1
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, 1997
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 27, 1998), was approximately
$510,000,000.
As of February 27, 1998, there were 24,680,936 shares of Common Stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Stockholders to
be held May 12, 1998 are incorporated herein by reference in Items 10, 11, 12,
and 13 of Part III of this report.
2
TABLE OF CONTENTS
PART I PAGE
ITEMS 1 AND 2 Business and Properties 2
ITEM 3 Legal Proceedings 16
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 17
ITEM 6 Selected Historical Financial Data 18
ITEM 7 Management's Discussion and Analysis of Financial Condition and Results of Operations 19
ITEM 8 Financial Statements and Supplementary Data 29
ITEM 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 56
PART III
ITEM 10 Directors and Executive Officers of the Registrant 56
ITEM 11 Executive Compensation 56
ITEM 12 Security Ownership of Certain Beneficial Owners and Management 56
ITEM 13 Certain Relationships and Related Transactions 56
PART IV
ITEM 14 Exhibits, Financial Statement Schedules and Reports on Form 8-K 57
----------
The statements regarding future financial performance and results and
market prices and the other statements which are not historical facts contained
in this report are forward-looking statements. The words "expect," "project,"
"estimate," "believe," "anticipate," "intend," "budget," "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.
1
3
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 and
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, 1997, the Company had approximately 938.6 Bcfe of total
proved reserves, 96% 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, 1997
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)
Total Appalachian Western
Company Region Region(2)
- --------------------------------------------------------------------------------
RESERVES/PRODUCTION:
Proved reserves
Developed (Bcfe) 767.9 346.4 421.5
Undeveloped (Bcfe) 170.7 71.5 99.2
--------- ------- -------
Total (Bcfe) 938.6 417.9 520.7
========= ======= =======
Daily production (Mmcfe) net 185.4 70.2 115.2
Gross productive wells 4,242.0 2,905.0 1,337.0
Net productive wells 3,441.4 2,696.4 745.0
Percent of wells operated 84.8% 96.7% 58.8%
ACREAGE:
Net acreage
Developed acreage 1,003,603 719,840 283,763
Undeveloped acreage 373,946 255,037 118,909
--------- ------- -------
Total 1,377,549 974,877 402,672
========= ======= =======
- --------------------------------------------------------------------------------
(1) As of December 31, 1997. 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.
2
4
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,
and recently has stepped up its emphasis on exploration. 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 new exploration opportunities.
While continuing its strong development drilling program, the Company has
significantly expanded its exploration program in the last two years. Both the
Appalachian and Western Regions added more exploratory wells to their respective
drilling programs in 1997, increasing from 25 to 33 wells in Appalachia and from
5 to 13 wells in the West. Both regions had favorable results in the 1997
program with success rates of 76% and 46%, in the Appalachian and Western
Regions, respectively. A large part of the exploration activity in the Western
Region has been focused in the Gulf Coast area. In 1997, reserves in the Gulf
Coast area grew from 27.1 Bcfe to 56.5 Bcfe, or 108%, due primarily to the
Company's exploratory drilling strategy. The Company's 1998 exploration program
includes drilling expenditures of $17 million, which represents 24% of the
planned 1998 drilling program.
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, 1997, the Company had approximately 417.9 Bcfe of proved reserves
(substantially all natural gas) in the Appalachian Region, constituting 45% of
the Company's total proved reserves.
The Company has 2,905 productive wells (2,696.4 net), of which 2,810 wells
are operated by the Company. There are multiple producing intervals which
include the Upper Devonian, Oriskany, Berea, and Big Lime trend formations at
depths primarily ranging from 1,500 to 6,000 feet. Average net daily production
in 1997 was 70.0 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 October 1997, the Company sold 912 wells primarily located in northwest
Pennsylvania (the "Meadville properties") which have been producing
approximately 15 Mmcfe per day from the Medina formation to Lomak Petroleum
Incorporated.
In 1997, the Company drilled 120 wells (96.8 net) in the Appalachian
Region, of which 87 were development wells (78.7 net). Capital and exploration
expenditures, including pipeline expenditures for the year were $38.0 million.
In the 1998 drilling program year, the Company has plans to drill 126 wells.
At December 31, 1997, the Company had 974,877 net acres in the region,
including 719,840 net developed acres. At year end, the Company had identified
205 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.
3
5
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 and include the Anadarko, Rocky Mountain and Gulf Coast areas. At
December 31, 1997, the Company had approximately 520.7 Bcfe of proved reserves
(93.8% natural gas) in the Western Region, constituting 55% of the Company's
total proved reserves.
ANADARKO
The Company has 760 productive wells (502.2 net) in the Anadarko area of
which 556 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 1997 was 46.5 Mmcfe.
In 1997, the Company drilled 35 wells (17.8 net) in Anadarko, including 32
development wells (16.2 net). Capital and exploration expenditures for the year
were $13.8 million. In the 1998 drilling program year, the Company has plans to
drill 45 wells.
At December 31, 1997, the Company had approximately 224,860 net acres,
including approximately 190,306 net developed acres. At year end, the Company
had identified 57 proved undeveloped drilling locations.
ROCKY MOUNTAINS
The Company has 420 productive wells (185.7 net) in the Rocky Mountain
area of which 196 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 1997 was 43.0
Mmcfe.
In October 1997, the Company acquired oil and gas producing properties
from Equitable Resources Energy Company in the Green River Basin of Wyoming (the
"Green River properties"). These properties included approximately 72 Bcfe of
reserves, interests in 63 wells with estimated daily net production of 10 Mmcfe,
and nearly 70 potential drilling locations. This acquisition increased the
Company's reserves in the area by 46%.
In 1997, the Company drilled 50 wells (26.6 net) in the Rocky Mountains
including 49 development wells (26.2 net). Capital and exploration expenditures
for the year were $61.9 million, including approximately $45 million for the
Green River property acquisition. In the 1998 drilling program year, the Company
has plans to drill 68 wells.
At December 31, 1997, the Company had approximately 150,421 net acres,
including approximately 76,507 net developed acres. At year end, the Company had
identified 75 proved undeveloped drilling locations.
GULF COAST
The Company has 157 productive wells (57.1 net) in the Gulf Coast area of
which 34 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 1997 was 25.3 Mmcfe.
In 1997, the Company drilled 20 wells (10.3 net) in the Gulf Coast
including 11 development wells (6.7 net). Capital and exploration expenditures
for the year were $25.4 million. In the 1998 drilling program year, the Company
has plans to drill 31 wells.
At December 31, 1997, the Company had approximately 27,391 net acres,
including approximately 16,950 net developed acres. At year end, the Company had
identified 5 proved undeveloped drilling locations.
4
6
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. Since Order 636 was issued, there has been 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 the premiums it has received.
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 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 and gathering 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 15% 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
compared 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 2,800 miles of pipeline with interconnects to three
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.
5
7
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 subsidiary purchases all of the Company's natural gas production in
the Western Region. This marketing subsidiary sells 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 15% of the Western Region's
production is sold under a 15 year cogeneration contract with 11 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 Gulf Coast interstate and intrastate pipelines, affording the
Company access to multiple markets.
The Company also produces and markets approximately 1,400 barrels a day of
crude oil/condensate in the Western Region at market responsive prices.
RISK MANAGEMENT
In 1997, 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 price swaps call for payments to (or to receive payments from)
counterparties based upon the differential between a fixed and a variable gas
price. 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, or
Note 13 of the Notes to the Consolidated Financial Statements for further
discussion.
6
8
RESERVES
CURRENT RESERVES
The following table sets forth information regarding the Company's
estimates of its net proved reserves at December 31, 1997.
Natural Gas (Mmcf) Liquids(1) (Mbbl) Total(2) (Mmcfe)
- -----------------------------------------------------------------------------------------------------------------------
Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total
- -----------------------------------------------------------------------------------------------------------------------
Appalachian 343,718 71,500 415,218 447 0 447 346,400 71,500 417,900
Western(3) 395,046 93,165 488,211 4,412 1,010 5,422 421,519 99,224 520,743
------- ------- ------- ----- ----- ----- ------- ------- -------
Total 738,764 164,665 903,429 4,859 1,010 5,869 767,919 170,724 938,643
======= ======= ======= ===== ===== ===== ======= ======= =======
- -----------------------------------------------------------------------------------------------------------------------
(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, 1997.
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 judgment. As
a result, estimates of different engineers often vary. In addition, results of
drilling, testing and production subsequent to the date of an estimate may
justify 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.
7
9
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, 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
------- ------- ------- --- ----- ----- ------- ------- ---------
Revisions of prior estimates 2,929 3,815 6,744 67 32 99 3,327 4,009 7,336
Extensions, discoveries and
other additions 42,609 66,582 109,191 147 647 794 43,493 70,463 113,956
Production (25,340) (38,549) (63,889) (48) (581) (629) (25,628) (42,035) (67,663)
Purchases of reserves in place 5,355 68,481 73,836 2 592 594 5,366 72,035 77,401
Sales of reserves in place (137,194) (876) (138,070) (55) (100) (155) (137,520) (1,478) (138,998)
------- ------- ------- --- ----- ----- ------- ------- ---------
DECEMBER 31, 1997 415,218 488,211 903,429 447 5,422 5,869 417,900 520,743 938,643
======= ======= ======= === ===== ===== ======= ======= =========
PROVED DEVELOPED RESERVES:
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
December 31, 1997 343,718 395,046 738,764 447 4,412 4,859 346,400 421,519 767,919
- ------------------------------------------------------------------------------------------------------------------------------------
APP = Appalachian Region
WEST = Western Region
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.
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.
8
10
Year Ended December 31,
1997 1996 1995
- ---------------------------------------------------------------------------------------
NET WELLHEAD SALES VOLUME:
Natural Gas (Bcf)(1)
Appalachian Region 25.3 26.2 26.4
Western Region(2) 38.6 32.6 29.8
Crude/Condensate/Ngl (Mbbl)
Appalachian Region 48 21 18
Western Region 584 576 722
PRODUCED NATURAL GAS SALES PRICE $(/MCF)(3)
Appalachian Region $ 3.00 $ 2.72 $ 2.22
Western Region $ 2.22 $ 2.02 $ 1.33
Weighted Average $ 2.53 $ 2.34 $ 1.75
Crude/Condensate Sales Price ($/Bbl)(3) $20.13 $ 21.14 $ 17.95
Production Costs ($/Mcfe)(4) $ 0.58 $ 0.56 $ 0.55
- ---------------------------------------------------------------------------------------
(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.
