<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 March 31, 1999
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 0-82
NORTH CAROLINA NATURAL GAS CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 56-0646235
- ------------------------------- -------------------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
150 Rowan Street, Fayetteville, North Carolina 28301-4993
(Address of principal executive offices)
(Zip Code)
(910) 483-0315
(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, $2.50 par value 10,190,787
- ----------------------------- -----------------------------
Class Number of Shares
<PAGE>2
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
NORTH CAROLINA NATURAL GAS CORPORATION AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
(in thousands)
ASSETS
March 31, September 30,
1999 1998
(unaudited) (audited)
----------- -----------
Gas Utility Plant
In service $ 333,455 $ 322,595
Less-Accumulated depreciation and amortization 120,636 115,181
----------- -----------
212,819 207,414
Construction work in progress 28,129 17,725
----------- -----------
Utility Plant, net 240,948 225,139
----------- -----------
Nonutility Property 8,246 7,653
Less-Accumulated depreciation 2,804 2,687
----------- -----------
Nonutility Property, net 5,442 4,966
----------- -----------
Current Assets
Cash and temporary cash investments 2,552 2,042
Restricted cash and temporary cash investments 5,812 4,745
Accounts receivable, less reserve 19,901 14,011
Inventories, at average cost -
Gas in storage 6,435 8,243
Materials and supplies 7,106 6,417
Merchandise 1,368 1,584
Deferred gas cot-unbilled volumes 2,910 618
Other current assets 744 840
----------- -----------
Total Current Assets 46,828 38,500
----------- -----------
Investment in joint ventures 80 81
Deferred charges and other assets 3,820 2,752
----------- -----------
Total Assets $ 297,118 $ 271,438
----------- -----------
----------- -----------
(The accompanying notes are an integral part of these balance sheets.)
<PAGE>3
NORTH CAROLINA NATURAL GAS CORPORATION AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
(in thousands)
CAPITALIZATION AND LIABILITIES
March 31, September 30,
1999 1998
(unaudited) (audited)
----------- -----------
Capitalization
Stockholders' investment:
Common stock, par value $2.50;
24,000 shares authorized;
shares issued and outstanding: 3/31/99-10,186;
09/30/98-10,125 $ 25,465 $ 25,312
Capital in excess of par value 36,178 34,625
Retained earnings 73,184 63,264
----------- -----------
134,827 123,201
----------- -----------
Long-term debt 59,000 59,000
----------- -----------
Total Capitalization 193,827 182,201
----------- -----------
Current Liabilities
Current maturities of long-term debt 2,000 2,000
Notes payable 28,000 20,000
Accounts payable 15,661 15,964
Refunds payable 4,675 1,930
Customer deposits 2,642 2,038
Restricted supplier refunds 5,812 4,745
Accrued interest 2,121 2,103
Accrued income and other taxes 4,628 2,623
Other current liabilities 2,601 3,261
----------- -----------
Total Current Liabilities 68,140 54,664
----------- -----------
Other Credits
Deferred income taxes 23,738 23,440
Regulatory liability related to income taxes, net 1,921 1,871
Unamortized investment tax credits 2,229 2,328
Postretirement and post employment benefit liability 3,387 3,278
Long-term Incentive compensation and directors'
retirement obligation 1,973 1,593
Other 1,903 2,063
----------- -----------
Total Other Credits 35,151 34,573
----------- -----------
Total Capitalization and Liabilities $ 297,118 $ 271,438
----------- -----------
----------- -----------
(The accompanying notes are an integral part of these balance sheets)
<PAGE>4
NORTH CAROLINA NATURAL GAS CORPORATION AND SUBSIDIARIES
Condensed Consolidated Statements of Income (Unaudited)
For the Three Months Ended March 31, 1999 and 1998
(in thousands except per share amounts)
1999 1998
----------- -----------
Operating Revenues $ 69,953 $ 75,696
Cost of Sales 39,424 45,116
----------- -----------
Gross Margin 30,529 30,580
----------- -----------
Operating Expense and Taxes:
Operations and Maintenance 7,148 7,548
Deprectiation and Amortization 3,224 2,895
General Taxes 2,648 2,589
----------- -----------
Total Operating Expenses and Taxes 13,020 13,032
----------- -----------
Operating Income 17,509 17,548
Other Income 91 124
----------- -----------
Income Before Interest and Taxes 17,600 17,672
Interest Charges, net 1,265 1,495
----------- -----------
Net Income Before Income Taxes 16,335 16,177
Income Taxes 6,040 6,029
----------- -----------
Net Income $ 10,295 $ 10,148
----------- -----------
----------- -----------
Average Common Shares Outstanding 10,165 10,051
----------- -----------
----------- -----------
Basic Earnings Per Share $ 1.01 $ 1.01
----------- -----------
----------- -----------
Diluted Earnings Per Share (Note 3) $ 1.01 $ 1.01
----------- -----------
----------- -----------
Dividends Declared Per Share $ 0.265 $ 0.250
----------- -----------
----------- -----------
(The accompanying notes are an integral part of these statements)
<PAGE>5
NORTH CAROLINA NATURAL GAS CORPORATION AND SUBSIDIARIES
Condensed Consolidated Statements of Income (Unaudited)
For the Six Months Ended March 31, 1999 and 1998
(in thousands except per share amounts)
1999 1998
----------- -----------
Operating Revenues $ 119,995 $ 144,923
Cost of Sales 68,934 91,614
----------- -----------
Gross Margin 51,061 53,309
----------- -----------
Operating Expense and Taxes:
