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EXHIBIT 1
TABLE OF CONTENTS
PAGE
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Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 1
Selected Financial Data..................................... 18
Report of Independent Accountants........................... 19
Consolidated Statement of Income for the Years 1997 through
1999...................................................... 21
Consolidated Balance Sheet at December 31, 1998 and 1999.... 22
Consolidated Statement of Cash Flows for the Years 1997
through 1999.............................................. 24
Consolidated Statement of Comprehensive Income for the Years
1997 through 1999......................................... 25
Notes to Consolidated Financial Statements.................. 26
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[This Page Intentionally Left Blank]
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
(All per share references, unless indicated, are stated as basic earnings
per share.)
MERGER
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.
The Company announced on May 11, 1999 that, after careful consideration,
the Board of Directors had unanimously rejected an unsolicited merger proposal
from Columbia Energy Group. 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 will receive a combination of
DRI common stock and cash with a calculated 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 opinions of counsel on
the tax-free nature of the stock portion of the transaction.
On June 30, 1999, the shareholders of both the Company and DRI voted to
approve the merger of the two companies.
As of December 31, 1999, the Company and DRI had received all state and
federal regulatory approvals required for consummation of the merger. The
anticipated merger closing date is January 28, 2000. Reference is made to Note 2
to the consolidated financial statements, page 29, for additional information on
the merger.
RESULTS OF OPERATIONS
NET INCOME
Net income in 1999 was $136.8 million, or $1.43 a share, compared with net
income of $238.8 million, or $2.52 a share, in 1998. Net income in 1997 was
$304.4 million, or $3.21 a share. Prior year results, however, reflect the
Company's decision to discontinue its wholesale energy trading and marketing
operations in 1998 (see Note 3 to the consolidated financial statements, page
30). The Company recognized a loss on discontinued operations of $48.9 million,
or $.51 a share, in 1998 and $14.5 million, or $.15 a share, in 1997.
INCOME FROM CONTINUING OPERATIONS
Income from continuing operations was $136.8 million, $287.7 million and
$318.9 million for 1999, 1998 and 1997, respectively. On a per share basis,
income from continuing operations was $1.43 in 1999, compared to $3.03 in 1998
and $3.36 in 1997. Income from continuing operations for 1999 includes costs
related to the pending merger with DRI amounting to $212.7 million (see Note 2
to the consolidated financial statements, page 29). Excluding the merger costs,
income from continuing operations for 1999 would have been $282.1 million, or
$2.95 per share.
1999
Excluding merger costs in 1999 and the favorable effect of the resolution
of a regulatory contingency in 1998, income from continuing operations increased
$8.3 million compared to the prior year. Results for 1999 reflect increased gas
and oil production, higher average oil wellhead prices, and colder weather
compared to 1998, partially offset by higher operating expenses. Although
weather in the Company's retail service areas during 1999 was 7.9% warmer than
normal, it was 12.2% colder than 1998. Normal weather represents a measure of
temperature experienced over an historical time frame, the length of which may
differ depending on the
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regulatory jurisdiction. Results for 1999 also reflect a pretax net pension
credit of $71.8 million, compared to $56.5 million in 1998. The increase in this
noncash credit reflects higher investment returns earned by the Company's
defined benefit pension plans during 1999.
1998
Income from continuing operations for 1998 included a gain of $13.9 million
associated with the favorable resolution of a regulatory contingency. Excluding
this special item, income from continuing operations declined $45.1 million in
1998. The effects of warm winter weather and lower average wellhead prices for
gas and oil were only partially mitigated by ongoing cost reduction efforts and
the impact of higher oil production. Weather in the Company's retail service
areas was 17.8% warmer than normal and 19.3% warmer than 1997. The warmer than
normal weather in 1998 reduced earnings by $.47 per share. When compared to
normal, 1998 was the second warmest year in the Company's history.
1997
Income from continuing operations in 1997 increased $9.5 million from the
prior year. The favorable impact of higher gas and oil production and continued
cost containment efforts more than offset the effects of warmer weather and
lower average wellhead prices for both gas and oil. Weather in the Company's
retail service areas was 1.9% colder than normal but 4.3% warmer than 1996.
OPERATING REVENUES
Operating revenues include revenues from gas and oil sales, transportation
and storage of gas, gas and oil trading activities and by-product operations.
Total operating revenues in 1999 were $3,074.3 million, an increase of $313.9
million from 1998.
1999
Regulated gas sales revenues increased $23.5 million, to $1,397.2 million.
Regulated gas sales volumes increased 14.0 billion cubic feet (Bcf), to 221.1
Bcf, reflecting colder weather compared to the prior year. While gas sales
volumes increased for the residential and commercial customer groups, volumes
sold to industrial customers declined slightly. The effect of the overall
increase in gas sales volumes was partially mitigated by lower average sales
rates for all three customer groups, reflecting the pass through of lower
purchased gas costs compared to 1998.
Nonregulated gas sales revenues increased $113.5 million, to $607.9
million, in 1999. Nonregulated gas sales volumes totaled 244.9 Bcf, an increase
of 37.8 Bcf from the prior year. The increased sales volumes reflected increased
gas sales by CNG Field Services Company (CNG Field Services) and higher
production and sales by CNG Producing Company (CNG Producing).
Gas transportation and storage revenues totaled $566.8 million in 1999, up
$20.9 million from 1998. Gas transportation revenues increased $25.8 million in
1999 attributable in part to customers switching from sales to transportation
service at certain of the distribution subsidiaries, while storage service
revenues declined $4.9 million.
Other operating revenues increased $156.0 million in 1999, to $502.4
million. The increase was due chiefly to increased oil trading revenues from CNG
Producing, higher oil and condensate sales and increased sales of products
extracted from natural gas.
1998
Regulated gas sales revenues declined $477.3 million during 1998 compared
to the prior year, to $1,373.7 million. Regulated sales volumes declined 64.9
Bcf, to 207.1 Bcf, due chiefly to warmer weather in 1998. Residential customers
switching to transport service also caused a decline in sales volumes. In
addition, lower average sales rates for all three major customer
classes--residential, commercial and industrial--reflecting lower purchased gas
costs contributed to the decline in revenues.
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Nonregulated gas sales revenues increased $61.0 million in 1998, to $494.4
million, with sales volumes increasing 36.1 Bcf, to 207.1 Bcf. The increased
sales volumes in 1998 were due to gas sales by CNG Retail Services Corporation
(CNG Retail), in its first full year of operation, and CNG Field Services.
Gas transportation and storage revenues rose $53.8 million, to $545.9
million, in 1998. This improvement includes a $47.6 million increase associated
with gas transportation revenues due largely to customers switching from sales
to transport service at certain of the distribution subsidiaries.
Other operating revenues declined $54.2 million in 1998, to $346.4 million,
due primarily to lower revenues from oil production and oil trading activities
as a result of declining oil prices during 1998.
OPERATING EXPENSES
Operating expenses, including income taxes, were $2,614.9 million in 1999,
compared to $2,392.9 million and $2,766.7 million in 1998 and 1997,
respectively.
Purchased gas consistently represents the largest operating expense
category for the Company. Purchased gas costs were $911.7 million in 1999,
$900.4 million in 1998 and $1,114.1 million in 1997. This expense is influenced
primarily by changes in gas sales requirements, the price of gas supplies, and
the timing of recoveries of deferred purchased gas costs. The increase in 1999
was due chiefly to increased volume requirements in connection with colder
weather experienced in that year, while lower average purchase prices helped to
hold back the increase. The decline in 1998 was due primarily to decreased
volume requirements in connection with the warm weather in 1998, combined with
lower average purchase prices.
Liquids, capacity and other products purchased expense includes the cost of
oil, condensate and by-products purchased for resale, electricity purchased for
resale by CNG Retail, and pipeline capacity not associated with gas purchased.
This expense increased $134.6 million in 1999 due largely to increased oil
trading activity by CNG Producing and increased purchases of pipeline capacity
by CNG Transmission Corporation (CNG Transmission). During 1998, this expense
decreased $65.2 million due primarily to lower average purchase prices for oil
traded by CNG Producing and less pipeline capacity purchased by CNG
Transmission.
Combined operation and maintenance expense increased $65.2 million in 1999
due primarily to higher royalty expenses, increased allowance for doubtful
accounts at one of the distribution subsidiaries, and contributions to the CNG
Foundation. Combined operation and maintenance expense decreased $48.8 million
in 1998 due largely to lower royalty expense, lower amortization expense related
to abandoned facilities and lower general and administrative expenses. The
decline in 1998 was partially offset by workforce reduction charges recognized
in the fourth quarter of 1998 due principally to the plan to reorganize the
management structure of the Company's regulated operations.
Total depreciation and amortization (DD&A) expense increased $48.8 million
in 1999 due to higher gas and oil production volumes and $5.3 million in 1998
due to higher oil production volumes.
Taxes, other than income taxes, increased $18.1 million in 1999 due chiefly
to the timing of the recognition of excise tax expense by one of the
distribution subsidiaries and declined $14.3 million in 1998 for the same
reason.
Income taxes decreased $56.0 million in 1999 due to lower pretax income and
declined $26.7 million in 1998 due to lower pretax income and a lower effective
tax rate.
OTHER INCOME
Total other income (deductions) was $(198.2) million in 1999, compared to
$34.7 million in 1998 and $12.4 million in 1997. The caption in 1999 includes
expenses of $212.7 million recognized in connection with the Company's pending
merger with DRI (see Note 2 to the consolidated financial statements, page 29).
"Other-net" declined $19.4 million during 1999 due in part to lower gains on
property dispositions and reduced earnings from equity investments. In 1998 this
caption increased $20.8 million due principally to increased earnings from
equity investments at CNG International. Interest revenues decreased slightly in
1999 and increased $1.5 million in 1998.
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INTEREST CHARGES
Interest on long-term debt increased $2.0 million in 1999 and $1.4 million
in 1998. Interest recognized during 1999 in connection with $200 million of
debentures issued in October 1998 and $400 million of notes issued in September
1999, partially offset by the impact of the redemption in June 1999 of $100
million of debentures, was the primary reason for the increase in 1999. The 1998
increase was due chiefly to a full year of interest expense on the $300 million
of debentures issued in the fourth quarter of 1997, partially offset by reduced
interest expense in 1998 resulting from the redemption of the convertible
subordinated debentures. Other interest expense increased $8.9 million in 1999
and $13.9 million in 1998 due primarily to interest on commercial paper
borrowings.
FOURTH QUARTER RESULTS
Net income for the fourth quarter of 1999 was $67.0 million, or $.70 per
share, compared to $95.0 million, or $1.00 per share, in 1998. Excluding merger
expenses of $39.7 million recognized in the fourth quarter of 1999, net income
would have been $98.1 million, or $1.02 per share. Net income for the fourth
quarter of 1998 includes a loss from discontinued operations of $2.2 million, or
$.02 per share. Results for 1999 reflect increased gas and oil production,
higher average gas and oil wellhead prices and colder weather compared to the
fourth quarter of 1998. These factors were partly offset by higher operating
expenses in 1999, including contributions to the CNG Foundation and deferred
taxes associated with the potential sale of CNG International (see Note 9 to the
consolidated financial statements, page 36). The Company produced 46.8 Bcf of
gas during the fourth quarter of 1999, up 13% from 1998, and produced 2.5
million barrels of oil, a 22% increase over the prior year quarter. The
Company's fourth quarter 1999 average gas wellhead price was $2.52 per thousand
cubic feet (Mcf), up $.35 per Mcf, while average oil wellhead prices increased
$6.90 per barrel compared to the prior year quarter, to $16.64 per barrel.
Weather in the fourth quarter of 1999 was 4% colder than the prior year quarter.
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QUARTERS ENDED DECEMBER 31, 1999 1998
--------------------------- ---- ----
(In Millions)
Operating revenues.......................................... $ 955.8 $ 807.4
Operating expenses.......................................... (776.8) (654.4)
Operating income before income taxes........................ 179.0 153.0
Income taxes................................................ (40.4) (45.2)
Other income/expenses-net................................... (71.6) (10.6)
------- -------
Income from continuing operations........................... 67.0 97.2
Income (loss) from discontinued operations.................. -- (2.2)
------- -------
Net income.................................................. $ 67.0 $ 95.0
======= =======
Earnings (loss) per common share--basic (in dollars)
Continuing operations..................................... $ .70 $ 1.02
Discontinued operations................................... -- (.02)
------- -------
Net income.................................................. $ .70 $ 1.00
======= =======
Earnings (loss) per common share--diluted (in dollars)
Continuing operations..................................... $ .70 $ 1.01
Discontinued operations................................... -- (.02)
------- -------
Net income.................................................. $ .70 $ .99
======= =======
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NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," in 1998. 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
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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.
SEGMENTS OF THE BUSINESS
Due to the regulated nature of the distribution and transmission segments
of the Company's business, operating results can be affected by regulatory
delays when price increases are sought through general rate filings to recover
certain higher costs of operations. Weather is also an important factor since a
major portion of the gas sold or transported by the distribution and
transmission operations is ultimately used for space heating.
Operating results for each of the Company's business segments, which
include affiliated transactions, follow. Reference is made to Note 19 to the
consolidated financial statements, page 46, for additional segment information.
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OPERATING INCOME BEFORE INCOME TAXES 1999 1998 1997
------------------------------------ ---- ---- ----
(In Millions)
Distribution.................................. $203.4 $208.2 $266.6
Transmission.................................. 201.9 183.6 180.9
Exploration and production.................... 135.0 116.6 142.8
Other (a)..................................... 1.2 (1.4) (7.3)
Corporate and eliminations.................... (8.5) (9.9) (16.3)
------ ------ ------
Total.................................... $533.0 $497.1 $566.7
====== ====== ======
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(a) Includes CNG International, CNG Retail, CNG Products and Services, CNG
Power, CNG Field Services (formerly CNG Storage Services), Consolidated LNG,
CNG Research and CNG Coal.
DISTRIBUTION
"Distribution" represents the results of the four retail gas distribution
subsidiaries: The East Ohio Gas Company (East Ohio Gas), The Peoples Natural Gas
Company (Peoples Natural Gas), Virginia Natural Gas, Inc. (Virginia Natural Gas)
and Hope Gas, Inc. (Hope Gas). Reference is made to Note 2 to the consolidated
financial statements, page 29, regarding the requirement to sell or spin off
Virginia Natural Gas in connection with its merger with DRI.
Sales growth in the Company's residential service areas in Ohio,
Pennsylvania and West Virginia has generally been limited since such areas have
experienced minimal population growth, and the vast majority of households in
these areas already use natural gas for space heating. Growth in the retail
sales market has largely been at Virginia Natural Gas, due to customer
conversions from other energy sources and the past expansion of its service
territory. Since the Company's acquisition of this subsidiary in 1990, it has
experienced an annual customer growth rate of about 4%, compared to a growth
rate of less than 1% for the other distribution subsidiaries.
Similar to the unbundling of the services provided by gas pipeline
companies, gas distribution companies are adapting to the deregulation and
unbundling of the retail energy market. Under open access programs, natural gas
suppliers other than the local gas utility can use the utility's existing lines
to deliver gas to customers.
CNG Retail, created in 1997, markets natural gas, electricity, and consumer
products and services to residential, commercial and small industrial customers,
including those within the Company's traditional service territories. CNG Retail
is expected to enable the Company to take advantage of emerging deregulated
energy markets for both gas and electricity.
During the spring of 1997, Peoples Natural Gas opened its system in
Pennsylvania to customer choice. In addition, on July 2, 1997, the Public
Utilities Commission of Ohio approved East Ohio Gas' "Energy Choice"
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(EOG Energy Choice) pilot program which allows approximately 15% of East Ohio
Gas' residential and small business customers the opportunity to purchase their
natural gas from competing suppliers, if they so choose.
Reference is made to "Gas and Electric Industry Developments," page 11, for
additional information regarding industry deregulation.
DISTRIBUTION OPERATING INCOME BEFORE INCOME TAXES
1999
Operating income before income taxes declined $4.8 million in 1999, to
$203.4 million, compared to the prior year. The effect of higher operating
costs, including the timing of the recognition of excise tax expense and
increased allowance for doubtful accounts, more than offset the impact of colder
weather compared to 1998. In addition, workforce reduction costs were $5.2
million higher in 1999. Although weather in the Company's retail service areas
during 1999 was 7.9% warmer than normal, it was 12.2% colder than the prior
year. Operating income before income taxes attributable to Virginia Natural Gas
represented 15.5% of the total for this segment during 1999.
1998
Operating income before income taxes declined $58.4 million in 1998, to
$208.2 million, compared to 1997. The impact of warmer weather in 1998 was
partially mitigated by lower operation expenses and the timing of the
recognition of excise tax expense. Weather in the Company's retail service areas
was 17.8% warmer than normal and 19.3% warmer than 1997. The 1998 period also
included a $4.5 million charge for workforce reduction costs recognized in the
fourth quarter in connection with the Company's plan to reorganize and
centralize the management of its regulated operations.
1997
Operating income before income taxes was $266.6 million in 1997, up $8.2
million from the prior year. However, the 1996 period included workforce
reduction charges of $8.2 million. The effect of warmer weather in 1997 offset
the impact of lower operation and maintenance expenses during the year. Weather
in the Company's retail service areas was 1.9% colder than normal and 4.3%
warmer than 1996.
DISTRIBUTION OPERATING REVENUES
Operating revenues increased $28.3 million in 1999, to $1,640.1 million.
Regulated gas sales increased $22.0 million as higher sales volumes resulting
from the colder weather during 1999 more than offset the impact of lower average
sales rates. Gas transportation and storage revenues increased $12.4 million
reflecting higher volumes during 1999. The volume increase reflects the
continued migration of residential customers from sales to transport service.
Operating revenues attributable to Virginia Natural Gas represented 12.4% of the
total for this segment for 1999.
Operating revenues decreased $414.8 million, to $1,611.8 million, in 1998.
Average sales rates and volumes declined in 1998 compared to the prior year.
Sales rates declined due to the pass-through of lower purchased gas costs. Lower
volumes in 1998 reflected warmer weather during the year and the impact of
former residential sales customers who now purchase gas from other suppliers,
including CNG Retail. Gas transportation and storage revenues increased $44.0
million in 1998 due to both higher volumes and rates. The increase in gas
transportation volumes reflects the switch by residential customers from sales
to transport service.
DISTRIBUTION THROUGHPUT
Since distribution sales volumes largely represent gas used for space
heating, changes in volumes are primarily a function of the weather. In addition
to sales service, the distribution operations provide gas transportation
services to a wide range of customers, primarily commercial and industrial end
users. Therefore,
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the volume of gas transported can be affected by changes in both economic and
market conditions and are being impacted by the continued displacement of gas
sales volumes to other suppliers.
