UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-Q
QUARTERLY REPORT
PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTER ENDED
JUNE 30, 1999
COMMISSION FILE NUMBER 1-3196
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CONSOLIDATED NATURAL GAS COMPANY
A DELAWARE CORPORATION
CNG TOWER, 625 LIBERTY AVENUE, PITTSBURGH, PA 15222-3199
TELEPHONE (412) 690-1000
IRS EMPLOYER IDENTIFICATION NUMBER 13-0596475
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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 and (2) has been subject to such filing
requirements for the past 90 days. Yes___X___ No_______
Number of shares of Common Stock, $2.75 Par Value, outstanding at July 23,
1999: 95,928,496
<PAGE>
CONSOLIDATED NATURAL GAS COMPANY
FORM 10-Q QUARTERLY REPORT
For the Quarter Ended June 30, 1999
TABLE OF CONTENTS
PART I - FINANCIAL INFORMATION Page
ITEM 1. FINANCIAL STATEMENTS
CONSOLIDATED STATEMENT OF INCOME (Unaudited)
for the Three and Six Months Ended June 30, 1999 and 1998.... 1
CONDENSED CONSOLIDATED BALANCE SHEET
at June 30, 1999 (Unaudited), and December 31, 1998.......... 2
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
for the Six Months Ended June 30, 1999 and 1998.............. 3
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (Unaudited)
for the Three and Six Months Ended June 30, 1999 and 1998.... 4
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS................... 5
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.................... 13
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK............................................ 23
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS...................................... 24
ITEM 2. CHANGES IN SECURITIES.................................. 24
ITEM 3. DEFAULTS UPON SENIOR SECURITIES........................ 24
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.... 24
ITEM 5. OTHER INFORMATION...................................... 25
ITEM 6. EXHIBITS, AND REPORTS ON FORM 8-K...................... 25
SIGNATURES....................................................... 27
<PAGE>
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Consolidated Natural Gas Company and Subsidiaries
CONSOLIDATED STATEMENT OF INCOME
(Unaudited) (Thousands of Dollars)
<TABLE>
<CAPTION>
____________________________________________________________________________________________________________
Six Months to Three Months to
June 30 June 30
________________________ ______________________
1999 1998 1999 1998
____________________________________________________________________________________________________________
<S> <C> <C> <C> <C>
OPERATING REVENUES
Regulated gas sales.............................. $ 822,121 $ 819,618 $ 195,361 $207,672
Nonregulated gas sales........................... 287,236 239,403 135,366 107,828
__________ __________ __________ ________
Total gas sales.............................. 1,109,357 1,059,021 330,727 315,500
Gas transportation and storage................... 304,480 286,918 120,258 120,485
Other............................................ 199,046 183,654 115,450 94,443
__________ __________ __________ ________
Total operating revenues (Note 3)............ 1,612,883 1,529,593 566,435 530,428
__________ __________ __________ ________
OPERATING EXPENSES
Purchased gas.................................... 533,823 527,109 118,349 122,098
Liquids, capacity and other products purchased... 119,275 73,057 61,241 28,752
Operation expense................................ 311,101 306,551 158,928 149,841
Maintenance...................................... 48,466 39,998 24,427 19,791
Depreciation and amortization.................... 181,896 169,224 94,576 85,566
Taxes, other than income taxes................... 109,304 95,094 43,203 40,670
__________ __________ __________ ________
Subtotal..................................... 1,303,865 1,211,033 500,724 446,718
__________ __________ __________ ________
Operating income before income taxes......... 309,018 318,560 65,711 83,710
Income taxes..................................... 31,687 84,874 (43,976) 15,377
__________ __________ __________ ________
Operating income............................. 277,331 233,686 109,687 68,333
__________ __________ __________ ________
OTHER INCOME (DEDUCTIONS)
Interest revenues................................ 1,235 1,884 581 360
Merger-related expense (Note 2) ................. (165,338) - (165,338) -
Other-net........................................ 3,577 7,016 3,722 6,063
__________ __________ __________ ________
Total other income (deductions).............. (160,526) 8,900 (161,035) 6,423
__________ __________ __________ ________
Income (loss) before interest charges........ 116,805 242,586 (51,348) 74,756
__________ __________ __________ ________
INTEREST CHARGES
Interest on long-term debt....................... 52,185 54,426 25,625 26,029
Other interest expense........................... 11,236 7,629 5,944 4,106
Allowance for funds used during construction..... (5,579) (4,316) (2,893) (2,193)
__________ __________ __________ ________
Total interest charges....................... 57,842 57,739 28,676 27,942
__________ __________ __________ ________
INCOME (LOSS) FROM CONTINUING OPERATIONS......... 58,963 184,847 (80,024) 46,814
DISCONTINUED OPERATIONS (Note 5)
Loss from discontinued energy marketing
services operations, net of applicable
tax benefit.................................... - (17,238) - -
Income (loss) from disposal of energy marketing
services operations, including provision for
operating losses during the phase out period,
net of applicable tax or tax benefit........... - (31,911) - 10,989
_________ __________ ________ ________
NET INCOME (LOSS)................................ $ 58,963 $ 135,698 $(80,024) $ 57,803
========= ========= ======== ========
EARNINGS PER COMMON SHARE -- BASIC
Income (loss) from continuing operations (Note 8) $.62 $1.96 $(.84) $.49
Loss from discontinued operations.............. - (.18) - -
Income (loss) from disposal of
discontinued operations...................... - (.34) - .12
_____ _____ _____ ____
NET INCOME (LOSS)................................ $.62 $1.44 $(.84) $.61
===== ===== ===== ====
EARNINGS PER COMMON SHARE -- DILUTED
Income (loss) from continuing operations (Note 8) $.61 $1.92 $(.83) $.49
Loss from discontinued operations.............. - (.17) - -
Income (loss) from disposal of
discontinued operations...................... - (.33) - .11
_____ _____ ____ ____
NET INCOME (LOSS)................................ $.61 $1.42 $(.83) $.60
===== ===== ==== ====
_____________________________________________________________________________________________________________
</TABLE>
The Notes to Consolidated Financial Statements are an integral part of this
statement.
1
<PAGE>
ITEM 1. FINANCIAL STATEMENTS (Continued)
Consolidated Natural Gas Company and Subsidiaries
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
_____________________________________________________________________________
At June At December
30, 1999 31, 1998
(Unaudited)
_____________________________________________________________________________
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Gas utility and other plant.................... $ 5,169,140 $ 5,091,793
Accumulated depreciation and amortization...... (2,072,236) (1,999,484)
___________ ___________
Net gas utility and other plant........... 3,096,904 3,092,309
___________ ___________
Exploration and production properties.......... 4,266,977 4,080,672
Accumulated depreciation and amortization...... (2,830,706) (2,734,517)
___________ ___________
Net exploration and production properties. 1,436,271 1,346,155
___________ ___________
Net property, plant and equipment......... 4,533,175 4,438,464
___________ ___________
CURRENT ASSETS
Cash and temporary cash investments............ 78,884 135,453
Accounts receivable, less allowance for
doubtful accounts............................ 386,608 562,297
Gas stored - current portion................... 37,357 120,665
Materials and supplies (average cost method)... 30,046 27,940
Unrecovered gas costs.......................... 20,697 34,860
Deferred income taxes - current (net).......... 16,347 21,786
Prepayments and other current assets........... 201,319 258,899
___________ ___________
Total current assets...................... 771,258 1,161,900
___________ ___________
REGULATORY AND OTHER ASSETS
Other investments ............................. 311,201 302,307
Deferred charges and other assets.............. 480,303 459,229
___________ ___________
Total regulatory and other assets......... 791,504 761,536
___________ ___________
Total assets.............................. $ 6,095,937 $ 6,361,900
=========== ===========
STOCKHOLDERS' EQUITY AND LIABILITIES
CAPITALIZATION
Common stockholders' equity (Notes 6 and 7)
Common stock, par $2.75
(Issued: 1999 - 95,948,802 shares;
1998 - 95,944,551 shares).................. $ 263,860 $ 263,848
Capital in excess of par value............... 567,349 571,972
Retained earnings............................ 1,559,552 1,591,543
Treasury stock, at cost (1999 - 2,865
shares; 1998 - 495,123 shares)............. (167) (26,359)
Unearned compensation........................ - (1,396)
___________ ___________
Total common stockholders' equity......... 2,390,594 2,399,608
Long-term debt................................. 1,380,289 1,379,729
___________ ___________
Total capitalization...................... 3,770,883 3,779,337
___________ ___________
CURRENT LIABILITIES
Current maturities on long-term debt........... 7,125 111,125
Commercial paper............................... 450,903 558,900
Accounts payable............................... 307,084 423,695
Estimated rate contingencies and
refunds (Note 4)............................. 49,776 78,266
Amounts payable to customers................... 36,989 48,339
Taxes accrued.................................. 56,473 122,788
Temporary replacement reserve - gas
inventory.................................... 43,326 -
Other current liabilities...................... 307,115 201,224
__________ __________
Total current liabilities................. 1,258,791 1,544,337
___________ ___________
DEFERRED CREDITS
Deferred income taxes.......................... 811,375 780,928
Accumulated deferred investment tax credits.... 23,389 24,475
Deferred credits and other liabilities......... 231,499 232,823
___________ ___________
Total deferred credits.................... 1,066,263 1,038,226
___________ ___________
COMMITMENTS AND CONTINGENCIES
___________ ___________
Total stockholders' equity and liabilities $ 6,095,937 $ 6,361,900
=========== ===========
_____________________________________________________________________________
The Notes to Consolidated Financial Statements are an integral part of this
statement.
