Utility Throughput
- -----------------------------------------------------------------------------------------------------------------------
                                           Three Months Ended                           Nine Months Ended
                                                June 30,                                    June 30,
- -----------------------------------------------------------------------------------------------------------------------
                                                                  Increase/                                   Increase/
(MMcf)                                 2002           2001       (Decrease)       2002            2001       (Decrease)
- -----------------------------------------------------------------------------------------------------------------------
  Retail Sales:
    Residential                      12,747         10,643          2,104       60,338          68,491        (8,153)
    Commercial                        2,199          1,781            418       10,794          13,081        (2,287)
    Industrial                          866            809             57        2,458           3,468        (1,010)
- -----------------------------------------------------------------------------------------------------------------------
                                     15,812         13,233          2,579       73,590          85,040       (11,450)
- -----------------------------------------------------------------------------------------------------------------------
  Off-System Sales                    5,279          2,493           2,786      16,879           9,977         6,902
  Transportation                     15,482         14,903             579      51,991          56,267        (4,276)
- -----------------------------------------------------------------------------------------------------------------------
                                     36,573         30,629           5,944     142,460         151,284        (8,824)
- -----------------------------------------------------------------------------------------------------------------------

Operating revenues for the Utility segment decreased $24.1 million for the quarter ended June 30, 2002 as compared with the quarter ended June 30, 2001. The decrease for the quarter was primarily the result of a decrease in the average cost of purchased gas ($4.59 and $6.39 per thousand cubic feet (Mcf) during the quarters ended June 30, 2002 and 2001, respectively), offset partly by higher retail, off-system sales and transportation volumes, as shown in the table above. Colder weather, as shown in the table below, was the major factor for the increase in retail sales and transportation volumes. Greater volumes of off-system sales more than offset lower gas prices resulting in an increase in off-system sales revenues. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal.

        Operating revenues for the Utility segment decreased $436.3 million for the nine months ended June 30, 2002 as compared with the nine months ended June 30, 2001. The decrease for the nine months ended June 30, 2002 was primarily the result of a decrease in retail sales volumes, as shown above, a decrease in the average cost of purchased gas ($4.64 and $7.84 per MCF for the nine months ended June 30, 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.

        For both the quarter and nine months ended June 30, 2002, as compared with the quarter and nine months ended June 30, 2001, the decreases in other revenues primarily reflects an estimated refund provision of $1.8 million and $5.3 million, respectively, recorded in the Utility’s New York jurisdiction under an earnings sharing mechanism. This earnings sharing mechanism, which is in accordance with the three year rate settlement reached with the NYPSC that went into effect October 1, 2000 (New York Rate Settlement), requires the utility to share with customers 50% of earnings above a predetermined amount. Refund provisions were not recorded in the quarter or nine months ended June 30, 2001.

        Partly offsetting the decrease to revenue for the nine months ended June 30, 2002, as compared with the nine months ended June 30, 2001, was the positive impact of a lower bill credit in the Utility’s New York jurisdiction. In connection with the New York rate settlement, 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 June 30, 2002 were $5.7 million, a decrease of $0.4 million when compared with the quarter ended June 30, 2001. However, the earnings for the quarter ended June 30, 2001 included $0.5 million of non-recurring earnings associated with stock appreciation rights. Exclusive of this item, earnings were flat. Slightly higher operating expenses and the refund provision of $1.8 million ($1.2 million after tax) were largely offset by the impact of colder weather, which in the Pennsylvania jurisdiction was 25.3% colder than the quarter ended June 30, 2001. The impact of weather variations in the New York jurisdiction is mitigated by that jurisdiction's 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 April and May of 2002, the WNC resulted in a benefit to customers of $0.2 million after tax since it was colder than normal. For April and May of 2001, the WNC preserved earnings of $1.4 million after tax since it was warmer than normal. For the month of June 2002 compared to June 2001, both of which are outside the WNC period, the Utility segment's New York jurisdiction experienced a slight increase to earnings of $0.4 million since June 2002 was colder than June 2001. The Pennsylvania division has no WNC.

        The Utility segment's earnings for the nine months ended June 30, 2002 were $59.5 million, a decrease of $4.4 million when compared with the earnings of $63.9 million for the nine months ended June 30, 2001. However, the earnings for the nine months ended June 30, 2001 included $1.2 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. Lower normalized usage per account (normalized usage excludes the impact of weather on consumption) across the Utility's service territory due to a downturn in the economy and weather, which in the Pennsylvania jurisdiction was approximately 14.6% warmer than the nine months ended June 30, 2001, significantly decreased earnings in 2002. Also contributing to the decrease was the refund provision of $5.3 million ($3.4 million after tax) discussed above. The impact of the lower bill credit, discussed above, partly offset these decreases. In the New York jurisdiction, the impact of weather variations was largely mitigated by the WNC. For the October through May period of 2002 and 2001, the WNC preserved earnings of $9.9 million and $1.2 million after tax, respectively, since it was warmer than normal. For the month of June 2002 compared to June 2001, there was a slight increase to earnings as previously discussed.

