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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, 2000
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 [__].
This report contains 69 pages and four exhibits.
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, 2001), was approximately
$815,000,000. As of January 31, 2001, there were 29,280,349 shares of Common
Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Stockholders to
be held May 3, 2001, are incorporated herein by reference in Items 10, 11, 12
and 13 of Part III of this report.
TABLE OF CONTENTS
PART I PAGE
ITEMS 1 and 2 Business and Properties 3
ITEM 3 Legal Proceedings 17
ITEM 4 Submission of Matters to a Vote of Security Holders 18
Executive Officers of the Registrant 18
PART II
ITEM 5 Market for Registrant's Common Equity and Related Stockholder Matters 19
ITEM 6 Selected Historical Financial Data 19
ITEM 7 Management's Discussion and Analysis of Financial Condition
and Results of Operations 20
ITEM 7A Quantitative and Qualitative Disclosures about Market Risk 30
ITEM 8 Financial Statements and Supplementary Data 35
ITEM 9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 65
PART III
ITEM 10 Directors and Executive Officers of the Registrant 65
ITEM 11 Executive Compensation 65
ITEM 12 Security Ownership of Certain Beneficial Owners and Management 65
ITEM 13 Certain Relationships and Related Transactions 65
PART IV
ITEM 14 Exhibits, Financial Statements, Schedules and Reports on Form 8-K 66
___________________
The statements regarding future financial and operating performance and
results, and market prices and 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" 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
. Appalachia
. The Mid-Continent or Anadarko Basin
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.
Until a few years ago, our core holdings were long-lived Appalachian
natural gas reserves. We have used the cash flow from these properties,
together with strategic acquisitions, to shift the focus of our exploration
efforts to the Gulf Coast and Rocky Mountain areas. We believe these core
producing areas offer more value, accretive reserve and production growth and
higher rates of return on equity. Meanwhile, we have been rationalizing our
Appalachian operations by selective divestitures. In 2001, 48% of our capital
budget is allocated to the Gulf Coast, 18% to the Rocky Mountains, 26% to
Appalachia and the remaining 8% to the Mid-Continent area. While about 40% of
our proved reserves are located in Appalachia, reflecting the fact that we have
operated there for more than a century, this proportion has declined as our
production and reserves in the Gulf Coast and Rocky Mountains have grown.
In 1998, we participated in a 300 square mile 3D seismic shoot with Union
Pacific Resources Group, Inc. in south Louisiana and identified several deep,
high-potential exploratory prospects. We have drilled five successful wells in
five attempts with one additional well drilling at the end of 2000 on these
prospects. These successes include Etouffee, Bon Ton and Augen. Our 2001
drilling plan for this acreage includes four high-growth, high-potential wells.
Additional exploratory opportunities exist in this prospect area. Concurrent
with this project, we acquired $70.1 million of developed and undeveloped
properties from Oryx Energy Company also in south Louisiana. During 1999, we
increased our Gulf Coast production significantly through the completion of
several workover projects on wells acquired from Oryx. At the same time, we
actively reprocessed 3D seismic data acquired from Oryx, the interpretation of
which yielded five, high-potential exploratory prospects. One of these prospects
was successfully drilled in 2000 with another in-progress at the end of 2000.
Our 2001 capital spending program includes plans to drill two more of these
prospects and we expect to drill another in 2002. The success of these projects
in the Gulf Coast region has increased our daily production from 15 Mmcfe per
day in October 1998 to over 70 Mmcfe per day in December 2000. We continue to
acquire additional 3D seismic and leases in the Gulf Coast area. In addition,
our 2001 drilling program includes plans to drill additional wells in south
Louisiana, as we continue to focus our exploratory efforts on this high-growth,
high-potential region.
As of December 31, 2000, our proved reserves totaled just over 1.0 Tcfe,
94% of which was natural gas. We operate approximately 83% of the wells in
which we hold an interest. Daily production averaged 180.5 Mmcfe per day during
the first nine months of the year before increasing to approximately 185 Mmcfe
per day in October and November. December was the first month in which we
reached full production rates from our recent exploratory wells in south
Louisiana, which brought the average for that month to approximately 197 Mmcfe
per day.
3
The following table presents certain information as of December 31, 2000.
West
--------------------------------
Gulf Rocky Mid- Total
Coast Mountains Continent West Appalachia Total
-------- ---------- ---------- -------- ----------- ----------
Proved Reserves at Year End (Bcfe)
Developed 110.9 192.1 188.9 381.0 313.7 805.6
Undeveloped 33.1 54.0 29.2 83.2 96.8 213.1
------- ------- ------- ------- --------- ---------
Total 144.0 246.1 218.1 464.2 410.5 1,018.7
Average Daily Production (Mmcfe per day) 49.5 51.2 32.8 84.0 49.2 182.7
Reserves Life Index (in years) /(1)/ 7.9 13.1 18.2 15.1 22.8 15.2
Gross Productive Wells 384 490 672 1,162 2,243 3,789
Net Productive Wells 292.6 228.2 447.2 675.4 2,079.2 3,047.2
Percent Wells Operated 59.4% 48.8% 74.1% 63.4% 97.1% 82.9%
Net Acreage
Developed 50,673 81,940 184,399 266,339 743,540 1,060,552
Undeveloped 60,757 117,828 13,242 131,070 300,985 492,812
------- ------- ------- ------- --------- ---------
Total 111,430 199,768 197,641 397,409 1,044,525 1,553,364
_______________________________________________________________________________
/(1)/ Reserve Life Index is equal to year-end reserves divided by annual
production.
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
were $66.0 million in 2000, or 54% of our total 2000 capital and exploration
expenditures, and $36.8 million for 1999. 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 71.3 Mmcfe per day in December 2000. For 2001, we have budgeted $79.3
million (48% of our total 2001 capital budget) for capital expenditures in the
region. Our 2001 Gulf Coast drilling program emphasizes our exploration
opportunities.
We had 384 productive wells (292.6 net) in the Gulf Coast region as of
December 31, 2000, of which 228 wells are operated by us. Average net daily
production in 2000 was 49.5 Mmcfe, down from 52.0 Mmcfe in 1999 due to delays in
bringing production on-line early in 2000 from new wells not operated by us.
However, production from our drilling activity, which came on later in the year,
brought the average daily production rate to 71.3 Mmcfe for the month of
December 2000. At December 31, 2000, we had 144.0 Bcfe of proved reserves (74%
natural gas) in the Gulf Coast region, which was 14% of our total proved
reserves.
In 2000, we drilled 23 wells (11.2 net) in the Gulf Coast region, of which
17 wells (8.0 net) were development wells. We did not begin to realize the full
impact of our drilling successes in this region until late 2000. At year end,
the south Louisiana Etouffee prospect along with our new discoveries in the
Augen, Krescent and Bon Ton prospects in south Louisiana contributed to the
significant growth in net proved reserves. In the Gulf Coast region, we plan to
drill 29 wells in 2001.
At December 31, 2000, we had 111,430 net acres in the region, including
50,673 net developed, and we had identified 13 proved undeveloped drilling
locations.
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.
4
Currently, the majority 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. From time to time, we may also use hedges on a portion of our production
to reduce the potential risk of falling prices when we believe market conditions
are favorable. 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 2,000 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, 2000, we had 464.2 Bcfe of proved reserves (96% natural
gas) in the Western region, constituting 46% 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 246.1 Bcfe at December 31, 2000. Capital and exploration
expenditures were $23.9 million for 2000, or 20% of our total 2000 capital and
exploration expenditures, and $29.5 million for 1999, including $17.4 million
for property acquisitions. For 2001, we have budgeted $29.6 million (18% of our
total 2001 capital budget) for capital expenditures in the area. The 2001
drilling program consists of several new exploration plays complemented by
development drilling.
We had 490 productive wells (228.2 net) in the Rocky Mountains area as of
December 31, 2000, of which 239 wells are operated by us. Principal producing
intervals in the Rocky Mountains area are in the Frontier and Dakota formations
at depths ranging from 9,000 to 13,500 feet. Average net daily production in
2000 was 51.2 Mmcfe.
In 2000, we drilled 26 wells (15.8 net) in the Rocky Mountains, of which 25
wells (15.3 net) were development and extension wells. In 2001, we plan to
drill 46 wells.
At December 31, 2000, we had 199,768 net acres in the area, including
81,940 net developed acres, and we had identified 81 proved undeveloped drilling
locations.
Mid-Continent
Our Mid-Continent activities are concentrated in the Anadarko Basin in
southwestern Kansas, Oklahoma and the panhandle of Texas. Capital and
exploration expenditures were $7.6 million for 2000, or 6% of our total 2000
capital and exploration expenditures, and $4.1 million for 1999. For 2001, we
have budgeted $13.5 million (8% of our total 2001 capital budget) for capital
expenditures in the area.
As of December 31, 2000, we had 672 productive wells (447.2 net) in the
Mid-Continent area, of which 498 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 2000 was 32.8 Mmcfe. At December 31, 2000, we had 218.1 Bcfe of
proved reserves (97% natural gas) in the Mid-Continent area, 21% of our total
proved reserves.
In 2000, we drilled 19 wells (12.6 net) in the Mid-Continent, of which 18
wells (12.3 net) were development and extension wells. In 2001, we plan to
drill 35 wells.
At December 31, 2000, we had 197,641 net acres in the area, including
184,399 net developed acres, and we had identified 67 proved undeveloped
drilling locations.
5
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, the majority 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. From time to time, we may also use hedges on a portion of our
production to reduce the potential risk of falling prices when we believe market
conditions are favorable. 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 expired in June 2008. We received a payment of $12 million as
part of this buyout agreement. This contract was then replaced with a fixed
price sales contract that expires 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. After April 2001, we expect
that this production will be sold at market responsive prices.
We also produce and market approximately 700 barrels of crude
oil/condensate per day in the Western region at market-responsive prices.
APPALACHIAN REGION
Our Appalachian activities are concentrated in Pennsylvania, Ohio, West
Virginia and Virginia. We believe that our large undeveloped acreage position,
high concentration of wells, natural gas gathering and pipeline systems, and
storage capacity give us a competitive advantage in the region. We have
achieved a drilling success rate of 89% in the region since 1991. Capital and
exploration expenditures were $21.5 million for 2000, or 18% of our total 2000
capital spending, and $14.6 million for 1999. For 2001, we have budgeted $43.1
million (26% of our total 2001 capital budget) for capital expenditures in the
region.
At December 31, 2000, we had 2,243 productive wells (2,079.2 net), of which
2,177 wells are operated by us. There are multiple producing intervals that
include the Devonian Shale, Oriskany, Berea and Big Lime formations at depths
primarily ranging from 1,500 to 9,000 feet. Average net daily production in
2000 was 49.2 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, 2000, we had 410.6 Bcfe of proved reserves (substantially all
natural gas) in the Appalachian region, constituting 40% of our total proved
reserves. A regional office in Pittsburgh managed operations in this region
until its closure in mid 2000. Currently this region is managed from our office
in Charleston, West Virginia.
In 2000, we drilled 61 wells (52.0 net) in the Appalachian region, of which
52 wells (45.7 net) were development wells. In 2001, we plan to drill 130
wells.
At December 31, 2000, we had 1,044,525 net acres in the region, including
743,540 net developed, and we had identified 271 proved undeveloped drilling
locations.
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.
Most of our natural gas sales volume in the Appalachian region is sold at
index-based prices under contracts with a term of one year or less. Of these
short-term sales, spot market sales are made under month-to-month contracts,
while industrial and utility sales generally are made under year-to-year
contracts. Approximately 5% of Appalachian production is sold on fixed price
contracts that typically renew annually. From time to time, we
6
may also use 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, this premium has
typically been in the range of $0.40 to $0.50 per Mmbtu above the Henry Hub cash
price throughout the 1990s. 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 early 2001, the
premium has begun to increase again due to strengthening of demand and perceived
market shortages. The average 2000 premium was approximately $0.30 per Mmbtu.
Due to this recent volatility, we are not able to predict the level of this
premium for the future.
Ancillary to our exploration and production operations, we operate a number
of gas gathering and transmission pipeline systems, made up of approximately
2,450 miles of pipeline with interconnects to three interstate transmission
systems, seven local distribution companies and numerous end users as of the end
of 2000. 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 take part in development drilling operations without relying
upon third parties to transport our natural gas while incurring 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.
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 2000, 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 the differential between a fixed and a variable gas
price. 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 have not traditionally used derivatives to hedge a large portion of our
natural gas production, hedging only 9% of our total natural gas production with
derivatives in the last five years. We will continue to evaluate the benefit of
employing derivatives in the future. Please read Management's Discussion and
Analysis of Financial Condition and Results of Operations - Commodity Price
Swaps and Options for further discussion concerning our use of derivatives.
7
RESERVES
Current Reserves
The following table presents our estimated proved reserves at December 31,
2000.
Natural Gas (Mmcf) Liquids/(1)/ (Mbbl) Total/(2) /(Mmcfe)
- --------------------------------------------------------------------------------------------------------------------
Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total
- --------------------------------------------------------------------------------------------------------------------
Gulf Coast 77,721 28,074 105,795 5,525 837 6,362 110,871 33,093 143,964
Rocky Mountains 182,790 50,446 233,236 1,550 587 2,137 192,090 53,969 246,059
Mid-Continent 182,927 28,911 211,838 990 52 1,042 188,867 29,222 218,089
Appalachia 311,524 96,829 408,353 373 0 373 313,762 96,829 410,591
-----------------------------------------------------------------------------------------------
Total 754,962 204,260 959,222 8,438 1,476 9,914 805,590 213,113 1,018,703
===============================================================================================
________________________________________________________________________________
/(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 2000. While the high year-end natural gas price had a significant
impact on the present value of proved reserves as presented in the Supplemental
Oil and Gas Information discussion beginning on page 61, our reserve volumes did
not change appreciably due to the higher prices.
There are a number of uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond our control. 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, reserve estimates are often
different from the quantities of crude oil and natural gas that are ultimately
recovered. The meaningfulness of such estimates depends primarily on the
accuracy of the assumptions upon which they were based. In general, the volume
of production from oil and gas properties declines as reserves are depleted.
Except to the extent we acquire additional properties containing proved reserves
or conduct successful exploration and development activities or both, our proved
reserves will decline as reserves are produced.
8
Historical Reserves
The following table presents our estimated proved reserves for the periods
indicated.
Natural Gas Oil & Liquids Total
(Mmcf) (Mbbl) (Mmcfe) /(1)/
-------------------------------------------------------------------
December 31, 1997 903,428 5,869 938,643
-------------------------------------------------------------------
Revision of Prior Estimates (13,097) (1,644) (22,963)
Extensions, Discoveries and
Other Additions 94,892 835 99,904
Production (64,167) (736) (68,584)
Purchases of Reserves in Place 76,234 3,353 96,353
Sales of Reserves in Place (534) -- (534)
-------------------------------------------------------------------
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
===================================================================
Proved Developed Reserves
December 31, 1997 738,764 4,859 767,919
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
________________________________________________________________________________
/(1)/ Includes natural gas and natural gas equivalents determined by using the
ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural
gas liquids.
9
Volumes and Prices; Production Costs
The following table presents regional historical information about our net
wellhead sales volume for natural gas and oil (including condensate and natural
gas liquids), produced natural gas and oil sales prices, and production costs
per equivalent.
Year Ended December 31,
2000 1999 1998
------ ------ ------
Net Wellhead Sales Volume
Natural Gas (Bcf)
Gulf Coast 14.1 15.5 10.6
West 29.0 29.3 30.9
Appalachia 17.8 20.7 22.7
Crude/Condensate/Ngl (Mbbl)
Gulf Coast 669 579 215
West 289 341 482
Appalachia 32 43 39
Produced Natural Gas Sales Price ($/Mcf)/(1)/
Gulf Coast $ 3.79 $ 2.29 $ 2.15
West 2.86 1.96 1.90
Appalachia 3.24 2.53 2.53
Weighted Average 3.19 2.22 2.16
Crude/Condensate Sales Price ($/Bbl)/(1)/ $26.81 $17.22 $13.06
Production Costs ($/Mcfe)/(2)/ $ 0.70 $ 0.59 $ 0.57
______________________________________________________________________________
/(1)/ Represents the average sales prices (net of hedge activity) for all
production volumes (including royalty volumes) sold by Cabot Oil & Gas
during the periods shown net of related costs (principally purchased gas
royalty, transportation and storage).
/(2)/ Production costs include direct lifting costs (labor, repairs and
maintenance, materials and supplies), and the costs of administration of
production offices, insurance and property and severance taxes, but is
exclusive of depreciation and depletion applicable to capitalized lease
acquisition, exploration and development expenditures.
10
Acreage
The following tables summarize our gross and net developed and undeveloped
leasehold and mineral acreage at December 31, 2000. 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 0 0 312 312 312 312
Arkansas 0 0 240 6 240 6
Colorado 13,972 13,192 0 0 13,972 13,192
Kansas 29,067 27,765 0 0 29,067 27,765
Kentucky 2,266 901 0 0 2,266 901
Louisiana 44,587 35,446 114,154 41,972 158,741 77,418
Michigan 759 205 0 0 759 205
Montana 397 210 27,135 15,245 27,532 15,455
New York 2,956 1,117 7,641 4,382 10,597 5,499
North Dakota 0 0 870 96 870 96
Ohio 6,659 2,541 15,947 13,001 22,606 15,542
Oklahoma 165,037 115,150 13,646 8,596 178,683 123,746
Pennsylvania 127,972 77,918 48,077 42,051 176,049 119,969
Texas 61,192 42,301 72,831 22,711 134,023 65,012
Utah 1,740 530 20,034 16,862 21,774 17,392
Virginia 22,151 20,034 7,986 5,264 30,137 25,298
West Virginia 576,561 543,537 239,809 184,390 816,370 727,927
Wyoming 139,801 68,008 119,188 85,544 258,989 153,552
--------------------------------------------------------------------
Total 1,195,117 948,855 687,870 440,432 1,882,987 1,389,287
====================================================================
Mineral Fee Acreage
Developed Undeveloped Total
------------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
------------------------------------------------------------------------------------------
State
Colorado 0 0 160 6 160 6
Kansas 160 128 0 0 160 128
Louisiana 628 276 0 0 628 276
Montana 0 0 589 75 589 75
New York 0 0 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 79,384 50,458 49,497 147,913 128,881
--------------------------------------------------------------------
Total 132,753 111,697 59,007 52,380 191,760 164,077
====================================================================
Aggregate Total 1,327,870 1,060,552 746,877 492,812 2,074,747 1,553,364
====================================================================
11
Total Net Acreage by Region of Operation
Developed Undeveloped Total
-----------------------------------------------------------------------
Gulf Coast 50,673 60,757 111,430
West 266,339 131,070 397,409
Appalachia 743,540 300,985 1,044,525
----------------------------------------------
Total 1,060,552 492,812 1,553,364
==============================================
Productive Well Summary
The following table presents our ownership at December 31, 2000, 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). We consider productive wells to be producing wells and wells capable
of production 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 282 213.4 102 79.2 384 292.6
West 1,093 636.4 69 39.0 1,162 675.4
Appalachia 2,223 2,069.6 20 9.6 2,243 2,079.2
--------------------------------------------
Total 3,598 2,919.4 191 127.8 3,789 3,047.2
============================================
Drilling Activity
We drilled, participated in the drilling of, or acquired wells presented by
region in the table below for the periods indicated.
