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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 million primarily due to the debt increase
for the Oryx acquisition in December 1998 and to partially fund the 1998
drilling program.
Income tax expense was up $1.7 million due to the comparable increase in
earnings before income tax.
Gain on the sale of assets totaled $4 million for 1999 compared to $0.5
million in 1998. These gains are the result of the non-strategic asset
divestitures, primarily the sale of the Clarksburg properties in the Appalachian
region to EnerVest effective October 1999.
1998 AND 1997 COMPARED
NET INCOME AND REVENUES. We reported net income in 1998 of $1.9 million, or
$0.08 per share, down $21.3 million, or $0.92 per share, compared to 1997. Net
operating revenue of $159.6 million was down $25.5 million, or 14%, from 1997.
Natural gas sales of $138.9 million accounted for 87% of net operating revenue
in 1998. The decrease in net operating revenue was the result of a 15% decline
in realized natural gas prices and a 35% reduction in realized oil prices.
Operating income and net income were similarly impacted by the decrease in
energy commodity prices along with higher expenses attributable to our increased
exploration program.
31
In the Gulf Coast region, natural gas production volume was up 2.2 Bcf, or
26%, to 10.6 Bcf due to results of the 1997 and 1998 drilling programs, and in
part to the December 1998 acquisition of the Oryx properties. While production
increased over 1997 levels, the region did experience drilling delays and
mechanical failures in a significant field that deferred production into 1999
but left the field's total reserves substantially unchanged. Natural gas
production volume in the Western region was up 0.7 Bcf, or 2%, to 30.9 Bcf due
to increases in Rocky Mountains area production. This increase was the result of
both the 1997 purchase of oil and gas producing properties located in the Green
River Basin of Wyoming, and new wells brought on-line. Natural gas production
volume was down 2.6 Bcf, or 10%, to 22.7 Bcf in the Appalachian region due to
the September 1997 sale of producing properties located in northwest
Pennsylvania, which we refer to as the Meadville properties.
The average natural gas sales price for the year in the Gulf Coast region
decreased $0.37 per Mcf, or 15%, to $2.15, reducing net operating revenue by
$3.9 million on 10.6 Bcf of production. In the Western region, the average
natural gas sales price decreased $0.24 per Mcf, or 11%, to $1.90, decreasing
net operating revenues by $7.4 million on 30.9 Bcf of production. The average
natural gas sales price decreased $0.47 per Mcf, or 16%, to $2.53 in the
Appalachian region, decreasing net operating revenues by approximately $10.7
million on 22.7 Bcf of production. The overall weighted average natural gas
production sales price for the year decreased $0.37 per Mcf, or 15%, to $2.16.
Crude oil and condensate sales increased by 76 Mbbls, or 13%, increasing
revenue by $1.5 million over 1997. This increase was due to new production
brought on-line, combined with December production from the Oryx properties.
However, the 1998 average crude oil price declined 35% from 1997 levels,
reducing oil revenue by $4.5 million.
Brokered natural gas margin was up $1.4 million to $5.5 million due to a
26% volume increase over 1997, combined with a $0.01 per Mcf increase in the net
margin to $0.13 per Mcf.
OPERATING EXPENSES. Total operating expenses increased $11.3 million, or
9%, to $132.7 million. In December 1998, we recognized a $0.9 million
reorganization charge designed to reduce future operating expenses. The
reorganization charge was comprised of $0.4 million in direct operating expense,
$0.3 million in exploration expense, and $0.2 million in general and
administrative expense. The reorganization reduced the number of our employees
by 6%. The significant changes in operating expenses are explained as follows:
- Direct operations expense increased $0.9 million, or 3%, due primarily
to the $0.4 million direct operations component of the reorganization
charge in the fourth quarter and $0.5 million in higher workover costs
incurred primarily in the Gulf Coast region.
- Exploration expense increased $5.7 million, or 41%, due to:
o A $1.5 million increase in geological and geophysical activity
including seismic data purchases and consulting fees.
o A $2.3 million increase in dry hole cost, resulting from our
expanded drilling efforts in the Gulf Coast region where wells
are generally drilled at higher costs.
o A $1.4 million increase in exploration personnel-related expenses
such as salaries, benefits and relocation charges associated with
the increase in the exploration program.
o $0.3 million for the exploration expense component of the
reorganization that was expensed in December 1998.
- Depreciation, depletion, amortization and impairment expense increased
$2.1 million, or 5%, primarily due to the amortization of a lease
option purchased in the second quarter of 1998 related to a joint
venture with Union Pacific Resources in the Gulf Coast region.
Additionally, this expense increased in part due to higher units of
production expense in connection with increased production.
33
- General and administrative expense increased $2.2 million primarily
due to:
o $0.5 million for staffing increases in the third and fourth
quarters of 1997.
o $0.7 million for non-cash stock compensation for stock awards.
o $0.5 million accrued for certain executive retirement and
severance packages.
o $0.3 million due to higher relocation and travel expenses.
o $0.2 million recorded for the general and administrative
component of the reorganization in December 1998.
Interest expense increased $0.6 million, or 4%, due to higher levels of
debt outstanding on our revolving credit facility.
Income tax expense was down $14.1 million due to the comparable decrease in
earnings before income tax. Included in income tax expense was the interest
charged by the Internal Revenue Service on a deferred tax gain related to the
monetization of the Section 29 credits. This interest amount was $0.3 million in
1998 and $0.5 million in 1997.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
Oil and gas prices fluctuate widely, and low prices for an extended period
of time are likely to have a material adverse impact on our business.
Our revenues, operating results, financial condition and ability to borrow
funds or obtain additional capital depend substantially on prevailing prices for
natural gas and, to a lesser extent, oil. Declines in oil and gas prices may
materially adversely affect our financial condition, liquidity, ability to
obtain financing and operating results. Lower oil and gas prices also may reduce
the amount of oil and gas that we can produce economically. Historically, oil
and gas prices and markets have been volatile, with prices fluctuating widely,
and they are likely to continue to be volatile. Oil and gas prices declined
substantially in 1998 and, despite recent improvement, could decline again.
Because our reserves are predominantly natural gas, changes in natural gas
prices may have a particularly significant impact on our financial results.
Prices for oil and natural gas are subject to wide fluctuations in response
to relatively minor changes in the supply of and demand for oil and gas, market
uncertainty and a variety of additional factors that are beyond our control.
These factors include:
- The domestic and foreign supply of oil and natural gas.
- The level of consumer product demand.
- Weather conditions.
- Political conditions in oil producing regions, including the Middle
East.
- The ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls.
- The price of foreign imports.
- Actions of governmental authorities.
- Domestic and foreign governmental regulations.
- The price, availability and acceptance of alternative fuels.
- Overall economic conditions.
These factors and the volatile nature of the energy markets make it impossible
to predict with any certainty the future prices of oil and gas.
In order to reduce our exposure to short-term fluctuations in the price of
oil and natural gas, we sometimes enter into hedging arrangements. Our hedging
arrangements apply to only a portion of our production and provide only partial
price protection against declines in oil and gas prices. These hedging
arrangements may expose us to risk of financial loss and limit the benefit to us
of increases in prices. Please read the discussion below related to commodity
price swaps and Note 11 of the Notes to the Consolidated Financial Statements
for a more detailed discussion of our hedging arrangements.
34
COMMODITY PRICE SWAPS
From time to time, we enter into natural gas and crude oil swap agreements
with counterparties to hedge price risk associated with a portion of our
production. These derivatives are not held for trading purposes. Under these
price swaps, we receive a fixed price on a notional quantity of natural gas and
crude oil in exchange for paying a variable price based on a market-based index,
such as the NYMEX gas and crude oil futures. During 1999, we fixed the price at
an average of $2.64 per Mmbtu on quantities totaling 3,530,000 Mmbtu,
representing 5% of the natural gas production for the period. The notional
volume of the crude oil swap transactions was 306,000 Bbls at a price of $20.65
per Bbl, which represents approximately one-third of our total oil production
for 1999. During 1998 and 1997 we did not enter into any fixed price swaps to
hedge oil or natural gas production.
We use price swaps to hedge the natural gas price risk on brokered
transactions. Typically, we enter into contracts to broker natural gas at a
variable price based on the market index price. However, in some circumstances,
some of our customers or suppliers request that a fixed price be stated in the
contract. After entering into these fixed price contracts to meet the needs of
our customers or suppliers, we may use price swaps to effectively convert these
fixed price contracts to market-sensitive price contracts. These price swaps are
held by us to their maturity and are not held for trading purposes.
During 1999, 1998 and 1997, we entered into price swaps with total notional
quantities of 4,040,800, 2,226,000 and 1,416,000 Mmbtu, respectively, related to
our brokered activities, representing 7%, 5% and 4%, respectively, of our total
volume of brokered natural gas sold.
As of the years ending December 31, 1999, and 1998, we had open natural gas
and oil price swap contracts as follows:
Natural Gas Price Swaps
------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Mmbtu Contract Price (in $ millions)
- --------------------------------------------------------------------------------
As of December 31, 1999
- -----------------------
Natural Gas Price Swap on Brokered Transactions
-----------------------------------------------
First Quarter 2000.............. 1,009,800 $2.26 $(0.2)
As of December 31, 1998
- -----------------------
Natural Gas Price Swap on Brokered Transactions
-----------------------------------------------
Full Year 1999.................. 1,280,000 2.03 (0.3)
First Quarter 2000.............. 450,000 2.13 0.1
Financial derivatives related to natural gas reduced revenues by $0.1
million in 1999 and $0.3 million in 1998. These revenue reductions were offset
by higher realized revenue on the underlying physical gas sales.
35
We had open oil price swap contracts as follows:
Oil Price Swaps
------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Bbls Contract Price (in $ millions)
- --------------------------------------------------------------------------------
As of December 31, 1999
- -----------------------
Oil Price Swaps on Our Production
---------------------------------
First Quarter 2000.............. 182,000 $22.25 $(0.5)
Second Quarter 2000............. 182,000 23.08 (0.1)
Financial derivatives related to crude oil reduced revenue by $0.8 million
during 1999. This revenue reduction was offset by higher realized revenue on the
underlying physical oil sales. There were no crude oil price swaps outstanding
at December 31, 1998, or 1997.
We are exposed to market risk on these open contracts, to the extent of
changes in market prices of natural gas and oil. However, the market risk
exposure on these hedged contracts is generally offset by the gain or loss
recognized upon the ultimate sale of the commodity that is hedged.
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" (SFAS 133). SFAS 133 requires all derivatives to be
recognized in the statement of financial position as either assets or
liabilities and measured at fair value. In addition, all hedging relationships
must be designated, documented and continually reassessed. This statement is
effective for financial statements for fiscal years beginning after June 15,
2000. The Company has not yet completed its evaluation of the impact of the
provisions from SFAS 133 on its financial position or results of operations.
FAIR MARKET VALUE OF FINANCIAL INSTRUMENTS
The estimated fair value of financial instruments is the amount at which
the instrument could be exchanged currently between willing parties. The
carrying amounts reported in the consolidated balance sheet for cash and cash
equivalents, accounts receivable and accounts payable approximate fair value. We
use available marketing data and valuation methodologies to estimate fair value
of debt.
