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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, 1999
Commission file number 1-10447
CABOT OIL & GAS CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 04-3072771
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
1200 ENCLAVE PARKWAY, HOUSTON, TEXAS 77077
(Address of principal executive offices including Zip Code)
(281) 589-4600
(Registrant's telephone number)
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- -------------------
Class A Common Stock, par value $.10 per share New York Stock Exchange
Rights to Purchase Preferred Stock New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months and (2) has been subject to such filing
requirements for the past 90 days.
Yes [ X ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K [__].
The aggregate market value of Class A Common Stock, par value $.10 per
share ("Common Stock"), held by non-affiliates (based upon the closing sales
price on the New York Stock Exchange on February 29, 2000), was approximately
$390,000,000.
As of February 29, 2000, there were 24,793,578 shares of Common Stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Stockholders to
be held May 9, 2000, are incorporated herein by reference in Items 10, 11, 12
and 13 of Part III of this report.
1
TABLE OF CONTENTS
PART I PAGE
ITEMS 1 and 2 Business and Properties...................................... 3
ITEM 3 Legal Proceedings............................................ 18
ITEM 4 Submission of Matters to a Vote of Security Holders.......... 18
Executive Officers of the Registrant......................... 19
PART II
ITEM 5 Market for Registrant's Common Equity and
Related Stockholder Matters............................... 20
ITEM 6 Selected Historical Financial Data........................... 20
ITEM 7 Management's Discussion and Analysis of Financial
Condition and Results of Operations....................... 21
ITEM 7A Quantitative and Qualitative Disclosures about Market Risk... 32
ITEM 8 Financial Statements and Supplementary Data.................. 35
ITEM 9 Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.................... 63
PART III
ITEM 10 Directors and Executive Officers of the Registrant........... 63
ITEM 11 Executive Compensation....................................... 63
ITEM 12 Security Ownership of Certain Beneficial
Owners and Management..................................... 63
ITEM 13 Certain Relationships and Related Transactions............... 63
PART IV
ITEM 14 Exhibits, Financial Statement Schedules and
Reports on Form 8-K....................................... 64
--------------------------
The statements regarding future financial performance and results, and
market prices 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 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.
Our asset base combines the opportunity for production and reserve growth
from shorter life, higher margin properties with a core of stable, long-lived
reserves. Since our initial public offering in 1990, when our reserves were
located only in the longer-lived, lower-growth Appalachian and Mid-Continent
areas, we have acquired two new core areas that we believe have higher growth
potential - the onshore Gulf Coast and the Rocky Mountains - and we have
divested certain non-strategic properties, primarily in Appalachia. As a result,
we have focused our capital budget on projects that we believe have more
favorable risk/reward potential. We deploy the relatively stable excess cash
flows from our Appalachian and Mid-Continent properties to fund activities in
our higher growth, higher rate of return areas of the Gulf Coast and the Rocky
Mountains.
As of December 31, 1999, our proved reserves totaled 978.7 Bcfe, and
natural gas comprised 95% of our reserves. We operate approximately 83% of the
wells in which we have an interest. Despite the second and third quarter
divestiture of non-strategic properties producing 13.5 Mmcfe per day primarily
in Appalachia, our average daily net production for 1999 was 195.3 Mmcfe per
day, an increase of 4% over 1998. Exploration and exploitation success in the
Gulf Coast region has largely accounted for the production increase. Production
from the region rose 60% for 1999 compared to 1998, with average daily volumes
from the region increasing from 32.6 Mmcfe per day to 52.0 Mmcfe per day. The
following table presents certain information as of December 31, 1999.
West
----------------------------
Gulf Rocky Mid- Total
Coast Mountains Continent West Appalachia Total
- -------------------------------------------------------------------------------------------------------
Proved Reserves at Year End (Bcfe)
Developed................................ 80.6 186.3 178.5 364.8 308.6 753.9
Undeveloped.............................. 43.3 71.4 34.8 106.2 75.2 224.8
----- ----- ----- ----- ----- -----
Total................................... 123.9 257.7 213.3 471.0 383.8 978.7
Average Daily Production (Mmcfe per day)... 52.0 48.6 37.2 85.8 57.4 195.3
Reserves Life Index (in years)(1).......... 6.5 14.6 15.7 15.0 18.3 13.7
Gross Productive Wells..................... 367 469 661 1,130 2,270 3,767
Net Productive Wells....................... 264.1 210.1 433.5 643.6 2,105.8 3,013.5
Wells Operated............................. 59.9% 48.0% 74.3% 63.4% 96.3% 82.9%
Net Acreage
Developed................................ 50,746 75,062 180,352 255,414 745,346 1,051,506
Undeveloped acreage...................... 62,970 67,130 24,614 91,744 296,850 451,564
------- ------- ------- ------- --------- ---------
Total 113,716 142,192 204,966 347,158 1,042,196 1,503,070
- ----------
(1) Reserve Life Index is equal to year-end reserves divided by annual
production.
3
GULF COAST. Our Gulf Coast activities are concentrated in south Louisiana
and south Texas. Principal producing intervals are in the Wilcox and Vicksburg
formations in Texas and the Miocene age formations in Louisiana. Capital
expenditures were $36.8 million in 1999, or 42% of our total 1999 capital
expenditures and $128.7 million for 1998, which included a $70.1 million
acquisition in southern Louisiana from Oryx Energy Company. 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 52.0 Mmcfe per day in 1999. For 2000, we have
budgeted $49.8 million (57% of our total 2000 capital budget) for capital
expenditures in the region.
ROCKY MOUNTAINS. Our Rocky Mountains activities are concentrated in the
Green River Basin of Wyoming. Since our initial acquisition in the region in
1994 from Washington Energy, we have increased reserves from 171.6 Bcfe at
December 31, 1994, to 257.7 Bcfe at December 31, 1999. Capital expenditures,
including $17.4 million in property acquisitions, were $29.5 million for 1999,
or 33% of our total 1999 capital expenditures and $32.3 million for 1998. For
2000, we have budgeted $20.0 million (23% of our total 2000 capital budget) for
capital expenditures in the region.
MID-CONTINENT. Our Mid-Continent activities are concentrated in the
Anadarko Basin in southwestern Kansas, Oklahoma and the panhandle of Texas.
Capital expenditures were $4.1 million for 1999, or 5% of our total 1999 capital
expenditures and $20.2 million for 1998. For 2000, we have budgeted $1.8 million
(2% of our total 2000 capital budget) for capital expenditures in the region.
APPALACHIA. 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
expenditures were $14.6 million for 1999, or 17% of our total 1999 capital
expenditures and $43.2 million for 1998. For 2000, we have budgeted $16.0
million (18% of our total 2000 capital budget) for capital expenditures in the
region.
EXPLORATION, DEVELOPMENT AND PRODUCTION
Cabot Oil & Gas is one of the largest producers of natural gas in the
Appalachian Basin, where we have operated for more than a century. We have
operated in the Anadarko Basin (Mid-Continent) for more than 60 years. Our Rocky
Mountains and Gulf Coast activities were added with the acquisition of
Washington Energy Resources Company in 1994.