Operations and Maintenance 13,922 15,031
Deprectiation and Amortization 6,260 5,695
General Taxes 4,570 5,214
----------- -----------
Total Operating Expenses and Taxes 24,752 25,940
----------- -----------
Operating Income 26,309 27,369
Other Income 270 128
----------- -----------
Income Before Interest and Taxes 26,579 27,497
Interest Charges, net 2,459 2,761
----------- -----------
Net Income Before Income Taxes 24,120 24,736
Income Taxes 8,974 9,219
----------- -----------
Net Income $ 15,146 $ 15,517
----------- -----------
----------- -----------
Average Common Shares Outstanding 10,148 10,029
----------- -----------
----------- -----------
Basic Earnings Per Share $ 1.49 $ 1.55
----------- -----------
----------- -----------
Diluted Earnings Per Share (Note 3) $ 1.49 $ 1.55
----------- -----------
----------- -----------
Dividends Declared Per Share $ 0.515 $ 0.483
----------- -----------
----------- -----------
(The accompanying notes are an integral part of these statements)
<PAGE>6
NORTH CAROLINA NATURAL GAS CORPORATION AND SUBSIDIARIES
Condensed Consolidated Statements of Income (Unaudited)
For the Twelve Months Ended March 31, 1999 and 1998
(in thousands except per share amounts)
1999 1998
----------- -----------
Operating Revenues $ 206,987 $ 229,290
Cost of Sales 127,921 148,054
----------- -----------
Gross Margin 79,066 81,236
----------- -----------
Operating Expense and Taxes:
Operations and Maintenance 27,859 30,055
Deprectiation and Amortization 11,968 10,963
General Taxes 7,912 8,500
----------- -----------
Total Operating Expenses and Taxes 47,739 49,518
----------- -----------
Operating Income 31,327 31,718
Other Income 275 73
----------- -----------
Income Before Interest and Taxes 31,602 31,791
Interest Charges, net 4,777 5,068
----------- -----------
Net Income Before Income Taxes 26,825 26,723
Income Taxes 10,049 10,007
----------- -----------
Net Income $ 16,776 $ 16,716
----------- -----------
----------- -----------
Average Common Shares Outstanding 10,118 10,000
----------- -----------
----------- -----------
Basic Earnings Per Share $ 1.66 $ 1.67
----------- -----------
----------- -----------
Diluted Earnings Per Share (Note 3) $ 1.66 $ 1.67
----------- -----------
----------- -----------
Dividends Declared Per Share $ 1.015 $ 0.949
----------- -----------
----------- -----------
(The accompanying notes are an integral part of these statements)
<PAGE>7
NORTH CAROLINA NATURAL GAS CORPORATION AND SUBSIDIARIES
Condensed Consolidated Statements of Cash Flows (Unaudited)
For the Six Months Ended March 31, 1999 and 1998
(in thousands except per share amounts)
1999 1998
----------- -----------
Cash Flows From Operating Activities:
Net Income $ 15,146 $ 15,517
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation and amortization 6,260 5,705
Change in deferred income taxes and
deferred investment tax credits, net 55 318
Change in other current assets and liabilities (2,911) 9,563
Other 5 215
----------- -----------
Net cash provided by operating activities 18,555 31,318
----------- -----------
Cash Flows From Investing Activities
Property additions (24,626) (17,701)
Proceeds from Expansion Fund 2,101 631
Other, net - (83)
----------- -----------
Net cash used in investing activities (22,525) (17,153)
----------- -----------
Cash Flows From Financing Activities:
Increase (decrease) in notes payable 8,000 (5,000)
Cash dividends paid (5,226) (4,847)
Issuance of common stock through dividend reinvestment,
employee stock purchase, and key employee stock
option plans 1,706 1,397
----------- -----------
Net cash provided by (used in) financing activities 4,480 (8,450)
----------- -----------
Net increase in cash and temporary cash investments 510 5,715
Cash and temporary cash investments,
beginning of period 2,042 962
----------- -----------
Cash and temporary cash investments, end of period $ 2,552 $ 6,677
----------- -----------
----------- -----------
Cash paid for:
Interest, net of amounts capitalized $ 3,114 $ 2,544
Income taxes, net of refunds 6,316 850
(The accompanying notes are an integral part of these statements)
<PAGE>8
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
----------------------------------------------------
March 31, 1999
--------------
Note 1: The condensed financial statements included in this report reflect
only normal recurring adjustments which are, in the opinion of
management, necessary to a fair statement of the results for the
periods shown. Because of the seasonal nature of the Company's
business, the results of operations for the six-month period ended
March 31, 1999 are not necessarily indicative of the results for the
full year. These financial statements have been prepared by the
Company, without audit, pursuant to the rules and regulations of the
Securities and Exchange Commission. Certain information and footnote
disclosures normally included in financial statements prepared in
accordance with generally accepted accounting principles have been
condensed or omitted pursuant to such rules and regulations, although
the Company believes that the disclosures are adequate to make the
information presented not misleading. It is suggested that these
condensed financial statements be read in conjunction with the
financial statements and the notes included in the Company's annual
report for the fiscal year ended September 30, 1998.
Note 2: At March 31, 1999, the Company had $5.8 million in restricted supplier
refunds, of which $2.6 million were received in the current quarter.
