National Fuel Gas - 10-Q quarterly report FY

UtilityUtility Operating Revenues- ------------------------------- ------------------------------------------- ------------------------------------------
Three Months Ended Six Months Ended
March 31, March 31,
- ------------------------------- ------------------------------------------- ------------------------------------------
Increase/ Increase/
(Thousands) 2002 2001 (Decrease) 2002 2001 (Decrease)
- ------------------------------- ------------- -------------- -------------- ------------ -------------- --------------
Retail Sales Revenues:
Residential $200,844 $415,283 $(214,439) $365,680 $667,841 $(302,161)
Commercial 34,905 78,995 (44,090) 60,900 122,814 (61,914)
Industrial 4,927 9,273 (4,346) 8,093 20,677 (12,584)
- ------------------------------- ------------- -------------- -------------- ------------ -------------- --------------
240,676 503,551 (262,875) 434,673 811,332 (376,659)
- ------------------------------- ------------- -------------- -------------- ------------ -------------- --------------
Off-System Sales 21,507 39,384 (17,877) 32,851 61,371 (28,520)
Transportation 30,487 33,227 (2,740) 52,981 57,738 (4,757)
Other (650) 1,837 (2,487) (496) 1,725 (2,221)
- ------------------------------- ------------- -------------- -------------- ------------ -------------- --------------
$292,020 $577,999 $(285,979) $520,009 $932,166 $(412,157)
- ------------------------------- ------------- -------------- -------------- ------------ -------------- --------------Utility Throughput- ------------------------------- ------------------------------------------- ------------------------------------------
Three Months Ended Six Months Ended
March 31, March 31,
- ------------------------------- ------------------------------------------- ------------------------------------------
Increase/ Increase/
(MMcf) 2002 2001 (Decrease) 2002 2001 (Decrease)
- ------------------------------- ------------- -------------- -------------- ------------ -------------- --------------
Retail Sales:
Residential 29,678 33,847 (4,169) 47,591 57,848 (10,257)
Commercial 5,479 6,849 (1,370) 8,595 11,300 (2,705)
Industrial 894 986 (92) 1,593 2,659 (1,066)
- ------------------------------- ------------- -------------- -------------- ------------ -------------- --------------
36,051 41,682 (5,631) 57,779 71,807 (14,028)
- ------------------------------- ------------- -------------- -------------- ------------ -------------- --------------
Off-System Sales 7,651 4,302 3,349 11,600 7,483 4,117
Transportation 21,274 23,850 (2,576) 36,509 41,365 (4,856)
- ------------------------------- ------------- -------------- -------------- ------------ -------------- --------------
64,976 69,834 (4,858) 105,888 120,655 (14,767)
- ------------------------------- ------------- -------------- -------------- ------------ -------------- --------------

2002 Compared with 2001

Operating revenues for the Utility segment decreased $286.0 million and $412.2 million, respectively, for the quarter and six months ended March 31, 2002 as compared with the quarter and six months ended March 31, 2001. These decreases were primarily the result of decreases in retail sales volumes, as shown above, decreases in the average cost of purchased gas ($4.49 and $9.48 per thousand cubic feet (Mcf) during the quarters ended March 31, 2002 and 2001, respectively; $4.67 and $8.51 for the six months ended March 31, 2002 and 2001, respectively) and lower transportation volumes. Warmer weather, as shown in the table below, and a general economic downturn in the Utility segment’s sales territory were the major factors for the decrease in retail sales volumes and transportation volumes. The decreases in off-system sales revenues were largely due to lower gas prices which more than offset higher volumes. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal. The decreases to other revenues primarily reflects an estimated refund provision of $1.8 million and $3.4 million, respectively, recorded in the Utility’s New York jurisdiction in the quarter and six months ended March 31, 2002 that relates to a 50% sharing with customers of earnings over a predetermined amount. This earnings sharing mechanism is in accordance with the New York rate settlement that went into effect October 1, 2000. Refund provisions were not recorded in the quarter or six months ended March 31, 2001.

      Partly offsetting these decreases to revenue was the positive impact of a lower bill credit in the Utility's New York jurisdiction. In connection with the three year rate settlement reached with the New York State Public Service Commission that went into effect October 1, 2000, the Utility's New York customers received a $10.0 million rate decrease in the form of a bill credit for the November 1, 2000 through March 31, 2001 heating season. For the November 1, 2001 through March 31, 2002 heating season, the amount of the bill credit was reduced to $5.0 million.

      The Utility segment's earnings for the quarter ended March 31, 2002 were $35.7 million, a decrease of $3.7 million when compared with the quarter ended March 31, 2001. Significant factors for this decrease were the impact of weather, which in the Pennsylvania jurisdiction was 13.3% warmer than the quarter ended March 31, 2001 and a decrease in normalized usage per account (normalized usage excludes the impact of weather on consumption) due to a downturn in the economy. Also contributing to the decrease was the refund provision of $1.8 million ($1.2 million after tax). These decreases were offset, in part, by the positive impact of the lower bill credit discussed above. The impact of weather variations in the New York jurisdiction is mitigated by that jurisdiction's 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. In periods of colder than normal weather, the WNC benefits Distribution Corporation's New York customers. For the quarters ended March 31, 2002 and 2001, as the weather was warmer than normal in both periods, the WNC preserved earnings of $5.6 million (after tax) and $0.8 million (after tax), respectively.

      The Utility's segment's earnings for the six months ended March 31, 2002 were $53.7 million, a decrease of $4.0 million when compared with the earnings of $57.7 million for the six months ended March 31, 2001. However, the earnings for the six months ended March 31, 2001 included $0.8 million of non-recurring earnings associated with stock appreciation rights and $4.2 million of non-recurring after tax expense associated with early retirement offers in the Utility's New York and Pennsylvania jurisdictions. Exclusive of these two items, the decrease in earnings was $7.4 million. As previously discussed, lower normalized usage per account across the Utility's service territory and weather, which in the Pennsylvania jurisdiction was approximately 20.0% warmer than the six months ended March 31, 2001, significantly decreased earnings in 2002. Also contributing to the decrease was the refund provision of $3.4 million ($2.2 million after tax) discussed above. In the New York jurisdiction, the impact of weather variations was mitigated by the WNC. For the six months ended March 31, 2002, the WNC preserved earnings of $10.2 million after tax since it was warmer than normal. For the six months ended March 31, 2001, the WNC resulted in a benefit to customers of $0.2 million after tax since it was colder than normal.