DISTRIBUTION THROUGHPUT 1999* 1998 1997
----------------------- ----- ---- ----
(In Billion Cubic Feet)
Sales............................................ 221.4 207.6 272.7
Transportation................................... 208.6 198.9 189.4
----- ----- -----
Throughput..................................... 430.0 406.5 462.1
===== ===== =====
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* Includes 23.1 Bcf of sales throughput and 10.1 Bcf of transportation
throughput attributable to Virginia Natural Gas.
Gas sales volumes increased in 1999 compared to 1998 as the impact of
colder weather more than offset the continued displacement of sales volumes to
other suppliers. Residential gas sales volumes increased 10.5 Bcf in 1999, to
170.4 Bcf. The distribution operations transported 17.3 Bcf of gas during 1999,
up 2.7 Bcf from 1998, on behalf of former residential sales customers who now
purchase gas from other suppliers, including CNG Retail. Sales to commercial
customers increased 3.8 Bcf to 48.1 Bcf while volumes transported to these
customers was unchanged at 43.0 Bcf. Total deliveries to industrial customers
increased 7.1 Bcf, to 142.8 Bcf, compared to the prior year. Industrial
transport volumes were up 7.2 Bcf to 140.4 Bcf, while sales volumes declined
slightly, to 2.4 Bcf. Off-system transport volumes declined .2 Bcf in 1999, to
7.9 Bcf.
Gas sales volumes declined in 1998 compared to the prior year primarily as
a result of warmer weather and the continued displacement of sales volumes to
other suppliers. Residential gas sales volumes declined 47.9 Bcf in 1998, to
159.9 Bcf. The distribution subsidiaries transported 14.6 Bcf of gas in 1998,
compared to 2.7 Bcf in 1997, on behalf of former residential sales customers who
now purchase gas from other suppliers, including CNG Retail. Sales to commercial
customers declined 15.4 Bcf to 44.3 Bcf while volumes transported to these
customers decreased .3 Bcf to 43.0 Bcf, both declines being attributable to the
warm weather. Total deliveries to industrial customers decreased 2.6 Bcf, to
135.7 Bcf. Industrial transport volumes were down .8 Bcf to 133.2 Bcf, while
sales volumes declined 1.8 Bcf to 2.5 Bcf. Off-system transport volumes were
down 1.3 Bcf in 1998, to 8.1 Bcf.
TRANSMISSION
"Transmission" includes the results of the gas transmission, storage,
by-product and certain other activities of CNG Transmission and the by-products
business of CNG Power. Gas and oil production activities of CNG Transmission are
included in the exploration and production segment.
TRANSMISSION OPERATING INCOME BEFORE INCOME TAXES
1999
Operating income before income taxes increased $18.3 million in 1999, to
$201.9 million. As indicated below, the results for 1998 included a gain of
$13.9 million in connection with the favorable resolution of a regulatory
contingency. Lower operation and depreciation expenses and increased prices and
volumes for natural gas by-products contributed to the higher results for 1999.
1998
Operating income before income taxes was $183.6 million in 1998, an
increase of $2.7 million compared to the prior year. The 1998 results include
the impact of the favorable resolution of a regulatory contingency and a charge
for workforce reduction costs of $1.1 million. Also, the 1997 results included a
charge amounting to $5.8 million recognized in connection with CNG
Transmission's withdrawal from participation in a gas storage development
project.
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1997
Operating income before income taxes declined slightly in 1997, to $180.9
million. While the 1997 period included the charge for the storage project
indicated above, 1996 results included a $5.1 million charge for workforce
reduction costs.
TRANSMISSION OPERATING REVENUES
Total operating revenues increased $24.3 million, to $526.8 million, during
1999. Gas transportation revenues were up $27.3 million reflecting higher
average rates and volumes. Gas storage service revenues declined $1.5 million.
Revenues from the sale of by-products increased $4.8 million due to higher
average sales rates and volumes. Other operating revenues declined $6.3 million
compared to the prior year due to the $13.9 million favorable resolution of a
regulatory contingency recognized in 1998.
Total operating revenues increased $3.2 million during 1998, to $502.5
million. Gas transportation revenues increased $4.1 million, as higher average
rates more than offset lower volumes, and gas storage service revenues increased
$3.0 million. Revenues from the sale of by-products declined $18.2 million due
to lower sales rates. Higher other operating revenues for 1998 include $13.9
million relating to the favorable resolution of a regulatory contingency.
TRANSMISSION THROUGHPUT
The changing regulatory environment has created a number of opportunities
for pipeline companies to expand and serve new markets. The Company has taken
advantage of selected market expansion opportunities, concentrating its efforts
primarily in the Northeast and along the East Coast. This expansion is supported
by the Company's network of underground storage facilities and the location and
nature of its gridlike pipeline system as a link between the country's major
longline gas pipelines and the increasing energy demands of East Coast markets.
A further expansion project in conjunction with East Ohio Gas and others will
provide additional capacity at minimal cost. CNG Transmission's pipeline and
storage facilities will continue to enable retail end users to take advantage of
the accessibility of supplies nationwide in the evolving deregulation of the gas
industry at the retail level (see "Distribution," page 5, and "Gas and Electric
Industry Developments," page 11).
Variations in weather conditions can also have a significant impact on the
throughput of the transmission operations, since a substantial portion of the
gas deliveries of these operations is ultimately used by space-heating
customers. Also, transmission operations provide transportation services to a
wide range of customers, including commercial and industrial end users, electric
power generators, and local utility companies. Therefore, the volume of gas
transported can also be affected by changes in economic and market conditions.
Total throughput for the gas transmission operations, consisting entirely
of transportation volumes, was 647.2 Bcf, 612.5 Bcf and 732.8 Bcf for the years
1999, 1998 and 1997, respectively.
EXPLORATION AND PRODUCTION
"Exploration and production" (E&P) includes the results of CNG Producing
and the gas and oil production activities of CNG Transmission.
E&P OPERATING INCOME BEFORE INCOME TAXES
1999
Operating income before income taxes increased $18.4 million in 1999, to
$135.0 million. The effect of higher gas and oil production and higher oil
wellhead prices was partially offset by the impact of slightly lower gas
wellhead prices. Results for 1998 reflected lower gas and oil production during
the third quarter due in large part to four hurricanes and tropical storms that
forced temporary shutdowns of oil and natural gas wells in the Gulf of Mexico.
Those storms also delayed development efforts at the Nautilus complex, delaying
initial production at that location until the first quarter of 1999. During
1999, the Company added 417 Bcf of gas equivalent from additions, revisions, and
purchases of gas and oil reserves.
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1998
Operating income before income taxes in 1998 was $116.6 million, a decline
of $26.2 million from 1997. Results for 1998 reflected the impact of lower
average gas and oil wellhead prices and lower gas production, partially offset
by higher oil production. Both oil and gas production were negatively impacted
during 1998 due to the hurricanes and tropical storms noted above. Also, the
1997 results included a non-cash, pretax charge of $10.4 million related to the
Company's impairment of its Canadian oil producing properties. During 1998, the
E&P segment added 374 Bcf of gas equivalent from additions, revisions, and
purchases of gas and oil reserves, while CNG Producing also purchased 39 Bcf of
gas reserves from an affiliate, Peoples Natural Gas.
1997
Operating income before income taxes in 1997 was $142.8 million, up $9.6
million from 1996. As noted above, the 1997 results included an impairment
charge of $10.4 million. The results for 1997 reflected increased gas and oil
production that more than offset the impact of lower average wellhead prices for
gas and oil, higher royalty expense, increased operating costs related to
bringing certain new production on line and increased workover activity. During
1997, the Company added 315 Bcf of gas equivalent from additions, revisions, and
purchases of gas and oil reserves.
GAS AND OIL PRODUCTION, PRICES AND OTHER INFORMATION
The following table sets forth the Company's gas and oil production,
average wellhead prices and other information for the E&P operations for the
last three years:
1999 1998 1997
---- ---- ----
GAS (BCF)
Nonregulated................................................ 181.6 154.9 155.3
Regulated*.................................................. -- 2.6 2.8
--------- -------- --------
Total.................................................. 181.6 157.5 158.1
========= ======== ========
OIL (000 BBLS)
Nonregulated................................................ 10,315.7 7,894.7 7,312.0
========= ======== ========
AVERAGE WELLHEAD PRICES--NONREGULATED
Gas (per Mcf)............................................... $ 2.25 $ 2.26 $ 2.43
Oil (per Bbl)............................................... $ 13.19 $ 11.54 $ 16.07
OTHER E&P DATA--NONREGULATED
DD&A (per Mcf equivalent)................................... $ .93 $ .89 $ .88
Average production (lifting) cost (per Mcf equivalent)...... $ .33 $ .31 $ .33
- ---------------
* Cost-of-service. Cost-of-service gas reserves were held solely by Peoples
Natural Gas and sold to CNG Producing during 1998.
The Company's average gas wellhead price was $2.25 per Mcf in 1999, down
slightly from 1998. Gas production for 1999 was 181.6 Bcf, up 24.1 Bcf from
1998. The increase in gas production for 1999 was due chiefly to increased
production at the Main Pass 223 and High Island 571 fields and new production at
the Nautilus/Atlantis/Nemo complex in the Gulf of Mexico. Production from the
newly-acquired Lopeno Field in South Texas also contributed to higher gas
production in 1999. The Company's average oil wellhead price was $13.19 per
barrel in 1999, up $1.65 per barrel from the prior year period. The movement in
oil prices during 1999 is consistent with the worldwide trend in prices during
the year. Oil production in 1999 was 10.3 million barrels, up 31% from 1998. The
increased oil production in 1999 was due largely to new production at the
Nautilus/ Atlantis/Nemo complex that began in early 1999, and increased
production at Neptune that resulted from development work performed in 1998.
The Company's average gas wellhead price was $2.26 per Mcf in 1998, down
$.17 from 1997 but still favorable compared to industry-wide prices in 1998 due
to a market price hedging program. Gas production in
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1998 was down .6 Bcf, to 157.5 Bcf, compared to 1997. Average oil wellhead
prices were $11.54 per barrel in 1998, down $4.53 from 1997, while oil
production increased nearly 600,000 barrels, to 7.9 million barrels. The
increase in oil production in 1998 was due in part to a full year of production
at Neptune, a deep-water project in the Gulf of Mexico which began production in
March 1997.
E&P OPERATING REVENUES
Total operating revenues increased $222.1 million in 1999, to $853.2
million. Gas sales revenues increased $63.8 million due primarily to higher
sales volumes. Revenues from oil and condensate production and trading increased
$130.3 million due to higher sales volumes and higher average sales prices.
Revenues from oil trading increased $85.1 million and revenues from oil and
condensate production increased $45.2 million. Other operating revenues
increased $28.0 million during 1999 due in part to higher sales of by-products.
Total operating revenues for the E&P operations were $631.1 million in
1998, a decline of $74.6 million from 1997. Gas sales revenues decreased $9.4
million due to both lower volumes and lower average gas prices compared to 1997.
Revenues from oil and condensate production and trading declined $71.9 million
in 1998 as the effect of lower average sales prices outweighed the impact of
higher sales volumes. Revenues from oil trading decreased $45.6 million and
revenues from oil and condensate production declined $26.3 million. Other
operating revenues increased $6.7 million in 1998.
OTHER
This component, as described in the operating results table on page 5,
reported operating income before income taxes of $1.2 million in 1999 and
operating losses before income taxes of $1.4 million and $7.3 million in 1998
and 1997, respectively. Pretax operating income of $6.9 million attributable to
CNG Field Services in 1999 more than offset losses at the other subsidiaries
comprising this component. Losses at CNG Retail and CNG Products and Services
totaled $1.2 million, $5.3 million and $3.8 million in 1999, 1998 and 1997,
respectively. Partially offsetting the 1998 losses was $8.8 million of pretax
operating income from CNG Field Services.
Results of this component also reflect the operations of CNG International,
which had pretax operating losses of $4.4 million, $4.7 million and $6.8
million, for 1999, 1998 and 1997, respectively. However, earnings from CNG
International's operations are attributable to investments in foreign utilities
and pipelines which are accounted for under the equity method and are excluded
from the operating income amounts. CNG International reported a net loss of $1.5
million for 1999, net income of $2.5 million for 1998 and a net loss of $3.8
million in 1997 (see "International Activities" below).
DISCONTINUED OPERATIONS
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.
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 and
electricity business was substantially complete at December 31, 1998.
Losses from discontinued operations, net of applicable tax benefits, were
$17.2 million in 1998 and $14.5 million in 1997. In addition, during 1998 the
Company recognized a loss on disposal of the discontinued operations, including
a provision for operating losses during the phase out period, of $31.7 million,
net of applicable tax benefit.
INTERNATIONAL ACTIVITIES
As indicated in Note 19 to the consolidated financial statements, page 46,
during the fourth quarter of 1999 the Company decided to focus on the United
States oil and gas markets and, accordingly, has begun exploring the sale of CNG
International. CNG International's net assets totaled $251.0 million at December
31, 1999.
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In March 1998 CNG International purchased a 33.3% ownership interest in the
Dampier-to-Bunbury Natural Gas Pipeline (DBNGP) in Western Australia from the
Western Australia Government. One of CNG International's partners in the
purchase was El Paso Energy Corporation (El Paso), which also holds a 33.3%
ownership interest. In connection with their investments in DBNGP, CNG
International and El Paso formed DBNGP Finance Company LLC (DBNGP Finance).
DBNGP Finance is owned 50% by CNG International and 50% by EPED Holding Company,
a wholly-owned subsidiary of El Paso. Subsequent to the formation of DBNGP
Finance, the equity ownership interests of CNG International and El Paso in
DBNGP were transferred to this entity.
In October 1998 DBNGP Finance borrowed $250 million under a Senior Term
Loan Facility (Term Loan). The Term Loan matures October 2, 2001, can be
extended in one-year increments to October 2, 2003, and bears interest at a
variable rate. Of the gross proceeds received by DBNGP Finance under the Term
Loan, $100 million was distributed to CNG International. In connection with the
Term Loan, CNG International entered into an Equity Contribution Agreement with
DBNGP Finance. CNG International is contractually obligated to make equity
contributions to DBNGP Finance equal to the Term Loan proceeds distributed to
CNG International, plus interest on such proceeds, in the event that DBNGP
Finance is unable to service this debt. The Company is contractually obligated
to cause CNG International to make such equity contributions.
LIMITATION ON CAPITALIZED COSTS
As indicated in Note 1 to the consolidated financial statements, the
Company follows the full cost method of accounting for its gas and oil producing
activities prescribed by the Securities and Exchange Commission (SEC). Reference
is made to Note 6 to the consolidated financial statements, page 31, regarding
the Company's recognition under the SEC full cost rules of an impairment of its
gas and oil producing properties at December 31, 1997.
There are a number of factors, including prices, that determine whether or
not an impairment is required. Because gas wellhead prices are subject to sudden
and seasonal fluctuations, an impairment of these gas and oil properties is a
possibility at any quarterly measurement date, unless other factors such as
lower production costs or proved reserve additions mitigate the impact of a
price decline.
GAS AND ELECTRIC INDUSTRY DEVELOPMENTS
Gas industry competition at the retail level is receiving increased
attention from both regulators and legislators. Governments in three of the
states in which the Company operates distribution subsidiaries have enacted or
considered legislation regarding deregulation of natural gas at the retail
level. In Ohio, a 1996 law established customer choice as a state policy in the
supply of natural gas services. Implementation of the law, which allows retail
customers to obtain gas from an array of suppliers, is under way. In
Pennsylvania, legislation was enacted to unbundle gas utility merchant functions
and permit the Pennsylvania Public Utility Commission to certify marketers, in
addition to gas utilities, as suppliers of last resort, creating competition in
a traditional gas utility function. Virginia is currently operating under a
one-year unbundling pilot program, enacted in 1999. The Virginia General
Assembly is currently considering legislation to make the program permanent.
In addition to restructuring of the gas industry, the emerging unbundling
of services provided by electric utilities is leading toward the convergence of
the two industries to create one overall, highly competitive marketplace for a
customer's total energy needs. Regulators and legislators at the federal level
and in many states are considering, or are already implementing, initiatives to
promote increased competition in the electric industry. A major development was
the issuance in 1996 of FERC Orders 888 and 889. By requiring open access to the
national electric transmission grid, Order 888 fosters increased competition in
both the generation of electricity and the supply of bulk power to major
wholesale customers. The companion order, Order 889, addresses the timing,
information access and other administrative details associated with the FERC
deregulation initiative. Congress also is considering legislation intended to
facilitate the move to competition in the electric industry.
Although progress status varies, pro-competition electric legislation is at
least under consideration in many states. In Ohio, legislation enacted in 1999
will allow all consumers to choose their electric supplier beginning January 1,
2001. In Pennsylvania, all consumers may now choose their supplier. Competition
is also forthcoming
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in Virginia, where in 1999 the General Assembly passed the "Utility
Restructuring Act" which will phase in customer choice between 2002 and 2004.
Regulators and legislators in West Virginia are also debating issues related to
electric industry restructuring.
Reflecting the evolution to a more competitive energy environment, the pace
and size of business combinations among natural gas and electric utilities has
increased in recent years (reference is made to Note 2 to the consolidated
financial statements, page 29, regarding the Company's pending merger with DRI).
These business combinations have generally been initiated to provide benefits
from economies of scale, to reduce costs by the elimination of duplicate
facilities and processes, and to improve the strategic and competitive position
of the surviving entity.
Recent and pending regulatory actions may serve to further facilitate more
business combinations in the energy industry. The FERC has streamlined its
regulatory review process regarding pending mergers. In addition, Congress has
considered legislation to conditionally repeal the Public Utility Holding
Company Act of 1935 (PUHCA), to which the Company is subject. While it seems
unlikely that Congress will enact PUHCA legislation on a stand-alone basis, it
appears more likely that any comprehensive electric restructuring bill will
include a PUHCA repeal provision. If legislation to repeal or significantly
modify the provisions of the PUHCA becomes law, certain federal restrictions
related to diversification activities, including business combinations, for gas
and electric companies subject to the PUHCA may be eased.
ENVIRONMENTAL MATTERS
The Company is subject to various federal, state and local laws and
regulations relating to the protection of the environment. These laws and
regulations govern both current and future operations and potentially extend to
plant sites formerly owned or operated by the subsidiaries, or their
predecessors.
Reference is made to Note 17 to the consolidated financial statements, page
44, for a detailed description of environmental matters.
Estimates of liability in the environmental area are based on current
environmental laws and regulations and existing technology. The exact nature of
environmental issues which the Company may encounter in the future cannot be
predicted. Additional environmental liabilities may result in the future as more
stringent environmental laws and regulations are implemented and as the Company
obtains more specific information about its existing sites and production
facilities. At present, no estimate of any such additional liability, or range
of liability amounts, can be made. However, the amount of any such liabilities
could be material.
EFFECTS OF INFLATION
Although inflation rates have been low to moderate in recent years, any
change in price levels has an effect on operating results due to the capital
intensive and regulated nature of the Company's major business components. The
Company attempts to minimize the effects of inflation through cost control,
productivity improvements and regulatory actions where appropriate.