December 31, 1999 December 31, 1998
---------------------- ----------------------
Carrying Estimated Carrying Estimated
(In thousands) Amount Fair Value Amount Fair Value
- ----------------------------------------------------------------------------
DEBT
10.18% Notes........... $ 48,000 $ 50,020 $ 64,000 $ 68,185
7.19% Notes............ 100,000 91,237 100,000 93,145
Credit Facility........ 145,000 145,000 179,000 179,000
-------- -------- -------- --------
$293,000 $286,257 $343,000 $340,330
======== ======== ======== ========
36
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
- ---------------------------------------------------------------
Report of Independent Accountants.......................... 36
Consolidated Statement of Operations....................... 37
Consolidated Balance Sheet................................. 38
Consolidated Statement of Cash Flows....................... 39
Consolidated Statement of Stockholders' Equity............. 40
Notes to Consolidated Financial Statements................. 41
Supplemental Oil and Gas Information (Unaudited)........... 41
Quarterly Financial Information (Unaudited)................ 63
REPORT OF MANAGEMENT
The management of Cabot Oil & Gas Corporation is responsible for the
preparation and integrity of all information contained in the annual report. The
consolidated financial statements are prepared in conformity with generally
accepted accounting principles and, accordingly, include certain informed
judgments and estimates of management.
Management maintains a system of internal accounting and managerial
controls and engages internal audit representatives who monitor and test the
operation of these controls. Although no system can ensure the elimination of
all errors and irregularities, the system is designed to provide reasonable
assurance that assets are safeguarded, transactions are executed in accordance
with management's authorization, and accounting records are reliable for
financial statement preparation.
An Audit Committee of the Board of Directors, consisting of directors who
are not employees of the Company, meets periodically with management, the
independent accountants and internal audit representatives to obtain assurances
to the integrity of the Company's accounting and financial reporting and to
affirm the adequacy of the system of accounting and managerial controls in
place. The independent accountants and internal audit representatives have full
and free access to the Audit Committee to discuss all appropriate matters.
We believe that the Company's policies and system of accounting and
managerial controls reasonably assure the integrity of the information in the
consolidated financial statements and in the other sections of the annual
report.
Ray R. Seegmiller
Chairman of the Board,
Chief Executive Officer and President
March 10, 2000
37
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE STOCKHOLDERS AND BOARD OF DIRECTORS OF CABOT OIL & GAS CORPORATION:
In our opinion, the consolidated financial statements listed in the
accompanying index present fairly, in all material respects, the financial
position of Cabot Oil & Gas Corporation and its subsidiaries at December 31,
1999 and 1998, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1999, in conformity with
accounting principles generally accepted in the United States. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States which require that we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for the opinion expressed above.
PricewaterhouseCoopers LLP
Houston, Texas
February 11, 2000
38
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
Year Ended December 31,
(In thousands, except per share amounts) 1999 1998 1997
- ----------------------------------------------------------------------------------
NET OPERATING REVENUES
Natural Gas Production..................... $145,495 $138,903 $161,737
Crude Oil and Condensate................... 15,909 8,486 11,443
Brokered Natural Gas Margin................ 4,390 5,547 4,113
Other (Note 13)........................... 16,079 6,670 7,834
-------- -------- --------
181,873 159,606 185,127
OPERATING EXPENSES
Direct Operations.......................... 33,357 30,250 29,380
Exploration................................ 11,490 19,564 13,884
Depreciation, Depletion and Amortization... 53,357 41,186 40,598
Impairment of Unproved Properties.......... 3,950 4,402 2,856
Impairment of Long-Lived Assets............ 7,047 -- --
General and Administrative................. 20,136 21,950 19,744
Taxes Other Than Income.................... 16,988 15,324 14,874
-------- -------- --------
146,325 132,676 121,336
Gain on Sale of Assets....................... 3,950 473 61
-------- -------- --------
INCOME FROM OPERATIONS....................... 39,498 27,403 63,852
Interest Expense............................. 25,818 18,598 17,961
-------- -------- --------
Income Before Income Tax Expense............. 13,680 8,805 45,891
Income Tax Expense........................... 5,161 3,501 17,557
-------- -------- --------
NET INCOME................................... 8,519 5,304 28,334
Dividend Requirement on Preferred Stock...... 3,402 3,402 5,103
-------- -------- --------
Net Income Available to
Common Stockholders........................ $ 5,117 $ 1,902 $ 23,231
======== ======== ========
Basic Earnings per Share Available
to Common Stockholders..................... $ 0.21 $ 0.08 $ 1.00
Diluted Earnings per Share Available
to Common Stockholders..................... $ 0.21 $ 0.08 $ 0.97
Average Common Shares Outstanding............ 24,726 24,733 23,272
The accompanying notes are an integral part of these consolidated
financial statements.
39
CABOT OIL & GAS CORPORATION
CONSOLIDATED BALANCE SHEET
December 31,
(In thousands, except share amounts) 1999 1998
- -------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents.............................. $ 1,679 $ 2,200
Accounts Receivable.................................... 50,391 55,799
Inventories............................................ 10,929 9,312
Other.................................................. 3,641 3,804
-------- --------
Total Current Assets................................. 66,640 71,115
PROPERTIES AND EQUIPMENT (Successful Efforts Method)..... 590,301 629,908
OTHER ASSETS............................................. 2,539 3,137
-------- --------
$659,480 $704,160
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current Portion of Long-Term Debt...................... $ 16,000 $ 16,000
Accounts Payable....................................... 56,551 66,628
Accrued Liabilities.................................... 17,387 16,406
-------- --------
Total Current Liabilities............................ 89,938 99,034
LONG-TERM DEBT........................................... 277,000 327,000
DEFERRED INCOME TAXES.................................... 95,012 85,952
OTHER LIABILITIES........................................ 11,034 9,506
COMMITMENTS AND CONTINGENCIES (Note 8)
STOCKHOLDERS' EQUITY
Preferred Stock:
Authorized -- 5,000,000 Shares of $0.10 Par Value
-- 6% Convertible Redeemable Preferred; $50
Stated Value; 1,134,000 Shares Outstanding in
1999 and 1998 (Note 10).............................. 113 113
Common Stock:
Authorized -- 40,000,000 Shares of $0.10 Par Value
Issued and Outstanding -- 25,073,660 Shares in 1999
and 24,959,897 Shares in 1998........................ 2,507 2,496
Class B Common Stock
Authorized - 800,000 Shares of $0.10 Par Value
No Shares Issued..................................... -- --
Additional Paid-in Capital............................. 254,763 252,073
Accumulated Deficit.................................... (66,503) (67,630)
Less Treasury Stock, at Cost
302,600 Shares in 1999 and 1998..................... (4,384) (4,384)
-------- --------
Total Stockholders' Equity............................... 186,496 182,668
-------- --------
$659,480 $704,160
======== ========
The accompanying notes are an integral part of these consolidated
financial statements.
40
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended December 31,
(In thousands) 1999 1998 1997
- ---------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income..................................... $ 8,519 $ 5,304 $ 28,334
Adjustments to Reconcile Net Income
to Cash Provided by Operations
Depletion, Depreciation and Amortization... 53,357 41,186 40,598
Impairment of Unproved Properties.......... 3,950 4,402 2,856
Impairment of Long-Lived Assets............ 7,047 -- --
Deferred Income Tax Expense................ 9,060 5,844 10,681
Gain on Sale of Assets..................... (3,950) (473) (61)
Exploration Expense........................ 11,490 19,564 13,884
Other...................................... 2,439 1,834 1,419
Changes in Assets and Liabilities
Accounts Receivable........................ 5,408 3,873 8,137
Inventories................................ (1,617) (2,437) 1,922
Other Current Assets....................... 164 (1,602) (539)
Other Assets............................... 598 (1,264) (680)
Accounts Payable and Accrued Liabilities... (5,505) 10,263 (10,541)
Other Liabilities.......................... 1,528 743 (970)
-------- -------- --------
Net Cash Provided by Operations.......... 92,488 87,237 95,040
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures........................... (82,191) (203,632) (73,476)
Proceeds from Sale of Assets................... 56,328 1,054 48,916
Exploration Expense............................ (11,490) (19,564) (13,884)
-------- -------- --------
Net Cash Used by Investing..................... (37,353) (222,142) (38,444)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt............................... 125,000 217,000 11,000
Decrease in Debt............................... (175,000) (73,000) (60,000)
Exercise of Stock Options...................... 1,738 3,589 2,197
Treasury Stock Purchases....................... -- (4,384) --
Preferred Dividends Paid....................... (3,402) (3,402) (5,644)
Common Dividends Paid.......................... (3,992) (3,974) (3,732)
Increase in Debt Issuance Cost and Other....... -- (508) --
-------- -------- --------
Net Cash Provided (Used) by Financing.......... (55,656) 135,321 (56,179)
-------- -------- --------
Net Increase (Decrease) in Cash and
Cash Equivalents............................... (521) 416 417
Cash and Cash Equivalents,
Beginning of Year.............................. 2,200 1,784 1,367
-------- -------- --------
Cash and Cash Equivalents, End of Year........... $ 1,679 $ 2,200 $ 1,784
======== ======== ========
The accompanying notes are an integral part of these consolidated
financial statements.
41
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
Retained
Common Preferred Treasury Paid-In Earnings
(In thousands) Stock Stock Stock Capital (Deficit) Total
- -----------------------------------------------------------------------------------------
Balance at December 31, 1996... $2,284 $183 $243,283 $(85,046) $160,704
---------------------------------------------------------
Net Income..................... 28,334 28,334
Exercise of Stock Options...... 14 2,183 2,197
Preferred Stock Dividends...... (5,103) (5,103)
Common Stock Dividends
at $0.16 per Share.......... (3,732) (3,732)
Stock Grant Vesting............ 1,662 1,662
Conversion of $3.125 Preferred
Stock to Common Stock....... 165 (70) (95) 0
Other.......................... 4 (4) 0
---------------------------------------------------------
Balance at December 31, 1997... $2,467 $113 $247,033 $(65,551) $184,062
=========================================================
Net Income 5,304 5,304
Exercise of Stock Options...... 21 3,568 3,589
Preferred Stock Dividends...... (3,402) (3,402)
Common Stock Dividends
at $0.16 per Share.......... (3,974) (3,974)
Stock Grant Vesting............ 8 1,472 1,480
Treasury Stock Repurchase...... $(4,384) (4,384)
Other.......................... (7) (7)
---------------------------------------------------------
Balance at December 31, 1998... $2,496 $113 $(4,384) $252,073 $(67,630) $182,668
=========================================================
Net Income..................... 8,519 8,519
Exercise of Stock Options...... 7 1,492 1,499
Preferred Stock Dividends...... (3,402) (3,402)
Common Stock Dividends
at $0.16 per Share.......... (3,992) (3,992)
Stock Grant Vesting............ 4 1,198 1,202
Other.......................... 2 2
---------------------------------------------------------
Balance at December 31, 1999... $2,507 $113 $(4,384) $254,763 $(66,503) $186,496
=========================================================
- ----------
The accompanying notes are an integral part of these consolidated
financial statements.
42
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION
Cabot Oil & Gas Corporation and its subsidiaries are engaged in the
exploration, development, production and marketing of natural gas and, to a
lesser extent, crude oil and natural gas liquids. The Company also transports,
stores, gathers and purchases natural gas for resale. The Company operates in
one segment, natural gas and oil exploration and exploitation within the
continental United States.
Comprehensive income for all periods presented is equal to net income,
since the Company has no other comprehensive income items.
The consolidated financial statements contain the accounts of the Company
after eliminating all significant intercompany balances and transactions.