Year Ended December 31,
2000 1999 1998
-----------------------------------------------------------------------------
Gross Net Gross Net Gross Net
-----------------------------------------------------------------------------
Gulf Coast
Development Wells
Successful 14 6.3 10 6.2 9 4.0
Dry 3 1.7 3 3.0 0 0.0
Extension Wells
Successful 0 0.0 0 0.0 0 0.0
Dry 0 0.0 0 0.0 0 0.0
Exploratory Wells
Successful 4 2.2 2 0.6 7 4.6
Dry 2 1.0 1 0.5 1 1.0
----------------------------------------------
Total 23 11.2 16 10.3 17 9.6
==============================================
Wells Acquired/(1)/ 1 0.6 2 0.6 219 204.2
Wells in Progress at End
of Period 2 1.1 1 0.3 5 4.2
12
Year Ended December 31,
2000 1999 1998
--------------------------------------------------------------------
Gross Net Gross Net Gross Net
--------------------------------------------------------------------
West
Development Wells
Successful 33 22.7 19 9.0 64 36.2
Dry 3 1.0 1 1.0 4 1.9
Extension Wells
Successful 7 3.9 1 0.3 5 2.2
Dry 0 0.0 0 0.0 1 0.9
Exploratory Wells
Successful 1 0.3 0 0.0 2 0.7
Dry 1 0.5 2 1.3 3 2.0
-------------------------------------------
Total 45 28.4 23 11.6 79 43.9
===========================================
Wells Acquired/(1)/ 1 0.4 27 10.7 13 3.9
Wells in Progress at End
of Period 4 2.7 5 2.3 4 1.8
Year Ended December 31,
2000 1999 1998
---------------------------------------------------------------------
Gross Net Gross Net Gross Net
---------------------------------------------------------------------
Appalachia
Development Wells
Successful 47 41.5 26 19.0 77 69.4
Dry 5 4.2 1 0.5 6 4.8
Extension Wells
Successful 0 0.0 0 0.0 0 0.0
Dry 0 0.0 0 0.0 0 0.0
Exploratory Wells
Successful 5 3.8 3 2.0 18 11.0
Dry 4 2.5 4 2.0 8 5.0
---- ---- -- ---- --- ----
Total 61 52.0 34 23.5 109 90.2
==== ==== == ==== === ====
Wells Acquired/(1)/ 0 0.0 0 0.0 5 4.2
Wells in Progress at End
of Period 3 3.0 1 0.3 1 0.5
---------------------------------------------------------------------
/(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 and existing natural gas gathering and pipeline
systems and storage fields give us a competitive advantage over other producers
in the Appalachian region who do not have similar systems or facilities in
place. We 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.
13
OTHER BUSINESS MATTERS
Major Customer
We had no sales to any customer that exceeded 10% of our total gross
revenues in 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 wholesaler 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. As a result of the various omnibus rulemaking proceedings in the
late 1980s and early 1990s, and the individual pipeline restructuring
proceedings of the early to mid-1990s, the interstate pipelines are now required
to provide open and nondiscriminatory transportation and transportation-related
services to all producers, gas marketing companies, local distribution
companies, industrial end users and other customers seeking service. The FERC
expanded the impact of open access regulations to intrastate commerce through
its
14
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, (4) further refinement of transactions permitted in the
secondary market for released pipeline capacity and its relationship to open
access service in the primary market, and (5) 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. It remains to be seen what effect the FERC's other
activities will have on access to markets, the fostering of competition and the
cost of doing business.
As a result of these changes, sellers and buyers of gas have gained direct
access to the particular pipeline services they need and are better able to
conduct business with a larger number of counterparties. 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 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.
15
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.
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, 2000, Cabot Oil & Gas had 323 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.
16
In May 2000, we announced the closure of our regional office in Pittsburgh,
Pennsylvania. Approximately 15 jobs were eliminated as a result of this action,
while the remaining positions were either transferred to existing offices in
Charleston, West Virginia and Houston, Texas or remained in smaller facilities
in Pittsburgh.
In January 1999, we instituted a reorganization plan that resulted in a 6%
reduction in the number of active employees. In September 1999, we completed
the divestiture of certain properties in the Appalachian region that effectively
transferred 19 active employees to the acquiring company.
Other
Our profitability depends on certain factors that are beyond our control,
such as natural gas and crude oil prices. Please see Item 7. 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. The location of pipelines near populated areas,
including residential areas, commercial business centers and industrial sites,
could increase these risks. At December 31, 2000, we owned or operated
approximately 2,650 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. 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 sale of our oil and gas production depends on a number of factors
beyond our control. The factors include the availability and capacity of
transportation and processing facilities. Our failure to access these facilities
and obtain these services on acceptable terms could materially harm our
business.
ITEM 2. PROPERTIES
See Item 1. Business.
ITEM 3. LEGAL PROCEEDINGS
We are a party to various legal proceedings arising in the normal course of
our business, none of which, in management's opinion, should result in judgments
which would have a material adverse effect on us.
Environmental Liability
The EPA notified us in February 2000 that we might have 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
1989. The EPA stated that federal, state and local governmental agencies along
with the numerous private entities that used the Site for waste disposal will be
expected to pay the clean-up costs which could total as much as several hundred
million dollars. The EPA is also pursuing the owners/operators of the Site to
pay for remediation.
Documents received 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 stemmed from the fact that the
owners/operators of the Site do not have the financial means to implement a
closure plan for the Site. A group of potentially responsible parties,
including the Company, have had extensive settlement discussions with the EPA.
However, the parties have yet to
17
reach an agreement.
We have established a reserve that we believe to be adequate to cover this
potential environmental liability based on our estimate of the probable outcome
of this matter. While the potential impact of this claim may materially affect
quarterly or annual financial results, management does not believe it would
materially impact our financial position or cash flows. We will continue to
monitor the facts and our assessment of our liability related to this claim.
Wyoming Royalty Litigation
In June 2000, two overriding royalty owners sued us in Wyoming State court.
The plaintiffs have requested class certification under the Wyoming Rules of
Civil Procedure and allege that we have deducted impermissible 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.
While we believe that we have substantial defenses to this claim and intend
to vigorously assert such defenses, the investigation into this claim has only
just begun and, accordingly, we can not presently determine the likelihood or
range of any potential loss.
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, 2000 to December 31, 2000.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information about our executive officers
as of February 22, 2001, 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 65 Chairman of the Board, Chief Executive Officer 1995
and President
Michael B. Walen 52 Senior Vice President 1998
J. Scott Arnold 47 Vice President, Land and Associate General Counsel 1998
Robert G. Drake 53 Vice President, Management Information Systems 1998
Abraham D. Garza 54 Vice President, Human Resources 1998
Jeffrey W. Hutton 45 Vice President, Marketing 1995
Lisa A. Machesney 45 Vice President, Managing Counsel and
Corporate Secretary 1995
Scott C. Schroeder 38 Vice President, Chief Financial Officer and 1997
Treasurer
Henry C. Smyth 54 Vice President and Controller 1998
All officers are elected annually by our Board of Directors. All of the
executive officers have been employed by Cabot Oil & Gas Corporation for at
least the last five years.
18
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Common Stock is listed and principally traded on the New York Stock
Exchange under the ticker symbol "COG." The following table presents the high
and low 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
------------------------------------------------
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
1999
First Quarter $15.81 $10.94 $0.04
Second Quarter 19.94 14.00 0.04
Third Quarter 19.50 16.44 0.04
Fourth Quarter 18.00 13.38 0.04
As of January 31, 2001, there were 942 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) 2000 1999 1998 1997 1996
- --------------------------------------------------------------------------------------------
Income Statement Data
Operating Revenues $368,651 $294,037 $251,340 $269,771 $248,930
Income from Operations 64,817 39,498 27,403 63,852 48,787
Net Income Available to
Common Stockholders 29,221 5,117 1,902 23,231 15,258
Basic Earnings per Share
Available to Common
Stockholders/(1)/ $ 1.07 $ 0.21 $ 0.08 $ 1.00 $ 0.67
Dividends per Common Share $ 0.16 $ 0.16 $ 0.16 $ 0.16 $ 0.16
Balance Sheet Data
Properties and Equipment, Net $623,174 $590,301 $629,908 $469,399 $480,511
Total Assets 735,634 659,480 704,160 541,805 561,341
Long-Term Debt 253,000 277,000 327,000 183,000 248,000
Stockholders' Equity 242,505 186,496 182,668 184,062 160,704
- --------------------------------------------------------------------------------
/(1)/ See Earnings per Common Share under Note 15 of the Notes to the
Consolidated Financial Statements.
19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following 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 25.
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. From the third quarter of 1998 through 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 into early 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 on page 31.) 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, 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.
We reported earnings of $1.07 per share, or $29.2 million, for 2000. This
is up from the $0.21 per share, or $5.1 million, reported in 1999. The
improvement is a result of the stronger commodity price environment during the
year 2000, with our realized natural gas price up 44% to $3.19 per Mcf and our
crude oil price up 56% to $26.81 per Bbl.
A discussion of our results from recurring operations can be found in the
Results of Operations section, beginning on page 26. Before taking into account
selected non-recurring items, net income for 2000 was $30.2 million, or $1.10
per share, and $0.4 million, or $0.02 per share for 1999.
We drilled 129 gross wells with a success rate of 86% in 2000 compared to
73 gross wells and an 84% success rate in 1999. Total capital expenditures were
$122.6 million for 2000 compared to $88.1 million in 1999. Most of the $34.5
million increase was spent on drilling, with the largest activity increase
coming in the Gulf Coast region, where we continued to develop the Etouffee, Bon
Ton, Augen and Krescent prospects in south Louisiana. We increased our spending
for seismic data, both 2-D and 3-D, in order to evaluate our drilling
opportunities for 2000 and beyond. Additionally, a portion of our capital
budget in 2000 was spent to construct production facilities for use with several
wells in south Louisiana.
Total equivalent production for 2000 was 66.9 Bcfe, a decrease of 6% over
1999. Production delays on non-operated properties in the Gulf Coast region
combined with the sale of non-strategic properties in Appalachia in the fourth
quarter of 1999 accounted for much of this decline. By the fourth quarter, this
Gulf Coast production was on-line and we exited the year producing approximately
197 Mmcfe per day. Due to the increased demand for drilling rigs and crews,
some short drilling delays are anticipated in early 2001. However, whenever
possible, we have contracted rigs and crews to begin working on our 2001
drilling program.
During 2000, we improved our debt-to-equity 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.
20
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 25.
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
oil and natural gas and our ability to control and reduce costs. Demand for
natural gas has historically been subject to seasonal influences characterized
by peak demand and higher prices in the winter heating season. However, in the
summer of 2000, our realized gas prices began to climb and by the fourth quarter
of 2000, we were realizing the highest prices in the Company's history.
The primary sources of cash for us during 2000 were funds generated from
operations and proceeds from the sale of stock. Funds were used primarily for
exploration and development expenditures, the repurchase of the preferred stock,
dividend payments and the repayment of borrowings under the credit facility.
We had net cash inflows of $5.9 million during 2000. The net cash inflow
from operating activities of $119.0 million substantially offsets the $119.2
million of cash used for capital and exploration expenditures. The cash proceeds
from sale of common stock of $85.1 million effectively funded the repurchase of
the preferred stock, debt reduction and dividend payments.
(In millions) 2000 1999 1998
-----------------------------------------------------------------------
Cash Flows Provided by Operating Activities $119.0 $92.5 $87.2
-------------------------
Cash flows provided by operating activities in 2000 were $26.5 million
higher than in 1999. This improvement was primarily a result of increased
revenues from higher realized commodity prices.
Cash flows provided by operating activities in 1999 were $5.3 million
higher than in 1998. This improvement was a result of increased revenues from
higher realized commodity prices and the proceeds from the buyout of the long-
term gas sales contract. Partially offsetting this benefit was the less
favorable change in the balance sheet as we reduced the balance in accounts
payable between year ends.
(In millions) 2000 1999 1998
-----------------------------------------------------------------------
Cash Flows Used by Investing Activities $(116.1) $(37.4) $(222.1)
-----------------------------
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. Cash flows used by investing activities in 1998 were substantially
attributable to capital and exploration expenditures of $223.2 million, offset
by the receipt of $1.1 million in proceeds from the sale of certain oil and gas
properties. These 1998 expenditures included:
. $70.1 million used to purchase south Louisiana properties from Oryx in
December.
. $6.6 million spent as part of the joint exploration agreement with Union
Pacific Resources.
. $12 million used to acquire 21.8 Bcfe of proved reserves in the Western
region.
21
(In millions) 2000 1999 1998
--------------------------------------------------------------------------
Cash Flows Provided (Used) by Financing Activities $3.0 $(55.6) $135.3
----------------------
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.
Cash flows provided by financing activities in 1998 were increases in
borrowings on the revolving credit facility used to fund investing activities
such as the 1998 drilling program and the $83.6 million in property
acquisitions. Financing activities in 1998 also included the payment of
dividends and the purchase of shares in the open market under our share
repurchase program. The purchased shares are held as treasury shares.
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.
While the current price environment is quite strong, 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 $113 million, or 45% 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 interest expense for 2001 is projected to be $17.3 million. In May
2001, a $16.0 million principal payment is due on our 10.18% Notes. The amount
is reflected as Current Portion of Long-Term Debt on our balance sheet. The
payment is expected to be made with cash from operations and, if necessary, from
increased borrowings under our revolving credit facility.
Capitalization
Our capitalization information is as follows:
As of December 31,
(In millions) 2000 1999 1998
--------------------------------------------------------------------------------
Long-Term Debt $253.0 $277.0 $327.0
Current Portion of Long-Term Debt 16.0 16.0 16.0
------------------------------------
Total Debt $269.0 $293.0 $343.0
====================================
Stockholders' Equity
Common Stock (net of Treasury Stock) $242.5 $129.8 $126.0
Preferred Stock 0.0 56.7 56.7
------------------------------------
Total Equity 242.5 186.5 182.7
------------------------------------
Total Capitalization $511.5 $479.5 $525.7
====================================
Debt to Capitalization 52.6% 61.1% 65.2%
------------------------------------
22
During 2000, dividends were paid on our common stock totaling $4.4 million
and on our 6% convertible redeemable preferred stock totaling $2.2 million. We
have paid quarterly common stock dividends of $0.04 per share since becoming
publicly traded in 1990. The amount of future dividends is determined by our
Board of Directors and is dependent upon a number of factors, including future
earnings, financial condition and capital requirements.
In May 2000, we bought back all of the shares of preferred stock from the
holder for $51.6 million. Since this stock had been recorded at a stated value
of $56.7 million on our balance sheet, we realized a negative dividend to
preferred stockholders of $5.1 million. We received net proceeds of $71.5
million from the sale of 3.4 million shares of common stock in a public offering
primarily to fund this transaction. After repurchasing the preferred stock, the
excess proceeds were used to reduce debt.
Capital and Exploration Expenditures
On an annual basis, we generally fund most of our capital and exploration
activities, excluding major oil and gas property acquisitions, with cash
generated from operations. We budget these capital expenditures based on our
projected cash flows for the year.
The following table presents major components of our capital and
exploration expenditures for the three years ended December 31, 2000.
(In millions) 2000 1999 1998
-----------------------------------------------------------
Capital Expenditures
Drilling and Facilities $ 80.0 $ 43.9 $ 99.0
Leasehold Acquisitions 10.9 7.2 15.6
Pipeline and Gathering 3.2 3.8 5.3
Other 2.6 3.3 2.8
-------------------------
96.7 58.2 122.7
-------------------------
Proved Property Acquisitions 6.0 18.4 83.6/(1)/
Exploration Expenses 19.9 11.5 19.6
-------------------------
Total $122.6 $ 88.1 $225.9
=========================
-----------------------------------------------------------
/(1)/ Includes $70.1 million in oil and gas properties acquired from
Oryx Energy Company in December 1998.
Total capital and exploration expenditures for 2000 increased $34.5 million
compared to 1999, primarily as a result of the increased drilling program in
2000. The 2000 drilling program included an over 100% increase in net wells
drilled and a $3.5 million increase in geological and geophysical expenses,
including costs of obtaining seismic data. During the last half of 1999, we
acquired $17.4 million of oil and gas properties in the Moxa Arch in the Rocky
Mountains area, including 27 gross wells, approximately 16 Bcfe of proved
reserves and approximately 43,000 net undeveloped acres that complement our
existing Moxa Arch development.
We plan to drill 240 gross wells in 2001 compared with 129 gross wells
drilled in 2000. This 2001 drilling program includes $167.1 million in total
capital and exploration expenditures, up from $122.6 million in 2000, and is our
largest capital program to date. Expected spending in 2001 includes $93.0
million for drilling and facilities, and $48.6 million in exploration expenses.
In addition to the drilling and exploration program, other 2001 capital
expenditures are planned primarily for lease acquisitions 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.
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 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 $1.06 per
23
Mmbtu in 2000. In 1995 and 1996, we completed three transactions to monetize the
value of these tax credits, resulting in revenues of $2.2 million in 2000 and
approximately $4.1 million over the remaining two years. 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, to pay dividends, 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 7.19% Notes specify a minimum annual coverage ratio of
operating cash flow to interest expense for the trailing four quarters of 2.8 to
1.0. At December 31, 2000, the calculated ratio for 2000 was 6.3 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.
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 in 2000 was 44%
higher than in 1999. However, 1999 prices were up only 3% over 1998, after
declining 15% from 1997 to 1998. The volatility of natural gas prices in recent
years remains prevalent in 2001 with wide price swings in day-to-day trading on
the NYMEX futures market. Given this continued price volatility, we can not
predict with certainty what pricing levels will be in the future. Because
future cash flows are subject to these variables, there is no assurance that our
operations will provide cash sufficient to fully fund our planned capital
expenditures.
