NATIONAL FUEL GAS COMPANY OVERVIEW
Please note that this overview is a high-level summary of items that are discussed in greater detail in subsequent sections of this report.
The Company is a diversified energy company engaged principally in the production, gathering, transportation, distribution and marketing of natural gas. The Company operates an integrated business, with assets centered in westernNew York andPennsylvania , being utilized for, and benefiting from, the production and transportation of natural gas from the Appalachian basin. Current development activities are focused primarily in theMarcellus andUtica Shale . The common geographic footprint of the Company's subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Appalachian basin to markets inCanada and the easternUnited States . The Company's efforts in this regard are not limited to affiliated projects. The Company has also been designing and building pipeline projects for the transportation of natural gas for non-affiliated natural gas producers in the Appalachian basin. The Company also develops and produces oil reserves, primarily inCalifornia . The Company reports financial results for four business segments. For a discussion of the Company's earnings, refer to the Results of Operations section below. The Company continues to pursue development projects to expand its Pipeline and Storage segment. One project on Empire's system, referred to as theEmpire North Project , would allow for the transportation of 205,000 Dth per day of additional shale supplies from interconnections inTioga County, Pennsylvania , toTransCanada Pipeline , and the TGP 200 Line. Project construction is under way.The Empire North Project has a projected in-service date in the fourth quarter of fiscal 2020 and an estimated cost of approximately$145 million . Another project onSupply Corporation's system, referred to as theFM100 Project , will upgrade a 1950's era pipeline in northwesternPennsylvania and create approximately 330,000 Dth per day of additional transportation capacity onSupply Corporation's system inPennsylvania from a receipt point withNFG Midstream Clermont, LLC inMcKean County, Pennsylvania to theTranscontinental Gas Pipe Line Company, LLC system atLeidy, Pennsylvania .The FM100 Project has a target in-service date in late calendar 2021 and a preliminary cost estimate of approximately$280 million . These and other projects are discussed in more detail in the Capital Resources and Liquidity section that follows. OnFebruary 3, 2017 , the Company, in its Pipeline and Storage segment, receivedFERC approval of a project to move significant prospectiveMarcellus production fromSeneca's Western Development Area atClermont to an Empire interconnection withTransCanada Pipeline at Chippawa and an interconnection withTennessee Gas Pipeline's 200 Line inEast Aurora, New York ("Northern Access project"). In light of numerous legal actions and the need to complete necessary project development activities in advance of construction, the in-service date for the project is expected to be no earlier than fiscal 2022. For further discussion of the Northern Access project, refer to Item 1 at Note 8 - Commitments and Contingencies. Given the current low commodity price environment, the Company's Exploration and Production segment moved from a 3-rig development program to a 2-rig development program in the Appalachian region inJanuary 2020 , and intends to move to a single-rig development program during the second half of fiscal 2020. While this will result in lower capital spending in this segment (expected to be in the range of$375 million to$410 million for fiscal 2020),Seneca still anticipates an increase in natural gas production when comparing fiscal 2020 to fiscal 2019. As discussed in the following Critical Accounting Estimates section, the Company uses the full cost method of accounting for determining the book value of its oil and natural gas properties in the Exploration and Production segment and that book value is subject to a quarterly ceiling test. While the Company did not record an impairment under the ceiling test during the quarter endedDecember 31, 2019 , it is anticipated that the current low commodity price environment will lead to impairments during the remaining quarters of fiscal 2020. From a rate perspective,Supply Corporation filed a Section 4 rate case onJuly 31, 2019 . The new rates are scheduled to become effective onFebruary 1, 2020 , subject to refund, if the case is not settled before then. For further discussion ofSupply Corporation's rate matters, refer to the Rate and Regulatory Matters section below. From a legislation perspective, inJuly 2019 ,New York State enacted legislation known as the Climate Leadership & Community Protection Act (CLCPA). This climate legislation mandates reducing greenhouse gas emissions to 60% of 1990 levels by 2030, and to 15% of 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets. The legislation also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% by 2040. In the near-term, 29
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the CLCPA establishes a climate action council and a series of advisory panels
and working groups to study how the state will achieve the aggressive emission
reduction targets.
From a financing perspective, the Company expects to use cash on hand, cash from
operations and short-term debt to meet its capital expenditure needs for fiscal
2020 and may issue long-term debt during fiscal 2020 as needed.
CRITICAL ACCOUNTING ESTIMATES
For a complete discussion of critical accounting estimates, refer to "Critical
Accounting Estimates" in Item 7 of the Company's 2019 Form 10-K. There have
been no material changes to that disclosure other than as set forth below. The
information presented below updates and should be read in conjunction with the
critical accounting estimates in that Form 10-K.