9
11
ACREAGE
The following tables summarize the Company's gross and net developed and
undeveloped leasehold and mineral acreage at December 31, 1997. Acreage in which
the Company's interest is limited to royalty and overriding royalty interests is
excluded.
LEASEHOLD ACREAGE
At December 31, 1997
Developed Undeveloped Total
- -----------------------------------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
- -----------------------------------------------------------------------------------------------------------------
STATE
Alabama -- -- 312 312 312 312
Arkansas 240 6 -- -- 240 6
Colorado 24,474 20,771 32,264 29,141 56,738 49,912
Indiana 739 369 53,485 26,457 54,224 26,826
Kansas 33,264 28,850 1,278 896 34,542 29,746
Kentucky 2,680 990 15,679 7,657 18,359 8,647
Louisiana 2,070 357 3,419 542 5,489 899
Michigan 809 178 6,228 1,362 7,037 1,540
Montana 157 52 680 303 837 355
New York 2,520 1,057 3,461 2,853 5,981 3,910
North Dakota 160 20 870 96 1,030 116
Ohio 5,088 1,905 41,060 28,223 46,148 30,128
Oklahoma 182,867 119,611 46,776 31,107 229,643 150,718
Pennsylvania 93,998 77,294 34,913 22,656 128,911 99,950
Texas 77,412 44,290 26,079 11,663 103,491 55,953
Utah 1,740 530 20,653 17,274 22,393 17,804
Virginia 22,091 20,045 24,849 12,279 46,940 32,324
West Virginia 567,650 524,600 119,838 96,088 687,488 620,688
Wyoming 113,729 55,094 59,805 27,019 173,534 82,113
--------- ------- ------- ------- --------- ---------
Total 1,131,688 896,019 491,649 315,928 1,623,337 1,211,947
========= ======= ======= ======= ========= =========
MINERAL FEE ACREAGE
At December 31, 1997
Developed Undeveloped Total
- -----------------------------------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
- -----------------------------------------------------------------------------------------------------------------
STATE
Colorado 279 40 160 6 439 46
Kansas 160 128 -- -- 160 128
Montana -- -- 589 75 589 75
New York -- -- 4,281 1,070 4,281 1,070
Oklahoma 16,889 13,987 240 49 17,129 14,036
Pennsylvania 86 86 1,573 502 1,659 588
Texas 27 27 857 426 884 453
Virginia 17,817 17,817 100 34 17,917 17,851
West Virginia 89,264 75,499 56,817 55,856 146,081 131,355
--------- --------- ------- ------- --------- ---------
Total 124,522 107,584 64,617 58,018 189,139 165,602
========= ========= ======= ======= ========= =========
Aggregate Total 1,256,210 1,003,603 556,266 373,946 1,812,476 1,377,549
========= ========= ======= ======= ========= =========
10
12
Total Net Acreage by Area of Operation
At December 31, 1997
Developed Undeveloped Total
- ------------------------------------------------------------------------------------------------------
Appalachian Region 719,840 255,037 974,877
Western Region 283,763 118,909 402,672
--------- ------- ---------
Total 1,003,603 373,946 1,377,549
========= ======= =========
PRODUCTIVE WELL SUMMARY(1)
The following table reflects the Company's ownership at December 31, 1997
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, Texas, Kansas, North Dakota, Utah, Colorado and Wyoming).
Natural Gas Oil Total
Gross Net Gross Net Gross Net
- ------------------------------------------------------------------------------------------------------------------
Appalachian Region 2,883 2,684.9 22 11.5 2,905 2,696.4
Western Region 1,134 659.8 203 85.2 1,337 745.0
----------------------------------------------------------------------------
Total 4,017 3,344.7 225 96.7 4,242 3,441.4
============================================================================
- ------------------------------------------------------------------------------------------------------------------
(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,
1997 1996 1995
- ----------------------------------------------------------------------------------------------
GROSS NET Gross Net Gross Net
- ----------------------------------------------------------------------------------------------
APPALACHIAN REGION:
Development Wells
Natural Gas 82 73.7 85 81.6 17 16.4
Oil 0 0.0 1 1.0 0 0.0
Dry 5 5.0 12 12.0 5 4.3
Extension Wells
Natural Gas 0 0.0 0 0.0 1 0.3
Oil 0 0.0 0 0.0 0 0.0
Dry 0 0.0 0 0.0 1 0.5
Exploratory Wells
Natural Gas 20 10.9 10 5.0 2 0.5
Oil 5 0.9 5 0.9 2 0.5
Dry 8 6.3 10 5.2 5 2.0
--- ---- --- ----- -- ----
Total 120 96.8 123 105.7 33 24.5
=== ==== === ===== == ====
Wells Acquired(1)
Natural Gas 1 40.0 15 11.8 3 3.7
Oil 0 0.0 0 0.0 0 0.0
--- ---- --- ----- -- ----
Total 1 40.0 15 11.8 3 3.7
=== ==== === ===== == ====
Wells in Progress at End
of Period 4 3.1 2 1.5 3 3.0
11
13
Year Ended December 31,
1997 1996 1995
- -----------------------------------------------------------------------------------------------------------------
GROSS NET Gross Net Gross Net
- -----------------------------------------------------------------------------------------------------------------
WESTERN REGION:
Development Wells
Natural Gas 72 32.3 40 26.5 33 17.1
Oil 1 0.9 0 0.0 3 1.9
Dry 5 3.7 14 8.7 7 3.3
Extension Wells
Natural Gas 11 10.6 12 8.3 8 4.6
Oil 1 0.6 1 0.1 0 0.0
Dry 2 1.0 1 1.9 0 0.0
Exploratory Wells
Natural Gas 5 1.6 1 0.6 1 0.3
Oil 1 1.0 0 0 0 0.0
Dry 7 2.9 4 2.4 8 3.9
--- ---- -- ---- -- ----
Total 105 54.6 73 48.5 60 31.1
=== ==== == ==== == ====
Wells Acquired(1)
Natural Gas 63 18.5 25 11.9 0 2.7
Oil 2 0.2 3 0.4 0 0.1
--- ---- -- ---- -- ----
Total 65 18.7 28 12.3 0 2.8
=== ==== == ==== == ====
Wells in Progress at End
of Period 6 3.3 4 1.5 6 5.3
- -----------------------------------------------------------------------------------------------------------------
(1)Includes the acquisition of net interest in certain wells in the Appalachian
Region and in the Western Region in 1997, 1996 and 1995 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. The Company also believes that its competitive position
is enhanced by marketing its own gas through the operation of Cabot Oil & Gas
Marketing Corporation.
OTHER BUSINESS MATTERS
MAJOR CUSTOMER
The Company had no sales to any customer that exceeded 10% of the
Company's total gross revenues in 1997.
SEASONALITY
Demand for natural gas has historically been seasonal in nature, with peak
demand and typically higher prices occurring during the colder winter months.
12
14
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.
The statutory law affecting the oil and natural gas industry is under constant
review for amendment or expansion. Further, numerous departments and agencies,
federal, state and local, 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. 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
The 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 in a given field 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 of production from oil and natural gas wells, generally
prohibit the venting or flaring of natural gas and impose certain requirements
regarding the ratability of production. In this regard, such states as Texas,
Oklahoma and Louisiana have in recent years reviewed and substantially revised
the methodologies previously used by them to gather the necessary information
and make monthly determinations of appropriate field and well production
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 transported and marketed. Under the Natural Gas Act of 1938, the
Federal Energy Regulatory Commission (the "FERC") regulates the interstate
transportation and the sale in interstate commerce for resale of natural gas.
The FERC's jurisdiction over interstate sales of natural gas was substantially
modified by the Natural Gas Policy Act, under which the FERC continued to
regulate the maximum selling prices of certain categories of gas sold in "first
sales" in interstate and intrastate commerce. Effective January 1, 1993,
however, the Natural Gas Wellhead Decontrol Act (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 of the
Company's domestically produced natural gas may now be sold at market prices,
subject to the terms of any private contracts which may be in effect. The FERC's
jurisdiction over natural gas transportation was 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.
Previously, the interstate pipelines had acted primarily as wholesalers of
natural gas, purchasing the gas from producers in or within the vicinity of the
production areas and reselling the gas to large industrial customers and local
distribution companies. Among other things, Order No. 636 required interstate
pipelines to unbundle their wholesale merchant services into the various
constituent services, such as sales, transmission and storage, and to offer
these "unbundled" services individually to their customers. By requiring
interstate pipelines to "unbundle" their services and to provide their
13
15
customers with direct access to pipeline capacity, Order No. 636 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 interstate pipelines and obtain transportation of such
gas on a nondiscriminatory basis. Through similar orders pertaining to
intrastate pipelines which provide certain interstate services, the FERC has
expanded the impact of these so-called "open access" regulations to intrastate
commerce. The effect of Order No. 636 and related orders 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 individual interstate pipelines have had final open access
tariffs in place for several years, the FERC is continuing to review, assess and
modify its transportation regulations and the Company cannot predict what new or
different 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 have significantly affected the marketing of natural
gas. Some of the more notable of these regulatory initiatives have included (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 and a series of
orders in individual pipeline dockets 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 potential for 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.
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) 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 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 U.S. 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
14
16
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 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 342 active employees as of December 31, 1997. The Company
believes that its relations with its employees are satisfactory. The Company has
not entered into any collective bargaining agreements with its employees.
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
15
17
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, 1997, the Company owned or operated
approximately 2,800 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 judgments 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 20,000 Mmbtu of natural gas per day 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.
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, 1997 to December 31, 1997.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information about the executive officers
of the Company as of March 1, 1998, as such term is defined in Rule 3b-7
promulgated under the Securities Exchange Act of 1934, and certain other
officers of the Company.
16
18
Name Age Position Officer Since
------------------------------------------------------------------------------------------------------
Charles P. Siess, Jr. 71 Chairman of the Board and 1995
Chief Executive Officer
Ray R. Seegmiller 62 President, Chief Operating
Officer and Director 1995
James M. Trimble 49 Senior Vice President, Exploration and 1987
Production
Jim L. Batt 62 Vice President, Land 1988
Jeff W. Hutton 42 Vice President, Marketing 1995
Gerald F. Reiger 46 Vice President and Regional
Manager 1995
H. Baird Whitehead 47 Vice President and Regional
Manager 1987
Paul F. Boling 44 Controller 1996
Lisa A. Machesney 42 Corporate Secretary and Managing
Counsel 1995
Scott C. Schroeder 35 Treasurer 1997
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 and Chief Executive
Officer 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. Mr. Seegmiller served in this position
until March 1997 when he was promoted to Executive Vice President, Chief
Operating Officer. In September 1997, Mr. Seegmiller was promoted to his current
position of President, Chief Operating Officer and Director. Mr. Seegmiller has
been designated to replace Charles Siess as Chief Executive Officer upon the
expected retirement of Mr. Siess in 1998. 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.
