<PAGE 1>
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended December 31, 1993
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From to
Commission File Number 1-3880
NATIONAL FUEL GAS COMPANY
(Exact name of registrant as specified in its charter)
New Jersey 13-1086010
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
30 Rockefeller Plaza
New York, New York 10112
(Address of principal executive offices) (Zip Code)
(212) 541-7533
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES X NO
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Common stock, $1 par value, outstanding at January 31, 1994: 37,035,131 shares.
<PAGE 2>
Company or Group of Companies for which Report is Filed:
NATIONAL FUEL GAS COMPANY (Company or Registrant)
SUBSIDIARIES: National Fuel Gas Distribution Corporation (Distribution
Corporation)
National Fuel Gas Supply Corporation (Supply Corporation)
Penn-York Energy Corporation (Penn-York)
Seneca Resources Corporation (Seneca)
Empire Exploration, Inc. (Empire)
Utility Constructors, Inc. (UCI)
Highland Land & Minerals, Inc. (Highland)
Leidy Hub, Inc. (Leidy Hub)**
Data-Track Account Services, Inc. (Data-Track)
National Fuel Resources, Inc. (NFR)
INDEX
Part I. Financial Information Page
Item 1. Financial Statements
a. Consolidated Statements of Income and Earnings
Reinvested in the Business - Three Months Ended
December 31, 1993 and 1992 3
b. Consolidated Balance Sheet - December 31, 1993
and September 30, 1993 4 - 5
c. Consolidated Statement of Cash Flows - Three
Months Ended December 31, 1993 and 1992 6
d. Notes to Consolidated Financial Statements 7 - 14
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 15 - 24
Part II. Other Information
Item 1. Legal Proceedings 25 - 27
Item 2. Changes in Securities *
Item 3. Defaults Upon Senior Securities *
Item 4. Submission of Matters to a Vote of Security Holders *
Item 5. Other Information *
Item 6. Exhibits and Reports on Form 8-K 27
Signature 28
*The Company has nothing to report under this item.
**Effective December 29, 1993, Enerop Corporation's name was changed to Leidy
Hub, Inc.
<PAGE 3>
Part I. - Financial Information
Item 1. - Financial Statements
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
(Unaudited)
Three Months Ended
December 31,
1993 1992
(Thousands of Dollars)
INCOME
Operating Revenues $ 310,131 $294,220
Operating Expenses
Purchased Gas 144,158 134,014
Operation Expense 63,547 61,989
Maintenance 5,416 5,857
Property, Franchise and Other Taxes 25,283 24,585
Depreciation, Depletion and Amortization 17,885 16,538
Income Taxes - Net 15,097 12,785
271,386 255,768
Operating Income 38,745 38,452
Other Income 1,039 1,509
Income Before Interest Charges 39,784 39,961
Interest Charges
Interest on Long-Term Debt 8,883 10,071
Other Interest 3,101 3,949
11,984 14,020
Income Before Cumulative Effect 27,800 25,941
Cumulative Effect of Change
in Accounting for Income Taxes 3,826 -
Net Income Available for Common Stock 31,626 25,941
EARNINGS REINVESTED IN THE BUSINESS
Balance at October 1 335,907 314,334
367,533 340,275
Dividends on Common Stock
(1993 - $.385; 1992 - $.375) 14,191 12,721
Balance at December 31 $ 353,342 $327,554
Earnings Per Common Share
Income Before Cumulative Effect $ .76 $ .77
Cumulative Effect of Change
in Accounting for Income Taxes .10 -
Net Income Available for Common Stock $ .86 $ .77
Weighted Average Common Shares Outstanding 36,752,985 33,909,177
See Notes to Consolidated Financial Statements
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Item 1. - Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Balance Sheet
December 31,
1993 September 30,
(Unaudited) 1993
(Thousands of Dollars)
ASSETS
Property, Plant and Equipment $2,067,234 $2,039,436
Less - Accumulated Depreciation, Depletion
and Amortization 575,677 561,433
1,491,557 1,478,003
Current Assets
Cash and Temporary Cash Investments 17,795 13,595
Receivables - Net 142,861 86,957
Unbilled Utility Revenue 70,139 27,210
Gas Stored Underground 15,910 22,120
Materials and Supplies - at average cost 21,328 20,848
Unrecovered Purchased Gas Costs 36,262 20,772
Prepayments 17,425 17,094
321,720 208,596
Other Assets
Recoverable Future Taxes 104,156 -
Deferred Contract Reformation Costs 17,568 24,862
Unamortized Debt Expense 28,171 28,735
Other Regulatory Assets 46,600 37,788
Deferred Charges 3,332 2,249
Other 22,965 21,307
222,792 114,941
$2,036,069 $1,801,540
See Notes to Consolidated Financial Statements
<PAGE 5>
Item 1. - Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Balance Sheet
December 31,
1993 September 30,
(Unaudited) 1993
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common Stock Equity
Common Stock, $1 Par Value
Authorized - 100,000,000 Shares; Issued and
Outstanding - 36,988,913 Shares and 36,661,008
Shares, Respectively $ 36,989 $ 36,661
Paid In Capital 371,097 363,677
Earnings Reinvested in the Business 353,342 335,907
Total Common Stock Equity 761,428 736,245
Long-Term Debt 478,417 478,417
Total Capitalization 1,239,845 1,214,662
Current and Accrued Liabilities
Notes Payable to Banks and
Commercial Paper 238,600 196,800
Accounts Payable 65,778 42,893
Amounts Payable to Customers 32,214 40,776
Other Accruals and Current Liabilities 105,708 69,523
442,300 349,992
Deferred Credits
Taxes Refundable to Customers 31,985 -
Unamortized Investment Tax Credit 14,572 14,743
Accumulated Deferred Income Taxes 271,194 188,793
Other Deferred Credits 36,173 33,350
353,924 236,886
Commitments and Contingencies - -
$2,036,069 $1,801,540
See Notes to Consolidated Financial Statements
<PAGE 6>
Item 1. - Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Statement of Cash Flows
(Unaudited)
Three Months Ended
December 31,
1993 1992
(Thousands of Dollars)
OPERATING ACTIVITIES
Net Income Available for Common Stock $ 31,626 $ 25,941
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities:
Effect of Noncash Adjustments:
Cumulative Effect of Change in
Accounting for Income Taxes (3,826) -
Depreciation, Depletion and Amortization 17,885 16,538
Deferred Income Taxes 7,673 5,166
Other 1,820 1,856
55,178 49,501
Change in:
Receivables and Unbilled Utility Revenue (98,833) (92,320)
Gas Stored Underground and Materials and
Supplies 5,730 18,122
Unrecovered Purchased Gas Costs (15,490) (8,189)
Prepayments (331) 2,214
Accounts Payable 22,885 8,210
Amounts Payable to Customers (8,562) (5,357)
Other Accruals and Current Liabilities 42,647 23,065
Other Assets and Liabilities - Net (1,617) (1,487)
Net Cash Provided by (Used in)
Operating Activities 1,607 (6,241)
INVESTING ACTIVITIES
Capital Expenditures (31,124) (28,315)
Other 2,986 7
Net Cash Used in Investing Activities (28,138) (28,308)
FINANCING ACTIVITIES
Change in Notes Payable to Banks and Commercial
Paper 41,800 (2,900)
Proceeds from Issuance of Long-Term Debt - 50,000
Reduction of Long-Term Debt - (50,000)
Proceeds from Issuance of Common Stock 3,033 1,369
Dividends Paid on Common Stock (14,102) (12,681)
Net Cash Provided by (Used in)
Financing Activities 30,731 (14,212)
Net Increase (Decrease) in Cash and
Temporary Cash Investments 4,200 (48,761)
Cash and Temporary Cash Investments
at October 1 13,595 76,278
Cash and Temporary Cash Investments at December 31 $ 17,795 $ 27,517
See Notes to Consolidated Financial Statements
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Item 1. Financial Statements (cont.)