PIPELINE EXCHANGES
Natural gas gathering and pipeline operations normally include exchange
arrangements with customers and suppliers. The volumes of natural gas due to or
from the Company under exchange agreements are recorded at average selling or
purchase prices, as the case may be, and are adjusted monthly to reflect market
changes. The net value of exchanged natural gas is included in inventories in
the consolidated balance sheet.
PROPERTIES AND EQUIPMENT
The Company uses the successful efforts method of accounting for oil and
gas producing activities. Under this method, acquisition costs for proved and
unproved properties are capitalized when incurred. Exploration costs, including
geological and geophysical costs, the costs of carrying and retaining unproved
properties and exploratory dry hole drilling costs, are expensed. Development
costs, including the costs to drill and equip development wells, and successful
exploratory drilling costs to locate proved reserves are capitalized.
The impairment of unamortized capital costs is measured at a lease level
and is reduced to fair value if it is determined that the sum of expected future
net cash flows is less than the net book value. The Company determines if an
impairment has occurred through either adverse changes or as a result of the
annual review of all fields. During the fourth quarter of 1999, the Company
experienced a significant production decline from the Chimney Bayou field
located in the Texas Gulf Coast. This decline along with an unsuccessful
workover in the Lawson field in Louisiana resulted in a $7 million impairment of
long-lived assets. The impairment was measured based on discounted cash flows
utilizing a discount rate appropriate for risks associated with the related
properties.
Capitalized costs of proved oil and gas properties, after considering
estimated dismantlement, restoration and abandonment costs, net of estimated
salvage values, are depreciated and depleted on a field basis by the
units-of-production method using proved developed reserves. The costs of
unproved oil and gas properties are generally combined and amortized over a
period that is based on the average holding period for such properties and the
Company's experience of successful drilling. Properties related to gathering and
pipeline systems and equipment are depreciated using the straight-line method
based on estimated useful lives ranging from 10 to 25 years. Certain other
assets are also depreciated on a straight-line basis.
43
Future estimated plug and abandonment costs are accrued over the productive
life of the oil and gas properties on a units-of-production basis. The accrued
liability for plug and abandonment costs are included in accumulated
depreciation, depletion and amortization.
Costs of retired, sold or abandoned properties that make up a part of an
amortization base (partial field) are charged to accumulated depreciation,
depletion and amortization if the units-of-production rate is not significantly
affected. Accordingly, a gain or loss, if any, is recognized only when a group
of proved properties (entire field) that make up the amortization base has been
retired, abandoned or sold.
REVENUE RECOGNITION AND GAS IMBALANCES
The Company applies the sales method of accounting for natural gas revenue.
Under this method, revenues are recognized based on the actual volume of natural
gas sold to purchasers. Natural gas production operations may include joint
owners who take more or less than the production volumes entitled to them on
certain properties. Production volume is monitored to minimize these natural gas
imbalances. A natural gas imbalance liability is recorded in other liabilities
in the consolidated balance sheet if the Company's excess takes of natural gas
exceed its estimated remaining recoverable reserves for these properties.
INCOME TAXES
The Company follows the asset and liability method of accounting for income
taxes. Under this method, deferred tax assets and liabilities are recorded for
the estimated future tax consequences attributable to the differences between
the financial carrying amounts of existing assets and liabilities and their
respective tax bases. Deferred tax assets and liabilities are measured using the
tax rate in effect for the year in which those temporary differences are
expected to turn around. The effect of a change in tax rates on deferred tax
assets and liabilities is recognized in the year of the enacted rate change.
NATURAL GAS MEASUREMENT
The Company records estimated amounts for natural gas revenues and natural
gas purchase costs based on volumetric calculations under its natural gas sales
and purchase contracts. Variances or imbalances resulting from such calculations
are inherent in natural gas sales, production, operation, measurement, and
administration. Management does not believe that differences between actual and
estimated natural gas revenues or purchase costs attributable to the unresolved
variances or imbalances are material.
ACCOUNTS PAYABLE
This account includes credit balances to the extent that checks issued have
not been presented to the Company's bank for payment. These credit balances
included in accounts payable were $5.9 million at December 31, 1999, and $9.1
million at December 31, 1998.
RISK MANAGEMENT ACTIVITIES
From time to time, the Company enters into derivative contracts, such as
natural gas price swaps, as a hedging strategy to manage commodity price risk
associated with its inventories, production or other contractual commitments.
These transactions are executed for purposes other than trading. Gains or losses
on these hedging activities are generally recognized over the period that the
inventory, production or other underlying commitment is hedged as an offset to
the specific hedged item. Cash flows related to any recognized gains or losses
associated with these hedges are reported as cash flows from operations. If a
hedge is terminated prior to expected maturity, gains or losses are deferred and
included in income in the same period that the underlying production or other
contractual commitment is delivered. Unrealized gains or losses associated with
any derivative contracts not considered a hedge would be recognized currently in
the results of operations.
44
A derivative instrument qualifies as a hedge if:
- The item to be hedged exposes the Company to price risk.
- The derivative reduces the risk exposure and is designated as a hedge
at the time the Company enters into the contract.
- At the inception of the hedge and throughout the hedge period there is
a high correlation between changes in the market value of the
derivative instrument and the fair value of the underlying item being
hedged.
When the designated item associated with a derivative instrument matures,
is sold, extinguished or terminated, derivative gains or losses are recognized
as part of the gain or loss on the sale or settlement of the underlying item.
When a derivative instrument is associated with an anticipated transaction that
is no longer expected to occur or if correlation no longer exists, the gain or
loss on the derivative is recognized currently in the results of operations to
the extent the market value changes in the derivative have not been offset by
the effects of the price changes on the hedged item since the inception of the
hedge. See Note 11 Financial Instruments for further discussion.
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" (SFAS 133). SFAS 133 requires all derivatives to be
recognized in the statement of financial position as either assets or
liabilities and measured at fair value. In addition, all hedging relationships
must be designated, documented and continually reassessed. This statement is
effective for financial statements for fiscal years beginning after June 15,
2000. The Company has not yet completed its evaluation of the impact of the
provisions from SFAS 133 on its financial position or results of operations.
CASH EQUIVALENTS
The Company considers all highly liquid short-term investments with
original maturities of three months or less to be cash equivalents. At December
31, 1999, and 1998, the majority of cash and cash equivalents is concentrated in
one financial institution. The Company periodically assesses the financial
condition of the institution and believes that any possible credit risk is
minimal.
USE OF ESTIMATES
The preparation of financial statements that conform with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities, the
disclosure of contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenues and expenses during the
reporting period. The Company's most significant financial estimates are based
on the remaining proved oil and gas reserves (see Supplemental Oil and Gas
Information). Actual results could differ from those estimates.
2. PROPERTIES AND EQUIPMENT
Properties and equipment are comprised of the following:
December 31,
(In thousands) 1999 1998
- ----------------------------------------------------------------------
Proved Oil and Gas Properties............... $ 906,852 $ 921,463
Unproved Oil and Gas Properties............. 32,262 42,426
Gathering and Pipeline Systems.............. 124,708 121,999
Land, Building and Improvements............. 4,359 4,200
Other....................................... 23,206 20,468
---------- ----------
1,091,387 1,110,556
Accumulated Depreciation,
Depletion, Amortization and Impairments... (501,086) (480,648)
---------- ----------
$ 590,301 $ 629,908
========== ==========
45
As a component of accumulated depreciation, depletion and amortization,
total future plug and abandonment costs, accrued on a units-of-production basis,
were $11.5 million at December 31, 1999, and $11.6 million at December 31, 1998.
The Company believes that this accrual method adequately provides for its
estimated future plug and abandonment costs over the reserve life of the oil and
gas properties.
3. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
December 31,
(In thousands) 1999 1998
- --------------------------------------------------------------------------
Accounts Receivable
Trade Accounts.................................. $44,739 $41,397
Joint Interest Accounts......................... 4,395 6,712
Insurance Recoveries............................ 1,177 5,539
Current Income Tax Receivable................... 111 502
Other Accounts.................................. 263 2,123
------- -------
50,685 56,273
Allowance for Doubtful Accounts................. (294) (474)
Other Accounts.................................. 263 2,123
------- -------
$50,391 $55,799
======= =======
Accounts Payable
Trade Accounts.................................. $12,195 $13,229
Natural Gas Purchases........................... 14,918 17,031
Wellhead Gas Imbalances......................... 2,177 1,945
Royalty and Other Owners........................ 11,316 8,987
Capital Costs................................... 10,103 20,165
Dividends Payable............................... 851 851
Taxes Other than Income......................... 1,279 1,017
Drilling Advances............................... 614 900
Other Accounts.................................. 3,098 2,503
------- -------
$56,551 $66,628
======= =======
Accrued Liabilities
Employee Benefits............................... $ 5,203 $ 4,479
Taxes Other than Income......................... 8,471 7,357
Interest Payable................................ 2,780 2,406
Other Accrued................................... 933 2,164
------- -------
$17,387 $16,406
======= =======
Other Liabilities
Postretirement Benefits Other than Pension...... $ 799 $ 316
Accrued Pension Cost............................ 6,290 4,941
Taxes Other than Income and Other............... 3,945 4,249
------- -------
$11,034 $ 9,506
======= =======
46
4. INVENTORIES
Inventories are comprised of the following:
December 31,
(In thousands) 1999 1998
- --------------------------------------------------------------------------
Natural Gas and Oil in Storage.................... $ 8,702 $ 7,524
Tubular Goods and Well Equipment.................. 2,052 1,714
Pipeline Exchange Balances........................ 175 74
------- -------
$10,929 $ 9,312
======= =======
5. DEBT AND CREDIT AGREEMENTS
10.18% NOTES
In May 1990, the Company issued an aggregate principal amount of $80
million of its 12-year 10.18% Notes (10.18% Notes) to a group of nine
institutional investors in a private placement offering. The 10.18% Notes
require five annual $16 million principal payments each May starting in 1998.
The payment due in May 2000, classified as "Current Portion of Long-Term Debt,"
is a current liability on the Company's Consolidated Balance Sheet. The Company
may prepay all or any portion of the debt at any time with a prepayment penalty.
The 10.18% Notes contain restrictions on the merger of the Company or any
subsidiary with a third party except under certain limited conditions. There are
also various other restrictive covenants customarily found in such debt
instruments, including a restriction on the payment of dividends and a required
asset coverage ratio (present value of proved reserves to debt and other
liabilities) that must be at least 1.5 to 1.0.
7.19% NOTES
In November 1997, the Company issued an aggregate principal amount of $100
million of its 12-year 7.19% Notes (7.19% Notes) to a group of six institutional
investors in a private placement offering. The 7.19% Notes require five annual
$20 million principal payments starting in November 2005. The Company may prepay
all or any portion of the indebtedness on any date with a prepayment penalty.
The 7.19% Notes contain restrictions on the merger of the Company or any
subsidiary with a third party other than under certain limited conditions. There
are also various other restrictive covenants customarily found in such debt
instruments, including a required asset coverage ratio (present value of proved
reserves to debt and other liabilities) that must be at least 1.5 to 1.0, and a
minimum annual coverage ratio of operating cash flow to interest expense for the
trailing four quarters of 2.8 to 1.0.
