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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Fiscal year ended DECEMBER 31, 1996
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)
15375 MEMORIAL DRIVE, HOUSTON, TEXAS 77079
(Address of principal executive offices including Zip Code)
(281) 589-4600
(Registrant's telephone number)
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
CLASS A COMMON STOCK, PAR VALUE $.10 PER SHARE NEW YORK STOCK EXCHANGE
RIGHTS TO PURCHASE PREFERRED STOCK NEW YORK STOCK EXCHANGE
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K [__].
The aggregate market value of Class A Common Stock, par value $.10 per
share ("Common Stock"), held by non-affiliates (based upon the closing sales
price on the New York Stock Exchange on February 28, 1997), was approximately
$345,000,000.
As of February 28, 1997, there were 22,857,294 shares of Common Stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Stockholders to
be held May 6, 1997 are incorporated herein by reference in Items 10, 11, 12,
and 13 of Part III of this report.
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TABLE OF CONTENTS
PART I PAGE
ITEMS 1 AND 2 Business and Properties 2
ITEM 3 Legal Proceedings 15
ITEM 4 Submission of Matters to a Vote of Security Holders 16
Executive Officers of the Registrant 16
PART II
ITEM 5 Market for Registrant's Common Equity and Related
Stockholder Matters 16
ITEM 6 Selected Historical Financial Data 17
ITEM 7 Management's Discussion and Analysis of Financial
Condition and Results of Operations 18
ITEM 8 Financial Statements and Supplementary Data 27
ITEM 9 Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 53
PART III
ITEM 10 Directors and Executive Officers of the Registrant 53
ITEM 11 Executive Compensation 53
ITEM 12 Security Ownership of Certain Beneficial Owners and
Management 53
ITEM 13 Certain Relationships and Related Transactions 53
PART IV
ITEM 14 Exhibits, Financial Statement Schedules and Reports
on Form 8-K 54
------------------------
The statements regarding future financial performance and results and the
other statements which are not historical facts contained in this report are
forward-looking statements. The words "expect," "project," "estimate,"
"predict" and similar expressions are also intended to identify forward-looking
statements. Such statements involve risks and uncertainties, including, but not
limited to, market factors, market prices (including regional basis
differentials) of natural gas and oil, results for future drilling and
marketing activity, future production and costs and other factors detailed
herein and in the Company's 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.
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PART I
ITEM 1. BUSINESS
GENERAL
Cabot Oil & Gas Corporation (the "Company") explores for, develops,
produces, stores, transports, purchases and markets natural gas and, to a
lesser extent, produces and sells crude oil. Substantially all of the Company's
operations are in the Appalachian Region of West Virginia and Pennsylvania in
the Western Region, including the Anadarko Basin of southwestern Kansas,
Oklahoma and the Texas Panhandle, the Green River Basin of Wyoming, and South
Texas. At December 31, 1996, the Company had approximately 946.6 Bcfe of total
proved reserves, 97% of which was natural gas. A significant portion of the
Company's natural gas reserves is located in long-lived fields with extended
production histories.
The Company, a Delaware corporation, was organized in 1989 as the
successor to the oil and gas business of Cabot Corporation ("Cabot"), which was
begun in 1891. In 1990, the Company completed its initial public offering of
approximately 18% of the outstanding common stock held by Cabot. Cabot
distributed the remaining common stock of the Company to the shareholders of
Cabot in 1991. The Company has been publicly traded on the New York Stock
Exchange since its initial public offering.
Unless the context otherwise requires, all references herein to the
Company include Cabot Oil & Gas Corporation, its predecessors and subsidiaries.
Similarly, all references to Cabot include Cabot Corporation and its
affiliates. All references to wells are gross, unless otherwise stated.
The following table summarizes certain information, at December 31, 1996
regarding the Company's proved reserves, productive wells, developed and
undeveloped acreage and infrastructure.
SUMMARY OF RESERVES, PRODUCTION, ACREAGE AND OTHER INFORMATION BY
AREAS OF OPERATION(1)(2)
Total Appalachian Western
Company Region Region(2)
- ----------------------------------------------------------------------------
RESERVES/PRODUCTION:
Proved reserves
Developed (Bcfe) 796.2 436.6 359.6
Undeveloped (Bcfe) 150.4 92.3 58.1
--------- --------- -------
Total (Bcfe) 946.6 528.9 417.7
========= ========= =======
Daily production (Mmcfe) net 170.3 73.5 96.8
Gross productive wells 5,109 3,858 1,251
Net productive wells 4,258.0 3,578.8 679.1
Percent of wells operated 88.2% 97.0% 60.8%
ACREAGE:
Net acreage
Developed acreage 992,151 755,269 236,882
Undeveloped acreage 416,753 258,733 158,020
--------- --------- -------
Total 1,408,904 1,014,002 394,902
========= ========= =======
- ----------
(1) As of December 31, 1996. For additional information regarding the
Company's estimates of proved reserves and other data, see
"Business--Reserves," and the "Supplemental Oil and Gas Information" to
the Consolidated Financial Statements.
(2) Includes all properties outside the Appalachian Region, including
properties located in Anadarko, the Rocky Mountains and the Gulf Coast
areas.
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EXPLORATION, DEVELOPMENT AND PRODUCTION
The Company is one of the largest producers of natural gas in the
Appalachian basin, where it has conducted operations for more than a century.
The Company has had operations in the Anadarko basin for over 60 years. The
Company acquired its operations in the Rocky Mountains and the Gulf Coast
pursuant to the merger of Washington Energy Resources Company with the Company
which was completed in May 1994. Historically, the Company has maintained its
reserve base through low-risk development drilling and strategic acquisitions.
The Company continues to focus its operations in the Appalachian and Western
Regions through development of undeveloped reserves and acreage, acquisition of
oil and gas producing properties and, to a lesser extent, exploration.
APPALACHIAN REGION
The Company's exploration, development and production activities in the
Appalachian Region are concentrated in Pennsylvania, Ohio, West Virginia, and
Virginia. Operations are managed by a regional office in Pittsburgh. At
December 31, 1996, the Company had approximately 529 Bcfe of proved reserves
(substantially all natural gas) in the Appalachian Region, constituting 56% of
the Company's total proved reserves.
The Company has 3,858 productive wells (3,578.8 net), of which 3,744
wells are operated by the Company. There are multiple producing intervals which
include the Medina, Berea, and Big Lime trend formations at depths primarily
ranging from 1,500 to 6,000 feet. Average net daily production in 1996 was 73.5
Mmcfe. While natural gas production volumes from Appalachian reservoirs are
relatively low on a per-well basis compared to other areas of the United
States, the productive life of Appalachian reserves is relatively long.
In 1996, the Company drilled 123 wells (105.7 net) in the Appalachian
Region, of which 98 were development wells (94.6 net). Capital and exploration
expenditures, including pipeline expenditures for the year were $33.5 million.
In the 1997 drilling program year, the Company has plans to drill 138 wells.
At December 31, 1996, the Company had 1,014,002 net acres in the region,
including 755,269 net developed acres. At year end, the Company had identified
271 proved undeveloped drilling locations.
The Company also owns and operates a brine treatment plant near Franklin,
Pennsylvania. The plant, which began operating in 1985, processes and treats
waste fluid generated during the drilling, completion and subsequent production
of oil and gas wells. The plant provides services to the Company and certain
other oil and gas producers in southwestern New York, eastern Ohio and western
Pennsylvania.
The Company believes that it gains operational efficiency in the
Appalachian Region because of its large acreage position, high concentration of
wells, natural gas gathering and pipeline systems and storage capacity.
WESTERN REGION
The Company's exploration, development and production activities in the
Western Region are primarily focused in the Anadarko basin in Kansas, Oklahoma
and the Panhandle of Texas, in the Green River Basin of Wyoming and in South
Texas. Operations for the Western Region are managed from a regional office in
Denver. At December 31, 1996, the Company had approximately 417.7 Bcfe of
proved reserves (93.1% natural gas) in the Western Region, constituting 44% of
the Company's total proved reserves.
ANADARKO
The Company has 745 productive wells (486.7 net) in the Anadarko area of
which 546 wells are operated by the Company. Principal producing intervals in
Anadarko are in the Chase, Morrow and Chester formations at depths ranging from
1,500 to 11,000 feet. Average net daily production in 1996 was 48.6 Mmcfe.
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In 1996, the Company drilled 41 wells (26.0 net) in Anadarko (39
development wells, 25.3 net). Capital and exploration expenditures for the year
were $13.1 million. In the 1997 drilling program year, the Company has plans to
drill 56 wells.
At December 31, 1996, the Company had approximately 216,278 net acres,
including approximately 184,368 net developed acres. At year end, the Company
had identified 54 proved undeveloped drilling locations.
ROCKY MOUNTAIN
The Company has 318 productive wells (119.7 net) in the Rocky Mountain
area of which 161 wells are operated by the Company. Principal producing
intervals in Rocky Mountain are in the Frontier and Dakota formations at depths
ranging from 9,000 to 13,000 feet. Average net daily production in 1996 was
32.7 Mmcfe.
In 1996, the Company drilled 22 wells (17.1 net) in the Rocky Mountains
(21 development wells, 16.1 net). Capital and exploration expenditures for the
year were $13.9 million. In the 1997 drilling program year, the Company has
plans to drill 36 wells.
At December 31, 1996, the Company had approximately 154,947 net acres,
including approximately 37,990 net developed acres. At year end, the Company
had identified 46 proved undeveloped drilling locations.
GULF COAST
The Company has 188 productive wells (72.7 net) in the Gulf Coast area of
which 54 wells are operated by the Company. Principal producing intervals in
Gulf Coast are in the Frio, Wilcox and Vicksburg formations at depths ranging
from 6,000 to 14,000 feet. Average net daily production in 1996 was 15.5 Mmcfe.
In 1996, the Company drilled 10 wells (5.4 net) in the Gulf Coast (8
development wells, 4.8 net). Capital and exploration expenditures for the year
were $12.2 million. In the 1997 drilling program year, the Company has plans to
drill 26 wells.
At December 31, 1996, the Company had approximately 23,677 net acres,
including approximately 14,524 net developed acres. At year end, the Company
had identified 3 proved undeveloped drilling locations.
GAS MARKETING
The Company is engaged in a wide array of marketing activities designed
to offer its customers long-term, reliable supplies of natural gas. Utilizing
its pipeline and storage facilities, gas procurement ability and transportation
and natural gas risk management expertise, the Company provides a menu of
services that includes gas supply and transportation management, short and
long-term supply contracts, capacity brokering and risk management
alternatives.
The marketing of natural gas has changed significantly as a result of
FERC Order 636 ("Order 636"), which was issued by the Federal Energy Regulatory
Commission in 1992. Order 636 required pipelines to unbundle their gas sales,
storage and transportation services. As a result, local distribution companies
and end-users will separately contract these services from gas marketers and
producers. Order 636 has had the effect of creating greater competition in the
industry while also providing the Company the opportunity to serve broader
markets. In 1994, 1995 and 1996, there was an increase in the number of
third-party producers that use the Company to market their gas. In addition,
the Company has experienced, as a result of Order 636, increased competition
for markets which has placed pressure on margins.
APPALACHIAN REGION
The Company's principal markets for its Appalachian Region natural gas
are in the northeastern United States. The Company's marketing subsidiary
purchases the Company's natural gas production in the
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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 ("LDCs") and gas marketers both on and off the Company's
pipeline system.
A majority of the Company's natural gas sales volume in the Appalachian
Region is being sold at market responsive prices under contracts with a term of
one year or less. Of these short term sales, spot market sales are made under
month-to-month contracts while industrial and utility sales generally are made
under year-to-year contracts. Approximately 20% of the Appalachian production
is sold on fixed price contracts which typically renew annually.
The Company's Appalachian production is generally sold at a premium price
to production from other producing regions due to its close proximity to
eastern markets. However, that premium has been reduced from historic levels
due to increased competition in the market place resulting in part from changes
in transportation and sales arrangements due to the implementation of pipeline
open access tariffs and Order 636.
The Company operates a number of gas gathering and pipeline systems, made
up of approximately 3,400 miles of pipeline with interconnects to four
interstate pipeline systems and five LDCs. The Company's natural gas gathering
and pipeline systems enable the Company to connect new wells quickly and to
transport natural gas from the wellhead directly to interstate pipelines, LDCs
and industrial end-users. Control of its gathering and pipeline systems also
enables the Company to purchase, transport and sell natural gas produced by
third parties. In addition, the Company can undertake development drilling
operations without relying upon third parties to transport its natural gas
while incurring only the incremental costs of pipeline and compressor additions
to its system.
The Company has two natural gas storage fields located in West Virginia,
with a combined working capacity of approximately 4 Bcf of natural gas. The
Company uses 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 the Company to
periodically increase the volume of natural gas it can deliver by more than 40%
above the volume that it could deliver solely from its production in the
Appalachian Region. The pipeline systems and storage fields are fully
integrated with the Company's producing operations.
WESTERN REGION
The Company's principal markets for Western Region natural gas are in the
northwestern, midwestern, and northeastern United States. The Company's
marketing subsidiaries purchase all of the Company's natural gas production in
the Western Region. These marketing subsidiaries sell the natural gas to
cogenerators, natural gas processors, LDCs, industrial customers and marketing
companies.
Currently, a majority of the Company's natural gas production in the
Western Region is being sold primarily under contracts with a term of one year
or less at market-responsive prices. Approximately 20% of the Western Region's
production is sold under a 15 year cogeneration contract with 12 years
remaining that escalates in price by 5% per year (See Item 3. Legal
Proceedings). The Western Region properties are connected to the majority of
the midwestern, northwestern, and northeastern interstate pipelines, affording
the Company access to multiple markets.
The Company also produces and markets approximately 1,100 barrels a day
of crude oil/condensate in the Western Region at market responsive prices.
RISK MANAGEMENT
In 1996, the Company entered into certain transactions to manage price
risks associated with its production and purchase commitments. The Company
utilized certain natural gas price swap agreements ("price swaps") to attempt
to manage price risk more effectively and improve the Company's realized
natural gas prices. These
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price swaps call for payments to (or to receive payments from) counterparties
based upon the differential between a fixed and a variable gas price. At
December 31, 1996, the open price swaps (744,000 Mmbtu in notional quantity)
covered the months of January and February 1997. The Company plans to continue
to evaluate on an ongoing basis the benefit of this strategy in the future. See
the Overview section of Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations for further discussion.
RESERVES
CURRENT RESERVES
The following table sets forth information regarding the Company's
estimates of its net proved reserves at December 31, 1996.
Natural Gas(Mmcf) Liquids(1)(MBbl) Total(2)(Mmcfe)
- ------------------------------------------------------------------------------------------------------------
Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total
- ------------------------------------------------------------------------------------------------------------
Appalachian 434,558 92,301 526,859 334 0 334 436,560 92,301 528,861
Western(3) 333,540 55,218 388,758 4,351 481 4,832 359,646 58,103 417,749
------- ------- ------- ----- --- ----- ------- ------- -------
Total 768,098 147,519 915,617 4,685 481 5,166 796,206 150,404 946,610
======= ======= ======= ===== === ===== ======= ======= =======
- ---------
(1) Liquids include crude oil, condensate and natural gas liquids (Ngl).
(2) Natural Gas Equivalents are determined using the ratio of 6.0 Mcf of
natural gas to 1.0 Bbl of crude oil or condensate.
(3) Includes proved reserves attributable to Anadarko, Rocky Mountains and
the Gulf Coast Areas.
The proved reserve estimates presented herein were prepared by the
Company's petroleum engineering staff and reviewed by Miller and Lents, Ltd.,
independent petroleum engineers. For additional information regarding the
Company's estimates of proved reserves, the review of such estimates by Miller
and Lents, Ltd. and certain other information regarding the Company's oil and
gas reserves, see the Supplemental Oil and Gas Information to the Consolidated
Financial Statements included in Item 8 hereof. A copy of the review letter by
Miller and Lents, Ltd., has been filed as an exhibit to this Form 10-K. The
Company's estimates of proved reserves set forth in the foregoing table do not
differ materially from those filed by the Company with other federal agencies.
The Company's reserves are sensitive to natural gas sales prices and their
effect on economic producing rates. The Company's reserves are based on oil and
gas prices in effect at December 31, 1996.
There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond the control of the Company and,
therefore, the reserve information set forth in this Form 10-K represents only
estimates. Reserve engineering is a subjective process of estimating
underground accumulations of crude oil and natural gas that cannot be measured
in an exact manner, and the accuracy of any reserve estimate is a function of
the quality of available data and of engineering and geological interpretation
and judgement. 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 revision of such estimate. Accordingly, reserve
estimates are often different from the quantities of crude oil and natural gas
that are ultimately recovered. The meaningfulness of such estimates is highly
dependent upon the accuracy of the assumptions upon which they were based. In
general, the volume of production from oil and gas properties owned by the
Company declines as reserves are depleted. Except to the extent the Company
acquires additional properties containing proved reserves or conducts
successful exploration and development activities or both, the proved reserves
of the Company will decline as reserves are produced.
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HISTORICAL RESERVES
The following table sets forth certain information regarding the
Company's estimated proved reserves for the periods indicated.