While our 2001 plan now includes $167.1 million in capital and exploration
spending, we will periodically assess industry conditions and adjust our 2001
spending plan to ensure the adequate funding of our capital requirements,
including, if necessary, reductions in capital and exploration expenditures or
common stock dividends.
We believe our capital resources, supplemented with external financing if
necessary, are adequate to meet our capital requirements.
The preceding paragraphs contain forward-looking information. See Forward-
Looking Information in the following paragraph.
* * *
24
Forward-Looking Information
The statements regarding future financial and operating performance and
results, and market prices and 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" and similar expressions are
also intended to identify forward-looking statements. Such statements involve
risks and uncertainties, including, but not limited to, market factors, market
prices (including regional basis differentials) of natural gas and oil, results
for future drilling and marketing activity, future production and costs and
other factors detailed herein and in our other Securities and Exchange
Commission filings. Should one or more of these risks or uncertainties
materialize, or should underlying assumptions prove incorrect, actual outcomes
may vary materially from those indicated.
25
RESULTS OF OPERATIONS
For the purpose of reviewing our results of operations, "Net Income" is
defined as net income available to common stockholders.
Selected Financial and Operating Data
(In millions except where specified) 2000 1999 1998
---------------------------------------------------------------------
Operating Revenues $368.7 $294.0 $251.3
Operating Expenses 303.8 258.5 224.4
Operating Income 64.8 39.5 27.4
Interest Expense 22.9 25.8 18.6
Net Income 29.2 5.1 1.9
Earnings Per Share - Basic $ 1.07 $ 0.21 $ 0.08
Earnings Per Share - Diluted 1.06 0.21 0.08
Natural Gas Production (Bcf)
Gulf Coast 14.1 15.5 10.6
West 29.0 29.3 30.9
Appalachia 17.8 20.7 22.7
-------------------------
Total Company 60.9 65.5 64.2
Produced Natural Gas Sales Price ($/Mcf)
Gulf Coast $ 3.79 $ 2.29 $ 2.15
West 2.86 1.96 1.90
Appalachia 3.24 2.53 2.53
Total Company 3.19 2.22 2.16
Crude/Condensate
Volume (Mbbl) 953 929 650
Price ($/Bbl) $26.81 $17.22 $13.06
The table below presents the after-tax effects of certain selected items on
our results of operations for the three years ended December 31, 2000.
(In millions) 2000 1999 1998
----------------------------------------------------------------
Net Income Before Selected Items $30.2 $ 0.4 $ 1.9
Buyout of Gas Sales Contract 7.3
Impairment of Long-Lived Assets (5.6) (4.3)
Gain on Sale of Assets 2.4
Section 29 Tax Credit Provision (0.7)
Negative Preferred Stock Dividend 5.1
Contract Settlements 1.4
Bad Debt Expense (1.3)
Severance Costs (0.6)
-----------------------
Net Income $29.2 $ 5.1 $ 1.9
=======================
These selected items impacted our financial results. Because they are not
a part of our normal business, we have isolated their effects in the table
above. These selected items for 2000 were as follows:
. A $9.1 million impairment ($5.6 million after tax) was recorded on the
Beaurline field in south Texas as a result of a casing collapse in two of
the field's wells.
. As a result of repurchasing all of the preferred stock at less than the
book value, we recorded a $5.1 million negative stock dividend in May 2000.
. Miscellaneous net revenue, primarily from the settlement of a natural gas
sales contract, was recorded in the first quarter ($1.4 million after tax).
26
. As a result of bankruptcy proceedings of two of our customers, we recorded
$2.1 million in bad debt expense in the fourth quarter ($1.3 million after
tax).
. We announced the closure of the regional office in Pittsburgh in May 2000
and recorded costs of $1.0 million ($0.6 million after tax). These costs
were recorded in the income statement categories that will receive the
future savings benefit ($0.6 million in operations, $0.1 million in
exploration and $0.3 million in administration).
These selected items for 1999 were as follows:
. We had a 15-year cogeneration contract under which we sold approximately
20% of our Western region natural gas per year. The contract was due to
expire in 2008, but during 1999 we reached an agreement with the
counterparty under which the counterparty bought out the remainder of the
contract for $12 million. This transaction, completed in December 1999,
accelerated the realization of any future price premium that may have been
associated with the contract and added $12 million of pre-tax other revenue
($7.3 million after tax). We simultaneously sold forward a similar quantity
of Western region gas production through April 2001 at similar prices to
those in the old contract. The natural gas sales price stated in this new
contract was significantly below year-end market prices in the region. If
market prices remain above the fixed contract price beyond April 2001, we
could expect to realize notably higher natural gas sales prices on this
production.
. In the fourth quarter of 1999, we recorded impairments totaling $7 million
on two of our producing fields in the Gulf Coast region ($4.3 million after
tax). The Chimney Bayou field was impaired by $6.6 million due to a
significant reserve revision on the Broussard-Middleton 1R well in
connection with a decline in its natural gas production accompanied by a
marked increase in water production. The Broussard-Middleton 1R was the
only producing well in this field. The Lawson field was impaired by $0.4
million due to an unsuccessful workover on one of its wells.
. We recorded a $4 million gain on the sale of certain non-strategic oil and
gas assets, most notably the Clarksburg properties in the Appalachian
region sold to EnerVest effective October 1999 ($2.4 million after tax).
. We recorded a $1.2 million reserve against other revenue for certain wells
no longer deemed to be eligible for the Section 29 tight gas sands credit
following an industry tax court ruling ($0.7 million after tax). Late in
1999, the FERC issued a rule proposal that may ultimately restore the
eligibility for some or all of the wells in question. For an update on the
FERC's actions, please read Note 13 of the Notes to the Consolidated
Financial Statements.
2000 and 1999 Compared
The following discussion is based on our results before taking into account
the selected items discussed above.
Net Income and Revenues. We reported net income in 2000 of $30.2 million,
or $1.10 per share. During 1999, we reported net income of $0.4 million, or
$0.02 per share. Operating income increased $42.9 million, or 135%, and
operating revenues increased $83.1 million, or 29%, in 2000. The improvement in
operating revenues was mainly a result of the $48.7 million rise in natural gas
sales due to the increase in gas prices, and the $24.5 million increase in
brokered natural gas sales revenue. Operating revenues were reduced by a $10
million loss on natural gas price collar arrangements used during 2000. See
further discussion in Item 7A. Price and production volume increases in crude
oil also contributed to the higher operating revenues. Operating income was
similarly impacted by these revenue changes.
The average Gulf Coast natural gas production sales price rose $1.50 per
Mcf, or 66%, to $3.79, increasing operating revenues by approximately $21.2
million. In the Western region, the average natural gas production sales price
increased $0.90 per Mcf, or 46%, to $2.86, increasing operating revenues by
approximately $24.9 million. The average Appalachian natural gas production
sales price increased $0.71 per Mcf, or 28%, to $3.24, increasing operating
revenues by approximately $12.7 million. The overall weighted average natural
gas production sales price increased $0.97 per Mcf, or 44%, to $3.19, increasing
revenues by $58.8 million.
Natural gas production volume in the Gulf Coast region was down 1.4 Bcf, or
9%, to 14.1 Bcf primarily
27
due to production difficulties in the Beaurline field and delays in bringing new
production on-line in south Louisiana. Natural gas production volume in the
Western region was down 0.3 Bcf to 29.0 Bcf due primarily to lower levels of
drilling activity in the Mid-Continent area during 1999 and 2000. Natural gas
production volume in the Appalachian region was down 2.9 Bcf to 17.8 Bcf, as a
result of the sale of certain non-strategic assets in the Appalachian region
effective October 1, 1999, and a decrease in drilling activity in the region.
Total natural gas production was down 4.6 Bcf, or 7%, generating a revenue
decrease of $10.1 million in 2000.
Crude oil prices rose $9.59 per Bbl, or 56%, to $26.81, resulting in an
increase to operating revenues of approximately $9.2 million. The volume of
crude oil sold in the year increased slightly to 953 Mbbls, increasing operating
revenues by $0.4 million.
Brokered natural gas revenue increased $24.5 million, or 21%, over the
prior year. The sales price of brokered natural gas rose 52%, resulting in an
increase in revenue of $48.5 million. The volume of natural gas brokered this
year declined by 21%, reducing revenues by $24.0 million. After including the
related brokered natural gas costs, we realized a net margin of $5.4 million in
2000.
Excluding the selected items regarding the contract settlements in 2000,
and the sales contract buyout and the Section 29 tax credit provision in 1999,
other operating revenues increased $0.2 million to $5.5 million.
Costs and Expenses. Total costs and expenses from operations, excluding
the selected items related to the impairment of long-lived assets in each year
and the costs associated with closing the regional office in Pittsburgh during
2000, increased $40.2 million, or 16%, from 1999 due primarily to the following:
. Brokered natural gas cost increased $23.5 million, or 21%, primarily due to
the $46.5 million impact of higher purchased natural gas prices. This was
partially offset by a $23.0 million reduction to purchased natural cost,
the result of fewer brokered sales this year compared to the prior year.
. Production and pipeline expense increased $1.9 million, or 6%, primarily as
a result of costs associated with the expansion of the Gulf Coast regional
office, both in staffing and office facilities. Additionally, operational
costs for surface equipment and compressor maintenance were up in the Rocky
Mountains area where we drilled 50% more net wells in 2000 compared to
1999. On a units-of-production basis, our company-wide production and
pipeline expense was $0.53 per Mcfe in 2000 versus $0.47 per Mcfe in 1999.
. Exploration expense increased $8.3 million, or 72%, primarily as a result
of the following:
. A $3.5 million increase in geological and geophysical expenses over last
year due to increased drilling activity in all regions.
. A $1.3 million increase in delay rental costs over last year largely due
to delays in scheduled drilling projects in the Gulf Coast region.
. A $2.1 million increase for salaries, wages and incentive compensation
largely attributable to increased staffing in the Gulf Coast region to
support the expanded drilling program.
. A $0.5 million increase in dry hole costs. Although the drilling success
rate improved from 84% in 1999 to 86% in 2000, we recorded two
exploratory dry holes in the higher cost Gulf Coast region versus only
one in 1999.
. Depreciation, depletion, amortization and impairment expense, excluding the
selected item related to the SFAS 121 impairment in each year, increased
$0.5 million, or 1%, over 1999. A 6% decrease in total natural gas
equivalent production caused the expense to remain just slightly above last
year's level, despite the 7% increase in the per unit expense to $0.86 per
Mcfe.
. General and administrative expenses remained at the same level as in 1999.
. Taxes other than income increased $6.1 million as a result of higher
natural gas and oil revenues.
Interest expense decreased $2.9 million primarily due to lower average
levels of borrowing on the revolving credit facility.
Income tax expense was up $18.1 million due to the comparable increase in
earnings before income tax.
No significant asset sale activity occurred in 2000. Gain on the sale of
assets was $4 million for 1999.
28
These gains are the result of the non-strategic asset divestitures, primarily
the sale of the Clarksburg properties in the Appalachian region to EnerVest
effective October 1999.
1999 and 1998 Compared
The following discussion is based on our results before taking into account
the selected items discussed above.
Net Income and Revenues. We reported net income in 1999 of $0.4 million,
or $0.02 per share. During 1998, we reported net income of $1.9 million, or
$0.08 per share. Operating income increased $4.4 million, or 16%, and operating
revenues increased $31.9 million, or 13%, in 1999. The improvement in operating
revenues was mainly a result of the $19.3 million increase in brokered natural
gas revenue and the $7.4 million rise in crude oil and condensate sales, due to
both price improvements and production volume increases. Price and production
volume increases in natural gas also contributed to the higher operating
revenues. Operating income was similarly impacted by these revenue changes.
Net income was reduced by a $7.2 million increase in interest expense.
Natural gas production volume in the Gulf Coast region was up 4.9 Bcf, or
46%, to 15.5 Bcf primarily due to production from the Oryx acquisition, recent
discoveries and development in the Kacee field in south Texas, and the
redrilling of certain wells in the Beaurline field. Natural gas production
volume in the Western region was down 1.6 Bcf to 29.3 Bcf due primarily to lower
levels of drilling activity in the Mid-Continent area during 1998 and 1999.
Natural gas production volume in the Appalachian region was down 2.0 Bcf to 20.7
Bcf, as a result of the sale of certain non-strategic assets in the Appalachian
region effective October 1, 1999, and a decrease in drilling activity in the
region in 1999. Total natural gas production was up 1.3 Bcf, or 2%, yielding a
revenue increase of $2.7 million in 1999.
The average Gulf Coast natural gas production sales price rose $0.14 per
Mcf, or 7%, to $2.29, increasing operating revenues by approximately $2.2
million. In the Western region, the average natural gas production sales price
increased $0.06 per Mcf, or 3%, to $1.96, increasing operating revenues by
approximately $1.8 million. The average Appalachian natural gas production
sales price remained flat to last year at $2.53 per Mcf. The overall weighted
average natural gas production sales price increased $0.06 per Mcf, or 3%, to
$2.22, increasing revenues by $3.9 million.
The volume of crude oil sold in the year increased by 279 Mbbls, or 43%, to
929 Mbbls, increasing operating revenues by $3.6 million. The volume increase
was largely due to production from the Oryx acquisition. Crude oil prices rose
$4.16 per Bbl, or 32%, to $17.22, resulting in an increase to operating revenues
of approximately $3.8 million.
Brokered natural gas revenue increased $19.3 million or 20% over the prior
year. The sales price of brokered natural gas rose 5% resulting in an increase
in revenue of $4.9 million. Additionally, the volume of natural gas brokered
this year increased by 15%, increasing revenues by $14.4 million. After
including the related brokered natural gas costs, we realized a net margin of
$4.4 million in 1999.
Excluding the selected items regarding the sales contract buyout and the
Section 29 tax credit provision, other operating revenues decreased $1.3 million
to $5.4 million. The decline was a result of decreases in activity in the
following areas:
. Transportation revenue declined $0.6 million.
. Revenue from our brine treatment plants declined $0.3 million.
. Natural gas liquid sales declined $0.2 million due to lower activity levels
during 1999.
. Section 29 revenues decreased slightly due to normal production decline.
Costs and Expenses. Total costs and expenses from operations, excluding the
selected item related to the impairment of long-lived assets, increased $27.0
million, or 12%, from 1998 due primarily to the following:
. Brokered natural gas cost increased $20.4 million, or 22%, primarily due to
15% increase in volume which added $13.5 million of cost. Additionally, the
purchase cost of natural gas rose 7% resulting in an increase
29
in brokered natural gas cost of $6.9 million.
. Production and pipeline expense increased $3.1 million, or 10%, primarily
as a result of the incremental cost of operating the Oryx properties
acquired in December 1998. On a units-of-production basis, production and
pipeline expense was $0.47 per Mcfe in 1999 versus $0.44 per Mcfe in 1998.
. Exploration expense decreased $8.1 million, or 41%, primarily as a result
of:
. A $5.5 million reduction in dry hole costs from 1998, largely due to a
smaller drilling program in 1999 that resulted in seven dry holes
compared to 12 dry holes in 1998.
. A $2.2 million decrease in geological and geophysical costs over last
year largely due to a decline in seismic acquisition costs in the
Appalachian region.
. Depreciation, depletion, amortization and impairment expense, excluding the
select item related to the SFAS 121 impairment, increased $11.7 million, or
26%, over 1998. This increase was due to costs associated with the Oryx
properties, as well as higher finding costs in 1998 on certain fields in
the Gulf Coast region that were largely related to mechanical difficulties
associated with drilling. A 4% increase in total natural gas equivalent
production, including a 59% production increase in the higher finding cost
Gulf Coast region, is the other major component of the DD&A increase.
. General and administrative expenses decreased $1.8 million, or 8%, due to:
. Lower non-cash stock compensation expense for stock awards ($1.2
million).
. Lower outside consulting services ($0.6 million).
Interest expense increased $7.2 million primarily due to the debt increase
for the Oryx acquisition in December 1998 and to partially fund the 1998
drilling program.
Income tax expense was up $1.7 million due to the comparable increase in
earnings before income tax.
Gain on the sale of assets totaled $4 million for 1999 compared to $0.5
million in 1998. These gains are the result of the non-strategic asset
divestitures, primarily the sale of the Clarksburg properties in the Appalachian
region to EnerVest effective October 1999.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Oil and gas prices fluctuate widely, and low prices for an extended period of
time are likely to have a material adverse impact on our business.
Our revenues, operating results, financial condition and ability to borrow
funds or obtain additional capital depend substantially on prevailing prices for
natural gas and, to a lesser extent, oil. Declines in oil and natural gas prices
may materially adversely affect our financial condition, liquidity, ability to
obtain financing and operating results. Lower oil and gas prices also may reduce
the amount of oil and gas that we can produce economically. Historically, oil
and gas prices and markets have been volatile, with prices fluctuating widely,
and they are likely to continue to be volatile. Oil and gas prices declined
substantially in 1998 and, despite recent improvement, could decline again.
Because our reserves are predominantly natural gas, changes in natural gas
prices may have a particularly significant impact on our financial results.
Prices for oil and natural gas are subject to wide fluctuations in response
to relatively minor changes in the supply of and demand for oil and gas, market
uncertainty and a variety of additional factors that are beyond our control.
These factors include:
. The domestic and foreign supply of oil and natural gas.
. The level of consumer product demand.
. Weather conditions.
. Political conditions in oil producing regions, including the Middle East.
. The ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls.
. The price of foreign imports.
. Actions of governmental authorities.
30
. Domestic and foreign governmental regulations.
. The price, availability and acceptance of alternative fuels.
. Overall economic conditions.
These factors make it impossible to predict with any certainty the future prices
of oil and gas.
In order to reduce our exposure to short-term fluctuations in the price of
oil and natural gas, we sometimes enter into hedging arrangements. Our hedging
arrangements apply to only a portion of our production and provide only partial
price protection against declines in oil and gas prices. These hedging
arrangements may expose us to risk of financial loss and limit the benefit to us
of increases in prices. Please read the discussion below related to commodity
price swaps and Note 11 of the Notes to the Consolidated Financial Statements
for a more detailed discussion of our hedging arrangements.