REVOLVING CREDIT AGREEMENT
In November 1998, the Company replaced its $135 million Revolving Credit
Agreement that utilized five banks with a new $250 million Revolving Credit
Agreement (Credit Facility) with 10 banks. The term of the Credit Facility is
five years and expires on December 17, 2003. The available credit line is
subject to adjustment from time-to-time on the basis of the projected present
value (as determined by the banks' petroleum engineer) of estimated future net
cash flows from certain proved oil and gas reserves and other assets of the
Company. While the Company does not expect a change in the available credit
line, in the event that it is adjusted below the outstanding level of
borrowings, the Company has a period of 180 days to reduce its outstanding debt
to the adjusted credit line. The Credit Facility also includes a requirement to
pay down half of the debt in excess of the adjusted credit line within the first
90 days of such an adjustment. Interest rates are principally based on a
reference rate of either the rate for certificates of deposit (CD rate) or
LIBOR, plus a margin, or the prime rate. For CD rate and LIBOR borrowings,
interest rates are subject to increase if the indebtedness under the Credit
47
Facility is either greater than 60% or 80% of the Company's debt limit of $400
million, as shown below.
Debt Percentage
---------------------------------------------------
Lower than 60% 60% - 80% Higher than 80%
- ----------------------------------------------------------------------------
LIBOR margin............... 0.750% 1.00% 1.250%
CD margin.................. 0.875% 1.125% 1.375%
Commitment fee rate........ 0.250% 0.3750% 0.3750%
The Credit Facility provides for a commitment fee on the unused available
balance at an annual rate one-fourth of 1% or three-eighths of 1% depending on
the level of indebtedness as indicated above. The Company's effective interest
rates for the Credit Facility in the years ended December 31, 1999, 1998 and
1997 were 6.7%, 6.8% and 6.6%, respectively. The Credit Facility contains
various customary restrictions, which are the following:
(a) Prohibiting the merger of the Company or any subsidiary with a third
party except under certain limited conditions
(b) Prohibiting the sale of all or substantially all of the Company's or
any subsidiary's assets to a third party
(c) Requiring a minimum annual coverage ratio of operating cash flow to
interest expense for the trailing four quarters of 2.8 to 1.0
6. EMPLOYEE BENEFIT PLANS
PENSION PLAN
The Company has a non-contributory, defined benefit pension plan for all
full-time employees. Plan benefits are based primarily on years of service and
salary level near retirement. Plan assets are mainly fixed income investments
and equity securities. The Company complies with the Employee Retirement Income
Security Act of 1974 and Internal Revenue Code limitations when funding the
plan.
The Company has a non-qualified equalization plan to ensure payments to
certain executive officers of amounts to which they are already entitled under
the provisions of the pension plan, but which are subject to limitations imposed
by federal tax laws. This plan is unfunded.
Net periodic pension cost of the Company for the years ended December 31,
1999, 1998 and 1997 are comprised of the following:
(In thousands) 1999 1998 1997
- --------------------------------------------------------------------------
Qualified:
Current Year Service Cost................ $1,012 $ 853 $ 753
Interest Accrued on Pension Obligation... 1,072 945 810
Actual Return on Plan Assets............. (919) (1,434) (1,129)
Net Amortization and Deferral............ 88 706 491
Recognized Gain.......................... -- (20) --
------ ------ ------
Net Periodic Pension Cost................ $1,253 $1,050 $ 925
====== ====== ======
Non-Qualified
Current Year Service Cost................ $ 140 $ 81 $ 28
Interest Accrued on Pension Obligation... 67 45 6
Net Amortization......................... 77 54 27
Recognized Loss.......................... 35 20 --
Settlement Charge........................ -- 213 --
------ ------ ------
Net Periodic Pension Cost................ $ 319 $ 413 $ 61
====== ====== ======
48
The following table illustrates the funded status of the Company's pension
plans at December 31, 1999, and 1998, respectively:
1999 1998
Non- Non-
(In thousands) Qualified Qualified Qualified Qualified
- --------------------------------------------------------------------------------
Actuarial Present Value of
Accumulated Benefit Obligation.... $10,474 $504 $10,552 $438
Projected Benefit Obligation...... $14,009 $537 $15,491 $959
Plan Assets at Fair Value......... 12,092 -- 10,344 --
------- ---- ------- ----
Projected Benefit Obligation in
Excess of Plan Assets........... 1,917 537 5,147 959
Unrecognized Net Gain (Loss)...... 4,964 114 657 (537)
Unrecognized Prior Service Cost... (687) (707) (774) (784)
Adjustment to Recognize Minimum
Liability....................... -- 560 -- 801
------- ---- ------- ----
Accrued Pension Cost.......... $ 6,194 $504 $ 5,030 $439
======= ==== ======= ====
The change in the combined projected benefit obligation of the Company's
qualified and non-qualified pension plans during the last three years is
explained as follows:
(In thousands) 1999 1998 1997
- ------------------------------------------------------------------------------
Beginning of Year............................... $16,449 $13,441 $11,041
Service Cost.................................... 1,152 935 781
Interest Cost................................... 1,139 990 817
Plan Amendments................................. -- 488 --
Actuarial Loss (Gain)........................... (3,657) 1,803 1,192
Benefits Paid................................... (537) (1,208) (390)
------- ------- -------
End of Year..................................... $14,546 $16,449 $13,441
======= ======= =======
The change in the combined plan assets at fair value of the Company's
qualified and non-qualified pension plans during the last three years is
explained as follows:
(In thousands) 1999 1998 1997
- ------------------------------------------------------------------------------
Beginning of Year............................... $10,344 $ 8,890 $ 7,074
Actual Return on Plan Assets.................... 2,428 1,608 1,305
Employer Contribution........................... 101 1,227 1,077
Benefits Paid................................... (537) (1,208) (390)
Expenses Paid................................... (244) (173) (176)
------- ------- -------
End of Year..................................... $12,092 $10,344 $ 8,890
======= ======= =======
49
The reconciliation of the combined funded status of the Company's qualified
and non-qualified pension plans at the end of the last three years is explained
as follows:
(In thousands) 1999 1998 1997
- -------------------------------------------------------------------------------
Funded Status.................................... $ 2,454 $ 6,105 $ 4,550
Unrecognized Gain................................ 5,078 121 1,091
Unrecognized Prior Service Cost.................. (1,394) (1,558) (1,211)
------- ------- -------
Net Amount Recognized............................ $ 6,138 $ 4,668 $ 4,430
======= ======= =======
Accrued Benefit Liability - Qualified Plan....... $ 6,194 $ 5,030 $ 4,547
Accrued Benefit Liability - Non-Qualified Plan... 504 439 363
Intangible Asset................................. (560) (801) (480)
------- ------- -------
Net Amount Recognized............................ $ 6,138 $ 4,668 $ 4,430
======= ======= =======
Assumptions used to determine post-retirement benefit obligations and
pension costs are as follows:
1999 1998 1997
- -------------------------------------------------------------------------------
Discount Rate (1)................................ 7.75% 7.00% 7.50%
Rate of Increase in Compensation Levels.......... 4.00% 4.00% 4.50%
Long-Term Rate of Return on Plan Assets.......... 9.00% 9.00% 9.00%
- ----------
(1) Represents the rate used to determine the benefit obligation. A 7.0%
discount rate was used to compute pension costs in 1999, and a rate of 7.5%
was used in 1998 and 1997.
SAVINGS INVESTMENT PLAN
The Company has a Savings Investment Plan (SIP) which is a defined
contribution plan. The Company matches a portion of employees' contributions.
Participation in the SIP is voluntary and all regular employees of the Company
are eligible to participate. The Company charged to expense plan contributions
of $0.7 million, $0.8 million and $0.6 million in 1999, 1998 and 1997,
respectively. The Company's Common Stock is an investment option within the SIP.
DEFERRED COMPENSATION PLAN
In 1998, the Company established a Deferred Compensation Plan. This plan is
available to officers of the Company and acts as a supplement to the Savings
Investment Plan. The Company matches a portion of the employee's contribution
and those assets are invested in instruments selected by the employee. Unlike
the SIP, the Deferred Compensation Plan does not have dollar limits on tax
deferred contributions. However, the assets of this plan are held in a rabbi
trust and are subject to additional risk of loss in the event of bankruptcy or
insolvency of the Company. At December 31, 1999, the balance in the Deferred
Compensation Plan's rabbi trust was $1.15 million.
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits for retired employees, including their
spouses, eligible dependents and surviving spouses (retirees). These benefits
are commonly called postretirement benefits. Most employees become eligible for
these benefits if they meet certain age and service requirements at retirement.
The Company was providing postretirement benefits to 250 retirees at the end of
1999 and 251 retirees at the end of 1998.
50
When the Company adopted SFAS 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions," in 1992, it began amortizing the
$16.9 million accumulated postretirement benefit, known as the Transition
Obligation, over a period of 20 years.
The amortization benefit of the unrecognized Transition Obligation in 1998
and 1997, presented in the table below, is due to a cost-cutting amendment to
the postretirement medical benefits in 1993. The amendment prospectively reduced
the unrecognized Transition Obligation by $9.8 million and was amortized over a
5.75 year period beginning in 1993 and ending in 1998.
Postretirement benefit costs recognized during the last three years are as
follows:
(In thousands) 1999 1998 1997
- --------------------------------------------------------------------------------
Service Cost of Benefits Earned During the Year..... $ 225 $ 190 $ 168
Interest Cost on the Accumulated Postretirement
Benefit Obligation................................ 515 525 519
Amortization Benefit of the Unrecognized Gain....... (131) (165) (181)
Amortization Benefit of the Unrecognized
Transition Obligation............................. 690 (435) (808)
------ ----- -----
Total Postretirement Benefit Cost (Benefit)......... $1,299 $ 115 $(302)
====== ===== =====
The health care cost trend rate used to measure the expected cost in 1999
for medical benefits to retirees over age 65 was 8%, graded down to a trend rate
of 0% in 2001. The health care cost trend rate used to measure the expected cost
in 1999 for retirees under age 65 was also 8%, graded down to a trend rate of 0%
in 2001. Provisions of the plan should prevent further increases in employer
cost after 2001.
A one-percentage-point increase or decrease in health care cost trend rates
for future periods would similarly increase or decrease the accumulated net
postretirement benefit obligation by approximately $61,000 and, accordingly, the
total postretirement benefit cost recognized in 1999 would have also increased
or decreased by approximately $13,000.
The funded status of the Company's postretirement benefit obligation at
December 31, 1999, and 1998 is comprised of the following:
(In thousands) 1999 1998
- ------------------------------------------------------------------------------
Plan Assets at Fair Value.................................. $ -- $ --
Accumulated Postretirement Benefits Other Than Pensions.... 7,243 7,693
Unrecognized Cumulative Net Gain........................... 2,056 2,086
Unrecognized Transition Obligation......................... (7,940) (8,883)
------- -------
Accrued Postretirement Benefit Liability................ $ 1,359 $ 896
======= =======
51
The change in the accumulated postretirement benefit obligation during the
last three years is explained as follows:
(In thousands) 1999 1998 1997
- -----------------------------------------------------------------------------
Beginning of Year............................... $7,693 $7,303 $7,207
Service Cost.................................... 225 190 168
Interest Cost................................... 515 526 519
Amendments...................................... (253) 0 0
Actuarial Loss/(Gain)........................... (102) 230 3
Benefits Paid................................... (835) (556) (594)
------ ------ ------
End of Year..................................... $7,243 $7,693 $7,303
====== ====== ======
7. INCOME TAXES
Income tax expense is summarized as follows:
Year Ended December 31,
(In thousands) 1999 1998 1997
- ------------------------------------------------------------------------------
Current:
Federal....................................... $(3,899) $(1,696) $ 5,210
State......................................... -- 65 1,089
------- ------- -------
Total....................................... (3,899) (1,631) 6,299
------- ------- -------
Deferred
Federal....................................... 8,910 4,869 9,382
State......................................... 150 263 1,876
------- ------- -------
Total....................................... 9,060 5,132 11,258
------- ------- -------
Total Income Tax Expense........................ $ 5,161 $ 3,501 $17,557
======= ======= =======
In the table above, the $4.5 million refund received in 1999 that applied
to a net operating loss carryback to 1997 is reflected in "Current - Federal".