Oil, Condensate
Natural Gas(Mmcf) & NGLs(MBbl) Total(Mmcfe)
- ------------------------------------------------------------------------------------------------------------------------
APP WEST TOTAL APP WEST TOTAL APP WEST TOTAL
- ------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1993 555,933 252,347 808,280 136 2,690 2,826 556,749 268,487 825,236
Revisions of prior estimates (9,088) (15,539) (24,627) 54 (152) (98) (8,764) (16,451) (25,215)
Extensions, discoveries and
other additions 32,391 32,438 64,829 0 181 181 32,391 33,524 65,915
Production (29,668) (28,651) (58,319) (21) (803) (824) (29,794) (33,469) (63,263)
Purchases of reserves in place 16,963 151,994 168,957 0 5,992 5,992 16,963 187,946 204,909
Sales of reserves in place (6,037) 0 (6,037) (2) (39) (41) (6,049) (234) (6,283)
------- ------- ------- --- ----- ----- ------- ------- ---------
DECEMBER 31, 1994 560,494 392,589 953,083 167 7,869 8,036 561,496 439,803 1,001,299
------- ------- ------- --- ----- ----- ------- ------- ---------
Revisions of prior estimates 3,699 10,333 14,032 65 (713) (648) 4,086 6,061 10,147
Extensions, discoveries and
other additions 12,333 22,075 34,408 23 151 174 12,471 22,982 35,453
Production (27,530) (30,191) (57,721) (18) (722) (740) (27,637) (34,525) (62,162)
Purchases of reserves in place 576 840 1,416 0 15 15 576 929 1,505
Sales of reserves in place (34,016) (21,352) (55,368) (18) (1,509)(1,527) (34,123) (30,412) (64,535)
------- ------- ------- --- ----- ----- ------- ------- ---------
DECEMBER 31, 1995 515,556 374,294 889,850 219 5,091 5,310 516,869 404,838 921,707
------- ------- ------- --- ----- ----- ------- ------- ---------
Revisions of prior estimates (487) 3,261 2,774 (2) (130) (132) (501) 2,481 1,980
Extensions, discoveries and
other additions 40,703 29,005 69,708 137 249 386 41,526 30,500 72,026
Production (26,783) (31,979) (58,762) (21) (576) (597) (26,910) (35,435) (62,345)
Purchases of reserves in place 21,207 16,190 37,397 8 207 215 21,255 17,430 38,685
Sales of reserves in place (23,337) (2,013) (25,350) (7) (9) (16) (23,377) (2,065) (25,442)
------- ------- ------- --- ----- ----- ------- ------- ---------
DECEMBER 31, 1996 526,859 388,758 915,617 334 4,832 5,166 528,862 417,749 946,611
======= ======= ======= === ===== ===== ======= ======= =========
PROVED DEVELOPED RESERVES:
December 31, 1993 458,682 210,990 669,672 136 2,210 2,346 459,498 224,250 683,748
December 31, 1994 474,574 331,339 805,913 167 7,537 7,704 475,576 376,561 852,137
December 31, 1995 430,165 317,070 747,235 219 4,751 4,970 431,477 345,579 777,056
December 31, 1996 434,558 333,540 768,097 334 4,351 4,685 436,560 359,646 796,206
- ---------
APP = Appalachian Region
WEST = Western Region(1)
(1) For the year ended December 31, 1993, the Western reserves are
attributable to Anadarko only.
Note: Natural gas equivalents are determined using the ratio of 6.0 Mcf
of natural gas to 1.0 Bbl of crude oil or condensate.
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VOLUMES AND PRICES; PRODUCTION COSTS
The following table sets forth historical information regarding the
Company's sales and production volumes and average sales prices received for,
and average production costs associated with, its sales of natural gas and
crude oil, condensate and natural gas liquids (Ngl) for the periods indicated.
Year Ended December 31,
1996 1995 1994
- -------------------------------------------------------------------------
Net Wellhead Sales Volume:
Natural Gas (Bcf)(1)
Appalachian Region 26.2 26.4 28.7
Western Region(2) 32.6 29.8 28.3
Crude/Condensate/Ngl (MBbl)
Appalachian Region 21 18 20
Western Region 576 722 804
Produced Natural Gas Sales Price ($/Mcf)(3)
Appalachian Region $ 2.72 $ 2.22 $ 2.42
Western Region $ 2.02 $ 1.33 $ 1.65
Weighted Average $ 2.34 $ 1.75 $ 2.04
Crude/Condensate Sales Price ($/Bbl)(3) $21.14 $17.95 $ 16.66
Production Costs ($/Mcfe)(4) $ 0.56 $ 0.55 $ 0.62
- ---------
(1) Equal to the aggregate of production and the net changes in storage
and exchanges.
(2) Includes information regarding Anadarko, Rocky Mountains and Gulf
Coast.
(3) Represents the average sales prices for all production volumes (including
royalty volumes) sold by the Company during the periods shown net of
related costs (principally purchased gas royalty, transportation and
storage).
(4) Production costs include direct lifting costs (labor, repairs and
maintenance, materials and supplies), and the costs of administration of
production offices, insurance and property and severance taxes but is
exclusive of depreciation and depletion applicable to capitalized lease
acquisition, exploration and development expenditures.
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ACREAGE
The following tables summarize the Company's gross and net developed and
undeveloped leasehold and mineral acreage at December 31, 1996. Acreage in
which the Company's interest is limited to royalty and overriding royalty
interests is excluded. The undeveloped mineral fee acreage in West Virginia is
unleased.
LEASEHOLD ACREAGE
At December 31, 1996
Developed Undeveloped Total
- ---------------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
- ---------------------------------------------------------------------------------------------
STATE
Alabama -- -- 312 312 312 312
Arkansas -- -- 240 3 240 3
Colorado 14,742 13,406 60,283 53,314 75,025 66,720
Indiana -- -- 54,022 26,725 54,022 26,725
Kansas 33,104 29,210 6,591 2,785 39,695 31,995
Kentucky 2,680 990 15,677 7,656 18,357 8,646
Louisiana 1,541 290 4,697 904 6,238 1,194
Michigan 457 118 25,161 5,232 25,618 5,350
Montana 157 52 680 303 837 355
New York 19,365 15,557 2,282 2,216 21,647 17,773
North Dakota 160 20 870 96 1,030 116
Ohio 2,906 1,372 25,151 10,972 28,057 12,344
Oklahoma 172,234 113,811 43,832 28,737 216,066 142,548
Pennsylvania 129,577 122,144 58,454 53,209 188,031 175,353
Texas 70,453 41,447 20,708 7,849 91,161 49,296
Utah 1,740 446 23,231 19,133 24,971 19,579
Virginia 4,541 3,820 20,092 18,010 24,633 21,830
West Virginia 552,797 517,911 92,541 76,609 645,338 594,520
Wyoming 46,235 23,312 89,938 43,438 136,173 66,750
--------- ------- ------- ------- --------- ---------
Total 1,052,689 883,906 544,762 357,503 1,597,451 1,241,409
========= ======= ======= ======= ========= =========
CANADA
Alberta 1,429 563 316 79 1,745 642
British Columbia 665 166 1,992 498 2,657 664
--------- ------- ------- ------- --------- ---------
Total 2,094 729 2,308 577 4,402 1,306
========= ======= ======= ======= ========= =========
MINERAL FEE ACREAGE
At December 31, 1996
Developed Undeveloped Total
- ---------------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
- ---------------------------------------------------------------------------------------------
STATE
Colorado 174 25 265 21 439 46
Kansas 160 128 -- -- 160 128
Montana -- -- 589 75 589 75
New York -- -- 6,545 1,636 6,545 1,636
Oklahoma 16,581 13,979 240 49 16,821 14,028
Pennsylvania 70 70 1,618 547 1,688 617
Texas 27 27 847 424 874 451
Virginia 17,917 17,851 -- -- 17,917 17,851
West Virginia 89,201 75,436 56,882 55,921 146,083 131,357
--------- ------- ------- ------- --------- ---------
Total 124,130 107,516 66,986 58,673 191,116 166,189
========= ======= ======= ======= ========= =========
Aggregate Total 1,178,913 992,151 614,056 416,753 1,792,969 1,408,904
========= ======= ======= ======= ========= =========
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Total Net Acreage by Area of Operation
At December 31, 1996
Developed Undeveloped Total
- -------------------------------------------------------------
Appalachian Region 755,269 258,733 1,014,002
Western Region 236,882 158,020 394,902
======= ======= --=======
Total 992,151 416,753 1,408,904
======= ------- ---------
PRODUCTIVE WELL SUMMARY(1)
The following table reflects the Company's ownership at December 31, 1996
in natural gas and oil wells in the Appalachian Region (consisting of various
fields located in West Virginia, Pennsylvania, New York, Ohio, Virginia and
Kentucky), and in the Western Region (consisting of various fields located in
Louisiana, Oklahoma, North Texas, Kansas, North Dakota, Utah, South Texas,
Colorado, Wyoming and Canada).
Natural Gas Oil Total
Gross Net Gross Net Gross Net
- ----------------------------------------------------------------------
Appalachian Region 3,837 3,564.9 21 13.9 3,858 3,578.8
Western Region 1,006 572.9 245 106.2 1,251 679.1
----- ------- --- ----- ----- -------
Total 4,843 4,137.8 266 120.1 5,109 4,257.9
===== ======= === ===== ===== =======
- ---------
(1) "Productive" wells are producing wells and wells capable of production in
which the Company has a working interest.
DRILLING ACTIVITY
The Company drilled, participated in the drilling of, or acquired wells
as set forth in the table below for the periods indicated:
Year Ended December 31,
1996 1995 1994
Gross Net Gross Net Gross Net
- ---------------------------------------------------------------------------
APPALACHIAN REGION:
Development Wells
Natural Gas 85 81.6 18 16.7 133 128.2
Oil 1 1.0 0 0.0 0 0.0
Dry 12 12.0 6 4.8 7 6.5
Exploratory Wells
Natural Gas 10 5.0 2 0.5 0 0
Oil 5 0.9 2 0.5 0 0
Dry 10 5.2 5 2.0 2 0.5
--- ----- -- ---- --- -----
Total 123 105.7 33 24.5 142 135.2
=== ===== == ==== === =====
Wells Acquired(1)
Natural Gas 15 11.8 3 3.7 9 21.1
Oil 0 0.0 0 0.0 0 0.0
--- ----- -- ---- --- -----
Total 15 11.8 3 3.7 9 21.1
=== ===== == ==== === =====
Wells in Progress at End
of Period 2 1.5 3 3.0 2 1.3
10
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Year Ended December 31,
1996 1995 1994
- ---------------------------------------------------------------------------
Gross Net Gross Net Gross Net
- ---------------------------------------------------------------------------
WESTERN REGION:
Development Wells
Natural Gas 52 35.4 42 21.2 48 24.7
Oil 1 .1 2 1.9 7 3.1
Dry 15 10.6 7 3.8 8 5.3
Exploratory Wells
Natural Gas 1 0 1 0.3 0 0.0
Oil 0 0 0 0 0 0.0
Dry 4 2.4 8 3.9 3 0.8
-- ---- - --- --- -----
Total 73 48.5 60 31.1 66 33.9
== ==== = === === =====
Wells Acquired(1)
Natural Gas 25 11.9 0 2.7 413 115.7
Oil 3 0.4 0 0.1 140 52.3
-----
Total 28 12.3 0 2.8 553 168.0
== ==== = === === =====
Wells in Progress at End
of Period 4 1.5 6 5.3 7 1.9
- ---------
(1) Includes the acquisition of net interest in certain wells in the
Appalachian Region and in the Western Region in 1996, 1995 and 1994 in
which the Company already held an ownership interest.
COMPETITION
Competition in the Company's primary producing areas is intense. The
Company believes that its competitive position is affected by price, contract
terms and quality of service, including pipeline connection times, distribution
efficiencies and reliable delivery record. The Company believes that its
extensive acreage position and existing natural gas gathering and pipeline
systems and storage fields give it a competitive advantage over certain other
producers in the Appalachian Region which do not have such systems or
facilities in place. The Company also believes that its competitive position in
the Appalachian Region is enhanced by the absence of significant competition
from major oil and gas companies. The Company also actively competes against
some companies with substantially larger financial and other resources,
particularly in the Western Region.
OTHER BUSINESS MATTERS
MAJOR CUSTOMER
The Company had no sales to any customer that exceeded 10% of the
Company's total gross revenues in 1996.
SEASONALITY
Demand for natural gas has historically been seasonal in nature, with
peak demand and typically higher prices occurring during the colder winter
months.
REGULATION OF OIL AND NATURAL GAS PRODUCTION
The Company's oil and gas production and transportation operations are
subject to various types of regulation by federal, state and local authorities.
Legislation affecting the oil and natural gas industry is under constant review
for amendment or expansion. Further, numerous departments and agencies, both
federal and state, have issued rules and regulations affecting the oil and
natural gas industry and its individual members, compliance with which is often
difficult and costly and some of which may carry substantial penalties for
non-compliance.
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The regulatory burden on the oil and natural gas industry increases its cost of
doing business and, consequently, affects its profitability. Inasmuch as such
laws and regulations are frequently expanded, amended or reinterpreted, the
Company is unable to predict the future cost or impact of complying with such
regulations. However, the Company does not believe that under present
regulations it is affected in a significantly different manner by these
regulations than others in the industry.
EXPLORATION AND PRODUCTION
Exploration and production operations of the Company are subject to
various types of regulation at the federal, state and local levels. Such
regulation includes requiring permits for the drilling of wells, maintaining
bonding requirements in order 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 upon which wells are drilled and the plugging and
abandoning of wells. The Company's operations are also subject to various
conservation laws and regulations. These include the regulation of the size of
drilling and spacing units or proration units and the density of wells which
may be drilled and the unitization or pooling of oil and natural gas
properties. In this regard, 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 or production from oil and natural gas wells, generally prohibit
the venting or flaring of natural gas and impose certain requirements regarding
the ratability of production. In this regard, such states as Texas, Oklahoma
and Louisiana have in recent years reviewed and substantially revised methods
previously used to gather the necessary information and make monthly
determinations of appropriate field and well allowables. The effect of these
regulations is to limit the amounts of oil and natural gas the Company can
produce from its wells, and to limit the number of wells or the locations at
which the Company can drill.
NATURAL GAS MARKETING, GATHERING AND TRANSPORTATION
Federal legislation and regulatory controls have historically affected
the price of the natural gas produced by the Company and the manner in which
such production is marketed. The Federal Energy Regulatory Commission (the
"FERC") regulates the interstate transportation and sale for resale of natural
gas by interstate and intrastate pipelines. The FERC previously regulated the
maximum selling prices of certain categories of gas sold in "first sales" in
interstate and intrastate commerce under the Natural Gas Policy Act. Effective
January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the
"Decontrol Act") deregulated natural gas prices for all "first sales" of
natural gas, which includes all sales by the Company of its own production. As
a result, all sales of the Company's domestically produced natural gas may be
sold at market prices, unless otherwise committed by contract. The FERC's
jurisdiction over natural gas transportation was unaffected by the Decontrol
Act.
The Company's natural gas sales are affected by the regulation of
intrastate and interstate gas transportation. In an attempt to restructure the
interstate pipeline industry with the goal of providing enhanced access to, and
competition among, alternative natural gas suppliers, the FERC, commencing in
April 1992, issued Order Nos. 636, 636-A and 636-B ("Order No. 636") which have
altered significantly the interstate transportation and sale of natural gas.
Among other things, Order No. 636 required pipelines to unbundle the various
services that they had provided in the past, such as sales, transmission and
storage, and to offer these services individually to their customers. By
requiring interstate pipelines to "unbundle" their services and to provide
their customers with direct access to pipeline capacity held by them, Order No.
636 has enabled pipeline customers to choose the levels of transportation and
storage service they require, as well as to purchase natural gas directly from
third-party merchants other than the pipelines and obtain transportation of
such gas on a nondiscriminatory basis. The effect of Order No. 636 has been to
enable the Company to market its natural gas production to a wider variety of
potential purchasers. The Company believes that these changes generally have
improved the Company's access to transportation and have enhanced the
marketability of its natural gas production. To date, Order No. 636 has not had
any material adverse effect on the Company's ability to market and transport
its natural gas production. However, even though Order No. 636 has been
affirmed on appeal, with minor exceptions, and most individual pipelines have
final open access tariffs now in place, the FERC is continuing to review and
assess the effectiveness of it regulations and the Company cannot predict what
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new regulations may be adopted by the FERC and other regulatory authorities, or
what effect subsequent regulations may have on the Company's activities.
In recent years the FERC also has pursued a number of other important
policy initiatives which could significantly affect the marketing of natural
gas. Some of the more notable of these regulatory initiatives include (i) a
series of orders in individual pipeline proceedings articulating a policy of
generally approving the voluntary divestiture of interstate pipeline-owned
gathering facilities either to non-affiliated companies (a "spin off") or to
the pipeline's nonregulated affiliate (a "spin down "), (ii) the completion of
a rulemaking proceeding involving the regulation of pipelines with marketing
affiliates under Order No. 497, (iii) FERC's ongoing efforts to promulgate
standards for pipeline electronic bulletin boards and electronic data exchange,
(iv) a generic inquiry into the pricing of interstate pipeline capacity, (v)
efforts to refine FERC's regulations controlling the operation of the secondary
market for released pipeline capacity, (vi) a policy statement regarding
market-based rates and other non-cost-based rates for interstate pipeline
transmission and storage capacity and (vii) appropriate ratemaking procedures
for pipeline expansions and extensions. Several of these initiatives are
intended to enhance competition in natural gas markets, although some, such as
the so-called "spin-down" of previously regulated gathering facilities by
interstate pipelines to their affiliates, may have the adverse effect on some
in the industry of increasing the cost of doing business as a result of the
monopolization of those facilities by their new, unregulated owners. FERC
attempted to address some of these concerns in its orders authorizing such
"spin-downs," but one of its principal devices, the use of "default" contracts
to assure continuity of gathering services for two years after spin down, was
found unlawful on appeal and it remains to be seen what effect the FERC's other
activities will have on access to markets and the cost to do business. In
response to the FERC's policy of authorizing the interstate pipeline industry's
divestiture of these gathering facilities, several states (most notably
Oklahoma and Texas) have enacted or are considering laws and regulations
enhancing state level oversight over gathering. As to all of these recent FERC
and state initiatives, the ongoing, or, in some instances, preliminary evolving
nature of these regulatory initiatives makes it impossible at this time to
predict their ultimate impact upon the Company's activities.