Degree Days
- ----------------------------------------------------------------------------------------------------------------------
                                                                                             Percent (Warmer)
Three Months Ended                                                                              Colder Than
                                                                                      --------------------------------
June 30                               Normal          2002              2001               Normal        Prior Year
- ----------------------------------------------------------------------------------------------------------------------
Buffalo                                 968           1,039              779                 7.3             33.4
Erie                                    868             926              739                 6.7             25.3
- ----------------------------------------------------------------------------------------------------------------------
Nine Months Ended
June 30
- ----------------------------------------------------------------------------------------------------------------------
Buffalo                                6,649          5,753             6,503               (13.5)          (11.5)
Erie                                   6,047          5,283             6,183               (12.6)          (14.6)
- ----------------------------------------------------------------------------------------------------------------------

Pipeline and Storage

Pipeline and Storage Operating Revenues
- -------------------------------------------------------------------------------------------------------------------------
                                               Three Months Ended                         Nine Months Ended
                                                    June 30,                                  June 30,
- -------------------------------------------------------------------------------------------------------------------------
                                                                    Increase/                                   Increase/
(Thousands)                                2002         2001       (Decrease)         2002          2001       (Decrease)
- -------------------------------------------------------------------------------------------------------------------------
Firm Transportation                     $21,782      $22,626         $(844)         $66,875     $ 69,543       $(2,668)
Interruptible Transportation                941        1,067          (126)           2,448        2,707          (259)
- -------------------------------------------------------------------------------------------------------------------------
                                         22,723       23,693          (970)          69,323       72,250        (2,927)
- -------------------------------------------------------------------------------------------------------------------------
Firm Storage Service                     16,217       15,591           626           47,234       46,172         1,062
Interruptible Storage Service                 -          445          (445)               7          661          (654)
- -------------------------------------------------------------------------------------------------------------------------
                                         16,217       16,036           181           47,241       46,833           408
- -------------------------------------------------------------------------------------------------------------------------
Other                                     2,476        5,650        (3,174)           9,885       13,602        (3,717)
- -------------------------------------------------------------------------------------------------------------------------
                                        $41,416      $45,379       $(3,963)        $126,449     $132,685       $(6,236)
- -------------------------------------------------------------------------------------------------------------------------


Pipeline and Storage Throughput
- -------------------------------------------------------------------------------------------------------------------------
                                               Three Months Ended                         Nine Months Ended
                                                    June 30,                                  June 30,
- -------------------------------------------------------------------------------------------------------------------------
                                                                    Increase/                                   Increase/
(MMcf)                                     2002         2001       (Decrease)          2002         2001       (Decrease)
- -------------------------------------------------------------------------------------------------------------------------
Firm Transportation                      63,504       52,840         10,664         234,942      248,036       (13,094)
Interruptible Transportation              1,384        6,202         (4,818)          5,251       14,820        (9,569)
- -------------------------------------------------------------------------------------------------------------------------
                                         64,888       59,042          5,846         240,193      262,856       (22,663)
- -------------------------------------------------------------------------------------------------------------------------

Operating revenues for the Pipeline and Storage segment decreased $4.0 million and $6.2 million, respectively, for the quarter and nine months ended June 30, 2002 as compared with the quarter and nine months ended June 30, 2001. For the quarter ended June 30, 2002, the decrease can be attributed primarily to a $1.0 million decrease in transportation revenues, as shown in the table above, and a $3.0 million decrease in revenues from unbundled pipeline sales and open access transportation included in other revenues in the table above. For the nine months ended June 30, 2002, the decrease can be attributed primarily to a $2.9 million decrease in transportation revenues, as shown in the table above, and a $1.9 million decrease in cashout revenues included in other revenues in the table above. Cashout revenues represent a cash resolution of a gas imbalance whereby a customer pays Supply Corporation for gas the customer receives in excess of amounts delivered into Supply Corporation’s system by the customer’s shipper. Cashout revenues are offset by purchased gas expense. The decrease in transportation revenues for the quarter and nine month periods primarily reflects lower gathering rates (the rates charged by Supply Corporation to its transportation customers to move gas from a third-party well site or nearby meter to Supply Corporation’s transmission pipelines for delivery) as a result of a settlement with the FERC. However, this rate decrease is largely offset by a reduction in amortization expense, thus having little impact on net income. While transportation volumes increased during the quarter and decreased during the nine month period, 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 loss for the quarter ended June 30, 2002 was $0.5 million, a decrease of $13.5 million when compared with earnings of $13.0 million for the quarter ended June 30, 2001. However, the loss for the quarter ended June 30, 2002 included a $9.9 million non-recurring after tax expense ($15.2 million pre tax) associated with the impairment of the Company's investment in the Independence Pipeline project and the earnings for the quarter ended June 30, 2001 included $0.7 million of non-recurring earnings associated with stock appreciation rights. Exclusive of these two items, the decrease in earnings was $2.9 million. Lower revenues from unbundled pipeline sales and open access transportation and slightly higher operation and maintenance expense contributed to this earnings decrease. For further discussion of the impairment of the Company's investment in the Independence Pipeline, refer to Capital Resources and Liquidity, Investing Cash Flow, under the heading "Pipeline and Storage" in Item 2 of this report. The impairment is recorded on the Consolidated Statement of Income as Impairment of Investment in Partnership.

        The Pipeline and Storage segment's earnings for the nine months ended June 30, 2002 were $19.3 million, a decrease of $15.0 million when compared with earnings of $34.3 million for the nine months ended June 30, 2001. However, as discussed above, the earnings for the nine months ended June 30, 2002 included a $9.9 million non-recurring after tax expense associated with the impairment of the Company's investment in the Independence Pipeline project. Earnings for the nine months ended June 30, 2001 included $1.7 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 four items, there was a decrease in earnings of $1.9 million. This decrease can be attributed primarily to higher operation and maintenance expense.

