UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

 

Washington, D.C. 20549

 

 

FORM 10-Q

 

(Mark One)
ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003
or
o	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 1-3551

 

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý  No  o

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).    Yes  ý  No  o

 

Indicate the number of shares outstanding of each of issuer’s classes of common stock, as of the latest practicable date.

 

 

 

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

 

Index

 

Part I.   Financial Information:
	Item 1.	Financial Statements (Unaudited):
		Statements of Consolidated Income for the Three and Six Months Ended June 30, 2003 and 2002
		Statements of Condensed Consolidated Cash Flows for the Three and Six Months Ended June 30, 2003 and 2002
		Condensed Consolidated Balance Sheets as of June 30, 2003 and December 31, 2002
		Notes to Condensed Consolidated Financial Statements
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk
	Item 4.	Controls and Procedures
Part II.  Other Information:
	Item 4.	Submission of Matters to a Vote of Security Holders
	Item 5.	Other Information
	Item 6.	Exhibits and Reports on Form 8-K
Signature
Index to Exhibits

 

 

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

 

Statements of Consolidated Income (Unaudited)

 

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
		(Thousands, except per share amounts)
Operating revenues		$	218,496		$	226,671		$	560,818		$	520,714
Cost of sales		86,426			102,653			240,396			235,820
Net operating revenues		132,070			124,018			320,422			284,894
Operating expenses:
Operation and maintenance		18,601			18,412			37,456			35,996
Production and exploration		8,624			6,391			17,786			12,841
Selling, general and administrative		28,803			23,091			61,065			48,948
Impairment of long-lived assets		—			5,320			—			5,320
Depreciation, depletion and amortization		19,225			16,771			37,978			33,538
Total operating expenses		75,253			69,985			154,285			136,643
Operating income		56,817			54,033			166,137			148,251
Charitable contribution expense		—			—			(9,279		)	—
Equity earnings (losses) from nonconsolidated investments:
Westport		—			(625		)	3,614			(4,873		)
Other		1,519			432			2,751			2,063
		1,519			(193		)	6,365			(2,810		)
Minority interest		—			(1,949		)	(871		)	(3,399		)
Interest expense		10,782			9,259			23,103			18,838
Income from continuing operations before income taxes and cumulative effect of accounting change		47,554			42,632			139,249			123,204
Income taxes		16,159			13,443			43,375			41,643
Income from continuing operations before cumulative effect of accounting change		31,395			29,189			95,874			81,561
Income from discontinued operations		—			9,000			—			9,000
Cumulative effect of accounting change, net of tax		—			—			(3,556		)	(5,519		)
Net income		$	31,395		$	38,189		$	92,318		$	85,042
Earnings per share of common stock:
Basic:
Weighted average common shares outstanding		62,058			63,280			62,056			63,421
Income from continuing operations before cumulative effect of accounting change		$	0.51		$	0.46		$	1.55		$	1.29
Income from discontinued operations		—			0.14			—			0.14
Cumulative effect of accounting change, net of tax		—			—			(0.06		)	(0.09		)
Net income		$	0.51		$	0.60		$	1.49		$	1.34
Diluted:
Weighted average common shares outstanding		63,420			64,999			63,382			65,033
Income from continuing operations before cumulative effect of accounting change		$	0.50		$	0.45		$	1.52		$	1.25
Income from discontinued operations		—			0.14			—			0.14
Cumulative effect of accounting change, net of tax		—			—			(0.06		)	(0.08		)
Net income		$	0.50		$	0.59		$	1.46		$	1.31
Dividends declared per common share		$	0.30		$	0.17		$	0.50		$	0.34

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

2

 

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

 

Statements of Condensed Consolidated Cash Flows (Unaudited)

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
		(Thousands)
Cash flows from operating activities:
Income from continuing operations before cumulative effect of accounting change		$	31,395		$	29,189		$	95,874		$	81,561
Adjustments to reconcile income from continuing operations before cumulative effect of accounting change to net cash provided by operating activities:
Provision for doubtful accounts		1,214			760			8,879			5,029
Depreciation, depletion, and amortization		19,225			16,771			37,978			33,538
Impairment of assets		—			5,320			—			5,320
Charitable contribution		—			—			9,279			—
Deferred income taxes provision		29,190			10,055			40,309			12,255
Recognition of monetized production revenue		(13,888		)	(13,888		)	(27,624		)	(27,624		)
(Increase) decrease in undistributed earnings from nonconsolidated investments		(1,519		)	252			(6,365		)	3,536
Changes in other assets and liabilities		1,865			34,523			(12,827		)	62,936
Total adjustments		36,087			53,793			49,629			94,990
Net cash provided by operating activities		67,482			82,982			145,503			176,551
Cash flows from investing activities:
Capital expenditures		(57,785		)	(49,644		)	(90,635		)	(86,716		)
Purchase of minority interest in ABP		—			—			(44,200		)	—
Decrease in restricted cash		—			61,760			—			62,956
Decrease in equity of unconsolidated entities		—			192			—			973
Proceeds from sale of property		—			—			6,550			—
Net cash (used in) provided by investing activities		(57,785		)	12,308			(128,285		)	(22,787		)
Cash flows from financing activities:
Issuance of long-term debt		—			—			200,000			—
Dividends paid		(12,262		)	(10,702		)	(22,847		)	(20,783		)
Proceeds from exercises under employee compensation plans		9,744			7,463			18,527			9,703
Purchase of treasury stock		(18,651		)	(27,195		)	(34,831		)	(44,867		)
Loans against construction contracts		6,301			3,430			10,270			8,229
Repayments and retirement of long-term debt		—			(158		)	(15,167		)	(315		)
Redemption of Trust Preferred Capital Securities		(125,000		)	—			(125,000		)	—
Decrease in short-term loans		7,206			(64,205		)	(42,800		)	(128,911		)
Net cash used in financing activities		(132,662		)	(91,367		)	(11,848		)	(176,944		)
Net (decrease) increase in cash and cash equivalents		(122,965		)	3,923			5,370			(23,180		)
Cash and cash equivalents at beginning of period		146,083			2,519			17,748			29,622
Cash and cash equivalents at end of period		$	23,118		$	6,442		$	23,118		$	6,442
Cash paid during the period for:
Interest, net of amount capitalized		$	10,495		$	5,663		$	22,482		$	18,169
Income taxes paid, net of refund		$	8,942		$	12,736		$	10,045		$	11,707

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

3

 

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

 

Condensed Consolidated Balance Sheets (Unaudited)

 

		June 30, 2003			December 31, 2002
		(Thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	23,118		$	17,748
Accounts receivable (less accumulated provision for  doubtful accounts:  2003, $15,779; 2002, $15,294)		145,551			160,778
Unbilled revenues		103,998			130,348
Inventory		99,091			74,735
Derivative commodity instruments, at fair value		41,574			38,512
Prepaid expenses and other		7,464			7,930
Total current assets		420,796			430,051
Equity in nonconsolidated investments		105,489			245,792
Property, plant and equipment		2,678,885			2,545,138
Less accumulated depreciation and depletion		990,992			983,323
Net property, plant andequipment		1,687,893			1,561,815
Investments, available-for-sale		313,399			16,098
Other assets		189,755			183,135
Total		$	2,717,332		$	2,436,891

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

4

 

 

		June 30, 2003			December 31, 2002
		(Thousands)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt		$	30,259		$	24,250
Current portion of nonrecourse project financing		15,888			16,055
Short-term loans		63,200			106,000
Accounts payable		129,850			136,478
Prepaid gas forward sale		38,444			55,705
Derivative commodity instruments, at fair value		195,198			46,768
Current portion of project financing obligations		67,754			73,032
Other current liabilities		95,296			93,452
Total current liabilities		635,889			551,740
Long-term debt:
Debentures and medium-term notes		628,689			447,000
Deferred and other credits:
Deferred income taxes		401,585			350,690
Deferred investment tax credits		12,676			13,210
Prepaid gas forward sale		31,228			41,591
Project financing obligations		13,772			13,684
Other credits		151,092			115,337
Total deferred and other credits		610,353			534,512
Preferred trust securities		—			125,000
Capitalization:
Common stockholders’ equity:
Common stock, no par value, authorized 160,000 shares;  shares issued: June 30, 2003 and December 31, 2002, 74,504		340,415			287,597
Treasury stock, shares at cost: June 30, 2003, 12,173; December 31, 2002, 12,162 (net of shares and cost held in trust for deferred compensation of 604, $11,357 and 642, $12,273)		(287,307		)	(271,930		)
Retained earnings		856,976			787,505
Accumulated other comprehensive loss, net of tax		(67,683		)	(24,533		)
Total common stockholders’ equity		842,401			778,639
Total		$	2,717,332		$	2,436,891

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

5

 

Equitable Resources, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

 

A.                        Financial Statements

 

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X.  Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements.  In the opinion of management, these statements include all adjustments (consisting of only normal recurring accruals, unless otherwise disclosed in this Form 10-Q) necessary for a fair presentation of the financial position of Equitable Resources, Inc. and subsidiaries (the Company or Equitable Resources or Equitable) as of June 30, 2003, and the results of its operations and cash flows for the three and six month periods ended June 30, 2003 and 2002.

 

The balance sheet at December 31, 2002 has been derived from the audited financial statements at that date but does not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements.

 

Due to the seasonal nature of the Company’s natural gas distribution and energy marketing businesses and the volatility of natural gas prices, the interim statements for the three and six month periods ended June 30, 2003 are not necessarily indicative of the results that may be expected for the year ending December 31, 2003.

 

For further information, refer to the consolidated financial statements and footnotes thereto included in Equitable Resources’ Annual Report on Form 10-K for the year ended December 31, 2002 as well as in “Information Regarding Forward Looking Statements” on page 19 of this document.

 

As previously disclosed, the Securities and Exchange Commission (SEC) is conducting an ordinary course review of the Company’s periodic filings in connection with the filing of a Registration Statement on Form S-4 for the exchange of the Company’s privately placed 5.15% Notes due 2018.  As part of these ongoing discussions with the SEC, the Company has reviewed its accounting for certain items, and has corrected its accounting treatment.  The Company believes the changes have no significant impact on historical Consolidated Statements of Operations or Balance Sheets.  The adjustments recorded at June 30, 2003 relate to the following items:

 

Accounting for the Company’s equity investment in Westport

 

On April 10, 2000, the Company merged its Gulf of Mexico operations with Westport Oil and Gas Company for a minority interest in the combined company, named Westport Resources Corporation (Westport).  In light of the Company's 49% interest in the combined company, the Company adopted the equity method of accounting to record its investment in Westport.

 

As previously disclosed, the Company’s ownership percentage in Westport decreased through several Westport capital transactions with third parties (such as mergers and equity issuances), in which the Company did not participate.  The Company’s policy is not to recognize gains from the impact of these capital transactions.  Historically, the Company did not recognize increases to its equity investment in Westport for Westport capital transactions.  The accounting treatment required for the Westport capital transactions under the equity method would be to record the change to the investment in Westport and record the offsetting amount to the equity section of the Consolidated Balance Sheet as a component of common stock.  The financial statement impact of the Westport capital transactions, though diluting the Company’s ownership percentage in Westport, increased the book value of Westport’s equity and, similarly, increased the book basis of the Company’s equity method investment in Westport.

 

As of March 31, 2003, the Company began recording its investment in Westport as an available-for-sale security under Statement of Financial Accounting Standards (SFAS) No. 115 “Accounting for Certain Investments in Debt and Equity Securities” (Statement No. 115) rather than under the equity method of accounting.  The Company recorded a mark-to-market adjustment, net of tax, through accumulated other comprehensive income in the Consolidated Balance Sheet.  Had the Company increased the book basis of its investment in Westport while under the equity method of accounting, the initial mark-to-market entry would have recorded $52.9 million less in accumulated other comprehensive income, because the book basis just before that entry would have already been higher by that same $52.9 million.

 

6

 

As of June 30, 2003, the Company recorded a reclassification adjustment of $52.9 million to reduce accumulated other comprehensive income and increase common stock to reflect the increases in the book basis of the Company’s investment in Westport from the Westport capital transactions.  Therefore, the total mark-to-market basis of the Westport investment is unchanged as of June 30, 2003, but the increase in common stock value will prospectively reduce any realized gains on the sale of Westport stock by the Company due to the increase in book basis to $16.53 per share, from $10.25 per share.  There will be no additional impact to the ongoing Statement No. 115 mark-to-market adjustments as a result of the Westport capital transactions.

 

Accounting for the Company’s equity investment in Hunterdon Cogeneration Partnership LP (Hunterdon)

 

The Company has reevaluated its interest in Hunterdon and concluded that the Company effectively controls Hunterdon for consolidation purposes.  As a result, the Company began consolidating Hunterdon’s financial position, results of operations and cash flows as of June 30, 2003.  Hunterdon is considered part of the NORESCO segment.

 

The consolidation of Hunterdon removes the equity investment in Hunterdon of $2.5 million and increases minority interest by $2.5 million in the Condensed Consolidated Balance Sheet.  As of June 30, 2003, Hunterdon had $9.3 million of total assets, and $4.1 million of total liabilities, including $2.7 million of long-term debt of which $0.5 million is current.

 

Statement of Cash Flow treatment for prepaid gas forward sales

 

In the Company’s Statement of Cash Flows, the accounting presentation of the prepaid gas forward sales at the time the transactions were consummated was to reflect the activity as an operating cash flow item.  Consistent with the Company's previous presentation, the current presentation includes recognition of monetized production revenues related to prepaid forward gas sales in operating activities. The amount for the three months ended June 30, 2003 and 2002 is $13.9 million and is $27.6 million for the six month periods then ended. The operating activities for the years ended December 31, 2002 and 2001 include a reduction of $55.8 million for the recognition of monetized production revenues and include an increase of $209.3 million for the year ended December 31, 2000 for the receipt of cash. However, due to the complexity and different market variations of these types of transactions, the SEC has required other prepaid forward transactions of other issuers to be reflected as a financing activity in the Statement of Cash Flows.

 

 

The Company expects the SEC’s review to be finalized in the third quarter of 2003.  It is possible that the finalization of this review may lead to other necessary changes, including the possible restatement of the Company’s historical financial statements to reflect the foregoing changes.  The changes discussed herein are consistent with our best current knowledge of this review process.

 

B.                        Segment Information

 

The Company reports its operations in three segments, which reflect its lines of business.  Equitable Utilities’ operations comprise the sale and transportation of natural gas to customers at state-regulated rates, interstate pipeline transportation and storage of natural gas subject to federal regulation, the unregulated marketing of natural gas, and limited trading activities.  The Equitable Supply segment’s activities are comprised of the development, production, gathering, marketing and sale of natural gas and a small amount of associated oil, and the extraction and sale of natural gas liquids.  The NORESCO segment’s activities are comprised of an integrated group of energy-related products and services that are designed to reduce its customers’ operating costs and improve their energy efficiency, including combined heat and power and central boiler/chiller plant development, design, construction, ownership and operation; performance contracting; and energy efficiency programs.