Oil and Gas Exploration and Development Costs. The Company, in its Exploration
and Production segment, follows the full cost method of accounting for
determining the book value of its oil and natural gas properties. In accordance
with this methodology, the Company is required to perform a quarterly ceiling
test. Under the ceiling test, the present value of future revenues from the
Company's oil and gas reserves based on an unweighted arithmetic average of the
first day of the month oil and gas prices for each month within the twelve-month
period prior to the end of the reporting period (the "ceiling") is compared with
the book value of the Company's oil and gas properties at the balance sheet
date. If the book value of the oil and gas properties exceeds the ceiling, a
non-cash impairment charge must be recorded to reduce the book value of the oil
and gas properties to the calculated ceiling. At December 31, 2019 , the ceiling
exceeded the book value of the oil and gas properties by approximately $59.1
million . The 12-month average of the first day of the month price for crude oil
for each month during the twelve months ended December 31, 2019 , based on posted
Midway Sunset prices, was $59.50 per Bbl. The 12-month average of the first day
of the month price for natural gas for each month during the twelve months ended
December 31, 2019 , based on the quoted Henry Hub spot price for natural gas, was
$2.58 per MMBtu. (Note - because actual pricing of the Company's various
producing properties varies depending on their location and hedging, the prices
used to calculate the ceiling may differ from the Midway Sunset and Henry Hub
prices, which are only indicative of the 12-month average prices for the twelve
months ended December 31, 2019 . Pricing differences would include adjustments
for regional market differentials, transportation fees and contractual
arrangements.) The following table illustrates the sensitivity of the ceiling
test calculation to commodity price changes, specifically showing the amount the
ceiling would have exceeded the book value of the Company's oil and gas
properties at December 31, 2019 if crude oil prices were $5 per Bbl lower than
the average prices used at December 31, 2019 , as well as showing the impairment
that the Company would have recorded at December 31, 2019 if natural gas prices
were $0.25 per MMBtu lower than the average prices used at December 31, 2019 ,
and the impairment that the Company would have recorded at December 31, 2019 if
both natural gas prices and crude oil prices were $0.25 per MMBtu and $5 per Bbl
lower than the average prices used at December 31, 2019 (all amounts are
presented after-tax). These calculated amounts are based solely on price changes
and do not take into account any other changes to the ceiling test calculation,
including, among others, changes in reserve quantities and future cost
estimates. Looking ahead, the first day of the month Henry Hub spot price for
natural gas in January 2020 was $2.05 per MMBtu. Given these January prices, the
potential that prices could stay at this level in future months, and the
expected loss of higher gas and oil prices from the 12-month average that will
be used in the ceiling test at March 31, 2020 , June 30, 2020 and September 30,
2020 , the Company expects to experience ceiling test impairments in each of
these quarters.
Ceiling Testing Sensitivity to Commodity Price Changes
$0.25 /MMBtu
Decrease in
Natural Gas Prices
$0.25 /MMBtu $5.00 /Bbl and $5.00 /Bbl
Decrease in Decrease in Decrease in
(Millions) Natural Gas Prices Crude Oil Prices Crude Oil Prices
Excess of Ceiling over Book Value
under Sensitivity Analysis $ - $ 22.9 $ -
Calculated Impairment under
Sensitivity Analysis $ 186.2 $ - $ 222.4
For a more complete discussion of the full cost method of accounting, refer to "Oil and Gas Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's 2019 Form 10-K.
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RESULTS OF OPERATIONS
Earnings
The Company's earnings were $86.6 million for the quarter ended December 31,
2019 compared to earnings of $102.7 million for the quarter ended December 31,
2018 . The decrease in earnings of $16.1 million is primarily a result of lower
earnings in the Exploration and Production segment and Pipeline and Storage
segment. Higher earnings in the Gathering segment, Utility segment and Corporate
and All Other categories partially offset these decreases.
Earnings (Loss) by Segment
Three Months Ended
December 31,
(Thousands) 2019 2018 Increase (Decrease)
Exploration and Production $ 23,977 $ 38,214 $ (14,237 )
Pipeline and Storage 18,105 25,102 (6,997 )
Gathering 15,944 14,183 1,761
Utility 26,583 25,649 934
Total Reportable Segments 84,609 103,148 (18,539 )
All Other 371 82 289
Corporate 1,611 (570 ) 2,181
Total Consolidated $ 86,591 $ 102,660 $ (16,069 )
Exploration and Production
Exploration and Production Operating Revenues
Three Months Ended
December 31,
(Thousands) 2019 2018 Increase (Decrease)
Gas (after Hedging) $ 127,238 $ 119,750 $ 7,488
Oil (after Hedging) 37,841 35,264 2,577
Gas Processing Plant 688 975 (287 )
Other 172 6,887 (6,715 )
$ 165,939 $ 162,876 $ 3,063
Production Volumes
Three Months Ended
December 31,
2019 2018 Increase (Decrease)
Gas Production (MMcf)
Appalachia 54,284 45,305 8,979
West Coast 487 502 (15 )
Total Production 54,771 45,807 8,964
Oil Production (Mbbl)
Appalachia - 1 (1 )
West Coast 601 571 30
Total Production 601 572 29
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Average Prices
Three Months Ended
December 31,
2019 2018 Increase (Decrease)
Average Gas Price/Mcf
Appalachia $ 2.16 $ 2.93 $ (0.77 )
West Coast $ 4.98 $ 6.73 $ (1.75 )
Weighted Average $ 2.19 $ 2.97 $ (0.78 )
Weighted Average After Hedging $ 2.32 $ 2.61 $ (0.29 )
Average Oil Price/Bbl
Appalachia $ 54.49 $ 66.31 $ (11.82 )
West Coast $ 62.63 $ 65.71 $ (3.08 )
Weighted Average $ 62.63 $ 65.71 $ (3.08 )
Weighted Average After Hedging $ 62.92 $ 61.70 $ 1.22
2019 Compared with 2018
Operating revenues for the Exploration and Production segment increased $3.1
million for the quarter ended December 31, 2019 as compared with the quarter
ended December 31, 2018 . Gas revenues after hedging increased $7.5 million due
to a 9.0 Bcf increase in gas production, which was largely offset by the impact
of a $0.29 per Mcf decrease in the weighted average price of gas after hedging.
The increase in gas production was largely due to new Marcellus and Utica wells
completed and connected to sales in the Western and Eastern Development Areas in
the Appalachian region during the quarter ended December 31, 2019 as compared
with the quarter ended December 31, 2018 . Oil revenues after hedging increased
$2.6 million due to a 29 Mbbl increase in crude oil production coupled with the
impact of a $1.22 per Bbl increase in the weighted average price of oil after
hedging. The increase in oil production revenue was largely due to higher
production in the West Coast region. These increases to operating revenues were
partially offset by a $6.7 million decrease in other revenue primarily due to
mark-to-market adjustments related to hedging ineffectiveness that were recorded
during the quarter ended December 31, 2018 that did not recur during the quarter
ended December 31, 2019 .