The 1998 "Current - Federal" amount includes the effect of a $2.0 million income
tax refund received in 1998 that applied to a net operating loss carryback to
1992.
Total income taxes were different than the amounts computed by applying the
statutory federal income tax rate as follows:
Year Ended December 31,
(In thousands) 1999 1998 1997
- -----------------------------------------------------------------------------
Statutory Federal Income Tax Rate............. 35% 35% 35%
Computed "Expected" Federal Income Tax........ $ 4,788 $ 3,081 $16,062
State Income Tax, Net of Federal Income Tax... 506 352 1,927
Other, Net.................................... (133) 68 (432)
------- ------- -------
Total Income Tax Expense...................... $ 5,161 $ 3,501 $17,557
======= ======= =======
52
The tax effects of temporary differences that resulted in significant
portions of the deferred tax liabilities and deferred tax assets as of December
31, 1999, and 1998 were as follows:
(In thousands) 1999 1998
- ----------------------------------------------------------------------------
Deferred Tax Liabilities:
Property, Plant and Equipment...................... $133,982 $137,061
-------- --------
Deferred Tax Assets
Alternative Minimum Tax Credit Carryforwards....... 3,044 7,241
Net Operating Loss Carryforwards................... 20,165 25,663
Note Receivable on Section 29 Monetization (1)..... 11,228 12,320
Items Accrued for Financial Reporting Purposes..... 4,533 5,885
-------- --------
38,970 51,109
-------- --------
Net Deferred Tax Liabilities......................... $ 95,012 $ 85,952
======== ========
- ----------
(1) As a result of the monetization of Section 29 tax credits in 1996 and 1995,
the Company recorded an asset sale for tax purposes in exchange for a
long-term note receivable which will be repaid through 100% working and
royalty interest in the production from the sold properties.
At December 31, 1999, the Company has a net operating loss carryforward for
regular income tax reporting purposes of $51.2 million that will begin expiring
in 2011. In addition, the Company has an alternative minimum tax credit
carryforward of $3.0 million which does not expire and can be used to offset
regular income taxes in future years to the extent that regular income taxes
exceed the alternative minimum tax in any year.
8. COMMITMENTS AND CONTINGENCIES
LEASE COMMITMENTS
The Company leases certain transportation vehicles, warehouse facilities,
office space, and machinery and equipment under cancelable and non-cancelable
leases. Most of the leases expire within five years and may be renewed. Rent
expense under such arrangements totaled $5.0 million, $4.3 million and $4.1
million for the years ended December 31, 1999, 1998 and 1997, respectively. In
1998, the Company entered into a 10-year lease agreement for office space in
Houston, Texas, to house the corporate offices and the Gulf Coast regional
offices. The lease term commenced in August 1999 for annual rent expense of
approximately $2.6 million when the Company occupied the new office space, at
which time the lease on the former office space ended.
Future minimum rental commitments under non-cancelable leases in effect at
December 31, 1999 are as follows:
(In thousands)
-----------------------------------
2000....................... $ 4,944
2001....................... 4,832
2002....................... 4,739
2003....................... 3,503
2004....................... 3,262
Thereafter................. 13,768
-------
$35,048
=======
Minimum rental commitments are not reduced by minimum sublease rental income of
$0.9 million due in the future under non-cancelable subleases.
53
CONTINGENCIES
The Company is a defendant in various lawsuits and is involved in other gas
contract issues. In the Company's opinion, final judgments or settlements, if
any, which may be awarded in connection with any one or more of these suits and
claims could have a significant impact on the results of operations and cash
flows of any period. However, there would not be a material adverse effect on
the Company's financial position.
9. CASH FLOW INFORMATION
Cash paid for interest and income taxes is as follows:
Year Ended December 31,
(In thousands) 1999 1998 1997
---------------------------------------------------------------
Interest......................... $25,445 $18,341 $18,001
Income Taxes..................... $ 652 $ 827 $ 8,980
At December 31, 1999, and 1998, the Accounts Payable balance on the
Consolidated Balance Sheet included payables for capital expenditures of $10.1
million and $20.2 million, respectively.
10. CAPITAL STOCK
INCENTIVE PLANS
On May 12, 1998, the Amended and Restated 1994 Long-Term Incentive Plan and
the Amended and Restated 1994 Non-Employee Director Stock Option Plan were
approved by the shareholders. The Company has two other stock option plans: the
1990 Incentive Stock Option Plan and the 1990 Non-Employee Director Stock Option
Plan. Under these four plans (Incentive Plans), incentive and non-statutory
stock options, stock appreciation rights (SARs) and stock awards may be granted
to key employees and officers of the Company, and non-statutory stock options
may be granted to non-employee directors of the Company. A maximum of 3,860,000
shares of Common Stock, par value $0.10 per share, may be issued under the
Incentive Plans. All stock options have a maximum term of five or 10 years from
the date of grant, with most vesting over time. The options are issued at market
value on the date of grant. The minimum exercise period for stock options is six
months from the date of grant. No SARs have been granted under the Incentive
Plans.
Information regarding the Company's Incentive Plans is summarized below:
December 31,
1999 1998 1997
- ---------------------------------------------------------------------------------
Shares Under Option at Beginning of Period... 1,557,936 1,404,877 1,532,353
Granted...................................... 454,100 355,000 82,500
Exercised.................................... 55,032 152,917 139,836
Surrendered or Expired....................... 183,615 49,024 70,140
--------- --------- ---------
Shares Under Option at End of Period......... 1,773,389 1,557,936 1,404,877
========= ========= =========
Options Exercisable at End of Period......... 1,108,637 1,092,295 1,071,923
========= ========= =========
54
For each of the three most recent years, the price range for outstanding
options was $13.25 to $26.00 per share. The following tables provide more
information about the options by exercise price and year.
Options with exercise prices between $13.25 and $20.00 per share:
December 31,
1999 1998 1997
- -------------------------------------------------------------------------------------
OPTIONS OUTSTANDING
Number of Options.............................. 1,412,072 1,051,936 1,147,322
Weighted Average Exercise Price................ $ 16.07 $ 15.53 $ 15.60
Weighted Average Contractual Term (in years)... 2.40 2.46 3.30
OPTIONS EXERCISABLE
Number of Options.............................. 953,640 927,795 814,418
Weighted Average Exercise Price................ $ 15.44 $ 15.32 $ 15.17
Options with exercise prices between $20.01 and $26.00 per share:
December 31,
1999 1998 1997
- ------------------------------------------------------------------------------------
OPTIONS OUTSTANDING
Number of Options.............................. 361,317 506,000 257,555
Weighted Average Exercise Price................ $ 22.50 $ 22.04 $ 21.19
Weighted Average Contractual Term (in years)... 3.37 3.47 2.68
OPTIONS EXERCISABLE
Number of Options.............................. 154,997 164,500 257,555
Weighted Average Exercise Price................ $ 22.55 $ 21.17 $ 21.19
Under the Amended and Restated 1994 Long-Term Incentive Plan, the
Compensation Committee of the Board of Directors may grant awards of performance
shares of stock to members of the executive management group. Each grant of
performance shares has a three-year performance period, measured as the change
from July 1 of the initial year of the performance period to June 30 of the
third year. The number of shares of Common Stock received at the end of the
performance period is based mainly on the relative stock price growth between
the two measurement dates of Common Stock compared to that of a group of peer
companies. The performance shares that were granted on July 1, 1994, expired on
June 30, 1997, without issuing any Common Stock of the Company. The performance
shares granted in July 1995 were converted to 21,692 shares of the Company's
Common Stock in 1998, and the performance shares granted in July 1996 were
converted to 19,090 shares of the Company's Common Stock in 1999. The Board of
Directors has not issued performance shares since July 1996 and, currently,
there are no performance shares outstanding.
Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for
Stock-Based Compensation," outlines a fair value based method of accounting for
stock options or similar equity instruments. The Company has opted to continue
using the intrinsic value based method, as recommended by Accounting Principles
Board (APB) Opinion No. 25, to measure compensation cost for its stock option
plans.
55
If the Company had adopted SFAS 123, the pro forma results of operations
would be as follows:
1999 1998 1997
- --------------------------------------------------------------------------------
NET INCOME......................... $4.3 million $1.3 million $22.8 million
Net Income per Share............... $0.20 $0.06 $1.00
Weighted Average Value of Options
Granted During the Year (1)...... $4.78 $6.21 $4.26
ASSUMPTIONS:
Stock Price Volatility.......... 27.4% 26.1% 27.8%
Risk Free Rate of Return........ 5.21% 5.63% 6.34%
Dividend Rate (per year)........ $0.16 $0.16 $0.16
Expected Term (in years)........ 4 4 3
- ----------
(1) Calculated using the fair value based method.
The fair value of stock options included in the pro forma results for each
of the three years is not necessarily indicative of future effects on net income
and earnings per share.
DIVIDEND RESTRICTIONS
The Board of Directors of the Company determines the amount of future cash
dividends, if any, to be declared and paid on the Common Stock depending on,
among other things, the Company's financial condition, funds from operations,
the level of its capital and exploration expenditures, and its future business
prospects. The Company's 10.18% Note Agreement restricts certain payments
associated with the following:
(a) Purchasing, redeeming, retiring or otherwise acquiring any capital
stock of the Company or any option, warrant or other right to acquire
such capital stock.
(b) Declaring any dividend, if immediately prior to or after making
payments, the dividend exceeds consolidated net cash flow (as defined)
and the ratio of proved reserves to debt is less than 1.7 to 1, or
there has been an event of default under the Note Agreement.
As of December 31, 1999, these restrictions did not impact the Company's ability
to pay regular dividends. The 7.19% Note Agreement issued in 1997 does not have
a restricted payment provision.
TREASURY STOCK
In August 1998, the Board of Directors authorized the Company to repurchase
up to two million shares of outstanding Common Stock at market prices. The
timing and amount of these stock purchases are determined at the discretion of
management. The Company may use the repurchased shares to fund stock
compensation programs presently in existence, or for other corporate purposes.
As of December 31, 1998, the Company had repurchased 302,600 shares, or 15% of
the total authorized number of shares, for a total cost of approximately $4.4
million. No additional shares were repurchased during 1999. The stock repurchase
plan was funded from increased borrowings on the revolving credit facility. No
treasury shares were delivered or sold by the Company during the year.