Upon order of the North Carolina Utilities Commission (NCUC), the
Company has invested all of these funds in U.S. Treasury securities
until such time as the NCUC orders the funds transferred to an
Expansion Fund (the Fund). The Fund is administered by the NCUC
pursuant to legislation passed in July 1991, and it encourages the
expansion of natural gas service into unserved areas of the State,
including substantial portions of the Company's franchised service
territory. As of March 31, 1999, the Company had transferred a total
of $18.9 million to the Fund and has $17.0 million, including
interest, in the Fund. The total amount available in the Fund and in
restricted supplier refunds not yet transferred to the Fund was $22.8
million as of March 31, 1999. These funds are available to the Company
only upon application to the NCUC for an expansion project approved by
the NCUC.
In August 1995, the NCUC issued its Order approving the Company's
first expansion project to utilize the Fund. The project is to extend
NCNG's transmission pipeline 71 miles from Mount Olive through Duplin
County and on to the Marine Base-Camp Lejune in Jacksonville, North
Carolina. In Fiscal 1998, the Company constructed the first 20-mile
segment of 10-inch pipeline to Warsaw in Duplin County. The Company
has also completed another 20-mile segment from Warsaw east towards
Jacksonville. The Company continues to acquire rights-of-way for the
remainder of the route, and it is expected that the project will be
completed in late calendar 1999. Due to changes in construction
procedures and delays caused by required environmental studies, the
estimated cost to complete the project has increased $5.5 million to
$24.2 million. The Expansion Fund was to provide $12.4 million based
on the original economic feasibility analysis provided to, and
approved by, the NCUC. In November 1997, the Company applied to the
NCUC to request an additional $4.3 million from the Expansion Fund to
cover the increased costs. In
<PAGE>9
August 1998, the NCUC granted an additional $4.2 million of Expansion
Fund monies to be used for this project.
In April 1998, the Company filed an application with the NCUC to
extend its pipeline 38 miles to provide natural gas service to Bertie
and Martin counties using the Fund. In July, 1998 the Company filed an
amendment to extend this project an additional six miles to
Robersonville in Martin County. The amended main extension project
would run approximately 44 miles from Ahoskie to Robersonville and
cost $12.6 million. The negative net present value of the project
requested from the Fund is $7.5 million. This amendment was accepted
for filing by the NCUC on July 31, 1998. A hearing on the Company's
amended application was held in September 1998, and the NCUC issued
its Order approving the project and funding of the $7.5 million
negative net present value of the project from the Fund on November
19, 1998.
On July 28, 1998, the NCUC initiated a review to determine whether the
Company should be allowed to retain its exclusive franchise for
seventeen unserved counties in its service area, including three -
Bertie, Martin and Onslow - that are included in NCUC - approved
expansion projects currently in progress. Hearings were held December
7 and 8, 1998. On March 17, 1999, the NCUC issued its order revoking
the Company's franchise for fourteen of the counties. The NCUC decided
that the Company's exclusive franchise to serve Bertie, Martin and
Onslow counties would be retained. The Company believes that the loss
of these fourteen counties will not have an material adverse effect on
the Company because: 1) none of the fourteen other unserved counties
are economically feasible to serve as they are rural or coastal
counties located far from existing pipelines and do not have
significant potential natural gas loads; and 2) the Company may
reapply to serve such counties using Expansion Funds or the
newly-authorized Natural Gas Bond Funds, to the extent such funds are
available.
Note 3: In February 1997, the Financial Accounting Standards Board (FASB)
issued SFAS No. 128, "Earnings Per Share." SFAS No. 128 required the
Company to change the method used to compute earnings per share (EPS).
Primary EPS has been replaced with Basic EPS. Under the new
requirement for calculating Basic EPS, the dilutive effect of stock
options has been excluded. SFAS No. 128 also replaced fully diluted
EPS with diluted EPS. Diluted EPS gives effect to all dilutive
potential common shares that were outstanding during the period.
In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive
Income." SFAS No. 130 establishes standards for the reporting and
display of comprehensive income and its components in a full set of
general purpose financial statements. The Company adopted SFAS No. 130
on October 1, 1998, and it did not have a material impact on the
Company's financial statements.
In February 1998, the FASB issued SFAS No. 132, "Employers' Disclosure
about Pensions and Other Postretirement Benefits." SFAS No. 132 is an
amendment of FASB Statements No. 87, "Employers' Accounting for
Pensions", No. 88, "Employers' Accounting for Settlements and
Curtailments of Defined Benefit Pension Plans and for Termination
Benefits", and No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions." SFAS No. 132 requires additional
disclosures of the changes in the benefit obligation and plan assets
during the period, including
<PAGE>10
economic events during the period in its annual audited Financial
Statements. Economic events include amendments, combinations,
divestitures, curtailments and settlements. This statement is
effective for fiscal years beginning after December 15, 1997. The
Company adopted this standard October 1, 1998 and does not expect the
adoption to have a material effect on the Company's financial
statements.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS No. 133 standardizes the
accounting for derivative instruments, including certain derivative
instruments embedded in other contracts, by requiring that an entity
recognize those items as assets or liabilities in the statement of
financial position and measure them at fair value. This statement is
effective for fiscal years beginning after June 15, 1999. The Company
will adopt this standard October 1, 1999. The impact on the Company's
financial statements is not determinable at this time.
Note 4: NCNG adopted SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information," during the fourth quarter of
Fiscal 1998. SFAS No. 131 established standards for reporting
information about operating segments in annual financial statements
and requires selected information about operating segments in interim
financial reports issued to stockholders. It also established
standards for related disclosures about products and services and
geographic areas. Operating segments are defined as components of an
enterprise about which separate financial information is available
that is evaluated regularly by the chief operating decision maker, or
decision making group, in deciding how to allocate resources and in
assessing performance. NCNG's chief operating decision group is the
Company's senior executive management team which is comprised of the
President and Chief Executive Officer, Senior Vice Presidents and Vice
Presidents of each department.