The Company's pipeline systems and storage fields are regulated for
safety compliance by the Department of Transportation, the West Virginia Public
Service Commission, the Pennsylvania Department of Natural Resources and the
New York Department of Public Service. The Company's pipeline systems in each
state operate independently and are not interconnected.
ENVIRONMENTAL REGULATIONS
General. The Company's operations are subject to extensive federal, state
and local laws and regulations relating to the generation, storage, handling,
emission, transportation and discharge of materials into the environment.
Permits are required for the operation of various facilities of the Company,
and these permits are subject to revocation, modification and renewal by
issuing authorities. Governmental authorities have the power to enforce
compliance with their regulations, and violations are subject to fines,
injunctions or both. Such government regulation can increase the cost of
planning, designing, installing and operating oil and gas facilities. In most
instances, the regulatory requirements impose water and air pollution control
measures. Although the Company believes that compliance with environmental
regulations will not have a material adverse effect on the Company, risks of
substantial costs and liabilities related to environmental compliance issues
are inherent in oil and gas production operations, and no assurance can be
given that significant costs and liabilities will not be incurred. Moreover, it
is possible that other developments, such as stricter environmental laws and
regulations, and claims for damages to property or persons resulting from oil
and gas production would result in substantial costs and liabilities to the
Company.
Solid and Hazardous Waste. The Company currently owns or leases, and has
in the past owned or leased, numerous properties that have been used for
production of oil and gas for many years. Although the Company has utilized
operating and disposal practices that were standard in the industry at the
time, hydrocarbons or other solid wastes may have been disposed or released on
or under the properties owned or leased by the Company. In addition, many of
the properties have been operated by third parties. The Company had no control
over such parties' treatment of hydrocarbons or other solid wastes and the
manner in which such
13
15
substances may have been disposed or released. State and federal laws
applicable to oil and gas wastes and properties have gradually become stricter
over time. Under these new laws, the Company could be required to remove or
remediate previously disposed wastes (including wastes disposed or released by
prior owners and operators) or property contamination (including groundwater
contamination by prior owners or operators) or to perform remedial plugging
operations to prevent future contamination.
The Company generates some wastes that are 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." Furthermore, 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 statues, and
therefore be subject to more rigorous and costly disposal requirements.
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 classes of persons with respect to the release of a "hazardous
substance" into the environment. These persons include the owner and operator
of a site and any party that disposed or arranged for the disposal of the
hazardous substance found at a site. CERCLA also authorizes the EPA, and in
some cases, third parties, to take actions in response to threats to the public
health or the environment and to seek to recover from the responsible parties
the costs of such action. In the course of the Company's operations, the
Company has generated and will generate wastes that may fall within CERCLA's
definition of "hazardous substances." The Company may also be an owner of sites
on which "hazardous substances" have been released. Therefore, the Company may
be responsible under CERCLA for all or part of the costs to clean up sites at
which such wastes have been disposed.
Oil Pollution Act. The Oil Pollution Act of 1990 (the "OPA") and
regulations thereunder impose a variety of regulations 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 waste 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.
Air Emissions. The operations of the Company are subject to local, state
and federal laws and regulations for the control of emissions from sources of
air pollution. Administrative enforcement actions for failure to comply
strictly with air regulations or permits are generally resolved by payment of
monetary fines and correction of any identified deficiencies. Alternatively,
regulatory agencies could require the Company to cease construction or
operation of certain air emission sources. The Company believes that it is in
substantial compliance with the emission standards under local, state and
federal laws and regulations.
EMPLOYEES
The Company had 360 active employees as of December 31, 1996. The Company
believes that its relations with its employees are satisfactory. The Company
has not entered into any collective bargaining agreements with its employees.
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OTHER
The Company's profitability depends on certain factors that are beyond
its control, such as natural gas and crude oil prices. The nature of the oil
and gas business involves a variety of risks, including the risk of
experiencing certain operating hazards such as fires, explosions, blowouts,
cratering, oil spills and encountering formations with abnormal pressures, the
occurrence of any of which could result in substantial losses to the Company.
The operation of the Company's natural gas gathering and pipeline systems also
involves certain risks, including the risk of explosions and environmental
hazards caused by pipeline leaks and ruptures. The proximity of pipelines to
populated areas, including residential areas, commercial business centers and
industrial sites, could exacerbate such risks. At December 31, 1996, the
Company owned or operated approximately 3,400 miles of natural gas gathering
and pipeline systems. As part of its normal maintenance program, the Company
has identified certain segments of its pipelines which it believes require
repair, replacement or additional maintenance. In accordance with customary
industry practices, the Company maintains insurance against some, but not all,
of such risks.
ITEM 2. PROPERTIES
See Item 1. Business.
ITEM 3. LEGAL PROCEEDINGS
The Company and its subsidiaries are defendants or parties in numerous
lawsuits or other governmental proceedings arising in the ordinary course of
business. The Company is also involved in other gas contract issues. In the
opinion of the Company, final judgements or settlements, if any, which may be
awarded in connection with any one or more of these suits and claims could be
significant to the results of operations and cash flows of any period but would
not have a material adverse effect on the Company's financial position.
On February 10, 1997, Washington Energy Company and Puget Sound Power &
Light Company merged to form Puget Sound Energy, Inc. ("Puget"). As a result of
the merger, Puget is the holder of 2,133,000 shares of Common Stock and
1,134,000 shares of the Company's 6% Convertible Redeemable Preferred Stock
(convertible into 1,972,174 shares of Common Stock), all of which were
previously held by Washington Energy Company. Mr. William P. Vititoe, a member
of the Company's Board of Directors, is a consultant to Puget and was formerly
an officer and director of Washington Energy Company.
The Company sells approximately 20% of its natural gas production in the
Western Region to a cogeneration plant located in Bellingham, Washington and
owned by Encogen Northwest, L.P. ("Encogen") under a gas sales contract
containing a fixed price that escalates annually, a firm delivery arrangement
and a term continuing through June 30, 2008. Encogen sells all the electrical
power generated in the plant to Puget under an Agreement for Firm Power
Purchase ("Power Agreement"). The Company is aware that a dispute has arisen
between Puget and Encogen over the appropriate interpretation of certain
provisions of the Power Agreement, which dispute is currently being litigated.
Puget has requested the court, among other matters, to declare that Encogen is
in material breach of the Power Agreement. A finding by the court that Encogen
is in material breach of the Power Agreement could lead to termination of the
Power Agreement. Any restructuring or termination of the Power Agreement may
have a negative impact on the Company's gas sales arrangement with Encogen.
Encogen has requested that the Company consider restructuring its gas sales
arrangement with Encogen. To date the Company has been unwilling to restructure
its gas sales agreement without being fully compensated for the agreement's
value.
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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the
period from October 1, 1996 to December 31, 1996.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information about the executive
officers of the Company as of March 1, 1997, as such term is defined in Rule
3b-7 promulgated under the Securities Exchange Act of 1934, and certain other
officers of the Company.
Name Age Position Officer Since
- --------------------------------------------------------------------------------------------
Charles P. Siess, Jr. 70 Chairman of the Board, Chief Executive 1995
Officer and President
Ray R. Seegmiller 61 Executive Vice President, Chief Operating 1995
Officer and Treasurer
Jim L. Batt 61 Vice President, Land 1988
Jeff W. Hutton 41 Vice President, Marketing 1995
Gerald F. Reiger 45 Vice President and Regional Manager 1995
James M. Trimble 48 Vice President, Business Development 1987
and Engineering
H. Baird Whitehead 46 Vice President and Regional Manager 1987
Paul F. Boling 43 Controller 1996
Lisa A. Machesney 41 Corporate Secretary and Managing Counsel 1995
All officers are elected annually by the Company's Board of Directors.
With the exception of the following, all executive officers of the Company have
been employed by the Company for at least the last five years.
Charles P. Siess, Jr. has been Chairman of the Board, Chief Executive
Officer and President of the Company since May 1995. From February 1993 until
January 1994, Mr. Siess served as Acting General Manager of Bridas S.A.P.I.C.
(oil exploration in Argentina). Prior thereto, Mr. Siess served as Chairman of
the Board, Chief Executive Officer and President of the Company from December
1989 to December 1992.
Gerald F. Reiger has been Vice President, Regional Manager of the Company
since February 1995. From May 1994 until February 1995, Mr. Reiger served as
Regional Manager of the Company. Prior thereto, Mr. Reiger was associated with
Washington Energy Resources Company, a subsidiary of Washington Energy Company,
from 1992 to 1994. Prior thereto, Mr. Reiger served as U.S. Operations Manager
of DeKalb Energy Company.
Ray R. Seegmiller joined the Company as Vice President, Chief Financial
Officer and Treasurer in August 1995. From May 1988 until 1993, Mr. Seegmiller
served as President and Chief Executive of Terry Petroleum Company. Prior
thereto, Mr. Seegmiller held various officer positions with Marathon
Manufacturing Company.
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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 sets forth for the
periods indicated the high and low sales prices per share of the Common Stock,
as reported in the consolidated transaction reporting system, and the cash
dividends paid per share of the Common Stock:
Cash
High Low Dividends
- -------------------------------------------------------------
1996
First Quarter $ 16.88 $ 13.13 $ 0.04
Second Quarter 17.63 13.75 0.04
Third Quarter 18.38 13.75 0.04
Fourth Quarter 18.38 14.38 0.04
1995
First Quarter $ 16.00 $ 12.38 $ 0.04
Second Quarter 17.00 13.63 0.04
Third Quarter 15.38 13.00 0.04
Fourth Quarter 15.75 13.13 0.04
As of January 31, 1997, there were 1,478 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 sets forth a summary of selected consolidated
financial data for the Company 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 thereto.
Year Ended December 31,
(In thousands, except per share amounts) 1996 1995 1994 1993 1992
- ------------------------------------------------------------------------------------------------------------
INCOME STATEMENT DATA:
Net Operating Revenues $ 163,061 $ 121,083 $ 140,295 $ 115,816 $ 107,205
Income (Loss) from Operations 48,787 (116,758) 15,013 20,007 17,983
Net Income (Loss) Applicable to
All Common Stockholders 15,258 (92,171) (5,444) 2,088 2,227
EARNINGS (LOSS) PER SHARE APPLICABLE
TO ALL COMMON STOCKHOLDERS(1) $ .67 $ (4.05) $ (0.25) $ 0.10 $ 0.11
DIVIDENDS PER COMMON SHARE $ 0.16 $ 0.16 $ 0.16 $ 0.16 $ 0.16
BALANCE SHEET DATA:
Properties and Equipment, Net $ 480,511 $ 474,371 $ 634,934 $ 400,270 $ 306,723
Total Assets 561,341 528,155 688,352 445,001 348,696
Long-Term Debt 248,000 249,000 268,363 169,000 120,000
Stockholders' Equity 160,704 147,856 243,082 153,529 118,313
- ---------
(1) See "Earnings (Loss) Per Common Share" under Note 1 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 review of operations should be read in conjunction with the
Consolidated Financial Statements and the Notes thereto included elsewhere.
OVERVIEW
The substantial up swing in gas prices, coupled with actions taken in
1995 designed to return the Company to long-term profitability, played an
important part in the Company's performance in 1996 with record earnings and
operating cash flows. Operating results for 1996 included the benefit of the
following realizations:
o The average produced natural gas price was $2.34 per Mcf, up 34%
compared to 1995.
o As a result of the improved pricing environment, margins on brokered
natural gas sales increased 124%, or $3.1 million over 1995.
o Under its continued program to divest non-strategic properties, the
Company sold 339 wells located in the Appalachian Region, generating
$4.6 million in cash proceeds and a gain on sale of $1.6 million.
o Net interest costs were down $7.5 million, or 30%, primarily due to
the absence of interest rate swaps that were in place in 1995, lower
interest rates, a reduced debt balance and $1.7 million of interest
income related to an income tax refund for tax periods prior to 1990.
o Depreciation, depletion and amortization ("DD&A") expenses were down
$6.9 million or $0.11 per Mcfe of production. This reduction was
primarily the result of the impairment of long-lived assets recorded
as a result of adopting SFAS 121 in September 1995, which reduced the
depreciable basis of properties and equipment by $113.8 million.
Operating cash flows reached a record level, increasing $34.0 million,
or 82%, over 1995. Cash flows from operations, along with the $5.7 million of
proceeds from the sale of non-strategic properties, predominantly funded (1)
$73.3 million of capital and exploration expenditures, $49 million higher than
1995, and (2) $9.2 million of preferred and common stock dividend payments.
The Company drilled 154.2 net wells with a net success rate of 80%
compared to 55.4 net wells and a net 75% success rate in 1995. Along with the
higher success rate in 1996, the Company replaced 118% of production, through
drilling additions and revisions, versus 73% production replacement in 1995. In
1997 the Company plans to drill 256 wells and spend $78.3 million in capital
and exploration expenditures, 7% higher than 1996 expenditures.
Natural gas production equivalent was 62.3 Bcf, virtually unchanged
compared to 1995. The production from new wells reversed the downward trend in
production experienced in the early part of 1996 due to (1) the low level of
development activity in 1995, drilling only 55 net wells compared to an average
of 135 net wells per year over the previous five years, and (2) the sale of
non-strategic properties, representing quarterly production of 0.6 Bcf.
The Company had a number of gas price swaps in place to hedge a
significant portion of its production for the first four months of 1996. For
the remainder of 1996, the Company had one small hedge contract for the months
of May through September 1996 in a notional quantity equal to 5,000 Mmbtu per
day, or less than 4% of the Company's daily production. While the Company will
selectively use gas price hedges from time-to-time to protect certain markets
when substantial downside risks are perceived, management intends to structure
the hedge positions in a manner that retains upside potential.
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The Company's strategic pursuits are sensitive to energy commodity
prices, particularly the price of natural gas. While gas prices in many regions
of the U.S. moved up sharply in November and December of 1996 to near record
levels and some industry analysts predict continued improvements in 1997
pricing over 1996, the gas market has demonstrated significant price volatility
during the months of January, February, and March 1997. Consequently, there is
considerable uncertainty about gas prices for the rest of 1997 and beyond.
The Company remains focused on the following goals established in 1995,
applying a three pronged strategy of growth through the drill bit, growth
through synergistic acquisitions and growth through greater emphasis on
marketing. The Company believes that progress toward these goals is appropriate
in the current industry environment, enabling the Company to effectively
achieve its strategy over the long term.
o Increase cash flows, using a balance of increased production and
reduced costs. Significant progress has been made toward this goal,
and the Company expects to be profitable in 1997 if the Henry Hub
average price for the full year is $1.80 or more, assuming a
traditional correlation between Henry Hub prices and prices realized
by the Company in its regional markets.
o Maintain reserves per share while increasing production to protect
long-term shareholder value. An aggressive 1997 drilling program is
designed to result in 1997 production exceeding 1996, and reserves
are also expected to increase.
o Reduce debt as a percentage of total capitalization without diluting
existing shareholder value. To achieve this goal, project returns
will be compared with the marginal cost of debt when deciding whether
to reinvest or pay down debt. Other financing alternatives will also
be reviewed.
The preceding paragraphs, discussing the Company's strategic pursuits
and goals, contain forward-looking information. See FORWARD-LOOKING INFORMATION
on page 23.
FINANCIAL CONDITION
CAPITAL RESOURCES AND LIQUIDITY
The Company's capital resources consist primarily of cash flows from its
oil and gas properties and asset-based borrowing supported by its oil and gas
reserves. The Company's level of earnings and cash flows depend on many
factors, including the price of oil and natural gas and its ability to control
and reduce costs. Demand for oil and gas has historically been subject to
seasonal influences characterized by peak demand and higher prices in the
winter heating season. Natural gas prices and demand were up significantly in
1996 over 1995, resulting in higher cash flows.
The primary source of cash for the Company during 1996 was from funds
generated from operations. Primary uses of cash were funds used in operations,
exploration and development expenditures, acquisitions, dividends on preferred
and common stock and repayment of debt.
The Company had a net cash outflow of $1.7 million in 1996. Net cash
inflow from operating and financing activities totalled $65.9 million, funding
in most part the capital and exploration expenditures of $67.6 million, net of
the $5.7 million in proceeds from the sale of assets.
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(In millions) 1996 1995 1994
-------------------------------------------------------------------------------------------
Cash Flows Provided by Operating Activities $ 75.5 $ 41.5 $ 67.3
-------- ------- --------
Cash flows provided by operating activities in 1996 were substantially
higher, increasing $34 million over 1995, due predominantly to higher natural
gas prices.
Cash flows provided by operating activities in 1995 were lower by $25.8
million compared with 1994 primarily due to lower gas prices and higher
interest costs attributable to the 1994 and 1993 acquisitions.
