurred. During
2001, we drilled 30 exploratory wells and 18 of them were unsuccessful, adding
$37.9 million to exploration expense. This 40% success rate for exploratory
wells is not unusual, and as we focus more on our exploration program, we are
exposed to the risk of dry hole expense. Development costs, including the costs
to drill and equip development wells, and successful exploratory drilling costs
to locate proved reserves are capitalized.
We are also exposed to potential impairments if the book value of our
assets exceeds their future expected cash flows. This may occur if a field
discovers lower than anticipated reserves or if commodity prices fall below a
level that significantly effects anticipated future cash flows on the field. We
determine if an impairment has occurred through either adverse changes or as a
result of the annual review of all fields. The impairment of unamortized capital
costs is measured at a lease level and is reduced to fair value if it is
determined that the sum of expected future net cash flows is less than the net
book value.
Oil and Gas Reserves
The process of estimating quantities of proved reserves is inherently
uncertain, and the reserve data included in this document are only estimates.
Reserve engineering is a subjective process of estimating underground
accumulations of natural gas and crude oil that cannot be measured in an exact
manner. The process relies on interpretations of available geologic, geophysic,
engineering and production data. The extent, quality and reliability of this
technical data can vary. The process also requires certain economic assumptions,
some of which are mandated by the SEC, such as oil and gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds. The
accuracy of a reserve estimate is a function of:
. the quality and quantity of available data;
. the interpretation of that data;
. the accuracy of various mandated economic assumptions; and
. the judgment of the persons preparing the estimate.
Our proved reserve information included in this document is based on
estimates we prepared. Estimates prepared by others may be higher or lower than
our estimates.
Because these estimates depend on many assumptions, all of which may
substantially differ from actual results, reserve estimates may be different
from the quantities of natural gas and crude oil that are ultimately recovered.
In addition, results of drilling, testing and production after the date of an
estimate may justify material revisions to the estimate.
You should not assume that the present value of future net cash flows is
the current market value of our estimated proved natural gas and oil reserves.
In accordance with SEC requirements, we base the estimated discounted future net
cash flows from proved reserves on prices and costs on the date of the estimate.
Actual future prices and costs may be materially higher or lower than the prices
and costs as of the date of the estimate.
Our rate of recording depreciation, depletion and amortization expense
(DD&A) is dependent upon our estimate of proved reserves. If the estimates of
proved reserves declines, the rate at which we record DD&A expense increases,
reducing net income. Such a decline may result from lower market prices, which
may make it non-economic to drill for and produce higher cost fields. In
addition, the decline in proved reserve estimates may impact the outcome of our
annual impairment test under SFAS 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" when adopted.
29
Operating Risks and Insurance Coverage
Our business involves a variety of operating risks, including:
. blowouts, cratering and explosions;
. mechanical problems;
. uncontrolled flows of oil, natural gas or well fluids;
. fires;
. formations with abnormal pressures;
. pollution and other environmental risks; and
. natural disasters.
The operation of our natural gas gathering and pipeline systems also
involves various risks, including the risk of explosions and environmental
hazards caused by pipeline leaks and ruptures. The location of pipelines near
populated areas, including residential areas, commercial business centers and
industrial sites, could increase these risks. Any of these events could result
in loss of human life, significant damage to property, environmental pollution,
impairment of our operations and substantial losses to us. In accordance with
customary industry practice, we maintain insurance against some, but not all, of
these risks and losses. The occurrence of any of these events not fully covered
by insurance could have a material adverse effect on our financial position and
results of operations. The costs of these insurance policies are somewhat
dependent on our historical claims experience and also the areas in which we
choose to operate. During the past few years, we have drilled a higher
percentage of our wells in the Gulf Coast, where insurance rates are
significantly higher than in other regions such as Appalachia.
OTHER ISSUES AND CONTINGENCIES
Corporate Income Tax. We generate tax credits for the production of certain
qualified fuels, including natural gas produced from tight sands formations and
Devonian Shale. The credit for natural gas from a tight sand formation (tight
gas sands) amounts to $0.52 per Mmbtu for natural gas sold prior to 2003 from
qualified wells drilled in 1991 and 1992. A number of wells drilled in the
Appalachian region and Rocky Mountains during 1991 and 1992 qualified for the
tight gas sands tax credit. The credit for natural gas produced from Devonian
Shale is estimated to be $1.08 per Mmbtu in 2001. In 1995 and 1996, we completed
three transactions to monetize the value of these tax credits, resulting in
revenues of $2.0 million in 2001 and an estimated $2.1 million in 2002. See Note
13 of the Notes to the Consolidated Financial Statements for further discussion.
We have benefited in the past and may benefit in the future from the
alternative minimum tax (AMT) relief granted under the Comprehensive National
Energy Policy Act of 1992 (the Act). The Act repealed provisions of the AMT
requiring a taxpayer's alternative minimum taxable income to be increased on
account of certain intangible drilling costs (IDC) and percentage depletion
deductions. The repeal of these provisions generally applies to taxable years
beginning after 1992. The repeal of the excess IDC preference can not reduce a
taxpayer's alternative minimum taxable income by more than 40% of the amount of
such income determined without regard to the repeal of such preference.
Regulations. Our operations are subject to various types of regulation by
federal, state and local authorities. See Regulation of Oil and Natural Gas
Production and Transportation and Environmental Regulations in the Other
Business Matters section of Item 1 Business for a discussion of these
regulations.
Restrictive Covenants. Our ability to incur debt and to make certain types
of investments is subject to certain restrictive covenants in the Company's
various debt instruments. Among other requirements, our Revolving Credit
Agreement and the Notes (see Note 5 of the Notes to the Consolidated Financial
Statements) specify a minimum annual coverage ratio of operating cash flow to
interest expense for the trailing four quarters of 2.8 to 1.0. At December 31,
2001, the calculated ratio for 2001 was 10.0 to 1.0. In the unforeseen event
that we fail to comply with these covenants, the Company may apply for a
temporary waiver with the bank, which, if granted, would allow us a period of
time to remedy the situation. See further discussion in Capital Resources and
Liquidity and Note 5 of the Notes to the Consolidated Financial Statements for
further discussion.
30
CONCLUSION
Our financial results depend upon many factors, particularly the price of
natural gas and oil and our ability to market gas on economically attractive
terms. The average produced natural gas sales price received by us has changed
from year-to-year as follows:
2001: increased 37% over 2000 to $4.36 per Mcf
2000: increased 44% over 1999 to $3.19 per Mcf
1999: increased 3% over 1998 to $2.22 per Mcf
1998: decreased 15% from 1997 to $2.16 per Mcf
1997: increased 8% over 1996 to $2.53 per Mcf
The volatility of natural gas prices in recent years remains prevalent in 2002
with wide price swings in day-to-day trading on