Scott C. Schroeder has been Treasurer since May 1997. From October 1995 to
May 1997, Mr. Schroeder served as Assistant Treasurer. Prior to joining the
Company, Mr. Schroeder held various managerial positions with Pride Petroleum
Services (now known as Pride International). Prior thereto, Mr. Schroeder server
as Manager, Treasury Operations and Planning of DeKalb Energy Company.
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:
17
19
Cash
High Low Dividends
- ------------------------------------------------------------------------
1997
FIRST QUARTER $ 19.75 $ 15.88 $ 0.04
SECOND QUARTER 18.88 15.50 0.04
THIRD QUARTER 23.69 17.38 0.04
FOURTH QUARTER 25.06 16.50 0.04
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
As of January 31, 1998, there were 1,397 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) 1997 1996 1995 1994 1993
- -----------------------------------------------------------------------------------------------------------
INCOME STATEMENT DATA:
Net Operating Revenues $ 185,127 $ 163,061 $ 121,083 $ 140,295 $ 115,816
Income (Loss) from Operations 63,852 48,787 (116,758) 15,013 20,007
Net Income (Loss) Applicable to
Common Stockholders 23,231 15,258 (92,171) (5,444) 2,088
BASIC EARNINGS (LOSS) PER SHARE
APPLICABLE TO COMMON
STOCKHOLDERS(1) $ 1.00 $ 0.67 $ (4.05) $ (0.25) $ 0.10
DIVIDENDS PER COMMON SHARE $ 0.16 $ 0.16 $ 0.16 $ 0.16 $ 0.16
BALANCE SHEET DATA:
Properties and Equipment, Net $ 469,399 $ 480,511 $ 474,371 $ 634,934 $ 400,270
Total Assets 541,805 561,341 528,155 688,352 445,001
Long-Term Debt 183,000 248,000 249,000 268,363 169,000
Stockholders' Equity 184,062 160,704 147,856 243,082 153,529
- -----------------------------------------------------------------------------------------------------------
(1) See "Earnings (Loss) Per Common Share" under Note 20 of the Notes to the
Consolidated Financial Statements.
18
20
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 initial upswing in gas prices early in the year, coupled with a 8.5%
increase in natural gas production, played an important part in the Company's
performance in 1997 with record earnings and operating cash flows. Operating
results for 1997 included the benefit of the following:
o The average produced natural gas price was $2.53 per Mcf, up 8%
compared to 1996, while equivalent production was up 5.4 Bcfe, or
8.5%, compared to 1996.
o Under its continued asset rationalization program, involving the
divestiture of non-strategic properties, and synergistic growth
through new acquisitions, the Company completed a like-kind
exchange transaction in October 1997 which matched properties
purchased, including 63 wells and 74 potential drilling
locations, in the Green River Basin of Wyoming with a portion of
the properties divested in the Meadville district of the
Appalachian Region, including 912 wells and related assets. This
transaction generated net proceeds of $47.7 million.
o Net interest costs were down $1.1 million, or 6%, excluding the
benefit of the non-recurring $1.7 million of interest income
received in 1996 that related to an income tax refund for tax
periods prior to 1990. This reduction in interest cost was a
result of debt reductions made possible by strong operating cash
flow in 1997.
o Depreciation, depletion and amortization ("DD&A") expenses were
down $1.9 million or $0.09 per Mcfe of production. This
improvement was primarily the result of the reduction in high
cost depreciable assets due to the disposition of the Meadville
properties in September 1997.
Operating cash flows reached a record level of $95.0 million, increasing
$19.6 million, or 26%, from 1996. Cash flows from operations, along with the
$47.7 million of net proceeds from the Meadville/Green River property
transaction noted above, predominantly funded (1) $73.5 million of capital and
exploration expenditures, (excluding the Green River property acquisition) $12.8
million higher than 1996, (2) $49 million of net debt reductions and (3) $9.4
million of preferred and common stock dividend payments.
The Company drilled 151.4 net wells with a net success rate of 88%
compared to 154.2 net wells and a net 80% success rate in 1996. Along with the
higher success rate in 1997, the Company replaced 179% of production through
drilling additions and revisions, versus a 119% production replacement in 1996.
In 1998 the Company plans to drill 270 gross wells (173.2 net) and spend $111.0
million in capital and exploration expenditures, 17% higher than 1997
expenditures.
Natural gas production equivalent was 67.7 Bcf, an increase of 8.5% over
1996. The 1997 production growth resulted from the Company's expanded drilling
programs in 1996 and 1997. Additionally, the underperforming properties sold in
the Meadville district, effective September 1, 1997, which would have produced
an estimated 1.7 Bcfe in the remaining four months of 1997, were more than
offset by the acquired Green River properties which added 1.9 Bcfe to 1997
production.
19
21
The Company's strategic pursuits are sensitive to energy commodity
prices, particularly the price of natural gas. Gas prices rose to near record
levels in November and December 1996. Although prices rose still further in
January 1997, the gas market demonstrated significant price volatility in the
spring months. Prices in most regions rose sharply in October and November 1997,
but due to the unseasonably warm winter, softened in December and January 1998
to levels significantly below the prices realized in the corresponding months of
the prior year.
The Company remains focused on its strategies to grow through the drill
bit, through synergistic acquisitions and through greater emphasis on marketing.
The Company believes that these strategies are appropriate in the current
industry environment and establish a firm base which will enable the Company to
create shareholder value over the long term.
The success of these strategies is measured by the achievement of three
goals. The first of these goals is to increase cash flow from both increased
production and reduced costs. The Company has made significant progress in this
area. During 1997, production increased 8.5% while direct operating cost per
Mcfe declined $0.02, contributing to the 26% increase in operational cash flow.
The second goal is to maintain reserves per share while increasing
production to protect long-term shareholder value. Reserve additions from the
1997 drilling program replaced 168% of 1997 production. In total, reserve levels
decreased slightly due to actions taken as part of the asset rationalization
program. The Company plans to drill 270 gross wells in 1998 and increase
exploratory drilling, lease acquisition and geophysical expenditures.
Finally, the Company strives to reduce debt as a percentage of total
capitalization without diluting shareholder value. This ratio was 60.7% at the
end of 1996 and has improved to 51.9% in 1997 due mainly to a $49 million
reduction in total borrowings, made possible from the net proceeds generated
from the sale of the Meadville properties.
In October 1997, the Company exercised the option to convert all of the
$3.125 cumulative preferred stock into approximately 1,649,000 shares of Common
Stock. By eliminating the dividends on the $3.125 cumulative preferred shares,
an additional $2.2 million of annual earnings will be made available to common
shareholders in future years.
The preceding paragraphs, discussing the Company's strategic pursuits and
goals, contain forward-looking information. See FORWARD-LOOKING INFORMATION on
page 25.
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 were up in 1997 over 1996, resulting in higher cash
flows.
The primary sources of cash for the Company during 1997 were from funds
generated from operations and net cash proceeds from the sale of the Meadville
properties and acquisition of the Green River properties. 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 inflow of $0.4 million in 1997. Net cash
inflow from operating and financing activities totaled $38.9 million, funding
the capital and exploration expenditures of $38.4 million, net of the $48.9
million in net proceeds from the sale of assets.
(In millions) 1997 1996 1995
- --------------------------------------------------------------------------------
Cash Flows Provided by Operating Activities $ 95.0 $ 75.5 $ 41.5
------- ------- -------
20
22
Cash flows provided by operating activities in 1997 were substantially
higher, increasing $19.5 million over 1996, due primarily to higher natural gas
prices and production, and a significant reduction in trade receivables.
Cash flows provided by operating activities in 1996 were higher by $34
million compared with 1995 due predominantly to higher natural gas prices.
(In millions) 1997 1996 1995
- -----------------------------------------------------------------------------
Cash Flows Used by Investing Activities $(38.4) $ (67.6) $ (14.0)
------ ------- -------
Cash flows used by investing activities in 1997 were $29.2 million lower
than in 1996 due to net proceeds of $47.7 million received from the
Meadville/Green River property transaction, partially offset by the expenses of
the stronger 1997 drilling program.
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.
(In millions) 1997 1996 1995
- ----------------------------------------------------------------------------
Cash Flows Used by Financing Activities $ (56.2) $ (9.6) $ (28.2)
-------- ------- -------
Cash flows used by financing activities from 1997 consist primarily of the
$49.0 million net reduction in borrowings on the revolving credit facility as
well as dividend payments. The 1996 activity was mostly attributable to dividend
payments, but also included a $1.0 reduction in debt under the credit facility.
Cash flows used by financing activities from 1995 were primarily net
payments on the Company's revolving credit facility, reducing the debt under
this facility by $19.0 million.
The Company's available credit line under the revolving credit facility
was $235 million from June 1995 until November 1997. In November 1997, the
Company issued $100 million in 7.19% Notes (See Note 5 of the Notes to the
Consolidated Financial Statements for further discussion) and reduced the
available credit line to $135 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 $19 million at December 31, 1997.
The Company's 1998 interest expense is projected to be approximately $17
million. A principal payment of $16 million on the 10.18% private placement of
senior notes is due in the second quarter of 1998.
The Company has begun making necessary changes to its computer software in
preparation for the year 2000. These projects are on schedule and the Company
believes that the related costs will not be material to its results of
operations or financial condition.
Capitalization information on the Company is as follows:
(In millions) 1997 1996 1995
- ----------------------------------------------------------
Long-Term Debt $183.0 $248.0 $249.0
Current Portion of
Long-Term Debt 16.0 -- --
------ ------ ------
Total Debt 199.0 248.0 249.0
Stockholders' Equity
Common Stock 127.4 69.4 56.6
Preferred Stock 56.7 91.3 91.3
------ ------ ------
Total Equity 184.1 160.7 147.9
------ ------ ------
Total Capitalization $383.1 $408.7 $396.9
====== ====== ======
Debt to Capitalization 51.9% 60.7% 62.7%
------ ------ ------
21
23
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, 1997.
