United States
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 September 30, 2000
Commission File Number 1-3880
National
Fuel Gas Company
(Exact name of registrant as specified in its charter)
| New Jersey | 13-1086010 |
|---|---|
| (State or other jurisdiction of | (I.R.S. Employer |
| incorporation or organization) | Identification No.) |
| 10 Lafayette Square | 14203 |
| Buffalo, New York | (Zip Code) |
(Address of principal executive offices)
(716)
857-7000
Registrant's telephone number, including area code
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Name of each exchange on which registered |
|---|---|
| Common Stock, $1 Par Value, and | New York Stock Exchange |
| Common Stock Purchase Rights |
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 the 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. [ X ]
The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $2,207,381,000 as of November 30, 2000.
Common Stock, $1 Par Value, outstanding as of November 30, 2000: 39,384,950 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Annual Report to Shareholders for 2000 are incorporated by reference into Part I of this report. Portions of the registrant's definitive Proxy Statement for the Annual Meeting of Shareholders to be held February 15, 2001 are incorporated by reference into Part III of this report.
|
GENERAL INFORMATION ON FACILITIES |
PART I
The Company is a diversified energy company consisting of six reportable business segments.
1. The Utility segment operations are carried out by National Fuel Gas Distribution Corporation (Distribution Corporation), a New York corporation. Distribution Corporation sells natural gas or provides natural gas transportation services to approximately 735,000 customers through a local distribution system located in western New York and northwestern Pennsylvania. The principal metropolitan areas served by Distribution Corporation include Buffalo, Niagara Falls and Jamestown, New York and Erie and Sharon, Pennsylvania.Financial information about each of the Company's business segments can be found in Item 7, MD&A and also in Item 8 at Note I - Business Segment Information.
The Company's other wholly-owned subsidiaries are not included in any of the six reportable business segments and consist of the following:
No single customer, or group of customers under common control, accounted for more than 10% of the Company's consolidated revenues in 2000.
Rates and RegulationThe Utility segment's rates, services and other matters are regulated by the State of New York Public Service Commission (NYPSC) with respect to services provided within New York and by the Pennsylvania Public Utility Commission (PaPUC) with respect to services provided within Pennsylvania. For additional discussion of the Utility segment's rates and regulation, see Item 7, MD&A under the heading "Rate Matters" and Item 8 at Note B-Regulatory Matters.
The Pipeline and Storage segment's rates, services and other matters are regulated by the FERC. SIP is not itself regulated by the FERC, but its sole business is the ownership of an interest in Independence, whose construction, rates, services and other matters are or will be regulated by the FERC. For additional discussion of the Pipeline and Storage segment's rates and regulation, see Item 7, MD&A under the heading "Rate Matters" and Item 8 at Note B-Regulatory Matters.
The discussion under Item 8 at Note B-Regulatory Matters includes a description of the regulatory assets and liabilities reflected on the Company's Consolidated Balance Sheets in accordance with applicable accounting standards. To the extent that the criteria set forth in such accounting standards are not met by the operations of the Utility segment or the Pipeline and Storage segment, as the case may be, the related regulatory assets and liabilities would be eliminated from the Company's Consolidated Balance Sheets and such accounting treatment would be discontinued.
In the International segment, rates charged for the sale of thermal energy and electric energy at the retail level are subject to regulation and audit in the Czech Republic by the Czech Ministry of Finance. The regulation of electric energy rates at the retail level indirectly impacts the rates charged by the International segment for its electric energy sales at the wholesale level.
In addition, the Company and its subsidiaries are subject to the same federal, state and local regulations on various subjects as other companies doing similar business in the same locations.
The Utility SegmentDuring 2000, Distribution reached agreement with the Staff of the New York Department of Public Service, the New York State Consumer Protection Board, and Multiple Intervenors (an advocate for large commercial and industrial customers), that settles rates for a three year period beginning with 2001.
Additional discussion of the Utility segment appears below in this Item 1 under the headings "Sources and Availability of Raw Materials," "Competition" and "Seasonality," in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Pipeline and Storage SegmentSupply Corporation currently has service agreements for substantially all of its firm transportation capacity which totals approximately 1,839 MDth per day. The Utility segment has contracted for approximately 1,149 MDth per day or 62.5% of that capacity until 2003 and continuing year-to-year thereafter. An additional 536 MDth per day or 29.1% of Supply Corporation's firm transportation capacity is subject to firm contracts with nonaffiliated customers until 2003 or later.
Supply Corporation has available for sale to customers approximately 67,409 MDth of firm storage capacity. The Utility segment has contracted for 28,248 MDth or 41.9% of that capacity. Of that, 26,581 MDth or 39.4% of total storage capacity is contracted by the Utility segment under agreements with remaining initial terms expiring in 2003 or later. Other customers, both affiliated and nonaffiliated, have contracted for the remaining 39,161 MDth or 58.1% of firm storage capacity, and 15,276 MDth or 22.7% of total storage capacity is contracted by nonaffiliated customers until 2003 or later. Supply Corporation has been successful in marketing and obtaining executed contracts for storage service (at discounted rates) as it becomes available and expects to continue to do so.*
Additional discussion of the Pipeline and Storage segment appears below under the headings "Sources and Availability of Raw Materials," "Competition" and "Seasonality," in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Exploration and Production SegmentIn June 2000, Seneca, through its wholly-owned subsidiary, NFE, acquired the stock of Tri Link Resources Ltd., a Calgary, Alberta-based exploration and production company for approximately $123.8 million (and another $99.2 million in assumed debt which has been redeemed). Upon completing this acquisition, Tri Link was amalgamated into NFE. This acquisition increased Seneca's total reserve base to approximately one trillion cubic feet equivalent.*
Additional discussion of the Exploration and Production segment appears below under the headings "Sources and Availability of Raw Materials" and "Competition," in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The International SegmentAdditional discussion of the International segment appears below under the heading "Sources and Availability of Raw Materials," "Competition" and "Seasonality," in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Energy Marketing SegmentAdditional discussion of the Energy Marketing segment appears below under the headings "Sources and Availability of Raw Materials," "Competition" and "Seasonality," in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Timber SegmentAdditional discussion of the Timber segment appears below under the headings "Sources and Availability of Raw Materials," "Competition" and "Seasonality," in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
Sources and Availability of Raw MaterialsSupply Corporation transports and stores gas owned by its customers, whose gas originates in the southwestern and Appalachian regions of the United States as well as in Canada. SIP, through Independence, proposes to transport natural gas produced in Canada and in the continental United States.
The Exploration and Production segment seeks to discover and produce raw materials (natural gas, oil and hydrocarbon liquids) as further described in this report in Item 7, MD&A and Item 8 at Notes I-Business Segment Information and M - Supplementary Information for Oil and Gas Producing Activities.
Coal is the principal raw material for the International segment, constituting 45% of the cost of raw materials needed to operate the boilers which produce steam or hot water. Natural gas, oil, limestone and water combined account for the remaining 55% of such materials. Coal is purchased and delivered directly from the Mostecka Uhelna Spolecnost, a.s. mine for Horizon's largest coal-fired plant under a contract where price and quantity are the subject of negotiation each year. Based on the current extraction rate, this mine has proven reserves through 2030. Natural gas is imported by the Czech Republic government from Russia and the North Sea and is transported through the Transgas pipeline system which is majority owned by the Czech government and purchased by the International segment from two of the eight regional gas distribution companies. Oil is also imported. This segment purchases oil from domestic and foreign refineries.
With respect to the Timber segment, Highland requires an adequate supply of timber to process. Highland, however, mainly processes timber which is located on land owned by Seneca, and, therefore, the source and availability of this segment's primary raw material are generally known in advance.
The Energy Marketing segment depends on an adequate supply of natural gas and electricity. In 2000, this segment purchased 35.5 Bcf of natural gas and approximately 57,000 megawatt hours of electricity.
CompetitionThe electric industry is moving toward a more competitive environment as a result of the Federal Energy Policy Act of 1992 and initiatives undertaken by the FERC and various states. It is unclear at this point what impact this restructuring will have on the Company.*
The Company competes on the basis of price, service and reliability, product performance and other factors. Sources and providers of energy, other than those described under this "Competition" heading, do not compete with the Company to any significant extent.*
Competition: The Utility SegmentCompetition for large-volume customers continues with local producers or pipeline companies attempting to sell or transport gas directly to end-users located within the Utility segment's service territories (i.e., bypass). In addition, competition continues with fuel oil suppliers and may increase with electric utilities making retail energy sales.*
The Utility segment is now better able to compete, through its unbundled flexible services, in its most vulnerable markets (the large commercial and industrial markets).* The Utility segment continues to (i) develop or promote new sources and uses of natural gas or new services, rates and contracts and (ii) emphasize and provide high quality service to its customers.
SIP, through Independence, is competing for customers with other proposed pipeline projects which would bring natural gas from the Chicago area to the growing markets in the northeast and mid-Atlantic regions of the United States. In combination with expansion projects of Transcontinental Gas Pipe Line Corporation and ANR Pipeline Company, Independence intends to provide the least-cost path for this service and will access the storage and market hub at Leidy, Pennsylvania.* It is likely that not all of the proposed pipelines will go forward, and that the first project built will have an advantage over other proposed projects.* Independence is the first of the proposed projects to be approved by the FERC. If completed, the Independence pipeline would likely create opportunities for increased transportation and storage services by Supply Corporation.*
Competition: The Exploration and Production SegmentTo compete in this environment, Seneca and its wholly-owned subsidiary, NFE, each originate and act as operator on most prospects, minimize risk of exploratory efforts through partnership-type arrangements, apply the latest technology for both exploratory studies and drilling operations and focus on market niches that suit its size, operating expertise and financial criteria.
Competition: The International SegmentVolumes transported and stored by Supply Corporation may vary materially depending on weather, without materially affecting its earnings. Supply Corporation's rates are based on a straight fixed-variable rate design which allows recovery of all fixed costs in fixed monthly reservation charges. Variable charges based on volumes are designed only to reimburse the variable costs caused by actual transportation or storage of gas.
Variations in weather conditions can materially affect the volume of gas and electricity consumed by customers of the Energy Marketing segment.
The activities of the Timber segment vary on a seasonal basis and are subject to weather constraints. The timber harvesting and processing season occurs when timber growth is dormant and runs from approximately September to March. The operations conducted in the summer months focus on pulpwood and on thinning out lower-grade species from the timber stands to encourage the growth of higher-grade species.
Capital ExpendituresA discussion of capital expenditures by business segment is included in Item 7, MD&A under the heading "Investing Cash Flow."
Environmental MattersAgreements covering employees in collective bargaining units in New York were renegotiated in November 2000, effective beginning on November 26, 2000, and are scheduled to expire in February 2006. Agreements covering most employees in collective bargaining units in Pennsylvania were renegotiated, effective November 1998, and are scheduled to expire in April and May 2003.
The Company has numerous municipal franchises under which it uses public roads and certain other rights-of-way and public property for the location of facilities. When necessary, the Company renews such franchises.
- ----------------------- --------------------------------------------------------
Name and Age(2) Current Company Positions and Other Material
Business Experience During Past 5 Years(3)
- ----------------------- --------------------------------------------------------
Bernard J. Kennedy Chairman of the Board of Directors since March 1989
(69) and Chief Executive Officer since August 1988.
Mr. Kennedy has served as a Director since March 1978
and previously served as President from January 1987
to July 1999.
- ----------------------- --------------------------------------------------------
Philip C. Ackerman President since July 1999, Executive Vice President of
(56) Supply Corporation since October 1994 and President of
Horizon since September 1995. Mr. Ackerman has served
as a Director since March 1994, and previously served
as Senior Vice President from June 1989 to July 1999
and President of Distribution Corporation from October
1995 to July 1999.
- ----------------------- --------------------------------------------------------
Dennis J. Seeley President of Supply Corporation since March 2000.
(57) Mr. Seeley has served as Vice President of the Company
from January 2000 to April 2000, Senior Vice President
of Distribution Corporation from February 1997 to
March 2000 and Senior Vice President of Supply
Corporation from January 1993 to February 1997.
- ----------------------- --------------------------------------------------------
David F. Smith President of Distribution Corporation since July 1999.
(47) Mr. Smith served as Senior Vice President of
Distribution Corporation from January 1993 to July 1999.
- ----------------------- --------------------------------------------------------
James A. Beck President of Seneca since October 1996 and
(53) President of Highland since March 1998. Mr. Beck
previously served as Vice President of Seneca from
January 1994 to April 1995 and Executive Vice President
of Seneca from May 1995 to September 1996.
- ----------------------- --------------------------------------------------------
Joseph P. Pawlowski Treasurer since December 1980; Senior Vice President of
(59) Distribution Corporation since February 1992 and
Treasurer of Distribution Corporation since January
1981; Treasurer of Supply Corporation since June 1985
and Secretary of Supply Corporation since October 1995.
- ----------------------- --------------------------------------------------------
Gerald T. Wehrlin Controller since December 1980; Senior Vice President of
(62) Distribution Corporation since April 1991; Controller of
Seneca since September 1981; Vice President of
Horizon since February 1997. Mr. Wehrlin previously
served as Secretary and Treasurer of Horizon from
September 1995 to February 1997.
- ----------------------- --------------------------------------------------------
- ----------------------- --------------------------------------------------------
Name and Age(2) Current Company Positions and Other Material
Business Experience During Past 5 Years(3)
- ----------------------- --------------------------------------------------------
Walter E. DeForest Senior Vice President of Distribution Corporation since
(59) August 1993.
- ----------------------- --------------------------------------------------------
Bruce H. Hale Senior Vice President of Supply Corporation since
(51) February 1997 and Vice President of Horizon since
September 1995. Mr. Hale previously served as Senior
Vice President of Distribution Corporation from
January 1993 to February 1997.
- ----------------------- --------------------------------------------------------
(1) |
The Company has been advised that there are no family relationships among
any of the officers listed, and that there is no arrangement or
understanding among any one of them and any other persons pursuant to
which he was elected as an officer. The executive officers serve at the
pleasure of the Board of Directors. |
(2) |
Ages are as of September 30, 2000. |
(3) |
The information provided relates to the principal subsidiaries of the
Company. Many of the executive officers have in the past or currently
serve as officers or directors for other subsidiaries of the Company. |
The Utility segment has a net investment in property, plant and equipment of $939.8 million at September 30, 2000. The net investment in its gas distribution network (including 14,769 miles of distribution pipeline) and its services represent approximately 57% and 29%, respectively, of the Utility segment's net investment in property, plant and equipment at September 30, 2000.
The Pipeline and Storage segment represents a net investment of $475 million in property, plant and equipment at September 30, 2000. Transmission pipeline, with a net cost of $131.1 million, represents 28% of this segment's total net investment and includes 2,556 miles of pipeline required to move large volumes of gas throughout its service area. Storage facilities consist of 32 storage fields, four of which are jointly operated with certain pipeline suppliers, and 478 miles of pipeline. Net investment in storage facilities includes $81.1 million of gas stored underground-noncurrent, representing the cost of the gas required to maintain pressure levels for normal operating purposes as well as gas maintained for system balancing and other purposes, including that needed for no-notice transportation service. The Pipeline and Storage segment has 29 compressor stations with 74,671 installed compressor horsepower.
The Exploration and Production segment had a net investment in property, plant and equipment amounting to $998.9 million at September 30, 2000. Of this amount, $750.1 million relates to properties located in the United States. The remaining net investment of $248.8 million relates to properties located in Canada.
The International segment had a net investment in property, plant and equipment amounting to $172.6 million at September 30, 2000. UE's net investment in district heating and electric generation facilities was $171.8 million; and TK's net investment in district heating facilities was approximately $0.7 million.
The Timber segment had a net investment in property, plant and equipment of $95.6 million at September 30, 2000. Located primarily in northwestern Pennsylvania, the net investment includes four sawmills and approximately 150,000 acres of timber.
The Utility and Pipeline and Storage segments' facilities provided the capacity to meet its 2000 peak day sendout, including transportation service, of 1,779 million cubic feet (MMcf), which occurred on January 17, 2000. Withdrawals from storage of 779.5 MMcf provided approximately 43.8% of the requirements on that day.
Company maps are included throughout pages 3 through 16 of the paper copy of the Company's combined Annual Report to Shareholders/Form 10-K and are narratively described in the Apendix to this electronic filing and are incorporated herein by reference.
The following is a summary of certain oil and gas information taken from Seneca's records. All monetary amounts are expressed in U.S. dollars.
Production- --------------------------------------- ------------- ----------- ---------- For the Year Ended September 30 2000 1999 1998 - --------------------------------------- ------------- ----------- ---------- United States Average Sales Price per Mcf of Gas(1) $3.31 $2.20 $2.45 Average Sales Price per Barrel of Oil(1) $25.34 $12.85 $12.15 Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $0.51 $0.46 $0.45 - --------------------------------------- ------------- ----------- --------- Canada Average Sales Price per Mcf of Gas(1) $2.52 - - Average Sales Price per Barrel of Oil(1) $29.28 - - Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $1.41 - - - ---------------------------------------- ------------- ----------- --------- Total Average Sales Price per Mcf of Gas(1) $3.31 $2.20 $2.45 Average Sales Price per Barrel of Oil(1) $26.03 $12.85 $12.15 Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $0.58 $0.46 $0.45 - ---------------------------------------- ------------- ----------- ---------
(1) Prices do not reflect gains or losses from hedging activities.
Productive Wells
- --------------------------- ------------------ --------------- -----------------
At September 30, 2000 United States Canada Total
- --------------------------- ------------------ --------------- -----------------
Gas Oil Gas Oil Gas Oil
Productive Wells - gross 1,924 860 8 471 1,932 1,331
- net 1,782 782 3 427 1,785 1,209
- ----------------- --------- ------ ---------- ------- -------- --------- -------
Developed and Undeveloped Acreage
- ----------------------- ------------- ------------- -------------- -------------
At September 30, 2000 United Canada Total
States
- ----------------------- ------------- ------------- -------------- -------------
Developed Acreage - gross 641,535 68,917 710,452
- net 552,275 53,160 605,435
Undeveloped Acreage - gross 997,031 1,839,706 2,836,737
- net 716,759 1,827,910 2,544,669
- ----------------------- ------------- ------------- -------------- -------------
- --------------------------------------------------------------------------------
Productive Dry
---------------------------------------------------
For the Year Ended September 2000 1999 1998 2000 1999 1998
30
---------------------------------------------------
United States
Net Wells
Completed - Exploratory 13.89 12.95 10.72 6.53 5.64 4.97
- Development 82.82 95.26 14.11 1.00 4.75 2.00
- --------------------------------------------------------------------------------
Canada
Net Wells
Completed - Exploratory 1.00 - - - - -
- Development 21.50 - - 4.00 - -
- --------------------------------------------------------------------------------
Total
Net Wells
Completed - Exploratory 15.89 12.95 10.72 6.53 5.64 4.97
- Development 103.32 95.26 14.11 5.00 4.75 2.00
- --------------------------------------------------------------------------------
Present Activities
- ------------------------------- ---------- ------------ ---------- -----------
At September 30, 2000 United Canada Total
States
- ------------------------------- ---------- ------------ ---------- -----------
Wells in Process of Drilling - gross 30.00 2.00 32.00
- net 25.78 2.00 27.78
- ------------------------------- ---------- ------------ ---------- -----------
South Lost Hills Waterflood ProgramPART II
ITEM 5 Market for the Registrant's Common Stock and Related Shareholder MattersOn July 1, 2000, the Company issued 840 unregistered shares of Company common stock to the seven non-employee directors of the Company, 120 shares to each such director. These shares were issued as partial consideration for the directors' service as directors during the quarter ended September 30, 2000, pursuant to the Company's Retainer Policy for Non-Employee Directors. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933, as amended, as transactions not involving any public offering.
- -----------------------------------------------------------------------------------------------
Year Ended September 30 2000 1999 1998 1997 1996
- -----------------------------------------------------------------------------------------------
Summary of Operations (Thousands)
Operating Revenues $1,425,277 $1,263,274 $1,248,000 $1,265,812 $1,208,017
- -----------------------------------------------------------------------------------------------
Operating Expenses:
Purchased Gas 503,617 405,925 441,746 528,610 477,357
Fuel Used in Heat and
Electric Generation 54,893 55,788 37,837 1,489 -
Operation and Maintenance 350,383 328,800 321,411 286,537 309,206
Property, Franchise and
Other Taxes 78,878 91,146 92,817 100,549 99,456
Depreciation, Depletion and
Amortization 142,170 124,778 117,238 111,650 98,231
Impairment of Oil and Gas
Producing Properties - - 128,996 - -
Income Taxes 77,068 64,829 24,024 68,674 66,321
- -----------------------------------------------------------------------------------------------
1,207,009 1,071,266 1,164,069 1,097,509 1,050,571
- -----------------------------------------------------------------------------------------------
Operating Income 218,268 192,008 83,931 168,303 157,446
Other Income 10,408 12,343 35,870 3,196 3,869
- -----------------------------------------------------------------------------------------------
Income Before Interest Charges and
Minority Interest in
Foreign Subsidiaries 228,676 204,351 119,801 171,499 161,315
Interest Charges 100,085 87,698 85,284 56,811 56,644
- -----------------------------------------------------------------------------------------------
Minority Interest in
Foreign Subsidiaries (1,384) (1,616) (2,213) - -
- -----------------------------------------------------------------------------------------------
Income Before Cumulative Effect 127,207 115,037 32,304 114,688 104,671
Cumulative Effect of Change in
Accounting - - (9,116) - -
- -----------------------------------------------------------------------------------------------
Net Income Available for Common
Stock $127,207 $115,037 $23,188 $114,688 $104,671
- -----------------------------------------------------------------------------------------------
Per Common Share Data
Basic Earnings per Common Share $3.25 $2.98 $0.61(1) $3.01 $2.78
Diluted Earnings per Common Share $3.21 $2.95 $0.60(1) $2.98 $2.77
Dividends Declared $1.89 $1.83 $1.77 $1.71 $1.65
Dividends Paid $1.88 $1.82 $1.76 $1.70 $1.64
Dividend Rate at Year-End $1.92 $1.86 $1.80 $1.74 $1.68
At September 30:
Number of Common Shareholders 21,164 22,336 23,743 20,267 21,640
- -----------------------------------------------------------------------------------------------
Net Property, Plant and Equipment
(Thousands)
Utility $939,753 $919,642 $906,754 $889,216 $855,161
Pipeline and Storage 474,972 466,524 460,952 450,865 452,305
Exploration and Production 998,852 674,813 638,886 443,164 375,958
International 172,602 210,920 202,590 942 1,274
Energy Marketing 360 489 353 123 41
Timber 95,607 88,623 38,593 34,872 24,680
All Other 1,241 214 - 173 172
Corporate 4 7 9 11 15
- -----------------------------------------------------------------------------------------------
Total Net Plant $2,683,391 $2,361,232 $2,248,137 $1,819,366 $1,709,606
- -----------------------------------------------------------------------------------------------
Total Assets(Thousands) $3,236,888 $2,842,586 $2,684,459 $2,267,331 $2,149,772
- -----------------------------------------------------------------------------------------------
Capitalization (Thousands)
Common Stock Equity $ 987,437 $ 939,293 $ 890,085 $ 913,704 $ 855,998
Long-Term Debt, Net of
Current Portion 953,622 822,743 693,021 581,640 574,000
Total Capitalization $1,941,059 $1,762,036 1,583,106 $1,495,344 $1,429,998
- -----------------------------------------------------------------------------------------------
(1) 1998 includes oil and gas asset impairment of ($2.06) basic, ($2.04) diluted and cumulative effect of a change in depletion methods of ($0.24) basic and diluted. Refer to further discussion of these items in Notes to Financial Statements, Note A - Summary of Significant Accounting Policies.