Commodity Price Swaps and Options
Hedges on our Production
From time to time, we enter into natural gas and crude oil swap agreements
with counterparties to hedge price risk associated with a portion of our
production. These derivatives are not held for trading purposes. Under these
price swaps, we receive a fixed price on a notional quantity of natural gas and
crude oil in exchange for paying a variable price based on a market-based index,
such as the NYMEX gas and crude oil futures. During 2000, we fixed the price at
an average of $4.54 per Mcf on quantities totaling 315 Mmcf, representing less
than 1% of the Company's 2000 natural gas production. The notional volume of
the crude oil swap transactions was 364 Mbbls at a price of $22.67 per Bbl,
which represents approximately 38% of our total oil production for 2000.
During 1999, we fixed the price at an average of $2.88 per Mcf on quantities
totaling 3,237 Mmcf, representing 5% of the Company's 1999 natural gas
production. The notional volume of the crude oil swap transactions was 306
Mbbls at a price of $20.65 per Bbl, which represents approximately one-third of
our total oil production for 1999. During 1998, we did not enter into any fixed
price swaps to hedge oil or natural gas production.
As of the years ending December 31, 2000, and 1999, we had open natural gas
price swap contracts on our production as follows:
Natural Gas Price Swaps
----------------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Mmcf Contract Price (in $ millions)
-----------------------------------------------------------------------------------------------------------
As of December 31, 2000
----------------------
Natural Gas Price Swaps on Our Production in:
---------------------------------------------
Full Year 2001 918 $3.75 $(2.8)
Full Year 2002 678 3.11 (1.0)
Full Year 2003 423 2.81 (0.5)
As of December 31, 1999
-----------------------
None
Financial derivatives related to natural gas production reduced revenues by
$0.3 million in 2000 and $0.3 million in 1999.
31
We had open oil price swap contracts on our production as follows:
Oil Price Swaps
------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Bbls Contract Price (in $ millions)
--------------------------------------------------------------------------------------------
As of December 31, 2000
-----------------------
None
As of December 31, 1999
-----------------------
Oil Price Swaps on Our Production in:
-------------------------------------
First Quarter 2000 182,000 $22.25 $(0.5)
Second Quarter 2000 182,000 23.08 (0.1)
Financial derivatives related to crude oil reduced revenue by $2.2 million
during 2000 and by $0.8 million during 1999. There were no crude oil price swaps
outstanding at December 31, 1998.
During 2000, we used several costless collar arrangements to hedge a
portion of our natural gas production. There were seven collar arrangements
based on separate regional price indexes with a weighted average price floor of
$2.74/Mcf and a weighted average price ceiling of $3.38/Mcf. These collars were
in place during the months of April through October 2000. During this period, if
the index rose above the ceiling price, we paid the counterparty. If the
applicable index fell below the floor price, the counterparty paid us. These
collars covered a total quantity of 9,909 Mmcf, or 16% of our annual production.
In April and May 2000, the index prices all fell within the price collar and no
settlements were made. In June 2000, all of the indexes rose above the ceiling
prices and remained above the ceiling for the duration of the transaction
resulting in a $10 million reduction to our realized revenue for the year. If
these hedges had not been in place, our average realized natural gas price for
2000 would have been $0.17 per Mcf higher. There were no commodity price collars
in place during 1999.
In December 2000, we believed that the pricing environment provided a
strategic opportunity to significantly reduce the price risk on a portion of our
production through the use of costless collars. As of December 31, 2000, we had
open natural gas costless price collar arrangements to hedge our 2001 production
as follows:
Natural Gas Price Collars
-------------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Mmcf Ceiling / Floor (in $ millions)
-------------------------------------------------------------------------------------------------------
As of December 31, 2000
-------------------------------
Natural Gas Costless Collars on Our Production in:
--------------------------------------------------
First Quarter of 2001 5,274 $9.68/$5.59 --
Second Quarter of 2001 8,135 $9.68/$5.59 --
Third Quarter of 2001 8,224 $9.68/$5.59 --
Fourth Quarter of 2001 2,771 $9.68/$5.59 --
The natural gas price hedges, noted above, include several costless collar
arrangements based on eight price indexes at which we sell a portion of our
production. These hedges are in place for the months of February through
October 2001 and cover approximately half of our natural gas production during
this period.
Hedges on Brokered Transactions
We use price swaps to hedge the natural gas price risk on brokered
transactions. Typically, we enter into contracts to broker natural gas at a
variable price based on the market index price. However, in some circumstances,
some of our customers or suppliers request that a fixed price be stated in the
contract. After entering into these fixed price contracts to meet the needs of
our customers or suppliers, we may use price swaps to effectively convert these
fixed price contracts to market-sensitive price contracts. These price swaps are
held by us to their maturity and are not held for trading purposes.
32
We entered into price swaps with total notional quantities of 1,295 Mmcf in
2000, 3,572 Mmcf in 1999, and 1,971 Mmcf in 1998, related to our brokered
activities, representing 3%, 7%, and 5%, respectively, of our total volume of
brokered natural gas sold.
As of the years ending December 31, 2000, and 1999, we had open natural gas
price swap contracts on brokered transactions as follows:
Natural Gas Price Swaps
---------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Mmcf Contract Price (in $ millions)
-------------------------------------------------------------------------------------------------
As of December 31, 2000
-----------------------
None
As of December 31, 1999
-----------------------
Natural Gas Price Swaps on Brokered Transactions in:
----------------------------------------------------
First Quarter 2000 1,010 $2.26 $(0.2)
Financial derivatives related to natural gas reduced revenues by less than
$0.1 million in 2000 and increased revenues by $0.1 million in 1999.
We are exposed to market risk on these open contracts, to the extent of
changes in market prices of natural gas and oil. However, the market risk
exposure on these hedged contracts is generally offset by the gain or loss
recognized upon the ultimate sale of the commodity that is hedged.
Since its issuance, we have been modeling the impact of Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" (SFAS 133). We had two types of hedges in place as of
January 1, 2001 when SFAS 133 and SFAS 138 became effective. The first type is a
cash flow hedge that fixes the price of a certain monthly quantity of natural
gas sold in the Gulf Coast region through September 2003. Based on the current
index price strip, the impact of this hedge on January 1, 2001 was to record a
Hedge Loss of $0.1 million and a charge to Other Comprehensive Income of $4.2
million. Correspondingly, a Hedge Liability for $4.3 million was established.
The second type of hedge is a natural gas price costless collar agreement.
We entered into eight of these collars for a portion of our production at
regional indexes for the months of February through October 2001. The collars
have two components of value: intrinsic value and time value. Under SFAS 133,
both components will be valued at the end of each reporting period. Intrinsic
value arises when the index price is either above the ceiling or below the floor
for any period covered by the collar. If the index is above the ceiling for any
month covered by the collar, the intrinsic value would be the difference between
the index and the ceiling prices multiplied by the notional volume. Similar to
the current accounting treatment, intrinsic value related to the current month
would be recorded as a hedge loss (if the index is above the ceiling) or gain
(if the index is below the floor). Starting in 2001 under SFAS 133, any changes
in the intrinsic value component related to future months will be recorded in
Other Comprehensive Income, a component of stockholders' equity on the balance
sheet, rather than to the income statement to the extent that the hedge is
proven to be effective. In the case of these natural gas price collars, full
effectiveness with respect to the intrinsic value calculation is anticipated as
they are tied to the same indexes at which our natural gas is sold. Also new
under SFAS 133, the time value component, a market premium/discount, is marked-
to-market through the income statement each period. Since these collar
arrangements were executed on the last business day of 2000, the net premium
value at adoption on January 1, 2001 is zero.
33
Fair Market Value of Financial Instruments
The estimated fair value of financial instruments is the amount at which
the instrument could be exchanged currently between willing parties. The
carrying amounts reported in the consolidated balance sheet for cash and cash
equivalents, accounts receivable and accounts payable approximate fair value.
We use available marketing data and valuation methodologies to estimate the fair
value of debt.
December 31, 2000 December 31, 1999
Carrying Estimated Carrying Estimated
(In thousands) Amount Fair Value Amount Fair Value
----------------------------------------------------------------------
Debt
10.18% Notes $ 32,000 $ 33,162 $ 48,000 $ 50,020
7.19% Notes 100,000 97,033 100,000 91,237
Credit Facility 137,000 137,000 145,000 145,000
--------------------------------------------
$269,000 $267,195 $293,000 $286,257
============================================
34
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
--------------------------------------------------------
Report of Independent Accountants 36
Consolidated Statement of Operations 37
Consolidated Balance Sheet 38
Consolidated Statement of Cash Flows 39
Consolidated Statement of Stockholders' Equity 40
Notes to the Consolidated Financial Statements 41
Supplemental Oil and Gas Information (Unaudited) 61
Quarterly Financial Information (Unaudited) 65
REPORT OF MANAGEMENT
The management of Cabot Oil & Gas Corporation is responsible for the
preparation and integrity of all information contained in the annual report.
The consolidated financial statements are prepared in conformity with generally
accepted accounting principles and, accordingly, include certain informed
judgments and estimates of management.
Management maintains a system of internal accounting and managerial
controls and engages internal audit representatives who monitor and test the
operation of these controls. Although no system can ensure the elimination of
all errors and irregularities, the system is designed to provide reasonable
assurance that assets are safeguarded, transactions are executed in accordance
with management's authorization, and accounting records are reliable for
financial statement preparation.
An Audit Committee of the Board of Directors, consisting of directors who
are not employees of the Company, meets periodically with management, the
independent accountants and internal audit representatives to obtain assurances
to the integrity of the Company's accounting and financial reporting and to
affirm the adequacy of the system of accounting and managerial controls in
place. The independent accountants and internal audit representatives have full
and free access to the Audit Committee to discuss all appropriate matters.
We believe that the Company's policies and system of accounting and
managerial controls reasonably assure the integrity of the information in the
consolidated financial statements and in the other sections of the annual
report.
Ray Seegmiller
Chairman of the Board, Chief Executive Officer and President
February 22, 2001
35
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors of Cabot Oil & Gas Corporation:
In our opinion, the consolidated financial statements listed in the
accompanying index present fairly, in all material respects, the financial
position of Cabot Oil & Gas Corporation and its subsidiaries at December 31,
2000 and 1999, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 2000 in conformity with
accounting principles generally accepted in the United States of America. These
financial statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Houston, Texas
February 16, 2001
36
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
Year Ended December 31,
(In thousands, except per share amounts) 2000 1999 1998
---------------------------------------------------------------------------
OPERATING REVENUES
Natural Gas Production $194,185 $145,495 $138,903
Brokered Natural Gas 141,085 116,554 97,281
Crude Oil and Condensate 25,544 15,909 8,486
Other (Note 13) 7,837 16,079 6,670
-----------------------------
368,651 294,037 251,340
OPERATING EXPENSES
Brokered Natural Gas Cost 135,700 112,164 91,734
Production and Pipeline Operations 35,727 33,357 30,250
Exploration 19,858 11,490 19,564
Depreciation, Depletion and Amortization 53,441 53,357 41,186
Impairment of Unproved Properties 4,368 3,950 4,402
Impairment of Long-Lived Assets 9,143 7,047 --
General and Administrative 20,421 20,136 21,950
Bad Debt Expense (Note 3) 2,096 -- --
Taxes Other Than Income 23,041 16,988 15,324
-----------------------------
303,795 258,489 224,410
Gain (Loss) on Sale of Assets (39) 3,950 473
-----------------------------
INCOME FROM OPERATIONS 64,817 39,498 27,403
Interest Expense 22,878 25,818 18,598
-----------------------------
Income Before Income Tax Expense 41,939 13,680 8,805
Income Tax Expense 16,467 5,161 3,501
-----------------------------
NET INCOME 25,472 8,519 5,304
Preferred Stock Dividend (Note 10) (3,749) 3,402 3,402
-----------------------------
Net Income Available to
Common Stockholders $ 29,221 $ 5,117 $ 1,902
=============================
Basic Earnings per Share Available
to Common Stockholders $ 1.07 $ 0.21 $ 0.08
Diluted Earnings per Share Available
to Common Stockholders $ 1.06 $ 0.21 $ 0.08
Average Common Shares Outstanding 27,384 24,726 24,733
The accompanying notes are an integral part of these consolidated financial
statements.
37
CABOT OIL & GAS CORPORATION
CONSOLIDATED BALANCE SHEET
December 31,
(In thousands, except share amounts) 2000 1999
---------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 7,574 $ 1,679
Accounts Receivable 85,677 50,391
Inventories 11,037 10,929
Other 5,981 3,641
-------------------
Total Current Assets 110,269 66,640
PROPERTIES AND EQUIPMENT (Successful Efforts Method) 623,174 590,301
OTHER ASSETS 2,191 2,539
-------------------
$735,634 $659,480
===================
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current Portion of Long-Term Debt $ 16,000 $ 16,000
Accounts Payable 81,566 56,551
Accrued Liabilities 20,542 17,387
-------------------
Total Current Liabilities 118,108 89,938
LONG-TERM DEBT 253,000 277,000
DEFERRED INCOME TAXES 108,174 95,012
OTHER LIABILITIES 13,847 11,034
COMMITMENTS AND CONTINGENCIES (Note 8)
STOCKHOLDERS' EQUITY
Preferred Stock
Authorized - 5,000,000 Shares of $0.10 Par Value
-6% Convertible Redeemable Preferred; $50 Stated
Value;
No Shares Outstanding in 2000 and
1,134,000 Shares Outstanding in 1999 (Note 10) 0 113
Common Stock
Authorized - 40,000,000 Shares of $0.10 Par Value
Issued and Outstanding -
29,494,411 Shares in 2000 and
25,073,660 Shares in 1999 2,949 2,507
Class B Common Stock
Authorized - 800,000 Shares of $0.10 Par Value
No Shares Issued -- --
Additional Paid-in Capital 285,572 254,763
Accumulated Deficit (41,632) (66,503)
Less Treasury Stock, at Cost
302,600 Shares in 2000 and 1999 (4,384) (4,384)
-------------------
Total Stockholders' Equity 242,505 186,496
-------------------
$735,634 $659,480
===================
The accompanying notes are an integral part of these consolidated financial
statements.
38
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended December 31,
(In thousands) 2000 1999 1998
---------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 25,472 $ 8,519 $ 5,304
Adjustments to Reconcile Net Income
to Cash Provided by Operations
Depletion, Depreciation and Amortization 53,441 53,357 41,186
Impairment of Unproved Properties 4,368 3,950 4,402
Impairment of Long-Lived Assets 9,143 7,047 --
Deferred Income Tax Expense 13,162 9,060 5,844
(Gain) Loss on Sale of Assets 39 (3,950) (473)
Exploration Expense 19,858 11,490 19,564
Other 1,141 2,439 1,834
Changes in Assets and Liabilities
Accounts Receivable (35,286) 5,408 3,873
Inventories (108) (1,617) (2,437)
Other Current Assets (2,357) 164 (1,602)
Other Assets 348 598 (1,264)
Accounts Payable and Accrued Liabilities 26,976 (5,505) 10,263
Other Liabilities 2,813 1,528 743
---------------------------------
Net Cash Provided by Operations 119,010 92,488 87,237
---------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (99,359) (82,191) (203,632)
Proceeds from Sale of Assets 3,150 56,328 1,054
Exploration Expense (19,858) (11,490) (19,564)
---------------------------------
Net Cash Used by Investing (116,067) (37,353) (222,142)
---------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt 135,000 125,000 217,000
Decrease in Debt (159,000) (175,000) (73,000)
Sale of Common Stock 85,104 1,738 3,589
Retirement of Preferred Stock (51,600) -- --
Treasury Stock Purchases -- -- (4,384)
Preferred Dividends Paid (2,202) (3,402) (3,402)
Common Dividends Paid (4,350) (3,992) (3,974)
Increase in Debt Issuance Cost and Other -- -- (508)
---------------------------------
Net Cash Provided (Used) by Financing 2,952 (55,656) 135,321
---------------------------------
Net Increase (Decrease) in Cash and
Cash Equivalents 5,895 (521) 416
Cash and Cash Equivalents, Beginning of Year 1,679 2,200 1,784
---------------------------------
Cash and Cash Equivalents, End of Year $ 7,574 $ 1,679 $ 2,200
=================================
The accompanying notes are an integral part of these consolidated financial
statements.
39
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
Retained
Common Preferred Treasury Paid-In Earning
(In thousands) Stock Stock Stock Capital (Deficit) Total
---------------------------------------------------------------------------------------------
Balance at December 31, 1997 $2,467 $ 113 $247,033 $(65,551) $184,062
============================================================
Net Income 5,304 5,304
Exercise of Stock Options 21 3,568 3,589
Preferred Stock Dividends (3,402) (3,402)
Common Stock Dividends
at $0.16 per Share (3,974) (3,974)
Stock Grant Vesting 8 1,472 1,480
Treasury Stock Repurchase $(4,384) (4,384)
Other (7) (7)
------------------------------------------------------------
Balance at December 31, 1998 $2,496 $ 113 $(4,384) $252,073 $(67,630) $182,668
============================================================
Net Income 8,519 8,519
Exercise of Stock Options 7 1,492 1,499
Preferred Stock Dividends (3,402) (3,402)
Common Stock Dividends
at $0.16 per Share (3,992) (3,992)
Stock Grant Vesting 4 1,198 1,202
Other 2 2
------------------------------------------------------------
Balance at December 31, 1999 $2,507 $ 113 $(4,384) $254,763 $(66,503) $186,496
============================================================
Net Income 25,472 25,472
Exercise of Stock Options 77 14,764 14,841
Preferred Stock Dividends 3,749 3,749
Common Stock Dividends
at $0.16 per Share (4,350) (4,350)
Stock Grant Vesting 25 1,412 1,437
Issuance of Common Stock 340 71,219 71,559
Retirement of Preferred Stock (113) (56,586) (56,699)
------------------------------------------------------------
Balance at December 31, 2000 $2,949 $ 0 $(4,384) $285,572 $(41,632) $242,505
============================================================
The accompanying notes are an integral part of these consolidated financial
statements.
40
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
Cabot Oil & Gas Corporation and its subsidiaries are engaged in the
exploration, development, production and marketing of natural gas and, to a
lesser extent, crude oil and natural gas liquids. The Company also transports,
stores, gathers and purchases natural gas for resale. The Company operates in
one segment, natural gas and oil exploration and exploitation within the
continental United States.
The consolidated financial statements contain the accounts of the Company
after eliminating all significant intercompany balances and transactions.