(In millions) 1997 1996 1995
- --------------------------------------------------------------------------------
Capital Expenditures:
Drilling and Facilities $ 68.2 $ 42.7 $ 19.3
Leasehold Acquisitions 4.3 4.3 2.0
Pipeline and Gathering 6.1 6.3 2.2
Other 2.0 0.7 1.2
------- ------- -------
80.6 54.0 24.7
------- ------- -------
Proved Property Acquisitions(3) 45.6 6.6 --
WERCO Acquisition -- (5.3)(1) (8.4)(2)
------- ------- -------
45.6 1.3 (8.4)
------- ------- -------
Exploration Expenses 13.9 12.6 8.0
------- ------- -------
Total $ 140.1 $ 67.9 $ 24.3
======= ======= =======
- --------------------------------------------------------------------------------
(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) Includes $45.2 million in assets acquired from Equitable Resources Energy
Company in a like-kind exchange transaction with a portion of the assets
sold in the Meadville properties sale.
The substantially reduced level of 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 major 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 1998 have been increased 17% compared with 1997,
excluding proved property acquisitions. Depending on the level of future natural
gas prices, the Company intends to review and adjust the capital and exploration
expenditures planned for 1998 as industry conditions dictate. Presently, the
Company projects $111 million in capital and exploration expenditures for 1998
including $88.5 million for the drilling and exploration program. The Company
plans to drill 270 wells (173.2 net), compared with 225 wells (151.4 net)
drilled in 1997.
In addition to the drilling and exploration program, other 1998 capital
expenditures are planned primarily for producing property and lease acquisitions
and for gathering and pipeline infrastructure maintenance and construction.
During 1997, dividends were paid on the Company's common stock totaling
$3.7 million, on the $3.125 convertible preferred stock totaling $1.7 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
22
24
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.
OTHER ISSUES AND CONTINGENCIES
Encogen Gas Contract. See Item 3. Legal Proceedings on page 16 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
$1.05 per Mmbtu in 1997. In 1995 and 1996, the Company completed three
transactions to monetize the value of these tax credits, resulting in revenues
of $3.6 million in 1997 and approximately $16.4 million over the remaining five
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 10.18% and
7.19% Notes specify a minimum annual coverage ratio of operating cash flow to
interest expense for the trailing four quarters of 2.8 to 1.0. At December 31,
1997 the calculated ratio for 1997 was 5.3 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 1997 produced natural gas sales price
increased 8% compared to 1996, while production volumes increased 8.5%. As a
result, the Company experienced its highest level of earnings and operating cash
flow since becoming a public company in 1990. While prices in most regions of
the U.S. moved up sharply in November and December 1996 and January 1997, price
volatility in the gas market has remained prevalent in the last few years, as
demonstrated most recently in December 1997 and January 1998, with natural gas
prices dropping to levels substantially below the prices of the corresponding
months of the prior year. Given this continued price volatility, management
cannot predict with certainty what pricing levels will be for the rest of 1998
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 1998 plans include an increase in capital spending,
the Company will periodically assess industry conditions and will adjust its
1998 spending plan to ensure the adequate funding of its capital requirements,
including, among other things, reductions in capital expenditures or common
stock dividends.
The Company believes its capital resources, supplemented, if necessary,
with external financing, are adequate to meet its capital requirements.
23
25
The preceding paragraphs contain forward-looking information. See
Forward-Looking Information below.
* * *
FORWARD-LOOKING INFORMATION
The statements regarding future financial performance and results and
market prices and the other statements which are not historical facts contained
in this report are forward-looking statements. The words "expect," "project,"
"estimate," "believe," "anticipate," "intend," "budget," "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.
24
26
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's Western Region includes operations located in the
Anadarko area, the onshore Gulf Coast, and in the Rocky Mountains.
SELECTED FINANCIAL AND OPERATING DATA
(In millions except where specified) 1997 1996 1995
- -------------------------------------------------------------------------------
Net Operating Revenues $ 185.1 $ 163.1 $ 121.1
Operating Expenses 121.3 116.0 237.2
Interest Expense 18.0 17.4 24.9
Net Income (Loss) 23.2 15.3 (92.2)
Earnings (Loss) Per Share - Basic $ 1.00 $ 0.67 $ (4.05)
Natural Gas Production (Bcf)
Appalachia 25.3 26.8 27.5
West 38.6 32.0 30.2
-------- ------- --------
Total Company 63.9 58.8 57.7
======== ======= ========
Produced Natural Gas Sales Price ($/Mcf)
Appalachia $ 3.00 $ 2.72 $ 2.22
West $ 2.22 $ 2.02 $ 1.33
Total Company $ 2.53 $ 2.34 $ 1.75
Crude/Condensate
Volume (Mbbl) 574 520 618
Price ($/Bbl) $ 20.13 $ 21.14 $ 17.95
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, 1997.
(In millions) 1997 1996 1995
- --------------------------------------------------------------------------------
Net Income (Loss) Before Selected Items $ 23.2 $ 12.5 $(17.3)
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) $ 23.2 $ 15.3 $(92.2)
======== ====== ======
1997 AND 1996 COMPARED
Net Income and Revenues. The Company reported net income in 1997 of $23.2
million, or $1.00 per share, up $10.7 million, or $0.45 per share, compared to
1996, 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. Excluding these
pre-tax effects of the selected items, 1997 operating income and net operating
revenues increased $15.1 million and $22.1 million, respectively. Natural gas
sales comprised 87%, or $161.7 million, of net operating revenue in 1997. The
increase in net operating revenue was a result of both an 8% increase in the
produced natural gas sales price and an 8.5% increase in equivalent production.
Operating income and net income were similarly impacted by the
25
27
increases in natural gas prices and equivalent production along with lower
depreciation, depletion and amortization expense and interest expense.
Effective September 1, 1997, the Company sold proved reserves and acreage
located primarily in Northwest Pennsylvania (the "Meadville properties") for
$92.9 million to Lomak Petroleum Incorporated. The properties sold included 912
wells, producing approximately 15 Mmcfe net per day primarily from the Medina
formation. A portion of these assets were replaced, in a like-kind exchange
transaction, with oil and gas producing properties located in the Green River
Basin of Wyoming (the "Green River properties") purchased for $45.2 million in a
transaction with Equitable Resources Energy Company which closed on October 3,
1997. The purchased properties added an estimated 72 Bcfe of reserves, interests
in 63 wells with estimated daily net production of 10 Mmcfe and 74 potential
drilling locations to the Western Region. This acquisition increased the
Company's presence in the Rocky Mountains area by 46%.
Natural gas production volumes were down 1.5 Bcf, or 6%, to 25.3 Bcf in
the Appalachian Region as a result of the September sale of the Meadville
properties which were estimated to have produced 1.7 Bcfe in 1997 after the
sale. Natural gas production volumes were up 6.6 Bcf, or 21%, to 38.6 Bcf in the
Western Region due largely to new production from wells drilled and put on line
in the Rocky Mountains and Gulf Coast areas during the last half of 1996 and in
1997 and from the acquired Green River properties which produced 1.9 Bcfe.
In the Appalachian Region, the average natural gas production sales price
increased $0.28 per Mcf, or 10%, to $3.00, increasing net operating revenues by
approximately $7.1 million on 25.3 Bcf of production. The average Western Region
natural gas production sales price increased $0.20 per Mcf, or 10%, to $2.22,
increasing net operating revenues by approximately $7.7 million on 38.6 Bcf of
production. The overall weighted average natural gas production sales price
increased $0.19 per Mcf, or 8%, to $2.53.
Crude oil and condensate sales increased by 54 Mbbl, or 10%, primarily due
to new production brought on by the higher rate of drilling activity in 1996 and
1997 compared to 1995 levels.
Brokered natural gas margin was down $1.5 million to $4.1 million due
primarily to a $0.03 per Mcf decrease in the net margin to $0.12 per Mcf and in
part to a brokered volume decrease of 8% from 1996.
Operating Expense. The total operating expenses increased $5.3 million,
or 5%, to $77.9 million. The significant changes are explained as follows:
o Direct operation expense increased $1.0 million, or 4%, due to office
consolidation costs in the Western Region and the 8.5% increase in
equivalent production. Direct operating costs per Mcfe declined,
however, from $0.45 to $0.43 due in part to the sale of the higher
cost Meadville properties and the addition of new lower cost
production.
o Exploration expense increased $1.3 million primarily due to a $0.9
million rise in geological and geophysical expenses and a $0.3 million
increase in contract labor services related to the increased drilling
and exploration program in 1997.
o Depreciation, depletion, amortization and impairment expense decreased
$1.9 million, or 4%. due to the benefit of the Meadville/Green River
like-kind exchange transaction in the third quarter and due to the
decline in the Western Region DD &A rate related to the addition of
new lower cost production to existing fields.
o Taxes other than income increased $2.0 million, or 16%, due to the
increase in natural gas production revenues.
o General and administrative expense increased $2.9 million, or 17%,
due primarily to higher incentive and stock compensation expenses
related to the Company's marked improvement in earnings performance.
26
28
Interest expense, excluding the 1996 selected item, declined $1.1 million,
or 6%, due to a reduction in the Company's long-term debt level.
Income tax expense, excluding the selected item, was up $5.2 million due
to the comparable increase in earnings before income tax. The Company's
effective tax rate declined slightly due to a 0.2% reduction in the effective
state tax rate combined with a $0.2 million refund received on the prior year
percentage depletion claim.
1996 AND 1995 COMPARED
Net Income (Loss) and Revenues. The Company reported 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.
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.
27
29
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 totaled $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.
28
30
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
- ---------------------------------------------------------------------------
Report of Independent Accountants 31
Consolidated Statement of Operations 32
Consolidated Balance Sheet 33
Consolidated Statement of Cash Flows 34
Consolidated Statement of Stockholders' Equity 35
Notes to Consolidated Financial Statements 36
Supplemental Oil & Gas Information (Unaudited) 55
Quarterly Financial Information (Unaudited) 59
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 judgments and estimates of management.
Management maintains a system of internal accounting and managerial
controls and engages internal audit representatives who monitor and test the
operation of these controls. Although no system can ensure the elimination of
all errors and irregularities, the system is designed to provide reasonable
assurance that assets are safeguarded, transactions are executed in accordance
with management's authorization and accounting records are reliable for
financial statement preparation.
An Audit Committee of the Board of Directors, consisting of directors who
are not employees of the Company, meets periodically with management, the
independent accountants and internal audit representatives to obtain assurances
to the integrity of the Company's accounting and financial reporting and to
affirm the adequacy of the system of accounting and managerial controls in
place. The independent accountants and internal audit representatives have full
and free access to the Audit Committee to discuss all appropriate matters.