 

Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income, equity earnings in nonconsolidated investments, excluding Westport, and minority interest.  Interest charges and income taxes are managed on a consolidated basis.  Headquarters’ costs are billed to the operating segments based upon a fixed allocation of the headquarters’ annual operating budget.  Differences between budget and actual headquarters’ expenses are not allocated to the operating segments.

 

7

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
		(Thousands)
Revenues from external customers: (a)
Equitable Utilities		$	115,620		$	148,960		$	351,729		$	372,711
Equitable Supply		79,385			68,028			161,082			134,430
NORESCO		42,580			46,494			88,098			81,933
Less: intersegment revenues (b)		(19,089		)	(36,811		)	(40,091		)	(68,360		)
Total		$	218,496		$	226,671		$	560,818		$	520,714
Depreciation, depletion and amortization:
Equitable Utilities		$	6,789		$	6,587		$	13,524		$	13,105
Equitable Supply		12,019			9,711			23,601			19,470
NORESCO		341			444			690			881
Headquarters		76			29			163			82
Total		$	19,225		$	16,771		$	37,978		$	33,538
Operating income:
Equitable Utilities		$	12,728		$	15,080		$	71,755		$	68,555
Equitable Supply		45,767			40,711			94,180			79,356
NORESCO		2,432			(978		)	6,353			1,643
Unallocated expenses		(4,110		)	(780		)	(6,151		)	(1,303		)
Total operating income		$	56,817		$	54,033		$	166,137		$	148,251
Reconciliation of operating income to net income:
Equity earnings in nonconsolidated investments, excluding Westport:
Equitable Supply		$	24		$	66		$	262		$	118
NORESCO		1,452			366			2,389			1,945
Unallocated earnings		43			—			100			—
Total		$	1,519		$	432		$	2,751		$	2,063
Minority interest		$	—		$	(1,949	)	$	(871	)	$	(3,399	)
Charitable contribution expense		—			—			(9,279		)	—
Westport equity (losses) earnings		—			(625		)	3,614			(4,873		)
Interest expense		10,782			9,259			23,103			18,838
Income tax expense		16,159			13,443			43,375			41,643
Income from continuing operations before cumulative effect of accounting change		31,395			29,189			95,874			81,561
Income from discontinued operations		—			9,000			—			9,000
Cumulative effect of accounting change, net of tax (c)		—			—			(3,556		)	(5,519		)
Net income		$	31,395		$	38,189		$	92,318		$	85,042

 

		June 30, 2003			December 31, 2002
		(Thousands)
Segment Assets:
Equitable Utilities		$	911,088		$	929,718
Equitable Supply		1,147,287			1,079,924
NORESCO (d)		260,979			269,707
Total operating segments		2,319,354			2,279,349
Headquarters assets		397,978			157,542
Total		$	2,717,332		$	2,436,891

 

8

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
		(Thousands)
Expenditures for segment assets:
Equitable Utilities		$	14,708		$	12,985		$	23,376		$	22,305
Equitable Supply (e)		42,767			36,476			110,505			64,047
NORESCO		98			183			146			364
Unallocated expenditures		212			—			808			—
Total		$	57,785		$	49,644		$	134,835		$	86,716

 

(a)          Operating revenues for prior periods have been reduced to conform with EITF No. 02-3.  See Note J.

(b)         Intersegment revenues represents sales from Equitable Supply to the unregulated marketing affiliate of Equitable Utilities, which marketed all of the Equitable Supply production in 2002.  In 2003, Equitable Supply assumed the marketing of a substantial portion of its operated volumes and recorded the marketing activity directly.

(c)          Net income for the six months ended June 30, 2003 and 2002 has been adjusted to reflect the cumulative effect of an accounting change related to the adoption of Statement No. 143 and No. 142, respectively.  See Note J for additional information.

(d)         The Company’s goodwill balance as of June 30, 2003 and as of December 31, 2002 totaled $51.7 million and is entirely related to the NORESCO segment.  See Note J.

(e)          2003 expenditures include $44.2 million for the acquisition of the remaining 31% limited partner interest in Appalachian Basin Partners, LP.  See Note H.

 

C.                        Contract Receivables

 

The Company, through its NORESCO segment, enters into construction contracts with governmental and institutional counterparties whereby those counterparties finance the construction directly with the Company at prevailing market interest rates.  In order to accelerate cash collections and manage working capital requirements, the Company transfers these contract receivables due from customers to financial institutions.  The transfer price of the contract receivables is based on the face value of the executed contract with the financial institution.  The gain or loss on the sale of contract receivables is the difference between the existing carrying amount of the financial assets involved in the transfer and the transfer price of the contract with the financial institution.

 

Certain of these transfers do not immediately qualify as “sales” under SFAS No. 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities” (Statement No. 140).  For the contract receivables that are transferred and still controlled by the Company, a liability is established to offset the cash received from the transfer.  This liability is recognized until control has been surrendered in accordance with Statement No. 140, as the cash received by the Company can be called by the financial institution at any time until the Company’s ongoing involvement in the receivables concludes.  The Company de-recognizes the receivables and the liabilities when control has been surrendered in accordance with the criteria provided in Statement No. 140.  The Company does not retain any interests in the contract receivables once the sale is complete.  As of June 30, 2003, the Company had recorded a current liability of $67.8 million classified as current project financing obligations and a long-term liability of $13.8 million classified as project financing obligations on the Condensed Consolidated Balance Sheets.  The current project financing obligations represent transfers for which control is expected to be surrendered, or cash could be called, within one year.  The related assets are classified as unbilled revenues while construction progresses and as other assets upon completion of construction.

 

For the quarter ended June 30, 2003, approximately $4.5 million of the contract receivables met the criteria for sales treatment, generating a recognized gain of $0.1 million.  The de-recognition of the $4.5 million in receivables and the related liabilities is a non-cash transaction and is consequently not reflected in the Statements of Condensed Consolidated Cash Flows.

 

9

 

D.                        Derivative Instruments

 

Accounting Policy

 

Derivatives are held as part of a formally documented risk management program.  The Company’s risk management activities are subject to the management, direction and control of the Company’s Corporate Risk Committee (CRC).  The CRC reports to the Company’s Board of Directors and is comprised of the chief executive officer, the chief financial officer and other officers and employees.

 

The Company’s risk management program includes the use of exchange-traded natural gas futures contracts and options and over-the-counter (OTC) natural gas swap agreements and options (collectively referred to as derivative contracts) to hedge exposures to fluctuations in natural gas prices and for trading purposes.  The Company’s risk management program also includes the use of interest rate swap agreements to hedge exposures to fluctuations in interest rates.  At contract inception, the Company designates its derivative instruments as hedging or trading activities.  All derivative instruments are accounted for in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement No. 133), as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of Financial Accounting Standards Board Statement No. 133”  (Statement No. 137) and by SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” (Statement No. 138).  As a result, the Company recognizes all derivative instruments as either assets or liabilities and measures the effectiveness of the hedges, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at fair value.  The measurement of fair value is based upon actively quoted market prices when available.   In the absence of actively quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry publications.  If pricing information from external sources is not available, measurement involves judgment and estimates.  These estimates are based upon valuation methodologies deemed appropriate by the Company’s CRC.

 

The various derivative commodity instruments used by the Company to hedge its exposure to variability in expected future cash flows associated with the fluctuations in the price of natural gas related to the Company’s forecasted sale of equity production and forecasted natural gas purchases and sales have been designated and qualify as cash flow hedges.  Futures contracts obligate the Company to buy or sell a designated commodity at a future date for a specified price and quantity at a specified location.  Swap agreements involve payments to or receipts from counterparties based on the differential between a fixed and variable price for the commodity.  Exchange-traded instruments are generally settled with offsetting positions but may be settled by delivery or receipt of commodities.  OTC arrangements require settlement in cash.  The fair value of these derivative commodity instruments was a $41.3 million asset and a $195.2 million liability as of June 30, 2003, and a $30.9 million asset and a $25.0 million liability as of December 31, 2002.  These amounts are classified in the Condensed Consolidated Balance Sheets as derivative commodity instruments, at fair value.  The decrease in the net amount of derivative commodity instruments, at fair value, from December 31, 2002 to June 30, 2003 is primarily the result of the increase in natural gas prices.  The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as cash flow hedges total 344.8 Bcf and 265.1 Bcf as of June 30, 2003 and December 31, 2002, respectively, and primarily relate to natural gas swaps.  The open swaps at June 30, 2003 have maturities extending through December 2010.

 

The Company deferred a net loss of $94.1 million and a gain of $2.8 million in accumulated other comprehensive loss, net of tax, as of June 30, 2003 and December 31, 2002, respectively, associated with the effective portion of the change in fair value of its derivative commodity instruments designated as cash flow hedges.  Assuming no change in price or new transactions, the Company estimates that approximately $49.0 million of unrealized losses on its derivative commodity instruments reflected in accumulated other comprehensive loss, net of tax, as of June 30, 2003 will be recognized in earnings during the next twelve months due to the physical settlement of hedged transactions.

 

For the three months ended June 30, 2003 and 2002, ineffectiveness associated with the Company’s derivative commodity instruments designated as cash flow hedges (decreased) increased earnings by approximately ($1.7 million) and $0.1 million, respectively.  The ineffectiveness associated with the Company’s derivative commodity instruments is primarily the result of delivery points contained within the derivative instruments that are different than where the actual gas is physically delivered.  These amounts are included in operating revenues in the Statements of Consolidated Income.

 

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The Company conducts trading activities with derivative commodity instruments primarily through its unregulated marketing group.  The function of the Company’s trading business is to contribute to the Company’s earnings by taking market positions within defined limits subject to the Company’s corporate risk management policy.

 

At June 30, 2003, the absolute notional quantities of the futures and swaps held for trading purposes totaled 1.3 Bcf and 6.1 Bcf, respectively.

 

Below is a summary of the activity of the fair value of the Company’s derivative contracts with third parties held for trading purposes during the six months ended June 30, 2003 (in thousands).  The fair value of these contracts as of June 30, 2003 is insignificant to the consolidated financial position, results of operations and cash flows of the Company.

 

Fair value of contracts outstanding as of December 31, 2002		$	6,623
Contracts realized or otherwise settled		(117		)
Other changes in fair value (a)		(6,230		)
Fair value of contracts outstanding as of June 30, 2003		$	276

 

(a)          This amount includes a decrease of $7.2 million related to the adoption of EITF No. 02-3 which is no longer included as trading activity.  This change had no effect on other comprehensive income as the amount was fully reserved.  There were no other adjustments to the fair value of the Company’s derivative contracts held for trading purposes relating to changes in valuation techniques and assumptions during the six months ended June 30, 2003.

 

The following table presents maturities and the fair valuation source for the Company’s derivative commodity instruments that are held for trading purposes as of June 30, 2003.

 

Net Fair Value of Third Party Contract Assets (Liabilities) at Period-End

 

Source of Fair Value		Maturity Less than 1 Year			Maturity 1-3 Years			Maturity 3-5 Years			Total Fair Value
		(Thousands)
Prices actively quoted (NYMEX)(1)		$	59		$	51		$	—		$	110
Prices provided by other external sources (2)		125			4			37			166
Net derivative assets		$	184		$	55		$	37		$	276

 

(1) Contracts include futures and fixed price swaps

(2) Contracts include basis swaps

 

The overall portfolio of the Company’s energy derivatives held for risk management purposes approximates the notional quantity of the expected or committed transaction volume of physical commodities with commodity price risk for the same time periods.  Furthermore, the energy derivative portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits.  Therefore, an adverse impact to the fair value of the portfolio of energy derivatives held for risk management purposes associated with the hypothetical changes in commodity prices referenced above would be offset by a favorable impact on the underlying hedged physical transactions, assuming the energy derivatives are not closed out in advance of their expected term, the energy derivatives continue to function effectively as hedges of the underlying risk, and, as applicable, anticipated transactions occur as expected.

 

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E.             Investments

 

The Company owns approximately 13 million shares, or 19.5% of Westport, which decreased from 20.8% at the end of 2002.  The Company does not have operational control of Westport.  The decrease in the Company’s ownership in Westport is a result of the Company’s donation of 905,000 shares of Westport stock to a community giving foundation on March 31, 2003.  The foundation was established by the Company and is projected to facilitate the Company’s charitable giving program for approximately 10 years.  The contribution resulted in charitable contribution expense of $9.3 million with a corresponding one-time tax benefit of approximately $7.1 million (see Note I).

 

As a result of the decreased ownership, the Company changed the accounting treatment for its investment in the first quarter of 2003 from the equity method to available-for-sale, effective March 31, 2003.  The change in accounting method eliminated the inclusion of Westport’s results subsequent to March 31, 2003 in the Company’s earnings.  Also, the Company’s investment in Westport was reclassified to Investments, available-for-sale on the Condensed Consolidated Balance Sheet as of March 31, 2003, and was adjusted to fair market value, in accordance with Statement No. 115.  The equity investment at the time it was reclassified totaled $134.1 million.  The fair market value of the Company’s investment in Westport was $295.9 million as of June 30, 2003 and was calculated based upon the quoted market price of Westport as of June 30, 2003.  If the Company were to immediately liquidate its investment position in Westport, it would likely be at some discount to the quoted market price.  The increase in the carrying value of the investment of $161.8 million represents an unrealized gain recorded net of tax in accumulated other comprehensive income.  As described in Note A, as of June 30, 2003, the Company recorded a reclassification adjustment of $52.9 million to reduce accumulated other comprehensive income and increase common stock to reflect the increases in the book basis of the Company’s investment in Westport from previous Westport capital transactions.  Therefore, the total mark-to-market basis of the Westport investment is unchanged as of June 30, 2003, but the increase in common stock value will prospectively reduce any realized gains on the sale of Westport stock by the Company due to the increase in book basis to $16.53 per share, from $10.25 per share.  There will be no additional impact to the ongoing Statement No. 115 mark-to-market adjustments as a result of the Westport capital transactions.

 

The investments classified by the Company as available-for-sale also include approximately $17.5 million of debt and equity securities intended to fund plugging and abandonment and other liabilities for which the Company self-insures.  The Company utilizes the specific identification method to determine the cost of securities sold.  The net unrealized holding losses related to these securities as of June 30, 2003 and December 31, 2002 totaled $0.2 million and $1.5 million, respectively and are included net of tax in accumulated other comprehensive income.  There were no realized gains or losses associated with the investments during the six months ended June 30, 2003.  As of December 31, 2002, the Company performed an impairment analysis in accordance with Statement No. 115 and concluded that the decline below cost is not other-than-temporary.  Factors and considerations the Company used to support this conclusion (as more fully described in the Company’s 2002 Form 10K) have not changed in the second quarter 2003.