FINANCIAL CONDITION
DIVIDEND AND COMMON STOCK MATTERS
Total dividends paid to common shareholders in 1999 were $185.6 million
compared with $185.9 million in 1998 and $184.6 million in 1997.
During 1999, a total of 4,376 original issue shares were issued primarily
in connection with the exercise of outstanding stock options.
Under the Company's stock repurchase plan, up to 10 million shares of the
Company's common stock can be repurchased in the open market. Shares may also be
purchased in private transactions. The Company may also acquire shares of its
common stock through certain provisions of the various stock incentive plans.
The shares repurchased or acquired are held as treasury stock and are available
for reissuance for general corporate purposes or in connection with various
employee benefit plans. In January 1998, the Company purchased approximately
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4.6 million shares of its common stock in a private transaction for use in
satisfying the conversion rights of debentures called for redemption (see "Call
of Debentures," page 14). At December 31, 1999 and 1998, a total of 10,443 and
495,123 shares, respectively, were being held as treasury stock.
CAPITAL SPENDING
The current capital spending program for 2000 is estimated at $621.6
million, a 2% decrease compared with total capital spending in 1999. The
estimated 2000 budget has been allocated as follows: exploration and production,
$445.5 million; distribution, $122.8 million; transmission, $48.2 million; and
corporate and other, $5.1 million. Exploration and production operations reflect
increased spending on deep-water projects and increased conventional onshore and
offshore drilling. Transmission and distribution operations expenditures will
primarily be limited to spending for enhancements and improvements in the
pipeline system and related facilities. The "corporate and other" category
includes expenditures to upgrade information systems technology.
Funds required for the capital spending program, as well as for other
general corporate purposes, are expected to be obtained principally from
internal cash generation. The Company may require long-term financing in 2000 to
support capital spending, and may also utilize the capital markets to take
advantage of other opportunities or to increase its financial flexibility.
CAPITAL RESOURCES AND LIQUIDITY
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 half of the year. However, cash requirements for capital expenditures,
dividends, debt retirements and other working capital needs do not track this
pattern of cash receipts. Consequently, additional cash needs are satisfied
through the sale of short-term commercial paper notes or by the issuance of
long-term debt. As shown in the Consolidated Statement of Cash Flows, net cash
provided by operating activities from continuing operations was $368.2 million,
$767.4 million and $784.1 million for the years 1999, 1998 and 1997,
respectively. The decline in net cash provided by operating activities in 1999
was due in part to lower net income and refunds paid to customers under
regulatory procedures in 1999.
In September 1999, the Company sold $400 million of 7 1/4% Notes Due
October 1, 2004. The proceeds were used for general corporate purposes including
capital expenditures, reduction of short-term debt, repurchase of Company stock,
and the acquisition, retirement or redemption of debt securities.
The Company has a shelf registration with the SEC which would allow it to
sell up to an additional $1 billion of debt securities. The amount and timing of
any future sale of these securities will depend on capital requirements and
financial market conditions.
The Company's embedded long-term debt cost, excluding current maturities,
at year-end 1999 was 7.05%, compared with 6.96% for 1998 and 7.20% for 1997. The
long-term debt to capitalization ratio was 42.6%, 36.5% and 39.7% at the end of
1999, 1998 and 1997, respectively. Under the provisions of one of the indentures
covering the Company's outstanding senior debenture issues, the ratio cannot
exceed 60%. The Company's senior debentures are rated A2 by Moody's Investors
Service, BBB+ by Standard & Poor's, A by Duff and Phelps, and A by Fitch
Investors Service.
At December 31, 1999, the Company had a short-term credit agreement with a
group of banks for $1 billion. The Company made no borrowings under this
agreement during 1999 and there were no amounts outstanding under any credit
agreements at December 31, 1999 or 1998.
The Company utilizes short-term borrowings to finance gas inventories and
other working capital requirements. Funds from the sale of commercial paper
notes were used for these purposes in 1999, of which $685.7 million was
outstanding at year-end. The Company may utilize unused portions of its credit
agreements to provide support for commercial paper notes.
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CALL OF DEBENTURES
In January 1998 the Company called for redemption the entire principal
amount outstanding of its 7 1/4% Convertible Subordinated Debentures, totaling
$246.2 million. These debentures were convertible into shares of the Company's
common stock at an initial conversion price of $54 per share. The redemption
price was 102.18% of the principal amount plus accrued interest payable on
February 23, 1998. In anticipation of the call, in January 1998 the Company
purchased approximately 4.6 million shares of its common stock in a private
transaction to satisfy the potential conversion obligation. The right to convert
expired on February 13, 1998, and approximately 1.6 million of the acquired
shares were issued on conversion. The remaining acquired shares were sold in two
underwritten offerings during February and March 1998.
YEAR 2000 TECHNOLOGY ISSUE
The Company has addressed the inability of some computer application
software programs to distinguish between the year 1900 and 2000 due to a
commonly-used programming convention.
In the early 1990s, the Company identified business systems in need of
technology updates to successfully adapt to changes in the business climate and
the emerging competitive marketplace. These changes required the Company to move
toward common, integrated systems and computing platforms. Accordingly, many
systems representing older technology, which were not year 2000 ready, were
targeted for replacement. This plan has been executed through major initiatives
such as a company-wide implementation of Oracle Financial Applications, the
development of a new revenue and customer information system for the
distribution subsidiaries called "CAMP," and the development and implementation
of applications for gas control management and asset and facilities mapping.
The Company has addressed year 2000 issues via a systematic methodology
that mitigates risk and incorporates a thorough due diligence process. This
strategy recognized that the definition of "year 2000 compliance" varies broadly
depending on the industry, component, vendor, and/or device. In 1997, the
Company formalized its approach to year 2000 issues with the creation of a Year
2000 Project Office (Project Office) at the corporate level to coordinate
company-wide year 2000 activities. All of the Company's operating subsidiaries
have participated in this effort under the direction of the Project Office.
COSTS
As of December 31, 1999, the Company has spent a total of $12.3 million in
connection with its Project Office efforts, its use of external consultants and
the remediation of affected application systems. This amount includes $1.4
million of capitalized costs for hardware and software used in the testing
phase, and for application system and technical infrastructure replacements.
This amount excludes costs incurred in connection with the development and
installation of major new application systems which were expected to be year
2000 ready, the Company's potential share of year 2000 costs 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.
Additional costs expected to be incurred during 2000 are not expected to be
material to the Company's results of operations, cash flows or financial
position.
STATUS AS OF JANUARY 15, 2000
As of January 15, 2000, the Company has experienced no material adverse
effect on safety, revenues, assets, customer service or the environment
resulting from the millennium date change. However, continuity planning is in
place for the remainder of 2000, particularly for potentially sensitive dates
such as February 29, 2000, and the Company's computer applications, operations
and vendors continue to be monitored for year 2000-related problems. For those
minor issues that have arisen subsequent to December 31, 1999, actions have been
taken to remedy each occurrence in a satisfactory manner.
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RISKS
Significant progress continues in the development of CAMP for use at Hope
Gas, EOG Energy Choice and the River Gas Division of East Ohio Gas. However,
previous technical difficulties and delays caused the Company to invoke a
contingency plan which involved renovation of the current revenue/CIS
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, testing and implementation activities have been completed in
connection with this contingency plan. As of January 15, 2000, the current
revenue/CIS application systems used by the other distribution subsidiaries and
CAMP have not experienced any material adverse effects in connection with the
millennium date change. The costs incurred of $12.3 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 $65.2 million related to this project as
of December 31, 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.
PRICE RISK MANAGEMENT ACTIVITIES
In the normal course of business, certain of the Company's operations are
subject to market risk and credit risk in connection with the production,
purchase and sale of natural gas and oil and stored gas inventories. In
addition, the Company's foreign equity investments are subject to foreign
currency risk. Reference is made to Note 16 to the consolidated financial
statements, page 43, regarding the fair value of the Company's long-term debt
which is comprised of fixed-rate instruments.
MARKET AND CREDIT RISK
Price risk management activities expose the Company to market risk. Market
risk represents the potential loss that can be caused by the change in market
value of a particular commitment. The Company has appropriate operating
procedures in place that are administered by experienced management to help
ensure that proper internal controls are maintained. In addition, the Company
has established an independent function at the Corporate level to monitor
compliance with the price risk management policies of all subsidiaries.
Price risk management activities also expose the Company to credit risk.
Credit risk represents the potential loss that the Company would incur as a
result of nonperformance by counterparties pursuant to the terms of their
contractual obligations. The Company maintains credit policies with respect to
its counterparties that management believes minimize overall credit risk. Such
policies include the evaluation of a prospective counterparty's financial
condition, collateral requirements where deemed necessary, and the use of
standardized agreements which facilitate the netting of cash flows associated
with a single counterparty. The Company also monitors the financial condition of
existing counterparties on an ongoing basis. Considering the system of internal
controls in place and credit reserve levels at December 31, 1999, the Company
believes it unlikely that a material adverse effect on its financial position,
results of operations or cash flows would occur as a result of counterparty
nonperformance.
The Company uses over-the-counter (OTC) price swap agreements,
exchange-traded futures contracts, and option contracts to manage market risk
inherent in the production, purchase and sale of natural gas and oil and stored
gas inventories. The level of market risk exposure from these activities is
maintained within risk management guidelines.
USE OF DERIVATIVES--NATURAL GAS
Information for derivatives that are sensitive to changes in natural gas
prices follow. Net notional quantities are used to calculate the payments and
quantities to be exchanged under the contractual terms of the futures contracts,
swap agreements and option contracts ("collars") and are not a measure of the
Company's exposure to the use of these derivatives. All of the futures
contracts, swap agreements and option contracts included in the tables below
have been entered into to hedge the risk of market price changes in connection
with the future production, purchase and/or sale of natural gas. It should also
be noted that these disclosures exclude information
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about the Company's natural gas commodity purchase and sale commitments which
are sensitive to changes in natural gas prices, and information related to firm
transportation and storage agreements for which the Company must make specified
minimum payments each month. Therefore, the information presented regarding the
use of derivatives by the Company does not reflect the earnings impact of the
physical transactions that may offset the financial gains and losses arising
from the use of derivatives.
The following table presents net notional quantities and weighted average
settlement prices by expected maturity date for futures contracts used to hedge
natural gas price risk. At December 31, 1999, the Company held no futures
contracts with maturity dates extending beyond 2002.
EXPECTED MATURITY DATE UNREALIZED
--------------------------- GAIN
EXCHANGE-TRADED FUTURES CONTRACTS 2000 2001 2002 TOTAL AT 12/31/99
--------------------------------- ---- ---- ---- ----- -----------
(In Thousands)
Contract volumes (in 10,000 mmbtu), purchased
(sold)........................................ (628) 134 2 (492) $2,898
Weighted average settlement price (per
mmbtu)...................................... $2.31 $2.33 $2.56
At December 31, 1998, the Company held futures contracts related to natural
gas purchase and sale commitments and storage inventory covering 66.8 Bcf of gas
on a net basis maturing through 2001 having a net unrealized gain of $16.4
million.
The following table presents natural gas price swap information for
agreements in which the Company is obligated to pay or receive a fixed price in
exchange for receiving or paying a variable price at a location, and those in
which the Company pays or receives an amount based on prices at different
locations. At December 31, 1999, the Company had not entered into any price swap
agreements extending beyond 2003. The weighted average variable pay and receive
forward prices are based upon quotes obtained from third party brokers and
dealers that are active in the respective markets.
PRICE SWAP AGREEMENTS EXPECTED MATURITY DATE
(QUANTITIES IN 10,000 MMBTU) -------------------------------------- FAIR VALUE
(RATES PER MMBTU) 2000 2001 2002 2003 TOTAL AT 12/31/99
- ---------------------------- ---- ---- ---- ---- ----- -----------
(In Thousands)
Pay Fixed, Receive Variable
Net notional quantities............. 7,894 4,181 12,075 $ (4,979)
Weighted average pay rate......... $1.11 $1.38
Weighted average receive rate..... $1.03 $1.42
Receive Fixed, Pay Variable
Net notional quantities............. 5,702 3,072 2,918 2,904 14,596 $(14,019)
Weighted average pay rate......... $1.41 $2.40 $2.49 $2.56
Weighted average receive rate..... $1.43 $2.22 $2.35 $2.38
At December 31, 1998, the Company had price swap agreements of varying
duration outstanding to exchange monthly payments on net notional quantities of
gas over the ensuing five years. Net notional quantities and related fair value
at that date for swap agreements in which the Company pays a fixed price in
exchange for a variable price totaled 166.1 Bcf and $(23.5) million,
respectively. For swap agreements in which the Company pays a variable price in
exchange for a fixed price, net notional quantities and related fair value at
December 31, 1998 totaled 125.2 Bcf and $13.4 million, respectively.
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Three-way collars used by the Company at December 31, 1999, are shown in
the table below. For these derivatives, if the market price falls below the
collar floor, then the price received will equal the market price plus the
differential.
THREE-WAY COLLARS
(QUANTITIES IN 10,000 EXPECTED MATURITY DATE
MMBTU) -------------------------------------------------------------- FAIR VALUE
(RATES PER MMBTU) 2000 2001 2002 2003 TOTAL AT 12/31/99
- --------------------- ---- ---- ---- ---- ----- -----------
(In Thousands)
Net notional
quantities........... 8,010 1,200 1,200 1,200 11,610
Weighted average
price.............. $2.41-$2.62 $2.45-$2.70 $2.49-$2.74 $2.54-$2.79
Average collar floor
price.............. 2.11 2.13 2.13 2.14
Average
differential....... .30 .32 .36 .40 $(2,248)
Realized gains (losses) incurred by the Company in connection with its
natural gas price risk management activities for the years ended December 31,
1999 and 1998 amounted to $(4.3) million and $10.0 million, respectively.
USE OF DERIVATIVES--CRUDE OIL
At December 31, 1999, the Company held futures contracts expiring in 2000
covering the sale of 720,000 barrels of oil with a weighted average settlement
price of $25.20 per barrel and an aggregate unrealized loss of $3.9 million. In
addition, the Company had two-way collars expiring in 2000 covering 4,690,000
barrels of oil with a weighted average ceiling price of $19.11 per barrel and an
average strike price of $16.11 per barrel ("floor price"). The fair value of the
collars was $(18.7) million at December 31, 1999. All derivatives held by the
Company at December 31, 1999 have been entered into to hedge the risk of market
price changes in connection with the production and/or sale of crude oil.
At December 31, 1998, the Company was not a party to price swap agreements,
futures or option contracts in connection with the production or sale of crude
oil.
Realized gains (losses) incurred by the Company related to its crude oil
price risk management activities for the years ended December 31, 1999 and 1998
amounted to $(18.9) million and $13.4 million, respectively.
FORWARD-LOOKING INFORMATION
Certain matters discussed in this Management's Discussion and Analysis of
Financial Condition and Results of Operations and elsewhere herein 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 proposed 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.
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SELECTED FINANCIAL DATA
SUMMARY OF FINANCIAL DATA (THOUSAND $) 1999 1998 1997 1996(A) 1995(A)
- -------------------------------------- ---- ---- ---- ------- -------
EARNINGS
Gas sales........................................ $ 2,005,143 $ 1,868,110 $ 2,284,384 $ 2,149,771 $ 1,837,159
Gas transportation, storage and other............ 1,069,207 892,296 892,726 805,687 666,416
Total operating revenues..................... 3,074,350 2,760,406 3,177,110 2,955,458 2,503,575
Purchased gas.................................... 911,652 900,401 1,114,080 963,217 864,591
Liquids, capacity and other products purchased... 279,929 145,277 210,575 179,307 87,434
Operation and maintenance........................ 773,607 708,378 757,220 757,321 719,273
Depreciation and amortization.................... 378,710 329,913 324,638 302,883 255,949
Impairment of gas and oil producing properties... -- -- 10,351 -- 226,209
Taxes, other than income taxes................... 197,432 179,299 193,584 190,683 190,716
Operating income before income taxes........... 533,020 497,138 566,662 562,047 159,403
Income taxes..................................... 73,581 129,649 156,269 162,315 7,381
Other income-net................................. 14,488 34,700 12,442 8,975 10,661
Merger expense................................... 212,750 -- -- -- --
Write-down of coal properties.................... -- -- -- -- 31,266
Interest charges................................. 124,417 114,478 103,927 99,325 102,584
Income from continuing operations................ 136,760 287,711 318,908 309,382 28,833
DISCONTINUED OPERATIONS (Note 3)
Loss from discontinued energy marketing services
operations, net of applicable tax benefit...... -- (17,238) (14,528) (11,109) (7,489)
Loss from disposal of energy marketing services
operations, including provision for operating
losses during the phase out period, net of
applicable tax benefit......................... -- (31,707) -- -- --
NET INCOME....................................... 136,760 238,766 304,380 298,273 21,344
EARNINGS PER COMMON SHARE--BASIC
Income from continuing operations................ $ 1.43 $ 3.03 $ 3.36 $ 3.29 $ .31
Loss from discontinued operations................ -- (.18) (.15) (.12) (.08)
Loss from disposal of discontinued operations.... -- (.33) -- -- --
Net Income....................................... $ 1.43 $ 2.52 $ 3.21 $ 3.17 $ .23
EARNINGS PER COMMON SHARE--DILUTED
Income from continuing operations................ $ 1.42 $ 3.00 $ 3.30 $ 3.24 $ .31
Loss from discontinued operations................ -- (.18) (.15) (.11) (.08)
Loss from disposal of discontinued operations.... -- (.33) -- -- --
NET INCOME....................................... $ 1.42 $ 2.49 $ 3.15 $ 3.13 $ .23
Return on average stockholders' equity........... 5.7% 10.0% 13.3% 14.0% 1.0%
Times fixed charges earned....................... 2.33 4.03 4.90 5.04 1.32
----------- ----------- ----------- ----------- -----------
DIVIDENDS--CASH
Paid per common share............................ $ 1.94 $ 1.94 $ 1.94 $ 1.94 $ 1.94
Payout ratio................................... 135.7% 77.0% 60.4% 61.2% 843.5%
Declared per common share........................ $ 1.94 $ 1.94 $ 1.94 $ 1.94 $ 1.94
----------- ----------- ----------- ----------- -----------
ASSETS
Total assets................................. $ 6,535,219 $ 6,361,900 $ 6,313,694 $ 6,000,605 $ 5,418,293
Property, plant and equipment
Total investment............................... 9,040,439 9,172,465 8,714,758 8,304,205 7,929,350
Accumulated depreciation....................... 4,813,178 4,734,001 4,491,955 4,226,905 4,016,945
Capital expenditures and acquisitions............ 636,530 762,916 609,373 560,293 439,393
----------- ----------- ----------- ----------- -----------
CAPITAL STRUCTURE
Total common stockholders' equity............ $ 2,376,310 $ 2,399,608 $ 2,358,318 $ 2,205,152 $ 2,045,818
Long-term debt................................... 1,763,678 1,379,729 1,552,890 1,426,315 1,291,811
----------- ----------- ----------- ----------- -----------
Total capitalization......................... $ 4,139,988 $ 3,779,337 $ 3,911,208 $ 3,631,467 $ 3,337,629
=========== =========== =========== =========== ===========
Long-term debt ratio............................. 42.6% 36.5% 39.7% 39.3% 38.7%
Shares outstanding at year-end................... 95,938,009 95,449,428 95,622,622 94,933,631 93,591,623
Common stockholders' equity per share............ $ 24.77 $ 25.14 $ 24.66 $ 23.23 $ 21.86
- ---------------
(a) Certain amounts and ratios are not comparable with other years due to
special charges.