GULF COAST REGION
Our exploration, development and production activities in the Gulf Coast
region are concentrated in south Louisiana and south Texas. A regional office in
Houston manages operations. At December 31, 1999, we had 123.9 Bcfe of proved
reserves (77.8% natural gas) in the Gulf Coast region, constituting 13% of our
total proved reserves.
We had 367 productive wells (264.1 net) in the Gulf Coast region as of
December 31, 1999, of which 220 wells are operated by us. Principal producing
intervals in the Gulf Coast are in the Wilcox and Vicksburg formations in Texas,
and Miocene age formations in Louisiana at depths ranging from 3,000 to 18,000
feet. Average net daily production in 1999 was 52.0 Mmcfe.
In 1999, we drilled 16 wells (10.3 net) in the Gulf Coast region, of which
13 wells (9.2 net) were development wells. Capital and exploration expenditures
for the year were $36.8 million. Our most significant discovery occurred in the
first well drilled on the south Louisiana Etouffee prospect, a project in which
we have a 33% working interest. At year end, this field had 17.1 Bcfe of net
proved reserves. Production is expected to commence on the first well in
Etouffee during March 2000. The Gulf Coast region plans to drill 24 wells and
spend 57% of our $88.9 million capital budget in 2000.
At December 31, 1999, we had 113,716 net acres in the region, including
50,746 net developed acres. At the end of 1999, we had identified 17 proved
undeveloped drilling locations.
4
WESTERN REGION
Our exploration, development and production activities in the Western
region are primarily focused in the Rocky Mountains within the Green River Basin
of Wyoming and in the Mid-Continent within the Anadarko Basin in southwestern
Kansas, Oklahoma and the panhandle of Texas. A regional office in Denver manages
the operations. At December 31, 1999, we had 471.0 Bcfe of proved reserves
(96.0% natural gas) in the Western region, constituting 48% of our total proved
reserves.
ROCKY MOUNTAINS. We had 469 productive wells (210.1 net) in the Rocky
Mountains area as of December 31, 1999, of which 225 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 13,000 feet. Average net
daily production in 1999 was 48.6 Mmcfe.
In 1999, we drilled 19 wells (10.4 net) in the Rocky Mountains, of which 18
wells (9.4 net) were development and extension wells. Capital and exploration
expenditures for the year were $29.5 million. In 2000, we plan to drill 45 wells
and spend 23% of our capital budget in this area.
At December 31, 1999, we had 142,192 net acres in the area, including
75,062 net developed acres. At the end of 1999, we had identified 83 proved
undeveloped drilling locations.
MID-CONTINENT. As of December 31, 1999, we had 661 productive wells (433.5
net) in the Mid-Continent area, of which 491 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 13,000 feet. Average net
daily production in 1999 was 37.2 Mmcfe.
In 1999, we drilled four wells (1.2 net) in the Mid-Continent, of which
three wells (0.8 net) were development and extension wells. Capital and
exploration expenditures for the year were $4.1 million. In 2000, we plan to
drill four wells and spend 2% of our capital budget in this area.
At December 31, 1999, we had 204,966 net acres in the area, including
180,352 net developed acres. At the end of 1999, we had identified 67 proved
undeveloped drilling locations.
APPALACHIAN REGION
Our exploration, development and production activities in the Appalachian
region are concentrated in Pennsylvania, Ohio, West Virginia and Virginia. A
regional office in Pittsburgh manages operations. At December 31, 1999, we had
383.8 Bcfe of proved reserves (substantially all natural gas) in the Appalachian
region, constituting 39% of our total proved reserves.
At December 31, 1999, we had 2,270 productive wells (2,105.8 net), of which
2,187 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 1999
was 57.4 Mmcfe. While natural gas production volumes from Appalachian reservoirs
are relatively low on a per-well basis compared to other areas of the United
States, the productive life of Appalachian reserves is relatively long.
In 1999, we drilled 34 wells (23.5 net) in the Appalachian region, of which
27 wells (19.5 net) were development wells. Capital and exploration
expenditures, including pipeline expenditures, were $14.6 million for the year.
In 2000, we plan to drill 38 wells and spend 18% of our capital budget in this
region.
At December 31, 1999, we had 1,042,196 net acres in the region, including
745,346 net developed acres. At the end of 1999, we had identified 216 proved
undeveloped drilling locations.
We own and operate two natural gas storage fields in West Virginia with a
combined working gas capacity of 4 Bcf.
5
Ancillary to our exploration and production operations, 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.
We believe that we gain operational efficiency in the Appalachian region
because of our large acreage position, high concentration of wells, contiguous
natural gas gathering and pipeline systems and storage capacity.
GAS MARKETING
We are engaged in a wide array of marketing activities offering our
customers long-term, reliable supplies of natural gas. Utilizing our pipeline
and storage facilities, gas procurement ability and transportation and natural
gas risk management expertise, we provide a menu of services that includes gas
supply and transportation management, short-term and long-term supply contracts,
capacity brokering and risk management alternatives.
The marketing of natural gas has changed significantly as a result of FERC
Order 636, which was issued by the Federal Energy Regulatory Commission (FERC)
in 1992. FERC Order 636 required pipelines to unbundle their gas sales, storage
and transportation services. As a result, local distribution companies and
end-users separately contract these services from gas marketers and producers.
FERC Order 636 has had the effect of creating greater competition in the
industry while also providing us the opportunity to serve broader markets. Since
FERC Order 636 was issued, there has been an increase in the number of
third-party producers that use us to market their gas. Additionally, as a result
of FERC Order 636, we have experienced increased competition for markets, which
has placed pressure on the premiums we have received.
GULF COAST REGION
Our principal markets for Gulf Coast region natural gas are in the
industrialized Gulf Coast areas and the northeastern United States. Our
marketing subsidiary, Cabot Oil & Gas Marketing Corporation, purchases all of
our natural gas production in the Gulf Coast region. The marketing subsidiary
sells the natural gas to intrastate pipelines, natural gas processors and
marketing companies.
Currently, all of our natural gas sales volumes in the Gulf Coast region
are sold at market-responsive prices under contracts with terms of one to three
years. 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 1,500 barrels a day of crude
oil/condensate in the Gulf Coast region at market-responsive prices.
WESTERN REGION
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. The
marketing subsidiary sells the natural gas to cogenerators, natural gas
processors, local distribution companies, industrial customers and marketing
companies.
Currently, most of our natural gas production in the Western region is sold
primarily under contracts with a term of one year or less at market-responsive
prices. Through 1999, approximately 20% of the Western region's production was
sold under a 15-year cogeneration contract due to expire in 2009 that escalated
5% in price per year. In December 1999, the contract was bought out for a cash
payment of $12 million to Cabot Oil & Gas. Accordingly, our obligation to
deliver natural gas to the cogeneration facility was terminated and we have no
other obligation under the contract. The Western region properties are connected
to the majority of the midwestern and northwestern interstate and intrastate
pipelines, affording us access to multiple markets. We also produce and market
approximately 900 barrels of crude oil/condensate a day in the Western region at
market-responsive prices.