The Exploration and Production segment's earnings for the quarter ended
December 31, 2019 were $24.0 million , a decrease of $14.2 million when compared
with earnings of $38.2 million for the quarter ended December 31, 2018 . The
decrease in earnings was due to lower natural gas prices after hedging ($12.6
million ), higher depletion expense ($7.5 million ), higher production expenses
($6.5 million ), higher other operating expenses ($0.6 million ), higher interest
expense ($0.7 million ), a higher effective income tax rate ($1.3 million ), the
impact of the aforementioned prior year quarter mark-to-market adjustments
related to hedging ineffectiveness ($5.1 million ) and the impact of a
remeasurement of the segment's accumulated deferred income taxes in the prior
year quarter that did not recur in fiscal 2020 ($1.0 million ). The increase in
depletion expense was primarily due to the increase in production coupled with a
$0.06 per Mcfe increase in the depletion rate, which was driven by an increase
in capitalized costs in Seneca's full cost pool. The increase in production
expenses was primarily due to increased gathering and transportation costs in
the Appalachian region. The increase in other operating expenses was largely due
to an increase in purchased emissions credits in the West Coast region. The
increase in interest expense was largely due to increased intercompany
borrowings. The increase in the effective income tax rate was primarily due to
the impact of the Enhanced Oil Recovery tax credit that was applicable in the
quarter ended December 31, 2018 but was not available in the quarter ended
December 31, 2019 . These factors, which decreased earnings during the quarter
ended December 31, 2019 , were partially offset by the positive impacts of higher
natural gas production ($18.5 million ), higher crude oil production ($1.5
million ), higher crude oil prices after hedging ($0.6 million ) and lower other
taxes ($1.3 million ). The decrease in other taxes was primarily due to a lower
Pennsylvania impact fee accrual for the quarter ended December 31, 2019 as a
result of lower NYMEX natural gas prices.
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Table of Contents Pipeline and Storage
Pipeline and Storage Operating Revenues
Three Months Ended
December 31,
(Thousands) 2019 2018 Increase (Decrease)
Firm Transportation $ 53,191 $ 55,714 $ (2,523 )
Interruptible Transportation 261 421 (160 )
53,452 56,135 (2,683 )
Firm Storage Service 18,420 18,928 (508 )
Interruptible Storage Service 6 1 5
Other 342 2,005 (1,663 )
$ 72,220 $ 77,069 $ (4,849 )
Pipeline and Storage Throughput
Three Months Ended
December 31,
(MMcf) 2019 2018 Increase (Decrease)
Firm Transportation 208,648 191,901 16,747
Interruptible Transportation 714 916 (202 )
209,362 192,817 16,545
2019 Compared with 2018
Operating revenues for the Pipeline and Storage segment decreased $4.8 million
for the quarter ended December 31, 2019 as compared with the quarter ended
December 31, 2018 . The decrease in operating revenues was primarily due to a
decrease in transportation revenues of $2.7 million and a decrease in other
revenues of $1.7 million . The decrease in transportation revenues was primarily
attributable to an Empire system transportation contract termination in December
2018 . Partially offsetting this decrease was an increase in transportation
revenues due to an increase in Empire's rates effective January 1, 2019 in
accordance with Empire's rate case settlement, which was approved by the FERC on
May 3, 2019 , combined with an increase in demand charges for transportation
service from Supply Corporation's Line N to Monaca project, which was placed in
service on November 1, 2019 . The decrease in other revenues was due to proceeds
received by Supply Corporation in the first quarter of fiscal 2019 related to a
contract termination as a result of a shipper's bankruptcy that did not recur in
the first quarter of fiscal 2020.
Transportation volume for the quarter ended December 31, 2019 increased by 16.5
Bcf from the prior year's quarter. The increase in transportation volume for the
quarter primarily reflects an increase in capacity utilization by certain
contract shippers. Volume fluctuations, other than those caused by the addition
or termination of contracts, generally do not have a significant impact on
revenues as a result of the straight fixed-variable rate design utilized by
Supply Corporation and Empire.
The Pipeline and Storage segment's earnings for the quarter ended December 31,
2019 were $18.1 million , a decrease of $7.0 million when compared with earnings
of $25.1 million for the quarter ended December 31, 2018 . The decrease in
earnings was primarily due to the earnings impact of lower operating revenues of
$3.8 million , as discussed above, combined with higher income tax expense ($2.5
million ) and higher property taxes ($0.8 million ). The increase in income tax
expense is primarily due to permanent differences related to stock compensation
activity. The increase in property taxes was due to an increase in scheduled
payments in lieu of taxes in accordance with agreements in place, as well as
higher town, county and school taxes due to an increase in assessed values from
new projects placed in service. These earnings decreases were slightly offset by
a decrease in operating expenses ($0.6 million ) primarily due to a decrease in
personnel and compensation costs as well as costs associated with maintenance of
compressor stations, partially offset by an increase in pipeline integrity
program expenses.
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Table of Contents Gathering
Gathering Operating Revenues
Three Months Ended
December 31 ,
(Thousands) 2019 2018 Increase (Decrease)
Gathering Revenues
5,098
Gathering Volume
Three Months Ended
December 31,
2019 2018 Increase (Decrease)
Gathered Volume - (MMcf) 64,392 54,688 9,704
2019 Compared with 2018
Operating revenues for the Gathering segment increased $5.1 million for the
quarter ended December 31, 2019 as compared with the quarter ended December 31,
2018 . The increase was primarily due to a 9.7 Bcf net increase in gathered
volume resulting from a 4.0 Bcf, 3.8 Bcf and 3.5 Bcf increase in volume on
Midstream Company's Trout Run , Wellsboro and Clermont gathering systems,
respectively, offset by a 1.6 Bcf decline on the Covington gathering system. The
net increase in gathered volume can be attributed to the increase in Seneca's
gross natural gas production in the Appalachian region.