18
21
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of
Consolidated Natural Gas Company
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of income and comprehensive income and of cash flows
present fairly, in all material respects, the financial position of Consolidated
Natural Gas Company and subsidiaries (collectively, the Company) at December 31,
1999 and 1998, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1999, in conformity with
accounting principles generally accepted in the United States. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States, which require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for the opinion expressed above.
PRICEWATERHOUSECOOPERS LLP
600 Grant Street
Pittsburgh, Pennsylvania 15219-9954
January 26, 2000
19
22
[This Page Intentionally Left Blank]
20
23
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
- --------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1999 1998 1997
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars)
OPERATING REVENUES
Regulated gas sales......................................... $1,397,200 $1,373,691 $1,851,001
Nonregulated gas sales...................................... 607,943 494,419 433,383
---------- ---------- ----------
Total gas sales......................................... 2,005,143 1,868,110 2,284,384
Gas transportation and storage.............................. 566,811 545,933 492,080
Other....................................................... 502,396 346,363 400,646
---------- ---------- ----------
Total operating revenues (Note 5)....................... 3,074,350 2,760,406 3,177,110
---------- ---------- ----------
OPERATING EXPENSES
Purchased gas............................................... 911,652 900,401 1,114,080
Liquids, capacity and other products purchased.............. 279,929 145,277 210,575
Operation expense (Note 7).................................. 670,048 618,010 666,612
Maintenance................................................. 103,559 90,368 90,608
Depreciation and amortization (Note 6)...................... 378,710 329,913 324,638
Impairment of gas and oil producing properties (Note 6)..... -- -- 10,351
Taxes, other than income taxes.............................. 197,432 179,299 193,584
---------- ---------- ----------
Subtotal................................................ 2,541,330 2,263,268 2,610,448
---------- ---------- ----------
Operating income before income taxes.................... 533,020 497,138 566,662
Income taxes (Note 9)....................................... 73,581 129,649 156,269
---------- ---------- ----------
Operating income........................................ 459,439 367,489 410,393
---------- ---------- ----------
OTHER INCOME (DEDUCTIONS)
Interest revenues........................................... 2,406 3,165 1,663
Merger expense (Note 2)..................................... (212,750) -- --
Other-net................................................... 12,082 31,535 10,779
---------- ---------- ----------
Total other income (deductions)......................... (198,262) 34,700 12,442
---------- ---------- ----------
Income before interest charges.......................... 261,177 402,189 422,835
---------- ---------- ----------
INTEREST CHARGES
Interest on long-term debt.................................. 108,252 106,307 104,927
Other interest expense...................................... 28,623 19,659 5,774
Allowance for funds used during construction................ (12,458) (11,488) (6,774)
---------- ---------- ----------
Total interest charges.................................. 124,417 114,478 103,927
---------- ---------- ----------
INCOME FROM CONTINUING OPERATIONS........................... 136,760 287,711 318,908
DISCONTINUED OPERATIONS (Note 3)
Loss from discontinued energy marketing services
operations, net of applicable tax benefit................. -- (17,238) (14,528)
Loss from disposal of energy marketing services operations,
including provision for operating losses during the phase
out period, net of applicable tax benefit................. -- (31,707) --
---------- ---------- ----------
NET INCOME.................................................. $ 136,760 $ 238,766 $ 304,380
========== ========== ==========
EARNINGS PER COMMON SHARE--BASIC
Income from continuing operations (Note 4)................ $ 1.43 $ 3.03 $ 3.36
Loss from discontinued operations......................... -- (.18) (.15)
Loss from disposal of discontinued operations............. -- (.33) --
---------- ---------- ----------
NET INCOME.................................................. $ 1.43 $ 2.52 $ 3.21
========== ========== ==========
EARNINGS PER COMMON SHARE--DILUTED
Income from continuing operations (Note 4)................ $ 1.42 $ 3.00 $ 3.30
Loss from discontinued operations......................... -- (.18) (.15)
Loss from disposal of discontinued operations............. -- (.33) --
---------- ---------- ----------
NET INCOME.................................................. $ 1.42 $ 2.49 $ 3.15
========== ========== ==========
- --------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.
21
24
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
- --------------------------------------------------------------------------------
AT DECEMBER 31, 1999 1998
- ----------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
PROPERTY, PLANT AND EQUIPMENT (Note 6)
Gas utility and other plant................................. $4,648,120 $5,091,793
Accumulated depreciation and amortization................... (1,959,475) (1,999,484)
---------- ----------
Net gas utility and other plant........................ 2,688,645 3,092,309
---------- ----------
Exploration and production properties....................... 4,392,319 4,080,672
Accumulated depreciation and amortization................... (2,853,703) (2,734,517)
---------- ----------
Net exploration and production properties.............. 1,538,616 1,346,155
---------- ----------
Net property, plant and equipment...................... 4,227,261 4,438,464
---------- ----------
CURRENT ASSETS
Cash and temporary cash investments......................... 93,891 135,453
Accounts receivable
Customers................................................. 349,818 363,503
Unbilled revenues and other............................... 198,324 221,833
Allowance for doubtful accounts........................... (21,240) (23,039)
Inventories, at cost
Gas stored--current portion (Note 10)..................... 86,312 120,665
Materials and supplies (average cost method).............. 20,336 27,940
Unrecovered gas costs (Note 5).............................. 38,074 34,860
Deferred income taxes--current (net) (Note 9)............... 674 21,786
Net assets held for sale (Note 2)........................... 371,508 --
Prepayments and other current assets........................ 299,914 258,899
---------- ----------
Total current assets................................... 1,437,611 1,161,900
---------- ----------
Regulatory and Other Assets
Other investments......................................... 353,795 302,307
Deferred charges and other assets (Notes 5,7,8,9 and 17).... 516,552 459,229
---------- ----------
Total regulatory and other assets...................... 870,347 761,536
---------- ----------
Total assets........................................... $6,535,219 $6,361,900
========== ==========
- --------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.
22
25
- --------------------------------------------------------------------------------
AT DECEMBER 31, 1999 1998
- ----------------------------------------------------------------------------------------
(Thousands of Dollars)
STOCKHOLDERS' EQUITY AND LIABILITIES
CAPITALIZATION
Common stockholders' equity (Note 11)
Common stock, par value $2.75 per share
Authorized--400,000,000 shares
Issued, 1999--95,948,452 shares; 1998--95,944,551
shares................................................ $ 263,858 $ 263,848
Capital in excess of par value............................ 567,382 571,972
Retained earnings (Note 13)............................... 1,545,664 1,591,543
Treasury stock, at cost (1999-10,443 shares; 1998-495,123
shares)................................................ (594) (26,359)
Unearned compensation..................................... -- (1,396)
---------- ----------
Total common stockholders' equity...................... 2,376,310 2,399,608
Long-term debt (Note 14).................................... 1,763,678 1,379,729
---------- ----------
Total capitalization................................... 4,139,988 3,779,337
---------- ----------
CURRENT LIABILITIES
Current maturities on long-term debt........................ -- 111,125
Commercial paper (Note 15).................................. 685,731 558,900
Accounts payable............................................ 334,956 423,695
Estimated rate contingencies and refunds (Note 5)........... 44,914 78,266
Amounts payable to customers (Note 5)....................... 3,955 48,339
Taxes accrued............................................... 134,257 122,788
Dividends declared.......................................... 46,530 46,277
Other current liabilities................................... 102,883 154,947
---------- ----------
Total current liabilities.............................. 1,353,226 1,544,337
---------- ----------
DEFERRED CREDITS
Deferred income taxes (Note 9).............................. 808,031 780,928
Accumulated deferred investment tax credits................. 19,524 24,475
Deferred credits and other liabilities (Notes 5, 8 and 9)... 214,450 232,823
---------- ----------
Total deferred credits................................. 1,042,005 1,038,226
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 18)
---------- ----------
Total stockholders' equity and liabilities............. $6,535,219 $6,361,900
========== ==========
- --------------------------------------------------------------------------------
23
26
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
- --------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1999 1998 1997
- --------------------------------------------------------------------------------------------
(Thousands of Dollars)
CASH FLOWS FROM OPERATING ACTIVITIES
Income from continuing operations........................... $136,760 $287,711 $318,908
Adjustments to reconcile income from continuing operations
to net cash provided by operating activities
Depreciation and amortization........................... 378,710 329,913 324,638
Impairment of gas and oil producing properties.......... -- -- 10,351
Pension cost (credit)-net............................... (71,823) (56,496) (46,011)
Stock award amortization................................ 1,525 7,460 8,209
Deferred income taxes-net............................... 47,038 17,901 4,186
Investment tax credit................................... (2,267) (2,171) (2,193)
Changes in current assets and current liabilities
Accounts receivable-net................................ (7,073) 4,244 (14,953)
Inventories........................................... 19,707 (2,584) 38,125
Unrecovered gas costs................................. (3,214) 20,202 52,954
Accounts payable...................................... (52,327) 92,795 (1,511)
Estimated rate contingencies and refunds.............. (31,275) 49,154 7,510
Amounts payable to customers.......................... (38,469) 47,459 880
Taxes accrued......................................... 9,189 (614) 23,834
Other-net............................................. (80,204) (40,282) 3,517
Net assets held for sale.............................. (2,910) -- --
Changes in other assets and other liabilities........... 64,817 14,716 55,750
Other-net............................................... 54 (2,015) (70)
-------- -------- --------
Net cash provided by continuing operations............ 368,238 767,393 784,124
Net cash provided by (or used in) discontinued operations... (56) 44,735 (42,016)
-------- -------- --------
Net cash provided by operating activities............. 368,182 812,128 742,108
-------- -------- --------
CASH FLOWS USED IN INVESTING ACTIVITIES
Plant construction and other property additions
Acquisition of exploration and production assets.......... (165,844) -- --
Other................................................... (444,081) (561,654) (514,705)
Proceeds from dispositions of property, plant and
equipment-net............................................. 7,491 (1,267) 1,056
Cost of other investments-net............................... (42,530) (104,233) (86,763)
-------- -------- --------
Net cash used in continuing operations................ (644,964) (667,154) (600,412)
Net cash provided by (or used in) discontinued operations... -- 35,605 (6,256)
-------- -------- --------
Net cash used in investing activities................. (644,964) (631,549) (606,668)
-------- -------- --------
CASH FLOWS PROVIDED BY (OR USED IN) FINANCING ACTIVITIES
Issuance of common stock.................................... 196 11,719 28,722
Issuance of long-term debt.................................. 396,680 196,888 294,945
Repayments of long-term debt................................ (125,375) (327,323) (119,625)
Commercial paper-net........................................ 125,858 318,159 (134,368)
Dividends paid.............................................. (185,606) (185,858) (184,608)
Purchase of treasury stock.................................. (12,205) (280,863) (12,286)
Sale of treasury stock...................................... 33,013 162,763 12,266
Other-net................................................... -- (2,987) 25
-------- -------- --------
Net cash provided by (or used in) financing
activities........................................... 232,561 (107,502) (114,929)
-------- -------- --------
Net increase (or decrease) in cash and temporary cash
investments.......................................... (44,221) 73,077 20,511
CASH AND TEMPORARY CASH INVESTMENTS AT JANUARY 1............ 138,112 65,035 44,524
-------- -------- --------
CASH AND TEMPORARY CASH INVESTMENTS AT DECEMBER 31.......... $ 93,891 $138,112 $ 65,035
======== ======== ========
Continuing operations....................................... $ 93,891 $135,453 $ 49,566
Discontinued operations..................................... -- 2,659 15,469
-------- -------- --------
Total cash and temporary cash investments at December
31..................................................... $ 93,891 $138,112 $ 65,035
======== ======== ========
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for
Interest (net of amounts capitalized)..................... $121,158 $121,924 $114,314
Income taxes (net of refunds)............................. $ 30,714 $ 92,380 $126,372
Non-cash investing activities
Investment in partnership................................. $ 1,795 $ -- $ --
Non-cash financing activities
Issuance of common stock under benefit plans.............. $ 257 $ (240) $ 2,742
Conversion of 7 1/4% Convertible Subordinated
Debentures.............................................. $ -- $ 88,467 $ 40
-------- -------- --------
- --------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.
24
27
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
- --------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1999 1998 1997
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars)
NET INCOME.................................................. $136,760 $238,766 $304,380
OTHER COMPREHENSIVE INCOME, NET OF TAX
Pension liability adjustment.............................. 350 60 (309)
Foreign currency translation adjustment................... 2,718 (1,112) (4,166)
-------- -------- --------
COMPREHENSIVE INCOME........................................ $139,828 $237,714 $299,905
======== ======== ========
- --------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.
25
28
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Methods of allocating costs to accounting periods by the subsidiaries
subject to federal or state accounting and rate regulation may differ from
methods generally applied by nonregulated companies. However, when the
accounting allocations prescribed by regulatory authorities are used for
ratemaking, the economic effects thereof determine the application of generally
accepted accounting principles. Significant accounting policies of Consolidated
Natural Gas Company (the Parent Company) and subsidiaries (collectively, the
Company) within this framework are summarized in this Note.
USE OF ESTIMATES
The consolidated financial statements reflect certain estimates and
assumptions made by management that affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities at the date of
the financial statements, and the reported amounts of revenues and expenses for
the periods presented.
PRINCIPLES OF CONSOLIDATION
The Parent Company owns all of the capital stock of its subsidiaries. The
consolidated financial statements represent the accounts of the Company after
the elimination of intercompany transactions.
The Company follows the equity method of accounting for investments in
partnerships and corporate joint ventures when the Company is able to influence
the financial and operating policies of the investee. For all other investments,
the cost method is applied.
SEGMENT INFORMATION
Segment information is presented in accordance with the provisions of SFAS
No. 131, "Disclosures about Segments of an Enterprise and Related Information."
SFAS No. 131 requires the internal organization used by management for making
operating decisions and assessing performance to be the basis of the Company's
reportable segments.
REVENUE RECOGNITION
Revenues from sales and transportation services are recognized in the same
period in which the related volumes are delivered to customers. The Company
bills and recognizes sales revenues from residential and certain commercial and
industrial customers on the basis of scheduled meter readings. In addition,
revenues are recorded for estimated deliveries of gas to these customers from
the meter reading date to the end of the accounting period. For wholesale and
other commercial and industrial customers, revenues are based upon actual
deliveries to the end of the period.
UNRECOVERED GAS COSTS
Where permitted by regulatory authorities, the Company defers the
difference between the cost of gas (including certain related costs) and the
amount of such costs included in current rates. The differences are accounted
for as either unrecovered gas costs or amounts payable to customers. Unrecovered
amounts are recognized as purchased gas costs in future periods when the costs
are recovered through adjusted rates.
PRICE RISK MANAGEMENT ACTIVITIES
In the normal course of business, the Company utilizes derivative financial
instruments and derivative commodity instruments to manage exposure to price
risk in connection with the production, purchase and sale of natural gas and
oil, and for stored gas inventories. These derivatives include exchange-traded
futures and options contracts, which permit settlement by physical delivery of
the commodity, and over-the-counter (OTC) commodity price swap agreements and
options, which require settlement in cash.
26
29
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
For derivatives that qualify (based on correlation to price movements of
gas and oil) and are designated as hedges, related gains or losses are deferred
and subsequently recognized in income, as revenues or expense, in the same
period the hedged transaction occurs.
Under the OTC price swap agreements, the Company makes payments to, or
receives payments from, counterparties generally based on the difference between
fixed and variable gas and oil prices or on prices at different receipt points
as specified in the contracts. Settlement takes place under the swap agreements
on a monthly basis for the portion of the swap that has expired, and amounts
received or paid are recognized as an adjustment to gas and oil sales revenues,
purchased gas expense or transport capacity costs in the applicable settlement
month.
Cash flows from price risk management activities are reported in the
Consolidated Statement of Cash Flows as an operating activity, which is
consistent with the classification of the cash flows from the underlying
physical transaction.
PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION
GAS UTILITY AND OTHER PLANT
The property, plant and equipment accounts are stated at the cost incurred
or, where required by regulatory authorities, "original cost." Additions and
betterments are charged to the property accounts at cost. Upon normal retirement
of a plant asset, its cost is charged to accumulated depreciation together with
costs of removal less salvage. Maintenance, repairs and related costs are
charged principally to expense as incurred.
EXPLORATION AND PRODUCTION PROPERTIES
The Company follows the full cost method of accounting for gas and oil
producing activities prescribed by the SEC. Under the full cost method, all
costs directly associated with property acquisition, exploration, and
development activities are capitalized, with the principal limitation that such
amounts not exceed the present value of estimated future net revenues to be
derived from the production of proved gas and oil reserves. If net capitalized
costs exceed the estimated value at the end of any quarterly period, then a
permanent write-down of the assets must be recognized in that period. The
limitation test is performed separately for each cost center, with cost centers
established on a country-by-country basis.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization are recorded over the estimated service lives
of plant assets by application of the straight-line method or, in the case of
gas and oil producing properties, the unit-of-production method.
Under the full cost method of accounting, amortization is also accrued on
estimated future costs to be incurred in developing proved gas and oil reserves,
and on estimated dismantlement and abandonment costs net of projected salvage
values. However, the costs of investments in unproved properties and major
development projects are excluded from amortization until it is determined
whether or not proved reserves are attributable to such properties.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The subsidiaries subject to cost-of-service rate regulation capitalize the
estimated costs of funds used during the construction of major projects. Under
regulatory practices, those companies are permitted to include the costs
capitalized in rate base for rate-making purposes when the completed facilities
are placed in service. The remaining subsidiaries capitalize interest costs as
part of the cost of acquiring certain assets. Generally, interest is capitalized
on unproved properties and major construction and development projects on which
amortization is not yet being recognized.
27
30
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In determining the allowance for funds used during construction, the
following ranges of rates reflect the pretax cost of borrowed funds used to
finance construction expenditures: 1999-5 1/4% to 7%; 1998-5 1/2% to 7 1/8% and
1997-5 5/8% to 7 5/8%. Equity funds capitalized in those years were not
significant.
INCOME TAXES
The current provision for income taxes represents amounts paid or currently
payable. Investment tax credits which were required to be deferred by regulatory
authorities are being amortized as credits to income over the estimated service
lives of the related properties.