2
<PAGE>
ITEM 1. FINANCIAL STATEMENTS (Continued)
Consolidated Natural Gas Company and Subsidiaries
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (Thousands of Dollars)
_____________________________________________________________________________
Six Months to June 30
_____________________
1999 1998*
_____________________________________________________________________________
CASH FLOWS FROM OPERATING ACTIVITIES
Income from continuing operations................ $ 58,963 $ 184,847
Adjustments to reconcile income from continuing
operations to net cash provided by
operating activities
Depreciation and amortization................ 181,896 169,224
Pension cost (credit)-net.................... (33,990) (28,255)
Stock award amortization..................... 6,635 4,082
Deferred income taxes-net.................... 29,884 (11,946)
Changes in current assets and
current liabilities
Accounts receivable-net.................... 175,510 233,408
Inventories................................ 81,202 47,430
Unrecovered gas costs...................... 14,163 26,155
Accounts payable........................... (121,224) (117,828)
Estimated rate contingencies and refunds... (28,490) 19,092
Amounts payable to customers............... (11,350) 35,878
Taxes accrued.............................. (66,315) (18,573)
Temporary replacement reserve - gas
inventory................................ 43,326 21,527
Other-net.................................. 162,280 7,526
Changes in other assets and
other liabilities.......................... 11,085 23,419
Other-net.................................... 120 1,543
_________ _________
Net cash provided by continuing operations 503,695 597,529
Net cash provided by
discontinued operations................... 1,955 45,439
_________ _________
Net cash provided by operating activities 505,650 642,968
_________ _________
CASH FLOWS USED IN INVESTING ACTIVITIES
Plant construction and other property additions.. (274,803) (233,226)
Proceeds from dispositions of property, plant
and equipment-net.............................. (2,951) (2,980)
Cost of other investments........................ (5,020) (197,725)
_________ _________
Net cash used in continuing operations... (282,774) (433,931)
Net cash used in discontinued operations......... - (1,697)
_________ _________
Net cash used in investing activities.... (282,774) (435,628)
_________ _________
CASH FLOWS PROVIDED BY (OR USED IN) FINANCING ACTIVITIES
Issuance of common stock......................... 196 9,893
Repayments of long-term debt..................... (104,000) (161,698)
Commercial paper-net............................. (107,009) 144,888
Dividends paid................................... (92,556) (92,831)
Purchase of treasury stock....................... (11,253) (252,510)
Sale of treasury stock........................... 32,520 161,712
Other-net........................................ - (71)
_________ _________
Net cash used in financing activities.... (282,102) (190,617)
_________ _________
Net increase (or decrease) in cash and
temporary cash investments............... (59,226) 16,723
CASH AND TEMPORARY CASH INVESTMENTS AT JANUARY 1. 138,112 65,035
_________ _________
CASH AND TEMPORARY CASH INVESTMENTS AT JUNE 30... $ 78,886 $ 81,758
========= =========
Continuing operations............................ $ 78,884 $ 72,507
Discontinued operations.......................... 2 9,251
_________ _________
Total cash and temporary cash investments
at June 30............................... $ 78,886 $ 81,758
========= =========
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for
Interest (net of amounts capitalized).......... $ 59,397 $ 62,538
Income taxes (net of refunds).................. $ 15,951 $ 59,199
Non-cash financing activities
Issuance of common stock under benefit plans... $ 191 $ 773
Conversion of 7 1/4% Convertible
Subordinated Debentures...................... $ - $ 88,467
_____________________________________________________________________________
*Certain amounts reclassified for comparative purposes.
The Notes to Consolidated Financial Statements are an integral part of this
statement.
3
<PAGE>
ITEM 1. FINANCIAL STATEMENTS (Continued)
Consolidated Natural Gas Company and Subsidiaries
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(Unaudited) (Thousands of Dollars)
<TABLE>
<CAPTION>
_____________________________________________________________________________________
Six Months to June 30 Three Months to June 30
______________________ ________________________
1999 1998 1999 1998
_____________________________________________________________________________________
<S> <C> <C> <C> <C>
NET INCOME (LOSS)............. $58,963 $135,698 $(80,024) $57,803
OTHER COMPREHENSIVE INCOME,
NET OF TAX
Foreign currency
translation adjustment..... 1,707 323 1,087 35
_______ ________ ________ _______
COMPREHENSIVE INCOME (LOSS)... $60,670 $136,021 $(78,937) $57,838
======= ======== ======== =======
____________________________________________________________________________________
</TABLE>
The Notes to Consolidated Financial Statements are an integral part of this
statement.
4
<PAGE>
ITEM 1. FINANCIAL STATEMENTS (Continued)
Consolidated Natural Gas Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) With the exception of the Condensed Consolidated Balance Sheet at
December 31, 1998, which is derived from the Consolidated Balance Sheet
at that date which was included in Exhibit 99 to the Annual Report to the
Securities and Exchange Commission (SEC) on Form 10-K for 1998 (1998 Form
10-K), the consolidated financial statements appearing on pages 1 through 4
are unaudited. In the opinion of management, the information furnished
reflects all adjustments necessary to a fair statement of the results for
the interim periods presented.
(2) On February 22, 1999, the Company and Dominion Resources, Inc. (DRI)
announced that a definitive merger agreement was approved by the boards of
directors of both companies. DRI is a holding company with businesses in
regulated and competitive electric power, natural gas and oil development
and selected financial services. DRI's principal business subsidiary is
Virginia Electric and Power Company, a regulated public utility engaged in
the generation, transmission, distribution and sale of electric energy in
Virginia and northeastern North Carolina.
On April 18, 1999, the Company received an unsolicited merger proposal from
Columbia Energy Group (Columbia).
The Company announced on May 11, 1999 that, after careful consideration, the
Board of Directors had unanimously rejected the Columbia proposal. In
addition, on May 11, 1999, the Company announced that the Board of Directors
had unanimously approved an Amended and Restated Agreement and Plan of Merger
(Amended Plan of Merger) with DRI. Under the Amended Plan of Merger, the
Company's shareholders would receive a combination of DRI common stock and cash
with an aggregate firm value of $66.60 per share of common stock. Up to 60%
of the consideration to the Company's shareholders will be in the form of
DRI common stock and the balance will be in cash. The merger transaction
is conditioned, among other things, upon the approvals of shareholders of both
companies, opinions of counsel on the tax-free nature of the stock portion
of the transaction, approvals of various federal regulatory agencies, and
the completion of regulatory processes in the states where the combined
company will operate. The transaction is not conditioned upon obtaining
financing.
The Company and DRI filed a definitive joint proxy statement/prospectus with
the SEC on May 25, 1999 in connection with the planned merger.
On June 24, 1999, the Pennsylvania Public Utility Commission approved the
planned merger.
On June 30, 1999, the Company held a special meeting of shareholders to vote
on the approval and adoption of the Amended Plan of Merger with DRI
(see Part II, ITEM 4., "SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS,"
page 24). Also on that date, DRI held a similar meeting with its shareholders.
The shareholders of both CNG and DRI voted to approve the merger of the two
companies.
The approval of the merger constituted a change of control as defined in the
Company's stock incentive plans. Accordingly, the vesting of stock options
and certain other stock awards was accelerated pursuant to the provisions of
the plans and/or award agreements. Also, the change of control effectively
granted limited stock appreciation rights to holders of vested stock options
and certain other stock awards. Specifically, during the period July 1, 1999
through August 29, 1999, the plan and/or award agreements permit employees
to elect to receive a cash payment in exchange for surrendering vested stock
options and awards. This provision covers outstanding vested stock options
granted since 1989 to approximately 700 employees. The amount received will
be based on the value determined per the associated plans, which considers
the option exercise price, award value, and the change of control price as
defined in the plans. Based on the value of the awards expected to be
surrendered and cashed out, the Company recognized a charge to Other Income
(Deductions)for the quarter ended June 30, 1999. This charge amounted to
$153.5 million and reduced second quarter net income by $96.8 million, or
$1.01 per share.
5
<PAGE>
ITEM 1. FINANCIAL STATEMENTS (Continued)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The Company also recorded charges to Other Income (Deductions)for the quarter
ended June 30, 1999 amounting to $11.8 million representing direct incremental
costs of the pending merger (including fees of financial advisors, legal
counsel and related costs). These charges reduced second quarter net income by
$.12 per share. The Company expects to incur additional direct incremental
costs of approximately $11 million in connection with the pending merger
during the remainder of 1999.
The companies have applied for and expect to receive required SEC approval of
the merger under the Public Utility Holding Company Act of 1935 (PUHCA). It
is expected that DRI will become a registered holding company under PUHCA at
the time of the merger. Under one of the proposed structures, the Company will
become a wholly owned subsidiary of DRI. The Company's subsidiaries will
remain as such, with the Company remaining a registered holding company under
PUHCA.
SUBSEQUENT EVENT
The Public Service Commission of West Virginia approved the pending merger
on July 27, 1999.
(3) Because a major portion of the gas sold or transported by the Company's
distribution and transmission operations is ultimately used for space heating,
both revenues and earnings are subject to seasonal fluctuations. Seasonal
fluctuations are further influenced by the timing of price relief granted under
regulation to compensate for past cost increases.
(4) Certain increases in prices by the Company and other rate-making
issues are subject to final modification in regulatory proceedings. The
related accumulated provisions pertaining to these matters were $38.8 million
and $59.9 million at June 30, 1999, and December 31, 1998, respectively,
including interest. These amounts are reported in the Condensed Consolidated
Balance Sheet under "Estimated rate contingencies and refunds" together with
$11.0 million and $18.4 million, respectively, which are primarily refunds
received from suppliers and refundable to customers under regulatory
procedures.
(5) During April 1998, management approved a plan to discontinue the
Company's wholesale trading and marketing of natural gas and electricity,
including integrated energy management. On July 31, 1998, the sale of the
capital stock of CNG Energy Services Corporation, formerly a wholly-owned
subsidiary of the Company, to Sempra Energy Trading, a subsidiary of Sempra
Energy, was finalized. Included in the transaction were contracts for the
purchase and sale of natural gas as well as rights to natural gas pipeline and
storage capacity, mainly in the Northeast and Mid-Atlantic regions, and related
working capital. Proceeds of $37.4 million were received from the sale of the
stock, as adjusted for working capital items. The Company's transition out of
the wholesale gas business was substantially complete at December 31, 1998.
The remaining net liabilities associated with discontinued operations at June
30, 1999 and December 31, 1998 were not material.
The results of operations of these activities for the three- and six-month
periods ended June 30, 1998 are classified as "Discontinued Operations" in the
Consolidated Statement of Income. Cash flows in connection with operating and
investing activities for discontinued operations are reported separately in the
Condensed Consolidated Statement of Cash Flows. There were no cash flows
provided by, or used in, financing activities related to discontinued
operations.
Summarized results of operations of the discontinued operations are as follows:
6
<PAGE>
ITEM 1. FINANCIAL STATEMENTS (Continued)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
_______________________________________________________________________________
Six Months to Three Months to
June 30, 1998 June 30, 1998
_______________________________________________________________________________
(In Thousands)
Total operating revenues........ $ 792,586 $ -
Operating expenses.............. (818,105) -
________ ________
Operating loss before
income taxes............... (25,519) -
Income tax benefit.............. 9,011 -
Other income.................... 80 -
Interest charges................ (810) -
________ ________
Loss from discontinued
operations.................... $ (17,238) $ -
========= ========
Estimated income (loss)
from disposal before
income taxes.................. $ (50,145)* $ 15,855
Income tax
(provision) benefit........... 18,234 (4,866)
________ ________
Net income
(loss) from disposal.......... $(31,911)* $ 10,989
======== ========
______________________________________________________________________________
* Amounts include $22.3 million pretax provision ($14.4 million after taxes)
for expected operating losses during the shutdown period.