The Gathering segment's earnings for the quarter ended December 31, 2019 were
$15.9 million , an increase of $1.7 million when compared with earnings of $14.2
million for the quarter ended December 31, 2018 . The increase in earnings was
mainly due to the impact of higher gathering revenues discussed above ($4.0
million ), which was partially offset by higher operating expenses ($1.3
million ), higher depreciation expense ($0.4 million ), and the impact of a
nonrecurring income tax benefit recorded in the prior year quarter to adjust the
remeasurement of deferred income taxes resulting from the 2017 Tax Reform Act
($0.5 million ). The increase in operating expenses was due largely to increased
preventative maintenance and overhaul activities at Covington and Trout Run
compressor stations during the quarter ended December 31, 2019 . The increase in
depreciation expense was due to an increase in the average gross property, plant
and equipment assets in service as compared to the prior year.
Utility
Utility Operating Revenues
Three Months Ended
December 31,
(Thousands) 2019 2018 Increase (Decrease)
Retail Sales Revenues:
Residential $ 145,615 $ 165,333 $ (19,718 )
Commercial 19,661 22,742 (3,081 )
Industrial 1,267 1,493 (226 )
166,543 189,568 (23,025 )
Transportation 33,606 35,950 (2,344 )
Other (3,324 ) (2,861 ) (463 )
$ 196,825 $ 222,657 $ (25,832 )
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Utility Throughput
Three Months Ended
December 31,
(MMcf) 2019 2018 Increase (Decrease)
Retail Sales:
Residential 19,476 19,780 (304 )
Commercial 2,812 2,846 (34 )
Industrial 217 204 13
22,505 22,830 (325 )
Transportation 20,556 22,270 (1,714 )
43,061 45,100 (2,039 )
Degree Days
Percent Colder (Warmer) Than
Three Months Ended December 31, Normal 2019 2018 Normal(1) Prior Year(1)
Buffalo 2,253 2,232 2,325 (0.9 )% (4.0 )%
Erie 2,044 1,906 2,030 (6.8 )% (6.1 )%
(1) Percents compare actual 2019 degree days to normal degree days and actual
2019 degree days to actual 2018 degree days.
2019 Compared with 2018
Operating revenues for the Utility segment decreased$25.8 million for the quarter endedDecember 31, 2019 as compared with the quarter endedDecember 31, 2018 . The decrease primarily resulted from a$23.0 million decrease in retail gas sales revenue, a$2.3 million decrease in transportation revenues and a$0.5 million decrease in other revenues. The decrease in retail gas sales revenue was largely due to a decrease in the cost of gas sold (per Mcf) coupled with slightly lower throughput due to warmer weather. The decline in transportation revenues was primarily due a 1.7 Bcf decrease in transportation throughput due to warmer weather and the migration of residential transportation customers to retail. The decrease in other revenues was largely due to the impact of regulatory adjustments, including an earnings sharing accrual recorded in fiscal 2020 for$0.5 million in the segment'sNew York service territory. The Utility segment's earnings for the quarter endedDecember 31, 2019 were$26.6 million , an increase of$1.0 million when compared with earnings of$25.6 million for the quarter endedDecember 31, 2018 . The increase in earnings was largely attributable to the impact of regulatory adjustments ($0.9 million ) and the positive earnings impact related to a system modernization tracker ($0.3 million ). These increases were slightly offset by higher income tax expense ($0.8 million ). The increase in income tax expense was primarily due to permanent differences related to stock compensation activity.
Corporate and All Other
2019 Compared with 2018
Corporate and All Other operations had earnings of$2.0 million for the quarter endedDecember 31, 2019 , an increase of$2.5 million when compared with a loss of$0.5 million for the quarter endedDecember 31, 2018 . The increase in earnings was primarily attributable to lower unrealized losses on investments in equity securities recorded during the quarter endedDecember 31, 2019 ($4.2 million ) coupled with higher other income ($1.5 million ) that was driven largely by an increase in realized gains on investments in equity securities sold in the current quarter. These positive drivers of earnings were partially offset by the impact of the prior year remeasurement of deferred income taxes under the 2017 Tax Reform Act that lowered income tax expense for the quarter endedDecember 31, 2018 ($3.5 million ).
Interest Expense on Long-Term Debt
Interest on long-term debt was relatively flat for the quarter endedDecember 31, 2019 as compared with the quarter endedDecember 31, 2018 . No new additional debt was issued or repaid during the quarters endedDecember 31, 2019 and 35
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CAPITAL RESOURCES AND LIQUIDITY
The Company's primary sources of cash during the three-month period ended
December 31, 2019 consisted of cash provided by operating activities and net
proceeds from short-term borrowings. The Company's primary source of cash during
the three-month period ended December 31, 2018 consisted of cash provided by
operating activities.
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 stock-based
compensation.
Cash provided by operating activities in the Utility and Pipeline and Storage
segments may vary substantially 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 may 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 the
straight fixed-variable rate design used by Supply Corporation and Empire.
Because of the seasonal nature of the heating business in the Utility segment
and in the Company's NFR operations (included in the All Other category),
revenues in these businesses are relatively high during the heating season,
primarily the first and second quarters of the fiscal year, and receivable
balances historically increase during these periods from the receivable balances
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 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 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 as well as changes in production. The Company uses
various derivative financial instruments, including price swap agreements and
futures contracts in an attempt to manage this energy commodity price risk.
Net cash provided by operating activities totaled $167.7 million for the three
months ended December 31, 2019 , an increase of $63.3 million compared with
$104.4 million provided by operating activities for the three months ended
December 31, 2018 . The increase in cash provided by operating activities
primarily reflects higher cash provided by operating activities in the Utility
and Exploration and Production segments. The increase in the Utility segment is
primarily due to the timing of gas cost recovery and the timing of receivable
collections. The increase in the Exploration and Production segment is primarily
due to higher cash receipts from natural gas production. The increase in cash
provided by operating activities also reflects a decrease in contributions made
to the Retirement Plan, primarily in the Utility and Pipeline and Storage
segments.
