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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