National Fuel Gas Company
Notes to Consolidated Financial Statements
Note 1 - Summary of Significant Accounting Policies
Quarterly Earnings. The Company, in its opinion, has included all adjustments
that are necessary for a fair statement of the results of operations for the
periods. The fiscal 1994 consolidated financial statements will be examined by
the Company's independent accountants after the end of the fiscal year. The
consolidated financial statements and notes thereto, included herein, should be
read in conjunction with the financial statements and notes for the years ended
September 30, 1993, 1992 and 1991, that are included in the Company's 1993
Annual Report to the Securities and Exchange Commission (SEC) on Form 10-K.
The earnings for the three months ended December 31, 1993, should not be
taken as a prediction for the fiscal year ending September 30, 1994, as most of
the Company's business is seasonal in nature and is influenced by weather
conditions. Because of the seasonal nature of the Company's heating business,
earnings during the winter months normally represent a substantial part of
earnings for the entire fiscal year. The impact of abnormal weather on
earnings during the heating season is partially reduced by the operation of a
weather normalization clause included in Distribution Corporation's New York
tariff. The weather normalization clause is effective for October through May
billings. In addition, Supply Corporation's straight fixed variable rate
design, which allows for recovery of substantially all fixed costs in the
demand or reservation charge, reduces the earnings impact of both weather and
unused subscribed pipeline capacity.
Rate Refunds. Supply Corporation and Penn-York collect revenues subject to
refund if a final rate case settlement is pending. Estimated rate refunds are
recorded which reflect management's current estimate as to the ultimate outcome
of each rate case.
On October 15, 1993, Supply Corporation filed a Stipulation and Agreement
(the Settlement) with the Federal Energy Regulatory Commission (FERC)
respecting two rate proceedings, which resolves all the issues in these
proceedings. On December 30, 1993, the FERC issued an order approving the
Settlement, with slight modification. The amount of Supply Corporation's
refund liability at December 31, 1993, was $13,850,000, including interest.
The majority of this amount was refunded to Supply Corporation's customers,
including Distribution Corporation on January 31, 1994. The remainder will be
refunded in the near future. Distribution Corporation will pass back this
refund to its customers over a one year period beginning in March 1994 in New
York and a one year period beginning August 1994 in Pennsylvania.
Consolidated Statement of Cash Flows. For purposes of the Consolidated
Statement of Cash Flows, the Company considers all highly liquid debt
instruments purchased with a maturity of generally three months or less to be
<PAGE 8>
Item 1. Financial Statements (cont.)
December 31, 1993 and 1992, amounted to $10,626,000 and $5,269,000,
respectively. Income taxes paid during the three months ended December 31,
1993 and 1992 amounted to $864,000 and $520,000, respectively.
On December 10, 1993, the Company entered into a non-cash investing
activity whereby it issued 108,396 shares of Company common stock to Empire,
which in turn exchanged these shares for $3,184,000 of natural gas production
assets, $167,000 of other current assets and $280,000 of cash.
Reclassification. The cost of transporting gas is included on the Consolidated
Statement of Income in "Purchased Gas." Prior period amounts have been
reclassified to conform with current period presentation.
Financial Instruments. Seneca and NFR engage in the gas futures market to lock
in natural gas prices to decrease volatility related to fluctuations in market
prices. Gains or losses resulting from changes in the market value of these
transactions are deferred until the hedged commodity transaction occurs.
Seneca has also entered into certain price swap agreements to effectively
manage a portion of the market risk associated with fluctuations in the price
of natural gas. The agreements call for Seneca to make payments to (or receive
payments from) other parties based upon the differential between a fixed and a
variable price as specified by the contract. The current agreements run from
January 1994 through December 1994 and have a notional contract amount of
12,200,000 MMBtu of natural gas equivalent.
Management does not expect the gas futures or swap agreements to have a
material effect on either the results of operations or the financial condition
of the Company at this time.
NOTE 2 - Regulatory Matters
FERC Order 636 Transition Costs. As a result of the industry-wide
restructuring under FERC Order 636, Distribution Corporation is incurring
transition costs billed by Supply Corporation and other upstream pipeline
companies. Distribution Corporation's current estimate of these transition
costs, including its allocable share of Supply Corporation's transition costs,
is approximately $147,000,000. The majority of these costs relate to gas
supply realignment (GSR) and stranded costs. This estimate was determined from
information provided in the Order 636 compliance filings of Supply Corporation
and the five interstate pipeline companies that directly serve Supply
Corporation, and is exclusive of any potential stranded costs related to
production plant or gathering facilities which pipeline companies, including
Supply Corporation, may file for at a future date and any potential GSR costs
charged by an upstream supplier, which are subject to the outcome of its
bankruptcy proceedings. To date, approximately $24,900,000 of transition costs
have been accepted by the FERC for billing to Distribution Corporation or
Supply Corporation, subject to refund. This is exclusive of $14,687,000 of
Supply Corporation's over-recovered purchased gas costs refunded to
Distribution Corporation on September 30, 1993. Distribution Corporation has
been and will continue to be actively challenging relevant FERC filings made by
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Item 1. Financial Statements (cont.)
the upstream pipeline companies to ensure the eligibility and prudency of all
transition cost claims.
Currently, Distribution Corporation has estimated that transition costs
allocable to the Pennsylvania jurisdiction are approximately $50,600,000. On
October 15, 1993, the Pennsylvania Public Utility Commission (PaPUC) issued a
policy statement on the recovery of transition costs. The policy statement
permits local distribution companies, such as Distribution Corporation, the
opportunity for full recovery of GSR and stranded costs from customers through
a separate surcharge, and recovery of under-recovered purchased gas costs
(Account 191 costs) and costs related to new facilities from sales customers
through gas cost recovery rates. Effective August 1, 1993, Distribution
Corporation began recovering Account 191 transition costs from its Pennsylvania
sales customers in connection with its annual purchased gas cost filing. On
December 1, 1993, the PaPUC issued an order on certain issues concerning
recovery of GSR and stranded costs by Distribution Corporation in connection
with its March 31, 1993 rate filing with the PaPUC. Under this order,
Distribution Corporation began collecting, effective December 1, 1993,
approximately $4,000,000 of GSR and stranded costs from its customers.
Distribution Corporation is also allowed quarterly updates for transition cost
recovery and has implemented the first such update for an additional
$1,500,000, effective as of February 1, 1994.
In its August 27, 1993 rate filing with the State of New York Public
Service Commission (PSC), Distribution Corporation filed for recovery of an
initial annual amount of $24,900,000 of estimated transition costs. Currently,
total estimated transition costs for the New York jurisdiction are
approximately $96,400,000. The PSC has not determined its policy with respect
to the recovery of transition costs. However, on October 28, 1993, the PSC
instituted a state-wide proceeding to review the issues associated with Order
636 restructuring. The PSC currently expects to have this proceeding concluded
before the 1994-1995 heating season. Distribution Corporation is actively
participating in this state-wide proceeding.
While the state-wide proceeding is continuing, the PSC staff, in
connection with the above-noted and on-going rate case, has proposed that
transition costs allocable to sales customers be recovered from such customers
through the monthly Gas Adjustment Clause (GAC). Distribution Corporation has
accepted PSC staff's proposal and, effective February 1, 1994, began recovering
such costs from sales customers through the GAC. As with all costs included in
the GAC mechanism, the ultimate recovery of transition costs is subject to
final approval by the PSC. Since recovery of transition costs from
transportation customers is still being contested in this rate case,
Distribution Corporation will continue to defer amounts relating to those
customers until recovery is authorized by the PSC.