The increase in 1999 earnings of $3.6 million (exclusive of the two non-cash special items in 1998) was the result of higher earnings in the Utility, Timber, Energy Marketing and International segments and in Corporate operations. These higher earnings were offset in part by reduced earnings in the Exploration and Production segment. The Pipeline and Storage segment's earnings remained level with the prior year. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows.
Earnings (Loss) by Segment- ---------------------------------- ------------- -------------- ------------- Year Ended September 30 (Thousands) 2000 1999 1998 - ---------------------------------- ------------- -------------- ------------- Utility $57,662 $56,875 $51,788 Pipeline and Storage 31,614 39,765 39,852 Exploration and Production (1) 34,877 7,127 (64,110) International 3,282 2,276 1,279 Energy Marketing (7,790) 2,054 787 Timber 6,133 4,769 1,904 - ---------------------------------- ------------- ------------ ----------- Total Reportable Segments 125,778 112,866 31,500 All Other (371) (162) 143 Corporate 1,800 2,333 661 - ---------------------------------- ------------- ------------ ----------- Total Consolidated (1) $127,207 $115,037 $32,304 - ---------------------------------- ------------- ------------ -----------
(1) Before Cumulative Effect of a Change in Accounting in 1998. Exclusive of the non-cash asset impairment, 1998 earnings for the Exploration and Production segment and Total Consolidated would have been $15,004 and $111,418, respectively.
- ------------------------------------------- ------------- -------------- -------------
Year Ended September 30 (Thousands) 2000 1999 1998
- ------------------------------------------ ------------- -------------- -------------
Retail Revenues:
Residential $584,618 $581,022 $612,647
Commercial 93,914 101,482 123,807
Industrial 21,543 15,903 18,068
- ------------------------------------- ------------- ------------ -----------
700,075 698,407 754,522
- ------------------------------------- ------------- ------------ -----------
Off-System Sales 47,962 29,214 44,479
Transportation 104,534 77,600 62,844
Other (6,112) 2,134 9,335
- ------------------------------------- ------------- ------------ -----------
$846,459 $807,355 $871,180
- ------------------------------------- ------------- ------------ -----------
Utility Throughput - (MMcf)
- -------------------------------- ------------- -------------- -------------
Year Ended September 30 2000 1999 1998
- -------------------------------- ------------- -------------- -------------
Retail Sales:
Residential 68,196 71,177 71,704
Commercial 12,312 13,885 16,405
Industrial 4,276 4,144 4,298
- -------------------------------- ------------- -------------- -------------
84,784 89,206 92,407
- -------------------------------- ------------- -------------- -------------
Off-System Sales 12,833 12,469 16,192
Transportation 71,862 64,086 60,080
- -------------------------------- ------------- -------------- -------------
169,479 165,761 168,679
- -------------------------------- ------------- -------------- -------------
2000 Compared with 1999The increase in retail gas revenues for the Utility segment was primarily due to the recovery of higher gas costs, offset by a decrease in the volumes sold. The recovery of higher gas costs (gas costs are recovered dollar for dollar in revenues) resulted from a much higher cost of purchased gas. See further discussion of purchased gas below under the heading "Purchased Gas." The decrease in retail sales volumes was primarily the result of the migration of residential and small commercial customers to transportation service in both the New York and Pennsylvania jurisdictions, offset slightly by the impact of colder weather. The migration from gas sales to transportation is the result of customers turning to marketers for their gas supplies while using the Utility for their gas transportation service. Restructuring in the Utility segment's service territory is further discussed in the "Rate Matters" section that follows. Transportation revenues increased and volumes were up 7.8 billion cubic feet (Bcf) as a result of the migration noted above as well as the slightly colder weather. Off-system sales revenues increased largely due to increased gas prices and slightly higher volumes. However, due to profit sharing with retail customers, the margins resulting from off-system sales are minimal.
The decrease in other operating revenues of $8.2 million was due primarily to a $9.7 million reduction in refund pool revenue, as discussed below, and an $8.5 million reduction in revenue for various adjustments (including a provision for refund) related to the September 30, 2000 conclusion of the two year rate settlement approved by the State of New York Public Service Commission (NYPSC). Partly offsetting these decreases were two items that reduced revenue in 1999 that did not recur in 2000. The more significant item was the gas restructuring reserve which reduced revenues by $7.2 million in 1999. This special reserve put aside dollars to be applied against incremental costs that could result from the NYPSC's gas restructuring efforts and was required in 1999 by the terms of the rate settlement with the NYPSC. The NYPSC's gas restructuring efforts are further discussed in the "Rate Matters" section that follows. The second item that reduced 1999 revenues was a $0.4 million adjustment related to the final settlement of Internal Revenue Service (IRS) audits. Also offsetting the decreases noted above, 2000 revenue includes $0.7 million accrued to offset additional state income taxes that resulted from the enactment of tax changes in New York State. The revenue and related regulatory asset were recorded as the New York Department of Public Service has provided the opportunity of rate recovery by New York State utilities of such additional taxes. All of these items are included in the "Other" category of the Utility Operating Revenue table above.
As part of its 1998 two year rate settlement approved by the NYPSC, Distribution Corporation was allowed to utilize certain refunds from upstream pipeline companies and certain other credits (referred to as the "refund pool") to offset certain specific expense items. When dollars from the refund pool are utilized, revenue is recorded and an equal amount of operation and maintenance (O&M) expense is also recorded (thus there is no earnings impact). The amount of refund pool revenue, and related O&M expense, recognized in 2000 was $9.7 million less than in 1999.
1999 Compared with 1998The recovery of lower gas costs and the general base rate decrease in the New York jurisdiction effective October 1, 1998, caused the decrease in retail gas revenue. The recovery of lower gas costs resulted from both lower retail volumes sold of 3.2 Bcf and a lower average cost of purchased gas (see discussion of purchased gas below under the heading "Purchased Gas"). Despite weather that was colder than 1998, retail volumes sold decreased, mainly due to the migration of residential and small commercial retail customers to transportation service. Transportation revenue increased and volumes are up 3.9 Bcf as a result of the migration and because of colder weather. Off-system revenue is down due to lower volumes sold of 3.7 Bcf.
The decrease in other operating revenue of $7.2 million is due primarily to a $7.2 million gas restructuring reserve, as discussed above, reducing revenue in 1999, $6.0 million of revenue recorded in 1998 as a result of IRS audits and $0.4 million of a revenue reduction in 1999 due to a final IRS audit settlement. These items were offset in part by a $7.1 million lower refund provision recorded in 1999 as compared with the 1998 refund provision. The revenue related to the IRS audits represents the rate recovery of interest expense as allowed by the New York rate settlement of 1996. The refund provision represents the 50% sharing with customers of earnings over a predetermined amount in accordance with the New York rate settlements of 1996 and 1998. All of these items are included in the "Other" category of the Utility Operating Revenue table above.
EarningsThe increase in the market price of the Company's common stock, while benefiting shareholders, carried with it the required recognition of expense for SARs. This expense is spread across all segments, with the greatest impact on Pipeline and Storage, Utility and Exploration and Production segments. For 2000, total expense related to SARs for all segments was $9.2 million (after tax), and reflects the stock price increase from September 30, 1999 ($47.19 per common share) to September 30, 2000 ($56.06 per common share).
The impact of weather on Distribution Corporation's New York rate jurisdiction is tempered by a weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits Distribution Corporation's New York customers. In 2000, the WNC in New York preserved earnings of approximately $8.1 million (after tax) as weather, overall in the New York service territory, was warmer than normal for the period from October 1999 through May 2000. Since the Pennsylvania rate jurisdiction does not have a WNC, uncontrollable weather variations directly impact earnings. In the Pennsylvania service territory, since 2000 weather was only 0.9% colder than 1999, no significant earnings variances occurred.
1999 Compared with 1998Lower O&M and interest expenses, a lower refund provision in 1999 (as noted in the revenue discussion above), positive adjustments for lost and unaccounted-for gas related to 1998 and 1999 and slightly colder weather (which mainly benefits the Pennsylvania jurisdiction), were the positive contributors to earnings in 1999. These items offset the costs associated with the 1999 early retirement offers, as well as the effects of a rate settlement that included a $7.2 million rate reduction in New York that became effective October 1, 1998 and the previously discussed special gas restructuring reserve.
In 1999, the WNC in New York preserved earnings of approximately $6.3 million (after tax) as weather, overall in the New York service territory, was warmer than normal for the period from October 1998 through May 1999. In the Pennsylvania service territory, weather that was 4.0% colder than 1998 increased earnings by approximately $0.5 million (after tax).
Degree Days
- ------------ ----------- ------------ ---------------- --------------------------
Percent (Warmer)
Colder Than
--------------------------
Year Ended September 30 Normal Actual Normal Prior Year
- ------------- ----------- ------------ --------------- ------------- ------------
2000: Buffalo 6,932 6,312 (8.9%) 2.1%
Erie 6,230 5,657 (9.2%) 0.9%
- ------------- ----------- ------------ --------------- ------------- ------------
1999: Buffalo 6,848 6,179 (9.8%) 4.5%
Erie 6,223 5,607 (9.9%) 4.0%
- ------------- ----------- ------------ --------------- ------------- ------------
1998: Buffalo 6,689 5,914 (11.6%) (12.9%)
Erie 6,223 5,389 (13.4%) (15.7%)
- ------------- ----------- ------------ --------------- ------------- ------------
Purchased GasCurrently, Distribution Corporation has contracted for long-term firm transportation capacity with Supply Corporation and six other upstream pipeline companies, for long-term gas supplies with a combination of producers and marketers and for storage service with Supply Corporation and three nonaffiliated companies. In addition, Distribution Corporation can satisfy a portion of its gas requirements through spot market purchases. Changes in wellhead prices have a direct impact on the cost of purchased gas. Distribution Corporation's average cost of purchased gas, including the cost of transportation and storage, was $4.93 per thousand cubic feet (Mcf) in 2000, an increase of 29% from the average cost of $3.82 per Mcf in 1999. The average cost of purchased gas in 1999 was 7.5% lower than the $4.13 per Mcf in 1998.
- ------------------------------------- ------------- -------------- -------------
Year Ended September 30 (Thousands) 2000 1999 1998
- ------------------------------------- ------------- -------------- -------------
Firm Transportation $92,305 $91,279 $93,362
Interruptible Transportation 1,578 856 985
- ---------------------------------- ------------- -------------- -------------
93,883 92,135 94,347
- ---------------------------------- ------------- -------------- -------------
Firm Storage Service 62,899 63,655 62,850
Interruptible Storage Service 287 173 655
- ---------------------------------- ------------- -------------- -------------
63,186 63,828 63,505
- ---------------------------------- ------------- -------------- -------------
Other 12,590 12,820 13,131
- ---------------------------------- ------------- -------------- -------------
$169,659 $168,783 $170,983
- ---------------------------------- ------------- -------------- -------------
Pipeline and Storage Throughput - (MMcf)
- --------------------------------- ------------- -------------- -------------
Year Ended September 30 2000 1999 1998
- --------------------------------- ------------- -------------- -------------
Firm Transportation 291,818 300,242 298,738
Interruptible Transportation 21,730 8,061 14,310
- --------------------------------- ------------- -------------- -------------
313,548 308,303 313,048
- --------------------------------- ------------- -------------- -------------
2000 Compared with 1999Transportation volumes in this segment increased 5.2 Bcf. Generally, volume fluctuations do not have a significant impact on revenues as a result of Supply Corporation's straight fixed-variable (SFV) rate design. However, as mentioned above, the higher interruptible volumes did add to revenues in 2000.
1999 Compared with 1998Transportation volumes in this segment decreased 4.7 Bcf. Generally, volume fluctuations do not have a significant impact on revenues as a result of Supply Corporation's SFV rate design. However, as mentioned above, lower interruptible transportation volumes did negatively impact revenue for 1999.
- -------------------------- ------------- -------------- -------------
Year Ended September 30
(Thousands) 2000 1999 1998
- -------------------------- ------------- -------------- -------------
Gas (after Hedging) $108,832 $83,229 $82,910
Oil (after Hedging) 117,606 52,050 34,069
Gas Processing Plant 17,666 11,751 4,937
Other (6,034) (36) 2,356
- -------------------------- ------------- -------------- -------------
$238,070 $146,994 $124,272
- -------------------------- ------------- -------------- -------------
- -------------------------------------------- ------------- --------- ----------
Year Ended September 30 2000 1999 1998
- -------------------------------------------- ------------- --------- ----------
Gas Production (million cubic feet)
Gulf Coast 32,760 28,758 29,461
West Coast 4,374 3,977 2,146
Appalachia 4,344 4,431 4,867
Canada 192 - -
- -------------------------------------------- ------------- --------- ----------
41,670 37,166 36,474
- -------------------------------------------- ------------- --------- ----------
Oil Production (thousands of barrels)
Gulf Coast 1,415 1,373 1,228
West Coast 2,824 2,633 1,376
Appalachia 9 10 10
Canada 899 - -
- -------------------------------------------- ------------- --------- ----------
5,147 4,016 2,614
- -------------------------------------------- ------------- --------- ----------
Average Prices- ------------------------------------ ----------- ------------ ----------- Year Ended September 30 2000 1999 1998 - ------------------------------------ ----------- ------------ ----------- Average Gas Price/Mcf Gulf Coast $3.29 $2.15 $2.40 West Coast $3.62 $2.28 $2.14 Appalachia $3.16 $2.44 $2.88 Canada $2.52 - - Weighted Average $3.31 $2.20 $2.45 Weighted Average After Hedging(1) $2.61 $2.24 $2.27 Average Oil Price/bbl Gulf Coast $28.27 $15.18 $14.69 West Coast(2) $23.87 $11.62 $9.85 Appalachia $25.12 $14.73 $16.80 Canada $29.28 - - Weighted Average $26.03 $12.85 $12.15 Weighted Average After Hedging(1) $22.85 $12.96 $13.03 - ------------------------------------ ------------- ------------ -----------
(1) Refer to further discussion of hedging activities below under "Market Risk Sensitive Instruments" and in Note F - Financial Instruments in Item 8 of this report.
(2) Includes low gravity oil which generally sells for a lower price.
2000 Compared with 1999
- ----------------------------- ------------- -------------- -------------
Year Ended September 30
(Thousands) 2000 1999 1998
- ----------------------------- ------------- -------------- -------------
Heating $69,387 $71,974 $49,560
Electricity 31,426 34,158 22,774
Other 3,923 913 3,925
- ----------------------------- ------------- -------------- -------------
$104,736 $107,045 $76,259
- ----------------------------- ------------- -------------- -------------
International Heating and Electric Volumes- ------------------------------------- ------------- ------------ ----------- Year Ended September 30 2000 1999 1998 - ------------------------------------- ------------- ------------ ----------- Heating Sales (Gigajoules) (1) 10,222,024 10,047,042 7,116,776 Electricity Sales (megawatt hours) 1,147,303 1,138,980 763,848 - ------------------------------------- ------------- ------------ -----------
(1) Gigajoules = one billion joules. A joule is a unit of energy.
- ----------------------------------- -------------- --------------- ------------
Year Ended September 30
(Thousands) 2000 1999 1998
- ----------------------------------- -------------- --------------- ------------
Natural Gas (after Hedging) $139,614 $97,514 $86,877
Electricity 1,941 1,551 253
Other (7,626) 23 57
- ----------------------------------- -------------- -------------- ------------
$133,929 $99,088 $87,187
- ----------------------------------- -------------- -------------- ------------
Energy Marketing Volumes- ----------------------------------- ------------- -------------- ----------- Year Ended September 30 2000 1999 1998 - ----------------------------------- ------------- -------------- ----------- Natural Gas - (MMcf) 35,465 34,454 26,453 - ----------------------------------- ------------- -------------- -----------2000 Compared with 1999
- -------------------------- --------------- ---------------- -------------
Year Ended September 30
(Thousands) 2000 1999 1998
- -------------------------- --------------- ---------------- -------------
Log Sales $24,091 $18,276 $9,157
Green Lumber Sales 4,397 4,018 4,119
Kiln Dry Lumber Sales 10,152 8,197 3,991
Other 532 626 538
- -------------------------- --------------- ---------------- -------------
$39,172 $31,117 $17,805
- -------------------------- --------------- ---------------- -------------
Timber Board Feet
- --------------------------- --------------- ---------------- -------------
Year Ended September 30
(Thousands) 2000 1999 1998
- --------------------------- --------------- ---------------- -------------
Log Sales 9,370 6,902 2,794
Green Lumber Sales 8,193 8,541 7,634
Kiln Dry Lumber Sales 6,987 5,711 2,710
- --------------------------- --------------- ---------------- -------------
24,550 21,154 13,138
- --------------------------- --------------- ---------------- -------------
2000 Compared with 1999Other income decreased $23.5 million in 1999 compared with 1998. This decrease was primarily due to a decrease in interest income related to the settlement of IRS audits. In 1999 and 1998, $3.1 million and $18.5 million, respectively, of interest income was recognized related to these audits. Lower other income in 1999 also reflects two items recorded in 1998: a net gain of $5.1 million associated with U.S. dollar denominated debt in the International segment and a buyout of a firm transportation agreement by a Pipeline and Storage segment customer in the amount of $2.5 million. Partly offsetting these items was a $2.4 million gain recorded in 1999 resulting from the demutualization of an insurance company.
Interest ChargesOther interest charges increased $10.6 million in 2000 and decreased $9.8 million in 1999. The increase in 2000 was primarily the result of higher weighted average interest rates and higher average amounts of short-term debt outstanding. As discussed in "Financing Cash Flow" below, the acquisition of Tri Link was financed with short-term debt. The decrease in 1999 compared to 1998 resulted primarily from $11.7 million of interest expense recorded in 1998 related to the settlement of IRS audits. Partly offsetting this decrease in 1999, interest on short-term debt increased mainly as a result of higher average amounts of debt outstanding.
Outlook for 2001*The Company expects that earnings for 2001 will fall within the range of $168 million to $172 million, or $4.25 per basic common share to $4.35 per basic common share.* Higher earnings in the Exploration and Production segment is the main driver of the expected increase in earnings for 2001 as compared with actual earnings for 2000.* Production estimates for 2001 are in the range of 95 to 100 Bcfe (with oil representing 54% of that production).* Spot price assumptions for 2001 are $3.98 per Mcf for natural gas and $25.51 per bbl for crude oil.* Information on the Exploration and Production segment's hedging program is provided in the "Market Risk Sensitive Instruments" section that follows.
In the Utility segment, earnings are expected to be down in 2001 as compared with 2000.* The overall rate of return (operating income after income tax) is expected to be about 9% on an average rate base for 2001 of $623 million for the New York jurisdiction and about 9.5% on an average rate base for 2001 of $242 million in the Pennsylvania jurisdiction.* These figures compare to 2000's actual return on rate base of 10.1% in New York and 9.9% in Pennsylvania. The expected decrease in New York reflects the recent rate settlement with the NYPSC whereby rates in the New York jurisdiction are reduced by $10 million for 2001. In addition, the rate settlement reduced the targeted return on equity, above which earnings are shared 50% with rate payers, from 12% to 11.5%.
In the Pipeline and Storage segment, 2001 earnings are expected to increase as the overall rate of return on rate base should increase from 10.6% in 2000 to about 12 to 12.5% in 2001 on an average rate base in 2001 of $407 million.* Anticipated O&M savings is a significant reason for this increase.* In the International segment, earnings for 2001 are anticipated to be close to 2000 earnings after a reduction for the non-recurring income tax adjustment of $1.8 million that is included in 2000 earnings.*
In the Energy Marketing segment, 2001 earnings are expected to be at break even or a slight loss.* In the Timber segment, earnings for 2001 should be flat to slightly up as compared with 2000 earnings.* Earnings for all other, including Corporate, are expected to be flat to down slightly as compared with 2000 earnings.*
Capital Resources and Liquidity- ---------------------------------- ----------------- ------------- ------------- Year Ended September 30 (Millions) 2000 1999 1998 - ---------------------------------- ----------------- ------------- ------------- Provided by Operating Activities $238.2 $267.5 $249.9 Capital Expenditures (269.4) (256.1) (390.1) Investment in Subsidiaries, Net of Cash Acquired (123.8) (5.8) (112.0) Investment in Partnerships (4.4) (3.6) (5.5) Other Investing Activities 13.3 6.7 7.6 Short-Term Debt, Net Change 226.5 67.2 229.4 Long-Term Debt, Net Change (18.1) (15.6) 94.9 Issuance of Common Stock 14.3 10.7 7.9 Dividends Paid on Common Stock (73.0) (69.9) (67.0) Dividends Paid to Minority Interest (0.2) (0.2) (0.3) Effect of Exchange Rates on Cash (0.5) (2.1) 1.6 - ---------------------------------- ----------------- ------------- ---------- Net Increase (Decrease) in Cash and Temporary Cash Investments $2.9 $(1.2) $16.4 - ---------------------------------- ----------------- ------------- ----------Operating Cash Flow
Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from year to year because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather also significantly impact cash flow. The impact of weather on cash flow is tempered in the Utility segment's New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by Supply Corporation's SFV rate design.
Net cash provided by operating activities totaled $238.2 million in 2000, a decrease of $29.3 million compared with the $267.5 million provided by operating activities in 1999. The decrease is attributable primarily to higher gas costs in the Utility and Energy Marketing segments stemming from rising natural gas prices. In the Utility segment, any unrecovered gas costs are deferred for future recovery. Partially offsetting this negative impact to cash provided by operating activities, the Exploration and Production segment experienced an increase in cash provided by operating activities. Higher cash receipts from the sale of oil and gas production resulted from higher production and significantly higher prices.
Investing Cash FlowThe Company's expenditures for long-lived assets totaled $398.8 million in 2000. The table below presents these expenditures by business segment:
- ----------------------------------------- ---------------- ---------------- -------------
Total
Investments Expenditures
Capital in For
Corporations Long-
Year Ended September 30, 2000
(Millions) Expenditures or Lived
Partnerships Assets
- ---------------------------------- ---------------- ---------------- -------------
Utility $55.8 $ - $55.8
Pipeline and Storage 34.0(1) 1.8 35.8
Exploration and Production 156.2 123.8 280.0
International 9.8 - 9.8
Energy Marketing 0.1 - 0.1
Timber 13.6 - 13.6
All Other 1.1 2.6 3.7
- ---------------------------------- ---------------- ---------------- -------------
$270.6(1) $128.2 $398.8
- ---------------------------------- ---------------- ---------------- -------------
(1) Includes non-cash acquisition of $1.2 million in a stock-for-asset swap.