Exploration and Production

Exploration and Production Operating Revenues
- ----------------------------------------------------------------------------------------------------------------------
                                              Three Months Ended                        Nine Months Ended
                                                   June 30,                                 June 30,
- ----------------------------------------------------------------------------------------------------------------------
                                                                Increase/                                Increase/
(Thousands)                               2002         2001     (Decrease)          2002         2001    (Decrease)
- ----------------------------------------------------------------------------------------------------------------------
  Gas (after Hedging)                  $39,335      $46,632       $(7,297)      $111,244     $127,188      $(15,944)
  Oil (after Hedging)                   43,823       42,484         1,339        112,633      125,735       (13,102)
  Gas Processing Plant                   4,356       11,451        (7,095)        11,918       33,845       (21,927)
  Other                                    578        5,249         4,671)         6,554       18,753       (12,199)
  Intrasegment Elimination (1)          (4,013)     (14,096)       10,083        (10,066)     (38,755)       28,689
- ----------------------------------------------------------------------------------------------------------------------
                                       $84,079      $91,720       $(7,641)      $232,283     $266,766      $(34,483)
- ----------------------------------------------------------------------------------------------------------------------

⁽¹⁾ 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                       Nine Months Ended
                                                        June 30,                                 June 30,
- --------------------------------------------------------------------------------------------------------------------------
                                                                       Increase/                                Increase/
                                              2002         2001       (Decrease)        2002         2001      (Decrease)
- --------------------------------------------------------------------------------------------------------------------------
Gas Production (MMcf)
  Gulf Coast                                 6,779        7,665            (886)      19,576       21,080         (1,504)
  West Coast                                 1,211        1,078             133        3,654        3,176            478
  Appalachia                                 1,108          968             140        3,309        3,074            235
  Canada                                     1,447          111           1,336        5,088          341          4,747
- --------------------------------------------------------------------------------------------------------------------------
                                            10,545        9,822             723       31,627       27,671          3,956
- --------------------------------------------------------------------------------------------------------------------------
Oil Production (thousands of barrels)
  Gulf Coast                                   519          554             (35)       1,411        1,378             33
  West Coast                                   759          696              63        2,255        2,155            100
  Appalachia                                     2            2               -            4            5             (1)
  Canada                                       703          757             (54)       2,191        2,275            (84)
- --------------------------------------------------------------------------------------------------------------------------
                                             1,983        2,009             (26)       5,861        5,813             48
- --------------------------------------------------------------------------------------------------------------------------

Average Prices
- --------------------------------------------------------------------------------------------------------------------------
                                                   Three Months Ended                       Nine Months Ended
                                                        June 30,                                 June 30,
- --------------------------------------------------------------------------------------------------------------------------
                                                                       Increase/                                 Increase/
                                               2002        2001       (Decrease)        2002         2001       (Decrease)
- --------------------------------------------------------------------------------------------------------------------------
Average Gas Price/Mcf
  Gulf Coast                                  $3.37       $4.57         $(1.20)        $2.74        $5.84        $(3.10)
  West Coast                                  $3.35      $13.32         $(9.97)        $2.68       $12.59        $(9.91)
  Appalachia                                  $3.75       $5.65         $(1.90)        $3.75        $5.27        $(1.52)
  Canada                                      $3.04       $4.08         $(1.04)        $2.32        $4.67        $(2.35)
  Weighted Average                            $3.36       $5.63         $(2.27)        $2.77        $6.54        $(3.77)
  Weighted Average After
     Hedging                                  $3.73       $4.75         $(1.02)        $3.52        $4.60        $(1.08)

Average Oil Price/bbl
  Gulf Coast                                 $24.92      $26.49         $(1.57)       $21.59       $28.33        $(6.74)
  West Coast                                 $22.56      $23.33         $(0.77)       $18.37       $24.73        $(6.36)
  Appalachia                                 $23.31      $26.85         $(3.54)       $22.99       $29.15        $(6.16)
  Canada                                     $23.24      $23.92         $(0.68)       $18.28       $25.07        $(6.79)
  Weighted Average                           $23.42      $24.43         $(1.01)       $19.12       $25.72        $(6.60)
  Weighted Average After
     Hedging                                 $22.10      $21.15           $0.95       $19.22       $21.63        $(2.41)
- --------------------------------------------------------------------------------------------------------------------------

Operating revenues for the Exploration and Production segment decreased $7.6 million for the quarter ended June 30, 2002 as compared with the quarter ended June 30, 2001. Oil production revenue after hedging increased $1.3 million due to higher weighted average prices after hedging ($0.95 per bbl), offset slightly by a 1% decrease in oil production. Gas production revenue after hedging decreased $7.3 million due primarily to a decrease in the weighted average price of gas after hedging ($1.02 per Mcf), offset slightly by a 7% increase in natural gas production. The increase in gas production is 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 $7.1 million due to significantly lower gas prices (because there is a similar decrease in purchased gas expense, the impact on earnings is insignificant). Other revenues decreased $4.7 million largely due to non-recurring mark-to-market gains on derivative financial instruments that were recorded in the quarter ended June 30, 2001.