The Company has two segments: 1) a regulated natural gas transmission
and local distribution segment (LDC), and 2) an unregulated segment
which participates in related profit-making ventures. The customers of
the regulated LDC include residential, commercial, industrial,
electric generation, and wholesale classes. The unregulated segment
consists of natural gas marketing, propane sales and appliance sales
and services. The customers of the natural gas marketing subsidiaries
are industrial, wholesale and electric generation classes. The
unregulated propane business delivers and sells propane to
residential, commercial and small industrial customers. The appliance
sales and services business sells primarily to the residential and
commercial customer classes. The Company operates in a single
geographic area of southcentral and eastern North Carolina.
Because the Company earns full margins on the transportation of
natural gas in its regulated segment, management evaluates the
performance of the unregulated natural gas marketing subsidiaries
based on the additional margin added from their sales and their
ability to maintain contact with customers who choose to transport on
the regulated LDC's system. The Company evaluates the performance of
the propane business and the appliance sales and service operations
based on each unit's ability to earn a required rate of return on
investment, as determined by the senior executive management team, and
their ability to add regulated natural gas and unregulated propane gas
customers through conversion of electric heat pumps, water heaters and
other appliances to natural gas or propane systems. Operating
<PAGE>11
expenses, taxes and interest are allocated to the unregulated segment
in accordance with NCUC guidelines.
The following tables reconcile reportable segment revenues and
expenses for the three, six and twelve-months ended March 31 (in
thousands):
Three Months Ended Three Months Ended
March 31, 1999 March 31, 1998
------------------------------- ----------------------------------
Regulated Unregulated Total Regulated Unregulated Total
--------- --------- --------- --------- --------- ---------
Revenues $ 56,056 $ 13,897 $ 69,953 $ 57,549 $ 18,147 $ 75,696
Cost of Sales 27,773 11,651 39,424 29,330 15,786 45,116
--------- --------- --------- --------- --------- ---------
Gross Margin 28,283 2,246 30,529 28,219 2,361 30,580
Operating
Expenses 12,054 966 13,020 11,980 1,052 13,032
Other (Income)
Expenses (172) 81 (91) (124) - (124)
Interest
Expense, net 1,184 81 1,265 1,416 79 1,495
--------- --------- --------- --------- --------- ---------
Income
Before Taxes 15,217 1,118 16,335 14,947 1,230 16,177
Income Taxes 5,608 432 6,040 5,540 489 6,029
--------- --------- --------- --------- --------- ---------
Net Income $ 9,609 $ 686 $ 10,295 $ 9,407 $ 741 $ 10,148
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
Property $ 361,584 $ 8,246 $ 369,830 $ 324,104 $ 7,413 $331,517
Accumulated
Depreciation 120,636 2,804 123,440 109,746 2,587 112,333
--------- --------- --------- --------- --------- ---------
Net Property $ 240,948 $ 5,442 $ 246,390 $ 214,358 $ 4,826 $219,184
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
Capital
Expenditures
(net) $ 10,819 $ 272 $ 11,091 $ 8,054 $ 94 $ 8,148
--------- --------- --------- --------- --------- ----------
--------- --------- --------- --------- --------- ---------
<PAGE>12
Six Months Ended Six Months Ended
March 31, 1999 March 31, 1998
------------------------------- ----------------------------------
Regulated Unregulated Total Regulated Unregulated Total
--------- --------- --------- --------- --------- ---------
Revenues $ 92,019 $ 27,976 $ 119,995 $ 116,007 $ 28,916 $144,923
Cost of Sales 45,195 23,739 68,934 67,097 24,517 91,614
--------- --------- --------- --------- --------- ---------
Gross Margin 46,824 4,237 51,061 48,910 4,399 53,309
Operating
Expenses 22,552 2,200 24,752 23,728 2,212 25,940
Other (Income)
Expenses (205) (65) (270) (128) - (128)
Interest
Expense, net 2,305 154 2,459 2,605 156 2,761
--------- --------- --------- --------- --------- ---------
Income
Before Taxes 22,172 1,948 24,120 22,705 2,031 24,736
Income Taxes 8,210 764 8,974 8,417 802 9,219
--------- --------- --------- --------- --------- ---------
Net Income $ 13,962 $ 1,184 $ 15,146 $ 14,288 $ 1,229 $ 15,517
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
Property $ 361,584 $ 8,246 $ 369,830 $ 324,104 $ 7,413 $331,517
Accumulated
Depreciation 120,636 2,804 123,440 109,746 2,587 112,333
--------- --------- --------- --------- --------- ---------
Net Property $ 240,948 $ 5,442 $ 246,390 $ 214,358 $ 4,826 $219,184
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
Capital
Expenditures
(net) $ 21,904 $ 621 $ 22,525 $ 16,450 $ 703 $ 17,153
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
<PAGE>13
Twelve Months Ended Twelve Months Ended
March 31, 1999 March 31, 1998
------------------------------- ----------------------------------
Regulated Unregulated Total Regulated Unregulated Total
--------- --------- --------- --------- --------- ---------
Revenues $ 150,457 $ 56,530 $ 206,987 $ 174,859 $ 54,431 $229,290
Cost of Sales 77,437 50,484 127,921 99,811 48,243 148,054
--------- --------- --------- --------- --------- ---------
Gross Margin 73,020 6,046 79,066 75,048 6,188 81,236
Operating
Expenses 43,847 3,892 47,739 45,131 4,387 49,518
Other (Income)
Expenses (209) (66) (275) (73) - (73)
Interest
Expense, net 4,494 283 4,777 4,783 285 5,068
--------- --------- --------- --------- --------- ---------
Income
Before Taxes 24,888 1,937 26,825 25,207 1,516 26,723
Income Taxes 9,289 760 10,049 9,415 592 10,007
--------- --------- --------- --------- --------- ---------
Net Income $ 15,599 $ 1,177 $ 16,776 $ 15,792 $ 924 $ 16,716