Pipeline Exchanges
Natural gas gathering and pipeline operations normally include exchange
arrangements with customers and suppliers. The volumes of natural gas due to or
from the Company under exchange agreements are recorded at average selling or
purchase prices, as the case may be, and are adjusted monthly to reflect market
changes. The net value of exchanged natural gas is included in inventories in
the consolidated balance sheet.
Properties and Equipment
The Company uses the successful efforts method of accounting for oil and
gas producing activities. Under this method, acquisition costs for proved and
unproved properties are capitalized when incurred. Exploration costs, including
geological and geophysical costs, the costs of carrying and retaining unproved
properties and exploratory dry hole drilling costs, are expensed. Development
costs, including the costs to drill and equip development wells, and successful
exploratory drilling costs to locate proved reserves are capitalized.
The impairment of unamortized capital costs is measured at a lease level
and is reduced to fair value if it is determined that the sum of expected future
net cash flows is less than the net book value. The Company determines if an
impairment has occurred through either adverse changes or as a result of the
annual review of all fields. During 2000, two wells in the Beaurline field in
south Texas experienced casing collapses. This situation resulted in an
impairment to this field of $9.1 million, recorded in the second quarter
financial results. During the fourth quarter of 1999, the Company experienced a
significant production decline from the Chimney Bayou field located in the Texas
Gulf Coast. This decline along with an unsuccessful workover in the Lawson field
in Louisiana resulted in a $7 million impairment of long-lived assets during
1999. These impairments were measured based on discounted cash flows utilizing a
discount rate appropriate for risks associated with the related properties.
Capitalized costs of proved oil and gas properties, after considering
estimated dismantlement, restoration and abandonment costs, net of estimated
salvage values, are depreciated and depleted on a field basis by the units-of-
production method using proved developed reserves. The costs of unproved oil and
gas properties are generally combined and amortized over a period that is based
on the average holding period for such properties and the Company's experience
of successful drilling. Properties related to gathering and pipeline systems and
equipment are depreciated using the straight-line method based on estimated
useful lives ranging from 10 to 25 years. Certain other assets are also
depreciated on a straight-line basis.
Future estimated plug and abandonment costs are accrued over the productive
life of the oil and gas properties on a units-of-production basis. The accrued
liability for plug and abandonment costs is included in accumulated
depreciation, depletion and amortization.
Costs of retired, sold or abandoned properties that make up a part of an
amortization base (partial field) are charged to accumulated depreciation,
depletion and amortization if the units-of-production rate is not significantly
affected. Accordingly, a gain or loss, if any, is recognized only when a group
of proved properties (entire field) that make up the amortization base has been
retired, abandoned or sold.
41
Revenue Recognition and Gas Imbalances
The Company applies the sales method of accounting for natural gas revenue.
Under this method, revenues are recognized based on the actual volume of natural
gas sold to purchasers. Natural gas production operations may include joint
owners who take more or less than the production volumes entitled to them on
certain properties. Production volume is monitored to minimize these natural gas
imbalances. A natural gas imbalance liability is recorded in other liabilities
in the consolidated balance sheet if the Company's excess takes of natural gas
exceed its estimated remaining proved reserves for these properties.
Brokered Natural Gas Margin
In prior years, the revenues and expenses related to brokering natural gas
were reported net on the Consolidated Statement of Operations as Brokered
Natural Gas Margin. Beginning in 2000, these amounts are reported gross as part
of Operating Revenues and Operating Expenses. Prior year amounts have been
reclassified to conform to the current year presentation.
The Company realizes brokered margin as a result of buying and selling
natural gas in back-to-back transactions. The Company realized $5.4 million,
$4.4 million and $5.5 million of brokered natural gas margin in 2000, 1999 and
1998, respectively.
Income Taxes
The Company follows the asset and liability method of accounting for income
taxes. Under this method, deferred tax assets and liabilities are recorded for
the estimated future tax consequences attributable to the differences between
the financial carrying amounts of existing assets and liabilities and their
respective tax bases. Deferred tax assets and liabilities are measured using the
tax rate in effect for the year in which those temporary differences are
expected to turn around. The effect of a change in tax rates on deferred tax
assets and liabilities is recognized in the year of the enacted rate change.
Natural Gas Measurement
The Company records estimated amounts for natural gas revenues and natural
gas purchase costs based on volumetric calculations under its natural gas sales
and purchase contracts. Variances or imbalances resulting from such calculations
are inherent in natural gas sales, production, operation, measurement, and
administration. Management does not believe that differences between actual and
estimated natural gas revenues or purchase costs attributable to the unresolved
variances or imbalances are material.
Accounts Payable
This account includes credit balances to the extent that checks issued have
not been presented to the Company's bank for payment. These credit balances
included in accounts payable were $12.7 million at December 31, 2000, and $5.9
million at December 31, 1999.
Risk Management Activities
From time to time, the Company enters into derivative contracts, such as
natural gas price swaps or costless price collars, as a hedging strategy to
manage commodity price risk associated with its inventories, production or other
contractual commitments. These transactions are executed for purposes other than
trading. Gains or losses on these hedging activities are generally recognized
over the period that the inventory, production or other underlying commitment is
hedged as an offset to the specific hedged item. Cash flows related to any
recognized gains or losses associated with these hedges are reported as cash
flows from operations. If a hedge is terminated prior to expected maturity,
gains or losses are deferred and included in income in the same period that the
underlying production or other contractual commitment is delivered. Unrealized
gains or losses associated with any derivative contract not considered a hedge
would be recognized currently in the results of operations.
42
A derivative instrument qualifies as a hedge if all of the following tests
are met:
. The item to be hedged exposes the Company to price risk.
. The derivative reduces the risk exposure and is designated as a hedge at
the time the Company enters into the contract.
. At the inception of the hedge and throughout the hedge period there is a high
correlation between changes in the market value of the derivative instrument
and the fair value of the underlying item being hedged.
When the designated item associated with a derivative instrument matures,
is sold, extinguished or terminated, derivative gains or losses are recognized
as part of the gain or loss on the sale or settlement of the underlying item.
For example, in the case of natural gas price hedges, the gain or loss is
reflected in natural gas revenue. When a derivative instrument is associated
with an anticipated transaction that is no longer expected to occur or if
correlation no longer exists, the gain or loss on the derivative is recognized
currently in the results of operations to the extent the market value changes in
the derivative have not been offset by the effects of the price changes on the
hedged item since the inception of the hedge. See Note 11 Financial Instruments
for further discussion.
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). SFAS 133 requires all
derivatives to be recognized in the statement of financial position as either
assets or liabilities and measured at fair value. In addition, all hedging
relationships must be designated, reassessed and documented according to the
provisions of SFAS 133. This statement was initially effective for financial
statements for fiscal years beginning after June 15, 1999. However, in June
1999, the FASB issued SFAS 137, "Accounting for Derivative Instruments and
Hedging Activities - Deferral of Effective Date of SFAS 133," which delayed the
effective date of SFAS 133 to fiscal years beginning after June 15, 2000. In
June 2000, the FASB issued SFAS 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities". This pronouncement amended portions
of SFAS 133 and was adopted with SFAS 133 effective January 1, 2001.
Since the issuance of SFAS 133 and SFAS 138, the Company has been modeling
the proforma impact on our financial statements. The Company has certain cash
flow hedges (a price swap and eight costless collar arrangements) in place,
which were open as of January 1, 2001 when SFAS 133 and SFAS 138 became
effective. Based on the first of the year index price strip, the combined impact
of these hedges at adoption was a Hedge Loss of $0.1 million and a charge to
Other Comprehensive Income of $4.2 million. Correspondingly, a Hedge Liability
for $4.3 million was established.
Cash Equivalents
The Company considers all highly liquid short-term investments with
original maturities of three months or less to be cash equivalents. At December
31, 2000, and 1999, the majority of cash and cash equivalents is concentrated in
one financial institution. The Company periodically assesses the financial
condition of the institution and believes that any possible credit risk is
minimal.
Use of Estimates
In preparing financial statements, the Company follows generally accepted
accounting principles. These principles require management to make estimates and
assumptions that affect the reported amounts of assets and liabilities, the
disclosure of contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenues and expenses during the
reporting period. The Company's most significant financial estimates are based
on the remaining proved oil and gas reserves (see Supplemental Oil and Gas
Information). Actual results could differ from those estimates.
43
2. Properties and Equipment
Properties and equipment are comprised of the following:
December 31,
(In thousands) 2000 1999
-------------------------------------------------------------------
Proved Oil and Gas Properties $ 993,397 $ 906,852
Unproved Oil and Gas Properties 31,780 32,262
Gathering and Pipeline Systems 128,257 124,708
Land, Building and Improvements 4,538 4,359
Other 25,601 23,206
-----------------------
1,183,573 1,091,387
Accumulated Depreciation,
Depletion, Amortization and Impairments (560,399) (501,086)
-----------------------
$ 623,174 $ 590,301
=======================
As a component of accumulated depreciation, depletion and amortization,
total future plug and abandonment costs were $12.4 million at December 31, 2000,
and $11.5 million at December 31, 1999. The Company believes that this accrual
method adequately provides for its estimated future plug and abandonment costs
over the reserve life of the oil and gas properties.
3. Additional Balance Sheet Information
Certain balance sheet amounts are comprised of the following:
December 31,
(In thousands) 2000 1999
------------------------------------------------------------
Accounts Receivable
Trade Accounts $79,773 $44,739
Joint Interest Accounts 4,074 4,395
Insurance Recoveries 0 1,177
Current Income Tax Receivable 37 111
Other Accounts 4,347 263
-----------------
88,231 50,685
Allowance for Doubtful Accounts /(1)/ (2,554) (294)
-----------------
$85,677 $50,391
=================
Accounts Payable
Trade Accounts $20,855 $12,195
Natural Gas Purchases 12,525 14,918
Wellhead Gas Imbalances 2,185 2,177
Royalty and Other Owners 22,858 11,316
Capital Costs 13,486 10,103
Dividends Payable 0 851
Taxes Other than Income 2,654 1,279
Drilling Advances 456 614
Other Accounts 6,547 3,098
-----------------
$81,566 $56,551
=================
------------------------------------------------------------
/(1)/ Includes a $2.1 million addition in 2000 in connection with two trade
receivable accounts determined not to be collectible due to recent
bankruptcy filings of the customers.
44
December 31,
(In thousands) 2000 1999
---------------------------------------------------------------------
Accrued Liabilities
Employee Benefits $ 5,441 $ 5,203
Taxes Other than Income 11,363 8,471
Interest Payable 2,478 2,780
Other Accrued 1,260 933
-----------------
$20,542 $17,387
=================
Other Liabilities
Postretirement Benefits Other than Pension $ 1,497 $ 799
Accrued Pension Cost 6,743 6,290
Taxes Other than Income and Other 5,607 3,945
-----------------
$13,847 $11,034
=================
4. Inventories
Inventories are comprised of the following:
December 31,
(In thousands) 2000 1999
---------------------------------------------------------------------
Natural Gas and Oil in Storage $10,277 $ 8,702
Tubular Goods and Well Equipment 2,122 2,052
Pipeline Exchange Balances (1,362) 175
-----------------
$11,037 $10,929
=================
5. Debt and Credit Agreements
10.18% Notes
In May 1990, the Company issued an aggregate principal amount of $80
million of its 12-year 10.18% Notes (10.18% Notes) to a group of nine
institutional investors in a private placement offering. The 10.18% Notes
require five annual $16 million principal payments each May starting in 1998.
The fourth payment due in May 2001, classified as Current Portion of Long-Term
Debt, is a current liability on the Company's Consolidated Balance Sheet. The
Company may prepay all or any portion of the remaining $32 million of debt at
any time with a prepayment penalty. The 10.18% Notes contain restrictions on the
merger of the Company or any subsidiary with a third party except under certain
limited conditions. There are also various other restrictive covenants
customarily found in such debt instruments, including a restriction on the
payment of dividends and a required asset coverage ratio (present value of
proved reserves to debt and other liabilities) that must be at least 1.5 to 1.0.
7.19% Notes
In November 1997, the Company issued an aggregate principal amount of $100
million of its 12-year 7.19% Notes (7.19% Notes) to a group of six institutional
investors in a private placement offering. The 7.19% Notes require five annual
$20 million principal payments starting in November 2005. The Company may
prepay all or any portion of the indebtedness on any date with a prepayment
penalty. The 7.19% Notes contain restrictions on the merger of the Company or
any subsidiary with a third party other than under certain limited conditions.
There are also various other restrictive covenants customarily found in such
debt instruments. These covenants include a required asset coverage ratio
(present value of proved reserves to debt and other liabilities) that must be at
least 1.5 to 1.0, and a minimum annual coverage ratio of operating cash flow to
interest expense for the trailing four quarters of 2.8 to 1.0.
Revolving Credit Agreement
In November 1998, the Company replaced its $135 million Revolving Credit
Agreement that utilized five banks with a new $250 million Revolving Credit
Agreement (Credit Facility) with 9 banks. The term of the Credit Facility
expires on December 17, 2003. The available credit line is subject to adjustment
from time-to-time on the
45
basis of the projected present value (as determined by the banks' petroleum
engineer) of estimated future net cash flows from certain proved oil and gas
reserves and other assets of the Company. While the Company does not expect a
change in the available credit line, in the event that it is adjusted below the
outstanding level of borrowings, the Company has a period of 180 days to reduce
its outstanding debt to the adjusted credit line. The Credit Facility also
includes a requirement to pay down half of the debt in excess of the adjusted
credit line within the first 90 days of such an adjustment. Interest rates are
principally based on a reference rate of either the rate for certificates of
deposit (CD rate) or LIBOR, plus a margin, or the prime rate. For CD rate and
LIBOR borrowings, interest rates are subject to increase if the total
indebtedness is either greater than 60% or 80% of the Company's debt limit of
$400 million, as shown below.
Debt Percentage
-----------------------------------------------
Lower than 60% 60% - 80% Higher than 80%
===============================================
LIBOR margin 0.750% 1.000% 1.250%
CD margin 0.875% 1.125% 1.375%
Commitment fee rate 0.250% 0.375% 0.375%
The Credit Facility provides for a commitment fee on the unused avaible
balance at an annual rate one-fourth of 1% or three-eighths of 1% depending on
the level of indebtedness as indicated above. The Company's effective interest
rates for the Credit Facility in the years ended December 31, 2000, 1999 and
1998 were 7.8%, 6.7%, and 6.8%, respectively. The Credit Facility contains
various customary restrictions, which include the following:
(a) Prohibition of the merger of the Company or any subsidiary with a third
party except under certain limited conditions.
(b) Prohibition of the sale of all or substantially all of the Company's or
any subsidiary's assets to a third party.
(c) Maintenance of a minimum annual coverage ratio of operating cash flow to
interest expense for the trailing four quarters of 2.8 to 1.0.
6. Employee Benefit Plans
Pension Plan
The Company has a non-contributory, defined benefit pension plan for all
full-time employees. Plan benefits are based primarily on years of service and
salary level near retirement. Plan assets are mainly fixed income investments
and equity securities. The Company complies with the Employee Retirement Income
Security Act of 1974 and Internal Revenue Code limitations when funding the
plan.
The Company has a non-qualified equalization plan to ensure payments to
certain executive officers of amounts to which they are already entitled under
the provisions of the pension plan, but which are subject to limitations imposed
by federal tax laws. This plan is unfunded.
Net periodic pension cost of the Company for the years ended December 31,
2000, 1999 and 1998 are comprised of the following:
(In thousands) 2000 1999 1998
---------------------------------------------------------------------
Qualified
Current Year Service Cost $ 832 $1,012 $ 853
Interest Accrued on Pension Obligation 1,070 1,072 945
Expected Return on Plan Assets (1,123) (919) (1,434)
Net Amortization and Deferral 88 88 706
Recognized Gain (282) -- (20)
------- ------ -------
Net Periodic Pension Cost $ 585 $1,253 $ 1,050
======= ====== =======
46
(In thousands) 2000 1999 1998
---------------------------------------------------------------
Non-Qualified
Current Year Service Cost $ 60 $ 140 $ 81
Interest Accrued on Pension Obligation 42 67 45
Net Amortization 77 77 54
Recognized (Gain) Loss (5) 35 20
Settlement Charge -- -- 213
----- ----- -----
Net Periodic Pension Cost $ 174 $ 319 $ 413
===== ===== =====
The following table illustrates the funded status of the Company's pension
plans at December 31, 2000, and 1999, respectively:
2000 1999
(In thousands) Qualified Non-Qualified Qualified Non-Qualified
--------------------------------------------------------------------------------------------
Actuarial Present Value of
Accumulated Benefit Obligation $12,188 $ 753 $10,474 $ 504
Projected Benefit Obligation $16,173 $ 978 $14,009 $ 537
Plan Assets at Fair Value 11,801 -- 12,092 --
----------------------------------------------
Projected Benefit Obligation in Excess
of Plan Assets 4,372 978 1,917 537
Unrecognized Net Gain (Loss) 1,956 (351) 4,964 114
Unrecognized Prior Service Cost (599) (630) (687) (707)
Adjustment to Recognize Minimum
Liability -- 756 -- 560
----------------------------------------------
Accrued Pension Cost $ 5,729 $ 753 $ 6,194 $ 504
==============================================
The change in the combined projected benefit obligation of the Company's
qualified and non-qualified pension plans during the last three years is
explained as follows:
(In thousands) 2000 1999 1998
--------------------------------------------------------------
Beginning of Year $14,546 $16,449 $13,441
Service Cost 892 1,152 935
Interest Cost 1,112 1,139 990
Plan Amendments -- -- 488
Actuarial Loss (Gain) 1,328 (3,657) 1,803
Benefits Paid (727) (537) (1,208)
---------------------------------
End of Year $17,151 $14,546 $16,449
=================================
The change in the combined plan assets at fair value of the Company's
qualified and non-qualified pension plans during the last three years is
explained as follows:
(In thousands) 2000 1999 1998
--------------------------------------------------------------
Beginning of Year $12,092 $10,344 $ 8,890
Actual Return on Plan Assets (440) 2,428 1,608
Employer Contribution 1,172 101 1,227
Benefits Paid (727) (537) (1,208)
Expenses Paid (296) (244) (173)
---------------------------------
End of Year $11,801 $12,092 $10,344
=================================
47
The reconciliation of the combined funded status of the Company's qualified
and non-qualified pension plans at the end of the last three years is explained
as follows:
(In thousands) 2000 1999 1998
-----------------------------------------------------------------------------
Funded Status $ 5,350 $ 2,454 $ 6,105
Unrecognized Gain 1,605 5,078 121
Unrecognized Prior Service Cost (1,229) (1,394) (1,558)
---------------------------
Net Amount Recognized $ 5,726 $ 6,138 $ 4,668
===========================
Accrued Benefit Liability - Qualified Plan $ 5,729 $ 6,194 $ 5,030
Accrued Benefit Liability - Non-Qualified Plan 753 504 439
Intangible Asset (756) (560) (801)
---------------------------
Net Amount Recognized $ 5,726 $ 6,138 $ 4,668
===========================
Assumptions used to determine post-retirement benefit obligations and
pension costs are as follows:
2000 1999 1998
-----------------------------------------------------------------
Discount Rate /(1)/ 7.50% 7.75% 7.00%
Rate of Increase in Compensation Levels 4.00% 4.00% 4.00%
Long-Term Rate of Return on Plan Assets 9.00% 9.00% 9.00%
-----------------------------------------------------------------
/(1)/ Represents the rate used to determine the benefit obligation. A 7.75%
discount rate was used to compute pension costs in 2000, a rate of 7.0% was
used in 1999, and a rate of 7.5% was used in 1998.