 

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F.             Comprehensive Income (Loss)

 

Total comprehensive (loss) income, net of tax, was as follows:

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
		(Thousands)
Net income		$	31,395		$	38,189		$	92,318		$	85,042
Other comprehensive (loss) income:
Net change in cash flow hedges:
Natural gas (Note D)		(71,778		)	(22,128		)	(96,838		)	(80,082		)
Interest rate		30			—			73			—
Unrealized (loss) gain on available-for-sale securities:
Westport (Note E) (a)		(31,130		)	—			52,329			—
Other (Note E)		1,455			—			1,286			(574		)
Total comprehensive (loss) income		$	(70,028	)	$	16,061		$	49,168		$	4,386

 

(a)  Includes a reclassification of $52.9 million to common stock as discussed in Note A.

 

The components of accumulated other comprehensive (loss) income are as follows, net of tax:

 

		June 30, 2003			December 31, 2002
		(Thousands)
Net unrealized (loss) gain from hedging transactions		$	(95,148	)	$	1,617
Unrealized gain (loss) on available-for-sale securities		52,121			(1,494		)
Minimum pension liability adjustment		(24,663		)	(24,663		)
Foreign currency translation adjustment		7			7
		$	(67,683	)	$	(24,533	)

 

G.            Stock-Based Compensation

 

On February 27, 2003, the Company granted 439,400 stock units for the 2003 Executive Performance Incentive Share Plan.  The 2003 Plan was established to provide additional incentive benefits to retain senior executives of the Company and to further align the persons primarily responsible for the success of the Company with the interests of the shareholders.  The vesting of these units will occur on December 31, 2005, contingent upon the level of total shareholder return relative to the following 30 peer companies and will result in the distribution of zero to 878,800 units (200% of the units).

 

 

Under the 2003 Plan, the 30 peer companies may be adjusted by the Compensation Committee of the Company’s Board of Directors based on significant or unusual transactions or events that substantially affect the total shareholder return calculation of any company or that, for operational or non-operational reasons, do not reflect or otherwise skew the relevant performance metric intended to be measured.  The Company uses different peer groups for other purposes.

 

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The Company anticipates, based on current estimates, that a certain level of performance will be met and has expensed a ratable estimate of the units accordingly.  The expense for the three and six month periods ended June 30, 2003 was $3.9 million and $6.5 million, respectively, and is classified as selling, general and administrative expense.  These amounts were not allocated to the Company’s operating segments.  The stock units will not be dilutive to the Company’s share count as the value of the stock units will be paid in cash at the vesting date.

 

A restricted stock grant in the amount of 70,510 shares was also awarded to various employees during the first quarter of 2003.  The related expense recognized during the three and six month periods ended June 30, 2003 was $0.1 million and $0.2 million, respectively, and is classified as selling, general and administrative expense.

 

Additionally, 0.5 million stock options were awarded during the six months ended June 30, 2003.  The Company applies Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations in accounting for its stock-based compensation and has consequently not recognized any compensation cost for its stock option awards.

 

The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation” (Statement No. 123), to its employee stock-based awards.

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
		(Thousands)
Net income, as reported		$	31,395		$	38,189		$	92,318		$	85,042
Add:  Stock-based employee compensation expense included in reported net income, net of related tax effects		3,990			364			6,894			719
Deduct: Total stock-based employee compensation expense determined by the fair value method for all awards, net of related tax effects		(5,676		)	(2,400		)	(10,404		)	(4,025		)
Pro forma net income		$	29,709		$	36,153		$	88,808		$	81,736
Earnings per share:
Basic, as reported		$	0.51		$	0.60		$	1.49		$	1.34
Basic, pro forma		$	0.48		$	0.57		$	1.43		$	1.29
Diluted, as reported		$	0.50		$	0.59		$	1.46		$	1.31
Diluted, pro forma		$	0.47		$	0.56		$	1.40		$	1.26

 

H.            Appalachian Basin Partners, LP

 

In November 1995, the Company monetized Appalachian gas properties qualifying for the nonconventional fuels tax credit to a partnership, Appalachian Basin Partners, LP (ABP).  The Company recorded the proceeds as deferred revenue, which was recognized as production occurred.  The Company retained a partnership interest in the properties that increased substantially based on the attainment of a performance target.  The performance target was met near the end of 2001.  The Company consolidated the partnership starting in 2002, and the remaining portion not owned by the Company was recorded as minority interest.

 

In February 2003, the Company purchased the remaining 31% limited partnership interest in ABP from the minority interest holders for $44.2 million.  The limited partnership interest represents approximately 60.2 Bcf of reserves.  As a result, effective February 1, 2003, the Company no longer recognizes minority interest expense associated with ABP, which totaled $1.9 million for the three months ended June 30, 2002, and $0.9 million and $3.4 million for the six months ended June 30, 2003 and 2002, respectively.

 

I.              Income Taxes

 

The Company estimates an annual effective income tax rate, based on projected results for the year, and applies this rate to income before taxes to calculate income tax expense.  Any refinements made due to subsequent information, which affects the estimated annual effective income tax rate, are reflected as adjustments in the current period.  Separate effective income tax rates are calculated for net income from continuing operations, discontinued operations and cumulative effects of accounting changes.  As a result of the donation on March 31, 2003 of appreciated shares of

 

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Westport Resources Corporation to a charitable foundation created by the Company (see Note E), the Company reported a one-time tax benefit of approximately $7.1 million.  A gift of qualified appreciated stock allows for a tax deduction based on the fair market value of the gifted stock, resulting in a permanent difference between financial and tax reporting income that reduces the effective income tax rate.  A permanent tax benefit of $3.9 million resulted in a decrease of the Company’s 34.0% estimated annual effective income tax rate for net income from continuing operations for the six months ended June 30, 2003 to the Company’s 31.1% estimated effective income tax rate recorded during that period.

 

J.             Recently Adopted Accounting Standards

 

Asset Retirement Obligations

 

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143 “Accounting for Asset Retirement Obligations” (Statement No. 143).  Statement No. 143 was adopted by the Company effective January 1, 2003, and its primary impact was to change the method of accruing for well plugging and abandonment costs.  These costs were formerly recognized as a component of depreciation, depletion and amortization (DD&A) expense with a corresponding credit to accumulated depletion in accordance with SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (Statement No. 19).  At the end of 2002, the cumulative liability was approximately $20.9 million.  Under Statement No. 143, the fair value of the asset retirement obligations will be recorded as liabilities when they are incurred, which is typically at the time the wells are drilled.  Amounts recorded for the related assets will be increased by the amount of these obligations. Over time the liabilities are accreted for the change in their present value, through charges to operating expense, and the initial capitalized costs are depleted over the useful lives of the related assets.

 

The adoption of Statement No. 143 by the Company resulted in a one-time, net of tax charge to earnings of $3.6 million, or $0.06 per diluted share, during the six months ended June 30, 2003, which is reflected as a cumulative effect of accounting change in the Company’s Statements of Consolidated Income.  In addition to the one-time charge to earnings, the depletion rate in the Company’s Supply segment increased by $0.03 per Mcfe.

 

The Company also recognized a $28.7 million other long-term liability and a $2.3 million long-term asset upon adoption of Statement No. 143.  The long-term obligation relates to the estimated future expenditures required to plug and abandon the Company’s approximately 12,000 wells in Appalachia.  These wells will incur plugging and abandonment costs over an extended period of time, significant portions of which are not projected to occur for over 40 years.  Additionally, the Company does not have any assets that are legally restricted for purposes of settling the asset retirement obligation.

 

The following table presents a reconciliation of the beginning and ending carrying amounts of the asset retirement obligations:

 

		Three months ended June 30, 2003			Six months ended June 30, 2003
		(Thousands)
Asset retirement obligation as of beginning of period		$	29,182		$	28,690
Accretion expense		484			965
Liabilities incurred		98			109
Liabilities settled		(46		)	(46		)
Asset retirement obligation as of end of period		$	29,718		$	29,718

 

Assuming retroactive application of the change in accounting principle as of January 1, 2002, the pro forma effect of applying this new accounting principle on a retroactive basis would not materially change reported net income for the three and six month periods ended June 30, 2002.  Long-term liabilities, assuming retroactive application of the change in accounting principle as of January 1, 2002 and June 30, 2002, would have increased by $26.9 million and $27.7 million, respectively.

 

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Goodwill and Other Intangible Assets

 

In July 2001, the FASB issued SFAS No. 142, “Goodwill and Other Intangible Assets” (Statement No. 142), which was effective for the Company beginning in fiscal year 2002.  Under Statement No. 142, goodwill and intangible assets with indefinite lives are no longer amortized but are reviewed at least annually for impairment.  Separable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives.

 

In accordance with the requirements of Statement No. 142, the Company tested its goodwill for impairment as of January 1, 2002.  The fair value of the Company’s goodwill was estimated using discounted cash flow methodologies and market comparable information.  As a result of the impairment test, the Company recognized an impairment of $5.5 million, net of tax, or $0.08 per diluted share, to reduce the carrying value of the goodwill to its estimated fair value as the level of future cash flows from the NORESCO segment were expected to be less than originally anticipated.  In accordance with Statement No. 142, this impairment adjustment has been reported as the cumulative effect of an accounting change in the Company’s Statements of Consolidated Income retroactive to the first quarter 2002.

 

The Company’s goodwill balance as of June 30, 2003 totaled $51.7 million and is entirely related to the NORESCO segment.  The Company does not anticipate additional impairment and will perform the required annual impairment test of the carrying amount of goodwill in the fourth quarter of 2003.  No indicators of impairment were identified during the six months ended June 30, 2003.

 

Recognition and Reporting of Gains and Losses on Energy Trading Contracts

 

In June 2002, the FASB’s Emerging Issues Task Force (EITF) issued EITF No. 02-3, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” and No. 00-17, “Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10.”  In the fourth quarter 2002, the FASB revised its consensus contained in EITF No. 02-3.  EITF No. 02-3, as revised, rescinds the guidance contained in EITF No. 98-10 and requires that only energy trading contracts that meet the definition of a derivative in Statement No. 133 be carried at fair value.  Energy trading contracts that do not meet the definition of a derivative must be accounted for as an executory contract (i.e., on an accrual basis).

 

Additionally, EITF No. 02-3, as revised, states that it will no longer be an acceptable industry practice to account for energy inventory held for trading purposes at fair value when fair value exceeds cost, unless explicitly provided by other authoritative literature.  The EITF’s revised consensus is effective for all new energy trading contracts entered into and energy inventory held for trading purposes purchased after October 25, 2002.  For any energy trading contracts entered into or energy inventory held for trading purposes as of October 25, 2002, companies were required to recognize a cumulative effect of a change in accounting principle beginning the first day of the first fiscal period beginning after December 15, 2002.  The implementation of the above provisions of EITF No. 02-3, as revised, did not have a material impact on the Company’s consolidated financial statements.

 

EITF No. 02-3, as revised, also requires that all gains and losses on derivative instruments held for trading purposes be presented on a net basis in the income statement for all periods presented, whether or not settled physically.  For gains and losses on energy trading activities that are not derivatives pursuant to Statement No. 133, the presentation is determined based upon the guidance contained in EITF No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.”  This guidance is effective for all periods presented in financial statements issued for periods beginning after December 15, 2002 (earlier adoption was permitted).  Prior to this guidance, the Company reported the gains and losses on its energy trading contracts gross (i.e., included the revenues and costs comprising the gains and losses on energy trading derivative contracts within operating revenues and cost of sales, respectively) on its Statements of Consolidated Income in accordance with the guidance contained in EITF No. 98-10.  The reduction from a gross to a net classification has resulted in a reduction in both operating revenues and cost of sales for the Equitable Utilities segment for the three and six months ended June 30, 2002 of $42.8 million and $93.6 million, respectively.

 

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K.            Recently Issued Accounting Standards

 

Guarantees

 

In November 2002, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45).  FIN 45 clarifies and expands on existing disclosure requirements for guarantees, including loan guarantees.  It also would require that, at the inception of a guarantee, the Company recognize a liability for the fair value of its obligation under that guarantee.  The initial fair value recognition and measurement provisions will be applied on a prospective basis to certain guarantees issued or modified after December 31, 2002.

 

During 2000, the Company entered into a transaction with Appalachian Natural Gas Trust (ANGT) by which natural gas producing properties located in the Appalachian Basin region of the United States were sold.  ANGT manages the assets and produces, markets, and sells the related natural gas from the properties.  Appalachian NPI (ANPI) contributed cash and debt to ANGT.  The assets of ANPI, including its interest in ANGT, collateralize ANPI’s debt.  The Company provides ANPI with a liquidity reserve guarantee secured by the fair market value of the assets purchased by ANGT.  This guarantee is subject to certain restrictions and limitations, as defined in the guarantee agreement, as to the eligibility, amount and terms of the guarantee.  These restrictions limit the amount of the guarantee to the calculated present value of the project’s future cash flows from the preceding year-end until the termination date of the agreement.  The agreement also defines events of default, use of proceeds and demand procedures.  This guarantee was contracted for a market-based fee.  The Company has not recorded a liability for this guarantee, as the Company currently believes that the likelihood of making any payment under the guarantee is remote.

 

As of June 30, 2003, ANPI had $278.7 million of total assets, respectively, and $309.5 million of liabilities (including $201.5 million of long-term debt, including current maturities).  The Company’s maximum exposure to a loss as a result of its involvement with ANPI is $52.8 million.

 

A wholly owned subsidiary of the Company has provided two guarantees in the total amount of $5.4 million in support of a 50%-owned non-recourse financed energy project located in Panama.  The guarantees represent 50% of the performance guaranty for the project’s principal Power Purchase Agreement and cover a project loan debt service reserve requirement.  In accordance with FIN 45, the Company has not recorded a liability for this guarantee.

 

Revenue Arrangements with Multiple Deliverables

 

In November 2002, the EITF reached a consensus on Issue No. 00-21, “Revenue Arrangements with Multiple Deliverables” (EITF No. 00-21).  EITF No. 00-21 provides guidance on how to account for arrangements that involve the delivery or performance of multiple products, services and rights to use assets.  The provisions of EITF No. 00-21 will apply to revenue arrangements entered into in the fiscal periods beginning after June 15, 2003.  The Company is currently evaluating the impact EITF No. 00-21 will have on its financial position and results of operations.

 

Consolidation of Variable Interest Entities

 

In January 2003, the FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51” (FIN 46).  FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties.  FIN 46 is effective for all new variable interest entities created or acquired after January 31, 2003.  For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003.  Management is finalizing its evaluation of the effect, if any, that the adoption of FIN 46 will have on its results of operations and financial condition.  Disclosure has been made in the Company’s 2002 Form 10-K of all off balance sheet arrangements for which it is reasonably possible that consolidation will be required under FIN 46.

