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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to _____________
Commission file number 1-7176
THE COASTAL CORPORATION
(Exact name of registrant as specified in its character)
Delaware 74-1734212
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
Coastal Tower
Nine Greenway Plaza
Houston, Texas 77046-0995
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 877-1400
---------------------------
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months, and (2) has been subject to such filing
requirements for the past 90 days. Yes X No _____
As of July 31, 1996, there were outstanding 105,178,315 shares of Common
Stock, 331/3(cent) par value per share, and 386,649 shares of Class A Common
Stock, 331/3(cent) par value per share, of the Registrant.
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<PAGE>
PART I
FINANCIAL INFORMATION
Item 1. Financial Statements.
The financial statements of The Coastal Corporation and its subsidiaries
(the "Company") are presented herein and are unaudited, except for balances as
of December 31, 1995, and therefore are subject to year-end adjustments;
however, all adjustments which are, in the opinion of management, necessary for
a fair statement of the results of operations for the periods covered have been
made. The adjustments which have been made are of a normal recurring nature.
Such results are not necessarily indicative of results to be expected for the
year due to seasonal variations and market conditions affecting sales of natural
gas and petroleum products.
THE COASTAL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
<TABLE>
<CAPTION>
June 30, December 31,
ASSETS 1996 1995
----------- ------------
(Unaudited)
<S> <C> <C>
Current Assets:
Cash and cash equivalents............................................... $ 54.9 $ 58.4
Receivables, less allowance for doubtful accounts of $18.8 million
(1996) and $21.4 million (1995)...................................... 1,237.7 1,192.3
Inventories............................................................. 821.8 781.1
Prepaid expenses and other.............................................. 200.2 218.3
----------- -----------
Total Current Assets................................................. 2,314.6 2,250.1
----------- -----------
Property, Plant and Equipment - at cost:
Natural gas systems..................................................... 5,923.8 5,866.2
Refining, crude oil and chemical facilities............................. 2,133.2 1,957.8
Gas and oil properties - at full-cost................................... 1,569.2 1,450.9
Other................................................................... 761.0 743.1
----------- -----------
10,387.2 10,018.0
Accumulated depreciation, depletion and amortization.................... 3,740.8 3,556.1
----------- -----------
6,646.4 6,461.9
----------- -----------
Other Assets:
Goodwill................................................................ 516.3 525.7
Investments - equity method............................................. 538.3 447.4
Other................................................................... 864.2 973.7
----------- -----------
1,918.8 1,946.8
----------- -----------
$ 10,879.8 $ 10,658.8
=========== ===========
</TABLE>
See Notes to Consolidated Financial Statements.
- 1 -
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
<TABLE>
<CAPTION>
June 30, December 31,
LIABILITIES AND STOCKHOLDERS' EQUITY 1996 1995
----------- ------------
(Unaudited)
<S> <C> <C>
Current Liabilities:
Notes payable and preferred stock redeemable within one year............ $ 370.5 $ 123.2
Accounts payable........................................................ 1,637.8 1,630.2
Accrued expenses........................................................ 285.8 325.4
Current maturities on long-term debt.................................... 7.0 128.5
----------- -----------
Total Current Liabilities............................................ 2,301.1 2,207.3
----------- -----------
Debt:
Long-term debt, excluding current maturities............................ 3,689.4 3,661.7
----------- -----------
Deferred Credits and Other:
Deferred income taxes................................................... 1,495.3 1,473.8
Other deferred credits.................................................. 600.3 636.6
----------- -----------
2,095.6 2,110.4
----------- -----------
Mandatory Redemption Preferred Stock:
Issued by subsidiaries.................................................. - .6
----------- -----------
Common Stock and Other Stockholders' Equity:
Cumulative preferred stock (with aggregate liquidation preference
of $209.0 million)................................................... 2.7 2.7
Class A common stock.................................................... .1 .1
Common stock............................................................ 36.5 36.4
Additional paid-in capital.............................................. 1,233.0 1,225.0
Retained earnings....................................................... 1,653.9 1,547.1
----------- -----------
2,926.2 2,811.3
Less common stock in treasury - at cost................................. 132.5 132.5
----------- -----------
2,793.7 2,678.8
----------- -----------
$ 10,879.8 $ 10,658.8
=========== ===========
</TABLE>
See Notes to Consolidated Financial Statements.
- 2 -
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Millions of Dollars, Except Per Share)
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ---------------------
1996 1995 1996 1995
-------- ---------- -------- ---------
(Unaudited) (Unaudited)
<S> <C> <C> <C> <C>
Operating Revenues............................................ $ 2,938.0 $ 2,613.5 $ 6,033.1 $ 5,231.8
--------- ---------- --------- ---------
Operating Costs and Expenses:
Purchases.................................................. 2,252.4 1,880.6 4,612.9 3,777.8
Operating expenses......................................... 406.8 453.4 842.5 896.3
Depreciation, depletion and amortization................... 106.0 93.5 206.3 187.3
--------- ---------- --------- ---------
2,765.2 2,427.5 5,661.7 4,861.4
--------- ---------- --------- ---------
Operating Profit.............................................. 172.8 186.0 371.4 370.4
--------- ---------- --------- ---------
Other Income - net............................................ 18.3 6.9 36.4 24.3
--------- ---------- --------- ---------
Other Expenses:
General and administrative................................. 14.1 13.7 28.6 27.9
Interest and debt expense, less $1.8 million (1996)
and $1.4 million (1995) three months and $3.3
million (1996) and $3.2 million (1995)
six months capitalized.................................. 95.1 102.9 190.7 212.5
Taxes on income............................................ 15.8 19.1 39.9 39.5
--------- ---------- --------- ---------
125.0 135.7 259.2 279.9
--------- ---------- --------- ---------
Earnings Before Extraordinary Item............................ 66.1 57.2 148.6 114.8
Extraordinary item - loss on early extinguishment
of debt................................................. (12.0) - (12.0) -
--------- ---------- --------- ---------
Net Earnings.................................................. 54.1 57.2 136.6 114.8
Dividends on Preferred Stock.................................. 4.4 4.4 8.7 8.7
--------- ---------- --------- ---------
Net Earnings Available
to Common Stockholders.................................. $ 49.7 $ 52.8 $ 127.9 $ 106.1
========= ========== ========= =========
Earnings Per Share:
Before extraordinary item.................................. $ .58 $ .50 $ 1.32 $ 1.01
Extraordinary item......................................... (.11) - (.11) -
--------- ---------- --------- ---------
Net Earnings Per Common
and Common Equivalent Share............................. $ .47 $ .50 $ 1.21 $ 1.01
========= ========== ========= =========
Cash Dividends Per Common Share............................... $ .10 $ .10 $ .20 $ .20
========= ========== ========= =========
</TABLE>
See Notes to Consolidated Financial Statements.