UtilityDuring 2000, SIP made a $1.8 million investment in Independence Pipeline Company, a Delaware general partnership (Independence), and had an aggregate investment balance of $13.7 million at September 30, 2000. This investment represents a one-third partnership interest. The investment has been financed with short-term borrowings. Independence intends to build a 400-mile natural gas pipeline (the Independence Pipeline) from Defiance, Ohio to Leidy, Pennsylvania at an estimated cost of $680 million.* If construction never begins on the Independence Pipeline project, the Company's share of the development costs (including SIP's investment in Independence) is estimated not to exceed $15.0 million.*
On July 12, 2000, the FERC issued a Certificate of Public Convenience and Necessity (the Certificate) authorizing, among other things, the construction and operation of the Independence Pipeline, subject to satisfaction of various conditions spelled out in the Certificate and in previous FERC orders. Among those conditions is the requirement that, before construction may commence, Independence must file at FERC executed, firm transportation agreements with "no out" clauses for at least 68.2% of its capacity. (Independence already filed, on June 26 and July 6, 2000, precedent agreements for firm transportation amounting to about 38% of the capacity of the Independence Pipeline, thereby satisfying a FERC requirement previously imposed as a precondition to FERC's issuance of the Certificate.) The Independence Pipeline partners are working on obtaining the required customer commitments. The Certificate also requires that the Independence Pipeline be constructed and placed in service by July 12, 2003. Assuming contracts are in place in quantities satisfactory to the partners, the Independence Pipeline's planned in service date is November 1, 2002.*
The Certificate also includes an environmental condition that Independence file an "implementation plan" within 60 days after Independence accepted the Certificate. In October and November 2000, Independence timely filed a preliminary implementation plan which included a request for an extension of time to provide certain technical information, in order to allow the remaining field surveys (for example, for endangered species) to be commenced in spring 2001. This timing would be consistent with Independence's planned in service date of November 1, 2002, and the Certificate's deadline of July 12, 2003 to complete construction. On November 20, 2000, a FERC official issued a letter requiring Independence to file a full implementation plan, including the necessary technical information, by May 1, 2001, and warning that if Independence cannot comply with these terms, its Certificate authority could be in jeopardy. This letter also requires Independence to file monthly status reports on environmental permitting and land acquisition activities. It is possible that Independence will be unable to file timely an implementation plan which meets the requirements set out in the November 20 letter, and that Independence's application could be dismissed.*
Exploration and Production
The Exploration and Production segment capital expenditures included
approximately $113.6 million for the Company's offshore program in the Gulf of
Mexico, including offshore drilling expenditures, offshore construction, lease
acquisition costs and geological and geophysical expenditures. The remaining
$42.6 million of capital expenditures included onshore drilling, construction
and recompletion costs for wells located in Louisiana, Texas, California and
Canada as well as onshore geological and geophysical costs, including the
purchase of certain 3-D seismic data and fixed asset purchases.
In June 2000, the Company acquired the outstanding shares of Tri Link, a Calgary, Alberta based oil and gas exploration and production company. This acquisition built the Company's total reserve base to approximately one trillion cubic feet equivalent.* The cost of acquiring the outstanding shares of Tri Link was approximately $123.8 million. The acquisition was financed with short-term borrowings. Refer to "Financing Cash Flow" for a discussion of the redemption of the debt that was assumed as part of the Tri Link acquisition.
International
The majority of the International segment capital expenditures were concentrated
in the areas of improvements and replacements within the district heating and
power generation plants in the Czech Republic.
Energy Marketing
The Energy Marketing capital expenditures consisted primarily of furniture,
equipment and computer hardware and software.
Timber
The majority of the Timber segment's capital expenditures consisted of the
purchase of land and timber in Pennsylvania, and the construction or purchase of
new facilities and equipment for this segment's sawmill and kiln operations.
All Other
Expenditures for Long-Lived Assets for all other subsidiaries consisted of the
purchase of a 50% interest in a gas processing facility and the purchase of a
50% partnership interest in Seneca Energy II, LLC which generates and sells
electricity to a public utility by using methane gas obtained from a landfill
owned by an outside party.
Other Investing Activities
Other cash provided by or used in investing activities primarily reflects cash
received on the sale of investments in property, plant and equipment.
Estimated Capital Expenditures
The Company's estimated capital expenditures for the next three years are:*
- ------------------------------------------- ------------ ------------ ------------
Year Ended September 30 (Millions) 2001 2002 2003
- ------------------------------------------- ------------ ------------ ------------
Utility $49.8 $48.1 $47.1
Pipeline and Storage 38.2 26.6 19.9
Exploration and Production 164.9 180.8 202.1
International 15.5 2.5 2.5
Timber 5.0 5.0 5.0
- ------------------------------------------- ------------ ------------ ------------
$273.4 $263.0 $276.6
- ------------------------------------------- ------------ ------------ ------------
Estimated capital expenditures for the Utility segment in 2001 will be concentrated in the areas of main and service line improvements and replacements and, to a minor extent, the installation of new services.*
Estimated capital expenditures for the Pipeline and Storage segment in 2001 will be concentrated in the reconditioning of storage wells and the replacement of storage and transmission lines.* The estimated capital expenditures also include $5.0 million for an increase in horsepower at the Ellisburg, Pennsylvania compressor station.* In addition, $8.1 million has been budgeted for the construction of a transmission line from Lamont, Pennsylvania to Roystone, Pennsylvania.*
Estimated capital expenditures in 2001 for the Exploration and Production segment include approximately $105.4 million for the onshore program ($59.6 million in Canada).* Of this amount, approximately $59.9 million ($46.0 million in Canada) is intended to be spent on exploratory and development drilling.* The estimated expenditures also include approximately $59.5 million for the offshore program in the Gulf of Mexico.* Of this amount, approximately $49.9 million is intended to be spent on exploratory and development drilling.*
The estimated capital expenditures for the International segment in 2001 include approximately $13.0 million for the construction of a boiler at a district heating and power generation plant in the Czech Republic.* The new boiler will replace an existing boiler. Other capital expenditures will be concentrated on smaller improvements and replacements within the district heating and power generation plants.*
Estimated capital expenditures in the Timber segment will be concentrated in the purchase of land and timber as well as the construction or purchase of new facilities and equipment for this segment's sawmill and kiln operations.*
The Company continuously evaluates capital expenditures and investments in corporations and partnerships. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, timber or storage facilities and the expansion of transmission line capacities. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company's other business segments depends, to a large degree, upon market conditions.*
Financing Cash Flow
Consolidated short-term debt increased $226.5 million during 2000. The Company
continues to consider short-term debt an important source of cash for
temporarily financing capital expenditures and investments in corporations or
partnerships, gas-in-storage inventory, unrecovered purchased gas costs,
exploration and development expenditures and other working capital needs.
Fluctuations in these items can have a significant impact on the amount and
timing of short-term debt.
In June 2000, the Company paid approximately $99.2 million to redeem the bank loans and convertible debentures of Tri Link. These redemptions were financed with short-term debt.
In February 2000, the Company issued $150.0 million of 7.30% medium-term notes due in February 2003. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $149.3 million. The proceeds of this debt issuance were used to redeem $50.0 million of 6.60% medium-term notes which matured in February 2000 and to reduce short-term debt.
The Company's present liquidity position is believed to be adequate to satisfy known demands.* Under the Company's existing indenture covenants, at September 30, 2000, the Company would have been permitted to issue up to a maximum of $487.0 million in additional long-term unsecured indebtedness at projected market interest rates. In addition, at September 30, 2000, the Company had regulatory authorizations and unused short-term credit lines that would have permitted it to borrow an additional $130.5 million of short-term debt.
The Company's embedded cost of long-term debt was 7.0% at both September 30, 2000 and 1999, respectively.
In March 1998, the Company obtained authorization from the Securities and Exchange Commission (SEC), under the Holding Company Act, to issue long-term debt securities and equity securities in amounts not exceeding $2.0 billion at any one time outstanding during the order's authorization period, which extends to December 31, 2002. In August 1999, the Company registered $625.0 million of debt and equity securities under the Securities Act of 1933. After the November 2000 medium-term note issuance discussed below, the Company currently has $275.0 million of debt and equity securities registered under the Securities Act of 1933.
In November 2000, the Company issued $200.0 million of 7.50% medium-term notes due in November 2010. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $197.3 million. The proceeds of this debt issuance were used to reduce short-term debt.
The amounts and timing of the issuance and sale of debt or equity securities will depend on market conditions, regulatory authorizations, and the requirements of the Company.
The Company is involved in litigation arising in the normal course of business. The Company is involved in regulatory matters arising in the normal course of business that involve rate base, cost of service and purchased gas cost issues, among other things. While the resolution of such litigation or regulatory matters could have a material effect on earnings and cash flows in the year of resolution, none of this litigation, and none of these regulatory matters, are expected to change materially the Company's present liquidity position, nor have a material adverse effect on the financial condition of the Company.*
Market Risk Sensitive Instruments
Energy Commodity Price Risk
The Company, primarily in its Exploration and Production and Energy Marketing
segments, uses various derivative financial instruments (derivatives), including
price swap agreements, no cost collars options and futures contracts, as part of
the Company's overall energy commodity price risk management strategy. Under
this strategy, the Company manages a portion of the market risk associated with
fluctuations in the price of natural gas and crude oil, thereby attempting to
provide more stability to operating results. The Company has operating
procedures in place that are administered by experienced management to monitor
compliance with the Company's risk management policies. The derivatives are not
held for trading purposes. The fair value of these derivatives, as shown below,
represents the amount that the Company would have to pay the respective
counterparties at September 30, 2000 to terminate the derivatives. However, the
tables below and the fair value that is disclosed do not consider the physical
side of the natural gas and crude oil transactions that are related to the
financial instruments.
The Company may be exposed to credit risk on some of these derivatives. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check and then, on an ongoing basis, monitors counterparty credit exposure.
The following tables disclose natural gas and crude oil price swap information by expected maturity dates for agreements in which the Company receives a fixed price in exchange for paying a variable price as quoted in "Inside FERC" or on the New York Mercantile Exchange. Notional amounts (quantities) are used to calculate the contractual payments to be exchanged under the contract. The weighted average variable prices represent the prices as of September 30, 2000. At September 30, 2000, the Company had not entered into any natural gas or crude oil price swap agreements extending beyond 2003.
Natural Gas Price Swap Agreements
- ---------------------------------------- ----------------------------------------
Expected Maturity Dates
----------------------------------------
2001 2002 2003 Total
- ---------------------------------------- ---------- --------- ---------- ---------
Notional Quantities (Equivalent Bcf) 17.9 25.8 1.2 44.9
Weighted Average Fixed Rate (per Mcf) $2.79 $3.75 $2.78 $3.34
Weighted Average Variable Rate (per Mcf) $4.79 $4.80 $4.76 $4.79
- ---------------------------------------- ---------- --------- ---------- ---------
Crude Oil Price Swap Agreements
- ---------------------------------------- --------------------------------------------------
Expected Maturity Dates
--------------------------------------------------
2001 2002 2003 Total
- ---------------------------------------- ----------- ------------ ------------ ------------
Notional Quantities (Equivalent bbls) 3,717,915 4,840,980 1,803,000 10,361,895
Weighted Average Fixed Rate (per bbl) $21.04 $22.98 $19.93 $21.75
Weighted Average Variable Rate (per bbl) $33.87 $33.87 $33.87 $33.87
- ---------------------------------------- ----------- ------------ ------------ ------------
At September 30, 2000, the Company would have had to pay the respective counterparties an aggregate of approximately $54.8 million to terminate the natural gas price swap agreements outstanding at that date. The Company would have had to pay an aggregate of approximately $51.4 million to the counterparties to terminate the crude oil price swap agreements outstanding at September 30, 2000.
At September 30, 1999, the Company had natural gas price swap agreements covering 40.2 Bcf at a weighted average fixed rate of $2.69 per Mcf. The Company also had crude oil price swap agreements covering 2,296,000 bbls at a weighted average fixed rate of $19.00 per bbl. As can be seen from the September 30, 2000 tables above, the Company has significantly increased its use of crude oil price swap agreements, which is primarily attributable to the increase in crude oil production that will be experienced as a result of the Tri Link acquisition in 2000. Tri Link (or NFE, as it is now known), primarily produces crude oil.
The following tables disclose the notional quantities, the weighted average ceiling price and the weighted average floor price for the no cost collars used by the Company to manage natural gas and crude oil price risk. The no cost collars provide for the Company to receive monthly payments from (or make payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). At September 30, 2000, the Company had not entered into any natural gas or crude oil no cost collars extending beyond 2004.
No Cost Collars
- ------------------------------------------------------------------------------
Expected Maturity Dates
-----------------------------------------
2001 2002 2003 2004 Total
- --------------------------------------------- --------- --------- ------- ---------
Crude Oil
Notional Quantities (Equivalent 1,995,000 1,335,000 1,125,000 270,000 4,725,000
bbls)
Weighted Average Ceiling Price $30.07 $28.26 $26.41 $25.80 $28.44
(per bbl)
Weighted Average Floor Price (per $23.24 $21.91 $21.96 $22.00 $22.49
bbl)
Natural Gas
Notional Quantities (Equivalent 6.6 - - - 6.6
Bcf)
Weighted Average Ceiling Price $5.75 - - - $5.75
(per Mcf)
Weighted Average Floor Price (per $3.83 - - - $3.83
Mcf)
- --------------------------------------------- --------- --------- ------- ---------
At September 30, 2000, the Company would have had to pay the respective counterparties an aggregate of approximately $0.9 million to terminate the natural gas no cost collars outstanding at that date. The Company would have had to pay an aggregate of approximately $4.9 million to terminate the crude oil no cost collars outstanding at that date.
At September 30, 1999, the Company did not have any no cost collars outstanding. During 2000, the Company began entering into no cost collars on the basis of obtaining better value for its crude oil and natural gas production than could be experienced through the use of price swap agreements only. The concentration of the no cost collars in crude oil is attributable to the crude oil production from NFE, as discussed above.
The following table discloses the net notional quantities, weighted average contract prices and weighted average settlement prices by expected maturity date for futures contracts used to manage natural gas price risk. At September 30, 2000, the Company held no futures contracts with maturity dates extending beyond 2002.
Futures Contracts
- ----------------------------------------------------------------------------------
Expected Maturity Dates
-------------------------------
2001 2002 Total
- -------------------------------------------------- ---------- ---------- ---------
Contract Volumes Purchased (Sold) (Equivalent Bcf) (3.9) -(1) (3.9)
Weighted Average Contract Price (per Mcf) $4.23 $3.57 $4.20
Weighted Average Settlement Price (per Mcf) $5.28 $4.77 $5.25
- -------------------------------------------------- ---------- ---------- ---------
(1) Volumes purchased amount to approximately 38,000 Mcf.
At September 30, 2000, the Company would have had to pay $5.5 million to terminate these futures contracts.
At September 30, 1999, the Company had futures contracts covering 1.2 Bcf (net long position) at a weighted average contract price of $2.76 per Mcf.
The following table discloses the notional quantities and weighted average strike prices by expected maturity dates for options used by the Company to manage natural gas and crude oil price risk. At September 30, 2000, the Company held no options with maturity dates extending beyond 2001.
Options Purchased
- ------------------------------------------- ----------------------------------
Expected Maturity Date - 2001
- ------------------------------------------- ----------------------------------
Natural Gas
Notional Quantities (Equivalent Bcf) 31.1
Weighted Average Strike Price (per Mcf) $4.76
- ------------------------------------------- ----------- ----------------------
Options Sold
- ------------------------------------------- ----------------------------------
Expected Maturity Date - 2001
- ------------------------------------------- ----------------------------------
Natural Gas
Notional Quantities (Equivalent Bcf) 37.9
Weighted Average Strike Price (per Mcf) $4.76
- ------------------------------------------- ----------- ---------------- -----
Crude Oil
Notional Quantities (Equivalent bbls) 368,000
Weighted Average Strike Price (per bbl) $15.25
- ------------------------------------------- ----------- ---------------- -----
At September 30, 2000, the Company would have had to pay $9.8 million to terminate these options.
At September 30, 1999, the Company had purchased crude oil options outstanding covering 1,464,000 bbls at a weighted average strike price of $20.00 per bbl. The Company also had purchased natural gas options outstanding at September 30, 1999 covering 9.0 Bcf at a weighted average strike price of $2.72 per Mcf. The Company had sold crude oil options outstanding at September 30, 1999 covering 1,832,000 bbls at a weighted average strike price of $15.25 per bbl. The Company also had sold natural gas options outstanding at September 30, 1999 covering 31.0 Bcf at a weighted average strike price of $2.84 per Mcf.
Exchange Rate Risk
The International segment's investment in the Czech Republic is valued in Czech
korunas, and, as such, this investment is subject to currency exchange risk when
the Czech korunas are translated into U.S. dollars. The Exploration and
Production segment's investment in Canada is valued in Canadian dollars, and, as
such, this investment is subject to currency exchange risk when the Canadian
dollars are translated into U.S. dollars. During 2000, the Czech koruna
decreased in value in relation to the U.S. dollar resulting in a $23.1 million
negative adjustment to the Cumulative Foreign Currency Translation Adjustment
(CTA) (a component of Accumulated Other Comprehensive Income). The Canadian
dollar decreased in value in relation to the U.S. dollar resulting in a $4.3
million negative adjustment to the CTA. Further valuation changes to the Czech
koruna and Canadian dollar would result in corresponding positive or negative
adjustments to the CTA. Management cannot predict whether the Czech koruna or
Canadian dollar will increase or decrease in value against the U.S. dollar.*
Interest Rate Risk
The Company's exposure to interest rate risk primarily consists of short-term
debt instruments. At September 30, 2000, these instruments included short-term
bank loans and commercial paper totaling $601.2 million (domestically). The
interest rate on these short-term bank loans and commercial paper approximated
6.7%. The Company's short-term debt instruments also included $18.3 million of
short-term bank loans in the Czech Republic at September 30, 2000. The interest
rate on the Czech Republic loans approximated 5.7%.
The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company's long-term fixed rate debt as well as the other debt of certain of the Company's subsidiaries. The interest rates for the variable rate debt are based on those in effect at September 30, 2000:
- ------------------------------------------------------------------------------------- --------
Principal Amounts by Expected Maturity Dates
---------------------------------------------
(Millions of Dollars) 2001 2002 2003 2004 2005 Thereafter Total
- ------------------------------------------------------------------------------
National Fuel Gas Company
Long-Term Fixed Rate Debt $- $- $150 $225 $- $549 $924
Weighted Average Interest
Rate Paid -% -% 7.3% 7.3% -% 6.6% 6.9%
Fair Value = $887.2 million
- ----------------------------------------------------------------------------
Other Notes
Long-Term Debt(1) $11.3 $8.5 $8.6 $8.7 $2.7 $1.1 $40.9
Weighted Average Interest
Rate Paid 6.0% 5.9% 5.9% 5.9% 5.9% 6.0% 5.9%
Fair Value = $40.9 million
- ----------------------------------------------------------------------------
(1) $37.8 million is variable rate debt; $3.1 million is fixed rate debt.
The Company utilizes an interest rate swap to eliminate interest rate fluctuations on its CZK 1,356,534,000 term loan ($33.7 million at September 30, 2000), which carries a variable interest rate of six month Prague Interbank Offered Rate (PRIBOR) plus 0.475%. Under the terms of the interest rate swap, which extends until 2002, the Company pays a fixed rate of 8.31% and receives a floating rate of six month PRIBOR. The Company would have paid approximately $1.4 million to settle the interest rate swap at September 30, 2000.
RATE MATTERS
Utility Operation
New York Jurisdiction
On October 11, 2000, the NYPSC approved a settlement agreement (Agreement) between Distribution Corporation, Staff of the Department of Public Service, the New York State Consumer Protection Board and Multiple Intervenors (an advocate for large commercial and industrial customers) that establishes rates for a three-year period beginning October 1, 2000. The Agreement provides that customers will receive a bill credit of $17.6 million in the first year, of which $7.6 million relates to customers' share of earnings accumulated under previous settlements. The credit will be reduced to $5.0 million in the second year, and in the third and subsequent years the credit will remain at $5.0 million unless the Company can demonstrate that it is no longer justified. Also, earnings beyond a target level of 11.5% return on equity will be shared equally between shareholders and ratepayers. The Agreement provides further that the Company and interested parties will resume discussions to address the NYPSC's competition initiatives, including changes to "customer choice" transportation services, among other things. Those discussions are currently under way.
On November 3, 1998, the NYPSC issued its Policy Statement Concerning the Future of the Natural Gas Industry in New York State and Order Terminating Capacity Assignment (Policy Statement). The Policy Statement sets forth the NYPSC's "vision" on "how best to ensure a competitive market for natural gas in New York." That vision includes the following goals:
The Policy Statement provides that the most effective way to establish a competitive market in gas supply is "for local distribution companies to cease selling gas." The NYPSC indicated in its order that it hopes to accomplish that objective over a three-to-seven year transition period from the date the Policy Statement was issued, taking into account "statutory requirements" and the individual needs of each local distribution company (LDC).* The Policy Statement directs Staff to schedule "discussions" with each LDC on an "individualized plan that would effectuate our vision." In preparation for negotiations, LDCs will be required to address issues such as a strategy to hold new capacity contracts to a minimum, a long-term rate plan with a goal of reducing or freezing rates, and a plan for further unbundling. In addition, Staff was instructed to hold collaborative sessions with multiple parties to discuss generic issues including reliability and market power regulation. Distribution Corporation has participated in the collaborative sessions. These collaborative sessions have not yet produced a consensus document on all issues before the NYPSC. Distribution Corporation will continue to participate in all future collaborative sessions.*
On March 22, 2000, the NYPSC issued an order directing electric and gas utilities to file tariff amendments "to accommodate the wishes of retail access customers who prefer to receive combined, single bills from either their utility company or their [marketer]" (Billing Order). The tariff amendments will provide for marketer single-bill or utility single-bill services, thereby allowing a customer to choose a billing preference through the customer's choice of suppliers - utility or marketer. Distribution Corporation has permitted marketer single billing since 1996.
On November 1, 2000, Distribution Corporation filed tariff amendments in compliance with the Billing Order (and a subsequent order on rehearing of the Billing Order). Consistent with the provisions of the Billing Order, Distribution Corporation's filing proposes to maintain its long-standing marketer single-bill model and add a permanent version of a utility-provided competitive single-bill service that has been available since May 2000. In addition, the filing proposes a credit (called a "backout credit"), available to marketers that issue single retail bills, equal to the long-run marginal cost of billing services avoided by Distribution Corporation. Based on the methodology set forth in the Billing Order, Distribution Corporation calculated a backout credit of $0.66 per bill avoided. The charge for Distribution Corporation's competitive billing service was set at $0.71 (with a backout credit). The company's filing proposed an effective date of February 1, 2001 and is subject to review and approval by the NYPSC. At this time, Distribution Corporation is unable to ascertain the outcome of this proceeding.*
On March 30, 2000, a collaborative was convened to address the NYPSC's Order Instituting Proceeding in the so-called "Provider of Last Resort" (POLR) case. The collaborative was charged with the task of helping the NYPSC to "refine our concept of the mature competitive retail energy markets (especially the future role of the regulated utilities) and to identify and remove obstacles to its achievement." The parties in this case are addressing, among other things, issues arising from utilities exiting the merchant function. The proceeding is also focusing on utilities' responsibility to provide low-income assistance programs. Currently the parties are collaborating on a periodic basis and are in the process of identifying issues for further review. At this time, Distribution Corporation is unable to ascertain the outcome of the POLR proceeding.*
On April 12, 2000, the NYPSC issued an order setting forth procedures for implementation of electronic data interchange (EDI) for electronic exchange of retail access data in New York (EDI Order). As described by the NYPSC, EDI is the computer-to-computer exchange of routine business information in a standard form. The NYPSC believes that EDI is necessary to develop uniform data exchange protocol for the state's customer choice initiatives. The EDI Order adopts provisions of a report prepared after an EDI collaborative involving utilities, marketers and other interests. Distribution Corporation submitted its EDI implementation plans on May 31, 2000. Implementation of EDI is expected to begin on a limited, test-only basis during the fourth quarter of calendar 2000. At this time, Distribution Corporation is unable to ascertain the outcome of the EDI proceeding.*
The NYPSC continues to address, through various proceedings and "collaboratives," upstream pipeline capacity issues arising from the restructuring. At this point, Distribution Corporation remains authorized to release upstream intermediate capacity to marketers serving former sales customers. Costs relating to retained upstream transmission capacity are recovered through a transition cost surcharge. At this time, Distribution Corporation does not foresee any material changes to upstream capacity requirements in the near term.*
On May 15, 2000, the New York State tax law was amended to phase out the long-running tax on utility gross revenues beginning January 1, 2001. Offsetting the scheduled reductions, however, is the imposition of a net income based tax on the same utilities. In a report issued on October 13, 2000, the New York Department of Public Service recommended, among other things, that utilities be kept whole for any tax increases resulting from implementation of the changes. Toward that end, the report proposes that the mechanism in rates currently used for recovery of the gross revenue tax be utilized to collect the new income tax. To the extent a utility's income tax liability exceeds the amount collectible through the existing gross revenue tax recovery mechanism, deferral accounting would be authorized. The New York Department of Public Service's report is subject to review and approval by the NYPSC after the close of the public comment period on December 18, 2000. Distribution Corporation plans to file tariff amendments revising its tax recovery mechanism consistent with the New York Department of Public Service's recommendations. At this time, Distribution Corporation is unable to ascertain the outcome of this proceeding.*
Pennsylvania Jurisdiction
Distribution Corporation currently does not have a rate case on file with the Pennsylvania Public Utility Commission (PaPUC). Management will continue to monitor its financial position in the Pennsylvania jurisdiction to determine the necessity of filing a rate case in the future.