(In millions) 1996 1995 1994
-------------------------------------------------------------------------------------------
Cash Flows Provided (Used) by Investing Activities $ (67.6) $ (14.0) $ (158.8)
-------- ------- --------
Cash flows used by investing activities in 1996 were $53.5 million higher
than in 1995 due primarily to $40.6 million of increased capital and
exploration expenditures over 1995. The Company's 1995 drilling program was
scaled down, drilling only 55.4 net wells, compared to an average of 135 net
wells per year over the previous five years. The 1996 capital expenditures were
offset in part by proceeds of $5.7 million from the sale of assets.
Cash flows used by investing activities in 1995 were $144.8 million lower
than in 1994 due primarily to a $48.0 million decrease in capital expenditures
and the lack of a major acquisition in 1995 compared to the $78.5 million
capital outlay for the WERCO acquisition in 1994. The 1995 capital expenditures
were offset in part by proceeds of $8.4 million for a valuation adjustment on
the WERCO acquisition and $10.3 million in proceeds from the sale of assets.
(In millions) 1996 1995 1994
-------------------------------------------------------------------------------------------
Cash Flows Provided (Used) by Financing Activities $ (9.6) $ (28.2) $ 92.4
-------- ------- --------
Cash flows provided (used) by financing activities from 1994 to 1995 were
primarily borrowings from or payments on the Company's revolving credit
facility while in 1996 most of the activity was dividend payments. In 1996 and
1995 the Company reduced its debt under this facility by $1.0 million and $19.0
million, respectively. In 1994 the Company's debt under this facility increased
$99 million, including $78.5 million to partially fund the WERCO acquisition,
$6.2 million to purchase additional drilling locations in connection with the
1993 acquisition of proved properties from Emax Oil Company ("Emax"), and $7.1
million for other property acquisitions and capital expenditures.
Since June 1995, the Company's available credit line under the revolving
credit facility has been $235 million. The available credit line is subject to
adjustment on the basis of the projected present value of estimated future net
cash flows from proved oil and gas reserves (as determined by an independent
petroleum engineer's report incorporating certain assumptions provided by the
lender) and other assets. The Company's outstanding indebtedness under the
revolving credit facility was $168 million at December 31, 1996.
The Company's 1997 interest expense is projected to be approximately $19
million. No principal payments are due in 1997.
Capitalization information on the Company is as follows:
(In millions) 1996 1995 1994
-------------------------------------------------------------------------------------------
Long-Term Debt $ 248.0 $ 249.0 $ 268.3
Stockholders' Equity
Common Stock 69.4 56.6 151.8
Preferred Stock 91.3 91.3 91.3
-------- ------- --------
Total 160.7 147.9 243.1
-------- ------- --------
Total Capitalization $ 408.7 $ 396.9 $ 511.4
======== ======= ========
Debt to Capitalization 60.7% 62.7% 52.5%
-------- ------- --------
20
22
The Company's capitalization reflects the non-cash impact to equity of
the $69.2 million SFAS 121 impairment of long-lived assets recorded in 1995.
(See Note 15 of the Notes to the Consolidated Financial Statements for further
discussion.)
CAPITAL AND EXPLORATION EXPENDITURES
The following table presents major components of capital and exploration
expenditures for the three years ended December 31, 1996.
(In millions) 1996 1995 1994
-------------------------------------------------------------------------------------------
Capital Expenditures:
Drilling and Facilities $ 42.7 $ 19.3 $ 47.9
Leasehold Acquisitions 4.3 2.0 4.7
Pipeline and Gathering 6.3 2.2 8.9
Other 0.7 1.2 2.3
-------- ------- --------
54.0 24.7 63.8
-------- ------- --------
Proved Property Acquisitions 6.6 -- 8.9
WERCO Acquisition (5.3)(1) (8.4)(2) 216.2(3)
-------- ------- --------
1.3 (8.4) 225.1
-------- ------- --------
Exploration Expenses 12.6 8.0 8.0
-------- ------- --------
Total $ 67.9 $ 24.3 $ 296.9
======== ======= ========
- ---------
(1) An adjustment to the $40.2 million non-cash component relating to
deferred taxes for the difference between the tax and book bases of the
acquired properties, as required by SFAS 109, "Accounting for Income
Taxes", of the WERCO acquisition as a result of the $8.4 million
valuation adjustment received in 1995.
(2) A net cash payment received in connection with a valuation adjustment on
the 1994 WERCO acquisition.
(3) Included in capital expenditures for the WERCO acquisition was $97.5
million in common and preferred stock of the Company and a $40.2 million
non-cash component described in note (1).
The substantial reduction in capital and exploration expenditures in 1995
resulted from the downsized capital expenditures program resulting from
depressed gas prices and the absence of a major acquisition.
The Company generally funds its capital and exploration activities,
excluding oil and gas property acquisitions, with cash generated from
operations and budgets such capital expenditures based upon projected cash
flows, exclusive of acquisitions.
Planned expenditures for 1997 have been increased 7% compared with 1996.
Depending on the level of future natural gas prices, the Company intends to
review and adjust the capital and exploration expenditures planned for 1997 as
industry conditions dictate. Presently, the Company projects $78 million in
capital and exploration expenditures for 1997. The Company plans to drill 256
wells (167 net), compared with 196 wells (154 net) drilled in 1996. Capital
dedicated to the drilling program for 1997 is $61 million.
In addition to the drilling program, other 1997 capital expenditures are
planned primarily for producing property acquisitions and for gathering and
pipeline infrastructure maintenance and construction.
During 1996, dividends were paid on the Company's common stock totaling
$3.6 million, on the $3.125 convertible preferred stock totaling $2.2 million,
and on the 6% convertible redeemable preferred stock totaling $3.4 million. The
Company has paid quarterly common stock dividends of $0.04 per share since
becoming publicly traded in 1990. The amount of future dividends is determined
by the Board of Directors and is dependent upon a number of factors, including
future earnings, financial condition, and capital requirements.
21
23
OTHER ISSUES AND CONTINGENCIES
Encogen Gas Contract. See Item 3. Legal Proceedings on page 15 for a
discussion of this matter.
Corporate Income Tax. The Company generates tax credits for the
production of certain qualified fuels, including natural gas produced from
tight formations and Devonian Shale. The credit for natural gas from a tight
formation ("tight gas sands") amounts to $0.52 per Mmbtu for natural gas sold
prior to 2003 from qualified wells drilled in 1991 and 1992. A number of wells
drilled in the Appalachian Region during 1991 and 1992 qualified for the tight
gas sands tax credit. The credit for natural gas produced from Devonian Shale
is approximately $1.02 per Mmbtu in 1996. In 1995 and 1996, the Company
completed three transactions to monetize the value of these tax credits,
resulting in revenues of $3.4 million in 1996 and approximately $20 million
over the remaining six years (See Note 18 of the Notes to the Consolidated
Financial Statements for further discussion).
The Company has benefited in the past and may benefit in the future from
the alternative minimum tax ("AMT") relief granted under the Comprehensive
National Energy Policy Act of 1992. The Act repealed provisions of the AMT
requiring a taxpayer's alternative minimum taxable income to be increased on
account of certain intangible drilling costs ("IDC") and percentage depletion
deductions. The repeal of these provisions generally applies to taxable years
beginning after 1992. The repeal of the excess IDC preference cannot reduce a
taxpayer's alternative minimum taxable income by more than 40% of the amount of
such income determined without regard to the repeal of such preference.
Regulations. The Company's operations are subject to various types of
regulation by federal, state and local authorities. See "Regulation of Oil and
Natural Gas Production and Transportation" and "Environmental Regulations" in
the Other Business Matters section of Item 1. Business for a discussion of
these regulations.
Restrictive Covenants. The Company's ability to incur debt, to pay
dividends on its common and preferred stock, and to make certain types of
investments is dependent upon certain restrictive covenants in the Company's
various debt instruments. Among other requirements, the Company's revolving
credit facility specifies 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, 1996 the calculated ratio for 1996 was 4.8 to 1.
CONCLUSION
The Company's financial results depend upon many factors, particularly
the price of natural gas and its ability to market its production on
economically attractive terms. The Company's average 1996 produced natural gas
sales price increased 34% compared to 1995 and is the predominant reason for
its record 1996 earnings and operating cash flow performance since becoming a
public company in 1990. While prices in most regions of the U.S. moved up
sharply in November and December 1996, price volatility in the gas market has
remained prevalent in the last few years, as demonstrated most recently in the
first two months of 1997 with wide price swings in day-to-day trading on the
NYMEX futures market. Given this continued price volatility, management cannot
predict with certainty what pricing levels will be for the rest of 1997 and
beyond. Because future cash flows and earnings are subject to such variables,
there can be no assurance that the Company's operations will provide cash
sufficient to fully fund its capital requirements if prices should return to
the depressed levels of 1995.
While the Company's 1997 plans include an increase in capital spending,
potentially negative changes in industry conditions might require the Company
to adjust its 1997 spending plan to ensure the adequate funding of its capital
requirements, including, among other things, reductions in capital expenditures
or common stock dividends.
22
24
The Company believes its capital resources, supplemented, if necessary,
with external financing, are adequate to meet its capital requirements.
The preceding paragraphs contain forward-looking information. See
FORWARD-LOOKING INFORMATION below.
* * *
FORWARD-LOOKING INFORMATION
The statements regarding future financial performance and results and the
other statements which are not historical facts contained in this report are
forward-looking statements. The words "expect," "project," "estimate,"
"predict" and similar expressions are also intended to identify forward-looking
statements. Such statements involve risks and uncertainties, including, but not
limited to, market factors, market prices (including regional basis
differentials) of natural gas and oil, results for future drilling and
marketing activity, future production and costs and other factors detailed
herein and in the Company's 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 the Company's results of operations, "Net
Income (Loss)" is defined as net income (loss) applicable to common
stockholders. The Company merged its acquired holdings from the WERCO
acquisition, located in the Rocky Mountains and the onshore Gulf Coast, with
the Company's holdings in the Anadarko Region to form the "Western Region" in
1994.
SELECTED FINANCIAL AND OPERATING DATA
(In millions except where specified) 1996 1995 1994
- -----------------------------------------------------------------------------
Net Operating Revenues $ 163.1 $ 121.1 $ 140.3
Operating Expenses 116.0 237.2 125.4
Interest Expense 17.4 24.9 16.7
Net Income (Loss) 15.3 (92.2) (5.4)
Earnings (Loss) Per Share $ 0.67 $ (4.05) $ (0.25)
Natural Gas Production (Bcf)
Appalachia 26.8 27.5 29.7
West 32.0 30.2 28.6
------- ------- -------
Total Company 58.8 57.7 58.3
======= ======= =======
Produced Natural Gas Sales Price ($/Mcf)
Appalachia $ 2.72 $ 2.22 $ 2.42
West $ 2.02 $ 1.33 $ 1.65
Total Company $ 2.34 $ 1.75 $ 2.04
Crude/Condensate
Volume (MBbl) 520 618 687
Price ($/Bbl) $ 21.14 $ 17.95 $ 16.66
23
25
The table below presents the after-tax effects of certain selected items
("selected items") on the Company's results of operations for the three years
ended December 31, 1996.
(In millions) 1996 1995 1994
- ------------------------------------------------------------------------
Net Income (Loss) Before Selected Items $ 12.5 $ (17.3) $ (5.4)
Income tax refund 2.8
SFAS 121 impairment (69.2)
Cost reduction program (4.7)
Columbia settlement 2.6
Decoupled gas price hedges (2.0)
Terminated interest rate swaps (1.6)
------- ------- ------
Net Income (Loss) $ 15.3 $ (92.2) $ (5.4)
======= ======= ======
1996 AND 1995 COMPARED
Net Income (Loss) and Revenues. The Company reported a net income in 1996
of $12.5 million, or $0.55 per share, up $29.8 million, or $1.31 per share,
compared with 1995, excluding the impact of the selected items. The $2.8
million special item, or $0.12 per share, in 1996 related to a $1.8 million tax
refund for percentage depletion claimed for certain periods prior to 1990 and
$1.7 million of interest income ($1.0 million after tax) earned on the refund
amount. The $74.9 million from special items, or $3.29 per share, in 1995
consisted of a $113.8 million charge ($69.2 million after tax) related to the
adoption of SFAS 121, $7.7 million ($4.7 million after tax) for the cost
reduction program and other severance costs, $3.2 million ($2.0 million after
tax) loss related to uncovered gas price hedges and a $2.6 million charge ($1.6
million after tax) to interest expense to close interest rate swap contracts,
offset in part by other revenue of $4.3 million ($2.6 million after tax) in
connection with the sale of a Columbia bankruptcy claim. Excluding the pre-tax
effects of the selected items, operating income and net operating revenues
increased $39 million and $43.1 million, respectively. Natural gas sales
comprised 84%, or $137.5 million, of net operating revenue in 1996. The
increase in net operating revenues was driven primarily by a 34% increase in
the produced natural gas sales price. Net income (loss) and operating income
(loss), excluding selected items, were similarly impacted by the increase in
the produced natural gas sales price, as well as lower depreciation, depletion
& amortization and interest expenses.
Natural gas production volumes were down 0.7 Bcf, or 3%, to 26.8 Bcf in
the Appalachian Region, a result from the low level of drilling activity in
1995 and the sale of non-strategic properties. Natural gas production volumes
were up 1.8 Bcf, or 6%, to 32.0 Bcf in the Western Region due primarily to
Rocky Mountains and Gulf Coast area wells drilled and put on line in the second
and third quarters of 1996.
The average Appalachian natural gas production sales price increased
$0.50 per Mcf, or 23%, to $2.72, increasing net operating revenues by
approximately $13.6 million on 26.8 Bcf of production. In the Western Region,
the average natural gas production sales price increased $0.69 per Mcf, or 52%,
to $2.02, increasing net operating revenues by approximately $22.3 million on
32.0 Bcf of production. The overall weighted average natural gas production
sales price increased $0.59 per Mcf, or 34%, to $2.34.
Crude oil and condensate sales decreased 98 MBbl, or 16%, due primarily
to the low drilling activity in 1995 and the sale of various non-strategic oil
properties in 1995.
Brokered natural gas margin was up $3.1 million to $5.6 million due
primarily to a $0.08 per Mcf increase in the net margin to $0.15 per Mcf, a
result of the higher prices environment in 1996. Brokered volume was comparable
to 1995.
24
26
Operating Expenses. Total operating expenses, excluding the selected
items, were virtually unchanged, increasing $0.4 million. The significant
changes are explained as follows:
o Exploration expense increased $4.5 million due to the $4.1 million
increase in dry hole expense and the $0.4 million increase in
geological and geophysical expenses, a direct result of the increased
capital expenditure program in 1996.
o Depreciation, depletion, amortization and impairment expense
decreased $6.9 million, or 13%, due to a $0.11 per Mcfe decline in
the DD&A rate caused by the 1995 impairment of long-lived assets
which reduced depreciable basis by $113.8 million.
o Taxes other than income increased $1.6 million, or 14%, due primarily
to the increase in natural gas production revenues.
o The cost reduction program in 1995 consisted primarily of a 23% staff
reduction, achieved through early retirement and involuntary
termination programs. The pre-tax charges, a selected item, related
to this action totalled $6.8 million, comprised of $3.8 million in
salary and other severance related expense and a $3.0 million
non-cash charge for curtailments to the pension and postretirement
benefits plans.
Interest expense, excluding selected items, declined $3.1 million, or
14%, due primarily to the absence of the interest rate swaps which effectively
increased interest expense in 1995.
Income tax expense, excluding the selected item, was up $67.4 million due
to the comparable increase in earnings before income tax. The Company's
effective tax rate was virtually unchanged.
1995 AND 1994 COMPARED
Net Income (Loss) and Revenues. The Company reported a net loss in 1995
of $17.3 million, or $0.76 per share, down $11.9 million, or $0.52, compared
with 1994, excluding the impact of the selected items. The $74.9 million from
special items, or $3.29 per share, consisted of a $113.8 million charge ($69.2
million after tax) related to the adoption of SFAS 121, $7.7 million ($4.7
million after tax) for the cost reduction program and other severance costs,
$3.2 million ($2.0 million after tax) loss related to uncovered gas price
hedges and a $2.6 million charge ($1.6 million after tax) to interest expense
to close interest rate swap contracts, offset in part by other revenue of $4.3
million ($2.6 million after tax) in connection with the sale of a Columbia
bankruptcy claim. Excluding the pre-tax effects of the selected items,
operating income and operating revenues decreased $8.7 million and $24.3
million, respectively. Natural gas production revenues comprised 84%, or $101.3
million, of total net operating revenues in 1995. The decrease in total net
operating revenues was driven primarily by a 14% decrease in the average
produced natural gas sales price, and in part by a 1% increase in natural gas
production volumes due to higher gas purchased for resale (up 18%) as discussed
below. Net income (loss) and operating income (loss), excluding selected items,
were similarly impacted by the decline in the average natural gas price, as
well as higher financing costs in connection with the 1994 WERCO and 1993 Emax
acquisitions.
Natural gas production volume in the Appalachian Region was down 2.1 Bcf,
or 7%, to 27.5 Bcf due in part to higher pipeline curtailments and normal
production declines not fully replaced by new production due primarily to
reduced drilling activity in 1995. Natural gas production volumes were up 1.5
Bcf to 30.2 Bcf in the Western Region due primarily to a full year of operating
results from the WERCO acquisition.
The average Appalachian natural gas production sales price decreased
$0.20 per Mcf, or 9%, to $2.22, decreasing net operating revenues by
approximately $5.5 million. In the Western Region, the average natural gas
production sales price decreased $0.32 per Mcf, or 19%, to $1.33, decreasing
net operating revenues by approximately $9.7 million. Because the proportion of
lower priced Western Region production sales volume relative to total Company
production sales volume was up significantly, the weighted average natural gas
production sales price for the total Company decreased $0.29 per Mcf, or 14%,
to $1.75.