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
Property $ 361,584 $ 8,246 $ 369,830 $ 324,104 $ 7,413 $331,517
Accumulated
Depreciation 120,636 2,804 123,440 109,746 2,587 112,333
--------- --------- --------- --------- --------- ---------
Net Property $ 240,948 $ 5,442 $ 246,390 $ 214,358 $ 4,826 $219,184
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
Capital
Expenditures
(net) $ 39,187 $ 894 $ 40,081 $ 27,767 $ 991 $ 28,758
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
Note 5: On November 10, 1998, the Company and Carolina Power & Light Company
("CP&L"), entered into an Agreement and Plan of Merger (the
"Agreement") providing for a strategic business combination of the
Company and CP&L. Pursuant to the Agreement a newly formed
wholly-owned subsidiary of CP&L will be merged with and into the
Company. On April 22, 1999, the Agreement was amended to remove a
contingency which required the merger to be accounted for as a pooling
of interests. Under the Agreement, the holders of the Company's $2.50
par value common stock would receive shares of CP&L common stock based
on an exchange ratio to be determined by dividing $35 by the average
closing price of CP&L stock during the twenty consecutive trading days
prior to and including the fifth trading day prior to the closing date
of the transaction. The exchange ratio will not exceed 0.8594 nor be
less than 0.7032.
The Agreement has been approved by the Boards of Directors of the
Company and CP&L. Consummation of the merger is subject to certain
closing conditions, including approval by the shareholders of the
Company. The shareholders' meeting to consider such approval will be
held on June 29, 1999 for shareholders of record
<PAGE>14
at May 10, 1999. Consummation of the merger is also subject to receipt
of a favorable opinion of counsel that the merger will qualify as a
tax-free reorganization, the effectiveness of a Registration Statement
as filed by CP&L on May 10, 1999 in respect of its Common Stock to be
issued in the merger and certain regulatory approvals or filings,
including approvals by or filings with, the North Carolina Utilities
Commission, the South Carolina Public Service Commission, the
Securities and Exchange Commission, the filing of an exemption
statement on Form U-3A-2 with the SEC pursuant to the Public Utility
Holding Company Act, and such filings and approvals as may be required
by any applicable state securities or "blue sky" laws.
CP&L is an investor-owned electric utility which serves nearly 1.2
million customers in eastern North Carolina, the Asheville area and
the Pee Dee Region of South Carolina.
The description of the Agreement above does not purport to be complete
and is qualified in its entirety by the provisions of the Agreement.
Shareholders should read the agreement in its entirety. The Agreement,
as amended, is incorporated by reference to this Form 10-Q as Exhibit
2(c).
Note 6: On May 3, 1999, the Company announced that it would be discontinuing
its nonregulated merchandise sales and service business. The Company
does not expect the termination of this business to have a material
effect on the Company's financial statements.
<PAGE>15
Item 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(1) Material Changes in Financial Condition
---------------------------------------
Current cash requirements are financed primarily through internally
generated cash, the issuance of new common stock through dividend reinvestment
and an employee stock purchase plan along with short-term loans from committed
and uncommitted bank lines. The Company has committed bank lines of credit of
$39.0 million. In addition to its committed bank lines of credit, the Company
has uncommitted lines of credit totaling $30 million. At March 31, 1999, loans
totaling $28.0 million were outstanding under the lines of credit compared to
$20.0 million outstanding at September 30, 1998. The additional bank loans in
the six months ended March 31, 1999 were necessary to provide funds for the
Company's ongoing construction program and to finance the normal seasonal
increases in working capital, principally accounts receivable.
The Company's business is seasonal in nature as fluctuations in weather
dictate injecting and withdrawing from Company storage and billings to
residential and commercial customers. Injections of natural gas into storage and
a reduction in customer billings occur during the periods of warm weather (April
through October). Withdrawals from storage and increased customer billings occur
during periods of cold weather (November through March). In addition, the cost
of gas included in storage and rates is subject to changes in market conditions.
This seasonality is the primary reason for the lower volumes of gas in storage
at March 31, 1999. This seasonality is also the reason for higher levels of
unbilled volumes and for the higher level of accounts receivable at March 31,
1999 compared to September 30, 1998.
Refunds Payable represent the difference between the Company's benchmark
gas cost rate charged to customers and the actual cost of gas. As of March 31,
1999, the Company's benchmark rate charged to customers exceeded the actual cost
of gas, resulting in an increase in Refunds Payable. If the benchmark rate
charged to customers is less than the actual cost of gas in future periods,
Refunds Payable will decrease. It is the Company's policy to manage the
benchmark cost of gas to minimize, if possible, large over or under recoveries.
Unbilled volumes represent deliveries which occur in the current month but
will not be billed until the following month due to cycle billing. The increase
in unbilled volumes at March 31, 1999 is due to colder weather in the month of
March 1999.