- 3 -
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY
(Thousands of Shares and Millions of Dollars)
<TABLE>
<CAPTION>
Six Months Ended June 30,
-----------------------------------------------------
1996 1995
------------------------ -----------------------
Shares Amount Shares Amount
-------- -------- -------- ---------
(Unaudited)
<S> <C> <C> <C> <C>
Preferred stock, par value
331/3(cent) per share, authorized 50,000,000 shares:
Cumulative convertible preferred:
$1.19, Series A, redemption or liquidation
amount of $33 per share:
Beginning balance........................... 61 $ - 63 $ -
Converted to common......................... (1) - (1) -
----------- ---------- ----------- ----------
Ending balance.............................. 60 - 62 -
=========== ---------- =========== ----------
$1.83, Series B, redemption or liquidation
amount of $50 per share:
Beginning balance........................... 79 .1 84 .1
Converted to common......................... (3) - (3) -
----------- ---------- ----------- ----------
Ending balance.............................. 76 .1 81 .1
=========== ---------- =========== ----------
$5.00, Series C, redemption or liquidation
amount of $100 per share:
Beginning balance........................... 33 - 34 -
Converted to common......................... (1) - - -
----------- ---------- ----------- ----------
Ending balance.............................. 32 - 34 -
=========== ---------- =========== ----------
Cumulative preferred:
$2.125, Series H, liquidation amount
of $25 per share:
Beginning and ending balance 8,000 2.6 8,000 2.6
=========== ---------- =========== ----------
Class A common stock, par value 33-1/3(cent) per share,
authorized 2,700,000 shares:
Beginning balance................................ 404 .1 416 .1
Converted to common.............................. (25) - (10) -
Conversion of preferred stock and
exercise of stock options..................... 13 - 5 -
----------- ---------- ----------- ----------
Ending balance................................... 392 .1 411 .1
=========== ---------- =========== ----------
Common stock, par value 331/3(cent) per share, authorized
250,000,000 shares:
Beginning balance................................ 109,168 36.4 108,726 36.2
Conversion of preferred stock.................... 22 - 18 -
Conversion of Class A common stock............... 25 - 10 -
Exercise of stock options........................ 342 .1 78 .1
----------- ---------- ----------- ----------
Ending balance................................... 109,557 $ 36.5 108,832 $ 36.3
=========== ---------- =========== ----------
</TABLE>
See Notes to Consolidated Financial Statements.
- 4 -
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY
(Thousands of Shares and Millions of Dollars)
(Continued)
<TABLE>
<CAPTION>
Six Months Ended June 30,
------------------------------------------------------
1996 1995
------------------------ ------------------------
Shares Amount Shares Amount
----------- ---------- ---------- ----------
(Unaudited)
<S> <C> <C> <C> <C>
Additional paid-in capital:
Beginning balance................................... $ 1,225.0 $ 1,214.7
Exercise of stock options........................... 8.0 .8
---------- ----------
Ending balance...................................... 1,233.0 1,215.5
---------- ----------
Retained earnings:
Beginning balance................................... 1,547.1 1,336.0
Net earnings for period............................. 136.6 114.8
Dividends on preferred stock........................ (8.7) (8.7)
Dividends on common stock........................... (21.1) (21.0)
---------- ----------
Ending balance...................................... 1,653.9 1,421.1
---------- ----------
Less treasury stock - at cost.......................... 4,395 (132.5) 4,395 (132.5)
=========== ---------- =========== ----------
Total.................................................. $ 2,793.7 $ 2,543.2
========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
- 5 -
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)
<TABLE>
<CAPTION>
Six Months Ended
June 30,
-------------------------
1996 1995
--------- --------
(Unaudited)
<S> <C> <C>
Net Cash Flow From Operating Activities:
Earnings before extraordinary item.......................................... $ 148.6 $ 114.8
Add (subtract) items not requiring (providing) cash:
Depreciation, depletion and amortization................................. 208.4 189.2
Deferred income taxes.................................................... (.4) 13.4
Amortization of producer contract reformation costs...................... 15.9 14.7
Distributed (undistributed) earnings from equity investments............. 1.8 (2.8)
Working capital and other changes, excluding changes relating to cash and
non-operating activities:
Accounts receivable................................................... (88.1) 138.6
Inventories........................................................... (38.4) (22.7)
Prepaid expenses and other............................................ 28.5 29.8
Accounts payable...................................................... 3.1 (336.2)
Accrued expenses...................................................... (60.5) (22.2)
Other................................................................. 73.5 56.2
--------- --------
292.4 172.8
--------- --------
Cash Flow From Investing Activities:
Purchases of property, plant and equipment.................................. (340.9) (224.3)
Proceeds from sale of property, plant and equipment......................... 5.3 89.5
Additions to investments.................................................... (66.2) (56.1)
Proceeds from investments................................................... 13.6 47.9
Recovery of gas supply prepayments.......................................... .1 .3
--------- --------
(388.1) (142.7)
Cash Flow From Financing Activities:
Increase (decrease) in short-term notes .................................... 46.8 (28.7)
Redemption of mandatory redemption preferred stock.......................... (.1) -
Proceeds from issuing common stock.......................................... 8.1 .9
Proceeds from long-term debt issues......................................... 630.3 190.0
Payments to retire long-term debt........................................... (563.1) (206.3)
Dividends paid.............................................................. (29.8) (29.7)
--------- --------
92.2 (73.8)
--------- --------
Net Decrease in Cash and Cash Equivalents...................................... (3.5) (43.7)
Cash and Cash Equivalents at Beginning of Period............................... 58.4 73.5
--------- --------
Cash and Cash Equivalents at End of Period..................................... $ 54.9 $ 29.8
========= ========
</TABLE>
See Notes to Consolidated Financial Statements.
- 6 -
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
For additional information relative to operations and financial position,
reference is made to the Company's Annual Report on Form 10-K for the fiscal
year ended December 31, 1995. Certain minor reclassifications of prior period
statements have been made to conform with current reporting practices. The
effect of the reclassifications was not material to the Company's consolidated
results of operations or financial condition.
In October 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" ("FAS 123"), which establishes financial accounting and reporting
standards for stock-based employee compensation plans and for transactions in
which an entity issues its equity instruments to acquire goods and services from
nonemployees. FAS 123 requires, among other things, that compensation cost be
calculated for fixed stock options at the grant date by determining fair value
using an option-pricing model. The Company has the option of recognizing the
compensation cost over the vesting period as an expense in the statement of
consolidated operations or making pro forma disclosures in the notes to
financial statements as to the effects on net earnings as if the compensation
cost had been recognized in the statement of consolidated operations. The
Company adopted FAS 123 in 1996 and will make the required pro forma disclosures
in the notes to the annual financial statements. In March 1996, the Company
granted 661,500 options with an exercise price of $36.56. The exercise price was
equal to the market price of the stock at the grant date.
The Company adopted Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of" in 1996. The application of the new standard did not have a
material effect on the Company's consolidated results of operations or financial
position.
The interstate natural gas pipeline and certain storage subsidiaries are
subject to the regulations and accounting procedures of the Federal Energy
Regulatory Commission ("FERC"). These subsidiaries meet the criteria and,
accordingly, follow the reporting and accounting requirements of Statement of
Financial Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation" ("FAS 71"). FAS 71 provides that rate-regulated public
utilities account for and report assets and liabilities consistent with the
economic effect of the way in which regulators establish rates, if the rates
established are designed to recover the costs of providing the regulated service
and if the competitive environment makes it reasonable to assume that such rates
can be charged and collected. Although the accounting methods for companies
subject to rate regulation may differ from those used by non-regulated
companies, the accounting methods prescribed by the regulatory authority conform
to the generally accepted accounting principle of matching costs with the
revenue to which they apply.
Transactions which the subsidiaries have recorded differently than a
non-regulated entity include the following: the subsidiaries (i) have
capitalized the cost of equity funds used during construction, and, (ii) have
deferred purchase gas costs, gas transportation surcharges, contract reformation
costs, postemployment/postretirement benefit costs and income tax reductions
related to changes in federal income tax rates. These items are being, or are
anticipated to be, recovered or refunded in rates chargeable to customers.
The subsidiaries have applied FAS 71 and evaluate the applicability of
regulatory accounting and the recoverability of these assets through rate or
other contractual mechanisms on an ongoing basis. If FAS 71 accounting
principles should no longer be applicable to the subsidiaries' operations, an
amount would be charged to earnings as an extraordinary item. At June 30, 1996,
this amount was approximately $88 million, net of income taxes. The Company does
not expect that its cash flows would be affected by discontinuing application of
FAS 71. Any potential charge to earnings would be noncash and would have no
direct effect on the subsidiaries' ability to include the underlying deferred
items in their future rate proceedings or on their ability to collect the rates
set thereby.