A natural gas restructuring bill was signed into law on June 22, 1999. Entitled the Natural Gas Choice and Competition Act (Act), the new law requires all Pennsylvania LDCs to file tariffs designed to provide retail customers with direct access to competitive gas markets. Distribution Corporation submitted its compliance filing on October 1, 1999 for an effective date on or about July 1, 2000. The filing largely mirrored Distribution Corporation's System Wide Energy Select program previously in effect, which substantially complied with the Act's requirements. After negotiations with PaPUC Staff and intervenors, a settlement was reached with all parties except for the Pennsylvania Office of Consumer Advocate (OCA). The settlement parties generally agreed that Distribution Corporation's proposal needed only modest changes to meet the requirements of the Act. Hearings were held and briefs filed on OCA's open issues. In a Recommended Decision issued on March 31, 2000, the Administrative Law Judge rejected the OCA's arguments and recommended approval of the settlement agreement. On June 29, 2000, the PaPUC entered an Opinion and Order adopting the settlement, with immaterial changes. Distribution Corporation's restructured rates and services became effective on July 1, 2000.
Base rate adjustments in both the New York and Pennsylvania jurisdictions do not reflect the recovery of purchased gas costs. Such costs are recovered through operation of the purchased gas adjustment clauses of the appropriate regulatory authorities.
Pipeline and Storage
Supply Corporation currently does not have a rate case on file with the FERC. Management will continue to monitor Supply Corporation's financial position to determine the necessity of filing a rate case in the future.
Other Matters
Environmental Matters
It is the Company's policy to accrue estimated environmental clean-up costs
(investigation and remediation) when such amounts can reasonably be estimated
and it is probable that the Company will be required to incur such costs. The
Company has estimated its clean-up costs related to former manufactured gas
plant sites and third party waste disposal sites will be in the range of $6.4
million to $7.6 million.* The minimum liability of $6.4 million has been
recorded on the Consolidated Balance Sheet at September 30, 2000. Other than
discussed in Note H (referred to below), the Company is currently not aware of
any material additional exposure to environmental liabilities. However, adverse
changes in environmental regulations or other factors could impact the Company.*
The Company is subject to various federal, state and local laws and regulations
relating to the protection of the environment. The Company has established
procedures for the ongoing evaluation of its operations to identify potential
environmental exposures and comply with regulatory policies and procedures.
For further discussion refer to Note H - Commitments and Contingencies under the heading "Environmental Matters" in Item 8 of this report.
New Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). This statement was subsequently
amended by SFAS 137, "Accounting for Derivative Instruments and Hedging
Activities - Deferral of the Effective Date of FASB Statement No. 133," and by
SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging
Activities, an amendment of Statement 133." For a discussion of the impact on
the Company, see disclosure in Note A - Summary of Significant Accounting
Policies in Item 8 of this report.
Effects of Inflation
Although the rate of inflation has been relatively low over the past few years,
the Company's operations remain sensitive to increases in the rate of inflation
because of its capital spending and the regulated nature of a significant
portion of its business.
Safe Harbor for Forward-Looking Statements
The Company is including the following cautionary statement in this combined
Annual Report to Shareholders/Form 10-K to make applicable and take advantage of
the safe harbor provisions of the Private Securities Litigation Reform Act of
1995 for any forward-looking statements made by, or on behalf of, the Company.
Forward-looking statements include statements concerning plans, objectives,
goals, projections, strategies, future events or performance, and underlying
assumptions and other statements which are other than statements of historical
facts. From time to time, the Company may publish or otherwise make available
forward-looking statements of this nature. All such subsequent forward-looking
statements, whether written or oral and whether made by or on behalf of the
Company, are also expressly qualified by these cautionary statements. Certain
statements contained herein, including those which are designated with a "*",
are forward-looking statements and accordingly involve risks and uncertainties
which could cause actual results or outcomes to differ materially from those
expressed in the forward-looking statements. The forward-looking statements
contained herein are based on various assumptions, many of which are based, in
turn, upon further assumptions. The Company's expectations, beliefs and
projections are expressed in good faith and are believed by the Company to have
a reasonable basis, including, without limitation, management's examination of
historical operating trends, data contained in the Company's records and other
data available from third parties, but there can be no assurance that
management's expectations, beliefs or projections will result or be achieved or
accomplished. In addition to other factors and matters discussed elsewhere
herein, the following are important factors that, in the view of the Company,
could cause actual results to differ materially from those discussed in the
forward-looking statement:
ITEM 7A Quantitative and Qualitative Disclosures About Market Risk
Back to Table of ContentsRefer to the "Market Risk Sensitive Instruments" section in Item 7, MD&A.
ITEM 8 Financial Statements and Supplementary Data
Back to Table of ContentsFinancial Statements:
Report of Independent Accountants
Consolidated Balance Sheets at September 30, 2000 and 1999
Consolidated Statement of Cash Flows, three years ended September 30, 2000
Consolidated Statement of Comprehensive Income, three years ended September 30, 2000
Notes to Consolidated Financial Statements
Financial Statement Schedules:
For the three years ended September 30, 2000
II-Valuation and Qualifying Accounts
All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto.
Supplementary Data
Supplementary data that is included in Note K - Quarterly Financial Data (unaudited) and Note M - Supplementary Information for Oil and Gas Producing Activities, appears under this Item, and reference is made thereto.
Report of Management
Management is responsible for the preparation and integrity of the Company's financial statements. The financial statements have been prepared in accordance with generally accepted accounting principles and necessarily include some amounts that are based on management's best estimates and judgment.
The Company maintains a system of internal accounting and administrative controls and an ongoing program of internal audits that management believes provide reasonable assurance that assets are safeguarded and that transactions are properly recorded and executed in accordance with management's authorization. The Company's financial statements have been examined by our independent accountants, PricewaterhouseCoopers LLP, which also conducts a review of internal controls to the extent required by generally accepted auditing standards.
The Audit Committee of the Board of Directors, composed solely of outside directors, meets with management, internal auditors and PricewaterhouseCoopers LLP to review planned audit scope and results and to discuss other matters affecting internal accounting controls and financial reporting. The independent accountants have direct access to the Audit Committee and periodically meet with it without management representatives present.
Report of Independent Accountants
Back to Index of Financial StatementsTo the Board of Directors
and Shareholders of
National Fuel Gas Company
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of National Fuel Gas Company and its subsidiaries at September 30, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2000, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Buffalo, New York
October 23, 2000
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
- ------------------------------------------------- -------------- ------------- --------------
Year Ended September 30 (Thousands of Dollars,
Except Per Common Share Amounts) 2000 1999 1998
- ------------------------------------------------- -------------- ------------- --------------
Income
Operating Revenues $1,425,277 $1,263,274 $1,248,000
- ------------------------------------------------- -------------- ------------- --------------
Operating Expenses
Purchased Gas 503,617 405,925 441,746
Fuel Used in Heat and Electric Generation 54,893 55,788 37,837
Operation 326,933 304,919 295,618
Maintenance 23,450 23,881 25,793
Property, Franchise and Other Taxes 78,878 91,146 92,817
Depreciation, Depletion and Amortization 142,170 124,778 117,238
Impairment of Oil and Gas Producing
Properties - - 128,996
Income Taxes 77,068 64,829
24,024
- ------------------------------------------------- -------------- ------------- --------------
1,207,009 1,071,266 1,164,069
- ------------------------------------------------- -------------- ------------- --------------
Operating Income 218,268 192,008 83,931
Other Income 10,408 12,343
35,870
- ------------------------------------------------- -------------- ------------- --------------
Income Before Interest Charges and
Minority Interest in Foreign Subsidiaries 228,676 204,351 119,801
- ------------------------------------------------- -------------- ------------- --------------
Interest Charges
Interest on Long-Term Debt 67,195 65,402 53,154
Other Interest 32,890 22,296
32,130
- ------------------------------------------------- -------------- ------------- --------------
100,085 87,698
85,284
- ------------------------------------------------- -------------- ------------- --------------
Minority Interest in Foreign Subsidiaries (1,384) (1,616)
(2,213)
- ------------------------------------------------- -------------- ------------- --------------
Income Before Cumulative Effect 127,207 115,037 32,304
Cumulative Effect of Change in
Accounting for Depletion - -
(9,116)
- ------------------------------------------------- -------------- ------------- --------------
Net Income Available for Common Stock 127,207 115,037 23,188
- ------------------------------------------------- -------------- ------------- --------------
Earnings Reinvested in the Business
Balance at Beginning of Year 472,517 428,112 472,595
- ------------------------------------------------- -------------- ------------- --------------
599,724 543,149 495,783
Dividends on Common Stock 73,877 70,632
67,671
- ------------------------------------------------- -------------- ------------- --------------
Balance at End of Year $525,847 $472,517 $428,112
- ------------------------------------------------- -------------- ------------- --------------
Basic Earnings Per Common Share:
Income Before Cumulative Effect $3.25 $2.98 $0.85
Cumulative Effect of Change in Accounting
For Depletion - - (0.24)
- ------------------------------------------------- -------------- ------------- --------------
Net Income Available for Common Stock $3.25 $2.98 $0.61
- ------------------------------------------------- -------------- ------------- --------------
Diluted Earnings Per Common Share:
Income Before Cumulative Effect $3.21 $2.95 $0.84
Cumulative Effect of Change in Accounting
For Depletion - - (0.24)
- ------------------------------------------------- -------------- ------------- --------------
Net Income Available for Common Stock $3.21 $2.95 $0.60
- ------------------------------------------------- -------------- ------------- --------------
Weighted Average Common Shares Outstanding:
Used in Basic Calculation 39,116,921 38,663,981 38,316,397
Used in Diluted Calculation 39,583,100 39,041,728 38,703,526
- ------------------------------------------------- -------------- ------------- --------------
See Notes to Consolidated Financial Statements
Back to Index of Financial StatementsNational Fuel Gas Company
Consolidated Balance Sheets
- ------------------------------------------------- --------------- ---------------
At September 30 (Thousands of Dollars) 2000 1999
- ------------------------------------------------- --------------- ---------------
Assets
Property, Plant and Equipment $3,829,637 $3,390,875
Less - Accumulated Depreciation,
Depletion and Amortization 1,146,246 1,029,643
- ------------------------------------------------- --------------- ---------------
2,683,391 2,361,232
- ------------------------------------------------- --------------- ---------------
Current Assets
Cash and Temporary Cash Investments 32,125 29,222
Receivables - Net 122,127 97,828
Unbilled Utility Revenue 27,105 18,674
Gas Stored Underground 55,795 41,099
Materials and Supplies - at average cost 25,145 23,631
Unrecovered Purchased Gas Costs 29,681 4,576
Prepayments 32,293 35,072
- ------------------------------------------------- --------------- ---------------
324,271 250,102
- ------------------------------------------------- --------------- ---------------
Other Assets
Recoverable Future Taxes 84,199 87,724
Unamortized Debt Expense 19,841 21,717
Other Regulatory Assets 17,518 25,214
Deferred Charges 12,497 14,266
Other 95,171 82,331
- ------------------------------------------------- --------------- ---------------
229,226 231,252
- ------------------------------------------------- --------------- ---------------
$3,236,888 $2,842,586
- ------------------------------------------------- --------------- ---------------
See Notes to Consolidated Financial Statements
Back to Index of Financial StatementsNational Fuel Gas Company
Consolidated Balance Sheets
- -------------------------------------------------- ------------- -------------
At September 30 (Thousands of Dollars) 2000 1999
- -------------------------------------------------- ------------- -------------
Capitalization and Liabilities
Capitalization:
Common Stock Equity
Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued and
Outstanding - 39,329,803 Shares and 38,837,499
Shares, Respectively $ 39,330 $ 38,837
Paid In Capital 452,217 431,952
Earnings Reinvested in the Business 525,847 472,517
Accumulated Other Comprehensive Income (29,957) (4,013)
- -------------------------------------------------- ------------- -------------
Total Common Stock Equity 987,437 939,293
Long-Term Debt, Net of Current Portion 953,622 822,743
- -------------------------------------------------- ------------- -------------
Total Capitalization 1,941,059 1,762,036
- -------------------------------------------------- ------------- -------------
Minority Interest in Foreign Subsidiaries 23,031 27,589
- -------------------------------------------------- ------------- -------------
Current and Accrued Liabilities
Notes Payable to Banks and
Commercial Paper 619,502 393,495
Current Portion of Long-Term Debt 11,262 69,608
Accounts Payable 88,970 82,747
Amounts Payable to Customers 9,583 5,934
Other Accruals and Current Liabilities 84,961 87,310
- -------------------------------------------------- ------------- -------------
814,278 639,094
- -------------------------------------------------- ------------- -------------
Deferred Credits
Accumulated Deferred Income Taxes 326,994 275,008
Taxes Refundable to Customers 14,410 14,814
Unamortized Investment Tax Credit 9,951 11,007
Other Deferred Credits 107,165 113,038
- -------------------------------------------------- ------------- -------------
458,520 413,867
- -------------------------------------------------- ------------- -------------
Commitments and Contingencies - -
- -------------------------------------------------- ------------- -------------
$3,236,888 $2,842,586
- -------------------------------------------------- ------------- -------------
See Notes to Consolidated Financial Statements
Back to Index of Financial StatementsNational Fuel Gas Company
Consolidated Statement of Cash Flows
- ------------------------------------------------------- ------------- ------------- --------------
Year Ended September 30 (Thousands of Dollars) 2000 1999 1998
- ------------------------------------------------------- ------------- ------------- --------------
Operating Activities
Net Income Available for Common Stock $127,207 $115,037 $ 23,188
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities
Cumulative Effect of a Change in Accounting
for Depletion - - 9,116
Impairment of Oil and Gas Producing Properties - - 128,996
Depreciation, Depletion and Amortization 142,170 124,778 117,238
Deferred Income Taxes 41,858 14,030 (26,237)
Minority Interest in Foreign Subsidiaries 1,384 1,616 2,213
Other 4,540 7,018 (6,378)
Change in:
Receivables and Unbilled Utility Revenue (26,825) (18,161) 45,200
Gas Stored Underground and Materials and
Supplies (13,707) (7,280) (2,744)
Unrecovered Purchased Gas Costs (25,105) 1,740 (6,316)
Prepayments 3,436 (15,322) 829
Accounts Payable (16,372) 22,871 (24,975)
Amounts Payable to Customers 3,649 153 (4,735)
Other Accruals and Current Liabilities (4,642) 10,931 (15,481)
Other Assets 8,537 (906) 36
Other Liabilities (7,884) 10,999 9,913
- ------------------------------------------------------- ------------- ------------- --------------
Net Cash Provided by Operating Activities 238,246 267,504 249,863
- ------------------------------------------------------- ------------- ------------- --------------
Investing Activities
Capital Expenditures (269,371) (256,120) (390,118)
Investment in Subsidiaries, Net of Cash Acquired (123,809) (5,774) (111,966)
Investment in Partnerships (4,442) (3,633) (5,453)
Other 13,283 6,687 7,583
- ------------------------------------------------------- ------------- ------------- --------------
Net Cash Used in Investing Activities (384,339) (258,840) (499,954)
- ------------------------------------------------------- ------------- ------------- --------------
Financing Activities
Change in Notes Payable to Banks and Commercial
Paper 226,477 67,195 229,387
Net Proceeds from Issuance of Long-Term Debt 149,334 198,217 198,750
Reduction of Long-Term Debt (167,426) (213,849) (103,867)
Proceeds from Issuance of Common Stock 14,278 10,735 7,853
Dividends Paid on Common Stock (73,046) (69,878) (66,959)
Dividends Paid to Minority Interest (152) (246) (253)
- ------------------------------------------------------- ------------- ------------- --------------
Net Cash Provided by (Used in) Financing Activities 149,465 (7,826) 264,911
- ------------------------------------------------------- ------------- ------------- --------------
Effect of Exchange Rates on Cash (469) (2,053) 1,578
- ------------------------------------------------------- ------------- ------------- --------------
Net Increase (Decrease) in Cash and
Temporary Cash Investments 2,903 (1,215) 16,398
Cash and Temporary Cash Investments
at Beginning of Year 29,222 30,437 14,039
- ------------------------------------------------------- ------------- ------------- --------------
Cash and Temporary Cash Investments
at End of Year $ 32,125 $ 29,222 $ 30,437
- ------------------------------------------------------- ------------- ------------- --------------
Supplemental Disclosure of Cash Flow Information
Cash Paid For:
Interest $97,042 $75,813 $46,242
Income Taxes 41,928 48,995 64,537
- ------------------------------------------------------- ------------- ------------- --------------
See Notes to Consolidated Financial Statements
Back to Index of Financial StatementsNational Fuel Gas Company
Consolidated Statement of Comprehensive Income
- ---------------------------------------------- --------------------------------------------------------------
Year Ended September 30 (Thousands of
Dollars)
--------------------------------------------------------------
2000 1999 1998
-------------------- --------------------- -------------------
Net Income Available for Common Stock $127,207 $115,037 $23,188
- ---------------------------------------------- -------- ----------- -------- ----------- ------ -------------
Foreign Currency Translation Adjustment (27,463) (11,737) 9,350
Unrealized Gain on Securities Available for
Sale Arising During the Period 2,441 706 -
Reclassification Adjustment for Gains on
Securities Available for Sale Realized
in Net (103) - -
Income
- ---------------------------------------------- -------- ----------- -------- ----------- ------ -------------
Other Comprehensive Income (Loss), Before
Tax: (25,125) (11,031) 9,350
- ---------------------------------------------- -------- ----------- -------- ----------- ------ -------------
Income Tax Expense Related to Unrealized
Gain on Securities Available for Sale
Arising 855 247 -
During the Period
Reclassification Adjustment for Income Tax
Expense on Gains on Securities Available
for Sale Realized in Net Income (36) - -
- ---------------------------------------------- -------- ----------- -------- ----------- ------ -------------
Income Taxes - Net 819 247 -
- ---------------------------------------------- -------- ----------- -------- ----------- ------ -------------
Other Comprehensive Income (Loss), Net of
Tax (25,944) (11,278) 9,350
- ---------------------------------------------- -------- ----------- -------- ----------- ------ -------------
Comprehensive Income $101,263 $103,759 $32,538
- ---------------------------------------------- -------- ----------- -------- ----------- ------ -------------
See Notes to Consolidated Financial Statements
Back to Index of Financial StatementsNotes to Consolidated Financial Statements
Back to Index of Financial StatementsNote A - Summary of Significant Accounting Policies
Principles of Consolidation
The Company consolidates its majority owned subsidiaries. The equity method is
used to account for minority owned entities. All significant intercompany
balances and transactions are eliminated.
The preparation of the consolidated 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. Actual results could differ from those estimates.
Reclassification
Certain prior year amounts have been reclassified to conform with current year
presentation.
Regulation
The Company is subject to regulation by certain state and federal authorities.
The Company has accounting policies which conform to generally accepted
accounting principles, as applied to regulated enterprises, and are in
accordance with the accounting requirements and ratemaking practices of the
regulatory authorities. Reference is made to Note B - Regulatory Matters for
further discussion.
In the International segment, rates charged for the sale of thermal energy and electric energy at the retail level are subject to regulation and audit in the Czech Republic by the Czech Ministry of Finance. The regulation of electric energy rates at the retail level indirectly impacts the rates charged by the International segment for its electric energy sales at the wholesale level.
Revenues
Revenues are recorded as bills are rendered, except that service supplied but
not billed is reported as "Unbilled Utility Revenue" and is included in
operating revenues for the year in which service is furnished.
Unrecovered Purchased Gas Costs and Refunds
The Company's rate schedules in the Utility segment contain clauses that permit
adjustment of revenues to reflect price changes from the cost of purchased gas
included in base rates. Differences between amounts currently recoverable and
actual adjustment clause revenues, as well as other price changes and pipeline
and storage company refunds not yet includable in adjustment clause rates, are
deferred and accounted for as either unrecovered purchased gas costs or amounts
payable to customers.
Estimated refund liabilities to ratepayers represent management's current estimate of such refunds. Reference is made to Note B - Regulatory Matters for further discussion.
Property, Plant and Equipment
The principal assets of the Utility and Pipeline and Storage segments,
consisting primarily of gas plant in service, are recorded at the historical
cost when originally devoted to service in the regulated businesses, as required
by regulatory authorities.
Oil and gas property acquisition, exploration and development costs are capitalized under the full-cost method of accounting. All costs directly associated with property acquisition, exploration and development activities are capitalized, up to certain specified limits. If capitalized costs exceed these limits at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. Due to significant declines in oil prices in 1998, capitalized costs under the full-cost method of accounting exceeded these limits at March 31, 1998. The Company was required to recognize an impairment of its oil and gas producing properties in the quarter ended March 31, 1998. This charge amounted to $129.0 million (pretax) and reduced net income for 1998 by $79.1 million.
Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries' property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization are computed by application of either
the straight-line method or the units of production method, in amounts
sufficient to recover costs over the estimated service lives of property in
service, and for oil and gas properties, based on quantities produced in
relation to proved reserves (see discussion of change in method of depletion for
oil and gas properties below). The costs of unevaluated oil and gas properties
are excluded from this computation. For timber properties, depletion, determined
on a property by property basis, is charged to operations based on the annual
amount of timber cut in relation to the total amount of recoverable timber. The
provisions for depreciation, depletion and amortization, as a percentage of
average depreciable property, were 4.2% in 2000, 4.1% in 1999 and 4.3% in 1998
on a consolidated basis.
Cumulative Effect of Change in Accounting
Effective October 1, 1997, the Company changed its method of depletion for oil
and gas properties from the gross revenue method to the units of production
method. The units of production method was applied retroactively to prior years
to determine the cumulative effect through October 1, 1997. This cumulative
effect reduced earnings for 1998 by $9.1 million, net of income tax. Depletion
of oil and gas properties for 2000, 1999 and 1998 was computed under the units
of production method.