Net cash provided by operating activities decreased $12.8 million for the
six-month period ended March 31, 1999, as compared to the same period last year.
This decrease was due primarily to: 1) an increase (use of cash) in accounts
payable and other current liabilities for six months ended March 31, 1999 as
compared to the same period last year due to the timing of payments for
purchases of natural gas and construction materials; 2) there were no prepaid
taxes in the current six-month period ended March 31, 1999, compared to a
decrease in prepaid taxes (a source of cash) for the same period last year; and
3) a smaller increase in refunds payable for the six months ended March 31, 1999
as compared to the same period last year.
<PAGE>16
Construction spending was $22.5 million, after giving effect to monies
received from the Fund, for the six-month period ended March 31, 1999, compared
to $17.2 million for the same period in 1998. Construction expenditures for the
remainder of Fiscal Year 1999 are projected to be $36.0 million, net of an
estimated $10.4 million of monies expected to be received from the Fund.
Management believes that the Company's lines of credit and cash provided from
operating activities will be sufficient to satisfy the Company's anticipated
short-term cash requirements during the remainder of fiscal year 1999.
Net cash used in financing activities increased $12.9 million for the six
months ended March 31, 1999, as compared to the same period last year. The
increase was primarily due to an increase in borrowings of $8.0 million in
short-term debt for the six-months ended March 31, 1999, as compared to a
decrease in borrowings of $5.0 million in the same period last year.
(2) Material Changes in Results of Operations
-----------------------------------------
Net income increased by $147,000 and $60,000 for the three and twelve-month
periods ended March 31, 1999, respectively, and decreased $371,000 for six-month
period ended March 31, 1999, as compared to the same periods last year.
Weather for the three, six and twelve-month periods ended March 31, 1999
was 16%. 2% and 3% colder than the same periods last year. However, weather was
11.5%, 13% and 21% warmer than normal for the same three, six and twelve-month
periods.
Favorably impacting all periods were lower operations and maintenance
expenses due to increased cost control and slower customer growth, as well as an
increase in AFUDC caused by increased spending on the Company's expansion
projects. In addition, the three- month period was favorably impacted by
increased volumes of natural gas deliveries to customers due to slightly higher
oil prices causing alternative fuel customers to switch to natural gas from
their alternative fuel, primarily #6 oil, and weather which was colder than the
same period last year. Negatively impacting all periods were: 1) historically
low oil prices in the first quarter of Fiscal year 1999, causing alternative
fuel customers to switch to an alternative fuel, primarily #6 oil; 2) higher
interest charges due to higher levels of borrowings for construction programs;
3) increased depreciation due to higher plant levels; and 4) lower non- utility
income due to a slow down in appliance sales and service.
<PAGE>17
The chart below compares margins for the three, six and twelve-month
periods by customer class (000's omitted):
GROSS MARGIN BY CUSTOMER CLASS
------------------------------
3 Months 6 Months 12 Months
------------------ ------------------ ------------------
1999 1998 1999 1998 1999 1998
-------- -------- -------- -------- -------- --------
Residential 11,413 11,251 17,465 17,805 25,844 25,663
Commercial/
Small
Industrial 6,221 6,865 9,919 10,986 15,035 15,969
Industrial 7,249 6,884 13,710 14,325 24,674 25,825
Municipal 3,251 3,218 5,581 5,792 7,321 7,638
Unregulated 2,395 2,362 4,386 4,401 6,192 6,141
-------- -------- -------- -------- -------- --------
Total 30,529 30,580 51,061 53,309 79,066 81,236
-------- -------- -------- -------- -------- --------
-------- -------- -------- -------- -------- --------
Gross margin decreased $51,000, $2.3 million, and $2.2 million for the
three-month, six-month and twelve-month periods ended March 31, 1999,
respectively.
For the three-month period ended March 31, 1999, residential margins
increased due to colder weather in the latter part of the quarter, increased
facilities charges due to customer growth, as well as additional margins from
the Company's Weather Normalization Adjustment (WNA). The Company's WNA
ratemaking mechanism largely mitigates the change in margin from residential and
commercial customers (including those customers served by the four municipal
customers) due to fluctuations in weather patterns, and is in effect only from
November 16 to April 15 of each year. Commercial/Small Industrial margins
decreased due to warmer weather in the beginning of the quarter. Some of the
effects of warm weather are offset by the WNA, but not all customers in this
class are covered by the WNA. Industrial margins increased in the three-month
period due to lower natural gas prices and slightly higher oil prices causing
some alternative fuel customers to switch back to natural gas from # 6 oil.
For the six and twelve-month periods ended March 31, 1999, margin was down
for most classes of customers as compared the same period last year. The
decreases were due to: 1) weather which was 13% warmer than normal for six
months and 21% warmer than normal for twelve months; 2) historically low oil
prices in the first three months of this fiscal year which caused alternative
fuel customers to switch to #6 oil; 3) slower customer growth; and 4) lower
margins from the Company's propane operations as a result of warmer-than-normal
weather; 5) some plant closings in Fiscal 1998; and 6) a decrease in margin from
the Company's merchandise sales and services due to slower customer growth.
These decreases were somewhat offset by an increase in margin from the Company's
natural gas marketing
<PAGE>18
subsidiary as more customers switched from utility sales to transportation
services due to lower spot market prices for natural gas as compared to the
regulated utility's benchmark rate. In addition, the residential margin
increased in the twelve-month period ended March 31, 1998 as compared to the
same period last year due to the effects of the Company's WNA mechanism and
increased facilities charges from new customer additions.