The quarter ended June 30, 1998 includes a favorable adjustment
to revise certain previous estimates of shut-down costs in light of terms
included in the Company's agreement to sell the capital stock of CNG Energy
Services Corporation.
(6) A summary of the changes in common stock, capital in excess of par value,
unearned compensation and treasury stock subsequent to December 31, 1998,
follows:
<TABLE>
<CAPTION>
____________________________________________________________________________________________________________
Common Stock
Issued Capital in Treasury Stock
____________________ ____________________
Number Value Excess of Unearned Number
of Shares at Par Par Value Compensation of Shares Cost
________________________________________________________________________________________________________________
(In Thousands)
<S> <C> <C> <C> <C> <C> <C>
At December 31, 1998............. 95,945 $263,848 $571,972 $(1,396) (495) $ (26,359)
Common stock issued
Stock options and awards....... 4 12 192 - - -
Amortization and adjustment.... - - - 1,449 - -
Purchase of treasury stock....... - - - - (208) (11,253)
Sale of treasury stock........... - - (4,815) (53) 700 37,445
______ ________ ________ ________ ______ _________
At June 30, 1999................. 95,949 $263,860 $567,349 $ - (3) $ (167)
====== ======== ======== ======== ====== =========
________________________________________________________________________________________________________________
</TABLE>
7
<PAGE>
ITEM 1. FINANCIAL STATEMENTS (Continued)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(7) One of the indentures relating to the Company's debenture issues
contains restrictions on dividend payments by the Company and acquisitions
of its capital stock. Under these provisions, $448.2 million of consolidated
retained earnings was free from such restrictions at June 30, 1999.
(8) A reconciliation of the income from continuing operations and common
stock share amounts used in the calculation of basic and diluted earnings
per share (EPS) for the three months and six months ended June 30, 1999 and
1998 follows (income and share amounts in thousands):
<TABLE>
<CAPTION>
___________________________________________________________________________________________________________________________
Six Months to June 30 Three Months to June 30
________________________________ _________________________________
Income From Income From Per
Continuing Per Share Continuing Share
Operations Shares Amount Operations Shares Amount
___________________________________________________________________________________________________________________________
<S> <C> <C> <C> <C> <C> <C>
1999
Basic EPS................................. $ 58,963 95,571 $.62 $(80,024) 95,763 $(.84)
======== ====== ==== ======== ====== =====
Effect of dilutive securities:
Exercise of stock options............... 560 717
Vesting of performance shares........... 441 454
________ _______ _______ ______
Diluted EPS............................... $ 58,963 96,572 $.61 $(80,024) 96,934 $(.83)
======== ======= ==== ======== ====== =====
_____________________________________________________________________________________________________________________________
1998
Basic EPS................................. $184,847 94,234 $1.96 $46,814 95,447 $.49
======== ====== ===== ======= ====== ====
Effect of dilutive securities:
Exercise of stock options............... 628 651
Vesting of performance shares........... 374 380
Conversion of 7 1/4% Convertible
Subordinated Debentures................. 1,578 1,721 - -
________ ______ _______ ______
Diluted EPS............................... $186,425 96,957 $1.92 $46,814 96,478 $.49
======== ====== ===== ======= ====== ====
___________________________________________________________________________________________________________________________
___________________________________________________________________________________________________________________________
</TABLE>
(9) In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133 establishes new
accounting standards for derivative instruments and for hedging activities. In
June 1999, the FASB issued SFAS No. 137, "Accounting for Derivative Instruments
and Hedging Activities - Deferral of the Effective Date of FASB Statement No.
133." SFAS No. 137 delays, by one year, the effective date of SFAS No. 133.
Accordingly, the Company must adopt the provisions of SFAS No. 133 effective
January 1, 2001. The adoption of SFAS No. 133 is not expected to have a
material effect on the Company's financial position, results of operations or
cash flows.
8
<PAGE>
ITEM 1. FINANCIAL STATEMENTS (Continued)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(10) The following tables present segment information pertaining to the
Company's operations:
<TABLE>
<CAPTION>
_________________________________________________________________________________________________________________________________
Exploration
and Corporate and
Distribution Transmission Production Other Eliminations Total
_________________________________________________________________________________________________________________________________
(In Thousands)
<S> <C> <C> <C> <C> <C> <C>
SIX MONTHS TO JUNE 30, 1999
Operating Revenues
Nonaffiliated
Regulated gas sales . . . . . $822,121 $ - $ - $ - $ - $ 822,121
Nonregulated gas sales. . . . - - 186,595 100,641 - 287,236
Gas transportation and
storage . . . . . . . . . . 118,767 185,442 271 - - 304,480
Liquid sales. . . . . . . . . - - 130,780 - - 130,780
Other . . . . . . . . . . . . 13,386 18,117 25,181 11,582 - 68,266
________ ________ ________ _______ ________ __________
Total nonaffiliated. . . . 954,274 203,559 342,827 112,223 - 1,612,883
Affiliated. . . . . . . . . . . 3,636 61,516 23,014 12,617 (100,783) -
________ ________ ________ _______ ________ __________
Total operating revenues. . 957,910 265,075 365,841 124,840 (100,783) 1,612,883
Operating expenses
Purchased gas. . . . . . . . . . 498,402 7,767 18,133 105,766 (96,245) 533,823
Liquids, capacity and other
products purchased . . . . . . - 35,497 80,770 3,514 (506) 119,275
Operation expense. . . . . . . . 154,705 57,204 90,311 14,253 (5,372) 311,101
Maintenance. . . . . . . . . . . 24,948 12,126 11,020 117 255 48,466
Depreciation and amortization. . 38,686 27,987 111,345 887 2,991 181,896
Taxes, other than income taxes . 81,648 18,506 4,488 713 3,949 109,304
________ ________ ________ _______ _______ __________
Operating income before
income taxes. . . . . . . . 159,521 105,988 49,774 (410) (5,855) 309,018
________ ________ ________ _______ _______ __________
Income taxes . . . . . . . . . . 46,383 37,732 10,444 532 (63,404) 31,687
Interest revenues. . . . . . . . 41 1,744 500 754 (1,804) 1,235
Equity in earnings of
equity investees . . . . . . . - 3,473 2,942 520 - 6,935
Merger-related expense . . . . . - - - - 165,338 165,338
Other revenues-net . . . . . . . (2,704) (108) 60 (371) (235) (3,358)
Interest charges . . . . . . . . 23,679 11,951 13,084 1,131 7,997 57,842
________ ________ ________ _______ _______ __________
Income from continuing
operations . . . . . . . . . . $ 86,796 $ 61,414 $ 29,748 $(1,170) $(117,825) $ 58,963
======== ======== ======== ======= ======= ==========
Gas Sales (In Bcf) . . . . . . . 135.2 - 95.8 45.4 (20.0) 256.4
===== ===== ==== ==== ===== =====
Gas Transportation (In Bcf). . . 112.5 365.5 .3 - (100.8) 377.5
===== ===== ==== ==== ===== =====
_________________________________________________________________________________________________________________________________
</TABLE>
9
<PAGE>
ITEM 1. FINANCIAL STATEMENTS (Continued)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
<TABLE>
<CAPTION>
_________________________________________________________________________________________________________________________________
Exploration
and Corporate and
Distribution Transmission Production Other Eliminations Total
_________________________________________________________________________________________________________________________________
(In Thousands)
<S> <C> <C> <C> <C> <C> <C>
SIX MONTHS TO JUNE 30, 1998
Operating revenues
Nonaffiliated
Regulated gas sales . . . . . $818,495 $ - $ - $ 1,123 $ - $ 819,618
Nonregulated gas sales. . . . - - 192,976 46,427 - 239,403
Gas transportation and
storage . . . . . . . . . . 104,351 182,362 206 (1) - 286,918
Liquid sales. . . . . . . . . - - 110,717 - - 110,717
Other . . . . . . . . . . . . 13,316 35,813 14,973 5,338 3,497 72,937
________ _________ ________ ________ ________ ___________
Total nonaffiliated. . . . 936,162 218,175 318,872 52,887 3,497 1,529,593
Affiliated. . . . . . . . . . . 3,263 50,139 2,495 9,050 (64,947) -
________ _________ ________ ________ ________ ___________
Total operating revenues . 939,425 268,314 321,367 61,937 (61,450) 1,529,593
Operating expenses
Purchased gas . . . . . . . . . 504,215 23,323 15,904 46,647 (62,980) 527,109
Liquids, capacity and other
products purchased. . . . . . - 11,169 59,593 2,329 (34) 73,057
Operation expense . . . . . . . 151,426 63,283 81,406 10,736 (300) 306,551
Maintenance . . . . . . . . . . 22,536 12,155 4,236 35 1,036 39,998
Depreciation and amortization . 40,217 32,253 93,480 1,372 1,902 169,224
Taxes, other than income taxes. 68,890 18,432 3,871 266 3,635 95,094
________ _________ ________ ________ ________ __________
Operating income before
income taxes . . . . . . . 152,141 107,699 62,877 552 (4,709) 318,560
________ _________ ________ ________ ________ __________
Income taxes. . . . . . . . . . 44,988 34,172 14,792 9 (9,087) 84,874
Interest revenues . . . . . . . 224 2,184 588 1,100 (2,212) 1,884
Equity in earnings of
equity investees. . . . . . . - 4,558 2,140 1,368 - 8,066
Other revenues-net. . . . . . . 1,760 178 118 1,701 (4,807) (1,050)
Interest charges. . . . . . . . 25,251 11,156 10,590 4,868 5,874 57,739
________ _________ ________ ________ ________ __________
Income from continuing
operations. . . . . . . . . . $ 83,886 $ 69,291 $ 40,341 $ (156) $ (8,515) $ 184,847
======== ========= ======== ======== ======== ==========
Gas Sales (In Bcf). . . . . . . 124.9 - 80.2 16.6 (3.4) 218.3
===== ===== ==== ==== ===== =====
Gas Transportation (In Bcf) . . 105.1 335.4 .3 - (89.9) 350.9
===== ===== ==== ==== ===== =====
_________________________________________________________________________________________________________________________________
</TABLE>
10
<PAGE>
ITEM 1. FINANCIAL STATEMENTS (Continued)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
<TABLE>
<CAPTION>
_________________________________________________________________________________________________________________________________
Exploration
and Corporate and
Distribution Transmission Production Other Eliminations Total
_________________________________________________________________________________________________________________________________
(In Thousands)
