SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
For the fiscal year ended December 31, 2001
Commission file number 1-10447
CABOT OIL & GAS CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 04-3072771
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
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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
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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.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K [__].
The aggregate market value of Class A Common Stock, par value $.10 per share ("Common Stock"), held by non-affiliates (based upon the closing sales price on the New York Stock Exchange on January 31, 2002), was approximately $636,620,000. As of January 31, 2002, there were 31,905,097 shares of Common Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held May 2, 2002, are incorporated herein by reference in Items 10, 11, 12 and 13 of Part III of this report.
TABLE OF CONTENTS
PART I PAGE
ITEMS 1 and 2 Business and Properties 3
ITEM 3 Legal Proceedings 19
ITEM 4 Submission of Matters to a Vote of Security Holders 21
Executive Officers of the Registrant 21
PART II
ITEM 5 Market for Registrant's Common Equity and Related Stockholder Matters 22
ITEM 6 Selected Historical Financial Data 22
ITEM 7 Management's Discussion and Analysis of Financial Condition
and Results of Operations 23
ITEM 7A Quantitative and Qualitative Disclosures about Market Risk 38
ITEM 8 Financial Statements and Supplementary Data 43
ITEM 9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 78
PART III
ITEM 10 Directors and Executive Officers of the Registrant 78
ITEM 11 Executive Compensation 78
ITEM 12 Security Ownership of Certain Beneficial Owners and Management 78
ITEM 13 Certain Relationships and Related Transactions 78
PART IV
ITEM 14 Exhibits, Financial Statements, Schedules and Reports on Form 8-K 79
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The statements regarding future financial and operating performance and results, market prices, future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "plan," "forecast," "predict," "may," "should," "could" and similar expressions are also intended to identify forward-looking statements. These statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results for future drilling and marketing activity, future production and costs, and other factors detailed in this document and in our other Securities and Exchange Commission filings. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this document.
PART I
ITEM 1. BUSINESS
OVERVIEW
Cabot Oil & Gas is an independent oil and gas company engaged in the exploration, development, acquisition and exploitation of oil and gas properties located in four principal areas of the United States:
. The onshore Texas and Louisiana Gulf Coast
. The Rocky Mountains
. The Mid-Continent or Anadarko Basin
. Appalachia
Administratively, we operate in three regions - the Gulf Coast region, the Western region, which is comprised of the Rocky Mountains and Mid-Continent areas, and the Appalachian region.
In 2001, we enjoyed a strong energy commodity price environment for most of the year bolstered by gains realized on price hedges which were placed on about 44% of our production for the first nine months of 2001 natural gas production near the peak of the market in December 2000. Drilling successes, most notably in south Louisiana, over the past two years served to increase our 2001 production by 12% over 2000. While continuing to develop our existing fields and exploring for new discoveries, we took advantage of our strong cash flow and invested for the future. Most significantly, we acquired Cody Company in August 2001. With this transaction, we expanded and improved our development inventory and added 11 exploration prospects. In addition, we expanded our acreage position with a $12 million acquisition in the Rocky Mountains and added significantly to our seismic database in both the Rocky Mountains and Gulf Coast. The five months of production from the acquired Cody Company properties increased our annual production by an additional 9% over 2000, for a combined 21% production increase year-over-year.
The purchase of Cody Company was the largest acquisition in our Company's history. We paid $231.2 million in cash and common stock for all of the outstanding common stock of Cody Company. Substantially all of the proved reserves of Cody Company are located in the onshore Gulf Coast region, a strategic growth area for us. As of December 31, 2001, these properties contributed 39.1 Mmcfe of production per day and contained 92 proved undeveloped drilling locations.
In 2001, 87% of the wells that we drilled were successful. Drilling was successful on 40% of our 2001 exploration wells, as we tested new ideas and worked on building a foundation for the future. Our 2001 capital and exploration spending included $39.1 million for seismic data and lease acquisition. This spending will support our exploration and development drilling programs in 2002 and beyond. As we enter 2002 energy commodity prices have softened. We will concentrate our 2002 capital spending program on projects offering the prospect of acceptable risk and the strongest economics. As in the past, we will use the cash flow from our long-lived Appalachian and Mid-Continent natural gas reserves to fund our exploration and development efforts in the Gulf Coast and Rocky Mountain areas. We believe these two core producing areas offer more value, accretive reserve and production growth and higher rates of return on equity.
Our proved reserves totaled approximately 1.2 Tcfe at December 31, 2001, of which 90% was natural gas. This reserve level represents a 13% increase over the prior year end. The increase is due primarily to the Cody acquisition, which combined with drilling activities, replaced production by 268%. The Gulf Coast region now represents 26% of our total proved reserves, up from 14% at the end of 2000.
Net income of $47.1 million, or $1.56 per share, was the highest annual level of earnings that we have ever achieved. Cash flow from operations in 2001 of $250.4 million was also a record, and represented a 110% increase over last year. The strong commodity price environment combined with strategic price collars were the main factors in this year's financial success. Production improvements as discussed above also helped boost our earnings. Daily production averaged 199 Mmcfe per day during the first seven months of the year before increasing to approximately
255 Mmcfe per day in August with the acquisition of Cody Company. Overall, including the Cody acquisition and additional successes in south Louisiana, production averaged 222 Mmcfe per day in 2001. Development drilling on the Etouffee field in south Louisiana has expanded producing wells to six, two of which were drilled in 2001. This field, which is now fully developed, remains our largest producer and at December 31, 2001 was producing 137 Mmcfe per day (33 Mmcfe per day net to us).
The following table presents certain information as of December 31, 2001.
West
---------------------------------
Gulf Rocky Mid- Total
Coast Mountains Continent West Appalachia Total
-------- ---------- ---------- -------- ----------- ----------
Proved Reserves at Year End (Bcfe)
Developed 224.1 176.8 171.1 347.9 324.6 896.6
Undeveloped 76.2 50.6 28.0 78.6 102.7 257.5
------- ------- ------- ------- ------- ---------
Total 300.3 227.4 199.1 426.5 427.3 1,154.1
Average Daily Production (Mmcfe per day) 97.8 45.9 30.2 76.1 48.4 222.3
Reserve Life Index (in years) /(1)/ 8.4 13.6 18.1 15.4 24.2 14.2
Gross Wells 1,013 528 695 1,223 2,362 4,598
Net Wells /(2)/ 613.2 233.0 457.7 690.7 2,190.9 3,494.8
Percent Wells Operated 72.1% 49.1% 74.1% 63.3% 96.6% 82.3%
Net Acreage
Developed 103,836 85,058 180,981 266,039 743,204 1,113,079
Undeveloped 44,008 343,565 4,868 348,433 221,316 613,757
------- ------- ------- ------- ------- ---------
Total 147,844 428,623 185,849 614,472 964,520 1,726,836
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GULF COAST REGION
Our exploration, development and production activities in Gulf Coast region are concentrated in south Louisiana and south Texas. A regional office in Houston manages operations. Principal producing intervals are in the Wilcox and Vicksburg formations in Texas and the Miocene age formations in Louisiana at depths ranging from 3,000 to 20,500 feet. Capital and exploration expenditures made with cash and common stock were $352.1 million in 2001 or 78% of our total 2001 capital and exploration expenditures, and $66.0 million for 2000. The cash and common stock portion of the August 2001 acquisition of Cody Company accounted for $231.2 million of this amount, which did not include a non-cash deferred tax gross-up of $78.0 million. Our drilling and acquisition program has increased average daily production in the region from 15.6 Mmcfe per day in 1994, when we acquired our first Gulf Coast properties from Washington Energy, to 131.6 Mmcfe per day in December 2001. Of this production rate, 39.1 Mmcfe per day was associated with the newly acquired Cody properties and the remaining primarily represents production growth from our drilling activity. For 2002, we have budgeted $56.9 million (54% of our total 2002 capital budget) for capital expenditures in the region. Our 2002 Gulf Coast drilling program will emphasize our exploration opportunities and development drilling on the prospects acquired in the Cody acquisition.
We had 1,013 wells (613.2 net) in the Gulf Coast region as of December 31, 2001, of which 730 wells are operated by us. Average net daily production in 2001 was 97.8 Mmcfe, up from 49.5 Mmcfe in 2000 due both to drilling success in south Louisiana and to the Cody acquisition. At December 31, 2001, we had 300.3 Bcfe of proved reserves (67% natural gas) in the Gulf Coast region, which represented 26% of our total proved reserves.
In 2001, we drilled 35 wells (14.7 net) in the Gulf Coast region, of which 20 wells (7.76 net) were development wells. The south Louisiana Etouffee prospect and our new discoveries in the Augen field in south
Louisiana and Red Fish Bay prospects in south Texas, together with the Cody acquisition, contributed to the significant growth in net proved reserves. In the Gulf Coast region, we plan to drill 19 wells in 2002 of which seven are on prospects acquired from Cody.
At December 31, 2001, we had 147,844 net acres in the region, including 103,836 net developed, and we had identified 97 proved undeveloped drilling locations of which 92 were part of the Cody acquisition.
Our principal markets for Gulf Coast region natural gas are in the industrialized Gulf Coast area and the northeastern United States. Our marketing subsidiary, Cabot Oil & Gas Marketing Corporation, purchases all of our natural gas production in the Gulf Coast region. The marketing subsidiary sells the natural gas to intrastate pipelines, natural gas processors and marketing companies.
Currently, approximately 75% of our natural gas sales volumes in the Gulf Coast region are sold at index-based prices under contracts with terms of one to three years. The remaining 25% of our sales volumes are sold at index-based prices under short-term agreements. From time to time when we believe market conditions are favorable, we may implement financial hedges on a portion of our production in an attempt to reduce our exposure to price volatility. The Gulf Coast properties are connected to various processing plants in Texas and Louisiana with multiple interstate and intrastate deliveries, affording us access to multiple markets.
We also produce and market approximately 6,500 barrels per day of crude oil/condensate in the Gulf Coast region at market responsive prices.
WESTERN REGION
Our activities in the Western region are managed by a regional office in Denver. At December 31, 2001, we had 426.5 Bcfe of proved reserves (96% natural gas) in the Western region, constituting 37% of our total proved reserves.
Rocky Mountains
Our Rocky Mountains activities are concentrated in the Green River Basin and Washakie Basin of Wyoming. Since our initial acquisition in the area in 1994 from Washington Energy, we have increased reserves from 171.6 Bcfe at December 31, 1994, to 227.4 Bcfe at December 31, 2001. Capital and exploration expenditures were $42.9 million for 2001, or 9% of our total 2001 capital and exploration expenditures, and $23.9 million for 2000. In addition to drilling activity, approximately $15.4 million was expended in 2001 for lease acquisition and seismic data to provide exploration and development opportunities in the future. For 2002, we have budgeted $19.4 million (19% of our total 2002 capital budget) for capital expenditures in the area. The 2002 drilling program consists of several new exploration plays complemented by development drilling.
We had 528 wells (233.0 net) in the Rocky Mountains area as of December 31, 2001, of which 259 wells are operated by us. Principal producing intervals in the Rocky Mountains area are in the Almond, Frontier and Dakota formations at depths ranging from 9,000 to 13,500 feet. Average net daily production in the Rocky Mountains during 2001 was 45.9 Mmcfe.
In 2001, we drilled 31 wells (15.4 net) in the Rocky Mountains, of which 26 wells (11.5 net) were development and extension wells. In 2002, we plan to drill 41 wells.
At December 31, 2001, we had 428,623 net acres in the area, including 85,058 net developed acres, and we had identified 82 proved undeveloped drilling locations.
Mid-Continent
Our Mid-Continent activities are concentrated in the Anadarko Basin in southwestern Kansas, Oklahoma and the panhandle of Texas. Capital and exploration expenditures were $11.5 million for 2001, or 3% of our total 2001 capital and exploration expenditures, and $7.6 million for 2000. For 2002, we have budgeted $8.2 million (8% of our total 2002 capital budget) for capital expenditures in the area.
As of December 31, 2001, we had 695 wells (457.7 net) in the Mid-Continent area, of which 515 wells are operated by us. Principal producing intervals in the Mid-Continent are in the Chase, Morrow, Red Fork and Chester formations at depths ranging from 1,500 to 14,000 feet. Average net daily production in 2001 was 30.2 Mmcfe. At December 31, 2001, we had 199.1 Bcfe of proved reserves (97% natural gas) in the Mid-Continent area, 17% of our total proved reserves.
In 2001, we drilled 25 wells (17.2 net) in the Mid-Continent, all of which were development and extension wells. In 2002, we plan to drill 17 wells.
At December 31, 2001, we had 185,849 net acres in the area, including 180,981 net developed acres, and we had identified 62 proved undeveloped drilling locations.
Western Region Marketing
Our principal markets for Western region natural gas are in the northwestern, midwestern and northeastern United States. Cabot Oil & Gas Marketing purchases all of our natural gas production in the Western region. This marketing subsidiary sells the natural gas to power generators, natural gas processors, local distribution companies, industrial customers and marketing companies.
Currently, approximately 86% of our natural gas production in the Western region is sold primarily under contracts with a term of one to three years at index-based prices. Another 12% of the natural gas production is sold under short-term arrangements at index-based prices and the remaining 2% is sold under certain fixed-price contracts. From time to time when we believe market conditions are favorable, we may implement financial hedges on a portion of our production in an attempt to reduce our exposure to price volatility.. The Western region properties are connected to the majority of the midwestern and northwestern interstate and intrastate pipelines, affording us access to multiple markets.
In December 1999, we negotiated the buyout of a long-term, fixed price sales contract that covered approximately 20% of the Western region natural gas production and was due to expire in June 2008. We received a payment of $12 million as part of this contract buyout agreement. This contract was then replaced with a fixed price sales contract that expired in April 2001. The fixed natural gas sales price in both the original natural gas sales contract and the replacement sales contract was below the market price at year end 2000. After April 2001, this production was sold at market responsive prices.
We currently also produce and market approximately 600 barrels of crude oil/condensate per day in the Western region at market responsive prices.
APPALACHIAN REGION
Our Appalachian activities are concentrated in West Virginia, Pennsylvania, Ohio and Virginia. In this region, our assets include a large undeveloped acreage position, a high concentration of wells, natural gas gathering and pipeline systems, and storage capacity. We have achieved a drilling success rate of 89% in the region since 1991. Capital and exploration expenditures were $44.1 million for 2001, or 10% of our total 2001 capital spending, and $21.5 million for 2000. For 2002, we have budgeted $18.5 million (18% of our total 2002 capital budget) for capital expenditures in the region.
At December 31, 2001, we had 2,362 wells (2,190.9 net), of which 2,281 wells are operated by us. There are multiple producing intervals that include the Devonian Shale, Oriskany, Berea and Big Lime formations at depths
primarily ranging from 1,500 to 9,000 feet. Average net daily production in 2001 was 48.4 Mmcfe. While natural gas production volumes from Appalachian reservoirs are relatively low on a per-well basis compared to other areas of the United States, the productive life of Appalachian reserves is relatively long. At December 31, 2001, we had 427.3 Bcfe of proved reserves (substantially all natural gas) in the Appalachian region, constituting 37% of our total proved reserves. This region is managed from our office in Charleston, West Virginia.
In 2001, we drilled 117 wells (106.3 net) in the Appalachian region, of which 107 wells (97.0 net) were development wells. In 2002, we plan to drill 44 wells.
At December 31, 2001, we had 964,520 net acres in the region, including 743,204 net developed, and we had identified 292 proved undeveloped drilling locations.
Ancillary to our exploration and production operations, we operate a number of gas gathering and transmission pipeline systems, made up of approximately 2,500 miles of pipeline with interconnects to three interstate transmission systems, seven local distribution companies and numerous end users as of the end of 2001. The majority of our pipeline infrastructure in West Virginia is regulated by the Federal Energy Regulatory Commission (FERC). As such, the transportation rates and terms of service of our pipeline subsidiary, Cranberry Pipeline Corporation, are subject to the rules and regulations of the FERC. Our natural gas gathering and transmission pipeline systems enable us to connect new wells quickly and to transport natural gas from the wellhead directly to interstate pipelines, local distribution companies and industrial end users. Control of our gathering and transmission pipeline systems also enables us to purchase, transport and sell natural gas produced by third parties. In addition, we can engage in development drilling without relying upon third parties to transport our natural gas and incur only the incremental costs of pipeline and compressor additions to our system.
We have two natural gas storage fields located in West Virginia with a combined working capacity of approximately 4 Bcf. We use these storage fields to take advantage of the seasonal variations in the demand for natural gas and the higher prices typically associated with winter natural gas sales, while maintaining production at a nearly constant rate throughout the year. The storage fields also enable us to periodically increase the volume of natural gas that we can deliver by more than 40% above the volume that we could deliver solely from our production in the Appalachian region. The pipeline systems and storage fields are fully integrated with our operations.
In addition, we own and operate two brine treatment plants that process and treat waste fluid generated during the drilling, completion and production of oil and gas wells. The first plant, near Franklin, Pennsylvania, began operating in 1985. It provides services primarily to other oil and gas producers in southwestern New York, eastern Ohio and western Pennsylvania. In April 1998, we acquired a second brine treatment plant in Indiana, Pennsylvania that had been in existence since 1987.
Appalachian Region Marketing
The principal markets for our Appalachian region natural gas are in the northeastern United States. Cabot Oil & Gas Marketing purchases our natural gas production in the Appalachian region as well as production from local third- party producers and other suppliers to aggregate larger volumes of natural gas for resale. This marketing subsidiary sells natural gas to industrial customers, local distribution companies and gas marketers both on and off our pipeline and gathering system.
Approximately 65% of our natural gas sales volume in the Appalachian region is sold at index-based prices under contracts with a term of one to two years. In addition, spot market sales are made under month-to-month contracts, while industrial and utility sales generally are made under year-to-year contracts. Approximately 5% of Appalachian production is sold on fixed price contracts that typically renew annually. From time to time, we may also use financial hedges on a portion of our production to reduce the potential risk of falling prices when we believe market conditions are favorable.
Our Appalachian natural gas production has historically sold at a higher realized price, or premium, compared to production from other producing regions due to its proximity to northeastern markets. While year-to-year fluctuations in that premium are normal due to changes in market conditions, throughout the 1990's this
premium has typically been in the range of $0.40 to $0.50 per Mmbtu above the Henry Hub index spot price as published by Inside FERC's Gas Market Report for gas delivered to this point. This index is the basis for sales price in our standard natural gas sales contract. In 1999, however, the average premium declined to $0.27 per Mmbtu due to increases in supply in the eastern market. This decline continued into early 2000. However, late in 2000 and into 2001, the premium began to increase again due to strengthening of demand and perceived market shortages. The average 2001 premium was approximately $0.34 per Mmbtu. Due to this continued volatility, we are not able to predict the level of this premium for the future.
RISK MANAGEMENT
From time to time, when we believe that market conditions are favorable, we use certain financial instruments called derivatives to manage price risks associated with our production and brokering activities. While there are many different types of derivatives available, in 2001 we primarily employed natural gas and oil price swap and costless collar agreements to attempt to manage price risk more effectively. The price swaps call for payments to, or receipts from, counterparties based on whether the market price of natural gas for the period is greater or less than the fixed price established for that period when the swap is put in place. The costless collar arrangements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price is below the floor.
In December 2000, we entered into certain costless collar arrangements on half of our natural gas production for the months of February through October 2001. We realized revenue of $34.6 million under these arrangements. In December 2001, we again entered into price collar arrangements for 60% of our anticipated natural gas production for the months of January through April 2002. We will continue to evaluate the benefit of employing derivatives in the future. Please read Management's Discussion and Analysis of Financial Condition and Results of Operations - Commodity Price Swaps and Options for further discussion concerning our use of derivatives.
RESERVES
Current Reserves
The following table presents our estimated proved reserves at December 31, 2001.
Natural Gas (Mmcf) Liquids/(1)/ (Mbbl) Total/(2)/(Mmcfe)
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Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total
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Gulf Coast 148,692 53,734 202,426 12,567 3,744 16,311 224,096 76,198 300,294
Rocky Mountains 167,067 47,717 214,784 1,618 482 2,100 176,774 50,610 227,384
Mid-Continent 166,198 27,236 193,434 817 130 947 171,098 28,018 199,116
Appalachia 322,689 102,671 425,360 326 -- 326 324,644 102,671 427,315
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Total 804,646 231,358 1,036,004 15,328 4,356 19,684 896,612 257,497 1,154,109
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/(2)/ Natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural gas liquids.
The proved reserve estimates presented here were prepared by our petroleum engineering staff and reviewed by Miller and Lents, Ltd., independent petroleum engineers. For additional information regarding estimates of proved reserves, the review of such estimates by Miller and Lents, Ltd., and other information about our oil and gas reserves, see the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8. A copy of the review letter by Miller and Lents, Ltd. has been filed as an exhibit to this Form 10-K. Our estimates of proved reserves in the table above are consistent with those filed by us with other federal agencies. Our reserves are sensitive to natural gas and crude oil sales prices and their effect on economic producing rates. Our reserves are based on oil and gas index prices in effect on the last day of December 2001.
There are a number of uncertainties inherent in estimating quantities of proved reserves, including many
factors beyond our control such as commodity pricing. Therefore, the reserve information in this Form 10-K represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that can not be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. In general, the volume of production from oil and gas properties declines as reserves are depleted. Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced.
Historical Reserves
The following table presents our estimated proved reserves for the periods indicated.
Natural Gas Oil & Liquids Total
(Mmcf) (Mbbl) (Mmcfe)/(1)/
--------------------------------------------------------------
December 31, 1998 996,756 7,677 1,042,819
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Revision of Prior Estimates (1,555) 128 (787)
Extensions, Discoveries and
Other Additions 52,781 1,292 60,535
Production (65,502) (963) (71,279)
Purchases of Reserves in Place 26,515 361 28,685
Sales of Reserves in Place (79,393) (306) (81,232)
--------------------------------------------------------------
December 31, 1999 929,602 8,189 978,741
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Revision of Prior Estimates (14,796) 562 (11,423)
Extensions, Discoveries and
Other Additions 103,600 2,032 115,792
Production (60,934) (988) (66,872)
Purchases of Reserves in Place 5,118 120 5,838
Sales of Reserves in Place (3,368) (1) (3,373)
--------------------------------------------------------------
December 31, 2000 959,222 9,914 1,018,703
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Revision of Prior Estimates (44,266) 254 (42,737)
Extensions, Discoveries and
Other Additions 99,911 2,257 113,456
Production (69,162) (1,996) (81,139)
Purchases of Reserves in Place 91,290 9,255 146,819
Sales of Reserves in Place (991) -- (993)
--------------------------------------------------------------
December 31, 2001 1,036,004 19,684 1,154,109
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Proved Developed Reserves
December 31, 1998 788,390 5,822 823,321
December 31, 1999 720,670 5,546 753,944
December 31, 2000 754,962 8,438 805,590
December 31, 2001 804,646 15,328 896,612
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/(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.
Volumes and Prices; Production Costs
The following table presents regional historical information about our net wellhead sales volume for natural gas and oil (including condensate and natural gas liquids), produced natural gas and oil sales prices, and production costs per equivalent.
Year Ended December 31,
2001 2000 1999
-------------------------------------------------------------------------
Net Wellhead Sales Volume
Natural Gas (Bcf)
Gulf Coast 25.6 14.1 15.5
West 26.2 29.0 29.3
Appalachia 17.4 17.8 20.7
Crude/Condensate/Ngl (Mbbl)
Gulf Coast 1,694 669 579
West 267 289 341
Appalachia 35 32 43
Produced Natural Gas Sales Price ($/Mcf)/(1)/
Gulf Coast $ 4.44 $ 3.79 $ 2.29
West 3.88 2.86 1.96
Appalachia 4.96 3.24 2.53
Weighted Average 4.36 3.19 2.22
Crude/Condensate Sales Price ($/Bbl)/(1)/ $24.91 $26.81 $17.22
Production Costs ($/Mcfe)/(2)/ $ 0.72 $ 0.70 $ 0.59
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/(1)/ Represents the average sales prices (net of hedge activity) for all
production volumes (including royalty volumes) sold by Cabot Oil & Gas
during the periods shown net of related costs (principally purchased gas
royalty, transportation and storage).
/(2)/ Production costs include direct lifting costs (labor, repairs and
maintenance, materials and supplies), and the costs of administration of
production offices, insurance and property and severance taxes, but is
exclusive of depreciation and depletion applicable to capitalized lease
acquisition, exploration and development expenditures.
Acreage
The following tables summarize our gross and net developed and undeveloped leasehold and mineral acreage at December 31, 2001. Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.
Leasehold Acreage
Developed Undeveloped Total
-------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
-------------------------------------------------------------------------------------
State
Alabama 1,976 374 -- -- 1,976 374
Colorado 14,263 13,359 190,529 92,799 204,792 106,158
Kansas 29,067 27,765 -- -- 29,067 27,765
Kentucky 2,266 901 -- -- 2,266 901
Louisiana 53,408 41,468 24,314 12,983 77,722 54,451
Michigan 739 205 6,823 6,773 7,562 6,978
Montana 397 210 44,288 33,552 44,685 33,762
New York 2,956 1,117 436 155 3,392 1,272
New Mexico 480 96 -- -- 480 96
North Dakota -- -- 870 96 870 96
Ohio 6,288 2,389 9,225 7,361 15,513 9,750
Oklahoma 161,665 111,923 6,642 3,489 168,307 115,412
Pennsylvania 128,862 78,772 40,916 36,908 169,778 115,680
Texas 153,385 88,781 69,974 32,002 223,359 120,783
Utah 1,740 530 129,044 88,125 130,784 88,655
Virginia 22,195 20,072 7,606 4,981 29,801 25,053
West Virginia 577,372 542,752 170,168 113,241 747,540 655,993
Wyoming 141,733 70,959 197,622 128,912 339,355 199,871
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Total 1,298,792 1,001,673 898,457 561,377 2,197,249 1,563,050
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Mineral Fee Acreage
Developed Undeveloped Total
-------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
-------------------------------------------------------------------------------------
State
Colorado -- -- 160 6 160 6
Kansas 160 128 -- -- 160 128
Louisiana 628 276 -- -- 628 276
Montana -- -- 589 75 589 75
New York -- -- 4,281 1,070 4,281 1,070
Oklahoma 16,580 13,979 400 76 16,980 14,055
Pennsylvania 86 86 2,367 1,296 2,453 1,382
Texas 27 27 652 326 679 353
Virginia 17,817 17,817 100 34 17,917 17,851
West Virginia 97,455 79,093 50,458 49,497 147,913 128,590
--------------------------------------------------------------
Total 132,753 111,406 59,007 52,380 191,760 163,786
==============================================================
Aggregate Total 1,431,545 1,113,079 957,464 613,757 2,389,009 1,726,836
==============================================================
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Total Net Acreage by Region of Operation
Developed Undeveloped Total
--------------------------------------------------------------------
Gulf Coast 103,836 44,008 147,844
West 266,039 348,433 614,472
Appalachia 743,204 221,316 964,520
-------------------------------------------
Total 1,113,079 613,757 1,726,836
===========================================
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Well Summary
The following table presents our ownership at December 31, 2001, in natural gas and oil wells in the Gulf Coast region (consisting of various fields located in Louisiana and Texas), in the Western region (consisting of various fields located in Oklahoma, Kansas, Colorado and Wyoming) and in the Appalachian region (consisting of various fields located in West Virginia, Pennsylvania, Virginia and Ohio). This summary includes natural gas and oil wells in which we have a working interest or a reversionary interest as in the case of certain Section 29 tight sands and Devonian shale wells.
Natural Gas Oil Total
Gross Net Gross Net Gross Net
----------------------------------------------------------
Gulf Coast 613 375.6 400 237.6 1,013 613.2
West 1,152 652.4 71 38.3 1,223 690.7
Appalachia 2,339 2,180.0 23 10.9 2,362 2,190.9
--------------------------------------------
Total 4,104 3,208.0 494 286.8 4,598 3,494.8
============================================
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Drilling Activity
We drilled wells, participated in the drilling of wells, or acquired wells as indicated in the regional tables below.
Year Ended December 31,
2001 2000 1999
--------------------------------------------------------------------
Gross Net Gross Net Gross Net
--------------------------------------------------------------------
Gulf Coast
Development Wells
Successful 18 7.0 14 6.3 10 6.2
Dry 1 0.6 3 1.7 3 3.0
Extension Wells
Successful 1 0.1 -- -- -- --
Dry -- -- -- -- -- --
Exploratory Wells
Successful 8 4.6 4 2.2 2 0.6
Dry 7 2.4 2 1.0 1 0.5
----------------------------------------
Total 35 14.7 23 11.2 16 10.3
========================================
Wells Acquired/(1)/ 600 334.0 1 0.6 2 0.6
Wells in Progress at End
of Period 5 3.6 2 1.1 1 0.3
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Year Ended December 31,
2001 2000 1999
------------------------------------------------------------------------
Gross Net Gross Net Gross Net
------------------------------------------------------------------------
West
Development Wells
Successful 43 24.9 33 22.7 19 9.0
Dry 3 1.5 3 1.0 1 1.0
Extension Wells
Successful 5 2.4 7 3.9 1 0.3
Dry -- -- -- -- -- --
Exploratory Wells
Successful 1 0.8 1 0.3 -- --
Dry 4 3.0 1 0.5 2 1.3
--------------------------------------------
Total 56 32.6 45 28.4 23 11.6
============================================
Wells Acquired/(1)/ 10 0.1 1 0.4 27 10.7
Wells in Progress at End
of Period -- -- 4 2.7 5 2.3
Year Ended December 31,
2001 2000 1999
------------------------------------------------------------------------
Gross Net Gross Net Gross Net
------------------------------------------------------------------------
Appalachia
Development Wells
Successful 102 93.0 47 41.5 26 19.0
Dry 5 4.0 5 4.2 1 0.5
Extension Wells
Successful -- -- -- -- -- --
Dry -- -- -- -- -- --
Exploratory Wells
Successful 3 3.0 5 3.8 3 2.0
Dry 7 6.3 4 2.5 4 2.0
--------------------------------------------
Total 117 106.3 61 52.0 34 23.5
============================================
Wells Acquired/(1)/ 19 19.0 -- -- -- --
Wells in Progress at End
of Period -- -- 3 3.0 1 0.3
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Competition
Competition in our primary producing areas is intense. Price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery records, affect competition. We believe that our extensive acreage position, existing natural gas gathering and pipeline systems and storage fields enhance our competitive position over other producers in the Appalachian region who do not have similar systems or facilities in place. We also believe that our competitive position in the Appalachian region is enhanced by the lack of significant competition from major oil and gas companies. We also actively compete against other companies with substantially larger financial and other resources, particularly in the Western and Gulf Coast regions.
OTHER BUSINESS MATTERS
Major Customer
We had no sales to any customer that exceeded 10% of our total gross revenues in 2001, 2000 or 1999.
Seasonality
Demand for natural gas has historically been seasonal, with peak demand and typically higher prices occurring during the colder winter months.
Regulation of Oil and Natural Gas Exploration and Production
Exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells which may be drilled in a given field, and the unitization or pooling of oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas, and imposing certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas we can produce from our wells, and to limit the number of wells or the locations where we can drill. Because these statutes, rules and regulations undergo constant review and often are amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability. We do not believe, however, we are affected materially differently by these regulations than others in the industry.
Natural Gas Marketing, Gathering and Transportation
Federal legislation and regulatory controls have historically affected the price of the natural gas produced and the manner in which such production is transported and marketed. Under the Natural Gas Act of 1938, the FERC regulates the interstate sale and transportation of natural gas for resale. The FERC's jurisdiction over interstate natural gas sales was substantially modified by the Natural Gas Policy Act of 1978 (NGPA), under which the FERC continued to regulate the maximum selling prices of certain categories of gas sold in "first sales" in interstate and intrastate commerce. Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (Decontrol Act) deregulated natural gas prices for all "first sales" of natural gas, including all sales of our own production. As a result, all of our produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect. The FERC's jurisdiction over natural gas transportation and the sale for resale of natural gas in interstate commerce was not affected by the Decontrol Act.
Natural gas sales are affected by intrastate and interstate gas transportation regulation. Beginning with Order No. 436 in 1985 and continuing through Order No. 636 in 1992, the FERC adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesale marketers of gas to the primary role of gas transporters. Order No. 636 required that interstate pipelines generally cease making sales of natural gas. At the same time, FERC retained its statutory jurisdiction over the sale for resale of natural gas in interstate commerce, but issued to all entities (except interstate pipelines) a blanket certificate to make sales for resale of natural gas in interstate commerce at market based prices. As a result, pipelines divested their gas sales functions to marketing affiliates, which operate separately from the transporter and in direct competition with all other merchants. Interstate pipelines are now required to provide open and nondiscriminatory transportation and transportation-related services to all producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking service. The FERC expanded the impact of open access
regulations to intrastate commerce through its implementation of the NGPA provisions allowing intrastate pipelines to provide service in intrastate commerce on behalf of interstate pipelines.
More recently, the FERC has pursued other policy initiatives that have affected natural gas marketing. Most notable are (1) the large-scale divestiture of interstate pipeline-owned gas gathering facilities to affiliated or non-affiliated companies, which is a result of the FERC's requirement in Order No. 636 that interstate pipelines unbundle gathering services from transportation services, (2) further development of rules governing the relationship of the pipelines with their marketing affiliates, (3) the publication of standards relating to the use of electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information on a timely basis and to enable transactions to occur on a purely electronic basis, and (4) development of policy and promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of-service based rates) for transportation or transportation-related services upon a showing of lack of market control in the relevant service market.
The FERC continued its efforts to develop a competitive natural gas market
with Order No. 637, issued in 2000. Order No. 637 modifies FERC regulations to:
(1) lift the cost-based cap on pipeline transportation rates in the capacity
release market until September 30, 2002, for releases of pipeline capacity for
periods less than one year; (2) permit pipelines to file for authority to charge
different maximum cost-based rates for peak and off-peak periods; (3) encourage
auctions for pipeline capacity; (4) require that pipelines implement imbalance
management services for shippers; (5) restrict the ability of pipelines to
impose penalties for imbalances, overruns, and non-compliance with operational
flow orders; and (6) implement a number of new pipeline reporting requirements
to enhance market transparency. These Order No. 637 requirements are being
implemented by pipelines through individual tariff reform filings. Order No.
637 also requires the FERC Staff to analyze whether the FERC should develop
additional fundamental policy changes, including whether to pursue performance-
based or other non-cost based ratemaking methods and whether the FERC should
mandate greater standardization in terms and conditions of service across the
interstate pipeline grid.
As a result of these changes, sellers and buyers of gas have gained direct access to the particular pipeline services they need and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace.
We can not predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Similarly, it is impossible to predict what proposals, if any, that affect the oil and natural gas_industry might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Similarly, and despite the trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue, or what the ultimate effect will be on our sales of gas, can not be predicted.
Our pipeline systems and storage fields in West Virginia are regulated for safety compliance by the U.S. Department of Transportation and the West Virginia Public Service Commission.
Federal Regulation of Petroleum
Our sales of oil and natural gas liquids are not regulated and are at market prices. The price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. These regulations have generally been approved on judicial review. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. The first such review has been completed and on December 14, 2000, the FERC reaffirmed the current index. We are not able to predict with certainty the effect upon us of these relatively new federal regulations or of the periodic
review by the FERC of the index.
Environmental Regulations
General. Our operations are subject to extensive federal, state and local laws and regulations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Permits are required for the operation of our various facilities. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through fines, injunctions or both. Government regulations can increase the cost of planning, designing, installing and operating oil and gas facilities. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities related to environmental compliance issues are part of oil and gas production operations. No assurance can be given that significant costs and liabilities will not be incurred. Also, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production could result in substantial costs and liabilities to us.
Solid and Hazardous Waste. We currently own or lease, and have in the past owned or leased, numerous properties that were used for the production of oil and gas for many years. Although operating and disposal practices that were standard in the industry at the time may have been utilized, it is possible that hydrocarbons or other solid wastes may have been disposed of or released on or under the properties currently owned or leased by us. State and federal laws applicable to oil and gas wastes and properties have become more strict over time. Under these increasingly stringent requirements, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners and operators) or clean up property contamination (including groundwater contamination by prior owners or operators) or to perform plugging operations to prevent future contamination.
We generate some hazardous wastes that are already subject to the Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The Environmental Protection Agency (EPA) has limited the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. We could, therefore, be subject to more rigorous and costly disposal requirements in the future than we encounter today.
Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of hazardous substances into the environment. These persons include the owner and operator of a site and any party that disposed of or arranged for the disposal of hazardous substances found at a site. CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In the course of business, we have generated and will continue to generate wastes that may fall within CERCLA's definition of hazardous substances. We may also be an owner or operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such wastes have been disposed. See Item 3 Legal Proceedings for a discussion of the Casmalia Superfund Site.
Oil Pollution Act. The federal Oil Pollution Act of 1990 (OPA) and resulting regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The term "waters of the United States" has been broadly defined to include inland water bodies, including wetlands and intermittent streams. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages.
Clean Water Act. The Federal Water Pollution Control Act (FWPCA or Clean Water Act) and resulting regulations, which are implemented through a system of permits, also govern the discharge of certain contaminants into waters of the United States. Sanctions for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease construction or operation of certain facilities that are the source of water discharges. We believe that we comply with the Clean Water Act and related federal and state regulations in all material respects.
Clean Air Act. Our operations are subject to local, state and federal laws and regulations to control emissions from sources of air pollution. Payment of fines and correction of any identified deficiencies generally resolve penalties for failure to comply strictly with air regulations or permits. Regulatory agencies could also require us to cease construction or operation of certain facilities that are air emission sources. We believe that we substantially comply with the emission standards under local, state, and federal laws and regulations.
Employees
As of December 31, 2001, Cabot Oil & Gas had 366 active employees. We recognize that our success is significantly influenced by the relationship we maintain with our employees. Overall, we believe that our relations with our employees are satisfactory. The Company and its employees are not represented by a collective bargaining agreement.
Other
Our profitability depends on certain factors that are beyond our control, such as natural gas and crude oil prices. Please see Items 7 and 7A. We face a variety of hazards and risks that could cause substantial financial losses. Our business involves a variety of operating risks, including blowouts, cratering, explosions and fires, mechanical problems, uncontrolled flows of oil, natural gas or well fluids, formations with abnormal pressures, pollution and other environmental risks, and natural disasters. We conduct operations in shallow offshore areas, which are subject to additional hazards of marine operations, such as capsizing, collision and damage from severe weather.
Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. Any of these events could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. The costs of these insurance policies are somewhat dependent on our historical claims experience and also the areas in which we choose to operate. During the past few years, we have drilled a higher percentage of our wells in the Gulf Coast, where insurance rates are significantly higher than in other regions such as Appalachia. At December 31, 2001, we owned or operated approximately 2,900 miles of natural gas gathering and transmission pipeline systems throughout the United States. As part of our normal maintenance program, we have identified certain segments of our pipelines that we believe may require repair, replacement or additional maintenance and we schedule this maintenance as appropriate.
The sale of our oil and gas production depends on a number of factors beyond our control. The factors include the availability and capacity of transportation and processing facilities. Our failure to access these facilities and obtain these services on acceptable terms could materially harm our business.
ITEM 2. PROPERTIES
See Item 1. Business.
ITEM 3. LEGAL PROCEEDINGS
We are a party to various legal proceedings arising in the normal course of our business. All known liabilities are fully accrued based on management's best estimate of the potential loss. In management's opinion, final judgments or settlements, if any, which may be awarded in connection with any one or more of these suits and claims would not have a significant impact on the results of operations, financial position or cash flows of any period.
Environmental Liability
The EPA notified us in February 2000 of our potential liability for waste material disposed of at the Casmalia Superfund Site ("Site"), located on a 252- acre parcel in Santa Barbara County, California. Over 10,000 separate parties disposed of waste at the Site while it was operational from 1973 to 1992. The EPA stated that federal, state and local governmental agencies along with the numerous private entities that used the Site for disposal of approximately 4.5 billion pounds of waste would be expected to pay the clean-up costs, which are estimated by the EPA to be $271.9 million. The EPA is also pursuing the owners/operators of the Site to pay for remediation.
Documents received by us with the notification from the EPA indicate that we used the Site principally to dispose of salt water from two wells over a period from 1976 to 1979. There is no allegation that we violated any laws in the disposal of material at the Site. The EPA's actions stem from the fact that the owners/operators of the Site do not have the financial means to implement a closure plan for the Site.
A group of potentially responsible parties, including us, formed a group called the Casmalia Negotiating Committee ("CNC"). The CNC has had extensive settlement discussions with the EPA and has reached a settlement in principal to pay approximately $27 million toward Site clean up in return for a release from liability. The CNC is currently negotiating a consent decree to memorialize the settlement. On January 30, 2002, we placed $1,283,283 in an escrow account. This amount approximates our volumetric share of EPA's cost estimate, plus a 5% premium and is our settlement amount. The escrow account is being funded by us and many other CNC members to maximize the likelihood that there will be sufficient funds to fund the settlement agreement upon its completion, which is expected later in 2002. This cash settlement, once released from escrow and paid to the federal government, will resolve all federal claims against us for response costs and will release us from all response costs related to the Site, except for future claims against us for natural resource damage, unknown conditions, transshipment risks and claims by third parties, all of which are expected to be covered by insurance to be purchased by participating CNC members. Responsibility for certain State of California oversight and response costs, while not covered by the settlement or insurance, are not expected to be material. No determination has been made as to whether any insurance arrangement will allow us to recover our contribution to the settlement.