 

17

 

Derivative Instruments and Hedging Activities

 

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (Statement No. 149).  This Statement amends and clarifies the accounting and reporting for derivative instruments, including embedded derivatives, and for hedging activities under Statement No. 133.  Statement No. 149 amends Statement No. 133 to reflect the decisions made as part of the Derivatives Implemention Group (DIG) and in other FASB projects or deliberations.  Statement No. 149 is effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003.  The Company’s accounting for derivative instruments is in compliance with Statement No. 149 and Statement No. 133.  Therefore, the adoption of Statement No. 149 is not expected to have an impact on the Company’s consolidated financial statements.

 

Classification and Measurement of Certain Financial Instruments

 

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (Statement No. 150).  This Statement requires that certain financial instruments embodying an obligation to transfer assets or to issue equity securities be classified as liabilities. It is effective for financial instruments entered into or modified after May 31, 2003 and to all other instruments that exist as of the beginning of the first interim financial reporting period beginning after June 15, 2003.  This Statement had no impact on the Company’s consolidated financial statements for the six months ended June 30, 2003.  The Company is currently evaluating Statement No. 150 and does not expect Statement No. 150 to have an impact on its financial position and results of operations subsequent to June 30, 2003.

 

L.            Other Events

 

In February 2003, the Company issued $200 million of notes with a stated interest rate of 5.15% and a maturity date of March 2018.  A portion of the proceeds from the issuance were used to redeem the Company’s entire $125 million of 7.35% Trust Preferred Capital Securities on April 23, 2003.  No gain or loss was incurred as a result of this redemption.  The remainder of the proceeds from the February 2003 issuance has been designated for general corporate purposes.

 

After an extended period of troubled operations (more fully described in the Company’s 2002 Form 10K), ERI JAM, LLC, a subsidiary that holds the Company’s interest in an international infrastructure project, filed for bankruptcy protection under Chapter 11 in U.S. Bankruptcy Court (Delaware) in April 2003.  The Company will continue to consolidate the partnership until it no longer has control, which management expects to occur by the end of the year.  This change will not have a material effect on the Company’s financial position or results of operations as the Company has already written off its entire investment in the project and the project debt is non-recourse.

 

M.           Reclassification

 

Certain previously reported amounts have been reclassified to conform to the 2003 presentation.  These reclassifications did not affect reported net income or cash flows.

 

18

 

Equitable Resources, Inc. and Subsidiaries

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

INFORMATION REGARDING FORWARD LOOKING STATEMENTS

 

Disclosures in this Quarterly Report on Form 10-Q contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Statements that do not relate strictly to historical or current facts are forward-looking and can usually be identified by the use of words such as “should,” “anticipate,” “estimate,” “approximate,” “expect,” “may,” “will,” “project,” “intend,” “plan,” “believe” and other words of similar meaning in connection with any discussion of future operating or financial matters.  Without limiting the generality of the foregoing, such statements specifically include the amount of the Company’s plugging and abandonment obligations; the impact on the Company of Statement No. 142; the Company’s hedging strategy and the effectiveness of that strategy, including the impact on earnings of a change in NYMEX; the likelihood and cost of resolving operational and financial issues at the IGC/ERI Pan-Am Thermal project; the adequacy of the Company’s borrowing capacity to meet the Company’s liquidity requirements; the amount of unrealized gains on the Company’s derivative commodity instruments that will be recognized in earnings; the impact of new accounting pronouncements, including EITF No. 00-21, FIN 46, FIN 45, Statement No. 149 and Statement No. 150; the ultimate cost of the Company’s new customer and billing system; the resolution of issues relating to the Company’s Jamaican energy infrastructure project and the impact on the Company of the bankruptcy of that project; the Company’s pension plan funding obligations; the amount of or increase in future dividends; the ultimate outcome of regulatory reviews, including the SEC review; the affect on the Company’s operations and financial position of the final amendments to the Oil Pollution Prevention Regulation and any change in tax law; the benefit required to be paid by the Company under the 2003 Executive Performance Incentive Share Plan; the source of funding for the Company’s capital expenditure program; and other forward looking statements relating to financial results, cost savings and operational matters.  A variety of factors could cause the Company’s actual results to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements.  The risks and uncertainties that may affect the operations, performance and results of the Company’s business and forward-looking statements include, but are not limited to, the following:  weather conditions, commodity prices for natural gas and crude oil and associated hedging activities including changes in the hedge portfolio, availability and cost of financing, changes in interest rates, implementation and execution of cost restructuring initiatives, curtailments or disruptions in production, timing and availability of regulatory and governmental approvals, timing and extent of the Company’s success in acquiring utility companies and natural gas and crude oil properties, the ability of the Company to discover, develop and produce reserves, the ability of the Company to acquire and apply technology to its operations, the impact of competitive factors on profit margins in various markets in which the Company competes, the ability of the Company to execute on certain energy infrastructure projects, the ability of the Company to negotiate satisfactory collective bargaining agreements with its union employees, changes in accounting rules or their interpretation, the financial results achieved by Westport Resources, the ability to satisfy project finance lenders and other factors discussed in other reports (including Form 10-K) filed by the Company from time to time.

 

OVERVIEW

 

Equitable Resources’ consolidated income from continuing operations before cumulative effect of accounting change for the quarter ended June 30, 2003 totaled $31.4 million, or $0.50 per diluted share, compared to $29.2 million, or $0.45 per diluted share, reported for the same period a year ago.  The second quarter 2003 earnings from continuing operations before cumulative effect of accounting change increased from 2002 primarily due to higher realized selling prices, a $5.3 million impairment of the Company’s Jamaica power plant during the second quarter 2002, an increase in sales volumes from production, and minority interest expense recognized in 2002 associated with the Company’s ownership in Appalachian Basin Partners, LP (ABP).  These factors were partially offset by costs associated with the 2003 Executive Performance Incentive Share Plan, lower gas demand due to warmer weather, an increase in interest expense primarily due to a net increase in the amount of outstanding debt, and increased benefit and insurance costs.

 

19

 

Equitable Resources’ consolidated income from continuing operations before cumulative effect of accounting change for the six months ended June 30, 2003 totaled $95.9 million, or $1.52 per diluted share, compared to $81.6 million, or $1.25 per diluted share, reported for the same period a year ago.  The increase of $14.3 million is primarily the result of higher realized selling prices, increased equity earnings in nonconsolidated investments primarily related to the Company’s investment in Westport, a $5.3 million impairment of the Company’s Jamaica power plant during the second quarter 2002, an increase in sales volumes from production, higher gas demand due to colder weather, and minority interest expense recognized in 2002 associated with the Company’s ownership in ABP.  These factors were partially offset by costs associated with the 2003 Executive Performance Incentive Share Plan, an increase in interest expense primarily due to a net increase in the amount of outstanding debt, a charitable foundation contribution expense, and increased benefit and insurance costs.

 

RESULTS OF OPERATIONS

 

EQUITABLE UTILITIES

 

Equitable Utilities’ operations comprise the sale and transportation of natural gas to customers at state-regulated rates, interstate pipeline transportation and storage of natural gas subject to federal regulation, the unregulated marketing of natural gas, and limited trading activities.

 

In the third quarter of 2002, the Company reclassified all gains and losses on its energy trading contracts to a net presentation for all periods presented in accordance with EITF No. 02-3.

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
OPERATIONAL DATA
Capital expenditures (thousands)		$	14,708		$	12,985		$	23,376		$	22,305
Total operating expenses as a % of net operating revenues		71.19		%	66.95		%	49.25		%	47.88		%
FINANCIAL RESULTS (Thousands)
Utility revenues (regulated)		$	62,485		$	56,858		$	246,810		$	191,852
Marketing revenues		53,135			92,102			104,919			180,859
Total operating revenues		115,620			148,960			351,729			372,711
Utility purchased gas costs (regulated)		22,773			16,356			119,992			74,579
Marketing purchased gas costs		48,668			86,972			90,339			166,600
Net operating revenues		44,179			45,632			141,398			131,532
Operating expenses:
Operating and maintenance expense		12,722			12,596			25,825			24,220
Selling, general and administrative expense		11,940			11,369			30,294			25,652
Depreciation, depletion and amortization		6,789			6,587			13,524			13,105
Total operating expenses		31,451			30,552			69,643			62,977
Operating income		$	12,728		$	15,080		$	71,755		$	68,555

 

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Three Months Ended June 30, 2003

vs. Three Months Ended June 30, 2002

 

Net operating revenues decreased $1.5 million, or 3%, for the three months ended June 30, 2003 compared to the prior year second quarter.  The decrease in net operating revenues is primarily attributable to 12% warmer weather in the second quarter 2003 compared to the prior year second quarter.  Total operating expenses for the quarter were $31.5 million compared to the $30.6 million reported during the same period last year.  The increase in total operating expenses of $0.9 million, or 3%, is mainly due to increased insurance, legal and benefit costs and increased provisions for doubtful accounts ($0.3 million), partially offset by ongoing cost reduction initiatives.

 

Six Months Ended June 30, 2003

vs. Six Months Ended June 30, 2002

 

Net operating revenues increased by $9.9 million in 2003 compared to the six months ended June 30, 2002. The increase is net operating revenues is primarily due to colder weather in the first quarter 2003 offset by a decrease in storage-related revenue in the pipeline operations and warmer weather in the second quarter 2003.   Operating income increased 5% to $71.8 million for the current period compared to $68.6 million for the same period in 2002 due primarily to colder weather.   Total operating expenses increased $6.6 million from $63.0 million to $69.6 million. The increase is due to increased provisions for doubtful accounts, colder weather than in the prior year and increased insurance, legal and benefit costs.

 

Distribution Operations

 

Rates and Regulatory Matters

 

Equitable Utilities’ distribution operations are carried out by Equitable Gas Company (Equitable Gas), a division of the Company. The service territory for Equitable Gas includes southwestern Pennsylvania, municipalities in northern West Virginia and field line sales (also referred to as “Farm tap” service as the customer is served directly off a well or gathering pipeline) in eastern Kentucky.  The distribution operations provide natural gas services to approximately 271,000 customers, comprising 252,500 residential customers and 18,500 commercial and industrial customers.  Equitable Gas is subject to rate regulation by state regulatory commissions in Pennsylvania, West Virginia and Kentucky.

 

Over the last two years Equitable Gas has been working with state regulators to shift the manner in which costs are recovered from traditional cost of service rate making to performance-based rate making.  In 2001, Equitable Gas received approval from the Pennsylvania Public Utility Commission (PA PUC) to implement a performance-based incentive that provides customers a guaranteed purchased gas cost credit, while enabling Equitable Gas to retain any cost savings in excess of the credit through more effective management of upstream interstate pipeline capacity.  During the third quarter 2002, the PA PUC approved a one-year extension of this program through September 2004.  In that same order, the PA PUC approved a second performance-based initiative related to balancing services.  This initiative runs through 2005.  During the second quarter of 2003, Equitable Gas reached a settlement with all parties to extend its performance-based purchased gas costs incentive through September 2005.  The settlement also included a new performance-based incentive which allows Equitable to retain 25% of any revenue generated from a new service designed to increase the recovery of capacity costs from transportation customers.  A PA PUC Order approving the settlement is expected during the third quarter of 2003.

 

In the second quarter 2002, the PA PUC authorized Equitable Gas to offer a sales service that would give residential and small business customers the alternative to fix the unit cost of the commodity portion of their rate.  The program was developed in response to customer requests for a method to reduce the fluctuation in gas costs.  This “first of its kind” program in Pennsylvania is another in a series of service-enhancing initiatives implemented by Equitable Gas.  A competitor, Dominion Retail, Inc, has appealed the PA PUC order authorizing the new service to the Commonwealth Court of Pennsylvania.  Equitable Gas is awaiting the outcome of the appeal before offering the service.

 

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In the third quarter 2002, the PA PUC issued an order approving Equitable Gas’ request for a Delinquency Reduction Opportunity Program.  The program gives incentives to eligible customers to make payments exceeding their current bill amount and receive additional credits from Equitable Gas to reduce the customer’s delinquent balance.  The program will be fully funded through customer contributions and a surcharge in rates.

 

Equitable Gas completes quarterly purchased gas cost filings with the PA PUC, which are subject to quarterly reviews and annual audits by the PA PUC.  The PA PUC completed its most recent audit in 2001, which approved the Company’s purchased gas costs through 1999.  The Company’s purchased gas costs for the years 2000 through 2003 are currently unaudited by the PA PUC, but have received a prudency review by the PA PUC through 2002 in which no material issues have been noted.

 

Other

 

Equitable Gas is in the process of implementing a new customer information and billing system for which the Company has incurred $8.2 million of capital expenditures from project inception through June 30, 2003.  Based upon the information currently available to management, the implementation is expected to be successfully completed by the end of 2003.

 

Equitable Gas’ contract with the members of the local United Steelworkers union expired on April 15, 2003.  The Company and the union have agreed to work under the terms of the expired contract, while negotiating.

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
OPERATIONAL DATA
Degree days (normal = Qtr – 705, YTD – 3,635) (a)		554			632			3,669			3,041
O&M per customer (b)		$	65.6		$	60.3		$	156.9		$	130.8
Volumes (MMcf)
Residential sales and transportation		3,467			3,876			17,632			15,092
Commercial and industrial		4,965			6,147			16,555			16,562
Total throughput		8,432			10,023			34,187			31,654
FINANCIAL RESULTS (Thousands)
Net operating revenues:
Residential		$	18,318		$	19,528		$	66,464		$	59,258
Commercial and industrial		9,347			8,069			30,828			26,292
Other		911			894			2,477			2,194
Total net operating revenues		28,576			28,491			99,769			87,744
Operating expenses		23,457			22,175			53,835			46,815
Operating income		$	5,119		$	6,316		$	45,934		$	40,929

 

(a)                    The 30-year normal degree days’ figure is derived from the National Oceanic and Atmospheric Administration’s (NOAA) 30-year normal figures.  The NOAA released updated normal degree day figures for the period 1971 to 2000 and accordingly, Equitable Gas’ degree days decreased from 712 and 3,728 for the three and six months ended June 30, 2002 to 705 and 3,635 for the three and six months ended June 30, 2003.

(b)                   O&M is defined for this calculation as Operating Expenses less Depreciation less Other Taxes.  DD&A for the three and six months ended June 30, 2003 and 2002 totaled $4.9 million and $9.9 million, and $4.9 million and $9.7 million, respectively.  Other taxes for the three and six months ended June 30, 2003 and 2002 totaled $0.7 million and $0.9 million, and $1.4 million and $1.6 million, respectively.  There were approximately 271,000 customers during the periods covered.

 

22

 

Three Months Ended June 30, 2003

vs. Three Months Ended June 30, 2002

 

Net operating revenues for the second quarter 2003 increased by $0.1 million compared to  2002.  The increase was a result of increased delivery margins that were offset by warmer weather.  Heating degree days were 554, which is 12% warmer than the 632 degree days reported in 2002 and 21% warmer than the 30-year normal of 705.  Commercial and industrial volumes decreased 19% due to decreased domestic steel industry throughput.  Despite the decrease in commercial and industrial volumes, net operating revenues did not proportionately decrease due to the relatively low margins on industrial customer volumes.