PENSION AND OTHER BENEFIT PROGRAMS
The Company has qualified noncontributory defined benefit pension plans
covering substantially all employees. Benefits payable under the plans are based
primarily on each employee's years of service, age and base salary during the
five years prior to retirement. Net pension costs are determined by an
independent actuary, and the plans are funded on an annual basis to the extent
such funding is deductible under federal income tax regulations. Plan assets
consist primarily of equity securities, fixed income securities and insurance
contracts. The pension program also includes the payment of supplemental pension
benefits to certain retirees and the payment of benefits to certain retired
executives under company-sponsored nonqualified employee benefit plans. Certain
of these nonqualified plans are funded through contributions to a grantor trust.
The Company also sponsors defined benefit postretirement plans, covering
both salaried and hourly employees and certain dependents, that provide medical
and life insurance coverage benefits. These benefits are provided through
insurance companies and other providers with the annual cash outlays based on
the claim experience of the related plans. Employees who retire on or after
attaining age 55 and having rendered at least 15 years of service, or employees
retiring on or after attaining age 65, are eligible to receive benefits under
the plans. The plans are both contributory and noncontributory, depending on
age, retirement date, the plan elected by the employee, and whether the employee
is covered under a collective bargaining agreement. Most of the medical plans
contain cost-sharing features such as deductibles and coinsurance. For certain
of the contributory medical plans, retiree contributions and cost-sharing
features are adjusted annually.
ENVIRONMENTAL EXPENDITURES
Environmental-related expenditures associated with current operations are
generally expensed as incurred. Expenditures for the assessment and/or
remediation of environmental conditions related to past operations are charged
to expense or are deferred pending probable recovery in future rate-making
proceedings. In this connection, a liability is recognized when the assessment
or remediation effort is probable and the future costs are estimable. Estimated
future costs for the abandonment and restoration of gas and oil properties are
accrued currently through charges to depreciation.
Any related claims for recovery of environmental-related costs from
insurance carriers and other third parties or through regulatory procedures are
recognized separately as assets when future recovery is considered probable.
TEMPORARY CASH INVESTMENTS
Temporary cash investments consist of short-term, highly liquid investments
that are readily convertible to cash and present no significant interest rate
risk. For purposes of the Consolidated Statement of Cash Flows, temporary cash
investments are considered to be cash equivalents.
28
31
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
2. MERGER
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.
The Company announced on May 11, 1999 that, after careful consideration,
the Board of Directors had unanimously rejected an unsolicited merger proposal
from Columbia Energy Group. 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 will receive a combination of
DRI common stock and cash with a calculated 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 opinions of counsel on
the tax-free nature of the stock portion of the transaction.
On June 30, 1999, the shareholders of both the Company and DRI voted to
approve the merger of the two companies.
REGULATORY APPROVALS
During 1999, the Pennsylvania Public Utility Commission, the Public Service
Commission of West Virginia, the Virginia State Corporation Commission (VSCC)
and the North Carolina Utilities Commission each approved the Company's merger
with DRI. VSCC approval was based upon an agreement among the Company, DRI and
the VSCC staff to sell or spin off Virginia Natural Gas, a wholly-owned
subsidiary of the Company, within 12 months after the merger is completed and
was conditional upon a final review subsequent to SEC approval of the merger.
While not required for consummation of the merger, The Public Utilities
Commission of Ohio filed a statement with the SEC in support of the merger.
On November 5, 1999, the Federal Trade Commission accepted a proposed
consent agreement that would allow DRI to acquire the Company, provided DRI
divests Virginia Natural Gas to alleviate perceived anticompetitive effects that
would result from the merger.
The Federal Energy Regulatory Commission (FERC) voted on November 10, 1999,
to conditionally approve the pending merger. The companies filed a response with
the FERC accepting the conditions.
In its order dated December 15, 1999, the SEC approved the merger under the
Public Utility Holding Company Act of 1935 (PUHCA). DRI will become a registered
holding company under PUHCA at the time of the merger, and the Company will be
merged into a wholly-owned subsidiary of DRI (New CNG). The Company's
subsidiaries will become subsidiaries of New CNG, with New CNG becoming a
registered holding company under PUHCA.
On December 17, 1999, the Company and DRI announced an anticipated merger
closing date of January 28, 2000, conditional upon receiving final VSCC
approval. On December 21, 1999, the VSCC granted final approval of the merger,
representing the last regulatory approval required to enable consummation of the
merger. Accordingly, the net assets of Virginia Natural Gas totaling $371.5
million have been reclassified as held for sale in the Consolidated Balance
Sheet at December 31, 1999.
29
32
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
MERGER EXPENSES
Shareholder 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, the plan and/or award
agreements permitted the holder to elect, during the period July 1, 1999 through
August 29, 1999, to receive a cash payment in exchange for surrendering vested
stock options and awards. This provision covered outstanding vested stock
options granted since 1989 to approximately 700 employees. The amount to be paid
to the holders was based on the value determined per the associated plans, which
considered the option exercise price, award value, and the change of control
price as defined in the plans. Based on the value of the vested options and
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.
During 1999, the Company also recorded charges to Other Income (Deductions)
for other merger costs, including direct incremental costs (including fees of
financial advisors, legal counsel and other costs) and costs related to certain
executive employment agreements. These charges totaled $59.2 million and $39.7
million for the twelve months and three months ended December 31, 1999, and
reduced net income by $.51 per share and $.32 per share, respectively. The
Company expects to incur additional incremental costs, including costs
associated with contractual termination benefits, of approximately $36.0 million
at the date of consummation of the merger.
3. DISCONTINUED OPERATIONS
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.
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 and
electricity business was substantially complete at December 31, 1998. The
remaining net liabilities associated with discontinued operations at December
31, 1999 and 1998 were not material.
The results of operations of these activities for the years ended December
31, 1998 and 1997 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
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:
YEARS ENDED DECEMBER 31, 1998 1997
------------------------ ---- ----
(In Thousands)
Total operating revenues.......................... $792,586 $2,532,910
Operating expenses................................ (818,105) (2,554,386)
-------- ----------
Operating loss before income taxes.............. (25,519) (21,476)
Income tax benefit................................ 9,011 9,216
Other income...................................... 80 1,074
Interest charges.................................. (810) (3,342)
-------- ----------
Loss from discontinued operations................. $(17,238) $ (14,528)
======== ==========
Loss from disposal before income taxes............ $(48,263) $ --
Income tax benefit................................ 16,556 --
-------- ----------
Net loss from disposal............................ $(31,707) $ --
======== ==========
30
33
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
4. EARNINGS PER SHARE
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 each of the years ended December 31, 1999, 1998 and 1997 follows
(income and share amounts in thousands):
INCOME FROM
CONTINUING PER SHARE
OPERATIONS SHARES AMOUNT
---------- ------ ------
For the year ended December 31, 1999
BASIC EPS................................................... $136,760 95,752 $1.43
======== ======= =====
Effect of dilutive securities:
Exercise of stock options................................. 286
Vesting of performance awards............................. 221
-------- ------- -----
DILUTED EPS................................................. $136,760 96,259 $1.42
======== ======= =====
For the year ended December 31, 1998
BASIC EPS................................................... $287,711 94,836 $3.03
======== ======= =====
Effect of dilutive securities:
Exercise of stock options................................. 511
Vesting of performance shares............................. 374
Conversion of 7 1/4% Convertible Subordinated
Debentures............................................. 1,578 614
-------- ------- -----
DILUTED EPS................................................. $289,289 96,335 $3.00
======== ======= =====
For the year ended December 31, 1997
BASIC EPS................................................... $318,908 94,868 $3.36
======== ======= =====
Effect of dilutive securities:
Exercise of stock options................................. 674
Vesting of performance shares............................. 359
Conversion of 7 1/4% Convertible Subordinated
Debentures............................................. 12,128 4,559
-------- ------- -----
DILUTED EPS................................................. $331,036 100,460 $3.30
======== ======= =====
Performance awards were granted in 1999 and no shares were issued or
outstanding during 1999. Such awards were included in the calculation of diluted
EPS. Performance shares in 1997 and 1998 were considered contingent shares and,
although issued and outstanding, were excluded from the calculation of basic
EPS.
5. RATE MATTERS
The Company accounts for its regulated operations in accordance with SFAS
No. 71, "Accounting for the Effects of Certain Types of Regulation." When the
accounting allocations prescribed by regulatory authorities are
31
34
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
used for ratemaking, the allocation of costs among accounting periods by the
Company's regulated subsidiaries resulted in the recognition of regulatory
assets and liabilities at December 31, 1999 and 1998 as follows:
DECEMBER 31, 1999 1998
- ------------ ---- ----
(In Thousands)
Regulatory assets:
Unrecovered gas costs (Note 1)................... $ 38,074 $ 34,860
Workforce reduction costs (Note 7)............... 8,359 9,275
Other postretirement benefits (Note 8)........... 43,294 52,142
Deferred income taxes (Note 9)................... 114,452 102,797
Environmental-related expenditures (Note 17)..... 5,156 7,291
Other............................................ 9,351 18,103
-------- --------
Total regulatory assets....................... $218,686 $224,468
======== ========
Regulatory liabilities:
Amounts payable to customers (Note 1)............ $ 3,955 $ 48,339
Estimated rate contingencies and refunds......... 44,914 78,266
Income taxes refundable to customers-net (Note
9)............................................ 22,399 27,170
-------- --------
Total regulatory liabilities.................. $ 71,268 $153,775
======== ========
The Company assesses on an ongoing basis the recoverability of costs
recognized as regulatory assets and its ability to continue to apply SFAS No. 71
to its regulated operations. In the event that all or a portion of these
operations cease to meet the requirements of SFAS No. 71, the Company would be
required to assess the carrying value of certain assets and liabilities
previously subject to regulation.
ESTIMATED RATE CONTINGENCIES AND REFUNDS
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 $38.7 million and $59.9 million at
December 31, 1999 and 1998, including interest. These amounts are reported in
the Consolidated Balance Sheet under "Estimated rate contingencies and refunds"
together with $6.2 million and $18.4 million, respectively, which are primarily
refunds received from suppliers and refundable to customers under regulatory
procedures.
6. PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION
IMPAIRMENT OF GAS AND OIL PRODUCING PROPERTIES
As described in Note 1, the Company follows the full cost method of
accounting for gas and oil producing activities. Under these rules, the Company
recognized an impairment of its Canadian oil producing properties at December
31, 1997, due primarily to the decline in market prices for heavy oil
production. This non-cash charge amounted to $10.4 million and reduced 1997 net
income by $6.7 million, or $.07 per share.
DEPRECIATION AND AMORTIZATION
Amortization of capitalized costs under the full cost method of accounting
for the Company's exploration and production operations amounted to $.93 per Mcf
equivalent of gas and oil produced in 1999, $.89 in 1998 and $.88 in 1997.
32
35
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Costs of unproved properties capitalized under the full cost method of
accounting that are excluded from amortization at December 31, 1999, and the
years in which such excluded costs were incurred, follow:
INCURRED IN YEARS ENDED DECEMBER 31,
DECEMBER 31, ------------------------------------
1999 1999 1998 1997 PRIOR
---- ---- ---- ---- -----
(In Thousands)
Property acquisition costs............... $ 61,194 $23,740 $14,815 $21,364 $1,275
Exploration costs........................ 66,863 37,348 15,425 11,570 2,520
Capitalized interest..................... 11,912 1,769 3,248 6,040 855
-------- ------- ------- ------- ------
Total............................... $139,969 $62,857 $33,488 $38,974 $4,650
======== ======= ======= ======= ======
There are no significant properties, as defined by the SEC, excluded from
amortization at December 31, 1999. As gas and oil reserves are proved through
drilling or as properties are judged to be impaired, excluded costs and any
related reserves are transferred on an ongoing, well-by-well basis into the
amortization calculation.
7. WORKFORCE REDUCTION COSTS
During the fourth quarter of 1998, the Company recorded a provision for
severance and other employee-related costs in connection with programs to
improve efficiencies and reorganize business processes at both its corporate and
regulated subsidiaries. Certain severance benefits were enhanced under these
programs and such programs were completed during 1999. During 1999, a total of
241 employees were separated from the Company in conjunction with these
workforce reduction programs.
As a result of its workforce reduction programs, the Company recorded
charges in 1999 and 1998 amounting to $11.4 million and $9.4 million,
respectively. These charges reduced 1999 and 1998 net income by $7.4 million, or
$.08 per share, and $6.1 million, or $.06 per share, respectively. In addition,
certain of the regulated subsidiaries have deferred, as a regulatory asset, a
portion of workforce reduction costs from previous years' programs pending
recovery in rates. The balance of these deferrals was $8.4 million at December
31, 1999.
33
36
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
8. PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS
The following tables provide reconciliations of the changes in the
Company's pension and other postretirement benefit plan obligations and asset
fair values for each of the years ended December 31, 1999 and 1998, and a
statement of the funded status as of December 31, 1999 and 1998:
OTHER
PENSION POSTRETIREMENT
BENEFIT PLANS BENEFIT PLANS
------------------------ ---------------------
YEARS ENDED DECEMBER 31, 1999 1998 1999 1998
- ------------------------ ---- ---- ---- ----
(In Thousands)
CHANGE IN BENEFIT OBLIGATION:
Benefit obligation--January 1.................. $ 1,123,684 $1,037,728 $ 362,073 $ 358,748
Service cost................................... 28,741 24,852 9,702 10,021
Interest cost.................................. 70,934 69,320 20,471 23,714
Participant contributions...................... -- -- 3,178 3,027
Plan amendments................................ -- -- (127) (569)
Actuarial (gain) loss.......................... (185,451) 60,981 (75,029) (11,331)
Curtailment (gain)............................. -- (1,658) -- (130)
Benefit payments............................... (67,814) (67,539) (23,551) (21,407)
----------- ---------- --------- ---------
Benefit obligation--December 31................ $ 970,094 $1,123,684 $ 296,717 $ 362,073
=========== ========== ========= =========
CHANGE IN PLAN ASSETS:
Fair value of plan assets--January 1........... $ 2,069,152 $1,804,852 $ 111,893 $ 79,740
Actual return on plan assets................... 322,052 328,928 1,653 5,207
Employer contributions......................... 2,767 2,911 34,979 45,326
Participant contributions...................... -- -- 3,178 3,027
Benefit payments............................... (67,814) (67,539) (23,551) (21,407)
----------- ---------- --------- ---------
Fair value of plan assets-December 31.......... $ 2,326,157 $2,069,152 $ 128,152 $ 111,893
=========== ========== ========= =========
DECEMBER 31,
FUNDED STATUS:
Funded status--December 31..................... $ 1,356,063 $ 945,468 $(168,564) $(250,180)
Unrecognized net obligation (asset)............ (25,172) (33,195) 146,811 158,231
Unrecognized (gain) loss-net................... (1,119,162) (774,732) (58,083) 11,711
Unrecognized prior service cost................ 4,191 4,755 (5,180) (5,562)
----------- ---------- --------- ---------
Net amount recognized.......................... $ 215,920 $ 142,296 $ (85,016) $ (85,800)
=========== ========== ========= =========
Amounts recognized in the Consolidated Balance
Sheet at December 31 consist of the
following:
Prepaid benefit cost........................... $ 234,800 $ 159,317 $ -- $ --
Accrued benefit liability...................... (27,557) (28,536) (85,016) (85,800)
Intangible asset............................... 6,707 9,006 -- --
Accumulated other comprehensive income......... 1,970 2,509 -- --
----------- ---------- --------- ---------
Net amount recognized.......................... $ 215,920 $ 142,296 $ (85,016) $ (85,800)
=========== ========== ========= =========
The Company has nonqualified pension and supplemental pension plans which
do not have "plan assets" as defined by generally accepted accounting
principles. The total projected benefit obligation for these plans was $30.4
million and $33.3 million at December 31, 1999 and 1998, respectively, and is
included in the table above. The minimum liability recognized relating to these
plans was $8.7 million and $11.5 million at December 31, 1999 and 1998. The
related intangible asset recognized as of those dates amounted to $6.7 million
and $9.0 million, respectively. Adjustments of the minimum liability and
intangible asset due to changes in
34
37
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
assumptions or the financial status of these plans resulted in a credit (charge)
to other comprehensive income of $.3 million, $.1 million and $(.3) million for
the years ended December 31, 1999, 1998 and 1997, respectively.
The majority of estimated other postretirement benefit costs (SFAS No. 106
costs) and related transition obligation is attributable to the rate-regulated
subsidiaries. Pending the expected recovery of SFAS No. 106 costs and related
deferrals in regulatory proceedings, these subsidiaries have deferred the
differences between SFAS No. 106 costs and amounts included in rates. The
rate-regulated subsidiaries have obtained approval for recovery in rates from
their respective regulatory commissions for the increased level of expense
resulting from SFAS No. 106. The amount of SFAS No. 106 costs deferred at
December 31, 1999 and 1998, was $43.3 million and $52.1 million, respectively.
The FERC and certain state regulatory authorities have indicated that when
SFAS No. 106 costs are recovered in rates, amounts collected must be deposited
in irrevocable trust funds dedicated for the sole purpose of paying
postretirement benefits. Accordingly, four subsidiaries fund postretirement
benefit costs via voluntary employees' beneficiary associations (VEBAs). The
remaining subsidiaries do not prefund postretirement benefit costs, but rather
pay claims as presented. Assets held by the VEBAs consist primarily of
short-term fixed income securities.
Weighted average assumptions used in the determination of the benefit
obligations include the following:
OTHER
PENSION POSTRETIREMENT
BENEFIT PLANS BENEFIT PLANS
-------------- --------------
DECEMBER 31, 1999 1998 1999 1998
- ------------ ---- ---- ---- ----
Discount rate................................ 7.5% 6.5% 7.5% 6.5%
Expected return on plan assets............... 9.0% 9.0% 6.5% 6.5%
Rate of compensation increase
Non-union.................................. 5.0% 5.5% 5.0% 5.5%
Union...................................... 4.0% 5.5% 4.0% 5.5%
Net periodic benefit costs, as determined by independent actuaries,
included the following components:
OTHER POSTRETIREMENT
PENSION BENEFIT PLANS BENEFIT PLANS
--------------------------------- ---------------------------
YEARS ENDED DECEMBER 31, 1999 1998 1997 1999 1998 1997
- ------------------------ ---- ---- ---- ---- ---- ----
(In Thousands)
Service cost..................... $ 28,741 $ 24,852 $ 21,374 $ 9,702 $10,021 $ 9,901
Interest cost.................... 70,934 69,320 68,635 20,471 23,714 25,854
Expected return on assets........ (150,822) (131,640) (118,671) (6,255) (4,413) (2,859)
Prior service cost
amortization................... 564 965 1,125 (383) (406) (408)
Actuarial (gain) loss............ (14,018) (11,315) (10,402) (591) 206 271
Transition obligation
amortization................... (8,022) (7,042) (7,929) 11,293 11,302 11,418
Curtailment and special
termination benefits........... -- (1,658) -- -- (215) --
Special voluntary retirement
programs....................... 800 800 800 -- -- --
--------- --------- --------- ------- ------- -------
Net periodic benefit cost
(credit)....................... $ (71,823) $ (55,718) $ (45,068) $34,237 $40,209 $44,177
========= ========= ========= ======= ======= =======
For measurement purposes, a 5.0% annual rate of increase in the per capita
cost of covered health care benefits was assumed for 1999. The rate was assumed
to decrease to 4.75% for 2000 and remain at that level thereafter.