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Table of Contents Investing Cash Flow
Expenditures for Long-Lived Assets
The Company's expenditures for long-lived assets totaled$211.2 million during the three months endedDecember 31, 2019 and$174.9 million during the three months endedDecember 31, 2018 . The table below presents these expenditures: Total Expenditures for Long-Lived Assets Three Months EndedDecember 31 , (Millions) 2019 2018 Increase (Decrease) Exploration and Production: Capital Expenditures$ 126.9 (1)$ 120.2 (2) $ 6.7 Pipeline and Storage: Capital Expenditures 57.1 (1) 30.0 (2) 27.1 Gathering: Capital Expenditures 9.8 (1) 8.8 (2) 1.0 Utility: Capital Expenditures 17.2 (1) 15.9 (2) 1.3 All Other: Capital Expenditures 0.2 - 0.2$ 211.2 $ 174.9 $ 36.3
(1) At
segment, the Pipeline and Storage segment, the Gathering segment and the
Utility segment include
million, respectively, of non-cash capital expenditures. At
2019, capital expenditures for the Exploration and Production segment, the
Pipeline and Storage segment, the Gathering segment and the Utility segment
included
respectively, of non-cash capital expenditures.
(2) At
segment, the Pipeline and Storage segment, the Gathering segment and the
Utility segment included
million, respectively, of non-cash capital expenditures. At
2018, capital expenditures for the Exploration and Production segment, the
Pipeline and Storage segment, the Gathering segment and the Utility segment
included $51.3 million , $21.9 million , $6.1 million and $9.5 million ,
respectively, of non-cash capital expenditures.
Exploration and Production
The Exploration and Production segment capital expenditures for the three months endedDecember 31, 2019 were primarily well drilling and completion expenditures and included approximately$119.0 million for the Appalachian region (including$53.7 million in theMarcellus Shale area and$63.8 million in theUtica Shale area) and$7.9 million for theWest Coast region. These amounts included approximately$86.2 million spent to develop proved undeveloped reserves. The Exploration and Production segment capital expenditures for the three months endedDecember 31, 2018 were primarily well drilling and completion expenditures and included approximately$114.7 million for the Appalachian region (including$36.5 million in theMarcellus Shale area and$75.5 million in theUtica Shale area) and$5.5 million for theWest Coast region. These amounts included approximately$61.1 million spent to develop proved undeveloped reserves.
Pipeline and Storage
The Pipeline and Storage segment capital expenditures for the three months endedDecember 31, 2019 were primarily for expenditures related toEmpire's Empire North Project ($29.1 million ) andSupply Corporation's Line N toMonaca Project ($3.3 million ), as discussed below. In addition, the Pipeline and Storage segment capital expenditures for the three months endedDecember 31, 2019 include additions, improvements and replacements to this segment's transmission and gas storage systems. The Pipeline and Storage capital expenditures for the three months endedDecember 31, 2018 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems. In addition, the Pipeline and Storage segment capital expenditures for the three months endedDecember 31, 2018 include expenditures related toSupply Corporation's Line N toMonaca Project ($1.1 million ). In light of the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia - specifically in theMarcellus andUtica Shale producing areas -Supply Corporation and Empire have completed and continue to pursue several expansion projects designed to move anticipatedMarcellus andUtica production gas to other interstate pipelines 37
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and to on-system markets, and markets beyond theSupply Corporation and Empire pipeline systems. Preliminary survey and investigation costs for expansion, routine replacement or modernization projects are initially recorded as Deferred Charges on the Consolidated Balance Sheet. Management may reserve for preliminary survey and investigation costs associated with large projects by reducing the Deferred Charges balance and increasing Operation and Maintenance Expense on the Consolidated Statement of Income. If it is determined that it is highly probable that a project for which a reserve has been established will be built, the reserve is reversed. This reversal reduces Operation and Maintenance Expense and reestablishes the original balance in Deferred Charges. The amounts remain in Deferred Charges until such time as capital expenditures for the project have been incurred and activities that are necessary to get the construction project ready for its intended use are in progress. At that point, the balance is transferred from Deferred Charges to Construction Work in Progress, a component of Property, Plant and Equipment on the Consolidated Balance Sheet.Supply Corporation completed a project to provide incremental natural gas transportation services from Line N to the ethane cracker facility being constructed byShell Chemical Appalachia, LLC inPotter Township ,Pennsylvania ("Line N toMonaca Project "), with transportation service beginning onNovember 1, 2019 . This project involved construction of a 4.5 mile pipeline extension from Line N to the facility and has resulted inSupply Corporation securing incremental firm transportation capacity commitments totaling 133,000 Dth per day on Line N and on the pipeline extension to the facility.Supply Corporation was authorized to pursue the project byFERC under its blanket certificate as ofMay 30, 2018 . As ofDecember 31, 2019 , approximately$22.1 million has been spent on the Line N toMonaca Project , all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet atDecember 31, 2019 . Empire concluded an Open Season onNovember 18, 2015 , and has designed a project that would allow for the transportation of 205,000 Dth per day of additional shale supplies from interconnections inTioga County, Pennsylvania , toTransCanada Pipeline , and the TGP 200 Line ("Empire North Project "). This project is fully subscribed under long term agreements and received theFERC Section 7(c) certificate onMarch 7, 2019 . Project construction is under way.The Empire North Project has a projected in-service date in the fourth quarter of fiscal 2020 and an estimated capital cost of approximately$145 million .