Gas Stored Underground - Current
In the Utility segment, gas stored underground - current in the amount of $29.3
million is carried at lower of cost or market, on a last-in, first-out (LIFO)
method. Based upon the average price of spot market gas purchased in September
2000, including transportation costs, the current cost of replacing this
inventory of gas stored underground-current exceeded the amount stated on a LIFO
basis by approximately $104.2 million at September 30, 2000. All other gas
stored underground - current is carried at lower of cost or market on either an
average cost or first-in, first-out method.
Unamortized Debt Expense
Costs associated with the issuance of debt by the Company are deferred and
amortized over the lives of the related issues. Costs associated with the
reacquisition of debt related to rate-regulated subsidiaries are deferred and
amortized over the remaining life of the issue or the life of the replacement
debt in order to match regulatory treatment.
Foreign Currency Translation
The functional currency for the Company's foreign operations is the local
currency. Asset and liability accounts are translated at the rate of exchange on
the balance sheet date. Revenues and expenses are translated at the average
exchange rate during the period. Foreign currency translation adjustments are
recorded as a component of Accumulated Other Comprehensive Income.
Income Taxes
The Company and its domestic subsidiaries file a consolidated federal income tax
return. Investment Tax Credit, prior to its repeal in 1986, was deferred and is
being amortized over the estimated useful lives of the related property, as
required by regulatory authorities having jurisdiction. No provision has been
made for domestic income taxes applicable to undistributed earnings of foreign
subsidiaries as the amounts are considered to be permanently reinvested outside
the U.S.
Financial Instruments
Unrealized gains or losses from the Company's investments in marketable equity
securities are recorded as a component of Accumulated Other Comprehensive
Income. Reference is made to Note F - Financial Instruments for further
discussion.
The Company uses a variety of financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These instruments can be categorized as price swap agreements, no cost collars, options and futures contracts. Gains or losses from price swap agreements are accrued in operating revenues at the contract settlement dates. Options and futures contracts that have not been designated as hedges are marked-to-market on a quarterly basis with gains or losses recorded in operating revenues. For options that have been designated as hedges, premiums are amortized on a straight-line basis over the life of the option. Gains or losses resulting from the exercise of options that have been designated as hedges are reflected in operating revenues when the hedged commodity transaction occurs. Gains or losses from futures contracts that have been designated as hedges are recorded in other deferred credits or deferred debits until the hedged commodity transaction occurs, at which point they are reflected in operating revenues.
The Company also uses an interest rate swap to eliminate interest rate fluctuations on certain variable rate debt. Gains or losses are accrued in interest charges at the contract settlement dates.
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). This statement was subsequently amended by SFAS 137, "Accounting for Derivative Instruments and Hedging Activities--Deferral of the Effective Date of FASB Statement No. 133," and by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of Statement 133." SFAS 133, as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. This statement requires the Company to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The intended use of the derivatives and their designation as either a fair value hedge, a cash flow hedge, or a foreign currency hedge will determine when the gains or losses on the derivatives are to be reported in earnings and when they are to be reported as a component of other comprehensive income. The Company will adopt SFAS 133, as amended, during the first quarter of fiscal 2001. The cumulative effect of this change will decrease fiscal 2001 net income by approximately $0.3 million after tax. The cumulative effect of this change will decrease other comprehensive income by approximately $69.8 million after tax.
Accumulated Other Comprehensive Income (Loss)
The components of Accumulated Other Comprehensive Income (Loss) are as follows:
- ------------------------------------------------------ ------------- -------------- Year Ended September 30 (Thousands) 2000 1999 - ------------------------------------------------------ ------------- -------------- Cumulative Foreign Currency Translation Adjustment $(31,935) $(4,472) Net Unrealized Gain on Securities Available for Sale 1,978 459 - ------------------------------------------------------ ------------- -------------- Accumulated Other Comprehensive Loss $(29,957) $(4,013) - ------------------------------------------------------ ------------- --------------
Consolidated Statement of Cash Flows
For purposes of the Consolidated Statement of Cash Flows, the Company considers
all highly liquid debt instruments purchased with a maturity of generally three
months or less to be cash equivalents.
Earnings Per Common Share
Basic earnings per common share is computed by dividing income available for
common stock by the weighted average number of common shares outstanding for the
period. Diluted earnings per common share reflects the potential dilution that
could occur if securities or other contracts to issue common stock were
exercised or converted into common stock. The only potentially dilutive
securities the Company has outstanding are stock options. The diluted weighted
average shares outstanding shown on the Consolidated Statement of Income
reflects the potential dilution as a result of these stock options as determined
using the Treasury Stock Method.
Note B - Regulatory Matters
Regulatory Assets and Liabilities
The Company has recorded the following regulatory assets and liabilities:
- ------------------------------------------------------ ------------ -----------
At September 30 (Thousands) 2000 1999
- ------------------------------------------------------ ------------ -----------
Regulatory Assets:
Recoverable Future Taxes (Note C) $84,199 $87,724
Unrecovered Purchased Gas Costs (Note A) 29,681 4,576
Unamortized Debt Expense (Note A) 13,454 15,223
Pension and Post-Retirement Benefit Costs (Note G) 16,370 21,217
Other 1,148 3,997
- ------------------------------------------------------ ------------ -----------
Total Regulatory Assets 144,852 132,737
- ------------------------------------------------------ ------------ -----------
Regulatory Liabilities:
Amounts Payable to Customers (Note A) 9,583 5,934
New York Rate Settlements 21,315 18,913
Taxes Refundable to Customers (Note C) 14,410 14,814
Pension and Post-Retirement Benefit Costs(1) (Note G) 17,439 26,087
Other(1) 2,975 3,226
- ------------------------------------------------------ ------------ -----------
Total Regulatory Liabilities 65,722 68,974
- ------------------------------------------------------ ------------ -----------
Net Regulatory Position $79,130 $63,763
- ------------------------------------------------------ ------------ -----------
(1) Included in Other Deferred Credits on the Consolidated Balance Sheets.
If for any reason the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of their operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in income of the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item.
New York Rate Settlements
With respect to utility services provided in New York, the Company has entered
into rate settlements approved by the State of New York Public Service
Commission (NYPSC). The rate settlements provide for a sharing mechanism,
whereby earnings above a 12% return on equity (11.5% effective October 1, 2000)
are to be shared equally between shareholders and ratepayers. As a result of
this sharing mechanism, the Company had liabilities of $11.2 million and $8.6
million at September 30, 2000 and 1999, respectively. Of these amounts, $7.6
million and $3.0 million are included in Amounts Payable to Customers at
September 30, 2000 and 1999, respectively, to reflect the amounts estimated to
be passed back to customers in the following year. Other aspects of the
settlements include a special reserve of $7.8 million and $7.4 million at
September 30, 2000 and 1999, respectively, to be applied against the Company's
incremental costs resulting from the NYPSC's gas restructuring effort and a
"refund pool" of $5.6 million and $3.5 million at September 30, 2000 and 1999,
respectively. The refund pool is an accumulation of certain refunds from
upstream pipeline companies and certain credits which can be used to offset
certain specific expense items. Various other regulatory liabilities have also
been created through the New York rate settlements and amounted to $4.2 million
and $2.5 million at September 30, 2000 and 1999, respectively.
Note C - Income Taxes
The components of federal, state and foreign income taxes included in the Consolidated Statement of Income are as follows:
- ------------------------------------------- ------------- ----------- ----------
Year Ended September 30 (Thousands) 2000 1999 1998
- ------------------------------------------- ------------- ----------- ----------
Operating Expenses:
Current Income Taxes -
Federal $ 26,352 $ 43,467 $ 40,740
State 13,067 6,215 6,635
Deferred Income Taxes -
Federal 29,604 11,149 (21,687)
State 2,495 1,244 (5,997)
Foreign Income Taxes 5,550 2,754 4,333
- ------------------------------------------- ------------- ----------- ----------
77,068 64,829 24,024
Other Income:
Deferred Investment Tax Credit (1,051) (729) (665)
Minority Interest in Foreign Subsidiaries (259) (642) (1,218)
Cumulative Effect of Change in Accounting
for Depletion - - (5,737)
- ------------------------------------------- ------------- ----------- ----------
Total Income Taxes $ 75,758 $ 63,458 $ 16,404
- ------------------------------------------- ------------- ----------- ----------
The U.S. and foreign components of income (loss) before income taxes are as follows:
- ----------------------------------------------------- ------------- -------------- -------------
Year Ended September 30 (Thousands) 2000 1999 1998
- ----------------------------------------------------- ------------- -------------- -------------
U.S. $182,813 $169,038 $ 31,127
Foreign 20,152 9,457 8,465
- ----------------------------------------------------- ------------- -------------- -------------
$202,965 $178,495 $ 39,592
- ----------------------------------------------------- ------------- -------------- -------------
Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference:
- --------------------------------------------- --------------- ---------- --------- Year Ended September 30 (Thousands) 2000 1999 1998 - --------------------------------------------- --------------- ---------- --------- Income Tax Expense, Computed at Federal Statutory Rate of 35% $ 71,038 $ 62,473 $ 13,857 Increase (Reduction) in Taxes Resulting from: State Income Taxes 10,115 4,848 986 Depreciation 1,925 1,872 2,186 Property Retirements (1,470) (833) (1,609) Keyman Life Insurance (964) (502) (774) Prior Years' Tax Adjustment 137 (1,362) 2,846 Miscellaneous (5,023) (3,038) (1,088) - --------------------------------------------- --------------- ---------- --------- Total Income Taxes $ 75,758 $ 63,458 $ 16,404 - --------------------------------------------- --------------- ---------- ---------
Significant components of the Company's deferred tax liabilities and assets were as follows:
- ------------------------------------- ------------- ------------ At September 30 (Thousands) 2000 1999 - ------------------------------------- ------------- ------------ Deferred Tax Liabilities: Property, Plant and Equipment $375,660 $305,688 Other 23,776 19,045 - ------------------------------------- ------------- ------------ Total Deferred Tax Liabilities 399,436 324,733 - ------------------------------------- ------------- ------------ Deferred Tax Assets: Other (72,442) (49,725) - ------------------------------------- ------------- ------------ Total Net Deferred Income Taxes $326,994 $275,008 - ------------------------------------- ------------- ------------
Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $14.4 million and $14.8 million at September 30, 2000 and 1999, respectively. Also, regulatory assets, representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices amounted to $84.2 million and $87.7 million at September 30, 2000 and 1999, respectively.
Note D - Capitalization
Summary of Changes in Common Stock Equity
- --------------------- --------- ------------ ------------- ------------- -----------------
Earnings Accumulated
Paid Reinvested Other
(Thousands, Except Per Share Common Stock In in the Comprehensive
Amounts) Shares Amount Capital Business Income
- ---------------------- --------- ------------- ------------- ------------- -----------------
Balance at
September 30, 1997 38,166 $38,166 $405,028 $472,595 $(2,085)
Net Income Available
for Common Stock 23,188
Dividends Declared
on Common Stock
($1.77 Per Share) (67,671)
Other Comprehensive
Income, Net of Tax 9,350
Common Stock Issued
Under Stock and
Benefit Plans 303 303 11,211
- ---------------------- --------- ------------ ------------- ------------- -----------------
Balance at
September 30, 1998 38,469 38,469 416,239 428,112 7,265
Net Income Available
for Common Stock 115,037
Dividends Declared on
Common Stock
($1.83 Per Share) (70,632)
Other Comprehensive
Income, Net of Tax (11,278)
Common Stock Issued
Under Stock and
Benefit Plans 368 368 15,713
- ---------------------- --------- ------------ ------------- ------------- -----------------
Balance at
September 30, 1999 38,837 38,837 431,952 472,517 (4,013)
Net Income Available
for Common Stock 127,207
Dividends Declared on
Common Stock
($1.89 Per Share) (73,877)
Other Comprehensive
Income, Net of Tax (25,944)
Acquisition of
Natural Gas Assets 55 55 2,757
Common Stock Issued
Under Stock and
Benefit Plans 438 438 17,508
- ---------------------- --------- ------------- ------------- ------------- -----------------
Balance at
September 30, 2000 39,330 $39,330 $452,217 $525,847(1) $(29,957)
- ---------------------- --------- ------------- ------------- ------------- -----------------
(1) |
The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 2000, $451.5 million of accumulated earnings was free of such limitations. |
Common Stock
The Company has various plans which allow shareholders, customers and employees
to purchase shares of Company common stock. The National Fuel Direct Stock
Purchase and Dividend Reinvestment Plan allows shareholders to reinvest cash
dividends or make cash investments in the Company's common stock and provides
residential customers the opportunity to acquire shares of Company common stock
without the payment of any brokerage commissions or service charges in
connection with such acquisitions. The 401(k) Plans allow employees the
opportunity to invest in Company common stock, in addition to a variety of other
investment alternatives. At the discretion of the Company, shares purchased
under these plans are either original issue shares purchased directly from the
Company or shares purchased on the open market by an agent.
The Company also has a Director Stock Program under which it issues shares of Company common stock to its non-employee directors as partial consideration for their services as directors.
Shareholder Rights Plan
In 1996, the Company's Board of Directors adopted a shareholder rights plan
(Plan). Effective April 30, 1999, the Plan was amended and is now embodied in an
Amended and Restated Rights Agreement.
The holders of the Company's common stock have one right (Right) for each of their shares. Each Right, which will initially be evidenced by the Company's common stock certificates representing the outstanding shares of common stock, entitles the holder to purchase one-half of one share of common stock at a purchase price of $130 per share, being $65 per half share, subject to adjustment (Purchase Price).
The Rights become exercisable upon the occurrence of a distribution date. At any time following a distribution date, each holder of a Right may exercise its right to receive common stock (or, under certain circumstances, other property of the Company) having a value equal to two times the Purchase Price of the Right then in effect. However, the Rights are subject to redemption or exchange by the Company prior to their exercise as described below.
A distribution date would occur upon the earlier of (i) ten days after the public announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of the Company's common stock or other voting stock having 10% or more of the total voting power of the Company's common stock and other voting stock and (ii) ten days after the commencement or announcement by a person or group of an intention to make a tender or exchange offer that would result in that person acquiring, or obtaining the right to acquire, beneficial ownership of the Company's common stock or other voting stock having 10% or more of the total voting power of the Company's common stock and other voting stock.
In certain situations after a person or group has acquired beneficial ownership of 10% or more of the total voting power of the Company's stock as described above, each holder of a Right will have the right to exercise its Rights to receive common stock of the acquiring company having a value equal to two times the Purchase Price of the Right then in effect. These situations would arise if the Company is acquired in a merger or other business combination or if 50% or more of the Company's assets or earning power are sold or transferred.
At any time prior to the end of the business day on the tenth day following the announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of 10% or more of the total voting power of the Company, the Company may redeem the Rights in whole, but not in part, at a price of $.01 per Right, payable in cash or stock. A decision to redeem the Rights requires the vote of 75% of the Company's full Board of Directors. Also, at any time following the announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of 10% or more of the total voting power of the Company, 75% of the Company's full Board of Directors may vote to exchange the Rights, in whole or in part, at an exchange rate of one share of common stock, or other property deemed to have the same value, per Right, subject to certain adjustments.
After a distribution date, Rights that are owned by an acquiring person will be null and void. Upon exercise of the Rights, the Company may need additional regulatory approvals to satisfy the requirements of the Rights Agreement. The Rights will expire on July 31, 2008, unless they are exchanged or redeemed earlier than that date.
The Rights have anti-takeover effects because they will cause substantial dilution of the common stock if a person attempts to acquire the Company on terms not approved by the Board of Directors.
Stock Option and Stock Award Plans
The Company has various stock option and stock award plans which provide or
provided for the issuance of one or more of the following to key employees:
incentive stock options, nonqualified stock options, stock appreciation rights,
restricted stock, performance units or performance shares. Stock options under
all plans have exercise prices equal to the average market price of Company
common stock on the date of grant, and generally no option is exercisable less
than one year or more than ten years after the date of each grant.
For the years ended September 30, 2000, 1999 and 1998, no compensation expense was recognized for options granted under these plans. Had compensation expense for stock options granted under the Company's stock option and stock award plans been determined based on fair value at the grant dates, the Company's net income and earnings per share would have been reduced to the pro forma amounts below:
- -------------------------------- ------------- -------------- -------------
Year Ended September 30 2000 1999 1998
- -------------------------------- ------------- -------------- -------------
Net Income (Thousands):
As reported $127,207 $115,037 $23,188
Pro forma $123,107 $111,385 $18,859
Earnings Per Common Share:
Basic - As reported $3.25 $2.98 $0.61
Basic - Pro forma $3.15 $2.88 $0.49
Diluted - As reported $3.21 $2.95 $0.60
Diluted - Pro forma $3.11 $2.85 $0.49
- -------------------------------- ------------- -------------- -------------
Transactions involving option shares for all plans are summarized as follows:
- ------------------------------------- ------------------- ----------------------
Number of
Shares Subject Weighted Average
to Option Exercise Price
- ------------------------------------- ------------------- ----------------------
Outstanding at September 30, 1997 2,174,346 $33.21
Granted in 1998 770,000 $44.44
Exercised in 1998 (205,200) $27.41
Forfeited in 1998 (7,250) $41.68
- ------------------------------------- ------------------- ----------------------
Outstanding at September 30, 1998 2,731,896 $36.79
Granted in 1999 753,400 $46.70
Exercised in 1999 (111,504) $28.41
Forfeited in 1999 (9,700) $37.41
- ------------------------------------- ------------------- ----------------------
Outstanding at September 30, 1999 3,364,092 $39.29
Granted in 2000 891,100 $43.74
Exercised in 2000(1) (227,742) $30.16
Forfeited in 2000 (13,900) $46.15
- ------------------------------------- ------------------- ----------------------
Outstanding at September 30, 2000 4,013,550 $40.77
- ------------------------------------- ------------------- ----------------------
Option shares exercisable
at September 30, 2000 3,005,354 $39.63
Option shares available for future
grant at September 30, 2000(2) 1,099,830
- ------------------------------------- ------------------- ----------------------
|
(1) In connection with exercising these options, 58,458, 16,531 and 44,580
shares were surrendered and canceled during 2000, 1999 and 1998,
respectively. |
The weighted average fair value per share of options granted in 2000, 1999 and 1998 was $8.34, $7.43 and $7.91, respectively. These weighted average fair values were estimated on the date of grant using a binomial option pricing model with the following weighted average assumptions:
- -------------------------------------- --------------- ------------ ----------- Year Ended September 30 2000 1999 1998 - -------------------------------------- --------------- ------------ ----------- Quarterly Dividend Yield 1.07% 0.97% 0.98% Annual Standard Deviation (Volatility) 19.05% 18.86% 16.48% Risk Free Rate 6.74% 4.74% 5.77% Expected Term - in Years 5.5 5.0 5.5 - -------------------------------------- --------------- ------------ -----------
The following table summarizes information about options outstanding at September 30, 2000:
- ------------------------------------------------------------- --------------------------
Options Outstanding Options Exercisable
- ------------------------------------------------------------- --------------------------
Weighted
Number Average Weighted Number Weighted
Range of Outstanding Remaining Average Exercisable Average
Exercise Price at 9/30/00 Contractual Exercise at 9/30/00 Exercise
Life Price Price
- ------------------ ------------- ---------------- ----------- ------------- ------------
$23.81 - $35.72 697,026 3.8 years $29.34 697,026 $29.34
$35.73 - $49.72 3,316,524 7.8 years $43.17 2,308,328 $42.73
- ------------------ ------------- ---------------- ----------- --------------- ------------
Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. The market value of restricted stock on the date of the award is being recorded as compensation expense over the periods during which the vesting restrictions exist. Certificates for shares of restricted stock awarded under the Company's stock options and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective.
The following table summarizes the awards of restricted stock over the past three years:
- ------------------------------------- ------------- -------------- ------------- Year Ended September 30 2000 1999 1998 - ------------------------------------- ------------- -------------- ------------- Shares of Restricted Stock Awarded 7,589 6,580 7,609 Weighted Average Market Price of Stock on Award Date $48.94 $46.06 $44.88 - ------------------------------------- ------------- -------------- -------------
As of September 30, 2000, 75,693 shares of non-vested restricted stock were outstanding. Vesting restrictions will lapse as follows: 2001 - 35,104 shares; 2002 - 8,000 shares; 2003 - 12,925 shares; 2004 - 7,000 shares; 2005 - 6,000 shares; 2006 - 6,000 shares; and 2009 - 664 shares.
Stock Appreciation Rights (SARs) give the grantee the right to cash compensation equal to the appreciation in the market price of Company common stock from the grant date to the exercise date. SARs are marked-to-market each quarter with the related increase or decrease in expense recognized in the income statement. At September 30, 2000, 1,381,000 SARs were outstanding at a weighted average exercise price of $38.54.
Compensation expense related to SARs and restricted stock under the Company's stock plans was $14.9 million, $1.0 million and $4.1 million for the years ended September 30, 2000, 1999 and 1998, respectively.
Redeemable Preferred Stock
As of September 30, 2000, there were 10,000,000 shares of $1 par value Preferred
Stock authorized but unissued.
Long-Term Debt
The outstanding long-term debt is as follows:
- ------------------------------------ -------------- -------------
At September 30 (Thousands) 2000 1999
- ------------------------------------ -------------- -------------
Debentures:
7-3/4% due February 2004 $125,000 $125,000
Medium-Term Notes:
6.00% to 8.48% due February
2000 to August 2027(1) 799,000 699,000
- ------------------------------------ -------------- -------------
924,000 824,000
- ------------------------------------ -------------- -------------
Other Notes 40,884 68,351
- ------------------------------------ -------------- -------------
Total Long-Term Debt 964,884 892,351
Less Current Portion 11,262 69,608
- ------------------------------------ -------------- -------------
$953,622 $822,743
- ------------------------------------ -------------- -------------
|
(1)Includes $50 million of 8.48% medium-term notes due July 2024 which are callable at a redemption price of 105.94% through July 2001. The redemption price will decline in subsequent years. It also includes $100 million of 6.214% medium-term notes due August 2027 which are putable by debt holders only on August 12, 2002, at par. |
The aggregate principal amounts of long-term debt maturing for the next five years and thereafter are as follows: $11.3 million in 2001, $8.5 million in 2002, $158.6 million in 2003, $233.7 million in 2004, $2.7 million in 2005 and $550.1 million thereafter.
Note E - Short-Term Borrowings
The Company has SEC authorization under the Public Utility Holding Company Act of 1935, as amended, to borrow and have outstanding as much as $750.0 million of short-term debt at any time through December 31, 2002.
The Company historically has borrowed short-term funds either through bank loans or the issuance of commercial paper. As for the former, the Company maintains uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. These credit lines are revocable at the option of the financial institutions and are reviewed on an annual basis.
At September 30, 2000, the Company had outstanding short-term notes payable to banks and commercial paper of $419.5 million (domestic = $401.2 million; foreign = $18.3 million) and $200.0 million, respectively. At September 30, 1999, the Company had outstanding notes payable to banks and commercial paper of $246.0 million (domestic = $244.8 million; foreign = $1.2 million) and $147.5 million, respectively.
The weighted average interest rate on domestic notes payable to banks was 6.81% and 5.55% at September 30, 2000 and 1999, respectively. The interest rate on the foreign notes payable to banks was 5.73% and 6.35% at September 30, 2000 and 1999, respectively. The weighted average interest rate on commercial paper was 6.62% and 5.49% at September 30, 2000 and 1999, respectively.