Crude oil and condensate sales were virtually unchanged at 618 MBbl.
25
27
Costs and Expenses. Total costs and expenses, excluding the selected
items, decreased $13.5 million, or 6%, due primarily to the following:
o The costs of natural gas decreased $3.9 million to $92.8 million. The
decrease was primarily due to a $0.42 per Mcf decrease in the average
price of gas purchased for resale, partially offset by a 10.4 Bcf
increase in gas purchased for resale (including gas exchanges and
storage).
o Direct operations expense decreased $5.0 million, or 15%, due in
large part to reductions in (1) lease maintenance work and workovers,
(2) field and regional office expenses due primarily to the cost
reduction program, and (3) compressor rental and overhaul expenses.
o Depreciation, depletion, amortization and impairment expense,
excluding the $113.8 million impairment of long-lived assets in
connection with SFAS 121, decreased $2.3 million due primarily to the
decrease in the DD&A rate in the fourth quarter resulting from the
SFAS 121 impairment. Due to the adoption of SFAS 121, the Company's
DD&A rate is expected to decrease in future years by $0.13 per Mcfe.
o General and administrative expense decreased $1.4 million, or 8%, due
largely to costs savings realized from the cost reduction program.
o The cost reduction program, recorded in the first quarter, consisted
primarily of a 23% staff reduction, achieved through early retirement
and involuntary termination programs. The pre-tax charges related to
this action totalled $6.8 million, comprised of $3.8 million in
salary and other severance related expense ($3.6 million paid during
the nine months) and a $3.0 million non-cash charge for the impact of
the staff reduction to the pension and postretirement benefits plans.
o Taxes other than income decreased $0.9 million, or 7.6%, due
primarily to the decline in gas revenue.
Interest expense was up $8.2 million, or 49%, due to the increase in debt
primarily attributable to the WERCO acquisition in 1994 and the Emax
acquisition in 1993.
Income tax benefit was up $54.4 million due to the comparable decrease in
earnings before income tax. The Company's effective tax rate was virtually
unchanged.
26
28
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
- --------------------------------------------------------------------------
Report of Independent Accountants 28
Consolidated Statement of Operations 29
Consolidated Balance Sheet 30
Consolidated Statement of Cash Flows 31
Consolidated Statement of Stockholders' Equity 32
Notes to Consolidated Financial Statements 33
Supplemental Oil & Gas Information (Unaudited) 49
Quarterly Financial Information (Unaudited) 53
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 and other financial information are
prepared in conformity with generally accepted accounting principles and,
accordingly, include certain informed judgements 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.
March 7, 1997 Charles P. Siess, Jr.
Chairman of the Board,
Chief Executive Officer and President
27
29
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE STOCKHOLDERS AND BOARD OF DIRECTORS OF CABOT OIL & GAS CORPORATION:
We have audited the accompanying consolidated balance sheet of Cabot Oil
& Gas Corporation as of December 31, 1996 and 1995, and the related
consolidated statements of operations, stockholders' equity, and cash flows for
each of the three years in the period ended December 31, 1996. 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 in accordance with generally accepted auditing
standards. Those standards 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. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the consolidated financial position of Cabot
Oil & Gas Corporation as of December 31, 1996 and 1995, and the consolidated
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1996, in conformity with generally accepted
accounting principles.
As discussed in Notes 14 and 15 to the consolidated financial statements,
in 1995 the Company changed its method of applying the unit-of-production
method to calculate depreciation and depletion on producing oil and gas
properties, and accounting for the impairment of long-lived assets.
COOPERS & LYBRAND L.L.P.
Houston, Texas
March 7, 1997
28
30
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
Year Ended December 31,
(In thousands, except per share amounts) 1996 1995 1994
- ---------------------------------------------------------------------------------------
NET OPERATING REVENUES
Natural Gas Production $ 137,482 $ 101,260 $ 119,076
Crude Oil and Condensate 10,992 11,089 11,445
Brokered Natural Gas Margin 5,619 2,509 3,802
Other 8,968 6,225 5,972
--------- --------- ---------
163,061 121,083 140,295
OPERATING EXPENSES
Direct Operations 28,361 28,328 33,332
Exploration 12,559 8,031 8,014
Depreciation, Depletion and Amortization 42,689 47,206 51,040
Impairment of Long-Lived Assets (Note 15) -- 113,795 --
Impairment of Unproved Properties 2,701 5,047 3,556
General and Administrative 16,823 16,785 17,278
Cost Reduction Program (Note 12) -- 6,820 --
Taxes Other Than Income 12,826 11,215 12,141
--------- --------- ---------
115,959 237,227 125,361
Gain (Loss) on Sale of Assets 1,685 (614) 79
--------- --------- ---------
INCOME (LOSS) FROM OPERATIONS 48,787 (116,758) 15,013
Interest Expense 17,409 24,885 16,651
--------- --------- ---------
Income (Loss) Before Income Tax Expense 31,378 (141,643) (1,638)
Income Tax Expense (Benefit) 10,554 (55,025) (643)
--------- --------- ---------
NET INCOME (LOSS) 20,824 (86,618) (995)
Dividend Requirement on Preferred Stock 5,566 5,553 4,449
--------- --------- ---------
Net Income (Loss) Applicable to
Common Stockholders $ 15,258 $ (92,171) $ (5,444)
========= ========= =========
Earnings (Loss) Per Share Applicable
to Common Stockholders $ 0.67 $ (4.05) $ (0.25)
========= ========= =========
Average Common Shares Outstanding 22,807 22,775 22,018
========= ========= =========
- ---------
The accompanying notes are an integral part of these consolidated financial
statements.
29
31
CABOT OIL & GAS CORPORATION
CONSOLIDATED BALANCE SHEET
December 31,
(In thousands) 1996 1995
- ------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 1,367 $ 3,029
Accounts Receivable 67,810 42,014
Inventories 8,797 5,596
Other 1,663 1,709
--------- ---------
Total Current Assets 79,637 52,348
PROPERTIES AND EQUIPMENT (Successful Efforts Method) 480,511 474,371
OTHER ASSETS 1,193 1,436
--------- ---------
$ 561,341 $ 528,155
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable $ 56,338 $ 48,122
Accrued Liabilities 16,279 12,759
--------- ---------
Total Current Liabilities 72,617 60,881
LONG-TERM DEBT 248,000 249,000
DEFERRED INCOME TAXES 69,427 62,752
OTHER LIABILITIES 10,593 7,666
COMMITMENTS AND CONTINGENCIES (Note 8)
STOCKHOLDERS' EQUITY
Preferred Stock:
Authorized -- 5,000,000 Shares of $0.10 Par Value
Issued and Outstanding -- $3.125 Cumulative
Convertible Preferred; $50 Stated Value;
692,439 Shares in 1996 and 1995 -- 6% Convertible
Redeemable Preferred; $50 Stated Value; 1,134,000
Shares in 1996 and 1995 183 183
Common Stock:
Authorized -- 40,000,000 Shares of $0.10 Par Value
Issued and Outstanding -- 22,847,345 Shares and
22,783,319 Shares at December 31, 1996 and 1995,
respectively 2,284 2,278
Class B Common Stock:
Authorized -- 800,000 Shares of $0.10 Par Value
No Shares Issued -- --
Additional Paid-in Capital 243,283 242,058
Accumulated Deficit (85,046) (96,663)
--------- ---------
Total Stockholders' Equity 160,704 147,856
--------- ---------
$ 561,341 $ 528,155
========= =========
- ---------
The accompanying notes are an integral part of these consolidated financial
statements.
30
32
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended December 31,
(In thousands) 1996 1995 1994
- --------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss) $ 20,824 $ (86,618) $ (995)
Adjustments to Reconcile Net Income (Loss)
to Cash Provided by Operations:
Depletion, Depreciation, and Amortization 42,689 47,206 51,040
Impairment of Long-Lived Assets -- 113,795 --
Impairment of Unproved Properties 2,701 5,047 3,556
Deferred Income Tax Expense (Benefit) 12,017 (55,055) (796)
Loss (Gain) on Sale of Assets (1,685) 614 (79)
Exploration Expense 12,559 8,031 8,014
Other, Net 176 3,178 (1,535)
Changes in Assets and Liabilities:
Accounts Receivable (25,796) (3,848) (2,870)
Inventories (3,201) 2,788 (2,691)
Other Current Assets 46 (13) (944)
Other Assets 243 (37) (1,306)
Accounts Payable and Accrued Liabilities 11,199 5,838 16,167
Other Liabilities 3,713 565 (258)
--------- --------- ---------
Net Cash Provided by Operations 75,485 41,491 67,303
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (60,719) (24,672) (72,684)
Cost of Major Acquisition(1) -- 8,402 (78,525)
Proceeds from Sale of Assets 5,725 10,291 400
Exploration Expense (12,559) (8,031) (8,014)
--------- --------- ---------
Net Cash Used by Investing (67,553) (14,010) (158,823)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt 6,000 16,000 125,833
Decrease in Debt (7,000) (35,363) (27,000)
Exercise of Stock Options 613 348 654
Preferred Dividends Paid (5,566) (5,566) (3,550)
Common Dividends Paid and Other, Net (3,641) (3,644) (3,541)
--------- --------- ---------
Net Cash Provided (Used) by Financing (9,594) (28,225) 92,396
--------- --------- ---------
Net Increase (Decrease) in Cash and
Cash Equivalents (1,662) (744) 876
Cash and Cash Equivalents, Beginning of Year 3,029 3,773 2,897
--------- --------- ---------
Cash and Cash Equivalents, End of Year $ 1,367 $ 3,029 $ 3,773
========= ========= =========
- ---------
(1) Excludes non-cash consideration of $97.5 million of the Company's common
and preferred stock issued in connection with the WERCO acquisition. See
Note 11 WERCO Acquisition.
The accompanying notes are an integral part of these consolidated financial
statements.
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CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
Retained
Common Preferred Paid-In Earnings
(In thousands) Stock Stock Capital (Deficit) Total
- -------------------------------------------------------------------------------------------
Balance at December 31, 1993 $ 2,058 $ 69 $143,264 $ 8,138 $ 153,529
Net Loss (995) (995)
Exercise of Stock Options 4 650 654
Issuance of Common Stock 213 40,546 40,759
Issuance of Preferred Stock 114 56,586 56,700
Preferred Stock Dividends (4,449) (4,449)
Common Stock Dividends
at $0.16 Per Share (3,551) (3,551)
Tax Benefit of Stock Options 425 425
Other 10 10
------- ----- -------- -------- ---------
Balance at December 31, 1994 2,275 183 241,471 (847) 243,082
------- ----- -------- -------- ---------
Net Loss (86,618) (86,618)
Exercise of Stock Options 3 345 348
Preferred Stock Dividends (5,566) (5,566)
Common Stock Dividends
at $0.16 Per Share (3,631) (3,631)
Stock Grant Vesting 242 242
Other (1) (1)
------- ----- -------- -------- ---------
Balance at December 31, 1995 2,278 183 242,058 (96,663) 147,856
------- ----- -------- -------- ---------
Net Income 20,824 20,824
Exercise of Stock Options 6 607 613
Preferred Stock Dividends (5,566) (5,566)
Common Stock Dividends
at $0.16 Per Share (3,649) (3,649)
Stock Grant Vesting 618 618
Other 8 8
------- ----- -------- -------- ---------
Balance at December 31, 1996 $ 2,284 $ 183 $243,283 $(85,046) $ 160,704
======= ===== ======== ======== =========
- ---------
The accompanying notes are an integral part of these consolidated financial
statements.
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CABOT OIL & GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION
Cabot Oil & Gas Corporation and subsidiaries (the "Company") 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 consolidated financial statements contain the accounts of the Company
after elimination of all significant intercompany balances and transactions.
The results of operations of oil and gas properties purchased in the
acquisition of Washington Energy Resources Company ("WERCO") have been included
with those of the Company since May 2, 1994.
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 that locate proved reserves, are capitalized
Before the Company adopted Statement of Financial Accounting Standard
("SFAS") No. 121 on September 1, 1995, the Company limited the total amount of
unamortized capitalized costs to the value of future net revenues, based on
current prices and costs. Under SFAS 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of", the unamortized
capital costs at a lease level are reduced to fair value if the sum of expected
future net cash flows is less than the net book value (See Note 15 Accounting
For Long-Lived Assets).
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
unit-of-production method using proved developed reserves (See Note 14
Accounting Change). The costs of unproved oil and gas properties are generally
aggregated 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 cost is accrued over the productive
life of the oil and gas properties. The accrued liability for plug and
abandonment cost is included in accumulated depreciation, depletion and
amortization.
Costs of retired, sold or abandoned properties, constituting a part of an
amortization base, are charged to accumulated depreciation, depletion, and
amortization. Accordingly, gain or loss, if any, is recognized only
33
35
when a group of proved properties (or field), constituting 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. Volumetric production is monitored to minimize
these natural gas imbalances. A natural gas imbalance liability is recorded in
other liabilities in the consolidated balance sheet if the Company's excess
takes of natural gas exceed its estimated remaining recoverable reserves for
such properties.
INCOME TAXES
The Company follows the asset and liability method in accounting for
income taxes. Under this method, deferred tax assets and liabilities are
recorded for the estimated future tax consequences attributable to the
differences between the financial carrying amounts of existing assets and
liabilities and their respective tax bases. Deferred tax assets and liabilities
are measured using the tax rate in effect for the year in which those temporary
differences are expected to turn around. The effect of a change in tax rates on
deferred tax assets and liabilities is recognized in the year of the enacted
rate change.
NATURAL GAS MEASUREMENT
The Company records estimated amounts for natural gas revenues and
natural gas purchase costs based on volumetric calculations under its natural
gas sales and purchase contracts. Variances or imbalances resulting from such
calculations are inherent in natural gas sales, production, operation,
measurement, and administration. Management does not believe that differences
between actual and estimated natural gas revenues or purchase costs
attributable to the unresolved variances or imbalances are material.
ACCOUNTS PAYABLE
This account includes credit balances to the extent that checks issued
have not been presented to the Company's bank for payment. These credit
balances included in accounts payable were approximately $10.4 million and $6.2
million at December 31, 1996 and 1995, respectively.
EARNINGS (LOSS) PER COMMON SHARE
Earnings (loss) per common share is computed by dividing net income
(loss), less dividends on preferred stock, by the weighted average number of
shares of common stock ("Common Stock") outstanding during the respective
periods. The dilutive effect of stock options on earnings per common share is
insignificant for all periods and is not included in the computation of
earnings per common share.
Both the $3.125 cumulative convertible preferred stock and the 6%
convertible redeemable preferred stock ("preferred stock"), issued May 1994 and
May 1995, respectively, had an antidilutive effect on earnings per common
share. The preferred stock was determined not to be a common stock equivalent
at the time of issuance.
RISK MANAGEMENT ACTIVITIES
From time to time, the Company enters into certain commodity derivative
contracts as a hedging strategy to manage commodity price risk associated with
its inventories, production or other contractual commitments. The natural gas
price swap is the type of derivative instrument utilized by the Company. A
natural gas price swap is an agreement between two parties to exchange periodic
payments, usually on a monthly basis. One party pays a fixed price while the
other party typically pays a variable price. Notional quantities of natural gas
34
36
are used in each agreement, as the agreements do not involve the physical
exchange or delivery of natural gas. Gains or losses on these hedging
activities are generally recognized over the period that the inventory,
production or other underlying commitment is hedged. Unrealized gains or losses
associated with any natural gas price swap contracts not considered to be a
hedge are recognized currently in the results of operations. See Note 13
Financial Instruments for further discussion.
CASH EQUIVALENTS
The Company considers all highly liquid short-term investments with
original maturities of three months or less to be cash equivalents.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
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 remaining proved oil and gas reserves (see Supplemental Oil and Gas
Information). Actual results could differ from those estimates.
RECLASSIFICATIONS
Certain items within the Consolidated Statement of Operations for the
years ended 1995 and 1994 have been reclassified to conform with the 1996
presentation. Under the new presentation, the Company presents gas revenues
from its equity production net of related costs (principally transportation and
storage costs) in a new revenue item called "Natural Gas Production".
Similarly, the procurement costs related to the purchase and resale (brokered)
activity are netted against the gas revenues and presented in a new item called
"Brokered Natural Gas Margin" in the net operating revenues section.
2. PROPERTIES AND EQUIPMENT
Properties and equipment are comprised of the following:
December 31,
(In thousands) 1996 1995
- ------------------------------------------------------------
Unproved Oil and Gas Properties $ 15,746 $ 12,488
Proved Oil and Gas Properties 811,726 800,373
Gathering and Pipeline Systems 150,910 146,330
Land, Building and Improvements 5,221 5,551
Other 16,028 15,243
--------- ---------
999,631 979,985
Accumulated Depreciation,
Depletion and Amortization (519,120) (505,614)
--------- ---------
$ 480,511 $ 474,371
========= =========
As a component of accumulated depreciation, depletion and amortization,
total accrued future plug and abandonment cost was $14.8 million and $15.0
million at December 31, 1996 and 1995, respectively. The Company believes that
this accrual adequately provides for its estimated future plug and abandonment
cost.