<S> <C> <C> <C> <C> <C> <C>
THREE MONTHS TO JUNE 30, 1999
Operating revenues
Nonaffiliated
Regulated gas sales . . . . . $195,361 $ - $ - $ - $ - $ 195,361
Nonregulated gas sales. . . . - - 100,642 34,724 - 135,366
Gas transportation and
storage . . . . . . . . . . 43,764 76,372 122 - - 120,258
Liquid sales. . . . . . . . . - - 81,729 - - 81,729
Other . . . . . . . . . . . . 6,337 8,688 13,458 5,238 - 33,721
________ _________ ________ ________ ________ ___________
Total nonaffiliated. . . . 245,462 85,060 195,951 39,962 - 566,435
Affiliated. . . . . . . . . . . 1,814 22,491 11,960 3,602 (39,867) -
________ _________ ________ ________ ________ ___________
Total operating revenues . 247,276 107,551 207,911 43,564 (39,867) 566,435
Operating expenses
Purchased gas . . . . . . . . . 105,625 3,927 9,289 37,057 (37,549) 118,349
Liquids, capacity and other
products purchased. . . . . . - 9,672 50,070 1,939 (440) 61,241
Operation expense . . . . . . . 76,358 26,344 50,722 7,451 (1,947) 158,928
Maintenance . . . . . . . . . . 13,119 6,824 4,249 74 161 24,427
Depreciation and amortization . 19,360 14,082 59,547 443 1,144 94,576
Taxes, other than income taxes. 29,919 8,987 2,270 282 1,745 43,203
________ _________ ________ ________ ________ __________
Operating income before
income taxes . . . . . . . 2,895 37,715 31,764 (3,682) (2,981) 65,711
________ _________ ________ ________ ________ __________
Income taxes. . . . . . . . . . (4,182) 13,111 7,486 (317) (60,074) (43,976)
Interest revenues . . . . . . . 48 903 217 375 (962) 581
Equity in earnings of
equity investees. . . . . . . - 1,931 1,552 48 - 3,531
Merger-related expense. . . . . - - - - 165,338 165,338
Other revenues-net. . . . . . . (98) (46) 28 (280) 587 191
Interest charges. . . . . . . . 10,787 6,276 7,161 487 3,965 28,676
________ _________ ________ ________ ________ __________
Income from continuing
operations. . . . . . . . . . $ (3,760) $ 21,116 $ 18,914 $ (3,709) $(112,585) $ (80,024)
======== ========= ======== ======== ======== ==========
Gas Sales (In Bcf). . . . . . . 27.8 - 49.6 16.1 (8.3) 85.2
==== ===== ==== ==== ==== ====
Gas Transportation (In Bcf). . 46.9 112.8 .2 - (40.5) 119.4
==== ===== ==== ==== ===== =====
_________________________________________________________________________________________________________________________________
</TABLE>
11
<PAGE>
ITEM 1. FINANCIAL STATEMENTS (Concluded)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
<TABLE>
<CAPTION>
_________________________________________________________________________________________________________________________________
Exploration
and Corporate and
Distribution Transmission Production Other Eliminations Total
_________________________________________________________________________________________________________________________________
(In Thousands)
<S> <C> <C> <C> <C> <C> <C>
THREE MONTHS TO JUNE 30, 1998
Operating revenues
Nonaffiliated
Regulated gas sales . . . . . $207,671 $ - $ - $ 1 $ - $ 207,672
Nonregulated gas sales. . . . - - 94,474 13,354 - 107,828
Gas transportation and
storage . . . . . . . . . . 39,291 81,065 127 2 - 120,485
Liquid sales. . . . . . . . . - - 54,527 - - 54,527
Other . . . . . . . . . . . . 6,146 21,834 7,167 2,914 1,855 39,916
________ _________ ________ ________ ________ ___________
Total nonaffiliated. . . . 253,108 102,899 156,295 16,271 1,855 530,428
Affiliated. . . . . . . . . . . 877 16,961 1,122 4,062 (23,022) -
________ _________ ________ ________ ________ ___________
Total operating revenues . 253,985 119,860 157,417 20,333 (21,167) 530,428
Operating expenses
Purchased gas . . . . . . . . . 110,571 11,976 7,404 14,152 (22,005) 122,098
Liquids, capacity and other
products purchased. . . . . . - (1,379) 29,073 1,092 (34) 28,752
Operation expense . . . . . . . 70,309 31,043 41,439 4,137 2,913 149,841
Maintenance . . . . . . . . . . 10,700 6,753 1,710 23 605 19,791
Depreciation and amortization . 19,959 16,126 47,757 699 1,025 85,566
Taxes, other than income taxes. 27,928 9,146 1,806 138 1,652 40,670
________ _________ ________ ________ ________ __________
Operating income before
income taxes . . . . . . . 14,518 46,195 28,228 92 (5,323) 83,710
________ _________ ________ ________ ________ __________
Income taxes. . . . . . . . . . 412 11,298 6,032 (654) (1,711) 15,377
Interest revenues . . . . . . . 102 1,316 138 546 (1,742) 360
Equity in earnings of
equity investees. . . . . . . - 1,839 982 616 - 3,437
Other revenues-net. . . . . . . 570 588 85 947 436 2,626
Interest charges. . . . . . . . 11,832 5,811 5,253 3,220 1,826 27,942
________ _________ ________ ________ ________ __________
Income from continuing
operations. . . . . . . . . . $ 2,946 $ 32,829 $ 18,148 $ (365) $ (6,744) $ 46,814
======== ========= ======== ======== ======== ==========
Gas Sales (In Bcf). . . . . . . 29.8 - 40.7 4.8 (1.7) 73.6
==== ===== ==== === ==== ====
Gas Transportation (In Bcf) . . 42.3 119.7 .2 - (37.4) 124.8
==== ===== ==== ==== ===== =====
_________________________________________________________________________________________________________________________________
</TABLE>
12
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FINANCIAL CONDITION
Because of the seasonal nature of the regulated subsidiaries' heating business,
a substantial portion of the Company's cash receipts are realized in the first
six months of the year. In addition to satisfying cash requirements for
operations, capital expenditures, and dividend payments in the current and
prior year six-month periods, available cash was used to repay commercial paper
borrowings during 1999 and to make additional investments in Argentina and
Australia during 1998.
Due to the significant amount of revenues generated during the first six months
of a year, the consolidated balance sheet at the end of June typically shows an
increase in cash and temporary cash investments over the balance at the end of
the previous year. However, the balance of cash and temporary cash investments
at June 30, 1999, is less than the balance at December 31, 1998, due in part to
the net repayment of commercial paper borrowings noted above and the repayment
of long-term debt.
After the winter heating season and by June 30, accounts receivable have
declined, as is customary, from the high levels at the end of the previous
year and March of the current year. In addition, the inventory of stored gas
was reduced during the first six months of 1999 due to the demand for gas
during the winter heating season. Under the LIFO accounting method, the
excess of the estimated current cost of replacing inventories of gas withdrawn
from storage during the early part of the year over LIFO inventory cost at
the time of withdrawal is recorded in the income statement and as a current
liability. The amount charged to expense in the first six months of 1999 was
$108.1 million compared to $73.8 million in 1998. As the volume of gas
withdrawn from storage is replaced either partially or in its entirety later
in the year, the liability is eliminated. In the event the inventory is
not entirely replaced, any remaining liability is eliminated by an adjustment
to purchased gas expense.
During the remainder of 1999, funds required for the capital spending program
as well as other general corporate purposes are expected to be obtained
principally from internal cash generation and, if necessary, external
financing. External financing could be obtained through the issuance of new
debt and/or equity securities. In this regard, the Company has a shelf
registration with the SEC that permits the sale of up to $338.3 million of
debt or equity securities. The amount and timing of any future sale of these
securities will depend on capital requirements, including financing necessary
to enable the Company to pursue asset acquisition opportunities, and financial
market conditions.
The sale of commercial paper will be used to provide short-term financing
to the subsidiaries, primarily for gas inventory and other working capital
requirements. Borrowings under the Company's $1 billion short-term credit
agreement may be used for general corporate purposes, including the support
of commercial paper notes, and to temporarily finance capital expenditures.
This credit agreement, which replaced a $775 million short-term credit
agreement that expired in June 1999, is scheduled to expire on June 22, 2000.
There were no amounts outstanding under this credit agreement at June 30, 1999.
Reference is made to Note 2 to the consolidated financial statements, page 5,
for a discussion of the pending merger between the Company and DRI. Due to the
pending merger, Fitch IBCA, Moody's Investors Service and Standard & Poor's are
reviewing the Company's rated debt for possible downgrade.
In connection with this discussion of financial condition, reference is also
made to Notes 4, 6 and 7 to the consolidated financial statements.
13
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
(ALL PER SHARE REFERENCES, UNLESS INDICATED, ARE STATED AS BASIC EARNINGS
PER SHARE.)
RESULTS OF OPERATIONS
A major portion of the gas sold or transported by the Company's distribution
and transmission operations is ultimately used for space heating. As a result,
earnings are affected by changes in the weather. Because most of the operating
subsidiaries are subject to price regulation by federal or state commissions,
earnings can be affected by regulatory delays when price increases are sought
through general rate filings to recover certain higher costs of operation.
THREE MONTHS AND SIX MONTHS ENDED JUNE 30, 1999 AND 1998
SYSTEM RESULTS
The Company reported net income for the first six months of 1999 of $59.0
million, or $.62 per share, compared with net income of $135.7 million, or
$1.44 per share, in the first half of 1998. For the second quarter of 1999,
the Company reported a net loss of $80.0 million, or $.84 a share, compared
with net income of $57.8 million, or $.61 a share, in the prior year quarter.
Earnings for both 1998 periods reflect the Company's decision to discontinue
its wholesale energy trading and marketing operations (see Note 5 to the
consolidated financial statements, page 6). The Company recognized a loss on
these discontinued operations in the first six months of 1998 of $49.1
million. During the second quarter of 1998, the Company recognized income from
discontinued operations of $11.0 million which reflected a favorable adjustment
to revise certain previous estimates of shut-down costs in light of terms
included in the Company's agreement to sell its wholesale gas marketing
business. Accordingly, income from continuing operations in the first six
months and second quarter of 1998 was $184.8 million, or $1.96 per share, and
$46.8 million, or $.49 a share, respectively.