Note F - Financial Instruments
Fair Values
The fair market value of the Company's long-term debt is estimated based on
quoted market prices of similar issues having the same remaining maturities,
redemption terms and credit ratings. Based on these criteria, the fair market
value of long-term debt, including current portion, was as follows:
- ---------------------- ---------- ------------- -------------- -------------
2000 2000 1999 1999
Carrying Fair Carrying Fair
At September 30
(Thousands) Amount Value Amount Value
- ---------------------- ---------- ------------- -------------- -------------
Long-Term Debt $964,884 $928,066 $892,351 $867,056
- ---------------------- ---------- ------------- -------------- -------------
The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay.
Temporary cash investments, notes payable to banks and commercial paper are stated at amounts which approximate their fair value due to the short-term maturities of those financial instruments. Investments in life insurance are stated at their cash surrender values as discussed below. Investments in a mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.
Investments
Other assets includes cash surrender values of insurance contracts and
marketable equity securities. The cash surrender values of the insurance
contracts amounted to $49.4 million and $44.2 million at September 30, 2000 and
1999, respectively. The marketable equity securities amounted to $10.0 million
and $7.3 million at September 30, 2000 and 1999, respectively. The insurance
contracts and marketable equity securities are primarily informal funding
mechanisms for various benefit obligations the Company has to certain employees.
Derivative Financial Instruments
The Company uses a variety of derivative financial instruments to manage a
portion of the market risk associated with the fluctuations in the price of
natural gas and crude oil. These instruments can be categorized as price swap
agreements, no cost collars, options and futures contracts and are highly
correlated with the physical side of the natural gas and crude oil transactions
that are related to these instruments. The instruments are not held for trading
purposes. The fair value of these instruments at September 30, 2000 is a net
liability and is represented as the amount that the Company would have to pay to
terminate the instruments. However, the calculation of this liability to the
counterparties does not consider the physical side of the natural gas and crude
oil transactions that are related to the financial instruments.
Under the price swap agreements, the Company receives monthly payments from (or makes payments to) other parties based upon the difference between a fixed and a variable price as specified by the agreement. The variable price is either a crude oil price quoted on the New York Mercantile Exchange (NYMEX) or a quoted natural gas price in "Inside FERC." At September 30, 2000, the Company had natural gas price swap agreements covering a notional amount of 44.9 Bcf extending through 2003 at a weighted average fixed rate of $3.34 per Mcf. The Company also had crude oil price swap agreements covering a notional amount of 10,361,895 bbls extending through 2003 at a weighted average fixed rate of $21.75 per bbl. At September 30, 2000, the Company would have had to pay $106.2 million to terminate the price swap agreements.
Under the no cost collars, the Company receives monthly payments from (or makes payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). The variable price is either a crude oil price quoted on the NYMEX or a natural gas price quoted in "Inside FERC." At September 30, 2000, the Company had no cost collars on natural gas covering a notional amount of 6.6 Bcf extending through 2001 with a weighted average floor price of $3.83 per Mcf and a weighted average ceiling price of $5.75 per Mcf. The Company also had no cost collars on crude oil covering a notional amount of 4,725,000 bbls extending through 2004 with a weighted average floor price of $22.49 per bbl and a weighted average ceiling price of $28.44 per bbl. At September 30, 2000, the Company would have had to pay $5.8 million to terminate the no cost collars.
At September 30, 2000, the Company had purchased options outstanding on natural gas covering a notional amount of 31.1 Bcf extending through 2001 at a weighted average strike price of $4.76 per Mcf. The Company also had sold options outstanding on natural gas covering a notional amount of 37.9 Bcf extending through 2001 at a weighted average strike price of $4.76 per Bcf. The Company also had sold options outstanding on crude oil covering a notional amount of 368,000 bbls extending through 2001 at a weighted average strike price of $15.25 per bbl. At September 30, 2000, the Company would have had to pay $9.8 million to terminate all of these options.
At September 30, 2000, the Company had futures contracts covering 3.9 Bcf of gas on a net basis (net short position) extending through 2002 at a weighted average contract price of $4.20 per Mcf. The Company would have had to pay $5.5 million to terminate the futures contracts at September 30, 2000.
The Company may be exposed to credit risk on some of its derivative financial instruments. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on an ongoing basis monitors counterparty credit exposure.
The Company uses an interest rate swap to eliminate interest rate fluctuations on certain variable rate debt. Under the terms of the interest rate swap, which extends until 2002, the Company pays a fixed rate of 8.31% and receives a floating rate of six month Prague Interbank Offered Rate (PRIBOR). At September 30, 2000, the Company would have had to pay $1.4 million to terminate the interest rate swap.
Note G - Retirement Plan and Other Post-Retirement Benefits
The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Retirement Plan) that covers substantially all domestic employees of the Company. The Company provides health care and life insurance benefits for substantially all domestic retired employees under a post-retirement benefit plan (Post-Retirement Plan).
The Company's policy is to fund the Retirement Plan with at least an amount necessary to satisfy the minimum funding requirements of applicable laws and regulations and not more than the maximum amount deductible for federal income tax purposes. The Company has established Voluntary Employees' Beneficiary Association (VEBA) trusts for its Post-Retirement Plan. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations and are made to fund employees' post-retirement health care and life insurance benefits, as well as benefits as they are paid to current retirees. Retirement Plan and Post-Retirement Plan assets primarily consist of equity and fixed income investments or units in commingled funds or money market funds.
The Company is fully recovering its net periodic pension and post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorization. For financial reporting purposes, the difference between the amounts of pension cost and post-retirement benefit cost recoverable in rates and the amounts of such costs as determined by their actuary under applicable accounting principles is recorded as either a regulatory asset or liability, as appropriate. Pension and post-retirement benefit costs reflect the amount recovered from customers in rates during the year. Under the NYPSC's policies, the Company segregates the amount of such costs collected in rates, but not yet contributed to the Retirement and Post-Retirement Plans, into a regulatory liability account. This liability accrues interest at the NYPSC mandated interest rate and this interest cost is included in pension and post-retirement benefit costs. For purposes of disclosure, the liability also remains in the disclosed pension and post-retirement benefit liability amount because it has not yet been contributed.
Retirement Plan
Reconciliations of the Benefit Obligation, Retirement Plan Assets and Funded
Status, as well as the components of Net Periodic Benefit Cost and the Weighted
Average Assumptions are as follows:
- -------------------------------------------- ------------- ----------- ---------- Year Ended September 30 (Thousands) 2000 1999 1998 - -------------------------------------------- ------------- ----------- ---------- Change in Benefit Obligation Benefit Obligation at Beginning of Period $538,796 $532,250 $462,377 Service Cost 11,692 12,676 10,655 Interest Cost 37,954 36,299 35,485 Amendments - 1,691 - Actuarial (Gain) Loss (20,216) (13,598) 52,446 Benefits Paid (32,332) (30,522) (28,713) - -------------------------------------------- ------------- ----------- ---------- Benefit Obligation at End of Period $535,894 $538,796 $532,250 - -------------------------------------------- ------------- ----------- ---------- Change in Plan Assets Fair Value of Assets at Beginning of Period $537,958 $509,393 $473,205 Actual Return on Plan Assets 36,584 47,888 59,415 Employer Contribution 27,726 11,199 5,486 Benefits Paid (32,332) (30,522) (28,713) - -------------------------------------------- ------------- ----------- ---------- Fair Value of Assets at End of Period $569,936 $537,958 $509,393 - -------------------------------------------- ------------- ----------- ---------- Reconciliation of Funded Status Funded Status $34,042 $(838) $(22,857) Unrecognized Net Actuarial Gain (62,008) (45,853) (12,659) Unrecognized Transition Asset (11,148) (14,864) (18,580) Unrecognized Prior Service Cost 10,943 12,048 11,369 - -------------------------------------------- ------------- ----------- ---------- Accrued Benefit Cost $(28,171) $(49,507) $(42,727) - -------------------------------------------- ------------- ----------- ----------
- ----------------------------------------------- ------------- -------------- -------------
2000 1999 1998
- ----------------------------------------------- ------------- -------------- -------------
Weighted Average Assumptions as of September 30
Discount Rate 7.50% 7.25% 7.00%
Expected Return on Plan Assets 8.50% 8.50% 8.50%
Rate of Compensation Increase 5.00% 5.00% 5.00%
- ----------------------------------------------- ------------- -------------- -------------
Year Ended September 30 (Thousands)
Components of Net Periodic Benefit Cost
Service Cost $ 11,692 $ 12,676 $ 10,655
Interest Cost 37,954 36,299 35,485
Expected Return on Plan Assets (41,077) (38,158) (35,724)
Amortization of Prior Service Cost 1,106 1,012 1,065
Amortization of Transition Amount (3,716) (3,716) (3,716)
Recognition of Actuarial Loss 60 2,833 981
Early Retirement Window - 7,032 -
Net Amortization and Deferral for
Regulatory Purposes 206 2,721 4,829
- ----------------------------------------------- ------------- -------------- -------------
Net Periodic Benefit Cost $ 6,225 $ 20,699 $ 13,575
- ----------------------------------------------- ------------- -------------- -------------
The effect of the discount rate change in 2000 was to decrease the Benefit Obligation by $15.3 million as of the end of the period. The effect of the discount rate change in 1999 was to decrease the Benefit Obligation as of the end of the period by $15.9 million.
Other Post-Retirement Benefits
Reconciliations of the Benefit Obligation, Post-Retirement Plan Assets and
Funded Status, as well as the components of Net Periodic Benefit Cost and the
Weighted Average Assumptions are as follows:
- -------------------------------------------- ------------- -------------- ------------- Year Ended September 30 (Thousands) 2000 1999 1998 - -------------------------------------------- ------------- -------------- ------------- Change in Benefit Obligation Benefit Obligation at Beginning of Period $ 255,615 $ 256,983 $218,370 Service Cost 4,156 4,493 4,022 Interest Cost 18,142 17,635 17,122 Plan Participants' Contributions 414 673 867 Actuarial (Gain) Loss (355) (13,542) 27,014 Benefits Paid (11,512) (10,627) (10,412) - -------------------------------------------- ------------- -------------- ------------- Benefit Obligation at End of Period $ 266,460 $ 255,615 $256,983 - -------------------------------------------- ------------- -------------- ------------- Change in Plan Assets Fair Value of Assets at Beginning of Period $ 149,884 $ 122,870 $ 98,639 Actual Return on Plan Assets 18,527 17,345 14,602 Employer Contribution 19,044 19,623 19,174 Plan Participants' Contributions 414 673 867 Benefits Paid (11,512) (10,627) (10,412) - -------------------------------------------- ------------- -------------- ------------- Fair Value of Assets at End of Period $ 176,357 $ 149,884 $122,870 - -------------------------------------------- ------------- -------------- ------------- Reconciliation of Funded Status Funded Status $(90,103) $(105,731) $(134,113) Unrecognized Net Actuarial (Gain) Loss (8,676) (2,396) 19,660 Unrecognized Transition Obligation 92,653 99,780 106,907 - -------------------------------------------- ------------- -------------- ------------- Accrued Benefit Cost $ (6,126) $ (8,347) $ (7,546) - -------------------------------------------- ------------- -------------- -------------
- ----------------------------------------------- ------------- -------------- -------------
2000 1999 1998
- ----------------------------------------------- ------------- -------------- -------------
Weighted Average Assumptions as of September 30
Discount Rate 7.50% 7.25% 7.00%
Expected Return on Plan Assets 8.50% 8.50% 8.50%
Rate of Compensation Increase 5.00% 5.00% 5.00%
- ----------------------------------------------- ------------- -------------- -------------
Year Ended September 30 (Thousands)
Components of Net Periodic Benefit Cost
Service Cost $4,156 $4,493 $4,022
Interest Cost 18,142 17,635 17,122
Expected Return on Plan Assets (12,574) (10,134) (8,099)
Amortization of Transition Obligation 7,127 7,127 7,127
Amortization of (Gain) Loss (24) 1,304 683
Net Amortization and Deferral for
Regulatory Purposes 7,269 1,774 915
- ----------------------------------------------- ------------- -------------- -------------
Net Periodic Benefit Cost $ 24,096 $ 22,199 $ 21,770
- ----------------------------------------------- ------------- -------------- -------------
The effect of the discount rate change in 2000 was to decrease the Benefit Obligation by $8.9 million. The effect of the discount rate change in 1999 was to decrease the Benefit Obligation by $9.1 million.
The health care trend assumptions were changed in 2000 to better reflect anticipated future experience. The effect of the changed medical care, prescription drug and Medicare Part B assumptions mentioned below, was to increase the Accumulated Postretirement Benefit Obligation by $13.7 million.
The annual rate of increase in the per capita cost of covered medical care benefits was assumed to be 9.0% for 1998, 8.0% for 1999, 10.0% for 2000 and gradually decline to 5.5% by the year 2005 and remain level thereafter. The annual rate of increase for medical care benefits provided by healthcare maintenance organizations was assumed to be 7.5% in 1998, 7.0% in 1999, 10.0% in 2000 and gradually decline to 5.5% by the year 2005 and remain level thereafter. The annual rate of increase in the per capita cost of covered prescription drug benefits was assumed to be 9.0% for 1998, 8.0% for 1999, 15.0% for 2000 and gradually decline to 5.5% by the year 2005 and remain level thereafter. The annual rate of increase in the per capita Medicare Part B Reimbursement was assumed to be 9.0% for 1998, 8.0% for 1999, 10.0% for 2000 and gradually decline to 5.5% by the year 2005 and remain level thereafter.
The health care cost trend rate assumptions used to calculate the per capita cost of covered medical care benefits have a significant effect on the amounts reported. If the health care cost trend rates were increased by 1% in each year, the Benefit Obligation as of October 1, 2000 would be increased by $36.8 million. This 1% change would also have increased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 2000 by $3.9 million. If the health care cost trend rates were decreased by 1% in each year, the Benefit Obligation as of October 1, 2000 would be decreased by $29.2 million. This 1% change would also have decreased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 2000 by $3.3 million.
Note H - Commitments and Contingencies
Environmental Matters
The Company is subject to various federal, state and local laws and regulations
relating to the protection of the environment. The Company has established
procedures for the ongoing evaluation of its operations, to identify potential
environmental exposures and to comply with regulatory policies and procedures.
It is the Company's policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. The Company has estimated its remaining clean-up costs related to the sites described below in (i) and (ii) will be in the range of $6.4 million to $7.6 million. The minimum estimated liability of $6.4 million has been recorded on the Consolidated Balance Sheet at September 30, 2000. Other than discussed below, the Company is currently not aware of any material exposure to environmental liabilities. However, adverse changes in environmental regulations, new information or other factors could impact the Company.
(i) Former Manufactured Gas Plant Sites
The Company has incurred or is incurring clean-up costs at four former manufactured gas plant sites in New York and Pennsylvania. Remediation is substantially complete at a site where the Company has been designated by the New York Department of Environmental Conservation (DEC) as a potentially responsible party (PRP) and is also engaged in litigation with the DEC and the party who bought that site from the Company's predecessor. At a second site, remediation is in progress and is expected to be completed in 2001. At a third site the Company is negotiating with the DEC for clean-up under a voluntary program. The fourth is a site allegedly containing, among other things, manufactured gas plant waste and is in the investigation stage.
(ii) Third Party Waste Disposal Sites
The Company has been identified by the DEC or the United States Environmental Protection Agency as one of a number of companies considered to be PRPs with respect to two waste disposal sites in New York which were operated by unrelated third parties. The PRPs are alleged to have contributed to the materials that may have been collected at such waste disposal sites by the site operators. The ultimate cost to the Company with respect to the remediation of these sites will depend on such factors as the remediation plan selected, the extent of site contamination, the number of additional PRPs at each site and the portion of responsibility, if any, attributed to the Company. The remediation has been completed at one site, with final payments pending. At a second waste disposal site, the remedial design has been agreed to and the parties are in settlement discussions.
(iii) Other
The Company received, in 1998 and again in October 1999, notice that the DEC believes the Company is responsible for contamination discovered at an additional former manufactured gas plant site in New York. The Company, however, has not been named as a PRP. The Company responded to these notices that other companies operated that site before its predecessor did, that liability could be imposed upon it only if hazardous substances were disposed of at the site during a period when the site was operated by its predecessor, and that it was unaware of any such disposal. The Company has not incurred any clean-up costs at this site nor has it been able to reasonably estimate the probability or extent of potential liability.
Other
The Company, in its Utility segment, has entered into contractual commitments in
the ordinary course of business including commitments to purchase capacity on
nonaffiliated pipelines to meet customer gas supply needs. The majority of these
contracts (representing 87% of contracted demand capacity) expire within the
next five years. Costs incurred under these contracts are purchased gas costs,
subject to state commission review, and are being recovered in customer rates.
Management believes, to the extent any stranded pipeline costs are generated by
the unbundling of services in the Utility segment's service territory, such
costs will be recoverable from customers.
The Company is involved in litigation arising in the normal course of its business. In addition to the regulatory matters discussed in Note B - Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business that involve rate base, cost of service and purchased gas cost issues. While the resolution of such litigation or other regulatory matters could have a material effect on earnings and cash flows in the year of resolution, none of this litigation, and none of these other regulatory matters, are expected to have a material adverse effect on the financial condition of the Company at this time.
Note I - Business Segment Information
The Company has six reportable segments: Utility, Pipeline and Storage, Exploration and Production, International, Energy Marketing and Timber. The breakdown of the Company's reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.
The Utility segment operations are regulated by the NYPSC and the Pennsylvania Public Utility Commission (PaPUC) and are carried out by Distribution Corporation. Distribution Corporation sells natural gas to retail customers and provides natural gas transportation services in western New York and northwestern Pennsylvania.
The Pipeline and Storage segment operations are regulated by the Federal Energy Regulatory Commission (FERC) and are carried out by Supply Corporation and SIP. Supply Corporation transports and stores natural gas for utilities (including Distribution Corporation), natural gas marketers (including NFR) and pipeline companies in the northeastern United States markets. SIP, although not regulated itself by the FERC, holds a one-third partnership interest in the Independence Pipeline Company, whose rates, services and other matters are or will be regulated by the FERC.
The Exploration and Production segment, through Seneca, is engaged in exploration for, and development and purchase of, natural gas and oil reserves in the Gulf Coast region of Texas and Louisiana, in California, in Wyoming, in the Appalachian region of the United States and in the provinces of Manitoba, Alberta and Saskatchewan in Canada. Seneca's production is, for the most part, sold to purchasers located in the vicinity of its wells.
The International segment's operations are carried out by Horizon. Horizon engages in foreign energy projects through the investment of its indirect subsidiaries as the sole or partial owner of various business entities. Horizon's current emphasis is the Czech Republic where, through its subsidiaries, it owns majority interests in companies having district heating and power generation plants in the northern Bohemia region of the Czech Republic.
The Energy Marketing segment is comprised of NFR's operations. NFR is engaged in the retail marketing of natural gas, the marketing of electricity and the performance of energy management services for industrial, commercial, public authority and residential end-users located in the northeastern United States.
The Timber segment's operations are carried out by the Northeast division of Seneca and by Highland. This segment has timber holdings in the northeastern United States and several sawmills and kilns in Pennsylvania.
The data presented in the tables below reflect the reportable segments and reconciliations to consolidated amounts. The accounting policies of the segments are the same as those described in Note A - Summary of Significant Accounting Policies. Sales of products or services between segments are billed at regulated rates or at market rates, as applicable. Expenditures for long-lived assets include additions to property, plant and equipment and equity investments in corporations (stock acquisitions) or partnerships, net of any cash acquired. The Company evaluates segment performance based on income before discontinued operations, extraordinary items and cumulative effects of changes in accounting (when applicable). When these items are not applicable, the Company evaluates performance based on net income.
Year Ended September 30, 2000 (Thousands)
- -------------------------------------------------------------------------------------------------------
Pipeline Exploration
and and Energy
Utility Storage Production International Marketing Timber
- -------------------------------------------------------------------------------------------------------
Revenue from
External
Customers $ 827,231 $ 81,434 $ 237,845 $ 104,736 $ 133,929 $ 39,172
Intersegment
Revenues 19,228 88,225 225 - - -
Interest Expense 31,655 13,311 42,034 12,353 774 4,750
Depreciation,
Depletion and
Amortization 35,842 23,379 69,583 11,110 209 1,948
Income Tax
Expense 38,362 22,172 19,413 (1,783) (4,372) 3,816
Segment Profit
(Loss): Net
Income 57,662 31,614 34,877 3,282 (7,790) 6,133
Expenditures for
Additions to
Long-Lived Assets 55,799 35,806(1) 280,049 9,767 89 13,542
At September 30, 2000 (Thousands)
- -------------------------------------------------------------------------------------------------------
Segment Assets $1,219,496 $ 552,059 $1,088,066 $ 202,622 $ 47,121 $ 107,402
- -------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Total Corporate and
Reportable Intersegment Total
Segments All Other Eliminations Consolidated
- --------------------------------------------------------------------------------
Revenue from
External
Customers $1,424,347 $ 930 $ - $1,425,277
Intersegment
Revenues 107,678 4,415 (112,093) -
Interest Expense 104,877 262 (5,054) 100,085
Depreciation,
Depletion and
Amortization 142,071 97 2 142,170
Income Tax
Expense 77,608 (205) (335) 77,068
Segment Profit
(Loss): Net
Income 125,778 (371) 1,800 127,207
Expenditures for
Additions to
Long-Lived Assets 395,052 3,725 - 398,777
At September 30, 2000 (Thousands)
- --------------------------------------------------------------------------------
Segment Assets $3,216,766 $ 21,930 $ (1,808) $3,236,888
- --------------------------------------------------------------------------------
|
(1)Amount includes $1.2 million in a stock-for-asset swap. |
Year Ended September 30, 1999 (Thousands)
- --------------------------------------------------------------------------------------------------
Pipeline Exploration
and and Energy
Utility Storage Production International Marketing Timber
- --------------------------------------------------------------------------------------------------
Revenue from
External
Customers $ 801,053 $ 82,994 $ 140,212 $ 107,045 $ 99,088 $ 31,117
Intersegment
Revenues 6,302 85,789 6,782 - - -
Interest Expense 29,659 13,147 34,409 11,451 234 2,208
Depreciation,
Depletion and
Amortization 34,215 22,690 55,750 10,473 165 1,476
Income Tax
Expense 34,741 22,439 2,992 15 1,138 2,788
Segment Profit
(Loss): Net
Income 56,875 39,765 7,127 2,276 2,054 4,769
Expenditures for
Additions to
Long-Lived Assets 46,974 34,873 97,586 33,412 302 52,314
At September 30, 1999 (Thousands)
- --------------------------------------------------------------------------------------------------
Segment Assets $1,178,185 $ 542,962 $ 727,557 $ 255,042 $ 18,676 $ 98,830
- --------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Total Corporate and
Reportable Intersegment Total
Segments All Other Eliminations Consolidated
- --------------------------------------------------------------------------------
Revenue from
External
Customers $1,261,509 $ 1,765 $ - $1,263,274
Intersegment
Revenues 98,873 - (98,873) -
Interest Expense 91,108 100 (3,510) 87,698
Depreciation,
Depletion and
Amortization 124,769 7 2 124,778
Income Tax
Expense 64,113 55 661 64,829
Segment Profit
(Loss): Net
Income 112,866 (162) 2,333 115,037
Expenditures for
Additions to
Long-Lived Assets 265,461 66 - 265,527
At September 30, 1999 (Thousands)
- --------------------------------------------------------------------------------
Segment Assets $2,821,252 $ 7,351 $ 13,983 $2,842,586
- --------------------------------------------------------------------------------
Year Ended September 30, 1998 (Thousands)
- ---------------------------------------------------------------------------------------------------
Pipeline Exploration
and and Energy
Utility Storage Production International Marketing Timber
- ---------------------------------------------------------------------------------------------------
Revenue from
External
Customers $ 867,802 $ 84,218 $ 113,194 $ 76,259 $ 87,187 $ 17,805
Intersegment
Revenues 3,378 86,765 11,078 - - -
Interest Expense 44,639 15,232 21,454 7,188 31 1,580
Depreciation,
Depletion and
Amortization 33,459 21,816 50,937 7,309 91 3,527
Income Tax
Expense (Benefit) 30,076 29,644 (39,478) 2,158 471 1,445
Significant
Noncash Item:
Impairment of Oil
and Gas Producing
Properties - - 128,996 - - -
Segment Profit
(Loss): Income
Before Cumulative
Effect of Change
in Accounting 51,788 39,852 (64,110) 1,279 787 1,904
Expenditures for
Additions to
Long-Lived Assets 50,680 29,145 323,627 96,987 320 6,778
At September 30, 1998 (Thousands)
- ---------------------------------------------------------------------------------------------------
Segment Assets $1,171,645 $ 526,738 $ 673,706 $ 242,339 $ 16,944 $ 45,507
- ---------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Total Corporate and
Reportable Intersegment Total
Segments All Other Eliminations Consolidated
- --------------------------------------------------------------------------------
Revenue from
External
Customers $1,246,465 $ 1,535 $ - $1,248,000
Intersegment
Revenues 101,221 - (101,221) -
Interest Expense 90,124 33 (4,873) 85,284
Depreciation,
Depletion and
Amortization 117,139 97 2 117,238
Income Tax
Expense (Benefit) 24,316 119 (411) 24,024
Significant
Noncash Item:
Impairment of Oil
and Gas Producing
Properties 128,996 - - 128,996
Segment Profit
(Loss): Income
Before Cumulative
Effect of Change
in Accounting 31,500 143 661 32,304
Expenditures for
Additions to
Long-Lived Assets 507,537 - - 507,537
At September 30, 1998 (Thousands)
- --------------------------------------------------------------------------------
Segment Assets $2,676,879 $ 5,216 $ 2,364 $2,684,459
- --------------------------------------------------------------------------------
-------------------------------------- --------------- ------------- -------------
Geographic Information 2000 1999 1998
-------------------------------------- --------------- ------------- -------------
For the Year Ended September 30 (Thousands)
Revenues from External Customers(1):
United States $1,292,190 $1,156,229 $1,171,741
Czech Republic 104,736 107,045 76,259
Canada 28,351 - -
-------------------------------------- --------------- ------------- -------------
$1,425,277 $1,263,274 $1,248,000
At September 30 (Thousands)
-------------------------------------- --------------- ------------- -------------
Long-Lived Assets:
United States $2,480,406 $2,369,840 $2,258,817
Czech Republic 183,274 215,457 215,125
Canada 248,937 - -
-------------------------------------- --------------- ------------- -------------
$2,912,617 $2,585,297 $2,473,942
-------------------------------------- --------------- ------------- -------------
(1) Revenue is based upon the country in which the sale originates.