6
APPALACHIAN REGION
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. Our 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
market-responsive 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 10% of Appalachian production is sold on
fixed price contracts that typically renew annually.
Our Appalachian natural gas production is generally sold at a higher
realized price, or premium, compared to production from other producing regions
due to its close proximity to eastern 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. We expect that
the premium will remain at this lower level for the near future.
Ancillary to our exploration and production operations, we operate a number
of gas gathering and transmission pipeline systems, made up of approximately
2,390 miles of pipeline with interconnects to three interstate transmission
systems and seven local distribution companies as of the end of 1999. The
majority of our pipeline infrastructure in West Virginia is regulated by the
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.
RISK MANAGEMENT
In 1999, we used certain financial instruments, called derivatives, to
manage price risks associated with our production and brokering activities. The
impact of these derivatives on our financial results was not material. While
there are many different types of derivatives available, we primarily used
natural gas and oil price swap agreements to attempt to manage price risk more
effectively. These price swaps call for payments to, or receipts from,
counterparties based on the differential between a fixed and a variable gas
price. We will continue to evaluate the benefit of this strategy in the future.
Please read Management's Discussion and Analysis of Financial Condition and
Results of Operations - Commodity Price Swaps for further discussion concerning
our use of derivatives.
7
RESERVES
CURRENT RESERVES
The following table presents our estimated proved reserves at December 31,
1999.
Natural Gas (Mmcf) Liquids(1) (Mbbl) Total(2) (Mmcfe)
- ------------------------------------------------------------------------------------------------------------------
Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total
- ------------------------------------------------------------------------------------------------------------------
Gulf Coast........ 64,436 31,989 96,425 2,691 1,896 4,587 80,583 43,365 123,948
Rocky Mountains... 176,908 67,197 244,105 1,559 703 2,262 186,259 71,418 257,677
Mid-Continent..... 173,702 34,554 208,256 802 44 846 178,515 34,821 213,336
Appalachia........ 305,624 75,192 380,816 494 -- 494 308,587 75,193 383,780
------- ------- ------- ----- ----- ----- ------- ------- -------
Total............. 720,670 208,932 929,602 5,546 2,643 8,189 753,944 224,797 978,741
======= ======= ======= ===== ===== ===== ======= ======= =======
- ----------
(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 do not differ materially
from those filed by us with other federal agencies. Our reserves are sensitive
to natural gas sales prices and their effect on economic producing rates. Our
reserves are based on oil and gas prices in effect for December 1999.
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 cannot 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 (Mmcf)
---------------------------------------------------------
Rocky Mid- Total
Gulf Mtn Cont West App Total
------- ------- ------- ------- ------- -------
December 31, 1996................. 23,267 144,627 220,863 365,490 526,859 915,616
------- ------- ------- ------- ------- -------
Revision of Prior Estimates..... 5,234 677 (2,096) (1,419) 2,929 6,744
Extensions, Discoveries and
Other Additions............... 30,520 19,079 16,983 36,062 42,609 109,191
Production...................... (8,445) (13,957) (16,147) (30,104) (25,340) (63,889)
Purchases of Reserves in Place.. 1 68,480 0 68,480 5,355 73,836
Sales of Reserves in Place...... (419) (457) 0 (457) (137,194) (138,070)
------- ------- ------- ------- ------- -------
December 31, 1997................. 50,158 218,449 219,603 438,052 415,218 903,428
------- ------- ------- ------- ------- -------
Revision of Prior Estimates..... (7,545) (2,852) 579 (2,273) (3,279) (13,097)
Extensions, Discoveries and
Other Additions............... 16,524 24,450 11,608 36,058 42,310 94,892
Production...................... (10,620) (16,153) (14,710) (30,863) (22,684) (64,167)
Purchases of Reserves in Place.. 52,833 12,205 9,029 21,234 2,167 76,234
Sales of Reserves in Place...... 0 0 0 0 (534) (534)
------- ------- ------- ------- ------- -------
December 31, 1998................. 101,350 236,099 226,109 462,208 433,198 996,756
------- ------- ------- ------- ------- -------
Revision of Prior Estimates..... (749) 698 (1,576) (878) 72 (1,555)
Extensions, Discoveries and
Other Additions............... 17,029 12,799 4,560 17,359 18,393 52,781
Production...................... (15,503) (16,459) (12,832) (29,291) (20,708) (65,502)
Purchases of Reserves in Place.. 831 14,213 0 14,213 11,471 26,515
Sales of Reserves in Place...... (6,533) (3,245) (8,005) (11,250) (61,610) (79,393)
------- ------- ------- ------- ------- -------
December 31, 1999................. 96,425 244,105 208,256 452,361 380,816 929,602
======= ======= ======= ======= ======= =======
Proved Developed Reserves
December 31, 1996............... 21,955 116,034 195,551 311,585 434,558 768,098
December 31, 1997............... 41,016 164,432 189,598 354,030 343,718 738,764
December 31, 1998............... 61,186 177,136 189,165 366,301 360,903 788,390
December 31, 1999............... 64,436 176,908 173,702 350,610 305,624 720,670
Gulf = Gulf Coast
Rocky Mtn = Rocky Mountains
Mid-Cont = Mid-Continent or Anadarko
Total West = Rocky Mountains and Mid-Continent combined
App = Appalachia
9
Total (Mmcfe)(1)
-----------------------------------------------------------
Rocky Mid- Total
Gulf Mtn Cont West App Total
------- ------- ------- ------- ------- ---------
December 31, 1996................. 27,081 161,812 228,856 390,668 528,862 946,611
Revision of Prior Estimates..... 6,401 911 (3,303) (2,392) 3,327 7,336
Extensions, Discoveries and
Other Additions............... 33,079 19,974 17,410 37,384 43,493 113,956
Production...................... (9,255) (15,745) (17,035) (32,780) (25,628) (67,663)
Purchases of Reserves in Place.. 1 72,034 0 72,034 5,366 77,401
Sales of Reserves in Place...... (798) (680) 0 (680) (137,520) (138,998)
------- ------- ------- ------- ------- ---------
December 31, 1997................. 56,509 238,306 225,928 464,234 417,900 938,643
------- ------- ------- ------- ------- ---------
Revision of Prior Estimates..... (9,218) (9,616) (551) (10,167) (3,578) (22,963)
Extensions, Discoveries and
Other Additions............... 17,871 27,250 11,619 38,869 43,164 99,904
Production...................... (11,911) (18,341) (15,414) (33,755) (22,918) (68,584)
Purchases of Reserves in Place.. 72,201 12,468 9,330 21,798 2,354 96,353
Sales of Reserves in Place...... 0 0 0 0 (534) (534)
------- ------- ------- ------- ------- ---------
December 31, 1998................. 125,452 250,067 230,912 480,979 436,388 1,042,819
------- ------- ------- ------- ------- ---------
Revision of Prior Estimates..... 193 (1,215) (12) (1,227) 247 (787)
Extensions, Discoveries and
Other Additions............... 23,576 13,650 4,593 18,243 18,716 60,535
Production...................... (18,976) (17,747) (13,588) (31,335) (20,968) (71,279)
Purchases of Reserves in Place.. 872 16,266 0 16,266 11,547 28,685
Sales of Reserves in Place...... (7,169) (3,344) (8,569) (11,913) (62,150) (81,232)
------- ------- ------- ------- ------- ---------
December 31, 1999................. 123,948 257,677 213,336 471,013 383,780 978,741
======= ======= ======= ======= ======= =========
Proved Developed Reserves
December 31, 1996............... 25,577 131,048 203,021 334,069 436,560 796,206
December 31, 1997............... 45,913 180,304 195,302 375,606 346,400 767,919
December 31, 1998............... 77,452 188,102 193,674 381,776 364,093 823,321
December 31, 1999............... 80,583 186,259 178,515 364,774 308,587 753,944
Gulf = Gulf Coast
Rocky Mtn = Rocky Mountains
Mid-Cont = Mid-Continent or Anadarko
Total West = Rocky Mountains and Mid-Continent combined
App = Appalachia
- ----------
(1) Includes natural gas and natural gas equivalents determined by using the
ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural
gas liquids.