Savings Investment Plan
The Company has a Savings Investment Plan (SIP) which is a defined
contribution plan. The Company matches a portion of employees' contributions.
Participation in the SIP is voluntary and all regular employees of the Company
are eligible to participate. The Company charged to expense plan contributions
of $0.7 million, $0.7 million, and $0.8 million in 2000, 1999, and 1998,
respectively. The Company's Common Stock is an investment option within the SIP.
Deferred Compensation Plan
In 1998, the Company established a Deferred Compensation Plan. This plan is
available to officers of the Company and acts as a supplement to the Savings
Investment Plan. The Company matches a portion of the employee's contribution
and those assets are invested in instruments selected by the employee. Unlike
the SIP, the Deferred Compensation Plan does not have dollar limits on tax
deferred contributions. However, the assets of this plan are held in a rabbi
trust and are subject to additional risk of loss in the event of bankruptcy or
insolvency of the Company. At December 31, 2000, the balance in the Deferred
Compensation Plan's rabbi trust was $1.2 million.
Postretirement Benefits Other Than Pensions
In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits for retired employees, including their
spouses, eligible dependents and surviving spouses (retirees). These benefits
are commonly called postretirement benefits. Most employees become eligible for
these benefits if they meet certain age and service requirements at retirement.
The Company was providing postretirement benefits to 241 retirees at the end of
2000 and 250 retirees at the end of 1999.
When the Company adopted SFAS 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions," in 1992, it began amortizing the
$16.9 million accumulated postretirement benefit, known as the Transition
Obligation, over a period of 20 years.
The amortization benefit of the unrecognized Transition Obligation in 1998,
presented in the table below, is due to a cost-cutting amendment to the
postretirement medical benefits in 1993. The amendment prospectively reduced the
unrecognized Transition Obligation by $9.8 million and was amortized over a 5.75
year period
48
beginning in 1993 and ending in 1998.
Postretirement benefit costs recognized during the last three years are as
follows:
(In thousands) 2000 1999 1998
--------------------------------------------------------------------------
Service Cost of Benefits Earned During the Year $ 187 $ 225 $ 190
Interest Cost on the Accumulated Postretirement
Benefit Obligation 534 515 525
Amortization Benefit of the Unrecognized Gain (132) (131) (165)
Amortization Benefit of the Unrecognized
Transition Obligation 662 690 (435)
-----------------------
Total Postretirement Benefit Cost (Benefit) $1,251 $1,299 $ 115
=======================
The health care cost trend rate used to measure the expected cost in 2000
for medical benefits to retirees was 8%. Provisions of the plan should prevent
further increases in employer cost after 2000.
A one-percentage-point increase or decrease in health care cost trend rates
for future periods would not impact the accumulated net postretirement benefit
obligation or the total postretirement benefit cost recognized. Company costs
are capped at 2000 levels, and the retirees assume any future increases in
costs.
The funded status of the Company's postretirement benefit obligation at
December 31, 2000, and 1999 is comprised of the following:
(In thousands) 2000 1999
--------------------------------------------------------------------------
Plan Assets at Fair Value $ -- $ --
Accumulated Postretirement Benefits Other Than Pensions 5,429 7,243
Unrecognized Cumulative Net Gain 3,847 2,056
Unrecognized Transition Obligation (7,279) (7,940)
----------------
Accrued Postretirement Benefit Liability $ 1,997 $ 1,359
================
The change in the accumulated postretirement benefit obligation during the
last three years is presented as follows:
(In thousands) 2000 1999 1998
---------------------------------------------------------------
Beginning of Year $ 7,243 $ 7,693 $ 7,303
Service Cost 187 225 190
Interest Cost 534 515 526
Amendments 0 (253) 0
Actuarial Loss/(Gain) (1,923) (102) 230
Benefits Paid (612) (835) (556)
---------------------------
End of Year $ 5,429 $ 7,243 $ 7,693
===========================
49
7. Income Taxes
Income tax expense is summarized as follows:
Year Ended December 31,
(In thousands) 2000 1999 1998
- ----------------------------------------------------------------
Current
Federal $ 3,089 /(1)/ $(3,899) $(1,696)
State 216 -- 65
-------------------------------
Total 3,305 (3,899) (1,631)
-------------------------------
Deferred
Federal 11,804 8,910 4,869
State 1,358 150 263
-------------------------------
Total 13,162 9,060 5,132
-------------------------------
Total Income Tax Expense $ 16,467 $ 5,161 $ 3,501
===============================
- ----------------------------------------------------------------
/(1)/ The Federal Income Taxes Payable is zero at December 31, 2000
primarily as a result of tax payments made during the year and a $1.8
million tax benefit related to stock option exercises during 2000.
In the table above, the $4.5 million refund received in 1999 that
applied to a net operating loss carryback to 1997 is reflected in "Current -
Federal". The 1998 "Current - Federal" amount includes the effect of a $2.0
million income tax refund received in 1998 that applied to a net operating loss
carryback to 1992.
Total income taxes were different than the amounts computed by applying the
statutory federal income tax rate as follows:
Year Ended December 31,
(In thousands) 2000 1999 1998
- ------------------------------------------------------------------------------
Statutory Federal Income Tax Rate 35% 35% 35%
Computed "Expected" Federal Income Tax $14,679 $4,788 $3,081
State Income Tax, Net of Federal Income Tax 1,552 506 352
Other, Net 236 (133) 68
-------------------------
Total Income Tax Expense $16,467 $5,161 $3,501
=========================
The tax effects of temporary differences that resulted in significant
portions of the deferred tax liabilities and deferred tax assets as of December
31, 2000, and 1999 were as follows:
(In thousands) 2000 1999
- ----------------------------------------------------------------------------
Deferred Tax Liabilities
Property, Plant and Equipment $142,935 $133,982
------------------
Deferred Tax Assets
Alternative Minimum Tax Credit Carryforwards 5,817 3,044
Net Operating Loss Carryforwards 13,904 20,165
Note Receivable on Section 29 Monetization/(1)/ 6,397 11,228
Items Accrued for Financial Reporting Purposes 8,643 4,533
------------------
34,761 38,970
------------------
Net Deferred Tax Liabilities $108,174 $ 95,012
==================
- -----------------------------------------------------------------------------
/(1)/ As a result of the monetization of Section 29 tax credits in 1996 and
1995, the Company recorded an asset sale for tax purposes in exchange
for a long-term note receivable which will be repaid through 100%
working and royalty interest in the production from the sold
properties.
At December 31, 2000, the Company has a net operating loss carryforward for
regular income tax reporting purposes of $33.9 million that will begin expiring
in 2011. In addition, the Company has an alternative minimum tax credit
carryforward of $5.8 million which does not expire and can be used to offset
regular income taxes in future years to the extent that regular income taxes
exceed the alternative minimum tax in any year.
50
8. Commitments and Contingencies
Lease Commitments
The Company leases certain transportation vehicles, warehouse facilities,
office space, and machinery and equipment under cancelable and non-cancelable
leases. Leases for the Company's offices in Houston and Denver each run for
approximately nine more years. Most of the other leases expire within five years
and may be renewed. Rent expense under such arrangements totaled $6.3 million,
$5.0 million, and $4.3 million for the years ended December 31, 2000, 1999, and
1998, respectively.
Future minimum rental commitments under non-cancelable leases in effect at
December 31, 2000 are as follows:
(In thousands)
---------------------------
2001 $ 4,580
2002 4,455
2003 3,859
2004 3,663
2005 3,568
Thereafter 11,941
-------
$32,066
=======
Minimum rental commitments are not reduced by minimum sublease rental income of
$0.6 million due in the future under non-cancelable subleases.
Contingencies
The Company is a defendant in various lawsuits and is involved in other gas
contract issues. In the Company's opinion, final judgments or settlements, if
any, which may be awarded in connection with any one or more of these suits and
claims could have a significant impact on the results of operations and cash
flows of any period. However, there would not be a material adverse effect on
the Company's financial position.
Environmental Liability
The EPA notified the Company in February 2000 that it might have 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 1989. The EPA stated that federal, state and local
governmental agencies along with the numerous private entities that used the
Site for waste disposal will be expected to pay the clean-up costs which could
total as much as several hundred million dollars. The EPA is also pursuing the
owners/operators of the Site to pay for remediation.
Documents received with the notification from the EPA indicate that the
Company used the Site principally to dispose of salt water from two wells over a
period from 1976 to 1979. There is no allegation that the Company violated any
laws in the disposal of material at the Site. The EPA's actions stemmed from
the fact that the owners/operators of the Site do not have the financial means
to implement a closure plan for the Site. A group of potentially responsible
parties, including the Company, have had extensive settlement discussions with
the EPA. However, the parties have yet to reach an agreement.
The Company has a reserve that it believes to be adequate to cover this
potential environmental liability based on its estimate of the probable outcome
of this matter. While the potential impact to the Company may materially affect
quarterly or annual financial results, management does not believe it would
materially impact the Company's financial position or cash flows. The Company
will continue to monitor the facts and its assessment of its liability related
to this claim.
51
Wyoming Royalty Litigation
In June 2000, two overriding royalty owners sued the Company in Wyoming
State court. The plaintiffs have requested class certification under the
Wyoming Rules of Civil Procedure and allege that the Company has deducted
impermissible costs of production from royalty payments to the plaintiffs and
other similarly situated persons. Additionally, the suit claims that the
Company has failed to properly inform the plaintiffs and other similarly
situated persons of the deductions taken from royalties.
While the Company believes that it has substantial defenses to this claim
and intends to vigorously assert such defenses, the investigation into this
claim has only just begun and, accordingly, the Company can not presently
determine the likelihood or range of any potential loss.
9. Cash Flow Information
Cash paid for interest and income taxes is as follows:
Year Ended December 31,
(In thousands) 2000 1999 1998
----------------------------------------------
Interest $23,180 $25,445 $18,341
Income Taxes $ 1,419 $ 652 $ 827
At December 31, 2000, and 1999, the Accounts Payable balance on the
Consolidated Balance Sheet included payables for capital expenditures of $13.5
million and $10.1 million, respectively.
10. Capital Stock
Incentive Plans
On May 12, 1998, the Amended and Restated 1994 Long-Term Incentive Plan and
the Amended and Restated 1994 Non-Employee Director Stock Option Plan were
approved by the shareholders. The Company has two other stock option plans: the
1990 Incentive Stock Option Plan and the 1990 Non-Employee Director Stock Option
Plan. Under these four plans (Incentive Plans), incentive and non-statutory
stock options, stock appreciation rights (SARs) and stock awards may be granted
to key employees and officers of the Company, and non-statutory stock options
may be granted to non-employee directors of the Company. A maximum of 3,860,000
shares of Common Stock, par value $0.10 per share, may be issued under the
Incentive Plans. All stock options have a maximum term of five or 10 years from
the date of grant, with most vesting over time. The options are issued at
market value on the date of grant. The minimum exercise period for stock
options is six months from the date of grant. No SARs have been granted under
the Incentive Plans.
Information regarding the Company's Incentive Plans is summarized below:
December 31,
2000 1999 1998
-----------------------------------------------------------------------------
Shares Under Option at Beginning of Period 1,773,389 1,557,936 1,404,877
Granted 299,250 454,100 355,000
Exercised 896,081 55,032 152,917
Surrendered or Expired 52,410 183,615 49,024
-------------------------------
Shares Under Option at End of Period 1,124,148 1,773,389 1,557,936
===============================
Options Exercisable at End of Period 474,599 1,108,637 1,092,295
===============================
52
For each of the three most recent years, the price range for outstanding
options was $13.25 to $22.75 per share. The following tables provide more
information about the options by exercise price and year.
Options with exercise prices between $13.25 and $20.00 per share:
December 31,
2000 1999 1998
-----------------------------------------------------------------------------------------------------
Options Outstanding
-------------------
Number of Options 866,498 1,412,072 1,051,936
Weighted Average Exercise Price $ 17.63 $ 16.07 $ 15.53
Weighted Average Contractual Term (in years) 2.60 2.40 2.46
Options Exercisable
-------------------
Number of Options 372,418 953,640 927,795
Weighted Average Exercise Price $ 16.27 $ 15.44 $ 15.32
Options with exercise prices between $20.01 and $22.75 per share:
December 31,
2000 1999 1998
------------------------------------------------------------------------------------------------------------
Options Outstanding
--------------------
Number of Options 257,650 361,317 506,000
Weighted Average Exercise Price $ 22.46 $ 22.50 $ 22.04
Weighted Average Contractual Term (in years) 1.90 3.37 3.47
Options Exercisable
--------------------
Number of Options 102,181 154,997 164,500
Weighted Average Exercise Price $ 22.51 $ 22.55 $ 21.17
Under the Amended and Restated 1994 Long-Term Incentive Plan, the
Compensation Sub-Committee of the Board of Directors may grant awards of
performance shares of stock to members of the executive management group. Each
grant of performance shares has a three-year performance period, measured as the
change from July 1 of the initial year of the performance period to June 30 of
the third year. The number of shares of Common Stock received at the end of the
performance period is based mainly on the relative stock price growth between
the two measurement dates of Common Stock compared to that of a group of peer
companies. The performance shares that were granted on July 1, 1994, expired on
June 30, 1997, without issuing any Common Stock of the Company. The performance
shares granted in July 1995 were converted to 21,692 shares of the Company's
Common Stock in 1998, and the performance shares granted in July 1996 were
converted to 19,090 shares of the Company's Common Stock in 1999. The Board of
Directors has not issued performance shares since July 1996, and currently,
there are no performance shares outstanding.
Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for
Stock-Based Compensation," outlines a fair value based method of accounting for
stock options or similar equity instruments. The Company has opted to continue
using the intrinsic value based method, as recommended by Accounting Principles
Board (APB) Opinion No. 25, to measure compensation cost for its stock option
plans.
If the Company had adopted SFAS 123, the pro forma results of operations
would be as follows:
2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------------
Net Income $28.2 million $4.3 million $1.3 million
Net Income per Share $1.03 $0.20 $0.06
Weighted Average Value of
Options Granted During the Year /(1)/ $6.63 $4.78 $6.21
Assumptions:
Stock Price Volatility 34.5% 27.4% 26.1%
Risk Free Rate of Return 5.21% 5.21% 5.63%
Dividend Rate (per year) $0.16 $0.16 $0.16
Expected Term (in years) 4 4 4
- -------------------------------------------------------------------------------------------------------------------------
/(1)/ Calculated using the fair value based method.
The fair value of stock options included in the pro forma results for each of
the three years is not necessarily
53
indicative of future effects on net income and earnings per share.
Dividend Restrictions
The Board of Directors of the Company determines the amount of future cash
dividends, if any, to be declared and paid on the Common Stock depending on,
among other things, the Company's financial condition, funds from operations,
the level of its capital and exploration expenditures, and its future business
prospects. The Company's 10.18% Note Agreement restricts certain payments
associated with the following:
(a) Purchasing, redeeming, retiring or otherwise acquiring any capital stock of
the Company or any option, warrant or other right to acquire such capital
stock.
(b) Declaring any dividend, if immediately prior to or after making payments,
the dividend exceeds consolidated net cash flow (as defined) and the ratio
of proved reserves to debt is less than 1.7 to 1, or there has been an
event of default under the Note Agreement.
As of December 31, 2000, these restrictions did not impact the Company's ability
to pay regular dividends. Neither the 7.19% Note Agreement nor the Credit
Facility Agreement has a restricted payment provision.
Treasury Stock
In August 1998, the Board of Directors authorized the Company to repurchase
up to two million shares of outstanding Common Stock at market prices. The
timing and amount of these stock purchases are determined at the discretion of
management. The Company may use the repurchased shares to fund stock
compensation programs presently in existence, or for other corporate purposes.
As of December 31, 1998, the Company had repurchased 302,600 shares, or 15% of
the total authorized number of shares, for a total cost of approximately $4.4
million. No additional shares were repurchased during 1999 or 2000. The stock
repurchase plan was funded from increased borrowings on the revolving credit
facility. No treasury shares were delivered or sold by the Company during the
year.
Purchase Rights
On January 21, 1991, the Board of Directors adopted the Preferred Stock
Purchase Rights Plan and declared a dividend distribution of one right for each
outstanding share of Common Stock. On December 8, 2000, the rights agreement
for the plan was amended and restated to extend the term of the plan to 2010 and
to make other changes. Each right becomes exercisable, at a price of $55, when
any person or group has acquired or made a tender or exchange offer for
beneficial ownership of 15 percent or more of the Company's outstanding Common
Stock. Each right entitles the holder, other than the acquiring person or
group, to purchase one one-hundredth of a share of Series A Junior Participating
Preferred Stock (Junior Preferred Stock). After a person or group acquires
beneficial ownership of 15% of the Common Stock, each right entitles the holder
to purchase Common Stock or other property having a market value (as defined in
the plan) of twice the exercise price of the right. An exception to this
triggering event applies in the case of a tender or exchange offer for all
outstanding shares of Common Stock determined to be fair and in the best
interests of the Company and its stockholders by a majority of the independent
directors. Under certain circumstances, the Board of Directors may opt to
exchange one share of Common Stock for each exercisable right. If there is a
15% holder and the Company is acquired in a merger or other business combination
in which it is not the survivor, or 50 percent or more of the Company's assets
or earning power are sold or transferred, each right entitles the holder to
purchase common stock of the acquiring company with a market value (as defined
in the plan) equal to twice the exercise price of each right. At December 31,
2000, and 1999, there were no shares of Junior Preferred Stock issued or
outstanding.