Income from continuing operations for the second quarter of 1999 includes costs
related to the pending merger with DRI amounting to $165.3 million (see Note 2
to the consolidated financial statements, page 5), and workforce reduction
costs totaling $6.3 million. Income from continuing operations for the second
quarter of 1998 included a gain of $13.9 million associated with a favorable
resolution of a regulatory contingency. Excluding special items, income from
continuing operations for the first six months of 1999 would have been $173.0
million, or $1.81 per share, compared to $170.9 million, or $1.81 per share, in
the first half of 1998. Second quarter income from continuing operations,
excluding special items, would have been $32.6 million, or $.34 per share, in
1999 compared to $32.9 million, or $.35 per share, in the prior year quarter.
Results from continuing operations for the first half of 1999 reflect colder
weather and increased gas and oil production, partially offset by lower
average wellhead prices for gas and oil compared with the respective 1998
period. Lower average gas and oil wellhead prices offset the favorable impact
of increased gas and oil production during the second quarter of 1999.
Weather in the Company's retail service territories in the first half of 1999
was 15.7% colder than 1998 but still 7.5% warmer than normal. In the second
quarter of 1999, weather was 2.1% warmer than last year and 19.9% warmer than
normal.
14
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
OPERATING REVENUES
Regulated gas sales revenues increased $2.5 million, to $822.1 million, in the
first six months of 1999 with sales volumes increasing 10.2 billion cubic feet
(Bcf), to 134.9 Bcf. Sales volumes increased during the 1999 first half for
the Company's residential and commercial customers, while sales volumes
declined slightly for industrial customers. Average sales rates for all
three customer groups declined compared to the first six months of 1998
reflecting lower purchased gas prices in 1999. In the 1999 second quarter,
regulated gas sales revenues decreased $12.3 million, to $195.4 million, as
sales volumes decreased 2.0 Bcf, to 27.8 Bcf. Combined sales volumes for
residential and commercial customers were down in the 1999 second quarter,
reflecting warmer weather, while average sales prices for those customer groups
increased slightly on a combined basis. Average sales rates and volumes for
industrial customers declined during the quarter.
In the first six months of 1999, nonregulated gas sales revenues increased
$47.8 million, to $287.2 million, with sales volumes increasing 27.9 Bcf, to
121.5 Bcf. Second quarter 1999 nonregulated gas sales revenues increased
$27.5 million, to $135.3 million, as sales volumes increased 13.6 Bcf, to 57.4
Bcf. Sales volume increases in both 1999 periods were due in large part to gas
sales by CNG Field Services Company and higher production and sales by CNG
Producing Company (CNG Producing).
Gas transportation and storage revenues were $304.5 million in the first half
of 1999, up $17.6 million from the first six months of 1998. In the second
quarter of 1999, gas transportation and storage revenues were $120.3 million,
down slightly from the prior year quarter. Amounts for 1999 include gas
transportation revenue increases of $21.2 million in the first half and $2.5
million in the second quarter attributable primarily to customers switching
from sales to transportation service at certain of the distribution
subsidiaries. Reduced storage service revenues in both 1999 periods offset the
increases.
Other operating revenues increased $15.4 million, to $199.1 million, in the
first six months of 1999, and increased $21.1 million, to $115.5 million,
in the second quarter. The improvements in both 1999 periods reflect increased
revenues from oil trading activities and oil and condensate sales, partially
offset by decreased revenues attributable to sales of products extracted from
natural gas and the resolution of certain regulatory contingencies in the
second quarter of 1998.
OPERATING EXPENSES
Operating expenses, excluding income taxes, increased $92.9 million in the
first half of 1999 and $54.1 million in the second quarter. Total purchased
gas expense increased $6.7 million in the first half of 1999, to $533.8
million, and declined $3.8 million, to $118.3 million, in the second quarter
compared to the respective prior year periods. Increased volume requirements
in connection with colder weather during the first quarter of 1999, partially
offset by lower average purchase prices, was the primary reason for the
increase in the six-month period. Lower average purchase
prices contributed to the second quarter 1999 decline. Liquids, capacity and
other products purchased was higher in both 1999 periods, increasing $46.2
million in the first half and $32.5 million in the second quarter. These
increases were due largely to increased purchases of pipeline capacity by CNG
Transmission Corporation (CNG Transmission) and higher oil trading volumes by
CNG Producing. Combined operation and maintenance expense increased $13.1
million in the first six months and $13.8 million in the second quarter of
1999 due primarily to workforce reduction costs and higher maintenance
expense, partially offset by reductions in miscellaneous general and
administrative expenses. Depreciation and amortization expense increased
$12.7 million in the first half of 1999 and $9.1 million in the second quarter
due chiefly to higher gas and oil production in 1999. Taxes, other than income
taxes, increased $14.2 million in the first six months of 1999, due primarily
to the timing of the recognition of certain taxes by one of the distribution
subsidiaries, and increased $2.5 million in the second quarter.
Income taxes declined $53.2 million in the first half of 1999 due to lower
pretax income. In the second quarter of 1999, income taxes declined $59.4
million due to a pretax loss in 1999, compared to pretax income in the prior
year quarter.
15
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
OTHER INCOME
Total other income (deductions) declined $169.4 million in the first half of
1999 and $167.5 million in the second quarter due chiefly to expenses totaling
$165.3 million recognized in the second quarter of 1999 in connection with the
Company's pending merger with DRI (see Note 2 to the consolidated financial
statements, page 5). Interest revenues decreased $.6 million in the first half
of 1999 and increased $.2 million in the second quarter. "Other-net" declined
$3.5 million in the first half of 1999, due in part to lower income from equity
investments, and decreased $2.3 million in the second quarter.
INTEREST CHARGES
Total interest charges of $57.8 million in the first half of 1999 were
relatively unchanged from the prior year period, while second quarter interest
charges increased $.7 million, to $28.7 million. The increased second quarter
1999 interest charges were due in part to higher interest costs associated with
commercial paper borrowings.
In connection with the discussion of results of operations, reference is also
made to Notes 3 and 10 to the consolidated financial statements.
BUSINESS SEGMENT RESULTS
DISTRIBUTION
Operating income before income taxes of the gas distribution operations was
$159.5 million in the first six months of 1999, compared to $152.1 million in
the first half of 1998. Excluding workforce reduction costs totaling $8.1
million related to a previously announced restructuring, 1999 first half
operating results would have been $167.6 million. Distribution throughput
in the first half of 1999 increased 17.7 Bcf, to 247.7 Bcf, reflecting weather
that was 15.7% colder than the first six months of 1998. Improved results
for the first six months of 1999 also reflect lower combined operation and
maintenance expense, partially mitigated by higher taxes, other than income
taxes.
Residential gas sales volumes increased 8.4 Bcf in the first half of 1999 to
104.2 Bcf. The distribution operations transported 10.6 Bcf of gas in the
first six months of 1999, compared to 7.6 Bcf in the first half of 1998,
on behalf of former residential sales customers who now purchase gas from
other suppliers, including CNG Retail Services Corporation. Sales to
commercial customers increased 2.2 Bcf to 29.2 Bcf while volumes transported
to these customers increased 1.9 Bcf to 26.8 Bcf. Total deliveries to
industrial customers increased 1.8 Bcf, to 72.5 Bcf, compared with the prior
year. Industrial transport volumes were up 1.9 Bcf to 71.1 Bcf, while sales
volumes declined slightly, to 1.4 Bcf. Off-system transport volumes were up
.6 Bcf in the first half of 1999, to 4.0 Bcf.
In the second quarter of 1999, the distribution operations reported operating
income before income taxes of $2.9 million, compared to $14.5 million in the
1998 second quarter. Excluding workforce reduction costs of $7.8 million, 1999
second quarter operating results would have been $10.7 million. Results for the
1999 quarter reflect weather that was 2.1% warmer than the prior year quarter,
higher maintenance costs and higher taxes, other than income taxes. Residential
gas sales volumes of 21.1 Bcf were down 1.9 Bcf compared to the 1998 quarter.
Gas transported on behalf of former residential sales customers totaled 2.9 Bcf
in the second quarter of 1999, unchanged from the prior year quarter.
Commercial sales volumes were up .3 Bcf, to 6.3 Bcf, while gas transported to
these customers was 8.7 Bcf, up 2.5 Bcf. Deliveries to industrial customers
increased 1.0 Bcf reflecting an increase in transport volumes of 1.1 Bcf
partially offset by a decline in sales volumes of .1 Bcf.
16
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
TRANSMISSION
Operating income before income taxes of the gas transmission operations
in the first six months of 1999 was $106.0 million, down $1.7 million from
the first half of 1998. In the second quarter of 1999, operating income before
income taxes was $37.7 million, a decrease of $8.5 million from 1998. However,
first half and second quarter 1998 results include $13.9 million resulting from
the favorable resolution of a regulatory contingency. Operating results for both
1999 periods reflect lower operating expenses compared to the respective prior
year periods.
Transmission throughput increased 30.1 Bcf in the first six months, due largely
to colder weather in the northeast in early 1999, and decreased 6.9 Bcf in the
second quarter compared to the prior year periods.
EXPLORATION AND PRODUCTION
The exploration and production operations reported operating income before
income taxes of $49.8 million in the first six months of 1999, compared to
$62.9 million in the first half of 1998. The effect of lower average gas
and oil wellhead prices in the first half of 1999 was only partially mitigated
by higher gas and oil production. In the second quarter, operating income
before income taxes was $31.8 million, up from $28.2 million in 1998. The
improvement in the 1999 second quarter results reflect the impact of higher
gas and oil production partially offset by lower average gas and oil wellhead
prices.
The Company's average gas wellhead price was $2.10 per thousand cubic feet
(Mcf) in the first six months of 1999, $.31 lower than 1998 but still favorable
in comparison with industry-wide prices in 1999. In the second quarter, the
average gas price was $2.18 per Mcf, down from $2.31 in the second quarter of
1998. Gas production in the first six months of 1999 was 89.0 Bcf, up 12.1 Bcf
from 76.9 Bcf in 1998. The increase in gas production in the first half of
1999 was due chiefly to increased production at the Main Pass 223 and High
Island 571 fields in the Gulf of Mexico. Second quarter gas production was
46.6 Bcf, up 7.2 Bcf from 39.4 Bcf in 1998 due in part to new production at
the Nautilus/Atlantis/Nemo complex in the Gulf of Mexico and at the Lopeno
Field in South Texas (see "EXPLORATION AND PRODUCTION", page 21).