Note J - Stock Acquisitions
In June 2000, the Company acquired the outstanding shares of Tri Link Resources, Ltd. (Tri Link) a Calgary, Alberta based oil and gas exploration and production company. The cost of acquiring the outstanding shares of Tri Link was approximately $123.8 million. Upon completing this acquisition, Tri Link was amalgamated under the name of National Fuel Exploration Corp. (NFE). NFE's results of operations were incorporated into the Company's consolidated financial statements for the period subsequent to the completion of the acquisition of Tri Link on June 15, 2000.
In May 1998, the Company acquired the outstanding shares of HarCor Energy, Inc. (HarCor) for approximately $32.6 million ($29.8 million, net of cash acquired). HarCor's results of operations were incorporated into the Company's consolidated financial statements for the period subsequent to the completion of the tender offer in May 1998.
During 1998 and 1999, the Company purchased majority ownership interests in Severoeeske teplarny, a.s. (SCT), Prvni severozapadni teplarenska, a.s. (PSZT) and Jablonecka teplarenska a realitni, a.s. (JTR) (a majority owned subsidiary of SCT). The cost of acquiring these shares in 1998 was $89.4 million ($82.2 million, net of cash acquired). In 1999, an additional $5.8 million was invested ($5.7 million, net of cash acquired). In 2000, SCT and PSZT merged and the merged company was renamed United Energy, a.s.
All of the acquisitions disclosed above were accounted for in accordance with the purchase method. The goodwill resulting from these acquisitions is being amortized over a twenty-year period and is recorded in Other Assets. This goodwill amounted to $8.7 million and $9.5 million at September 30, 2000 and 1999, respectively.
Details of the stock acquisitions made by the Company during 2000, 1999 and 1998 are as follows:
- ------------------------------------------ ----------- ------------ ------------
Year Ended September 30 (Millions)
2000 1999 1998
- ------------------------------------------ ----------- ------------ ------------
Assets acquired $259.9 $13.5 $313.5
Liabilities assumed (136.1) (7.3) (172.6)
Existing investment at acquisition - (0.4) (18.9)
Cash acquired at acquisition - (0.1) (10.0)
- ------------------------------------------ ----------- ------------ ------------
Cash paid, net of cash acquired $123.8 $5.7 $112.0
- ------------------------------------------ ----------- ------------ ------------
Note K - Quarterly Financial Data (unaudited)
In the opinion of management, the following quarterly information includes all adjustments necessary for a fair statement of the results of operations for such periods. Per common share amounts are calculated using the weighted average number of shares outstanding during each quarter. The total of all quarters may differ from the per common share amounts shown on the Consolidated Statement of Income. Those per common share amounts are based on the weighted average number of shares outstanding for the entire fiscal year. Because of the seasonal nature of the Company's heating business, there are substantial variations in operations reported on a quarterly basis.
- -------------- --------------- -------------- ---------------- -------------- -------------
Net
Income
Available
for Earnings Per
Quarter Operating Operating Common Common Share
----------------------------
Ended Revenues Income Stock Basic Diluted
- -------------- --------------- -------------- ---------------- -------------- -------------
2000 (Thousands, except per common share amounts)
- -------------- ------------------------------------------------ ---------------------------
12/31/1999 $377,031 $70,237 $ 44,868 $ 1.15 $1.14
3/31/2000 $517,767 $91,074 $ 71,051 $ 1.82 $1.81
6/30/2000(1) $281,201 $30,043 $ 9,070(2) $ 0.23 $0.23
9/30/2000 $249,278 $26,914 $ 2,218(3) $ 0.06 $0.06
- -------------- ---------------------------------------------------- -----------------------
1999 (Thousands, except per common share amounts)
- -------------- ---------------------------------------------------- -----------------------
12/31/1998 $340,422 $56,835 $ 37,619(4) $ 0.98 $0.97
3/31/1999 $483,404 $83,475 $ 61,145 $ 1.58 $1.57
6/30/1999 $248,658 $31,319 $ 11,840(5) $ 0.31 $0.30
9/30/1999 $190,790 $20,379 $ 4,433(6) $ 0.11 $0.11
- -------------- --------------- -------------- ---------------- -------------- -------------
|
(1) As revised. |
|
(3) Includes expense of $6.6 million related to SAR's, expense of $3.7 million for adjustments related to the New York rate settlement, expense of $1.6 million related to the recording of a loss contingency on fixed price sales contracts and income of $3.9 million related to mark-to-market and other revenue adjustments related to derivative financial instruments. |
|
(4) Includes income of $3.9 million related to IRS audit settlement and expense of $3.5 million related to an early retirement offer. |
|
(5) Includes expense of $3.8 million related to SAR's, expense of $1.1 million related to an early retirement offer and income of $1.0 million for lost and unaccounted for (LAUF) gas adjustment related to 1998. |
|
(6) Includes income of $1.6 million for LAUF gas adjustment related to 1999 and income of $1.6 million related to a gain on stock received from the demutualization of an insurance company. |
Note L - Market for Common Stock and Related Shareholder Matters (unaudited)
At September 30, 2000, there were 21,164 holders of National Fuel Gas Company common stock. The common stock is listed and traded on the New York Stock Exchange. Information related to restrictions on the payment of dividends can be found in Note D - Capitalization. The quarterly price ranges and quarterly dividends declared for the fiscal years ended September 30, 2000 and 1999, are shown below:
- --------------------------------- ------------------------------ -------------
Price Range Dividends
------------------------------
Quarter Ended High Low Declared
- --------------------------------- --------------- -------------- -------------
2000
- --------------------------------- --------------- -------------- -------------
12/31/1999 $52.94 $46.00 $.465
3/31/2000 $46.75 $39.38 $.465
6/30/2000 $51.94 $43.13 $.480
9/30/2000 $58.81 $48.13 $.480
- --------------------------------- --------------- -------------- -------------
1999
- --------------------------------- --------------- -------------- -------------
12/31/1998 $49.63 $44.88 $.450
3/31/1999 $46.50 $39.25 $.450
6/30/1999 $50.00 $37.50 $.465
9/30/1999 $49.75 $44.63 $.465
- --------------------------------- --------------- -------------- -------------
Note M - Supplementary Information for Oil and Gas Producing Activities
The following supplementary information is presented in accordance with SFAS 69, "Disclosures about Oil and Gas Producing Activities," and related SEC accounting rules. All monetary amounts are expressed in U.S. dollars.
Capitalized Costs Relating to Oil and Gas Producing Activities
- ---------------------------------------------- -------------- -------------
At September 30 (Thousands)
2000 1999
- ---------------------------------------------- -------------- -------------
Proved Properties $1,218,871 $880,470
Unproved Properties 152,360 92,097
- ---------------------------------------------- -------------- -------------
1,371,231 972,567
Less - Accumulated Depreciation, Depletion
and Amortization 390,267 315,675
- ---------------------------------------------- -------------- -------------
$980,964 $656,892
- ---------------------------------------------- -------------- -------------
Costs related to unproved properties are excluded from amortization as they represent unevaluated properties that require additional drilling to determine the existence of oil and gas reserves. Following is a summary of such costs excluded from amortization at September 30, 2000:
- ----------------------- -------------- --------------------------------------------------
Total as of Year Costs Incurred
--------------------------------------------------
(Thousands) September 30, 2000 2000 1999 1998 Prior
- ----------------------- -------------- ------------ ------------ ------------ -----------
Acquisition Costs $152,360 $106,665 $5,608 $31,640 $8,447
- ----------------------- -------------- ------------ ------------ ------------ -----------
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
- ------------------------------------- ------------- -------------- -------------
Year Ended September 30 (Thousands) 2000 1999 1998
- ------------------------------------- ------------- -------------- -------------
United States
- ------------------------------------- ------------- -------------- -------------
Property Acquisition Costs:
Proved $ 2,848 $ 2,798 $189,201
Unproved 19,066 11,530 88,369
Exploration Costs 50,163 52,141 74,421
Development Costs 72,039 30,985 23,887
- ------------------------------------- ------------- -------------- -------------
144,116 97,454 375,878
- ------------------------------------- ------------- -------------- -------------
Canada
- ------------------------------------- ------------- -------------- -------------
Property Acquisition Costs:
Proved 157,835 - -
Unproved 76,504 - -
Exploration Costs 573 - -
Development Costs 11,013 - -
- ------------------------------------- ------------- -------------- -------------
245,925 - -
- ------------------------------------- ------------- -------------- -------------
Total
- ------------------------------------- ------------- -------------- -------------
Property Acquisition Costs: (1)
Proved 160,683 2,798 189,201
Unproved 95,570 11,530 88,369
Exploration Costs 50,736 52,141 74,421
Development Costs 83,052 30,985 23,887
- ------------------------------------- ------------- -------------- -------------
$390,041 $97,454 $375,878
- ------------------------------------- ------------- -------------- -------------
|
(1) Total proved and unproved property acquisition costs for 2000 of $256.3 million include $236.5 million related to the Tri Link acquisition (now known as NFE). Total proved and unproved property acquisition costs for 1998 of $277.6 million include amounts related to the HarCor, Bakersfield Energy and Whittier Trust properties acquired in 1998 of $87.0 million, $25.3 million and $141.1 million, respectively. |
Results of Operations for Producing Activities
- ------------------------------------------------------ ------------- -------------- -------------
Year Ended September 30 (Thousands, Except Per Mcfe 2000 1999 1998
Amounts)
- ------------------------------------------------------ ------------- -------------- -------------
United States
- ------------------------------------------------------ ------------- -------------- -------------
Operating Revenues:
Natural Gas (includes revenues from sales to
affiliates
of $237, $6,365 and $11,065, respectively) $137,336 $ 81,734 $ 89,284
Oil, Condensate and Other Liquids 107,645 51,592 31,770
- ------------------------------------------------------ ------------- -------------- -------------
Total Operating Revenues(1) 244,981 133,326 121,054
Production/Lifting Costs 33,979 28,119 23,622
Depreciation, Depletion and Amortization
($0.97, $0.89 and $0.96 per Mcfe of production) 64,624 54,439 50,221
Impairment of Oil and Gas Producing Properties(2) - - 128,996
Income Tax Expense (Benefit) 52,656 16,255 (28,949)
- ------------------------------------------------------ ------------- -------------- -------------
Results of Operations for Producing Activities
(excluding corporate overheads and interest 93,722 34,513 (52,836)
charges)
- ------------------------------------------------------ ------------- -------------- -------------
Canada
- ------------------------------------------------------ ------------- -------------- -------------
Operating Revenues:
Natural Gas 485 - -
Oil, Condensate and Other Liquids 26,320 - -
- ------------------------------------------------------ ------------- -------------- -------------
Total Operating Revenues(1) 26,805 - -
Production/Lifting Costs 7,858 - -
Depreciation, Depletion and Amortization
($0.77 , $ - and $ - per Mcfe of production) 4,321 - -
Income Tax Expense 6,121 - -
- ------------------------------------------------------ ------------- -------------- -------------
Results of Operations for Producing Activities
(excluding corporate overheads and interest 8,505 - -
charges)
- ------------------------------------------------------ ------------- -------------- -------------
Total
- ------------------------------------------------------ ------------- -------------- -------------
Operating Revenues:
Natural Gas (includes revenues from sales to
affiliates
of $237, $6,365 and $11,065, respectively) 137,821 81,734 89,284
Oil, Condensate and Other Liquids 133,965 51,592 31,770
- ------------------------------------------------------ ------------- -------------- -------------
Total Operating Revenues(1) 271,786 133,326 121,054
Production/Lifting Costs 41,837 28,119 23,622
Depreciation, Depletion and Amortization
($0.95, $0.89 and $0.96 per Mcfe of production) 68,945 54,439 50,221
Impairment of Oil and Gas Producing Properties(2) - - 128,996
Income Tax Expense (Benefit) 58,777 16,255 (28,949)
- ------------------------------------------------------ ------------- -------------- -------------
Results of Operations for Producing Activities
(excluding corporate overheads and interest $102,227 $ 34,513 $(52,836)
charges)
- ------------------------------------------------------ ------------- -------------- -------------
|
(1) Exclusive of hedging gains and losses. See further discussion in Note F - Financial Instruments. |
|
(2) See discussion of impairment in Note A - Summary of Significant Accounting Policies. |
Reserve Quantity Information (unaudited)
The Company's proved oil and gas reserves are located in the United States and
Canada. The estimated quantities of proved reserves disclosed in the table below
are based upon estimates by qualified Company geologists and engineers and are
audited by independent petroleum engineers. Such estimates are inherently
imprecise and may be subject to substantial revisions 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.
- ------------------------------- ---------------------------------- ----------------------------------
Gas MMcf Oil Mbbl
---------------------------------- ----------------------------------
U.S. Canada Total U.S. Canada Total
- ------------------------------- ---------- ----------- ----------- ---------- ----------- -----------
Proved Developed and
Undeveloped Reserves:
September 30, 1997 232,449 - 232,449 17,981 - 17,981
Extensions and Discoveries 40,293 - 40,293 640 - 640
Revisions of
Previous Estimates (18,623) - (18,623) (4,191) - (4,191)
Production (36,474) - (36,474) (2,614) - (2,614)
Sales of Minerals in Place - - - - - -
Purchases of Minerals
in Place and Other 107,420 - 107,420 54,775 - 54,775
- ------------------------------- ---------- ----------- ----------- ---------- ----------- -----------
September 30, 1998 325,065 - 325,065 66,591 - 66,591
Extensions and Discoveries 46,423 - 46,423 3,716 - 3,716
Revisions of
Previous Estimates (13,091) - (13,091) 9,808 - 9,808
Production (37,166) - (37,166) (4,016) - (4,016)
Sales of Minerals in Place (439) - (439) (280) - (280)
Purchases of Minerals
in Place and Other - - - - - -
- ------------------------------- ---------- ----------- ----------- ---------- ----------- -----------
September 30, 1999 320,792 - 320,792 75,819 - 75,819
Extensions and Discoveries 34,641 - 34,641 2,167 1,765 3,932
Revisions of
Previous Estimates (8,001) - (8,001) 4,000 - 4,000
Production (41,478) (192) 41,670) (4,248) (899) (5,147)
Sales of Minerals in Place (7,444) - (7,444) (227) - (227)
Purchases of Minerals
in Place and Other - 3,349 3,349 - 41,320 41,320
- ------------------------------- ---------- ----------- ----------- ---------- ----------- -----------
September 30, 2000 298,510 3,157 301,667 77,511 42,186 119,697
- ------------------------------- ---------- ----------- ----------- ---------- ----------- -----------
Proved Developed Reserves:
September 30, 1997 194,454 - 194,454 11,354 - 11,354
September 30, 1998 230,508 - 230,508 48,081 - 48,081
September 30, 1999 222,929 - 222,929 57,333 - 57,333
September 30, 2000 227,250 3,157 230,407 66,074 35,130 101,204
- ------------------------------- ---------- ----------- ----------- ---------- ----------- -----------
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves (unaudited)
The Company cautions that the following
presentation of the standardized measure of discounted future net cash flows is
intended to be neither a measure of the fair market value of the Company's oil
and gas properties, nor an estimate of the present value of actual future cash
flows to be obtained as a result of their development and production. It is
based upon subjective estimates of proved reserves only and attributes no value
to categories of reserves other than proved reserves, such as probable or
possible reserves, or to unproved acreage. Furthermore, it is based on year-end
prices and costs adjusted only for existing contractual changes, and it assumes
an arbitrary discount rate of 10%. Thus, it gives no effect to future price and
cost changes certain to occur under the widely fluctuating political and
economic conditions of today's world.
The standardized measure is intended instead to provide a somewhat better means for comparing the value of the Company's proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities.
- ------------------------------------------- ------------- -------------- -------------
Year Ended September 30 (Thousands)
2000 1999 1998
United States
- ------------------------------------------- ------------- -------------- -------------
Future Cash Inflows $3,886,499 $2,402,308 $1,547,216
Less:
Future Production Costs 600,243 560,459 413,753
Future Development Costs 179,565 185,617 160,884
Future Income Tax Expense at
Applicable Statutory Rate 1,006,366 477,205 245,120
- ------------------------------------------- ------------- -------------- -------------
Future Net Cash Flows 2,100,325 1,179,027 727,459
Less:
10% Annual Discount for Estimated
Timing of Cash Flows 859,950 471,768 260,688
- ------------------------------------------- ------------- -------------- -------------
Standardized Measure of Discounted Future
Net Cash Flows 1,240,375 707,259 466,771
- ------------------------------------------- ------------- -------------- -------------
Canada
- ------------------------------------------- ------------- -------------- -------------
Future Cash Inflows 1,083,598 - -
Less:
Future Production Costs 277,067 - -
Future Development Costs 21,399 - -
Future Income Tax Expense at
Applicable Statutory Rate 286,148 - -
- ------------------------------------------- ------------- -------------- -------------
Future Net Cash Flows 498,984 - -
Less:
10% Annual Discount for Estimated
Timing of Cash Flows 221,227 - -
- ------------------------------------------- ------------- -------------- -------------
Standardized Measure of Discounted Future
Net Cash Flows 277,757 - -
- ------------------------------------------- ------------- -------------- -------------
Total
- ------------------------------------------- ------------- -------------- -------------
Future Cash Inflows 4,970,097 2,402,308 1,547,216
Less:
Future Production Costs 877,310 560,459 413,753
Future Development Costs 200,964 185,617 160,884
Future Income Tax Expense at
Applicable Statutory Rate 1,292,514 477,205 245,120
- ------------------------------------------- ------------- -------------- -------------
Future Net Cash Flows 2,599,309 1,179,027 727,459
Less:
10% Annual Discount for Estimated
Timing of Cash Flows 1,081,177 471,768 260,688
- ------------------------------------------- ------------- -------------- -------------
Standardized Measure of Discounted Future
Net Cash Flows $1,518,132 $707,259 $466,771
- ------------------------------------------- ------------- -------------- -------------
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
- ------------------------------------------------------ ------------- -------------- -------------
Year Ended September 30 (Thousands) 2000 1999 1998
- ------------------------------------------------------ ------------- -------------- -------------
United States
- ------------------------------------------------------ ------------- -------------- -------------
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year $707,259 $466,771 $383,200
Sales, Net of Production Costs (211,002) (53,615) (97,432)
Net Changes in Prices, Net of Production Costs 795,408 317,356 (180,853)
Purchases of Minerals in Place - - 364,102
Sales of Minerals in Place (11,914) (2,706) -
Extensions and Discoveries 186,818 122,894 36,844
Changes in Estimated Future Development Costs (82,270) (97,082) (104,181)
Previously Estimated Development Costs Incurred 88,322 72,349 28,514
Net Change in Income Taxes at
Applicable Statutory Rate (292,371) (232,085) 57,190
Revisions of Previous Quantity Estimates 20,736 40,964 (75,136)
Accretion of Discount and Other 39,389 72,413 54,523
- ------------------------------------------------------ ------------- -------------- -------------
Standardized Measure of Discounted
Future Net Cash Flows at End of Year 1,240,375 707,259 466,771
- ------------------------------------------------------ ------------- -------------- -------------
Canada
- ------------------------------------------------------ ------------- -------------- -------------
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year - - -
Sales, Net of Production Costs (18,948) - -
Net Changes in Prices, Net of Production Costs - - -
Purchases of Minerals in Place 424,072 - -
Sales of Minerals in Place - - -
Extensions and Discoveries 2,979 - -
Changes in Estimated Future Development Costs - - -
Previously Estimated Development Costs Incurred - - -
Net Change in Income Taxes at
Applicable Statutory Rate (150,057) - -
Revisions of Previous Quantity Estimates - - -
Accretion of Discount and Other 19,711 - -
- ------------------------------------------------------ ------------- -------------- -------------
Standardized Measure of Discounted
Future Net Cash Flows at End of Year 277,757 - -
- ------------------------------------------------------ ------------- -------------- -------------
Total
- ------------------------------------------------------ ------------- -------------- -------------
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year 707,259 466,771 383,200
Sales, Net of Production Costs (229,950) (53,615) (97,432)
Net Changes in Prices, Net of Production Costs 795,408 317,356 (180,853)
Purchases of Minerals in Place 424,072 - 364,102
Sales of Minerals in Place (11,914) (2,706) -
Extensions and Discoveries 189,797 122,894 36,844
Changes in Estimated Future Development Costs (82,270) (97,082) (104,181)
Previously Estimated Development Costs Incurred 88,322 72,349 28,514
Net Change in Income Taxes at
Applicable Statutory Rate (442,428) (232,085) 57,190
Revisions of Previous Quantity Estimates 20,736 40,964 (75,136)
Accretion of Discount and Other 59,100 72,413 54,523
- ------------------------------------------------------ ------------- -------------- -------------
Standardized Measure of Discounted
Future Net Cash Flows at End of Year $1,518,132 $707,259 $466,771
- ------------------------------------------------------ ------------- -------------- -------------
Schedule II - Valuation and Qualifying Accounts
Back to Index of Financial Statements
- ---------------------------------- ------------ ----------- ------------ ------------- ------------
Additions Additions
Balance at Charged Charged to Balance at
to
(Thousands) Beginning Costs Other End of
and
Description of Accounts(1) Deductions(2) Period
Period Expenses
- ---------------------------------- ------------ ----------- ------------ ------------- ------------
Year Ended September 30, 2000
Reserve for Doubtful Accounts $7,842 $15,177 $ - $11,006 $12,013
- ---------------------------------- ------------ ----------- ------------ ------------- ------------
Year Ended September 30, 1999
Reserve for Doubtful Accounts $6,232 $15,337 $ 1 $13,728 $7,842
- ---------------------------------- ------------ ----------- ------------ ------------- ------------
Year Ended September 30, 1998
Reserve for Doubtful Accounts $8,291 $15,861 $746 $18,666 $6,232
- ---------------------------------- ------------ ----------- ------------ ------------- ------------
|
(1) Represents opening balance sheet reserve plus exchange rate impact of translating the Czech koruna to the U.S. dollar for Horizon. |
|
(2) Amounts represent net accounts receivable written-off. |
ITEM 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Back to Table of ContentsNone
PART III
ITEM 10 Directors and Executive Officers of the Registrant
Back to Table of ContentsThe information required by this item concerning the directors of the Company is omitted pursuant to Instruction G of Form 10-K since the Company's definitive Proxy Statement for its February 15, 2001 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2000. The information concerning directors is set forth in the definitive Proxy Statement under the captions entitled "Nominees for Election as Directors for Three-Year Terms to Expire 2003," "Directors Whose Terms Expire in 2002," "Directors Whose Terms Expire in 2001," and "Compliance with Section 16(a) of the Securities Exchange Act of 1934" and is incorporated herein by reference. Information concerning the Company's executive officers can be found in Part I, Item 1, of this report.