The chart below shows total throughput volumes (in thousands of dt) for the
three, six and twelve-month periods ended March 31, 1999 and 1998 by customer
class:
THROUGHPUT VOLUMES (mdt) BY CUSTOMER CLASS
------------------------------------------
3 Months 6 Months 12 Months
------------------ ------------------ ------------------
1999 1998 1999 1998 1999 1998
-------- -------- -------- -------- -------- --------
Residential 3,191 3,354 4,322 4,944 5,752 6,326
Commercial/
Small
Industrial 2,479 2,434 3,858 4,134 6,099 6,405
Industrial 7,661 6,951 15,387 14,891 33,894 33,583
Municipal 3,325 3,158 5,842 5,960 8,712 9,111
-------- -------- -------- -------- -------- --------
Total 16,656 15,897 29,409 29,929 54,457 55,425
-------- -------- -------- -------- -------- --------
-------- -------- -------- -------- -------- --------
The following chart shows the same total throughput volume classified by
sales and transportation:
THROUGHPUT VOLUMES (Mdt) BY TYPE OF SERVICE
-------------------------------------------
3 Months 6 Months 12 Months
------------------ ------------------ ------------------
1999 1998 1999 1998 1999 1998
-------- -------- -------- -------- -------- --------
Sales 10,202 8,583 15,580 18,766 24,981 27,409
Transportation 6,454 7,314 13,829 11,163 29,476 28,016
-------- -------- -------- -------- -------- --------
Total 16,656 15,897 29,409 29,929 54,457 55,425
-------- -------- -------- -------- -------- --------
-------- -------- -------- -------- -------- --------
Throughput volumes increased for the three-month period ended March 31,
1999, as compared to the same period last year. This increase in volumes was due
to weather which was 16% colder than the same period last year, and lower
natural gas prices relative to oil prices causing alternative fuel customers to
switch back to natural gas from # 6 oil. Transportation volumes decreased for
the three-month period ended March 31, 1999 due to the benchmark commodity cost
of gas in the Company's rates being lower than the spot market price of natural
gas. This caused customers who normally transport on the Company's system to
purchase their natural gas supplies on a bundled sales rate from the Company.
<PAGE>19
Throughput volumes decreased for the six-month period and remained flat for
the twelve-month period ended March 31, 1999 as compared to the same periods
last year. The decrease in volumes was due to: 1) weather which, while being
slightly colder than the same periods last year, was warmer than normal as
compared to the same periods last year; 2) historically low oil prices which
resulted in alternative fuel customers switching to #6 oil; and 3) slower
customer growth. However, transportation volumes increased over the same six-
month and twelve month periods last year due to the spot market price of natural
gas being lower than the Company's benchmark price of gas included in its
regulated rates. This caused large industrial and electric generation customers
who can purchase gas from alternative sources, including the Company's marketing
subsidiary, to buy gas on the spot market and transport it on the Company's
system rather than purchase bundled sales service from the utility.
Operating revenues decreased $5.7 million, $24.9 million, and $22.3 million
for the three, six and twelve-month periods ended March 31, 1999, respectively,
as compared to the same periods last year. These decreases were caused by mix
changes to greater transportation volumes to industrial and municipal customers
and lower sale volumes as shown in the table "Throughput Volumes (Mdt) By Type
of Service" on page 18 for the six and twelve-month periods, and lower commodity
prices of natural gas for all periods.
Cost of sales decreased $5.7 million, $22.7 million and $20.1 million for
the three, six and twelve-month periods ended March 31, 1999, respectively, as
compared to the same periods last year. These decreases were caused primarily
by: 1) increased transportation of customer-owned gas and lower sales of gas by
the Company for the six and twelve month periods; and 2) a decreases in the
average commodity cost of gas in each period as compared to the same periods
last year.
Operating and maintenance expenses decreased $400,000, $1.1 million, and
$2.2 million for the three, six and twelve-month periods ended March 31, 1999 as
compared to the same period last year. The primary reasons for the decreases
were: 1) lower bad debt losses due to the lower commodity price of natural gas,
resulting in lower average gas bills and increased collection efforts; 2) lower
administrative and general expenses; 3) a reduction in employees; and 4) lower
transmission expenses due to the lower cost of natural gas used in the Company's
compressor stations as well as a decrease in the operating time of those
stations due to lower throughput volumes.
Depreciation expense increased in all periods as compared to the same
periods last year due to the addition of utility plant in service, primarily
transmission and distribution plant related to expansion and customer growth.
General taxes increased in the three-month period and decreased in the six
and twelve-month periods as compared to the same periods last year. The most
significant tax is the state gross receipts tax, which is based on utility
revenue, and therefore tracks the changes in utility revenues. Offsetting the
decrease in gross receipts tax were higher property and payroll taxes.
Interest expense decreased in the three, six and-twelve month periods as
compared to the same periods last year. These decreases were due primarily to an
increase in allowance for funds used during construction related to increased
construction work in progress for a major expansion project, and lower interest
expense on long-term debt due to scheduled debt
<PAGE>20
repayments. Offsetting those decreases was increased interest expense for
short-term borrowings.