- 7 -
<PAGE>
Supplemental information relative to the Statement of Consolidated Cash
Flows includes the following: The Company made cash payments for interest and
financing fees, net of amounts capitalized, of $203.6 million and $228.7 million
for the six months ended June 30, 1996 and 1995, respectively. Cash payments for
income taxes amounted to $41.7 million and $30.2 million for the six months
ended June 30, 1996 and 1995, respectively.
2. Inventories
Inventories were as follows (millions of dollars):
<TABLE>
<CAPTION>
June 30, December 31,
1996 1995
----------- ------------
(Unaudited)
<S> <C> <C>
Refined products, crude oil and chemicals............................... $ 597.7 $ 556.5
Natural gas in underground storage...................................... 46.8 49.9
Coal, materials and supplies............................................ 177.3 174.7
----------- ----------
$ 821.8 $ 781.1
=========== ==========
</TABLE>
The excess of replacement cost over the carrying value of natural gas in
underground storage carried by the last-in, first-out method was approximately
$38.3 million at June 30, 1996 and $36.5 million at December 31, 1995.
3. Common Stock
On June 30, 1996, 3,325,947 shares of Common Stock of the Company were
reserved for employee stock option plans, 721,284 shares were reserved for
conversion of the Series A, B, and C Preferred Stocks, 391,736 shares were
reserved for conversion of outstanding Class A Common Stock and 22,246 shares
were reserved for conversion of Class A Common Stock subject to future issuance.
The Class A Common Stock reserved for future issuance consists of 2,280 shares
reserved for employee stock option plans and 19,966 shares reserved for
conversion of the Series A, B, and C Preferred Stocks.
4. Income Taxes
Provisions for income taxes were as follows (millions of dollars):
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ---------------------
1996 1995 1996 1995
--------- ---------- --------- ---------
(Unaudited) (Unaudited)
<S> <C> <C> <C> <C>
Current Income Taxes:
Federal................................................. $ 17.9 $ 9.1 $ 32.5 $ 23.3
Foreign................................................. .3 .1 .9 .4
State................................................... 3.4 2.3 6.9 2.4
--------- ---------- --------- ---------
21.6 11.5 40.3 26.1
--------- ---------- --------- ---------
Deferred Income Taxes:
Federal................................................. (6.0) 9.0 - 15.0
Foreign................................................. .9 - 1.4 -
State................................................... (.7) (1.4) (1.8) (1.6)
--------- ---------- --------- ---------
(5.8) 7.6 (.4) 13.4
--------- ---------- --------- ---------
$ 15.8 $ 19.1 $ 39.9 $ 39.5
========= ========== ========= =========
</TABLE>
Interim period provisions for federal income taxes are based on estimated
effective annual income tax rates.
- 8 -
<PAGE>
5. Extraordinary Item
In June 1996, the Company retired $400.0 million of 11-3/4% Senior
Debentures due in 2006. Payment of the redemption premium and the recognition of
deferred costs related to the Debentures resulted in an extraordinary loss of
$12.0 million ($.11 per share), net of income taxes of $6.5 million.
6. Litigation, Regulatory and Environmental Matters
Litigation
A subsidiary of Coastal initiated a suit against TransAmerican Natural Gas
Corporation ("TransAmerican") in the District Court of Webb County, Texas for
breach of two gas purchase agreements. In February 1993, TransAmerican filed a
Third Party Complaint and a Counterclaim in this action against Coastal and
certain subsidiaries. TransAmerican alleged breach of contract, fraud,
conspiracy, duress, tortious interference and violations of the Texas Free
Enterprises and Anti-trust Act arising out of the gas purchase agreements. Final
judgment in this matter was entered April 22, 1994. The subsidiary was awarded
approximately $2.0 million, including pre-judgment interest and attorney fees.
All of TransAmerican's claims and causes of action were denied. The judgment has
been appealed by TransAmerican and the case is presently pending before the
Court of Appeals for the Fourth Judicial District at San Antonio, Texas.
In December 1992, certain of Colorado Interstate Gas Company's ("CIG")
natural gas lessors in the West Panhandle Field filed a complaint in the U.S.
District Court for the Northern District of Texas claiming underpayment, breach
of fiduciary duty, fraud and negligent misrepresentation. Management believes
that CIG has numerous defenses to the lessors' claims, including (i) that the
royalties were properly paid, (ii) that the majority of the claims were released
by written agreement and (iii) that the majority of the claims are barred by the
statute of limitations. In March of 1995, the Trial Court granted a partial
summary judgment in favor of CIG, holding that the four-year statute of
limitations had not been tolled, that the releases are valid, and dismissing all
tort claims and claims for breach of any duty of disclosure. The remaining claim
for underpayment of royalties was tried to a jury which, in May 1995, made
findings favorable to CIG. On June 7, 1995, the Trial Court entered a judgment
that the lessors recover no monetary damages from CIG and permanently estopping
the lessors from asserting any claim based on an interpretation of the contract
different than that asserted by CIG in the litigation. The lessors' motion for a
new trial is pending. On June 7, 1996, the same plaintiffs sued CIG in state
court in Amarillo, Texas for underpayment of royalties. CIG removed the second
lawsuit to federal court which granted a stay of the second lawsuit pending the
outcome of the first lawsuit.
A natural gas producer has filed a claim on behalf of the U.S. government
in the U.S. District Court for the District of Columbia under the federal False
Claims Act. The Second Amended Complaint filed on May 24, 1996, against seventy
(70) defendants, including ANR Pipeline Company ("ANR Pipeline"), CIG and
Coastal States Gas Transmission Company, alleges that the defendants' methods of
measuring the heating content and volume of natural gas purchased from
federally-owned or Indian properties have caused underpayment of royalties to
the U.S. government. Responsive pleadings will be filed and discovery will soon
commence.
Numerous other lawsuits and other proceedings which have arisen in the
ordinary course of business are pending or threatened against the Company or its
subsidiaries.
Although no assurances can be given and no determination can be made at
this time as to the outcome of any particular lawsuit or proceeding, the Company
believes there are meritorious defenses to substantially all of the above claims
and that any liability which may finally be determined should not have a
material adverse effect on the Company's consolidated financial position or
results of operations.
Regulatory Matters
On January 31, 1996, the FERC issued a "Statement of Policy and Request for
Comments" in Docket Nos. RM95-6 and RM96-7 with respect to a pipeline's ability
to negotiate and charge rates for individual customers' services which would not
be limited to the "cost-based" rates established by the FERC in traditional rate
making. Under this Policy, a pipeline and a customer will be allowed to
negotiate a contract for service which provides for rates and charges that
- 9 -
<PAGE>
exceed the pipeline's posted maximum tariff rates, provided that the shipper
agreeing to such negotiated rates has the ability to elect to receive service
at the pipeline's posted maximum rate (known as a "recourse rate"). In order
to implement this Policy, a pipeline must make an initial tariff filing with
the FERC to indicate that it intends to contract for services under this
Policy, and subsequent tariff filings will indicate each instance where the
pipeline has negotiated a rate for service which exceeds the posted maximum
tariff rate. The FERC has also requested comments on whether this "recourse
rate" program should be extended to other terms and conditions of pipeline
transportation services.