As
of
Supply Corporation has developed itsFM100 Project , which will upgrade a 1950's era pipeline in northwesternPennsylvania and create approximately 330,000 Dth per day of additional transportation capacity inPennsylvania from a receipt point withNFG Midstream Clermont, LLC inMcKean County to theTranscontinental Gas Pipe Line Company, LLC ("Transco") system atLeidy, Pennsylvania . A precedent agreement has been executed bySupply Corporation andTransco whereby this additional capacity is expected to be leased byTransco and become part of aTransco expansion project ("Leidy South") that will create incremental transportation capacity toTransco Zone 6 markets.Seneca is the anchor shipper on Leidy South, providingSeneca with an outlet to premium markets for itsMarcellus andUtica production from both theClermont-Rich Valley and Trout Run-Gamble areas.Supply Corporation filed a Section 7(c) application with theFERC inJuly 2019 .The FM100 Project has a target in-service date in late calendar 2021 and a preliminary cost estimate of approximately$280 million . As ofDecember 31, 2019 , approximately$5.0 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet atDecember 31, 2019 .Supply Corporation and Empire have developed a project which would move significant prospectiveMarcellus production fromSeneca's Western Development Area atClermont to an Empire interconnection withTransCanada Pipeline at Chippawa and an interconnection with TGP's 200 Line inEast Aurora, New York (the "Northern Access project"). The Northern Access project would provide an outlet to Dawn-indexed markets inCanada and to the TGP line serving theU.S. Northeast. The Northern Access project involves the construction of approximately 99 miles of largely 24" pipeline and approximately 27,500 horsepower of compression on the two systems.Supply Corporation , Empire andSeneca executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. OnFebruary 3, 2017 , the Company receivedFERC approval of the project. Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for theNew York portion of the project (the Water Quality Certification for thePennsylvania portion of the project was received in January of 2017).The United States Court of Appeals for the Second Circuit (the "Second Circuit Court of Appeals ") held in the Company's favor in its appeal of this decision, vacating the NYDEC denial and remanding to the NYDEC. The NYDEC subsequently issued a second denial, which the Company has appealed to theSecond Circuit Court of Appeals . The court has held this appeal in abeyance pending the outcome of theFERC waiver appeal, described below. While the Company's initial appeal was pending before theSecond Circuit Court of Appeals , theFERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification.FERC denied rehearing requests associated with its Order, andFERC's decisions have been appealed and are pending in a separate action before theSecond Circuit Court of Appeals . In addition, the Company commenced legal action inNew York State Supreme Court challenging the NYDEC's actions with regard to various 38
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state permits. The Company remains committed to the project. In light of these pending legal actions and the need to complete necessary project development activities in advance of construction, the in-service date for the project is expected to be no earlier than fiscal 2022. The Company will update the$500 million preliminary cost estimate when there is further clarity on that date. As ofDecember 31, 2019 , approximately$57.8 million has been spent on the Northern Access project, including$23.3 million that has been spent to study the project, for which no reserve has been established. The remaining$34.5 million spent on the project has been capitalized as Construction Work in Progress.
Gathering
The majority of the Gathering segment capital expenditures for the three months endedDecember 31, 2019 were for the continued expansion ofMidstream Company's Trout Run gathering system,Midstream Company's Clermont gathering system andMidstream Company's Wellsboro gathering system, as discussed below.Midstream Company spent$5.5 million ,$3.2 million and$1.1 million , respectively, during the three months endedDecember 31, 2019 on the development of theTrout Run ,Clermont andWellsboro gathering systems. These expenditures were largely attributable to new gathering pipelines and the continued development of centralized station facilities, including increased compression horsepower at theTrout Run gathering system. The majority of the Gathering segment capital expenditures for the three months endedDecember 31, 2018 were for the continued expansion of theTrout Run gathering system,Clermont gathering system andWellsboro gathering system.Midstream Company spent$1.3 million ,$3.0 million and$4.0 million , respectively, during the three months endedDecember 31, 2018 on the development of theTrout Run ,Clermont andWellsboro gathering systems.NFG Midstream Clermont, LLC , a wholly owned subsidiary ofMidstream Company , continues to develop an extensive gathering system with compression in thePennsylvania counties ofMcKean ,Elk andCameron . TheClermont gathering system was initially placed in service inJuly 2014 . The current system consists of three compressor stations and backbone and in-field gathering pipelines. The total cost estimate for the continued buildout will be dependent on the nature and timing ofSeneca's long-term plans.NFG Midstream Wellsboro, LLC , a wholly owned subsidiary ofMidstream Company , continues to develop itsWellsboro gathering system inTioga County, Pennsylvania . The current system consists of a dehydration and metering station and backbone and in-field gathering pipelines.NFG Midstream Trout Run, LLC , a wholly owned subsidiary ofMidstream Company , continues to develop itsTrout Run gathering system inLycoming County, Pennsylvania . TheTrout Run gathering system was initially placed in service inMay 2012 . The current system consists of three compressor stations and backbone and in-field gathering pipelines.Midstream Company intends to extend this system in 2020. Combining this extension with reduced drilling activity in the Exploration and Production segment, the Gathering segment's capital expenditures are expected to be in the range of$50 million to$60 million for fiscal 2020.
Utility
The majority of the Utility segment capital expenditures for the three months endedDecember 31, 2019 andDecember 31, 2018 were made for main and service line improvements and replacements, as well as main extensions.
Project Funding
Over the past two years, the Company has been financing the Pipeline and Storage
segment and Gathering segment projects mentioned above, as well as the
Exploration and Production segment and Utility segment capital expenditures,
with cash from operations as well as proceeds received from the sale of oil and
gas assets. Going forward, while the Company expects to use cash on hand, cash
from operations and short-term debt to finance these projects, the Company may
issue long-term debt as necessary during fiscal 2020 to help meet its capital
expenditures needs. The level of short-term and long-term borrowings will depend
upon the amount of cash provided by operations, which, in turn, will likely be
impacted by natural gas and crude oil prices combined with production from
existing wells.
The Company continuously evaluates capital expenditures and potential
investments in corporations, partnerships, and other business entities. The
amounts are subject to modification for opportunities such as the acquisition of
attractive oil and gas properties, natural gas storage facilities, natural gas
gathering and compression facilities and the expansion of natural gas
transmission line capacities, regulated utility assets and other opportunities
as they may arise. 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.