35
38
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Assumed health care cost trend rates have a significant effect on the
amounts reported for the postretirement health care plans. A 1% change in the
assumed health care cost trend rate would have the following effects on 1999
service and interest cost and the accumulated postretirement benefit obligation
at December 31, 1999:
1% INCREASE 1% DECREASE
----------- -----------
(In Thousands)
Effect on aggregate service and interest cost components of
net periodic cost........................................... $ 3,560 $ (2,953)
Effect on the health care component of the accumulated
postretirement benefit obligation......................... $25,897 $(22,043)
9. INCOME TAXES
"Income taxes" in the Consolidated Statement of Income include the
following:
YEARS ENDED DECEMBER 31, 1999 1998 1997
------------------------ ---- ---- ----
(In Thousands)
Income tax expense attributable to continuing operations:
Current provision
Federal................................................ $23,046 $ 96,295 $136,095
State.................................................. 5,764 17,624 18,181
Deferred income taxes-net
Federal................................................ 44,115 21,390 4,175
State.................................................. 2,923 (3,489) 11
Investment tax credit..................................... (2,267) (2,171) (2,193)
------- -------- --------
Income tax expense attributable to continuing operations.... 73,581 129,649 156,269
Income tax benefit attributable to discontinued
operations................................................ -- (25,567) (9,216)
------- -------- --------
Total.................................................. $73,581 $104,082 $147,053
======= ======== ========
Income taxes differed from the amounts shown in the next table that were
computed by applying the statutory federal income tax rate of 35% to reported
pretax income from continuing operations. The reasons for the differences
follow:
YEARS ENDED DECEMBER 31, 1999 1998 1997
------------------------ ---- ---- ----
(In Thousands)
Income before taxes--continuing operations................. $210,341 $417,360 $475,177
======== ======== ========
Computed "expected" tax expense--continuing operations..... $ 73,619 $146,076 $166,312
Increases (or reductions) in tax resulting from:
Production tax credit.................................... (10,576) (11,351) (10,359)
Investment tax credit.................................... (2,267) (2,171) (2,193)
State income taxes....................................... 5,646 9,188 11,825
CNG International equity earnings........................ 3,777 -- --
Miscellaneous............................................ 3,382 (12,093) (9,316)
-------- -------- --------
Income taxes attributable to continuing operations......... $ 73,581 $129,649 $156,269
======== ======== ========
Effective tax rate....................................... 35.0% 31.1% 32.9%
The current and noncurrent deferred income taxes reported in the
Consolidated Balance Sheet at December 31, 1999 and 1998 represent the net
expected future tax consequences attributable to temporary
36
39
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
differences between the carrying amounts of nontax assets and liabilities and
their tax bases. These temporary differences and the related tax effect were as
follows:
1999 1998
------------------------------ ------------------------------
DEFERRED DEFERRED INCOME DEFERRED DEFERRED INCOME
DECEMBER 31, INCOME TAXES TAXES-CURRENT INCOME TAXES TAXES-CURRENT
- ------------ ------------ ------------- ------------ -------------
(In Thousands)
Deferred tax liabilities:
Excess of tax over book depreciation..... $554,754 $ -- $559,430 $ --
Exploration and intangible well drilling
costs.................................. 243,186 -- 244,832 --
Unrecovered gas costs.................... -- 11,570 -- 15,908
Net pension credits...................... 88,147 -- 78,212 --
CNG International equity earnings........ 8,874 -- -- --
Other.................................... 7,054 -- 36,145 --
-------- ------- -------- --------
Total liabilities...................... 902,015 11,570 918,619 15,908
-------- ------- -------- --------
Deferred tax assets:
Tax basis step-up in connection with
acquisition of subsidiary.............. -- -- 18,096 --
Deferred investment tax credits.......... 11,642 -- 14,443 --
Overheads capitalized for tax purposes... 10,520 -- 11,138 --
Supplier and other refunds............... -- 12,244 -- 18,503
AMT carryforward......................... 13,843 -- -- --
Other.................................... 57,979 -- 94,014 19,191
Valuation allowance...................... -- -- -- --
-------- ------- -------- --------
Total assets........................... 93,984 12,244 137,691 37,694
-------- ------- -------- --------
Total deferred tax liability (asset)... $808,031 $ (674) $780,928 $(21,786)
======== ======= ======== ========
Prior to the fourth quarter of 1999, a deferred tax liability was not
recognized in connection with the unremitted earnings arising from the
investments of CNG International given the Company's intention to permanently
reinvest such earnings. However, the Company has provided a deferred tax
liability amounting to $8.9 million at December 31, 1999, as it has now begun
exploring the sale of CNG International.
A regulatory liability amounting to $22.4 million has been recorded at
December 31, 1999 representing the reduction to previously recorded deferred
income taxes associated with rate-regulated activities that are expected to be
refundable to customers, net of certain taxes collectible from customers. Also,
a regulatory asset corresponding to the recognition of additional deferred
income taxes not previously recorded because of past rate-making practices
amounting to $114.5 million has been recorded at December 31, 1999.
10. GAS STORED
The distribution subsidiaries, except Virginia Natural Gas, value their
stored gas inventory under the LIFO method. Based upon the average price of gas
purchased during 1999, the current cost of replacing the inventory of "Gas
stored--current portion" exceeded the amount stated on a LIFO basis by
approximately $168.7 million at December 31, 1999. Virginia Natural Gas and CNG
Retail value their stored gas inventory under the weighted average cost method.
A portion of gas in underground storage used as a pressure base and for
operational balancing is included in "Property, Plant and Equipment" in the
amount of $126.4 million at December 31, 1999 and 1998.
37
40
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
11. COMMON STOCKHOLDERS' EQUITY
A summary of the changes in stockholders' equity follows:
COMMON STOCK CAPITAL IN EXCESS
ISSUED OF PAR VALUE TREASURY STOCK
-------------------- ----------------------------- ------------------
NUMBER
NUMBER VALUE RETAINED UNEARNED OF
OF SHARES AT PAR PAID-IN OTHER TOTAL EARNINGS COMPENSATION SHARES COST
--------- ------ ------- ----- ----- -------- ------------ ------ ----
(In Thousands)
Balance at December 31,
1996...................... 94,934 $261,068 $496,722 $40,280 $537,002 $1,424,624 $(17,542) -- $ --
Net income................ -- -- -- -- -- 304,380 -- -- --
Cash dividends declared
Common stock ($1.94 per
share)................ -- -- -- -- -- (184,942) -- -- --
Common stock issued
Stock options........... 612 1,683 23,615 -- 23,615 -- -- -- --
DRP*.................... 62 171 3,244 -- 3,244 -- -- -- --
Stock awards-net........ 25 69 1,318 -- 1,318 -- (1,350) -- --
Conversion of
debentures............ 1 2 38 -- 38 -- -- -- --
Performance
shares-net............ (11) (29) (106) -- (106) -- 135 -- --
Amortization and
adjustment............ -- -- 1,490 -- 1,490 -- 7,807 -- --
Purchase of treasury
stock................... -- -- -- -- -- -- -- (220) (12,286)
Sale of treasury stock and
other................... -- -- 154 -- 154 -- -- 219 12,248
Pension liability
adjustment (Note 8)..... -- -- -- -- -- (309) -- -- --
Foreign currency
translation
adjustment.............. -- -- -- -- -- (4,166) -- -- --
------ -------- -------- ------- -------- ---------- -------- ------ ---------
Balance at December 31,
1997.................... 95,623 262,964 526,475 40,280 566,755 1,539,587 (10,950) (1) (38)
Net income................ -- -- -- -- -- 238,766 -- -- --
Cash dividends declared
Common stock ($1.94 per
share)................ -- -- -- -- -- (185,758) -- -- --
Common stock issued
Stock options........... 282 777 11,548 -- 11,548 -- -- -- --
Stock awards-net........ 32 86 1,364 -- 1,364 -- (1,283) -- --
Performance
shares-net............ 8 21 402 -- 402 -- (423) -- --
Amortization and
adjustment............ -- -- (2,393) -- (2,393) -- 11,321 -- --
Purchase of treasury
stock................... -- -- -- -- -- -- -- (5,081) (280,326)
Sale of treasury stock and
other................... -- -- (3,863) -- (3,863) -- (61) 2,949 163,290
Conversion of
debentures.............. -- -- (1,841) -- (1,841) -- -- 1,638 90,715
Pension liability
adjustment (Note 8)..... -- -- -- -- -- 60 -- -- --
Foreign currency
translation
adjustment.............. -- -- -- -- -- (1,112) -- -- --
------ -------- -------- ------- -------- ---------- -------- ------ ---------
Balance at December 31,
1998.................... 95,945 263,848 531,692 40,280 571,972 1,591,543 (1,396) (495) (26,359)
Net income................ -- -- -- -- -- 136,760 -- -- --
Cash dividends declared
Common stock ($1.94 per
share)................ -- -- -- -- -- (185,859) -- -- --
Common stock issued
Stock options........... 4 11 185 -- 185 -- -- -- --
Stock awards-net........ (1) (1) (12) -- (12) -- 20 -- --
Amortization............ -- -- -- -- -- -- 1,438 -- --
Purchase of treasury
stock................... -- -- -- -- -- -- -- (225) (12,205)
Sale of treasury stock.... -- -- (4,763) -- (4,763) -- (62) 710 37,970
Other..................... -- -- -- -- -- 152 -- -- --
Pension liability
adjustment (Note 8)..... -- -- -- -- -- 350 -- -- --
Foreign currency
translation
adjustment.............. -- -- -- -- -- 2,718 -- -- --
------ -------- -------- ------- -------- ---------- -------- ------ ---------
Balance at December 31,
1999.................... 95,948 $263,858 $527,102 $40,280 $567,382 $1,545,664 $ -- (10) $ (594)
====== ======== ======== ======= ======== ========== ======== ====== =========
- ---------------
* Dividend Reinvestment Plan.
UNISSUED SHARES
At December 31, 1999, 304,051,548 shares of common stock were unissued.
Shares have been registered with the SEC for possible issuance under various
benefit plans or to shareholders under the Dividend Reinvestment Plan. Shares
acquired pursuant to these plans can consist of original issue shares, treasury
shares or shares purchased in the open market.
38
41
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
TREASURY STOCK
Under a plan approved by the Board of Directors, the Company can purchase
in the open market up to 10,000,000 shares of its common stock. The Company may
also acquire shares of its common stock through certain provisions of the
Company's various stock incentive plans. Shares repurchased or acquired are held
as treasury stock and are available for reissuance for general corporate
purposes or in connection with various employee benefit plans. When treasury
shares are reissued, the difference between the market value at reissuance and
the cost of shares is reflected in "Capital in excess of par value." At December
31, 1999 and 1998, a total of 10,443 and 495,123 shares, respectively, were
being held as treasury stock. As of January 28, 2000, the anticipated closing
date of the Company's merger with DRI, any remaining outstanding treasury stock
of the Company will be retired.
1997 STOCK INCENTIVE PLAN
The 1997 Stock Incentive Plan (1997 Plan) provided for the granting of
stock awards, stock options and other stock-based awards to employees and
directors of the Company effective January 1, 1997, including grants made on or
after that date pursuant to the Long-Term Strategic Incentive Program described
below. The maximum number of shares authorized for issuance in each calendar
year was determined in accordance with a formula contained in the 1997 Plan. As
of January 28, 2000, no further grants will be made under the 1997 Plan or the
Long-Term Strategic Incentive Program due to the Company's pending merger with
DRI.
Stock awards granted under the plan may have been in the form of restricted
stock or deferred stock. Shares issued as restricted stock awards were held by
the Company until the attached restrictions lapse. Deferred stock awards
generally consisted of a right to receive shares at the end of specified
deferral periods. The market value of the stock award on the date granted was
recorded as compensation expense over the applicable restriction or deferral
period.
Stock options granted under the plan allowed the purchase of common shares
at a price not less than fair market value at the date of grant and not less
than par value. These options, other than tri-annual options granted under the
Long-Term Strategic Incentive Program, generally were exercisable in four equal
annual installments commencing with the second anniversary of the grant and
expired after 10 years from the date of grant.
The granting of stock awards constituted a non-cash financing activity of
the Company.
LONG-TERM STRATEGIC INCENTIVE PROGRAM
Grants under the Long-Term Strategic Incentive Program consisted of
performance restricted stock awards (performance shares or performance stock
credits) and stock options. Grants were made under this program in January 1996
and January 1999.
Performance shares vested contingent upon attainment of certain strategic
business results over a three-year period. The market value of the performance
shares on the grant date, as adjusted quarterly for changes in the current
market price of the Company's common stock, was recorded as compensation expense
over the three-year vesting period.
Stock options granted under this program (tri-annual options) vested after
three years and would be exercisable from the vesting date until ten years from
the grant date if certain strategic business results were attained during the
vesting period. However, the exercise period would be reduced to one day for all
or a portion of the options granted if such results were not achieved. As the
number of options were known and the option price equaled the market price at
the grant date, no compensation expense was recognized for these options under
generally accepted accounting principles.
There were no grants outstanding under this program at December 31, 1999.
39
42
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
ACCOUNTING FOR STOCK AWARDS AND STOCK OPTIONS
As permitted by generally accepted accounting principles, the Company
follows Accounting Principles Board Opinion No. 25 and related interpretations
(APB No. 25) for accounting for stock-based compensation. The Company granted
stock awards, including performance shares, totaling 459,000 shares in 1999,
54,000 shares in 1998, and 98,000 shares in 1997 with weighted average market
prices per share on award dates of $53.91, $49.54 and $52.53, respectively. The
Company recorded compensation expense of $159.1 million for the year ended
December 31, 1999 in connection with its performance shares, restricted stock
and other stock compensation awards, and stock options that were surrendered and
cashed out in connection with shareholder approval of the Company's pending
merger with DRI (see Note 2, page 29). The Company recorded compensation expense
of $9.4 million and $9.7 million for the years ended December 31, 1998 and 1997,
respectively, in connection with its performance shares, restricted stock and
other stock compensation awards.
In accordance with APB No. 25, no compensation expense has been recognized
for the Company's stock options, other than for those surrendered and cashed out
during 1999 in connection with shareholder approval of the Company's merger with
DRI.
A summary of stock option activity for the years ended December 31, 1997
through 1999, follows:
WEIGHTED AVERAGE
NUMBER OPTION PRICE
OF SHARES PER SHARE
--------- ----------------
(In Thousands)
Shares under option:
At January 1, 1997............................. 5,517 $43.90
Granted (1).................................... 885 $54.09
Exercised...................................... (612) $41.33
Cancelled (1).................................. (583) $45.74
------ ------
At December 31, 1997........................... 5,207 $45.73
Granted (2).................................... 914 $58.34
Exercised...................................... (309) $41.73
Cancelled (2).................................. (307) $51.32
------ ------
At December 31, 1998........................... 5,505 $47.73
Granted (3).................................... 3,800 $53.79
Exercised...................................... (700) $46.55
Cancelled (3).................................. (2,266) $53.51
Surrendered.................................... (6,337) $49.44
------ ------
At December 31, 1999........................... 2 $55.47
====== ======
- ---------------
(1) Includes 332,084 tri-annual options granted and 367,883 tri-annual options
cancelled.
(2) Includes 106,750 tri-annual options granted and 96,114 tri-annual options
cancelled.
(3) Includes 3,002,917 tri-annual options granted and 1,968,211 tri-annual
options cancelled.
Options were exercisable for the purchase of 2,000 shares, 734,741 shares
and 599,534 shares at December 31, 1999, 1998 and 1997, respectively.
40
43
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FAIR VALUE DISCLOSURES
The following table presents the weighted-average fair value of stock
options granted during 1997 and 1998 and the weighted-average assumptions used
to compute fair values under the Black-Scholes option-pricing model:
YEARS ENDED DECEMBER 31, 1998 1997
- ------------------------ ---- ----
Option fair value....................................... $10.49 $8.96
Assumptions
Dividend yield.......................................... 3.3% 3.6%
Expected volatility................................... 19.8% 16.8%
Risk-free interest rate............................... 5.7% 6.4%
Expected option life (years).......................... 4.8 4.8
If compensation expense for the Company's stock options granted during 1997
and 1998 had been determined based on the fair value at the grant dates for such
awards, the effect on the Company's net income and EPS for each of those years
would have been as follows:
YEARS ENDED DECEMBER 31, 1998 1997
- ------------------------ ---- ----
NET INCOME (In Millions):
As reported.......................................... $238.8 $304.4
Pro forma............................................ $231.7 $298.8
BASIC EPS:
As reported.......................................... $ 2.52 $ 3.21
Pro forma............................................ $ 2.44 $ 3.15
DILUTED EPS:
As reported.......................................... $ 2.49 $ 3.15
Pro forma............................................ $ 2.42 $ 3.10
Reference is made to Note 2, page 29, regarding the surrender and cash out
of stock options between July 1, 1999 and August 29, 1999 in connection with
shareholder approval of the Company's pending merger with DRI.
12. PREFERRED STOCK
The Company's authorized preferred stock consists of 5,000,000 shares at a
par value of $100 each. There were no shares of preferred stock issued or
outstanding at December 31, 1999 or 1998.
13. DIVIDEND RESTRICTIONS
One of the Company's indentures relating to senior debenture issues
contains restrictions on dividend payments by the Company and acquisitions of
its capital stock. Under the indenture provisions, $432.0 million of
consolidated retained earnings was free from such restrictions at December 31,
1999. The indenture also imposes dividend limitations on the subsidiaries, but
at December 31, 1999, these limitations did not restrict their ability to pay
dividends to the Company.
41
44
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
14. LONG-TERM DEBT
Long-term debt, excluding current maturities, follows:
DECEMBER 31, 1999 1998
- ------------ ---- ----
(In Thousands)
Notes 7 1/4%, Due October 1, 2004................. $ 400,000 $ --
Debentures
6%, Due October 15, 2010........................ 200,000 200,000
6.8%, Due December 15, 2027..................... 300,000 300,000
6 5/8%, Due December 1, 2008.................... 150,000 150,000
6 7/8%, Due October 15, 2026.................... 150,000 150,000
7 3/8%, Due April 1, 2005....................... 150,000 150,000
6 5/8%, Due December 1, 2013.................... 150,000 150,000
5 3/4%, Due August 1, 2003...................... 150,000 150,000
8 3/4%, Due October 1, 2019..................... 128,625 142,875
Unamortized debt discount, less premium......... (14,947) (13,146)
---------- ----------
Total........................................ $1,763,678 $1,379,729
========== ==========
Discounts and premiums and the expenses incurred in connection with the
issuance of debentures are being amortized on a basis which will equitably
distribute the amount to "Interest on long-term debt" over the life of each
debenture issue.