Degree Days- ---------------------------------- -------------- -------------- -------------------- --------------------------------
Percent (Warmer)
Three Months Ended Colder Than
--------------------------------
March 31 Normal 2002 2001 Normal Prior Year
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Buffalo 3,361 2,915 3,236 (13.3) (9.9)
Erie 3,160 2,698 3,112 (14.6) (13.3)
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Six Months Ended
March 31
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Buffalo 5,681 4,714 5,724 (17.0) (17.6)
Erie 5,179 4,357 5,444 (15.9) (20.0)
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------

Pipeline and StoragePipeline and Storage Operating Revenues- ------------------------------------ ---------------------------------------- -------------------------------------------
Three Months Ended Six Months Ended
March 31, March 31,
- ------------------------------------ ---------------------------------------- -------------------------------------------
Increase/ Increase/
(Thousands) 2002 2001 (Decrease) 2002 2001 (Decrease)
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Firm Transportation $22,710 $24,175 $(1,465) $45,093 $46,917 $(1,824)
Interruptible Transportation 728 832 (104) 1,508 1,641 (133)
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
23,438 25,007 (1,569) 46,601 48,558 (1,957)
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Firm Storage Service 15,643 15,512 131 31,016 30,580 436
Interruptible Storage Service 6 49 (43) 7 216 (209)
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
15,649 15,561 88 31,023 30,796 227
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Other 3,001 4,074 (1,073) 7,409 7,952 (543)
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
$42,088 $44,642 $(2,554) $85,033 $87,306 $(2,273)
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------Pipeline and Storage Throughput- ---------------------------------- ---------------------------------------- ---------------------------------------
Three Months Ended Six Months Ended
March 31, March 31,
- ---------------------------------- ---------------------------------------- ---------------------------------------
Increase/ Increase/
(MMcf) 2002 2001 (Decrease) 2002 2001 (Decrease)
- ---------------------------------- ------------ ------------ -------------- ----------- ----------- ---------------
Firm Transportation 99,387 105,655 (6,268) 171,438 195,197 (23,759)
Interruptible Transportation 1,878 2,667 (789) 3,867 8,617 (4,750)
- ---------------------------------- ------------ ------------ -------------- ----------- ----------- ---------------
101,265 108,322 (7,057) 175,305 203,814 (28,509)
- ---------------------------------- ------------ ------------ -------------- ----------- ----------- ---------------

2002 Compared with 2001

Operating revenues for the Pipeline and Storage segment decreased $2.6 million and $2.3 million, respectively, for the quarter and six months ended March 31, 2002 as compared with the quarter and six months ended March 31, 2001. For the quarter ended March 31, 2002, the increase can be attributed primarily to a $1.6 million decrease in transportation revenues and a $0.4 million decrease in revenues from unbundled pipeline sales and open access transportation included in other revenues. For the six months ended March 31, 2002, the decrease can be attributed primarily to a $2.0 million decrease in transportation revenues. The decrease in transportation revenues for the quarter and six month periods primarily reflects lower gathering rates (the rates charged by Supply Corporation to its transportation customer to move gas from a third-party well site to Supply Corporation’s pipeline for delivery to the customer) as per a settlement with the Federal Energy Regulatory Commission (FERC). However, this rate decrease is largely offset by a reduction in amortization expense, thus having little impact on net income. While transportation volumes decreased significantly during both the quarter and six month periods, volume fluctuations generally do not have a significant impact on revenues as a result of Supply Corporation’s straight fixed-variable rate design.

      The Pipeline and Storage segment's earnings for the quarter ended March 31, 2002 were $9.8 million, a decrease of $5.0 million when compared with earnings of $14.8 million for the quarter ended March 31, 2001. However, the earnings for the quarter ended March 31, 2001 included $4.6 million of non-recurring earnings associated with stock appreciation rights and $0.5 million of non-recurring after

tax expense associated with an early retirement offer. Exclusive of these two items, the decrease in earnings was only $0.9 million. As discussed above, lower revenues from unbundled pipeline sales and open access transportation and slightly higher operation expense contributed to this earnings decrease.

      The Pipeline and Storage segment's earnings for the six months ended March 31, 2002 were $19.8 million, a decrease of $1.6 million when compared with earnings of $21.4 million for the six months ended March 31, 2001. However, earnings for the six months ended March 31, 2001 included $1.0 million of non-recurring earnings associated with stock appreciation rights, $2.6 million of non-recurring earnings realized upon the buyout by a customer of a long-term transportation contract, and $1.1 million of non-recurring after tax expense associated with early retirement offers. Exclusive of these three items, there was an increase in earnings of $0.9 million. This increase can be attributed primarily to an increase in revenues from unbundled pipeline sales and open access transportation.