        Operating revenues for the Exploration and Production segment decreased $34.5 million for the nine months ended June 30, 2002 as compared with the nine months ended June 30, 2001. Oil production revenue after hedging decreased $13.1 million due to a $2.41 per bbl decrease in the weighted average price of oil after hedging. Gas production revenue after hedging, decreased $15.9 million. Decreases in the weighted average price after hedging ($1.08 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 $21.9 million due to significantly lower gas prices. Other revenues decreased $12.2 million largely due to non-recurring mark-to-market gains on derivative financial instruments that were recorded in the nine months ended June 30, 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 June 30, 2002 were $11.2 million, a decrease of $8.7 million when compared with earnings of $19.9 million for the quarter ended June 30, 2001. As discussed above, a decrease in the weighted average price of natural gas after hedging ($1.02 per Mcf) was a major factor in the earnings decrease. Higher workover expenses in the Gulf Coast region, the most significant of which occurred on Eugene Island Block 264, also contributed to the earnings decrease.

        The Exploration and Production segment's earnings for the nine months ended June 30, 2002 were $21.4 million, a decrease of $38.1 million when compared with earnings of $59.5 million for the nine months ended June 30, 2001. As discussed above, decreases in the commodity prices of crude oil and natural gas ($2.41 per bbl and $1.08 per Mcf, respectively) were primarily responsible for this earnings decrease. Higher workover expenses in the Gulf Coast region also contributed to the earnings decrease. The major workover expenditures occurred on Vermilion 252 and Eugene Island Block 264.

International

International Operating Revenues
- -------------------------------------------------------------------------------------------------------------------------------
                                                  Three Months Ended                           Nine Months Ended
                                                       June 30,                                    June 30,
- ------------------------------------------------------------------------------------------------------------------------------
                                                                        Increase/                                   Increase/
(Thousands)                                   2002          2001       (Decrease)         2002          2001       (Decrease)
- ------------------------------------------------------------------------------------------------------------------------------

   Heating                                 $10,091       $10,845           $(754)      $59,181       $63,149        $(3,968)
   Electricity                               6,723         5,575           1,148        21,372        21,987           (615)
   Other                                       740           598             142         2,184         1,689            495
- ------------------------------------------------------------------------------------------------------------------------------
                                           $17,554       $17,018            $536       $82,737       $86,825        $(4,088)
- ------------------------------------------------------------------------------------------------------------------------------

International Heating and Electric Volumes
- ------------------------------------------------------------------------------------------------------------------------------
                                                  Three Months Ended                           Nine Months Ended
                                                       June 30,                                    June 30,
- ------------------------------------------------------------------------------------------------------------------------------

                                                                       Increase/                                   Increase/
                                              2002          2001      (Decrease)          2002          2001      (Decrease)
- ------------------------------------------------------------------------------------------------------------------------------

   Heating Sales (Gigajoules) (1)        1,251,064     1,538,739       (287,675)     8,016,670     9,152,522     (1,135,852)
   Electricity Sales
     (megawatt hours)                     238,417       225,112         13,305        789,002       847,042        (58,040)

- -------------------------------------------------------------------------------------------------------------- ---------------
 (1) Gigajoules = one billion joules.  A joule is a unit of energy.

Operating revenues for the International segment increased $0.5 million for the quarter and decreased $4.1 million for the nine months ended June 30, 2002 as compared with the quarter and nine months ended June 30, 2001, respectively. The increase for the quarter ended June 30, 2002 was due primarily to higher electric revenues in the Czech Republic as electric volumes increased 6% over the quarter ended June 30, 2001. United Energy, a.s. (UE), the Company's major district heating and electric generation company in the Czech Republic, sells electricity at the wholesale level to regional electric distribution companies. However, UE competes with the Czech Republic's dominant state-owned wholesale energy producer. UE's electricity rates were lower in the quarter ended June 30, 2002 than they were in the quarter ended June 30, 2001 and it became economical for the distribution companies to purchase more electric power from UE. The decrease in heat revenues for the quarter ended June 30, 2002 compared to the quarter ended June 30, 2001 was largely due to the June 2001 sale of Jablonecka teplarenska a realitni, a.s. (JTR) (a district heating plant which had heating revenues of $1.2 million and $7.1 million, respectively, for the quarter and nine months ended June 30, 2001, and heating volumes of 114,326 gigajoules and 685,137 gigajoules, respectively, for the quarter and nine months ended June 30, 2001). The decrease in revenues for the nine months ended June 30, 2002 compared to the nine months ended June 30, 2001 was largely due to lower heating revenues in the Czech Republic. Warm weather and the sale of JTR contributed to this decrease.

        The International segment's loss for the quarter ended June 30, 2002 was $3.3 million, which was $1.4 million greater than the loss of $1.9 million for the quarter ended June 30, 2001. This can be attributed to higher operation and maintenance expenses, a lower effective tax rate, and a loss in connection with the disposition of Teplarna Kromeriz, which more than offset higher heat and electric margins.

        The International segment's earnings for the nine months ended June 30, 2002 were $1.5 million, a decrease of $1.6 million when compared with earnings of $3.1 million for the nine months ended June 30, 2001. Lower interest expense was more than offset by higher operation and maintenance expenses.