There is no long-term debt maturing in the years 2000 and 2001. The
aggregate principal amounts of the Company's long-term debt maturing in the
years 2002 through 2004 are: $7.1 million; $157.1 million and $407.1 million.
In March 1998, CNG International purchased a 33.3% ownership interest in
the Dampier-to-Bunbury Natural Gas Pipeline (DBNGP) in Western Australia from
the Western Australia Government. One of CNG International's partners in the
purchase was El Paso Energy Corporation (El Paso), which also holds a 33.3%
ownership interest. In connection with their investments in DBNGP, CNG
International and El Paso formed DBNGP Finance Company LLC (DBNGP Finance).
DBNGP Finance is owned 50% by CNG International and 50% by EPED Holding Company,
a wholly-owned subsidiary of El Paso. Subsequent to the formation of DBNGP
Finance, the equity ownership interests of CNG International and El Paso in
DBNGP were transferred to this entity.
In October 1998, DBNGP Finance borrowed $250.0 million under a Senior Term
Loan Facility (Term Loan). The Term Loan matures October 2, 2001, can be
extended in one-year increments to October 2, 2003, and bears interest at a
variable rate. Of the gross proceeds received by DBNGP Finance under the Term
Loan, $100.0 million was distributed to CNG International. In connection with
the Term Loan, CNG International entered into an Equity Contribution Agreement
with DBNGP Finance. CNG International is contractually obligated to make equity
contributions to DBNGP Finance equal to the Term Loan proceeds distributed to
CNG International, plus interest on such proceeds, in the event that DBNGP
Finance is unable to service this debt. The Company is contractually obligated
to cause CNG International to make such equity contributions. Reference is made
to Note 19 to the consolidated financial statements, page 46, regarding the
potential sale of CNG International.
15. SHORT-TERM BORROWINGS
The weighted average interest rate on the Company's commercial paper notes
outstanding at December 31, 1999 and 1998, was 6.45% and 5.22%, respectively.
The Company has a $1.0 billion credit agreement with a group of banks.
Borrowings under this agreement are in the form of revolving credits and may, at
the option of the Company, be structured either as syndicated
42
45
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
loans by a group of participating banks or money market loans by individual
banks. The loans may be borrowed, paid or repaid and reborrowed on a few days
notice. Varying interest rate options are available for syndicated loans, while
the interest rate on money market loans is determined from quotes rendered by
the participating banks. This agreement may be used for general corporate
purposes, including the support of commercial paper notes. This agreement is
currently scheduled to expire on June 22, 2000; however, the Company expects
that the agreement will be renewed or replaced by a comparable agreement. A
facility fee is charged under this agreement but is not considered significant.
There were no borrowings outstanding under this agreement at December 31, 1999.
16. FINANCIAL INSTRUMENTS
FAIR VALUES
The estimated fair value of the Company's long-term debt, including current
maturities, was as follows at December 31, 1999 and 1998:
1999 1998
----------------------- -----------------------
CARRYING FAIR CARRYING FAIR
DECEMBER 31, AMOUNT VALUE AMOUNT VALUE
- ------------ ------ ----- ------ -----
(In Thousands)
Long-term debt................................ $1,778,625 $1,664,090 $1,504,000 $1,584,633
The fair values were estimated based upon closing transactions and/or
quotations for the Company's debentures as of those dates. Temporary cash
investments and commercial paper notes are stated at amounts which approximate
fair value due to the short maturities of those financial instruments.
DERIVATIVES AND PRICE RISK MANAGEMENT ACTIVITIES
The Company's price risk management activities include exchange-traded
futures and options contracts, which can be settled through the purchase or
delivery of commodities, and OTC price swap agreements and options, which
require settlement in cash. These instruments are used to manage commodity price
risk regarding the production, purchase and sale of natural gas and oil and for
stored gas inventories.
FUTURES AND OPTIONS CONTRACTS
At December 31, 1999, the Company had natural gas futures contracts related
to gas purchase and sale commitments and gas storage inventory covering 4.9 Bcf
of gas on a net basis maturing through 2002. Also, at December 31, 1999, the
Company had futures contracts in connection with its crude oil production
covering 720,000 barrels of oil on a net basis maturing in 2000. The Company's
net unrealized loss related to futures contracts was approximately $1.0 million
at December 31, 1999.
Also at December 31, 1999, the Company utilized options contracts
("collars"), including three-way collars covering 116.1 Bcf of gas on a net
basis maturing through 2003, and two-way collars covering 4,690,000 barrels of
oil expiring in 2000. The Company's net unrealized loss related to its use of
options contracts was approximately $21.0 million at December 31, 1999.
As these futures and options contracts qualify and have been designated as
hedges, any gains or losses resulting from market price changes are expected to
be generally offset by the related physical transaction.
SWAP AGREEMENTS
In addition to futures and options contracts, the Company enters into OTC
price swap agreements to manage its exposure to commodity price risk under
existing sales commitments. At December 31, 1999, the Company had swap
agreements of varying duration outstanding with several counterparties to
exchange monthly payments on net notional quantities of gas over the ensuing
four years. Net notional quantities at December 31, 1999 related to
43
46
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
those swap agreements in which the Company pays a fixed price in exchange for a
variable price totaled 120.8 Bcf, while net notional quantities related to
agreements in which the Company pays a variable price in exchange for a fixed
price totaled 146.0 Bcf. Net notional quantities or amounts do not represent the
quantities or amounts exchanged by the parties and, thus, are not a measure of
the exposure of the Company through its use of derivatives. The amounts
exchanged are calculated on the basis of monthly notional quantities and other
terms of the agreements. The Company's net unrealized loss related to swap
agreements was approximately $19.0 million at December 31, 1999. Profits
expected on anticipated sales related to the hedged transactions should
generally offset the estimated unrealized losses on the swap agreements.
MARKET AND CREDIT RISK
Price risk management activities expose the Company to market risk. Market
risk represents the potential loss that can be caused by the change in market
value of a particular commitment. The Company has appropriate operating
procedures in place that are administered by experienced management to help
ensure that proper internal controls are maintained. In addition, the Company
has established an independent function at the Corporate level to monitor
compliance with the price risk management policies of all subsidiaries.
Price risk management activities also expose the Company to credit risk.
Credit risk represents the potential loss that the Company would incur as a
result of nonperformance by counterparties pursuant to the terms of their
contractual obligations. The Company maintains credit policies with respect to
its counterparties that management believes minimize overall credit risk. Such
policies include the evaluation of a prospective counterparty's financial
condition, collateral requirements where deemed necessary, and the use of
standardized agreements which facilitate the netting of cash flows associated
with a single counterparty. The Company also monitors the financial condition of
existing counterparties on an ongoing basis. Considering the system of internal
controls in place and credit reserve levels at December 31, 1999, the Company
believes it unlikely that a material adverse effect on its financial position,
results of operations or cash flows would occur as a result of counterparty
nonperformance.
17. ENVIRONMENTAL MATTERS
The Company is subject to various federal, state and local laws and
regulations relating to the protection of the environment. These laws and
regulations govern both current and future operations and potentially extend to
plant sites formerly owned or operated by the subsidiaries, or their
predecessors.
The Company has taken a proactive position with respect to environmental
concerns. As part of normal business operations, subsidiaries periodically
monitor their properties and facilities to identify and resolve potential
environmental matters, and the Company conducts general environmental audits on
a continuing basis at its operating facilities to monitor compliance with
environmental laws and regulations. As part of this process, voluntary surveys
at subsidiary sites have been conducted to determine the extent of any possible
soil contamination and when contamination has been discovered remediation
efforts are undertaken. Further, on August 16, 1990, CNG Transmission entered
into a Consent Order and Agreement with the Commonwealth of Pennsylvania
Department of Environmental Protection (DEP) in which CNG Transmission has
agreed with the DEP's determination of certain violations of the Pennsylvania
Solid Waste Management Act, the Pennsylvania Clean Streams Law and the rules and
regulations promulgated thereunder. No civil penalties have been assessed.
Pursuant to the Order and Agreement, CNG Transmission continues to perform
sampling, testing and analysis, and conducts a program of remediation at some of
its Pennsylvania facilities. Total remediation costs in connection with these
sites and the Order and Agreement are not expected to be material with respect
to the Company's financial position, results of operations or cash flows. The
Company has recognized an estimated liability amounting to $6.7 million at
December 31, 1999, for future costs expected to be incurred to remediate or
mitigate hazardous substances at these sites and at facilities covered by the
Order and Agreement.
Inasmuch as certain environmental-related expenditures are expected to be
recoverable in future regulatory proceedings, a regulatory asset has been
recognized amounting to $5.2 million at December 31, 1999. Also,
44
47
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
uncontested claims amounting to $.8 million at December 31, 1999, were
recognized for environmental-related costs probable for recovery through
joint-interest operating agreements.
The total amounts included in operating expenses for remediation and other
environmental-related costs, and the components of such costs, are as follows:
YEARS ENDED DECEMBER 31, 1999 1998 1997
- ------------------------ ---- ---- ----
(In Thousands)
Recurring costs for ongoing operations........... $2,691 $2,595 $3,430
Remediation and other compliance costs........... 1,301 3,549 1,701
Other............................................ 549 195 14
------ ------ ------
Total....................................... $4,541 $6,339 $5,145
====== ====== ======
CNG Transmission and certain of the distribution subsidiaries are subject
to the Federal Clean Air Act (Clean Air Act) and the Federal Clean Air Act
Amendments of 1990 (1990 amendments) which added significantly to the existing
Clean Air Act requirements. As a result of the 1990 amendments, these
subsidiaries were required to install Reasonably Available Control Technology at
some compressor stations to reduce nitrogen oxide emissions and to acquire Title
V permits for major facilities. Progress is on schedule for these permits, with
no major expenditures anticipated.
The 1990 amendments will also require installation of Maximum Available
Control Technology (MACT) to control the emissions of certain hazardous air
pollutants from compressor engines. The Company cannot estimate what its
expenditures for MACT-related controls will be. However, the mandated controls
will not affect a large number of its compressor engines and the related costs
are not expected to be material.
Additionally, the Company may be required, under an Environmental
Protection Agency nitrogen oxide state implementation program call, to include
additional compressor engines in the control mandates for the 1990 Amendments.
The estimated costs of such federal and/or state imposed hardware additions are
not expected to be material.
The total capital expenditures required to comply with the 1990 amendments
are expected to be recoverable through future regulatory proceedings.
The Company has determined that it is associated with 16 former
manufactured gas plant sites, four of which are currently owned by subsidiaries.
Studies conducted by other utilities at their former manufactured gas plants
have indicated that their sites contain coal tar and other potentially harmful
materials. None of the 16 former sites with which the Company is associated is
under investigation by any state or federal environmental agency, and no
investigation or action is currently anticipated. At this time it is not known
if, or to what degree, these sites may contain environmental contamination.
Therefore, the Company is not able to estimate the cost, if any, that may be
required for the possible remediation of these sites.
The DEP has proposed a penalty of $380,000 related to a hydrocarbon spill
in February 1998 at a CNG Transmission facility in Aliquippa, Beaver County,
Pennsylvania. CNG Transmission will settle the matter by contributing $280,000
to a Supplemental Environmental Program (SEP) and $100,000 directly to the DEP.
Under the SEP, several environmental programs will be undertaken which will
benefit the Conservation District of Beaver County, Pennsylvania.
Estimates of liability in the environmental area are based on current
environmental laws and existing technology. The exact nature of environmental
issues which the Company may encounter in the future cannot be predicted.
Additional environmental liabilities may result in the future as more stringent
environmental laws and regulations are implemented and as the Company obtains
more specific information about its existing sites and production facilities. At
present, no estimate of any such additional liability, or range of liability
amounts, can be made. However, the amount of any such liabilities could be
material.
45
48
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
18. COMMITMENTS AND CONTINGENCIES
Lease arrangements of the Company are principally for office space,
business machines and transportation equipment. None of these arrangements,
individually or in the aggregate, are material capital leases. Rental expense
incurred in the years 1997 through 1999 was not material, and future rental
payments required under leases in effect at December 31, 1999, are not material.
It is estimated that the Company's 2000 capital spending program will
amount to $621.6 million, and that approximately $445.5 million of that amount
will be directed to gas and oil producing activities. In connection with the
capital spending program, the Company has entered into certain contractual
commitments.
The Company has claims and suits arising in the ordinary course of business
pending against it, but, in the opinion of management and counsel, the ultimate
liability will not have a material effect on its financial position, results of
operations or cash flows.
19. SEGMENT INFORMATION
The Company is organized primarily on the basis of products and services
sold in the United States.
The operations of the four retail gas distribution subsidiaries have been
aggregated into the "Distribution" segment. These subsidiaries sell gas and/or
provide transportation services to residential, commercial and industrial
customers in Ohio, Pennsylvania, Virginia and West Virginia, and are subject to
price regulation by their respective state utility commissions. Reference is
made to Note 2, page 29, regarding the requirement to sell or spin off Virginia
Natural Gas in connection with its merger with DRI.
Transmission operations include the activities of CNG Transmission, an
interstate pipeline company regulated by the FERC which provides gas
transportation, storage and related services to affiliates and to utilities and
end users in the Midwest, the Mid-Atlantic states and the Northeast. CNG
Transmission also holds a 16% general partnership interest in the Iroquois Gas
Transmission System, L.P., a limited partnership that owns and operates an
interstate natural gas pipeline that transports Canadian gas to utility and
power generation customers in New York and New England. Transmission operations
also include the by-products business of CNG Power.
Exploration and production includes the results of CNG Producing and the
gas and oil production activities of CNG Transmission. These operations are
located throughout the United States and in the Gulf of Mexico. CNG Producing
also owns a working interest in a heavy oil program in Alberta, Canada.
The activities of CNG International, CNG Field Services, CNG Retail, CNG
Products and Services Company (CNG Products and Services), CNG Power,
Consolidated LNG, CNG Research Company and CNG Coal are included in the "Other"
category.
CNG International engages in energy-related activities outside of the
United States and holds equity investments in Australia and Latin America.
During the fourth quarter of 1999, the Company decided to focus on the United
States oil and gas markets and, accordingly, has now begun exploring the sale of
CNG International.
CNG Retail was established in 1997 to pursue opportunities arising from the
deregulation of the energy industry at the retail level. CNG Products and
Services provides certain energy-related services to customers of the Company's
distribution subsidiaries and others.
The accounting policies of the segments are the same as those described in
the "Summary of Significant Accounting Policies." Transactions between
affiliates are recognized at prices which approximate market value. Significant
transactions between the operating components are eliminated to reconcile the
segment information to consolidated amounts.
46
49
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following table presents segment information pertaining to the
Company's operations:
EXPLORATION CORPORATE
AND AND
DISTRIBUTION* TRANSMISSION PRODUCTION OTHER ELIMINATIONS TOTAL
------------- ------------ ---------- ----- ------------ -----
(In Thousands)
1999
Operating revenues
Nonaffiliated
Regulated gas sales........... $1,397,200 $ -- $ -- $ -- $ -- $1,397,200
Nonregulated gas sales........ -- -- 396,974 210,969 -- 607,943
Gas transportation and
storage..................... 209,155 357,019 462 175 -- 566,811
Liquid sales.................. -- -- 334,298 -- -- 334,298
Other......................... 28,275 49,991 61,685 28,147 -- 168,098
---------- ---------- ---------- -------- --------- ----------
Total nonaffiliated......... 1,634,630 407,010 793,419 239,291 -- 3,074,350
Affiliated...................... 5,514 119,743 59,734 22,547 (207,538) --
---------- ---------- ---------- -------- --------- ----------
Total operating revenues.... 1,640,144 526,753 853,153 261,838 (207,538) 3,074,350
Operating expenses
Purchased gas................. 825,543 15,550 50,050 216,965 (196,456) 911,652
Liquids, capacity and other
products purchased............ -- 65,155 206,569 10,438 (2,233) 279,929
Operation expense............... 332,595 123,992 198,281 29,852 (14,672) 670,048
Maintenance..................... 56,021 28,876 17,467 381 814 103,559
Depreciation and amortization... 79,682 55,516 235,936 1,741 5,835 378,710
Taxes, other than income
taxes......................... 142,869 35,737 9,820 1,295 7,711 197,432
---------- ---------- ---------- -------- --------- ----------
Operating income before
income taxes.............. 203,434 201,927 135,030 1,166 (8,537) 533,020
---------- ---------- ---------- -------- --------- ----------
Income taxes.................... 48,054 70,034 29,000 5,943 (79,450) 73,581
Interest revenues............... -- 2,841 1,027 1,294 (2,756) 2,406
Equity in earnings of equity
investees..................... -- 5,876 5,817 11,335 -- 23,028
Merger expense.................. -- -- -- -- 212,750 212,750
Other revenues-net.............. (5,834) (578) 181 (4,456) (259) (10,946)
Interest charges................ 48,249 23,917 30,464 2,848 18,939 124,417
---------- ---------- ---------- -------- --------- ----------
Income from continuing
operations.................... $ 101,297 $ 116,115 $ 82,591 $ 548 $(163,791) $ 136,760
========== ========== ========== ======== ========= ==========
Other significant non-cash
items:
Pension cost (credit)-net..... $ (54,256) $ (20,380) $ 1,700 $ 587 $ 526 $ (71,823)
Stock award amortization...... $ 19 $ 12 $ 1,134 $ 10 $ 350 $ 1,525
---------- ---------- ---------- -------- --------- ----------
Investment in equity
investees..................... $ -- $ 38,498 $ 50,810 $260,080 $ -- $ 349,388
Total assets................ $2,874,009 $1,460,434 $1,767,106 $375,406 $ 58,264 $6,535,219
Capital expenditures............ $ 110,793 $ 48,865 $ 434,575 $ 38,369 $ 3,928 $ 636,530
---------- ---------- ---------- -------- --------- ----------
* Includes income from continuing operations of $13.8 million attributable
to Virginia Natural Gas.