We have established a reserve that management believes to be adequate to provide for this environmental liability based on its estimate of the probable outcome of this matter and estimated legal costs.
Wyoming Royalty Litigation
In June 2000, two overriding royalty owners sued us in Wyoming State court for unspecified damages. The plaintiffs have requested class certification under the Wyoming Rules of Civil Procedure and allege that we have deducted improper costs of production from royalty payments to the plaintiffs and other similarly situated persons. Additionally, the suit claims that we have failed to properly inform the plaintiffs and other similarly situated persons of the deductions taken from royalties. In December 2001, fourteen overriding royalty owners sued us in Wyoming federal court. The plaintiffs in the federal case have made the same general claims pertaining to deductions from their overriding royalty as the plaintiffs in the Wyoming state court case but have not asked for class certification.
Management believes that we have substantial defenses to these claims and intends to vigorously assert such defenses. We have a reserve that we believe is adequate to provide for these potential liabilities based on our estimate of the probable outcome of this matter. While the potential impact to us may materially affect quarterly or annual financial results including cash flows, management does not believe it would materially impact our financial position or results of operations.
West Virginia Royalty Litigation
In late December 2001, two royalty owners sued us in West Virginia State court for an unspecified amount of damages. The plaintiffs have requested class certification under the West Virginia Rules of Civil Procedure and allege that we have failed to pay royalty based upon the wholesale market value of the gas produced, that we have taken improper deductions from the royalty and that we have failed to properly inform the plaintiffs and other similarly situated persons of deductions taken from the royalty.
Although the investigation into this claim has just begun, we intend to vigorously defend the case. We cannot currently determine the likelihood or range of any potential outcome.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the period from October 1, 2001 to December 31, 2001.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information about our executive officers as of February 15, 2002, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, and certain of our other officers.
Name Age Position Officer Since
---------------------------------------------------------------------------------------------------
Ray R. Seegmiller 66 Chairman of the Board and Chief Executive Officer 1995
Dan O. Dinges 48 President and Chief Operating Officer 2001
Michael B. Walen 53 Senior Vice President, Exploration and Production 1998
J. Scott Arnold 48 Vice President, Land and Associate General Counsel 1998
R. Scott Butler 47 Vice President, Regional Manager, Western Region 2001
Robert G. Drake 54 Vice President, Management Information Systems 1998
Abraham D. Garza 55 Vice President, Human Resources 1998
Jeffrey W. Hutton 46 Vice President, Marketing 1995
Lisa A. Machesney 46 Vice President, Managing Counsel and
Corporate Secretary 1995
A. F. (Tony) Pelletier 49 Vice President, Regional Manager, Gulf Coast Region 2001
Scott C. Schroeder 39 Vice President, Chief Financial Officer and Treasurer 1997
Henry C. Smyth 55 Vice President and Controller 1998
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All officers are elected annually by our Board of Directors. Except for the following, all of the executive officers have been employed by Cabot Oil & Gas Corporation for at least the last five years.
Dan O. Dinges joined Cabot Oil & Gas Corporation as President and Chief Operating Officer and as a member of the Board of Directors in September 2001. Mr. Dinges came to Cabot after a 20-year career with Samedan Oil Corporation, a subsidiary of Noble Affiliates, Inc. The last three years, Mr. Dinges served as Samedan's Senior Vice President, as well as Division General Manager for the Offshore Division, a position he held since August 1996. He also served as a member of the Executive Operating Committee for Samedan. Mr. Dinges started his career as a Landman for Mobil Oil Corporation covering Louisiana, Arkansas and the central Gulf of Mexico. After four years of expanding responsibilities at Mobil he joined Samedan as a Division Landman - Offshore. Over the years, Mr. Dinges held positions of increasing responsibility at Samedan including Division Manager, Vice President and ultimately Senior Vice President. Mr. Dinges received his BBA degree in Petroleum Land Management from The University of Texas.
R. Scott Butler has been Vice President, Regional Manager, Western Region since October 2001. Mr. Butler joined Cabot in 1998 as Director of Exploration and was named Regional Manager, Western Region, in February 2001. He came to Cabot following a 19-year career with Chevron where he served in roles of increasing responsibility focusing on exploration in the lower 48 states. Mr. Butler holds a bachelor's degree from Stanford University and a master's from the University of Nevada at Reno, both in geology. He is a member of the American Association of Petroleum Geologists and serves as a director-at-large for the Independent Petroleum Association of Mountain States.
A. F. (Tony) Pelletier has been Vice President, Regional Manager, Gulf Coast Region since October 2001. Mr. Pelletier joined the Company in April 2001 as Regional Manager, Gulf Coast. Before coming to Cabot, he held positions of increasing responsibility at PetroCorp Incorporated, most recently as Executive Vice President and Chief Operating Officer. Prior to that, he worked at Exxon Company USA in a variety of engineering and supervisory capacities. Mr. Pelletier holds a B.S. in Mechanical Engineering and a master's in Civil Engineering, both from Texas A&M University. He is a registered professional engineer in the state of Texas.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Common Stock is listed and principally traded on the New York Stock Exchange under the ticker symbol "COG." The following table presents the high and low closing sales prices per share of the Common Stock during certain periods, as reported in the consolidated transaction reporting system. Cash dividends paid per share of the Common Stock are also shown.
Cash
High Low Dividends
------------------------------------------------
2001
First Quarter $32.00 $25.88 $0.04
Second Quarter 34.20 24.22 0.04
Third Quarter 26.33 16.70 0.04
Fourth Quarter 24.99 18.35 0.04
2000
First Quarter $18.06 $14.19 $0.04
Second Quarter 24.94 16.75 0.04
Third Quarter 21.25 17.38 0.04
Fourth Quarter 31.75 19.00 0.04
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As of January 31, 2002, there were 849 registered holders of the Common Stock. Shareholders include individuals, brokers, nominees, custodians, trustees, and institutions such as banks, insurance companies and pension funds. Many of these hold large blocks of stock on behalf of other individuals or firms.
ITEM 6. SELECTED HISTORICAL FINANCIAL DATA
The following table summarizes selected consolidated financial data for Cabot Oil & Gas for the periods indicated. This information should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations, and the Consolidated Financial Statements and related Notes.
Year Ended December 31,
(In thousands, except per share amounts) 2001 2000 1999 1998 1997
----------------------------------------------------------------------------------------------
Income Statement Data
Operating Revenues $ 447,042 $368,651 $294,037 $251,340 $269,771
Income from Operations 95,366 64,817 39,498 27,403 63,852
Net Income Available to
Common Stockholders 47,084 29,221 5,117 1,902 23,231
Basic Earnings per Share
Available to Common
Stockholders/(1)/ $ 1.56 $ 1.07 $ 0.21 $ 0.08 $ 1.00
Dividends per Common Share $ 0.16 $ 0.16 $ 0.16 $ 0.16 $ 0.16
Balance Sheet Data
Properties and Equipment, Net $ 981,338 $623,174 $590,301 $629,908 $469,399
Total Assets 1,069,031 735,634 659,480 704,160 541,805
Long-Term Debt 393,000 253,000 277,000 327,000 183,000
Stockholders' Equity 346,552 242,505 186,496 182,668 184,062
----------------------------------------------------------------------------------------------
/(1)/See Earnings per Common Share under Note 15 of the Notes to the Consolidated Financial Statements.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying notes included elsewhere in this Form 10-K contain additional information that should be referred to when reviewing this material.
Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. Please read Forward-Looking Information on page 32.
We operate in one segment, natural gas and oil exploration and development.
OVERVIEW
Our financial results depend upon many factors, particularly the price of natural gas and our ability to market our production on economically attractive terms. Price volatility in the natural gas market has remained prevalent in the last few years. In the first quarter of 1999, we experienced a decline in energy commodity prices, resulting in lower revenues and net income during this period. However, in the summer of 1999 and continuing through 2000, prices improved. For the months of April through October 2000, we had certain natural gas hedges in place that prevented us from realizing the full impact of this price environment. (See the Commodity Price Swaps and Options discussion about hedging on page 38.) Despite this limitation, our realized natural gas price for each month in the year 2000 was higher than the same month of any previous year. In the final months of 2000 and into early 2001, the NYMEX futures market reported unprecedented natural gas contract prices. We benefited from this market with our realized natural gas price reaching $5.66 per Mcf in December and $8.46 per Mcf in January 2001. When the NYMEX futures market was near its high on the last day of December 2000, we entered into a series of price collars that protected us from the subsequent price decline until their expiration in October 2001. These price collar arrangements boosted 2001 revenue by $34.6 million, increasing the average realized natural gas price by $0.50 per Mcf. The table below illustrates how natural gas prices have fluctuated over the course of 2001. "Index" represents the Henry Hub index price. The "2001" price is the natural gas price realized by us and it includes the impact of the natural gas price collar arrangements:
(in $ per Mcf) Natural Gas Prices by Month
--------------------------------------------------------------------------------
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
Index 9.91 6.22 5.03 5.35 4.87 3.73 3.16 3.19 2.34 1.86 3.16 2.28
2001 8.46 6.28 4.91 5.05 5.08 4.25 3.96 3.79 3.57 3.24 3.06 2.32
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Prices for crude oil have followed a similar path as the commodity market fell through 2001. The table below contains the West Texas Intermediate index price ("Index") and our realized crude oil prices by month for 2001.
(in $ per Bbl) Crude Oil Prices by Month
--------------------------------------------------------------------------------
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Index 28.66 27.40 26.30 28.46 28.37 26.26 26.35 27.20 23.43 21.18 19.44 19.84
2001 30.32 29.20 26.44 26.31 29.12 27.85 24.72 25.71 24.50 22.85 19.05 19.85
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We reported earnings of $1.56 per share, or $47.1 million, for 2001. This is up from the $1.07 per share, or $29.2 million, reported in 2000. The improvement is a result of the stronger commodity price environment during the year 2001 and the impact of the natural gas price collar arrangements, which combined to push our realized natural gas price up 37% to $4.36 per Mcf. Additionally, natural gas production was up 14% and crude oil sales volumes were up 100% from last year. Overall, on a Mcf equivalent basis, our production grew more than 21% over 2000. A 12% production increase was a result of our drilling successes in 2000 and 2001, and the remaining 9% increase resulted from the acquisition of Cody Company, which was effective August 1, 2001.
A discussion of our results from recurring operations can be found in the Results of Operations section, beginning on page 33. Before taking into account selected items, net income for 2001 was $51.9 million, or $1.71 per share, and $30.2 million, or $1.10 per share for 2000.
In August 2001, we acquired the stock of Cody Company, the parent of Cody Energy LLC ("Cody acquisition") for $231.2 million consisting of $181.3 million of cash and 1,999,993 shares of common stock valued at $49.9 million. Substantially all of the proved reserves of Cody Company are located in the onshore Gulf Coast region. The acquisition was recorded using the purchase method of accounting. As such, the Company reflected the assets and liabilities acquired at fair value in the Company's balance sheet effective August 1, 2001 and the results of operations of Cody Company beginning August 1, 2001. In 2001, these acquired properties contributed 6.2 Bcfe of production, $17.0 million of operating revenue and $19.2 million of operating expenses including $11.6 million of DD&A expense. Additional 2001 costs included $5.3 million of interest expense. These properties contributed $10.3 million in operating cash flow to 2001. The purchase price totaling approximately $315.6 million was allocated to specific assets and liabilities based on certain estimates of fair values, resulting in approximately $302.4 million allocated to property and $13.2 million allocated to working capital items. This $315.6 million was comprised of non-cash common stock consideration of $49.9 million and a non-cash deferred tax gross-up of $78.0 million and acquisition related fees and costs of $6.4 million. The deferred tax gross-up pertains to the deferred income taxes attributable to the differences between the tax basis and the estimated fair value of the acquired oil and gas properties.
We drilled 208 gross wells with a success rate of 87% in 2001 compared to 129 gross wells and an 86% success rate in 2000. Total capital expenditures were $453.4 million for 2001, including $181.3 million in cash and $49.9 million in common stock paid for Cody Company, compared to $122.6 million in 2000. Capital spent in drilling activity increased $39.5 million, with the largest activity increase coming in the Gulf Coast region, where we continued to develop the Etouffee, Augen and Lake Pelto prospects in south Louisiana and initiated new exploration in south Texas. We increased our spending for seismic data, both 2-D and 3-D, and lease acquisition costs both in the Gulf Coast and Rocky Mountains in order to evaluate and expand our drilling opportunities for 2001 and beyond. The largest portion of this spending occurred in December 2001.
Total equivalent production for 2001 was 81.1 Bcfe, an increase of 21% over 2000. Of this increase, 12% resulted from drilling activity and the remaining 9% was a result of the production from the acquired Cody Company properties.
At the end of 2001, our debt-to-total capitalization ratio was 53.1%, up slightly from the end of 2000. This result was achieved despite expending $181.3 million as cash consideration in the Cody acquisition which was sourced primarily by the issuance of $170 million in private placement Notes. During 2000, we improved our debt-to-total capitalization ratio from 61.1% at the end of 1999 to 52.6% at the close of 2000. This improvement was a result of several significant accomplishments. We sold 3.4 million shares of common stock in May 2000 for net proceeds of $71.5 million, of which $51.6 million was used to repurchase all of our preferred stock. The remaining proceeds, along with another $14.8 million from employee stock option exercises, were used to reduce debt and pay dividends. From year end 1999 to year end 2000, we reduced debt by $24 million.
We remain focused on our strategies to grow through the drill bit, concentrating on the highest expected_return opportunities, and from synergistic acquisitions. We believe these strategies are appropriate in the current industry environment, enabling us to add shareholder value over the long term.
The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. Please read Forward-Looking Information on page 32.
FINANCIAL CONDITION
Capital Resources and Liquidity
Our capital resources consist primarily of cash flows from our oil and gas properties and asset-based borrowing supported by oil and gas reserves. Our level of earnings and cash flows depends on many factors, including the price of natural gas and oil, our ability to find and produce hydrocarbons and our ability to control and reduce costs. Demand for
natural gas has historically been subject to seasonal influences characterized by peak demand and higher prices in the winter heating season. However, in the summer of 2000, our realized gas prices began to climb to unseasonably high levels and by January 2001, we realized the highest prices in the Company's history. Then in 2001, our realized natural gas price declined throughout the year to a low of $2.32 per Mcf in December. A mild winter and the economic recession may be contributing factors in the 2001 pricing volatility.
The primary sources of cash during 2001 were funds generated from operations, proceeds from the issuance of Notes (see Note 5 of the Notes to the Consolidated Financial Statements) and, to a lesser extent, proceeds from the sale of stock. Funds were used primarily for exploration and development expenditures, including the acquisition of Cody Company in August 2001, and dividend payments.
We had a net cash outflow of $1.9 million during 2001. The net cash inflow from operating activities of $250.4 million combined with the increase in debt of $124.0 million to substantially fund the $386.1 million of cash used for capital and exploration expenditures. Cash proceeds from the sales of non- strategic assets and the sale of stock combined to provide an additional $14.6 million of cash flow.
(In millions) 2001 2000 1999
------------------------------------------------------------------------
Cash Flows Provided by Operating Activities $250.4 $119.0 $92.5
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Cash flows provided by operating activities in 2001 were $131.4 million higher than in 2000 and cash flows provided by operating activities in 2000 were $26.5 million higher than in 1999. These improvements were primarily a result of increased revenues from higher realized commodity prices and to a lesser extent to increased natural gas and oil production.
(In millions) 2001 2000 1999
------------------------------------------------------------------------
Cash Flows Used by Investing Activities $(379.2) $(116.1) $(37.4)
--------------------------
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Cash flows used by investing activities in 2001 included the $181.3 million cash portion of the Cody Company acquisition. Additionally, capital spending for drilling and facilities increased $39.5 million, or 49%, from last year to $119.5 million. We drilled 208 gross wells, which represents a 61% increase over 2000.
Cash flows used by investing activities in 2000 were attributable to capital and exploration expenditures of $119.2 million, offset by the receipt of $3.1 million in proceeds received from the sale of non-strategic oil and gas properties.
Cash flows used by investing activities in 1999 were attributable to capital and exploration expenditures of $93.7 million, offset by the receipt of $56.3 million in proceeds received from the sale of non-strategic oil and gas properties.
(In millions) 2001 2000 1999
------------------------------------------------------------------------
Cash Flows Provided (Used) by Financing Activities $126.9 $3.0 $(55.6)
--------------------
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Cash flows provided by financing activities in 2001 included the impact of issuing $170 million in a private placement of Notes in July 2001 used to partially fund the Cody Company acquisition. Partially offsetting this debt increase was the reduction to the balance outstanding on the revolving credit facility and the May 2001 prepayment of $16 million in debt that was due in May 2002.
Cash flows provided by financing activities in 2000 included $85.1 million in proceeds received from the sale of common stock, both in a block trade and through the exercise of employee stock options. Of the proceeds, $51.6 million was used to repurchase all of the outstanding shares of preferred stock. Additional cash used in financing activities included $24 million used to reduce the year-end debt balance to $269 million from $293 million in 1999 and cash used to pay dividends to stockholders.
Cash flows used by financing activities in 1999 included $50 million used to reduce the year-end debt balance to $293 million from $343 million in 1998 and cash used to pay cash dividends to stockholders.
We have a revolving credit facility with a group of banks, the revolving term of which runs to December 2003. The available credit line under this facility, currently $250 million, is subject to adjustment on the basis of the present value of estimated future net cash flows from proved oil and gas reserves (as determined by the banks' petroleum engineer) and other assets. Accordingly, oil and gas prices are an important part of this computation. Since the current price environment remains volatile, management can not predict how future price levels may change the banks' long-term price outlook. To reduce the impact of any redetermination, we strive to manage our debt at a level below the available credit line in order to maintain excess borrowing capacity. At year end, this excess capacity totaled $127 million, or 51% of the total available credit line. Management believes it has the ability to finance, if necessary, our capital requirements, including acquisitions. Oil and gas prices also affect the calculation of the financial ratios for debt covenant compliance. Please read Note 5 of the Notes to the Consolidated Financial Statements for a more detailed discussion of our revolving credit facility.
In the event that the available credit line is adjusted below the outstanding level of borrowings, we have a period of 180 days to reduce our outstanding debt to the adjusted credit line. The revolving credit agreement also includes a requirement to pay down half of the debt in excess of the adjusted credit line within the first 90 days of any adjustment.
Our 2002 interest expense is expected to be approximately $29.2 million, including interest on the $170 million 7.33% weighted average fixed rate notes used to partially fund the acquisition of Cody Company. In May 2001, a $16 million principal payment was made on the 10.18% Notes. This amount had been reflected as "Current Portion of Long-Term Debt" on the balance sheet. Additionally, the final $16 million payment on these notes that was due in May 2002 was paid in May 2001 using existing capacity on the revolving credit agreement.
Capitalization
Our capitalization information is as follows:
As of December 31,
(In millions) 2001 2000 1999
----------------------------------------------------------------------------
Long-Term Debt $393.0 $253.0 $277.0
Current Portion of Long-Term Debt -- 16.0 16.0
----------------------
Total Debt $393.0 $269.0 $293.0
======================
Stockholders' Equity
Common Stock (net of Treasury Stock) $346.6 $242.5 $129.8
Preferred Stock -- -- 56.7
----------------------
Total Equity 346.6 242.5 186.5
----------------------
Total Capitalization $739.6 $511.5 $479.5
======================
Debt to Capitalization 53.1% 52.6% 61.1%
----------------------
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During 2001, dividends were paid on our common stock totaling $4.8 million. We have paid quarterly common stock dividends of $0.04 per share since becoming publicly traded in 1990. The amount of future dividends is determined by our Board of Directors and is dependent upon a number of factors, including future earnings, financial condition and capital requirements.
In May 2000, we bought back all of the shares of preferred stock from the holder for $51.6 million. Since this stock had been recorded at a stated value of $56.7 million on our balance sheet, we realized a negative dividend to preferred stockholders of $5.1 million. We received net proceeds of $71.5 million from the sale of 3.4 million shares of common stock in a public offering primarily to fund this transaction. After repurchasing the preferred stock, the excess proceeds were used to reduce debt.
Capital and Exploration Expenditures
On an annual basis, we generally fund most of our capital and exploration activities, excluding major oil and gas property acquisitions, with cash generated from operations. We budget these capital expenditures based on our projected cash flows for the year.
The following table presents major components of our capital and exploration expenditures for the three years ended December 31, 2001.
(In millions) 2001 2000 1999
----------------------------------------------------------------------
Capital Expenditures
Drilling and Facilities $119.5 $ 80.0 $43.9
Leasehold Acquisitions 12.9 10.9 7.2
Pipeline and Gathering 3.8 3.2 3.8
Other 1.9 2.6 3.3
-------------------------------
138.1 96.7 58.2
-------------------------------
Proved Property Acquisitions 244.1/(1)/ 6.0 18.4
Exploration Expenses 71.2 19.9 11.5
-------------------------------
Total $453.4 $122.6 $88.1
===============================
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Total capital and exploration expenditures for 2001 increased $330.8 million compared to 2000, primarily as a result of the $231.2 million Cody acquisition. The remaining increase of $99.6 million was due primarily to increased drilling activity as well as increases in leasehold acquisitions costs consistent with our future drilling plans. The 2001 drilling program included an over 68% increase in net wells drilled and a $15.3 million increase in geological and geophysical expenses, including costs of obtaining seismic data that supports future drilling programs.
We plan to drill 121 gross wells in 2002 compared with 208 gross wells drilled in 2001. This 2002 drilling program includes $104.6 million in total capital and exploration expenditures, down from $453.4 million in 2001, which was our largest capital program to date. Expected spending in 2002 includes $62.6 million for drilling and dry hole exposure, $7.8 million for lease acquisition and $9.9 million in geological and geophysical expenses. In addition to the drilling and exploration program, other 2002 capital expenditures are planned primarily for production equipment and for gathering and pipeline infrastructure maintenance and construction. We will continue to assess the natural gas price environment and may increase or decrease the capital and exploration expenditures accordingly.
Contractual Obligations
We are committed to making cash payments in the future on two types on contracts: Note agreements and leases. We have no off-balance sheet debt or other such unrecorded obligations and we have not guaranteed the debt of any other party. Below is a schedule of the future payments that we were obligated to make based on agreements in place as of December 31, 2001.
Payments Due by Year
2003 2005 2007 &
(in thousands) Total 2002 to 2004 to 2006 Beyond
--------------------------------------------------------------------------------------------------------------
Long-Term Debt /(1)/ $393,000 $ -- $123,000 $40,000 $230,000
Operating Leases /(2)/ 29,843 5,194 8,555 7,474 8,620
-------- ------ -------- ------- --------
Total Contractual Cash Obligations $422,843 $5,194 $131,555 $47,474 $238,620
--------------------------------------------------------------------------------------------------------------
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/(1)/ The $123 million shown as scheduled for payment in 2003 represents
the December 31, 2001 balance outstanding on the revolving credit
facility. Typically, we are able to replace this credit agreement
with a new one as this comes due. See discussion in Note 5 of the
Notes to the Consolidated Financial Statements.
/(2)/ A discussion of operating leases can be found in Note 8 of the
Notes to the Consolidated Financial Statements. We have no capital
leases.
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Potential Impact of Our Critical Accounting Policies
Readers of this document and users of the information contained in it should be aware of how certain events may impact our financial results based on the accounting policies in place. The three most significant policies are discussed below.
Commodity Pricing and Risk Management Activities
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and, to a lesser extent, oil. Declines in oil and gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil and gas prices also may reduce the amount of oil and gas that we can produce economically. Historically, oil and gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results. In particular, substantially lower prices would significantly reduce revenue and could potentially impact the outcome of our annual impairment test under SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" when adopted. Because our reserves are predominantly natural gas, changes in natural gas prices may have a particularly large impact on our financial results.
The majority of production is sold at market responsive prices. Generally, if the commodity indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. However, management may mitigate this price risk in a number of ways. Most recently, we have used financial instruments such as natural gas price collar arrangements to reduce the impact of declining pricing on our revenue. Under a price collar arrangement, there is also risk that the index prices will rise above the ceiling price and the Company will not be able to realize the full benefit of the market improvement.
We covered 16% of our production in 2000 with natural gas price collar arrangements and prices rose above the ceiling during some months. If we had not had these collars in place in 2000, our realized natural gas price would have been $0.17 per Mcf higher. In 2001, we covered 35% of our natural gas production with price collar arrangements and prices were below the floor for several months. The gains from the 2001 price collars improved our annual realized natural gas price by $0.50 per Mcf.
Successful Efforts Method of Accounting
We use the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including seismic purchases and processing, exploratory dry hole drilling costs and costs of carrying and retaining unproved properties are expensed as incurred. During 2001, we drilled 30 exploratory wells and 18 of them were unsuccessful, adding $37.9 million to exploration expense. This 40% success rate for exploratory wells is not unusual, and as we focus more on our exploration program, we are exposed to the risk of dry hole expense. Development costs, including the costs to drill and equip development wells, and successful exploratory drilling costs to locate proved reserves are capitalized.
We are also exposed to potential impairments if the book value of our assets exceeds their future expected cash flows. This may occur if a field discovers lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows on the field. We determine if an impairment has occurred through either adverse changes or as a result of the annual review of all fields. The impairment of unamortized capital costs is measured at a lease level and is reduced to fair value if it is determined that the sum of expected future net cash flows is less than the net book value.
Oil and Gas Reserves
The process of estimating quantities of proved reserves is inherently uncertain, and the reserve data included in this document are only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and crude oil that cannot be measured in an exact manner. The process relies on interpretations of available geologic, geophysic, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:
. the quality and quantity of available data;
. the interpretation of that data;
. the accuracy of various mandated economic assumptions; and
. the judgment of the persons preparing the estimate.
Our proved reserve information included in this document is based on estimates we prepared. Estimates prepared by others may be higher or lower than our estimates.
Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of natural gas and crude oil that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.
You should not assume that the present value of future net cash flows is the current market value of our estimated proved natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.
Our rate of recording depreciation, depletion and amortization expense (DD&A) is dependent upon our estimate of proved reserves. If the estimates of proved reserves declines, the rate at which we record DD&A expense increases, reducing net income. Such a decline may result from lower market prices, which may make it non-economic to drill for and produce higher cost fields. In addition, the decline in proved reserve estimates may impact the outcome of our annual impairment test under SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" when adopted.
Operating Risks and Insurance Coverage
Our business involves a variety of operating risks, including:
. blowouts, cratering and explosions;
. mechanical problems;
. uncontrolled flows of oil, natural gas or well fluids;
. fires;
. formations with abnormal pressures;
. pollution and other environmental risks; and
. natural disasters.
The operation of our natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks. Any of these events could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. The costs of these insurance policies are somewhat dependent on our historical claims experience and also the areas in which we choose to operate. During the past few years, we have drilled a higher percentage of our wells in the Gulf Coast, where insurance rates are significantly higher than in other regions such as Appalachia.
OTHER ISSUES AND CONTINGENCIES
Corporate Income Tax. We generate tax credits for the production of certain qualified fuels, including natural gas produced from tight sands formations and Devonian Shale. The credit for natural gas from a tight sand formation (tight gas sands) amounts to $0.52 per Mmbtu for natural gas sold prior to 2003 from qualified wells drilled in 1991 and 1992. A number of wells drilled in the Appalachian region and Rocky Mountains during 1991 and 1992 qualified for the tight gas sands tax credit. The credit for natural gas produced from Devonian Shale is estimated to be $1.08 per Mmbtu in 2001. In 1995 and 1996, we completed three transactions to monetize the value of these tax credits, resulting in revenues of $2.0 million in 2001 and an estimated $2.1 million in 2002. See Note 13 of the Notes to the Consolidated Financial Statements for further discussion.
We have benefited in the past and may benefit in the future from the alternative minimum tax (AMT) relief granted under the Comprehensive National Energy Policy Act of 1992 (the Act). The Act repealed provisions of the AMT requiring a taxpayer's alternative minimum taxable income to be increased on account of certain intangible drilling costs (IDC) and percentage depletion deductions. The repeal of these provisions generally applies to taxable years beginning after 1992. The repeal of the excess IDC preference can not reduce a taxpayer's alternative minimum taxable income by more than 40% of the amount of such income determined without regard to the repeal of such preference.
Regulations. Our operations are subject to various types of regulation by federal, state and local authorities. See Regulation of Oil and Natural Gas Production and Transportation and Environmental Regulations in the Other Business Matters section of Item 1 Business for a discussion of these regulations.
Restrictive Covenants. Our ability to incur debt and to make certain types of investments is subject to certain restrictive covenants in the Company's various debt instruments. Among other requirements, our Revolving Credit Agreement and the Notes (see Note 5 of the Notes to the Consolidated Financial Statements) specify a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. At December 31, 2001, the calculated ratio for 2001 was 10.0 to 1.0. In the unforeseen event that we fail to comply with these covenants, the Company may apply for a temporary waiver with the bank, which, if granted, would allow us a period of time to remedy the situation. See further discussion in Capital Resources and Liquidity and Note 5 of the Notes to the Consolidated Financial Statements for further discussion.
CONCLUSION
Our financial results depend upon many factors, particularly the price of natural gas and oil and our ability to market gas on economically attractive terms. The average produced natural gas sales price received by us has changed from year-to-year as follows:
2001: increased 37% over 2000 to $4.36 per Mcf 2000: increased 44% over 1999 to $3.19 per Mcf 1999: increased 3% over 1998 to $2.22 per Mcf 1998: decreased 15% from 1997 to $2.16 per Mcf 1997: increased 8% over 1996 to $2.53 per Mcf
The volatility of natural gas prices in recent years remains prevalent in 2002 with wide price swings in day-to-day trading on the NYMEX futures market. Given this continued price volatility, we can not predict with certainty what pricing levels will be in the future. Because future cash flows are subject to these variables, there is no assurance that our operations will provide cash sufficient to fully fund our planned capital expenditures.
While our 2002 plan now includes $104.6 million in capital and exploration spending, we will periodically assess industry conditions and adjust our 2002 spending plan to ensure the adequate funding of our capital requirements, including, if necessary, reductions in capital and exploration expenditures or common stock dividends. We believe our capital resources, supplemented with external financing if necessary, are adequate to meet our capital requirements.
The preceding paragraphs contain forward-looking information. See Forward- Looking Information on page 32.
Recently Issued Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statements of Financial Accounting Standards No. 141 "Business Combinations"
("SFAS 141") and No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142").
SFAS 141 requires all business combinations initiated after June 30, 2001 to be
accounted for under the purchase method. For all business combinations for which
the date of acquisition is after June 30, 2001, SFAS 141 also establishes
specific criteria for the recognition of intangible assets separately from
goodwill. SFAS 141 also requires unallocated negative goodwill (in a case where
the purchase price is less than fair market value of the acquired assets) to be
written off immediately as an extraordinary gain, rather than deferred and
amortized. SFAS 142 changes the accounting for goodwill and other intangible
assets after an acquisition. The most significant changes made by SFAS 142 are:
1) goodwill and intangible assets with indefinite lives will no longer be
amortized; 2) goodwill and intangible assets with indefinite lives must be
tested for impairment at least annually; and 3) the amortization period for
intangible assets with finite lives will no longer be limited to forty years.
The Company does not believe that the adoption of these statements will have a
material effect on its financial position, results of operations, or cash flows.
In June 2001, the FASB also approved for issuance SFAS 143 "Asset Retirement Obligations." SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets such as wells and production facilities. SFAS 143 guidance covers (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long- lived asset and subsequently allocated to expense using a systematic and rational method. The Company will adopt the statement effective no later than January 1, 2003, as required. The transition adjustment resulting from the adoption of SFAS 143 will be reported as a cumulative effect of a change in accounting principle. At this time, the Company cannot reasonably estimate the effect of the adoption of this statement on its financial position, results of operations, or cash flows.
In August 2001, the FASB also approved SFAS 144, "Accounting for the Impairment or Disposal of Long-
Lived Assets" ("SFAS 144"). SFAS 144 replaces SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." The new accounting model for long-lived assets to be disposed of by sale applies to all long-lived assets, including discontinued operations, and replaces the provisions of APB Opinion No. 30, "Reporting Results of Operations-Reporting the Effects of Disposal of a Segment of a Business", for the disposal of segments of a business. SFAS 144 requires that those long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. Therefore, discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. SFAS 144 also broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The provisions of SFAS 144 are effective for financial statements issued for fiscal years beginning after December 15, 2001 and, generally are to be applied prospectively. At this time, the Company cannot estimate the effect of this statement on its financial position, results of operations, or cash flows.
* * *
Forward-Looking Information
The statements regarding future financial and operating performance and results, market prices, future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "plan," "forecast," "predict," "may," "should," "could" and similar expressions are also intended to identify forward-looking statements. 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.
Selected Financial and Operating Data
(In millions except where specified) 2001 2000 1999
------------------------------------------------------------------
Operating Revenues $447.0 $368.7 $294.0
Operating Expenses 351.7 303.8 258.5
Operating Income 95.4 64.8 39.5
Interest Expense 20.8 22.9 25.8
Net Income 47.1 29.2 5.1
Earnings Per Share - Basic $ 1.56 $ 1.07 $ 0.21
Earnings Per Share - Diluted $ 1.53 $ 1.06 $ 0.21
Natural Gas Production (Bcf)
Gulf Coast 25.6 14.1 15.5
West 26.2 29.0 29.3
Appalachia 17.4 17.8 20.7
----------------------
Total Company 69.2 60.9 65.5
Produced Natural Gas Sales Price ($/Mcf)
Gulf Coast $ 4.44 $ 3.79 $ 2.29
West 3.88 2.86 1.96
Appalachia 4.96 3.24 2.53
Total Company $ 4.36 $ 3.19 $ 2.22
Crude/Condensate
Volume (Mbbl) 1,908 953 929
Price ($/Bbl) $24.91 $26.81 $17.22
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The table below presents the after-tax effects of certain selected items on our results of operations for the three years ended December 31, 2001.
(In millions) 2001 2000 1999
----------------------------------------------------------------
Net Income Before Selected Items $ 51.9 $ 30.2 $ 0.4
Change in Derivative Fair Value 0.1
Severance Tax Refund 0.7
Buyout of Gas Sales Contract 7.3
Impairment of Long-Lived Assets (4.2) (5.6) (4.3)
Gain on Sale of Assets 2.4
Section 29 Tax Credit Provision (0.7)
Negative Preferred Stock Dividend 5.1
Contract Settlements 1.4
Bad Debt Expense (1.4) (1.3)
Severance Costs (0.6)
----------------------
Net Income $ 47.1 $ 29.2 $ 5.1
======================
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These selected items impacted our financial results. Because they are not a part of our normal business, we have isolated their effects in the table above. These selected items for 2001 were as follows:
. The change in derivative fair value 2001 related to the adoption of SFAS 133 on January 1, 2001. See Note 11 of the Notes to the Consolidated Financial Statements for further discussion.
. A severance tax refund of $0.7 million ($1.1 million pre-tax) was received in the third quarter for taxes
previously paid in Louisiana that recently qualified for the Severance Tax Relief Program as deep wells.
. A total impairment of $4.2 million ($6.9 million pre-tax) recorded in 2001. Two fields in the Gulf Coast region were impaired in the third quarter since the cost capitalized exceeded the future undiscounted cash flows. Also, one natural gas processing plant in the Rocky Mountains area was written down to fair market value. In the fourth quarter, the Starpath prospect in the Gulf Coast region was impaired.
. As a result of the Enron bankruptcy, we recorded $1.4 million ($2.3 million pre-tax) of bad debt expense primarily related to physical natural gas sales made to Enron in November 2001.
These selected items for 2000 were as follows:
. A $9.1 million impairment ($5.6 million after tax) was recorded on the Beaurline field in south Texas as a result of a casing collapse in two of the field's wells.
. As a result of repurchasing all of the preferred stock at less than the book value, we recorded a $5.1 million negative stock dividend in May 2000.
. Miscellaneous net revenue, primarily from the settlement of a natural gas sales contract, was recorded in the first quarter ($1.4 million after tax). See Note 13 of the Notes to the Consolidated Financial Statements for further discussion.
. As a result of bankruptcy proceedings of two of our customers, we recorded $2.1 million in bad debt expense in the fourth quarter ($1.3 million after tax).
. We announced the closure of the regional office in Pittsburgh in May 2000 and recorded costs of $1.0 million ($0.6 million after tax). These costs were recorded in the income statement categories that will receive the future savings benefit ($0.6 million in operations, $0.1 million in exploration and $0.3 million in administration).
These selected items for 1999 were as follows:
. We had a 15-year cogeneration contract under which we sold approximately 20% of our Western region natural gas per year. The contract was due to expire in 2008, but during 1999 we reached an agreement with the counterparty under which the counterparty bought out the remainder of the contract for $12 million. This transaction, completed in December 1999, accelerated the realization of any future price premium that may have been associated with the contract and added $12 million of pre-tax other revenue ($7.3 million after tax). We simultaneously sold forward a similar quantity of Western region gas production through April 2001 at similar prices to those in the old contract. The natural gas sales price stated in this new contract was significantly below year-end 2000 market prices in the region. See Note 13 of the Notes to the Consolidated Financial Statements for further discussion.
. In the fourth quarter of 1999, we recorded impairments totaling $7 million on two of our producing fields in the Gulf Coast region ($4.3 million after tax). The Chimney Bayou field was impaired by $6.6 million due to a significant reserve revision on the Broussard- Middleton #1R well in connection with a decline in its natural gas production accompanied by a marked increase in water production. The Broussard-Middleton #1R was the only producing well in this field. The Lawson field was impaired by $0.4 million due to an unsuccessful workover on one of its wells.
. We recorded a $4 million gain on the sale of certain non-strategic oil and gas assets, most notably the Clarksburg properties in the Appalachian region sold to EnerVest effective October 1999 ($2.4 million after tax).
. We recorded a $1.2 million reserve against other revenue for certain wells no longer deemed to be eligible for the Section 29 tight gas sands credit following an industry tax court ruling ($0.7 million after tax). Late in 1999, the FERC issued a rule proposal that may ultimately restore the eligibility for some or all of the wells in question. For an update on the FERC's actions, please read Note 13 of the Notes to the Consolidated Financial Statements.
2001 and 2000 Compared
The following discussion is based on our results before taking into account the selected items discussed above.
Net Income and Revenues. We reported net income in 2001 of $51.9 million, or $1.71 per share. During 2000, we reported net income of $30.2 million, or $1.10 per share. Operating income increased $28.5 million, or 38%, and operating revenues increased $80.6 million, or 22%, in 2001. The improvement in operating revenues was mainly a result of the $107.3 million rise in natural gas sales due to the increases in both natural gas prices and production, and the $22.0 million increase in crude oil sales revenue. Natural gas revenue and our realized price were bolstered by a $34.6 million gain on natural gas price collar arrangements used during 2001. See further discussion in Item 7A. These improvements were partially offset by a decline in brokered natural gas volume that reduced operating revenues by $50.4 million. Operating income was similarly impacted by these revenue changes.
The average Gulf Coast natural gas production sales price rose $0.65 per Mcf, or 17%, to $4.44, increasing operating revenues by approximately $16.6 million. In the Western region, the average natural gas production sales price increased $1.02 per Mcf, or 36%, to $3.88, increasing operating revenues by approximately $26.7 million. The average Appalachian natural gas production sales price increased $1.72 per Mcf, or 53%, to $4.96, increasing operating revenues by approximately $29.9 million. The overall weighted average natural gas production sales price increased $1.17 per Mcf, or 37%, to $4.36 per Mcf in 2001.
Natural gas production volume in the Gulf Coast region was up 11.5 Bcf, or 82%, to 25.6 Bcf primarily due to production from our discoveries in south Louisiana and production from the Cody Company properties acquired in August 2001. Natural gas production volume in the Western region was down 2.8 Bcf, or 10%, to 26.2 Bcf due primarily to lower levels of drilling activity in the Mid-Continent area during the past three years. Natural gas production volume in the Appalachian region was down 0.4 Bcf, or 2%, to 17.4 Bcf, as a result of lower than anticipated success of the Oriskany drilling program in the region in late 2000 and into 2001. Total natural gas production was up 8.3 Bcf, or 14%, in 2001.
Crude oil prices fell $1.90 per Bbl, or 7%, to $24.91, resulting in a decrease to operating revenues of approximately $3.6 million. The volume of crude oil sold in the year doubled to 1,908 Mbbls, increasing operating revenues by $25.6 million. This production increase was a result of our 2000 drilling success in south Louisiana (80% increase) and the acquisition of Cody Company (20% increase).
Brokered natural gas revenue decreased $50.4 million, or 36%, from the prior year. The sales price of brokered natural gas rose 37%, resulting in an increase in revenue of $24.5 million. The volume of natural gas brokered this year declined by 53%, reducing revenues by $74.9 million. After including the related brokered natural gas costs, we realized a net margin of $2.9 million in 2001 compared to a net margin of $5.4 million in 2000.