 

Operating expenses of $23.5 million for the 2003 second quarter increased compared to the 2002 second quarter operating expenses of $22.2 million.  The increased operating costs were due to increased insurance, legal and benefit costs and provisions for doubtful accounts, partially offset by ongoing cost reduction initiatives.

 

Six Months Ended June 30, 2003

vs. Six Months Ended June 30, 2002

 

Weather in the distribution service territory for the six months ended June 30, 2003, was 1% colder than normal and 21% colder than last year, primarily associated with cold temperatures in the first quarter 2003 which were partially offset by warmer second quarter 2003 weather.  Residential volumes increased 17% from prior year, while commercial and industrial volumes remained flat.

 

Net operating revenues for the six months ended June 30, 2003, increased to $99.8 million from $87.7 million, or 14% from the same period last year. The increase is attributable to colder weather and increased delivery margins.

 

Operating expenses of $53.8 million for the six months ended June 30, 2003 increased $7.0 million compared to $46.8 million for the same period in 2002.  The increase in operating expenses was primarily due to increased provisions for doubtful accounts ($4.0 million), as well as increased legal, insurance and employee benefit costs. These expenses combined with higher cold-weather related operating costs from the first quarter 2003 for the repair of leaks and increased emergency calls were slightly offset by cost reductions in the second quarter 2003.

 

Pipeline Operations

 

Interstate Pipeline

 

The pipeline operations of Equitrans, L.P. (Equitrans) and Carnegie Interstate Pipeline Company (Carnegie Pipeline), subsidiaries of the Company, are subject to rate regulation by the Federal Energy Regulatory Commission (FERC).  Equitrans’ last general rate change application (rate case) was filed in 1997.  The rate case was resolved through a FERC approved settlement among all parties.  The settlement provided, with certain limited exceptions, that Equitrans would not file a general rate increase with an effective date before August 1, 2003.  In addition, Equitrans was required to file a general rate increase application to take effect no later than August 1, 2003.

 

In the second quarter 2002, Equitrans filed with the FERC to merge its assets and operations with the assets and operations of Carnegie Pipeline.  Included in this filing was a request for a deferral of the 2003 rate case requirement discussed above.

 

In April 2003, Equitrans filed a proposed settlement with FERC related to the second quarter 2002 filing to merge its assets with the assets of Carnegie Pipeline.  The settlement also provided for a continuation of the rate moratorium until April 2005.  FERC subsequently received a protest to the settlement.  Equitrans has filed comments with FERC to address the protest.  On July 1, 2003, Equitrans received an order form the FERC approving the merger of Equitrans and Carnegie Pipeline but denying the request for deferral of the 2003 rate case requirement discussed above.  In response to this order, Equitrans filed a motion for extension of time seeking to extend its filing deadline from August 1, 2003 until December 1, 2003.  Equitrans’ motion was approved by the FERC in an order issued on July 31, 2003. Equitrans continues to explore and evaluate settlement options, which would extend the rate moratorium.

 

23

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
OPERATIONAL DATA
Transportation throughput (BBtu)		16,387			21,971			36,815			38,690
FINANCIAL RESULTS (Thousands)
Net operating revenues		$	11,136		$	12,010		$	27,049		$	29,528
Operating expenses		7,547			7,457			14,927			14,197
Operating income		$	3,589		$	4,553		$	12,122		$	15,331

 

Three Months Ended June 30, 2003

vs. Three Months Ended June 30, 2002

 

Total transportation throughput decreased 5.6 thousand BBtu, or 25%, over the prior year quarter.  The decreased throughput is primarily attributable to the decrease in distribution throughput, a decrease in demand associated with warmer weather compared to the prior year, higher prices and the weak economy.  Because the margin from these firm transportation contracts is generally derived from fixed monthly fees, regardless of the volumes transported, the decreased throughput did not significantly impact net revenues.

 

Net operating revenues decreased by $0.9 million from $12.0 million in 2002 to $11.1 million in 2003.  The decrease in net revenues from the prior year quarter is due almost entirely to lost storage revenue opportunities resulting from higher gas prices and a weak economy.  The high prices and lack of demand resulted in the segment’s inability to take advantage of commercial opportunities that typically exist.

 

Operating expenses were consistent with the prior year quarter as on-going cost reduction initiatives were offset by increased legal, insurance and employee benefit costs.

 

Six Months Ended June 30, 2003

vs. Six Months Ended June 30, 2002

 

Net operating revenues for the six months ended June 30, 2003, were $27.0 million compared to $29.5 million for the same period in 2002. The decrease in net revenues from the prior year quarter is due almost entirely to lost storage revenue opportunities due to firm customer delivery demands in the first quarter from colder weather and higher gas prices. In addition, the high gas prices and lack of demand in the second quarter resulted in the inability to take advantage of commercial opportunities that typically exist.

 

Operating expenses increased by $0.7 million, or 5%, to $14.9 million. The increase in operating costs is primarily due to increased legal, insurance and employee benefit costs, partially offset by ongoing cost reduction initiatives.

 

24

 

Equitable Marketing

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
OPERATIONAL DATA
Total throughput (BBtu)		5,900			37,716			20,057			88,073
Net operating revenues/MMbtu		$	0.76		$	0.14		$	0.73		$	0.16
FINANCIAL RESULTS (Thousands)
Net operating revenues		$	4,467		$	5,131		$	14,580		$	14,260
Operating expenses		447			920			881			1,965
Operating income		$	4,020		$	4,211		$	13,699		$	12,295

 

Three Months Ended June 30, 2003

vs. Three Months Ended June 30, 2002

 

Net operating revenues decreased by $0.7 million or 13% from the prior year quarter due almost entirely to lost storage revenue opportunities resulting from higher gas prices.  The high prices and lack of demand resulted in the inability to take advantage of excess capacity commercial opportunities that typically exist.   Additionally, at the beginning of 2003, the Equitable Supply segment assumed the direct marketing of a substantial portion of its operated volumes, which had previously been marketed by Equitable Marketing. These volumes, totaling approximately 35 thousand BBtu for the three months ended June 30, 2003, had been marketed by Equitable Marketing at very low margins.  Although the assumption of these volumes by Equitable Supply did not have a significant impact on Equitable Marketing’s net revenues for the three months ended June 30, 2003, it was the primary reason for the significant increase in the unit marketing margins during that same period.

 

Operating expenses for the current quarter of $0.4 million decreased $0.5 million from the second quarter 2002.  The decrease was due to a reduction in bad debt expense and continued cost reduction initiatives associated with the Company’s decision to de-emphasize low margin trading-oriented activities.

 

Six Months Ended June 30, 2003

vs. Six Months Ended June 30, 2002

 

Net operating revenues for the six months ended June 30, 2003 increased slightly due to increased unit marketing margins.  The Equitable Supply segment assumed the direct marketing of a substantial portion of its operated volumes at the beginning of 2003, which had previously been marketed by Equitable Marketing. These volumes, totaling approximately 67 thousand BBtu for the six months ended June 30, 2003, had been marketed by Equitable Marketing at very low margins.  Although the assumption of these volumes by Equitable Supply did not have a significant impact on Equitable Marketing’s net revenues for the six months ended June 30, 2003, it was the primary reason for the significant increase in the unit marketing margins during that same period.

 

Operating expenses decreased by $1.1 million as a result of the recovery of a bankrupt customer’s balance that was reserved for in 2002 and as a result of a reduction in bad debt expense.

 

25

 

EQUITABLE SUPPLY

 

Equitable Supply operates two lines of business – production and gathering – with operations in the Appalachian region of the United States.  Equitable Production develops, produces and sells natural gas and, to a limited extent, crude oil and its associated by-products.  Equitable Gathering engages in natural gas gathering and the processing and sale of natural gas liquids.

 

Purchase and Sale of Gas Properties

 

In November 1995, the Company monetized Appalachian gas properties qualifying for the nonconventional fuels tax credit to a partnership, Appalachian Basin Partners, LP (ABP).  The Company recorded the proceeds as deferred revenue, which was recognized as production occurred.  The Company retained a partnership interest in the properties that increased substantially based on the attainment of a performance target.  The performance target was met at the end of 2001.  The Company consolidated the partnership starting in 2002, and the remaining portion not owned by the Company was recorded as minority interest.

 

In February 2003, the Company purchased the remaining 31% limited partnership interest in ABP from the minority interest holders for $44.2 million.  The limited partner interest represents approximately 60.2 Bcf of reserves.  Effective February 1, 2003, the minority interest is no longer being recognized.

 

In February 2003, the Company sold approximately 500 of its low-producing wells, within two of its non-strategic districts, in two separate transactions.  The sales resulted in a decrease of 15.3 Bcf of net reserves for proceeds of approximately $6.6 million.  The wells produced approximately 0.8 Bcf annually.  The Company did not recognize a gain or a loss as a result of this disposition.

 

26

 

Operational and Financial Data

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
OPERATIONAL DATA
Total sales volumes (MMcfe) (a)		15,563			14,819			31,080			29,714
Total operated volumes (MMcfe) (b)		22,645			22,291			45,001			44,797
Volumes handled (MMcfe) (c)		32,108			31,921			67,417			65,168
Selling, general, and administrative  ($/Mcfe handled)		$	0.22		$	0.17		$	0.21		$	0.17
Capital expenditures (thousands) (d)		$	42,767		$	36,476		$	110,505		$	64,047
FINANCIAL DATA (Thousands)
Production revenues		$	62,292		$	53,583		$	126,971		$	104,397
Gathering revenues		17,093			14,445			34,111			30,033
Total operating revenues		79,385			68,028			161,082			134,430
Operating expenses:
Lease operating expense, excluding severance taxes		5,012			4,265			9,928			9,009
Severance tax		3,499			1,970			7,386			3,380
Land and leasehold maintenance		113			156			472			452
Gathering and compression expense		5,879			5,816			11,631			11,776
Selling, general and administrative		7,096			5,399			13,884			10,987
Depreciation, depletion and amortization (DD&A)		12,019			9,711			23,601			19,470
Total operating expenses		33,618			27,317			66,902			55,074
Operating income		$	45,767		$	40,711		$	94,180		$	79,356
Equity from nonconsolidated investments		$	24		$	66		$	262		$	118
Minority interest		$	—		$	(1,949	)	$	(871	)	$	(3,399	)

 

(a)                                  Includes net equity sales and monetized sales volumes

(b)                                 Includes net equity volumes, monetized volumes, and volumes in which interests were sold, but which the Company still operates for a fee.

(c)                                  Includes operated volumes plus volumes gathered for third parties.

(d)                                 Capital expenditures for the six months ended June 30, 2003 include the purchase of the remaining 31% limited partnership interest in ABP ($44.2 million) which was approved by Board of Directors of the Company in addition to the total amount originally authorized for the 2003 capital budget program.

 

27

 

Three Months Ended June 30, 2003

vs. Three Months Ended June 30, 2002

 

Equitable Supply’s operating income for the three months ended June 30, 2003 was $45.8 million, 12% higher than the $40.7 million earned for the three months ended June 30, 2002.  The segment’s results were favorably impacted by higher commodity prices, increased natural gas sales volume and increased gathering revenues.

 

Operating revenues for the second quarter 2003 increased 17% to $79.4 million compared to $68.0 million in 2002, which is primarily attributable to a higher effective price and increases in sales volumes and gathering revenues.  Equitable Supply’s weighted average well-head sales price realized on produced volumes for the 2003 second quarter was $3.83 per Mcfe compared to $3.46 per Mcfe for the same period last year.  The $0.37 per Mcfe increase in the weighted average well-head sales price was attributable to higher NYMEX prices, higher hedged prices and increased basis over the second quarter 2002.  Increased natural gas sales volumes were primarily a result of new wells drilled in 2002 and 2003.  Increased gathering revenues reflect increased Company production volumes and increased rates billed to equity and third party customers.

 

Total operating expenses for the three months ended June 30, 2003 were $33.6 million compared to $27.3 million in last year’s second quarter.  The main factors in the increase were depreciation, depletion and amortization ($2.3 million), selling, general and administrative expenses ($1.7 million) and severance tax ($1.5 million).  The increase in DD&A was due to a $0.10 increase in the unit depletion rate and increased production volumes.  The $0.10 increase is made up of a $0.04 increase from 2002 drilling costs, a $0.03 increase due to the February 2003 acquisition of the ABP limited partnership interest described above, and a $0.03 increase due to the January 1, 2003 adoption of Statement No. 143 “Accounting for Asset Retirement Obligation” described in Note J to the financial statements.  The increase in selling, general and administrative expenses was related to increased legal and insurance costs and an increase in professional staffing.  The increased severance tax was a direct function of market prices.

 

Six Months Ended June 30, 2003

vs. Six Months Ended June 30, 2002

 

Equitable Supply’s operating income for the six months ended June 30, 2003 was $94.2 million, 19% higher than the $79.4 million earned for the six months ended June 30, 2002.  The segment’s results were favorably impacted by higher commodity prices, increased natural gas sales volume and increased gathering revenues, somewhat offset by increased operating expenses.

 

Operating revenues for the six months ended June 30, 2003, increased 20% to $161.1 million compared to $134.4 million in 2002, which was primarily attributable to a higher effective price and an increase in sales volumes and gathering revenues.  Equitable Supply’s weighted average well-head sales price realized on produced volumes for the six months ended June 30, 2003 was $3.91 per Mcfe compared to $3.34 per Mcfe for the same period last year.  The $0.57 per Mcfe increase in the weighted average well-head sales price is attributable to higher NYMEX prices, increased hedge volumes, higher hedged prices and increased basis over the same period in 2002.

 

Total operating expenses were $66.9 million for the six months ended June 30, 2003, compared to $55.1 million for the six months ended June 30, 2002.  This increase was primarily due to increased DD&A costs ($4.1 million), severance taxes attributable to higher gas prices ($4.0 million), and increased selling, general and administrative expense relating to increases in legal costs, insurance premiums and staffing costs ($2.9 million).