47
50
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
EXPLORATION CORPORATE
AND AND
DISTRIBUTION TRANSMISSION PRODUCTION OTHER ELIMINATIONS TOTAL
------------ ------------ ---------- ----- ------------ -----
(In Thousands)
1998
Operating revenues
Nonaffiliated
Regulated gas sales........... $1,372,568 $ -- $ -- $ 1,123 $ -- $1,373,691
Nonregulated gas sales........ -- -- 369,736 124,683 -- 494,419
Gas transportation and
storage..................... 197,888 347,600 436 9 -- 545,933
Liquid sales.................. -- -- 204,030 -- -- 204,030
Other......................... 35,498 54,887 34,042 12,899 5,007 142,333
---------- ---------- ---------- -------- --------- ----------
Total nonaffiliated......... 1,605,954 402,487 608,244 138,714 5,007 2,760,406
Affiliated...................... 5,855 100,060 22,860 23,684 (152,459) --
---------- ---------- ---------- -------- --------- ----------
Total operating revenues.... 1,611,809 502,547 631,104 162,398 (147,452) 2,760,406
Operating expenses
Purchased gas................. 835,222 46,559 39,972 125,223 (146,575) 900,401
Liquids, capacity and other
products purchased............ -- 24,662 115,397 5,218 -- 145,277
Operation expense............... 311,154 128,701 156,024 25,406 (3,275) 618,010
Maintenance..................... 50,579 28,011 9,823 245 1,710 90,368
Depreciation and amortization... 75,064 57,343 185,902 6,769 4,835 329,913
Taxes, other than income
taxes......................... 131,575 33,684 7,344 916 5,780 179,299
---------- ---------- ---------- -------- --------- ----------
Operating income before
income taxes.............. 208,215 183,587 116,642 (1,379) (9,927) 497,138
---------- ---------- ---------- -------- --------- ----------
Income taxes.................... 58,314 60,708 23,117 (300) (12,190) 129,649
Interest revenues............... 703 4,394 1,118 2,379 (5,429) 3,165
Equity in earnings of equity
investees..................... -- 8,667 4,791 11,917 -- 25,375
Other revenues-net.............. 6,678 1,122 250 1,699 (3,589) 6,160
Interest charges................ 46,847 25,098 21,650 8,249 12,634 114,478
---------- ---------- ---------- -------- --------- ----------
Income from continuing
operations.................... $ 110,435 $ 111,964 $ 78,034 $ 6,667 $ (19,389) $ 287,711
========== ========== ========== ======== ========= ==========
Other significant non-cash
items:
Pension cost (credit)-net..... $ (42,529) $ (15,801) $ 1,423 $ 213 $ 198 $ (56,496)
Stock award amortization...... $ 1,039 $ 634 $ 1,708 $ 322 $ 3,757 $ 7,460
---------- ---------- ---------- -------- --------- ----------
Investment in equity
investees..................... $ -- $ 36,785 $ 47,834 $210,608 $ -- $ 295,227
Total assets................ $2,946,758 $1,553,518 $1,523,936 $350,258 $ (12,570) $6,361,900
Capital expenditures............ $ 146,563 $ 56,748 $ 352,781 $193,118 $ 11,903 $ 761,113
---------- ---------- ---------- -------- --------- ----------
48
51
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
EXPLORATION CORPORATE
AND AND
DISTRIBUTION TRANSMISSION PRODUCTION OTHER ELIMINATIONS TOTAL
------------ ------------ ---------- ----- ------------ -----
(In Thousands)
1997
Operating revenues
Nonaffiliated
Regulated gas sales........... $1,844,221 $ -- $ -- $ 6,780 $ -- $1,851,001
Nonregulated gas sales........ -- -- 396,282 37,101 -- 433,383
Gas transportation and
storage..................... 153,904 337,475 701 -- -- 492,080
Liquid sales.................. -- -- 275,902 -- -- 275,902
Other......................... 24,577 60,639 27,287 5,787 6,454 124,744
---------- ---------- ---------- -------- --------- ----------
Total nonaffiliated......... 2,022,702 398,114 700,172 49,668 6,454 3,177,110
Affiliated...................... 3,859 101,179 5,508 12,962 (123,508) --
---------- ---------- ---------- -------- --------- ----------
Total operating revenues.... 2,026,561 499,293 705,680 62,630 (117,054) 3,177,110
Operating expenses
Purchased gas................. 1,158,721 8,592 31,535 34,817 (119,585) 1,114,080
Liquids, capacity and other
products purchased............ -- 53,203 157,101 271 -- 210,575
Operation expense............... 324,150 133,681 166,990 34,056 7,735 666,612
Maintenance..................... 50,533 28,426 9,604 47 1,998 90,608
Depreciation and amortization... 77,389 62,258 181,356 406 3,229 324,638
Impairment of gas and oil
producing properties.......... -- -- 10,351 -- -- 10,351
Taxes, other than income
taxes......................... 149,198 32,263 5,917 347 5,859 193,584
---------- ---------- ---------- -------- --------- ----------
Operating income before
income taxes.............. 266,570 180,870 142,826 (7,314) (16,290) 566,662
---------- ---------- ---------- -------- --------- ----------
Income taxes.................... 74,699 64,512 31,686 (2,940) (11,688) 156,269
Interest revenues............... 1,172 2,011 1,330 2,322 (5,172) 1,663
Equity in earnings of equity
investees..................... -- 8,929 3,275 5,462 -- 17,666
Other revenues-net.............. (2,152) (86) 217 (6,996) 2,130 (6,887)
Interest charges................ 48,419 24,051 22,372 1,983 7,102 103,927
---------- ---------- ---------- -------- --------- ----------
Income from continuing
operations.................... $ 142,472 $ 103,161 $ 93,590 $ (5,569) $ (14,746) $ 318,908
========== ========== ========== ======== ========= ==========
Other significant non-cash
items:
Impairment of gas and oil
producing properties........ $ -- $ -- $ 10,351 $ -- $ -- $ 10,351
Pension cost (credit)-net..... $ (33,335) $ (12,819) $ 1,257 $ 81 $ (1,195) $ (46,011)
Stock award amortization...... $ 1,201 $ 836 $ 1,847 $ 279 $ 4,046 $ 8,209
---------- ---------- ---------- -------- --------- ----------
Investment in equity
investees..................... $ -- $ 34,518 $ 38,558 $143,122 $ -- $ 216,198
Total assets................ $2,879,312 $1,501,640 $1,360,068 $827,497 $(254,823) $6,313,694
Capital expenditures............ $ 147,213 $ 49,300 $ 299,897 $ 95,801 $ 10,906 $ 603,117
---------- ---------- ---------- -------- --------- ----------
20. SUPPLEMENTARY FINANCIAL INFORMATION--UNAUDITED
(A) Gas and Oil Producing Activities (Excluding Cost-of-service
Rate-Regulated Activities)
The following disclosures exclude the Company's gas producing activities
subject to cost-of-service rate regulation. Certain disclosures about these
activities are included under "Cost-of-Service Properties" in this Note (A).
49
52
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
CAPITALIZED COSTS
The aggregate amounts of costs capitalized by subsidiaries for their gas
and oil producing activities, and related aggregate amounts of accumulated
depreciation and amortization, follow:
DECEMBER 31, 1999 1998
------------ ---- ----
(In Thousands)
Capitalized costs of
Proved properties......................................... $3,735,130 $3,594,042
Unproved properties....................................... 479,869 389,977
---------- ----------
Subtotal............................................... 4,214,999 3,984,019
---------- ----------
Accumulated depreciation of
Proved properties......................................... 2,556,099 2,542,026
Unproved properties....................................... 181,981 160,222
---------- ----------
Subtotal............................................... 2,738,080 2,702,248
---------- ----------
Net capitalized costs.................................. $1,476,919 $1,281,771
========== ==========
TOTAL COSTS INCURRED
The following costs were incurred by subsidiaries in their gas and oil
producing activities during the years 1997 through 1999:
YEARS ENDED DECEMBER 31, 1999 1998 1997
------------------------ ---- ---- ----
(In Thousands)
Property acquisition costs
Proved properties........................................ $171,011 $ 20,597 $ 14,142
Unproved properties...................................... 33,029 29,512 43,951
-------- -------- --------
Subtotal.............................................. 204,040 50,109 58,093
Exploration costs.......................................... 112,725 115,429 101,891
Development costs.......................................... 95,436 176,220 118,746
-------- -------- --------
Total................................................. $412,201 $341,758 $278,730
======== ======== ========
RESULTS OF OPERATIONS
The Company cautions that the following standardized disclosures required
by the FASB do not represent the results of operations based on its historical
financial statements. In addition to requiring different determinations of
revenues and costs, the disclosures exclude the impact of interest expense and
corporate overheads.
YEARS ENDED DECEMBER 31, 1999 1998 1997
------------------------ ---- ---- ----
(In Thousands)
Revenues (net of royalties) from:
Sales to nonaffiliated companies......................... $381,723 $357,729 $403,233
Transfers to other operations............................ 52,237 24,785 7,973
-------- -------- --------
Total................................................. 433,960 382,514 411,206
-------- -------- --------
Less:Production (lifting) costs............................ 80,959 62,937 65,286
Depreciation and amortization......................... 224,280 176,587 172,046
Impairment of producing properties.................... -- -- 10,351
Income tax expense.................................... 37,554 40,977 48,987
-------- -------- --------
Results of operations................................. $ 91,167 $102,013 $114,536
======== ======== ========
50
53
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
COMPANY-OWNED RESERVES (NON-COST-OF-SERVICE RESERVES)
Estimated net quantities of proved gas and oil (including condensate)
reserves in the United States and Canada at December 31, 1997 through 1999, and
changes in the reserves during those years, are shown in the two schedules which
follow:
YEARS ENDED DECEMBER 31, 1999 1998 1997
------------------------ ---- ---- ----
(In Bcf)
PROVED DEVELOPED AND UNDEVELOPED RESERVES*--GAS
At January 1.............................................. 1,313 1,141 1,040
Changes in reserves
Extensions, discoveries and other additions............ 132 214 210
Revisions of previous estimates........................ (80) 70 31
Production............................................. (182) (155) (155)
Purchases of gas in place**............................ 278 43 29
Sales of gas in place.................................. (12) -- (14)
----- ----- -----
At December 31............................................ 1,449 1,313 1,141
===== ===== =====
PROVED DEVELOPED RESERVES*--GAS
At January 1.............................................. 1,052 925 900
At December 31............................................ 1,139 1,052 925
- ---------------
* Net before royalty.
** Amount for 1998 includes 39 Bcf of reserves transferred by sale to CNG
Producing from an affiliate, Peoples Natural Gas.
The preceding proved developed and undeveloped gas reserves at December 31,
1999, 1998 and 1997, include United States reserves of 1,448, 1,312 and 1,140
Bcf which, together with the Canadian reserves and the gas reserves reported
under "Cost-of-Service Properties," are as contained in reports of Ralph E.
Davis Associates, Inc., independent geologists.
YEARS ENDED DECEMBER 31, 1999 1998 1997
------------------------ ---- ---- ----
(In Thousand Bbls)
PROVED DEVELOPED AND UNDEVELOPED RESERVES*--OIL
At January 1.............................................. 57,074 50,627 50,457
Changes in reserves
Extensions, discoveries and other additions............ 7,185 11,275 4,582
Revisions of previous estimates........................ 6,164 2,960 1,741
Production............................................. (10,316) (7,895) (7,312)
Purchases of oil in place.............................. 1,096 107 1,182
Sales of oil in place.................................. (1,416) -- (23)
------- ------ ------
At December 31............................................ 59,787 57,074 50,627
======= ====== ======
PROVED DEVELOPED RESERVES*--OIL
At January 1.............................................. 42,750 37,568 24,989
At December 31............................................ 47,303 42,750 37,568
------- ------ ------
- ---------------
* Net before royalty.
The foregoing proved developed and undeveloped oil reserves at December 31,
1999, 1998 and 1997 include United States reserves of 51,649, 51,230 and 44,160
thousand barrels, respectively. These, together with the Canadian reserves, are
as contained in reports of Ralph E. Davis Associates, Inc.
51
54
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN
The following tabulation has been prepared in accordance with the FASB's
rules for disclosure of a standardized measure of discounted future net cash
flows relating to Company-owned proved gas and oil reserve quantities.
DECEMBER 31, 1999 1998 1997
------------ ---- ---- ----
(In Thousands)
Future cash inflows...................................... $3,995,475 $2,562,741 $3,197,532
Less: Future development and production costs............ 906,676 756,352 658,281
Future income tax expense......................... 934,217 482,585 766,233
---------- ---------- ----------
Future net cash flows.................................... 2,154,582 1,323,804 1,773,018
Less annual discount (10% a year)........................ 801,494 435,540 606,509
---------- ---------- ----------
Standardized measure of discounted future net cash
flows.................................................. $1,353,088 $ 888,264 $1,166,509
========== ========== ==========
In the foregoing determination of future cash inflows, sales prices for gas
were based on contractual arrangements or market prices at each year-end. Prices
for oil were based on average prices received from sales in the month of
December each year. Future costs of developing and producing the proved gas and
oil reserves reported at the end of each year shown were based on costs
determined at each such year end, assuming the continuation of existing economic
conditions. Future income taxes were computed by applying the appropriate
year-end or future statutory tax rate to future pretax net cash flows, less the
tax basis of the properties involved, and giving effect to tax deductions, or
permanent differences and tax credits.
It is not intended that the FASB's standardized measure of discounted
future net cash flows represent the fair market value of the Company's proved
reserves. The Company cautions that the disclosures shown are based on estimates
of proved reserve quantities and future production schedules which are
inherently imprecise and subject to revision, and the 10% discount rate is
arbitrary. In addition, present costs and prices are used in the determinations
and no value may be assigned to probable or possible reserves.
The following tabulation is a summary of changes between the total
standardized measure of discounted future net cash flows at the beginning and
end of each year.
YEARS ENDED DECEMBER 31, 1999 1998 1997
------------------------ ---- ---- ----
(In Thousands)
Standardized measure of discounted future net cash flows
at January 1............................................ $ 888,264 $1,166,509 $1,431,997
Changes in the year resulting from Sales and transfers
of gas and oil produced during the year, less
production costs...................................... (353,001) (319,577) (345,920)
Prices and production and development costs related to
future production.................................. 792,565 (657,675) (660,014)
Extensions, discoveries and other additions, less
production and development costs................... 186,527 144,595 256,366
Previously estimated development costs incurred during
the year........................................... 56,606 71,172 38,409
Revisions of previous quantity estimates.............. (212,644) 38,015 101,352
Accretion of discount................................. 120,822 166,707 209,210
Income taxes.......................................... (263,369) 180,611 159,528
Purchases and sales of proved reserves in place-net... 264,748 35,639 40,815
Other (principally timing of production).............. (127,430) 62,268 (65,234)
---------- ---------- ----------
Standardized measure of discounted future net cash flows
at December 31........................................ $1,353,088 $ 888,264 $1,166,509
========== ========== ==========
52
55
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
COST-OF-SERVICE PROPERTIES
As previously stated, activities subject to cost-of-service rate
regulation, consisting solely of gas reserves and related production, are
excluded from the foregoing information. In December 1998, Peoples Natural Gas,
a subsidiary, transferred by sale all of its remaining gas production properties
to CNG Producing, a nonregulated subsidiary. Accordingly, there were no
remaining cost-of-service properties as of December 31, 1999 or 1998, and there
was no cost-of-service production during 1999.
At December 31, 1997, net capitalized costs of cost-of-service properties
amounted to $8.4 million. Related proved reserves of gas were located in the
United States and amounted to 42 Bcf at December 31, 1997. Gas production for
the years 1998 and 1997 amounted to 2 and 3 Bcf, respectively.
(B) QUARTERLY FINANCIAL DATA
A summary of the quarterly results of operations for the years 1999 and
1998 follows. 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, and
third quarter results are usually the least significant of the year for the
Company. Seasonal fluctuations are further influenced by the timing of price
relief granted under regulation to compensate for certain past cost increases.
QUARTER
-------------------------------------------
1999 FIRST SECOND THIRD FOURTH
---- ----- ------ ----- ------
(In Thousands)
Total operating revenues.................................... $1,046,448 $566,435 $505,610 $955,857
Operating income before income taxes*....................... $ 243,307 $ 65,711 $ 44,999 $179,003
Income (loss) from continuing operations.................... $ 138,987 $(80,024) $ 10,820 $ 66,977
Net income (loss)........................................... $ 138,987 $(80,024) $ 10,820 $ 66,977
Earnings per common share--basic
Income (loss) from continuing operations.................. $ 1.46 $ (.84) $ .11 $ .70
---------- -------- -------- --------
Net income (loss)........................................... $ 1.46 $ (.84) $ .11 $ .70
========== ======== ======== ========
Earnings per common share--diluted
Income (loss) from continuing operations.................. $ 1.44 $ (.83) $ .11 $ .70
---------- -------- -------- --------
Net income (loss)........................................... $ 1.44 $ (.83) $ .11 $ .70
========== ======== ======== ========
- ---------------
* Second, third and fourth quarter amounts include merger expenses of $165.3
million, $7.7 million and $39.7 million, respectively. Which revised basic EPS
by $1.13, $.06 and $.32 per share, respectively. See Note 2, page 29, for
further information on the Company's pending merger with DRI.
53
56
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONCLUDED)
QUARTER
-----------------------------------------
1998 FIRST SECOND THIRD FOURTH
- ---- ----- ------ ----- ------
(In Thousands)
Total operating revenues.................................... $999,165 $530,428 $423,448 $807,365
Operating income before income taxes........................ $234,850 $ 83,710 $ 25,516 $153,062
Income from continuing operations........................... $138,033 $ 46,814 $ 5,627 $ 97,237
Discontinued operations (Note 3)
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............................................ $(42,900) $ 10,989 $ 2,425 $ (2,221)
Net income.................................................. $ 77,895 $ 57,803 $ 8,052 $ 95,016
Earnings per common share--basic*
Income from continuing operations......................... $ 1.48 $ .49 $ .06 $ 1.02
Loss from discontinued operations......................... (.18) -- -- --
Income (loss) from disposal of discontinued operations.... (.46) .12 .02 (.02)
-------- -------- -------- --------
Net income.................................................. $ .84 $ .61 $ .08 $ 1.00
======== ======== ======== ========
Earnings per common share--diluted*
Income from continuing operations......................... $ 1.45 $ .49 $ .06 $ 1.01
Loss from discontinued operations......................... (.18) -- -- --
Income (loss) from disposal of discontinued operations.... (.45) .11 .02 (.02)
-------- -------- -------- --------
Net income.................................................. $ .82 $ .60 $ .08 $ .99
======== ======== ======== ========
- ---------------
* The sum of the quarterly amounts does not equal the year's amount because the
quarterly calculations are based on a changing number of average shares.
(C) Common Stock Market Prices and Related Matters
At December 31, 1999, there were 30,659 holders of the Company's common
stock. The principal market for the stock is the New York Stock Exchange.
Quarterly price ranges and dividends declared on the common stock for the years
1999 and 1998 follow. Restrictions on the payment of dividends are discussed in
Note 13.
QUARTER
---------------------------------
FIRST SECOND THIRD FOURTH
----- ------ ----- ------
Market Price Range
1999--High............................. $57 3/4 $61 3/16 $64 1/8 $65 7/16
--Low............................. $48 11/16 $48 1/2 $60 5/8 $61 7/8
1998--High............................. $60 1/2 $60 1/8 $59 $55 15/16
--Low............................. $53 1/4 $54 15/16 $41 11/16 $50 7/16
Dividends Declared per Share
1999................................... $.485 $.485 $.485 $.485
1998................................... $.485 $.485 $.485 $.485
54