Management believes that any transition costs resulting from the
implementation of Orders 636, 636-A and 636-B should be fully recoverable from
the respective customers of Supply Corporation and Distribution Corporation to
the extent such costs are prudently incurred.
<PAGE 10>
Item 1. Financial Statements (cont.)
Penn-York/Supply Corporation Merger. On January 19, 1994, the FERC issued an
order approving the merger of Penn-York into Supply Corporation, which was
applied for on May 21, 1992. After the merger, Supply Corporation will
continue to provide all the services Penn-York provides under the same rates,
terms and conditions. The merger must be completed within one year from the
date of the FERC's order.
NOTE 3 - Income Taxes
On October 1, 1993, the Company adopted Financial Accounting Standards No.
109 (SFAS 109), "Accounting for Income Taxes." The adoption of SFAS 109
changed the Company's method of accounting for income taxes from the deferred
method to an asset and liability approach. Previously, deferred taxes were
provided for the tax effects of timing differences between financial reporting
purposes and tax reporting purposes. The asset and liability approach requires
the recognition of deferred tax liabilities and assets for the expected future
tax consequences attributable to temporary differences between the carrying
amounts of assets and liabilities and their tax bases. In addition, such
deferred tax assets and liabilities will be adjusted for the effects of enacted
changes in tax laws and rates.
The cumulative effect of this change increased net income by $3,826,000 as
a result of the reduction in deferred income taxes associated with the
Company's nonregulated operations. A reduction in previously recorded deferred
income taxes associated with rate-regulated activities of $31,985,000 has been
reclassified to a regulatory liability since such amounts are expected to be
refundable to customers under regulatory procedures.
In addition, under SFAS 109, the Company is required to recognize
additional deferred tax liabilities and assets for timing differences on which
deferred tax treatment was not permitted by regulatory authorities. The
recognition of these deferred tax balances will have no effect on earnings due
to the recording of corresponding regulatory assets representing future amounts
collectible from customers in the rate-making process. The additional deferred
taxes amounted to $104,156,000 at December 31, 1993.
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Item 1. Financial Statements (cont.)
At December 31, 1993, the deferred tax liabilities (assets) were comprised
of the following (in thousands):
Accumulated Deferred
Deferred Income Taxes
Income Taxes Current*
Deferred Tax Liabilities:
Excess of tax over book depreciation $176,244 $ -
Exploration and intangible well
drilling costs 70,859 -
Unrecovered purchased gas costs - 11,333
Other 66,397 -
Total Deferred Tax Liabilities 313,500 11,333
Deferred Tax Assets:
Deferred investment tax credits (8,793) -
Overheads capitalized for tax purposes (8,293) -
Tax credit carryforwards (4,786) -
Provisions for rate contingencies and
refunds - (6,104)
Other (20,434) -
Total Deferred Tax Assets (42,306) (6,104)
Total Net Deferred Income Taxes $271,194 $ 5,229
* Included on the Consolidated Balance Sheet in "Other Accruals and Current
Liabilities."
The components of federal and state income taxes included in the
Consolidated Statement of Income are as follows (in thousands):
Three Months Ended
December 31,
1993 1992
Operating Expenses:
Current Income Taxes -
Federal $ 7,884 $ 7,740
State (460) (121)
Deferred Income Taxes 7,673 5,166
15,097 12,785
Other Income
Deferred Investment Tax Credit (172) (174)
Cumulative effect prior to
October 1, 1993 of applying SFAS
No. 109 (3,826) -
Total Income Taxes $11,099 $12,611
<PAGE 12>
Item 1. Financial Statements (cont.)
Total income taxes as reported differ from the amounts that were computed
by applying the federal income tax rate to income before income taxes. The
following is a reconciliation of this difference (in thousands):
Three Months Ended
December 31,
1993 1992
Net income available for common stock $31,626 $25,941
Total income taxes 11,099 12,611
Income before income taxes 42,725 38,552
Income tax expense, computed at
statutory rate of 35% in 1993
and 34% in 1992 14,954 13,108
Increase (reduction) in taxes resulting from:
Current state income taxes (299) (77)
Depreciation 425 642
Production tax credits (432) (279)
Miscellaneous 277 (783)
Income taxes charged to operating income 14,925 12,611
Cumulative effect prior to October 1, 1993 of
applying SFAS No. 109 (3,826) -
Total Income Taxes $11,099 $12,611
NOTE 4 - Capitalization
Common Stock. During the three months ended December 31, 1993, the Company
issued 72,133 shares of common stock under the Company's Customer Stock
Purchase Plan and 29,000 shares to participants in the Company's section 401(k)
plans.
In December 1993, 121,494 shares of restricted stock were awarded under
the 1993 Award and Option Plan. Restrictions on 113,494 shares will lapse
respecting an equal number of shares on each January 2, 1996 through 2001.
Restrictions on 8,000 shares will lapse respecting an equal number of shares on
each January 2, 2001 through 2004.
In December 1993, the Company issued 108,396 shares of common stock to
Empire, which in turn exchanged these shares for natural gas production assets.
See further discussion of this acquisition under "Consolidated Statement of
Cash Flows," in Note 1.
<PAGE 13>
Item 1. Financial Statements (cont.)
NOTE 5 - Other Post-Retirement Benefits
In addition to providing retirement plan benefits, the Company currently
provides health care and life insurance benefits for substantially all retired
employees under a post-retirement benefit plan (Post-Retirement Plan).
The Company has adopted SFAS 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions" (SFAS 106), effective October 1,
1993. This statement required the Company to change its accounting for these
post-retirement benefits from the "pay-as-you-go" (cash) basis to the accrual
basis.
The Company has established Voluntary Employees' Beneficiary Association
(VEBA) trusts for collectively bargained employees and non-bargaining
employees. The VEBA trusts are similar to the Company's Retirement Plan trust.
Contributions to the VEBA trusts are tax deductible, subject to limitations
contained in the Internal Revenue Code and regulations. Contributions to the
VEBA trusts are intended to fund employees' post-retirement health care and
life insurance benefits, as well as benefits as they are paid to current
retirees.
The Company has elected to amortize the initial accumulated liability
(transition obligation) to net periodic post-retirement benefit cost on a
straight-line basis over a 20-year period.
The following table sets forth the Post-Retirement Plan's funded status,
as determined by its consulting actuary, as of October 1, 1993:
(in thousands)
Accumulated Post-Retirement Benefit Obligation $179,742
Fair Value of Post-Retirement Plan Assets 7,185
Transition Obligation $172,557
Service Cost $ 3,974
Interest Cost 13,714
Expected Return on Post-Retirement Plan Assets (1,035)
Amortization of Transition Obligation 8,628
Post-Retirement Benefit Cost for Fiscal 1994 $ 25,281
Approximately $6,415,000 of post-retirement benefit cost has been recorded
for the three months ended December 31, 1993. Of this amount, $707,000 has
been deferred for regulatory purposes and $5,708,000 has been recognized in the
Consolidated Statement of Income.
The weighted-average assumed discount rate used in determining the
accumulated post-retirement benefit obligation was 7.75% at the beginning and
end of the fiscal year. The average assumed annual rate of salary increase for
the applicable life insurance plans was 5%.
<PAGE 14>
Item 1. Financial Statements (Concl.)