Under ANR Pipeline's Interim Settlement, which became effective November 1,
1992 and expired on November 1, 1993, gas inventory demand charges were
collected from ANR Pipeline's former resale customers. This method of gas cost
recovery required refunds for any over-collections and placed ANR Pipeline at
risk for under-collections. As required by the Interim Settlement, on April 29,
1994, ANR Pipeline filed with the FERC a reconciliation report showing
over-collections and proposing refunds totaling $45.1 million. Certain customers
have disputed the level of those refunds. Pursuant to a February 27, 1995 FERC
order approving ANR Pipeline's refund allocation methodology, ANR Pipeline paid
undisputed refunds on March 29, 1995 of $45.1 million, together with applicable
interest, subject to further investigation of the claims made by the customers.
The FERC's approval of ANR Pipeline's refund allocation methodology was appealed
by certain customers to the United States Court of Appeals for the D.C. Circuit
and that appeal was dismissed in an April 24, 1996 Court order. On May 2, 1995,
the FERC issued an order setting other issues for an evidentiary hearing which
concluded on May 29, 1996. ANR Pipeline submitted an adjusted reconciliation
report on October 31, 1995, which was also disputed by certain customers and
which was also consolidated with the ongoing evidentiary hearing. Initial briefs
were filed on July 31, 1996, and reply briefs are due to be filed September 26,
1996.
On April 8, 1992, the FERC issued Order 636, which required significant
changes in the services provided by interstate natural gas pipelines. ANR
Pipeline and numerous other parties have sought judicial review of aspects of
Order 636 before the United States Court of Appeals for the D.C. Circuit. On
July 16, 1996, the Court issued its opinion upholding the basic structure of
Order 636, while remanding certain limited aspects to the FERC for further
consideration. Several persons, including ANR Pipeline, have also appealed
aspects of the FERC's orders approving ANR Pipeline's restructuring filings made
pursuant to Order 636 and these appeals are now expected to be scheduled for
briefing. ANR Pipeline placed its restructured services under Order 636 into
effect on November 1, 1993. On March 24, 1994, the FERC issued its "Fourth Order
on Compliance Filing and Third Order on Rehearing," which addressed numerous
rehearing issues and confirmed that, after minor tariff modifications, ANR
Pipeline would be fully in compliance with Order 636 and the requirements of the
orders on its restructuring filings.
Under FERC Docket No. RP94-43, ANR Pipeline filed a general rate increase
on November 1, 1993. By a March 23, 1994 order, the FERC granted and denied
various requests for summary disposition and established hearing procedures for
issues remaining to be investigated in the proceeding. The hearing commenced on
January 31, 1996 and concluded on April 24, 1996. Initial briefs were filed on
July 15, 1996, and reply briefs are due September 13, 1996. Under the March 23,
1994 order, certain costs were reduced or eliminated, resulting in revised rates
that reflect an $85.7 million increase in the cost of service underlying that
approved in the Interim Settlement, and a $182.8 million increase over the cost
of service underlying ANR Pipeline's approved rates for its Order 636
restructured services. On April 29, 1994, ANR Pipeline filed a motion with the
FERC that placed the new rates into effect May 1, 1994, subject to refund. ANR
Pipeline's filing was accepted by the FERC in a September 21, 1994 order,
subject to further modifications, including an additional reduction in cost of
service of approximately $5 million. ANR Pipeline submitted revised rates in
compliance with this order on October 6, 1994, which rates are currently in
effect, subject to refund. ANR Pipeline sought rehearing of various aspects of
the March 23, 1994 order and the FERC denied rehearing in a December 8, 1994
order. On January 26, 1995, ANR Pipeline appealed these orders to the United
States Court of Appeals for the D.C. Circuit, and the Court is expected to
schedule the cases for briefing.
The FERC has also issued a series of orders and orders on rehearing in ANR
Pipeline's rate proceeding that apply a new policy governing the order of
attribution of revenues received by ANR Pipeline related to transition costs
under Order 636. Under that new policy, ANR Pipeline is required to first
attribute the revenues it receives for its services to the recovery of its
transition costs under Order 636. In its pending rate proceeding, the revenues
ANR Pipeline receives for its services were first attributed to the recovery of
its base cost of service. The FERC's change in its revenue attribution policy
has the effect of understating ANR Pipeline's currently effective maximum rates
and has accelerated its amortization of transition costs. In light of the FERC's
policy, ANR Pipeline has filed with the FERC to increase its
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<PAGE>
discount recovery adjustment in its pending rate proceeding. ANR Pipeline has
also sought judicial review of these orders before the United States Court of
Appeals for the D.C. Circuit, and the Court is expected to schedule the case
for briefing.
Claims were filed in 1990 in the United States District Court in North
Dakota by Dakota Gasification Company ("Dakota") and the United States
Department of Energy regarding ANR Pipeline's obligations under certain gas
purchase and transportation contracts with the Great Plains Coal Gasification
Plant (the "Plant"). On February 16, 1994, ANR Pipeline, Dakota and the
Department of Energy executed a Settlement Agreement (the "Settlement
Agreement"), which, subject to FERC approval, resolves the litigation and
disputes among the parties, amends the gas purchase agreement between ANR
Pipeline and Dakota and terminates the transportation contract with the Plant.
On August 3, 1994, ANR Pipeline filed a petition with the FERC requesting: (i)
approval of the Settlement Agreement; (ii) an order approving ANR Pipeline's
proposed tariff mechanism to recover the costs incurred to implement the
Settlement Agreement; and (iii) an order dismissing a then pending FERC
proceeding wherein certain of ANR Pipeline's customers challenged Dakota's
pricing under the original gas supply contract. By an October 18, 1994 order,
the FERC consolidated ANR Pipeline's petition with similar petitions of three
other pipeline companies. Hearings were held before the FERC Administrative Law
Judge ("ALJ") on the prudence of the Settlement Agreement, and on December 29,
1995, the ALJ issued an Initial Decision rejecting the proposed Settlement
Agreement and determining the level of Dakota costs that ANR Pipeline and the
other pipeline companies would be permitted to recover from their customers
beginning as of May 1993. Because the amounts ANR Pipeline has billed to its
customers since May 1993 are greater than the Dakota costs ANR Pipeline would be
permitted to recover under the Initial Decision, ANR Pipeline may be required to
refund to its customers the amount of excess collections. At June 30, 1996, that
potential refund amount is approximately $78 million, plus interest. It is ANR
Pipeline's position that (i) the Settlement Agreement is prudent, (ii) the FERC
has no lawful authority to order refunds for past periods and (iii) even if
refunds were ultimately found to be lawful, ANR Pipeline should not lawfully be
required to refund amounts in excess of the amounts it collects from Dakota. ANR
Pipeline has filed with the FERC seeking reversal of the Initial Decision, and
approval of the Settlement Agreement. By order issued July 17, 1996, the FERC
scheduled an oral argument for September 25, 1996 and a decision is expected
before the end of 1996.
Order 636 provides mechanisms for recovery of transition costs associated
with compliance with that Order. Limited aspects of those mechanisms are the
subject of the Court remand discussed above. ANR Pipeline's transition costs
consist primarily of gas supply realignment costs and pricing differential
costs. As of June 30, 1996, ANR Pipeline incurred transition costs in the amount
of $58.3 million. In addition, ANR Pipeline recorded a contingent liability for
$74.9 million representing future above-market gas purchase obligations,
including future obligations of $60.2 million associated with the Settlement
Agreement, as discussed above. The charge related to the contingent liability
has been deferred in anticipation of future rate recovery. ANR Pipeline has
filed for recovery of approximately $44.5 million of incurred transition costs.
The FERC has accepted $42.7 million of these filings for recovery, of which
$28.6 million has been settled with the parties to the respective FERC
proceedings. Those filings not settled are subject to refund and further
proceedings. Additional transition costs filings will be made by ANR Pipeline in
the future.