 

28

 

Equitable Production

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
OPERATIONAL DATA
Net equity sales (MMcfe) (a)		12,053			11,309			24,099			22,733
Average (well-head) sales price ($/Mcfe)		$	4.01		$	3.52		$	4.11		$	3.36
Monetized sales (MMcfe) (b)		3,510			3,510			6,981			6,981
Average (well-head) sales price ($/Mcfe)		$	3.23		$	3.28		$	3.23		$	3.26
Average of net equity and monetized (well-head) sales price ($/Mcfe)		$	3.83		$	3.46		$	3.91		$	3.34
Company usage, line loss (MMcfe) (a)		1,488			1,447			2,545			2,787
Lease operating expense (LOE),  excluding severance tax ($/Mcfe)		$	0.29		$	0.26		$	0.30		$	0.28
Severance tax ($/Mcfe)		$	0.21		$	0.12		$	0.22		$	0.10
Production depletion ($/Mcfe)		$	0.49		$	0.39		$	0.48		$	0.39
Depreciation, depletion and amortization (in thousands):
Production depletion		$	8,346		$	6,345		$	16,301		$	12,777
Other depreciation, depletion and amortization		495			385			970			684
Total depreciation, depletion and amortization		$	8,841		$	6,730		$	17,271		$	13,461
Total operated volumes (MMcfe) (c)		22,645			22,291			45,001			44,797
FINANCIAL DATA (Thousands)
Net equity sales		$	48,287		$	39,815		$	98,964		$	76,374
Monetized sales		11,349			11,498			22,574			22,769
Other revenue		2,656			2,270			5,433			5,254
Total production revenues		62,292			53,583			126,971			104,397
Operating expenses:
Lease operating expense, excluding severance taxes		5,012			4,265			9,928			9,009
Severance tax		3,499			1,970			7,386			3,380
Land and leasehold maintenance		113			156			472			452
Selling, general and administrative (SG&A)		4,683			3,564			9,163			7,252
Depreciation, depletion and amortization (DD&A)		8,841			6,730			17,271			13,461
Total operating expenses		22,148			16,685			44,220			33,554
Operating income		$	40,144		$	36,898		$	82,751		$	70,843
Equity from nonconsolidated investments		$	24		$	66		$	262		$	118
Minority interest		$	—		$	(1,949	)	$	(871	)	$	(3,399	)

 

(a)          Effective January 1, 2003, the Company adjusted its method for using a natural gas equivalents conversion factor to convert gallons of liquid hydrocarbon sales to equivalent volumes of natural gas sales.  This change results in an additional 0.3 Bcfe of natural gas sales volume and a corresponding reduction to reported Company usage and line loss for the second quarter 2003.

(b)         Volumes sold associated with the Company’s two prepaid natural gas sales contracts.

(c)          Includes equity volumes, monetized volumes, and volumes in which interests were sold, but which the Company still operates for a fee.

 

29

 

Three Months Ended June 30, 2003

vs. Three Months Ended June 30, 2002

 

Equitable Production’s operating income for the three months ended June 30, 2003 was $40.1 million, a 9% increase over the prior year’s second quarter operating income of $36.9 million.  Production revenues were up $8.7 million from $53.6 million in the second quarter 2002 to $62.3 million in the second quarter 2003.  This increase results from an effective sales price of $3.83 per Mcfe compared to $3.46 per Mcfe in the prior year quarter and a 0.7 Bcf increase in sales volumes.

 

Sales volume increases resulting from new drilling in the past 12 months were partially offset by the sale of gas properties previously noted (0.2 Bcfe), coupled with increased interstate pipeline system curtailment (0.2 Bcfe) and production issues surrounding automation implementation and surveillance (0.1 Bcfe).

 

Operating expenses were up $5.5 million over the prior year quarter from $16.7 million to $22.1 million.  The increase is a result of increased depreciation, depletion and amortization costs ($2.1 million), higher severance taxes attributable to higher natural gas prices ($1.5 million), increased SG&A due to higher insurance premiums, legal costs and professional staffing ($1.1 million), and increased lease operating expenses ($0.8 million).  Depreciation, depletion and amortization increased as a result of increased production volumes and a $0.10 increase in the unit depletion rate, from $0.39 in the 2002 second quarter to $0.49 in the 2003 second quarter.  Of the total $0.10 per Mcfe increase in the unit depletion rate, $0.04 per Mcfe relates to the developmental drilling program, $0.03 is attributable to the changes resulting from purchases and sales of natural gas properties and $0.03 per Mcfe is a result of the implementation of SFAS No. 143, described in Note J.  The increase in lease operating expenses is primarily a result of increases in property taxes resulting from increased commodity sales prices, liability insurance premiums and road maintenance costs due to severe weather and flooding in 2003.

 

Six Months Ended June 30, 2003

vs. Six Months Ended June 30, 2002

 

Equitable Production’s operating income for the six months ended June 30, 2003 was $82.8 million, a 17% increase over the prior year’s six months operating income $70.8 million.  Production revenues were up $22.6 million, largely due to an increase in the effective sales price.

 

Operating expenses increased $10.6 million over the prior year quarter from $33.6 million to $44.2 million.  The increase is a result of higher severance taxes attributable to higher natural gas prices ($4.0 million), increased DD&A costs ($3.8 million), increased SG&A due to higher insurance premiums and legal costs and increased staffing ($1.9 million), and increased lease operating expenses due to increases in property taxes resulting from increased commodity sales prices, liability insurance premiums and road maintenance costs due to severe weather and flooding in 2003 ($0.9 million).

 

30

 

Equitable Gathering

 

Operational and Financial Data

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
OPERATIONAL DATA
Gathered volumes (MMcfe)		29,177			28,917			61,729			59,532
Average gathering fee ($/Mcfe) (a)		$	0.58		$	0.50		$	0.55		$	0.50
Gathering and compression expense ($/Mcfe)		$	0.20		$	0.20		$	0.19		$	0.20
Gathering and compression depreciation ($/Mcfe)		$	0.10		$	0.10		$	0.09		$	0.09
Depreciation, depletion and amortization (in thousands):
Gathering and compression depreciation		$	2,924		$	2,782		$	5,831		$	5,655
Other depreciation, depletion and amortization		254			199			499			354
Total depreciation, depletion and amortization		$	3,178		$	2,981		$	6,330		$	6,009
FINANCIAL DATA (Thousands)
Gathering revenues		$	17,030		$	14,419		$	33,896		$	30,007
Other revenues		63			26			215			26
Total operating revenues		17,093			14,445			34,111			30,033
Operating expenses:
Gathering and compression expense		5,879			5,816			11,631			11,776
Selling, general and administrative (SG&A)		2,413			1,835			4,721			3,735
Depreciation, depletion and amortization (DD&A)		3,178			2,981			6,330			6,009
Total operating expenses		11,470			10,632			22,682			21,520
Operating income		$	5,623		$	3,813		$	11,429		$	8,513

 

(a)                Revenues associated with the use of pipelines and other equipment to collect, process and deliver natural gas from the field where it is produced to the trunk or main transmission line.  Many contracts are for a blended gas commodity and gathering price in which case the Company utilizes standard measures in order to split the price into its two components.

 

Three Months Ended June 30, 2003

vs. Three Months Ended June 30, 2002

 

Equitable Gathering’s operating income for the three months ended June 30, 2003 of $5.6 million increased $1.8 million or 47% over the prior year’s second quarter operating income of $3.8 million.  Gathering revenues were $17.1 million compared to $14.4 million in the second quarter 2002, an 18% increase.

 

Operating revenues increased $2.6 million in the second quarter of 2003 versus the same quarter last year.  The main factors in the increase were additional throughput from new customers and an increase in third party gathering rates ($1.5 million), an increase in equity volumes ($0.6 million), and an increase in average equity gathering rates ($0.5 million).

 

Operating expenses were $11.5 million in the second quarter of 2003, a $0.8 million increase over the $10.6 million in the same quarter last year.  SG&A expenses were higher due to increased insurance premiums, legal and staffing costs.

 

31

 

Six Months Ended June 30, 2003

vs. Six Months Ended June 30, 2002

 

Equitable Gathering’s operating income for the six months ended June 30, 2003 of $11.4 million increased $2.9 million over the prior year’s six months ended June 30, 2002 operating income of $8.5 million.  Operating revenues increased $4.1 million year over year, due to increased throughput and slightly higher average rates.

 

Operating expenses were up $1.2 million to $22.7 million for the six months ended June 30, 2003 from $21.5 million for the six months ended June 30, 2002.  The increase is mainly due to selling, general and administrative expenses ($1.0 million) resulting from increased insurance premiums, legal and staffing costs.

 

NORESCO

 

NORESCO provides energy-related products and services that are designed to reduce its customers’ operating costs and to improve their productivity.  The segment’s activities are comprised of combined heat and power and central boiler/chiller plant development, design, construction, ownership and operation; performance contracting; and energy efficiency programs.  NORESCO’s customers include governmental, military, institutional, and industrial end-users.  NORESCO’s energy infrastructure group develops, designs, constructs and operates facilities in the United States and operates private power plants in selected international countries.

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
OPERATIONAL DATA
Revenue backlog, end of period (thousands)		$	78,399		$	157,410		$	78,399		$	157,410
Construction completed (thousands)		$	29,954		$	30,917		$	60,516		$	52,222
Capital expenditures (thousands)		$	98		$	183		$	146		$	364
Gross profit margin		20.0		%	22.3		%	20.4		%	23.1		%
SG&A as a % of revenue		13.5		%	12.0		%	12.4		%	13.5		%
FINANCIAL RESULTS (Thousands)
Energy service contract revenues		$	42,580		$	46,494		$	88,098		$	81,933
Energy service contract costs		34,074			36,136			70,156			63,001
Net operating revenues (gross profit margin)		8,506			10,358			17,942			18,932
Operating expenses:
Selling, general and administrative		5,733			5,572			10,899			11,088
Impairment of long-lived assets		—			5,320			—			5,320
Depreciation		341			444			690			881
Total operating expenses		6,074			11,336			11,589			17,289
Operating income (loss)		$	2,432		$	(978	)	$	6,353		$	1,643
Equity earnings from nonconsolidated investments		$	1,452		$	366		$	2,389		$	1,945

 

32

 

Three Months Ended June 30, 2003

vs. Three Months Ended June 30, 2002

 

NORESCO’s operating income increased $3.4 million to $2.4 million from a loss of $1.0 million in the second quarter 2002.  This increase in operating income is primarily attributable to a write-down of $5.3 million for the Jamaica Power Plant during the second quarter of 2002.  Net of the Jamaica write-down, operating income decreased by $1.9 million from $4.3 in the second quarter 2002. The decrease was primarily due to a decrease of $1.1 million in construction activity and construction gross margin from the same period in 2002, and a decrease of $0.7 million in operating income from that same period last year due to the shut-down of the Jamaica power plant.  Total revenue for the second quarter 2003 decreased by 8% to $42.6 million, compared to $46.5 million in the second quarter 2002, due to a reduction in construction backlog.

 

Revenue backlog in the current year decreased by $79.0 million from $157.4 million on June 30, 2002 to $78.4 million on June 30, 2003, primarily due to a decrease in new energy infrastructure and federal government performance contracts awarded.  Additionally, two large projects that were slated for signings in the second quarter 2003 were delayed.

 

NORESCO’s second quarter 2003 gross margin decreased to $8.5 million compared to $10.4 million during the second quarter 2002.  Gross profit margin decreased as a percentage of revenue from 22.3% in the second quarter 2002 to 20.0% in the second quarter 2003.  The decrease in gross margin was due to the gross profit margin mix of construction completed for the period.

 

Equity in earnings from power plant investments during the second quarter 2003 increased to $1.5 million from $0.4 million during the second quarter 2002.  This increase is primarily due to higher equity in earnings from the Pan Am project due to improved operating margins and lower bad debt expense from the Rhode Island project.

 

Total operating expenses decreased by $5.2 million to $6.1 million for the second quarter 2003 versus $11.3 million for the same period in 2002, primarily due to a write-down of $5.3 million for the Jamaica power plant during the second quarter of 2002.  Net of the Jamaica impairment operating expenses were relatively flat.  SG&A as a percentage of revenue increased to 13.5% versus 12.0% for the same period last year, due to a decrease in revenue for the period.

 

Six Months Ended June 30, 2003

vs. Six Months Ended June 30, 2002

 

NORESCO’s operating income increased $4.8 million to $6.4 million from $1.6 million in the same period last year.  This increase was primarily attributable a write-off of $5.3 million for the Jamaica power plant during 2002. Net of the Jamaica impairment, operating income decreased $0.5 million to $6.4 million, from $6.9 million in the second quarter of 2002.  The decrease is due to a $0.8 million decrease in operating income from the Jamaica power plant since its shut-down, partially offset by a reduction in operating expenses.  Revenue increased by 7.6% to $88.1 million compared to $81.9 million in 2002, which was mainly due to increased construction activity.

 

NORESCO’s gross margin decreased to $17.9 million compared to $18.9 million during the first half of 2002 primarily due to the reduction of $0.8 million from the shut-down of the Jamaica power plant.  Gross margin as a percentage of revenue decreased to 20.4% in the first half of 2003 compared to 23.1% during the same period in 2002.  The decrease in gross margin was due to the gross profit margin mix of construction completed for the period.

 

Equity in earnings from power plant investments during the six months ended June 30, 2003 increased to $2.4 million from $1.9 million during the first half of 2002.  This increase was primarily due to improved operating margins for the Pan Am project and lower bad debt expense from the Rhode Island project.

 

Total operating expenses decreased $5.7 million to $11.6 million versus $17.3 million for the same period in 2002.  Net of the Jamaica write-down of $5.3 million in the second quarter of 2002, operating expenses decreased $0.4 million, primarily due to reduced direct labor expenses.   SG&A as a percentage of revenue decreased to 12.4% versus 13.5% for the same period last year.

 

33

 

EQUITY IN NONCONSOLIDATED INVESTMENTS

 

On April 10, 2000, Equitable Resources merged its Gulf of Mexico operations with Westport Oil and Gas Company for approximately $50 million in cash and approximately 49% of a minority interest in the combined company, named Westport Resources Corporation (Westport).  Equitable Resources accounted for this investment under the equity method of accounting.  In October 2000, Westport completed an initial public offering (IPO) of its shares.  Equitable Resources sold 1.325 million shares in this IPO for an after-tax gain of $4.3 million.  On August 21, 2001, Westport Resources completed a merger with Belco Oil & Gas.  On March 31, 2003, the Company donated 905,000 shares to a community giving foundation.  As a result, the Company currently owns approximately 13 million shares, or 19.5% of Westport, a decrease from 20.8% at the end of 2002.  The Company does not have operational control of Westport.  As a result of the decreased ownership, the Company changed the accounting treatment for its investment in the first quarter of 2003 from the equity method to available-for-sale, effective March 31, 2003.  The change in accounting method eliminated the inclusion of Westport’s results subsequent to March 31, 2003 in the Company’s earnings.  Also, the Company’s investment in Westport was reclassified to Investments, available-for-sale on the Condensed Consolidated Balance Sheet as of March 31, 2003, and was adjusted to fair market value, in accordance with Statement No. 115.  The equity investment at the time it was reclassified totaled $134.1 million.  The fair market value of the Company’s investment in Westport was $295.9 million as of June 30, 2003 and was calculated based upon the quoted market price of Westport as of June 30, 2003.  If the Company were to immediately liquidate its investment position in Westport, it would likely be at some discount to the quoted market price.  The increase in the carrying value of the investment of $161.8 million represents an unrealized gain recorded net of tax in accumulated other comprehensive income.  As described in Note A to the Condensed Consolidated Financial Statements, as of June 30, 2003, the Company recorded a reclassification adjustment of $52.9 million to reduce accumulated other comprehensive income and increase common stock to reflect the increases in the book basis of the Company’s investment in Westport from the previous Westport capital transactions.  Therefore, the total mark-to-market basis of the Westport investment is unchanged as of June 30, 2003, but the increase in common stock value will prospectively reduce any realized gains on sale of Westport stock by the Company due to the increase in book basis to $16.53 per share, from $10.25 per share.  There will be no additional impact to the ongoing Statement No. 115 mark-to-market adjustments as a result of the Westport capital transactions.