Exploration and ProductionExploration and Production Operating Revenues- ----------------------------------- ---------------------------------------- -----------------------------------------
Three Months Ended Six Months Ended
March 31, March 31,
- ----------------------------------- ---------------------------------------- -----------------------------------------
Increase/ Increase/
(Thousands) 2002 2001 (Decrease) 2002 2001 (Decrease)
- ----------------------------------- ------------ ------------ -------------- ------------- ------------ --------------
Gas (after Hedging) $36,804 $48,232 $(11,428) $ 71,909 $80,557 $(8,648)
Oil (after Hedging) 35,472 40,777 (5,305) 68,809 83,251 (14,442)
Gas Processing Plant 3,344 11,876 (8,532) 7,562 22,394 (14,832)
Other 536 (2,434) 2,970 5,978 13,504 (7,526)
Intrasegment Elimination * (2,951) (15,154) 12,203 (6,053) (24,659) 18,606
- ----------------------------------- ------------ ------------ -------------- ------------- ------------ --------------
$73,205 $83,297 $(10,092) $148,205 $175,047 $(26,842)
- ----------------------------------- ------------ ------------ -------------- ------------- ------------ --------------
* Represents the elimination of certain West Coast gas production revenue included in "Gas (after Hedging)" in the table above that
is sold to the gas processing plant shown in the table above. An elimination for the same dollar amount is made to reduce the gas
processing plant's Purchased Gas expense.
- ----------------------------------------- -------------------------------------- --------------------------------------Production Volumes Three Months Ended Six Months Ended
March 31, March 31,
- ----------------------------------------- -------------------------------------- --------------------------------------
Increase/ Increase/
2002 2001 (Decrease) 2002 2001 (Decrease)
- ----------------------------------------- ---------- ----------- --------------- ----------- ----------- --------------Gas Production (MMcf)
Gulf Coast 5,609 6,987 (1,378) 12,797 13,416 (619)
West Coast 1,196 1,052 144 2,442 2,097 345
Appalachia 1,144 1,064 80 2,202 2,106 96
Canada 1,810 108 1,702 3,641 230 3,411
- ----------------------------------------- ---------- ----------- --------------- ----------- ----------- --------------
9,759 9,211 548 21,082 17,849 3,233
- ----------------------------------------- ---------- ----------- --------------- ----------- ----------- --------------Oil Production (thousands of barrels)
Gulf Coast 438 468 (30) 892 824 68
West Coast 747 714 33 1,496 1,459 37
Appalachia 1 1 - 3 3 -
Canada 733 777 (44) 1,488 1,518 (30)
- ----------------------------------------- ---------- ----------- --------------- ----------- ----------- --------------
1,919 1,960 (41) 3,879 3,804 75
- ----------------------------------------- ---------- ----------- --------------- ----------- ----------- --------------

Average Prices- ----------------------------------------- --------------------------------------- ----------------------------------------
Three Months Ended Six Months Ended
March 31, March 31,
- ----------------------------------------- --------------------------------------- ----------------------------------------
Increase/ Increase/
2002 2001 (Decrease) 2002 2001 (Decrease)
- ----------------------------------------- ----------- ----------- --------------- ------------ ------------ --------------Average Gas Price/McfGulf Coast $2.41 $7.18 $(4.77) $2.41 $6.57 $(4.16)
West Coast $2.35 $15.04 $(12.69) $2.35 $12.21 $(9.86)
Appalachia $3.82 $5.99 $(2.17) $3.74 $5.09 $(1.35)
Canada $1.99 $5.18 $(3.19) $2.03 $4.95 $(2.92)
Weighted Average $2.49 $7.92 $(5.43) $2.48 $7.04 $(4.56)
Weighted Average After Hedging $3.77 $5.24 $(1.47) $3.41 $4.51 $(1.10)Average Oil Price/bblGulf Coast $20.16 $27.86 $(7.70) $19.65 $29.56 $(9.91)
West Coast $17.15 $23.79 $(6.64) $16.25 $25.40 $(9.15)
Appalachia $19.19 $29.90 $(10.71) $22.80 $30.53 $(7.73)
Canada $17.51 $23.38 $(5.87) $15.93 $25.64 $(9.71)
Weighted Average $17.98 $24.60 $(6.62) $16.92 $26.40 $(9.48)
Weighted Average After Hedging $18.48 $20.81 $(2.33) $17.74 $21.88 $(4.14)
- ----------------------------------------- ----------- ----------- --------------- ------------ ------------ --------------

2002 Compared with 2001

Operating revenues for the Exploration and Production segment decreased $10.1 million for the quarter ended March 31, 2002 as compared with the quarter ended March 31, 2001. Oil production revenue after hedging decreased $5.3 million due to lower commodity prices ($2.33 per bbl) and a 2% decrease in oil production. Gas production revenue after hedging decreased $11.4 million due primarily to a decrease in the weighted average price of gas after hedging ($1.47 per Mcf), offset slightly by a 6% increase in natural gas production. Overall gas production increased, primarily due to the Canadian properties acquired in June 2001 (Player Petroleum Corporation acquisition), partially offset by decreased production in the Gulf Coast region. The decrease in Gulf Coast production is the result of the previously announced strategy to exit the Gulf of Mexico and shift emphasis to longer lived reserves. Gas processing plant revenues decreased $8.5 million due to significantly lower gas prices. Other revenues increased $3.0 million largely due to non-recurring mark-to-market losses on derivative financial instruments that were recorded in the quarter ended March 31, 2001.

      Operating revenues for the Exploration and Production segment decreased $26.8 million for the six months ended March 31, 2002 as compared with the six months ended March 31, 2001. Oil production revenue after hedging decreased $14.4 million due to a $4.14 per bbl decrease in the weighted average price of oil after hedging. Gas production revenue after hedging, decreased $8.6 million. Decreases in the weighted average price after hedging ($1.10 per Mcf) more than offset an overall increase in gas production. As stated above, the overall increase in gas production is largely attributable to the Canadian properties acquired in June 2001 offset partially by decreased production in the Gulf Coast region. Gas processing plant revenues decreased $14.8 million due to significantly lower gas prices. Other revenues decreased $7.5 million largely due to non-recurring mark-to-market gains on derivative financial instruments that were recorded in the six months ended March 31, 2001.

      Refer to further discussion of derivative financial instruments in the "Market Risk Sensitive Instruments" section that follows. Refer to the tables above for production and price information.

      The Exploration and Production segment's earnings for the quarter ended March 31, 2002 were $8.7 million, a decrease of $7.9 million when compared with earnings of $16.6 million for the quarter ended March 31, 2001. As discussed above, decreases in the commodity prices of crude oil and natural gas ($2.33 per bbl and $1.47 per Mcf, respectively) were primarily responsible for this earnings decrease.