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37
3. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
December 31,
(In thousands) 1996 1995
- ------------------------------------------------------------------------
Accounts Receivable
Trade Accounts $ 63,458 $ 38,119
Other Accounts 5,021 5,138
-------- --------
68,479 43,257
Allowance for Doubtful Accounts (669) (1,243)
-------- --------
$ 67,810 $ 42,014
======== ========
Accounts Payable
Trade Accounts $ 12,277 $ 9,312
Natural Gas Purchases 20,726 12,523
Royalty and Other Owners 13,469 10,842
Capital Costs 5,409 6,518
Dividends Payable 1,391 1,391
Taxes Other Than Income 1,170 749
Gas Price Swaps (Note 13) -- 3,205
Other Accounts 1,896 3,582
-------- --------
$ 56,338 $ 48,122
======== ========
Accrued Liabilities
Employee Benefits $ 4,432 $ 2,506
Taxes Other Than Income 8,407 7,633
Interest Payable 2,188 1,883
Other Accrued 1,252 737
-------- --------
$ 16,279 $ 12,759
======== ========
Other Liabilities
Postretirement Benefits Other Than Pension $ 1,853 $ 2,640
Accrued Pension Cost 4,022 3,144
Taxes Other Than Income and Other 4,718 1,882
-------- --------
$ 10,593 $ 7,666
======== ========
4. INVENTORIES
Inventories are comprised of the following:
December 31,
(In thousands) 1996 1995
- ---------------------------------------------------------
Natural Gas in Storage $ 7,312 $ 4,058
Tubular Goods and Well Equipment 1,677 1,485
Pipeline Exchange Balances (192) 53
------- -------
$ 8,797 $ 5,596
======= =======
5. DEBT AND CREDIT AGREEMENTS
SHORT-TERM DEBT
The Company has a $5.0 million unsecured short-term line of credit with a
bank which it uses as part of its cash management program. The interest rate on
the line of credit is at the bank's prime rate minus 1%. The debt agreement was
established in February 1996, replacing the previous $5 million short-term line
with another bank. Aside from a more favorable rate, prime rate minus 1% versus
prime rate, the terms of the new line of
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38
credit are comparable to the previous line of credit. At December 31, 1996 and
1995, no debt was outstanding under the respective lines.
10.18% NOTES
In May 1990, the Company issued an aggregate principal amount of $80
million of its 12-year 10.18% Notes (the "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 starting in May 1998. The
Company may prepay all or any portion of the indebtedness on any date with a
prepayment premium. Due to the impact of the interest rate swap instruments
obtained in 1993 (see "Interest Rate Swap Agreements" under Note 13 Financial
Instruments), the Company's effective interest rate for the 10.18% Notes in the
year ended December 31, 1995 was 12.6%. This effective rate excluded the $2.6
million charge in December 1995 to terminate the remaining interest rate swaps.
Without the impact of the interest rate swaps, closed in 1995, the effective
interest rate returned to 10.18% in 1996. The 10.18% Notes contain restrictions
on the merger of the Company or any subsidiary with a third party other than
under certain limited conditions, as well as various other restrictive
covenants customarily found in such debt instruments, including a restriction
on the payment of dividends or the repurchase of equity securities. Such
covenants about dividends and equity securities are less restrictive than the
covenants contained in the Credit Facility referred to below.
REVOLVING CREDIT AGREEMENT
In January 1990, the Company entered into an $85 million Revolving Credit
Agreement (the "Credit Facility") with a bank (later expanded to five banks and
a $260 million available line of credit). In 1995, the Company amended its
Credit Facility decreasing the available credit line to $235 million. The
available credit line is subject to adjustment from time-to-time on the basis
of the projected present value (as determined by a petroleum engineer's report
incorporating certain assumptions provided by the lender) of estimated future
net cash flows from certain proved oil and gas reserves and other assets of the
Company. In May 1996, the revolving term under the Credit Facility was extended
one year to June 1998. 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. The margin above the reference rate is presently
equal to 3/4 of 1% for the LIBOR based rate, or 7/8 of 1% for the CD based
rate. The Credit Facility provides for a commitment fee on the unused available
balance at an annual rate of 3/8 of 1% and a commitment fee on the unavailable
balance of the credit line at an annual rate of 1/4 of 1%. The Company's
effective interest rates for the Credit Facility in the years ended December
31, 1996, 1995 and 1994 were 6.6%, 6.8% and 5.7%, respectively. Although the
revolving term of the Credit Facility expires in June 1998, it may be extended
with the banks' approval. If such term is not extended, the indebtedness
outstanding will be payable in 24 quarterly installments. Interest rates are
subject to increase if the indebtedness under the Credit Facility is greater
than 80% of the Company's debt limit of $315 million, as noted below. The
Credit Facility contains various restrictive covenants customarily found in
such facilities, including restrictions (i) prohibiting the merger of the
Company or any subsidiary with a third party other than under certain limited
conditions, (ii) prohibiting the sale of all or substantially all of the
Company's or any subsidiary's assets to a third party, and (iii) requiring a
minimum annual coverage ratio of operating cash flow to interest expense for
the trailing four quarters of 2.8 to 1.0.
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6. EMPLOYEE BENEFIT PLANS
PENSION PLAN
The Company has a non-contributory, defined benefit pension plan covering
all full-time employees. The benefits for this plan are based primarily on
years of service and pay near retirement. Plan assets consist principally of
fixed income investments and equity securities. The Company funds the plan in
accordance with the Employee Retirement Income Security Act of 1974 and
Internal Revenue Code limitations.
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,
1996, 1995 and 1994 are comprised of the following:
(In thousands) 1996 1995 1994
- -------------------------------------------------------------------------------
QUALIFIED:
Current Year Service Cost $ 737 $ 722 $ 901
Interest Accrued on Pension Obligation 744 742 652
Actual Return on Plan Assets (948) (1,327) (428)
Net Amortization 448 934 102
Curtailment Gain -- (376) --
Special Termination Benefit -- 766 --
------- ------- -------
Net Periodic Pension Cost $ 981 $ 1,461 $ 1,227
======= ======= =======
NON-QUALIFIED:
Current Year Service Cost $ 90 $ 63 $ 134
Interest Accrued on Pension Obligation 6 23 32
Net Amortization 34 39 49
Curtailment Loss -- 37 --
Settlement Charge -- 174 --
------- ------- -------
Net Periodic Pension Cost $ 130 $ 336 $ 215
======= ======= =======
The following table sets forth the funded status of the Company's pension
plans at December 31, 1996 and 1995, respectively:
1996 1995
(In thousands) Qualified Non-Qualified Qualified Non-Qualified
- --------------------------------------------------------------------------------------------------
Actuarial Present Value of:
Vested Benefit Obligation $ 6,946 $ 31 $ 6,281 $ 65
Accumulated Benefit Obligation 7,621 81 6,864 83
Projected Benefit Obligation $ 10,960 $ 81 $ 10,069 $ 83
Plan Assets at Fair Value 7,074 -- 6,417 --
-------- -------- -------- --------
Projected Benefit Obligation in Excess
of Plan Assets 3,886 81 3,652 83
Unrecognized Net Gain 1,750 140 1,232 44
Unrecognized Prior Service Cost (950) (386) (1,037) (423)
-------- -------- -------- --------
Accrued (Prepaid) Pension Cost $ 4,686 $ (165) $ 3,847 $ (296)
======== ======== ======== ========
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Assumptions used to determine benefit obligations and pension costs are
as follows:
1996 1995 1994
- ---------------------------------------------------------------------------
Discount Rate 7.50% 7.50%(1) 8.50%
Rate of Increase in Compensation Levels 4.50% 4.50%(1) 5.50%
Long-Term Rate of Return on Plan Assets 9.00% 9.00% 9.00%
- ---------
(1) Represents the rates used to determine the benefit obligation. An 8.5%
discount rate and 5.5% rate of increase in compensation levels were used
to compute pension costs.
SAVINGS INVESTMENT PLAN
The Company has a Savings Investment Plan (the "SIP") which is a defined
contribution plan. The Company matches a portion of employees' contributions.
Participation in the SIP is voluntary and all regular employees of the Company
are eligible to participate. The Company charged to expense plan contributions
of $0.6 million, $0.8 million and $0.9 million in 1996, 1995 and 1994,
respectively. Effective February 1, 1994, the Company's common stock was added
as an investment option within the SIP.
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits ("postretirement benefits") for retired
employees, including their spouses, eligible dependents and surviving spouses
("retirees"). Substantially all employees become eligible for these benefits if
they meet certain age and service requirements at retirement. The Company was
providing postretirement benefits to 295 retirees and 273 retirees at the end
of 1996 and 1995, respectively.
The Company adopted SFAS 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions", in 1992 and elected to amortize the accumulated
postretirement benefit obligation at January 1, 1992 (the "Transition
Obligation") over 20 years.
The amortization benefit of the unrecognized Transition Obligation in
1996, 1995 and 1994, presented in the table below, is due to a cost-cutting
amendment to the postretirement medical benefits in 1993. The amendment
prospectively reduced the unrecognized Transition Obligation by $9.8 million
and is amortized over a 5.75 year period beginning in 1993.
Postretirement benefit costs recognized in the years ended December 31,
1996, 1995 and 1994 are comprised of the following:
(In thousands) 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------
Service Cost of Benefits Earned During the Year $ 99 $ 140 $ 152
Interest Cost on the Accumulated Postretirement Benefit Obligation 522 517 470
Amortization Benefit of the Unrecognized Gain (163) (249) (207)
Amortization Cost (Benefit) of the Unrecognized Transition Obligation (807) (821) (859)
Curtailment Loss -- 2,074 --
Special Termination -- 503 --
------- ------- -------
Total Postretirement Benefit Cost (Benefit) $ (349) $ 2,164 $ (444)
======= ======= =======
The health care cost trend rate used to measure the expected cost in 1997
for medical benefits to retirees over age 65 was 8.4%, graded down to a trend
rate of 0% in 2001. The health care cost trend rate used to measure the
expected cost in 1997 for retirees under age 65 was 9.5%, graded down to a
trend rate of 0% in 2001. Provisions of the plan should prevent further
increases in employer cost after 2001.
The weighted average discount rate used in determining the actuarial
present value of the benefit obligation at December 31, 1996 and 1995 was 7.5%.
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41
A one-percentage-point increase in health care cost trend rates for
future periods would increase the accumulated net postretirement benefit
obligation by approximately $216 thousand and, accordingly, the total
postretirement benefit cost recognized in 1996 would have also increased by
approximately $23 thousand.
The funded status of the Company's postretirement benefit obligation at
December 31, 1996 and 1995 is comprised of the following:
(In thousands) 1996 1995
- --------------------------------------------------------------------------------
Plan Assets at Fair Value $ -- $ --
Accumulated Postretirement Benefits Other Than Pensions
Retirees 5,681 5,512
Active Participants 1,526 1,722
------- -------
7,207 7,234
Unrecognized Cumulative Net Gain 2,614 2,546
Unrecognized Transition Obligation (7,587) (6,779)
------- -------
Accrued Postretirement Benefit Liability $ 2,234 $ 3,001
======= =======
7. INCOME TAXES
Income tax expense (benefit) is summarized as follows:
Year Ended December 31,
(In thousands) 1996 1995 1994
- ---------------------------------------------------------------------------
CURRENT:
Federal $ (1,229) $ -- $ --
State 316 30 153
-------- -------- --------
Total (913) 30 153
-------- -------- --------
DEFERRED:
Federal 9,756 (46,430) (1,987)
State 1,711 (8,625) 1,191
-------- -------- --------
Total 11,467 (55,055) (796)
-------- -------- --------
Total Income Tax Expense (Benefit) $ 10,554 $(55,025) $ (643)
======== ======== ========
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) 1996 1995 1994
- ---------------------------------------------------------------------------------------
Statutory Federal Income Tax Rate 35% 35% 35%
Computed "Expected" Federal Income Tax $ 10,982 $(49,575) $ (574)
State Income Tax, Net of Federal Income Tax 1,317 (5,586) 873
Other, Net (1,745) 136 (942)
-------- -------- --------
Total Income Tax Expense (Benefit) $ 10,554 $(55,025) $ (643)
======== ======== ========
Income taxes for the year ended December 31, 1996 were decreased by $1.8
million due to a federal income tax refund in connection with percentage
depletion claimed in certain periods prior to the Company's IPO in 1990. The
Company also received $1.7 million of interest income in connection with the
income tax refund.
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42
The tax effects of temporary differences that gave rise to significant
portions of the deferred tax liabilities and deferred tax assets as of December
31, 1996 and 1995 were as follows:
(In thousands) 1996 1995
- ----------------------------------------------------------------------------
DEFERRED TAX LIABILITIES:
Property, Plant and Equipment $ 115,099 $ 110,582
--------- ---------
DEFERRED TAX ASSETS:
Alternative Minimum Tax Credit Carryforwards 3,786 4,614
Net Operating Loss Carryforwards 17,708 22,620
Note Receivable on Section 29 Monetization(1) 18,347 15,048
Items Accrued for Financial Reporting Purposes 5,831 5,548
--------- ---------
45,672 47,830
--------- ---------
Net Deferred Tax Liabilities $ 69,427 $ 62,752
========= =========
- ----------
(1) As a result of the monetization of Section 29 tax credits in 1996 and
1995, the Company recorded an asset sale for tax purposes in exchange for
a long-term note receivable which will be repaid through 100% working and
royalty interest in the production from the sold properties.
At December 31, 1996, the Company has a net operating loss carryforward
for regular income tax reporting purposes of $50.1 million which will begin
expiring in 2009. In addition, the Company has an alternative minimum tax
credit carryforward of $3.8 million which does not expire and is available to
offset regular income taxes in future years to the extent that regular income
taxes exceed the alternative minimum tax in any such year. In 1996, the Company
recorded a $5.3 million adjustment reducing deferred tax liabilities for the
reversal of temporary differences associated with the $8.4 million valuation
adjustment received in 1995 on the 1994 WERCO acquisition (See Note 11 WERCO
Acquisition).
8. COMMITMENTS AND CONTINGENCIES
LEASE COMMITMENTS
The Company leases certain transportation vehicles, warehouse facilities,
office space and machinery and equipment under cancelable and non-cancelable
leases, most of which expire within five years and may be renewed by the
Company. Rent expense under such arrangements totalled $4.8 million, $4.9
million and $5.5 million for the years ended December 31, 1996, 1995 and 1994,
respectively. Future minimum rental commitments under non-cancelable leases in
effect at December 31, 1996 are as follows:
(In thousands)
1997 $ 3,364
1998 2,723
1999 1,916
2000 1,051
2001 695
Thereafter 1,080
--------
$ 10,829
========
Minimum rental commitments are not reduced by minimum sublease rental
income of $1.8 million due in the future under non-cancelable subleases.
CONTINGENCIES
The Company is a defendant in various lawsuits and is involved in other
gas contract issues. In the opinion of the Company, final judgements or
settlements, if any, which may be awarded in connection with any one or more of
these suits and claims could be significant to the results of operations and
cash flows of any period but would not have a material adverse effect on the
Company's financial position.
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The Company sells approximately 20% of its natural gas production in the
Western Region to a cogeneration plant owned by Encogen Northwest, L.P.
("Encogen") under a contract containing a fixed price that escalates annually,
a firm delivery arrangement and a term continuing through June 30, 2008.
Encogen has requested that the Company consider restructuring this agreement.
Thus far the Company has been unwilling to restructure the agreement without
full compensation for the agreements value. See Item 3. Legal Proceedings for
further discussion of this matter.
9. CASH FLOW INFORMATION
Cash paid for interest and income taxes is as follows:
Year Ended December 31,
(In thousands) 1996 1995 1994
- ------------------------------------------------------------------------
Interest $ 17,105 $ 24,744 $ 16,002
Income Taxes $ 873 $ 197 $ 210
At December 31, 1996 and 1995, the majority of cash and cash equivalents
is concentrated in one financial institution. Additionally, the Company has
accounts receivable that are subject to credit risk.
10. CAPITAL STOCK
INCENTIVE PLANS
On May 20, 1994, the 1994 Long-Term Incentive Plan and the 1994
Non-Employee Director Stock Option Plan were approved by the shareholders. The
Company has two other stock option plans - the Incentive Stock Option Plan,
adopted in 1990, and the 1990 Non-Employee Director Stock Option Plan. Under
these four plans (the "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 2,660,000
shares of Common Stock, par value $0.10 per share, are subject to issuance
under the Incentive Plans. All stock options have a maximum term of five or ten
years from the date of grant and vest 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,
1996 1995 1994
- ------------------------------------------------------------------
Shares Under Option at
Beginning of Period 1,310,318 953,775 684,525
Granted 311,750 565,750 301,900
Exercised 41,094 2,400 12,050
Surrendered or Expired 48,621 206,807 20,600
--------- --------- ---------
Shares Under Option at
End of Period 1,532,353 1,310,318 953,775
========= ========= =========
Option Price Range per Share $ 13.25 - $ 13.25 - $ 13.25 -
26.00 26.00 26.00
Options Exercisable at End
of Period 1,021,362 852,692 447,907
========= ========= =========
Management has reviewed Statement of Financial Accounting Standards
("SFAS") No. 123, "Accounting for Stock-Based Compensation", which outlines a
fair value based method of accounting for stock options or similar equity
instruments and has opted to continue using the intrinsic value based method,
as prescribed by Accounting Principles Board ("APB") Opinion No. 25, to measure
compensation cost for its stock option plans.