 

During 2000, the Company, through its Equitable Supply segment, entered into transactions with Eastern Seven Partners, L.P. (ESP) and Appalachian Natural Gas Trust (ANGT) by which natural gas producing properties located in the Appalachian Basin region of the United States were sold.  The Company has retained a 1% interest in ESP and ANGT and has separately negotiated arms-length, market-based rates with each of these entities for gathering, marketing and operating fees to deliver their natural gas to market.  The Company’s cumulative investment in ESP and ANGT as of June 30, 2003 totaled $62.0 million.  The Company’s equity earnings for its investment in ESP and ANGT for the three months ended June 30, 2003 and 2002 was not significant.

 

There are currently five NORESCO projects held through equity in nonconsolidated entities, which consist of private power generation, cogeneration and central plant facilities located domestically and in selected international locations.  When possible, long-term power purchase agreements (PPAs) are signed with the customer whereby the customer agrees to purchase the energy generated by the plant.  The length of these contracts ranges from 1 to 30 years.  The Company has not made an investment since April 2001 and has a cumulative investment of $46.2 million as of June 30, 2003.  The Company’s share of the earnings for the second quarter of 2003 and 2002 related to the total investment was $1.5 million and $0.4 million, respectively.  These projects generally are financed with nonrecourse financings at the project level.

 

As has been previously reported, the Company owns a 50% interest in the supplier of power and conditioned air to a mall located in Providence, RI.  The project company has experienced billing disputes with the mall stores (its customers), and the project has reserved for the amounts in dispute pending their resolution.  In 2002, the project company sued a major mall tenant in State court and later threatened to shut off its power and conditioned air.  This resulted in a settlement featuring a sizeable down payment to the project company, and an agreement by the customer to pay a percentage of the invoiced amounts going forward. The project company also has been in discussions with the mall owner for a global settlement that would resolve outstanding payment issues.   NORESCO’s equity interest in this non-recourse financed project is $4.3 million as of June 30, 2003.  The Company is currently investigating all possible options for resolution of the dispute.

 

34

 

The Company owns a 50% interest in a Panamanian electric generation project, IGC/ERI Pan-Am Thermal.  The project had previously agreed to retrofit the plant to conform to environmental noise standards by a target date of August 31, 2001.  Unforeseen events delayed the final completion date of the required retrofits, and the project obtained an extension from the Panamanian government while the government evaluates a land acquisition/rezoning proposal, which, if accepted and executed, would eliminate the need for a retrofit requirement.  The creditor sponsor continues to evaluate the land acquisition/rezoning proposal while concurrently exploring the feasibility of a final technical resolution to the noise issues.  In September and October 2002, the Panamanian government adopted two resolutions which affect the plant’s compliance requirements—by suspending the noise mitigation deadline while the Company achieves the objectives of the land acquisition and rezoning proposal, and by modifying the noise standards applicable to the plant (by making them less stringent).  In June 2003, the Supreme Court of Panama found unconstitutional the compliance requirement that modified the noise standards applicable to the plant.  The impact on the project is currently being assessed.  The expected additional cost to the Company of achieving resolution of this issue, whether by a plant retrofit or implementation of the land acquisition/rezoning proposal, is not expected to exceed $1.5 million and would be funded by project funds.

 

Additionally, this project experienced poor financial performance during 2002 due to adverse weather (abnormally high rainfall), other adverse market-related conditions, and reduced plant availability related to planned and unplanned outages.  These factors depressed revenues, causing a drop below the minimum debt service coverage ratio covenant of the non-recourse loan document.  The Company has been actively coordinating with the creditor sponsor on this matter and during the second half of 2002 and the first half of 2003 experienced improvement in operational and financial performance.  Despite the debt service coverage ratio issues, cash flows are expected to be sufficient to service the debt through 2003.

 

Finally, the project company inadvertently violated a covenant in the project loan agreement, which restricts contracting for certain power sales.  The violation has been disclosed to the creditor sponsor and a formal waiver is actively being sought.

 

NON-GAAP DISCLOSURES

 

The SEC issued a final rule regarding the use of non-Generally Accepted Accounting Principles (GAAP) financial measures by public companies.  The rule defines a non-GAAP financial measure as a numerical measure of an issuer’s historical or future financial performance, financial position or cash flows that:

 

1)              Exclude amounts, or is subject to adjustments that have the effect of excluding amounts, that are included in the comparable measure calculated and presented in accordance with GAAP in the financial statements.

2)              Includes amounts, or is subject to adjustments that have the effect of including amounts, that are excluded from the comparable measure so calculated and presented.

 

The Company has reported operating income, minority interest and equity earnings from nonconsolidated investments, excluding Westport, by segment in the MD&A section of this Form 10-Q because management evaluates the operating segments based on their contribution to the Company’s consolidated results based on these items, and management believes investors would find this information useful.  Interest charges and income taxes are managed on a consolidated basis and are allocated proportionately to the operating segments based upon the respective capital structures and separate company income tax liabilities of the operating segments.  Headquarters’ costs are billed to the operating segments based upon a fixed allocation of the headquarters’ annual operating budget.  Differences between budget and actual headquarters’ expenses are not allocated to the operating segments.

 

The Company has reconciled the segments’ operating income, minority interest and equity earnings from nonconsolidated investments, excluding Westport, to the Company’s consolidated operating income, minority interest and equity earnings from nonconsolidated investment totals in Footnote B to the Notes to the Condensed Consolidated Financial Statements.  Additionally, these subtotals are reconciled to the Company’s consolidated net income in Footnote B.  The Company has also reported the components of each segment’s operating income and various operational measures in the MD&A section of this Form 10-Q, and where appropriate, has provided a footnote describing how the measure was derived.  The components of each segment’s operating income and the various operational measures were included to enhance the discussion of each segment’s operations.

 

35

 

CAPITAL RESOURCES AND LIQUIDITY

 

Operating Activities

 

Cash flows provided by operating activities totaled $145.5 million, a $31.1 million decrease from the $176.6 million recorded in the prior year period.  The decrease is primarily the result of the decrease in cash provided from working capital due to an increase in inventory during the six months ended June 30, 2003 as compared to a decrease during the six months ended June 30, 2003 generally resulting from increased natural gas prices in the current year.  This decrease was partially offset by an increase in income from continuing operations before cumulative effect of accounting change, as adjusted to net cash provided by operating activities, primarily due to the performance of the Company’s operating segments as previously described.

 

In the Company’s Statement of Cash Flows, the accounting presentation of the prepaid gas forward sales at the time the transactions were consummated was to reflect the activity as an operating cash flow item.  Consistent with the Company's previous presentation, the current presentation includes recognition of monetized production revenues related to prepaid forward gas sales in operating activities. The amount for the three months ended June 30, 2003 and 2002 is $13.9 million and $27.6 million for the six month periods then ended. However, due to the complexity and different market variations of these types of transactions, the SEC has required other prepaid forward transactions of other issuers to be reflected as a financing activity in the Statement of Cash Flows.  See Note A to the Company's Condensed Consolidated Financial Statements for additional information.

 

Investing Activities

 

Cash flows used in investing activities during the first six months of 2003 totaled $128.3 million, a $105.5 million increase from the $22.8 million recorded in the prior year period.  The change from the prior year is primarily attributable to an increase in capital expenditures of $48.1 million related to the purchase of the remaining limited partnership interest in ABP, a decrease in restricted cash totaling $63.0 during 2002 as a result of restrictions lapsing on proceeds relating to the sale in 2001 of oil-dominated fields within the Supply segment, the combination of which are offset by the proceeds received from the sale of wells in Ohio during 2003.

 

The Company expects to finance its authorized 2003 capital expenditures program with cash generated from operations and with short-term financing.  The ABP transaction was approved separately from the capital expenditures program and was financed through short-term financing.

 

Financing Activities

 

Cash flows used in financing activities during the first six months of 2003 totaled $11.8 million, a $165.1 million decrease from the $176.9 million recorded in the prior year period.  The decrease is primarily the result of the $200 million issuance of notes in February 2003, with a stated interest rate of 5.15% and a maturity date of March 2018.  The proceeds from the issuance were used to retire the Company’s entire $125 million of 7.35% Trust Preferred Securities on April 23, 2003, and for general corporate purposes, including reducing the Company’s short-term debt balance.  Excluding proceeds received from the debt issuance, cash flows used in financing activities during 2003 were relatively consistent with 2002 and primarily related to the Company’s continued focus on reducing its short-term debt, paying dividends, and purchasing shares of its outstanding stock through the use of cash provided by operating activities.

 

36

 

During the first quarter of 2001, a Jamaican energy infrastructure project, owned by a consolidated subsidiary, experienced defaults relating to various loan covenants.  Consequently, the Company reclassified the non-recourse project financing from long-term debt to current liabilities.  The plant has not operated to expected levels and remediation efforts were ineffective.  As a result, in the second quarter of 2002, the Company reviewed the project for impairment and recognized an impairment loss of $5.3 million. During the first quarter of 2003, the Jamaica power plant project shut down its engines and terminated most of the staff in order to preserve available cash while discussions among different parties involved in the project continued, seeking a global settlement.   After an extended period of troubled operations (more fully described in the Company’s 2002 Form 10K), ERI JAM, LLC, a subsidiary that holds the Company’s interest in the international infrastructure project, filed for bankruptcy protection under Chapter 11 in U.S. Bankruptcy Court (Delaware) in April 2003.  The Company will continue to consolidate the partnership until it no longer has control, which management expects to occur by the end of the year.  This change will not have a material effect on the Company’s financial position or results of operations as the Company has already written off its entire investment in the project and the project debt is non-recourse.

 

The Company has adequate borrowing capacity to meet its financing requirements.  Bank loans and commercial paper, supported by available credit, are used to meet short-term financing requirements.  The Company maintains, with a group of banks, a three-year revolving credit agreement providing $250 million of available credit, and a 364-day credit agreement providing $250 million of available credit that expire in 2005 and 2003, respectively.  As of June 30, 2003, the Company has the authority to arrange for a commercial paper program up to $650 million.

 

Hedging

 

The Company’s overall objective in its hedging program is to protect earnings from undue exposure to the risk of changing commodity prices.

 

With respect to hedging the Company’s exposure to changes in natural gas commodity prices, management’s objective is to provide price protection for the majority of expected production for the years 2003 through 2008, and over 25% of expected equity production for the years 2009 through 2010.  The Company’s exposure to a $0.10 change in NYMEX is less than $0.005 in 2003 and is approximately $0.01 in 2004 and 2005.  While the Company does use derivative instruments that create a price floor in order to provide downside protection while allowing the Company to participate in upward price movements through the use of costless collars and straight floors, the preponderance of instruments tend to be fixed price swaps or NYMEX-traded forwards.  This approach avoids the higher cost of option instruments but limits the upside potential.  The Company also engages in basis swaps to mitigate the fixed price exposure inherent in its firm capacity commodity commitments.  During the quarter ended June 30, 2003, the Company hedged approximately 4.0 Bcf of natural gas basis exposure through June 2004.

 

The approximate volumes and prices of the Company’s hedges and fixed price contracts for 2003 to 2005 are:

 

		2003			2004			2005
Volume (Bcf)		47			49			46
Average Price per Mcf (NYMEX)*		$	4.22		$	4.50		$	4.60

 

* The above price is based on a conversion rate of 1.05 MMbtu/Mcf

 

Commitments and Contingencies

 

The Company has annual commitments of approximately $25.4 million for demand charges under existing long-term contracts with various pipeline suppliers for periods extending up to 9 years as of June 30, 2003, which relate to natural gas distribution and production operations.  However, approximately $19.5 million of these costs are recoverable in customer rates.

 

37

 

There are various claims and legal proceedings against the Company arising in the normal course of business.  Although counsel is unable to predict with certainty the ultimate outcome, management and counsel believe that the Company has significant and meritorious defenses to any claims and intends to pursue them vigorously.  The Company has provided adequate reserves and therefore believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position of the Company.  The reserves recorded by the Company do not include any amounts for legal costs expected to be incurred.  It is the Company’s policy to recognize any legal costs associated with any claims and legal proceedings against the Company as they are incurred.

 

The various regulatory authorities that oversee Equitable’s operations, from time to time, make inquiries or investigations into the activities of the Company.  Equitable is not aware of any wrongdoing relating to any such inquiries or investigations.

 

The Company has received informal requests for information from the Commodity Futures Trading Commission (CFTC) regarding the reporting of prices to industry publications during 2000, 2001, and 2002.  The Company has cooperated fully with the CFTC in this matter as the Company always does when regulatory bodies make requests.  The Company has investigated this matter thoroughly internally and uncovered no evidence to date that any of its employees ever intentionally reported any false information to any industry publication.

 

In July 2002, the EPA published a final rule that amends the Oil Pollution Prevention Regulation.  The effective date of the rule was August 16, 2002.  Under the final rule, Owners/Operators of existing facilities were to revise their Spill Prevention, Control and Countermeasure (SPCC) plans on or before February 17, 2003 and were required to implement the amended plans as soon as possible but not later than August 18, 2003.  On April 17, 2003, the EPA extended the compliance deadlines for plan amendment to August 17, 2004 and implementation of the amended plan as soon as possible, but not later than February 18, 2005.  There is currently active litigation against the final rule and management anticipates that the regulation will be modified.  If the regulation is implemented in its current form, management believes that the Company may either incur capital expenditures in remediation, the amount of which is uncertain but expected to be significant, or plug and abandon an undetermined number of marginal wells.  Management is currently in the process of evaluating the impact of compliance with this final rule.

 

The Company is also subject to federal state and local environmental laws and regulations.  These laws and regulations, which are constantly changing, can require expenditures for remediation and may in certain instances result in assessment of fines.  The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures.  The estimated costs associated with identified situations that require remedial action are accrued.  However, certain costs are deferred as regulatory assets when recoverable through regulated rates.  Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material.  Management believes that any such required expenditures will not be significantly different in either their nature or amount in the future and does not know of any environmental liabilities that will have a material effect on the Company’s financial position or results of operations.