      The Exploration and Production segment's earnings for the six months ended March 31, 2002 were $10.1 million, a decrease of $29.5 million when compared with earnings of $39.6 million for the six months ended March 31, 2001. As discussed above, decreases in the commodity prices of crude oil and natural gas ($4.14 per bbl and $1.10 per Mcf, respectively) were primarily responsible for this earnings decrease.

InternationalInternational Operating Revenues- -------------------------------------- ------------------------------------------- -------------------------------------------
Three Months Ended Six Months Ended
March 31, March 31,
- -------------------------------------- ------------------------------------------- -------------------------------------------
Increase/ Increase/
(Thousands) 2002 2001 (Decrease) 2002 2001 (Decrease)
- -------------------------------------- ------------- ------------- --------------- ------------- ------------- ---------------
Heating $26,417 $30,596 $(4,179) $49,090 $52,304 $(3,214)
Electricity 7,550 7,537 13 14,649 16,412 (1,763)
Other 678 449 229 1,444 1,091 353
- -------------------------------------- ------------- ------------- --------------- ------------- ------------- ---------------
$34,645 $38,582 $(3,937) $65,183 $69,807 $(4,624)
- -------------------------------------- ------------- ------------- --------------- ------------- ------------- ---------------International Heating and Electric Volumes- -------------------------------------- ------------------------------------------- -------------------------------------------
Three Months Ended Six Months Ended
March 31, March 31,
- -------------------------------------- ------------------------------------------- -------------------------------------------
Increase/ Increase/
2002 2001 (Decrease) 2002 2001 (Decrease)
- -------------------------------------- ------------- ------------- --------------- ------------- ------------- ---------------
Heating Sales (Gigajoules) (1) 3,533,914 4,280,832 (746,918) 6,765,606 7,613,783 (848,177)
Electricity Sales
(megawatt hours) 288,904 291,906 (3,002) 550,585 621,930 (71,345)
- -------------------------------------- ------------- ------------- --------------- ------------- ------------- ---------------
(1) Gigajoules = one billion joules. A joule is a unit of energy.

      The International segment's earnings for the quarter ended March 31, 2002 were $3.8 million, an increase of $1.0 million when compared with earnings of $2.8 million for the quarter ended March 31, 2001. The increase can be attributed primarily to lower interest expense and a lower effective tax rate. Partially offsetting these earnings increases are lower heat margins and higher operation expenses.

      The International segment's earnings for the six months ended March 31, 2002 were $4.8 million, a decrease of $0.2 million when compared with earnings of $5.0 million for the six months ended March 31, 2001. Lower interest expense and lower taxes were more than offset by lower heat and electric margins and higher operation expenses.

Energy MarketingEnergy Marketing Operating Revenues- ----------------------------------- -------------------------------------------- ----------------------------------------
Three Months Ended Six Months Ended
March 31, March 31,
- ----------------------------------- -------------------------------------------- ----------------------------------------
Increase/ Increase/
(Thousands) 2002 2001 (Decrease) 2002 2001 (Decrease)
- ----------------------------------- ------------- -------------- --------------- ----------- ------------- --------------
Natural Gas (after Hedging) $52,213 $128,948 $(76,735) $85,016 $175,729 $(90,713)
Electricity - 565 (565) - 1,013 (1,013)
Other (77) (139) 62 (95) 818 (913)
- ----------------------------------- ------------- -------------- --------------- ----------- ------------- --------------
$52,136 $129,374 $(77,238) $84,921 $177,560 $(92,639)
- ----------------------------------- ------------- -------------- --------------- ----------- ------------- --------------Energy Marketing Volumes- ----------------------------------- -------------------------------------------- ----------------------------------------
Three Months Ended Six Months Ended
March 31, March 31,
- ----------------------------------- -------------------------------------------- ----------------------------------------
Increase/ Increase/
2002 2001 (Decrease) 2002 2001 (Decrease)
- ----------------------------------- ------------- -------------- --------------- ----------- ------------- --------------
Natural Gas - (MMcf) 11,785 14,477 (2,692) 18,975 22,204 (3,229)
- ----------------------------------- ------------- -------------- --------------- ----------- ------------- --------------

2002 Compared with 2001

Operating revenues for the Energy Marketing segment decreased $77.2 million and $92.6 million, respectively, for the quarter and six months ended March 31, 2002, as compared with the quarter and six months ended March 31, 2001. These decreases primarily reflect lower gas sales revenue due to the decreased price of natural gas.

      Earnings in the Energy Marketing segment increased $2.0 million and $2.6 million, respectively for the quarter and six months ended March 31, 2002 as compared with the quarter and six months ended March 31, 2001. These increases primarily reflect higher margins on gas sales and lower interest expense.

TimberTimber Operating Revenues- ------------------------------- ------------------------------------------- ---------------------------------------------
Three Months Ended Six Months Ended
March 31, March 31,
- ------------------------------- ------------------------------------------- ---------------------------------------------
Increase/ Increase/
(Thousands) 2002 2001 (Decrease) 2002 2001 (Decrease)
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
Log Sales $ 5,625 $9,723 $(4,098) $11,002 $16,135 $(5,133)
Green Lumber Sales 1,995 1,663 332 3,639 2,993 646
Kiln Dry Lumber Sales 4,056 3,078 978 7,138 6,083 1,055
Other 223 171 52 451 361 90
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
Operating Revenues $11,899 $14,635 $(2,736) $22,230 $25,572 $(3,342)
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------Timber Board Feet- ------------------------------- ------------------------------------------- ---------------------------------------------
Three Months Ended Six Months Ended
March 31, March 31,
- ------------------------------- ------------------------------------------- ---------------------------------------------
Increase/ Increase/
(Thousands) 2002 2001 (Decrease) 2002 2001 (Decrease)
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
Log Sales 2,304 3,087 (783) 4,428 5,148 (720)
Green Lumber Sales 3,657 2,817 840 6,667 5,083 1,584
Kiln Dry Lumber Sales 2,959 2,185 774 4,930 4,253 677
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
8,920 8,089 831 16,025 14,484 1,541
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------

2002 Compared with 2001

Operating revenues for the Timber segment decreased $2.7 million and $3.3 million, respectively, for the quarter and six months ended March 31, 2002, as compared with the quarter and six months ended March 31, 2001. Though sales in board feet increased for the quarter and six months ended March 31, 2002 as compared with quarter and six months ended March 31, 2001, revenues were down due to a change in sales mix. Sales of high priced veneer logs, such as cherry and oak decreased but sales of lower priced lumber increased. This change in sales mix is largely due to poor logging conditions, which accounted for the decrease in higher priced log sales. The weather was warmer and wetter than normal, which hampered the ability to cut and haul logs.