The annual rate of increase in the per capita cost of covered medical care
benefits for the active participants and medical plans available to new
retirees was assumed to be 13% for 1994; this rate was assumed to decrease
gradually to 5.5% by the year 2002 and remain at that level thereafter. The
annual rate of increase in the per capita cost of covered medical care benefits
for the medical plans not available to new retirees was assumed to be 8% for
1994, 7% for 1995, 6% for 1996 and 5.5% for each year after 1996. The annual
rate of increase in the per capita cost of covered prescription drug benefits
was assumed to be 14% for 1994. This rate was assumed to decrease gradually to
5.5% by the year 2003 and remain level thereafter.
The health care cost trend rate assumptions used to calculate the per
capita cost of covered medical care benefits have a significant effect on the
amounts reported. If the health care cost trend rates were increased by 1% in
each year, the accumulated post-retirement benefit obligation as of October 1,
1993, would be increased by $26.6 million. This 1% change would also increase
the aggregate of the service and interest cost components of net periodic
post-retirement benefit cost for 1994 by $3.1 million.
Distribution Corporation, Supply Corporation and Penn-York represent
virtually all of the Company's total post-retirement benefit costs. The PSC,
PaPUC and the FERC have each issued a generic policy statement on SFAS 106.
These policy statements essentially allow for the full recovery of
post-retirement benefit costs provided amounts collected are funded.
Distribution Corporation, Supply Corporation and Penn-York are fully recovering
their net periodic post-retirement benefit costs. The Company's current policy
is to invest Post-Retirement Plan assets primarily in equity securities and
municipal bonds.
NOTE 6 - Commitments and Contingencies
In addition to the litigation discussed in Part II, Item 1 of this report,
the Company is involved in litigation arising in the normal course of business.
In addition to the regulatory matters discussed in Note 2, the Company is
involved in other regulatory matters arising in the normal course of business
that involve rate base, cost of service and purchased gas cost issues. While
the resolution of such litigation or other regulatory matters could have a
material effect on earnings and cash flows in the year of resolution, none of
this litigation, and none of these other regulatory matters, is expected to
have a material effect on the financial condition of the Company at this time.
<PAGE 15>
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
RESULTS OF OPERATIONS
Earnings.
Net income available for common stock was $31.6 million during the quarter
ended December 31, 1993. This includes $3.8 million of earnings related to the
cumulative effect of a required change in accounting for income taxes adopted
October 1, 1993, in accordance with the Financial Accounting Standards Board's
(FASB) Statement of Financial Accounting Standards No. 109, "Accounting for
Income Taxes" (SFAS 109). Income before the cumulative effect of the change in
accounting for income taxes amounted to $27.8 million, an increase of $1.9
million, or 7%, from the $25.9 million earned during the same period a year ago.
The increase in earnings, before the cumulative effect of the change in
accounting for income taxes, is attributable to higher earnings from the
Company's Pipeline and Storage segment, mainly because of the approval of a
favorable rate settlement by the Federal Energy Regulatory Commission (FERC)
and receipt of a refund of prior costs related to joint storage sites. In
addition, the Company's Nonregulated operations showed improved results when
compared with the first quarter of last year. The Exploration and Production
segment's earnings increased slightly as a result of increased gas and oil
production. However, this was largely offset by higher depletion expense. The
Company's pipeline construction subsidiary incurred a smaller loss this year
compared with last year's first quarter, and earnings of the Company's gas
marketing subsidiary improved.
Earnings from the Company's Utility Operation were down despite colder
weather and general rate increases because of the timing of gas cost
adjustments in the New York jurisdiction and the loss in margin from the shift
of industrial throughput from sales service to transportation service and
alternative fuels.
Earnings per common share were $.86 for the quarter ended December 31,
1993. This includes earnings of $.10 per share related to the cumulative
effect of a required change in accounting for income taxes in accordance with
SFAS 109. Earnings per common share before the cumulative effect of the change
in accounting for income taxes amounted to $.76. This compares to earnings per
common share of $.77 for the quarter ended December 31, 1992. Per share
amounts reflect a greater number of weighted average shares outstanding in the
current period resulting mainly from the sale of 2.5 million shares of common
stock on May 20, 1993.
<PAGE 16>
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations (Cont.)
Financial Information by Business Segment.
The following tables compare System Throughput, Production Volumes,
Operating Revenues and Operating Income Before Income Taxes by business
segment, with the corresponding prior period:
SYSTEM THROUGHPUT
(millions of cubic feet-MMcf)
Three Months Ended
December 31,
1993 1992 % Change
Utility Operation
Retail Sales:
Residential 26,997 26,636 1.4
Commercial 7,722 7,808 (1.1)
Industrial 1,716 2,868 (40.2)
36,435 37,312 (2.4)
Transportation 12,258 11,165 9.8
48,693 48,477 .4
Pipeline and Storage
Wholesale Sales* - 41,920 (100.0)
Transportation 79,771 36,597 118.0
79,771 78,517 1.6
Less-Intersegment Throughput:
Sales - 39,065 (100.0)
Transportation 50,121 8,082 520.2
50,121 47,147 6.3
Total System Throughput 78,343 79,847 (1.9)
* Effective August 1, 1993, sales contracts were converted to transportation
and storage arrangements as a result of restructuring under FERC Order 636.
PRODUCTION VOLUMES
Exploration and Production
Three Months Ended
December 31,
1993 1992 % Change
Gas Production - (MMcf)
Gulf Coast 3,076 1,791 71.7
West Coast 208 298 (30.2)
Appalachia 1,574 1,675 (6.0)
4,858 3,764 29.1
Oil Production - (Thousands of Barrels)
Gulf Coast 99 53 86.8
West Coast 102 113 (9.7)
Appalachia 3 5 (40.0)
204 171 19.3
<PAGE 17>
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations (Cont.)
OPERATING REVENUES
(in thousands)
Three Months Ended
December 31,
1993 1992 % Change
Regulated
Utility Operation
Retail Revenues:
Residential $196,660 $184,555 6.6
Commercial 50,361 47,588 5.8
Industrial 8,394 13,184 (36.3)
255,415 245,327 4.1
Transportation 8,212 6,734 21.9
Other 1,071 733 46.1
264,698 252,794 4.7
Pipeline and Storage
Wholesale Revenues* - 158,023 (100.0)
Storage Service 14,553 8,952 62.6
Transportation 22,682 9,251 145.2
Other 881 792 11.2
38,116 177,018 (78.5)
Nonregulated
Exploration and Production 14,332 11,968 19.8
Other 14,786 9,031 63.7
29,118 20,999 38.7
Less-Intersegment Revenues 21,801 156,591 (86.1)
$310,131 $294,220 5.4
* Effective August 1, 1993, sales contracts were converted to transportation
and storage arrangements as a result of restructuring under FERC Order 636.
OPERATING INCOME BEFORE
INCOME TAXES
(in thousands)
Three Months Ended
December 31,
1993 1992 % Change
Regulated
Utility Operation $33,632 $35,581 (5.5)
Pipeline and Storage 16,729 13,946 20.0
Nonregulated
Exploration and Production 3,584 3,212 11.6
Other 635 (1,023) 162.1
4,219 2,189 92.7
Corporate (738) (479) (54.1)
$53,842 $51,237 5.1
<PAGE 18>
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations (Cont.)
Utility Operation.