We believe that the Company's policies and system of accounting and
managerial controls reasonably assure the integrity of the information in the
consolidated financial statements and in the other sections of the annual
report.
Charles P. Siess, Jr. Ray Seegmiller
Chairman of the Board and President and
Chief Executive Officer Chief Operating Officer
March 6, 1998
29
31
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, 1997 and 1996, and the related consolidated
statements of operations, stockholders' equity, and cash flows for each of the
three years in the period ended December 31, 1997. 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, 1997 and 1996, and the consolidated results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1997, 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 6, 1998
30
32
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
Year Ended December 31,
(In thousands, except per share amounts) 1997 1996 1995
- ---------------------------------------------------------------------------------------
NET OPERATING REVENUES
Natural Gas Production $ 161,737 $ 137,482 $ 101,260
Crude Oil and Condensate 11,443 10,992 11,089
Brokered Natural Gas Margin 4,113 5,619 2,509
Other 7,834 8,968 6,225
--------- --------- ---------
185,127 163,061 121,083
OPERATING EXPENSES
Direct Operations 29,380 28,361 28,328
Exploration 13,884 12,559 8,031
Depreciation, Depletion and Amortization 40,598 42,689 47,206
Impairment of Long-Lived Assets (Note 15) -- -- 113,795
Impairment of Unproved Properties 2,856 2,701 5,047
General and Administrative 19,744 16,823 16,785
Cost Reduction Program (Note 12) -- -- 6,820
Taxes Other Than Income 14,874 12,826 11,215
--------- --------- ---------
121,336 115,959 237,227
Gain (Loss) on Sale of Assets 61 1,685 (614)
--------- --------- ---------
INCOME (LOSS) FROM OPERATIONS 63,852 48,787 (116,758)
Interest Expense 17,961 17,409 24,885
--------- --------- ---------
Income (Loss) Before Income Tax Expense 45,891 31,378 (141,643)
Income Tax Expense (Benefit) 17,557 10,554 (55,025)
--------- --------- ---------
NET INCOME (LOSS) 28,334 20,824 (86,618)
Dividend Requirement on Preferred Stock 5,103 5,566 5,553
--------- --------- ---------
Net Income (Loss) Applicable to
Common Stockholders $ 23,231 $ 15,258 $ (92,171)
========= ========= =========
Basic Earnings (Loss) Per Share Applicable
to Common Stockholders (Note 20) $ 1.00 $ 0.67 $ (4.05)
========= ========= =========
Diluted Earnings (Loss) Per Share Applicable
to Common Stockholders (Note 20) $ 0.97 $ 0.66$ (4.05)
========= ========= =========
Average Common Shares Outstanding 23,272 22,807 22,775
========= ========= =========
- ----------------------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial
statements.
31
33
CABOT OIL & GAS CORPORATION
CONSOLIDATED BALANCE SHEET
December 31,
(In thousands) 1997 1996
- ---------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 1,784 $ 1,367
Accounts Receivable 59,672 67,810
Inventories 6,875 8,797
Other 2,202 1,663
--------- ---------
Total Current Assets 70,533 79,637
PROPERTIES AND EQUIPMENT (Successful Efforts Method) 469,399 480,511
OTHER ASSETS 1,873 1,193
--------- ---------
$ 541,805 $ 561,341
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current Portion of Long-Term Debt $ 16,000 --
Accounts Payable 52,348 $ 56,338
Accrued Liabilities 17,524 16,279
--------- ---------
Total Current Liabilities 85,872 72,617
LONG-TERM DEBT 183,000 248,000
DEFERRED INCOME TAXES 80,108 69,427
OTHER LIABILITIES 8,763 10,593
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; 0 Shares in
1997 and 692,439 Shares 1996 -- 6% Convertible Redeemable Preferred; $50
Stated Value; 1,134,000 Shares in 1997 and 1996 113 183
Common Stock:
Authorized -- 40,000,000 Shares of $0.10 Par Value Issued and Outstanding
-- 24,667,262 Shares and 22,847,345 Shares at December 31, 1997 and 1996,
respectively 2,467 2,284
Class B Common Stock:
Authorized -- 800,000 Shares of $0.10 Par Value
No Shares Issued -- --
Additional Paid-in Capital 247,033 243,283
Accumulated Deficit (65,551) (85,046)
--------- ---------
Total Stockholders' Equity 184,062 160,704
--------- ---------
$ 541,805 $ 561,341
========= =========
- ---------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial
statements.
32
34
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended December 31,
(In thousands) 1997 1996 1995
- ----------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss) $ 28,334 $20,824 $ (86,618)
Adjustments to Reconcile Net Income (Loss)
to Cash Provided by Operations:
Depletion, Depreciation, and Amortization 40,598 42,689 47,206
Impairment of Long-Lived Assets -- -- 113,795
Impairment of Unproved Properties 2,856 2,701 5,047
Deferred Income Tax Expense (Benefit) 10,681 12,017 (55,055)
Loss (Gain) on Sale of Assets (61) (1,685) 614
Exploration Expense 13,884 12,559 8,031
Other, Net 1,419 176 3,178
Changes in Assets and Liabilities:
Accounts Receivable 8,137 (25,796) (3,848)
Inventories 1,922 (3,201) 2,788
Other Current Assets (539) 46 (13)
Other Assets (680) 243 (37)
Accounts Payable and Accrued Liabilities (10,541) 11,199 5,838
Other Liabilities (970) 3,713 565
---------- ------- -------
Net Cash Provided by Operations 95,040 75,485 41,491
---------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (73,476) (60,719) (24,672)
Cost of Major Acquisition -- -- 8,402
Proceeds from Sale of Assets 48,916 5,725 10,291
Exploration Expense (13,884) (12,559) (8,031)
---------- ------- -------
Net Cash Used by Investing (38,444) (67,553) (14,010)
---------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt 11,000 6,000 16,000
Decrease in Debt (60,000) (7,000) (35,363)
Exercise of Stock Options 2,197 613 348
Preferred Dividends Paid (5,644) (5,566) (5,566)
Common Dividends Paid and Other, Net (3,732) (3,641) (3,644)
---------- ------- -------
Net Cash Used by Financing (56,179) (9,594) (28,225)
---------- ------- -------
Net Increase (Decrease) in Cash and
Cash Equivalents 417 (1,662) (744)
Cash and Cash Equivalents, Beginning of Year 1,367 3,029 3,773
---------- ------- -------
Cash and Cash Equivalents, End of Year $ 1,784 $ 1,367 $ 3,029
========== ======= =======
- ----------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial
statements.
33
35
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, 1995 $ 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, 1996 $ 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, 1997 $ 2,284 $ 183 $243,283 $(85,046) $ 160,704
======= ===== ======== ======== =========
Net Income 28,334 28,334
Exercise of Stock Options 14 2,183 2,197
Preferred Stock Dividends (5,103) (5,103)
Common Stock Dividends (3,732) (3,732)
at $0.16 Per Share
Stock Grant Vesting 1,662 1,662
Conversion of $3.125 Preferred
Stock to Common Stock 165 (70) (95) 0
Other 4 (4) 0
------- ----- -------- -------- ---------
BALANCE AT DECEMBER 31, 1997 $ 2,467 $ 113 $247,033 $(65,551) $ 184,062
======= ===== ======== ======== =========
- ---------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial
statements.
34
36
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.
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 it is determined
that the sum of expected future net cash flows is less than the net book value
(See Note 15 Accounting For Long-Lived Assets). The Company makes a
determination of an impairment event through either adverse changes or a
periodic review of all fields each year.
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 when a group
of proved properties (or field), constituting the amortization base, has been
retired, abandoned or sold.
35
37
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 $5.5 million and $10.4 million
at December 31, 1997 and 1996, respectively.
EARNINGS (LOSS) PER COMMON SHARE
In February 1997, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 128, Earnings per Share ("SFAS
128"). The Company has adopted this statement effective December 31, 1997. SFAS
128 simplifies the computation of earnings per share for companies with complex
capital structure by replacing primary and fully diluted presentations with the
new basic and diluted disclosures. It has not impacted the Company's previously
disclosed earnings per share since the Company had a simple capital structure
and because earnings per share in prior years was calculated in the same manner
that the new "Basic" earnings per share is presented. Basic earnings per share
amounts are based on the weighted average of shares outstanding ( 23,272,432 in
1997 and 22,806,516 in 1996). See Note 20 Earnings (Loss) Per Common Share for
further discussion.
RISK MANAGEMENT ACTIVITIES
From time to time, the Company enters into derivative contracts, such as
natural gas price swaps, as a hedging strategy to manage commodity price risk
associated with its inventories, production or other contractual commitments.
Gains or losses on these hedging activities are generally recognized over the
period that the inventory, production or other underlying commitment is hedged.
The cash flows related to any recognized gains or losses associated with these
hedges are reported as cash flows from operations. If the hedge is terminated
prior to expected maturity, gains or losses are deferred and included in income
in the same period that the underlying production or other contractual
commitment is delivered. Unrealized gains or losses associated with any
derivative contracts not considered to be a hedge are recognized currently in
the results of operations.
36
38
The conditions to be met for a derivative instrument to qualify as a hedge
are as follows: (1) the item to be hedged exposes the Company to price risk; (2)
the derivative reduces the risk exposure and is designated as a hedge at the
time the derivative contract is entered into; and (3) at the inception of the
hedge and throughout the hedge period there is a high correlation of the changes
in the market value of the derivative instrument and the fair value of the
underlying item being hedged.
When the designated item associated with a derivative instrument matures,
is sold, extinguished or terminated, derivative gains or losses are recognized
as part of the gain or loss on sale or settlement of the underlying item. When a
derivative instrument is associated with an anticipated transaction that is no
longer expected to occur or if correlation no longer exists, the gain or loss on
the derivative is recognized currently in the results of operations to the
extent the market value changes in the derivative have not been offset by the
effects of the price changes on the hedged item since the inception of the
hedge. See Note 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 year
ended 1995 have been reclassified to conform with the 1996 and 1997
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) 1997 1996
- ------------------------------------------------------------
Unproved Oil and Gas Properties $ 24,618 $ 15,746
Proved Oil and Gas Properties 744,381 811,726
Gathering and Pipeline Systems 116,360 150,910
Land, Building and Improvements 3,896 5,221
Other 17,525 16,028
--------- ---------
906,780 999,631
Accumulated Depreciation,
Depletion and Amortization (437,381) (519,120)
--------- ---------
$ 469,399 $ 480,511
========= =========
As a component of accumulated depreciation, depletion and amortization,
total accrued future plug and abandonment cost was $13.1 million and $14.8
million at December 31, 1997 and 1996, respectively. The Company believes that
this accrual adequately provides for its estimated future plug and abandonment
cost.