      Earnings in the Timber segment decreased $1.0 million for the quarter ended March 31, 2002 as compared with the quarter ended March 31, 2001. This decrease is due primarily to lower margins resulting from the change in sales mix described above.

      Earnings in the Timber segment decreased $1.9 million for the six months ended March 31, 2002 as compared with the six months ended March 31, 2001. However, earnings for the six months ended March 31, 2001 included a non-recurring after-tax gain of $1.4 million on the sale of timber properties. Exclusive of this gain, there was a decrease in earnings of $0.5 million. This decrease is due primarily to lower margins resulting from the change in sales mix described above.

Corporate and All Other Operations

2002 Compared with 2001

      Corporate and all other operations experienced a loss of $0.3 million for the quarter ended March 31, 2002, an improvement of $1.2 million over the loss of $1.5 million for the quarter ended March 31, 2001. The loss for the quarter ended March 31, 2001 included $0.8 million of non-recurring earnings associated with stock appreciation rights and $2.5 million of non-recurring after tax expense associated with a mark-to-market loss on natural gas inventory by Upstate Energy, Inc. (Upstate), the Company's wholly-owned subsidiary which is engaged in stored gas trading.

      Corporate and all other operations experienced a loss of $1.0 million for the six months ended March 31, 2002, an improvement of $1.4 million over the loss of $2.4 million for the six months ended March 31, 2001. The loss for the six months ended March 31, 2001 included $0.2 million of non-recurring earnings associated with stock appreciation rights and $2.5 million of non-recurring after tax expense associated with a mark-to-market loss on natural gas inventory by Upstate, as discussed above.

Other Income and Interest Charges

Other Income

      Other income decreased $6.6 million for the six months ended March 31, 2002 compared with the six months ended March 31, 2001. This decrease was principally due to two non-recurring events in the prior year: (1) a buyout of a long-term transportation contract by a customer in the Pipeline and Storage segment and (2) a realized gain on sale of certain timber properties in the Timber segment.

Interest Charges

Interest on long-term debt increased $2.2 million and $5.0 million, respectively, for the quarter and six months ended March 31, 2002 as compared with the quarter and six months ended March 31, 2001. These increases can be attributed primarily to higher average amounts of long-term debt outstanding.

      Other interest charges decreased $3.7 million and $8.8 million, respectively, for the quarter and six months ended March 31, 2002 as compared with the quarter and six months ended March 31, 2001. These decreases resulted mainly from a decrease in the average amount of short-term debt outstanding and lower weighted average interest rates.

      The increase in the average amount of long-term debt outstanding and the decrease in the average amount of short-term debt outstanding and the resulting impact on interest expense can be attributed to the November 2000 and November 2001 medium-term note issuances. In November 2000, the Company issued $200.0 million of 7.50% medium-term notes due in November 2010 and in November 2001, the Company issued $150.0 million of 6.70% medium-term notes due in November 2011. In both cases, proceeds from the medium-term note issuances were used to reduce short-term borrowings.

CAPITAL RESOURCES AND LIQUIDITY

Operating Cash Flow.

Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, deferred income taxes and minority interest in foreign subsidiaries.

      Cash provided by operating activities in the Utility and the Pipeline and Storage segments may vary from period to period 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 straight fixed-variable rate design.

      Because of the seasonal nature of the heating business in the Utility, Energy Marketing and International segments, revenues in these segments are relatively high during the heating season, primarily the first and second quarters of the year, and receivables historically increase during these periods from what was receivable at September 30.

      The storage gas inventory normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. For storage gas inventory accounted for under the last-in, first-out (LIFO) method, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets and is included under the caption "Other Accruals and Current Liabilities." Such reserve is reduced as the inventory is replenished.

      Cash provided by operating activities in the Exploration and Production segment may vary from period to period as a result of changes in the commodity prices of natural gas and crude oil. The Company uses various derivative financial instruments, including price swap agreements, no cost collars and options in an attempt to manage this energy commodity price risk.

      Net cash provided by operating activities totaled $166.3 million for the six months ended March 31, 2002, a decrease of $17.3 million compared with $183.6 million provided by operating activities for the six months ended March 31, 2001. Lower cash receipts from the sale of oil and gas in the Exploration and Production segment more than offset lower working capital requirements in the Utility and Energy Marketing segments due to falling gas prices. Oil and gas prices were down significantly in the Exploration and Production segment and higher production did not compensate for the decrease in prices.

Investing Cash Flow.

Expenditures for Long-Lived Assets
Expenditures for long-lived assets include additions to property, plant and equipment (capital expenditures) and investments in corporations (stock acquisitions) or partnerships, net of any cash acquired.

      The Company's expenditures for long-lived assets totaled $109.7 million during the six months ended March 31, 2002. The table below presents these expenditures:

------------------------------------------------------------- ----------------------- -----------------------
Six Months Ended March 31, 2002
(in millions of dollars)
-------------------------------------- ---------------------- ----------------------- -----------------------
Investments in Total
Capital Corporations or Expenditures for
Expenditures Partnerships Long-Lived Assets
-------------------------------------- ---------------------- ----------------------- -----------------------
Utility 22.0 - 22.0
Pipeline and Storage 12.1 0.4 12.5
Exploration and Production 69.0 - 69.0
International 2.7 - 2.7
Timber 3.5 - 3.5
Energy Marketing - - -
All Other - - -
-------------------------------------- ---------------------- ----------------------- -----------------------
109.3 0.4 109.7
-------------------------------------- ---------------------- ----------------------- -----------------------

Utility
The majority of the Utility capital expenditures were made for replacement of mains and main extensions, as well as for the replacement of service lines.