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Table of Contents Financing Cash Flow Consolidated short-term debt increased$84.6 million when comparing the balance sheet atDecember 31, 2019 to the balance sheet atSeptember 30, 2019 . The maximum amount of short-term debt outstanding during the quarter endedDecember 31, 2019 was$173.3 million . The Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. AtDecember 31, 2019 , the Company had outstanding commercial paper of$139.8 million . The Company did not have any outstanding short-term notes payable to banks atDecember 31, 2019 . OnOctober 25, 2018 , the Company entered into a Fourth Amended and Restated Credit Agreement (Credit Agreement) with a syndicate of 12 banks. This Credit Agreement provides a$750.0 million multi-year unsecured committed revolving credit facility throughOctober 25, 2023 . The Company also has uncommitted lines of credit with financial institutions for general corporate purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institution and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future. The total amount available to be issued under the Company's commercial paper program is$500.0 million . The commercial paper program is backed by the Credit Agreement, which provides that the Company's debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or afterJuly 1, 2018 , not to exceed$250 million . AtDecember 31, 2019 , the Company's debt to capitalization ratio (as calculated under the facility) was .51. The constraints specified in the Credit Agreement would have permitted an additional$1.77 billion in short-term and/or long-term debt to be outstanding atDecember 31, 2019 (further limited by the indenture covenants discussed below) before the Company's debt to capitalization ratio exceeded .65. A downgrade in the Company's credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company's subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources, including cash provided by operations. The Credit Agreement contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating$40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating$40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As ofDecember 31, 2019 , the Company did not have any debt outstanding under the Credit Agreement.
None of the Company's long-term debt as of
The Company's embedded cost of long-term debt was 4.69% at both
Under the Company's existing indenture covenants atDecember 31, 2019 , the Company would have been permitted to issue up to a maximum of$1.05 billion in additional long-term indebtedness at then current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. The Company's present liquidity position is believed to be adequate to satisfy known demands. However, if the Company were to experience a significant loss in the future (for example, as a result of an impairment of oil and gas properties), it is possible, depending on factors including the magnitude of the loss, that these indenture covenants would restrict the Company's ability to issue additional long-term unsecured indebtedness for a period of up to nine calendar months, beginning with the fourth calendar month following the loss. This would not preclude the Company from issuing new indebtedness to replace maturing debt. Please refer to the Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test. 40
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The Company's 1974 indenture pursuant to which$99.0 million (or 4.6%) of the Company's long-term debt (as ofDecember 31, 2019 ) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived. OTHER MATTERS In addition to the legal proceedings disclosed in Part II, Item 1 of this report, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the period in which they are resolved, they are not expected to change materially the Company's present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company. During the three months endedDecember 31, 2019 , the Company contributed$7.8 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and$0.7 million to its VEBA trusts for its other post-retirement benefits. In the remainder of 2020, the Company expects its contributions to the Retirement Plan to be in the range of$17.0 million to$22.0 million . In the remainder of 2020, the Company expects its contributions to its VEBA trusts to be in the range of$2.0 million to$2.5 million .
Market Risk Sensitive Instruments
OnJuly 21, 2010 , the Dodd-Frank Act was signed into law. The Dodd-Frank Act includes provisions related to the swaps and over-the-counter derivatives markets that are designed to promote transparency, mitigate systemic risk and protect against market abuse. Although regulators have issued certain regulations, other rules that may impact the Company have yet to be finalized. The CFTC's Dodd-Frank regulations continue to preserve the ability of non-financial end users to hedge their risks using swaps without being subject to mandatory clearing. In 2015, legislation was enacted to exempt from margin requirements swaps used by non-financial end users to hedge or mitigate commercial risk. In 2016, the CFTC issued a reproposal to its position limit rules that would impose speculative position limits on positions in 28 core physical commodity contracts as well as economically equivalent futures, options and swaps. While the Company does not intend to enter into positions on a speculative basis, such rules could nevertheless impact the ability of the Company to enter into certain derivative hedging transactions with respect to such commodities. If the Company reduces its use of hedging transactions as a result of final regulations to be issued by the CFTC, results of operations may become more volatile and cash flows may be less predictable. There may be other rules developed by the CFTC and other regulators that could impact the Company. While many of those rules place specific conditions on the operations of swap dealers and major swap participants, concern remains that swap dealers and major swap participants will pass along their increased costs stemming from final rules through higher transaction costs and prices or other direct or indirect costs. Finally, given the additional authority granted to the CFTC on anti-market manipulation, anti-fraud and disruptive trading practices, it is difficult to predict how the evolving enforcement priorities of the CFTC will impact our business. Should the Company violate any laws or regulations applicable to our hedging activities, it could be subject to CFTC enforcement action and material penalties and sanctions. The Company continues to monitor these enforcement and other regulatory developments, but cannot predict the impact that evolving application of the Dodd-Frank Act may have on its operations. The accounting rules for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. AtDecember 31, 2019 , the Company determined that nonperformance risk would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company's (assuming the derivative is in a loss position) credit default swaps rates. For a complete discussion of market risk sensitive instruments, refer to "Market Risk Sensitive Instruments" in Item 7 of the Company's 2019 Form 10-K. There have been no subsequent material changes to the Company's exposure to market risk sensitive instruments. 41
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Table of Contents Rate and Regulatory Matters Utility Operation Delivery rates for both theNew York andPennsylvania divisions are regulated by the states' respective public utility commissions and typically are changed only when approved through a procedure known as a "rate case." ThePennsylvania division does not have a rate case on file. See below for a description of the current rate proceedings affecting theNew York division. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated "supply charge" on the customer bill.
New York Jurisdiction
OnApril 24, 2019 , the NYPSC issued an order extending the sunset provision of the tracker previously approved by the NYPSC that allowsDistribution Corporation to recover increased investment in utility system modernization for one year (untilMarch 31, 2021 ). The extension is contingent on a one year stay-out of a general rate case filing that would prevent new rates from becoming effective prior toApril 1, 2021 .
Pennsylvania Jurisdiction
Distribution Corporation's Pennsylvania jurisdiction delivery rates are being charged to customers in accordance with a rate settlement approved by the PaPUC. The rate settlement does not specify any requirement to file a future rate case.