Excluding the selected items regarding the contract settlements in 2000, other operating revenues increased $1.6 million to $7.1 million. This increase in 2001 is primarily the result of a settlement received as a result of a lawsuit and increased revenue from the sale of natural gas liquids.
Costs and Expenses. Total costs and expenses from operations, excluding the selected items related to the impairment of long-lived assets and bad debt in each year and the costs associated with closing the regional office in Pittsburgh during 2000, increased $52.1 million, or 18%, from 2000 due primarily to the following:
. Brokered natural gas cost decreased $47.9 million, or 35%, primarily due to the $73.0 million impact of the lower volume of brokered sales in 2001. This was partially offset by a $25.1 million increase due to higher natural gas costs compared to the prior year.
. Production and pipeline expense increased $6.0 million, or 17%, primarily as a result of costs associated with operating the Cody Company properties acquired in August 2001. Additionally, increased staffing and insurance costs were incurred to support the expanded 2001 drilling program. On a units-of-production basis, our company- wide production and pipeline expense was $0.51 per Mcfe in 2001 versus $0.53 per Mcfe in 2000 as a result of the increased production discussed above.
. Exploration expense increased $51.4 million, or 261%, primarily as a result of the following:
. A $15.3 million increase in geological and geophysical expenses over last year due to the acquisition of seismic data for future evaluation and increased drilling activity in all regions.
. A $34.9 million increase in dry hole costs. Although the drilling success rate improved from 86% in 2000 to 87% in 2001, we drilled a total of 208 gross wells in 2001, a 61% increase over 2000. We recorded seven exploratory dry holes in the higher cost Gulf Coast region versus only two in 2000. We also recorded four exploratory dry holes in the Rocky Mountains area and seven in the Appalachian region for a total of 18, up from a Company total of seven in 2000.
. A $0.8 million increase for salaries, wages and incentive compensation largely attributable to increased staffing in the Gulf Coast region to support the expanded drilling program.
. Depreciation, depletion, amortization and impairment expense, excluding the selected item related to the SFAS 121 impairment in each year, increased $30.6 million, or 53%, over 2000. Natural gas equivalent production increased 21%, increasing DD&A expense by $12.3 million. The 27% increase in the per unit expense from $0.86 per Mcfe to $1.09 per Mcfe was a result of increased production in the higher cost Gulf Coast region (including the newly acquired Cody properties) and resulted in an $18.3 million increase to DD&A expense for 2001.
. General and administrative expenses increased $5.5 million, primarily as a result of increased staffing during the transition period following the Cody Company acquisition and other staffing increases that support our larger operations. Additional cost increases were realized in incentive compensation programs as well as technology updates and related software maintenance.
. Taxes other than income increased $6.4 million as a result of higher natural gas and oil revenues.
Interest expense decreased $2.1 million due to a lower weighted average interest rate realized in 2001. This was despite the new Notes issued to partially fund the acquisition of Cody Company in August 2001.
Income tax expense was up $10.2 million due to the comparable increase in earnings before income tax. Our effective tax rate decreased in 2001 reflecting a shift of activity between states.
2000 and 1999 Compared
The following discussion is based on our results before taking into account the selected items discussed above.
Net Income and Revenues. We reported net income in 2000 of $30.2 million, or $1.10 per share. During 1999, we reported net income of $0.4 million, or $0.02 per share. Operating income increased $42.9 million, or 135%, and operating revenues increased $83.1 million, or 29%, in 2000. The improvement in operating revenues was mainly a result of the $48.7 million rise in natural gas sales due to the increase in gas prices, and the $24.5 million increase in brokered natural gas sales revenue. Operating revenues were reduced by a $10 million loss on natural gas price collar arrangements used during 2000. See further discussion in Item 7A. Price and production volume increases in crude oil also contributed to the higher operating revenues. Operating income was similarly impacted by these revenue changes.
The average Gulf Coast natural gas production sales price rose $1.50 per Mcf, or 66%, to $3.79, increasing operating revenues by approximately $21.2 million. In the Western region, the average natural gas production sales price increased $0.90 per Mcf, or 46%, to $2.86, increasing operating revenues by approximately $24.9 million. The average Appalachian natural gas production sales price increased $0.71 per Mcf, or 28%, to $3.24, increasing operating revenues by approximately $12.7 million. The overall weighted average natural gas production sales price increased $0.97 per Mcf, or 44%, to $3.19, increasing revenues by $58.8 million.
Natural gas production volume in the Gulf Coast region was down 1.4 Bcf, or 9%, to 14.1 Bcf primarily due to production difficulties in the Beaurline field and delays in bringing new production on-line in south Louisiana. Natural gas production volume in the Western region was down 0.3 Bcf to 29.0 Bcf due primarily to lower levels of drilling activity in the Mid- Continent area during 1999 and 2000. Natural gas production volume in the Appalachian
region was down 2.9 Bcf to 17.8 Bcf, as a result of the sale of certain non- strategic assets in the Appalachian region effective October 1, 1999, and a decrease in drilling activity in the region. Total natural gas production was down 4.6 Bcf, or 7%, generating a revenue decrease of $10.1 million in 2000.
Crude oil prices rose $9.59 per Bbl, or 56%, to $26.81, resulting in an increase to operating revenues of approximately $9.2 million. The volume of crude oil sold in the year increased slightly to 953 Mbbls, increasing operating revenues by $0.4 million.
Brokered natural gas revenue increased $24.5 million, or 21%, over the prior year. The sales price of brokered natural gas rose 52%, resulting in an increase in revenue of $48.5 million. The volume of natural gas brokered this year declined by 21%, reducing revenues by $24.0 million. After including the related brokered natural gas costs, we realized a net margin of $5.4 million in 2000.
Excluding the selected items regarding the contract settlements in 2000, and the sales contract buyout and the Section 29 tax credit provision in 1999, other operating revenues increased $0.2 million to $5.5 million.
Costs and Expenses. Total costs and expenses from operations, excluding the selected items related to the impairment of long-lived assets in each year and the costs associated with closing the regional office in Pittsburgh during 2000, increased $40.2 million, or 16%, from 1999 due primarily to the following:
. Brokered natural gas cost increased $23.5 million, or 21%, primarily due to the $46.5 million impact of higher purchased natural gas prices. This was partially offset by a $23.0 million reduction to purchased natural cost, the result of fewer brokered sales this year compared to the prior year.
. Production and pipeline expense increased $1.9 million, or 6%, primarily as a result of costs associated with the expansion of the Gulf Coast regional office, both in staffing and office facilities. Additionally, operational costs for surface equipment and compressor maintenance were up in the Rocky Mountains area where we drilled 50% more net wells in 2000 compared to 1999. On a units-of-production basis, our company-wide production and pipeline expense was $0.53 per Mcfe in 2000 versus $0.47 per Mcfe in 1999.
. Exploration expense increased $8.3 million, or 72%, primarily as a result of the following:
. A $3.5 million increase in geological and geophysical expenses over last year due to increased drilling activity in all regions.
. A $1.3 million increase in delay rental costs over last year largely due to delays in scheduled drilling projects in the Gulf Coast region.
. A $2.1 million increase for salaries, wages and incentive compensation largely attributable to increased staffing in the Gulf Coast region to support the expanded drilling program.
. A $0.5 million increase in dry hole costs. Although the drilling success rate improved from 84% in 1999 to 86% in 2000, we recorded two exploratory dry holes in the higher cost Gulf Coast region versus only one in 1999.
. Depreciation, depletion, amortization and impairment expense, excluding the selected item related to the SFAS 121 impairment in each year, increased $0.5 million, or 1%, over 1999. A 6% decrease in total natural gas equivalent production caused the expense to remain just slightly above last year's level, despite the 7% increase in the per unit expense to $0.86 per Mcfe.
. General and administrative expenses remained at the same level as in 1999.
. Taxes other than income increased $6.1 million as a result of higher natural gas and oil revenues.
Interest expense decreased $2.9 million primarily due to lower average levels of borrowing on the revolving credit facility.
Income tax expense was up $18.1 million due to the comparable increase in earnings before income tax.
No significant asset sale activity occurred in 2000. Gain on the sale of assets was $4 million for 1999. These gains are the result of the non- strategic asset divestitures, primarily the sale of the Clarksburg properties in the
Appalachian region to EnerVest effective October 1999.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Oil and gas prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business.
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and, to a lesser extent, oil. Declines in oil and natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil and gas prices also may reduce the amount of oil and gas that we can produce economically. Historically, oil and gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Oil and gas prices declined substantially in 1998 and early 1999, moved higher through 2000 and into 2001 before declining back to year-end 1998 levels in October 2001. 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 make it impossible to predict with any certainty the future prices of oil and gas.
Our hedging policy is designed to reduce the risk of price volatility for our production in the natural gas, natural gas liquids and crude oil markets. Currently we are focusing on protection from natural gas price declines, particularly in light of our capital spending plans. A hedging committee that consists of members of senior management overseas our hedging activity. Our hedging arrangements apply to only a portion of our production and provide only partial price protection against declines in oil and gas prices. These hedging arrangements may expose us to risk of financial loss and limit the benefit to us of increases in prices. Please read the discussion below related to commodity price swaps and Note 11 of the Notes to the Consolidated Financial Statements for a more detailed discussion of our hedging arrangements.
Commodity Price Swaps and Options
Hedges on Production - 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 2001, we fixed the price at an average of $3.75 per Mcf on quantities totaling 918 Mmcf, representing 1% of the Company's 2001 natural gas production. We did not have crude oil swap arrangements covering our production in 2001. During 2000, we fixed the price at an average of $4.54 per Mcf on quantities totaling 315 Mmcf, representing less
than 1% of the Company's 2000 natural gas production. The notional volume of the crude oil swap transactions was 364 Mbbls at a price of $22.67 per Bbl, which represented approximately 38% of our total oil production for 2000. During 1999, we fixed the price at an average of $2.88 per Mcf on quantities totaling 3,237 Mmcf, representing 5% of the Company's 1999 natural gas production. The notional volume of the crude oil swap transactions was 306 Mbbls at a price of $20.65 per Bbl, which represented approximately one-third of our total oil production for 1999.
The natural gas price swap arrangement that we entered into during the third quarter of 2000 covered a portion of production over the period of October 2000 through September 2003. However, the counterparty declared bankruptcy in December 2001. Based on the terms of the natural gas swap contract, this action resulted in the cancellation of the contract. At the time of cancellation, the contract's value was less than $0.2 million. As of the years ending December 31, 2001, and 2000, we had open natural gas price swap contracts on our production as follows:
Natural Gas Price Swaps
------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Mmcf Contract Price (in $ millions)
-----------------------------------------------------------------------------------------
As of December 31, 2001
-----------------------
None
As of December 31, 2000
-----------------------
Natural Gas Price Swaps on Production in:
----------------------------------------
Full Year 2001 918 $3.75 $(2.8)
Full Year 2002 678 3.11 (1.0)
Full Year 2003 423 2.81 (0.5)
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Financial derivatives related to natural gas production reduced revenues by $0.8 million in 2001 and $0.3 million in 2000.
We had no open oil price swap contracts outstanding on our production at December 31/st/ of 2001 or 2000. Financial derivatives related to crude oil reduced revenue by $2.2 million during 2000, but had no impact on 2001 results.
Hedges on Production - Options
In December 2000, we believed that the pricing environment provided a strategic opportunity to significantly reduce the price risk on a portion of our production through the use of costless collars. Under the costless collar arrangements, if the index rises above the ceiling price, we pay the counterparty. If the applicable index falls below the floor, the counterparty pays us. The 2001 natural gas price hedges include several costless collar arrangements based on eight price indexes at which we sell a portion of our production. These hedges were in place for the months of February through October 2001 and covered 24,404 Mmcf, or 35%, of our natural gas production for the year. All indexes were within the collars during February and April, some fell below the floor during the period of March, and all indexes were below the floor from June through October, resulting in a $34.6 million cash revenue for the year. These gains contributed $0.50 per Mcf to our average realized natural gas price for 2001.
During 2000, we used several costless collar arrangements to hedge a portion of our natural gas production. There were seven collar arrangements based on separate regional price indexes with a weighted average price floor of $2.74 per Mcf and a weighted average price ceiling of $3.38 per Mcf. These collars were in place during the months of April through October 2000. During this period, if the index rose above the ceiling price, we paid the counterparty. If the applicable index fell below the floor price, the counterparty paid us. These collars covered a total quantity of 9,909 Mmcf, or 16% of our annual production. In April and May 2000, the index prices all fell within the price collar and no settlements were made. In June 2000, all of the indexes rose above the ceiling prices and remained above the ceiling for the duration of the transaction resulting in a $10 million reduction to our realized revenue for the year. If these hedges had not been in place, our average realized natural gas price for 2000 would have been $0.17 per Mcf higher.
Again in December of 2001, we believed that the pricing environment provided a strategic opportunity to significantly reduce the price risk on a portion of our future production through the use of natural gas price collar arrangements. As of December 31, 2001, we had open natural gas price collar arrangements to hedge our production as follows:
Natural Gas Price Collars
---------------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Mmcf Ceiling / Floor (in $ millions)
---------------------------------------------------------------------------------------------------
As of December 31, 2001
-----------------------
Natural Gas Collars on Production in:
------------------------------------
First Quarter of 2002 12,082 $3.54/$2.68 --
Second Quarter of 2002 4,027 $3.54/$2.68 --
As of December 31, 2000
-----------------------
Natural Gas Costless Collars on Production in:
---------------------------------------------
First Quarter of 2001 5,274 $9.68/$5.59 --
Second Quarter of 2001 8,135 $9.68/$5.59 --
Third Quarter of 2001 8,224 $9.68/$5.59 --
Fourth Quarter of 2001 2,771 $9.68/$5.59 --
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The natural gas price hedges open at December 31, 2001, noted above, included several collar arrangements based on nine price indexes at which we sell a portion of our production. These hedges are in place for the months of January through April 2002 and cover approximately 60% of our anticipated natural gas production during this period. A premium totaling $0.9 million was paid to purchase these collar arrangements.
Hedges on Brokered Transactions
We use price swaps to hedge the natural gas price risk on brokered transactions. Typically, we enter into contracts to broker natural gas at a variable price based on the market index price. However, in some circumstances, some of our customers or suppliers request that a fixed price be stated in the contract. After entering into these fixed price contracts to meet the needs of our customers or suppliers, we may use price swaps to effectively convert these fixed price contracts to market-sensitive price contracts. These price swaps are held by us to their maturity and are not held for trading purposes.
We entered into price swaps with total notional quantities of 1,295 Mmcf in 2000 and 3,572 Mmcf in 1999 related to our brokered activities, representing 3% and 7% respectively, of our total volume of brokered natural gas sold. We did not use price swaps on brokered transactions in 2001.
As of the years ending December 31, 2000 and 2001, we had no open natural gas price swap contracts on brokered transactions. Financial derivatives related to natural gas reduced revenues by less than $0.1 million in 2000 and had no impact on revenue in 2001.
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.
Adoption of SFAS 133
We adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) on January 1, 2001. Under SFAS 133, the fair value of each derivative instrument is recorded as either an asset or liability on the balance sheet. At the end of each period, these instruments are marked-to-market. The gain or loss on the change in fair value is recorded as Other Comprehensive Income, a component of equity, to the extent that the derivative instrument is an effective hedge. Under SFAS 133, effectiveness is a measurement of how closely correlated the hedge instrument is with the underlying physical sale. For example, a natural gas price swap that converts Henry Hub index to a fixed price would be perfectly correlated,
and 100% effective, if the underlying gas was sold at the Henry Hub index. Any portion of the gains or losses that are considered ineffective under the SFAS 133 test are recorded immediately as a component of operating revenue on the statement of operations.
When we adopted SFAS 133, we had two types of hedges in place. The first type was a cash flow hedge that set the price of a certain monthly quantity of natural gas sold in the Gulf Coast region through September 2003. Based on the index price strip, the impact of this hedge on January 1, 2001 was to record a Hedge Loss of $0.1 million and a charge to Other Comprehensive Income of $4.2 million. Correspondingly, a Hedge Liability for $4.3 million was established. This instrument was cancelled in December 2001 with the bankruptcy of the counterparty. No balance related to this hedge remains in Other Comprehensive Income.
The second type of hedge outstanding at January 1, 2001 was a natural gas price costless collar agreement. We had entered into eight of these collars for a portion of our production at regional indexes for the months of February through October 2001. The collars had two components of value: intrinsic value and time value. Under SFAS 133, both components were valued at the end of each reporting period. Intrinsic value arises when the index price is either above the ceiling or below the floor for any period covered by the collar. If the index is above the ceiling for any month covered by the collar, the intrinsic value would be the difference between the index and the ceiling prices multiplied by the notional volume. In accordance with the initial SFAS 133 guidance, intrinsic value related to the current month would be recorded as a hedge loss (if the index is above the ceiling) or gain (if the index is below the floor). Starting in 2001 under amended guidance on SFAS 133, any changes in the intrinsic value component related to future months were recorded in Other Comprehensive Income, a component of stockholders' equity on the balance sheet, rather than to the income statement to the extent that the hedge was proven to be effective. These natural gas price collars were considered to be highly effective with respect to the intrinsic value calculation, since they were tied to the same indexes at which our natural gas is sold. Also under SFAS 133, the time value component, a market premium/discount, was marked-to-market through the income statement each period. Since these collar arrangements were executed on the last business day of 2000, the net premium value at adoption on January 1, 2001 was zero.
As of December 31, 2001, we had a series of nine natural gas price collar arrangements in place. In accordance with the latest guidance from the FASB's Derivative Implementation Group, we test the effectiveness of the combined intrinsic and time values and the effective portion of each will be recorded as a component of Other Comprehensive Income. Any ineffective portion will be recorded as a gain or loss in the current period. As of December 31, 2001, we have recorded $1.4 million of Other Comprehensive Income, a $0.1 million Unrealized Hedge Gain and a $1.5 million Hedge Asset.
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. The Company uses available marketing data and valuation methodologies to estimate fair value of debt.
Long-Term Debt
December 31, 2001 December 31, 2000
Carrying Estimated Carrying Estimated
(In thousands) Amount Fair Value Amount Fair Value
--------------------------------------------------------------------------
Debt
10.18% Notes $ -- $ -- $ 32,000 $ 33,162
7.19% Notes 100,000 104,961 100,000 97,033
7.26% Notes 75,000 79,187 -- --
7.36% Notes 75,000 79,225 -- --
7.46% Notes 20,000 21,097 -- --
Credit Facility 123,000 123,000 137,000 137,000
-------------------------------------------
$393,000 $407,470 $269,000 $267,195
===========================================
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
-----------------------------------------------------------------------------------------------------------
Report of Independent Accountants 44
Consolidated Statement of Operations for the Years Ended December 31, 2001, 2000 and 1999 45
Consolidated Balance Sheet at December 31, 2001 and 2000 46
Consolidated Statement of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999 47
Consolidated Statement of Stockholders' Equity for the Years Ended December 31, 2001, 2000 and 1999 48
Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2001, 2000 and 1999 49
Notes to the Consolidated Financial Statements 50
Supplemental Oil and Gas Information (Unaudited) 74
Quarterly Financial Information (Unaudited) 78
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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 accounting principles generally accepted in the United States of America and, accordingly, include certain informed judgments and estimates of management.
Management maintains a system of internal accounting and managerial controls and engages internal audit representatives who monitor and test the operation of these controls. Although no system can ensure the elimination of all errors and irregularities, the system is designed to provide reasonable assurance that assets are safeguarded, transactions are executed in accordance with management's authorization, and accounting records are reliable for financial statement preparation.
An Audit Committee of the Board of Directors, consisting of directors who are not employees of the Company, meets periodically with management, the independent accountants and internal audit representatives to obtain assurances to the integrity of the Company's accounting and financial reporting and to affirm the adequacy of the system of accounting and managerial controls in place. The independent accountants and internal audit representatives have full and free access to the Audit Committee to discuss all appropriate matters.
We believe that the Company's policies and system of accounting and managerial controls reasonably assure the integrity of the information in the consolidated financial statements and in the other sections of the annual report.
Ray Seegmiller
Chairman of the Board and Chief Executive Officer
February 22, 2002
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, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 11 to the Notes to the Consolidated Financial Statements, the Company changed its method of accounting for its derivative instruments and hedging activities in connection with its adoption of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended.
PricewaterhouseCoopers LLP
Houston, Texas
February 15, 2002
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
Year Ended December 31,
(In thousands, except per share amounts) 2001 2000 1999
----------------------------------------------------------------------------
OPERATING REVENUES
Natural Gas Production $301,529 $194,185 $145,495
Brokered Natural Gas 90,710 141,085 116,554
Crude Oil and Condensate 47,544 25,544 15,909
Change in Derivative Fair Value (Note 11) 142 -- --
Other (Note 13) 7,117 7,837 16,079
-----------------------------
447,042 368,651 294,037
OPERATING EXPENSES
Brokered Natural Gas Cost 87,785 135,700 112,164
Production and Pipeline Operations 41,217 35,727 33,357
Exploration 71,165 19,858 11,490
Depreciation, Depletion and Amortization 80,619 53,441 53,357
Impairment of Unproved Properties 7,803 4,368 3,950
Impairment of Long-Lived Assets 6,852 9,143 7,047
General and Administrative 25,650 20,421 20,136
Bad Debt Expense (Note 3) 2,270 2,096 --
Taxes Other Than Income 28,341 23,041 16,988
-----------------------------
351,702 303,795 258,489
Gain (Loss) on Sale of Assets 26 (39) 3,950
-----------------------------
INCOME FROM OPERATIONS 95,366 64,817 39,498
Interest Expense and Other 20,817 22,878 25,818
-----------------------------
Income Before Income Tax Expense 74,549 41,939 13,680
Income Tax Expense 27,465 16,467 5,161
-----------------------------
NET INCOME 47,084 25,472 8,519
Preferred Stock Dividend (Note 10) -- (3,749) 3,402
-----------------------------
Net Income Available to
Common Stockholders $ 47,084 $ 29,221 $ 5,117
=============================
Basic Earnings per Share Available
to Common Stockholders $ 1.56 $ 1.07 $ 0.21
Diluted Earnings per Share Available
to Common Stockholders $ 1.53 $ 1.06 $ 0.21
Average Common Shares Outstanding 30,276 27,384 24,726
|
The accompanying notes are an integral part of these consolidated financial statements.
CABOT OIL & GAS CORPORATION
CONSOLIDATED BALANCE SHEET
December 31,
(In thousands, except share amounts) 2001 2000
----------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 5,706 $ 7,574
Accounts Receivable 50,711 85,677
Inventories 17,560 11,037
Other 11,010 5,981
---------------------
Total Current Assets 84,987 110,269
PROPERTIES AND EQUIPMENT (Successful Efforts Method) 981,338 623,174
OTHER ASSETS 2,706 2,191
---------------------
$1,069,031 $735,634
=====================
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current Portion of Long-Term Debt $ -- $ 16,000
Accounts Payable 79,575 81,566
Accrued Liabilities 30,665 20,542
---------------------
Total Current Liabilities 110,240 118,108
LONG-TERM DEBT 393,000 253,000
DEFERRED INCOME TAXES 200,859 108,174
OTHER LIABILITIES 18,380 13,847
COMMITMENTS AND CONTINGENCIES (Note 8)
STOCKHOLDERS' EQUITY
Preferred Stock
Authorized - 5,000,000 Shares of $0.10 Par Value
- 6% Convertible Redeemable Preferred; $50 Stated Value;
No Shares Outstanding in 2001 and 2000 (Note 10) -- --
Common Stock
Authorized - 40,000,000 Shares of $0.10 Par Value
Issued and Outstanding -
31,905,097 Shares in 2001 and
29,494,411 Shares in 2000 3,191 2,949
Class B Common Stock
Authorized - 800,000 Shares of $0.10 Par Value
No Shares Issued -- --
Additional Paid-in Capital 346,260 285,572
Retained Earnings (Accumulated Deficit) 650 (41,632)
Other Comprehensive Income 835 --
Less Treasury Stock, at Cost
302,600 Shares in 2001 and 2000 (4,384) (4,384)
---------------------
Total Stockholders' Equity 346,552 242,505
---------------------
$1,069,031 $735,634
=====================
|
The accompanying notes are an integral part of these consolidated financial statements.
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended December 31,
(In thousands) 2001 2000 1999
---------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 47,084 $ 25,472 $ 8,519
Adjustments to Reconcile Net Income
to Cash Provided by Operations
Depletion, Depreciation and Amortization 80,619 53,441 53,357
Impairment of Unproved Properties 7,803 4,368 3,950
Impairment of Long-Lived Assets 6,852 9,143 7,047
Deferred Income Tax Expense 14,157 13,162 9,060
(Gain) Loss on Sale of Assets (26) 39 (3,950)
Exploration Expense 71,165 19,858 11,490
Change in Derivative Fair Value (142) -- --
Other 2,995 1,141 2,439
Changes in Assets and Liabilities
Accounts Receivable 34,966 (35,286) 5,408
Inventories (6,523) (108) (1,617)
Other Current Assets (3,524) (2,357) 164
Other Assets (515) 348 598
Accounts Payable and Accrued Liabilities (7,859) 26,976 (5,505)
Other Liabilities 3,383 2,813 1,528
---------------------------------
Net Cash Provided by Operations 250,435 119,010 92,488
---------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (127,129) (99,359) (82,191)
Acquisition of Cody Company /(1)/ (187,785) -- --
Proceeds from Sale of Assets 6,829 3,150 56,328
Exploration Expense (71,165) (19,858) (11,490)
---------------------------------
Net Cash Used by Investing (379,250) (116,067) (37,353)
---------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt 435,000 135,000 125,000
Decrease in Debt (311,000) (159,000) (175,000)
Sale of Common Stock 7,749 85,104 1,738
Common Dividends Paid (4,802) (4,350) (3,992)
Preferred Dividends Paid -- (2,202) (3,402)
Retirement of Preferred Stock -- (51,600) --
---------------------------------
Net Cash Provided (Used) by Financing 126,947 2,952 (55,656)
---------------------------------
Net Increase (Decrease) in Cash and
Cash Equivalents (1,868) 5,895 (521)
Cash and Cash Equivalents, Beginning of Year 7,574 1,679 2,200
---------------------------------
Cash and Cash Equivalents, End of Year $ 5,706 $ 7,574 $ 1,679
=================================
|
/1/ The amount excludes non-cash consideration of $49.9 million in common stock issued in connection with the acquisition of Cody Company in August 2001. This amount also excludes the $78.0 million deferred taxes pertaining to the difference between the fair value of the assets acquired and the related tax basis. The amount includes the $181.3 million in cash consideration plus $6.4 million in capitalized acquisition costs. See Note 14, Acquisition of Cody Company.
The accompanying notes are an integral part of these consolidated financial statements.
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
Accumulated
Compre- Retained
Common Stock Preferred Treasury Paid-In hensive Earnings
(In thousands) Shares Par Stock Stock Capital Income (Deficit) Total
----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 24,960 $2,496 $ 113 $(4,384) $252,073 $(67,630) $182,668
--------------------------------------------------------------------------------
Net Income 8,519 8,519
Exercise of Stock Options 72 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 42 4 1,198 1,202
Other 2 2
--------------------------------------------------------------------------------
Balance at December 31, 1999 25,074 $2,507 $ 113 $(4,384) $254,763 $(66,503) $186,496
================================================================================
Net Income 25,472 25,472
Exercise of Stock Options 766 77 14,764 14,841
Preferred Stock Dividends 3,749 3,749
Common Stock Dividends
at $0.16 per Share (4,350) (4,350)
Stock Grant Vesting 254 25 1,412 1,437
Issuance of Common Stock 3,400 340 71,219 71,559
Retirement of Preferred Stock (113) (56,586) (56,699)
--------------------------------------------------------------------------------
Balance at December 31, 2000 29,494 $2,949 $ -- $(4,384) $285,572 $(41,632) $242,505
================================================================================
Net Income 47,084 47,084
Exercise of Stock Options 411 42 9,339 9,381
Common Stock Dividends
at $0.16 per Share (4,802) (4,802)
Other Comprehensive Income 835 835
Stock Grant Vesting 1,689 1,689
Issuance of Common Stock 2,000 200 49,660 49,860
--------------------------------------------------------------------------------
Balance at December 31, 2001 31,905 $3,191 $ -- $(4,384) $346,260 $ 835 $ 650 $346,552
================================================================================
|
The accompanying notes are an integral part of these consolidated financial statements.
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Year Ended December 31,
(In thousands) 2001 2000 1999
------------------------------------------------------------------------------------
Net Income Available to Common Stockholders $ 47,084 $29,221 $5,117
--------------------------
Other Comprehensive Income
--------------------------
Cumulative Effect of Change in Accounting Principle
on January 1, 2001 (4,269) -- --
Reclassification Adjustments for Settled Contracts 33,762 -- --
Changes in Fair Value of Outstanding Hedge Positions (28,131) -- --
Deferred Income Tax (527) -- --
--------------------------
Total Other Comprehensive Income 835 -- --
--------------------------
Comprehensive Income $ 47,919 $29,221 $5,117
==========================
|
The accompanying notes are an integral part of these consolidated financial statements.
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
Cabot Oil & Gas Corporation and its subsidiaries are engaged in the exploration, development, production and marketing of natural gas and, to a lesser extent, crude oil and natural gas liquids. The Company also transports, stores, gathers and purchases natural gas for resale. The Company operates in one segment, natural gas and oil exploration and exploitation within the continental United States.
The consolidated financial statements contain the accounts of the Company after eliminating all significant intercompany balances and transactions.
Recently Issued Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statements of Financial Accounting Standards No. 141 "Business Combinations"
("SFAS 141") and No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142").
SFAS 141 requires all business combinations initiated after June 30, 2001 to be
accounted for under the purchase method. For all business combinations for
which the date of acquisition is after June 30, 2001, SFAS 141 also establishes
specific criteria for the recognition of intangible assets separately from
goodwill. SFAS 141 also requires unallocated negative goodwill (in a case where
the purchase price is less than fair market value of the acquired assets) to be
written off immediately as an extraordinary gain, rather than deferred and
amortized. SFAS 142 changes the accounting for goodwill and other intangible
assets after an acquisition. The most significant changes made by SFAS 142 are:
1) goodwill and intangible assets with indefinite lives will no longer be
amortized; 2) goodwill and intangible assets with indefinite lives must be
tested for impairment at least annually; and 3) the amortization period for
intangible assets with finite lives will no longer be limited to 40 years. The
Company does not believe that the adoption of these statements will have a
material effect on its financial position, results of operations or cash flows.
The Company did not record goodwill as part of the Cody acquisition.
In June 2001, the FASB also approved for issuance SFAS 143 "Asset Retirement Obligations." SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets such as wells and production facilities. SFAS 143 guidance covers (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long- lived asset and subsequently allocated to expense using a systematic and rational method. The Company will adopt the statement effective no later than January 1, 2003, as required. The transition adjustment resulting from the adoption of SFAS 143 will be reported as a cumulative effect of a change in accounting principle. At this time, the Company cannot reasonably estimate the effect of the adoption of this statement on its financial position, results of operations or cash flows.
In August 2001, the FASB also approved SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 144 replaces SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." The new accounting model for long-lived assets to be disposed of by sale applies to all long-lived assets, including discontinued operations, and replaces the provisions of APB Opinion No. 30, "Reporting Results of Operations-Reporting the Effects of Disposal of a Segment of a Business", for the disposal of segments of a business. SFAS 144 requires that those long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. Therefore, discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. SFAS 144 also broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The provisions of SFAS 144 are
effective for financial statements issued for fiscal years beginning after December 15, 2001 and, generally are to be applied prospectively. At this time, the Company cannot estimate the effect of this statement on its financial position, results of operations, or cash flows.
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 2001, the Company recorded a total impairment of $6.9 million primarily related to three Gulf Coast fields for which capitalized cost exceeded the future undiscounted cash flows. Additionally, one natural gas processing plant in the Rocky Mountains was written down to fair market value. During 2000, two wells in the Beaurline field in south Texas experienced casing collapses. This situation resulted in an impairment to this field of $9.1 million, recorded in the second quarter financial results. During the fourth quarter of 1999, the Company experienced a significant production decline from the Chimney Bayou field located in the Texas Gulf Coast. This decline along with an unsuccessful workover in the Lawson field in Louisiana resulted in a $7.0 million impairment of long-lived assets during 1999. These impairments were measured based on discounted cash flows utilizing a discount rate appropriate for risks associated with the related properties.
Capitalized costs of proved oil and gas properties, after considering estimated dismantlement, restoration and abandonment costs, net of estimated salvage values, are depreciated and depleted on a field basis by the units-of- production method using proved developed reserves. The costs of unproved oil and gas properties are generally combined and amortized over a period that is based on the average holding period for such properties and the Company's experience of successful drilling. Properties related to gathering and pipeline systems and equipment are depreciated using the straight-line method based on estimated useful lives ranging from 10 to 25 years. Certain other assets are also depreciated on a straight-line basis.
Future estimated plug and abandonment costs are accrued over the productive life of the oil and gas properties on a units-of-production basis. The accrued liability for plug and abandonment costs is included in accumulated depreciation, depletion and amortization. As a component of accumulated depreciation, depletion and amortization, total future plug and abandonment costs were $14.4 million at December 31, 2001, and $12.4 million at December 31, 2000. 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.
The Company estimated at December 31, 2001 that it would ultimately require approximately $50.8 million to plug and abandon its properties at the end of their economic life occurring over the next 50 years. These costs would include plugging all wells, removing all equipment and returning all sites to the original condition. The Company anticipates these plugging and abandoning operations to occur throughout future years as each well is fully produced. Under SFAS 143, the Company will record the discounted present value of this amount as a component of the capitalized cost of proved oil and gas properties, and increase the future estimated liability monthly by recording implied interest. These costs will be expensed over the life of the reserves.
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 proved reserves for these properties.
Brokered Natural Gas Margin
In prior years, the revenues and expenses related to brokering natural gas were reported net on the Consolidated Statement of Operations as Brokered Natural Gas Margin. Beginning in 2000, these amounts are reported gross as part of Operating Revenues and Operating Expenses. Prior year amounts have been reclassified to conform to the current year presentation.
The Company realizes brokered margin as a result of buying and selling natural gas in back-to-back transactions. The Company realized $2.9 million, $5.4 million, and $4.4 million of brokered natural gas margin in 2001, 2000, and 1999, respectively.
Income Taxes
The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. 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 from outstanding checks in zero balance cash accounts. These credit balances included in accounts payable were $9.7 million at December 31, 2001, and $12.7 million at December 31, 2000.
Risk Management Activities
From time to time, the Company enters into derivative contracts, such as natural gas price swaps or costless price collars, as a hedging strategy to manage commodity price risk associated with its inventories, production or other contractual commitments. These transactions are executed for purposes other than trading. Gains or losses on these hedging activities are generally recognized over the period that the inventory, production or other underlying
commitment is hedged as an offset to the specific hedged item. Cash flows related to any recognized gains or losses associated with these hedges are reported as cash flows from operations. If a hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period that the underlying production or other contractual commitment is delivered. Unrealized gains or losses associated with any derivative contract not considered a hedge would be recognized currently in the results of operations.
A derivative instrument qualifies as a hedge if all of the following tests are met:
. The item to be hedged exposes the Company to price risk.
. The derivative reduces the risk exposure and is designated as a hedge at the
time the Company enters into the contract.
. At the inception of the hedge and throughout the hedge period there is a high
correlation between changes in the market value of the derivative instrument
and the fair value of the underlying item being hedged.
When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on the sale or settlement of the underlying item. For example, in the case of natural gas price hedges, the gain or loss is reflected in natural gas revenue. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if correlation no longer exists, the gain or loss on the derivative is recognized currently in the results of operations to the extent the market value changes in the derivative have not been offset by the effects of the price changes on the hedged item since the inception of the hedge. See Note 11 Financial Instruments for further discussion.
On January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) and Statement of Financial Accounting Standards No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities" (SFAS 138). SFAS 133 requires all derivatives to be recognized in the statement of financial position as either assets or liabilities and measured at fair value. In addition, all hedging relationships must be designated, reassessed and documented according to the provisions of SFAS 133. SFAS 138 amended portions of SFAS 133 and was adopted with SFAS 133.
All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness will be assessed. Both at the inception of the hedge and on an quarterly basis going forward, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.
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, 2001, and 2000, the cash and cash equivalents are primarily concentrated in two financial institutions. The Company periodically assesses the financial condition of these institutions and believes that any possible credit risk is minimal.
Environmental Matters
Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Any insurance recoveries are recorded as assets when received.
Use of Estimates
In preparing financial statements, the Company follows generally accepted accounting principles. These principles require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The Company's most significant financial estimates are based on the remaining proved oil and gas reserves (see Supplemental Oil and Gas Information). Actual results could differ from those estimates.
2. Properties and Equipment
Properties and equipment are comprised of the following:
December 31,
(In thousands) 2001 2000
----------------------------------------------- ---------- ----------
Proved Oil and Gas Properties $1,400,341 $ 993,397
Unproved Oil and Gas Properties 70,709 31,780
Gathering and Pipeline Systems 131,768 128,257
Land, Building and Improvements 4,674 4,538
Other 27,513 25,601
---------- ----------
1,635,005 1,183,573
Accumulated Depreciation,
Depletion, Amortization and Impairments (653,667) (560,399)
---------- ----------
$ 981,338 $ 623,174
========== ==========
|
As a component of accumulated depreciation, depletion and amortization, total future plug and abandonment costs were $14.4 million at December 31, 2001, and $12.4 million at December 31, 2000. See further discussion in Note 1.
On February 14, 2002, the Company determined that two exploratory wells (one in the Gulf Coast and one in Appalachia) were unsuccessful and would be abandoned. As of December 31, 2001, costs of approximately $7.7 million had been incurred on these wells and this amount is included as a component of Exploration Expense in the Statement of Operations. The Company anticipates recording additional pre-tax dry hole expense of $2.5 million in the first quarter of 2002 associated with drilling and abandoning these wells.
3. Additional Balance Sheet Information
Certain balance sheet amounts are comprised of the following:
December 31,
(In thousands) 2001 2000
---------------------------------------------- ------- -------
Accounts Receivable
Trade Accounts $39,570 $79,773
Joint Interest Accounts 12,889 4,074
Current Income Tax Receivable 2,662 37
Other Accounts 986 4,347
------- -------
56,107 88,231
Allowance for Doubtful Accounts /(1)/ (5,396) (2,554)
------- -------
$50,711 $85,677
======= =======
|
December 31,
(In thousands) 2001 2000
-----------------------------------------------------------------------
Other Current Assets
Derivative Instrument Asset - SFAS 133 $ 2,387 $ --
Drilling Advances 2,111 2,459
Prepaid Balances 2,114 2,172
Restricted Cash and Other Accounts /(1)/ 4,398 1,350
------- -------
$11,010 $ 5,981
======= =======
Accounts Payable
Trade Accounts $19,914 $23,757
Natural Gas Purchases 4,559 12,525
Wellhead Gas Imbalances 2,353 2,185
Royalty and Other Owners 11,041 22,858
Capital Costs 30,923 13,486
Taxes Other than Income 2,686 2,654
Drilling Advances 2,627 456
Other Accounts 5,472 3,645
------- -------
$79,575 $81,566
======= =======
Accrued Liabilities
Employee Benefits $ 7,151 $ 5,441
Taxes Other than Income 13,623 11,363
Interest Payable 6,996 2,478
Other Accrued 2,895 1,260
------- -------
$30,665 $20,542
======= =======
Other Liabilities
Postretirement Benefits Other than Pension $ 1,689 $ 1,497
Accrued Pension Cost 7,280 6,743
Taxes Other than Income and Other 9,411 5,607
------- -------
$18,380 $13,847
======= =======
|
4. Inventories
Inventories are comprised of the following:
December 31,
(In thousands) 2001 2000
-----------------------------------------------------------------------
Natural Gas and Oil in Storage $12,622 $10,277
Tubular Goods and Well Equipment 4,059 2,122
Pipeline Exchange Balances 879 (1,362)
------- -------
$17,560 $11,037
======= =======
|
5. Debt and Credit Agreements
10.18% Notes
In May 1990, the Company issued an aggregate principal amount of $80 million of its 12-year 10.18% Notes (10.18% Notes) to a group of nine institutional investors in a private placement offering. The 10.18% Notes require five annual $16 million principal payments each May starting in 1998. The fourth payment due in May 2001, classified as Current Portion of Long-Term Debt, was a current liability on the Company's Consolidated Balance Sheet at December 31, 2000. However, the Company prepaid the remaining $32 million in May 2001 along with a $0.9 million prepayment penalty, which was recorded as a component of interest expense.
7.19% Notes
In November 1997, the Company issued an aggregate principal amount of $100 million of its 12-year 7.19% Notes (7.19% Notes) to a group of six institutional investors in a private placement offering. The 7.19% Notes require five annual $20 million principal payments starting in November 2005. The Company may prepay all or any portion of the indebtedness on any date with a prepayment penalty. The 7.19% Notes contain restrictions on the merger of the Company or any subsidiary with a third party other than under certain limited conditions. There are also various other restrictive covenants customarily found in such debt instruments. These covenants include a required asset coverage ratio (present value of proved reserves to debt and other liabilities) that must be at least 1.5 to 1.0, and a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0.