Pipeline and Storage
The majority of the Pipeline and Storage capital expenditures were made for additions, improvements, and replacements to this segment's transmission and storage systems.

      During the six months ended March 31, 2002, SIP made an additional $383,000 investment in Independence Pipeline Company (Independence). SIP's total investment through March 31, 2002 was $15.0 million. The investment represents a one-third partnership interest in Independence. The investment has been financed with short-term borrowings. Independence was formed to build the Independence Pipeline, a 400-mile natural gas pipeline from Defiance, Ohio to Leidy, Pennsylvania at an estimated cost of about $700 million.* If the Independence Pipeline is not constructed, SIP's share of the developmental costs (including SIP's investment in Independence) is estimated not to exceed $15.5 million.* This amount represents the estimated maximum pre tax charge to earnings that would be recorded if the project is not constructed.*

      In November 2001, Independence filed a partial implementation plan as well as a request to extend the due date for a complete implementation plan to November 2003 and the in-service date to November 2004. To date, FERC has not responded to the partial implementation plan or the request for extension. If FERC were not to grant these extensions, it would be probable that Independence's current FERC authorization would expire before the project could be built.* Regardless of what FERC may do, each owner of Independence is able to withdraw from the partnership at any time. The Company is uncertain about the future of the Independence project; in the event of significant negative developments, it is reasonably likely that the Company would record a pre tax charge to earnings estimated not to exceed $15.5 million.*

      For a further discussion of SIP's investment in Independence, refer to "Investing Cash Flow" under "Capital Resources and Liquidity" in Item 7 of the Company's 2001 Form 10-K. Other than those matters discussed above, there have been no subsequent material changes regarding this investment.

             The Company also continues to explore various opportunities to participate in transporting gas to the Northeast, either through Supply Corporation’s system or in partnership with others. This includes the proposed Northwinds Pipeline that the Company and TransCanada PipeLines Limited are pursuing. This project would be a 215-mile, 30-inch natural gas pipeline that would originate in Kirkwall, Ontario, cross into the United States near Buffalo, New York and follow a southerly route to its destination in the Ellisburg-Leidy area in Pennsylvania.* The initial capacity of the pipeline would be approximately 500 million cubic feet of natural gas per day with the estimated cost of the pipeline ranging from $350-$400 million.* At March 31, 2002, the Company had not incurred any material costs associated with this project.

Exploration and Production
The Exploration and Production segment capital expenditures for the six months ended March 31, 2002 included approximately $52.6 million for on-shore drilling construction and recompletion costs for wells located in Louisiana, Texas, California and Canada as well as onshore geological and geophysical costs and fixed asset purchases. Of the $52.6 million amount, $18.6 million was spent on the Exploration and Production segment’s Canadian properties. The Exploration and Production segment’s capital expenditures also included approximately $16.4 million for Seneca’s offshore program in the Gulf of Mexico, including offshore drilling expenditures, offshore construction, lease acquisition costs and geological and geophysical expenditures.

      The Company anticipates reducing the Exploration and Production segment's 2002 and 2003 capital expenditures from $141.0 million and $117.2 million, respectively, as previously disclosed in the Company's 2001 Form 10-K, to $92 million and $100 million, respectively, for 2002 and 2003.*

      During the six months ended March 31, 2002, the Exploration and Production segment sold oil and gas properties amounting to $14.1 million. Most of these properties were in the Gulf Coast region. These proceeds were recorded as a reduction of property, plant and equipment and are reflected in Other Investing Activities on the Consolidated Statement of Cash Flows.

International
The majority of the International segment capital expenditures were concentrated in improvements and replacements within the district heating and power generation plants in the Czech Republic.

Timber
The majority of the Timber segment capital expenditures were made for purchases of land and timber for Seneca’s timber operations, as well as equipment for Highland’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.

In November 2001, the Company issued $150.0 million of 6.70% medium-term notes due in November 2011. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $149.0 million. The proceeds of this debt issuance were used to reduce short-term debt.

      Consolidated short-term debt decreased $192.0 million during the first six months of 2002 primarily due to the November 2001 medium-term note issuance discussed above. The Company continues to consider short-term debt an important source of cash for temporarily financing capital expenditures and investments in corporations and/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. The Company has Securities and Exchange Commission (SEC) authorization under the Public Utility Holding Company Act of 1935, to borrow and have outstanding as much as $750.0 million of short-term debt at any time through December 31, 2002. The total amount available to be issued under the Company's commercial paper program is $200.0 million. The commercial paper program is backed up by a $200.0 million 364-day credit facility, which is available as long as the Company maintains an investment grade credit rating. With regards to the Company's short-term notes payable to banks, the Company utilizes uncommitted bank lines of credit aggregating to $530.0 million. These uncommitted bank lines of credit are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed.* If a downgrade in the Company's commercial paper program credit ratings were to occur, access to the commercial paper markets might not be possible. However, the Company could borrow under its uncommitted bank lines of credit or seek other liquidity sources, including cash provided by operations. At March 31, 2002, the Company had outstanding short-term notes payable to banks and commercial paper of $109.1 million and $188.6 million, respectively.

      The Company also has authorization from the SEC, under the Public Utility Holding Company Act of 1935, 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 million of debt and equity securities under the Securities Act of 1933. Of the $625 million that was originally registered, the Company currently has $125.0 million of securities available to be issued under the Securities Act of 1933.

      The Company's indenture contains covenants which limit, among other things, the incurrence of funded debt. Funded debt basically is indebtedness maturing more than one year after the date of issuance. Because of the impairment of oil and gas producing properties recorded by the Company in September 2001, the earnings impact of warm weather and low commodity prices in the six months ended March 31, 2002, and higher long-term debt interest requirements stemming from the November 2001 medium-term note issuance discussed above, these covenants will restrict the Company's ability to issue additional funded debt, with certain exceptions, until at least the first quarter of fiscal 2003.* This will not, however, limit the Company's issuance of funded debt to refund existing funded debt. Also, these covenants will not limit the Company's ability to utilize short-term debt, which is discussed above.