The rights expire on January 21, 2010, and may be redeemed by the Company
for $0.01 per right at any time before a person or group acquires beneficial
ownership of 15% of the Common Stock.
Preferred Stock
At December 31, 1999, and 1998, 1,134,000 shares of 6% convertible
redeemable preferred stock (6% preferred stock) were issued and outstanding. In
May 2000, the Company repurchased all of the then-outstanding
54
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 the Company's balance
sheet, the benefit from a $5.1 million negative dividend to preferred
stockholders was included in net income available to common shareholders. After
this repurchase transaction, the Company retired all shares of preferred stock.
This transaction was funded by the sale of common stock in a public
offering. The Company sold 3.4 million shares to the public at $21.50 per
share. After deducting the costs of this transaction, the Company received net
proceeds of $71.5 million. After repurchasing the preferred stock, the excess
proceeds from this transaction were used to reduce debt on the Company's
revolving credit facility.
11. Financial Instruments
The estimated fair value of financial instruments is the amount at which
the instrument could be exchanged currently between willing parties. The
carrying amounts reported in the consolidated balance sheet for cash and cash
equivalents, accounts receivable, and accounts payable approximate fair value.
The Company uses available marketing data and valuation methodologies to
estimate fair value of debt.
December 31, 2000 December 31, 1999
Carrying Estimated Carrying Estimated
(In thousands) Amount Fair Value Amount Fair Value
---------------------------------------------------------------------
Debt
10.18% Notes $ 32,000 $ 33,162 $ 48,000 $ 50,020
7.19% Notes 100,000 97,033 100,000 91,237
Credit Facility 137,000 137,000 145,000 145,000
-------------------------------------------
$269,000 $267,195 $293,000 $286,257
===========================================
Long-Term Debt
The fair value of long-term debt is the estimated cost to acquire the debt,
including a premium or discount for the difference between the issue rate and
the year-end market rate. The fair value of the 10.18% Notes and the 7.19%
Notes is based on interest rates currently available to the Company. The Credit
Facility approximates fair value because this instrument bears interest at rates
based on current market rates.
Commodity Price Swaps and Options
Hedges on our Production
From time to time, the Company enters into natural gas and crude oil swap
agreements with counterparties to hedge price risk associated with a portion of
our production. These derivatives are not held for trading purposes. Under
these price swaps, the Company receives a fixed price on a notional quantity of
natural gas and crude oil in exchange for paying a variable price based on a
market-based index, such as the NYMEX gas and crude oil futures. During 2000,
the Company fixed the price at an average of $4.54 per Mcf on quantities
totaling 315 Mmcf, representing less than 1% of the Company's 2000 natural gas
production. The notional volume of the crude oil swap transactions was 364
Mbbls at a price of $22.67 per Bbl, which represents approximately 38% of the
Company's total oil production for 2000. During 1999, the Company fixed the
price at an average of $2.88 per Mcf on quantities totaling 3,237 Mmcf,
representing 5% of the Company's 1999 natural gas production. The notional
volume of the crude oil swap transactions was 306 Mbbls at a price of $20.65 per
Bbl, which represents approximately one-third of the Company's total oil
production for 1999. During 1998, the Company did not enter into any fixed
price swaps to hedge oil or natural gas production.
55
As of the years ending December 31, 2000, and 1999, the Company had open
natural gas price swap contracts on its production as follows:
Natural Gas Price Swaps
-------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Mmcf Contract Price (in $ millions)
--------------------------------------------------------------------------------------------
As of December 31, 2000
-----------------------
Natural Gas Price Swaps on Production in:
----------------------------------------
Full Year 2001 918 $3.75 $(2.8)
Full Year 2002 678 3.11 (1.0)
Full Year 2003 423 2.81 (0.5)
As of December 31, 1999
---------------------------------------------
None
Financial derivatives related to natural gas production reduced revenues by
$0.3 million in 2000 and $0.3 million in 1999.
The Company had open oil price swap contracts on its production as follows:
Oil Price Swaps
-----------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Bbls Contract Price (in $ millions)
----------------------------------------------------------------------------------------
As of December 31, 2000
-----------------------
None
As of December 31, 1999
-----------------------
Oil Price Swaps on Production in:
--------------------------------
First Quarter 2000 182,000 $22.25 $(0.5)
Second Quarter 2000 182,000 23.08 (0.1)
Financial derivatives related to crude oil reduced revenue by $2.2 million
during 2000 and by $0.8 million during 1999. There were no crude oil price
swaps outstanding at December 31, 1998.
During 2000, the Company used several costless price collar agreements (put
and call options) to hedge a portion of its natural gas production. There were
seven collar arrangements based on separate regional price indexes with a
weighted average price floor of $2.74/Mcf and a weighted average price ceiling
of $3.38/Mcf. These collars were in place during the months of April through
October 2000. During this period, if the index rose above the ceiling price,
the Company paid the counterparty. If the applicable index fell below the floor
price, the counterparty paid the Company. These collars covered a total
quantity of 9,909 Mmcf, or 16% of our annual production. In April and May 2000,
the index prices all fell within the price collar and no settlements were made.
In June 2000, all of the indexes rose above the ceiling prices and remained
above the ceiling for the duration of the transaction resulting in a $10 million
reduction to the Company's realized revenue for the year. If these hedges had
not been in place, the average realized natural gas price for 2000 would have
been $0.17 per Mcf higher. There were no commodity price collar arrangements in
place during 1999.
56
As of December 31, 2000, the Company had open natural gas costless price
collar arrangements on its production as follows:
Natural Gas Price Collars
-------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Mmcf Ceiling / Floor (in $ millions)
---------------------------------------------------------------------------------------------
As of December 31, 2000
-----------------------
Natural Gas Costless Collar on Production in:
--------------------------------------------
First Quarter of 2001 5,274 $9.68/$5.59 --
Second Quarter of 2001 8,135 $9.68/$5.59 --
Third Quarter of 2001 8,224 $9.68/$5.59 --
Fourth Quarter of 2001 2,771 $9.68/$5.59 --
The natural gas price hedges, noted above, include costless price collar
agreements based on eight price indexes at which the Company sells a portion of
its production. These hedges are in place for the months of February through
October 2001 and cover approximately half of the Company's natural gas
production during this period.
Hedges on Brokered Transactions
The Company uses price swaps to hedge the natural gas price risk on
brokered transactions. Typically, the Company enters into contracts to broker
natural gas at a variable price based on the market index price. However, in
some circumstances, some customers or suppliers request that a fixed price be
stated in the contract. After entering into these fixed price contracts to meet
the needs of the customers or suppliers, the Company may use price swaps to
effectively convert these fixed price contracts to market-sensitive price
contracts. These price swaps are held by the Company to their maturity and are
not held for trading purposes.
During 2000, 1999, and 1998, the Company entered into price swaps with
total notional quantities of 1,295, 3,572, and 1,971 Mmcf, respectively, related
to its brokered activities, representing 3%, 7%, and 5%, respectively, of its
total volume of brokered natural gas sold.
As of the years ending December 31, 2000, and 1999, the Company had open
natural gas price swap contracts on brokered transactions as follows:
Natural Gas Price Swaps
--------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Mmcf Contract Price (in $ millions)
-------------------------------------------------------------------------------------------------------
As of December 31, 2000
-----------------------
None
As of December 31, 1999
-----------------------
Natural Gas Price Swap on Brokered Transactions in:
--------------------------------------------------
First Quarter 2000 1,010 $2.26 $(0.2)
Financial derivatives related to natural gas reduced revenues by less than
$0.1 million in 2000 and increased revenues by $0.1 million in 1999.
The Company is exposed to market risk on these open contracts, to the
extent of changes in market prices of natural gas and oil. However, the market
risk exposure on these hedged contracts is generally offset by the gain or loss
recognized upon the ultimate sale of the commodity that is hedged.
Since its issuance, the Company has been modeling the impact of Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). The Company had two types of
hedges in place as of January 1, 2001 when SFAS 133 and SFAS 138 became
effective. The first type is a cash flow hedge that fixes the price of a
certain monthly quantity of natural gas sold in the Gulf Coast region through
September 2003. Based on the current index price strip, the impact of this
hedge on January 1, 2001
57
was to record a Hedge Loss of $0.1 million and a charge to Other Comprehensive
Income of $4.2 million. Correspondingly, a Hedge Liability for $4.3 million was
established.
The second type of hedge is a natural gas costless price collar. The
Company entered into eight of these collars for a portion of our production at
regional indexes for the months of February through October 2001. The collars
have two components of value: intrinsic value and time value. Under SFAS 133,
both components will be valued at the end of each reporting period. Intrinsic
value arises when the index price is either above the ceiling or below the floor
for any period covered by the collar. If the index is above the ceiling for any
month covered by the collar, the intrinsic value would be the difference between
the index and the ceiling prices multiplied by the notional volume. Similar to
the current accounting treatment, intrinsic value related to the current month
would be recorded as a hedge loss (if the index is above the ceiling) or gain
(if the index is below the floor). Starting in 2001 under SFAS 133, any changes
in the intrinsic value component related to future months will be recorded in
Other Comprehensive Income, a component of equity, rather than to the income
statement to the extent that the hedge is proven to be effective. In the case
of these natural gas price collars, full effectiveness is anticipated as they
are tied to the same indexes at which our natural gas is sold. Also new under
SFAS 133, the time value component, a market premium/discount, is marked-to-
market through the income statement each period. Since these collar
arrangements were executed on the last business day of 2000, the net premium
value at adoption on January 1, 2001 is zero.
Credit Risk
Although notional contract amounts are used to express the volume of
natural gas price agreements, the amounts that can be subject to credit risk in
the event of non-performance by third parties are substantially smaller. The
Company does not anticipate any material impact on its financial results due to
non-performance by the third parties. The Company had no sales to any customer
that exceeded 10% of total gross revenues in 2000 or 1999.
12. Oil and Gas Property Transactions
In September and December 1999, the Company purchased oil and gas producing
properties in the Moxa Arch of the Green River Basin in southwest Wyoming for
$8.9 and $8.5 million, respectively. The assets included approximately 16 Bcfe
of proved reserves, approximately 43,000 undeveloped net acres, and 27 wells
producing a net 3.8 Mmcfe per day at the time of the acquisition.
Also in September 1999, the Company sold non-strategic oil and gas
properties located in Pennsylvania and West Virginia to EnerVest for
approximately $46 million. These properties represented 716 wells and 62.2 Bcfe
of proved reserves. A portion of this transaction and the two previously
mentioned were completed as a tax-deferred exchange deferring a taxable gain of
$8.9 million.
In the second quarter of 1999, the Company sold certain non-strategic
properties in the Gulf Coast region's Provident City field. These properties
were producing 3.5 Mmcfe per day from eight wells. The sales price was $9
million, and the transaction contributed to a gain of approximately $1.0 million
on the Company's second quarter income statement.
Effective December 1, 1998, the Company purchased onshore southern
Louisiana properties and 3-D seismic inventory from Oryx Energy Company for
approximately $70.1 million. The purchased assets included 10 fields covering
over 34,000 net acres with 68 producing wells. Total proved reserves are
approximately 72 Bcfe. This transaction was funded by the Company's revolving
line of credit. See discussion in Note 5 Debt and Credit Agreements.
In the fourth quarter of 1998, the Company purchased oil and gas producing
properties in the Lookout Wash Unit of Wyoming from Oxy USA, Inc. for $5.2
million. The properties acquired included 11.2 Bcfe of proved reserves and more
than 10 potential drilling locations. Additionally in 1998, the Company
acquired oil and gas producing properties in Oklahoma during the second quarter
for $6.6 million. Included in the purchase were 9.3 Bcfe of proved reserves, 10
wells and undeveloped acreage.
58
13. Other Revenue
During 2000, the Company reached settlements on certain natural gas
contract disputes with various counterparties. As a result, the Company
recorded net revenue of approximately $2.3 million to Other Revenue during 2000.
The Company had a 15-year cogeneration contract under which approximately
20% of the Western region natural gas was sold per year. The contract was due
to expire in 2008, but during 1999 the Company reached an agreement with the
counterparty under which the counterparty bought out the remainder of the
contract for $12 million. This transaction was completed in December 1999,
adding $12 million of pre-tax other revenue. Simultaneously, the Company sold
forward a similar monthly volume of Western region gas through April 2001 at
prices similar to those in the monetized contract.
Other revenue includes income generated from the monetization of the value
of Section 29 tax credits (monetized credits) from most of our qualifying
Appalachian and Rocky Mountains properties. Revenue from these monetized
credits was $2.2 million in 2000, $1.3 million in 1999, and $2.7 million in
1998. These monetized credits are expected to generate future revenues through
2002 of $4.1 million. The production, revenues, expenses and proved reserves
for these properties will continue to be reported by the Company as Other
Revenue until the production payment is satisfied.
During 1999, an industry tax court ruling concluded that the Section 29
tight sands tax credits (Section 29 credits) would not be available on wells not
certified by the FERC. Because the FERC discontinued the certification process
for qualifying wells in 1992, there was no avenue to obtain the well
certifications. Accordingly, the Company stopped recording revenue on non-
certified wells and established a reserve related to previously recorded amounts
on these wells. This resulted in a $1.2 million reduction to other revenue in
1999. Subsequent to 1999, the certification process has been reinstated by
FERC, and the Company has begun applying for the well certificates and accruing
Section 29 credit revenues related to these wells.
14. Supplemental Full Cost Accounting Information
U.S. oil and gas producing entities may utilize one of two methods of
financial accounting: successful efforts or full cost. Given the current
composition of the Company's properties, management considers the successful
efforts method to be more appropriate than the full cost method primarily
because the successful efforts method results in moderately better matching of
costs and revenues. It has come to management's attention that certain users of
the Company's financial statements believe that information about the Company
prepared under the full cost method would also be useful. As a result, the
following supplemental full cost information is also included.
Successful efforts methodology is explained in Note 1 Summary of
Significant Accounting Policies.
Under the full cost method of accounting, all costs incurred in the
acquisition, exploration and development of oil and gas properties are
capitalized. These capitalized costs and estimated future development and
dismantlement costs are amortized on a units-of-production method based on
proved reserves. Net capitalized costs of oil and gas properties are limited to
the lower of unamortized cost or the cost center ceiling, defined as the
following:
. The present value (10% discount rate) of estimated unescalated future net
revenues from proved reserves, plus
. The cost of properties not being amortized, plus
. The lower of cost or estimated fair value of unproved properties included
in the costs being amortized, minus
. The deferred tax liabilities for the temporary differences between the book
and tax basis of oil and gas properties.
Proceeds from the sale of oil and gas properties are applied to reduce the costs
in the cost center unless the sale involves a significant quantity of reserves
in relation to the cost center. In this case, a gain or loss is recognized.
Unevaluated properties and associated costs not currently being amortized and
included in oil and gas properties
59
totaled $31.8 million, $32.3 million, and $42.4 million at December 31, 2000,
1999, and 1998, respectively.
Because of the capital cost limitations described above, full cost entities
are not subject to the impairment test prescribed by SFAS 121.
The full cost method of accounting allows for the capitalization of certain
general and administrative, region office and interest expense. Pre-tax
capitalizable administrative expenses were $5.0 million in 2000, $4.6 million in
1999, and $4.6 million in 1998. Pre-tax capitalizable interest expense was
$2.4 million in 2000, $2.7 million in 1999, and $2.0 million in 1998.
2000 1999 1998
---------------------------------------------------------------------
Successful Full Successful Full Successful Full
(In thousands, except per share amounts) Efforts Cost Efforts Cost Efforts Cost
- -----------------------------------------------------------------------------------------------------------------
Balance Sheet
Properties and Equipment, Net $623,174 $834,877 $590,301 $782,156 $629,907 $816,759
Stockholders' Equity 242,505 372,702 186,496 304,487 182,668 297,583
Debt to Capitalization Ratio 52.6% 41.9% 61.1% 49.0% 65.2% 53.5%
Income Statement
Depreciation, Depletion, Amortization
and Unproved Property Impairment $ 66,952 $ 67,002 $ 64,354 $ 66,891 $ 45,588 $ 60,165
Net Income Available to
Common Stockholders 29,221 41,427 5,117 8,194 1,902 4,676
Basic Earnings Per Share $ 1.07 $ 1.51 $ 0.21 $ 0.33 $ 0.08 $ 0.19
15. Earnings per Common Share
Full year basic earnings per share for the Company were $1.07, $0.21, and
$0.08 in 2000, 1999, and 1998, respectively, and were based on the weighted
average shares outstanding of 27,383,848 in 2000, 24,726,030 in 1999, and
24,733,465 in 1998. Diluted earnings per share for the Company were $1.06,
$0.21, and $0.08 in 2000, 1999, and 1998, respectively. The diluted earnings
per share amounts are based on weighted average shares outstanding plus common
stock equivalents. Common stock equivalents include stock awards and stock
options, and totaled 281,210 in 2000, 225,177 in 1999, and 372,937 in 1998.
Both the $3.125 cumulative convertible preferred stock and the 6%
convertible redeemable preferred stock issued May 1993 and May 1994,
respectively, had an antidilutive effect on earnings per common share. The
preferred stock was determined not to be a common stock equivalent when it was
issued. As such, no adjustments were made to net income in the computation of
earnings per share for 1999 or 1998. No preferred stock was outstanding at the
end of 2000. See Note 10 Capital Stock for further discussion.
60
CABOT OIL & GAS CORPORATION
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Oil and Gas Reserves
Users of this information should be aware that the process of estimating
quantities of "proved" and "proved developed" natural gas and crude oil reserves
is very complex, requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each reservoir. The
data for a given reservoir may also change substantially over time as a result
of numerous factors including, but not limited to, additional development
activity, evolving production history and continual reassessment of the
viability of production under varying economic conditions. As a result,
material revisions to existing reserve estimates may occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the subjective
decisions and variances in available data for various reservoirs make these
estimates generally less precise than other estimates included in the financial
statement disclosures.
Proved reserves represent estimated quantities of natural gas, crude oil
and condensate that geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under
economic and operating conditions in effect when the estimates were made.
Proved developed reserves are proved reserves expected to be recovered
through wells and equipment in place and under operating methods used when the
estimates were made.