7.33% Weighted Average Fixed Rate Notes
To partially fund the cash portion of the acquisition of Cody Company in August 2001, the Company issued $170 million of Notes to a group of seven institutional investors in a private placement transaction in July 2001. Prior to the determination of the Note's interest rates, the Company entered into a treasury lock in order to reduce the risk of rising interest rates. Interest rates rose during the pricing period, resulting in a $0.7 million gain that will be amortized over the life of the Notes, and thereby reducing the effective interest rate by 5.5 basis points. All of the Notes have bullet maturities and were issued in three separate tranches as follows:
Principal Term Coupon
------------------------------------------
Tranche 1 $75,000,000 10-year 7.26%
Tranche 2 $75,000,000 12-year 7.36%
Tranche 3 $20,000,000 15-year 7.46%
|
The Notes were issued under the same Note Purchase Agreement as the 7.19% Notes.
Revolving Credit Agreement
The Company has a $250 million Revolving Credit Agreement (Credit Facility) that utilizes nine banks. The term of the Credit Facility expires on December 17, 2003. The available credit line is subject to adjustment from time-to-time on the basis of the projected present value (as determined by the banks' petroleum engineer) of estimated future net cash flows from certain proved oil and gas reserves and other assets of the Company. While the Company does not expect a change in the available credit line, in the event that it is adjusted below the outstanding level of borrowings, the Company has a period of 180 days to reduce its outstanding debt to the adjusted credit line. The Credit Facility also includes a requirement to pay down half of the debt in excess of the adjusted credit line within the first 90 days of such an adjustment.
Interest rates are principally based on a reference rate of either the rate for certificates of deposit (CD rate) or LIBOR, plus a margin, or the prime rate. For CD rate and LIBOR borrowings, interest rates are subject to increase if the total indebtedness is either greater than 60% or 80% of the Company's debt limit of $520 million, as shown below.
Debt Percentage
---------------------------------------------
Lower than 60% 60% - 80% Higher than 80%
=============================================
LIBOR margin 0.750% 1.000% 1.250%
CD margin 0.875% 1.125% 1.375%
Commitment fee rate 0.250% 0.375% 0.375%
|
The Credit Facility provides for a commitment fee on the unused 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, 2001, 2000 and 1999 were 7.6%, 7.8%, and 6.7%, respectively. The Credit Facility contains various customary restrictions, which include the following:
(a) Prohibition of the merger of the Company or any subsidiary with a third
party except under certain limited conditions.
(b) Prohibition of the sale of all or substantially all of the Company's or
any subsidiary's assets to a third party.
(c) Maintenance of a minimum annual coverage ratio of operating cash flow to
interest expense for the trailing four quarters of 2.8 to 1.0.
The Company was in compliance with all covenants at December 31, 2001 and 2000.
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, 2001, 2000 and 1999 are comprised of the following:
(In thousands) 2001 2000 1999
----------------------------------------------------------------------
Qualified
Current Year Service Cost $ 914 $ 832 $1,012
Interest Accrued on Pension Obligation 1,198 1,070 1,072
Expected Return on Plan Assets (1,064) (1,123) (919)
Net Amortization and Deferral 88 88 88
Recognized Gain (28) (282) --
--------------------------
Net Periodic Pension Cost $ 1,108 $ 585 $1,253
==========================
(In thousands) 2001 2000 1999
----------------------------------------------------------------------
Non-Qualified
Current Year Service Cost $ 88 $ 60 $ 140
Interest Accrued on Pension Obligation 72 42 67
Net Amortization 77 77 77
Recognized (Gain) Loss 21 (5) 35
--------------------------
Net Periodic Pension Cost $ 258 $ 174 $ 319
==========================
|
The following table illustrates the funded status of the Company's pension plans at December 31, 2001, and 2000, respectively:
2001 2000
(In thousands) Qualified Non-Qualified Qualified Non-Qualified
-----------------------------------------------------------------------------------------------
Actuarial Present Value of:
Accumulated Benefit Obligation $14,279 $ 816 $12,188 $ 753
Projected Benefit Obligation $18,996 $ 898 $16,173 $ 978
Plan Assets at Fair Value 9,909 -- 11,801 --
---------------------------------------------------
Projected Benefit Obligation in Excess
of Plan Assets 9,087 898 4,372 978
Unrecognized Net Gain (Loss) (2,153) (260) 1,956 (351)
Unrecognized Prior Service Cost (511) (553) (599) (630)
Adjustment to Recognize Minimum
Liability -- 731 -- 756
---------------------------------------------------
Accrued Pension Cost $ 6,423 $ 816 $ 5,729 $ 753
===================================================
|
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) 2001 2000 1999
-------------------------------------------------------------------------
Beginning of Year $17,151 $14,546 $16,449
Service Cost 1,002 892 1,152
Interest Cost 1,270 1,112 1,139
Actuarial Loss (Gain) 1,166 1,328 (3,657)
Benefits Paid (695) (727) (537)
-------------------------
End of Year $19,894 $17,151 $14,546
=========================
|
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) 2001 2000 1999
-------------------------------------------------------------------------
Beginning of Year $11,801 $12,092 $10,344
Actual Return on Plan Assets (1,527) (440) 2,428
Employer Contribution 584 1,172 101
Benefits Paid (695) (727) (537)
Expenses Paid (254) (296) (244)
-------------------------
End of Year $ 9,909 $11,801 $12,092
=========================
|
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) 2001 2000 1999
-------------------------------------------------------------------------
Funded Status $ 9,985 $ 5,350 $ 2,454
Unrecognized Gain (Loss) (2,413) 1,605 5,078
Unrecognized Prior Service Cost (1,064) (1,229) (1,394)
-------------------------
Net Amount Recognized $ 6,508 $ 5,726 $ 6,138
=========================
Accrued Benefit Liability - Qualified Plan $ 6,423 $ 5,729 $ 6,194
Accrued Benefit Liability - Non-Qualified Plan 816 753 504
Intangible Asset (731) (756) (560)
-------------------------
Net Amount Recognized $ 6,508 $ 5,726 $ 6,138
=========================
|
Assumptions used to determine projected post-retirement benefit obligations and pension costs are as follows:
2001 2000 1999
-----------------------------------------------------------------------
Discount Rate /(1)/ 7.25% 7.50% 7.75%
Rate of Increase in Compensation Levels 4.00% 4.00% 4.00%
Long-Term Rate of Return on Plan Assets 9.00% 9.00% 9.00%
------------------------------------------------------------------------
|
/(1)/ Represents the rate used to determine the benefit obligation. A 7.50% discount rate was used to compute pension costs in 2001, a rate of 7.75% in 2000, and a rate of 7.0% was used in 1999.
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 in cash. 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 $1.0 million, $0.7 million, and $0.7 million in 2001, 2000, and 1999, respectively. The plan contribution rose in 2001 due to an increase in the Company's matching program. Effective July 1, 2001, the Company increased its dollar-for-dollar matching limit from 4% to 6% of an employee's pretax earnings. 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, 2001, the balance in the Deferred Compensation Plan's rabbi trust was $1.0 million.
The employee participants guide the diversification of trust assets. The trust assets are invested in 13 mutual funds that cover the investment spectrum from equity to money market. These mutual funds are publicly quoted and reported at market value. No shares of Cabot Oil & Gas stock are held by the trust. Settlement payments are made to participants in cash, either in a lump sum or in periodic installments. The market value of the trust assets is recorded on the Company's balance sheet as a component of "Other Assets" and the corresponding liability is recorded as a component of "Other Liabilities."
There is no impact on earnings or earnings per share from the changes in market value of the deferred compensation plan assets for two reasons. First, the changes in market value of the trust assets are offset completely by changes in the value of the liability, which represents trust assets belonging to plan participants. Second, no shares of Cabot Oil & Gas stock are held in the trust.
The Company charged to expense plan contributions of less than $20,000 in each year presented.
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 240 retirees at the end of 2001 and 241 retirees at the end of 2000.
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.
Postretirement benefit costs recognized during the last three years are as follows:
(In thousands) 2001 2000 1999
-------------------------------------------------------------------------------
Service Cost of Benefits Earned During the Year $ 175 $ 187 $ 225
Interest Cost on the Accumulated Postretirement
Benefit Obligation 388 534 515
Amortization Benefit of the Unrecognized Gain (291) (132) (131)
Amortization Benefit of the Unrecognized
Transition Obligation 662 662 690
----- ------ ------
Total Postretirement Benefit Cost $ 934 $1,251 $1,299
===== ====== ======
|
The health care cost trend rate used to measure the expected cost in 2000 for medical benefits to retirees was 8%. Provisions of the plan should prevent further increases in employer cost after 2000.
A one-percentage-point increase or decrease in health care cost trend rates for future periods would not impact the accumulated net postretirement benefit obligation or the total postretirement benefit cost recognized. Company costs are capped at 2000 levels and the retirees assume any future increases in costs.
The funded status of the Company's postretirement benefit obligation at December 31, 2001, and 2000 is comprised of the following:
(In thousands) 2001 2000
---------------------------------------------------------------------------------------------------
Plan Assets at Fair Value $ -- $ --
Accumulated Postretirement Benefits Other Than Pensions 5,507 5,429
Unrecognized Cumulative Net Gain 3,292 3,847
Unrecognized Transition Obligation (6,617) (7,279)
------- -------
Accrued Postretirement Benefit Liability $ 2,182 $ 1,997
======= =======
|
The change in the accumulated postretirement benefit obligation during the last three years is presented as follows:
(In thousands) 2001 2000 1999
--------------------------------------------------------------------------
Beginning of Year $5,429 $ 7,243 $ 7,693
Service Cost 175 187 225
Interest Cost 388 534 515
Amendments -- -- (253)
Actuarial Loss (Gain) 265 (1,923) (102)
Benefits Paid (750) (612) (835)
------ ------- -------
End of Year $5,507 $ 5,429 $ 7,243
====== ======= =======
|
7. Income Taxes
Income tax expense is summarized as follows:
Year Ended December 31,
(In thousands) 2001 2000 1999
---------------------------------------------------------------------
Current
Federal $10,984 /(1)/ $ 3,089/(2)/ $(3,899)
State 496 216 --
------------------------------------
Total 11,480 3,305 (3,899)
------------------------------------
Deferred
Federal 13,723 11,804 8,910
State 2,262 1,358 150
------------------------------------
Total 15,985 13,162 9,060
------------------------------------
Total Income Tax Expense $27,465 $16,467 $ 5,161
====================================
|
/(2)/ The Federal Income Taxes Payable is zero at December 31, 2000 primarily as a result of tax payments made during the year and a $1.8 million tax benefit related to stock option exercises during 2000.
In the table above, the $4.5 million refund received in 1999 that applied to a net operating loss carryback to 1997 is reflected in "Current -Federal."
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) 2001 2000 1999
----------------------------------------------------------------------------------------
Statutory Federal Income Tax Rate 35% 35% 35%
Computed "Expected" Federal Income Tax $ 26,092 $14,679 $4,788
State Income Tax, Net of Federal Income Tax 2,758 1,552 506
Other, Net (1,385) /(1)/ 236 (133)
---------------------------------
Total Income Tax Expense $ 27,465 $16,467 $5,161
=================================
|
The tax effects of temporary differences that resulted in significant portions of the deferred tax liabilities and deferred tax assets as of December 31, 2001, and 2000 were as follows:
(In thousands) 2001 2000
-----------------------------------------------------------------------
Deferred Tax Liabilities
Property, Plant and Equipment $224,031 $142,935
------------------
Deferred Tax Assets
Alternative Minimum Tax Credit Carryforwards 4,943 5,817
Net Operating Loss Carryforwards 1,715 13,904
Note Receivable on Section 29 Monetization/ (1)/ 4,928 6,397
Items Accrued for Financial Reporting Purposes 11,586 8,643
------------------
23,172 34,761
------------------
Net Deferred Tax Liabilities $200,859 $108,174
==================
|
As of December 31, 2001, the Company had a net operating loss carryforward of $1.7 million for state income tax reporting purposes and none available for regular federal income tax purposes. The Company has alternative minimum tax credit carryforwards of $4.9 million which do 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 such 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. Leases for the Company's offices in Houston and Denver each run for approximately eight more years. With the acquisition of Cody Company in August 2001, the Company assumed certain lease agreements, most of which expire in 2004. Most of the other leases expire within five years and may be renewed. Rent expense under such arrangements totaled $7.7 million, $6.3 million, and $5.0 million for the years ended December 31, 2001, 2000, and 1999, respectively.
Future minimum rental commitments under non-cancelable leases in effect at December 31, 2001 are as follows:
(In thousands)
-----------------------------
2002 $ 5,194
2003 4,602
2004 3,953
2005 3,855
2006 3,619
Thereafter 8,620
-------
$29,843
=======
|
Minimum rental commitments are not reduced by minimum sublease rental income of $0.3 million due in the future under non-cancelable subleases.
Contingencies
The Company is a defendant in various lawsuits and is involved in other gas contract issues. All known liabilities are fully accrued based on management's best estimate of the potential loss. In management's opinion, final judgments or settlements, if any, which may be awarded in connection with any one or more of these suits and claims would not have a significant impact on the results of operations, financial position or cash flows of any
period.
Environmental Liability
The EPA notified the Company in February 2000 of its potential liability for waste material disposed of at the Casmalia Superfund Site ("Site"), located on a 252-acre parcel in Santa Barbara County, California. Over 10,000 separate parties disposed of waste at the Site while it was operational from 1973 to 1992. The EPA stated that federal, state and local governmental agencies along with the numerous private entities that used the Site for disposal of approximately 4.5 billion pounds of waste would be expected to pay the clean-up costs, which are estimated by the EPA to be $271.9 million. The EPA is also pursuing the owners/operators of the Site to pay for remediation.
Documents received by the Company with the notification from the EPA indicate that the Company used the Site principally to dispose of salt water from two wells over a period from 1976 to 1979. There is no allegation that the Company violated any laws in the disposal of material at the Site. The EPA's actions stem from the fact that the owners/operators of the Site do not have the financial means to implement a closure plan for the Site.
A group of potentially responsible parties, including the Company, formed a group, called the Casmalia Negotiating Committee ("CNC"). The CNC has had extensive settlement discussions with the EPA and has reached a settlement in principal to pay approximately $27 million toward Site clean up in return for a release from liability. The CNC is currently negotiating a consent decree to memorialize the settlement. On January 30, 2002, the Company placed $1,283,283 in an escrow account. This amount approximates the Company's volumetric share of EPA's cost estimate, plus a 5% premium and is the Company's settlement amount. The escrow account is being funded by the Company and many other CNC members to maximize the likelihood that there will be sufficient funds to fund the settlement agreement upon its completion, which is expected later in 2002. This cash settlement, once released from escrow and paid to the federal government, will resolve all federal claims against the Company for response costs and will release the Company from all response costs related to the Site, except for future claims against the Company for natural resource damage, unknown conditions, transshipment risks and claims by third parties, all of which are expected to be covered by insurance to be purchased by participating CNC members. Responsibility for certain State of California oversight and response costs, while not covered by the settlement or insurance, are not expected to be material. No determination has been made as to whether any insurance arrangement will allow the Company to recover its contribution to the settlement.
The Company has established a reserve that management believes to be adequate to provide for this environmental liability based on its estimate of the probable outcome of this matter and estimated legal costs.
Wyoming Royalty Litigation
In June 2000, two overriding royalty owners sued the Company in Wyoming State court for unspecified damages. The plaintiffs have requested class certification under the Wyoming Rules of Civil Procedure and allege that the Company has deducted improper costs of production from royalty payments to the plaintiffs and other similarly situated persons. Additionally, the suit claims that the Company has failed to properly inform the plaintiffs and other similarly situated persons of the deductions taken from royalties. In December 2001, fourteen overriding royalty owners sued the Company in Wyoming federal court. The plaintiffs in the federal case have made the same general claims pertaining to deductions from their overriding royalty as the plaintiffs in the Wyoming state court case but have not asked for class certification.
The Company believes that it has substantial defenses to these claims and intends to vigorously assert such defenses. The Company has a reserve that it believes is adequate to provide for these potential liabilities based on its estimate of the probable outcome of this matter. While the potential impact to the Company may materially affect quarterly or annual financial results including cash flows, management does not believe it would materially impact the Company's financial position.
West Virginia Royalty Litigation
In late December 2001, two royalty owners sued the Company in West Virginia State court for an unspecified amount of damages. The plaintiffs have requested class certification under the West Virginia Rules of Civil Procedure and allege that the Company has failed to pay royalty based upon the wholesale market value of the gas produced, that the Company has taken improper deductions from the royalty and that the Company has failed to properly inform the plaintiffs and other similarly situated persons of deductions taken from the royalty.
Although the investigation into this claim has just begun, the Company intends to vigorously defend the case. Management cannot currently determine the likelihood or range of any potential outcome.
9. Cash Flow Information
Cash paid for interest and income taxes is as follows:
Year Ended December 31,
(In thousands) 2001 2000 1999
-------------------------------------------------
Interest $16,295 $23,180 $25,445
Income Taxes $14,395 $ 1,419 $ 652
|
At December 31, 2001, and 2000, the Accounts Payable balance on the Consolidated Balance Sheet included payables for capital expenditures of $30.9 million and $13.5 million, respectively.
10. Capital Stock
Incentive Plans
On May 3, 2001, the Second Amended and Restated 1994 Long-Term Incentive Plan and the Second 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 5,260,000 shares of Common Stock 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,
2001 2000 1999
-----------------------------------------------------------------------------------
Shares Under Option at Beginning of Period 1,124,148 1,773,389 1,557,936
Granted 454,100 299,250 454,100
Exercised 408,949 896,081 55,032
Surrendered or Expired 87,678 52,410 183,615
-------------------------------------
Shares Under Option at End of Period 1,081,621 1,124,148 1,773,389
=====================================
Options Exercisable at End of Period 355,778 474,599 1,108,637
=====================================
|
For each of the three most recent years, the price range for outstanding options was $14.69 to $27.30 per share. The following tables provide more information about the options by exercise price and year.
Options with exercise prices between $14.69 and $20.00 per share:
December 31,
2001 2000 1999
----------------------------------------------------------------------------------------------------------
Options Outstanding
-------------------
Number of Options 480,561 866,498 1,412,072
Weighted Average Exercise Price $ 17.79 $ 17.63 $ 16.07
Weighted Average Contractual Term (in years) 1.50 2.60 2.40
Options Exercisable
-------------------
Number of Options 211,734 372,418 953,640
Weighted Average Exercise Price $ 17.29 $ 16.27 $ 15.44
Options with exercise prices between $20.01 and $27.30 per share:
December 31,
2001 2000 1999
----------------------------------------------------------------------------------------------------------
Options Outstanding
-------------------
Number of Options 601,060 257,650 361,317
Weighted Average Exercise Price $ 25.44 $ 22.46 $ 22.50
Weighted Average Contractual Term (in years) 4.30 1.90 3.37
Options Exercisable
-------------------
Number of Options 144,044 102,181 154,997
Weighted Average Exercise Price $ 22.45 $ 22.51 $ 22.55
|
Under the Second Amended and Restated 1994 Long-Term Incentive Plan, the Compensation Sub-Committee of the Board of Directors may grant awards of performance shares of stock to members of the executive management group. Each grant of performance shares has a three-year performance period, measured as the change from July 1 of the initial year of the performance period to June 30 of the third year. The number of shares of Common Stock received at the end of the performance period is based mainly on the relative stock price growth between the two measurement dates of Common Stock compared to that of a group of peer companies. The performance shares granted in July 1996 were converted to 19,090 shares of the Company's Common Stock in 1999. The Board of Directors has not issued performance shares since July 1996, and currently, there are no performance shares outstanding.
Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based Compensation," outlines a fair value based method of accounting for stock options or similar equity instruments. The Company has opted to continue using the intrinsic value based method, as recommended by Accounting Principles Board (APB) Opinion No. 25, to measure compensation cost for its stock option plans.
If the Company had adopted SFAS 123, the pro forma results of operations would be as follows:
2001 2000 1999
-------------------------------------------------------------------------------------------------------------
Net Income/(1)/ $45.7 million $28.2 million $ 4.3 million
Net Income per Share $1.51 $1.03 $0.20
Weighted Average Value of
Options Granted During the Year/(2)/ $8.61 $6.63 $4.78
Assumptions
Stock Price Volatility 34.9% 34.5% 27.4%
Risk Free Rate of Return 4.7% 5.21% 5.21%
Dividend Rate (per year) $0.16 $0.16 $0.16
Expected Term (in years) 4 4 4
-------------------------------------------------------------------------------------------------------------
|
/(1)/ Net income is defined as Net Income Available to Common
Shareholders.
/(2)/ 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. None of the note or credit agreements in place 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, 2000 or 2001. The stock repurchase plan was funded from increased borrowings on the revolving credit facility. No treasury shares were delivered or sold by the Company during the year.
Purchase Rights
On January 21, 1991, the Board of Directors adopted the Preferred Stock Purchase Rights Plan and declared a dividend distribution of one right for each outstanding share of Common Stock. On December 8, 2000, the rights agreement for the plan was amended and restated to extend the term of the plan to 2010 and to make other changes. Each right becomes exercisable, at a price of $55, when any person or group has acquired or made a tender or exchange offer for beneficial ownership of 15 percent or more of the Company's outstanding Common Stock. Each right entitles the holder, other than the acquiring person or group, to purchase one one-hundredth of a share of Series A Junior Participating Preferred Stock (Junior Preferred Stock). After a person or group acquires beneficial ownership of 15% of the Common Stock, each right entitles the holder to purchase Common Stock or other property having a market value (as defined in the plan) of twice the exercise price of the right. An exception to this triggering event applies in the case of a tender or exchange offer for all outstanding shares of Common Stock determined to be fair and in the best interests of the Company and its stockholders by a majority of the independent directors. Under certain circumstances, the Board of Directors may opt to exchange one share of Common Stock for each exercisable right. If there is a 15% holder and the Company is acquired in a merger or other business combination in which it is not the survivor, or 50 percent or more of the Company's assets or earning power are sold or transferred, each right entitles the holder to purchase common stock of the acquiring company with a market value (as defined in the plan) equal to twice the exercise price of each right. At December 31, 2001, and 2000, there were no shares of Junior Preferred Stock issued or outstanding.
The rights expire on January 21, 2010, and may be redeemed by the Company for $0.01 per right at any time before a person or group acquires beneficial ownership of 15% of the Common Stock.
Preferred Stock
At December 31, 1999 and 1998, 1,134,000 shares of 6% convertible redeemable preferred stock (6% preferred stock) were issued and outstanding. The shares of 6% preferred stock were issued in May 1994 to the seller in connection with Cabot Oil & Gas' acquisition of a subsidiary of the seller. The 6% preferred stock had a liquidation preference of $50 per share, provided for quarterly cash dividends at the rate of 6% per annum, was convertible into Cabot Oil & Gas Class A common stock at the holder's option at a conversion price of $28.75, and was entitled to 1.739 votes per share, generally voting together with the Class A common stock. The 6% preferred stock was not redeemable at the holder's option, but was redeemable at the option of Cabot Oil & Gas commencing in May 1998 at a price of $50 per share, payable in shares of Class A common stock until May 1999 and in cash thereafter, plus cash in an amount equal to accrued and unpaid dividends.
In October 1999, Cabot Oil & Gas agreed with the holder of the 6% preferred stock that the Company would repurchase all the 6% preferred stock for $51.6 million in cash or Class A common stock. During the second
quarter of 2000, the Company completed this repurchase and paid the holder of the preferred stock $51.6 million in cash. The cash payment was funded using a portion of the proceeds from the issuance of 3,400,000 shares of Class A common stock in a registered offering at a price of $21.50 per share (yielding net proceeds of $71.5 million, after expenses). The remaining proceeds of this offering of Class A common stock were used to reduce borrowings under the revolving credit facility.
The difference between the payment to the holder of the 6% preferred stock ($51.6 million) and the carrying amount of the 6% preferred stock on the Company's balance sheet ($56.7 million) was added to net earnings available to common shareholders in the calculation of earnings per share. This difference represents a forgone return to the preferred shareholder and is treated similar to a dividend; accordingly, a negative dividend of $5.1 million was recognized upon the repurchase.
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.
Long-Term Debt
December 31, 2001 December 31, 2000
Carrying Estimated Carrying Estimated
(In thousands) Amount Fair Value Amount Fair Value
----------------------------------------------------------------
Debt
10.18% Notes $ -- $ -- $ 32,000 $ 33,162
7.19% Notes 100,000 104,961 100,000 97,033
7.26% Notes 75,000 79,187 -- --
7.36% Notes 75,000 79,225 -- --
7.46% Notes 20,000 21,097 -- --
Credit Facility 123,000 123,000 137,000 137,000
-------------------------------------------
$393,000 $407,470 $269,000 $267,195
===========================================
|
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, the 7.19% Notes, the 7.26% Notes, the 7.36% Notes and the 7.46% Notes is based on interest rates currently available to the Company. The 10.18% Notes were repaid in May 2001. The Credit Facility approximates fair value because this instrument bears interest at rates based on current market rates.
Commodity Price Swaps and Options
Hedges on Production - 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. During 2001, the Company fixed the price at an average of $3.75 per Mcf on quantities totaling 918 Mmcf, representing 1% of the Company's 2001 natural gas production. The Company did not have crude oil swap arrangements covering its production in 2001. During 2000, the Company fixed the price at an average of $4.54 per Mcf on quantities totaling 315 Mmcf, representing less than 1% of the Company's 2000 natural gas production. The notional volume of the crude oil swap transactions was 364 Mbbls at a price of $22.67 per Bbl, which represents approximately 38% of the Company's total oil production for 2000. During 1999, the Company fixed the price at an average of $2.88 per Mcf on quantities totaling 3,237 Mmcf, representing 5% of the Company's 1999 natural gas production. The notional volume of the crude oil swap transactions was 306 Mbbls at a price of $20.65 per Bbl, which represents approximately one-third of the Company's total oil production for 1999.
The natural gas price swap arrangement that the Company entered into during the third quarter of 2000 covered a portion of production over the period of October 2000 through September 2003. However, the counterparty declared bankruptcy in December 2001. Based on the terms of the natural gas swap contract, this action results in the cancellation of the contract. As of the years ending December 31, 2001, and 2000, the Company had open natural gas price swap contracts on its production as follows:
Natural Gas Price Swaps
----------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Mmcf Contract Price (in $ millions)
--------------------------------------------------------------------------------------
As of December 31, 2001
-----------------------
None
As of December 31, 2000
-----------------------
Natural Gas Price Swaps on Production in:
----------------------------------------
Full Year 2001 918 $3.75 $(2.8)
Full Year 2002 678 3.11 (1.0)
Full Year 2003 423 2.81 (0.5)
|
Financial derivatives related to natural gas production reduced revenues by $0.8 million in 2001 and $0.3 million in 2000.
The Company had no open oil price swap contracts outstanding on its production at December 31/st/ of 2001 or 2000. Financial derivatives related to crude oil reduced revenue by $2.2 million during 2000, but had no impact on 2001 results.
Hedges on Production - Options
In December 2000, management believed that the pricing environment provided a strategic opportunity to significantly reduce the price risk on a portion of the Company's production through the use of costless collars. Under the costless collar arrangements, if the index rises above the ceiling price, the Company pays the counterparty. If the applicable index falls below the floor, the counterparty pays the Company. The natural gas price hedges include several costless collar arrangements based on eight price indexes at which the Company sells a portion of its production. These hedges were in place for the months of February through October 2001 and covered 24,404 Mmcf, or 35%, of the Company's natural gas production for the year. All indexes were within the collars during February and April, some fell below the floor during the period of March, and all indexes were below the floor from June through October, resulting in $34.6 million cash revenue for the year. This revenue contributed $0.50 per Mcf to the Company's average realized natural gas price for 2001.
During 2000, the Company used several costless collar arrangements to hedge a portion of its natural gas production. There were seven collar arrangements based on separate regional price indexes with a weighted average price floor of $2.74 per Mcf and a weighted average price ceiling of $3.38 per Mcf. These collars were in place during the months of April through October 2000. These collars covered a total quantity of 9,909 Mmcf, or 16% of the Company's annual production. In April and May 2000, the index prices all fell within the price collar and no settlements were made. In June 2000, all of the indexes rose above the ceiling prices and remained above the ceiling for the duration of the transaction resulting in a $10 million reduction to the Company's realized revenue for the year. If these hedges had not been in place, the Company's average realized natural gas price for 2000 would have been $0.17 per Mcf higher.
Again in December of 2001, management believed that the pricing environment provided a strategic opportunity to significantly reduce the price risk on a portion of the Company's future production through the use of natural gas price collar arrangements. A premium totaling $0.9 million was paid to purchase these collar arrangements. This cost will be expensed as the instruments are marked- to-market each quarter. As of December 31, 2001, the Company had open natural gas price collar arrangements to hedge production as follows:
Natural Gas Price Collars
-----------------------------------------
Volume Weighted Unrealized
in Average Gain/(Loss)
Contract Period Mmcf Ceiling / Floor (in $ millions)
-----------------------------------------------------------------------------------------------
As of December 31, 2001
-----------------------
Natural Gas Collars on Production in:
------------------------------------
First Quarter of 2002 12,082 $3.54/$2.68 --
Second Quarter of 2002 4,027 $3.54/$2.68 --
As of December 31, 2000
-----------------------
Natural Gas Costless Collars on Production in:
---------------------------------------------
First Quarter of 2001 5,274 $9.68/$5.59 --
Second Quarter of 2001 8,135 $9.68/$5.59 --
Third Quarter of 2001 8,224 $9.68/$5.59 --
Fourth Quarter of 2001 2,771 $9.68/$5.59 --
|
The natural gas price hedges open at December 31, 2001, noted above, include several collar arrangements based on nine price indexes at which the Company sells a portion of its production. These hedges are in place for the months of January through April 2002 and cover approximately 60% of the Company's anticipated natural gas production during this period. A premium totaling $0.9 million was paid to purchase these collar arrangements.
Hedges on Brokered Transactions
The Company uses price swaps to hedge the natural gas price risk on brokered transactions. Typically, the Company enters into contracts to broker natural gas at a variable price based on the market index price. However, in some circumstances, some of the customers or suppliers request that a fixed price be stated in the contract. After entering into these fixed price contracts to meet the needs of the customers or suppliers, the Company may use price swaps to effectively convert these fixed price contracts to market-sensitive price contracts. These price swaps were held by the Company to their maturity and are not held for trading purposes.
The Company entered into price swaps with total notional quantities of 1,295 Mmcf in 2000, and 3,572 Mmcf in 1999 related to its brokered activities, representing 3% and 7% respectively, of its total volume of brokered natural gas sold. The Company did not use price swaps on brokered transactions in 2001.
As of the years ending December 31, 2000 and 2001, the Company had no open natural gas price swap contracts on brokered transactions. Financial derivatives related to natural gas reduced revenues by less than $0.1 million in 2000 and had no impact on revenue in 2001.
The Company is exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and oil. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged.
Adoption of SFAS 133
The Company adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) on January 1, 2001. Under SFAS 133, the fair value of each derivative instrument is recorded as either an asset or liability on the balance sheet. At the end of each period, these instruments are marked-to-market. The gain or loss on the change in fair value is recorded as Other Comprehensive Income, a component of equity, to the extent that the derivative instrument is an effective hedge. Under SFAS 133, effectiveness is a measurement of how closely correlated the hedge instrument is with the underlying physical sale. For example, a natural gas price swap that converts Henry Hub index to a fixed price would be perfectly correlated, and 100% effective, if the underlying gas was sold at the Henry Hub index. Any portion of the gains or losses that are considered ineffective under the SFAS 133 test are recorded immediately as a component of operating revenue on the statement of operations.
When the Company adopted SFAS 133, two types of hedges were in place. The first type was a cash flow hedge that sets the price of a certain monthly quantity of natural gas sold in the Gulf Coast region through September
2003. Based on the index price strip, the impact of this hedge on January 1, 2001 was to record a Hedge Loss of $0.1 million and a charge to Other Comprehensive Income of $4.2 million. Correspondingly, a Hedge Liability for $4.3 million was established. This instrument was cancelled in the December 2001 with the bankruptcy of the counterparty. No balance related to this hedge remains in Other Comprehensive Income.
The second type of hedge outstanding at January 1, 2001 was a natural gas
price costless collar agreement. The Company had entered into eight of these
collars for a portion of its production at regional indexes for the months of
February through October 2001. The collars had two components of value:
intrinsic value and time value. Under SFAS 133, both components were valued at
the end of each reporting period. Intrinsic value arises when the index price is
either above the ceiling or below the floor for any period covered by the
collar. If the index is above the ceiling for any month covered by the collar,
the intrinsic value would be the difference between the index and the ceiling
prices multiplied by the notional volume. Similar to the current accounting
treatment, intrinsic value related to the current month would be recorded as a
hedge loss (if the index is above the ceiling) or gain (if the index is below
the floor). Starting in 2001 under SFAS 133, any changes in the intrinsic value
component related to future months were recorded in Other Comprehensive Income,
a component of stockholders' equity on the balance sheet, rather than to the
income statement to the extent that the hedge was proven to be effective. These
natural gas price collars were considered to be highly effective with
respect to the intrinsic value calculation since they were tied to the same
indexes at which the Company's natural gas is sold. Also under SFAS 133, the
time value component, a market premium/discount, was marked-to-market through
the income statement each period. Since these collar arrangements were executed
on the last business day of 2000, the net premium value at adoption on January
1, 2001 was zero.
As of December 31, 2001, the Company had a series of nine natural gas price collar arrangements in place. In accordance with the latest guidance from the FASB's Derivative Implementation Group, the Company determines the effectiveness of the combined intrinsic and time values, and the effective portion of each will be recorded as a component of Other Comprehensive Income. Any ineffective portion will be recorded as a gain or loss in the current period. As of December 31, 2001, the Company had recorded $1.4 million of Other Comprehensive Income ($0.8 million net of deferred taxes), a $0.1 million Unrealized Hedge Gain and a $1.5 million Hedge Asset.
Other Comprehensive Income
Comprehensive income includes net income and certain items recorded directly to stockholders' equity and classified as Other Comprehensive Income. The Company recorded Other Comprehensive Income for the first time in January of 2001. Following the adoption of SFAS 133, the Company recorded an after-tax credit to Other Comprehensive Income of $0.8 million in 2001 related to the change in fair value of certain derivative financial instruments that has qualified for cash flow hedge accounting.
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 2001, 2000 or 1999.
12. Oil and Gas Property Transactions
In September and December 1999, the Company purchased oil and gas producing properties in the Moxa Arch of the Green River Basin in southwest Wyoming for $8.9 and $8.5 million, respectively. The assets included approximately 16 Bcfe of proved reserves, approximately 43,000 undeveloped net acres, and 27 wells producing a net 3.8 Mmcfe per day at the time of the acquisition.
Also in September 1999, the Company sold non-strategic oil and gas properties located in Pennsylvania and West Virginia to EnerVest for approximately $46 million. These properties represented 716 wells and 62.2 Bcfe of proved reserves.
The property transactions in September and December 1999 qualified in part for Section 1031 exchange treatment for tax purposes. This treatment resulted in the $8.9 million deferred gain for tax purposes. For tax purposes, the assets acquired in the exchange were recorded at the value (tax basis) of the assets given up. The "gain" is deferred and recognized through lower tax depreciation on these assets and/or by inclusion in the taxable gain/loss calculation should these assets be subsequently sold.
For financial statement purposes, these transactions were treated as a purchase and a sale, as opposed to a deferred transaction. The asset sale resulted in a $4.1 million gain for financial statement purposes, which was recorded in September 1999.
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 $9.1 million, and the transaction contributed to a gain of approximately $1.0 million on the Company's second quarter income statement.
13. Other Revenue
Settlement of Contract Dispute
During 2000, the Company reached settlement on a natural gas contract dispute. As a result, the Company recorded net revenue of approximately $2.3 million to Other Revenue during 2000.
The dispute involved a contract under which the customer was obligated to take-or-pay a daily base quantity of natural gas over a 10-year period ending in 2003. The customer also agreed to pay a reservation charge in exchange for the right to purchase optional quantities of natural gas from the Company. The sales price of the natural gas sold under this contract increased over time.
In 1997, the customer's parent company decided to close the facility that was purchasing the gas from the Company. The Company agreed to market the gas that had been committed to the customer and the customer agreed to pay the difference between the price the Company received and an agreed upon price until December 31, 1998. Starting on January 1, 1999, the customer again became responsible for purchasing the gas under the original contract terms. The Company invoiced the customer for the contractual sales quantities during 1999, but received no payment. The unpaid balance was included in accounts receivable.
When the Company reached the contract settlement with this customer in the first quarter of 2000, a portion of the settlement was used to satisfy the accounts receivable account. The remainder represented a contract buy-out and was recorded in Other Revenue. No reserve had been recorded for this dispute.
Sales Contract
The Company had a 15-year natural gas sales contract under which approximately 20% of the Western region natural gas was sold per year to an independent third-party cogeneration facility. The contract was a standard long- term, natural gas sales contract under which the Company sold gas to the facility for a fixed price, which escalated annually. Revenue from the sale of natural gas is included in "Natural Gas Production" on the Consolidated Statement of Operations. The contract was due to expire in 2008. The customer requested to be released from the contract, and during 1999, the Company reached an agreement with the customer under which the
customer bought out the remainder of the contract for a $12 million cash payment to the Company in exchange for a release from future obligations under the contract. This transaction was completed in December 1999, and the $12 million payment was recorded as other revenue. Simultaneously, the Company sold forward a similar monthly volume of Western region gas through April 2001 at prices similar to those in the monetized contract.
Section 29 Tax Credits
Other revenue includes income generated from the monetization of the value of Section 29 tax credits (monetized credits) from most of the Company's qualifying Appalachian and Rocky Mountains properties. Revenue from these monetized credits was $2.0 million in 2001, $2.2 million in 2000, and $1.3 million in 1999. These monetized credits are expected to generate future revenues in 2002 of $2.1 million. The production, revenues, expenses and proved reserves for these properties will continue to be reported by the Company as Other Revenue until the production payment is satisfied.
During 1999, an industry tax court ruling concluded that the Section 29
tight sands tax credits (Section 29 credits) would not be available on wells not
certified by the FERC. Because the FERC discontinued the certification process
for qualifying wells in 1992, there was no avenue to obtain the well
certifications. Accordingly, the Company stopped recording revenue on non-
certified wells and established a reserve related to previously recorded amounts
on these wells. This resulted in a $1.2 million reduction to other revenue in
1999. Subsequent to 1999, the certification process has been reinstated by FERC,
and the Company has begun applying for the well certificates and accruing
Section 29 credit revenues related to these wells.
14. Acquisition of Cody Company
Effective in August 2001, the Company acquired the stock of Cody Company, the parent of Cody Energy LLC ("Cody acquisition") for $231.2 million comprised of $181.3 million of cash and 1,999,993 shares of common stock valued at $49.9 million. Substantially all of the proved reserves of Cody Company are located in the onshore Gulf Coast region. The acquisition was accounted for using the purchase method of accounting. As such, the Company reflected the assets and liabilities acquired at fair value in the Company's balance sheet effective August 1, 2001 and the results of operations of Cody Company beginning August 1, 2001. The purchase price totaling approximately $315.6 million was allocated to specific assets and liabilities based on certain estimates of fair values resulting in approximately $302.4 million allocated to property and $13.2 million allocated to working capital items. This $315.6 million amount was inclusive of a $78.0 million non-cash item pertaining to the deferred income taxes attributable to the differences between the tax basis and the fair value of the acquired oil and gas properties, and acquisition related fees and costs of $6.4 million. The purchase price allocation is preliminary and subject to change as additional information becomes available. Management does not expect the final purchase price allocation to differ materially from the preliminary allocation.
The following unaudited pro forma condensed income statement information has been prepared to give effect to the Cody acquisition as if it had occurred on January 1, 2000. The information presented is not necessarily indicative of the results of future operations of the Company.
Year Ended December 31,
(In thousands) 2001 2000
--------------------------------------------------------------------------
Revenues $505,528 $444,793
Net Income $ 54,513 $ 25,997
per share - Basic $ 1.75 $ 0.90
per share - Diluted $ 1.73 $ 0.89
|
The results of operations for Cody Company are consolidated with Cabot Oil & Gas Corporation as of August 1, 2001.
15. Earnings per Common Share
Full year basic earnings per share for the Company were $1.56, $1.07, and $0.21 in 2001, 2000, and 1999, respectively, and were based on the weighted average shares outstanding of 30,275,906 in 2001, 27,383,848 in 2000, and 24,726,030 in 1999. Diluted earnings per share for the Company were $1.53, $1.06, and $0.21 in 2001, 2000, and 1999, 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 408,361 in 2001, 281,210 in 2000, and 225,177 in 1999.
The 6% convertible redeemable preferred stock issued May 1994 had an antidilutive effect on earnings per common share. The preferred stock was determined not to be a common stock equivalent when it was issued. As such, no adjustments were made to net income in the computation of earnings per share for 1999. No preferred stock was outstanding at the end of 2000 or 2001. See Note 10 Capital Stock for further discussion.