Energy Marketing

Energy Marketing Operating Revenues
- -------------------------------------------------------------------------------------------------------------------------
                                                Three Months Ended                         Nine Months Ended
                                                     June 30,                                   June 30,
- -------------------------------------------------------------------------------------------------------------------------
                                                                      Increase/                                Increase/
(Thousands)                                2002           2001       (Decrease)          2002       2001      (Decrease)
- -------------------------------------------------------------------------------------------------------------------------

Natural Gas (after Hedging)             $42,406        $56,663       $(14,257)       $127,422   $232,392     $(104,970)
Electricity                                   -            349           (349)             -       1,362        (1,362)
Other                                        62             12             50            (33)        830          (863)
- -------------------------------------------------------------------------------------------------------------------------
                                        $42,468        $57,024       $(14,556)       $127,389   $234,584     $(107,195)
- -------------------------------------------------------------------------------------------------------------------------

Energy Marketing Volumes
- -------------------------------------------------------------------------------------------------------------------------
                                                Three Months Ended                         Nine Months Ended
                                                     June 30,                                   June 30,
- -------------------------------------------------------------------------------------------------------------------------
                                                                       Increase/                                Increase/
                                            2002           2001       (Decrease)       2002          2001      (Decrease)
- -------------------------------------------------------------------------------------------------------------------------

Natural Gas - (MMcf)                      8,975          8,794             181      27,950        30,998        (3,048)
- -------------------------------------------------------------------------------------------------------------------------

Operating revenues for the Energy Marketing segment decreased $14.6 million and $107.2 million, respectively, for the quarter and nine months ended June 30, 2002, as compared with the quarter and nine months ended June 30, 2001. These decreases primarily reflect lower gas sales revenue due to the decreased price of natural gas.

Earnings in the Energy Marketing segment increased $5.4 million and $8.0 million, respectively, for the quarter and nine months ended June 30, 2002 as compared with the quarter and nine months ended June 30, 2001. These increases primarily reflect higher margins on gas sales and lower interest and operation and maintenance expenses.

Timber

Timber Operating Revenues
- -------------------------------------------------------------------------------------------------------------------------
                                           Three Months Ended                            Nine Months Ended
                                                June 30,                                     June 30,
- -------------------------------------------------------------------------------------------------------------------------
                                                                  Increase/                                     Increase/
(Thousands)                             2002          2001       (Decrease)          2002          2001        (Decrease)
- -------------------------------------------------------------------------------------------------------------------------

Log Sales                             $5,642        $3,049           $2,593       $16,645       $19,185        $(2,540)
Green Lumber Sales                     1,476         1,326              150         5,114         4,319            795
Kiln Dry Lumber Sales                  4,021         3,394              627        11,159         9,477          1,682
Other                                    925           764              161         1,376         3,338         (1,962)
- -------------------------------------------------------------------------------------------------------------------------
Operating Revenues                   $12,064        $8,533           $3,531       $34,294       $36,319        $(2,025)
- -------------------------------------------------------------------------------------------------------------------------

Timber Board Feet
- -------------------------------------------------------------------------------------------------------------------------
                                           Three Months Ended                            Nine Months Ended
                                                June 30,                                     June 30,
- -------------------------------------------------------------------------------------------------------------------------
                                                                  Increase/                                    Increase/
(Thousands)                             2002          2001       (Decrease)          2002          2001       (Decrease)
- -------------------------------------------------------------------------------------------------------------------------

Log Sales                              1,794         1,764             30           6,221         6,912           (691)
Green Lumber Sales                     3,146         2,744            402           9,812         7,827           1,985
Kiln Dry Lumber Sales                  2,841         2,349            492           7,771         6,602           1,169
- -------------------------------------------------------------------------------------------------------------------------
                                       7,781         6,857            924          23,804        21,341           2,463
- -------------------------------------------------------------------------------------------------------------------------

Operating revenues for the Timber segment increased $3.5 million and decreased $2.0 million, respectively, for the quarter and nine months ended June 30, 2002, as compared with the quarter and nine months ended June 30, 2001. The increase for the quarter can largely be attributed to higher sales of cherry veneer logs which command higher than average margins. When comparing the nine months ended June 30, 2002 to June 30, 2001, operating revenues decreased as weather that was warmer and wetter than normal during the first and second quarters of 2002 hampered the ability to cut and haul logs, specifically cherry veneer. The Company made up for some of this lost revenue through the sale of lower priced lumber. Revenues for the nine month period were also down due to the fact that the nine months ended June 30, 2001 had a $2.8 million gain from the sale of land and standing timber. For the nine months ended June 30, 2002 there was a gain of $0.7 million on the sale of standing timber. These gains are reflected in other revenues in the table above.

        Earnings in the Timber segment increased $0.5 million for the quarter ended June 30, 2002 as compared with the quarter ended June 30, 2001. This increase is due primarily to higher margins resulting from increased sales of cherry veneer logs, as discussed above.

        Earnings in the Timber segment decreased $1.4 million for the nine months ended June 30, 2002 as compared with the nine months ended June 30, 2001. This decrease is due primarily to lower margins resulting from the change in sales mix (i.e., less high margin cherry and more low margin lumber) that resulted from the poor harvesting conditions that existed during the first and second quarters of 2002, as discussed above. This factor, in conjunction with lower gains from the sale of land and standing timber discussed above, accounted for the decrease.

        Corporate and all other operations experienced a loss of $0.6 million for the quarter ended June 30, 2002, a decline of $0.8 million from the earnings of $0.2 million for the quarter ended June 30, 2001. The earnings decrease is largely due to higher interest costs.

        Corporate and all other operations experienced a loss of $1.7 million for the nine months ended June 30, 2002, an improvement of $0.5 million over the loss of $2.2 million for the nine months ended June 30, 2001. The loss for the nine months ended June 30, 2001 included $0.3 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, the Company's wholly-owned subsidiary which is engaged in stored gas trading. Exclusive of these items, earnings decreased $1.7 million largely due to higher interest costs.