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The pro forma results of operations, had the Company adopted SFAS 123,
were net income of $14.8 million, or $0.65 per share, in 1996 and a net loss of
$92.9 million, or $4.08 per share, in 1995. Under the fair value based method,
the weighted average fair values of options granted during 1996 and 1995 were
$5.51 and $4.52, respectively. The fair value of stock options was calculated
using a Black-Scholes stock option valuation model with the following weighted
average assumptions for grants in 1996 and 1995: stock price volatility of 25.8
percent; risk free rate of return ranging from 6.20 percent to 6.46 percent;
dividend rate of $0.16 per year; and an expected term of 5 years. The fair
value of stock options included in the pro forma results for 1996 and 1995 are
not necessarily indicative of future effects on net income and earnings per
share.
DIVIDEND RESTRICTIONS
The determination of the amount of future cash dividends, if any, to be
declared and paid on the Common Stock will be subject to the discretion of the
Board of Directors of the Company and will depend upon, among other things, the
Company's financial condition, funds from operations, the level of its capital
and exploration expenditures, and its future business prospects. The Company's
10.18% note agreement restricts certain payments ("Restricted Payments," as
defined in the note agreement) associated with (i) purchasing, redeeming,
retiring or otherwise acquiring any capital stock of the Company or any option,
warrant or other right to acquire such capital stock or (ii) declaring any
dividend, if immediately prior to or after giving effect to such payments, the
dividend exceeds consolidated net cash flows, as defined, and the ratio of
proved reserves to debt is less than 1.7 to 1, or an event of default has
occurred under the note agreement. As of December 31, 1996, such restrictions
had no adverse impact on the Company's ability to pay regular dividends.
PURCHASE RIGHTS
On January 21, 1991, the Board of Directors adopted the Preferred Stock
Purchase Rights Plan and declared a dividend distribution of one right for each
outstanding share of Common Stock. Each right becomes exercisable, at a price
of $55, when any person or group has acquired, obtained the right to acquire or
made a tender or exchange offer for beneficial ownership of 15 percent or more
of the Company's outstanding Common Stock, except pursuant to a tender or
exchange offer for all outstanding shares of Common Stock deemed to be fair and
in the best interests of the Company and its stockholders by a majority of the
independent Continuing Directors (as defined in the plan). Each right entitles
the holder, other than the acquiring person or group, to purchase one
one-hundredth of a share of Series A Junior Participating Preferred Stock
("Junior Preferred Stock"), or to receive, after certain triggering events,
Common Stock or other property having a market value (as defined in the plan)
of twice the exercise price of each right. After the rights become exercisable,
if the Company is acquired in a merger or other business combination in which
it is not the survivor or 50 percent or more of the Company's assets or earning
power are sold or transferred, 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, 1996,
there were no shares of Junior Preferred Stock issued.
The rights, which expire on January 21, 2001, and the exercise price are
subject to adjustment and may be redeemed by the Company for $0.01 per right at
any time before they become exercisable. Under certain circumstances, the
Continuing Directors may opt to exchange one share of Common Stock for each
exercisable right.
PREFERRED STOCK
At December 31, 1996 and 1995, 692,439 shares of the Company's $3.125
cumulative convertible preferred stock ("$3.125 preferred stock") were issued
and outstanding. Each share has a stated value of $50 and is convertible any
time by the holder into Common Stock at a conversion price of $21 per share,
subject to adjustment. The $3.125 preferred stock is redeemable by the Company
for a stated redemption price per share, starting at $55 per share in 1993 and
declining to $50 per share in 2003, plus accrued dividends. Prior to May 31,
1997, the Company's option to redeem the $3.125 preferred stock is subject to a
provision that the Common Stock closing price must equal at least 130% of the
conversion price for 20 of 30 consecutive trade days. The
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Company also has the option to convert the $3.125 preferred stock to Common
Stock at the conversion price provided the Company has the right to redeem the
$3.125 preferred stock, as described above, and the closing price of the Common
Stock is at least equal to the conversion price for 20 consecutive trading
days.
At December 31, 1996 and 1995, 1,134,000 shares of 6% convertible
redeemable preferred stock ("6% preferred stock") were issued and outstanding
(See Note 11 WERCO Acquisition). Each share has voting rights equal to
approximately 1.7 shares of Common Stock, a stated value of $50 and is
convertible by the holder, at any time at least five days prior to the date
fixed for redemption by the Company's Board of Directors, into Common Stock at
a conversion price of $28.75 per share, subject to adjustment. Starting on May
2, 1998, the 6% preferred stock is redeemable, in whole or in part, at the
Company's option price of $50 per share. Commencing May 2, 1998 and continuing
until May 2, 1999, the Company may redeem the 6% preferred stock at $50 per
share, payable in Common Stock, using the market price of the Common Stock on
the date redeemed, plus a cash payment for the accrued dividends due on the
shares redeemed. On or after May 2, 1999, the $50 per share redemption price is
payable in cash, plus a cash payment for accrued dividends due on the shares
redeemed.
11. WERCO ACQUISITION
On May 2, 1994, the Company completed the merger between a Company
subsidiary and Washington Energy Resources Company ("WERCO"), a wholly-owned
subsidiary of Washington Energy Company. The Company acquired the stock of
WERCO in a tax-free exchange. Total capitalized costs related to the
acquisition were $202.5 million, comprised of cash and stock consideration of
$167.6 million (net of an $8.4 million post-closing adjustment in 1995) and a
$34.9 million non-cash component (net of a $5.3 million reduction in 1996
related to the 1995 post-closing adjustment) in connection with the deferred
income taxes attributable to the differences between the tax and book bases of
the acquired properties, as required by SFAS 109, "Accounting for Income
Taxes". The acquisition was recorded using the purchase method. The oil and gas
properties are located in the Green River Basin of Wyoming and in the Gulf
Coast.
The Company issued 2,133,000 shares of Common Stock and 1,134,000 shares
of 6% convertible redeemable preferred stock ($50 per share stated value) to
Washington Energy Company in exchange for the capital stock of WERCO.
The $8.4 million post-closing adjustment was a net cash payment received
in 1995 related to a valuation adjustment and was recorded as a reduction to
the net book value of certain of the oil and gas properties acquired. In 1996,
the net book value of certain oil and gas properties was further reduced by a
$5.3 million non-cash adjustment. This adjustment was to record the reversal of
the differences between the tax and book basis related to the 1995 post-closing
adjustment.
12. COST REDUCTION PROGRAM
In January 1995, the Company announced a cost reduction program which
included a voluntary early retirement program, a 15% targeted reduction in work
force and a consolidation of management in the Rocky Mountain, Anadarko and
onshore Gulf Coast areas into a single Western Region. Accordingly, the Company
recognized a liability and charged to expense $6.8 million in termination
benefits for 115 employees, or 23% of the total work force, including 24
employees who elected early retirement. The employee termination's were made in
virtually all departments both at the Company's corporate headquarters and each
of the operating region/area offices. The termination benefits included $3.8
million for severance and related costs, which were paid out by year end and a
$3.0 million non-cash charge for curtailments to the Company's pension ($0.4
million) and postretirement ($2.6 million) benefits plans.
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13. FINANCIAL INSTRUMENTS
The following disclosures on the estimated fair value of financial
instruments are presented in accordance with SFAS 107, "Disclosures about Fair
Value of Financial Instruments". Fair value, as defined in SFAS 107, is the
amount at which the instrument could be exchanged currently between willing
parties. The Company uses available marketing data and valuation methodologies
to estimate fair value of debt.
December 31, 1996 December 31, 1995
Carrying Estimated Carrying Estimated
(In thousands) Amount Fair Value Amount Fair Value
- -----------------------------------------------------------------------------------
DEBT:
10.18% Notes $ 80,000 $ 86,433 $ 80,000 $ 89,258
Credit Facility 168,000 168,000 169,000 169,000
--------- --------- --------- ---------
$ 248,000 $ 254,433 $ 249,000 $ 258,258
========= ========= ========= =========
OTHER FINANCIAL INSTRUMENTS:
Gas Price Swaps -- $ 763 -- $ (4,176)
LONG-TERM DEBT
The fair value of long-term debt is the estimated cost to acquire the
debt, including a premium or discount for the differential between the issue
rate and the year-end market rate. The fair value of the 10.18% Notes is based
upon interest rates available to the Company. The Credit Facility and the
short-term line approximate fair value because these instruments bear interest
at rates based on current market rates.
INTEREST RATE SWAP AGREEMENTS
In November 1993, the Company executed reverse interest rate swap
agreements with four banks that effectively converted the Company's $80 million
fixed rate notes into variable rate notes. Under the swap agreements, the
Company paid a variable rate of interest that was based on the six-month LIBOR.
The banks paid the Company fixed rates of interest that average 5.00%. The four
agreements had notional principal of $20 million each with terms of two, three,
four and five years. The fair value was determined by obtaining termination
values from third parties.
In January 1995, the Company entered into four additional swap agreements
which effectively fixed interest payments on the original interest rate swaps
until May 1997. In 1995, the Company recorded $4.5 million of interest expense
related to these swap agreements including a $2.6 million charge in December
1995 when cash payments were made to close out the remaining swap positions.
GAS PRICE SWAPS
The Company has entered into several price swap agreements with
counterparties. In a majority of the natural gas price swap agreements, the
Company receives a fixed price ("fixed price swap contracts") for a notional
quantity of natural gas in exchange for its paying a variable price based on a
market based index, such as the NYMEX gas futures. The fixed price swap
contracts are used to hedge price risk associated with the Company's
production. During 1996, the fixed prices received on closed contracts ranged
from $1.02 to $2.54 per Mmbtu on total notional quantities of 17,600,000 Mmbtu.
There were no fixed price swap contracts open at December 31, 1996.
Certain of the fixed price swap contracts, open at December 31, 1995,
became 'uncovered' due to an unprecedented decoupling of the NYMEX gas prices
from realizable sales prices in the physical markets. These 'uncovered' hedge
contracts had notional quantities totaling 5,480,000 Mmbtu and covered the
contract months of January to April 1996. Accordingly, the Company recorded a
$3.2 million unrealized loss at December 31, 1995. Excluding the 'uncovered'
hedge contracts, the estimated fair value of price swaps in the table above are
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for hedged transactions in which gains or losses are recognized in results of
operations over the periods that production or purchased gas is hedged (see
"Risk Management Activities" under Note 1).
After entering into certain fixed price sales contracts to meet the needs
of its customers, the Company opened gas swap agreements to convert these fixed
price contracts to market-sensitive price contracts. During 1996, these
agreements had total notional quantities of 1,002,000 Mmbtu in closed contracts
and another 744,000 Mmbtu in open contracts at December 31, 1996.
The Company is exposed to market risk on these open contracts to the
extent of changes in market prices for natural gas. However, the market risk
exposure on these hedged contracts is generally offset by the gain or loss
recognized upon the ultimate sale of the natural gas that is hedged.
CREDIT RISK
Although notional contract amounts are used to express the volume of gas
price and interest rate swap agreements, the amounts potentially subject to
credit risk, in the event of non-performance by third parties, are
substantially smaller. The Company does not anticipate any material impact to
its financial results due to non-performance by the third parties.
14. ACCOUNTING CHANGE
Effective January 1, 1995, the Company changed from the
property-by-property basis to the field basis of applying the
unit-of-production method to calculate depreciation and depletion on producing
oil and gas properties. The field basis provides for the aggregation of wells
that have a common geological reservoir or field. The field basis provides a
better matching of expenses with revenues over the productive life of the
properties, and, therefore, the Company believes the new method is preferable
to the property-by-property basis. Because the cumulative effect of the change
in method from prior periods was insignificant, a pre-tax charge of $303
thousand, such amount ("pre-1995 amount") was included with depreciation,
depletion and amortization ("DD&A") expense in 1995. The net effect of the
change in method resulted in a $3,967 thousand decrease in DD&A expense and a
$2,428 thousand increase in net earnings in 1995, including the impact of the
pre-1995 amount. The pro forma impact on the results of operations in 1994, had
the change in method been implemented at the beginning of 1994, would have been
a decrease in DD&A expense of approximately $2,378 thousand and a $1,446
thousand increase in net earnings. The reduction in DD&A expense for 1995 due
to the change in method was offset by higher levels of DD&A expense primarily
due to reserve revisions.
15. ACCOUNTING FOR LONG-LIVED ASSETS
Effective September 30, 1995, the Company adopted SFAS No. 121
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to be Disposed Of". SFAS 121 requires that an impairment loss be recognized
when the carrying amount of an asset exceeds the sum of the undiscounted
estimated future cash flow of the asset. Under SFAS 121, the Company reviewed
the impairment of oil and gas properties and related assets on an economic unit
basis. For each economic unit determined to be impaired, an impairment loss
equal to the difference between the carrying value and the fair value of the
economic unit was recognized. Fair value, on an economic unit basis, was
estimated to be the present value of expected future net cash flows over the
economic lives of the reserves. As a result of the adoption of SFAS 121, the
Company recognized a non-cash charge during the third quarter of $113.8 million
($69.2 million after tax).
16. SALE OF NON-CORE OIL AND GAS PROPERTIES
The Company sold various non-core oil and gas properties in the
Appalachian Region, receiving proceeds of $4.6 million, in 1996 and in the
Western Region, obtaining proceeds of $7.6 million, in 1995.
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17. OTHER REVENUE
The Company recorded $4.6 million ($4.3 million net of severance taxes)
in 1995 in other revenue in connection with the sale of certain Columbia Gas
Transmission Corporation ("Columbia") bankruptcy claims. The claims related to
the remaining value of gas sales in contracts terminated by Columbia as part of
its bankruptcy filing in 1991.
18. MONETIZATION OF SECTION 29 TAX CREDITS
The Company completed two transactions in September and November 1995 and
a third transaction in August 1996 to monetize the value of Section 29 tax
credits from most of its qualifying Appalachian and Rocky Mountain properties.
The transactions provided up-front cash of $2.8 million in 1995 and $0.6
million in 1996 which was recorded as a reduction to the net book value of
natural gas properties, and will generate additional revenues through 2002
estimated at $23 million ($3.4 million in 1996) related to the value of future
Section 29 tax credits attributable to these properties. Employing a volumetric
production payment structure, the production, revenues, expenses and proved
reserves related to these properties will continue to be reported by the
Company until the production payment is satisfied.
19. SUPPLEMENTAL FULL COST ACCOUNTING INFORMATION
U.S. oil and gas producing entities may utilize one of two methods of
financial accounting: successful efforts or full cost. Given the current
composition of the Company's properties, management considers the successful
efforts method to be more appropriate than the full cost method primarily
because the successful efforts method results in moderately better matching of
costs and revenues. It has come to management's attention that certain users of
the Company's financial statements believe that information about the Company,
prepared under the full cost method, would be useful. As a result, management
has presented the following supplemental full cost information.
Successful efforts methodology is explained in Note 1. Summary of
Significant Accounting Policies.
Under the full cost method of accounting, all costs incurred in the
acquisition, exploration and development of oil and gas properties are
capitalized. Such capitalized costs and estimated future development and
dismantlement costs are amortized on a unit-of-production method based on
proved reserves. Net capitalized costs of oil and gas properties are limited to
the lower of unamortized cost or the cost center ceiling, defined as: (1) the
present value (10% discount rate) of estimated unescalated future net revenues
from proved reserves, plus (2) the cost of properties not being amortized, plus
(3) the lower of cost or estimated fair value of unproved properties included
in the costs being amortized, minus (4) the deferred tax liabilities for the
temporary differences between the book and tax basis of oil and gas properties.
Proceeds from the sale of oil and gas properties are applied to reduce the
costs in the cost center unless the sale involves a significant quantity of
reserves in relation to the cost center, in which case a gain or loss is
recognized. Unevaluated properties and associated costs not currently being
amortized and included in oil and gas properties totaled $15.7 million, $12.5
million, and $20.8 million at December 31, 1996, 1995, and 1994, respectively.
Because of the capital cost limitations, described above, full cost
entities are not subject to the impairment test prescribed by SFAS 121 (see
Note 15. Accounting for Long-Lived Assets).
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1996 1995 1994
--------------------- ------------------------ ------------------------
Successful Full Successful Full Successful Full
(In thousands, except per share amounts) Efforts Cost Efforts Cost Efforts Cost
- -------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET:
Properties and Equipment, Net $ 480,511 $ 657,957 $ 474,371 $ 646,322 $ 634,934 $ 684,114
Stockholders' Equity 160,704 269,833 147,856 253,606 243,082 273,328
INCOME STATEMENT:
Depreciation, Depletion, Amortization
and Unproved Property Impairment $ 45,390 $ 50,769 $ 52,253 $ 51,922 $ 54,596 $ 56,027
Impairment of Long-Lived Assets -- -- 113,795 -- -- --
Impairment - Full Cost Ceiling -- -- -- -- -- 76,100
Net Income (Loss) Applicable
to Common Stockholders 15,258 18,637 (92,171) (17,481) (5,444) (48,245)
Earnings (Loss) Per Share $ 0.67 $ 0.82 $ (4.05) $ (0.77) $ (0.25) $ (2.19)
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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. Consequently,
material revisions to existing reserve estimates may occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the significance of
the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with 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 existing at the time the estimates were
made.
Proved developed reserves are proved reserves expected to be recovered
through wells and equipment in place and under operating methods being utilized
at the time the estimates were made.
Estimates of proved and proved developed reserves at December 31, 1996,
1995 and 1994 were based on studies performed by the Company's petroleum
engineering staff. The estimates prepared by the Company's engineering staff
were reviewed by Miller and Lents, Ltd., who indicated in their recent letter
dated February 10, 1997 that, based on their investigation and subject to the
limitations described in such letter, it was their judgement that the results
of those estimates and projections for 1996 were reasonable in the aggregate.
No major discovery or other favorable or adverse event subsequent to
December 31, 1996 is believed to have caused a material change in the estimates
of proved or proved developed reserves as of that date.