CABOT OIL & GAS CORPORATION
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Oil and Gas Reserves
Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, 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, 2001, 2000, and 1999 were based on studies performed by the Company's petroleum engineering staff. The estimates were reviewed by Miller and Lents, Ltd., who indicated in their letter dated February 8, 2002, 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, 2001, 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.
Natural Gas
-----------------------------------
December 31,
(Millions of cubic feet) 2001 2000 1999
------------------------------------------------------------------------------------
Proved Reserves
Beginning of Year 959,222 929,602 996,756
Revisions of Prior Estimates (44,266) (14,796) (1,555)
Extensions, Discoveries and Other Additions 99,911 103,600 52,781
Production (69,162) (60,934) (65,502)
Purchases of Reserves in Place 91,290 5,118 26,515
Sales of Reserves in Place (991) (3,368) (79,393)
-----------------------------------
End of Year 1,036,004 959,222 929,602
===================================
Proved Developed Reserves 804,646 754,962 720,670
===================================
Percentage of Reserves Developed 77.7% 78.7% 77.5%
===================================
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Liquids
----------------------------------
December 31,
(Thousands of barrels) 2001 2000 1999
-----------------------------------------------------------------------------------
Proved Reserves
Beginning of Year 9,914 8,189 7,677
Revisions of Prior Estimates 254 562 128
Extensions, Discoveries and Other Additions 2,257 2,032 1,292
Production (1,996) (988) (963)
Purchases of Reserves in Place 9,255 120 362
Sales of Reserves in Place -- (1) (307)
----------------------------------
End of Year 19,684 9,914 8,189
==================================
Proved Developed Reserves 15,328 8,438 5,546
==================================
Percentage of Reserves Developed 77.9% 85.1% 67.7%
==================================
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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) 2001 2000 1999
-------------------------------------------------------------------------------------
Aggregate Capitalized Costs Relating
to Oil and Gas Producing Activities $1,632,101 $1,180,692 $1,088,640
Aggregate Accumulated Depreciation,
Depletion and Amortization $ 651,657 $ 558,463 $ 499,201
|
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) 2001 2000 1999
-------------------------------------------------------------------------------------
Property Acquisition Costs, Proved /(1)/ $245,079 $ 5,954 $18,395
Property Acquisition Costs, Unproved /(1)/ 21,116 10,869 7,163
Exploration and Extension Well Costs /(2)/ 91,261 40,008 16,117
Development Costs 90,246 59,879 39,239
------------------------------------
Total Costs $447,702 $116,710 $80,914
====================================
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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) 2001 2000 1999
-------------------------------------------------------------------------------------
Operating Revenues $339,064 $214,116 $156,018
Costs and Expenses
Production 58,382 46,721 41,942
Other Operating 22,656 17,249 17,009
Exploration /(1)/ 71,165 19,858 11,490
Depreciation, Depletion and Amortization 89,286 63,200 62,446
------------------------------------
Total Costs and Expenses 241,489 147,028 132,887
------------------------------------
Income Before Income Taxes 97,575 67,088 23,131
Provision for Income Taxes 34,151 23,481 8,096
------------------------------------
Results of Operations $ 63,424 $ 43,607 $ 15,035
====================================
|
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, 2001, 2000, and 1999 for natural gas ($ per Mcf) were $2.65, $9.63, and $2.36, respectively, and for oil ($ per Bbl) were $18.56, $26.18, and $24.15, 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.
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) 2001 /(1)/ 2000 /(1)/ 1999 /(1)/
------------------------------------------------------------------------------------
Future Cash Inflows $ 3,107,668 $ 9,497,181 $ 2,401,349
Future Production Costs (823,988) (1,435,489) (622,025)
Future Development Costs (266,833) (192,893) (164,377)
----------- ----------- -----------
Future Net Cash Flows Before Income Taxes 2,016,847 7,868,799 1,614,947
10% Annual Discount for Estimated
Timing of Cash Flows (1,065,747) (4,332,551) (877,129)
----------- ----------- -----------
Standardized Measure of Discounted Future
Net Cash Flows Before Income Taxes 951,100 3,536,248 737,818
Future Income Tax Expenses,
Net of 10% Annual Discount /(2)/ (185,074) (1,126,416) (150,261)
---------------------------------------
Standardized Measure of Discounted
Future Net Cash Flows $ 766,026 $ 2,409,832 $ 587,557
=======================================
|
/(2)/ Future income taxes before discount were $558,085, $2,642,810, and $457,256 for the years ended December 31, 2001, 2000 and 1999, respectively.
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following is an analysis of the changes in the Standardized Measure:
Year Ended December 31,
(In thousands) 2001 2000 1999
---------------------------------------------------------------------------------------------
Beginning of Year $ 2,409,832 $ 587,557 $ 594,078
Discoveries and Extensions,
Net of Related Future Costs 100,084 486,236 65,210
Net Changes in Prices and Production Costs /(1)/ (2,545,349) 2,441,921 1,354
Accretion of Discount 353,625 73,782 73,893
Revisions of Previous Quantity
Estimates, Timing and Other (358,134) (81,093) (20,162)
Development Costs Incurred 26,158 28,540 19,586
Sales and Transfers, Net of Production Costs (280,682) (167,395) (114,076)
Net Purchases (Sales) of Reserves in Place 119,149 16,440 (26,916)
Net Change in Income Taxes 941,343 (976,156) (5,410)
------------------------------------
End of Year $ 766,026 $2,409,832 $ 587,557
====================================
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CABOT OIL & GAS CORPORATION
SELECTED DATA (UNAUDITED)
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
(In thousands, except per share amounts) First Second Third Fourth Total --------------------------------------------------------------------------------------------- 2001 Operating Revenues $154,891 $107,606 $104,226 $ 80,319 $447,042 Impairment of Long-Lived Assets -- -- 1,721 5,131 6,852 Operating Income (Loss) 68,526 26,976 21,601 (21,737) 95,366 Net Income (Loss) 39,062 13,593 10,031 (15,602) 47,084 Basic Earnings per Share $ 1.33 $ 0.46 $ 0.33 $ (0.49) $ 1.56 Diluted Earnings per Share $ 1.32 $ 0.45 $ 0.32 $ (0.49) $ 1.53 2000 Operating Revenues $ 85,120 $ 82,447 $ 86,237 $114,847 $368,651 Impairment of Long-Lived Assets -- 9,143 -- -- 9,143 Operating Income 14,773 420 15,799 33,825 64,817 Net Income 4,494 1,518 6,137 17,072 29,221 Basic Earnings per Share $ 0.18 $ 0.05 $ 0.21 $ 0.59 $ 1.07 Diluted Earnings per Share $ 0.18 $ 0.05 $ 0.21 $ 0.58 $ 1.06 --------------------------------------------------------------------------------------------- |
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information under the caption "Election of Directors" in the Company's definitive Proxy Statement in connection with the 2001 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 41.
2. Financial Statement Schedules
None.
3. Exhibits
The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith.
Exhibit
Number Description
------ -----------
3.1 Certificate of Incorporation of the Company (Registration Statement No.
33-32553).
3.2 Amended and Restated Bylaws of the Company amended September 6, 2001.
4.1 Form of Certificate of Common Stock of the Company (Registration Statement
No. 33-32553).
4.2 Certificate of Designation for Series A Junior Participating Preferred
Stock (Form 10-K for 1994).
4.3 Rights Agreement dated as of March 28, 1991, between the Company and The
First National Bank of Boston, as Rights Agent, which includes as Exhibit
A the form of Certificate of Designation of Series A Junior Participating
Preferred Stock (Form 8-A, File No. 1-10477).
(a) Amendment No. 1 to the Rights Agreement dated February 24, 1994 (Form
10-K for 1994).
(b) Amendment No. 2 to the Rights Agreement dated December 8, 2000 (Form
8-K for December 21, 2000).
4.4 Certificate of Designation for 6% Convertible Redeemable Preferred Stock
(Form 10-K for 1994).
4.5 Amended and Restated Credit Agreement dated as of May 30, 1995, among the
Company, Morgan Guaranty Trust Company, as agent and the banks named
therein.
(a) Amendment No. 1 to Credit Agreement dated September 15, 1995 (Form 10-
K for 1995).
(b) Amendment No. 2 to Credit Agreement dated December 24, 1996 (Form 10-K
for 1996).
4.6 Note Purchase Agreement dated May 11, 1990, among the Company and certain
insurance companies parties thereto (Form 10-Q for the quarter ended June
30, 1990).
(a) First Amendment dated June 28, 1991 (Form 10-K for 1994).
(b) Second Amendment dated July 6, 1994 (Form 10-K for 1994).
4.7 Note Purchase Agreement dated November 14, 1997, among the Company and the
purchasers named therein (Form 10-K for 1997).
4.8 Note Purchase Agreement dated as of July 26, 2001 among Cabot Oil & Gas
Corporation and the Purchasers listed therein (Form 8-K for August 30,
2001).
|
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.
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).
Exhibit
Number Description
--------------------------------------------------------------------------------
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).
10.11 Supplemental Executive Retirement Agreements of the Company (Form 10-K
for 1991).
10.12 Settlement Agreement and Mutual Release (Tax Issues) between Cabot
Corporation and the Company dated July 7, 1992 (Form 10-Q for the
quarter ended June 30, 1992).
10.13 Agreement of Merger dated February 25, 1994, among Washington Energy
Company, Washington Energy Resources Company, the Company and COG
Acquisition Company (Form 10-K for 1993).
10.14 1990 Non-employee Director Stock Option Plan of the Company (Form S-8
dated June 23, 1990).
(a) First Amendment to 1990 Non-employee Director Stock Option Plan
(Post-Effective Amendment No. 2 to Form S-8 dated March 7, 1994).
(b) Second Amendment to 1990 Non-employee Director Stock Option Plan
(Form 10-K for 1995).
10.15 Second Amended and Restated 1994 Long-Term Incentive Plan of the
Company.
10.16 Second Amended and Restated 1994 Non-Employee Director Stock Option
Plan.
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 as Amended September 1, 2001.
10.20 Trust Agreement dated September 2000 between Harris Trust and Savings
Bank and the Company.
10.21 Lease Agreement between the Company and DNA COG, Ltd. dated April 24,
1998 (Form 10-K for 1998).
10.22 Credit Agreement dated as of December 17, 1998, between the Company and
the banks named therein (Form 10-K for 1998).
10.23 Letter Agreement with Puget Sound Energy Company dated September 21,
1999 (Form 10-K for 1999).
10.24 Agreement and Plan of Merger, dated June 20, 2001, among Cabot Oil & Gas
Corporation, COG Colorado Corporation, Cody Company and the shareholders
of Cody Company (Form 8-K for June 28, 2001).
(a) Amendment to Agreement and Plan of Merger dated as of July 10, 2001
to the Agreement and plan of Merger, dated June 20, 2001, among
Cabot Oil & Gas Corporation, COG Colorado Corporation, Cody Company
and the shareholders of Cody Company (Form 8-K for August 30, 2001).
(b) Closing Agreement dated August 16, 2001 (Form 8-K for August 30,
2001).
10.25 Employment Agreement between the Company and Dan O. Dinges dated August
29, 2001.
21.1 Subsidiaries of Cabot Oil & Gas Corporation.
23.1 Consent of PricewaterhouseCoopers LLP.
23.2 Consent of Miller and Lents, Ltd.
28.1 Miller and Lents, Ltd. Review Letter dated February 8, 2002.
|
B. REPORTS ON FORM 8-K
Item 2: Acquisition or Disposition of Assets filing made on October 30, 2001 as
an amendment to the August 30, 2001 Form 8-K. This amendment includes Item 7.
Financial Statements and Exhibits.
Item 5: Other Events filing made on January 8, 2002 includes Item 7. Press
Release dated December 14, 2001 and titled "Cabot Oil & Gas Announces Natural
Gas Hedges."
Item 5: Other Events filing made on January 28, 2002 includes Item 7. Press
Release dated January 22, 2002 and titled "Cabot Oil & Gas Provides 2001 Capital
Program Update", and Item 7. Press Release dated January 24, 2002 and titled
"Cabot Oil & Gas Announces Full Year and Fourth Quarter Results."
Item 5: Other Events filing made on February 20, 2002 includes Item 7. Press
Release dated February 14, 2002 and titled "Cabot Oil & Gas Finalizes Year-End
Reserves", and Item 7. Press Release dated February 19, 2002 and titled "Cabot
Oil & Gas Chairman & CEO to Retire."
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 19/th/ of February 2002.
CABOT OIL & GAS CORPORATION
By: /s/ Ray R. Seegmiller
------------------------------------
Ray R. Seegmiller
Chairman of the Board and
Chief Exective Officer
|
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 and Chief February 19, 2002
-------------------------
Ray R. Seegmiller Executive Officer
(Principal Executive Officer)
/s/ Dan O. Dinges President and Chief Operating February 19, 2002
-------------------------
Dan O. Dinges Officer
/s/ Scott C. Schroeder Vice President, Chief Financial Officer February 19, 2002
-------------------------
Scott C. Schroeder and Treasurer
(Principal Financial Officer)
/s/ Henry C. Smyth Vice President and Controller February 19, 2002
-------------------------
Henry C. Smyth (Principal Accounting Officer)
/s/ Robert F. Bailey Director February 19, 2002
-------------------------
Robert F. Bailey
/s/ Henry O. Boswell Director February 19, 2002
-------------------------
Henry O. Boswell
/s/ John G. L. Cabot Director February 19, 2002
-------------------------
John G. L. Cabot
/s/ James G. Floyd Director February 19, 2002
-------------------------
James G. Floyd
/s/ C. Wayne Nance Director February 19, 2002
-------------------------
C. Wayne Nance
|
/s/ P. Dexter Peacock Director February 19, 2002 --------------------------- P. Dexter Peacock /s/ Charles P. Siess, Jr. Director February 19, 2002 --------------------------- Charles P. Siess, Jr. /s/ Arthur L. Smith Director February 19, 2002 --------------------------- Arthur L. Smith /s/ William P. Vititoe Director February 19, 2002 --------------------------- William P. Vititoe |
Exhibit 3.2
AMENDED AND RESTATED
BY-LAWS
OF
CABOT OIL & GAS CORPORATION
Adopted August 5, 1994
Amended February 20, 1997
Amended May 3, 2001
Amended September 6, 2001
I. Certificate of Incorporation................................ 1
II. Annual Meeting of Stockholders.............................. 2
III. Special Meetings of Stockholders............................ 3
IV. Place of Stockholders' Meetings............................. 3
V. Notice of Stockholders' Meetings............................ 3
VI. Quorum and Action of Stockholders........................... 8
VII. Proxies and Voting.......................................... 9
VIII. Action by Written Consent................................... 10
IX. Board of Directors.......................................... 12
X. Powers of the Board of Directors............................ 14
XI. Executive Committee......................................... 14
XII. Committees.................................................. 16
XIII. Meetings of the Board of Directors.......................... 16
XIV. Quorum and Action of Directors.............................. 17
XV. Restrictions on Stock Transfer.............................. 18
XVI. Compensation of Directors................................... 18
XVII. Officers and Agents......................................... 19
XVIII. Chairman of the Board of Directors.......................... 19
XIX. President.................................................... 20
XX. Executive Vice Presidents, Senior Vice Presidents............ 21
XXI. Chief Financial Officer...................................... 21
XXII. Secretary and Assistant Secretaries.......................... 22
XXIII. Treasurer and Assistant Treasurers........................... 23
XXIV. General Counsel and Assistant General Counsels............... 24
XXV. Controller................................................... 25
XXVI. Resignations and Removals.................................... 26
XXVII. Vacancies.................................................... 27
XXVIII. Waiver of Notice............................................. 28
XXIX. Certificates of Stock........................................ 28
XXX. Transfer of Shares of Stock.................................. 29
XXXI. Transfer Books: Record Date.................................. 30
XXXII. Loss of Certificates......................................... 31
XXXIII. Seal......................................................... 31
XXXIV. Execution of Papers.......................................... 31
XXXV. Fiscal Year.................................................. 32
XXXVI. Dividends.................................................... 32
XXXVII. Respecting Certain Contracts................................. 32
XXXVIII. Indemnification of Directors, Officers and Employees......... 33
XXXIX. Amendments................................................... 35
The name, location of the principal office or place of business in Delaware, and the objects or purposes of the Corporation shall be as set forth in its Certificate of Incorporation. These By-laws, the powers of the Corporation and of its directors and stockholders, and all matters concerning the management of the business and conduct of the affairs of the Corporation shall be subject to such provisions in regard thereto, if any, as are set forth in the Certificate of Incorporation; and the Certificate of Incorporation is hereby made a part of these By-laws. In these By-laws, references to the Certificate of Incorporation mean the provisions of the Certificate of Incorporation (as that term is defined in the General Corporation Law of the State of Delaware) of the Corporation as from time to time in effect, and references to these By-laws or to any requirement or provision of law mean these By-laws or such requirement or provision of law as from time to time in effect.
The annual meeting of stockholders shall be held at such date and time as the Board of Directors may designate. Purposes for which the annual meeting is to be held, in addition to those prescribed by law, by the Certificate of Incorporation and by these By-laws, may be specified by the chairman of the board of directors, the president or by the board of directors.
If the election of directors shall not be held on the day provided for by these By-laws, the directors shall cause the election to be held as soon thereafter as convenient, and to that end, if the election of directors shall not be held at the annual meeting, a special meeting of the stockholders may be held in place of such omitted meeting or election, and any business transacted or election held at such special meeting shall have the same effect as if transacted or held at the annual meeting, and in such cases all references in these By-laws, except in this Article II and in Article IV to the annual meeting of the stockholders, or to the annual election of directors, shall be deemed to refer to or include such special meeting. Any such special meeting shall be called, and the purposes thereof shall be specified in the call, as provided in Article III.
The Chairman of a meeting of stockholders may adjourn the meeting from time to time. No notice of the time and place of adjourned meetings need be given except as required by law. The stockholders present at a duly called meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough stockholders to leave less than a quorum. Any previously scheduled meeting of the stockholders may be postponed, by resolution of the Board of
Directors upon public notice given prior to the date previously scheduled for such meeting of stockholders.
A special meeting of the stockholders may be called at any time by the chairman of the board of directors, the president or by the board of directors. Such call shall state the time, place and purposes of the meeting.
The annual election of directors, whether at the original or any adjourned session of the annual meeting of the stockholders or of a special meeting held in place thereof, shall be held at such place as the board of directors shall fix for each such meeting. Sessions of such meetings for any other purposes, and the original or any adjourned session of any other special meeting of the stockholders, shall be held at such place within or without the State of Delaware as shall be stated in the call or in the vote of adjournment, as the case may be.
Except as may be otherwise required by law, by the Certificate of Incorporation or by other provisions of these By-laws, a written notice of each meeting of stockholders, stating the place, day and hour thereof and the purposes for which the meeting is called, shall be given, at least ten days but no more than sixty days before the
date of the meeting, to each stockholder entitled to vote thereat by leaving such notice with him or her or at his or her residence or usual place of business, or by mailing it, postage prepaid, addressed to such stockholder at his or her address as it appears upon the books of the Corporation. Such notice shall be given by the secretary or an assistant secretary or in case of their death, absence, incapacity or refusal, by some other officer or by a person designated by the board of directors.
(1) Nominations of persons for election to the Board of Directors of the Company and the proposal of business to be considered by the stockholders may be made at an annual meeting of stockholders (a) pursuant to the Company's notice of meeting, (b) by or at the direction of the Board of Directors or (c) by any stockholder of the Company who was a stockholder of record at the time of giving of notice provided for in this By-law, who is entitled to vote at the meeting and who complies with the notice procedures set forth in this By-law.
(2) For nominations or other business to be properly brought before an annual meeting by a stockholder pursuant to clause (c) of paragraph (B)(1) of this By-law, the stockholder must have given timely notice thereof in writing to the Secretary of the Company and such other business must otherwise be a proper matter for stockholder action. To be timely, a stockholder's notice shall be delivered to the Secretary at the principal executive offices of the Company not later than the close of business on the 60th day nor earlier than the close of business on the 90th day prior to the first anniversary of the preceding year's annual meeting; provided, however, that in the event that the date of the annual meeting is more than 30 days before or more than 60 days after
such anniversary date, notice by the stockholder to be timely must be so delivered not earlier than the close of business on the 90th day prior to such annual meeting and not later than the close of business on the later of the 60th day prior to such annual meeting or the 10th day following the day on which public announcement of the date of such meeting is first made by the Company. In no event shall the public announcement of an adjournment of an annual meeting commence a new time period for the giving of a stockholder's notice as described above. Such stockholder's notice shall set forth (a) as to each person whom the stockholder proposes to nominate for election or reelection as a director all information relating to such person that is required to be disclosed in solicitations of proxies for election of directors in an election contest, or is otherwise required, in each case pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (the "Exchange Act") and Rule 14a-11 thereunder (including such person's written consent to be named in the proxy statement as a nominee and to serving as a director if elected); (b) as to any other business that the stockholder proposes to bring before the meeting, a brief description of the business desired to be brought before the meeting, the reasons for conducting such business at the meeting and any material interest in such business of such stockholder and the beneficial owner, if any, on whose behalf the proposal is made; and (c) as to the stockholder giving the notice and the beneficial owner, if any, on whose behalf the nomination or proposal is made (i) the name and address of such stockholder, as they appear on the Company's books, and of such beneficial owner and (ii) the class and number of shares of the Company which are owned beneficially and of record by such stockholder and such beneficial owner.
(3) Notwithstanding anything in the second sentence of paragraph (B)(2) of this By-law to the contrary, in the event that the number of directors to be elected to the Board of Directors of the Company is increased and there is no public announcement by the Company naming all of the nominees for director or specifying the size of the increased Board of Directors at least 70 days prior to the first anniversary of the preceding year's annual meeting, a stockholder's notice required by this By-law shall also be considered timely, but only with respect to nominees for any new positions created by such increase, if it shall be delivered to the Secretary at the principal executive offices of the Company not later than the close of business on the 10th day following the day on which such public announcement is first made by the Company.
required by paragraph (B)(2) of this By-law shall be delivered to the Secretary at the principal executive offices of the Company not earlier than the close of business on the 90th day prior to such special meeting and not later than the close of business on the later of the 60th day prior to such special meeting or the 10th day following the day on which public announcement is first made of the date of the special meeting and of the nominees proposed by the Board of Directors to be elected at such meeting. In no event shall the public announcement of an adjournment of a special meeting commence a new time period for the giving of a stockholder's notice as described above.
(2) For purposes of this By-law, "public announcement" shall mean disclosure in a press release reported by the Dow Jones News Service, Associated Press or comparable national news service or in a document publicly filed by the Company with the Securities and Exchange Commission pursuant to Section 13, 14 or 15(d) of the Exchange Act.
(3) Notwithstanding the foregoing provisions of this By-law, a stockholder shall also comply with all applicable requirements of the Exchange Act and the rules and regulations thereunder with respect to the matters set forth in this By-law. Nothing in this By-law shall be deemed to affect any rights of stockholders to request inclusion of proposals in the Company's proxy statement pursuant to Rule 14a-8 under the Exchange Act.
At any meeting of the stockholders, a quorum for the election of any director or for the consideration of any question shall consist of a majority in interest of all stock issued and outstanding and entitled to vote for the election of such director or upon such question, respectively, except in any case where a larger quorum is required by law, by the Certificate of Incorporation or by these By-laws. Stock owned by the Corporation, if any, shall not be deemed outstanding for this purpose. In any case, any meeting may be adjourned from time to time by a majority of the votes properly cast upon the question, whether or not a quorum is present, and the meeting may be held as adjourned without further notice.
When a quorum for an election is present at any meeting, the affirmative vote of the holders of a plurality of the voting power of the stock of the Company which is present at the meeting shall elect to such office. When a quorum for the consideration of a question is present at any meeting, the affirmative vote of the holders of a majority of the voting power of the stock of the Company which is present at the meeting shall decide
the quorum, except in any case where a larger vote is required by law, by the Certificate of Incorporation or by these By-laws.
Except as otherwise may be provided in the Certificate of Incorporation and subject to the provisions of Article XXXI of these By-laws, each stockholder at every meeting of the stockholders shall be entitled to one vote in person or by proxy for each share of the capital stock held by such stockholder, but no proxy shall be voted after six months from its date, unless the proxy provides for a longer period; and except where the transfer books of the Corporation shall have been closed or a date shall have been fixed as a record date for the determination of the stockholders entitled to vote, as provided in Article XXXI, no share of stock shall be voted at any election for directors which has been transferred on the books of the Corporation within the twenty days preceding such election of directors. Shares of the capital stock of the Corporation belonging to the Corporation shall not be voted upon directly or indirectly.
Persons holding stock in a fiduciary capacity shall be entitled to vote the shares so held, or to give any consent permitted by law, and persons whose stock is pledged shall be entitled to vote, or to give any consent permitted by law, unless in the transfer by the pledgor on the books of the Corporation he or she shall have expressly empowered the pledgee to vote thereon, in which case only the pledgee or his or her proxy may represent said stock and vote thereon or give any such consent.
The secretary shall prepare or cause to be prepared, at least ten days before every election of directors, a complete list of the stockholders entitled to vote at said election,
arranged in alphabetical order, and showing the address of each stockholder and the number of shares registered in the name of each stockholder. Such list shall be open to the examination of any stockholder during ordinary business hours, at the place where such election meeting is to be held, or such other place as may be specified in the notice of the meeting, within the city, town or village where the election meeting is to be held, for said ten days, and shall be produced and kept at the time and place of the election meeting for the duration of the election meeting, and be subject to the inspection of any stockholder who may be present. The original or duplicate stock ledger shall conclusively list and identify the stockholders entitled to examine such list or to vote in person or by proxy at such election.
A. In order that the corporation may determine the stockholders entitled to consent to corporate action in writing without a meeting, the Board of Directors may fix a record date, which record date shall not precede the date upon which the resolution fixing the record date is adopted by the Board of Directors, and which date shall not be more than 10 days after the date upon which the resolution fixing the record date is adopted by the Board of Directors. Any stockholder of record seeking to have the stockholders authorize or take corporate action by written consent shall, by written notice to the Secretary, request the Board of Directors to fix a record date. The Board of Directors shall promptly, but in all events within 10 days after the date on which such a request is received, adopt a resolution fixing the record date. If no record date has been fixed by the Board of Directors within 10 days of the date on which such a request is received, the
record date for determining stockholders entitled to consent to corporate action in writing without a meeting, when no prior action by the Board of Directors is required by applicable law, shall be the first date on which a signed written consent setting forth the action taken or proposed to be taken is delivered to the corporation by delivery to its principal place of business or to any officer or agent of the corporation having custody of the book in which proceedings of meetings of stockholders are recorded. Delivery made to the corporation's registered office shall be by hand or by certified or registered mail, return receipt requested. If no record date has been fixed by the Board of Directors and prior action by the Board of Directors is required by applicable law, the record date for determining stockholders entitled to consent to corporate action in writing without a meeting shall be at the close of business on the date on which the Board of Directors adopts the resolution taking such prior action.
B. Every written consent shall bear the date of signature of each stockholder who signs the consent and no written consent shall be effective to take the corporate action referred to therein unless, within 60 days of the record date established in accordance with paragraph (A) of this Article VIII, a written consent or consents signed by a sufficient number of holders to take such action are delivered to the corporation in the manner prescribed in paragraph (A) of this Article.
C. In the event of the delivery, in the manner provided by this Article, to the corporation of the requisite written consent or consents to take corporate action and/or any related revocation or revocations, the corporation shall engage nationally recognized independent inspectors of elections for the purpose of promptly performing a ministerial review of the validity of the consents and revocations. For the purpose of permitting a
prompt ministerial review by the independent inspectors, no action by written consent without a meeting shall be effective until the earlier of (i) five business days following delivery to the corporation of consents signed by the holders of the requisite minimum number of votes that would be necessary to take such action, which delivery shall be accompanied by a certification by the stockholder of record (or his or her designee) who delivered, in accordance with paragraph (A) above, the written notice to the Secretary requesting the Board of Directors to fix a record date or (ii) such date as the independent inspectors certify to the corporation that the consents delivered to the corporation in accordance with this Article represent at least the minimum number of votes that would be necessary to take the corporate action. Nothing contained in this paragraph shall in any way be construed to suggest or imply that the Board of Directors or any stockholder shall not be entitled to contest the validity of any consent or revocation thereof, whether during or after such five business day period, or to take any other action (including, without limitation, the commencement, prosecution or defense of any litigation with respect thereto).
The number of directors which constitute the whole board of directors shall be not less than three nor more than twenty. Within the limits above specified, the number of directors shall be determined by resolution of the board of directors. The directors shall be elected at the annual meeting of the stockholders, except as provided elsewhere in these By-laws, and each director elected shall hold office until a successor is elected and qualified, or until he or she sooner dies, resigns or is removed or replaced. Directors need
not be stockholders. Newly-created directorships resulting from any increase in the authorized number of directors voted by the board of directors between annual meetings may be filled, at the discretion of the board, by an election at a meeting of stockholders held for that purpose, or by an election at a meeting of the board of directors, by vote of a majority of the directors then in office though less than a quorum, and each director so chosen shall hold office until the next annual election of the class of directors to which such director is assigned and until his or her successor is duly elected and shall qualify, unless he or she sooner dies, resigns, or is removed or replaced.
The board of directors shall be divided into three classes as designated by the initial members of the board of directors. Each class shall be as nearly equal in number as possible to the other classes so designated. The term of office of the first class shall expire at the first annual meeting of stockholders; of the second class one year thereafter; and of the third class two years thereafter. Each subsequent class of directors shall be elected for a full term of office of three years. At all subsequent annual meetings thereafter, the number of directors equal to the number constituting the class whose term expires at the time of such meeting shall be elected to hold office for the full term of office of three years. Upon the creation of any new directorships resulting from any increase in the authorized number of directors voted by the board of directors between annual meetings, such new directors shall be assigned to one of the aforementioned three classes by the vote of a majority of the directors then in office, provided that after such appointment to a class, each class shall be as nearly equal in number as possible to the other classes of the board of directors.
The provisions of the foregoing paragraph of this Article IX may not be altered, amended or repealed except by the vote of the holders of a majority of the voting power of the issued and outstanding stock of the Corporation at any annual, regular or special stockholders' meeting called for that purpose, the notice of which shall specify the subject matter of the proposed alteration, amendment or repeal of this Article IX.
The board of directors shall have and may exercise all the powers of the Corporation, except such as are conferred exclusively upon the stockholders by law, by the Certificate of Incorporation or by these By-laws.
Such executive committee shall be vested with power to take any action which the board itself could take, except as hereinafter provided, with respect to the conduct and management of the business of the Corporation, including declaring dividends, designating and altering the duties, powers and compensation of the officers and agents of the Corporation, electing or appointing the officers and agents other than the chairman of
the board of directors, president, treasurer and secretary, filling vacancies other than those vacancies occurring within the board of directors and executive committee, and authorizing or ratifying all purchases, sales, contracts, offers, conveyances, transfers, negotiable instruments, powers of attorney, bonds, and other transactions and instruments of every kind, as well as authorizing the seal of the Corporation to be affixed to all papers which may require it.
If an executive committee is elected, each member of such executive committee shall hold office until the first meeting of the board of directors following the next annual meeting of the stockholders and until his or her successor is elected and qualified, or until he or she sooner dies, resigns, is removed, is replaced by change of membership or becomes disqualified by ceasing to be a director.
One-half of the members of the executive committee then in office, but in no case less than two members, shall constitute a quorum for the transaction of business, but any meeting may be adjourned from time to time by affirmative vote of a majority of the votes cast upon the question, whether or not a quorum is present, and upon such majority consent to adjourn, the meeting may be adjourned without further notice. All minutes of proceedings of the executive committee shall be kept by the secretary or an assistant secretary and shall be available to the board of directors upon its verbal or written request. The executive committee may make rules not inconsistent herewith for the holding and conducting of its meetings, but unless otherwise provided in such rules, its meetings shall be held and conducted in the same manner, as nearly as may be, as is provided in these By-laws for meetings of the board of directors. The board of directors shall have power
and authority to rescind any vote or resolution of the executive committee, but no such rescission shall have retroactive effect.
The board of directors may at any time and from time to time, by resolution adopted by a majority of the whole board of directors, appoint, designate, change the membership of or terminate the existence of one or more committees, each committee to consist of two or more of the directors of the Corporation. Each such committee shall have such name as may be determined from time to time by resolution adopted by the board of directors and shall have and may exercise such powers of the board of directors in the management of the business and affairs of the Corporation, including the power to authorize the seal of the Corporation to be affixed to all papers which may require it, as may be determined from time to time by resolution adopted by a majority of the whole board. One-half of the members of each such committee then in office, but in no case less than two members, shall constitute a quorum for the transaction of business, but any meeting may be adjourned from time to time by affirmative vote of a majority of the votes cast upon the question, whether or not a quorum is present, and upon such majority consent to adjourn, the meeting may be adjourned without further notice. All minutes of proceedings of committees shall be kept by the secretary or an assistant secretary and shall be available to the board of directors upon its verbal or written request.
Regular meetings of the board of directors may be held without call or formal notice at such places either within or without the State of Delaware and at such times as the board may from time to time determine. A regular meeting of the board of directors may be held without call or formal notice immediately after and at the same place as the annual meeting of the stockholders.
Special meetings of the board of directors may be held at any time and at any place either within or without the State of Delaware when called by the chairman of the board, the president, the chief financial officer or two or more directors, reasonable notice thereof being given to each director by the secretary or an assistant secretary, or in the case of the death, absence, incapacity or refusal of the secretary or an assistant secretary, by the officer or directors calling the meeting, or without call or formal notice if each director then in office is either present at the special meeting or waives notice before or after such meeting. A waiver of notice in writing, signed by a director entitled to such notice shall be deemed to satisfy such notice requirement whether such written waiver of notice were signed before or after the time of the meeting. In any case it shall be deemed sufficient notice to a director to send notice addressed to him or her at his or her usual or last known business or residence address by postage paid mail at least forty-eight hours before the meeting, or by telegram, telex or facsimile transmission at least twenty-four hours before the meeting, or to give notice to him or her in person at least twenty-four hours before the meeting either by telephone, or by handing him or her a written notice.
At any meeting of the board of directors, except in any case where a larger quorum or the vote of a larger number of directors is required by law, by the Certificate of Incorporation or by these By-laws, a quorum for any election or for the consideration of any question shall consist of one-half of the directors then in office, but in no case less than two directors, but any meeting may be adjourned from time to time by a majority of the votes cast upon the question, whether or not a quorum is present, and upon such majority consent to adjournment, the meeting may be adjourned without further notice. When a quorum is present at any meeting, the votes of a majority of the directors present and voting shall be requisite and sufficient to elect any officer, and a majority of the directors present and voting shall decide any questions brought before such meeting, except in any case where a larger vote is required by law, by the Certificate of Incorporation or by these By-laws.
The board of directors by resolution or resolutions may from time to time, in connection with any employee stock option or purchase plan, fix limitations and restrictions on the transfer of any or all of the authorized but unissued shares or treasury shares of the Corporation made available for such stock option or purchase plan, such restrictions to take effect upon the issue, sale or transfer of such shares. No such limitation or restriction shall be valid unless notice thereof is given on the certificate or certificates representing such shares.
The directors may be paid their expenses, if any, of attendance at each meeting of the board of directors and may be paid a fixed sum for attendance at each meeting of the board of directors or a stated salary as director. No such payment shall preclude any director from serving the Corporation in any other capacity and receiving compensation therefor. Members of special or standing committees may be paid like compensation for attending committee meetings.
The officers of the Corporation shall be chosen by the board of directors and shall consist of a chairman of the board, a president, one or more vice presidents, a secretary, a treasurer and such other officers as the board shall deem necessary or appropriate. The board of directors, in its discretion, may choose a chief financial officer, one or more executive vice presidents, senior vice presidents, assistant secretaries and assistant treasurers. Two or more offices may be held by the same person, except that when one person holds the offices of both president and secretary such person shall not hold any other office.
The board of directors at its first meeting after each annual meeting of stockholders shall choose the corporate officers, of whom only the chairman of the board and the president must be board members. At any time as it shall deem necessary, the board of directors may choose any other officers and agents, who shall hold their offices
for such terms, and shall exercise such powers, and perform such duties, as the board shall determine from time to time.
Any vacancies occurring in any office of the Corporation shall be filled by the board of directors.
The chairman of the board, who may be the chief executive officer of the Corporation, shall perform all duties commonly incident to his or her office and shall perform such other duties as the board of directors shall from time to time designate. The chairman of the board shall preside at all meetings of the stockholders and of the board of directors at which he or she is present, except as otherwise voted by the board of directors.
The chief executive officer, in addition to his or her other duties, shall have general and active management authority of corporate business and shall ensure that all orders and resolutions of the board of directors are carried into effect.
The president, who may be the chief executive officer or the chief operating officer of the Corporation, shall have such duties and powers as shall be designated from time to time by the chairman of the board or the board of directors. The president shall have all the powers and shall discharge all the duties, other than those as a director, of the chairman of the board or the chief executive officer during his or her absence or his or her inability or incapacity to act. The president shall preside at all meetings of the
stockholders and the board of directors, except when the chairman of the board or the chief executive officer is present at such meetings.
The chief operating officer shall have general responsibility for the daily operations of the Corporation and shall have such duties and powers as shall be designated from time to time by the chairman of the board, the chief executive officer or the board of directors.
Any executive vice president, any senior vice president or, if they are not available, any available vice president, shall have all the powers and shall discharge all the duties of the president during his or her absence or his or her inability or incapacity to act, and each such vice president shall further have such powers and discharge such duties as are imposed upon them by these By- laws or may be from time to time conferred or imposed upon them by the chairman of the board, the chief executive officer, the president, the chief operating officer or the board of directors. Any executive vice president or senior vice president may be the chief operating officer of the Corporation.
The chief financial officer, if such officer is appointed, or if not, the treasurer, shall be responsible for developing, recommending and implementing financial policies of the Corporation and shall have general responsibility for protecting the Corporation's financial position. He or she shall keep and maintain or cause to be kept and maintained,
adequate and correct books and records of accounts of the properties and business transactions of the Corporation, including accounts of its assets, liabilities, receipts, disbursements, gains, losses capital, retained earnings and shares. He or she shall represent the Corporation in its transactions with banks and other financial institutions.
The secretary or an assistant secretary shall attend all meetings of the stockholders and all meetings of the board of directors and its committees, and shall record all the proceedings of the meetings of the stockholders and of the board of directors and its committees in a book or books to be kept for that purpose. He or she shall give, or cause to be given, notice of all meetings of the stockholders and meetings of the board of directors and shall perform such other duties as may be prescribed by the chairman of the board, the president or by the board of directors, under whose supervision the secretary shall work. The secretary shall keep in safe custody the seal of the Corporation and when authorized by the chairman of the board, the president, the board of directors, or these By-laws, affix the same to any instrument requiring it and, when so affixed, the secretary or an assistant secretary shall attest the seal by signing his or her name to the sealed document. The secretary shall be responsible for the stock ledger (which may, however, be kept by any transfer agent or agents of the Corporation under the direction of the secretary).
The assistant secretary, or if there are more than one, the assistant secretaries, in the order determined by the secretary, shall in the absence or disability of the secretary perform the duties and exercise the powers of the secretary, and shall perform such other
duties and have such other powers as the chairman of the board, the president, the board of directors and the secretary may from time to time prescribe.
The treasurer shall have custody of the corporate funds and securities and shall keep, or cause to be kept, full and accurate account of receipts and disbursements in books belonging to the Corporation, and shall deposit or cause to be deposited all monies and other valuable effects in the name and to the credit of the Corporation in such depositories as may be designated by the board of directors. The treasurer shall invest surplus funds in such investments as he or she shall deem appropriate in consultation with the chief financial officer and pursuant to this authority may buy and sell securities on behalf of the Corporation from time to time. He or she shall disburse or cause to be disbursed the funds of the Corporation as may be ordered by the board of directors, the chairman of the board or such other officer as the chairman of the board may from time to time designate, taking proper vouchers for such disbursements. The treasurer shall work under the supervision of the chief financial officer, if the board of directors has appointed such an officer.
If required by the board of directors, the treasurer shall give the Corporation a bond (which shall be renewed every six years) in such sum and with such surety or sureties as shall be satisfactory to the board of directors for the faithful performance of his or her office and for the restoration to the Corporation in case of his or her death, resignation, retirement or removal from office, of all books, papers, vouchers, money and other property of whatever kind in his or her possession or under his or her control
belonging to the Corporation. The assistant treasurer, if any, shall in the absence or disability of the treasurer, perform the duties and exercise the powers of the treasurer and shall perform such other duties and have such other powers as the chairman of the board, the president, the board of directors and the treasurer may from time to time prescribe and shall be responsible to and shall report to the treasurer.