56
PURCHASE RIGHTS
On January 21, 1991, the Board of Directors adopted the Preferred Stock
Purchase Rights Plan and declared a dividend distribution of one right for each
outstanding share of Common Stock. Each right becomes exercisable, at a price of
$55, when any person or group has acquired, obtained the right to acquire or
made a tender or exchange offer for beneficial ownership of 15 percent or more
of the Company's outstanding Common Stock. An exception to the right occurs
following a tender or exchange offer for all outstanding shares of Common Stock
determined to be fair and in the best interests of the Company and its
stockholders by a majority of the independent Continuing Directors (as defined
in the plan). Each right entitles the holder, other than the acquiring person or
group, to purchase one one-hundredth of a share of Series A Junior Participating
Preferred Stock (Junior Preferred Stock), or to receive, after certain
triggering events, Common Stock or other property having a market value (as
defined in the plan) of twice the exercise price of each right. The rights
become exercisable if the Company is acquired in a merger or other business
combination in which it is not the survivor, or 50 percent or more of the
Company's assets or earning power are sold or transferred. Once it becomes
exercisable, each right entitles the holder to purchase common stock of the
acquiring company with a market value (as defined in the plan) equal to twice
the exercise price of each right. At December 31, 1999, and 1998, there were no
shares of Junior Preferred Stock issued or outstanding.
The rights, which expire on January 21, 2001, and the exercise price are
subject to adjustment and may be redeemed by the Company for $0.01 per right at
any time before they become exercisable. Under certain circumstances, the
Continuing Directors may opt to exchange one share of Common Stock for each
exercisable right.
PREFERRED STOCK
At December 31, 1999, and 1998, 1,134,000 shares of 6% convertible
redeemable preferred stock (6% preferred stock) were issued and outstanding.
Each share has voting rights equal to approximately 1.7 shares of Common Stock
and a stated value of $50. At any time, the stock is convertible by the holder
into Common Stock at a conversion price of $28.75 per share. While the 6%
preferred stock does not have a mandatory redemption requirement, it is
redeemable for cash at $50 per share plus accrued dividends due on the shares
redeemed.
The Company has entered into a letter agreement with the holder of the 6%
preferred stock to repurchase these shares before November 1, 2000, for a total
price of $51.6 million. Cash flow from operations, additional borrowings or
proceeds from the sale of equity may be used to fund this transaction. The value
of these shares on the Company's balance sheet is $56.7 million. This repurchase
will retire all of the preferred stock outstanding and will simplify the
Company's capital structure.
The Company had 692,439 shares of $3.125 cumulative convertible preferred
stock ($3.125 preferred stock) issued and outstanding until October 1997 when
these shares were converted into 1,648,664 shares of Common Stock. Each share
had a stated value of $50 and could be converted any time by the holder into
Common Stock at a conversion price of $21 per share. While there was no
mandatory requirement, these shares could also be redeemed under certain
provisions and fixed redemption prices. The Company had the option to convert
the $3.125 preferred stock into shares of Common Stock valued at the conversion
price if the closing price of the Common Stock was at least equal to the
conversion price for 20 consecutive trading days.
57
11. FINANCIAL INSTRUMENTS
The estimated fair value of financial instruments is the amount at which
the instrument could be exchanged currently between willing parties. The
carrying amounts reported in the consolidated balance sheet for cash and cash
equivalents, accounts receivable, and accounts payable approximate fair value.
The Company uses available marketing data and valuation methodologies to
estimate fair value of debt.
December 31, 1999 December 31, 1998
Carrying Estimated Carrying Estimated
(In thousands) Amount Fair Value Amount Fair Value
- --------------------------------------------------------------------------------
Debt:
10.18% Notes................... $ 48,000 $ 50,020 $ 64,000 $ 68,185
7.19% Notes.................... 100,000 91,237 100,000 93,145
Credit Facility................ 145,000 145,000 179,000 179,000
-------- -------- -------- --------
$293,000 $286,257 $343,000 $340,330
======== ======== ======== ========
LONG-TERM DEBT
The fair value of long-term debt is the estimated cost to acquire the debt,
including a premium or discount for the difference between the issue rate and
the year-end market rate. The fair value of the 10.18% Notes and the 7.19% Notes
is based on interest rates currently available to the Company. The Credit
Facility approximates fair value because this instrument bears interest at rates
based on current market rates.
COMMODITY PRICE SWAPS
From time to time, the Company enters into natural gas and crude oil swap
agreements with counterparties to hedge price risk associated with a portion of
its production. These derivatives are not held for trading purposes. Under these
price swaps, the Company receives a fixed price on a notional quantity of
natural gas and crude oil in exchange for paying a variable price based on a
market-based index, such as the NYMEX gas and crude oil futures.
The Company uses price swaps to hedge the natural gas price risk on
brokered transactions. Typically, the Company enters into contracts to broker
natural gas at a variable price based on the market index price. However, in
some circumstances, some customers or suppliers request that a fixed price be
stated in the contract. After entering into these fixed price contracts to meet
the needs of customers or suppliers, the Company may use price swaps to
effectively convert these fixed price contracts to market-sensitive price
contracts. These price swaps are held to their maturity and are not held for
trading purposes.
58
As of the years ending December 31, 1999, and 1998, the Company had open
natural gas and oil price swap contracts as follows:
Natural Gas Price Swaps
-------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Mmbtu Contract Price (in $ millions)
- --------------------------------------------------------------------------------
As of December 31, 1999
- -----------------------
Natural Gas Price Swap on Brokered Transactions
-----------------------------------------------
First Quarter 2000........... 1,009,800 $2.26 $(0.2)
As of December 31, 1998
- -----------------------
Natural Gas Price Swap on Brokered Transactions
-----------------------------------------------
Full Year 1999............... 1,280,000 2.03 (0.3)
First Quarter 2000........... 450,000 2.13 0.1
Financial derivatives related to natural gas reduced revenues by $0.1
million in 1999 and by $0.3 million in 1998. These revenue reductions were
offset by higher realized revenue on the underlying physical gas sales.
We had open oil price swap contracts as follows:
Oil Price Swaps
-------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Bbls Contract Price (in $ millions)
- --------------------------------------------------------------------------------
As of December 31, 1999
- -----------------------
Oil Price Swaps on Our Production
---------------------------------
First Quarter 2000............ 182,000 $22.25 $(0.5)
Second Quarter 2000........... 182,000 23.08 (0.1)
Financial derivatives related to crude oil reduced revenue by $0.8 million
during 1999. This revenue reduction was offset by higher realized revenue on the
underlying physical oil sales. There were no crude oil price swaps outstanding
at December 31, 1998 or 1997.
For a detailed discussion about derivative instruments, please read Item
7A, "Quantitative and Qualitative Disclosures about Market Risk" in the
Company's Form 10-K.
CREDIT RISK
Although notional contract amounts are used to express the volume of
natural gas price agreements, the amounts that can be subject to credit risk in
the event of non-performance by third parties are substantially smaller. The
Company does not anticipate any material impact on its financial results due to
non-performance by the third parties. The Company had no sales to any customer
that exceeded 10% of total gross revenues in 1999 or 1998.
59
12. OIL AND GAS PROPERTY TRANSACTIONS
In September and December 1999, the Company purchased oil and gas producing
properties in the Moxa Arch of the Green River Basin in southwest Wyoming for
$8.9 and $8.5 million, respectively. The assets included approximately 16 Bcfe
of proved reserves, approximately 43,000 undeveloped net acres, and 27 wells
producing a net 3.8 Mmcfe per day at the time of the acquisition.
Also in September 1999, the Company sold non-strategic oil and gas
properties located in Pennsylvania and West Virginia to EnerVest Appalachia,
L.P. for approximately $46 million. These properties represented 716 wells and
62.2 Bcfe of proved reserves. A portion of this transaction and the two
previously mentioned were completed as a tax-deferred exchange deferring a
taxable gain of $8.9 million.
In the second quarter of 1999, the Company sold certain non-strategic
properties in the Gulf Coast region's Provident City field. These properties
were producing 3.5 Mmcfe per day from eight wells. The sales price was $9
million, and the transaction contributed to a gain of approximately $1.0 million
on the Company's second quarter income statement.
Effective December 1, 1998, the Company purchased onshore southern
Louisiana properties and 3-D seismic inventory from Oryx Energy Company for
approximately $70.1 million. The purchased assets included 10 fields covering
over 34,000 net acres with 68 producing wells. Total proved reserves are
approximately 72 Bcfe. This transaction was funded by the Company's newly
expanded revolving line of credit. See discussion in Note 5 Debt and Credit
Agreements.
In the fourth quarter of 1998, the Company purchased oil and gas producing
properties in the Lookout Wash Unit of Wyoming from Oxy USA, Inc. for $5.2
million. The properties acquired included 11.2 Bcfe of proved reserves and more
than 10 potential drilling locations. Additionally in 1998, the Company acquired
oil and gas producing properties in Oklahoma during the second quarter for $6.6
million. Included in the purchase were 9.3 Bcfe of proved reserves, 10 wells and
undeveloped acreage.
In the fourth quarter of 1997, the Company closed two notable asset
transactions. Properties in Northwest Pennsylvania (the Meadville properties),
including 912 wells and 15 Mmcfe per day of production, were sold to Lomak
Petroleum Incorporated (now known as Range Resources Corporation) for $92.9
million. In a like-kind exchange transaction, the Company matched a portion of
the Meadville properties sold with approximately $45 million in oil and gas
producing properties acquired from Equitable Resources Energy Company, including
63 wells and 10 Mmcfe per day of production.
13. OTHER REVENUE
The Company had a 15-year cogeneration contract under which approximately
20% of the Western region natural gas was sold per year. The contract was due to
expire in 2008, but during 1999 the Company reached an agreement with the
counterparty under which the counterparty bought out the remainder of the
contract for $12 million. This transaction was completed in December 1999,
adding $12 million of pre-tax other revenue. Simultaneously, Cabot Oil & Gas
sold forward a similar quantity of Western region gas for the next 16 months at
prices similar to those in the monetized contract.
Since 1995, other revenue has included an income source generated from two
transactions in September and November 1995 and a third transaction in August
1996 to monetize the value of Section 29 tax credits (monetized credits) from
most of our qualifying Appalachian and Rocky Mountains properties. The
transactions provided up-front cash of $2.8 million in 1995 and $0.6 million in
1996, which was recorded as a reduction to the net book value of natural gas
properties. Revenue from these monetized credits was $1.3 million in 1999, $2.7
million in 1998 and $3.6 million in 1997. These transactions are expected to
generate future revenues through 2002 of $5.4 million. Using a volumetric
production payment structure, the production, revenues, expenses and proved
reserves for these properties will continue to be reported by the Company as
Other Revenue until the production payment is satisfied.
60
During 1999, an industry tax court ruling concluded that the Section 29
tight sands tax credits would not be available on wells not certified by the
FERC. Because the FERC discontinued the certification process for qualifying
wells in 1992, there is currently no avenue to obtain the well certifications.
Accordingly, the Company stopped recording revenue on non-certified wells and
established a reserve related to previously recorded amounts on these wells.
This resulted in a $1.2 million reduction to other revenue in 1999.
14. SUPPLEMENTAL FULL COST ACCOUNTING INFORMATION
U.S. oil and gas producing entities may utilize one of two methods of
financial accounting: successful efforts or full cost. Given the current
composition of the Company's properties, management considers the successful
efforts method to be more appropriate than the full cost method primarily
because the successful efforts method results in moderately better matching of
costs and revenues. It has come to management's attention that certain users of
the Company's financial statements believe that information about the Company
prepared under the full cost method would also be useful. As a result, the
following supplemental full cost information is also included.
Successful efforts methodology is explained in Note 1 Summary of
Significant Accounting Policies.