The following table sets forth the Company's net proved reserves,
including changes therein, and proved developed reserves for the periods
indicated, as estimated by the Company's engineering staff. All reserves are
located in the United States (more than 99%) or Canada.
Natural Gas
-------------------------------------
December 31,
(Millions of cubic feet) 1996 1995 1994
- ------------------------------------------------------------------------------------------
PROVED RESERVES
Beginning of Year 889,850 953,083 808,280
Revisions of Prior Estimates 2,774 14,032 (24,627)
Extensions, Discoveries and Other Additions 69,708 34,408 64,829
Production (58,762) (57,721) (58,319)
Purchases of Reserves in Place 37,397 1,416 168,957
Sales of Reserves in Place (25,350) (55,368) (6,037)
--------- --------- ---------
End of Year 915,617 889,850 953,083
========= ========= =========
PROVED DEVELOPED RESERVES 768,097 747,235 805,913
========= ========= =========
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Liquids
----------------------------------------
December 31,
(Thousands of barrels) 1996 1995 1994
- ----------------------------------------------------------------------------------------------
PROVED RESERVES
Beginning of Year 5,310 8,036 2,826
Revisions of Prior Estimates (132) (648) (98)
Extensions, Discoveries and Other Additions 386 174 181
Production (597) (740) (824)
Purchases of Reserves in Place 215 15 5,992
Sales of Reserves in Place (16) (1,527) (41)
-------- -------- --------
End of Year 5,166 5,310 8,036
======== ======== ========
PROVED DEVELOPED RESERVES 4,685 4,970 7,704
======== ======== ========
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
The following table sets forth the aggregate amount of capitalized costs
relating to natural gas and crude oil producing activities and the aggregate
amount of related accumulated depreciation, depletion and amortization.
Year Ended December 31,
(In thousands) 1996 1995 1994
- ------------------------------------------------------------------------------
Aggregate Capitalized Costs Relating
to Oil and Gas Producing Activities $ 997,531 $ 977,885 $ 980,676
Aggregate Accumulated Depreciation,
Depletion and Amortization $ 517,249 $ 503,757 $ 346,080
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) 1996 1995 1994
- ------------------------------------------------------------------------------------
Property Acquisition Costs - Proved $ 6,637 $ 33 $ 184,835
Property Acquisition Costs - Unproved 4,355 2,006 4,685
Exploration and Extension Well Costs 14,192 8,670 9,402
Development Costs 41,036 18,610 46,463
--------- --------- ---------
Total costs $ 66,220 $ 29,319 $ 245,385
========= ========= =========
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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) 1996 1995 1994
- --------------------------------------------------------------------------
Operating Revenues $ 150,096 $ 110,418 $ 126,307
Costs and Expenses
Production 35,161 34,062 39,114
Other Operating 15,155 22,783 16,787
Exploration 12,559 8,031 8,014
Depreciation, Depletion and
Amortization 40,810 161,886 48,075
--------- --------- ---------
Total Cost and Expenses 103,685 226,762 111,990
--------- --------- ---------
Income (Loss) Before Income Taxes 46,411 (116,344) 14,317
Provision for Income Taxes
Expense (Benefit) 16,244 (40,720) 5,011
--------- --------- ---------
Results of Operations $ 30,167 $ (75,624) $ 9,306
========= ========= =========
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES
The following information has been developed utilizing procedures
prescribed by SFAS 69 and based on natural gas and crude oil reserve and
production volumes estimated by the Company's engineering staff. It may be
useful for certain comparison purposes, but should not be solely relied upon in
evaluating the Company or its performance. Further, information contained in
the following table should not be considered as representative of 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 in reviewing the following information: (i) future costs and selling
prices will probably differ from those required to be used in these
calculations; (ii) due to future market conditions and governmental
regulations, actual rates of production achieved in future years may vary
significantly from the rate of production assumed in the calculations; (iii)
selection of a 10% discount rate is arbitrary and may not be reasonable as a
measure of the relative risk inherent in realizing future net oil and gas
revenues; and (iv) 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, 1996, 1995
and 1994 were for oil ($/Bbl) $22.86, $17.06 and $18.34, respectively, and for
natural gas ($/Mcf) $3.55, $2.06 and $1.88, respectively. Future cash inflows
were reduced by estimated future development and production costs based on
year-end costs in order to arrive at net cash flow before tax. Future income
tax expense has been computed by applying year-end statutory tax rates to
future pretax net cash flows, reduced by the tax basis of the properties
involved. Use of a 10% discount rate is required by SFAS 69.
Management does not rely solely upon the following information in making
investment and operating decisions. Such decisions are based upon a wide range
of factors, including estimates of probable as well as proved reserves, and
varying price and cost assumptions considered more representative of a range of
possible economic conditions that may be anticipated.
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Standardized Measure is as follows:
Year Ended December 31,
(In thousands) 1996(1) 1995(1) 1994
- ------------------------------------------------------------------------------------------
Future Cash Inflows $ 3,528,558 $ 2,194,751 $ 2,219,559
Future Production and
Development Costs (773,631) (644,586) (723,767)
----------- ----------- -----------
Future Net Cash Flows Before
Income Taxes 2,754,927 1,550,165 1,495,792
10% Annual Discount for
Estimated Timing of Cash Flows (1,589,290) (884,861) (880,130)
----------- ----------- -----------
Standardized Measure of
Discounted Future Net Cash Flows
Before Income Taxes 1,165,637 665,304 615,662
Future Income Tax Expenses,
Net of 10% Annual Discount(2) (331,331) (152,356) (125,167)
----------- ----------- -----------
Standardized Measure of Discounted
Future Net Cash Flows $ 834,306 $ 512,948 $ 490,495
=========== =========== ===========
(1) Includes the future cash inflows, production costs and development costs,
as well as the tax basis, relating to the properties included in the
transactions to monetize the value of Section 29 tax credits. See Note 18
of the Notes to the Consolidated Financial Statements.
(2) Future income taxes before discount were $887,583, $462,058 and $433,212
for the years ended December 31, 1996, 1995 and 1994, 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) 1996 1995 1994
- ------------------------------------------------------------------------------------------
Beginning of Year $ 512,948 $ 490,495 $ 467,900
Discoveries and Extensions,
Net of Related Future Costs 99,983 21,881 24,188
Net Changes in Prices and
Production Costs 416,042 57,057 (133,750)
Accretion of Discount 66,530 61,566 64,110
Revisions of Previous Quantity
Estimates, Timing and Other (7,874) 1,707 (32,654)
Development Costs Incurred 10,294 5,665 16,631
Sales and Transfers, Net of
Production Costs (114,935) (76,356) (87,193)
Net Purchases (Sales) of
Reserves in Place 30,293 (21,878) 123,232
Net Change in Income Taxes (178,975) (27,189) 48,031
--------- --------- ---------
End of Year $ 834,306 $ 512,948 $ 490,495
========= ========= =========
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54
CABOT OIL & GAS CORPORATION
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
(In thousands except per share amounts) First Second Third Fourth Total
- ---------------------------------------------------------------------------------------------------------------
1996
Net Operating Revenues $ 41,198 $ 37,346 $ 35,497 $ 49,020 $ 163,061
Operating Income 15,929 8,615 7,577 16,666 48,787
Net Income 5,258 853 2,974 6,173 15,258
Earnings Per Share $ 0.23 $ 0.04 $ 0.13 $ 0.27 $ 0.67
1995
Net Operating Revenues $ 32,587 $ 29,621 $ 29,623 $ 29,252 $ 121,083
Operating Income (Loss) (5,366) (680) (111,708)(1) 996 (116,758)
Net Loss (8,200) (5,291) (73,309)(1) (5,371) (92,171)
Loss Per Share $ (0.36) $ (0.23) $ (3.22) $ (0.24) $ (4.05)
- ----------
(1) Includes a $113.8 million charge ($69.2 million after tax) for the
impairment of long-lived assets resulting from the adoption of SFAS 121.
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 to be set forth under the caption "Election of Directors"
in the Company's definitive proxy statement ("Proxy Statement") in connection
with the 1997 annual stockholders meeting is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information appearing under the caption "Executive Compensation" in
the Proxy Statement is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information appearing under the captions "Beneficial Ownership of
Over Five Percent of Common Stock" and "Beneficial Ownership of Directors and
Executive Officers" in the Proxy Statement is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
53
55
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES AND REPORTS ON FORM 8-K
A. INDEX
1. CONSOLIDATED FINANCIAL STATEMENTS
See Index on page 27
2. FINANCIAL STATEMENT SCHEDULES
None
3. EXHIBITS
The following instruments are included as exhibits to this report. Those
exhibits below incorporated by reference herein are indicated as such by the
information supplied in the parenthetical thereafter. If no parenthetical
appears after an exhibit, copies of the instrument have been included herewith.
Exhibit
Number Description
- --------------------------------------------------------------------------------
3.1 Certificate of Incorporation of the Company (Registration Statement No.
33-32553).
3.2 Amended and Restated Bylaws of the Company adopted August 5, 1994.
4.1 Form of Certificate of Common Stock of the Company (Registration Statement
No. 33-32553).
4.2 Certificate of Designation for Series A Junior Participating Preferred
Stock (Form 10-K for 1994).
4.3 Rights Agreement dated as of March 28, 1991 between the Company and The
First National Bank of Boston, as Rights Agent, which includes as Exhibit
A the form of Certificate of Designation of Series A Junior Participating
Preferred Stock (Form 8-A, File No. 1-10477).
(a) Amendment No. 1 to the Rights Agreement dated February 24, 1994 (Form
10-K for 1994).
4.4 Certificate of Designation for $3.125 Convertible Preferred Stock (Form
10-K for 1993).
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.
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 Certificate of Designation for 6% Convertible Redeemable Preferred Stock
(Form 10-K for 1994).
10.1 Supplemental Executive Retirement Agreement between the Company and
Charles P. Siess, Jr. (Form 10-K for 1995).
10.2 Form of Change in Control Agreement between the Company and Certain
Officers (Form 10-K for 1995).
10.3 Letter Agreement dated January 11, 1990 between Morgan Guaranty Trust
Company of New York and the Company (Registration Statement No. 33-32553).
10.4 Form of Annual Target Cash Incentive Plan of the Company (Registration
Statement No. 33-32553).
10.5 Form of Incentive Stock Option Plan of the Company (Registration Statement
No. 33-32553).
(a) First Amendment to the Incentive Stock Option Plan (Post-Effective
Amendment No. 1 to S-8 dated April 26, 1993).
10.6 Form of Stock Subscription Agreement between the Company and certain
executive officers and directors of the Company (Registration Statement
No. 33-32553).
10.7 Transaction Agreement between Cabot Corporation and the Company dated
February 1, 1991 (Registration Statement No. 33-37455).
54
56
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. (incorp. by ref. 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.
10.11 Supplemental Executive Retirement Agreements of the Company (Form 10-K
for 1991).
10.12 Settlement Agreement and Mutual Release (Tax Issues) between Cabot
Corporation and the Company dated July 7, 1992 (Form 10-Q for the quarter
ended June 30, 1992).
10.13 Agreement of Merger dated February 25, 1994 among Washington Energy
Company, Washington Energy Resources Company, the Company and COG
Acquisition Company (Form 10-K for 1993).
10.14 1990 Nonemployee Director Stock Option Plan of the Company (Form S-8
dated June 23, 1990)
(a) First Amendment to 1990 Nonemployee Director Stock Option Plan
(Post-Effective Amendment No. 2 to Form S-8 dated March 7, 1994).
(b) Second Amendment to 1990 Nonemployee Director Stock Option Plan (Form
10-K for 1995).
10.15 1994 Long-Term Incentive Plan of the Company (Form S-8 dated May 20,
1994 - Registration Statement No. 33-53723).
10.16 1994 Nonemployee Director Stock Option Plan (Form S-8 dated May 20, 1994 -
Registration Statement No. 33-53723).
10.17 Employment Agreement between the Company and Ray R. Seegmiller dated
September 25, 1995 (Form 10-K for 1995).
21.1 Subsidiaries of Cabot Oil & Gas Corporation.
23.1 Consent of Coopers & Lybrand L.L.P.
23.2 Consent of Miller and Lents, Ltd.
27 Financial Data Schedule.
28.1 Miller and Lents, Ltd. Review Letter dated February 10, 1997.
B. REPORTS ON FORM 8-K
None
55
57
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 10th of March 1997.
CABOT OIL & GAS CORPORATION
By: /s/ Charles P. Siess, Jr.
--------------------------------
Charles P. Siess, Jr.
Chairman of the Board, Chief
Executive Officer and President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons in the capacities and on
the dates indicated.
Signature Title Date
- ------------------------------------------------------------------------------------------------------------
/s/ Charles P. Siess, Jr. Chairman of the Board, March 10, 1997
- -------------------------------- Chief Executive Officer and President
Charles P. Siess, Jr
(Principal Executive Officer)
/s/ Ray R. Seegmiller Executive Vice President, Chief Operating March 10, 1997
- -------------------------------- Officer and Treasurer
Ray R. Seegmiller
/s/ Paul F. Boling Controller (Principal Accounting Officer) March 10, 1997
- --------------------------------
Paul F. Boling
/s/ Robert F. Bailey Director March 10, 1997
- --------------------------------
Robert F. Bailey
/s/ Samuel W. Bodman Director March 10, 1997
- --------------------------------
Samuel W. Bodman
/s/ Henry O. Boswell Director March 10, 1997
- --------------------------------
Henry O. Boswell
/s/ John G. L. Cabot Director March 10, 1997
- --------------------------------
John G. L. Cabot
/s/ William R. Esler Director March 10, 1997
- --------------------------------
William R. Esler
/s/ William H. Knoell Director March 10, 1997
- --------------------------------
William H. Knoell
/s/ C. Wayne Nance Director March 10, 1997
- --------------------------------
C. Wayne Nance
/s/ William P. Vititoe Director March 10, 1997
- --------------------------------
William P. Vititoe
56
58
INDEX TO EXHIBITS
Exhibit
Number Description
- --------------------------------------------------------------------------------
3.1 Certificate of Incorporation of the Company (Registration Statement No.
33-32553).
3.2 Amended and Restated Bylaws of the Company adopted August 5, 1994.
4.1 Form of Certificate of Common Stock of the Company (Registration Statement
No. 33-32553).
4.2 Certificate of Designation for Series A Junior Participating Preferred
Stock (Form 10-K for 1994).
4.3 Rights Agreement dated as of March 28, 1991 between the Company and The
First National Bank of Boston, as Rights Agent, which includes as Exhibit
A the form of Certificate of Designation of Series A Junior Participating
Preferred Stock (Form 8-A, File No. 1-10477).
(a) Amendment No. 1 to the Rights Agreement dated February 24, 1994 (Form
10-K for 1994).
4.4 Certificate of Designation for $3.125 Convertible Preferred Stock (Form
10-K for 1993).
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.
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 Certificate of Designation for 6% Convertible Redeemable Preferred Stock
(Form 10-K for 1994).
10.1 Supplemental Executive Retirement Agreement between the Company and
Charles P. Siess, Jr. (Form 10-K for 1995).
10.2 Form of Change in Control Agreement between the Company and Certain
Officers (Form 10-K for 1995).
10.3 Letter Agreement dated January 11, 1990 between Morgan Guaranty Trust
Company of New York and the Company (Registration Statement No. 33-32553).
10.4 Form of Annual Target Cash Incentive Plan of the Company (Registration
Statement No. 33-32553).
10.5 Form of Incentive Stock Option Plan of the Company (Registration Statement
No. 33-32553).
(a) First Amendment to the Incentive Stock Option Plan (Post-Effective
Amendment No. 1 to S-8 dated April 26, 1993).
10.6 Form of Stock Subscription Agreement between the Company and certain
executive officers and directors of the Company (Registration Statement
No. 33-32553).
10.7 Transaction Agreement between Cabot Corporation and the Company dated
February 1, 1991 (Registration Statement No. 33-37455).
59
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. (incorp. by ref. 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.
10.11 Supplemental Executive Retirement Agreements of the Company (Form 10-K
for 1991).
10.12 Settlement Agreement and Mutual Release (Tax Issues) between Cabot
Corporation and the Company dated July 7, 1992 (Form 10-Q for the quarter
ended June 30, 1992).
10.13 Agreement of Merger dated February 25, 1994 among Washington Energy
Company, Washington Energy Resources Company, the Company and COG
Acquisition Company (Form 10-K for 1993).
10.14 1990 Nonemployee Director Stock Option Plan of the Company (Form S-8
dated June 23, 1990)
(a) First Amendment to 1990 Nonemployee Director Stock Option Plan
(Post-Effective Amendment No. 2 to Form S-8 dated March 7, 1994).
(b) Second Amendment to 1990 Nonemployee Director Stock Option Plan (Form
10-K for 1995).
10.15 1994 Long-Term Incentive Plan of the Company (Form S-8 dated May 20,
1994 - Registration Statement No. 33-53723).
10.16 1994 Nonemployee Director Stock Option Plan (Form S-8 dated May 20, 1994 -
Registration Statement No. 33-53723).
10.17 Employment Agreement between the Company and Ray R. Seegmiller dated
September 25, 1995 (Form 10-K for 1995).
21.1 Subsidiaries of Cabot Oil & Gas Corporation.
23.1 Consent of Coopers & Lybrand L.L.P.
23.2 Consent of Miller and Lents, Ltd.
27 Financial Data Schedule.
28.1 Miller and Lents, Ltd. Review Letter dated February 10, 1997.