10
VOLUMES AND PRICES; PRODUCTION COSTS
The following table presents regional historical information about our net
wellhead sales volume for natural gas and oil (including condensate and natural
gas liquids) produced natural gas and oil sales prices and production costs per
equivalent.
Year Ended December 31,
1999 1998 1997
------ ------ ------
Net Wellhead Sales Volume
Natural Gas (Bcf)(1)
Gulf Coast................................ 15.5 10.6 8.4
West...................................... 29.3 30.9 30.2
Appalachia (2)............................ 20.7 22.7 25.3
Crude/Condensate/Ngl (Mbbl)
Gulf Coast............................... 561 215 135
West..................................... 325 482 447
Appalachia............................... 43 39 48
Produced Natural Gas Sales Price ($/Mcf)(3)
Gulf Coast................................. $ 2.29 $ 2.15 $ 2.52
West....................................... 1.96 1.90 2.14
Appalachia................................. 2.53 2.53 3.00
Weighted Average........................... 2.22 2.16 2.53
Crude/Condensate Sales Price ($/Bbl)(3)...... $17.22 $13.06 $20.13
Production Costs ($/Mcfe)(4)................. $ 0.59 $ 0.57 $ 0.58
- ---------------
(1) Equal to the aggregate of production and the net changes in storage and
exchanges.
(2) The decline in the Appalachian region natural gas sales volume is
attributed to the sale of the Meadville properties effective September 1,
1997. Prior to the sale, these properties produced 3.6 Bcf, or 14.7 Mmcf
per day, during the eight-month period ending August 31, 1997. In addition,
a further decline is associated with the sale of properties in the
Clarksburg district effective October 1, 1999. Prior to this sale, those
properties produced approximately 7 Mmcf per day.
(3) Represents the average sales prices 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).
(4) 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.
ACREAGE
The following tables summarize our gross and net developed and undeveloped
leasehold and mineral acreage at December 31, 1999. Acreage in which our
interest is limited to royalty and overriding royalty interests is excluded.
11
LEASEHOLD ACREAGE
At December 31, 1999
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........ 13,812 13,192 0 0 13,812 13,192
Kansas.......... 29,067 27,765 0 0 29,067 27,765
Kentucky........ 2,434 934 0 0 2,434 934
Louisiana....... 42,687 33,898 111,250 39,225 153,937 73,123
Michigan........ 759 205 0 0 759 205
Montana......... 397 210 680 303 1,077 513
New York........ 2,737 1,098 2,812 1,252 5,549 2,350
North Dakota.... 0 0 870 96 870 96
Ohio............ 6,207 2,421 27,045 22,206 33,252 24,627
Oklahoma........ 161,112 111,063 32,405 20,129 193,517 131,192
Pennsylvania.... 131,220 81,163 40,685 33,054 171,905 114,217
Texas........... 66,628 44,238 78,929 27,510 145,557 71,748
Utah............ 1,740 530 20,034 16,862 21,774 17,392
Virginia........ 22,240 20,039 10,880 6,823 33,120 26,862
West Virginia... 574,811 542,199 221,634 181,618 796,445 723,817
Wyoming......... 121,099 61,130 76,084 49,788 197,183 110,918
--------- ------- ------- ------- --------- ---------
Total...........1,176,950 940,085 623,860 399,184 1,800,810 1,339,269
========= ======= ======= ======= ========= =========
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
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............ 132,125 111,421 59,007 52,380 191,132 163,801
========= ========= ======= ======= ========= =========
Aggregate Total...1,309,075 1,051,506 682,867 451,564 1,991,942 1,503,070
========= ========= ======= ======= ========= =========
12
TOTAL NET ACREAGE BY REGION OF OPERATION
Developed Undeveloped Total
- ----------------------------------------------------------------
Gulf Coast............ 50,746 62,970 113,716
West.................. 255,414 91,744 347,158
Appalachia............ 745,346 296,850 1,042,196
--------- ------- ---------
Total........ 1,051,506 451,564 1,503,070
========= ======= =========
PRODUCTIVE WELL SUMMARY
The following table presents our ownership at December 31, 1999, 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, New York,
Ohio, Virginia and Kentucky). 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 wells.
Natural Gas Oil Total
Gross Net Gross Net Gross Net
- -------------------------------------------------------------------------------
Gulf Coast.......... 268 190.8 99 73.3 367 264.1
West................ 1,058 601.1 72 42.5 1,130 643.6
Appalachia.......... 2,246 2,096.0 24 9.8 2,270 2,105.8
----- ------- --- ---- ----- -------
Total...... 3,572 2,887.9 195 125.6 3,767 3,013.5
===== ======= === ===== ===== =======
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,
1999 1998 1997
Gross Net Gross Net Gross Net
- -----------------------------------------------------------------------------
Gulf Coast
Development Wells
Successful.......... 10 6.2 9 4.0 7 3.5
Dry................. 3 3.0 0 0.0 1 0.6
Extension Wells
Successful.......... 0 0.0 0 0.0 3 2.6
Dry................. 0 0.0 0 0.0 0 0.0
Exploratory Wells
Successful.......... 2 0.6 7 4.6 5 1.6
Dry................. 1 0.5 1 1.0 4 2.0
-- ---- -- --- -- ----
Total.......... 16 10.3 17 9.6 20 10.3
== ==== == === == ====
Wells Acquired (1)........ 2 0.6 219 204.2 0 0.0
Wells in Progress at End
of Period.............. 1 0.3 5 4.2 0 0.0
13
Year Ended December 31,
1999 1998 1997
Gross Net Gross Net Gross Net
- -----------------------------------------------------------------------------
West
Development Wells
Successful.......... 19 9.0 64 36.2 66 29.7
Dry................. 1 1.0 4 1.9 4 3.1
Extension Wells
Successful.......... 1 0.3 5 2.2 9 8.6
Dry................. 0 0.0 1 0.9 2 1.0
Exploratory Wells
Successful.......... 0 0.0 2 0.7 1 1.0
Dry................. 2 1.3 3 2.0 3 0.9
-- ---- -- ---- -- ----
Total........... 23 11.6 79 43.9 85 44.3
== ==== == ==== == ====
Wells Acquired (1)........ 27 10.7 13 3.9 65 18.7
Wells in Progress at End
of Period.............. 5 2.3 4 1.8 6 3.3
Year Ended December 31,
1999 1998 1997
Gross Net Gross Net Gross Net
- -----------------------------------------------------------------------------
Appalachia
Development Wells
Successful.......... 26 19.0 77 69.4 82 73.7
Dry................. 1 0.5 6 4.8 5 5.0
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.......... 3 2.0 18 11.0 25 11.8
Dry................. 4 2.0 8 5.0 8 6.3
-- ---- --- ---- --- ----
Total........... 34 23.5 109 90.2 120 96.8
== ==== === ==== === ====
Wells Acquired (1)........ 0 0 5 4.2 1 40.0
Wells in Progress at End
of Period.............. 1 0.3 1 0.5 4 3.1
- ----------
(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 wells purchased and then resold during 1999.