On October 31, 1995, as amended on February 22 and March 20, 1996, CIG
filed an application with the FERC seeking authority to transfer to CIG Field
Services Company ("CFS"), a subsidiary of CIG, certain facilities presently used
for the gathering of natural gas that are subject to certificates of public
convenience and necessity. In that filing, CIG requested that the FERC declare
that in the hands of CFS the transferred facilities will be considered
"nonjurisdictional" gathering facilities. The transferred facilities under the
amended filings have a net book value of approximately $33 million. On June 26,
1996, the FERC approved CIG's request. While CIG has sought clarification of
that order in one specific area, other parties have filed for rehearing. Certain
producer/shippers have requested rehearing on the issues of whether the FERC has
the legal authority to allow a spindown and whether any spindown must be
predicated upon a finding of adequate competition for the gathering market that
CIG serves. The first of those rehearing arguments has been resolved in the
recent Conoco v. FERC (Case No. 94-1724) decision of the United States Court of
Appeals for the District of Columbia Circuit in which the court concluded that
the FERC has authority to allow a spindown of gathering systems to a
non-jurisdictional affiliate. Thus, CIG expects this aspect of the rehearing
request to be denied by the FERC. With regard to the second of the
producer/shipper issues, while the FERC has confronted the same issue in other
cases and ruled against the producer/shippers, those rulings are on appeal to
various Courts of Appeal. The FERC's rationale for such rulings has been
grounded, in part, upon the fact that it was also imposing a
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<PAGE>
"default contract" on the pipeline affiliate. A "default contract" essentially
ensures continuity of service under pre-spindown terms and conditions for a
minimum of two years. The court in Conoco, however, has now ruled that the
FERC is without statutory authority to require the pipeline affiliate to enter
into a default contract, but has remanded the continuity of service issue to the
FERC for further consideration. Another rehearing application was filed by
another entity contesting CIG's failure to spindown the Panhandle Field
gathering system along with the other gathering systems. CIG previously answered
this same contention in earlier pleadings, but the FERC did not specifically
address this issue in its order. Generally, FERC precedent allows the pipeline
discretion in determining which, if any, gathering systems to spindown or
spin-off. At this point it cannot be determined when the FERC may act on the
pending rehearing applications in CIG's spindown in light of the remand in
Conoco.
On March 29, 1996, CIG filed with the FERC under Docket No. RP96-190 to
increase its rates by approximately $30 million annually and to realign certain
transportation services. On April 25, 1996, the FERC accepted the filing to
become effective October 1, 1996, subject to refund. In this filing, CIG also
established a new tariff provision to allow CIG to enter into negotiated rate
arrangements. The FERC has also accepted this provision, subject to refund,
effective May 1, 1996. Hearing and discovery procedures have been established
for the case. In the event that the case cannot be settled prior to hearing, the
schedule provides for commencement of hearings before an ALJ at the FERC in June
1997.
CIG, ANR Pipeline, ANR Storage Company and Wyoming Interstate Company, Ltd.
("WIC"), subsidiaries of the Company, are regulated by the FERC. Certain of the
above regulatory matters and other regulatory issues remain unresolved among
these companies, their customers, their suppliers and the FERC. The Company has
made provisions which represent management's assessment of the ultimate
resolution of these issues. As a result, the Company anticipates that these
regulatory matters will not have a material adverse effect on its consolidated
financial position or results of operations. While the Company estimates the
provisions to be adequate to cover potential adverse rulings on these and other
issues, it cannot estimate when each of these issues will be resolved.
Environmental Matters
The Company's operations are subject to extensive and evolving federal,
state and local environmental laws and regulations. The Company anticipates
capital expenditures of approximately $55 million in 1996 in order to comply
with such laws and regulations. The majority of the 1996 expenditures is
attributable to construction projects at the Company's refineries. The Company
currently anticipates capital expenditures for environmental compliance for the
years 1997 through 1999 of $20 to $40 million per year. Additionally,
appropriate governmental authorities may enforce the laws and regulations with a
variety of civil and criminal enforcement measures, including monetary penalties
and remediation requirements.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as "Superfund," as reauthorized, imposes liability, without regard to
fault or the legality of the original act, for disposal of a "hazardous
substance." Certain subsidiaries of the Company and a company in which Coastal
owns a 50% interest have been named as a potentially responsible party ("PRP")
in several "Superfund" waste disposal sites. At the 15 sites for which there is
sufficient information, total clean-up costs are estimated to be approximately
$337 million, and the Company estimates its pro-rata exposure, to be paid over a
period of several years, is approximately $5 million and has made appropriate
provisions. At 5 other sites, the Environmental Protection Agency ("EPA") is
currently unable to provide the Company with an estimate of total clean-up costs
and, accordingly, the Company is unable to calculate its share of those costs.
Finally, at 9 other sites, the Company has paid amounts to other PRPs or to the
EPA as its proportional share of associated clean-up costs. As to these latter
sites, the Company believes that its activities were de minimis. Additionally,
certain subsidiaries of the Company have been named as PRPs in two state sites.
At one site, the North Carolina Department of Health, Environment and Natural
Resources has estimated the total clean-up costs to be approximately $50
million, but the Company believes that the subsidiaries' activities at this site
were de minimis. At the other state site, the Florida Department of
Environmental Protection has estimated the total clean-up costs to be
approximately $40,000.
There are additional areas of environmental remediation responsibilities to
which the Company may be subject. The states have regulatory programs that
mandate waste clean-up. The Clean Air Act Amendments of 1990 include new
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<PAGE>
permitting regulations which will result in increased operating expenditures.
Coastal is also supplying reduced-emission reformulated gasoline in all of its
markets where such gasoline is required.
In March 1996, the EPA issued a Notice of Violation to Coastal Eagle Point
Oil Company, a subsidiary of Coastal, and the Eagle Point Cogeneration
Partnership in which Coastal has an indirect 50% interest. The Notice alleges
certain violations of permit conditions and an administrative consent order
involving the installation and testing of certain units at the New Jersey
facility, but the EPA has not specified the relief it is seeking. The Company
believes that this action could result in monetary sanctions which, while not
material to the Company and its subsidiaries, could exceed $100,000.
Future information and developments will require the Company to continually
reassess the expected impact of these environmental matters. However, the
Company has evaluated its total environmental exposure based on currently
available data, including its potential joint and several liability, and
believes that compliance with all applicable laws and regulations will not have
a material adverse impact on the Company's liquidity, consolidated financial
position or results of operations.
Item 2.A. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Management's Discussion and Analysis of Financial Condition and Results of
Operations includes certain forward-looking statements reflecting the Company's
expectations in the near future; however, many factors which may affect the
actual results, especially natural gas prices and changing regulations, are
difficult to predict. Accordingly, there is no assurance that the Company's
expectations will be realized.
The Notes to Consolidated Financial Statements contain information that is
pertinent to the following analysis.
Liquidity and Capital Resources
The Company uses the following consolidated ratios to measure liquidity and
its ability to meet future funding needs and debt service requirements.
<TABLE>
<CAPTION>
Twelve Months Ended
-------------------------------
June 30, December 31,
1996 1995
--------------- ------------
(Unaudited)
<S> <C> <C>
Net return on average common stockholders' equity.............. 11.2% 10.8%
Cash flow from operating activities to long-term debt.......... 20.8% 17.7%
Total debt to total capitalization............................. 59.3% 59.4%
Times interest earned (before tax)............................. 1.8 1.8
</TABLE>
The above ratios reflect increased earnings in the 1996 six months period.
Decreases in working capital also contributed to the increase in the cash flow
from operating activities to long-term debt ratio.
Financing for capital expansion, mandatory debt retirements and other
expenditures will be provided by internally generated funds, existing credit
lines, proceeds from the sale of selective non-core assets and new financings.