        The Company's unconsolidated subsidiaries consist of equity method investments in Seneca Energy II, LLC, (Seneca Energy), Model City Energy, LLC (Model City), and Energy Systems North East, LLC (ESNE). The Company has 50% ownership interests in each of these entities. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties. ESNE generates electricity from an 80-megawatt, combined cycle, natural gas-fired power plant in North East, Pennsylvania. ESNE sells its electricity into the New York power grid. The Company also had a 33-1/3% equity method investment in Independence Pipeline Company which was written off in the quarter ended June 30, 2002, as previously discussed. The Independence write-off of $15.2 million ($9.9 million after tax) is recorded on the Consolidated Statement of Income as Impairment of Investment in Partnership.

        Income (Loss) from unconsolidated subsidiaries decreased $0.7 million for the quarter ended June 30, 2002 compared with the quarter ended June 30, 2001. This decrease can largely be attributed to lower electric generation revenues and higher repair and maintenance expenditures at Seneca Energy and ESNE.

        Income (Loss) from unconsolidated subsidiaries decreased $1.5 million for the nine months ended June 30, 2002 compared with the nine months ended June 30, 2001. This decrease is largely attributable to losses experienced by ESNE during the nine months ended June 30, 2002 of $0.5 million compared to income in the prior year of $0.3 million. ESNE was formed on April 30, 2001 so income for the nine months ended June 30, 2001 did not reflect any of the normal operating losses that ESNE incurs during the fall and winter months. ESNE generates most of its electricity during the spring and summer months when electricity demand peaks for air conditioning requirements. Seneca Energy also experienced an earnings decrease of $0.8 million due to lower electric generation revenues and higher repair and maintenance expenditures on the generating engines. Some repairs were delayed from 2001 to 2002 to enable Seneca Energy to operate more hours while market prices for electricity were higher than normal.

Although variances in Other Income items and Interest Charges are discussed in the earnings discussion by segment above, following is a recap on a consolidated basis:

Other income decreased $0.8 million for the quarter ended June 30, 2002 compared with the quarter ended June 30, 2001. This decrease is due primarily to lower interest income.

        Other income decreased $4.5 million for the nine months ended June 30, 2002 compared with the nine months ended June 30, 2001. This decrease was principally due to a buyout of a long-term transportation contract by a customer in the Pipeline and Storage segment in the prior year.

Interest on long-term debt increased $2.2 million and $7.3 million, respectively, for the quarter and nine months ended June 30, 2002 as compared with the quarter and nine months ended June 30, 2001. These increases can be attributed primarily to higher average amounts of long-term debt outstanding.

        Other interest charges decreased $2.7 million and $11.5 million, respectively, for the quarter and nine months ended June 30, 2002 as compared with the quarter and nine months ended June 30, 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. Cash flow from operations was also used to reduce short-term debt.

The Company’s primary sources of cash during the nine-month period ended June 30, 2002 consisted of cash provided by operating activities and long-term debt. These sources were supplemented by issuances of common stock under the Company’s stock and benefit plans.

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, impairment of investment in partnership, income or loss from unconsolidated subsidiaries net of cash distributions, 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 fiscal 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 fiscal 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 $305.0 million for the nine months ended June 30, 2002, a decrease of $32.1 million compared with $337.1 million provided by operating activities for the nine months ended June 30, 2001. Lower cash receipts from the sale of oil and gas in the Exploration and Production segment more than offset higher margins on gas sales in the Energy Marketing segment. Oil and gas prices were down significantly in the Exploration and Production segment and higher production did not compensate for the decrease in prices.

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 $176.1 million during the nine months ended June 30, 2002. The table below presents these expenditures:

- ----------------------------------------------------------------------------------------------------------------------
Nine Months Ended June 30, 2002
(in millions of dollars)
- ----------------------------------------------------------------------------------------------------------------------
                                                                      Investments in               Total
                                                      Capital          Corporations          Expenditures for
                                                    Expenditures     And Partnerships        Long-Lived Assets
- ----------------------------------------------------------------------------------------------------------------------
Utility                                                $ 35.4               $  -                    $ 35.4
Pipeline and Storage                                     18.2                0.5                      18.7
Exploration and Production                               94.3                  -                      94.3
International                                             3.3                  -                       3.3
Timber                                                   24.4                  -                      24.4
Energy marketing                                            -                  -                         -
All Other                                                   -                  -                         -
- ----------------------------------------------------------------------------------------------------------------------
                                                      $ 175.6              $ 0.5                    $ 176.1
- ----------------------------------------------------------------------------------------------------------------------

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.

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 nine months ended June 30, 2002, SIP made an additional $536,000 investment in Independence Pipeline Company (Independence), bringing SIP's total investment to $15.2 million. In June 2002, Independence submitted a motion to FERC requesting that FERC vacate the

certificate issued to Independence on July 12, 2000 to construct, own and operate the Independence Pipeline. Independence took this action because it had been unable to obtain sufficient customer contracts to proceed with the project. In connection with the filing of the motion by Independence, SIP wrote off its $15.2 million investment in Independence, as previously discussed. FERC formally vacated the certificate in an order issued in July 2002.

        The Company 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 June 30, 2002, the Company had not incurred any material costs associated with this project.

The Exploration and Production segment capital expenditures for the nine months ended June 30, 2002 included approximately $66.4 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 $66.4 million amount, $20.6 million was spent on the Exploration and Production segment’s Canadian properties. The Exploration and Production segment’s capital expenditures also included approximately $27.9 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 2003 capital expenditures from $100.0 million, as previously disclosed in the Company's Form 10-Q for the quarter ending March 31, 2002, to $86.5 million, for 2003.* The Company is reducing its capital expenditures forecast for 2003 in the anticipation of reducing debt.*

        During the nine months ended June 30, 2002, the Exploration and Production segment sold oil and gas properties amounting to $16.8 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.