14
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. We believe that marketing our own gas through the operation of Cabot
Oil & Gas Marketing Corporation enhances our competitive position.
OTHER BUSINESS MATTERS
MAJOR CUSTOMER
We had no sales to any customer that exceeded 10% of our total gross
revenues in 1999 or 1998.
SEASONALITY
Demand for natural gas has historically been seasonal, with peak demand and
typically higher prices during the colder winter months.
REGULATION OF OIL AND NATURAL GAS PRODUCTION 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 and 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
prohibit the venting or flaring of natural gas, and impose 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. Cabot Oil & Gas, however, does not believe it is 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 transportation and the sale in interstate commerce for resale of
natural gas. The FERC's jurisdiction over interstate natural gas sales was
substantially modified by the Natural Gas Policy Act, 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,
which may be in effect. The FERC's jurisdiction over natural gas transportation
was not affected by the Decontrol Act.
15
Natural gas sales are affected by intrastate and interstate gas
transportation regulation. Beginning in 1985, 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. All gas
marketing by the pipelines was required to be divested to a marketing affiliate,
which operates 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 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. Through similar orders affecting
intrastate pipelines that provide similar interstate services, the FERC expanded
the impact of open access regulations to intrastate commerce.
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, (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 review of the role of 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 the pipeline's demonstration 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 cannot
predict what new or different regulations the FERC and other regulatory agencies
may adopt, or what effect subsequent regulations may have on our activities.
In the past, Congress has been very active in the area of gas regulation.
However, as discussed above, the more recent trend has been in favor of
deregulation and the promotion of competition in the gas industry. Thus, in
addition to "first sale" deregulation, Congress also repealed incremental
pricing requirements and gas use restraints that were previously applicable.
There are other legislative proposals pending in the Federal and state
legislatures which, if enacted, would significantly affect the petroleum
industry. At the present time, it is impossible to predict what proposals, if
any, 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, cannot be predicted.
Our pipeline systems and storage fields are regulated for safety compliance
by the U.S. Department of Transportation, the West Virginia Public Service
Commission and the Pennsylvania Department of Natural Resources. Our pipeline
systems in each state operate independently and are not interconnected.
16
FEDERAL REGULATION OF PETROLEUM
Sales of oil and natural gas liquids by the Company 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 will 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 is scheduled for
2000. The Company is not able to predict with certainty the effect upon it of
these relatively new federal regulations or of the periodic review by 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 various Cabot Oil & Gas 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 parts of oil and gas production operations.
No assurance can be given that significant costs and liabilities will not be
incurred. Also, it is possible that other developments, such as stricter
environmental laws and regulations, and claims for damages to property or
persons resulting from oil and gas production would 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 stricter over time.
Under these more 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.
17
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 a hazardous substance 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 the hazardous substance
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. Cabot Oil & Gas 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.
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 discharge of certain contaminants to waters of the United
States. Sanctions for failure to comply strictly with the Clean Water Act
requirements are generally resolved by payment of fines and correction of any
identified deficiencies, but regulatory agencies could require us to cease
construction or operation of certain facilities that are the sources 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 Cabot Oil & Gas 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, 1999, Cabot Oil & Gas had 332 active employees. We
recognize that our success is significantly influenced by the relationship we
maintain with our employees. Overall, we believe that our relations with our
employees are satisfactory. The Company and its employees are not represented by
a collective bargaining agreement. In January 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.
18
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, 1999, we owned or operated
approximately 2,590 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.
The EPA notified us in February 2000 that we may 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 for the clean-up costs which could total as much as several
hundred million dollars. The EPA is also pursuing the owner(s)/operator(s) of
the Site to pay for remediation.
The total amount of environmental investigation and cleanup costs that we
may incur with respect to the foregoing is not known at this time and,
accordingly, we have not recorded a reserve related to this possible liability.
While the potential impact to the quarterly or annual financial results may be
material, we do not believe it would materially impact our financial position.
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, 1999 to December 31, 1999.
19
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information about our executive officers
as of March 1, 2000, as such term is defined in Rule 3b-7 of the Securities
Exchange Act of 1934, and certain of our other officers.
Officer
Name Age Position Since
- --------------------------------------------------------------------------------
Ray R. Seegmiller 64 Chairman of the Board, Chief Executive
Officer and President 1995
James M. Trimble 51 Senior Vice President 1987
H. Baird Whitehead 49 Senior Vice President 1987
J. Scott Arnold 46 Vice President, Land and Associate
General Counsel 1998
Paul F. Boling 46 Vice President, Finance 1996
Robert G. Drake 52 Vice President, Information Systems 1998
Abraham D. Garza 53 Vice President, Human Resources 1998
Jeffrey W. Hutton 44 Vice President, Marketing 1995
Lisa A. Machesney 44 Vice President, Managing Counsel and
Corporate Secretary 1995
Scott C. Schroeder 37 Vice President and Treasurer 1997
John B. Lawman, Jr. 42 Vice President and Regional Manager 1999
Robert R. McBride 43 Vice President and Regional Manager 1999
Michael B. Walen 51 Vice President and Regional Manager 1998
Henry C. Smyth 53 Controller 1998
All officers are elected annually by our Board of Directors. Except for the
following, all of the executive officers have been employed by Cabot Oil & Gas
for at least the last five years.
Ray R. Seegmiller joined Cabot Oil & Gas as Vice President, Chief Financial
Officer and Treasurer in August 1995. Mr. Seegmiller served in this position
until March 1997 when he was promoted to Executive Vice President and Chief
Operating Officer. In September 1997, Mr. Seegmiller was promoted to President
and Chief Operating Officer and was elected as a Director. Mr. Seegmiller
replaced Charles Siess as Chief Executive Officer upon the retirement of Mr.
Siess in May 1998. Mr. Seegmiller was named Chairman of the Board in May 1999.