On February 28, 1996, the Company announced that it will seek qualified
buyers for its coal operations. The proceeds from the proposed sale would be
used to significantly strengthen the Company's balance sheet by the repayment of
high-cost debt and other obligations, and to provide improved financial
flexibility to pursue opportunities in the Company's other lines of business.
- 13 -
<PAGE>
On June 15, 1996 the Company redeemed all of its 11-3/4% Senior Debentures
due June 15, 2006, of which $400 million in principal amount was outstanding.
Debentures in the principal amount of $60 million were redeemed at par plus
accrued interest to the date of redemption pursuant to sinking fund provisions,
with the securities selected for redemption by lot. The remaining $340 million
in debentures was redeemed at 103.917% of par plus accrued interest to the date
of redemption.
The Company has approved an $80 million increase in its 1996 capital
expenditures budget for Exploration and Production. Recent success in South
Texas and in the Gulf of Mexico offshore Texas and Louisiana have identified
substantial new opportunities for low-risk, high potential development drilling
programs. With the increase in the 1996 program, natural gas equivalent
production will increase substantially from 1995 and per-unit costs should be
reduced.
Funding for certain proposed projects is anticipated to be provided through
non-recourse project financings in which the projects' assets and contracts will
be pledged as collateral. Equity participation by other entities will be
considered. To the extent required, cash for equity contributions to projects
will be from general corporate funds.
The Company continues to maintain a financial position that will enable it
to generate and obtain capital for financing needs in the foreseeable future.
Unused lines of credit at June 30, 1996 were as follows (millions of dollars):
Short-term............................................ $ 462.3
Long-term*............................................ 417.0
----------
$ 879.3
*As of June 30, 1996, $235 million of unused long-term credit lines was
dedicated to a specific use. This amount was subsequently reduced to
$45.1 million.
In June 1996, Coastal Natural Gas Company, a wholly owned subsidiary,
completed a new $1 billion, five-year, unsecured revolving credit facility. The
new credit facility replaces an existing $750 million credit agreement.
Borrowings under the new credit facility are being used for general corporate
purposes.
Results of Operations
The changes in the Company's earnings for the three and six-month periods
ended June 30, 1996 in comparison to the same periods in 1995 are a result of
the following:
Operating Revenues. The operating revenues by segment were as follows
(millions of dollars):
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ---------------------
1996 1995 1996 1995
--------- ---------- --------- ---------
(Unaudited) (Unaudited)
<S> <C> <C> <C> <C>
Natural gas............................................. $ 925.0 $ 716.4 $ 1,928.4 $ 1,509.1
Refining, marketing and chemicals....................... 1,876.0 1,712.6 3,832.9 3,358.7
Exploration and production.............................. 115.5 67.3 200.5 130.7
Coal.................................................... 106.3 111.7 213.6 225.7
Power................................................... 25.8 7.7 46.0 15.3
Other................................................... 8.2 39.5 16.2 81.7
Adjustments and eliminations............................ (118.8) (41.7) (204.5) (89.4)
--------- ---------- --------- ---------
$ 2,938.0 $ 2,613.5 $ 6,033.1 $ 5,231.8
========= ========== ========= =========
</TABLE>
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<PAGE>
Operating Profit (Loss). The operating profit (loss) by segment was as
follows (millions of dollars):
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ---------------------
1996 1995 1996 1995
--------- ---------- --------- ---------
(Unaudited) (Unaudited)
<S> <C> <C> <C> <C>
Natural gas............................................. $ 73.8 $ 83.3 $ 199.9 $ 215.8
Refining, marketing and chemicals....................... 23.5 72.3 58.3 96.5
Exploration and production.............................. 41.0 4.5 55.1 7.4
Coal ................................................... 23.9 25.7 42.3 50.0
Power................................................... 7.8 .1 10.2 (.1)
Other................................................... 2.8 .1 5.6 .8
--------- ---------- --------- ---------
$ 172.8 $ 186.0 $ 371.4 $ 370.4
========= ========== ========= =========
</TABLE>
Natural Gas. The increases in operating revenues of $208.6 million for the
second quarter and $419.3 million for the six months ended June 30, 1996 can be
attributed to increased prices and volumes, primarily for the unregulated gas
marketing companies. Transportation and storage revenues decreased in both
periods, reflecting the continued, intensified competition across the United
States natural gas industry.
Purchases increased by $226.7 million for the three months and $438.2
million for the six months ended June 30, 1996, due to increased prices and
volumes. Gross profit decreased by $18.1 million and $18.9 million for the three
months and six months periods, respectively.
The operating profit decrease of $9.5 million in the second quarter results
from reduced transportation and storage revenues of $22.6 million and other
decreases of $.2 million offset by decreased operating expenses of $12.0 million
and increased margins of $1.3 million. The operating expense decrease results
from reduced salaries and benefits due to an early retirement incentive program
in 1995, lower ad valorem taxes of $4.0 million and reduced gas and gas liquids
handling costs. The operating profit decrease of $15.9 million for the six month
period results from reduced transportation and storage revenue of $26.0 million
and decreased margins of $5.0 million offset by decreased operating expenses of
$7.3 million, increased volumes of $4.0 million and other increases of $3.8
million. The decreased operating expenses result from reductions for salaries,
benefits and gas and gas liquids handling costs.
Refining, Marketing and Chemicals. Operating revenues increased by $163.4
million in the second quarter and $474.2 million in the six months ended June
30, 1996 as a result of higher prices and increased volumes. Purchases for the
segment increased by $212.7 million and $502.1 million for the three and six
month periods, respectively, resulting in gross profit decreases of $49.3
million for the second quarter and $27.9 million for the six month period.
The operating profit decrease of $48.8 million for the second quarter
results from lower margins of $66.9 million and a non-recurring gain of $17.0
million from the sale of certain liquid pipeline assets in 1995 offset by
improved volumes of $22.6 million; increased gross profit from the sale, trading
and exchanging of third party products of $8.5 million, decreased operating
expenses of $2.0 million and other increases of $2.0 million. For the six months
ended June 30, 1996, operating profit decreased by $38.2 million as lower
margins of $74.0 million; the $17.0 million non-recurring gain noted above;
increased operating expenses of $7.2 million and other of $1.0 million were
offset by increased volumes of $48.7 million and increased gross profit of $12.3
million from the sale, trading and exchanging of third party products. The
increased operating expenses for the six month period results from expanded
retail operations and the acquisition of a chemical plant in the first quarter
of 1996. Increased production from the Company's refineries and petrochemical
facility in Montreal, Quebec are responsible for the volume increases in both
periods.
Exploration and Production. Operating revenues increased by $48.2 million
and $69.8 million in the three month and six month periods ended June 30, 1996,
respectively, as a result of improved production volumes and higher prices for
all products. The production volume increase results from Coastal's ongoing
drilling program.
- 15 -
<PAGE>
Operating profit increased by $36.5 million in the three months ended June
30, 1996 as increases for improved volumes of $20.3 million; higher prices of
$19.6 million; the net effects of hedging and monetization activities of $9.0
million and other increases of $.2 million were partially offset by increased
operating expenses of $6.1 million and higher depreciation, depletion and
amortization of $6.5 million. For the six month period, operating profit
increased by $47.7 million as higher prices of $34.3 million; improved volumes
of $30.5 million; a $5.3 million net increase from hedging and monetization
activities and other increases of $.2 million were partially offset by increased
operating expenses of $13.0 million and higher depreciation, depletion and
amortization of $9.6 million. The increased operating expenses for both periods
are primarily due to higher costs associated with increased volumes at the
Company's processing plants. Expenses related to producing wells increased for
the six month period, but were down in the second quarter. Depreciation,
depletion and amortization increased in the three month and six month periods
due to the improved production volumes.