Under the full cost method of accounting, all costs incurred in the
acquisition, exploration and development of oil and gas properties are
capitalized. These capitalized costs and estimated future development and
dismantlement costs are amortized on a units-of-production method based on
proved reserves. Net capitalized costs of oil and gas properties are limited to
the lower of unamortized cost or the cost center ceiling, defined as the
following:
- The present value (10% discount rate) of estimated unescalated future
net revenues from proved reserves, plus
- The cost of properties not being amortized, plus
- The lower of cost or estimated fair value of unproved properties
included in the costs being amortized, minus
- The deferred tax liabilities for the temporary differences between the
book and tax basis of oil and gas properties
Proceeds from the sale of oil and gas properties are applied to reduce the costs
in the cost center unless the sale involves a significant quantity of reserves
in relation to the cost center. In this case, a gain or loss is recognized.
Unevaluated properties and associated costs not currently being amortized and
included in oil and gas properties totaled $32.3 million, $42.4 million and
$24.6 million at December 31, 1999, 1998 and 1997, respectively.
Because of the capital cost limitations described above, full cost entities
are not subject to the impairment test prescribed by SFAS 121.
The full cost method of accounting allows for the capitalization of general
and administrative, region office and interest expense. Pre-tax capitalizable
administrative expenses were $4.6 million in 1999, $4.6 million in 1998 and $4.2
million in 1997. Pre-tax capitalizable interest expense was $2.7 million in
1999, $2.0 million in 1998 and $1.4 million in 1997.
61
1999 1998 1997
------------------ ------------------ -----------------
Successful Full Successful Full Successful Full
(In thousands, except per share amounts) Efforts Cost Efforts Cost Efforts Cost
- -------------------------------------------------------------------------------------------------------
BALANCE SHEET:
Properties and Equipment, Net............ $590,301 $782,156 $629,907 $816,759 $469,399 $651,739
Stockholders' Equity..................... 186,496 304,487 182,668 297,583 184,062 296,201
Debt to Capitalization Ratio............. 61.1% 49.0% 65.2% 53.5% 51.9% 40.2%
INCOME STATEMENT:
Depreciation, Depletion, Amortization
and Unproved Property Impairment....... $ 64,354 $ 66,891 $ 45,588 $ 60,165 $ 43,454 $ 52,383
Net Income Available to
Common Stockholders.................... 5,117 8,194 1,902 4,676 23,231 26,240
Basic Earnings Per Share................. $ 0.21 $ 0.33 $ 0.08 $ 0.19 $ 1.00 $ 1.13
15. EARNINGS PER COMMON SHARE
Full year basic earnings per share for the Company were $0.21, $0.08 and
$1.00 in 1999, 1998 and 1997, respectively, and were based on the weighted
average shares outstanding of 24,726,030 in 1999, 24,733,465 in 1998, and
23,272,432 in 1997. Diluted earnings per share for the Company were $0.21, $0.08
and $0.97 in 1999, 1998 and 1997, respectively. The diluted earnings per share
amounts are based on weighted average shares outstanding plus common stock
equivalents. Common stock equivalents include stock awards and stock options,
and totaled 225,177 in 1999, 372,937 in 1998 and 649,632 in 1997.
Both the $3.125 cumulative convertible preferred stock and the 6%
convertible redeemable preferred stock issued May 1993 and May 1994,
respectively, had an antidilutive effect on earnings per common share. The
preferred stock was determined not to be a common stock equivalent when it was
issued. As such, no adjustments were made to reported net income in the
computation of earnings per share. The Company, under the provisions of the
stock, converted the $3.125 cumulative convertible preferred stock to Common
Stock in October 1997. See Note 10 Capital Stock for further discussion.
16. SUBSEQUENT EVENT
The Company was notified by the EPA in February 2000 that it 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 the
Company 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 Company may materially affect the quarterly or
annual financial results, management does not believe it would materially impact
the Company's financial position.
62
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
OIL AND GAS RESERVES
Users of this information should be aware that the process of estimating
quantities of "proved" and "proved developed" natural gas and crude oil reserves
is very complex, requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each reservoir. The
data for a given reservoir may also change substantially over time as a result
of numerous factors including, but not limited to, additional development
activity, evolving production history and continual reassessment of the
viability of production under varying economic conditions. As a result, material
revisions to existing reserve estimates may occur from time to time. Although
every reasonable effort is made to ensure that reserve estimates reported
represent the most accurate assessments possible, the subjective decisions and
variances in available data for various reservoirs make these estimates
generally less precise than other estimates included in the financial statement
disclosures.
Proved reserves represent estimated quantities of natural gas, crude oil
and condensate that geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under
economic and operating conditions in effect when the estimates were made.
Proved developed reserves are proved reserves expected to be recovered
through wells and equipment in place and under operating methods used when the
estimates were made.
Estimates of proved and proved developed reserves at December 31, 1999,
1998 and 1997 were based on studies performed by the Company's petroleum
engineering staff. The estimates were reviewed by Miller and Lents, Ltd., who
indicated in their letter dated February 4, 2000, that based on their
investigation and subject to the limitations described in their letter, they
believe the results of those estimates and projections were reasonable in the
aggregate.
No major discovery or other favorable or unfavorable event after December
31, 1999, is believed to have caused a material change in the estimates of
proved or proved developed reserves as of that date.
The following table illustrates the Company's net proved reserves,
including changes, and proved developed reserves for the periods indicated, as
estimated by the Company's engineering staff. All reserves are located in the
United States.
Natural Gas
-----------------------------
December 31,
(Millions of cubic feet) 1999 1998 1997
- -------------------------------------------------------------------------------
PROVED RESERVES
Beginning of Year.............................. 996,756 903,429 915,617
Revisions of Prior Estimates................... (1,555) (13,097) 6,744
Extensions, Discoveries and Other Additions.... 52,781 94,891 109,191
Production..................................... (65,502) (64,167) (63,889)
Purchases of Reserves in Place................. 26,515 76,234 73,836
Sales of Reserves in Place..................... (79,393) (534) (138,070)
-------- -------- --------
End of Year..................................... 929,602 996,756 903,429
======= ======= =======
PROVED DEVELOPED RESERVES........................ 720,670 788,390 738,764
======= ======= =======
63
Liquids
-----------------------------
December 31,
(Thousands of barrels) 1999 1998 1997
- -------------------------------------------------------------------------------
PROVED RESERVES
Beginning of Year.............................. 7,677 5,869 5,166
Revisions of Prior Estimates................... 128 (1,644) 99
Extensions, Discoveries and Other Additions.... 1,292 835 794
Production..................................... (963) (736) (629)
Purchases of Reserves in Place................. 362 3,353 594
Sales of Reserves in Place..................... (307) -- (155)
-------- -------- --------
End of Year.................................... 8,189 7,677 5,869
======= ======= =======
PROVED DEVELOPED RESERVES........................ 5,546 5,822 4,859
======= ======= =======
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
The following table illustrates the total amount of capitalized costs
relating to natural gas and crude oil producing activities and the total amount
of related accumulated depreciation, depletion and amortization.
Year Ended December 31,
(In thousands) 1999 1998 1997
- -------------------------------------------------------------------------------
Aggregate Capitalized Costs Relating
to Oil and Gas Producing Activities... $1,088,640 $1,107,877 $904,669
Aggregate Accumulated Depreciation,
Depletion and Amortization............ $ 499,201 $ 478,766 $435,502
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND
DEVELOPMENT ACTIVITIES
Costs incurred in property acquisition, exploration and development
activities were as follows:
Year Ended December 31,
(In thousands) 1999 1998 1997
- -------------------------------------------------------------------------------
Property Acquisition Costs, Proved...... $ 18,395 $ 83,584 $ 45,573
Property Acquisition Costs, Unproved.... 7,163 15,587 4,302
Exploration and Extension Well Costs.... 16,117 36,310 28,633
Development Costs 39,239 82,235 53,441
-------- -------- --------
Total Costs............................. $ 80,914 $217,716 $131,949
======== ======== ========
64
HISTORICAL RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES
The results of operations for the Company's oil and gas producing
activities were as follows:
Year Ended December 31,
(In thousands) 1999 1998 1997
- ------------------------------------------------------------------------------
Operating Revenues........................... $156,018 $147,856 $173,865
Costs and Expenses
Production................................. 41,942 38,802 39,068
Other Operating............................ 17,009 20,070 18,017
Exploration................................ 11,490 19,564 13,884
Depreciation, Depletion and Amortization... 62,446 43,127 39,485
-------- -------- --------
Total Costs and Expenses............... 132,887 121,563 110,454
-------- -------- --------
Income Before Income Taxes................... 23,131 26,293 63,411
Provision for Income Taxes................... 8,096 9,203 22,194
-------- -------- --------
Results of Operations........................ $ 15,035 $ 17,090 $ 41,217
======== ======== ========
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO
PROVED OIL AND GAS RESERVES
The following information has been developed utilizing SFAS 69 procedures
and based on natural gas and crude oil reserve and production volumes estimated
by the Company's engineering staff. It can be used for some comparisons, but
should not be the only method used to evaluate the Company or its performance.
Further, the information in the following table may not represent realistic
assessments of future cash flows, nor should the Standardized Measure of
Discounted Future Net Cash Flows be viewed as representative of the current
value of the Company.
The Company believes that the following factors should be taken into
account when reviewing the following information:
- Future costs and selling prices will probably differ from those
required to be used in these calculations.
- Due to future market conditions and governmental regulations, actual
rates of production in future years may vary significantly from the
rate of production assumed in the calculations.
- Selection of a 10% discount rate is arbitrary and may not be a
reasonable measure of the relative risk that is part of realizing
future net oil and gas revenues.
- Future net revenues may be subject to different rates of income
taxation.
Under the Standardized Measure, future cash inflows were estimated by
applying year-end oil and gas prices adjusted for fixed and determinable
escalations to the estimated future production of year-end proved reserves.
The average prices related to proved reserves at December 31, 1999, 1998
and 1997 were for natural gas ($ per Mcf) $2.36, $2.26 and $2.62, respectively,
and for oil ($ per Bbl) $24.15, $10.23 and $19.02, respectively. Future cash
inflows were reduced by estimated future development and production costs based
on year-end costs to arrive at net cash flow before tax. Future income tax
expense was computed by applying year-end statutory tax rates to future pretax
net cash flows, less the tax basis of the properties involved. SFAS 69 requires
the use of a 10% discount rate.
65
Management does not use only the following information when making
investment and operating decisions. These decisions are based on a number of
factors, including estimates of probable as well as proved reserves, and varying
price and cost assumptions considered more representative of a range of
anticipated economic conditions.
Standardized Measure is as follows:
Year Ended December 31,
(In thousands) 1999(1) 1998(1) 1997(1)
- -------------------------------------------------------------------------------
Future Cash Inflows................... $2,401,349 $2,382,860 $2,539,287
Future Production and
Development Costs.................. (786,402) (780,705) (686,689)
---------- ---------- ----------
Future Net Cash Flows Before
Income Taxes....................... 1,614,947 1,602,155 1,852,598
10% Annual Discount for Estimated
Timing of Cash Flows............... (877,129) (863,226) (1,013,837)
---------- ---------- ----------
Standardized Measure of
Discounted Future Net Cash
Flows Before Income Taxes.......... 737,818 738,929 838,761
Future Income Tax Expenses,
Net of 10% Annual Discount (2)..... (150,261) (144,851)(3) (227,796)
---------- ---------- ----------
Standardized Measure of Discounted
Future Net Cash Flows.............. $ 587,557 $ 594,078 $ 610,965
========== ========== ==========
- ----------
(1) Includes the future cash inflows, production costs and development
costs, as well as the tax basis, relating to the properties included
in the transactions to monetize the value of Section 29 tax credits.