37
39
3. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
December 31,
(In thousands) 1997 1996
- ------------------------------------------------------------------------
Accounts Receivable
Trade Accounts $ 49,315 $ 63,458
Insurance Recoveries 3,043 --
Current Income Tax Receivable 1,291 --
Other Accounts 6,562 5,021
-------- --------
60,211 68,479
Allowance for Doubtful Accounts (539) (669)
-------- --------
$ 59,672 $ 67,810
======== ========
Accounts Payable
Trade Accounts $ 6,209 $ 12,277
Natural Gas Purchases 13,991 20,726
Royalty and Other Owners 11,995 13,469
Capital Costs 12,936 5,409
Dividends Payable 851 1,391
Taxes Other Than Income 1,478 1,170
Drilling Advances 2,333 111
Other Accounts 2,555 1,785
-------- --------
$ 52,348 $ 56,338
======== ========
Accrued Liabilities
Employee Benefits $ 6,067 $ 4,432
Taxes Other Than Income 8,314 8,407
Interest Payable 2,147 2,188
Other Accrued 996 1,252
-------- --------
$ 17,524 $ 16,279
======== ========
Other Liabilities
Postretirement Benefits Other Than Pension $ 992 $ 1,853
Accrued Pension Cost 3,742 4,022
Taxes Other Than Income and Other 4,029 4,718
-------- --------
$ 8,763 $ 10,593
======== ========
4. INVENTORIES
Inventories are comprised of the following:
December 31,
(In thousands) 1997 1996
- --------------------------------------------------------------------------------
Natural Gas in Storage $ 6,322 $ 7,312
Tubular Goods and Well Equipment 1,663 1,677
Pipeline Exchange Balances (1,110) (192)
---------- ---------
$ 6,875 $ 8,797
========== =========
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
38
40
more favorable rate, prime rate minus 1% versus prime rate, the terms of the new
line of credit are comparable to the previous line of credit. At December 31,
1997 and 1996, 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
payment due in May 1998 is classified as "Current Portion of Long-Term Debt", a
current liability on the Company's Consolidated Balance Sheet. 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 and 1997. 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 and a required asset coverage ratio (present value of
proved reserves to debt and other liabilities) that must be at least 1.5 to 1.0.
7.19% NOTES
In November 1997, the Company issued an aggregate principal amount of
$100 million of its 12-year 7.19% Notes (the "7.19% Notes") to a group of six
institutional investors in a private placement offering. The 7.19% Notes require
five annual $20 million principal payments starting in November 2005. The
Company may prepay all or any portion of the indebtedness on any date with a
prepayment premium. The 7.19% Notes contain restrictions on the merger of the
Company or any subsidiary with a third party other than under certain limited
conditions, as well as various other restrictive covenants customarily found in
such debt instruments, including a required asset coverage ratio (present value
of proved reserves to debt and other liabilities) that must be at least 1.5 to
1.0; and a minimum annual coverage ratio of operating cash flow to interest
expense for the trailing four quarters of 2.8 to 1.0.
REVOLVING CREDIT AGREEMENT
The Company has a $135 million Revolving Credit Agreement (the "Credit
Facility") with five banks. During 1997, the Company elected to reduce its
availability under the Credit Facility to the existing $135 million level from
$235 million in connection with the issuance of the 7.19% Notes. 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 1997, the revolving term under the Credit Facility was extended
one year to June 1999. 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,
1997, 1996 and 1995 were 6.6%, 6.6% and 6.8%, respectively. Although the
revolving term of the Credit Facility expires in June 1999, 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.
39
41
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,
1997, 1996 and 1995 are comprised of the following:
(In thousands) 1997 1996 1995
- --------------------------------------------------------------------------------------------
QUALIFIED:
Current Year Service Cost $ 753 $ 737 $ 722
Interest Accrued on Pension Obligation 810 744 742
Actual Return on Plan Assets (1,129) (948) (1,327)
Net Amortization 491 448 934
Curtailment Gain -- -- (376)
Special Termination Benefit -- -- 766
------- -------- ---------
Net Periodic Pension Cost $ 925 $ 981 $ 1,461
======= ======== =========
NON-QUALIFIED:
Current Year Service Cost $ 28 $ 90 $ 63
Interest Accrued on Pension Obligation 6 6 23
Net Amortization 27 34 39
Curtailment Loss -- -- 37
Settlement Charge -- -- 174
------- -------- ---------
Net Periodic Pension Cost $ 61 $ 130 $ 336
======= ======== =========
The following table sets forth the funded status of the Company's pension
plans at December 31, 1997 and 1996, respectively:
1997 1996
(In thousands) QUALIFIED NON-QUALIFIED QUALIFIED NON-QUALIFIED
- ------------------------------------------------------------------------------------------------------
Actuarial Present Value of:
Vested Benefit Obligation $ 7,838 $ 246 $ 6,946 $ 31
Accumulated Benefit Obligation 8,669 363 7,621 81
Projected Benefit Obligation $ 12,772 $ 668 $ 10,960 $ 81
Plan Assets at Fair Value 8,890 -- 7,074 --
-------- -------- --------- ---------
Projected Benefit Obligation in Excess
of Plan Assets 3,882 668 3,886 81
Unrecognized Net Gain (Loss) 1,527 (436) 1,750 140
Adjustment to Recognize Minimum
Liability 480
Unrecognized Prior Service Cost (862) (349) (950) (386)
-------- -------- --------- --------
Accrued (Prepaid) Pension Cost $ 4,547 $ 363 $ 4,686 $ (165)
======== ======== ========= ========
40
42
Assumptions used to determine benefit obligations and pension costs are as
follows:
1997 1996 1995
- --------------------------------------------------------------------------------
Discount Rate 7.50% 7.50% 7.50%(1)
Rate of Increase in Compensation Levels 4.50% 4.50% 4.50%(1)
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, $0.6 million and $0.8 million in 1997, 1996 and 1995,
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 259 retirees and 295 retirees at the end of
1997 and 1996, 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
1997, 1996 and 1995, 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,
1997, 1996 and 1995 are comprised of the following:
(In thousands) 1997 1996 1995
- -----------------------------------------------------------------------------------------------
Service Cost of Benefits Earned During the Year $ 168 $ 99 $ 140
Interest Cost on the Accumulated Postretirement
Benefit Obligation 519 522 517
Amortization Benefit of the Unrecognized Gain (181) (163) (249)
Amortization Cost (Benefit) of the Unrecognized
Transition Obligation (808) (807) (821)
Curtailment Loss -- -- 2,074
Special Termination -- -- 503
------- ------- -------
Total Postretirement Benefit Cost (Benefit) $ (302) $ (349) $ 2,164
======= ======= =======
41
43
The health care cost trend rate used to measure the expected cost in 1997
for medical benefits to retirees over age 65 was 8.2%, 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 8.5%, 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, 1997 and 1996 was 7.5%.
A one-percentage-point increase in health care cost trend rates for future
periods would increase the accumulated net postretirement benefit obligation by
approximately $167 thousand and, accordingly, the total postretirement benefit
cost recognized in 1996 would have also increased by approximately $17 thousand.
The funded status of the Company's postretirement benefit obligation at
December 31, 1997 and 1996 is comprised of the following:
(In thousands) 1997 1996
- ------------------------------------------------------------------------------------------
Plan Assets at Fair Value $ -- $ --
Accumulated Postretirement Benefits Other Than Pensions
Retirees 5,626 5,681
Active Participants 1,677 1,526
-------- -------
7,303 7,207
Unrecognized Cumulative Net Gain 2,429 2,614
Unrecognized Transition Obligation (8,395) (7,587)
-------- -------
Accrued Postretirement Benefit Liability $ 1,337 $ 2,234
======== =======
7. INCOME TAXES
Income tax expense (benefit) is summarized as follows:
Year Ended December 31,
(In thousands) 1997 1996 1995
- ------------------------------------------------------------------------------------
CURRENT:
Federal $ 5,210 $ (1,229) $ --
State 1,089 316 30
---------- ---------- -----------
Total 6,299 (913) 30
---------- ---------- -----------
DEFERRED:
Federal 9,382 9,756 (46,430)
State 1,876 1,711 (8,625)
---------- ---------- ----------
Total 11,258 11,467 (55,055)
---------- ---------- ----------
Total Income Tax Expense (Benefit) $ 17,557 $ 10,554 $ (55,025)
========== ========== ==========
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) 1997 1996 1995
- -----------------------------------------------------------------------------------------
Statutory Federal Income Tax Rate 35% 35% 35%
Computed "Expected" Federal Income Tax $ 16,062 $ 10,982 $(49,575)
State Income Tax, Net of Federal Income Tax 1,927 1,317 (5,586)
Other, Net (432) (1,745) 136
-------- -------- --------
Total Income Tax Expense (Benefit) $ 17,557 $ 10,554 $(55,025)
======== ======== ========
42
44
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.
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, 1997 and 1996 were as follows:
(In thousands) 1997 1996
- ----------------------------------------------------------------------------
DEFERRED TAX LIABILITIES:
Property, Plant and Equipment $115,808 $115,099
-------- --------
DEFERRED TAX ASSETS:
Alternative Minimum Tax Credit Carryforwards 9,674 3,786
Net Operating Loss Carryforwards 6,749 17,708
Note Receivable on Section 29 Monetization(1) 13,933 18,347
Items Accrued for Financial Reporting Purposes 5,344 5,831
-------- --------
35,700 45,672
-------- --------
Net Deferred Tax Liabilities $ 80,108 $ 69,427
======== ========
- ----------------------------------------------------------------------------
(1) As a result of the monetization of Section 29 tax credits in 1997 and 1996,
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, 1997, the Company has a net operating loss carryforward
for regular income tax reporting purposes of $18.2 million which will begin
expiring in 2009. In addition, the Company has an alternative minimum tax credit
carryforward of $9.7 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 totaled $4.1 million, $4.8 million
and $4.9 million for the years ended December 31, 1997, 1996 and 1995,
respectively. Future minimum rental commitments under non-cancelable leases in
effect at December 31, 1997 are as follows:
(In thousands)
- ----------------------------------------------
1998 $ 2,932
1999 2,146
2000 1,422
2001 1,039
2002 906
Thereafter 430
--------
$ 8,875
========
Minimum rental commitments are not reduced by minimum sublease rental
income of $1.4 million due in the future under non-cancelable subleases.