Coal. Operating revenues decreased by $5.4 million in the three months and
$12.1 million in the six months ended June 30, 1996, respectively, as a result
of reduced volumes sold and lower prices. The volumes decrease for the six
months includes the deferral of certain coal deliveries during the first half
which should be made up later this year. Operating profit decreased by $1.8
million in the three month period as reduced volumes of $4.5 million and lower
prices of $4.8 million were offset by reduced operating expenses of $5.6 million
and other increases of $1.9 million. The decrease in operating profit for the
three month period can be partially attributed to a temporary outage at a major
customer's plant. For the six month period, operating profit decreased by $7.7
million, as reduced volumes of $10.6 million and lower prices of $8.9 million
were partially offset by reduced operating expenses of $7.9 million and other
increases of $3.9 million. The reduced operating expenses for both periods are a
result of the reduced volumes sold, while the other increases result from sales
in 1996 of coke from the Company's refinery at Aruba.
On February 28, 1996, the Company announced that it will seek qualified
buyers for its Coal operations. The proceeds from the proposed sale would be
used to significantly strengthen the Company's balance sheet by repayment of
high-cost debt and other obligations, and to provide improved financial
flexibility to pursue opportunities in the Company's other lines of business.
The Coal operations had operating revenues of $459.6 million, $451.3 million and
$443.2 million for the years ended December 31, 1995, 1994 and 1993,
respectively; with operating profit for the same periods of $98.7 million, $98.2
million and $95.1 million, respectively. Identifiable assets of the Coal
operations were $518.6 million and $498.3 million as of December 31, 1995 and
1994, respectively.
Power. The operating revenue increases of $18.1 million and $30.7 million
for the three month and six month periods ended June 30, 1996, respectively; as
well as the respective operating profit increases of $7.7 million and $10.3
million, result primarily from the power plant in El Salvador which was not in
operation in the first six months of 1995.
Other. The decreases in operating revenues of $31.3 million and $65.5
million for the three months and six months ended June 30, 1996, respectively,
are due to the trucking activities, which were merged into a new company in
which Coastal has a 50% interest in November 1995. Operating profit increased by
$2.7 million and $4.8 million for the three and six month periods, respectively,
due primarily to the losses from trucking operations in 1995 not recurring.
Other Income-Net. The increases of $11.4 million for the second quarter and
$12.1 million for the six months ended June 30, 1996 result from a non-recurring
$10.0 million provision in 1995 for suspension of operations at the then
50%-owned Pacific Refining Company and increased equity income from
unconsolidated subsidiaries.
Interest and Debt Expense. Interest and debt expense decreased by $7.8
million in the second quarter due to reduced rates on variable rate debt. The
decrease of $21.8 million in the six month period ended June 30, 1996 is due to
reduced rates on variable rate debt and lower debt levels.
Taxes on Income. Federal income taxes decreased by $6.2 million in the 1996
second quarter and $5.8 million in the six month period as a result of a lower
effective federal income tax rate partially offset by increased earnings before
extraordinary item. State and foreign income taxes increased by $2.9 million in
the three month period and $6.2 million in the six month period.
- 16 -
<PAGE>
Environmental Matters
The Company's operations are subject to extensive and evolving federal,
state and local environmental laws and regulations. The Company anticipates
capital expenditures of approximately $55 million in 1996 in order to comply
with such laws and regulations. The majority of the 1996 expenditures is
attributable to construction projects at the Company's refineries. The Company
currently anticipates capital expenditures for environmental compliance for the
years 1997 through 1999 of $20 to $40 million per year. Additionally,
appropriate governmental authorities may enforce the laws and regulations with a
variety of civil and criminal enforcement measures, including monetary penalties
and remediation requirements.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as "Superfund," as reauthorized, imposes liability, without regard to
fault or the legality of the original act, for disposal of a "hazardous
substance." Certain subsidiaries of the Company and a company in which Coastal
owns a 50% interest have been named as a PRP in several "Superfund" waste
disposal sites. At the 15 sites for which there is sufficient information, total
clean-up costs are estimated to be approximately $337 million, and the Company
estimates its pro-rata exposure, to be paid over a period of several years, is
approximately $5 million and has made appropriate provisions. At 5 other sites,
the EPA is currently unable to provide the Company with an estimate of total
clean-up costs and, accordingly, the Company is unable to calculate its share of
those costs. Finally, at 9 other sites, the Company has paid amounts to other
PRPs or to the EPA as its proportional share of associated clean-up costs. As to
these latter sites, the Company believes that its activities were de minimis.
Additionally, certain subsidiaries of the Company have been named as PRP's in
two state sites. At one site, the North Carolina Department of Health,
Environment and Natural Resources has estimated the total clean-up costs to be
approximately $50 million, but the Company believes that the subsidiaries'
activities at this site were de minimis. At the other state site, the Florida
Department of Environmental Protection has estimated the total clean-up costs to
be approximately $40,000.
There are additional areas of environmental remediation responsibilities to
which the Company may be subject. The states have regulatory programs that
mandate waste clean-up. The Clean Air Act Amendments of 1990 include new
permitting regulations which will result in increased operating expenditures.
Coastal is also supplying reduced-emission reformulated gasoline in all of its
markets where such gasoline is required.
Future information and developments will require the Company to continually
reassess the expected impact of these environmental matters. However, the
Company has evaluated its total environmental exposure based on currently
available data, including its potential joint and several liability, and
believes that compliance with all applicable laws and regulations will not have
a material adverse impact on the Company's liquidity, consolidated financial
position or results of operations.
Item 2.B. Other Developments.
On June 28, 1996, ANR Iroquois, Inc. ("ANR Iroquois"), a subsidiary of ANR
Pipeline, purchased the stock of Tennessee/New England Pipeline Company, a
subsidiary of Tennessee Gas Pipeline Company ("Tennessee") and the owner of a
13.2% general partnership interest in Iroquois Gas Transmission System, L.P.
("Iroquois"), for approximately $30 million. In accordance with the purchase
agreement with Tennessee, ANR Iroquois has concurrently agreed to sell one half
of the 13.2% interest to CNG Iroquois, Inc. ("CNG"), a unit of Consolidated
Natural Gas Company. That transaction is subject to the receipt of necessary
regulatory approvals by CNG. When it is complete, ANR Pipeline's general
partnership ownership interest in Iroquois would increase from 9.4% to 16%.
Iroquois owns a 370-mile pipeline which transports gas from Canada to the
northeastern United States (the "Iroquois Pipeline"). Iroquois contracted with
Iroquois Pipeline Operating Company ("IPOC") for IPOC to construct and operate
the Iroquois Pipeline. On April 25, 1996, Iroquois acquired all of the
outstanding stock of IPOC; however, IPOC is not controlled by ANR Iroquois.
Federal and state agencies (including the United States Attorney's office for
the Northern District of New York) have been investigating alleged civil and
criminal violations of laws related to the construction and operation of the
Iroquois Pipeline. In May 1996, IPOC was able to effect settlements with the
federal and state agencies resolving those investigations, subject to court
approval. A petition for rehearing is pending before the New York State Public
Service Commission relative to its approval of the settlement with IPOC. Under
the various
- 17 -
<PAGE>
settlements, IPOC, among other things, agreed to the payments of fines,
penalties and other payments, to undertake additional restoration work and to
undertake for a ten-year period, certain monitoring activities with respect to
the pipeline and the pipeline right-of-way. The ultimate impact of the
settlement payments on ANR Iroquois' share of earnings from Iroquois is
approximately $2 million.