From May 1988 until 1993, Mr. Seegmiller served as President and Chief Executive
Officer of Terry Petroleum Company. Prior to that, Mr. Seegmiller held various
officer positions with Marathon Manufacturing Company.
Abraham D. Garza joined Cabot Oil & Gas in August 1995 as Director, Human
Resources. He was named to his current position as Vice President, Human
Resources in May 1998. Previously, Mr. Garza served as Human Resources Director
at Texfield, Inc. and in various management positions of increasing
responsibility at Marathon Manufacturing Company.
Scott C. Schroeder has been Vice President and Treasurer since April 1998.
From May 1997 to that time he served as Treasurer. From October 1995 to May
1997, Mr. Schroeder served as Assistant Treasurer. Prior to joining Cabot Oil &
Gas, Mr. Schroeder held various managerial positions with Pride Petroleum
Services (now known as Pride International). Prior to that, Mr. Schroeder served
as Manager, Treasury Operations and Planning of DeKalb Energy Company.
Robert R. McBride joined Cabot Oil & Gas as Vice President and Regional
Manager in September 1999. Prior to his current position, he served as President
and General Manager for Pennzoil Venezuela Corporation S.A. He previously held
positions of increasing responsibility at American Exploration Company and
Tenneco.
20
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Common Stock is listed and principally traded on the New York Stock
Exchange under the ticker symbol "COG". The following table presents the high
and low 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
- -----------------------------------------------------
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
1998
First Quarter...... $22.63 $17.06 $ 0.04
Second Quarter..... 23.88 18.06 0.04
Third Quarter...... 20.44 12.75 0.04
Fourth Quarter..... 18.13 13.38 0.04
As of January 31, 2000, there were 1,087 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) 1999 1998 1997 1996 1995
- -------------------------------------------------------------------------------------------
INCOME STATEMENT DATA:
Net Operating Revenues.................. $181,873 $159,606 $185,127 $163,061 $ 121,083
Income (Loss) from Operations........... 39,498 27,403 63,852 48,787 (116,758)
Net Income (Loss) Applicable to
Common Stockholders.................. 5,117 1,902 23,231 15,258 (92,171)
BASIC EARNINGS (LOSS) PER SHARE
APPLICABLE TO COMMON STOCKHOLDERS (1)... $0.21 $0.08 $1.00 $0.67 $(4.05)
DIVIDENDS PER COMMON SHARE................ $0.16 $0.16 $0.16 $0.16 $ 0.16
BALANCE SHEET DATA:
Properties and Equipment, Net........... $590,301 $629,908 $469,399 $480,511 $ 474,371
Total Assets............................ 659,480 704,160 541,805 561,341 528,155
Long-Term Debt.......................... 277,000 327,000 183,000 248,000 249,000
Stockholders' Equity.................... 186,496 182,668 184,062 160,704 147,856
- ----------
(1) See "Earnings per Common Share" under Note 15 of the Notes to the
Consolidated Financial Statements.
21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion is intended to assist you in understanding our
results of operations and our present financial condition. Our Consolidated
Financial Statements and the accompanying notes included elsewhere in this Form
10-K contain additional information that should be referred to when reviewing
this material.
Statements in this discussion may be forward-looking. These forward-looking
statements involve risks and uncertainties, including those discussed below,
which could cause actual results to differ from those expressed. Please read
"Forward-Looking Information" on page 27.
We operate in one segment, natural gas and oil exploration and
exploitation. Prior to 1998, we operated in two regions: the Appalachian region
and the Western region, which included the Mid-Continent, Rocky Mountains and
Gulf Coast areas. Beginning in 1998, a third region was created with the
formation of the Gulf Coast region, leaving the Mid-Continent and Rocky
Mountains areas in the Western region. For purposes of the comparisons below,
prior period results have been restated to conform to this three-region
structure.
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. This more favorable price
environment helped us improve from a $3.3 million net loss in the first quarter
of 1999 to net income of $4.6 million in the fourth quarter.
We reported earnings of $0.21 per share, or $5.1 million, for 1999. This is
up from the $0.08 per share, or $1.9 million, reported in 1998. The improvement
is partially credited to the stronger commodity price environment during the
last half of the year, accompanied by a 4% increase in equivalent production.
Our realized natural gas price for the fourth quarter of $2.61 per Mcf was 21%
higher than last year's fourth quarter price of $2.16 per Mcf. Our price for the
entire year of $2.22 per Mcf was 3% higher than the 1998 price of $2.16 per Mcf.
Also contributing to our 1999 results were the following selected items:
- $12 million in revenue received for the monetization of a long-term
gas sales contract in December 1999
- A $4 million gain realized on the sale of non-strategic assets,
primarily in Appalachia
- The recognition of a $7 million impairment of long-lived assets
- The $1.2 million pre-tax provision for certain wells no longer deemed
to be eligible for the Section 29 tight gas sands credit following a
recent industry tax court ruling.
A discussion of these selected items can be found in the Results of Operations
section, beginning on page 28.
Total equivalent production for 1999 was 71.3 Bcfe, an increase of 4% over
1998, despite the Appalachian divestiture and the significantly reduced drilling
program in place for 1999 compared to 1998. This increase was due primarily to
production from the December 1998 Oryx acquisition and new production brought on
by the 1998 and 1999 drilling programs of a combined 278 gross (189.1 net)
wells.
22
During 1999, we entered into several property sales intended to high grade
our reserve base. In September 1999, we sold Appalachian properties with
reserves of 58.8 Bcfe for $46.3 million. Subsequent to this sale, we used part
of the proceeds from this divestiture of non-strategic properties to purchase
$17.4 million of proved reserves adjacent to our existing properties in
Wyoming's Green River Basin and the balance of the proceeds to reduce debt by
$28.6 million. These acquired properties added 15.8 Bcfe of proved reserves and
approximately 43,000 undeveloped acres. Additionally, we sold other
non-strategic properties in several smaller transactions during the year for $10
million. In total, 1999 assets sales resulted in a gain of $4 million. These
actions eliminated approximately 22% of our total well count but reduced our
production by only 5%.
We purchased producing oil and gas properties and other assets located in
south Louisiana from Oryx Energy Company for $70.1 million in December 1998.
These properties included interests in 10 fields covering 34,345 net acres with
68 producing wells. The acquisition also included a 160 square mile 3-D seismic
inventory. Proved reserves acquired were approximately 72 Bcfe. By reworking
certain non-producing wells, we have increased the daily production rate from
11.5 Mmcfe in December 1998 to an average rate of 15.8 Mmcfe in 1999. In
addition, we plan to commence our exploration and development drilling program
on these properties in 2000.
We drilled 73 gross wells with a success rate of 84% in 1999 compared to
205 gross wells and an 89% success rate in 1998. Total capital expenditures were
$88.1 million for 1999 compared to $225.9 million in 1998, which included $70.1
million for the acquisition of the south Louisiana properties. We reduced our
1999 budgeted capital and exploration expenditures in response to the weak
energy price environment in the fourth quarter of 1998 and in early 1999.