Estimates of proved and proved developed reserves at December 31, 2000,
1999, and 1998 were based on studies performed by the Company's petroleum
engineering staff. The estimates were reviewed by Miller and Lents, Ltd., who
indicated in their letter dated February 8, 2001, that based on their
investigation and subject to the limitations described in their letter, they
believe the results of those estimates and projections were reasonable in the
aggregate.
No major discovery or other favorable or unfavorable event after December
31, 2000, is believed to have caused a material change in the estimates of
proved or proved developed reserves as of that date.
The following table illustrates the Company's net proved reserves,
including changes, and proved developed reserves for the periods indicated, as
estimated by the Company's engineering staff. All reserves are located in the
United States.
Natural Gas
---------------------------
December 31,
(Millions of cubic feet) 2000 1999 1998
- ---------------------------------------------------------------------------
Proved Reserves
Beginning of Year 929,602 996,756 903,429
Revisions of Prior Estimates (14,796) (1,555) (13,097)
Extensions, Discoveries and Other Additions 103,600 52,781 94,891
Production (60,934) (65,502) (64,167)
Purchases of Reserves in Place 5,118 26,515 76,234
Sales of Reserves in Place (3,368) (79,393) (534)
---------------------------
End of Year 959,222 929,602 996,756
===========================
Proved Developed Reserves 754,962 720,670 788,390
===========================
Percentage of Reserves Developed 78.7% 77.5% 79.1%
===========================
61
Liquids
----------------------
December 31,
(Thousands of barrels) 2000 1999 1998
------------------------------------------------------------------------
Proved Reserves
Beginning of Year 8,189 7,677 5,869
Revisions of Prior Estimates 562 128 (1,644)
Extensions, Discoveries and Other Additions 2,032 1,292 835
Production (988) (963) (736)
Purchases of Reserves in Place 120 362 3,353
Sales of Reserves in Place (1) (307) --
----------------------
End of Year 9,914 8,189 7,677
======================
Proved Developed Reserves 8,438 5,546 5,822
======================
Percentage of Reserves Developed 85.1% 67.7% 75.8%
======================
Capitalized Costs Relating to Oil and Gas Producing Activities
The following table illustrates the total amount of capitalized costs
relating to natural gas and crude oil producing activities and the total amount
of related accumulated depreciation, depletion and amortization.
Year Ended December 31,
(In thousands) 2000 1999 1998
--------------------------------------------------------------------------
Aggregate Capitalized Costs Relating
to Oil and Gas Producing Activities $1,180,692 $1,088,640 $1,107,877
Aggregate Accumulated Depreciation,
Depletion and Amortization $ 558,463 $ 499,201 $ 478,766
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development
Activities
Costs incurred in property acquisition, exploration and development
activities were as follows:
Year Ended December 31,
(In thousands) 2000 1999 1998
-------------------------------------------------------------------
Property Acquisition Costs, Proved $ 5,954 $18,395 $ 83,584
Property Acquisition Costs, Unproved 10,869 7,163 15,587
Exploration and Extension Well Costs 40,008 16,117 36,310
Development Costs 59,879 39,239 82,235
---------------------------
Total Costs $116,710 $80,914 $217,716
===========================
62
Historical Results of Operations from Oil and Gas Producing Activities
The results of operations for the Company's oil and gas producing
activities were as follows:
Year Ended December 31,
(In thousands) 2000 1999 1998
- ------------------------------------------------------------------------------
Operating Revenues $214,116 $156,018 $147,856
Costs and Expenses
Production 46,721 41,942 38,802
Other Operating 17,249 17,009 20,070
Exploration /(1)/ 19,858 11,490 19,564
Depreciation, Depletion and Amortization 63,200 62,446 43,127
----------------------------
Total Costs and Expenses 147,028 132,887 121,563
----------------------------
Income Before Income Taxes 67,088 23,131 26,293
Provision for Income Taxes 23,481 8,096 9,203
----------------------------
Results of Operations $ 43,607 $ 15,035 $ 17,090
============================
---------------------------------------------------------------------------
/(1)/ Includes administrative exploration costs of $8,442, $5,633, and
$6,223 for the years ended December 31, 2000, 1999, and 1998,
respectively. These costs are excluded from the Company's calculation
of finding costs.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves
The following information has been developed utilizing SFAS 69 procedures
and based on natural gas and crude oil reserve and production volumes estimated
by the Company's engineering staff. It can be used for some comparisons, but
should not be the only method used to evaluate the Company or its performance.
Further, the information in the following table may not represent realistic
assessments of future cash flows, nor should the Standardized Measure of
Discounted Future Net Cash Flows be viewed as representative of the current
value of the Company.
The Company believes that the following factors should be taken into
account when reviewing the following information:
. Future costs and selling prices will probably differ from those required to
be used in these calculations.
. Due to future market conditions and governmental regulations, actual rates
of production in future years may vary significantly from the rate of
production assumed in the calculations.
. Selection of a 10% discount rate is arbitrary and may not be a reasonable
measure of the relative risk that is part of realizing future net oil and
gas revenues.
. Future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by
applying year-end oil and gas prices adjusted for fixed and determinable
escalations to the estimated future production of year-end proved reserves.
The average prices related to proved reserves at December 31, 2000, 1999,
and 1998 for natural gas ($ per Mcf) were $9.63, $2.36, and $2.26, respectively,
and for oil ($ per Bbl) were $26.18, $24.15, and $10.23, respectively. Future
cash inflows were reduced by estimated future development and production costs
based on year-end costs to arrive at net cash flow before tax. Future income
tax expense was computed by applying year-end statutory tax rates to future
pretax net cash flows, less the tax basis of the properties involved. SFAS 69
requires the use of a 10% discount rate.
63
Management does not use only the following information when making
investment and operating decisions. These decisions are based on a number of
factors, including estimates of probable as well as proved reserves, and varying
price and cost assumptions considered more representative of a range of
anticipated economic conditions.
Standardized Measure is as follows:
Year Ended December 31,
(In thousands) 2000 /(1)/ 1999 /(1)/ 1998 /(1)/
------------------------------------------------------------------------------------
Future Cash Inflows $ 9,497,181 $ 2,401,349 $ 2,382,860
Future Production and Development Costs (1,628,382) (786,402) (780,705)
---------------------------------------
Future Net Cash Flows Before Income Taxes 7,868,799 1,614,947 1,602,155
10% Annual Discount for Estimated
Timing of Cash Flows (4,332,551) (877,129) (863,226)
---------------------------------------
Standardized Measure of Discounted Future
Net Cash Flows Before Income Taxes 3,536,248 737,818 738,929
Future Income Tax Expenses,
Net of 10% Annual Discount /(2)/ (1,126,416) (150,261) (144,851)
---------------------------------------
Standardized Measure of Discounted
Future Net Cash Flows $ 2,409,832 $ 587,557 $ 594,078
=======================================
---------------------------------------------------------------------------
/(1)/ Includes the future cash inflows, production costs and development
costs, as well as the tax basis, relating to the properties included
in the transactions to monetize the value of Section 29 tax credits.
See Note 13 of the Notes to the Consolidated Financial Statements.
/(2)/ Future income taxes before discount were $2,642,810, $457,256, and
$446,980 for the years ended December 31, 2000, 1999, and 1998,
respectively.
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves
The following is an analysis of the changes in the Standardized Measure:
Year Ended December 31,
(In thousands) 2000 1999 1998
-------------------------------------------------------------------------------------
Beginning of Year $ 587,557 $ 594,078 $ 610,965
Discoveries and Extensions,
Net of Related Future Costs 486,236 65,210 72,275
Net Changes in Prices and Production Costs /(1)/ 2,441,921 1,354 (195,529)
Accretion of Discount 73,782 73,893 83,876
Revisions of Previous Quantity
Estimates, Timing and Other (81,093) (20,162) (36,547)
Development Costs Incurred 28,540 19,586 20,236
Sales and Transfers, Net of Production Costs (167,395) (114,076) (109,054)
Net Purchases (Sales) of Reserves in Place 16,440 (26,916) 64,911
Net Change in Income Taxes (976,156) (5,410) 82,945
----------------------------------
End of Year $2,409,832 $ 587,557 $ 594,078
==================================
/(1)/ For 2000, the prices for natural gas used in this calculation were
regional cash price quotes on the last day of the year. These prices were higher
than the Company actually realized in December 2000. Further, based on market
conditions in February 2001, the prices are not indicative of those that the
Company expects to realize consistently in the future. If reserves had been
valued at a $4.00/Mcf price (which is close to the Henry Hub average for 2000)
using the same year-end regional basis differentials, total proved reserves
would still be above the 1 Tcfe mark with a resulting standardized measure of
discounted future net cash flows before income taxes of $1.3 billion.
64
CABOT OIL & GAS CORPORATION
SELECTED DATA (UNAUDITED)
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
(In thousands, except per share amounts) First Second Third Fourth Total
- ------------------------------------------------------------------------------------------
2000
Operating Revenues $85,120 $82,447 $86,237 $114,847 $368,651
Impairment of Long-Lived Assets -- 9,143 -- -- 9,143
Operating Income 14,773 420 15,799 33,825 64,817
Net Income 4,494 1,518 6,137 17,072 29,221
Basic Earnings Per Share $ 0.18 $ 0.05 $ 0.21 $ 0.59 $ 1.07
Diluted Earnings Per Share $ 0.18 $ 0.05 $ 0.21 $ 0.58 $ 1.06
1999
Operating Revenues $59,046 $61,634 $78,078 $ 95,279 $294,037
Impairment of Long-Lived Assets -- -- -- 7,047 7,047
Operating Income 2,844 8,155 14,061 14,438 39,498
Net Income (Loss) (3,293) 110 3,679 4,621 5,117
Basic Earnings (Loss) Per Share $ (0.13) $ -- $ 0.15 $ 0.19 $ 0.21
Diluted Earnings (Loss) Per Share $ (0.13) $ -- $ 0.15 $ 0.19 $ 0.21
- ------------------------------------------------------------------------------------------
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information under the caption "Election of Directors" in the Company's
definitive Proxy Statement in connection with the 2000 annual stockholders'
meeting is incorporated by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information under the caption "Executive Compensation" in the
definitive Proxy Statement is incorporated by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information under the captions "Beneficial Ownership of Over Five
Percent of Common Stock" and "Beneficial Ownership of Directors and Executive
Officers" in the definitive Proxy Statement is incorporated by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
65
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES AND REPORTS ON FORM 8-K
A. INDEX
1. Consolidated Financial Statements
See Index on page 35.
2. Financial Statement Schedules
None.
3. Exhibits
The following instruments are included as exhibits to this report. Those
exhibits below incorporated by reference herein are indicated as such by the
information supplied in the parenthetical thereafter. If no parenthetical
appears after an exhibit, copies of the instrument have been included herewith.
Exhibit
Number Description
- --------------------------------------------------------------------------------
3.1 Certificate of Incorporation of the Company (Registration Statement No.
33-32553).
3.2 Amended and Restated Bylaws of the Company adopted February 20, 1997
(Form S-3 July 1999).
4.1 Form of Certificate of Common Stock of the Company (Registration
Statement No. 33-32553).
4.2 Certificate of Designation for Series A Junior Participating Preferred
Stock (Form 10-K for 1994).
4.3 Rights Agreement dated as of March 28, 1991, between the Company and The
First National Bank of Boston, as Rights Agent, which includes as Exhibit
A the form of Certificate of Designation of Series A Junior Participating
Preferred Stock (Form 8-A, File No. 1-10477).
(a) Amendment No. 1 to the Rights Agreement dated February 24, 1994 (Form
10-K for 1994).
(b) Amendment No. 2 to the Rights Agreement dated December 8, 2000 (Form
8-K for December 21, 2000).
4.4 Certificate of Designation for 6% Convertible Redeemable Preferred Stock
(Form 10-K for 1994).
4.5 Amended and Restated Credit Agreement dated as of May 30, 1995, among the
Company, Morgan Guaranty Trust Company, as agent and the banks named
therein.
(a) Amendment No. 1 to Credit Agreement dated September 15, 1995 (Form
10-K for 1995).
(b) Amendment No. 2 to Credit Agreement dated December 24, 1996 (Form
10-K for 1996).
4.6 Note Purchase Agreement dated May 11, 1990, among the Company and certain
insurance companies parties thereto (Form 10-Q for the quarter ended June
30, 1990).
(a) First Amendment dated June 28, 1991 (Form 10-K for 1994).
(b) Second Amendment dated July 6, 1994 (Form 10-K for 1994).
4.7 Note Purchase Agreement dated November 14, 1997, among the Company and
the purchasers named therein (Form 10-K for 1997).
10.1 Supplemental Executive Retirement Agreement between the Company and
Charles P. Siess, Jr. (Form 10-K for 1995).
10.2 Form of Change in Control Agreement between the Company and Certain
Officers (Form 10-K for 1995).
10.3 Letter Agreement dated January 11, 1990, between Morgan Guaranty Trust
Company of New York and the Company (Registration Statement No. 33-
32553).
10.4 Form of Annual Target Cash Incentive Plan of the Company (Registration
Statement No. 33-32553).
10.5 Form of Incentive Stock Option Plan of the Company (Registration
Statement No. 33-32553).
(a) First Amendment to the Incentive Stock Option Plan (Post-Effective
Amendment No. 1 to S-8 dated April 26, 1993).
10.6 Form of Stock Subscription Agreement between the Company and certain
executive officers and directors of the Company (Registration Statement
No. 33-32553).
66
Exhibit
Number Description
- --------------------------------------------------------------------------------
10.7 Transaction Agreement between Cabot Corporation and the Company dated
February 1, 1991 (Registration Statement No. 33-37455).
10.8 Tax Sharing Agreement between Cabot Corporation and the Company dated
February 1, 1991 (Registration Statement No. 33-37455).
10.9 Amendment Agreement (amending the Transaction Agreement and the Tax
Sharing Agreement) dated March 25, 1991 (incorporated by reference from
Cabot Corporation's Schedule 13E-4, Am. No. 6, File No. 5-30636).
10.10 Savings Investment Plan & Trust Agreement of the Company (Form 10-K for
1991).
(a) First Amendment to the Savings Investment Plan dated May 21, 1993
(Form S-8 dated November 1, 1993).
(b) Second Amendment to the Savings Investment Plan dated May 21, 1993
(Form S-8 dated November 1, 1993).
(c) First through Fifth Amendments to the Trust Agreement (Form 10-K for
1995).
(d) Third through Fifth Amendments to the Savings Investment Plan
(Form 10-K for 1996).
10.11 Supplemental Executive Retirement Agreements of the Company (Form 10-K
for 1991).
10.12 Settlement Agreement and Mutual Release (Tax Issues) between Cabot
Corporation and the Company dated July 7, 1992 (Form 10-Q for the
quarter ended June 30, 1992).
10.13 Agreement of Merger dated February 25, 1994, among Washington Energy
Company, Washington Energy Resources Company, the Company and COG
Acquisition Company (Form 10-K for 1993).
10.14 1990 Non-employee Director Stock Option Plan of the Company (Form S-8
dated June 23, 1990).
(a) First Amendment to 1990 Non-employee Director Stock Option Plan
(Post-Effective Amendment No. 2 to Form S-8 dated March 7, 1994).
(b) Second Amendment to 1990 Non-employee Director Stock Option Plan
(Form 10-K for 1995).
10.15 Amended and Restated 1994 Long-Term Incentive Plan of the Company (Form
10-K for 1998).
10.16 Amended and Restated 1994 Non-Employee Director Stock Option Plan (Form
10-K for 1998).
10.17 Employment Agreement between the Company and Ray R. Seegmiller dated
September 25, 1995 (Form 10-K for 1995).
10.18 Form of Indemnity Agreement between the Company and Certain Officers
(Form 10-K for 1997).
10.19 Deferred Compensation Plan of the Company (Form 10-K for 1998).
10.20 Trust Agreement dated August 1998 between Bankers Trust Company and the
Company (Form 10-K for 1998).
10.21 Lease Agreement between the Company and DNA COG, Ltd. dated April 24,
1998 (Form 10-K for 1998).
10.22 Credit Agreement dated as of December 17, 1998, between the Company and
the banks named therein (Form 10-K for 1998).
10.23 Letter Agreement with Puget Sound Energy Company dated September 21,
1999 (Form 10-K for 1999).
21.1 Subsidiaries of Cabot Oil & Gas Corporation.
23.1 Consent of PricewaterhouseCoopers LLP.
23.2 Consent of Miller and Lents, Ltd.
28.1 Miller and Lents, Ltd. Review Letter dated February 8, 2001.
B. Reports on Form 8-K
Form 8-K Item 5. Other Events filed on December 21, 2000.
67
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized, in the City of Houston, State of Texas,
on the 22nd of February 2001.
CABOT OIL & GAS CORPORATION
By: /s/ Ray R. Seegmiller
----------------------------------------
Ray R. Seegmiller
Chairman of the Board,
Chief Executive Officer and President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons in the capacities and on
the dates indicated.
Signature Title Date
- --------------------------------------------------------------------------------
/s/ Ray R. Seegmiller Chairman of the Board, Chief February 22, 2001
- ----------------------- Executive Officer and President
Ray R. Seegmiller (Principal Executive Officer)
/s/ Scott C. Schroeder Vice President, Chief Financial February 22, 2001
- ----------------------- Officer and Treasurer
Scott C. Schroeder (Principal Financial Officer)
/s/ Henry C. Smyth Vice President and Controller February 22, 2001
- ----------------------- (Principal Accounting Officer)
Henry C. Smyth
/s/ Robert F. Bailey Director February 22, 2001
- -----------------------
Robert F. Bailey
/s/ Henry O. Boswell Director February 22, 2001
- -----------------------
Henry O. Boswell
/s/ John G. L. Cabot Director February 22, 2001
- -----------------------
John G. L. Cabot
/s/ William R. Esler Director February 22, 2001
- -----------------------
William R. Esler
/s/ C. Wayne Nance Director February 22, 2001
- -----------------------
C. Wayne Nance
/s/ P. Dexter Peacock Director February 22, 2001
- -----------------------
P. Dexter Peacock
68
/s/ Charles P. Siess, Jr. Director February 22, 2001
- ---------------------------
Charles P. Siess, Jr.
/s/ Arthur L. Smith Director February 22, 2001
- ---------------------------
Arthur L. Smith
/s/ William P. Vititoe Director February 22, 2001
- ---------------------------
William P. Vititoe
69