ITEM 11 Executive Compensation
Back to Table of ContentsThe information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company's definitive Proxy Statement for its February 15, 2001 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2000. The information concerning executive compensation is set forth in the definitive Proxy Statement under the captions "Executive Compensation" and "Compensation Committee Interlocks and Insider Participation" and, excepting the "Report of the Compensation Committee" and the "Corporate Performance Graph," is incorporated herein by reference.
ITEM 12 Security Ownership of Certain Beneficial Owners and Management
Back to Table of Contents(a) Security Ownership of Certain Beneficial Owners
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company's definitive Proxy Statement for its February 15, 2001 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2000. The information concerning security ownership of certain beneficial owners is set forth in the definitive Proxy Statement under the caption "Security Ownership of Certain Beneficial Owners and Management" and is incorporated herein by reference.
(b) Security Ownership of Management
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company's definitive Proxy Statement for its February 15, 2001 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2000. The information concerning security ownership of management is set forth in the definitive Proxy Statement under the caption "Security Ownership of Certain Beneficial Owners and Management" and is incorporated herein by reference.
(c) Changes in Control
None
ITEM 13 Certain Relationships and Related Transactions
Back to Table of ContentsThe information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company's definitive Proxy Statement for its February 15, 2001 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2000. The information regarding certain relationships and related transactions is set forth in the definitive Proxy Statement under the caption "Compensation Committee Interlocks and Insider Participation" and is incorporated herein by reference.
PART IV
ITEM 14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K
Back to Table of ContentsAll financial statement schedules filed as part of this report are included in Item 8 of this Form 10-K and reference is made thereto.
None
Exhibit
Number Description of Exhibits
3(i) Articles of Incorporation:
o Restated Certificate of Incorporation of National Fuel
Gas Company dated September 21, 1998 (Exhibit 3.1,
Form 10-K for fiscal year ended September 30, 1998 in
File No. 1-3880)
3(ii) By-Laws:
o National Fuel Gas Company By-Laws as amended on
February 17, 2000 (Exhibit 3.1, Form 10-K for fiscal
year ended June 30, 2000 in File No. 1-3880)
(4) Instruments Defining the Rights of Security Holders,
Including Indentures:
o Indenture dated as of October 15, 1974, between the
Company and The Bank of New York (formerly Irving Trust
Company) (Exhibit 2(b) in File No. 2-51796)
o Third Supplemental Indenture dated as of December 1,
1982, to Indenture dated as of October 15, 1974, between
the Company and The Bank of New York (formerly Irving
Trust Company) (Exhibit 4(a)(4) in File No. 33-49401)
o Tenth Supplemental Indenture dated as of February 1,
1992, to Indenture dated as of October 15, 1974, between
the Company and The Bank of New York (formerly Irving
Trust Company) (Exhibit 4(a), Form 8-K dated February
14, 1992 in File No. 1-3880)
o Eleventh Supplemental Indenture dated as of May 1, 1992,
to Indenture dated as of October 15, 1974, between the
Company and The Bank of New York (formerly Irving Trust
Company) (Exhibit 4(b), Form 8-K dated February 14, 1992
in File No. 1-3880)
o Twelfth Supplemental Indenture dated as of June 1, 1992,
to Indenture dated as of October 15, 1974, between the
Company and The Bank of New York (formerly Irving Trust
Company) (Exhibit 4(c), Form 8-K dated June 18, 1992 in
File No. 1-3880)
o Thirteenth Supplemental Indenture dated as of March 1,
1993, to Indenture dated as of October 15, 1974, between
the Company and The Bank of New York (formerly Irving
Trust Company) (Exhibit 4(a)(14) in File No. 33-49401)
o Fourteenth Supplemental Indenture dated as of July 1,
1993, to Indenture dated as of October 15, 1974, between
the Company and The Bank of New York (formerly Irving
Trust Company) (Exhibit 4.1, Form 10-K for fiscal year
ended September 30, 1993 in File No. 1-3880)
o Fifteenth Supplemental Indenture dated as of September
1, 1996 to Indenture dated as of October 15, 1974,
between the Company and The Bank of New York (formerly
Irving Trust Company) (Exhibit 4.1, Form 10-K for fiscal
year ended September 30, 1996 in File No. 1-3880)
o Indenture dated as of October 1, 1999, between the
Company and The Bank of New York (Exhibit 4.1, Form 10-K
for fiscal year ended September 30, 1999 in File No.
1-3880)
o Officer's Certificate Establishing Medium-Term Notes
dated October 14, 1999 (Exhibit 4.2, Form 10-K for
fiscal year ended September 30, 1999 in File No. 1-3880)
o Amended and Restated Rights Agreement, dated as of April
30, 1999, between National Fuel Gas Company and HSBC
Bank USA (Exhibit 10.2, Form 10-Q for the quarterly
period ended March 31, 1999 in File No. 1-3880)
(10) Material Contracts:
(iii) Compensatory plans for officers:
o Employment Agreement, dated September 17, 1981, with
Bernard J. Kennedy (Exhibit 10.4, Form 10-K for fiscal
year ended September 30, 1994 in File No. 1-3880)
o Tenth Amendment to Employment Agreement with Bernard J.
Kennedy, effective September 1, 1999 (Exhibit 10.1, Form
10-K for fiscal year ended September 30, 1999 in File
No. 1-3880)
o Agreement dated August 1, 1986, with Joseph P. Pawlowski
(Exhibit 10.1, Form 10-K for fiscal year ended September
30,1997 in File No. 1-3880)
o Agreement dated August 1, 1986, with Gerald T. Wehrlin
(Exhibit 10.2, Form 10-K for fiscal year ended September
30, 1997, in File No. 1-3880)
o Form of Employment Continuation and Noncompetition
Agreements, dated as of December 11, 1998, with Philip
C. Ackerman, Walter E. DeForest, Joseph P. Pawlowski,
Dennis J. Seeley, David F. Smith and Gerald T. Wehrlin
(Exhibit 10.1, Form 10-Q for the quarterly period ended
June 30, 1999 in File No. 1-3880)
o Severance Agreement, Release and Waiver dated March 27,
2000, between National Fuel Gas Supply Corporation and
Richard Hare (Exhibit 10.2, Form 10-Q for the quarterly
period ended March 31, 2000)
o Form of Employment Continuation and Noncompetition
Agreement, dated as of December 11, 1998, with James A.
Beck (Exhibit 10.3, Form 10-Q for the quarterly period
ended June 30, 1999 in File No. 1-3880)
o National Fuel Gas Company 1983 Incentive Stock Option
Plan, as amended and restated through February 18, 1993
(Exhibit 10.2, Form 10-Q for the quarterly period ended
March 31, 1993 in File No. 1-3880)
o National Fuel Gas Company 1984 Stock Plan, as amended
and restated through February 18, 1993 (Exhibit 10.3,
Form 10-Q for the quarterly period ended March 31, 1993
in File No. 1-3880)
o Amendment to the National Fuel Gas Company 1984 Stock
Plan, dated December 11, 1996 (Exhibit 10.7, Form 10-K
for fiscal year ended September 30, 1996 in File No.
1-3880)
o National Fuel Gas Company 1993 Award and Option Plan,
dated February 18, 1993 (Exhibit 10.1, Form 10-Q for the
quarterly period ended March 31, 1993 in File No.
1-3880)
o Amendment to National Fuel Gas Company 1993 Award and
Option Plan, dated October 27, 1995 (Exhibit 10.8, Form
10-K for fiscal year ended September 30, 1995 in File
No. 1-3880)
o Amendment to National Fuel Gas Company 1993 Award and
Option Plan, dated December 11, 1996 (Exhibit 10.8, Form
10-K for fiscal year ended September 30, 1996 in File
No. 1-3880)
o Amendment to National Fuel Gas Company 1993 Award and
Option Plan, dated December 18, 1996 (Exhibit 10, Form
10-Q for the quarterly period ended December 31, 1996 in
File No. 1-3880)
o Amended and Restated National Fuel Gas Company 1997
Award and Option Plan, as amended and restated through
February 17, 2000 (Exhibit 10.1, Form 10-Q for the
quarterly period ended March 31, 2000 in File No.
1-3880)
o National Fuel Gas Company Deferred Compensation Plan, as
amended and restated through May 1, 1994 (Exhibit 10.7,
Form 10-K for fiscal year ended September 30, 1994 in
File No. 1-3880)
o Amendment to the National Fuel Gas Company Deferred
Compensation Plan, dated September 19, 1996 (Exhibit
10.10, Form 10-K for fiscal year ended September 30,
1996 in File No. 1-3880)
o Amendment to the National Fuel Gas Company Deferred
Compensation Plan, dated September 27, 1995 (Exhibit
10.9, Form 10-K for fiscal year ended September 30, 1995
in File No. 1-3880)
o National Fuel Gas Company Deferred Compensation Plan, as
amended and restated through March 20, 1997 (Exhibit
10.3, Form 10-K for fiscal year ended September 30, 1997
in File No. 1-3880)
o Amendment to National Fuel Gas Company Deferred
Compensation Plan dated June 16, 1997 (Exhibit 10.4,
Form 10-K for fiscal year ended September 30, 1997 in
File No. 1-3880)
o Amendment No. 2 to the National Fuel Gas Company
Deferred Compensation Plan, dated March 13, 1998
(Exhibit 10.1, Form 10-K for fiscal year ended September
30, 1998 in File No. 1-3880)
o Amendment to the National Fuel Gas Company Deferred
Compensation Plan, dated February 18, 1999 (Exhibit
10.1, Form 10-Q for the quarterly period ended March 31,
1999 in File No. 1-3880)
o National Fuel Gas Company Tophat Plan, effective March
20, 1997 (Exhibit 10, Form 10-Q for the quarterly period
ended June 30, 1997 in File No. 1-3880)
o Amendment No. 1 to the National Fuel Gas Company Tophat
Plan, dated April 6, 1998 (Exhibit 10.2, Form 10-K for
fiscal year ended September 30, 1998 in File No. 1-3880)
o Amendment No. 2 to the National Fuel Gas Company Tophat
Plan, dated December 10, 1998 (Exhibit 10.1, Form 10-Q
for the quarterly period ended December 31, 1998 in File
No. 1-3880)
o Death Benefits Agreement, dated August 28, 1991, with
Bernard J. Kennedy (Exhibit 10-TT, Form 10-K for fiscal
year ended September 30, 1991 in File No. 1-3880)
o Amendment to Death Benefit Agreement of August 28, 1991,
with Bernard J. Kennedy, dated March 15, 1994 (Exhibit
10.11, Form 10-K for fiscal year ended September 30,
1995 in File No. 1-3880)
o Amended and Restated Split Dollar Insurance Agreement,
effective June 15, 2000 among National Fuel Gas Company,
Bernard J. Kennedy, and Joseph B. Kennedy, as Trustee of
the Trust under the Agreement dated January 9, 1998
(Exhibit 10.1, Form 10-Q for the quarterly period ended
June 30, 2000 in File No. 1-3880)
o Contingent Benefit Agreement effective June 15, 2000
between National Fuel Gas Company and Bernard J. Kennedy
(Exhibit 10.2, Form 10-Q for the quarterly period ended
June 30, 2000 in File No. 1-3880)
o Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 17, 1997 with Philip
C. Ackerman (Exhibit 10.5, Form 10-K for fiscal year
ended September 30, 1997 in File No. 1-3880)
o Amendment Number 1 to Amended and Restated Split Dollar
Insurance and Death Benefit Agreement by and Between
National Fuel Gas Company and Philip C. Ackerman, dated
March 23, 1999 (Exhibit 10.3, Form 10-K for fiscal year
ended September 30, 1999 in File No. 1-3880)
o Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997 with Joseph
P. Pawlowski (Exhibit 10.7, Form 10-K for fiscal year
ended September 30, 1997 in File No. 1-3880)
o Amendment Number 1 to Amended and Restated Split Dollar
Insurance and Death Benefit Agreement by and Between
National Fuel Gas Company and Joseph P. Pawlowski, dated
March 23, 1999 (Exhibit 10.5, Form 10-K for fiscal year
ended September 30, 1999 in File No. 1-3880)
o Second Amended and Restated Split Dollar Insurance
Agreement dated June 15, 1999 with Gerald T. Wehrlin
(Exhibit 10.6, Form 10-K for fiscal year ended September
30, 1999 in File No. 1-3880)
o Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997 with Walter
E. DeForest (Exhibit 10.7, Form 10-K for fiscal year
ended September 30, 1999 in File No. 1-3880)
o Amendment Number 1 to Amended and Restated Split Dollar
Insurance and Death Benefit Agreement by and Between
National Fuel Gas Company and Walter E. DeForest, dated
March 29, 1999 (Exhibit 10.8, Form 10-K for fiscal year
ended September 30, 1999 in File No. 1-3880)
o Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997 with Dennis
J. Seeley (Exhibit 10.9, Form 10-K for fiscal year ended
September 30, 1999 in File No. 1-3880)
o Amendment Number 1 to Amended and Restated Split Dollar
Insurance and Death Benefit Agreement by and Between
National Fuel Gas Company and Dennis J. Seeley, dated
March 29, 1999 (Exhibit 10.10, Form 10-K for fiscal year
ended September 30, 1999 in File No. 1-3880)
o Split Dollar Insurance and Death Benefit Agreement dated
September 15, 1997 with Bruce H. Hale (Exhibit 10.11,
Form 10-K for fiscal year ended September 30, 1999 in
File No. 1-3880)
o Amendment Number 1 to Split Dollar Insurance and Death
Benefit Agreement by and Between National Fuel Gas
Company and Bruce H. Hale, dated March 29, 1999 (Exhibit
10.12, Form 10-K for fiscal year ended September 30,
1999 in File No. 1-3880)
o Split Dollar Insurance and Death Benefit Agreement dated
September 15, 1997 with David F. Smith (Exhibit 10.13,
Form 10-K for fiscal year ended September 30, 1999 in
File No. 1-3880)
o Amendment Number 1 to Split Dollar Insurance and Death
Benefit Agreement by and Between National Fuel Gas
Company and David F. Smith, dated March 29, 1999
(Exhibit 10.14, Form 10-K for fiscal year ended
September 30, 1999 in File No. 1-3880)
o National Fuel Gas Company and Participating Subsidiaries
Executive Retirement Plan as amended and restated
through November 1, 1995 (Exhibit 10.10, Form 10-K for
fiscal year ended September 30, 1995 in File No. 1-3880)
o National Fuel Gas Company and Participating Subsidiaries
1996 Executive Retirement Plan Trust Agreement (II)
dated May 10, 1996 (Exhibit 10.13, Form 10-K for fiscal
year ended September 30, 1996 in File No. 1-3880)
o Amendments to National Fuel Gas Company and
Participating Subsidiaries Executive Retirement Plan
dated September 18, 1997 (Exhibit 10.9, Form 10-K for
fiscal year ended September 30, 1997 in File No. 1-3880)
o Amendments to the National Fuel Gas Company and
Participating Subsidiaries Executive Retirement Plan
dated December 10, 1998 (Exhibit 10.2, Form 10-Q for the
quarterly period ended December 31, 1998 in File No.
1-3880)
o Amendments to National Fuel Gas Company and
Participating Subsidiaries Executive Retirement Plan
effective September 16, 1999 (Exhibit 10.15, Form 10-K
for fiscal year ended September 30, 1999 in File No.
1-3880)
o Administrative Rules with Respect to at Risk Awards
under the 1993 Award and Option Plan (Exhibit 10.14,
Form 10-K for fiscal year ended September 30, 1996 in
File No. 1-3880)
o Administrative Rules with Respect to at Risk Awards
under the 1997 Award and Option Plan (Exhibit A,
Definitive Proxy Statement, Schedule 14(A) filed January
14, 2000 in File No. 1-3880)
o Administrative Rules of the Compensation Committee of
the Board of Directors of National Fuel Gas Company, as
amended and restated, effective December 10, 1998
(Exhibit 10.3, Form 10-Q for the quarterly period ended
December 31, 1998 in File No. 1-3880)
o Excerpts of Minutes from the National Fuel Gas Company
Board of Directors Meeting of February 20, 1997
regarding the Retirement Benefits for Bernard J. Kennedy
(Exhibit 10.10, Form 10-K for fiscal year ended
September 30, 1997 in File No. 1-3880)
o Excerpts of Minutes from the National Fuel Gas Company
Board of Directors Meeting of March 20, 1997 regarding
the Retainer Policy for Non-Employee Directors (Exhibit
10.11, Form 10-K for fiscal year ended September 30,
1997 in File No. 1-3880)
(12) Computation of Ratio of Earnings to Fixed Charges
(21) Subsidiaries of the Registrant: See Item 1 of Part I of
this Annual Report on Form 10-K
(23) Consents of Experts:
23.1 Consent of Ralph E. Davis Associates, Inc.
23.2 Consent of Independent Accountants
23.3 Consent of McDaniel & Associates Consultants Ltd.
(27) Financial Data Schedules:
27.1 Financial Data Schedule for the Twelve Months Ended
September 30, 2000
27.2 Restated Financial Data Schedule for the Twelve Months
Ended September 30, 1999
(99) Additional Exhibits:
99.1 Report of Ralph E. Davis Associates, Inc.
99.2 Report of McDaniel & Associates Consultants Ltd.
All other exhibits are omitted because they are not applicable or the
required information is shown elsewhere in this Annual Report on Form
10-K.
o Incorporated herein by reference as indicated.
Pursuant to the requirements of Section 13 or 15(d) 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.
National Fuel Gas Company
(Registrant)
---------------------------------
By /s/ B. J. Kennedy
---------------------------
B. J. Kennedy
Chairman of the Board
and Chief Executive Officer
Date: December 7, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title
/s/ B. J. Kennedy Chairman of the Board,
---------------------------
B. J. Kennedy Chief Executive Officer and Director
Date: December 7, 2000
/s/ P. C. Ackerman President, Principal Financial
--------------------------
P. C. Ackerman Officer and Director
Date: December 7, 2000
/s/ R. T. Brady Director
-------------------------
R. T. Brady
Date: December 7, 2000
/s/ J. V. Glynn Director
-------------------------
J. V. Glynn
Date: December 7, 2000
/s/ W. J. Hill Director
-------------------------
W. J. Hill
Date: December 7, 2000
/s/ B. S. Lee Director
-------------------------
B. S. Lee
Date: December 7, 2000
/s/ E. T. Mann Director
-------------------------
E. T. Mann
Date: December 7, 2000
/s/ G. L. Mazanec Director
-------------------------
G. L. Mazanec
Date: December 7, 2000
/s/ J. F. Riordan Director
-------------------------
J. F. Riordan
Date: December 7, 2000
/s/ J. P. Pawlowski Treasurer and Principal
--------------------------
J. P. Pawlowski Accounting Officer
Date: December 7, 2000
APPENDIX TO ITEM 2 - PROPERTIES
Six maps outlining the Company's operating areas at September 30, 2000 are
included throughout pages 3 - 16 of the paper format version of the
Company's combined Annual Report to Shareholders/Form 10-K. The first map
identifies the Company's Exploration and Production operating area (i.e.,
Seneca's operating area). The second map identifies the Company's Utility
operating area (i.e., Distribution Corporation's service area). The third
map identifies the Company's Pipeline and Storage operating area (i.e.,
Supply Corporation's storage areas and pipelines). The fourth map
identifies the Company's Timber Operating area (i.e., Seneca's and
Highland's timber and sawmill operations). The fifth map identifies the
Company's International operating area (i.e., Horizon's Czech Republic
operations). The sixth map identifies the Company's Energy Marketing
operating area (i.e., NFR's marketing service area).
APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION - GRAPHS
A. The Revenue Dollar - 2000
Two pie graphs detailing the revenue dollar in 2000: where it came from
and where it went to, broken down as follows:
Where it came from:
$ .405 Residential Gas Sales
.151 Oil and Gas Production Revenues
.113 Commercial, Industrial and Off-System Gas Sales
.093 Energy Marketing Revenues
.086 Gas Transportation Revenues
.048 District Heating Revenues
.027 Timber and Sawmill Revenues
.022 Gas Storage Service Revenues
.022 Electric Generation Revenues
.033 Other Revenues
$1.000 Total
Where it went to:
$ .349 Gas Purchased
.140 Wages, Including Benefits
.109 Other Materials and Services
.107 Taxes
.099 Depreciation
.069 Interest
.051 Dividends - Common Stock
.038 Fuel Used in Heat and Electric Generation
.037 Reinvested in the Business
.001 Minority Interest in Foreign Subsidiaries
$1.000 Total
Exhibit Index
-------------
(12) Computation of Ratio of Earnings to Fixed
Charges
23.1 Consent of Ralph E. Davis Associates, Inc.
23.2 Consent of Independent Accountants
23.3 Consent of McDaniel & Associates Consultants Ltd.
27.1 Financial Data Schedule for the Twelve
Months Ended September 30, 2000
27.2 Restated Financial Data Schedule for the
Twelve Months Ended September 30, 1999
99.1 Report of Ralph E. Davis Associates, Inc.
99.2 Report of McDaniel & Associates Consultants Ltd.