However, we front-end loaded the 1999 development and exploration plan to
maximize production from this year's drilling program and to provide more
flexibility to drill more wells if cash flows improved later in the year, which
they did. Accordingly, during the year, we increased our 1999 capital and
exploration expenditure program by approximately $35 million in response to the
improving natural gas prices during the third quarter.
As mentioned earlier, we received $12 million in December 1999 to monetize
a long-term gas sales contract, which had been sourced by production from our
Rocky Mountains area. The contract provided for a fixed natural gas price that
escalated 5% annually. The contract had a remaining term of less than nine
years. We have entered into certain forward-sale agreements with other
counterparties to deliver a similar quantity of gas at prices similar to those
of the monetized contract. These forward-sale contracts had a remaining life of
16 months at the end of 1999.
During the fourth quarter of 1999, we experienced a significant production
decline from the only well in our Chimney Bayou field located in the Texas Gulf
Coast. This decline, along with an unsuccessful workover in our Lawson field in
Louisiana, resulted in a $7 million impairment of long-lived assets.
We remain focused on our strategies to grow through the drill bit,
concentrating on the highest 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 27.
23
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. Natural gas
prices were unseasonably low during much of 1998 and into the first half of
1999. In late spring and into the summer of 1999, prices began to show
improvement and by the fourth quarter, we experienced the highest quarterly
realized price in two years.
The primary sources of cash for us during 1999 were funds generated from
operations, proceeds from the sale of non-strategic oil and gas properties and
the proceeds from the monetization of the long-term gas sales contract. Funds
were used primarily for exploration and development expenditures, proved
property acquisitions, dividend payments and the repayment of borrowings under
the credit facility.
We had net cash outflows of $0.5 million during 1999. The net cash inflow
from operating activities of $92.5 million substantially offsets the $93.7
million of cash used for capital and exploration expenditures. The cash proceeds
from asset sales of $56.3 million effectively funded the debt reduction and
dividend payment.
(In millions) 1999 1998 1997
- ---------------------------------------------------------------------------------
Cash Flows Provided by Operating Activities.......... $ 92.5 $ 87.2 $ 95.0
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 monetization 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.
Cash flows provided by operating activities in 1998 were $7.8 million lower
than in 1997, due predominantly to lower natural gas and oil prices, partially
offset by a significant increase in the accounts payable balance resulting
mainly from higher fourth quarter spending activity.
(In millions) 1999 1998 1997
- ---------------------------------------------------------------------------------
Cash Flows used by Investing Activities.............. $ (37.4) $(222.1) $(38.4)
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.
24
Cash flows used by investing activities in 1998 were $183.7 million higher
than in 1997, due primarily to the capital and exploration expenditures that
increased $135.8 million over 1997, and the receipt in 1997 of $47.7 million in
net proceeds from the sale of producing properties located in northwest
Pennsylvania. 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
Mid-Continent and Rocky Mountains areas of the Western region.
(In millions) 1999 1998 1997
- ---------------------------------------------------------------------------------
Cash Flows Provided (Used) by Financing Activities... $(55.6) $135.3 $(56.2)
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 related to the 1998 drilling program
and $83.6 million in property acquisitions. Financing activities in 1998 also
included the payment of stock dividends and the purchase of shares in the open
market under our share repurchase program. The purchased shares are held as
treasury shares.
Cash flows used by financing activities from 1997 consist primarily of the
$49.0 million net reduction in borrowings on the revolving credit facility as
well as dividend payments.
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. Oil
and gas prices also affect the calculation of the financial ratios for debt
covenant compliance. While we do not currently believe that our credit
availability is likely to be significantly reduced, management cannot predict
how current price levels may change the banks' long-term price outlook.
Therefore, we can give no assurance that our available credit line will not be
adversely impacted in 2000 or as to the amount of credit that will continue to
be available under this facility. 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
$105 million, or 42% of the total available credit line. Management believes
that we have the ability to finance, if necessary, our capital requirements,
including acquisitions. 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.
25
Our interest expense for 2000 is projected to be $23.3 million. In May
2000, 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) 1999 1998 1997
- --------------------------------------------------------------------------
Long-Term Debt............................ $277.0 $327.0 $183.0
Current Portion of Long-Term Debt......... 16.0 16.0 16.0
------ ------ ------
Total Debt............................ $293.0 $343.0 $199.0
====== ====== ======
Stockholders' Equity
Common Stock (net of Treasury Stock).... $129.8 $126.0 $127.4
Preferred Stock......................... 56.7 56.7 56.7
------ ------ ------
Total Equity...................... 186.5 182.7 184.1
------ ------ ------
Total Capitalization...................... $479.5 $525.7 $383.1
====== ====== ======
Debt to Capitalization.................... 61.1% 65.2% 51.9%
------ ------ ------
During 1999, dividends were paid on our common stock totaling $4.0 million
and on our 6% convertible redeemable preferred stock totaling $3.4 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.
We have entered into an agreement with Puget Sound Energy, Inc., the holder
of our preferred stock, to repurchase their preferred shares by November 1,
2000. As outlined in the agreement, the preferred shares that are recorded on
our balance sheet for $56.7 million will be repurchased for $51.6 million. Cash
flow from operations, additional borrowings or proceeds from the sale of equity
may be used to fund this transaction. Please read Note 10 of the Notes to the
Consolidated Financial Statements for further discussion of this agreement.
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.
26
The following table presents major components of our capital and
exploration expenditures for the three years ended December 31, 1999.
(In millions) 1999 1998 1997
- -------------------------------------------------------------------
Capital Expenditures:
Drilling and Facilities........... $ 43.9 $ 99.0 $ 68.2
Leasehold Acquisitions............ 7.2 15.6 4.3
Pipeline and Gathering............ 3.8 5.3 6.1
Other............................. 3.3 2.8 2.0
------ ------ ------
58.2 122.7 80.6
------ ------ ------
Proved Property Acquisitions........ 18.4 83.6(1) 45.6(2)
Exploration Expenses................ 11.5 19.6 13.9
------ ------ ------
Total............................. $ 88.1 $225.9 $140.1
====== ====== ======
- ----------
(1) Includes $70.1 million in oil and gas properties acquired from Oryx Energy
Company in December 1998.
(2) Includes $45.2 million in oil and gas properties acquired from Equitable
Resources Energy Company in a like-kind exchange transaction with a portion
of the assets sold in the Meadville property sale.
Total capital and exploration expenditures for 1999 decreased $137.8
million compared to 1998, primarily as a result of this year's reduced drilling
program and the $70.1 million acquisition of proved properties from Oryx in
December 1998. Additionally in 1998, we made an initial $5.0 million leasehold
acquisition in connection with our joint exploration program with Union Pacific
Resources and also purchased 9.3 Bcfe of proved resources in the Mid-Continent
for $6.6 million. 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 110 gross wells in 2000 compared with 73 gross wells
drilled in 1999. This 2000 drilling program includes $88.9 million in total
capital and exploration expenditures, up from $88.1 million in 1999. Expected
spending in 2000 includes $49.1 million for drilling and facilities, and $25.2
million in exploration expenses. In addition to the drilling and exploration
program, other 2000 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.