Despite increased revenues resulting from a slight increase in Utility
throughput and general rate increases in the New York jurisdiction effective
July 23, 1993 and in the Pennsylvania jurisdiction effective December 1, 1993,
operating income before income taxes for the Utility Operation decreased $1.9
million for the current quarter compared with the same period a year ago. This
resulted from slightly higher operation and maintenance expense, from
adjustments to gas costs and from a loss in margin from the shift of industrial
gas sales to transportation service and to alternative fuels. Approximately
25% of the 1.2 billion cubic feet (Bcf) decline in industrial sales went to
oil. However, Distribution Corporation has a revenue sharing mechanism in its
New York jurisdiction that will provide a means to recover from its core
customers 90% of the margin lost on these sales before the end of the fiscal
year. The operation and maintenance expense increase is primarily due to the
timing of incurrence of expenses. The decrease in pretax operating income
resulting from the adjustments to gas costs relates to certain gas cost
adjustments that are always made in the first quarter of the fiscal year based
upon a rate year cycle ending August 31. The adjustments in both years
decreased gas costs; however, the decrease in gas costs in the current year was
less than in the prior year.
The Utility Operation's earnings should be favorably impacted in the
second quarter from the Pennsylvania jurisdiction's new rates, which became
effective December 1, 1993, combined with the extremely cold weather
experienced in January 1994. However, the impact of weather in the Utility
Operation's New York rate jurisdiction is tempered by its weather normalization
clause (WNC).
Degree Days
Three Months Ended December 31:
Percent Colder
(Warmer) Than
Normal 1993 1992 Normal Last Year
Buffalo 2,261 2,327 2,284 2.9 1.9
Erie 2,037 2,183 2,024 7.2 7.9
Rate Matters - Utility Operation. In August 1993, Distribution Corporation
filed in its New York rate jurisdiction a request for an annual rate increase
of $55.4 million, or 8.5%, with a return on equity of 12.16%. New rates are
expected to become effective in late July 1994. Included in the requested rate
increase is an initial amount of $24.9 million for the recovery of transition
costs arising from FERC Order 636. This represents 3.8% out of the total 8.5%
requested increase. The State of New York Public Service Commission (PSC) has
not determined its policy with respect to the recovery of transition costs.
However, on October 28, 1993, the PSC instituted a state-wide proceeding to
review the issues associated with Order 636 restructuring. The PSC currently
expects to have this proceeding concluded before the 1994-1995 heating season.
Distribution Corporation is actively participating in this state-wide
proceeding.
<PAGE 19>
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations (Cont.)
While the state-wide proceeding is continuing, the PSC staff, in
connection with the above-noted and on-going rate case, has proposed that
transition costs allocable to sales customers be recovered from such customers
through the monthly Gas Adjustment Clause (GAC). Distribution Corporation has
accepted PSC staff's proposal and, effective February 1, 1994, began recovering
such costs from sales customers through the GAC. As with all costs included in
the GAC mechanism, the ultimate recovery of transition costs is subject to
final approval by the PSC. Since recovery of transition costs from
transportation customers is still being contested in this rate case,
Distribution Corporation will continue to defer amounts relating to those
customers until recovery is authorized by the PSC.
In July 1993, in connection with a previously approved two-year
settlement, Distribution Corporation received PSC approval for the second year
of this settlement. The approval was for a rate increase of $13.3 million, or
2.1%, for the 12-month period ending July 31, 1994. This rate increase went
into effect on July 23, 1993.
In March 1993, Distribution Corporation filed with the Pennsylvania Public
Utility Commission (PaPUC) for an annual rate increase in its Pennsylvania
jurisdiction of $33.4 million, or approximately 16.2%, with a return on equity
of 12.4%. Included in the requested rate increase was an initial amount of
$8.2 million for the recovery of transition costs arising from FERC Order 636.
On December 1, 1993, an order was issued by the PaPUC authorizing an annual
rate increase of $11.4 million, or 4.9%, exclusive of transition costs. The
new rates became effective as of December 1, 1993.
The PaPUC's December 1 order also addressed certain issues concerning
recovery of gas supply realignment (GSR) costs and stranded costs resulting
from the implementation of FERC Order 636. Under this order, Distribution
Corporation began collecting, effective December 1, 1993, approximately $4
million of GSR and stranded costs from its customers. Distribution Corporation
is also allowed quarterly updates for transition cost recovery and has
implemented the first such update for an additional $1.5 million, effective as
of February 1, 1994. In addition, in connection with its annual purchased gas
cost filing, effective August 1, 1993, Distribution Corporation began
recovering estimated transition costs from its Pennsylvania customers related
to its upstream pipeline suppliers' balances of under-recovered purchased gas
costs to be billed to Distribution Corporation as a result of their
restructuring under Order 636.
Distribution Corporation expects to file for an annual rate increase in
its Pennsylvania jurisdiction in March 1994, for rates that will become
effective in December 1994.
General rate increases do not reflect the recovery of purchased gas costs.
Such costs are recovered through operation of the purchased gas adjustment
clauses of the regulatory authorities having jurisdiction.
<PAGE 20>
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations (Cont.)
Pipeline and Storage.
Operating income before income taxes for the Pipeline and Storage segment
increased $2.8 million as compared with the same period a year ago. Several
factors contributed to this increase, the most significant of which was the
settlement of Supply Corporations rate proceedings, discussed below under "Rate
Matters - Pipeline and Storage." Revenues for the quarter ended December 31,
1992 were based upon rates that were in effect, subject to refund. Management
reduced those revenues by recording an estimated refund provision accrual.
Based upon settlement of these rate proceedings in October 1993, it was
determined that the estimated refund provision was too high and revenues were
understated in the first quarter of fiscal 1993 by approximately $3.7 million.
This revenue was recognized in the fourth quarter of fiscal 1993.
Partly offsetting the rate settlement impact is the effect of Supply
Corporation's Straight Fixed Variable (SFV) rate design under FERC Order 636,
which became effective August 1, 1993. Under SFV, substantially all fixed
costs are recovered in the demand, or reservation charge, removing the
seasonality in the revenue stream and making monthly operating income somewhat
flat. The rate design that Supply Corporation was under prior to adopting
Order 636 allowed for recovery of approximately 50% of fixed costs in the
demand charge and 50% in the commodity charge. Under this prior rate design,
more revenue was recognized in periods of high throughput (i.e., winter
months). The SFV rate design accounted for an approximate $2.6 million
decrease in revenues and pretax operating income for the three months ended
December 31, 1993 as compared to the same period of last year. The effect of
SFV will create an even greater negative variance for the quarter ending March
31, 1994, but should show a positive variance, relative to the prior year, in
the third and fourth quarters of fiscal 1994.
In addition, for the three months ended December 31, 1993, Supply
Corporation recorded the receipt of approximately $1.3 million in refunds from
upstream pipeline companies for the correction of prior period overbillings on
joint storage operations.
Rate Matters - Pipeline and Storage. For a discussion of the Penn-York and
Supply Corporation merger, refer to Note 2 - Regulatory Matters.
On December 30, 1993, the FERC issued an order approving, with slight
modification, an Offer of Settlement (the Settlement), which was filed with the
FERC on October 15, 1993, respecting two Supply Corporation rate proceedings.
As modified, the Settlement provides for rates that will produce annual
revenues of approximately $125 million between July 1, 1992 and July 31, 1993.
Rates for the period beginning August 1, 1993 reflect reduced costs after
restructuring plus certain settlement concessions and provide for rates that
will produce revenues of approximately $121 million annually.
Supply Corporation expects to file for a rate increase in September 1994,
for rates that will become effective in April 1995.
<PAGE 21>
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations (Cont.)
Exploration and Production.
Operating income before income taxes from the Company's Exploration and
Production operations increased $.4 million compared with the same period a
year ago. Higher operating revenues of $2.4 million resulted mainly from
increased Gulf Coast natural gas production which was more than sufficient to
offset lower gas prices. System natural gas production increased 29% and
System weighted average gas prices declined $.09 per Mcf for the quarter ended
December 31, 1993, compared with the quarter ended December 31, 1992. However,
higher revenues from production were mostly offset by an increase in depletion
expense. Under this segment's method of computing depletion expense (unit of
revenue method) the depletion rate increases in a declining price environment.