      The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating and capital leases. The Company's consolidated subsidiaries have operating leases, the majority of which are with the Utility and the Pipeline and Storage segments, having a remaining lease commitment of approximately $35.7 million. These leases have been entered into for the use of vehicles, construction tools, meters, computer equipment and other items and are accounted for as operating leases. The Company's minority owned entities, which are accounted for under the equity method, have capital leases of electric generating equipment having a remaining lease

commitment of approximately $10.4 million. The Company has guaranteed 50% or $5.2 million of these capital lease commitments.

      The following table summarizes the Company's expected future contractual cash obligations as of March 31, 2002, and the twelve-month periods over which they occur:

- -------------------------------------- -----------------------------------------------------------------------------------------
Payments by Expected Maturity Dates
-----------------------------------------------------------------------------------------
(Millions of Dollars) 2002-2003 2003-2004 2004-2005 2005-2006 2006-2007 Thereafter Total
- -------------------------------------- ------------ ------------ ----------- ----------- ----------- -------------- ------------
Long-Term Debt $ 257.5 $ 134.2 $ 107.9 $ 4.0 $ 1.8 $ 799.2 $1,304.6
Short-Term Bank Notes 109.1 - - - - - 109.1
Commercial Paper 188.6 - - - - - 188.6
Operating Lease Commitments 9.0 7.0 5.5 4.2 3.0 7.0 35.7
Capital Lease Commitments 1.2 1.2 1.3 1.5 1.3 3.9 10.4
- -------------------------------------- ------------ ------------ ----------- ----------- ----------- -------------- ------------

      The Company has made certain guarantees on behalf of its subsidiaries. The guarantees relate primarily to: (i) obligations under derivative financial instruments, which are included on the consolidated balance sheet in accordance with SFAS 133 (see Item 2, MD&A under the headings "Critical Accounting Policies" and "Accounting for Derivative Financial Instruments"); (ii) Utility segment obligations to purchase gas to be resold in its regulated business in accordance with established regulatory mechanisms to pass through the cost of that gas to its retail customers; (iii) NFR or Upstate obligations to purchase gas or to purchase gas transportation/storage services where the amounts actually due on those obligations each month are included on the consolidated balance sheet as a current liability; and (iv) other obligations which are reflected on the consolidated balance sheet. The Company believes that the chance it would be required to make payments under the guarantees is slight, and therefore has not included them on the table above.*

      The amounts and timing of the issuance and sale of debt and/or equity securities will depend on market conditions, indenture requirements, regulatory authorizations, and the capital 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

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

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

and Multiple Intervenors (an advocate for large commercial and industrial customers) that established 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 customers. The Agreement provided further that the Company and interested parties would resume discussions to address the NYPSC’s competition initiatives, including changes to “customer choice” transportation services, among other things. Those discussions commenced in November 2000 and produced an interim “Joint Proposal,” or settlement agreement, addressing several discrete issues of interest to the parties and the NYPSC. In an order issued on May 30, 2001, the NYPSC adopted the parties’ Joint Proposal. As recommended by the parties, the Joint Proposal modified Distribution Corporation’s operations relating to transportation services and transactions with marketers and producers of indigenous natural gas. Under the Joint Proposal, the parties also agreed to continue negotiations to implement additional features of the NYPSC’s restructuring initiative (described below). Those confidential discussions, dubbed “Phase III negotiations,” concluded on January 18, 2002 when the parties executed a “Comprehensive Joint Proposal”. The Comprehensive Joint Proposal proposes a number of changes to Distribution Corporation’s rates and services through September 30, 2003, including the following:

• Modification of transportation balancing services and upstream capacity rules for the benefit of marketers and to preserve reliability;
• A customer funded “back-out credit” provided to marketers (or marketer customers) to reduce marketer costs and thereby promote competition;
• Provisions to promote increased marketer usage of indigenous natural gas;
• An expanded low-income program that provides arrearage forgiveness and a discounted rate for up to 30,000 customers;
• Increased customer funding to offset the cost of uncollectibles;
• Unbundling of gas costs from delivery rates; and
• Mechanisms for recovery of stranded pipeline and unbundling costs.

      The Comprehensive Joint Proposal was filed with the NYPSC on January 23, 2002 and approved with immaterial modifications on April 18, 2002, effective May 1, 2002. Distribution Corporation's base rates will not be materially changed under the Comprehensive Joint Proposal, which is not intended to modify the rate and revenue requirements established in the Agreement described above.

      For a complete discussion of New York Jurisdiction Rate Matters, refer to "New York Jurisdiction" under "Rate Matters" in Item 7 of the Company's 2001 Form 10-K. Other than those matters discussed above, there have been no subsequent material changes regarding rate matters in the New York Jurisdiction.

Pennsylvania Jurisdiction

Distribution Corporation currently does not have a rate case on file with the Pennsylvania Public Utility Commission. Management will continue to monitor its financial position in the Pennsylvania jurisdiction to determine the necessity of filing a rate case in the future.

      For a complete discussion of Pennsylvania Jurisdiction Rate Matters, refer to "Pennsylvania Jurisdiction" under "Rate Matters" in Item 7 of the Company's 2001 Form 10-K. There have been no subsequent material changes regarding rate matters in the Pennsylvania Jurisdiction.

      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

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. 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. At March 31, 2002, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be in the range of $5.3 million to $6.3 million.* The minimum liability of $5.3 million has been recorded on the Consolidated Balance Sheet at March 31, 2002. Other than discussed in Note H of the 2001 Form 10-K (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.*

      For further discussion refer to Note H - Commitments and Contingencies under the heading "Environmental Matters" in Item 8 of the Company's 2001 Form 10-K.