YEAR 2000
Many computer systems were built using software that processed transactions
using two digits to represent the year. This type of software generally required
modifications to function properly with dates after December 31, 1999 or to
become year 2000 compliant. The same issue applied to microprocessors embedded
in machinery and equipment, such as gas compressors and pipeline meters. The
impact of failing to identify those computer systems operated by us or our
business partners that are not year 2000 compliant and to correct the problem
could have been significant to our ability to operate and report results, as
well as potentially expose us to third-party liability. We did not experience
any computer system failures as a result of entering the year 2000. Cabot Oil &
Gas will continue to monitor its computer systems for any potential errors that
may have resulted from this change.
27
Prior to January 1, 2000, we completed all of the necessary modifications
to our computer systems and embedded microprocessors. This project was completed
on schedule and the total related costs were $2.2 million, funded by cash from
operations or borrowings on our revolving credit facility. Of the total project
cost, $2.0 million was attributable to the purchase of new software and
equipment that was capitalized. The remaining $0.2 million was expensed.
Prior to the end of 1999, we contacted our significant customers and
suppliers in order to determine our exposure to their potential failure to
become year 2000 compliant. Although we are not aware of any year 2000
compliance problems with any of our customers or suppliers, we cannot guarantee
that their systems have been operating or will continue to operate without
interruption in the new millennium.
OTHER ISSUES AND CONTINGENCIES
CORPORATE INCOME TAX. Cabot Oil & Gas generates 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
$1.07 per Mmbtu in 1999. In 1995 and 1996, Cabot Oil & Gas completed three
transactions to monetize the value of these tax credits, resulting in revenues
of $1.3 million in 1999 and approximately $5.4 million over the remaining three
years. See Note 13 of the Notes to the Consolidated Financial Statements for
further discussion.
Cabot Oil & Gas has 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 cannot 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. The Company's 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. The Company's ability to incur debt, to pay
dividends on its common and preferred stock, and to make certain types of
investments is subject to certain restrictive covenants in the Company's various
debt instruments. Among other requirements, the Company's 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, 1999, the calculated ratio for 1999 was 4.6 to 1. In the unforeseen
event that Cabot Oil & Gas fails to comply with these covenants, it may apply
for a temporary waiver with the bank, which, if granted, would allow the Company
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.
28
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 1999 was up 3%
over 1998, after declining 15% from 1997 to 1998. The volatility of natural gas
prices in recent years remains prevalent in 2000 with wide price swings in
day-to-day trading on the NYMEX futures market. Given this continued price
volatility, we cannot predict with certainty what pricing levels will be in the
future. Because future cash flows are subject to these variables, we cannot
assure you that our operations will provide cash sufficient to fully fund our
planned capital expenditures.
While our 2000 plans now include $88.9 million in capital spending, we will
periodically assess industry conditions and adjust our 2000 spending plan to
ensure the adequate funding of our capital requirements, including, among other
things, reductions in capital 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.
* * *
FORWARD-LOOKING INFORMATION
The statements regarding future financial performance and results, and
market prices 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.
RESULTS OF OPERATIONS
For the purpose of reviewing our results of operations, "Net Income" is
defined as net income available to common stockholders.
29
SELECTED FINANCIAL AND OPERATING DATA
(In millions except where specified) 1999 1998 1997
- -------------------------------------------------------------------------
Net Operating Revenues.................... $181.9 $159.6 $185.1
Operating Expenses........................ 146.3 132.7 121.3
Operating Income.......................... 39.5 27.4 63.9
Interest Expense.......................... 25.8 18.6 18.0
Net Income................................ 5.1 1.9 23.2
Earnings Per Share - Basic................ $ 0.21 $ 0.08 $ 1.00
Earnings Per Share - Diluted.............. 0.21 0.08 0.97
Natural Gas Production (Bcf)
Gulf Coast.............................. 15.5 10.6 8.4
West.................................... 29.3 30.9 30.2
Appalachia.............................. 20.7 22.7 25.3
------ ------ ------
Total Company........................... 65.5 64.2 63.9
Produced Natural Gas Sales Price ($/Mcf)
Gulf Coast.............................. $ 2.29 $ 2.15 $ 2.52
West.................................... 1.96 1.90 2.14
Appalachia.............................. 2.53 2.53 3.00
Total Company........................... 2.22 2.16 2.53
Crude/Condensate
Volume (Mbbl)........................... 929 650 574
Price ($/Bbl)........................... $17.22 $13.06 $20.13
The table below presents the after-tax effects of certain selected items on
our results of operations for the three years ended December 31, 1999.
(In millions) 1999 1998 1997
- -------------------------------------------------------------------------------
NET INCOME BEFORE SELECTED ITEMS........ $ 0.4 $ 1.9 $23.2
Monetization of Gas Sales Contract.... 7.3
Impairment of Long-Lived Assets....... (4.3)
Gain on Sale of Assets................ 2.4
Section 29 Tax Credit Provision....... (0.7)
----- ----- -----
Net Income............................ $ 5.1 $ 1.9 $23.2
===== ===== =====
These selected items impacted our 1999 financial results. Because they are
not a part of our normal business, we have isolated their effects in the table
above. These selected items 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. We simultaneously sold
forward a similar quantity of Western region gas for the next 16
months at similar prices to those in the monetized contract.
30
- In the fourth quarter of 1999, we recorded impairments totaling $7
million on two of our producing fields in the Gulf Coast region. 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.
- 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 a recent industry tax court ruling. The FERC
recently issued a rule proposal that may ultimately restore the
eligibility for some or all of the wells in question. We will continue
to monitor other tax court decisions and announcements from the FERC
regarding this issue.
1999 AND 1998 COMPARED
NET INCOME AND REVENUES. We reported net income in 1999 of $0.4 million, or
$0.02 per share, excluding the impact of the selected items. During 1998, we
reported net income of $1.9 million, or $0.08 per share. Excluding the pre-tax
effect of the selected items, operating income increased $4.4 million, or 16%,
and operating revenues increased $11.5 million, or 7%, in 1999. Natural gas
production made up 87%, or $145.5 million, of net operating revenue. The
improvement in operating revenues was mainly a result of 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 net 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 net operating revenues by
approximately $1.8 million. The average Appalachian natural gas production sales
price remained flat to last year at $2.53. 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 net 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 net
operating revenues of approximately $3.8 million.
The brokered natural gas margin decreased $1.2 million to $4.4 million. The
primary cause was a $0.04 per Mcf reduction to net margin that resulted in a
$2.0 million revenue decline. The effect of the lower margin was partially
offset by a 6.5 Bcf volume increase, resulting in a $0.8 million increase in
brokered natural gas margin.
31
Excluding the selected items regarding the sales contract monetization and
the Section 29 tax credit provision, other net 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 $6.6
million, or 5%, from 1998 due primarily to the following:
- Direct operating 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, direct
operating 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:
o 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.
o 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 FAS 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:
o Lower non-cash stock compensation expense for stock awards ($1.2
million).
o Lower outside consulting services ($0.6 million).
Interest expense increased $7.2 millio