The low oil price at the end of December 1993 was a significant factor in the
higher depletion rate for the quarter.
Other Nonregulated.
Operating income before income taxes associated with this segment
increased $1.7 million from the prior year mainly due to a better performance
by UCI, the Company's pipeline construction subsidiary. UCI incurred a smaller
loss in this year's first quarter compared with the same period last year. The
first quarter of fiscal 1993 included a large unprofitable job for UCI. In
addition, NFR, the Company's gas marketing subsidiary, had higher pretax
operating income in the quarter ended December 31, 1993 compared with the same
period last year as a result of increased volumes marketed.
Income Taxes.
Income taxes increased $2.3 million for the current quarter mainly because
of an increase in pretax income. The increase also reflects the increase in
the federal tax rate from 34% to 35%. Section 29 tight sands tax credits
related to gas production from qualified gas wells was $432,000 for the quarter
ended December 31, 1993 compared with $279,000 for the same period of the prior
year. These credits are a direct reduction of income tax expense.
Interest Charges.
Total interest charges decreased $2 million for the current quarter
compared with the same quarter of last year. Interest on long-term debt
decreased $1.2 million mainly because of lower interest rates due to
refinancing activities that have occurred since November 1992. Other interest
decreased $.8 million mainly because of lower interest on short-term debt.
Lower average amounts outstanding and lower interest rates caused this decline.
CAPITAL RESOURCES AND LIQUIDITY
The Company's primary sources of cash during the three month period
consisted of cash provided by operating activities and short-term bank loans
and commercial paper. These sources were supplemented by issuances of common
stock under the Company's Customer Stock Purchase Plan and section 401(K) Plans.
<PAGE 22>
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations (Cont.)
Operating Cash Flow
Internally generated cash from operating activities consists of net income
available for common stock, adjusted for noncash expenses, noncash income and
changes in operating assets and liabilities. Noncash items include
depreciation, depletion and amortization, deferred income taxes and allowance
for funds used during construction. For the three months ended December 31,
1993, a noncash income item also included the cumulative effect of a required
change in accounting for income taxes in accordance with SFAS 109.
Cash provided by operating activities in the Utility Operation and the
Pipeline and Storage segments may vary substantially from period to period
because of fluctuations in weather, over/under-recovered purchased gas costs,
supplier refunds and the impact of rate cases. The impact of weather in the
Utility Operation's New York rate jurisdiction is tempered by its WNC.
Effective August 1, 1993, Supply Corporation restructured under FERC Order
636. As Supply Corporation is no longer in the merchant function, it no longer
incurs over/under-recovered purchased gas costs. <PAGE>
Also, Supply Corporation's
SFV rate design reduces the impact of weather on
its cash flow.
Because of the seasonal nature of the Company's heating business, revenues
are relatively high during the quarter ended December 31, and the Consolidated
Balance Sheet at the end of December usually shows an increase in cash and
temporary cash investments over balances at the end of September. Receivables
and unbilled utility revenue historically increase from September to December
with the beginning of winter weather.
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. Under the last-in, first-out (LIFO) method of accounting, the
current cost of replacing gas withdrawn from storage is recorded in the
Consolidated Statement of Income and a reserve for gas replacement is recorded
in the Consolidated Balance Sheet and is included under the caption "Other
Accruals and Current Liabilities." Such reserve is reduced as the inventory is
replenished.
Net cash provided by operating activities totaled $1.6 million for the
quarter, an increase of $7.8 million compared with $6.2 million used by
operating activities in the first quarter of last year. This increase reflects
the Exploration and Production segment's higher operating revenues and earnings
coupled with their increased payable balances.
<PAGE 23>
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations (Cont.)
Investing Cash Flow
Capital Expenditures
The Company's capital expenditures totaled $34.3 million during the three
month period. This total includes $3.2 million of gas production assets
acquired in exchange for Company common stock. Total expenditures for the
quarter represent 23% of the total capital expenditure budget for fiscal 1994
of $147.2 million. The following table presents first quarter capital
expenditures by business segment:
(in thousands) Percentage
Regulated
Utility Operation $13,891 40.5%
Pipeline and Storage 4,352 12.7
Nonregulated
Exploration and Production 15,316 44.6
Other 749 2.2
16,065 46.8
$34,308 100.0%
The bulk of the Utility Operation's capital expenditures were made for
replacement of mains and main extensions, as well as for the replacement of
service lines and the installation of new services.
Pipeline and Storage capital expenditures during the quarter included $1.8
million to increase compression at two locations. In addition, capital
expenditures were made for additions, improvements, and replacements to the
this segment's transmission and storage systems.
Supply Corporation's Laurel Fields Storage Project is incurring delays in
establishing precedent agreements, thus, capital expenditures related to this
project are expected to be delayed until 1996.
Approximately 73% of the Exploration and Production segment's capital
expenditures were made by Seneca for the exploration and development of oil
and gas properties, specifically offshore in the Gulf of Mexico and in the
Austin Chalk formation in the Northeast Clay field in central Texas. In
addition, Empire acquired $3.2 million of natural gas production assets in
exchange for Company common stock. This acquisition added approximately 3 Bcf
of gas reserves.
Other Nonregulated capital expenditures included expenditures by UCI for
the acquisition of equipment.
The Company's capital expenditure program is under continuous review. The
amounts are subject to modification for opportunities in the natural gas
industry such as the acquisition of attractive oil and gas properties or
storage facilities and the expansion of transmission line capacities. The
magnitude of future capital expenditures in the regulated segments depends, to
<PAGE 24>
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations (Concl.)
a large degree, upon market conditions coupled with adequate rate relief.
Other
Cash received on the sale of the Company's investment in property, plant
and equipment is reflected as a cash flow from investing activities. For the
three months ended December 31, 1993, approximately $2.3 million of cash was
received related to the sale of Seneca's interest in its Alberta, Canada gas
reserves.
Financing Cash Flows
Consolidated short-term debt increased by $41.8 million during the first
quarter. The Company considers short-term bank loans and commercial paper
important sources of cash for temporarily financing construction expenditures,
gas in storage inventory, unrecovered purchased gas costs and other working
capital needs.
The Company, through Seneca and NFR, is engaged in the gas futures market
and in certain natural gas price swap agreements as a means of managing a
portion of the market risk associated with fluctuations in the market price of
natural gas. For further discussion, see disclosure under "Financial
Instruments" in Note 1, "Summary of Significant Accounting Policies."
At December 31, 1993, the Company had Security and Exchange Commission
authority remaining under a shelf registration filed in March 1993 to issue and
sell up to $320 million of debentures and/or medium-term notes. Depending on
market conditions and the requirements of the Company, the Company may issue
and sell approximately $100 million of the debentures and/or medium-term notes
within the remainder of fiscal 1994. The proceeds of such sales would be used
to replace outstanding short-term borrowings, to redeem or discharge higher
cost long-term debt, to finance a portion of the Company's capital expenditures
and/or for other general corporate purposes.
In addition to the litigation discussed in Part II, Item 1, of this
report, the Company is involved in litigation arising in the normal course of
business. In addition to the regulatory matters discussed in Note 2, the
Company is involved in other regulatory matters arising in the normal course of
business that involve rate base, cost of service and purchased gas cost issues,
among other things. While the resolution of such litigation or other
regulatory matters could have a material effect on earnings and cash flows in
the year of resolution, none of this other litigation and none of these other
regulatory matters are expected to change materially the Company's present
liquidity position.