The Company's average oil wellhead price was $10.66 per barrel in the first
half of 1999, down from $12.60 per barrel in the prior year period. The
average oil wellhead price for the second quarter of 1999 was $12.21 per
barrel compared to $12.71 in 1998. The decline in oil prices for both
1999 periods is consistent with the worldwide trend in prices during the
year. Oil production in the first six months of 1999 was 5.1 million barrels,
up 27% from 4.0 million barrels in 1998. Second quarter 1999 oil production
was 2.8 million barrels, up 45% from 1.9 million barrels in 1998. The increase
in oil production in both 1999 periods was due largely to new production at
the Nautilus/Atlantis/Nemo complex that began in late 1998 and early 1999.
See ITEM 3., "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK,"
page 23, for information regarding CNG Producing's use of derivatives at
June 30, 1999. In addition to these financial instruments, CNG Producing
has long-term sales contracts primarily with various cogeneration facilities
to hedge the risk of future price decreases. Minimum contract volumes and
prices for the remainder of 1999 and the following five years are summarized
below:
_______________________________________________________________________________
Volumes Weighted Average Price
Year (Bcf) (Mcf)
_______________________________________________________________________________
Remainder of 1999 11.7 $2.96
2000 19.7 $3.00
2001 15.6 $2.93
2002 11.3 $2.98
2003 8.8 $3.13
2004 8.4 $3.31
_______________________________________________________________________________
17
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
OTHER
The "Other" segment reported an operating loss before income taxes of $.4
million in the first half of 1999, a decline of $1.0 million compared to the
first six months of 1998. This segment reported an operating loss before
income taxes of $3.7 million in the second quarter of 1999, a decline of $3.8
million compared to the prior year quarter. The decreases in both 1999 periods
are due primarily to operating losses at the Company's unregulated retail
marketing subsidiaries.
SELECTED TWELVE-MONTH DATA
The following selected financial data (unaudited) relates to the twelve months
ended June 30, 1999 (in thousands of dollars):
______________________________________________________________________________
Operating revenues..................................... $2,843,696
Operating expenses..................................... 2,356,100
Operating income before income taxes............... 487,596
Income taxes........................................... 76,462
Other income (loss).................................... (134,726)
Interest charges....................................... 114,581
Income from continuing operations...................... 161,827
Discontinued operations................................ 204
Net income......................................... $ 162,031
Earnings per common share -- basic................. $1.70
Earnings per common share -- diluted............... $1.68
Times fixed charges earned............................. 2.69
______________________________________________________________________________
OTHER INFORMATION
YEAR 2000 TECHNOLOGY ISSUE
Reference is made to Exhibit 99 to the Company's 1998 Form 10-K regarding the
Company's approach to addressing the Year 2000 technology issue.
PROJECT STATUS
The following summarizes the Company's progress in the major project areas
through June 30, 1999:
<TABLE>
<CAPTION>
PHASE
Continuity
PROJECT AREA Inventory Assessment Repair/ Testing Planning
Replace
<S> <C> <C> <C> <C> <C>
APPLICATION
SYSTEMS Complete Complete Repair: Complete In progress In progress
Replacement:
In progress
PROCESS CONTROL
COMPONENTS Complete Complete In progress In progress In progress
TECHNICAL
INFRASTRUCTURE Complete Complete In progress In progress In progress
PHYSICAL
INFRASTRUCTURE Complete Complete In progress In progress In progress
BUSINESS In Final Not Not In progress
PARTNERS AND validation assessment applicable applicable
SUPPLIERS in progress
</TABLE>
18
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
APPLICATION SYSTEMS. During the assessment phase, approximately 80 application
systems were identified requiring some degree of repair or replacement.
However, the Company's actions to upgrade to newer, more functional versions of
vendor software have mitigated many existing year 2000 issues. These upgrade
activities will continue through mid-1999. Repair and replacement activities
for internally developed application systems began in March 1998. Nearly all
repair activities were completed (99%) by June 1999, while some replacement
activities (76% complete) will continue through September 1999. None of the
replacement activities are considered to be critical. Testing of all critical
application systems is nearly complete and is expected to be finalized by
September 1999. Overall, the Company considers 97% of its critical application
systems portfolio to be year 2000 ready. For critical application systems,
"year 2000 ready" indicates that the Company has completed repair or
replacement activities and independent testing. Reference is made to "Risks,"
page 21, for information on the status of the development of a new revenue and
customer information system for the distribution subsidiaries called "CAMP."
In July 1999, the Company implemented year 2000 change control methods to
ensure future stability in the application system and technical infrastructure
environments.
PROCESS CONTROL COMPONENTS. For process control components inventoried by the
Company, approximately 43% are not date sensitive, and therefore are not
affected by year 2000 issues. For date sensitive components, the Company is
experiencing via testing activities a year 2000 failure rate of approximately
2% to 3%. Replacement of a small number of non-compliant components will
continue through the remainder of 1999 as year 2000 compliant upgrades and
replacements become available from vendors. Unit testing activities for the
Company's regulated businesses are approximately 88% complete, while unit
testing for the Company's E&P business is 92% complete. System testing of the
interaction of process control components began in April 1999 and is expected
to be completed in October 1999.
TECHNICAL INFRASTRUCTURE. Technical infrastructure has been analyzed directly
with vendors and via the use of an external vendor research database service.
This information is being used to guide year 2000 upgrades of infrastructure
as necessary. Repair, replacement and testing activities are nearly 100%
complete for all categories of technical infrastructure, while efforts in the
critical area of application servers are 97% complete. The Company completed
a substantial portion of year 2000 upgrades by the end of 1998, and is
continuing with testing in 1999. The Company is also closely monitoring the
status of vendor-supplied products to ensure their continuing year 2000
compliance.
The Company has completed an inventory of its desktop personal computers and
continues to deploy updated desktop infrastructure that is year 2000 ready
concurrent with the implementation of various new application systems. The
Company has completed testing to confirm year 2000 readiness of this
infrastructure and associated software, and is installing software upgrades
and hardware replacements. The Company has also completed examining the
year 2000 aspects of user-created desktop files, applications and spreadsheets
and repairs are being made as necessary.
PHYSICAL INFRASTRUCTURE. The Company has completed an inventory and analysis
of gas and non-gas related physical infrastructure components that may be
subject to year 2000 problems. Of the facilities inventoried, 109 are
considered critical. The Company is currently focusing on repair and
testing activities where necessary. The loss of electrical power to the
Company's compression facilities is a major risk to the continued reliable
transmission and delivery of natural gas. The Company has identified 91
critical facilities which have electrical power backup and is currently
performing load testing (74% complete) to ensure this power is adequate to
continue the transmission and delivery processes.
Where facilities are leased, the Company has identified and contacted building
managers/lessors to ensure they are actively addressing the year 2000 issue.
The Company is also using facilities information as a primary component of its
continuity planning effort.
19
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
BUSINESS PARTNER AND VENDOR RELATIONSHIPS. Strategic business partner and
vendor relationships have been identified and assessment continues via
questionnaires and interviews. Over 1,200 business partner and vendor
relationships had been identified and queried. Of the business partners and
vendors identified, only about 250 are prioritized as strategic to key Company
business processes. Of these strategic relationships, over 87% have already
reported to the Company that they are either compliant or making good progress
in mitigating any year 2000 issues. In conjunction with business continuity
planning, the Company is currently validating its business partner inventory
and obtaining updated status information. The Company has developed a risk
assessment methodology which it will employ to rate each of the critical
business partners. To validate business continuity planning assumptions,
various segments of the Company are conducting face-to-face meetings with
critical business partners and developing cooperative relationships where
necessary to further mitigate risk. Risk assessment will continue throughout
1999. The Company's analysis includes the year 2000 status of operations in
Argentina and Australia in which the Company has investments.
CONTINUITY PLANNING. This project seeks to complement year 2000 activities
that have been performed to date by ensuring that critical business processes
are operational during and after the date change. Business continuity
planning consists of developing and testing different types of plans, including
a "zero day" plan, a continuity plan and a recovery plan. The Company has
completed development of continuity planning methodology, has identified
critical business processes throughout the Company, and has trained business
continuity managers to develop and coordinate plans. As of June 1999, 248
plans were identified. The majority of these plans are related to the
activities of the Company's regulated businesses, in areas such as gas supply,
gas control, transmission and storage, and distribution. Business continuity
planning is 72% complete for the Company's regulated businesses. The Company
is also actively performing recovery and zero-day planning for application
systems which are critical to continued operations. This activity commenced
in June 1999 and is expected to be completed by the end of August 1999.
Through continuity planning, the Company is also identifying capital
improvements which are necessary to support the various continuity plans.
The Company expects to spend $1.3 million in permanent capital improvements,
such as for the purchase and deployment of power generators, by the end of
1999.
COSTS
Based upon project status as described above, the Company expects to spend
a total of approximately $20.4 million in connection with its Year 2000
Project Office efforts, its use of external consultants and the repair of
affected application systems. This estimate includes capitalized costs for
hardware and software used (or expected to be used) in the testing phase,
and for application system and technical infrastructure replacements. This
estimate excludes costs incurred or expected to be incurred in connection
with the development and installation of major new application systems which
are expected to be year 2000 ready, the Company's potential share of year
2000 costs that may be incurred by partnerships and joint ventures in which
the Company participates but is not the operator, and internal labor costs
other than those of the core Project Office. As of June 30, 1999, the
Company has incurred costs approximating $7.8 million (of which $1.4 million
has been capitalized) in connection with its year 2000 efforts. Total costs
incurred as of June 30, 1999, as a proportion of the total year 2000 budget,
is not indicative of the progress of the project.
20
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
RISKS
Significant progress continues in the development of CAMP for use at Hope
Gas and EOG Energy Choice. However, previous technical difficulties and
delays have caused the Company to invoke a contingency plan which involves
renovation of the current revenue application system for the other distribution
subsidiaries and 20 related application systems to make such systems year 2000
ready. These current systems collectively address the business processes which
were to be handled by CAMP. Renovation activities have been completed in
connection with this contingency plan and implementation, including testing, is
scheduled to be completed by August 1999. Under a worst case scenario, the
current revenue application systems would not be year 2000 ready by the end of
1999 for the other distribution subsidiaries and CAMP would not be successfully
implemented or year 2000 ready at Hope Gas and EOG Energy Choice. The estimate
of $20.4 million referred to above includes approximately $3.4 million of costs
in connection with the CAMP contingency plan. Concurrent with this effort, the
Company is continuing the development of CAMP and has capitalized $59.7 million
related to this project as of June 30, 1999. The CAMP core software is a
licensed product of the Company's independent accountants,
PricewaterhouseCoopers LLP (PwC), and PwC is the primary information systems
consultant on this project.