The Year 2000 issue exists because many computer systems and applications
use two- digit fields to designate a year. As the Year 2000 date change occurs,
date-sensitive systems will recognize the Year 2000 as 1900, or not at all. This
inability to recognize or properly treat the Year 2000 may cause systems to
process critical financial and operational information incorrectly. NCNG began
evaluation of this problem in 1995. The Company has assessed and identified
internal software and hardware components in both information technology and
non- information technology applications. As a result of this assessment, the
Company has replaced all critical systems with new software, and in some cases
hardware, which is Year 2000 ready. Existing non-Year 2000 ready systems have
been replaced as the new systems were installed. Substantially all remediation
work is complete. The Company is now beginning integration testing and expects
to have it complete by the end of the summer. The estimated cost of replacement,
including $5.8 million incurred to date, is $5.9 million. The cost of program
changes, as opposed to replacement, and testing are considered normal operating
expenses and not separately budgeted or tracked. All work related to Year 2000
remediation and testing is being performed by NCNG employees. Approximately 15
people in different functional areas have been assisting in the replacement and
remediation. The cost of completion and projected completion dates are
estimates, which are derived utilizing numerous assumptions of future events,
including the continued availability of certain resources, third-party vendor
compliance and other factors. NCNG considers these costs to be prudent costs
incurred in the ordinary course of business, and therefore, recoverable through
rates.
The Company's Year 2000 plan includes an assessment of critical suppliers
and vendors to determine the adequacy of their Year 2000 plans. The Company has
segregated its suppliers into three classes of critical business supply: high,
medium and low. NCNG has contacted all suppliers in the high and medium classes.
To date, 75% of suppliers contacted have responded, and 33% of those respondents
listed themselves as compliant with the remainder having a target date in
mid-1999. The Company will adjust its contingency plans through December 1999
for those suppliers, if any, which appear to be inadequately addressing the Year
2000 issue. Such plans will include securing an alternative supplier, where
possible. While the Company will continue to monitor supplier and vendor
progress on this issue, the Company does not control third-party Year 2000
remediation plans and cannot guarantee that all third parties will be Year 2000
compliant. The Company cannot quantify at this time the impact of the failure of
one or more suppliers to deliver critical supplies and services.
At this time, the most reasonably likely worst case scenario is that a few
key customers could experience temporary reductions in their natural gas
requirements due to their own Year 2000 problems. In the event that this
scenario does occur, we do not expect it to have a material adverse effect on
the Company's financial position and results of operations due to the fact that:
1) no one customer represents more than 7% of total yearly throughput; 2)
currently, during the winter months many of our large interruptible customers
are regularly curtailed in severe weather; and 3) the temporary loss of a few
customers would have no greater effect than the losses we currently experience
when alternative fuel prices are below natural gas prices, causing large
customers not to purchase natural gas. A temporary load
<PAGE>21
loss is the probable extent of the Company's most likely worst-case scenario.
That, in itself, is not unusual.
The industry in which the Company operates has business interruption plans
in place for operating under adverse conditions such as storm-related supplier
outages. The Company is in the process of establishing a Year 2000 contingency
plan utilizing current business interruption plans and expects to have it
completed in late 1999.
Statements made herein and elsewhere in this quarterly report which are not
historical in fact are forward-looking statements. In connection with the "Safe
Harbor" provisions of the Private Securities Reform Act of 1995, the Company
cautions that, while it believes such statements to be reasonable and makes them
in good faith, they almost always vary from actual results, depending upon the
circumstances. Investors should be aware of important factors that could have a
material impact on future results. These factors include, but are not limited
to, weather, the regulatory environment, financial market conditions, interest
rate fluctuations, customers' preferences, unforeseen competition, and other
uncertainties, all of which are difficult to predict, and most of which are
beyond the control of the Company.
<PAGE>22
PART II - OTHER INFORMATION
---------------------------
Item 1. Legal Proceedings
- ------- -----------------
None.
Item 2. Changes in the Rights of the Company's Security Holders
- ------- -------------------------------------------------------
None.
Item 3. Default Upon Senior Securities
- ------- ------------------------------
None.
Item 4. Submission of Matters to a Vote of Security Holders
- ------- ---------------------------------------------------
None.
Item 5. Other Information
- ------- -----------------
None.
Item 6. Exhibits and Reports on Form 8-K
- ------- --------------------------------
(a) Exhibits
None.
(b) Reports on Form 8-K
None.
<PAGE>23
SIGNATURE
---------
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
NORTH CAROLINA NATURAL GAS CORPORATION
---------------------------------------
(Registrant)
Date: May 17, 1999 /s/ Gerald A. Teele
-----------------------------------------
Gerald A. Teele
Senior Vice President, Treasurer and
Chief Financial Officer
(Principal Financial Officer)
Date: May 17, 1999 /s/ Ronald J. Josephson
-----------------------------------------
Ronald J. Josephson
Vice President-Financial Services
(Principal Accounting Officer)
<PAGE>24
NORTH CAROLINA NATURAL GAS CORPORATION AND SUBSIDIARIES
-------------------------------------------------------
INDEX OF EXHIBITS
-----------------
The following exhibit is filed as part of this Form 10-Q for the period
ended March 31, 1999:
Exhibit
Number
- --------
27 - Financial Data Schedule
2(c) - Agreement and Plan of Merger by and Among Carolina Power &
Light Company, North Carolina Natural Gas Corporation and
Carolina Acquisition Corporation Dated as of November 10,
1998, as Amended and Restated as of April 2, 1999,
incorporated by reference to the Carolina Power & Light Form
S-4 filed May 10, 1999
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000072596
<NAME> NORTH CAROLINA NATURAL GAS CORPORATION
<MULTIPLIER> 1,000
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<FISCAL-YEAR-END> sep-30-1999
<PERIOD-END> mar-31-1999
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