The Company's present liquidity position is believed to be adequate to
satisfy known demands. The Company is reevaluating the treatment of regulatory
assets under its indenture covering long-term debt. Based upon a preliminary
reevaluation, the Company estimates that it would be permitted, under the
covenants of its indenture, to issue approximately $600 million in additional
long-term unsecured indebtedness at December 31, 1993. In addition, at
December 31, 1993, the Company had unused short-term credit lines of $111.4
million.
<PAGE 25>
Part II. Other Information
Item 1. Legal Proceedings
Paragon/TGX Litigation
A. New York Litigation
On November 30, 1984, Distribution Corporation commenced an action against
Paragon Resources, Inc. (Paragon) and TGX Corp. (collectively Paragon/TGX), in
the United States District Court for the Western District of New York (the
District Court) seeking a declaratory judgment concerning the contract effect
of a December 20, 1983 PSC order (the Disapproval Order). Among other things,
that order disapproved a 1974 gas purchase agreement between Distribution
Corporation's predecessor in interest, Iroquois Gas Corporation, and Paragon
(the "Paragon Contract"). Paragon/TGX counterclaimed for (i) a declaration
that the PSC order did not affect the Paragon Contract in any way, whatsoever,
(ii) approximately $4,400,000 in respect of take-or-pay claims, and (iii)
unquantified amounts in respect of other alleged breaches of the Paragon
Contract. Commencing with its payment for production received in September
1984, Distribution Corporation has paid Paragon/TGX for Paragon Contract gas at
prices below those developed by the Paragon Contract's price formula, as the
same have been impacted, from time to time, by the Natural Gas Policy Act of
1978 (NGPA).
On the basis of a Memorandum and Order dated December 10, 1988, the
District Court in January 1991 issued a partial summary judgment which declared
that, whereas the Disapproval Order abrogated only the Paragon Contract's price
term, the legal consequence of such abrogation was to render the Paragon
Contract "void and no longer of any force or effect" as of December 20, 1983.
On December 3, 1991 the U. S. Court of Appeals for the Second Circuit (the
Second Circuit) reversed the District Court's partial summary judgment and
remanded the case to the District Court for further proceedings. The Second
Circuit agreed with the District Court that the Disapproval Order had "voided
the Contract's price term," but did not agree that the Paragon Contract as a
whole was "voided by the cancellation of the price term." Rather, the Second
Circuit found that Paragon/TGX had elected an option available to it under the
Paragon Contract to continue that contract, in the aftermath of the Disapproval
Order, at "a price consistent with" that order.
In a letter dated December 13, 1991, TGX demanded that Distribution
Corporation pay it $21,874,042 (including interest), alleged to represent the
difference between the amount received by Paragon/TGX in respect of Paragon
Contract gas delivered during the period September 1984 through October 1991,
and the amount allegedly due TGX in respect of such gas during such period.
Distribution Corporation rejected TGX's demand.
By Order entered March 23, 1992, the District Court granted Distribution
Corporation permission to amend its reply to Paragon/TGX's counterclaims to
allege, among other things, (i) Distribution Corporation's "termination" of the
Paragon Contract by letter effective February 1, 1988; (ii) Paragon's pre-
September 1984 repudiation of the Paragon Contract; and (iii) the PSC's
"primary jurisdiction" to interpret the Disapproval Order as respects "a price
consistent" therewith. With respect to (iii) above, Distribution Corporation
<PAGE 26>
Item 3. Legal Proceedings - (Cont.)
notes that the New York State Public Service Law provides that no charge for
gas made pursuant to a contract with a New York gas utility shall exceed the
"just and reasonable charge" for such gas. In response to Distribution
Corporation's motion for partial summary judgment in respect of the defense
denominated (ii) above, the District Court, in a Memorandum and Order entered
July 10, 1992, as revised by a Memorandum and Order entered March 1, 1993,
denied Distribution Corporation's summary judgment motion (due to a perceived
question of fact as to the occurrence of a condition precedent to Paragon's
pre-September 1984 contract repudiation), but confirmed Distribution
Corporation's right to assert the repudiation defense upon the trial of the
action.
On January 4, 1993, the District Court entered a non-final order
purportedly responsive to a February 13, 1992 Paragon/TGX motion. The order
purports to declare that, by voiding the Paragon Contract price escalation
mechanism effective December 31, 1983, the PSC's 1983 Disapproval Order
effectively capped the Paragon Contract price, at the lesser, from time to
time, of (i) the 1983 Paragon Contract summer/winter "base prices," or (ii) the
applicable "Natural Gas Ceiling Prices" set forth in 18 CFR paragraph 271.101
Table I. Under date of January 19, 1993 Distribution Corporation sought
rehearing, reargument, reconsideration and clarification of the January 4, 1993
order. On July 12, 1993, the District Court filed a Memorandum and Order
granting in part the January 19, 1993 motion. The July 12, 1993 Order stated
that, while the January 4, 1993 Memorandum and Order did determine that an
obligation on Distribution Corporation's part to pay for gas purchased pursuant
to the gas purchase agreement at the applicable NGPA ceiling price arose out of
the conduct of the parties after the NGPA became effective and that the PSC
Order issued December 20, 1983 did not relieve Distribution Corporation of such
obligation, it did not determine the just and reasonable price for the gas
pursuant to Public Service Law section 110(4), set a contract price for the
duration of the contract, resolve any defenses presented by Distribution
Corporation, determine whether such obligation continues until the present
time, or rule on any deregulation issues.
Other motions are pending before the District Court regarding the
amendment of the pleadings of the parties and a request by TGX that
Distribution Corporation be required to pay a higher price for Paragon Contract
gas.
B. Louisiana Litigation
On February 22, 1990, TGX, the purported assignee of the Paragon Contract,
filed a voluntary petition pursuant to Chapter 11 of the United States
Bankruptcy Code in the United States Bankruptcy Court for the Western District
of Louisiana (the Bankruptcy Court). Thereafter TGX commenced a "turnover"
proceeding against Distribution Corporation, premised upon TGX's December 13,
1991 payment demand described above under "New York Litigation." Pursuant to a
partial settlement agreement between TGX and Distribution Corporation, approved
by the Bankruptcy Court in August 1992, TGX has withdrawn the "turnover"
proceeding and Distribution Corporation has paid to TGX $2,940,000 in
consideration of, among other things, TGX's release of Distribution Corporation
from the cause of action asserted in the "turnover" proceeding. TGX is still
<PAGE 27>
Item 3. Legal Proceedings - (Concl.)
free to pursue its breach of contract counterclaims in the New York Litigation.
However, the $2,940,000 paid by Distribution Corporation to TGX will be
credited against the amount, if any, which is ultimately adjudged due TGX
and/or Paragon in the New York Litigation.
C. State Commission Proceedings
By its "Order Instituting Proceeding," issued in Case 93-G-0352, et al.,
and effective April 28, 1993, the PSC granted Distribution Corporation deferral
authority in respect of the New York allocable share ($2,006,000) of the
partial settlement payment described above under "Louisiana Litigation" and
instituted a proceeding designed to address Distribution Corporation's request
for recovery authority in respect of that amount. Distribution Corporation has
received authority to treat the Pennsylvania allocable share ($934,000) of the
partial settlement payment as a gas cost experienced during the twelve (12)
month period ending November 30, 1992.
The PSC proceeding is also expected to address Distribution Corporation's
recovery in New York of gas costs incurred in respect of the Paragon Contract
during the reconciliation period September 1, 1991 through August 30, 1992.
Finally, the PSC proceeding is expected to include the review of the Paragon
Contract in light of the "just and reasonable" standard of the New York Public
Service Law. The parties to the PSC proceeding have submitted testimony and
will submit briefs to the Administrative Law Judge.
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 December 31, 1993.