43
45
CONTINGENCIES
The Company is a defendant in various lawsuits and is involved in other
gas contract issues. In the opinion of the Company, final judgments 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.
The Company sells approximately 20,000 Mmbtu of its natural gas per day 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) 1997 1996 1995
- --------------------------------------------------------------------------------
Interest $18,001 $17,105 $24,744
Income Taxes $ 8,980 $ 873 $ 197
At December 31, 1997 and 1996, 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.
At December 31, 1997 and 1996, the Accounts Payable balance on the
Consolidated Balance Sheet included payables for capital expenditures of $12.9
million and $5.4 million, respectively.
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 most 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:
44
46
December 31,
1997 1996 1995
- --------------------------------------------------------------------------------------
Shares Under Option at
Beginning of Period 1,532,353 1,310,318 953,775
Granted 82,500 311,750 565,750
Exercised 139,836 41,094 2,400
Surrendered or Expired 70,140 48,621 206,807
---------- ---------- ----------
Shares Under Option at
End of Period 1,404,877 1,532,353 1,310,318
========== ========== ==========
Option Price Range per Share $ 13.25 - $ 13.25 - $ 13.25 -
26.00 26.00 26.00
Options Exercisable at End
of Period 1,071,923 1,021,362 852,692
========== =========== ==========
Under the 1994 Long-Term Incentive plan, the Compensation Committee of the
Board of Directors may grant awards of performance shares of stock to members of
the executive management group. Each grant of performance shares has a
three-year performance period, measured as the change from July 1 of the initial
year of the performance period to June 30 of the third succeeding year. The
number of shares of common stock received at the end of the performance period
is based principally on the relative stock price growth between the two
measurement dates of the Company's common stock as compared to that of a list of
company peers. The performance shares which were granted on July 1, 1994,
expired on June 1, 1997 without the issuance of any common stock of the Company.
Performance shares granted in July of 1995 and 1996 may be converted to shares
of common stock, depending upon the Company's relative performance to the peer
group measured on June 1st of 1998 and 1999, respectively.
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.
The pro forma results of operations, had the Company adopted SFAS 123,
were net income of $22.9 million and $14.8 million, or $0.98 and $0.65 per
share, in 1997 and 1996, respectively, 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 1997, 1996 and 1995 were $4.26, $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 1997, 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 each of the three years
is 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, 1997, such restrictions
had no adverse impact on the Company's ability to pay regular dividends. The
agreement related to 7.19% Notes issued in 1997 contains no restricted payment
provision.
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
45
47
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, 1997, 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, 692,439 shares of the Company's $3.125 cumulative
convertible preferred stock ("$3.125 preferred stock") were issued and
outstanding. Each share had a stated value of $50 and was convertible any time
by the holder into Common Stock at a conversion price of $21 per share. These
shares were also redeemable under certain provisions and fixed redemption
prices. The Company had the option to convert the $3.125 preferred stock into
shares of Common Stock valued at the conversion price if the closing price of
the Common Stock was at least equal to the conversion price for 20 consecutive
trading days. In October 1997, the Company exercised this right and converted
all of the 692,439 shares of $3.125 preferred stock into 1,648,664 shares of
Common Stock.
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.
46
48
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 terminations 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.
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, 1997 DECEMBER 31, 1996
CARRYING ESTIMATED CARRYING ESTIMATED
(IN THOUSANDS) AMOUNT FAIR VALUE AMOUNT FAIR VALUE
- -----------------------------------------------------------------------------------------------
DEBT:
10.18% Notes $ 80,000 $ 86,555 $ 80,000 $ 86,433
7.19% Notes 100,000 102,693 -- --
Credit Facility 19,000 19,000 168,000 168,000
---------- ---------- --------- ----------
$ 199,000 $ 208,248 $ 248,000 $ 254,433
========== ========== ========= ==========
OTHER FINANCIAL INSTRUMENTS:
Gas Price Swaps -- $ (350) -- $ 763
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 and the
7.19% 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.
47
49
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.
GAS PRICE SWAPS
The Company has entered into several price swap agreements with
counterparties. In a majority of the natural gas price swap agreements in 1996,
the Company received 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. During 1997, the Company
entered into no fixed price swap contracts to hedge prices on its production.
Typically, the Company enters into contracts to sell its natural gas at a
variable price based on the market index price. However, in some circumstances,
some of the Company's customers request that a fixed price be stated in the
contract. After entering into these certain fixed price sales contracts to meet
the needs of its customers, the Company typically opens gas swap agreements to
convert these fixed price contracts to market-sensitive price contracts. These
agreements had total notional quantities of 2,683,000 Mmbtu and 1,002,000 Mmbtu
in closed contracts in 1997 and 1996, respectively. In 1997 and 1996, this
represented approximately 7% and 3%, respectively, of the Company's total volume
of brokered gas sold. Additional agreements which remained open at year end had
notional quantities of 248,000 Mmbtu and 744,000 Mmbtu in 1997 and 1996,
respectively.
The estimated fair value of price swaps in the table above are 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).
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.
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.
48
50
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 1995 of $113.8 million ($69.2
million after tax).
16. OIL AND GAS PROPERTY TRANSACTIONS
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.
In the fourth quarter of 1997, the Company closed two notable asset
transactions. Properties in northwest Pennsylvania (the "Meadville properties"),
including 912 wells and 15 Mmcfed of production, were sold to Lomak Petroleum
Incorporated for $92.9 million. In a like-kind exchange transaction, the Company
matched a portion of the Meadville properties sold with approximately $45
million in oil and gas producing properties acquired from Equitable Resources
Energy Company, including 63 wells and 10 Mmcfed of production.
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 ($3.6 million in 1997 and $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 as Other Revenue until the production payment is satisfied.
49
51
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 $24.6 million, $15.7 million, and
$12.5 million at December 31, 1997, 1996, and 1995, 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).
1997 1996 1995
-------------------- ------------------- --------------------------
SUCCESSFUL FULL SUCCESSFUL FULL SUCCESSFUL FULL
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) EFFORTS COST EFFORTS COST EFFORTS COST
- ----------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET:
Properties and Equipment, Net $ 469,399 $ 651,739 $ 480,511 $ 657,957 $ 474,371 $ 646,322
Stockholders' Equity 184,062 296,201 160,704 269,833 147,856 253,606
INCOME STATEMENT:
Depreciation, Depletion, Amortization
and Unproved Property Impairment $ 43,454 $ 52,383 $ 45,390 $ 50,769 $ 52,253 $ 51,922
Impairment of Long-Lived Assets -- -- -- -- 113,795 --
Impairment - Full Cost Ceiling -- -- -- -- -- --
Net Income (Loss) Applicable
to Common Stockholders 23,231 26,240 15,258 18,637 (92,171) (17,481)
Basic Earnings (Loss) Per Share $ 1.00 $ 1.13 $ 0.67 $ 0.82 $ (4.05 $ (0.77)
20. EARNINGS (LOSS) PER COMMON SHARE
The adoption of SFAS 128 effective December 31, 1997, requires the
restatement of Earnings (Loss) Per Share of each year presented in the
Consolidated Statement of Operations. Since the Company has a simple capital
structure, previously disclosed Earnings (Loss) Per Share represents Basic
Earnings (Loss) Per Share. Diluted Earnings (Loss) Per Share reflects the
assumed conversion of outstanding stock options and stock grants.
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.
During 1997, 1,648,664 common shares were issued upon conversion of all of
the 692,439 shares of $3.125 Cumulative Convertible Preferred stock. The
preferred stock became convertible at the Company's option when the
50
52
Company's common shares closed at or above the $21.00 conversion price of the
$3.125 cumulative convertible preferred stock for twenty consecutive days.
Earnings per share, basic and diluted, are calculated as follows:
(in thousands, except per share data) 1997 1996 1995
- -----------------------------------------------------------------------------------------------
BASIC EARNINGS (LOSS) PER COMMON SHARE:
Income before cumulative effect of changes $ 23,231 $ 15,258 $(22,984)
in accounting principles
Cumulative effect of changes in accounting principles -- -- (69,187)
-------- -------- --------
Net Income - Basic EPS $ 23,231 $ 15,258 $(92,171)
Weighted average common shares outstanding 23,272 22,807 22,775
Basic earnings (loss) per common share $ 1.00 $ 0.67 $ (4.05)
=================================================================================================
DILUTED EARNINGS (LOSS) PER COMMON SHARE:
Income before cumulative effect of changes $ 23,231 $ 15,258 $(22,984)
in accounting principles
Cumulative effect of changes in accounting principles -- -- (69,187)
-------- -------- --------
Net Income - Diluted EPS $ 23,231 $ 15,258 $(92,171)
Diluted earnings (loss) per common share $ 0.97 $ 0.66 $ (4.05)
Weighted average common shares outstanding 23,272 22,807 22,775
Dilutive effect of:
Stock Options(1) 275 70 --
Stock Grants(1) 375 116 --
Weighted average shares outstanding - Diluted 23,922 22,993 22,775
=====================================================================================================
(1) In 1995, the stock options and stock grants are anti-dilutive and,
therefore, excluded from the calculation of Diluted Earnings (Loss) Per Share.
51
53
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, 1997,
1996 and 1995 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 9,1998 that, based on their investigation and subject to the
limitations described in such letter, it was their judgment that the results of
those estimates and projections for 1997 were reasonable in the aggregate.
No major discovery or other favorable or adverse event subsequent to
December 31, 1997 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.