If a material year 2000 problem is not corrected in a timely manner, an
interruption in, or a failure of, certain normal business activities or
operations of the Company could occur. Such instances could materially and
adversely affect the Company's financial position, cash flows and/or results
of operations. Due to the uncertainty inherent in the year 2000 issue,
including the uncertainty of year 2000 readiness of third party vendors,
business partners and customers, the Company cannot determine at this time
whether the consequences of any year 2000 failures will have a material impact
on its financial position, cash flows or results of operations. However, the
Company's Project Office activities and the implementation of new application
systems are expected to reduce the risk of a material year 2000 failure.
ATLANTIC ALLIANCE PROJECT
On July 19, 1999, CNG Transmission and Tennessee Gas Pipeline Company, a
business unit of El Paso Energy Corporation, announced the Atlantic Alliance
Project to jointly offer natural gas transportation service of up to 750,000
dekatherms per day from the Chicago market center and the Niagara Import Point
into eastern markets. The Atlantic Alliance will combine the use of existing
facilities and rights-of-way with construction of limited incremental
facilities to provide the new services. Construction will be in phases to
correspond with customer service requests. However, the full 750,000
dekatherms per day could be available as early as November 1, 2001, pending
required approval of the Federal Energy Regulatory Commission.
The Atlantic Alliance will target developing markets in New York, Pennsylvania,
and New England. It will include access to Transcontinental Gas Pipe Line
Corporation and the proposed MarketLink Project at Leidy, Pennsylvania, and to
Columbia Gas Transmission Corporation and the proposed Millennium Project at
Horseheads or Greenwood, New York.
EXPLORATION AND PRODUCTION
As previously reported, CNG Producing, acting alone or with partners, was the
high bidder on nine tracts offered at the federal government's March 17, 1999
Gulf of Mexico lease sale. The Company's bids totaled $7.3 million for the
properties, six of which are located in deepwater areas of the Gulf of Mexico.
The government has accepted all nine bids. The Company's working interests in
three of the deepwater properties will be 100% each, while working interests in
the other three deepwater tracts will be 50% each. The Company will have 100%
working interests in two of the three remaining properties and a 33.3% interest
in the third.
In June 1999, CNG Producing entered into a definitive purchase agreement to
acquire interests in Lopeno and two adjacent South Texas natural gas fields.
Coupled with its purchase of a 50% interest earlier in 1999 in the Lopeno
field, CNG Producing will own nearly a 100% interest in the field. The
aggregate cost of the two transactions was approximately $125 million.
21
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Concluded)
Lopeno and the adjacent fields located in South Texas contain 50 active wells
with current working interest production of 56 million cubic feet of natural
gas a day. As a result of the acquisitions, the Company's capital spending for
the E&P segment in 1999 is expected to total approximately $476 million, up
$139 million from the originally approved budget of $337 million.
OTHER
As previously reported, on April 14, 1999, CNG Power Company, a wholly-owned
subsidiary of the Company, and DRI signed an agreement (Agreement) to develop
natural gas-fired power generation facilities along the Company's natural gas
pipeline system. Under the terms of the Agreement, the companies have
identified 45 potential development sites along the Company's natural gas
pipeline network in Ohio, Pennsylvania, New York, West Virginia and Virginia.
A separate development entity is to be formed for each suitable site pursuant
to an operating agreement or other appropriate documents to be mutually agreed
upon between the parties. Affiliates of the Company and DRI will develop, own,
operate and maintain the facilities on an equal basis.
In connection with the Agreement, on May 25, 1999 the Company and DRI announced
that they expect to begin development of four natural gas-fired electric power
generation facilities: two 600-megawatt facilities in Ohio; a 300- to
600-megawatt facility in Pennsylvania; and a 300- to 600-megawatt facility in
West Virginia. These new facilities represent an investment of up to $800
million and construction is anticipated to be completed by mid-2002.
The Company has guaranteed the performance of CNG Power Company under the
Agreement. The Agreement is not conditioned upon the pending merger of the
Company and DRI (see Note 2 to the consolidated financial statements, page 5).
FORWARD-LOOKING INFORMATION
Certain matters discussed in this Form 10-Q, including Management's Discussion
and Analysis of Financial Condition and Results of Operations, are
"forward-looking statements" intended to qualify for the safe harbors from
liability established by the Private Securities Litigation Reform Act of 1995.
These forward-looking statements can generally be identified as such because
the context of the statement will include words such as the Company "believes,"
"anticipates," "expects" or words of similar import. Similarly, statements that
describe the Company's future plans, objectives or goals are also forward-
looking statements. Such statements may address future events and conditions
concerning the Company's pending merger with DRI, capital expenditures,
earnings, risk management, litigation, the year 2000 technology issues and
costs, environmental matters, rate and other regulatory matters, liquidity
and capital resources, and financial accounting and reporting matters. Actual
results in each instance could differ materially from those currently
anticipated in such statements, due to factors such as: natural gas and
electric industry restructuring, including ongoing state and federal
activities; the weather; demographics; general economic conditions and specific
economic conditions in the Company's distribution service areas; developments
in the legislative, regulatory and competitive environment in which the Company
operates; and other circumstances affecting anticipated revenues and costs.
Risks in connection with the Company's year 2000 efforts include the Company's
ability to successfully identify, correct and test, in a timely manner,
potential year 2000 problems which could have a significant impact on specific
business functions or processes, and the ability of third party vendors,
business partners and customers to ensure year 2000 readiness of their systems
and business operations.
22
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
As described in the 1998 Form 10-K, the Company utilizes over-the-counter
(OTC) price swap agreements, option contracts, and exchange-traded futures
contracts to manage market price risk inherent in the production, purchase
and sale of natural gas and oil and stored gas inventories.
In connection with its price risk management activities, CNG Producing has
hedged the following natural gas and crude oil production using derivatives
as of June 30, 1999:
<TABLE>
<CAPTION>
___________________________________________________________________________________________________________________________________
FINANCIAL INSTRUMENT 1999 2000 2001 2002 2003
<C> <C> <C> <C> <C>
OIL (000 barrels)
Futures/Swaps . . . . . . . . . . . . 1,710
Weighted Average Price (per barrel) . $15.22
Two-way Collars . . . . . . . . . . . 840 5,124
Weighted Average Price (per barrel) . $15.00-$17.50 $16.11-$19.11
GAS (million mmbtu)
Futures/Swaps . . . . . . . . . . . . 47.1 29.0 29.0 29.0 29.0
Weighted Average Price (per mmbtu). . $2.25 $2.33 $2.32 $2.35 $2.38
Three-way Collars . . . . . . . . . . 72.0 12.0 12.0 12.0
Weighted Average Price (per mmbtu). . $2.41-$2.61 $2.45-$2.70 $2.49-$2.74 $2.54-$2.79
Average Collar Floor Price. . . . . . $2.10 $2.13 $2.13 $2.14
Average Differential. . . . . . . . . $0.31 $0.32 $0.36 $0.40
___________________________________________________________________________________________________________________________________
</TABLE>
For the three-way collars above, if the market price falls below the collar
floor, then the price received will equal the market price plus the
differential.
CNG Producing's hedging activities in connection with its natural gas and crude
oil production resulted in aggregate unrealized losses at June 30, 1999 of
$27.2 million and $12.3 million, respectively. Realized gains (losses)
incurred by CNG Producing related to price risk management activities are
summarized below (in thousands):
_______________________________________________________________________________
SIX MONTHS TO THREE MONTHS TO
JUNE 30 JUNE 30
1999 1998 1999 1998
Natural Gas . . . . . . $14,411 $7,214 $ 2,039 $ 446
Crude Oil . . . . . . . $(2,338) $7,976 $(2,338) $5,400
_______________________________________________________________________________
Unrealized and realized gains and losses related to the use of derivatives do
not reflect the impact on earnings of the related physical transactions. The
effect of these physical transactions has, or is expected to, substantially
offset the financial gains and losses arising from the use of derivatives.
At June 30, 1999, unrealized gains and losses arising from the Company's use
of derivatives, other than at CNG Producing, were not material.
***************
In connection with the financial information included in PART I of this report,
reference is made to the Company's 1998 Form 10-K, including Exhibit 99
thereto, and its quarterly report to the SEC on Form 10-Q for the quarter
ended March 31, 1999.
23
<PAGE>
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
There have been no material new legal proceedings instituted in the second
quarter of 1999, and there have been no material developments during the
quarter in the legal proceedings disclosed in the Company's 1998 Form 10-K
or in any earlier Form 10-Q for 1999 as then pending, except as noted below.
As previously reported, on April 20, 1999, the Company and the directors party
to the suit were served with a purported Class Action Complaint, Civil Action
No. 17114-NC, styled Gerold Garfinkel v. Raymond E. Galvin, Paul E. Lego,
Margaret A. McKenna, William S. Barrack, Jr., Steven A. Minter, J. W. Connolly,
George A. Davidson, Jr., Richard P. Simmons, and Consolidated Natural Gas
Company. The Complaint was filed in the Delaware Court of Chancery on
April 20, 1999. The Complaint seeks injunctive relief in the form of an order
to the individual Board members to sell the Company for the highest value to
the shareholders, an accounting of any damages resulting from any failure
to sell the Company for the highest value, a determination with respect
to the reasonableness of the break-up fee in the agreement with DRI and other
miscellaneous relief. The Complaint also seeks an award of costs and
attorneys' fees. Several additional purported Class Action Complaints against
the Company and its directors seeking essentially the same relief have been
combined with this action. The Company has moved to dismiss.
The Pennsylvania Department of Environmental Protection has informed the
Company that it expects to issue a Notice of Violation and associated penalties
with respect to a spill of fuel oil from a CNG Transmission facility into an
unnamed tributary of Raccoon Creek, Beaver County, Pennsylvania, in February
1998. The spill resulted from an unexpected rupture of underground pipelines
and has been remediated. It is anticipated that penalties, which are being
negotiated, will exceed $100,000.
ITEM 2. CHANGES IN SECURITIES
(a) See response to ITEM 6., page 25, re: May 21, 1999 filing.
(b) Limitations on the payment of dividends by the Company are set forth
in Note 7 to the consolidated financial statements, page 8, and reference is
made thereto.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company's Annual Meeting of Shareholders was held on April 13, 1999.