The general counsel, if the board of directors appoints such an officer, shall be the chief counseling officer of the Corporation in all legal matters, and, subject to the control by the board of directors, he or she shall have charge of all matters of legal import to the Corporation. His or her relationship to the Corporation shall in all respects be that of an attorney to a client. The general counsel shall have charge of all litigation of the Corporation and keep himself or herself advised of the progress of all legal proceedings and claims by and against the Corporation, or in which the Corporation is interested by reason of its ownership and control of other Corporations. The general counsel shall maintain records of all lawsuits and actions of every nature in which the Corporation may be a party, or in which it is interested, with sufficient data to show the nature of the case and the proceedings therein, and such records and the papers relating thereto shall be open at all times to the inspection of the directors and the executive officers of the Corporation.
The general counsel shall give to the board of directors and to any officer of the Corporation, whenever requested to do so, his or her opinion upon any question affecting the interests of the Corporation and when requested by the chairman of the board, the
president, a vice president, or by the board of directors or the executive committee, give his or her opinion upon any subject that may be referred to him or her.
The general counsel may, in his or her discretion, on behalf of the Corporation, retain such independent attorneys, or law firms, in any and all parts of the world, as he or she may deem necessary to assist him or her in the performance of his or her duties and to protect and further the interests of the Corporation.
The general counsel shall have power and authority to execute in the name of the Corporation any and all bonds or stipulations for costs or other purposes connected with legal proceedings in any of the courts of justice, for the protection or enforcement of the rights and interests of this Corporation; and, by instrument in writing, he or she may delegate to any such authority appropriate power and authority to execute such bonds or stipulations.
The assistant general counsel, or, if there are more than one, the assistant general counsels, shall, in the order determined by the general counsel, in the absence or disability of the general counsel, perform his or her duties and exercise his or her powers and shall perform such other duties and have such other powers as the chairman of the board, the president, the board of directors and the general counsel may from time to time prescribe.
The controller, if the board of directors elects such an officer, shall be the chief accounting officer of the Corporation, shall keep its books of account and accounting records, and shall be in charge of the Corporation's accounting policies and procedures.
The controller shall work under the supervision of the chief financial officer. The controller shall, with the approval of the board of directors, arrange for annual audits by independent public accountants.
If required by the board of directors, the controller shall give the Corporation a bond (which shall be renewed every six years) in such sum and with such surety or sureties as shall be satisfactory to the board of directors for the faithful performance of his or her office and for the restoration to the Corporation in case of his or her death, resignation, retirement or removal from office, of all books, papers, vouchers, money and other property of whatever kind in his or her possession or under his or her control belonging to the Corporation.
The assistant controller, if any, shall in the absence or disability of the controller perform the duties and exercise the powers of the controller, and shall perform such other duties and have such other powers as the chairman of the board, the president, the board of directors and the controller may from time to time prescribe, and shall be responsible to and shall report to the controller.
Any director or officer may resign at any time by delivering his or her resignation in writing to the chairman of the board, the president or the secretary, or to a meeting of the board of directors. Such resignation shall take effect at the time stated in the resignation, or if no time be so stated therein, immediately upon its delivery, and without the necessity of its being accepted unless the resignation shall so state.
The stockholders may remove any director from office, by vote of a majority in interest of the stock issued and outstanding and entitled to vote for such removal, at any meeting called for that purpose. The board of directors may at any time, by vote of a majority of the directors then in office, remove from office the chairman of the board, the president, any executive vice president, any vice president, the chief financial officer, the treasurer, the secretary, the general counsel or the controller at a special meeting called for that purpose. Any other officer, agent or employee may be removed from office, agency or employment by (i) vote of the board of directors at any meeting thereof, or (ii) in the case of any officer, agent or employee not elected to his or her position by the board of directors, by any committee or officer upon whom such power may be conferred by the board of directors.
No director or officer resigning, and (except where a right to receive compensation for a definite future period shall be expressly provided in a written agreement with the Corporation duly approved by the board of directors) no director or officer being removed shall have any right to any compensation as such director or officer for any period following his or her resignation or removal, or any right to damages on account of such removal, whether his or her compensation be by the month or by the year or otherwise.
If the office of any director becomes vacant, by reason of death, resignation or removal, a successor may be elected by the board of directors by vote of a majority of the remaining directors then in office whether or not the remaining directors constitute a
quorum. If the office of any officer becomes vacant, by reason of death, resignation, removal or disqualification, a successor may be elected or appointed by the board of directors by vote of a majority of the directors present and voting. Each such successor shall hold office for the unexpired terms, and until his or her successor shall be elected or appointed and qualified, or until he or she sooner dies, resigns, is removed or replaced or becomes disqualified. The board of directors shall have and may exercise all its powers notwithstanding the existence of one or more vacancies in its number as fixed by the stockholders, subject to any requirements of law or of these By- laws as to the number of directors required for a quorum or for any vote, resolution or other action.
Whenever any notice is required to be given by law or under the provisions of the Certificate of Incorporation or of these By-laws, a written waiver of notice, signed by the person or persons entitled to such notice shall be deemed to satisfy such notice requirement, whether such waiver was signed and delivered before or after the meeting or other event for which notice is waived.
Every holder of stock in the Corporation shall be entitled to have a certificate, signed in the name of the Corporation, by the chairman of the board, the president or a vice president and by the treasurer or an assistant treasurer or the secretary or an assistant secretary of the Corporation, certifying the number of shares owned by him or her in the Corporation; provided, however, that where any such certificate is countersigned by a
transfer agent, other than the Corporation or its employee, or by a registrar, other than the Corporation or its employee, any other signature on such certificate may be a facsimile, engraved, stamped or printed. In case any officer or officers who shall have signed, or whose facsimile signature or signatures shall have been used on any such certificate or certificates shall cease to be such officer or officers of the Corporation, whether because of death, resignation or otherwise, before such certificate or certificates shall have been delivered by the Corporation, such certificate or certificates may nevertheless be adopted by the Corporation and be issued and delivered as though the person or persons who signed such certificate or certificates or whose facsimile signature or signatures have been used thereon had not ceased to be such officer or officers of the Corporation, and any such issue and delivery shall be regarded as an adoption by the Corporation of such certificate or certificates. Certificates of stock shall be in such form as shall, in conformity to law, be prescribed from time to time by the board of directors.
Subject to applicable restrictions upon transfer, if any, title to a certificate of stock and to the shares represented thereby shall be transferred only by delivery of the certificate properly endorsed, or by delivery of the certificate accompanied by a written assignment of the same, or a written power of attorney to sell, assign or transfer the same or the shares represented thereby, properly executed; but the person registered on the books of the Corporation as the owner of shares shall have the exclusive right to receive dividends thereon and, except as provided in Article VII with respect to stock which has been pledged, to vote thereon as such owner or to give any consent permitted by law, and
shall be held liable for such calls and assessments, if any, as may lawfully be made thereon, and except only as may be required by law, may in all respects be treated by the Corporation as the exclusive owner thereof. It shall be the duty of each stockholder to notify the Corporation of his or her post office or mailing address and to furnish to the Corporation such other information as the Corporation may by law be required to obtain.
The board of directors shall have power to close the stock transfer books of the Corporation for a period not exceeding sixty days preceding the date of any meeting of stockholders or the date for payment of any dividend or the date for the allotment of rights or the date when any change or conversion or exchange of capital stock shall go into effect or for a period of not exceeding sixty days in connection with obtaining the consent of stockholders for any purpose; provided, however, that in lieu of closing the stock transfer books as aforesaid, the board of directors may fix in advance a date, not exceeding sixty days preceding the date of any meeting of stockholders, or any other of the above-mentioned events, or a date in connection with obtaining such consent, as a record date for the determination of the stockholders entitled to notice of, and to vote at, any such meeting and any adjournment thereof, or entitled to receive payment of any such dividend, or to any such allotment of rights, or to exercise the rights in respect to any such change, conversion or exchange of capital stock, or to give such consent, and in such case such stockholders and only such stockholders as shall be stockholders of record on the date so fixed shall be entitled to such notice of, and to vote at, such meeting and any adjournment thereof, or to receive payment of such dividend, or to receive such allotment
of rights, or to exercise such rights, or to give such consent, as the case may be, notwithstanding any transfer of any stock on the books of the Corporation after any such record date fixed as aforesaid.
In the case of the alleged loss or destruction or the mutilation of a certificate of stock, a duplicate certificate may be issued in place thereof upon such terms in conformity with law as the board of directors may prescribe.
The corporate seal of the Corporation shall, subject to alteration by the board of directors, consist of a flat-faced circular die with the word "Delaware", together with the name of the Corporation and the year of its organization, cut or engraved thereon. The corporate seal of the Corporation may be used by causing it or a facsimile thereof to be impressed or affixed or reproduced or otherwise.
Unless the board of directors generally or in particular cases authorizes the execution thereof in some other manner, all deeds, leases, transfers, sales of securities, contracts, proxies, bonds, notes, checks, drafts and other obligations, agreements and undertakings made, accepted or endorsed by the Corporation, shall be signed by the chairman of the board, the president or by one of the vice presidents, and, if such papers
require a seal, the seal of the Corporation shall be affixed thereto and attested by the secretary or an assistant secretary.
Except as from time to time otherwise provided by the board of directors, the fiscal year of the Corporation shall commence on the first day of January of each year, commencing January 1, 1991.
Dividends upon the capital stock of the Corporation, subject to the provisions of the Certificate of Incorporation, if any, may be declared by the board of directors at any regular or special meeting, pursuant to law. Dividends may be paid in cash, in property, or in shares of the capital stock, subject to the provisions of the Certificate of Incorporation. Before payment of any dividend, there may be set aside, out of any funds of the Corporation available for dividends, such sum or sums as the directors from time to time, in their absolute discretion, think proper as a reserve or reserves to meet contingencies, or for equalizing dividends, or for repairing or maintaining any property of the Corporation, or for such other purpose as the directors shall think conducive to the interests of the Corporation, and the directors may modify or abolish any such reserve in the manner in which it was created.
The directors of the Corporation are likely to be connected with other corporations, partnerships, associations or firms with which from time to time this Corporation may have business dealings. No contract or other transaction between the Corporation and any other corporation, partnership, association or firm and no act of the Corporation shall be affected by the fact that directors of this Corporation are pecuniarily or otherwise interested in, or are directors, members or officers of such other corporation, partnership, association or firm. Any director individually, or any firm of which such director may be a member, may be a party to or may be pecuniarily or otherwise interested in any contract or transaction of the Corporation, provided that the fact that he or she or such firm is so interested shall be disclosed or shall have been known to the board of directors or a majority thereof that approves such contract or transaction. Every contract, act or transaction which at any annual meeting of the stockholders, or at any meeting of the stockholders called for that purpose, among others, of considering such contract, act or transaction, shall be authorized, approved or ratified by vote of the holders of a majority of the shares in the capital stock of the Corporation present in person or represented by proxy at such meeting (provided that a quorum of stockholders be there present or represented by proxy) shall be as valid and binding upon the Corporation and upon all its stockholders as though such a contract, act or transaction had been expressly authorized, approved and ratified by every stockholder of the Corporation.
The Corporation shall indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (and whether or not by or in the right of the Corporation) by reason of the fact that he is or was a director, officer, employee or agent of the Corporation, or is or was serving at the request of the Corporation as a director, officer, employee or agent of another company, partnership, joint venture, trust or other enterprise or is or was serving as a fiduciary of any employee benefit plan, fund or program sponsored by the Corporation or such other company, partnership, joint venture, trust or other enterprise, against expenses (including attorney's fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding, to the extent and under the circumstances permitted by the General Corporation Law of the State of Delaware as amended from time to time. Such indemnification (unless ordered by a court) shall be made as authorized in a specific case upon a determination that indemnification of the director, officer, employee or agent is proper in the circumstances because he has met the applicable standards of conduct set forth in the General Corporation Law of the State of Delaware. Such determination shall be made (1) by the board of directors by vote of a majority of a quorum consisting of directors who were not parties to such action, suit or proceeding, or (2) if such quorum is not obtainable, or even if obtainable a quorum of disinterested directors so directs by independent legal counsel in a written opinion, or (3) by the stockholders. The foregoing right of indemnification shall not be deemed
exclusive of any other rights to which those seeking indemnification may be entitled under any by-law, agreement, vote of stockholders or disinterested directors or otherwise, and shall continue as to a person who has ceased to be a director, officer, employee or agent and shall inure to the benefit of the heirs, executors and administrators of such a person.
Except as provided in Article IX, these By-laws may be altered, amended or repealed by (i) the affirmative vote of the holders of a majority of the voting power of the issued and outstanding stock of the Corporation or (ii) the affirmative vote of the majority of the directors then holding office at any annual, regular or special stockholders or directors meeting, called for that purpose, the notice of which shall specify the subject matter of the proposed alteration, amendment or repeal and the articles to be affected thereby. Any by-law, whether made, altered, amended or repealed by the stockholders or directors, may be repealed, amended, further amended or reinstated, as the case may be, by either the stockholders or the directors as aforesaid.
Exhibit 10.2
AGREEMENT
THIS AGREEMENT, made and entered into as of the 17/th/ day of July, 2001 by and between CABOT OIL & GAS CORPORATION, with its principal office at 1200 Enclave Parkway, Houston, Texas 77077 (together with its successors and assigns permitted under this Agreement, the "Company"), and __________________ (the "Executive"),
W I T N E S S E T H:
WHEREAS, on November 3, 1995, the Compensation Committee of the Board of Directors of the Company authorized and adopted a Change in Control Program to provide for certain benefits to certain of the officers of the Company in the event of certain terminations of employment, and determined that such program would be in the best interests of the Company; and
WHEREAS, on July 17, 2001, upon the recommendation of its Compensation Committee, the Board of Directors of the Company authorized and adopted certain modifications to the Change in Control Program; and
WHEREAS, the Company and Executive both desire to amend that certain Agreement between the Company and Executive dated as of the ____ day of ____________ to reflect the action by the Board of Directors with respect to the Company's Change in Control Program, such amendment to be evidenced by entering into this agreement (this "Agreement"), which supersedes and replaces such prior agreement;
NOW, THEREFORE, in consideration of the premises and mutual covenants contained herein and for other good and valuable consideration, the receipt of which is mutually acknowledged, the Company and the Executive (individually a "Party" and together the "Parties") agree as follows:
(I) dishonesty by Executive which results in significant loss to the Company and significant personal enrichment to the Executive;
(II) a material failure of Executive to perform his obligations under this Agreement (other than any such failure resulting from incapacity due to physical or mental illness); or
(III) the willful and continued failure of the Executive to perform substantially the Executive's duties with the Company or one of its affiliates (other than any such failure resulting from incapacity due to physical or mental illness), after a written demand for substantial performance is delivered to the Executive by the Board or the Chief Executive Officer of the Company which specifically identifies the manner in which the Board or Chief Executive Officer believes that the Executive has not substantially performed the Executive's duties.
(I) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the "Exchange Act")) (a "Person") of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 35% or more of either (1) the then outstanding shares of common stock of the Company (the "Outstanding Company Common Stock") or (2) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the "Outstanding Company Voting Securities"); provided, however, that for purposes of this subsection (I), the following acquisitions shall not constitute a Change of Control: (i) any acquisition directly from the Company, (ii)
any acquisition by the Company, (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any entity controlled by the Company or (iv) any acquisition by any entity pursuant to a transaction which complies with clauses (1), (2) and (3) of subsection (III) of this definition; or
(II) Individuals who, as of the date hereof, constitute the Board (the "Incumbent Board") cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Company's stockholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or
(III) Consummation of a reorganization, merger or consolidation
or sale or other disposition of all or substantially all of the assets
of the Company (a "Business Combination"), in each case, unless,
following such Business Combination, (1) all or substantially all of
the individuals and entities who were the beneficial owners,
respectively, of the Outstanding Company Common Stock and Outstanding
Company Voting Securities immediately prior to such Business
Combination beneficially own, directly or indirectly, more than 50%
of, respectively, the then outstanding shares of common stock and the
combined voting power of the then outstanding voting securities
entitled to vote generally in the election of directors, as the case
may be, of the entity resulting from such Business Combination
(including, without limitation, an entity that as a result of such
transaction owns the Company or all or substantially all of the
Company's assets either directly or through one or more subsidiaries)
in substantially the same proportions as their ownership, immediately
prior to such Business Combination, of the Outstanding Company Common
Stock and Outstanding Company Voting Securities, as the case may be,
(2) no Person (excluding any entity resulting from such Business
Combination or any employee benefit plan (or related trust) of the
Company or such entity resulting from such Business Combination)
beneficially owns, directly or indirectly, 35% or more of,
respectively, the then outstanding shares of common equity of the
entity resulting from such Business Combination or the combined
voting power of the then outstanding voting securities of such entity except to the extent that such ownership existed prior to the Business Combination and (3) at least a majority of the members of the board of directors of the corporation, or the similar managing body of a non- corporate entity, resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or
(IV) Approval by the stockholders of the Company of a complete liquidation or dissolution of the Company, other than a liquidation or dissolution in connection with a transaction to which subsection (III) applies.
(I) any loss of the Executive's titles or positions in effect at the time of a Change in Control or any adverse change in the position to which the Executive reports or the principal departmental functions that report to the Executive at the time of a Change in Control (reporting relationships) that in any case results in a diminution of the Executive's responsibility or the Executive's access to the Chief Executive Officer of the Company;
(II) the assignment to the Executive of any duties inconsistent in any respect with the Executive's position (including status, offices, titles and reporting relationships), authority, duties or responsibilities as in effect on the date of a Change in Control, or any other action by the Company which results in a diminution in such position, authority, duties or responsibilities, excluding action not taken in bad faith and which is remedied by the Company promptly after receipt of notice thereof given by the Executive;
(III) any reduction in total aggregate compensation, including the aggregate benefits of all fringe benefits, performance shares, Bonus opportunity, long-term incentive opportunity or perquisites applicable to the Executive immediately prior to a Change in Control, or any reduction in Base Salary, Bonus opportunity or long-term incentive opportunity from that immediately preceding a Change in Control;
(IV) the relocation of the Executive's office location as assigned to him by the Company to a location more than 35 miles from his office location at the time of a Change in Control;
(V) any failure by the Company to comply with any of the provisions of this Agreement, other than a failure not occurring in bad faith and which is remedied by the Company promptly after receipt of notice thereof given by the Executive;
(VI) any purported termination by the Company of the Executive's employment otherwise than as expressly permitted by this Agreement for Cause; or
(VII) any failure by the Company to comply with and satisfy
Section 5 of this Agreement, provided that the successor contemplated
by Section 5 has received, at least 10 days prior to the giving of
notice of constructive termination by the Executive, written notice
from the Company or the Executive of the requirements of Section 5 of
the Agreement.
(I) the Company enters into an agreement, the consummation of which would result in the occurrence of a Change in Control;
(II) any person (including the Company) publicly announces an intention to take or to consider taking actions which if consummated would constitute a Change in Control;
(III) any Person, who is or becomes the beneficial owner, directly or indirectly, of securities of the Company representing 9.5% or more of the combined voting power of the Company's then outstanding securities, increases his beneficial ownership of such securities by 5% or more over the percentage so owned by such Person on the date hereof; or
(IV) the Board adopts a resolution to the effect that, for purposes of this Agreement, a potential Change in Control has occurred.
(I) an amount of cash equal to the product of (A) Annual Compensation times (B) three; and
(II) payment with respect to any performance shares granted to Executive, such payment to be prorated based on actual service completed at the time of the Executive's termination without Cause or Constructive Termination Without Cause, and valued according to the percentage of goal attainment on the date of termination, notwithstanding any contrary provisions of such grants or any plans pursuant to which they are granted; and
(III) immediate vesting and exercisability of all of the Executive's options to purchase securities of the Company, and immediate vesting and lapse of restrictions on any restricted stock grants, outstanding at the time of the Executive's termination without Cause or Constructive Termination Without Cause, whether or not such would be the result under the provisions of such options or stock
grants or any plans pursuant to which they are granted, and each of Executive's options shall remain outstanding until the earlier to occur of exercise of the option or the expiration of the option at the end of its full term, without regard to any provision for expiration prior thereto by reason of termination of employment; and
(IV) at Executive's election, and subject to Executive's payment of the applicable premiums set forth on Schedule A, continued medical, dental and life insurance coverage (or reimbursement for the premiums for such coverage or reimbursement for covered expenses, at the Company's election) in each case for three years following the date of the Executive's termination without Cause or Constructive Termination Without Cause as though the Executive's employment were continued in effect during such time and without regard to any benefit reductions implemented after the date of such termination; provided that Executive may elect to receive one or more of such coverages and not the others; provided further that COBRA coverage shall commence only as of the end of such three-year period; and
(V) immediate crediting of an additional three years of service in the Company's non-qualified retirement plans in which the Executive is participating at the time of the Change in Control, and payments under a non-qualified plan equal to the sum of (i) the additional benefits that would be attributable to a crediting of an additional three years of service in the Company's qualified plans in which the Executive is participating at the time of the Change in Control and (ii) the Executive's benefits that are not vested under any non-qualified or qualified Company employee pension benefit plans; and
(VI) reimbursement as bills are submitted by Executive to the Company for outplacement assistance in an amount not to exceed 15% of Executive's Base Salary in effect on the date of a Change in Control, or, if termination of employment occurs prior to a Change in Control, termination of employment; and
(VII) the sum of (x) any unpaid salary earned by Executive for periods prior to employment termination plus (y) the Executive's target Bonus for the fiscal year of termination prorated for the actual elapsed days of such fiscal year prior to such termination.
Anything in this Agreement to the contrary notwithstanding, in the event it shall be determined that any payment or distribution by the Company to or for the benefit of the
Executive (whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or otherwise, but determined without regard to any Gross-up Payment required under this paragraph) (a "Payment") would be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code of 1986, as amended (the "Code"), or any interest or penalties are incurred by the Executive with respect to such excise tax (such excise tax, together with any such interest and penalties, are hereinafter collectively referred to as the "Excise Tax"), then the Executive shall be entitled to receive an additional payment (a "Gross-up Payment") in an amount such that after payment by the Executive of all income, excise and other taxes (and any interest and penalties imposed with respect thereto), the Executive retains an amount of the Gross-Up Payment equal to the Excise Tax imposed upon the Payments.
(a) Executive agrees not to terminate his employment for reasons other than death, disability or Constructive Termination without Cause (x) during the 90-day period following a Change in Control or (y) during a Potential Change in Control Period.
(b) In the event, within two years following a Change in Control occurring during the Term, the Executive's employment is terminated by the Company without Cause (other than by death or disability) or there is a Constructive Termination Without Cause, then the Executive shall be entitled to receive the Termination Benefits. The Termination Benefit described in clauses (I), (II) and (VII) of the definition of Termination Benefits shall be paid immediately upon such termination in a cash lump sum. Except as otherwise provided in the definition of Constructive Termination Without Cause, the failure of the Executive to effect a Constructive Termination Without Cause as to any one event described in such definition shall not affect his entitlement to effect a Constructive Termination Without Cause as to any other such event.
(c) In the event the Executive's employment is terminated prior to a
Change in Control by the Company Without Cause (other than by death or
disability) or there is a Constructive Termination Without Cause and either
(i) the Executive reasonably demonstrates that such termination was at the
request of a third party or as a result of actions by the third party who
has taken steps reasonably calculated to effect a Change in Control or (ii)
the termination occurs during a Potential Change in Control Period, then
the Executive's employment shall be deemed to have terminated following a
Change in Control and the Executive shall be entitled to receive the
Termination Benefits as provided in Section 2(b). Prior to a Change in
Control, the determination of what events constitute grounds for a
Constructive Termination
Without Cause and the amount of Termination Benefits payable on a termination shall be made as if a Change in Control occurred immediately prior to the event or termination, as applicable.
(d) If (i) the Executive's employment is terminated for Cause, (ii) the Executive voluntarily terminates his employment and such does not constitute a Constructive Termination Without Cause, or (iii) the Executive's employment is terminated by death or disability, then the Executive shall not be entitled to receive the Termination Benefits.
(a) In the event of any dispute concerning this Agreement, either Executive or the Company may compel the resolution of such dispute by binding arbitration pursuant to the commercial arbitration rules of the American Arbitration Association. The location of such arbitration shall be the city in which the Executive's principal office with the Company is located. Upon receipt of a written demand for arbitration, a hearing shall be scheduled to be held within 60 days of receiving such demand. All costs, fees and expenses, including attorney fees of both the Executive and the Company, of any arbitration in connection with this Agreement which results in any decision or settlement requiring the Company to make a payment or provide any form of compensation to the Executive in excess of any amount
agreed to be paid by the Company shall be borne by, and be the obligation of, the Company. In the event the arbitration does not result in such a decision or settlement, each party shall bear its own expenses and 50% of the costs and expenses of the arbitration. The obligation of the Company under this Section 12 shall survive the termination for any reason of this Agreement (whether such termination is by the Company, by the Executive, upon the expiration of this Agreement or otherwise).
(b) In the event that any person asserts that any of the payments or benefits provided to or in respect of Executive pursuant to this Agreement or otherwise, by or on behalf of the Company, are subject to excise taxes under Section 4999 of the Code, the Company shall assume, and pay the costs of, the dispute with such person but may settle such dispute in its discretion.
(c) Pending the outcome or resolution of any arbitration, the Company shall continue payment of all amounts due the Executive without regard to any dispute but only if Executive agrees in writing that if and to the extent that the Company prevails he will promptly repay to the Company (or, regardless of the existence of such agreement, the Company may set off against any amounts due to the Executive) appropriate amounts plus interest at the applicable Federal Rate provided for in Section 7872(f)(2)(A) of the Code from the date any amount was paid by the Company to the Executive.
If to the Company or the Board:
Cabot Oil & Gas Corporation
1200 Enclave Parkway
Houston, Texas 77077
Attention: Secretary
If to the Executive:
or entity, other than authorized officers, directors and employees of the Company, in any manner whatsoever, any Confidential Information without the prior written consent of the Board.
IN WITNESS WHEREOF, the undersigned have executed this Agreement as of the date first written above.
CABOT OIL & GAS CORPORATION
Date: ___________________ By________________________________________________
Ray R. Seegmiller
Chairman, President and CEO
EXECUTIVE
Date: ___________________ __________________________________________________
-12-
|
Attached to and made a part
|
Schedule A
In the event the Executive so elects in accordance with Section 1(n)(IV) of the Agreement and subject to the Company's election rights provided in the same Section, the premiums payable by the Executive for continued medical, dental and life insurance coverage shall be such premiums as are in effect at the Company immediately prior to the Change in Control.
Exhibit 10.15
CABOT OIL & GAS CORPORATION
SECOND AMENDED AND RESTATED 1994 LONG-TERM
INCENTIVE PLAN
1. Objectives. The Cabot Oil & Gas Corporation Second Amended and Restated 1994 Long-Term Incentive Plan (the "Plan") is designed to attract and retain key executives and other selected employees and reward them for making major contributions to the success of Cabot Oil & Gas Corporation, a Delaware corporation (the "Company"), and its Subsidiaries (as hereinafter defined). These objectives are to be accomplished by making awards under the Plan and thereby providing Participants (as hereinafter defined) with a proprietary interest in the growth and performance of the Company and its Subsidiaries.
2. Definitions. As used herein, the terms set forth below shall have the following respective meanings:
"Award" means the grant of any form of Stock Option, Stock Appreciation Right, Stock Award, Performance Award or Cash Award, whether granted singly, in combination or in tandem, to a Participant pursuant to any applicable terms, conditions and limitations as the Committee may establish in order to fulfill the objectives of the Plan.
"Award Agreement" means a written agreement between the Company and a Participant that sets forth the terms, conditions and limitations applicable to an Award.
"Board" means the Board of Directors of the Company.
"Cash Award" means an Award denominated in cash.
"Code" means the Internal Revenue Code of 1986, as amended from time to time.
"Committee" means such committee of the Board as is designated by the Board to administer the Plan.
"Common Stock" means the Class A Common Stock, par value $.10 per share, of the Company.
"Company" means Cabot Oil & Gas Corporation.
"Employee" means any person who is receiving remuneration for personal services (or could be receiving remuneration except for an authorized leave of absence) as an employee of the Company.
"Exchange Act" means the Securities Exchange Act of 1934, as amended from time to time.
"Fair Market Value" means, as of a particular date, (i) if the shares of Common Stock are listed on a national securities exchange, the average between the highest and lowest sales price per share of Common Stock on the consolidated transaction reporting system for the principal such national securities exchange on that date, or, if there shall have been no such sale so reported on that date, on the last preceding date on which such a sale was so reported, or, at the discretion of the Committee, the price prevailing on the exchange at the time of the relevant event on such date; (ii) if the shares of Common Stock are not so listed but are quoted in the NASDAQ National Market System, the average between the highest and lowest sales price per share of Common Stock on the NASDAQ National Market System on that date, or, if there shall have been no such sale so reported on that date, on the last preceding date on which such a sale was so reported or, at the discretion of the Committee, the price prevailing on the NASDAQ National Market at the time of the relevant event on such date or (iii) if the Common Stock is not so listed or quoted, the average between the closing bid and asked price on that date, or, if there are no quotations available for such date, on the last preceding date on which such quotations shall be available, as reported by NASDAQ, or, if not reported by NASDAQ, by the National Quotation Bureau, Inc.
"Incentive Stock Option" or "ISO" means a Stock Option that complies with Section 422 of the Code.
"Participant" means an employee of the Company or any of its Subsidiaries to whom an Award has been made under this Plan.
"Performance Award" means an Award paid, vested or otherwise deliverable on account of one or more pre-established objective Performance Goals established by the Committee.
"Performance Goal" means a standard established by the Committee to determine in whole or in part whether a Performance Award shall be earned.
"Restricted Stock" means Common Stock that is restricted or subject to forfeiture provisions.
"Stock Award" means an Award consisting of Common Stock or denominated in units of Common Stock.
"Stock Appreciation Right" or "SAR" means the right to receive a payment, in cash or Common Stock, equal to the excess of the Fair Market Value or other specified valuation of a number of shares of Common Stock on the date the stock appreciation right is exercised over a specific strike price.
"Stock Based Awards Limitations" means the limitations applied to any awards granted hereunder as described in Section 7(f)(i) and (ii) of the Plan.
"Stock Option" means a right to purchase a specified number of shares of Common Stock at a specified price that is not less than the greater of (i) the Fair Market Value of
the Common Stock on the date of grant and (ii) the par value of the Common Stock on the date of grant.
"Subsidiary" means any corporation of which the Company directly or indirectly owns shares representing more than 50% of the voting power of all classes or series of capital stock of such corporation which have the right to vote generally on matters submitted to a vote of the stockholders of such corporation.
3. Eligibility. Employees and individuals who have agreed to become Employees of the Company and its Subsidiaries are eligible for an Award under this Plan.
4. Common Stock Available for Awards. There shall be available for Awards granted wholly or partly in Common Stock (including rights or options which may be exercised for or settled in Common Stock) during the term of this Plan an aggregate of 3,700,000 shares of Common Stock of which no more than 30% of such shares will be used for Stock Awards. The Board and the appropriate officers of the Company shall from time to time take whatever actions are necessary to file required documents with governmental authorities and stock exchanges and transaction reporting systems to make shares of Common Stock available for issuance pursuant to Awards. Common Stock related to Awards that are forfeited or terminated, expire unexercised, are settled in cash in lieu of Stock or in a manner such that all or some of the shares covered by an Award are not issued to a Participant, or are exchanged for Awards that do not involve Common Stock, shall immediately become available for Awards hereunder. The Committee may from time to time adopt and observe such procedures concerning the counting of shares against the Plan maximum as it may deem appropriate.
5. Administration. This Plan shall be administered by the Committee, which shall have full and exclusive power to interpret this Plan and to adopt such rules, regulations and guidelines for carrying out this Plan as it may deem necessary or proper, all of which powers shall be exercised in the best interests of the Company and in keeping with the objectives of this Plan. The Committee may, in its discretion, provide for the extension of the exercisability of an Award, accelerate the vesting or exercisability of an Award, eliminate or make less restrictive any restrictions contained in an Award, waive any restriction or other provision of this Plan or an Award or otherwise amend or modify an Award in any manner that is either (i) not adverse to the Participant holding such Award or (ii) consented to by such Participant. The Committee may correct any defect or supply any omission or reconcile any inconsistency in this Plan or in any Award in the manner and to the extent the Committee deems necessary or desirable to carry it into effect. Any decision of the Committee in the interpretation and administration of this Plan shall lie within its sole and absolute discretion and shall be final, conclusive and binding on all parties concerned. No member of the Committee or officer of the Company to whom it has delegated authority in accordance with the provisions of Paragraph 6 of this Plan shall be liable for anything done or omitted to be done by him or her, by any member of the Committee or by any officer of the Company in connection with the performance of any duties under this Plan, except for his or her own willful misconduct or as expressly provided by statute. The Committee shall establish the vesting schedule, if any, for each Award. It is the intent of this Plan that any Stock Option grants will never be repriced or reissued.
6. Delegation of Authority. The Committee may delegate to the Chief Executive Officer and to other senior officers of the Company its duties under this Plan pursuant to such conditions or limitations as the Committee may establish.
7. Awards. The Committee shall determine the type or types of Awards to be made to each Participant under this Plan. Each Award made hereunder shall be embodied in an Award Agreement, which shall contain such terms, conditions, performance requirements and limitations as shall be determined by the Committee in its sole discretion and shall be signed by the Participant and by the Chief Executive Officer, the Chief Operating Officer, or any Vice President of the Company for and on behalf of the Company. Awards may consist of those listed in this Paragraph 7 and may be granted singly, in combination or in tandem.
(a) Stock Option. An Award may consist of a right to purchase a specified number of shares of Common Stock at a specified price that is not less than the greater of (i) the Fair Market Value of the Common Stock on the date of grant and (ii) the par value of the Common Stock on the date of grant. A Stock Option may be in the form of an Incentive Stock Option which, in addition to being subject to applicable terms, conditions and limitations established by the Committee, complies with Section 422 of the Code.
(b) Stock Appreciation Right. An Award may consist of a right to receive a payment, in cash or Common Stock, equal to the excess of the Fair Market Value or other specified valuation of a specified number of shares of Common Stock on the date the Stock Appreciation Right is exercised over a specified strike price as set forth in the applicable Award Agreement.
(c) Stock Award. An Award may consist of Common Stock or may be denominated in units of Common Stock. All or part of any Stock Award may be subject to conditions established by the Committee, and set forth in the Award Agreement, which may include, but are not limited to, continuous service with the Company and its Subsidiaries, achievement of specific business objectives, increases in specified indices, attaining specified growth rates and other comparable measurements of performance. Such Awards may be based on Fair Market Value or other specified valuations. The certificates evidencing shares of Common Stock issued in connection with a Stock Award shall contain appropriate legends and restrictions describing the terms and conditions of the restrictions applicable thereto.
(d) Cash Award. An Award may be denominated in cash with the amount of the eventual payment subject to future service and such other restrictions and conditions as may be established by the Committee, and set forth in the Award Agreement, including, but not limited to, continuous service with the Company and its Subsidiaries, achievement of specific business objectives, increases in specified indices, attaining specified growth rates and other comparable measurements of performance.
(e) Performance Award. Without limiting the type or number of Awards that may be made under the other provisions of this Plan, an Award may be in the form of a Performance Award. A Performance Award shall be paid, vested or otherwise deliverable solely
on account of the attainment of one or more pre-established, objective
Performance Goals established by the Committee prior to the earlier to occur of
(i) 90 days after the commencement of the period of service to which the
Performance Goal relates and (ii) the lapse of 25% of the period of service (as
scheduled in good faith at the time the goal is established), and in any event
while the outcome is substantially uncertain. A Performance Goal is objective if
a third party having knowledge of the relevant facts could determine whether the
goal is met. Such a Performance Goal may be based on one or more business
criteria that apply to the Employee, one or more business units of the Company,
or the Company as a whole, and may include one or more of the following:
increased revenue, net income, stock price, market share, earnings per share,
return on equity, return on assets, decrease in costs, shareholder value, net
cash flow, total shareholder return, return on capital, return on investors'
capital, operating income, funds from operations, cash flow, cash from
operations, after-tax operating income, reserve addition, proceeds from
dispositions, production volumes, refinery runs, net cash flow before financing
activities, reserve replacement ratio, finding and development costs, refinery
utilizations and total market value. Unless otherwise stated, such a Performance
Goal need not be based upon an increase or positive result under a particular
business criterion and could include, for example, maintaining the status quo or
limiting economic losses (measured, in each case, by reference to specific
business criteria). In interpreting Plan provisions applicable to Performance
Goals and Performance Awards, it is the intent of the Plan to conform with the
standards of Section 162(m) of the Code and Treasury Regulation (S) 1.162-
27(e)(2)(i), and the Committee in establishing such goals and interpreting the
Plan shall be guided by such provisions. Prior to the payment of any
compensation based on the achievement of Performance Goals, the Committee must
certify in writing that applicable Performance Goals and any of the material
terms thereof were, in fact, satisfied. Subject to the foregoing provisions, the
terms, conditions and limitations applicable to any Performance Awards made
pursuant to this Plan shall be determined by the Committee.
(f) Notwithstanding anything to the contrary contained in this Plan, the following limitations shall apply to any Awards made hereunder:
(i) no Participant may be granted, during any calendar year, Awards consisting of Stock Options or Stock Appreciation Rights that are exercisable for more than 500,000 shares of Common Stock;
(ii) no Participant may be granted, during any calendar year, Stock Awards covering or relating to more than 100,000 shares of Common Stock; and
(iii) no Participant may be granted Awards consisting of cash or in any other form permitted under this Plan (other than Awards consisting of Stock Options or Stock Appreciation Rights or Stock Awards) in respect of any calendar year having a value determined on the date of grant in excess of $1,000,000.
8. Payment of Awards.
(a) General. Payment of Awards may be made in the form of cash or Common Stock or combinations thereof and may include such restrictions as the Committee
shall determine, including in the case of Common Stock, restrictions on transfer and forfeiture provisions. As used herein, "Restricted Stock" means Common Stock that is restricted or subject to forfeiture provisions.
(b) Deferral. With the approval of the Committee, payments may be deferred, either in the form of installments or a future lump sum payment. The Committee may permit selected Participants to elect to defer payments of some or all types of Awards in accordance with procedures established by the Committee. Any deferred payment, whether elected by the Participant or specified by the Award Agreement or by the Committee, may be forfeited if and to the extent that the Award Agreement so provides.
(c) Dividends and Interest. Dividends or dividend equivalent rights may be extended to and made part of any Award denominated in Common Stock or units of Common Stock, subject to such terms, conditions and restrictions as the Committee may establish. The Committee may also establish rules and procedures for the crediting of interest on deferred cash payments and dividend equivalents for deferred payment denominated in Common Stock or units of Common Stock.
9. Stock Option Exercise. The price at which shares of Common Stock may be purchased under a Stock Option shall be paid in full at the time of exercise in cash or, if permitted by the Committee, by means of tendering Common Stock or surrendering another Award, including Restricted Stock, valued at Fair Market Value on the date of exercise, or any combination thereof. The Committee shall determine acceptable methods for tendering Common Stock or other Awards to exercise a Stock Option as it deems appropriate. If permitted by the Committee, payment may be made by successive exercises by the Participant. The Committee may provide for loans from the Company to permit the exercise or purchase of Awards and may provide for procedures to permit the exercise or purchase of Awards by use of the proceeds to be received from the sale of Common Stock issuable pursuant to an Award. Unless otherwise provided in the applicable Award Agreement, in the event shares of Restricted Stock are tendered as consideration for the exercise of a Stock Option, a number of the shares issued upon the exercise of the Stock Option, equal to the number of shares of Restricted Stock used as consideration therefor, shall be subject to the same restrictions as the Restricted Stock so submitted as well as any additional restrictions that may be imposed by the Committee.
10. Tax Withholding. The Company shall have the right to deduct applicable taxes from any Award payment and withhold, at the time of delivery or vesting of cash or shares of Common Stock under this Plan, an appropriate amount of cash or number of shares of Common Stock or a combination thereof for payment of taxes required by law or to take such other action as may be necessary in the opinion of the Company to satisfy all obligations for withholding of such taxes. The Committee may also permit withholding to be satisfied by the transfer to the Company of shares of Common Stock theretofore owned by the holder of the Award with respect to which withholding is required. If shares of Common Stock are used to satisfy tax withholding, such shares shall be valued based on the Fair Market Value when the tax withholding is required to be made.
11. Amendment, Modification, Suspension or Termination. The Board may amend, modify, suspend or terminate this Plan for the purpose of meeting or addressing any changes in legal requirements or for any other purpose permitted by law except that (i) no amendment or alteration that would impair the rights of any Participant under any Award previously granted to such Participant shall be made without such Participant's consent and (ii) no amendment or alteration shall be effective prior to approval by the Company's stockholders to the extent such approval is then required by applicable legal requirements.
12. Termination of Employment. Upon the termination of employment by a Participant, any unexercised, deferred or unpaid Awards shall be treated as provided in the specific Award Agreement evidencing the Award. In the event of such a termination, the Committee may, in its discretion, provide for the extension of the exercisability of an Award, accelerate the vesting or exercisability of an Award, eliminate or make less restrictive any restrictions contained in an Award, waive any restriction or other provision of this Plan or an Award or otherwise amend or modify the Award in any manner that is either (i) not adverse to such Participant or (ii) consented to by such Participant.