Natural Gas
---------------------------------------------
December 31,
(Millions of cubic feet) 1997 1996 1995
- ------------------------------------------------------------------------------------------------
PROVED RESERVES
Beginning of Year 915,617 889,850 953,083
Revisions of Prior Estimates 6,744 2,774 14,032
Extensions, Discoveries and Other Additions 109,191 69,708 34,408
Production (63,889) (58,762) (57,721)
Purchases of Reserves in Place 73,836 37,397 1,416
Sales of Reserves in Place (138,070) (25,350) (55,368)
-------- ------- -------
End of Year 903,429 915,617 889,850
======= ======= =======
PROVED DEVELOPED RESERVES 738,764 768,097 747,235
======= ======= =======
52
54
Liquids
----------------------------------
December 31,
(Thousands of barrels) 1997 1996 1995
- ---------------------------------------------------------------------------------------
PROVED RESERVES
Beginning of Year 5,166 5,310 8,036
Revisions of Prior Estimates 99 (132) (648)
Extensions, Discoveries and Other Additions 794 386 174
Production (629) (597) (740)
Purchases of Reserves in Place 594 215 15
Sales of Reserves in Place (155) (16) (1,527)
----- ----- -----
End of Year 5,869 5,166 5,310
===== ===== =====
PROVED DEVELOPED RESERVES 4,859 4,685 4,970
===== ===== =====
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) 1997 1996 1995
- -------------------------------------------------------------------------------
Aggregate Capitalized Costs Relating
to Oil and Gas Producing Activities $ 904,669 $ 997,531 $ 977,885
Aggregate Accumulated Depreciation,
Depletion and Amortization $ 435,502 $ 517,249 $ 503,757
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) 1997 1996 1995
- --------------------------------------------------------------------------------
Property Acquisition Costs - Proved $ 45,573 $ 6,637 $ 33
Property Acquisition Costs - Unproved 4,302 4,355 2,006
Exploration and Extension Well Costs 28,633 14,192 8,670
Development Costs 53,441 41,036 18,610
-------- -------- --------
Total Costs $131,949 $ 66,220 $ 29,319
======== ======== ========
53
55
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) 1997 1996 1995
- ----------------------------------------------------------------------------------
Operating Revenues $ 173,865 $ 150,096 $ 110,418
Costs and Expenses
Production 39,068 35,161 34,062
Other Operating 18,017 15,155 22,783
Exploration 13,884 12,559 8,031
Depreciation, Depletion and
Amortization 39,485 40,810 161,886
--------- --------- ---------
Total Cost and Expenses 110,454 103,685 226,762
--------- --------- ---------
Income (Loss) Before Income Taxes 63,411 46,411 (116,344)
Provision for Income Taxes
Expense (Benefit) 22,194 16,244 (40,720)
--------- --------- ---------
Results of Operations $ 41,217 $ 30,167 $ (75,624)
========= ========= =========
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, 1997, 1996
and 1995 were for oil ($/Bbl) $19.02, $22.86 and $17.06, respectively, and for
natural gas ($/Mcf) $2.44, $3.55 and $2.06, 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.
54
56
Standardized Measure is as follows:
Year Ended December 31,
(In thousands) 1997(1) 1996(1) 1995
- ----------------------------------------------------------------------------------------------
Future Cash Inflows $2,539,287 $ 3,528,558 $ 2,194,751
Future Production and
Development Costs (686,689) (773,631) (644,586)
---------- ----------- -----------
Future Net Cash Flows Before
Income Taxes 1,852,598 2,754,927 1,550,165
10% Annual Discount for
Estimated Timing of Cash Flows (1,013,837) (1,589,290) (884,861)
---------- ----------- -----------
Standardized Measure of
Discounted Future Net Cash Flows
Before Income Taxes 838,761 1,165,637 665,304
Future Income Tax Expenses,
Net of 10% Annual Discount(2) (227,796) (331,331) (152,356)
---------- ----------- -----------
Standardized Measure of Discounted
Future Net Cash Flows (3) $ 610,965 $ 834,306 $ 512,948
========== =========== ===========
(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 $582,639, $887,583 and $462,058
for the years ended December 31, 1997, 1996 and 1995, respectively.
(3) The change in discounted future cash flows from 1996 to 1997 is primarily a
result of the $1.11 per Mcf decrease in average natural gas price.
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) 1997 1996 1995
- -------------------------------------------------------------------------------------------------
Beginning of Year $ 834,306 $ 512,948 $ 490,495
Discoveries and Extensions,
Net of Related Future Costs 113,032 99,983 21,881
Net Changes in Prices and
Production Costs (367,112) 416,042 57,057
Accretion of Discount 116,564 66,530 61,566
Revisions of Previous Quantity
Estimates, Timing and Other (10,798) (7,874) 1,707
Development Costs Incurred 17,435 10,294 5,665
Sales and Transfers, Net of
Production Costs (138,274) (114,935) (76,356)
Net Purchases (Sales) of
Reserves in Place (57,723) 30,293 (21,878)
Net Change in Income Taxes 103,535 (178,975) (27,189)
---------- ----------- -----------
End of Year $ 610,965 $ 834,306 $ 512,948
========== ========== ==========
55
57
CABOT OIL & GAS CORPORATION
SELECTED DATA (UNAUDITED)
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
(In thousands except per share amounts) First Second Third Fourth Total
- -------------------------------------------------------------------------------------------------------
1997
NET OPERATING REVENUES $ 52,792 $ 39,407 $ 40,773 $ 52,155 $185,127
OPERATING INCOME 22,715 10,013 10,830 20,294 63,852
NET INCOME 9,692 1,955 2,289 9,295 23,231
BASIC EARNINGS PER SHARE $ 0.42 $ 0.09 $ 0.10 $ 0.39 $ 1.00
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
Basic Earnings Per Share $ 0.23 $ 0.04 $ 0.13 $ 0.27 $ 0.67
- -------------------------------------------------------------------------------------------------------
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 1998 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.
56
58
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES AND REPORTS ON FORM 8-K
A. INDEX
1. CONSOLIDATED FINANCIAL STATEMENTS
See Index on page 30.
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 6% Convertible Redeemable Preferred
Stock (Form 10-K for 1994).
4.5 Amended and Restated Credit Agreement dated as of May 30, 1995 among
the Company, Morgan Guaranty Trust Company, as agent and the banks
named therein.
(a) Amendment No. 1 to Credit Agreement dated September 15, 1995
(Form 10-K for 1995).
(b) Amendment No. 2 to Credit Agreement dated December 24, 1996
(Form 10-K for 1996).
4.6 Note Purchase Agreement dated May 11, 1990 among the Company and
certain insurance companies parties thereto (Form 10-Q for the quarter
ended June 30, 1990).
(a) First Amendment dated June 28, 1991 (Form 10-K for 1994).
(b) Second Amendment dated July 6, 1994 (Form 10-K for 1994).
4.7 Note Purchase Agreement dated November 14, 1997 among the Company and
the purchasers named therein.
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).
57
59
10.7 Transaction Agreement between Cabot Corporation and the Company dated
February 1, 1991 (Registration Statement No. 33-37455).
10.8 Tax Sharing Agreement between Cabot Corporation and the Company dated
February 1, 1991 (Registration Statement No. 33-37455).
10.9 Amendment Agreement (amending the Transaction Agreement and the Tax
Sharing Agreement) dated March 25, 1991. (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
(Form 10-K for 1996).
10.11 Supplemental Executive Retirement Agreements of the Company (Form 10-K
for 1991).
10.12 Settlement Agreement and Mutual Release (Tax Issues) between Cabot
Corporation and the Company dated July 7, 1992 (Form 10-Q for the
quarter ended June 30, 1992).
10.13 Agreement of Merger dated February 25, 1994 among Washington Energy
Company, Washington Energy Resources Company, the Company and COG
Acquisition Company (Form 10-K for 1993).
10.14 1990 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).
10.18 Form of Indemnity Agreement between the Company and Certain Officers.
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 9, 1998.
B. REPORTS ON FORM 8-K
None
58
60
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 1998.
CABOT OIL & GAS CORPORATION
By: /s/ Charles P. Siess, Jr.
---------------------------------
Charles P. Siess, Jr.
Chairman of the Board and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons in the capacities and on
the dates indicated.
Signature Title Date
--------- ----- ----
/s/ Charles P. Siess, Jr. Chairman of the Board and March 10, 1998
- -------------------------------- Chief Executive Officer
Charles P. Siess, Jr (Principal Executive Officer)
/s/ Ray R. Seegmiller President, Chief Operating March 10, 1998
- -------------------------------- Officer and Director
Ray R. Seegmiller (Principal Financial Officer)
/s/ Paul F. Boling Controller March 10, 1998
- -------------------------------- (Principal Accounting Officer)
Paul F. Boling
/s/ Robert F. Bailey Director March 10, 1998
- --------------------------------
Robert F. Bailey
/s/ Samuel W. Bodman Director March 10, 1998
- --------------------------------
Samuel W. Bodman
/s/ Henry O. Boswell Director March 10, 1998
- --------------------------------
Henry O. Boswell
/s/ John G. L. Cabot Director March 10, 1998
- --------------------------------
John G. L. Cabot
/s/ William R. Esler Director March 10, 1998
- --------------------------------
William R. Esler
/s/ William H. Knoell Director March 10, 1998
- --------------------------------
William H. Knoell
/s/ C. Wayne Nance Director March 10, 1998
- --------------------------------
C. Wayne Nance
/s/ William P. Vititoe Director March 10, 1998
- --------------------------------
William P. Vititoe
59
61
EXHIBIT INDEX
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 6% Convertible Redeemable Preferred
Stock (Form 10-K for 1994).
4.5 Amended and Restated Credit Agreement dated as of May 30, 1995 among
the Company, Morgan Guaranty Trust Company, as agent and the banks
named therein.
(a) Amendment No. 1 to Credit Agreement dated September 15, 1995
(Form 10-K for 1995).
(b) Amendment No. 2 to Credit Agreement dated December 24, 1996
(Form 10-K for 1996).
4.6 Note Purchase Agreement dated May 11, 1990 among the Company and
certain insurance companies parties thereto (Form 10-Q for the quarter
ended June 30, 1990).
(a) First Amendment dated June 28, 1991 (Form 10-K for 1994).
(b) Second Amendment dated July 6, 1994 (Form 10-K for 1994).
4.7 Note Purchase Agreement dated November 14, 1997 amoung the Company and
the purchasers named therein.
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).
62
10.7 Transaction Agreement between Cabot Corporation and the Company dated
February 1, 1991 (Registration Statement No. 33-37455).
10.8 Tax Sharing Agreement between Cabot Corporation and the Company dated
February 1, 1991 (Registration Statement No. 33-37455).
10.9 Amendment Agreement (amending the Transaction Agreement and the Tax
Sharing Agreement) dated March 25, 1991. (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
(Form 10-K for 1996).
10.11 Supplemental Executive Retirement Agreements of the Company (Form 10-K
for 1991).
10.12 Settlement Agreement and Mutual Release (Tax Issues) between Cabot
Corporation and the Company dated July 7, 1992 (Form 10-Q for the
quarter ended June 30, 1992).
10.13 Agreement of Merger dated February 25, 1994 among Washington Energy
Company, Washington Energy Resources Company, the Company and COG
Acquisition Company (Form 10-K for 1993).
10.14 1990 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).
10.18 Form of Indemnity Agreement between the Company and Certain Officers.
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 9, 1998.