Common shareholders voted on four items. The voting results on these matters
were as follows:
1. Election of three Directors whose term of office expires May 2002.
VOTES VOTES BROKER
NOMINEES FOR WITHHELD NON-VOTES
Raymond E. Galvin 80,004,568 2,431,213 0
Paul E. Lego 79,427,030 3,008,751 0
Margaret A. McKenna 79,604,774 2,831,007 0
Directors whose term of office continued after the meeting:
Term expiring May 2000: William S. Barrack, Jr., Ray J. Groves and
Steven A. Minter
Term expiring May 2001: J. W. Connolly, George A. Davidson, Jr. and
Richard P. Simmons
24
<PAGE>
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS (Concluded)
2. Ratification of the appointment of PricewaterhouseCoopers LLP as
independent accountants.
VOTES VOTES BROKER
FOR AGAINST ABSTENTIONS NON-VOTES
80,831,294 1,189,368 415,119 0
3. Action on the Company's Performance Restricted Stock Awards.
VOTES VOTES BROKER
FOR AGAINST ABSTENTIONS NON-VOTES
75,397,358 6,003,861 1,034,562 0
4. Action on a stockholder-proposed resolution regarding bonuses.
VOTES VOTES BROKER
FOR AGAINST ABSTENTIONS NON-VOTES
7,394,932 64,936,725 1,983,835 8,120,289
The Company held a special meeting of shareholders on June 30, 1999 to vote
on the approval and adoption of the Amended Plan of Merger with DRI.
The voting results on this matter were as follows:
VOTES VOTES
FOR AGAINST ABSTENTIONS
78,049,820 1,109,080 591,369
ITEM 5. OTHER INFORMATION
None, other than as described elsewhere in this report.
ITEM 6. EXHIBITS, AND REPORTS ON FORM 8-K
REPORTS ON FORM 8-K
As previously reported, on May 7, 1999, the Company filed a Current Report
on Form 8-K (Form 8-K) regarding the Company's adoption of amendments to
the Severance Pay Policy of Consolidated Natural Gas Company and Its
Participating Subsidiaries Who Are Not Represented by a Recognized Union.
On May 20, 1999, the Company filed a Form 8-K which included, as an Exhibit,
the Amended and Restated Agreement and Plan of Merger, as of May 11, 1999, by
and between CNG and DRI (see Note 2 to the consolidated financial statements,
page 5).
On May 21, 1999, the Company filed a Registration Statement on Form 8-A/A which
included, as an Exhibit, Amendment No. 3 to the Consolidated Natural Gas
Company Rights Agreement (Rights Agreement). The Rights Agreement was
initially filed with the SEC on January 23, 1996, as an Exhibit to a Form 8-K.
On July 1, 1999, the Company filed a Form 8-K which included, as an Exhibit,
a press release concerning the results of the special shareholder meetings
held concurrently by the Company and DRI regarding shareholder approval of the
pending merger (see ITEM 4. above).
25
<PAGE>
ITEM 6. EXHIBITS, AND REPORTS ON FORM 8-K (Concluded)
EXHIBITS
______________________________________________________________________________
SEC
Exhibit
Number Description of Exhibit
______________________________________________________________________________
(11) Statement re Computation of Per Share Earnings:
Computations of Earnings Per Common Share -- Basic, and Earnings
Per Common Share -- Diluted of Consolidated Natural Gas Company
and Subsidiaries for the three months and six months ended June
30, 1999 and 1998
(12) Statement re Computation of Ratios:
Ratio of Earnings to Fixed Charges of Consolidated Natural Gas Company
and Subsidiaries for the twelve months ended June 30, 1999
(27) Financial Data Schedule has been filed electronically
______________________________________________________________________________
26
<PAGE>
SIGNATURES
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.
CONSOLIDATED NATURAL GAS COMPANY
_______________________________________
(Registrant)
D. M. WESTFALL
_______________________________________
D. M. Westfall, Senior Vice President,
Nonregulated Business
and Chief Financial Officer
S. R. MCGREEVY
_______________________________________
S. R. McGreevy, Vice President,
Accounting and Financial Control
August 3, 1999
27
<PAGE>
EXHIBIT INDEX
______________________________________________________________________________
SEC
Exhibit
Number Description of Exhibit
______________________________________________________________________________
(11) Statement re Computation of Per Share Earnings:
Computations of Earnings Per Common Share -- Basic, and Earnings
Per Common Share -- Diluted of Consolidated Natural Gas Company and
Subsidiaries for the three months and six months ended June 30, 1999
and 1998 is filed herewith
(12) Statement re Computation of Ratios:
Ratio of Earnings to Fixed Charges of Consolidated Natural Gas Company
and Subsidiaries for the twelve months ended June 30, 1999 is filed
herewith
(27) Financial Data Schedule is filed herewith
______________________________________________________________________________
EXHIBIT 11
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
COMPUTATION OF EARNINGS PER COMMON SHARE
(In Thousands, Except Per Share Data)
<TABLE>
<CAPTION>
________________________________________________________________________________________________________________________
Six Months to Three Months to
June 30, 1999 June 30, 1999
_______________________________ ________________________________
Per Share Per Share
Net Income Shares Amount Net Income Shares Amount
________________________________________________________________________________________________________________________
<S>
EARNINGS PER COMMON SHARE -- BASIC
Income (loss) from continuing operations.. $ 58,963 95,571 $ .62 $(80,024) 95,763 $(.84)
________ _______ _____ _______ ______ _____
NET INCOME (LOSS) ........................ $ 58,963 95,571 $ .62 $(80,024) 95,763 $(.84)
======== ======= ===== ======== ====== =====
EARNINGS PER COMMON SHARE -- DILUTED
Income (loss) from continuing operations.. $ 58,963 95,571 $(80,024) 95,763
Effect of dilutive securities:
Exercise of stock options............... 560 717
Vesting of performance shares........... 441 454
________ _______ _______ ______
Income (loss) from continuing operations,
as adjusted............................. 58,963 96,572 $ .61 (80,024) 96,934 $(.83)
________ _______ _____ _______ ______ _____
NET INCOME (LOSS), AS ADJUSTED............ $ 58,963 96,572 $ .61 $(80,024) 96,934 $(.83)
======== ======= ===== ======= ====== =====
________________________________________________________________________________________________________________________
Six Months to Three Months to
June 30, 1998 June 30, 1998
_______________________________ ________________________________
Per Share Per Share
Net Income Shares Amount Net Income Shares Amount
________________________________________________________________________________________________________________________
<S> <C> <C> <C> <C> <C> <C>
EARNINGS PER COMMON SHARE -- BASIC
Income from continuing operations......... $184,847 94,234 $1.96 $46,814 95,447 $.49
Loss from discontinued operations......... (17,238) (.18) - -
Income (loss) from disposal of
discontinued operations................. (31,911) (.34) 10,989 .12
________ _______ _____ _______ ______ ____
NET INCOME................................ $135,698 94,234 $1.44 $57,803 95,447 $.61
======== ======= ===== ======= ====== ====
EARNINGS PER COMMON SHARE -- DILUTED
Income from continuing operations......... $184,847 94,234 $46,814 95,447
Effect of dilutive securities:
Exercise of stock options............... 628 651
Vesting of performance shares........... 374 380
Conversion of 7 1/4% Convertible
Subordinated Debentures............... 1,578 1,721 - -
________ _______ _______ ______
Income from continuing operations,
as adjusted............................. 186,425 96,957 $1.92 46,814 96,478 $.49
Loss from discontinued operations......... (17,238) (.17) - -
Income (loss) from disposal of
discontinued operations................. (31,911) (.33) 10,989 .11
________ _______ _____ _______ ______ ____
NET INCOME, AS ADJUSTED................... $137,276 96,957 $1.42 $57,803 96,478 $.60
======== ======= ===== ======= ====== ====
</TABLE>
EXHIBIT 12
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
RATIO OF EARNINGS TO FIXED CHARGES
(Thousands of Dollars)
_____________________________________________________________________________
Twelve Months to June 30 1999
_____________________________________________________________________________
Earnings:
Income from continuing operations......................... $161,827
Add income taxes.......................................... 76,462
________
Income from continuing operations before income taxes... 238,289
Distributed income from unconsolidated investees,
less equity in earnings thereof......................... (6,970)
________
Subtotal................................................ 231,319
________
Add fixed charges:
Interest on long-term debt, including amortization
of debt discount and expense less premium............. 104,066
Other interest expense.................................. 23,266
Portion of rentals deemed to be representative
of the interest factor............................... 9,498
________
TOTAL FIXED CHARGES......................................... 136,830
________
TOTAL EARNINGS.............................................. $368,149
========
RATIO OF EARNINGS TO FIXED CHARGES.......................... 2.69
========
_____________________________________________________________________________
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED FINANCIAL STATEMENTS INCLUDED IN ITEM 1 OF CONSOLIDATED NATURAL
GAS COMPANY'S QUARTERLY REPORT ON FORM 10-Q FOR THE QUARTER ENDED JUNE 30,
1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-START> JAN-01-1999
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,096,904
<OTHER-PROPERTY-AND-INVEST> 1,436,271
<TOTAL-CURRENT-ASSETS> 771,258
<TOTAL-DEFERRED-CHARGES> 480,303
<OTHER-ASSETS> 311,201
<TOTAL-ASSETS> 6,095,937
<COMMON> 263,860
<CAPITAL-SURPLUS-PAID-IN> 527,069
<RETAINED-EARNINGS> 1,559,552
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,390,594
0
0
<LONG-TERM-DEBT-NET> 1,380,289
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 450,903
<LONG-TERM-DEBT-CURRENT-PORT> 7,125
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,907,139
<TOT-CAPITALIZATION-AND-LIAB> 6,095,937
<GROSS-OPERATING-REVENUE> 1,612,883
<INCOME-TAX-EXPENSE> 31,687
<OTHER-OPERATING-EXPENSES> 1,303,865
<TOTAL-OPERATING-EXPENSES> 1,335,552
<OPERATING-INCOME-LOSS> 277,331
<OTHER-INCOME-NET> (160,526)
<INCOME-BEFORE-INTEREST-EXPEN> 116,805
<TOTAL-INTEREST-EXPENSE> 57,842
<NET-INCOME> 58,963
92,813
<EARNINGS-AVAILABLE-FOR-COMM> 58,963
<COMMON-STOCK-DIVIDENDS> 92,813
<TOTAL-INTEREST-ON-BONDS> 96,447
<CASH-FLOW-OPERATIONS> 505,650
<EPS-BASIC> .62
<EPS-DILUTED> .61
</TABLE>