Pipeline and Storage
Supply Corporation filed a Section 4 rate case onJuly 31, 2019 proposing rate increases to be effectiveSeptember 1, 2019 . The proposed rates reflect an annual cost of service of$295.4 million , a rate base of$970.8 million and a proposed cost of equity of 15%. TheFERC has accepted the filed rates and suspended the effective date of the increases untilFebruary 1, 2020 , when the rates will be made effective, subject to refund. If the rates finally approved at the end of the proceeding exceed the rates that were in effect atJuly 31, 2019 , but are less than rates put into effect subject to refund onFebruary 1, 2020 ,Supply Corporation would be required to refund the difference between the rates collected subject to refund and the final approved rates, with interest at theFERC -approved rate. If the rates approved at the end of the proceeding are lower than the rates in effect atJuly 31, 2019 , such lower rates will become effective prospectively from the date of the applicableFERC order, and refunds with interest will be limited to the difference between the rates collected subject to refund and the rates in effect atJuly 31, 2019 .
Empire's 2019 rate settlement requires a Section 4 rate case filing no later
than
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 requirements.
For further discussion of the Company's environmental exposures, refer to Item 1 at Note 8 - Commitments and Contingencies under the heading "Environmental Matters."
Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation inthe United States . These efforts include legislative proposals and new regulations at the state and federal level, and private party litigation related to greenhouse gas emissions.The U.S. Congress has not yet passed any federal climate change legislation and we cannot predict when or ifCongress will pass such legislation and in what form. In the absence of such legislation, theEPA regulates greenhouse gas emissions pursuant to the Clean Air Act. The regulations implemented byEPA impose more stringent leak detection and repair requirements, and further address reporting and control of methane and volatile organic compound emissions. The current administration has issued executive orders to review and potentially roll back 42
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many of these burdensome regulations, and, in turn, litigation (not involving the Company) has been instituted to challenge the administration's efforts. The Company must continue to comply with all applicable regulations. A number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions.Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines and is in the process of evaluating cap-and-trade programs (e.g., Regional Greenhouse Gas Initiative). InCalifornia , the Company currently complies withCalifornia cap-and-trade rules, which increases the Company's cost of environmental compliance in its Exploration and Production segment. Legislation or regulation that aims to reduce greenhouse gas emissions could also include emissions limits, reporting requirements, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. Federal, state or local governments may provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources.New York State , for example, passed the CLCPA that mandates reducing greenhouse gas emissions to 60% of 1990 levels by 2030, and to 15% of 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets. The CLCPA also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% by 2040. These climate change and greenhouse gas initiatives could impact the Company's customer base and assets depending on regulatory treatment afforded in the process. These initiatives could also increase the Company's cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by administrative agencies, make it difficult to predict a long-term business impact across twenty or more years.
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 the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words "anticipates," "estimates," "expects," "forecasts," "intends," "plans," "predicts," "projects," "believes," "seeks," "will," "may," and similar expressions, are "forward-looking statements" as defined in the Private Securities Litigation Reform Act of 1995 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 Company's expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, 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 the price of natural gas or oil; 2. Impairments under theSEC's full cost ceiling test for natural gas and oil reserves; 3. Changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real
property, and exploration and production activities such as hydraulic
fracturing;
4. Delays or changes in costs or plans with respect to Company projects or
related projects of other companies, including difficulties or delays
in obtaining necessary governmental approvals, permits or orders or in
obtaining the cooperation of interconnecting facility operators;
5. Governmental/regulatory actions, initiatives and proceedings, including
those involving rate cases (which address, among other things, target
rates of return, rate design and retained natural gas),
environmental/safety requirements, affiliate relationships, industry
structure, and franchise renewal;
6. Changes in price differentials between similar quantities of natural
gas or oil at different geographic locations, and the effect of such
changes on commodity production, revenues and demand for pipeline
transportation capacity to or from such locations;
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7. Financial and economic conditions, including the availability of
credit, and occurrences affecting the Company's ability to obtain
financing on acceptable terms for working capital, capital expenditures
and other investments, including any downgrades in the Company's credit
ratings and changes in interest rates and other capital market
conditions;
8. Factors affecting the Company's ability to successfully identify, drill
for and produce economically viable natural gas and oil reserves,including among others geology, lease availability, title disputes,
weather conditions, shortages, delays or unavailability of equipment
and services required in drilling operations, insufficient gathering,
processing and transportation capacity, the need to obtain governmental
approvals and permits, and compliance with environmental laws and
regulations;
9. Increasing health care costs and the resulting effect on health
insurance premiums and on the obligation to provide other
post-retirement benefits;
10. Other changes in price differentials between similar quantities ofnatural gas or oil having different quality, heating value, hydrocarbon
mix or delivery date;
11. The cost and effects of legal and administrative claims against the
Company or activist shareholder campaigns to effect changes at the
Company;
12. Uncertainty of oil and gas reserve estimates;
13. Significant differences between the Company's projected and actual
production levels for natural gas or oil;
14. Changes in demographic patterns and weather conditions;
15. Changes in the availability, price or accounting treatment of
derivative financial instruments;
16. Changes in laws, actuarial assumptions, the interest rate environment
and the return on plan/trust assets related to the Company's pension
and other post-retirement benefits, which can affect future funding
obligations and costs and plan liabilities;
17. Changes in economic conditions, including global, national or regional
recessions, and their effect on the demand for, and customers' ability
to pay for, the Company's products and services;
18. The creditworthiness or performance of the Company's key suppliers,
customers and counterparties;
19. The impact of information technology, cybersecurity or data security
breaches;
20. Economic disruptions or uninsured losses resulting from major
accidents, fires, severe weather, natural disasters, terrorist
activities or acts of war;
21. Significant differences between the Company's projected and actual
capital expenditures and operating expenses; or
22. Increasing costs of insurance, changes in coverage and the ability to
obtain insurance.
The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
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