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.

The majority of the Timber segment capital expenditures were made for the purchase of land and timber rights in Potter County, Pennsylvania in June 2002. The land, consisting of approximately 3,656 acres, was purchased by Seneca from Wending Creek 3656, LLC, an entity controlled by certain members of the John Rigas family for $464,930. A Form 8-K filed by Adelphia Communications Corporation (Adelphia) on June 14, 2002 states that the Rigas family had previously agreed to transfer the land to Adelphia in exchange for a $464,930 reduction in the amount of the Rigas family’s primary co-borrowing obligations, and Seneca paid the purchase price of the land directly to Adelphia. Highland purchased the timber rights associated with the land from ACC Operations, Inc., a wholly owned subsidiary of Adelphia, for $19,535,070. The remaining capital expenditures were for smaller purchases of land and timber as well as 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.*

In August 2002, $97.7 million of the Company’s $100.0 million 6.214% medium-term notes due August 2027 were repaid by the Company at par plus accrued interest. The Company used short-term debt to refund the $97.7 million to the debt holders. The remaining $2.3 million of the original $100.0 million issuance is scheduled to mature in August 2027.

        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 $255.7 million during the first nine months of 2002 primarily due to the November 2001 medium-term note issuance, discussed above, and the use of cash from operations to pay down short-term debt. 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 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 by a $200.0 million 364-day credit facility, which is available as long as the Company maintains an investment grade credit rating. The current credit facility expires on September 11, 2002; and the Company is in the process of renewing such back-up facility. With regards to the Company's short-term notes payable to banks, the Company utilizes uncommitted bank lines of credit aggregating $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 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 June 30, 2002, the Company had outstanding short-term notes payable to banks and commercial paper of $109.9 million and $124.1 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 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'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 nine months ended June 30, 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's indenture also contains certain cross-default provisions wherein the failure by the Company to pay the scheduled interest or principal on its outstanding short-term or long-term debt (if such failure is not cured) could trigger the obligation to re-pay the debt outstanding under said indenture. The Company believes that it has adequate committed credit facilities in place to protect against such defaults.*

        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 $33.2 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 June 30, 2002, and the twelve-month periods over which they occur:

- ------------------------------------------------------------------------------------------------------------------------------
                                                            Payments by Expected Maturity Dates
                               -----------------------------------------------------------------------------------------------

                                     2002-       2003 -       2004 -       2005 -        2006 -
(Millions of Dollars)                2003        2004         2005         2006          2007        Thereafter       Total
- ------------------------------------------------------------------------------------------------------------------------------

Long-Term Debt                    $ 260.0     $ 136.0      $ 107.9        $ 4.7          $ 1.1        $ 799.1       $1,308.8
Short-Term Bank Notes                109.9           -            -            -              -              -          109.9
Commercial Paper                     124.1           -            -            -              -              -          124.1
Operating Lease
   Commitments                         8.6         6.5          5.1          3.8            2.8            6.4           33.2
Capital Lease
   Commitments                         1.2         1.3          1.3          1.6            1.5            3.5           10.4
- ------------------------------------------------------------------------------------------------------------------------------

        The Company has made certain other 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 likelihood it would be required to make payments under the guarantees is remote, and therefore has not included them on the table above.*

        The Company is involved in litigation arising in the normal course of business. Also in the normal course of business, the Company is involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, compliance with regulations, 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 period 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.*

        The Company has a tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) that covers substantially all domestic employees of the Company. The Company has been making contributions to the Retirement Plan over the last several years that equate to the maximum funding requirements of applicable laws and regulations. In light of the dramatic decline in the stock market over the last several months, the Company anticipates that it will continue making maximum funding contributions to the Retirement Plan.* During the nine months ended June 30, 2002, the Company contributed $15.4 million to the Retirement Plan. At some point on or before March 15, 2003, the Company anticipates contributing an additional $20.6 million to the Retirement Plan.* The Company expects that funding of these contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments and/or through short-term borrowings.*

For a complete discussion of market risk sensitive instruments, refer to “Market Risk Sensitive Instruments” in Item 7 of the Company’s 2001 Form 10-K. There have been no subsequent material changes to the Company’s exposure to market risk sensitive instruments.

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 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.

On September 20, 2001, the NYPSC issued an order under which Distribution Corporation was Ordered to Show Cause why an action for penalties up to $19 million should not be commenced against it for alleged violations of consumer protection requirements. According to the NYPSC, the alleged violations may have caused or contributed to the death of an individual in an unheated apartment. On December 3, 2001, Distribution Corporation filed its response (submitted under a seal of confidentiality imposed by the Supreme Court, Erie County designed to protect the personal privacy interests of the deceased individual) and requested that the NYPSC either close (dismiss) the Show Cause proceeding based on the evidence presented in Distribution’s response, or hold administrative evidentiary hearings “to demonstrate that a penalty action is unwarranted.” On July 25, 2002 the NYPSC issued an order granting Distribution Corporation’s request for hearings, and referred the matter to an administrative law judge for scheduling. The Company believes and will continue to vigorously assert that the NYPSC’s allegations lack merit.

        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.

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.

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.