13. Assignability. Unless otherwise determined by the Committee and provided in the Award Agreement, no Award or any other benefit under this Plan constituting a derivative security within the meaning of Rule 16a-1(c) under the Exchange Act shall be assignable or otherwise transferable except by will or the laws of descent and distribution or pursuant to a qualified domestic relations order as defined by the Code or Title I of the Employee Retirement Income Security Act, or the rules thereunder. The Committee may prescribe and include in applicable Award Agreements other restrictions on transfer. Any attempted assignment of an Award or any other benefit under this Plan in violation of this Paragraph 13 shall be null and void.
14. Adjustments.
(a) The existence of outstanding Awards shall not affect in any manner the right or power of the Company or its stockholders to make or authorize any or all adjustments, recapitalizations, reorganizations or other changes in the capital stock of the Company or its business or any merger or consolidation of the Company, or any issue of bonds, debentures, preferred or prior preference stock (whether or not such issue is prior to, on a parity with or junior to the Common Stock) or the dissolution or liquidation of the Company, or any sale or transfer of all or any part of its assets or business, or any other corporate act or proceeding of any kind, whether or not of a character similar to that of the acts or proceedings enumerated above.
(b) In the event of any subdivision or consolidation of outstanding shares of Common Stock or declaration of a dividend payable in shares of Common Stock or capital reorganization or reclassification or other transaction involving an increase or reduction in the number of outstanding shares of Common Stock, the Committee may adjust proportionally (i) the number of shares of Common Stock reserved under this Plan and covered by outstanding Awards denominated in Common Stock or units of Common Stock; (ii) the exercise or other price in respect of such Awards; (iii) the appropriate Fair Market Value and other price
determinations for such Awards; and (iv) the Stock Based Awards Limitations, as provided in Section 7(f)(ii) to reflect such transaction. In the event of any consolidation or merger of the Company with another corporation or entity or the adoption by the Company of a plan of exchange affecting the Common Stock or any distribution to holders of Common Stock of securities or property (other than normal cash dividends or dividends payable in Common Stock), the Committee shall make such adjustments or other provisions as it may deem equitable, including adjustments to avoid fractional shares, to give proper effect to such event. In the event of a corporate merger, consolidation, acquisition of property or stock, separation, reorganization or liquidation, the Committee shall be authorized to issue or assume stock options, regardless of whether in a transaction to which Section 424(a) of the Code applies, by means of substitution of new options for previously issued options or an assumption of previously issued options, or to make provision for the acceleration of the exercisability of, or lapse of restrictions with respect to, Awards and the termination of unexercised options in connection with such transaction.
15. Restrictions. No Common Stock or other form of payment shall be issued with respect to any Award unless the Company shall be satisfied based on the advice of its counsel that such issuance will be in compliance with applicable federal and state securities laws. Certificates evidencing shares of Common Stock delivered under this Plan may be subject to such stop transfer orders and other restrictions as the Committee may deem advisable under the rules, regulations and other requirements of the Securities and Exchange Commission, any securities exchange or transaction reporting system upon which the Common Stock is then listed and any applicable federal and state securities law. The Committee may cause a legend or legends to be placed upon any such certificates to make appropriate reference to such restrictions.
16. Unfunded Plan. Insofar as it provides for Awards of cash, Common Stock or rights thereto, this Plan shall be unfunded. Although bookkeeping accounts may be established with respect to Participants who are entitled to cash, Common Stock or rights thereto under this Plan, any such accounts shall be used merely as a bookkeeping convenience. The Company shall not be required to segregate any assets that may at any time be represented by cash, Common Stock or rights thereto, nor shall this Plan be construed as providing for such segregation, nor shall the Company nor the Board nor the Committee be deemed to be a trustee of any cash, Common Stock or rights thereto to be granted under this Plan. Any liability or obligation of the Company to any Participant with respect to a grant of cash, Common Stock or rights thereto under this Plan shall be based solely upon any contractual obligations that may be created by this Plan and any Award Agreement, and no such liability or obligation of the Company shall be deemed to be secured by any pledge or other encumbrance on any property of the Company. Neither the Company nor the Board nor the Committee shall be required to give any security or bond for the performance of any obligation that may be created by this Plan.
17. Governing Law. This Plan and all determinations made and actions taken pursuant hereto, to the extent not otherwise governed by mandatory provisions of the Code or the securities laws of the United States, shall be governed by and construed in accordance with the laws of the State of Delaware.
18. Effective Date of Plan. This amended and restated Plan shall be effective as of the date (the "Effective Date") it is approved by the Board of Directors of the Company. Notwithstanding the foregoing, the adoption of this Plan is expressly conditioned upon the approval by the holders of a majority of shares of Common Stock present, or represented, and entitled to vote at a meeting of the Company's stockholders held on or before ___________, 2001. If the stockholders of the Company should fail so to approve the provisions of this Plan, the Plan shall revert to the provisions as in effect under the Amended and Restated 1994 Long-Term Incentive Plan of Cabot Oil & Gas Corporation.
Exhibit 10.16
SECOND AMENDED AND RESTATED
1994 NONEMPLOYEE DIRECTOR STOCK OPTION PLAN
of
CABOT OIL & GAS CORPORATION
1. Purpose of the Plan. This Nonemployee Director Stock Option Plan (the "Plan") is intended as an incentive to retain and attract persons of training, experience and ability to serve as independent directors on the Board of Directors of Cabot Oil & Corporation, a Delaware corporation (the "Company"), to encourage the sense of proprietorship of such persons and to stimulate the active interest of such persons in the development and financial success of the Company. It is further intended that the options granted pursuant to this Plan (the "Options") will be nonqualified options within the meaning of Section 83 of the Internal Revenue Code of 1986, as amended (the "Code").
2. Stockholder Approval. All Options granted pursuant to this Plan are subject to, and may not be exercised before, the approval of this Plan by the affirmative vote of the holders of a majority of the outstanding shares of the Class A Common Stock, par value $.10 per share (the "Common Stock"), of the Company that are present, or represented, and entitled to vote at a meeting of the Company's stockholders.
3. Designation of Participants; Automatic Grant of Options. Each director of the Company who is not an employee of the Company or any Subsidiary (as hereinafter defined) of the Company (any such director being hereinafter referred to as a "Nonemployee Director") shall be granted Options as described hereunder. Each individual who becomes a Nonemployee Director after the Effective Date shall automatically be granted Options to purchase 10,000 shares of Common Stock (subject to adjustment as provided in Paragraph 10) on the date such person first becomes a Nonemployee Director. Furthermore, at each annual meeting of stockholders (other than when the director's status as such terminates at such meeting), each Nonemployee Director shall automatically be granted Options to purchase an additional 5,000 shares of Common Stock (subject to adjustment as provided in Paragraph 10) on such date. Notwithstanding the foregoing, in the case of any grant of Options made on a date subsequent to the Effective Date, such grant shall only be made if the number of shares subject to future grant under this Plan is sufficient to make all automatic grants required to be made pursuant to this Plan on such date of grant. As used herein, the term "Subsidiary" of the Company shall mean any corporation of which the Company directly or indirectly owns shares representing more than 50% of the voting power of all classes or series of capital stock of such corporation which have the right to vote generally on matters submitted to a vote of the stockholders of such corporation.
4. Option Agreement. Each Option granted hereunder shall be embodied in a written option agreement ("Option Agreement"), which shall be subject to the terms and conditions set forth herein and shall be signed by the Optionee and by the Chief Executive Officer, the Chief Operating Officer, or any Vice President of the Company for and on behalf of the Company.
5. Common Stock Reserved for the Plan. Subject to adjustment as provided in Paragraph 10 hereof, a total of 500,000 shares of Common Stock shall be reserved for issuance upon the exercise of Options granted pursuant to this Plan. The shares subject to the Plan shall consist of unissued shares or previously issued shares reacquired and held by the Company, or any parent or subsidiary of the Company, in its treasury. The Board of Directors and the appropriate officers of the Company shall from time to time take whatever actions are necessary to execute, acknowledge, file and deliver any documents required to be filed with or delivered to any governmental authority or any stock exchange or transaction reporting system on which shares of Common Stock are listed or quoted in order to make shares of Common Stock available for issuance to an Optionee (as hereinafter defined) pursuant to this Plan. Common Stock subject to Options that are forfeited or terminated or expire unexercised in such a manner that all or some of the shares subject thereto are not issued to an Optionee shall immediately become available for the granting of Options. As used herein, the term "Optionee" shall mean any Nonemployee Director to whom Options are granted hereunder.
6. Option Price.
(a) The purchase price of each share of Common Stock that is subject to an Option granted pursuant to this Plan shall be 100% of the Fair Market Value of such share of Common Stock on the date the Option is granted.
(b) The Fair Market Value of a share of Common Stock on a particular date shall be deemed to be (i) if the shares of Common Stock are listed on a national securities exchange, the average between the highest and lowest sales price per share of Common Stock on the consolidated transaction system reporting system for such national securities exchange on that date, or, if there shall have been no such sale so reported on that date, on the last preceding date on which such a sale was so reported, or, at the discretion of the Board of Directors, the price prevailing on the exchange at the time
of the relevant event on such date; (ii) if the shares of Common Stock are not so listed but are quoted in the NASDAQ National Market System, the average between the highest and lowest sales price per share of Common Stock on the NASDAQ National Market System on that date, or, if there shall have been no such sale so reported on that date, on the last preceding date on which such a sale was so reported or, at the discretion of the Board of Directors, the price prevailing on the NASDAQ National Market at the time of the relevant event on such date or (iii) if the Common Stock is not so listed or quoted, the average between the closing bid and asked price on that date, or, if there are no quotations available for such date, on the last preceding date on which such quotations shall be available, as reported by NASDAQ, or, if not reported by NASDAQ, by the National Quotation Bureau, Inc.
7. Option Period. Each Option granted pursuant to this Plan shall
terminate and be of no force and effect with respect to any shares of Common
Stock not purchased by the Optionee upon the earliest to occur of the following:
(a) the expiration of five years following the date upon which the Option is
granted; (b) the expiration of one year following the date upon which the
Optionee ceases to be a Nonemployee Director by reason of death, disability or
mandatory retirement; or (c) the expiration of three months following the date
on which the Optionee ceases to be a Nonemployee Director for any reason other
than death, disability or mandatory retirement.
8. Exercise of Options.
(a) Options granted pursuant to this Plan shall be exercisable, on a cumulative basis, as follows: (i) with respect to 33 1/3% of the total number of shares of Common Stock initially subject to any Option, such Option shall be exercisable on the first anniversary of the date of grant; and (ii) with respect to the remaining shares of Common Stock subject to any Option, such Option shall be exercisable with respect to an additional 33 1/3% of the total number of shares initially subject thereto as of the second and third anniversaries of the date of the grant.
(b) An Option may be exercised solely by the Optionee during his lifetime or after his death by the person or persons entitled thereto under his will or the laws of descent and distribution.
(c) In the event that an Optionee ceases to serve as a Nonemployee Director for any reason other than death, disability or mandatory retirement, an Option granted to such Optionee may be exercised only to the extent such Option was exercisable at the time he ceased to serve in such capacity.
(d) In the event that an Optionee ceases to serve as a Nonemployee Director by reason of death, disability or mandatory retirement, at a time when an Option granted hereunder is still in force and unexpired under the terms of Paragraph 7 hereof, each such unmatured Option shall be accelerated. Such acceleration shall be effective as of the date of death, disability or retirement, as appropriate, and each Option so accelerated shall be exercisable in full for so long as it is still in force and unexpired under the terms of Paragraph 7 hereof.
(e) The purchase price of the shares as to which an Option is exercised shall be paid in full at the time of the exercise. Such purchase price shall be payable in cash or by means of tendering theretofore owned Common Stock which has been held by the Optionee for more than six months, valued at Fair Market Value on the date of exercise, or any combination thereof. An Optionee may also exercise an Option by use of the proceeds to be received from the sale of Common Stock issuable pursuant to the Option. No holder of an Option shall be, or have any of the rights or privileges of, a stockholder of the Company in respect of any shares subject to any Option unless and until certificates evidencing such shares shall have been issued by the Company to such holder.
9. Assignability. Unless otherwise determined by the Board of Directors and provided in the Option Agreement, no Option shall be assignable or otherwise transferable except by will or the laws of descent and distribution or pursuant to a qualified domestic relations order as defined by the Code or Title I of the Employee Retirement Income Security Act, or the rules thereunder. Any attempted assignment of an Option in violation of this Paragraph 9 shall be null and void.
10. Adjustments.
(a) The existence of outstanding Options shall not affect in any manner the right or power of the Company or its stockholders to make or authorize any or all adjustments, recapitalizations, reorganizations or other changes in the capital stock of the Company or its business or any merger or consolidation of the Company, or any issue of bonds, debentures, preferred or prior preference stock (whether or not such issue is prior to, on a parity with or junior to the Common Stock) or the dissolution or liquidation of the Company, or any sale or transfer of all or any part of its assets or
business, or any other corporate act or proceeding of any kind, whether or not of a character similar to that of the acts or proceedings enumerated above.
(b) In the event of any subdivision or consolidation of outstanding shares of Common Stock or declaration of a dividend payable in shares of Common Stock or capital reorganization or reclassification or other transaction involving an increase or reduction in the number of outstanding shares of Common Stock, the Board of Directors may adjust proportionally (i) the number of shares of Common Stock reserved under these Options; and (ii) the exercise price of such Options. In. the event of any consolidation or merger of the Company with another corporation or entity or the adoption by the Company of a plan of exchange affecting the Common Stock or any distribution to holders of Common Stock of securities or property (other than normal cash dividends or dividends payable in Common Stock), the Board of Directors shall make such adjustments or other provisions as it may deem equitable, including adjustments to avoid fractional shares, to give proper effect to such event. In the event of a corporate merger, consolidation, acquisition of property or stock, separation, reorganization or liquidation, the Board of Directors shall be authorized to issue or assume stock options, regardless of whether in a transaction to which Section 424(a) of the Code applies, by means of substitution of new options for previously issued options or an assumption of previously issued options, or to make provision for the acceleration of the exercisability of, or lapse of restrictions with respect to, the termination of unexercised options in connection with such transaction.
(c) An Option shall become fully exercisable upon a Change in Control (as
hereinafter defined) of the Company. For purposes of this Plan, a "Change of
Control" shall be conclusively deemed to have occurred if (and only if) any of
the following events shall have occurred: (a) there shall have occurred an event
required to be reported in response to Item 6(e) of Schedule 14A of Regulation
14A (or in response to any similar item on any similar schedule or form)
promulgated under the Securities Exchange Act of 1934, as amended (the "Exchange
Act"), whether or not the Company is then subject to such reporting requirement;
(b) any "person" (as such term is used in Sections 13(d) and 14(d) of the
Exchange Act) shall have become the "beneficial owner" (as defined in Rule 13d-3
under the Exchange Act), directly or indirectly, of securities of the Company
representing 20% or more of the combined voting power of the Company's then
outstanding voting securities without prior approval of at least two-thirds of
the members of the Board of Directors in office immediately prior to such
person's attaining such percentage interest; (c) the Company is a party to a
merger, consolidation, sale of assets or other reorganization, or a proxy
contest, as a consequence of which members of the Board of Directors in office
immediately prior to such transaction or event constitute less than a majority
of the Board of Directors thereafter or (d) during. any period of two
consecutive years, individuals who at the beginning of such period constituted
the Board of Directors (including for this purpose any new director whose
election or nomination for election by the Company's stockholders was approved
by a vote of at least two-thirds of the directors then still in office who were
directors at the beginning of such period) cease for any reason to constitute at
least a majority of the Board of Directors.
11. Taxes. The Company may make such provisions as it may deem appropriate for the withholding of any taxes that it determines is required in connection with any Options granted to any Optionee hereunder.
12. Amendments or Termination. The Board of Directors of the Company may amend, alter or discontinue this Plan, except that (a) no amendment or alteration that would impair the rights of any Optionee under any Option that he has been granted shall be made without his consent and (b) no amendment or alteration shall be effective prior to approval by the Company's stockholders to the extent such approval is then required.
13. Government Regulations. This Plan, and the granting and exercise of Options hereunder, and the obligation of the Company to sell and deliver shares of Common Stock under such Options, shall be subject to all applicable laws, rules and regulations, and to such approvals on the part of any governmental agencies or national securities exchanges or transaction reporting systems as may be required.
14. Governing Law. This Plan and all determinations made and actions taken pursuant hereto, to the extent not otherwise governed by mandatory provisions of the Code or the securities laws of the United States, shall be governed by and construed in accordance with the laws of the State of Delaware.
15. Effective Date of Plan. This amended and restated Plan shall be effective as of the date (the "Effective Date") it is approved by the Board of Directors of the Company. Notwithstanding the foregoing, the adoption of this amended and restated Plan is expressly conditioned upon the approval by the holders of a majority of shares of Common Stock present, or represented, and entitled to vote at a meeting of the Company's stockholders held on or before __________________, 2001. If the stockholders of the Company should fail so to approve this amended and restated Plan prior to such date, this amended and restated Plan shall revert to the provisions of the prior plan and all grants of options hereunder in excess of The Plan's limitations shall be null and void.
16. Miscellaneous. The granting of any Option shall not impose upon the Company, the Board of Directors of the Company or any other directors of the Company any obligation to nominate any Optionee for election as a director and the right of the stockholders of the Company to remove any person as a director of the Company shall not be diminished or affected by reason of the fact that an Option has been granted to such person.
Exhibit 10.19
CABOT OIL & GAS CORPORATION
DEFERRED COMPENSATION PLAN
(As Established Effective June 1, 1998)
Cabot Oil & Gas Corporation, a Delaware corporation (the "Company"),
having established the Cabot Oil & Gas Corporation Deferred Compensation Plan,
effective June 1, 1998, (the "Plan"), and having reserved the right under
Section VIII.4 thereof to amend the Plan, does hereby amend the Plan, effective
as herein provided, as follows:
1. Section 1.2(z) of the Plan is hereby amended, effective July 1, 2001 by replacing 4% with 6% in the first sentence thereof.
2. Section 1.2(bb) is hereby amended in its entirety, effective September 1, 2001, to read as follows:
"'Payment Date' shall mean the time as soon as practicable after (1) the last day of the month in which the Participant's employment terminates for any reason or (2) the Future Date Withdrawal, if sooner."
3. The first sentence of Section IV.3 of the Plan is hereby amended in its entirety, effective February 1, 2000, to read as follows:
"The Company has created a Trust with Harris Trust & Savings Bank with such banking corporation to act as Trustee."
4. Section V1.2, effective September 1, 2001, is hereby amended by adding a subsection (e) thereto to read as follows:
elect an early distribution of the balance (the "Distributable Balance") of his or her Distributable Amount in a lump sum subject to the satisfaction of one of the following restrictions:
(1) Ten percent of the retired or disabled Participant's Distributable Balance shall be permanently forfeited and the Company shall have no obligation to such Participant or his or her beneficiary with respect to the forfeited amount; or
(2) The Participant demonstrates to the satisfaction of the Committee that circumstances affecting the Participant have changed significantly and the Committee in its sole discretion determines that the distribution of the Distributable Balance of the Distributable Amount in a lump sum is appropriate and authorizes such a lump sum payment.
IN WITNESS WHEREOF, the Company has caused this amendment to be executed by its duly authorized officer this _____ day of ________________, 2001, but effective as of the date specified herein.
CABOT OIL & GAS CORPORATION
By_____________________________________
Name:_______________________________
Title:______________________________
Exhibit 10.20
TRUST AGREEMENT (this "Trust Agreement") made this 1st day of February, 2000, by and between Cabot Oil & Gas Corporation, a Delaware corporation (the "Company" or "Grantor"), and HARRIS TRUST AND SAVINGS BANK, an Illinois banking corporation (the "Trustee").
WHEREAS, the Company has adopted the nonqualified deferred compensation plan listed in Appendix A (the "Plan");
WHEREAS, the Company has incurred or expects to incur liability under the terms of the Plan with respect to the Participants;
WHEREAS, the Company desires to establish a trust (hereinafter called the "Trust") and, in its discretion, to contribute to the Trust assets that shall be held therein, subject to the claims of the Company's creditors in the event the Company is Insolvent, to provide an alternative source of funds to assist the Company in meeting its liabilities under the Plan;
WHEREAS, the Company desires to direct the investment of the Trust assets; and
WHEREAS, Harris Trust and Savings Bank is willing to act as Trustee of the Trust upon all of the terms and conditions hereinafter set forth.
NOW, THEREFORE, the Company and the Trustee declare and agree that the Trustee will receive, hold and administer all sums of money and such other property acceptable to the Trustee as shall from time to time be contributed, paid or delivered to it hereunder, IN TRUST, upon all of the following terms and conditions:
1. Establishment of Trust.
(a) The Company hereby establishes with the Trustee a Trust consisting of deposits of cash or other property acceptable to the Trustee, which shall become the principal of the Trust, to be held, administered and disposed of by the Trustee as provided in this Trust Agreement. All such cash and other property, all investments and reinvestments made therewith and the income and proceeds thereof, less the payments or other distributions which, at the time of reference, shall have been made by the Trustee, are referred to herein as the "Trust" or "Fund".
(b) The Trust hereby established shall be irrevocable.
(c) The Trust is intended to be a grantor trust within the meaning of subpart E, part I, subchapter J, chapter 1, subtitle A of the Code of which the Company is the grantor. The Company acknowledges that determination of the status of the Trust as a grantor trust has been made by the Company and Harris Trust and Savings Bank assumes no responsibility in this regard. The Company represents and covenants to the Trustee that at all times during the continuation of the Trust: the Trust shall constitute an unfunded arrangement and the establishment of this Trust shall not affect the status of any Plan as an unfunded plan maintained for the purpose of providing deferred compensation for a select group of management or highly compensated employees and/or as an excess benefit plan for purposes of Title I of ERISA; if any interests in the Plan are deemed to be "securities," within the meaning of the Securities Act, each offering by the Company of any such interests either has been or will be registered under the Securities Act or falls or will fall within an available exemption from the registration requirements of such Act, and complies or will comply with any applicable state securities laws; and the Trust is not required to register as an investment company under the Investment Company Act of 1940, as amended.
(d) Unless and until withdrawn from trust as provided herein, the principal of the Trust, and any earnings thereon, shall be held separate and apart from other funds of the Company (or any other grantor trust established by the Company) and shall be used exclusively for the uses and purposes of Participants and general creditors of the Company as herein set forth. Participants shall have no preferred claim on, or any beneficial ownership interest in, any assets of the Trust. Any rights created under a Plan and this Trust Agreement shall be unsecured contractual rights of Participants against the Company, and, subject to the other terms and conditions of this Trust Agreement, to the extent that the Company fails to pay a Participant benefits to which such Participant is entitled under a Plan, such Participant shall be entitled to receive such deficiency from the available assets of the Trust, but not in excess of the amount required by the Payment Schedule to be paid to such Participant. Any claim of a Participant to receive benefits under a Plan in addition to the payments set forth in the Payment Schedule for such Participant shall be solely against the Company and not against the Trust or the Trustee. Any assets held by the Trust will be subject to the claims of the general creditors of the Company under Federal and state law in the event the Company becomes Insolvent.
(e) The Trustee shall be responsible only for contributions actually received by it. The amount and timing of each or any contribution shall be determined in the sole discretion of the Company. The Company may undertake under the terms of a Plan or a related agreement to which the Trustee is not a party to make contributions at specific intervals or on the occurrence of a specific event. If the Company fails to make any such contribution, in whole or in part, the Company shall be responsible for notifying affected Participants. The Trustee shall have no obligation to police the Company's compliance therewith or to notify Participants thereof. The Trustee shall have no duty or responsibility to any Person to bring any proceeding or take any other action to compel any contributions by the Company, except to add such contributions to the Trust for the account of the designated Plans if and when received by the Trustee.
(f) The Trustee shall maintain a separate account, and such sub- accounts as the Company shall deem advisable to reflect the Equitable Share of the Plan, or part thereof, in the
Trust. The Company shall advise the Trustee of the Equitable Shares at the time of each contribution to or distribution from the Trust.
2. Payments to Participants.
(a) The Company shall be solely responsible for keeping, and providing to the Recordkeeper, accurate books and records with respect to the employees of the Company, their compensation and their beneficiaries' rights and interests in the Trust pursuant to the Plan. As soon as practicable after the establishment of this Trust and the addition of any nonqualified deferred compensation plan to Appendix A, or the amendment of any Plan, the Company shall provide the Recordkeeper with certified copies of such Plans and/or amendments, and all related documents. The Trustee shall not be required to maintain any separate records or accounts with respect to any Participant, and any records or accounts required to be maintained pursuant to the terms of any Plan shall be the responsibility of the Company or Recordkeeper.
(b) As soon as practicable after the establishment of this Trust, the Company shall deliver a Payment Schedule to the Trustee. The Company shall regularly revise or update the Payment Schedule, as required. Except as otherwise provided in Section 3, upon receipt from the Company of such Payment Schedule, which shall include the amount of Federal, state and local tax required to be withheld, the Trustee shall make payments at the times and in the manner and form specified in such Payment Schedule to Participants and to the Company with respect to any taxes withheld from such payments in accordance with the Company's instructions, all to the extent funds are available in the Trust with respect to the applicable Plan. The Trustee shall not make any payments to Participants from the Trust other than as required by the Payment Schedule.
(c) The Company may make payment of benefits directly to Participants as they become due under the terms of the Plan. In such event, the Company shall also provide for the reporting and withholding of any Federal, state or local taxes that may be required to be withheld with respect to such benefit payments. The Company shall notify the Trustee of its decision to pay such benefits directly prior to the time amounts are payable to Participants, and any such notice received by the Trustee shall constitute an amendment of the affected Payment Schedule.
(d) If the principal of the Trust, and any earnings thereon, allocated to a Plan are not sufficient to make payments of all benefits then payable as of a payment date in accordance with the Payment Schedule, the Trustee shall notify the Company of the deficiency and the Company shall determine the specific amounts to be paid to each payee and provide such to the Trustee in writing.
(e) The Company shall have sole responsibility for the payment of all withholding taxes to, and the filing of all required tax returns with, the appropriate taxing authority and shall furnish each Participant with the appropriate tax information form evidencing such payment and the amount thereof. The Company shall provide the Trustee with a schedule of all benefits that have been paid by the Company directly to Participants and a schedule of all tax
withholding payments made by it to the taxing authorities within fifteen (15) days after the end of the month in which such payments have been made.
(f) The entitlement of a Participant to benefits under the Plan shall be determined by the Company and any claim for such benefits shall be considered and reviewed by the Company or its designee under the procedures set forth in the applicable Plan. The Trustee shall have no responsibility with regard to administration of the Plan. Without limiting the generality of the foregoing, the Trustee shall have no responsibility should the Trust, or any Plan's interest in the Trust, have insufficient assets from which to make any distribution called for under any Payment Schedule or Plan, the Trustee shall have no responsibility to interpret the provisions of the Plan, and the Trustee shall have no responsibility for determining whether any Participant has become entitled to any distribution under any Plan, or the amount thereof, and the Trustee shall be entitled to rely solely upon the accuracy, timeliness and completeness of the latest Payment Schedule delivered to it by the Company.
(g) The Trustee shall notify the Company periodically of any returned or undeliverable payments to Participants. Any payments remaining unclaimed for [six (6)] months after such notice has been given to the Company shall be returned to Trust and allocated to the account of the Plan originally debited.
3. Trustee Responsibility Regarding Payments to Trust Beneficiary When Company is Insolvent.
(a) At all times during the continuance of this Trust, as provided in Section 1 (d) hereof, the principal and income of the Trust shall be subject to claims of general creditors of the Company under Federal and state law.
(b) The Trustee shall cease payment of benefits to Participants if the Company is Insolvent, as set forth below.
(1) The Board of Directors and the Chief Executive Officer of
the Company shall have the duty to inform the Trustee in writing if
the Company is Insolvent. If a person claiming to be a creditor of the
Company alleges in writing to the Trustee, or the Trustee has actual
knowledge, or the Trustee otherwise receives, in accordance with
paragraph (f) of Section 15, written notification, that the Company
has become or may be Insolvent, the Trustee shall determine whether
the Company is Insolvent for purposes of this Trust Agreement by
requesting confirmation that the Company is not Insolvent (a "Section
3(b)(1) Confirmation") from the Board of Directors, acting through its
Chairman, and the Chief Executive Officer of the Company. The Trustee
shall, without further inquiry of any Person, conclusively rely on
such confirmation for all purposes of this Trust Agreement, and,
pending such determination, the Trustee shall discontinue payment of
benefits to Participants.
(2) Unless the Trustee, acting through the Trustee's officer to
whom notices hereunder are to be directed as provided in Section
15(f), has actual knowledge that the Company is or may be Insolvent,
or has received written notification, in accordance with paragraph (f)
of Section 15, from the Company or a Person claiming to be a creditor
of the Company alleging that the Company is Insolvent, the Trustee
shall have no duty to the Company or the Company's creditors to
inquire whether the Company is Insolvent.
(3) If the Trustee does not receive a Section 3(b)(1) Confirmation, the Trustee shall discontinue payments to Participants and shall hold the assets of the Trust for the benefit of the Company's general creditors until the Trustee either receives a court order directing the disposition of the Trust, or the Chairman of the Board of Directors and the Chief Executive Officer of the Company deliver a written notice to the Trustee confirming that the Company is no longer Insolvent (a "Section 3(b)(3) Confirmation"); provided, however, in no event shall the provisions of Sections 10 and 11 providing for the payment of the Trust's expenses and taxes be suspended.
(4) Nothing in this Trust Agreement is intended to and shall not in any way diminish any rights of Participants to pursue their rights as general creditors of the Company with respect to benefits due under the Plan or otherwise.
(5) The Trustee shall resume the payment of benefits to Participants in accordance with Section 2 only after the Trustee has received a Section 3(b)(1) or a Section 3(b)(3) Confirmation.
(c) Provided that there are sufficient assets, if the Trustee discontinues the payment of benefits from the Trust and subsequently resumes such payments pursuant to Section 3(b), the first payment following such discontinuance shall include the aggregate amount of all payments due to Participants under the terms of the Plan for the period of such discontinuance, less the aggregate amount of any payments certified by the Company to the Trustee to have been made to such Participants by the Company in lieu of the payments provided for hereunder during any such period of discontinuance.
4. Payments to Company.
Except as provided in Sections 3, 10 and 11, the Company shall have no right or power to direct the Trustee to return to the Company or to divert to others, any of the Trust assets before all payment of benefits have been made to Participants pursuant to the terms of the Plan, as certified to the Trustee by the Company in writing, and all obligations owed to the Trustee under Section 10, and all taxes under Section 11, have been fully satisfied or otherwise provided for. If the Plan terminates prior to the termination of this Trust, any excess assets after the satisfaction of all liabilities thereunder and hereunder, shall be allocated as directed by the Company.
5. Investment Authority.
(a) Discretionary authority for the management and control of the assets of the Trust may be retained, allocated or delegated, as the case may be, for one or more purposes, to and among the Asset Managers by the Company in its absolute discretion. The terms and conditions of appointment, authority and retention of any Asset Manager shall be the sole responsibility of the Company. Any investment policy, and any related guidelines, established by the Company from time to time, shall be communicated to the affected Asset Manager and monitored by the Company. The assets of the Trust shall be invested and reinvested, without distinction between principal and income, at such time or times in such investments pursuant to such investment strategies or courses of action and in such shares and proportions, as each Asset Manager, in its sole discretion, shall deem advisable, subject to such policies and guidelines, if any. The initial Asset Manager shall be the Company and all of the assets of the Trust shall be under its exclusive control and management until further written direction to the Trustee.
(b) The Company shall promptly notify the Trustee in writing of the appointment or removal of an Asset Manager and shall specify the portion of the Trust to be managed by such Asset Manager. Each Asset Manager shall have sole and complete investment responsibility for the assets of the Trust that are subject to its discretionary authority or control and the Trustee shall receive, hold and transfer assets purchased or sold by the Asset Manager in accordance with the directions of such Asset Manager. The Trustee shall be under no duty or obligation to review or to question any direction of any Asset Manager, or to review the securities or any other property held in any Directed Fund with respect to prudence, proper diversification or compliance with any limitation on an Asset Manager's authority under this Trust Agreement or the terms of a Plan, any investment policies and guidelines, or any agreement entered into between the Company and the Asset Manager or imposed by applicable law, or to make any suggestions or recommendations to any Asset Manager or the Company with respect to the retention or investment of any Directed Fund. The Trustee shall have no authority to take any action or to refrain from taking any action with respect to any asset of a Directed Fund unless and until it is directed to do so by the Asset Manager of such Directed Fund or the Company.
(c) The Trustee will have no responsibility for any asset allocated to a Directed Fund upon the resignation or removal of an Asset Manager unless and until the Trustee has been notified in writing by the Company that the Asset Manager's authority will be terminated or relinquished, and the Trustee has agreed in writing to become an Asset Manager or that such assets are to be integrated with a Discretionary Fund, as the case may be. In no event shall the Trustee be liable for any losses to the Trust resulting from the disposition of any investment made for a Directed Fund or for the retention of any illiquid or unmarketable investment or for the holding of any other asset acquired therefor if the Trustee is unable to dispose of such investment because of any securities laws restrictions or if an orderly liquidation of such investment is difficult under prevailing conditions, or for failure to comply with any investment or diversification limitations imposed by the Company, or for any other violation of the terms of this Trust Agreement, any Plan or applicable law or laws, as a result of the addition of such assets to the Discretionary Fund.
(d) No person dealing with the Trustee or an Asset Manager hereunder shall be under any obligation to see to the proper application of any money paid or property delivered to the Trustee or the Asset Manager, or to inquire into the authority of the Trustee or the Asset Manager as to any transaction, or the validity, expediency or propriety thereof.
6. Powers of the Asset Managers.
(a) Without in any way limiting the powers and discretions conferred upon the Asset Managers by the other provisions of this Trust Agreement or by law, each Asset Manager shall be vested with the following powers and discretions, and, upon the directions of the Asset Manager, the Trustee shall make, execute, acknowledge and deliver any and all documents of transfer and conveyance and any and all other instruments that may be necessary or appropriate to enable-such Asset Manager to carry out such powers and discretions:
(1) to invest and reinvest in any property, real, personal or mixed, wherever situated and whether or not productive of income or consisting of wasting assets, including, without limitation, common and preferred stocks, bonds, notes, debentures (including convertible stocks and securities but not including any stock or other security (or right to acquire such stock or other security) of the Company (other than a de minimis amount held in commingled investment vehicles in which an Asset Manager invests)), leaseholds, mortgages, certificates of deposit or demand or time deposits (including any such deposits with the Trustee), securities of investment companies, registered or unregistered (notwithstanding that the Asset Manager, or Trustee, or an affiliate of the Asset Manager, acts as investment adviser, custodian, transfer agent, registrar, sponsor, distributor or manager or provides, for compensation, other services to the investment company, including specifically the Harris Insight Funds from which the Trustee receives an investment advisory fee, all or a part of which is paid to Trustee's affiliate Harris Investment Management, Inc. for its portfolio management service provided to Harris Insight Funds), interests in partnerships and trusts, insurance contracts, and oil, mineral or gas properties, royalties, interests or rights, without being limited to the classes of property in which trustees are authorized to invest by any applicable law or any rule or court of any state and without regard to the proportion any such property may bear to the entire amount of the Trust assets;
(2) to retain any property at any time received by the Trust;
(3) to purchase, sell, exchange, convey, transfer or otherwise dispose of any property by private contract or at public auction;
(4) to grant and exercise options for the purchase or exchange of property held by it;
(5) to enter into contracts or to make commitments, either alone or in company with others, to sell or acquire property;
(6) to purchase, sell, write or issue puts, calls or other options, covered or uncovered, to enter into financial futures contracts, forward placement contracts, standby contracts and similar arrangements commonly referred to as "derivatives", and in connection therewith, to deposit, hold (or direct the Trustee to deposit or hold) or pledge assets of the Trust;
(7) to exercise all voting or other rights (but subject to the suspension of any voting rights as a result of any broker loan or similar agreement); to give general or special proxies or powers of attorney with or without power of substitution; to exercise any conversion privileges, subscription rights or other options and to make any payments incidental thereto; to participate in any plan of reorganization, consolidation, merger, combination, liquidation or other similar plan relating to property that is subject to its management and control and to consent to or oppose any such plan or any action thereunder or any contract, lease, mortgage, purchase, sale or other action by any person, and to delegate discretionary powers and to pay any assessments or charges in connection therewith;
(8) to manage, administer, operate, insure, repair, improve, develop, preserve, mortgage, lease or otherwise deal with, for any period, any real property or any oil, mineral or gas properties, royalties, interest, or rights directly or through any corporation, either alone or by joining with others, using Trust assets for any such purposes, to modify, extend, renew, waive or otherwise adjust any provision of any such mortgage or lease and to make provision for amortization of the investment in or depreciation of the value of such property; and
(9) to acquire the remaining undivided interest of any Affiliate Trust created by an Affiliate pursuant to Section 18 without notice to or consent of any other Person.
(b) In addition, the Trustee is hereby authorized:
(1) to register any securities held in the Trust or to take title to any property in its own name or in the name of a nominee or nominees, with or without the addition of words indicating that such securities or other property are held as trustee, and to hold any securities in bearer form, and to combine certificates representing such securities with certificates of the same issue held by the Trustee in other representative capacities or as agent for customers, or to deposit or to arrange for the deposit of such securities in any qualified central depository, domestic or foreign, even though, when so deposited, such securities may be merged and held in bulk in the name of the nominee of such depository with other securities deposited therein by other depositors, or to deposit or arrange for the deposit of any securities
issued by the United States Government, or any agency or instrumentality thereof, with a Federal Reserve Bank, but the books and records of the Trustee shall at all times show that all such investments are part of the Trust;
(2) to employ on behalf of the Trust suitable agents, accountants, actuaries, investment advisers, financial or employee benefits consultants, sub-custodians and depositories, domestic or foreign, counsel, who may be counsel to the Company or the Trustee, and others, to assist it in determining or performing its duties or obligations hereunder, and to pay their reasonable expenses and compensation from the Trust to the extent not paid by the Company, and to confer upon any depository or sub-custodian the powers conferred upon the Trustee by subparagraph (1) of this Section 6(b) as well as the power to appoint subagents and sub-depositories, wherever situated, in connection with the retention of securities or other property;
(3) to extend the time of payment of any obligation held by it;
(4) subject to Section 9(b) and with the consent of the Company:
to compromise, compound, submit to arbitration or settle any claims,
debts, damages or obligations due or owing to or from, or otherwise
adjust all claims in favor of or against, the Trust, except that the
consent of the Company shall not be required in connection with any
claim with respect to which the Trustee is not entitled to be
reimbursed or indemnified for liabilities, damages and expenses under
this Agreement; to commence or defend suits or legal proceedings to
protect any interest of the Trust; and to represent the Trust in all
suits or legal proceedings in any court or before any other body or
tribunal;
(5) to organize under the laws of any state a corporation or trust for the purpose of acquiring and holding title to any property which it is authorized or directed to acquire hereunder and to exercise, or permit the Asset Manager with respect thereto, to exercise any or all of the powers set forth herein;
(6) to hold uninvested any monies received by it, without incurring any liability for the payment of interest thereon, until such monies shall be invested or disbursed; and
(7) to be reimbursed for the expenses incurred in exercising any of the foregoing powers or to pay the reasonable expenses incurred by any agent, manager or trustee appointed pursuant hereto.
(c) All rights associated with the assets of the Trust shall be exercised by the Company, the Trustee, or an Asset Manager, as hereinabove provided, and shall in no event be exercisable by, or rest with, Participants.
(d) The Company reserves the right to transfer to the Trust paid-up life insurance contracts (each a "PLIC") on or for the life of any Participant or to direct, in writing, the Trustee to purchase a PLIC on or for the life of any such Participant out of amounts held in the Trust with respect to one or more Plans. A PLIC shall be an asset of the Trust subject to the claims of the Company's creditors in the event the Company is Insolvent. The proceeds of any PLIC shall, upon the death of the insured Participant or otherwise, upon receipt by the Trustee, be credited to the Equitable Share of the applicable Plan. The Trustee shall have no power to name a beneficiary of the PLIC other than the Trust, to consent to the assignment of the PLIC (as distinct from conversion of the PLIC to a different form upon the written direction of the Company) other than to a successor trustee hereunder, or to loan to any Person (other than the Company) the proceeds of any borrowing against such PLIC. Except as provided in this paragraph (d), the Trustee's sole responsibility with respect to any insurance contract, including a PLIC, to be held under the Trust or purchased with Trust assets shall be as directed owner and custodian thereof and the Company shall be solely responsible for determining the issuer and the terms of any such insurance contract and monitoring the terms of the insurance contract and the issuer thereof to determine and protect the Trust's rights and to instruct the Trustee in the exercise of those rights.