In January 1996, CIG announced an open season for interested parties to
request new transportation capacity on its Wind River Lateral. The lateral has a
current capacity of 195,000 Mcf per day and transports natural gas from the Wind
River Basin, where producers have increased natural gas production by more than
25 percent since 1992. On March 29, 1996, CIG filed an application with the FERC
for authority to expand the capacity of the Wind River Lateral by 68 MMcf per
day. The cost of the expansion is estimated to be approximately $10.8 million. A
technical conference was held at the FERC and as a result of that conference,
this application is unopposed by any party. CIG expects that the FERC will act
on the application and issue the requested certificate of public convenience and
necessity in the third or fourth quarter of 1996.
Effective as of June 1, 1996, Pacific Refining Company ("PRC") was
restructured as a wholly-owned, indirect subsidiary of the Company, with the
addition of Coastal Energy Corporation as a 2% general partner and with the
abandonment by the China National Chemicals Import & Export Corporation of its
interest in PRC and its $10 million contribution to capital. The Company is
operating this facility as a crude and product terminal as well as for
purchasing and terminaling asphalt for sales to third parties.
- 18 -
<PAGE>
PART II
OTHER INFORMATION
Item 1. Legal Proceedings.
The information required hereunder is incorporated by reference into Part
II of this Report from Note 6 of the Notes to Consolidated Financial Statements
set forth in Part I of this Report and from Item 2.A., "Management's Discussion
and Analysis of Financial Condition and Results of Operations - Environmental
Matters" set forth in Part I of this Report.
Item 2. Changes in Securities.
None.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
The 1996 Annual Meeting of Stockholders of the Company was held on May 2,
1996. At such meeting all four directors nominated as a Class I director were
elected uncontested: (i) 92,468,055 votes were cast for the election of Harold
Burrow and 350,055 votes were withheld; (ii) 127,545,910 votes were cast for the
election of John M. Bissell and 178,400 votes were withheld; (iii) 127,466,575
votes were cast for the election of Roy D. Chapin, Jr. and 257,735 votes were
withheld; and (iv) 127,336,882 votes were cast for the election of Jerome S.
Katzin and 387,428 votes were withheld.
A stockholder proposal requesting that the Company (a) make a greater
effort to find qualified women and minority candidates for nomination to the
Company's Board of Directors; (b) issue a statement committing the Company to a
policy of board inclusiveness; and (c) issue a report describing the criteria
for board qualification and the process of selecting the board candidates, was
voted upon at such meeting. The stockholder proposal was defeated: 14,475,234
affirmative votes and 102,527,204 negative votes were cast with respect to such
matter. There were also 6,190,836 abstentions and 4,309,415 broker non-votes.
Item 5. Other Information.
None.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits.
11 - Statement re Computation of Per Share Earnings.
27 - Financial Data Schedule.
(b) Reports on Form 8-K.
No reports on Form 8-K were filed during the quarter ended
June 30, 1996.
- 19 -
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this Report to be signed on its behalf by the
undersigned thereunto duly authorized.
THE COASTAL CORPORATION
(Registrant)
Date: August 12, 1996 By: COBY C. HESSE
---------------------------------
Coby C. Hesse
Senior Vice President
and Controller
(As Authorized Officer and
Chief Accounting Officer)
- 20 -
<PAGE>
INDEX TO EXHIBITS
Exhibit
Number Description
- -------------------------------------------------------------------------------
11 Statement Re Computation of Per Share Earnings
27 Financial Data Schedule
- 21 -
<PAGE>
EXHIBIT 11
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT RE COMPUTATION OF PER SHARE EARNINGS
(Millions of Dollars, Except Per Share Amounts,
and Thousands of Shares)
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ---------------------
1996 1995 1996 1995
--------- ---------- --------- ---------
(Unaudited) (Unaudited)
<S> <C> <C> <C> <C>
COMMON STOCK AND EQUIVALENTS:
Net earnings applicable to common stock and
common stock equivalents................................... $ 49.7 $ 52.8 $ 127.9 $ 106.1
========= ========== ========= =========
Average number of common shares outstanding................... 105,079 104,412 104,967 104,382
Class A common shares......................................... 395 413 395 414
Common share equivalents:
$1.19 Cumulative Convertible Preferred, Series A*.......... 223 231 223 231
Dilutive effect of outstanding stock options after
application of treasury stock method*...................... 593 293 561 247
--------- ---------- --------- ---------
Average common and common equivalent shares................... 106,290 105,349 106,146 105,274
========= ========== ========= =========
Net earnings per average common and common equivalent share outstanding:
Earnings before extraordinary item......................... $ .58 $ .50 $ 1.32 $ 1.01
Extraordinary item......................................... (.11) - (.11) -
--------- ---------- --------- ---------
Net earnings............................................... $ .47 $ .50 $ 1.21 $ 1.01
========= ========== ========= =========
ASSUMING FULL DILUTION:
Net earnings applicable to common stock and
common stock equivalents................................... $ 49.7 $ 52.8 $ 127.9 $ 106.1
Dividends applicable to dilutive preferred stock:
Series B................................................... .1 - .1 .1
Series C................................................... - .1 .1 .1
--------- ---------- --------- ---------
Adjusted net earnings assuming full dilution.................. $ 49.8 $ 52.9 $ 128.1 $ 106.3
========= ========== ========= =========
Average number of common shares outstanding................... 105,079 104,412 104,967 104,382
Class A common shares......................................... 395 413 395 414
Common and Class A common share equivalents:
Series A Preferred Stock*.................................. 223 231 223 231
Equivalent common and Class A common shares from
Series B and C Preferred Stock*............................ 518 549 518 549
Dilutive effect of outstanding stock options after
application of treasury stock method*...................... 680 300 680 300
--------- ---------- --------- ---------
Fully diluted shares.......................................... 106,895 105,905 106,783 105,876
========= ========== ========= =========
Fully diluted earnings per share:
Earnings before extraordinary item......................... $ .58 $ .50 $ 1.31 $ 1.00
Extraordinary item......................................... (.11) - (.11) -
--------- ---------- --------- ---------
Net earnings**............................................. $ .47 $ .50 $ 1.20 $ 1.00
========= ========== ========= =========
<FN>
* Convertible securities and options are not considered in the calculations
if the effect of the conversion is anti-dilutive.
** Reporting not required by generally accepted accounting principles because
of small variances from earnings on average common and common equivalent
shares.
</FN>
</TABLE>
- 22 -
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THE SCHEDULE CONTAINS SUMMARY FINANCIAL
INFORMATION EXTRACTED FROM THE COASTAL
CORPORATION FORM 10-Q QUARTERLY REPORT
FOR THE PERIOD ENDED JUNE 30, 1996 AND
IS QUALIFIED IN ITS ENTIRETY BY REFERENCE
TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> JUN-30-1996
<CASH> 55
<SECURITIES> 0
<RECEIVABLES> 1,238
<ALLOWANCES> 0
<INVENTORY> 822
<CURRENT-ASSETS> 2,315
<PP&E> 10,387
<DEPRECIATION> 3,741
<TOTAL-ASSETS> 10,880
<CURRENT-LIABILITIES> 2,301
<BONDS> 3,689
0
3
<COMMON> 37
<OTHER-SE> 2,754
<TOTAL-LIABILITY-AND-EQUITY> 10,880
<SALES> 6,033
<TOTAL-REVENUES> 6,070
<CGS> 4,613
<TOTAL-COSTS> 5,662
<OTHER-EXPENSES> 28
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 191
<INCOME-PRETAX> 189
<INCOME-TAX> 40
<INCOME-CONTINUING> 149
<DISCONTINUED> 0
<EXTRAORDINARY> (12)
<CHANGES> 0
<NET-INCOME> 137
<EPS-PRIMARY> 1.21
<EPS-DILUTED> 1.20
</TABLE>