The federal law under which FERC regulates Supply Corporation’s rates, practices, and terms and conditions of service requires, among other things, that Supply Corporation not grant any undue preference or advantage to any person. In March of 2001, FERC staff began a routine audit of Supply Corporation’s practices and dealings with “marketing affiliates,” i.e., other Company subsidiaries which conduct natural gas transportation and/or storage transactions with Supply. On July 11, 2002, FERC adopted an order instituting an investigation directed to Supply Corporation and its natural gas marketing affiliates, under Sections 4 and 5 of the Natural Gas Act and Section 501 of the Natural Gas Policy Act. This is not an investigation into Supply’s currently effective rates, or any energy trading activities, “wash sales,” “round-trip transactions,” sales of electricity into the California market, or other activities that have been the subjects of recent news stories regarding other publicly traded energy companies. The Company does not engage in any such energy trading activities. The stated basis for instituting the investigation is information received during the audit which indicates there may have been violations of FERC regulations, specifically:

Supply Corporation and its affiliates continue to cooperate with FERC staff by providing responses to multiple document requests in connection with this investigation and the preceding audit, and by making individuals available for interviews. The Company believes, based on the information presently known, that neither Supply Corporation nor any affiliate has received any benefit from any technical violations of FERC regulations which may have occurred, and that the ultimate resolution of this proceeding will not materially affect the Company’s operations or financial condition.

The Company is subject to various federal, state and local laws and regulations (including those of the Czech Republic) 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 June 30, 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 $5.2 million to $6.2 million.* The minimum liability of $5.2 million has been recorded on the Consolidated Balance Sheet at June 30, 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;
    
    
21. Changes in accounting principles or the application of such principles to the Company;
    
    
22. Changes in laws and regulations to which the Company is subject, including tax, environmental and employment laws and regulations; or
    
    
23. The cost and effects of legal and administrative claims against 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.

        In an action instituted in the New York State Supreme Court, Chautauqua County on January 31, 2000 against Seneca Resources Corporation ("Seneca"), National Fuel Resources, Inc., and "National Fuel Gas Corporation," Donald J. and Margaret Ortel and Brian and Judith Rapp, "individually and on behalf of all those similarly situated," allege, in an amended complaint which adds National Fuel Gas Company as a party defendant (a) that Seneca underpaid royalties due under leases operated by it, and (b) that Seneca's co-defendants (i) fraudulenty participated in and concealed such alleged underpayment, and (ii) induced Seneca's alleged breach of such leases. Plaintiffs seek an accounting, declaratory and related injunctive relief, and compensatory and exemplary damages. Defendants have denied each of plaintiffs' material substantive allegations and set up twenty-five affirmative defenses in separate verified answers.

A motion was made by plaintiffs on July 15, 2002 to certify a class comprising all persons presently and formerly entitled to receive royalties on the sale of natural gas produced and sold from wells operated in New York by Seneca (and its predecessor Empire Exploration, Inc.).

The defendants will respond to that motion by August 19, 2002. Oral argument is scheduled for early September. If a class were certified, discovery would begin on the merits of the claims, and the case eventually tried or settled. The Company believes, based on the information presently known, that the ultimate resolution of this matter will not be material to the consolidated financial condition, results of operations, or cash flow of the Company.* No assurances can be given, however, as to the ultimate outcome of this matter, and it is possible that the outcome could be material to results of operations or cash flow for a particular quarter or annual period.

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

The Company is involved in litigation arising in the normal course of business. Also, in the normal course of business, the Company is involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, compliance with regulations, 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 period of resolution, none of this litigation, and none of these regulatory matters, are expected to have a material adverse effect on the financial condition of the Company.

         On April 1, 2002, the Company issued a total of 1,920 unregistered shares of Company common stock to the eight non-employee directors of the Company, 240 shares to each such director. The shares were issued as partial consideration for the directors' services during the quarter ended June 30, 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.

Item 6.  Exhibits and Reports on Form 8-K

         (a)     Exhibits

                 Exhibit
                 Number             Description of Exhibit

                  (12)              Statements regarding Computation of Ratios:
                                    Ratio of Earnings to Fixed  Charges for the Twelve  Months  Ended June 30, 2002
                                    and the Fiscal Years Ended September 30, 1997 through 2001.

                  (99)              Additional Exhibits:

                   99.1             National Fuel Gas Company Consolidated Statement of Income for the Twelve Months Ended June 30, 2002 and
                                    2001.

               99.2             Written statements of Chief Executive Officer and Principal Financial Officer pursuant
                                    to Section 906 of the Sarbanes-Oxley Act of 2002.

        (b)                        Reports on Form 8-K

                                    On April 30, 2002,  the Company filed a Form 8-K  regarding two press  releases
                                    issued  by  the Company.  The  first  press  release concerned
                                    earnings  for the  quarter  ended  March 31,  2002.  The second  press  release
                                    concerned  projected earnings for the fiscal year ending September 30, 2003 and
                                    projected oil and gas production of the Company's subsidiary,  Seneca Resources
                                    Corporation.  The  report  included  partial  financial  statements  and  other
                                    financial information.

                                    On June 26,  2002,  the  Company  filed a Form 8-K  regarding  a press  release
                                    issued by the Company  concerning its investment in the  Independence  Pipeline
                                    Company.  The report included 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 99.1               National Fuel Gas Company Consolidated Statement of
                           Income for the Twelve Months Ended March 31, 2002
                           and 2001.

Exhibit 99.2               National Fuel Gas Company Statement Pursuant to Section 906
                           of Sarbanes-Oxley Act of 2002.