See Note 13 of the Notes to the Consolidated Financial Statements.
(2) Future income taxes before discount were $457,256, $446,980 and
$582,639 for the years ended December 31, 1999, 1998 and 1997,
respectively.
(3) Future income tax expense decreased as a result of tax benefits
realized on property acquisitions and drilling activity late in 1998.
66
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES
The following is an analysis of the changes in the Standardized Measure:
Year Ended December 31,
(In thousands) 1999 1998 1997
- --------------------------------------------------------------------------------
Beginning of Year.............................. $594,078 $610,965 $834,306
Discoveries and Extensions,
Net of Related Future Costs................. 65,210 72,275 113,032
Net Changes in Prices and Production Costs..... 1,354 (195,529) (367,112)
Accretion of Discount.......................... 73,893 83,876 116,564
Revisions of Previous Quantity
Estimates, Timing and Other................. (20,162) (36,547) (10,798)
Development Costs Incurred..................... 19,586 20,236 17,435
Sales and Transfers, Net of Production Costs... (114,076) (109,054) (138,274)
Net Purchases (Sales) of Reserves in Place..... (26,916) 64,911 (57,723)
Net Change in Income Taxes..................... (5,410) 82,945 103,535
-------- -------- --------
End of Year.................................... $587,557 $594,078 $610,965
======== ======== ========
CABOT OIL & GAS CORPORATION
SELECTED DATA (UNAUDITED)
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
(In thousands, except
per share amounts) First Second Third Fourth Total
- ---------------------------------------------------------------------------------
1999
Net Operating Revenues.............. $35,280 $41,061 $45,690 $59,842 $181,873
Impairment of Long-Lived Assets..... -- -- -- 7,047 7,047
Operating Income.................... 2,844 8,155 14,061 14,438 39,498
Net Income (Loss)................... (3,293) 110 3,679 4,621 5,117
Basic Earnings (Loss) Per Share..... $ (0.13) $ -- $ 0.15 $ 0.19 $ 0.21
Diluted Earnings (Loss) Per Share... $ (0.13) $ -- $ 0.15 $ 0.19 $ 0.21
1998
Net Operating Revenues.............. $40,791 $41,667 $37,386 $39,762 $159,606
Operating Income.................... 10,714 9,876 1,701 5,112 27,403
Net Income (Loss)................... 2,993 2,283 (2,524) (850) 1,902
Basic Earnings (Loss) Per Share..... $ 0.12 $ 0.09 $ (0.10) $ (0.03) $ 0.08
Diluted Earnings (Loss) Per Share... $ 0.12 $ 0.09 $ (0.10) $ (0.03) $ 0.08
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
67
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information under the caption "Election of Directors" in the Company's
definitive Proxy Statement in connection with the 2000 annual stockholders'
meeting is incorporated by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information under the caption "Executive Compensation" in the
definitive Proxy Statement is incorporated by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information under the captions "Beneficial Ownership of Over Five
Percent of Common Stock" and "Beneficial Ownership of Directors and Executive
Officers" in the definitive Proxy Statement is incorporated by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES AND REPORTS ON FORM 8-K
A. INDEX
1. Consolidated Financial Statements
See Index on page 34.
2. Financial Statement Schedules
None.
3. Exhibits
The following instruments are included as exhibits to this report. Those
exhibits below incorporated by reference herein are indicated as such by the
information supplied in the parenthetical thereafter. If no parenthetical
appears after an exhibit, copies of the instrument have been included herewith.
68
Exhibit
Number Description
- --------------------------------------------------------------------------------
3.1 Certificate of Incorporation of the Company (Registration Statement No.
33-32553).
3.2 Amended and Restated Bylaws of the Company adopted February 20, 1997
(Form S-3 July 1999).
4.1 Form of Certificate of Common Stock of the Company (Registration
Statement No. 33-32553).
4.2 Certificate of Designation for Series A Junior Participating Preferred
Stock (Form 10-K for 1994).
4.3 Rights Agreement dated as of March 28, 1991, between the Company and The
First National Bank of Boston, as Rights Agent, which includes as
Exhibit A the form of Certificate of Designation of Series A Junior
Participating Preferred Stock (Form 8-A, File No. 1-10477).
(a) Amendment No. 1 to the Rights Agreement dated February 24, 1994
(Form 10-K for 1994).
4.4 Certificate of Designation for 6% Convertible Redeemable Preferred Stock
(Form 10-K for 1994).
4.5 Amended and Restated Credit Agreement dated as of May 30, 1995, among
the Company, Morgan Guaranty Trust Company, as agent and the banks named
therein.
(a) Amendment No. 1 to Credit Agreement dated September 15, 1995
(Form 10-K for 1995).
(b) Amendment No. 2 to Credit Agreement dated December 24, 1996
(Form 10-K for 1996).
4.6 Note Purchase Agreement dated May 11, 1990, among the Company and
certain insurance companies parties thereto (Form 10-Q for the quarter
ended June 30, 1990).
(a) First Amendment dated June 28, 1991 (Form 10-K for 1994).
(b) Second Amendment dated July 6, 1994 (Form 10-K for 1994).
4.7 Note Purchase Agreement dated November 14, 1997, among the Company and
the purchasers named therein (Form 10-K for 1997).
10.1 Supplemental Executive Retirement Agreement between the Company and
Charles P. Siess, Jr. (Form 10-K for 1995).
10.2 Form of Change in Control Agreement between the Company and Certain
Officers (Form 10-K for 1995).
10.3 Letter Agreement dated January 11, 1990, between Morgan Guaranty Trust
Company of New York and the Company (Registration Statement No.
33-32553).
10.4 Form of Annual Target Cash Incentive Plan of the Company (Registration
Statement No. 33-32553).
10.5 Form of Incentive Stock Option Plan of the Company (Registration
Statement No. 33-32553).
(a) First Amendment to the Incentive Stock Option Plan
(Post-Effective Amendment No. 1 to S-8 dated April 26, 1993).
10.6 Form of Stock Subscription Agreement between the Company and certain
executive officers and directors of the Company (Registration Statement
No. 33-32553).
10.7 Transaction Agreement between Cabot Corporation and the Company dated
February 1, 1991 (Registration Statement No. 33-37455).
10.8 Tax Sharing Agreement between Cabot Corporation and the Company dated
February 1, 1991 (Registration Statement No. 33-37455).
10.9 Amendment Agreement (amending the Transaction Agreement and the Tax
Sharing Agreement) dated March 25, 1991 (incorporated by reference from
Cabot Corporation's Schedule 13E-4, Am. No. 6, File No. 5-30636).
10.10 Savings Investment Plan & Trust Agreement of the Company (Form 10-K for
1991).
(a) First Amendment to the Savings Investment Plan dated May 21,
1993 (Form S-8 dated November 1, 1993).
(b) Second Amendment to the Savings Investment Plan dated May 21,
1993 (Form S-8 dated November 1, 1993).
(c) First through Fifth Amendments to the Trust Agreement (Form 10-K
for 1995).
(d) Third through Fifth Amendments to the Savings Investment Plan
(Form 10-K for 1996).
69
10.11 Supplemental Executive Retirement Agreements of the Company (Form 10-K
for 1991).
10.12 Settlement Agreement and Mutual Release (Tax Issues) between Cabot
Corporation and the Company dated July 7, 1992 (Form 10-Q for the
quarter ended June 30, 1992).
10.13 Agreement of Merger dated February 25, 1994, among Washington Energy
Company, Washington Energy Resources Company, the Company and COG
Acquisition Company (Form 10-K for 1993).
10.14 1990 Nonemployee Director Stock Option Plan of the Company (Form S-8
dated June 23, 1990).
(a) First Amendment to 1990 Nonemployee Director Stock Option Plan
(Post-Effective Amendment No. 2 to Form S-8 dated March 7,
1994).
(b) Second Amendment to 1990 Nonemployee Director Stock Option Plan
(Form 10-K for 1995).
10.15 Amended and Restated 1994 Long-Term Incentive Plan of the Company (Form
10-K for 1998).
10.16 Amended and Restated 1994 Non-Employee Director Stock Option Plan (Form
10-K for 1998).
10.17 Employment Agreement between the Company and Ray R. Seegmiller dated
September 25, 1995 (Form 10-K for 1995).
10.18 Form of Indemnity Agreement between the Company and Certain Officers
(Form 10-K for 1997).
10.19 Deferred Compensation Plan of the Company (Form 10-K for 1998).
10.20 Trust Agreement dated August 1998 between Bankers Trust Company and the
Company (Form 10-K for 1998).
10.21 Lease Agreement between the Company and DNA COG, Ltd. dated April 24,
1998 (Form 10-K for 1998). 10.22 Credit Agreement dated as of December
17, 1998, between the Company and the banks named therein (Form 10-K for
1998).
10.23 Letter Agreement with Puget Sound Energy Company dated September 21,
1999
21.1 Subsidiaries of Cabot Oil & Gas Corporation.
23.1 Consent of PricewaterhouseCoopers LLP.
23.2 Consent of Miller and Lents, Ltd.
27 Financial Data Schedule.
28.1 Miller and Lents, Ltd. Review Letter dated February 4, 2000.
B. REPORTS ON FORM 8-K
None
70
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized, in the City of Houston, State of Texas,
on the 18th of March 2000.
CABOT OIL & GAS CORPORATION
By: /s/ Ray Seegmiller
-------------------------------------
Ray Seegmiller
Chairman of the Board,
Chief Executive Officer and President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons in the capacities and on
the dates indicated.
Signature Title Date
- --------------------------------------------------------------------------------
/s/ Ray R. Seegmiller Chairman of the Board, Chief March 21, 2000
- --------------------------- Executive Officer and President
Ray R. Seegmiller (Principal Executive Officer)
/s/ Paul F. Boling Vice President, Finance March 21, 2000
- --------------------------- (Principal Financial Officer)
Paul F. Boling
/s/ Henry C. Smyth Controller March 21, 2000
- --------------------------- (Principal Accounting Officer)
Henry C. Smyth
/s/ Robert F. Bailey Director March 21, 2000
- ---------------------------
Robert F. Bailey
/s/ Henry O. Boswell Director March 21, 2000
- ---------------------------
Henry O. Boswell
/s/ John G. L. Cabot Director March 21, 2000
- ---------------------------
John G. L. Cabot
/s/ William R. Esler Director March 21, 2000
- ---------------------------
William R. Esler
/s/ William H. Knoell Director March 21, 2000
- ---------------------------
William H. Knoell
71
/s/ C. Wayne Nance Director March 21, 2000
- ---------------------------
C. Wayne Nance
/s/ P. Dexter Peacock Director March 21, 2000
- ---------------------------
P. Dexter Peacock
/s/ Charles P. Siess, Jr. Director March 21, 2000
- ---------------------------
Charles P. Siess, Jr.
/s/ Arthur L. Smith Director March 21, 2000
- ---------------------------
Arthur L. Smith
/s/ William P. Vititoe Director March 21, 2000
- ---------------------------
William P. Vititoe
72