(99) National Fuel Gas Company Consolidated
Statement of Income for the Twelve Months
Ended December 31, 1993 and 1992.
(b) Reports on Form 8-K
None
<PAGE 28>
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 under-
signed thereunto duly authorized.
NATIONAL FUEL GAS COMPANY
(Registrant)
/S/ Joseph P. Pawlowski
Joseph P. Pawlowski
Treasurer and Principal
Accounting Officer
Date: February 14, 1994
<TABLE>
<CAPTION>
EXHIBIT 12
NATIONAL FUEL GAS COMPANY
COMPUTATION OF ACTUAL RATIO OF
EARNINGS TO FIXED CHARGES
(UNAUDITED)
(Thousands of Dollars)
Twelve
Months
Ended Year Ended September 30
12/31/93 1993 1992 1991 1990 1989
EARNINGS:
<S> <C> <C> <C> <C> <C> <C>
Income Before Interest Charges(1) $125,462 $125,742 $118,222 $110,240 $109,781 $104,065
Allowance for Borrowed Funds
Used in Construction 132 174 1,088 2,278 1,273 775
Federal Income Tax 21,292 21,148 17,680 (3,929) 17,435 18,085
State Income Tax 2,640 2,979 3,426 342 2,419 4,168
Deferred Income Taxes - Net(3) 19,431 16,923 14,130 26,880 7,657 3,624
Investment Tax Credit - Net (694) (698) (711) (746) (798) (890)
Rentals(2) 5,667 5,621 5,857 4,915 4,915 4,915
$173,930 $171,889 $159,692 $139,980 $142,682 $134,742
FIXED CHARGES:
Interest and Amortization
of Premium and Discount
on Funded Debt $ 37,320 $ 38,507 $ 39,949 $ 41,916 $ 37,236 $ 29,949
Interest on Commercial Paper
and Short-Term Notes Payable 6,721 7,465 12,093 11,933 12,521 15,339
Other Interest(1) 4,478 4,727 6,958 9,679 9,298 7,132
Rentals(2) 5,667 5,621 5,857 4,915 4,915 4,915
$ 54,186 $ 56,320 $ 64,857 $ 68,443 $ 63,970 $ 57,335
Ratio of Earnings to
Fixed Charges 3.21 3.05 2.46 2.05 2.23 2.35
Note: (1) For the twelve months ended December 31, 1993, and the fiscal years ended September 30, 1993 and
1992, $1,478,000, $1,374,000, and $1,129,000, representing the amortization of loss on reacquired
debt each period, respectively, has been excluded from "Other Interest" and included as a
componenet of "Income Before Interest Charges."
(2) Rentals shown above represent the portion of all rentals (other than delay rentals) deemed
representative of the interest factor.
(3) For the twelve months ended December 31, 1993, excludes the cumulative effect of change in
accounting for income taxes in the amount of ($3,826,000).
</TABLE>
EXHIBIT 99
NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENT OF INCOME
(UNAUDITED)
Twelve Months Ended
December 31,
1993 1992
(Thousands of Dollars)
INCOME
Operating Revenues $1,036,294 $942,238
Operating Expenses
Purchased Gas 419,149 378,926
Operation Expense 260,476 244,650
Maintenance 23,871 23,187
Property, Franchise and Other Taxes 96,091 90,406
Depreciation, Depletion and Amortization 70,772 58,410
Income Taxes - Net 43,358 34,353
913,717 829,932
Operating Income 122,577 112,306
Other Income 4,363 5,064
Income Before Interest Charges 126,940 117,370
Interest Charges
Interest on Long-Term Debt 37,320 39,353
Other Interest 12,544 18,746
49,864 58,099
Income Before Cumulative Effect 77,076 59,271
Cumulative Effect of Change
in Accounting for Income Taxes 3,826 -
Net Income Available for Common Stock $ 80,902 $ 59,271
Earnings Per Common Share
Income Before Cumulative Effect $2.16 $1.86
Cumulative Effect of Change
in Accounting for Income Taxes .11 -
Net Income Available for Common Stock $2.27 $1.86
Weighted Average Common Shares Outstanding 35,655,517 31,881,532
<TABLE>
<CAPTION>
EXHIBIT 99
DATA STATED IN THOUSANDS
VOLUNTARY SCHEDULE - CERTAIN FINANCIAL INFORMATION
- ---------COLUMN A-------- ---------------COLUMN B---------------- --COLUMN C-- --COLUMN D-- --COLUMN E-- --COLUMN F--
REGULATION STATEMENT CAPTION FIRST QUARTER FIRST QUARTER YEAR-TO-DATE YEAR-TO-DATE
1994 1993 1994 1993
<S> <C> <C> <C> <C> <C>
5-02(1) Cash and Cash Items $ 17,795 $ 27,517
5-02(3)(a)(1) Accounts Receivable - Trade $ 149,911 $ 139,222
5-02(4) Allowance for Doubtful Accounts $ 7,050 $ 7,380
5-02(6)(a)(1) Finished Goods $ 15,910 $ 10,048
5-02(6)(a)(1) Finished Goods $ 21,328 $ 21,954
5-02(7) Prepaid Expenses $ 17,425 $ 13,391
5-02(8) Other Current Assets $ 106,401 $ 74,336
5-02(9) Total Current Assets $ 321,720 $ 279,088
5-02(13) Property, Plant & Equipment $2,067,234 $1,943,662
5-02(14) Accumulated Depreciation, Depletion
and Amortization of Property, Plant
and Equipment $ 575,677 $ 515,600
5-02(18) Total Assets $2,036,069 $1,803,253
5-02(19)(a)(1) Payable to Banks for Borrowings $ 238,600 $ 224,100
5-02(19)(a)(4) Trade Creditors $ 65,778 $ 53,682
5-02(20) Other Current Liabilities $ - $ 50,000
5-02(20) Other Current Liabilities $ 137,922 $ 118,257
5-02(21) Total Current Liabilities $ 442,300 $ 446,039
5-02(22) Bonds Mortgages and Similar Debt $ 478,417 $ 479,500
5-02(26)(a) Other Liabilities $ 271,194 $ 188,967
5-02(26)(b) Other Liabilities $ 14,572 $ 15,266
5-02(26)(c) Other Liabilities $ 68,158 $ 25,051
5-02(30) Common Stock $ 36,989 $ 33,947
5-02(31)(a)(1) Additional Paid In Capital $ 371,097 $ 286,929
5-02(31)(a)(3)(ii) Retained Earnings-Unappropriated $ 353,342 $ 327,554
5-02(32) Total Liabilities and Stockholders' Equity $2,036,069 $1,803,253
5-03(b)(1)(b) Operating Revenues Utilities & Others $ 310,131 $ 294,220 $310,131 $294,220
5-03(b)(1)(e) Other Revenues $ 1,039 $ 1,509 $ 1,039 $ 1,509
5-03(b)(2)(b) Operating Expenses Utilities & Others $ 256,289 $ 242,983 $256,289 $242,983
5-03(b)(8) Interest & Amortization of Debt Disc. $ 11,984 $ 14,020 $ 11,984 $ 14,020
5-03(b)(10) Income Before Taxes and Other Items $ 42,897 $ 38,726 $ 42,897 $ 38,726
5-03(b)(11) Income Tax Expense $ 15,097 $ 12,785 $ 15,097 $ 12,785
5-03(b)(14) Income/Loss from Continuing Operations $ 27,800 $ 25,941 $ 27,800 $ 25,941
5-03(b)(18) Cumulative Effect of Change in Accounting
for Income Taxes $ 3,826 $ - $ 3,826 $ -
5-03(b)(19) Net Income or Loss $ 31,626 $ 25,941 $ 31,626 $ 25,941
</TABLE>