(e) When the Trustee delivers property against payment, delivery of the property and receipt of payment may not be simultaneous. In such case, the risk of non-receipt of payment shall be the Trust's, and the Trustee shall have no liability therefor. All credits to the Trust of the anticipated proceeds of sales and redemption of property arid of anticipated income from property shall be conditional upon receipt by the Trustee of final payment and may be reversed to the extent final payment is not received. At the discretion of the Trustee, the Trust may make use of such conditional credits. To the extent such credits do not become unconditional by receipt of final payment, the Trust shall reimburse the Trustee upon demand for the amount of such conditional credits. When the Trustee is to receive property, it is authorized to accept documents in lieu of such property as long as such documents contain the agreement of the issuer thereof to hold such property subject to the Trustee's sole order. The Trustee may, in its discretion, advance funds to the Trust to facilitate the settlement of any trade. In the event of such an advance, the Trust shall immediately reimburse the Trustee for the amount thereof.
7. Disposition of Income.
During the term of this Trust, all income received by the Trust, net of expenses charged to income and taxes, shall be added to principal and reinvested.
8. Accounting by Trustee.
(a) The Trustee shall maintain records of all investments, receipts, and disbursements under this Trust Agreement, and all accounts, books and records relating thereto shall be open to inspection and audit at all reasonable times during normal business hours by any Person designated by the Company.
(b) Within a reasonable time after the close of each calendar year (or such shorter period as to which the Company and Trustee may agree), or of any termination of the duties
of the Trustee hereunder, the Trustee shall deliver to the Company a written
statement of transactions reflecting its acts and transactions as trustee
hereunder during such calendar year (or such shorter period), or during such
period from the close of the last calendar year or last statement period to the
termination of the Trustee's duties, respectively, including a statement of the
then current value of the Trust. Any such statement shall be deemed an account
stated and accepted and approved by the Company, and the Trustee shall be
relieved and discharged to all Persons with respect to all matters and things
contained in such statement as though such account had been settled and allowed
by a judgment or decree of a court of competent jurisdiction in an action or
proceeding to which the Company and all Persons having any beneficial interest
in the Trust were parties, unless the Company shall have filed with the Trustee
specific written exceptions or objections to any such statement within ninety
(90) days of receipt thereof by the Company.
(c) The Trustee will determine the value of the Trust as of each reporting date under Section 8. Except in the case of an investment in which amortized cost is the valuation method designated, assets will be valued at their market values at the close of business on such date, or, in the absence of readily ascertainable market values, at such values as the Trustee determines in accordance with methods consistently followed and uniformly applied or obtained as provided below. The Company acknowledges and agrees that in the normal course of valuing assets, the Trustee may rely on pricing information provided by recognized pricing services which the Trustee deems to be reliable or provided by the Asset Manager or dealers or sponsors of pooled investment vehicles ("dealers"), and that the Trustee does not verify, warrant or represent the accuracy or completeness of such information, and shall not be liable for any diminution or inflation in the value of any assets as a result of any inaccurate or incomplete information furnished or transmitted by such pricing services or the Asset Managers or dealers. The Trustee may rely for all purposes of this Trust Agreement on the latest valuation information submitted to it even if such information predates the purported valuation date. The Company will provide or cause the Asset Managers to provide the Trustee with all information needed by the Trustee to value such assets and to report and account under this Trust Agreement.
(d) The Trustee shall have the right, at the expense of the Trust, to apply at any time to a court of competent jurisdiction for judicial settlement of any account of the Trustee not previously settled as herein provided or for the determination of any question of construction or for instructions. In any such action or proceeding it shall be necessary to join as parties only the Trustee and the Company (although the Trustee may also join such other Persons as it may deem appropriate), and judgment or decree entered therein shall be conclusive.
9. Indemnification; Liabilities of the Trustee.
(a) (1) The Trustee shall be indemnified and held harmless by the Company from and against any claim, liability, loss, damage or expenses (including, but not limited to, reasonable attorneys' fees and expenses incurred in preparing, investigating or defending any claim) that may be asserted against the Trustee arising out of any action taken or omitted by the Trustee pursuant to this Trust Agreement, except due to the Trustee's own negligence or willful misconduct. Any loss, damage
or expense that is not paid by the Company under this Section or
Section 10 shall be paid from the assets of the Trust and, until so
paid, shall constitute a charge on the Trust and a lien against the
assets of the Trust in favor of the Trustee.
(2) The Company shall be indemnified and held harmless by the Trustee from and against any claim, liability, loss, damage or expenses (including, but not limited to, reasonable attorneys' fees and expenses incurred in preparing, investigating or defending any claim) that may be asserted against the Company arising out of any negligent action or omission by the Trustee hereunder or arising out of its willful misconduct hereunder.
(b) If the Trustee undertakes or defends any litigation, action,
proceeding or appeal arising in connection with this Trust, the Company agrees
to indemnify the Trustee against the Trustee's costs, expenses and liabilities
(including, without limitation, reasonable attorneys' fees and expenses)
relating thereto and to be primarily liable for such payments, and to make
periodic payments in respect of such fees and expenses during the course of any
such proceedings. The Trustee shall not be required to take any action pursuant
to Section 6(b)(4), or pursuant to a direction by the Company pursuant to
Section 11(b), or otherwise, unless it shall have been indemnified by the
Company or the Trust to the Trustee's reasonable satisfaction against any
liabilities and expenses it might incur therefrom. The Trustee shall also be
entitled to reasonable payment from the Trust for allocation of the Trustee's
personnel to the investigation and defense or prosecution thereof, at the
Trustee's normal hourly billing rates. If the Company does not pay such costs,
fees, expenses and liabilities in a reasonably timely manner, the Trustee shall
charge the assets of the Trust to the extent sufficient for any unpaid costs,
fees, expenses and liabilities.
(c) Any charges allocable to the Trust under this Section or
Section 10 shall be allocated pro rata, to and among the Equitable Shares of the
Plans having an interest in the claim, action or proceeding.
(d) Under no circumstances shall the Trustee incur liability in contract, tort or otherwise to any Person for any consequential, special or punitive damages, whether or not foreseeable, with respect to the Trust or its role as Trustee of the Trust.
10. Expenses and Compensation of Trustee.
The Company shall pay to or reimburse the Trustee its reasonable expenses incurred or arising out of the management and administration of the Trust, including, without limitation, advances for or prompt reimbursement of reasonable fees and expenses of counsel and any other Person which provides services contemplated herein or under any Plan, and, in addition, the Company shall pay the Trustee reasonable compensation for the Trustee's services hereunder, the amount of which shall be agreed upon from time to time by the Company and the Trustee in writing; provided, however, that, to the extent that the Company does not timely pay or reimburse any amounts payable or reimbursable by the Company pursuant to this Section 10, such amounts shall be paid or reimbursed from the assets of the Trust and, until so paid or reimbursed, shall be a charge on the Trust and shall constitute a lien on the assets of the Trust in favor of the Trustee. If the Trustee
amends its fee schedules and forwards an amended fee schedule to the Company requesting its agreement thereto and the Company fails to object thereto in writing within ninety (90) days thereafter, the amended fee schedule shall be deemed to be agreed upon by the Company and the Trustee, as of its stated effective date.
11. Taxes.
(a) All income, deductions and credits attributable to the Trust belong to the Company and will be included on the Company's income tax returns. Any and all Federal, state, local or other tax returns required to be filed with respect to the Trust shall be prepared and filed by the Company. The Company shall pay any Federal, state, local or other taxes imposed or levied with respect to the assets and/or income of the Trust or any part thereof under existing or future laws. Upon furnishing the Trustee with evidence reasonably required by the Trustee of any such tax payments made directly by the Company, the Company shall be entitled to receive reimbursement from the assets of the Trust for the full amount of such taxes paid by it. The Trustee shall promptly notify the Company of any notice it receives relating to any taxes imposed or levied with respect to the assets and/or income of the Trust. If the Trustee receives notice that any such taxes are not timely paid by the Company, the Trustee shall pay such taxes from the assets of the Trust to the extent sufficient therefor, prior to any payments to Participants, after notifying the Company as herein provided. As provided in Section 2(b), the Trustee shall deduct any taxes required to be withheld with respect to any payments made to Participants pursuant to the Trust, with any such taxes being paid out of the Trust.
(b) The Company, in its discretion, may undertake, at the sole expense of the Company, to defend any tax claims which are asserted by the Internal Revenue Service against any Participant and which the Company determines would affect Participants generally. In addition, the Company may contest or, subject to Section 9(b), direct the Trustee to contest the validity or amount of any tax, claim, assessment or demand otherwise respecting the Trust or any part thereof, but the Company shall have the sole authority and responsibility to determine whether or not to appeal any determination made by the Internal Revenue Service or by any court. The Company may, but shall not be required to, agree to reimburse directly, or direct the Trustee to reimburse, any Participant for any taxes, interest or penalties in respect of tax claims hereunder which the Company determines would affect Participants generally, upon receipt of documentation of same (but in no event shall the Trust be responsible therefor in, the absence of such direction). Any distributions from the Trust to a Participant under this Section for reimbursements of taxes (but not for reimbursement of interest or penalties) shall reduce the benefits payable to such Participant under the Plan.
12. Resignation and Removal of Trustee; Appointment of Successor.
(a) The Trustee may resign or be removed upon sixty (60) days' prior written notice to or from the Company, as the case may be, at any time.
(b) Such resignation or removal shall be effective upon the earlier of the expiry of the notice period provided herein (unless a shorter period is agreed upon by the parties) and the appointment of a successor trustee.
(c) Upon resignation or removal of the Trustee, the Company shall appoint any natural person or persons or a bank or trust company, or combination thereof, as a successor to replace the Trustee hereunder. Any such successor trustee shall have all the rights, powers and duties granted the Trustee hereunder, including ownership rights in the Trust assets. Such appointment of a successor trustee shall be effected by delivery to the Trustee of (i) a written appointment of such successor trustee, duly executed by the Company and (ii) a written acceptance by such successor trustee, duly executed thereby. The Trustee shall execute any instruments necessary or reasonably requested by the successor trustee to evidence the transfer.
(d) If a successor trustee shall not have been appointed prior to the effective time of the Trustee's resignation, the Trustee may apply to any court of competent jurisdiction for the appointment of a successor trustee or for instructions. All expenses of the Trustee in connection with such proceeding shall be allowed and charged to the Trust as administrative expenses of the Trust.
(e) The Trustee is authorized to reserve such amount as it may deem advisable for payments of its fees and expenses in connection with the settlement of its account or otherwise, and any balance of such reserve remaining after the payment of such fees and expenses shall be paid over to the successor trustee. The Trustee is authorized to invest such reserves in any investment authorized under the terms of this Trust Agreement appropriate for the temporary investment of cash reserves of trusts. After the acceptance and approval of its account and the payment of its expenses, the Trustee shall transfer and deliver the balance of the Trust to such successor, and the Trustee shall have no further responsibilities to any Person under this Trust Agreement.
13. Amendment or Termination.
(a) This Trust Agreement (including any Appendices or Schedules) may be amended, in whole or in part, at any time and from time to time, by the Company. Notwithstanding the foregoing, (i) the Company shall ensure that no such amendment conflicts with the terms of the Plan or shall make the Trust revocable, and (ii) no amendment (including the deletion or addition of a Plan on Appendix A) which affects the rights, duties or responsibilities of the Trustee may be made without the Trustee's prior written consent.
(b) Any limitations contained in Section 13(a) shall not apply with respect to any amendment which is reasonably necessary, in the opinion of counsel to the Company and reasonably acceptable to the Trustee, to preserve the status of the Trust as a grantor trust and the status of the Plan as unfunded for Federal income tax purposes and for purposes of ERISA.
(c) The Trust shall not terminate until the date on which
Participants are no longer entitled to benefits pursuant to the terms of the
Plan; provided, however, the Trust shall terminate prior to such date if and
when all of the assets of the Trust are consumed in satisfaction of the claims
of the general creditors of the Company pursuant to Section 3. Upon satisfaction
of all liabilities under the Plans with respect to all Participants, the
Company, pursuant to a resolution of its Board of Directors, may terminate the
Trust by delivery to the Trustee of (i) a certified copy of such resolution,
(ii) a certification of the Plans' enrolled actuary confirming that all
liabilities under the Plans have been satisfied, and (iii) a written instrument
of termination duly executed and acknowledged in the same form as this Trust
Agreement.
(d) Upon termination of the Trust in accordance with this
Section 13, the Trustee shall, after acceptance and approval of its account, at
the direction of the Company, return any assets remaining in the Trust to the
Company. Upon completing such distribution, the Trustee shall be relieved and
discharged of any responsibilities under this Trust Agreement. The powers of the
Trustee under this Section and Section 12 shall continue as long as any assets
of the Trust remain in its possession.
14. Authorities.
(a) After the execution of this Trust Agreement, the Company or any successor thereto shall promptly file with the Trustee a certified list of the names and specimen signatures of the officers of the Company and any Persons authorized to act for the Company or any successor thereto. The Company shall cause each Investment Manager to file with the Trustee a certified list of the names and specimen signatures of those individuals authorized to direct the Trustee on its behalf. The Trustee shall be fully protected in acting upon any certifications, instructions, notices, directions, requests or approvals and other communications ("Instructions"), howsoever transmitted, received by the Trustee and purporting to be from any such Persons which the Trustee reasonably believed to be from such a Person, each such Instruction constituting a certification by the Person so giving that such Instruction is in conformity with the terms of the Plan, the Trust and/or other related documents, and the Trustee shall be fully protected in omitting to act in the absence of Instructions.
(b) Any agreement or understanding between the Company and any Person (including an Investment Manager) or any other provision of this Trust Agreement to the contrary notwithstanding, all Instructions to the Trustee shall be in writing or in such other form including transmission by electronic means through the facilities of third parties or otherwise, agreed to by the Trustee. The Trustee shall be fully protected in acting in accordance therewith, but shall not thereby assume responsibility for any errors or inaccuracies contained in the Instructions to the Trustee or for any delays or failures in such transmission facilities caused by the failure, breakdown or unavailability of any such means of communication or equipment not due to the Trustee's own negligence or willful misconduct.
(c) The Trustee shall have the right to assume, in the absence of notice in writing to the contrary, that no event constituting a change in, or terminating, the authority of any Person, including any Asset Manager, has occurred.
(d) The Trustee shall incur no liability under this Trust Agreement for any failure to act pursuant to any Instruction from any Asset Manager, the Company or any other Person or the designee of any of them unless and until it shall have been received in the form acceptable to the Trustee.
15 Miscellaneous.
(a) Any provision of this Trust Agreement prohibited by law shall be ineffective to the extent of any such prohibition, without invalidating the remaining provisions hereof.
(b) Except as required by law, benefits payable to Participants under this Trust Agreement may not be anticipated, assigned (either at law or in equity), alienated, pledged, encumbered or subjected to attachment, garnishment, levy, execution or other legal or equitable process by creditors of Participants.
(c) This Trust Agreement shall be construed and interpreted under, and the Trust hereby created shall be governed by, the laws of the State of Illinois, insofar as such laws do not contravene any applicable Federal laws, rule or regulations. Section 9 of this Trust Agreement shall be construed as a contract between the Company and the Trustee according to the laws of the State of Illinois in effect from time to time. Nothing in this Trust Agreement shall be construed to subject the Trust created hereunder to ERISA or to cause it to be treated as other than a grantor trust.
(d) This Trust Agreement shall be binding upon and inure to the benefit of any successor(s) or assign(s) of the Company or the Trustee, or any of its businesses, in whole or in part, as the result of merger, consolidation, reorganization, transfer of assets or otherwise, and any subsequent successor thereto. In the event of any such merger, consolidation, reorganization, transfer of assets or other similar transaction, the successor to the Company or the Trustee or its business or relevant part thereof or any subsequent successor thereto shall promptly notify the other party hereto in writing of its successorship and furnish it with the information specified in Section 14.
(e) The undertakings and obligations of the Company, and the entitlements of the Trustee, under Sections 9 and 10 of this Trust Agreement shall survive the termination, amendment or restatement of this Trust Agreement, or the resignation or removal of the Trustee.
(f) Until notice be given in writing to the contrary, all instructions, notices and other communications shall be delivered or sent:
If to the Trustee to: Harris Trust and Savings Bank 111 West Monroe Street Sixth Floor West Chicago, Illinois 60603 Attention: Mark J. Kovel Tel.: (312) 461-7524 Fax: (312) 765-8080
If to the Company to: Cabot Oil & Gas Corporation 1200 Enclave Parkway Houston, Texas 77077 Attention: Human Resources Tel.: (281) 589-4600 Fax.: (281) 589-4910
(g) Notwithstanding any powers granted to the Trustee or any other Person pursuant to this Trust Agreement or by applicable law, no Person shall have any power that could give this Trust the objective of carrying on a business and dividing the gains therefrom, within the meaning of Section 301.7701-2 of the Procedure and Administrative Regulations promulgated pursuant to the Code.
(h) The Company shall, at any time and from time to time, upon the reasonable request of the Trustee, execute and deliver such further instruments and do such further acts as may be necessary or proper to effectuate the purpose of this Trust Agreement.
(i) Neither the gender nor the number (singular or plural) of any word shall be construed to exclude another gender or number when a different gender or number would be appropriate.
(j) The words "paragraph" and "Section" shall be to provisions of this Trust Agreement and the titles to Sections of this Trust Agreement are for convenience of reference only, and this Trust Agreement is not to be construed by reference thereto.
(k) This Trust Agreement may be executed in any number of counterparts, each of which shall be deemed to be an original, but all of which shall together constitute only one agreement.
(l) The Trustee's obligations are limited to those set out in this Trust Agreement. No additional duties or obligations shall be imposed on the Trustee or implied from the terms of this Trust Agreement. In case of any conflict or inconsistency between the terms of this Trust Agreement and any Plan, in determining the obligations and responsibilities of the Trustee, the terms of this Trust Agreement shall control.
(m) The Company hereby irrevocably and unconditionally agrees for itself and for any Participants (or their beneficiaries) that all claims, actions, suits or proceedings against,
or involving, the Trust, this Agreement or the Trustee shall exclusively be brought in the Court of the State of Illinois sitting in Cook County or in the Federal District Court for the Northern District of Illinois, and it further agrees that all such claims, actions, suits or proceedings shall be heard and determined by such courts. Nothing in this Agreement shall affect any right that the Trustee may have to bring any claim, action, suit or proceeding relating to this Agreement or the Trust against the Company or any other person in the courts of any other jurisdiction.
16 Definitions.
When used herein, the following terms shall have the following meanings:
(1) "Asset Manager" shall mean, individually or collectively as the context shall require, the Trustee, with respect to those assets of the Trust allocated to the Discretionary Fund, or an Investment Manager or the Company with respect to those assets of the Trust allocated to a Directed Fund to the extent each is authorized to exercise, discretionary investment authority or control over such assets under Section 5(a).
(2) "Chief Executive Officer" shall mean the highest ranking officer of the Company at the relevant time.
(3) "Code" shall mean the Internal Revenue Code of 1986, as amended, and the regulations promulgated and rulings issued thereunder.
(4) "Directed Fund" shall mean each portion of the Trust subject to the discretionary management and control of an Asset Manager other than the Trustee. If more than one Directed Fund is established under this Trust Agreement, "Directed Fund" shall also mean the Directed Fund subject to the management and control of a particular Asset Manager, as the context may require.
(5) "Discretionary Fund" shall mean any portion of the Trust subject to the discretionary management and control of the Trustee pursuant to a separate written asset management agreement between the Company and the Trustee.
(6) "Equitable Share" shall mean the interest of any Plan in the Trust or, if the context shall require, an Investment Fund.
(7) "ERISA" shall mean the Employee Retirement Income Security Act of 1974, as amended, and the regulations promulgated and rulings issued thereunder.
(8) "Insolvent" shall mean (i) the Company is generally not paying its debts as such debts become due unless such debts are the subject of a bona fide dispute, or (ii) the Company is subject to a pending proceeding as a debtor under the United States Bankruptcy Code, Title 11 of the United States Code, or other
proceedings intended to liquidate or rehabilitate the Company's estate, or (iii) the Company is subject to regulation by Federal or state regulators and such regulators have determined that the Company is insolvent or should be placed in Insolvency or similar proceedings.
(9) "Investment Fund" shall mean an account allocated to an Asset Manager for investment in which one or more Plans may have an interest.
(10) "Investment Manager" shall mean (i) an investment adviser registered under the Investment Advisers Act of 1940, (ii) an investment adviser which is not registered as an investment adviser under such Act by reason of paragraph (1) of section 203A(a) of such Act but is registered as an investment adviser under the laws of the state in which it maintains its principal office and place of business, and, at the time such adviser last filed the registration form most recently filed by it with such State in order to maintain the its registration under the laws of such State, also filed a copy of such form with the United States Secretary of Labor; (iii) a bank as defined in that Act, or (iv) an insurance company qualified to manage, acquire or dispose of any assets of the trusts under the laws of one or more State.
(11) "Participant" shall mean an active or former employee or director of the Company who is a participant under a Plan, and any beneficiary of such an employee or director.
(12) "Payment Schedule" means the document delivered to the Trustee by the Company or Recordkeeper showing the amounts payable in accordance with the terms of the Plan in respect of each Participant, the manner in which such amounts are to be paid (as provided for or available under the Plan), the time of commencement for payment of such amounts, the addresses or depositary to which such payments are to be sent, and the Plan, and if relevant, the Investment Fund(s), to be charged.
(13) "Person" shall mean a natural person, trust,.estate, corporation of any kind or purpose, mutual company, joint-stock company, unincorporated organization, association, partnership, joint venture, employee organization, committee, board, Participant, trustee, partner, or venturer acting in an individual, fiduciary or representative capacity, as the context may require.
(14) "Recordkeeper" shall mean the Company, or, if different, the Person (other than the Trustee) appointed by the Company to discharge the Company's obligations under Section 2.
(15) "Securities Act" shall mean the Securities Act of 1933, as amended.
(16) "writing" or "written" shall mean a manually signed instrument or electronic transmission through a facility approved by the Trustee.
17 Effective Date.
The effective date of this Trust Agreement shall be the date of its execution set forth on page 1 of this Trust Agreement, or, if later, the date of its adoption by a Plan added to Appendix A after such date.
18 Establishment of Trust by Affiliates.
(a) Any affiliate or subsidiary of the Company (an "Affiliate" and "Parent", respectively) that is obligated to provide benefits to Participants under one or more non-qualified deferred compensation or supplemental retirement Plans may, with the consent of the Parent and the Trustee, by execution of an adoption agreement substantially in the form of Appendix B, elect to establish a trust (the "Affiliate Trust"), which shall be a separate trust subject to all of the terms and conditions of this Trust Agreement (including the provisions of this Section 18) to the same extent and effect as if it had been separately negotiated between the Trustee and such Affiliate (the "Affiliate Trust Agreement"), pursuant to which (and except as herein provided) such Affiliate shall be "the Company" and Grantor thereof for all purposes of such Affiliate Trust Agreement (including, without limitation, the provisions of paragraphs (c) and (d) of Section 1 and Section 3, which provisions shall be construed to apply separately to the Parent and each Affiliate.
(b) The Affiliate-Grantor appoints Parent, including its
designees under Section 14, as its agent for all purposes of the Affiliate Trust
Agreement to receive notices, reports or other communications hereunder, to give
Confirmations under Section 3, or, where action is required to or may be taken
by or on behalf of the "Company" to take or refrain from taking such acts, and
Affiliate shall be bound by the decisions, Instructions and actions of the
Parent under or affecting the Affiliate Trust Agreement, and the Trustee shall
be fully protected by the Parent and the Affiliate-Grantor under Section 9 and
Section 15(e) in relying upon the decisions, instructions, actions, and
directions of the Parent; provided, however, in no event shall Parent use the
power and authority granted it hereunder to direct the Trustee to pay over any
assets of the Trust to the Parent under Section 4 or Section 13, or creditors of
Parent under Section 3.
(c) The Trustee shall not be required to give notice to or to obtain the consent of the Affiliate-Grantor with respect to any action to be taken by the Trustee on or pursuant to the actions of the Parent pursuant to the Affiliate Trust Agreement, and the Parent shall have the sole authority to enforce the Affiliate Trust Agreement on behalf of any Affiliate.
IN WITNESS WHEREOF, the parties hereto have caused this Trust Agreement to be duly executed as of the day and year first above written.
Attest: CABOT OIL & GAS CORPORATION
By: _______________________ By: __________________________
Name: Name:
Title: Title:
Attest: HARRIS TRUST AND SAVINGS BANK
By: _______________________ By: __________________________
Name: Name:
|
Title: Title:
STATE OF ILLINOIS )
) ss.:
COUNTY OF COOK )
|
On the ____ day of ____________, 2000, before me personally came
_________________ to me known, who being by me duly sworn, did depose and say:
that he/she resides in ____________________________; that he/she is the
_____________________________ of HARRIS TRUST AND SAVINGS BANK, the
corporation described in and which executed the above instrument; that he/she
knows the seal of said corporation; that the seal affixed to said instrument
is such corporate seal; that it was so affixed by order of the Board of
Directors of said corporation, and that he/she signed his/her name thereto by
like order.
Notary Public
STATE OF TEXAS )
) ss.:
COUNTY OF HARRIS )
|
On the _____ day of ____________, 2000, before me personally came
_______________, to me known, who being by me duly sworn, did depose and say:
that he/she resides in Houston, Texas; that he/she is the _______________ of
Cabot Oil & Gas Corporation, the corporation described in and which executed the
above instrument; that he/she knows the seal of said corporation; that the seal
affixed to said instrument is such corporate seal; that it was so affixed by
order of the Board of Directors of said corporation, and that he/she signed
his/her name thereto by like order.
Notary Public
The following Company plan is subject to this Trust:
The Cabot Oil & Gas Corporation Deferred Compensation Plan, effective as of June 1, 1998
The undersigned __________________________ (the "Affiliate"), a _____________ of _____________________ (the "Parent"), has adopted, and/or incurred, or expects to incur, liability under, one or more nonqualified deferred compensation plans listed in Appendix A to that certain Trust Agreement (the "Trust Agreement"), made as of ________________ ___, 20___, by and between the Parent and Harris Trust and Savings Bank (the "Trustee"). The Affiliate hereby adopts the Trust Agreement for the uses and purposes set forth in the Trust Agreement, which, for purposes hereof, shall be construed as applying separately to the Affiliate as if the Affiliate were the "Company", therein, except as otherwise provided herein or in Section 18 of the Trust Agreement. As so adopted by the Affiliate, the Trust Agreement shall be known as the "Affiliate Trust Agreement," and the Affiliate shall be the Grantor of the separate trust established by the Affiliate Trust Agreement.
The Affiliate agrees and confirms that it shall be subject to all of the terms and conditions of the Trust Agreement, as heretofore or hereafter amended. The Affiliate further agrees and confirms that: (a) it will be bound by the decisions, instructions, actions and directions of the Parent under or affecting the Affiliate Trust Agreement and the Affiliate as provided in Section 18 of the Trust Agreement, and the Trustee shall be fully protected by the Affiliate in relying upon the decisions, instructions, actions, and directions of the Parent; (b) the Trustee shall not be required to give notice to or to obtain the consent of the Affiliate with respect to any action taken or to be taken by the Trustee on or to the instructions of the Parent or otherwise pursuant or with respect to the Affiliate Trust Agreement; and (c) the Parent shall have the sole authority to enforce the Affiliate Trust Agreement on behalf of the Affiliate.
IN WITNESS WHEREOF, the Affiliate has caused this Adoption Agreement to be duly executed as of this ____ day of __________________________, 2000.
AFFILIATE Attest:
By: _____________________________ By: ________________________________
Name: Name:
|
Title: Title:
Accepted and agreed:
PARENT
By: _____________________________ Date: ______________________________
Name:
Title:
HARRIS TRUST AND SAVINGS BANK
By: _____________________________ Date: _____________________________
Name:
Title:
STATE OF ILLINOIS )
) ss. :
COUNTY OF COOK )
|
On the ____ day of _______________________, 2000, before me personally came _____________________________________ to me known, who being by me duly sworn, did depose and say: that he/she resides in______________________________; that he/she is the _____________________________ of HARRIS TRUST AND SAVINGS BANK, the corporation described in and which executed the above instrument; that he/she knows the seal of said corporation; that the seal affixed to said instrument is such corporate seal; that it was so affixed by order of the Board of Directors of said corporation, and that he/she signed his/her name thereto by like order.
Notary Public
STATE OF TEXAS )
) ss. :
COUNTY OF HARRIS )
|
On the ____ day of ________________________, 2000, before me personally came __________________________________ to me known, who being by me duly sworn, did depose and say: that he/she resides in ___________________________________; that he/she is the _______________________________ of the ____________________________, the corporation described in and which executed the above instrument; that he/she knows the seal of said corporation; that the seal affixed to said instrument is such corporate seal; that it was so affixed by order of the Board of Directors of said corporation, and that he/she signed his/her name thereto by like order.
Notary Public
STATE OF )
) ss. :
COUNTY OF )
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On the ____day of __________________________, 2000, before me personally came_______________________________ to me known, who being by me duly sworn, did depose and say: that he/she resides in ___________________________; that he/she is the ____________ of the ___________________________, the corporation described in and which executed the above instrument; that he/she knows the seal of said corporation; that the seal affixed to said instrument is such corporate seal; that it was so affixed by order of the Board of Directors of said corporation, and that he/she signed his/her name thereto by like order.
Notary Public
Exhibit 10.25
August 29, 2001
Mr. Dan O. Dinges
6606 Centre Place Circle
Spring, Texas 77379
Dear Dan:
The following reflects your revised compensation package with respect to your joining Cabot Oil & Gas Corporation (the "Company") and replaces the offer letter to you dated July 19, 2001:
. Effective upon the date you report to work, the Board of Directors of the Company has appointed you a member of the Board of Directors and elected you to the office of President and Chief Operating Officer of the Company. You will report to work at the Company on or before September 17, 200l or on a later mutually agreed to date.
. Commencing on the date you report to work at the Company, you will receive a base salary at the annual rate of $350,000. This salary will be subject to an annual review, normally completed in February each year, for possible increase.
. On the date you report to work at the Company, you will receive a sign-on bonus of $150,000.
. You will be a participant in the annual bonus program, the Annual Target Cash Incentive Plan. Your annual target will be 60% of your base salary. Actual award level is determined by Company performance, as defined by the terms of the Plan and objectives defined for annual performance. For 2001, your award will be prorated to reflect your employment for less than the entire year.
. The term of this agreement will extend until your 65/th/ birthday. If your employment is terminated by the Company for any reason other than Cause or disability, or if you terminate your employment for Good Reason, you shall receive: (i) a lump sum cash payment equal to two times your annual base salary plus two times your annual target bonus, (ii) continuation of applicable
Letter to Mr. Dan O. Dinges August 29, 2001
medical and life insurance programs for 24 months following termination at the premium rate applicable to active executives, (iii) full vesting of all of your restricted stock awards from the Company and (iv) full vesting of all your stock option awards from the Company. The stock options will continue to be exercisable until the earlier of (a) the third anniversary of the date of your termination or (b) the date on which the stock option would have expired had you remained an employee. The 24-month continuation of medical coverage shall be in addition to any coverage period available to you under COBRA.
- For purposes hereof, the term Cause means (i) a dishonest or other act of material misconduct that results in your substantial personal enrichment, results in a substantial economic loss to the Company, or is otherwise materially contrary to the best interest of the Company, or (ii) willful repeated refusals by you to substantially perform the duties of your position.
- For purposes hereof, the term Good Reason means the Company's assignment to you of any duties materially inconsistent with your position, or any other act by the Company that results in a diminution in your position, authority, duties or responsibilities, or any reduction in your base salary, bonus or long-term incentive opportunity, or any reduction in other benefits or perquisites (other than a reduction in those benefits or perquisites applicable to executive officers of the Company generally).
. On the date you report to work at the Company, you will be granted an option to purchase 75,000 shares of Company common stock at an exercise price of the average of the high and low trading prices on that date. The option will become exercisable with respect to 25,000 of the shares on the first anniversary of the award, 25,000 of the shares on the second anniversary of the award, and 25,000 of the shares on the third anniversary of the award. The term of the option is five years, in accordance with the Company's customary stock option agreement.
. On the date you report to work at the Company, you will be granted 25,000 restricted shares of Company common stock. All 25,000 shares shall vest on the third anniversary of the award, in accordance with the Company's customary restricted stock award agreement.
. You will next be eligible for a long-term incentive award as part of the normal annual award cycle defined for members of the executive group, which normally occurs in May of each year.
Letter to Mr. Dan O. Dinges August 29, 2001
. You will be entitled to four weeks of vacation per year, and you will be entitled to participate in all benefit and perquisite programs offered by the Company to executive officers, including the Company's disability program, according to the terms of the plans as in effect from time to time.
. The Company will pay the initiation fee for a Northgate Country Club membership and for one dining/luncheon club membership. These memberships shall be Company memberships. Ownership of the country club membership shall transfer to you, with the Company paying all expenses associated with the transfer, after completion of seven years of employment. The Company will pay the monthly dues for both of these clubs during your employment.
. You will immediately be a participant in the Company's Change in Control Program, subject to your execution of the relevant Change in Control Agreement. In the event of a change in control of the Company, you will be required to elect between the benefits provided under this agreement and the benefits provided under the Change in Control Agreement.
. The Company will provide to you term life insurance coverage equal to three times your annual salary, up to a policy maximum of $1 million, under its standard program for executives as in effect from time to time.
. You will be entitled to participate in the Company's pension plan and supplemental plan in accordance with the terms of the relevant plan as in effect from time to time. The supplemental plan is designed to restore benefits lost under the pension plan as a result of provisions of the Internal Revenue Code of 1986, as amended, and the Employment Retirement Income Security Act of 1974, as amended.
. You agree to abide by all Company policies, including execution of the Company's standard form of confidentiality agreement and passing a drug test (as have all current employees). You represent to the Company that you are not prohibited from entering into this agreement by any other agreement.
. The Company shall pay all of the fees, costs and expenses (including reasonable attorneys' fees) that you incur in order to enforce your rights under this agreement. This provision shall only apply if you receive a judgement in your favor, as a result of your enforcement action.
. No provision of this agreement may be amended unless such amendment is agreed to in writing and signed by you and an authorized officer of the Company.
. This agreement may not be assigned or transferred by the Company without your prior written consent.
Letter to Mr. Dan O. Dinges August 29, 2001
. This offer of employment shall remain open for your acceptance until 5:00
p.m. (Central) on September 17, 2001. If you fail to execute and return
this offer by the deadline, it shall be deemed revoked.
If you are in agreement with the terms and conditions contained in this letter, please sign one copy in the space provided below and return to the undersigned.
Very truly yours,
/s/ Ray R. Seegmiller Ray R. Seegmiller |
Accepted and agreed to by:
/s/ Dan O. Dinges Dan O. Dinges Date: September 17, 200l |
Exhibit 21.1
SUBSIDIARIES OF CABOT OIL & GAS CORPORATION
Big Sandy Gas Company
Cabot Oil & Gas Marketing Corporation *
Cabot Oil & Gas U.K. Limited
Cabot Petroleum North Sea, Ltd.
Cody Company
Cody Energy LLC
Cody Oil & Gas, Inc.
Cody Texas, LP
Cranberry Pipeline Corporation *
Franklin Brine Treatment Corporation
* Denotes significant subsidiary.
EXHIBIT 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (File Nos. 333-68350 and 333-83819) and Form S-8 (File Nos. 333-37632, 33-53723, 33-35476, 33-35478, 33-71134, 33-53723, and 333-83819) of Cabot Oil & Gas Corporation of our report dated February 15, 2002 relating to the consolidated financial statements, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Houston, Texas
February 22, 2002
EXHIBIT 23.2
February 19, 2002
Cabot Oil & Gas Corporation
1200 Enclave Parkway
Houston, TX 77077-1607
Re: Securities and Exchange Commission Form 10-K of Cabot Oil & Gas Corporation
Gentlemen:
The firm of Miller and Lents, Ltd. consents to the use of its name and to the use of its report dated February 8, 2002 regarding the Cabot Oil & Gas Corporation Proved Reserves and Future Net Revenues as of December 31, 2001, which report is to be included by reference in Form 10-K to be filed by Cabot Oil & Gas Corporation with the Securities and Exchange Commission.
Miller and Lents, Ltd. has no financial interest in Cabot Oil & Gas Corporation or in any of its affiliated companies or subsidiaries and is not to receive any such interest as payment for such report. Miller and Lents, Ltd. also has no director, officer, or employee employed or otherwise connected with Cabot Oil & Gas Corporation. We are not employed by Cabot Oil & Gas Corporation on a contingent basis.
Very truly yours,
MILLER AND LENTS, LTD.
By /s/ James A. Cole ---------------------------- James A. Cole Senior Vice President |
JAC/mk
Exhibit 28.1
February 8, 2002
Cabot Oil & Gas Corporation
1200 Enclave Parkway
Houston, TX 77077-1607
Re: Reserves and Future Net Revenues As of December 31, 2001 SEC Price Case
Gentlemen:
At your request, we reviewed the estimates of proved reserves of oil, natural gas liquids, and gas and the future net revenues associated with these reserves that Cabot Oil & Gas Corporation, hereinafter Cabot, attributes to its net interests in oil and gas properties as of December 31, 2001. Cabot's estimates, shown below, are in accordance with the definitions contained in Securities and Exchange Commission Regulation S-X, Rule 4-10(a) as shown in the Appendix.
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Net Reserves Future Net Revenues
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Reserve Category Liquids, Gas, Undiscounted, Discounted at
MBbls. MMcf M$ 10% Per Year,
M$
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Proved Developed 15,328 804,647 1,663,332 835,245
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Proved Undeveloped 4,357 231,358 353,516 115,855
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Total Proved 19,685 1,036,005 2,016,848 951,100
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We made independent estimates for all the proved reserves estimated by Cabot. Based on our investigations and subject to the limitations described hereinafter, it is our judgment that (1) Cabot has an effective system for gathering data and documenting information required to estimate its proved reserves and to project its future net revenues, (2) in making its estimates and projections, Cabot used appropriate engineering, geologic, and evaluation principles and techniques that are in accordance with practices generally accepted in the petroleum industry, and (3) the results of those estimates and projections are, in the aggregate, reasonable.
Cabot Oil & Gas Corporation February 8, 2002
All reserves discussed herein are located within the continental United States and Canada. Gas volumes were estimated at the appropriate pressure base and temperature base that are established for each well or field by the applicable sales contract or regulatory body. Total gas reserves were obtained by summing the reserves for all the individual properties and are therefore stated herein at a mixed pressure base.
Cabot represents that the future net revenues reported herein were computed based on prices for oil, natural gas liquids, and gas as of Cabot's fiscal year end, December 31, 2001, and are in accordance with Securities and Exchange Commission guidelines. The present value of future net revenues was computed by discounting the future net revenues at 10 per cent per annum. Estimates of future net revenues and the present value of future net revenues are not intended and should not be interpreted to represent fair market values for the estimated reserves.
In conducting our investigations, we reviewed the pertinent available engineering, geological, and accounting information for each well or designated property to satisfy ourselves that Cabot's estimates of reserves and future production forecasts and economic projections are, in the aggregate, reasonable. We independently selected a sampling of properties in each region and reviewed the direct operating expenses and product prices used in the economic projections.
In its estimates of proved reserves and future net revenues associated with its proved reserves, Cabot has considered that a portion of its facilities associated with the movement of its gas in the Appalachian Region to its markets are unusual in that the construction and operation of these facilities are highly dependent on its producing operations. Cabot has deemed the portion of the cost of these facilities associated with its revenue interest gas as costs that are attributable to its oil and gas producing activities, and accordingly, has included these costs in its computation of the future net revenues associated with its proved reserves.
Reserve estimates were based on decline curve extrapolations, material balance calculations, volumetric calculations, analogies, or combinations of these methods for each well, reservoir, or field. Reserve estimates from volumetric calculations and from analogies are often less certain than reserve estimates based on well performance obtained over a period during which a substantial portion of the reserves were produced.
In making its projections, Cabot estimated yearly well abandonment costs except where salvage values were assumed to offset these expenses. Costs for any possible future environmental claims were not included. Cabot's estimates include no adjustments for production prepayments, exchange agreements, gas balancing, or similar arrangements. We were provided with no information concerning these conditions, and we have made no investigations of these matters as such was beyond the scope of this investigation.
The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our informed judgments based on accepted standards of professional investigation but are subject to those generally recognized uncertainties associated with interpretation of geological, geophysical, and engineering information. Government policies and market conditions different from those employed in this study may cause the total quantity of oil, natural gas liquids, or gas to be recovered, actual production rates, prices received, or operating and capital costs to vary from those presented in this report.
In conducting these evaluations, we relied upon production histories, accounting and cost data, and other financial, operating, engineering, and geological data supplied by Cabot. To a lesser extent, nonproprietary data existing in the files of Miller and Lents, Ltd., and data obtained from commercial services were used. We also relied, without independent verification, upon Cabot's representation of its ownership
Cabot Oil & Gas Corporation February 8, 2002
interests, payout balances and reversionary interests, the current prices, and the transportation fees applicable to each property.
Miller and Lents, Ltd. is an independent oil and gas consulting firm. None of the principals of this firm have any financial interests in Cabot or in any of its affiliated companies. Our fee is not contingent upon the results of our work or report, and we have not performed other services for Cabot that would affect our objectivity.
Very truly yours,
MILLER AND LENTS, LTD.
By_______________________________
James A. Cole
Senior Vice President
JAC/mk