Safe Harbor for Forward-Looking Statements. The Company is including the following cautionary statement in this Form 10-Q to make applicable and take advantage of the safe harbor provisions of Section 21E of the Securities Exchange Act of 1934 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, 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 without limitation those which are designated with an asterisk (“*”), 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 statements:

1. Changes in economic conditions, including economic disruptions caused by terrorist activities;
   
   
2. Changes in demographic patterns and weather conditions;
   
   
3. Changes in the availability and/or price of natural gas and oil;
   
   
4. Inability to obtain new customers or retain existing ones;
   
   
5. Significant changes in competitive factors affecting the Company;
   
   
6. Governmental/regulatory actions, initiatives and proceedings, including those affecting acquisitions, financings, allowed rates of return, industry and rate structure, franchise renewal, and environmental/safety requirements;
   
   
7. Unanticipated impacts of restructuring initiatives in the natural gas and electric industries;
   
   
8. Significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays or changes in project costs;
   
   
9. The nature and projected profitability of pending and potential projects and other investments;
   
   
10. Occurrences affecting the Company's ability to obtain funds from operations, debt or equity to finance needed capital expenditures and other investments;
    
    
11. Uncertainty of oil and gas reserve estimates;
    
    
12. Ability to successfully identify and finance oil and gas property acquisitions and ability to operate and integrate existing and any subsequently acquired business or properties;
    
    
13. Ability to successfully identify, drill for and produce economically viable natural gas and oil reserves;
    
    
14. Significant changes from expectations in the Company's actual production levels for natural gas or oil;
    
    
15. Changes in the availability and/or price of derivative financial instruments;
    
    
16. Changes in the price of natural gas or oil and the related effect given the accounting treatment or valuation of related derivative financial instruments;
    
    
17. Inability of the various counterparties to meet their obligations with respect to the Company's financial instruments;
    
    
18. Regarding foreign operations, changes in trade and monetary policies, inflation and exchange rates, taxes, operating conditions, laws and regulations related to foreign operations, and political and governmental changes;
    
    
19. Significant changes in tax rates or policies or in rates of inflation or interest;
    
    
20. Significant changes in the Company's relationship with its employees or contractors and the potential adverse effects if labor disputes, grievances or shortages were to occur; or
    
    

21. Changes in accounting principles or the application of such principles to the Company.

      The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.

Refer to the “Market Risk Sensitive Instruments” section in Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations.

For a discussion of various environmental matters, refer to Part I, Item 1 at Note 4 and Part I, Item 2 – MD&A of this report under the heading “Other Matters.”

      On January 2, 2002, the Company issued a total of 1,680 unregistered shares of Company common stock to the seven non-employee directors then sitting on the Board of Directors, 240 shares to each such director. Also on January 2, 2002, Bernard J. Kennedy retired as Chairman of the Board. Mr. Kennedy remained a director of the Company, and on January 3, 2002, the Company issued to him 235 unregistered shares of Company common stock. All of these unregistered shares issued on January 2, 2002 and January 3, 2002 were issued as partial consideration for the directors' services during the quarter ended March 31, 2002, pursuant to the Company's Retainer Policy for Non-Employee Directors. These transactions were exempt from registration by Section 4(2) of the Securities Act of 1933 as transactions not involving a public offering.

      The Annual Meeting of Shareholders of National Fuel Gas Company was held on February 21, 2002. At that meeting, the shareholders elected directors, appointed independent accountants, approved an amended and restated compensation plan, rejected a shareholder proposal to limit certain executive compensation awards, and rejected a shareholder proposal to create a committee to address alleged discrimination in employment.

The total votes were as follows:
Against Broker
For Or Withheld Abstain Non- Votes
--- ----------- ------- ----------
(i) Election of directors to
serve for a three-year
term:
- Robert T. Brady 66,313,821 1,934,425 - -
- William J. Hill 66,255,565 1,992,681 - -
- Bernard J. Kennedy 65,637,281 2,610,965 - -

            Directors whose term of office continued after the meeting:

            Term expiring in 2003: Eugene T. Mann, George L. Mazanec, and John F. Riordan.

            Term expiring in 2004: Philip C. Ackerman, James V. Glynn and Bernard S. Lee.

Against Broker
For Or Withheld Abstain Non- Votes
--- ----------- ------- ----------
(ii) Appointment of
PricewaterhouseCoopers
LLP as independent
accountants 66,675,888 1,141,716 430,642 -
(iii) Approval of the amended
and restated Annual At
Risk Compensation
Incentive Program 54,811,858 12,373,925 1,062,463 -
(iv) Adoption of shareholder
proposal to limit certain
executive compensation
awards 7,094,742 46,682,846 1,418,438 13,052,220
(v) Adoption of shareholder
proposal to create
committee to address
alleged discrimination
in employment 3,843,968 47,426,672 3,927,881 13,049,725

(a) Exhibits
ExhibitNumber Description of Exhibit(12) Statements regarding Computation of Ratios:
Ratio of Earnings to Fixed Charges for the
Twelve Months Ended March 31, 2002 and the
Fiscal Years Ended September 30, 1997 through
2001.
(99) National Fuel Gas Company Consolidated
Statement of Income for the Twelve Months
Ended March 31, 2002 and 2001.

(b) Reports on Form 8-K
On January 25, 2002, the Company filed a
Form 8-K regarding a press release issued
by the Company concerning earnings for the
first quarter ended December 31,
2001. The report included partial financial
statements and other financial
information.

SIGNATURE

        Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

NATIONAL FUEL GAS COMPANY
-------------------------
(Registrant)
/s/Joseph P. Pawlowski
------------------------------
Joseph P. Pawlowski
Treasurer and
Principal Accounting Officer

Exhibit 12 Statements regarding Computation of Ratios:
Ratio of Earnings to Fixed Charges for the Twelve
Months Ended March 31, 2002 and the Fiscal Years Ended
September 30, 1997 through 2001.
Exhibit 99 National Fuel Gas Company Consolidated Statement of
Income for the Twelve Months Ended March 31, 2002
and 2001.