 

Benefit Plans

 

The condition of the financial markets over the last few years has led to a significant reduction in the fair market value of the Company’s pension plan assets.  As a result, the Company’s benefit obligation relating to its pension plan is significantly underfunded.  The Company expects to make contributions to its pension plans during 2003 totaling at least $30 million by the end of the third quarter 2003.  The Company made a $0.9 million and a $0.7 million contribution to its pension plan in April and July of 2003, respectively.  The Company is currently reviewing its benefit plan options before the remaining contribution is made.

 

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Stock-Based Compensation

 

The Company applies Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees,” and related interpretations in accounting for its stock-based compensation and has consequently not recognized any compensation cost for its stock option awards.  Had compensation cost been determined based upon the fair value at the grant date for the prior years’ stock option grants and the 0.5 million stock option grant awarded during the six months ended June 30, 2003 consistent with the methodology prescribed in Statement No. 123 “Accounting for Stock-Based Compensation,” net income and diluted earnings per share for the six months ended June 30, 2003 would have been reduced by an estimated $3.5 million or $0.06 per diluted share.  The estimate of compensation cost is based upon the use of the Black-Scholes option pricing model.  The Black-Scholes model is considered a “theoretical” or probability model used to estimate what an option would sell for in the market today.  The Company does not represent that this method yields an exact value of what an unrelated third party (i.e., the market) would be willing to pay to acquire such options.

 

Nonconventional Fuels Tax Credits

 

As a result of the Company’s increased partnership interest in ABP in 2002, the Company began receiving a greater percentage of the nonconventional fuels tax credit.  This resulted in a reduction in the Company’s effective tax rate during 2002.  The nonconventional fuels tax credit expired at the end of 2002.  On April 11, 2003, the Energy Policy Act of 2003 (H.R. 6) was passed by the House of Representatives and included an extension of the nonconventional fuels tax credit for existing qualifying wells and for newly drilled qualifying wells.  A different Senate proposal to extend the nonconventional fuels tax credit for newly drilled qualifying wells was included in the Energy Policy Bill of 2002 (H.R. 4).  H.R. 4 was passed by the Senate on July 31, 2003 as a substitute bill to the Energy Policy Bill of 2003 (S. 14) in a compromise among Senate Republicans and Democrats.  H.R. 6 and H.R. 4 contain many different provisions that must be resolved and conferees from the House of Representatives and the Senate will be named to work on a compromise of the two bills.  Any extension of the nonconventional fuels tax credit continues to be uncertain.

 

Dividend

 

On July 17, 2003, the Board of Directors of the Company declared a regular quarterly cash dividend of 30 cents per share, payable September 1, 2003 to shareholders of record on August 15, 2003.  This is a 50% increase over the June 1, 2003 dividend and is the second increase in 2003, resulting in a total increase of 76%.  Going forward, the Company is targeting dividend growth at a rate similar to the rate of its earnings per share growth.

 

Purchase of Treasury Stock

 

During the three and six months ended June 30, 2003, the Company repurchased 483,000 and 931,000 shares of Equitable Resources, Inc. stock, respectively.  The total number of shares repurchased since October 1998 is approximately 16.2 million out of the current 18.8 million share repurchase authorization.

 

Acquisitions and Dispositions

 

In February 2003, the Company purchased the remaining 31% limited partnership interest in ABP from the minority interest holders for $44.2 million.  The limited partnership interest represents approximately 60.2 Bcf of reserves.  As a result, effective February 1, 2003, the Company no longer recognizes minority interest expense associated with ABP, which totaled $1.9 million for the three months ended June 30, 2002, and $0.9 million and $3.4 million for the six months ended June 30, 2003 and 2002, respectively.

 

In February 2003, the Company sold approximately 500 of its low-producing wells, within two of its non-strategic districts, in two separate transactions.  The sales resulted in a decrease of 15.3 Bcf of net reserves for proceeds of approximately $6.6 million.  The wells produced approximately 0.8 Bcf annually.

 

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Critical Accounting Policies

 

The Company’s critical accounting policies are described in the notes to the Company’s consolidated financial statements for the year ended December 31, 2002 contained in the Company’s Annual Report on Form 10-K.  Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to the Company’s condensed consolidated financial statements for the period ended June 30, 2003.  The application of these policies may require management to make judgments and estimates about the amounts reflected in the consolidated financial statements.  Management uses historical experience and all available information to make these estimates and judgments, and different amounts could be reported using different assumptions and estimates.

 

Schedule of Certain Contractual Obligations

 

Below is a table that details the future projected payments for the Company’s significant contractual obligations as of June 30, 2003.  Approximately $19.5 million of the unconditional purchase obligations listed below are recoverable in rates.

 

		Payments Due by Period
		Total			2003			2004-2005			2006-2007			2008+
		(Thousands)
Interest expense		$	566,693		$	20,042		$	76,956		$	74,821		$	394,874
Long-term debt		674,836			25,387			31,614			14,335			603,500
Unconditional purchase obligations		212,507			16,421			60,896			55,319			79,871
Total contractual cash obligations		$	1,454,036		$	61,850		$	169,466		$	144,475		$	1,078,245

 

Included in long-term debt is a current portion of non-recourse project financing totaling $15.9 million that relates directly to the defaults on the debt convenants for the Jamaican energy infrastructure project in the NORESCO segment previously discussed, for which the bank may attempt to call the loan.

 

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Equitable Resources, Inc. and Subsidiaries

 

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

 

The Company’s primary market risk exposure is the volatility of future prices for natural gas, which can affect the operating results of the Company through the Equitable Supply segment and the unregulated marketing group within the Equitable Utilities segment.  The Company uses simple, non-leveraged derivative instruments that are placed with major institutions whose creditworthiness is continually monitored.  The Company also enters into energy trading contracts to leverage its assets and limit the exposure to shifts in market prices.  The Company’s use of these derivative financial instruments is implemented under a set of policies approved by the Company’s Corporate Risk Committee and Board of Directors.

 

With respect to energy derivatives held by the Company for purposes other than trading (hedging activities), the Company continued to execute its hedging strategy by utilizing price swaps and futures of approximately 248.9 Bcf of natural gas.  Some of these derivatives have hedged expected equity production through 2010.  A decrease of 10% in the market price of natural gas would increase the fair value of natural gas instruments by approximately $131.1 million at June 30, 2003.

 

With respect to derivative contracts held by the Company for trading purposes, as of June 30, 2003, a decrease of 10% in the market price of natural gas would decrease the fair market value by approximately $0.2 million.  An increase of 10% in the market price would increase the fair market value by approximately $0.2 million.  The Company determined the change in the fair value of the natural gas instruments in a method similar to its normal change in fair value as described in Footnote D to the Notes to the Condensed Consolidated Financial Statements.  The Company assumed a 10% change in the price of natural gas from its levels at June 30, 2003.  The price change was then applied to the natural gas instruments recorded on the Company’s balance sheet, resulting in the change in fair value.

 

See Footnote D regarding Derivative Instruments in the Notes to the Condensed Consolidated Financial Statements and the Hedging section contained in the Capital Resources and Liquidity section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for further information.

 

The Company is exposed to market risk associated with its holdings in Westport, which is accounted for as an available-for-sale security.  The Company does not attempt to reduce this risk through the use of derivatives.

 

Item 4.    Controls and Procedures

 

The Chief Executive Officer and Chief Financial Officer conducted an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as defined in Exchange Act Rule 13a-15(e) as of the end of the period covered by this report.  Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this report.  There were no significant changes in internal controls over financial reporting that occurred during the second quarter of 2003 that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

 

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PART II.  OTHER INFORMATION

 

Item 4.    Submission of Matters to a Vote of Security Holders

 

a).            The Annual Meeting of Shareholders was held on May 15, 2003.

 

b).           Brief description of matters voted upon:

 

(1)                                  Elected the named directors to serve three-year terms as follows:

 

Director		Shares Voted For		Shares Withheld
E. Lawrence Keyes, Jr.		44,908,845		12,190,019
Thomas A. McConomy		44,913,617		12,185,247
Barbara S. Jeremiah		56,502,674		596,190

 

The following Directors terms continue after the Annual Meeting of Shareholders:

until 2004 – Murry S. Gerber, and George L. Miles, Jr.;

until 2005 – Phyllis A. Domm, Ed.D., David L. Porges, James E. Rohr, and David S. Shapira

 

(2)                                  Ratified appointment of Ernst & Young, LLP, as independent auditors for the year ended December 31, 2003.  Vote was 54,434,827 shares for; 2,599,313 shares against and 64,724 shares abstained.

 

Item 5.           Other Information

 

Commencing in its Consolidated Financial Statements filed with the SEC on Form 10-K for the year ended December 31, 2002, the Company prepared its financial statements in compliance with EITF No. 02-3, as revised (see Note J to the Condensed Consolidated Financial Statements), which required some reclassifications for prior periods.  As a result, the Company believes that its investors may find the following quarterly segment information to be informative:

 

		March 31			June 30			September 30			December 31
		(Thousands)
2003
Operating Revenues:
Equitable Utilities		$	236,109		$	115,620
Equitable Supply		81,697			79,385
NORESCO		45,518			42,580
Intersegment revenues		(21,002		)	(19,089		)
Total		$	342,322		$	218,496
2002
Operating Revenues:
Equitable Utilities		$	223,751		$	148,960		$	129,496		$	252,066
Equitable Supply		66,402			68,028			72,031			82,531
NORESCO		35,439			46,494			54,210			53,964
Intersegment revenues		(31,549		)	(36,811		)	(41,319		)	(54,625		)
Total		$	294,043		$	226,671		$	214,418		$	333,936
2001
Operating Revenues:
Equitable Utilities		$	397,936		$	190,344		$	113,014		$	147,764
Equitable Supply		90,487			75,556			68,323			67,912
NORESCO		34,464			35,311			40,312			47,292
Intersegment revenues		(83,182		)	(58,399		)	(35,976		)	(21,824		)
Total		$	439,705		$	242,812		$	185,673		$	241,144

 

The segment information provided above is in accordance with the guidance contained in EITF No. 02-3, as revised.

 

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Item 6.    Exhibits and Reports on Form 8-K

 

(a)          Exhibits:

 

10.1                                 Equitable Resources, Inc. $250,000,000 364-Day Credit Agreement dated November 1, 2002

 

10.2                                 Equitable Resources, Inc. $250,000,000 Revolving Credit Agreement dated November 1, 2002

 

10.3                                 Indenture with The Bank of New York, as successor to Bank of Montreal Trust Company, as Trustee, dated as of July 1, 1996

 

10.4                                 Resolutions adopted January 16, 2003 by the Board of Directors establishing the terms of the offering of up to $200,000,000 aggregate principal amount of 5.15% Notes due 2018

 

10.5                                 Officer’s Declaration dated February 20, 2003 establishing the terms of the issuance and sale of the Notes of the Company in an aggregate amount of up to $200,000,000

 

10.6                                 Officer’s Certificate dated February 27, 2003 certifying the terms and form of the Notes in an aggregate amount of up to $200,000,000

 

10.7                                 Resolutions adopted October 17, 2002 by the Board of Directors establishing the terms of the offering of up to $200,000,000 aggregate principal amount of 5.15% Notes Due 2012

 

10.8                                 Officer’s Declaration dated November 7, 2002 establishing the terms of the issuance and sale of the Notes of the Company in an aggregate amount of up to $200,000,000

 

10.9                                 Officer’s Certificate dated November 15, 2002 certifying the terms and form of the Notes in an aggregate amount of up to $200,000,000

 

10.10                           Equitable Resources, Inc. Directors’ Deferred Compensation Plan (as amended and restated May 15, 2003)

 

31.1                                 Certification by Murry S. Gerber pursuant to Rule 13a-14(a) or Rule 15d-14(a)

 

31.2                                 Certification by David L. Porges pursuant to Rule 13a-14(a) or Rule 15d-14(a)

 

32                                        Certification by Murry S. Gerber and David L. Porges pursuant to 18 U.S.C Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

(b)   Reports on Form 8-K during the quarter ended June 30, 2003:

 

(i)       Form 8-K dated April 2, 2003 disclosing the Company’s issuance of a press release announcing the creation of a community giving foundation.

 

(ii)    Form 8-K dated April 22, 2003 disclosing the Company’s issuance of a press release announcing the results of its first quarter 2003 earnings.

 

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Signature

 

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

	EQUITABLE RESOURCES, INC.
	(Registrant)
	/s/ David L. Porges
	David L. Porges
	Executive Vice President and Chief Financial Officer
Date:  August 14, 2003

 

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INDEX TO EXHIBITS

 

Exhibit No.		Document Description
10.1		Equitable Resources, Inc. $250,000,000 364-Day Credit Agreement dated November 1, 2002		Filed Herewith
10.2		Equitable Resources, Inc. $250,000,000 Revolving Credit Agreement dated November 1, 2002		Filed Herewith
10.3		Indenture with The Bank of New York, as successor to Bank of Montreal Trust Company, as Trustee, dated as of July 1, 1996		Filed as Exhibit 4.01(a) to Form S-4 Registration Statement (#333-103178) filed on February 13, 2003.
10.4		Resolutions adopted January 16, 2003 by the Board of Directors establishing the terms of the offering of up to $200,000,000 aggregate principal amount of 5.15% Notes due 2018		Filed previously as Exhibit 4.01(b) to Form S-4 Registration Statement (#333-104392) filed on April 8, 2003.
10.5		Officer’s Declaration dated February 20, 2003 establishing the terms of the issuance and sale of the Notes of the Company in an aggregate amount of up to $200,000,000		Filed previously as Exhibit 4.01(c) to Form S-4 Registration Statement (#333-104392) filed on April 8, 2003.
10.6		Officer’s Certificate dated February 27, 2003 certifying the terms and form of the Notes in an aggregate amount of up to $200,000,000		Filed previously as Exhibit 4.01(d) to Form S-4 Registration Statement (#333-104392) filed on April 8, 2003.
10.7		Resolutions adopted October 17, 2002 by the Board of Directors establishing the terms of the offering of up to $200,000,000 aggregate principal amount of 5.15% Notes Due 2012		Filed previously as Exhibit 4.01(b) to Form S-4/A Registration Statement (#333-103178) filed on March 12, 2003.
10.8		Officer’s Declaration dated November 7, 2002 establishing the terms of the issuance and sale of the Notes of the Company in an aggregate amount of up to $200,000,000		Filed previously as Exhibit 4.01(c) to Form S-4/A Registration Statement (#333-103178) filed on March 12, 2003.
10.9		Officer’s Certificate dated November 15, 2002 certifying the terms and form of the Notes in an aggregate amount of up to $200,000,000		Filed previously as Exhibit 4.01(d) to Form S-4/A Registration Statement (#333-103178) filed on March 12, 2003.
10.10		Equitable Resources, Inc. Directors’ Deferred Compensation Plan (as amended and restated May 15, 2003)		Filed Herewith
31.1		Certification by Murry S. Gerber pursuant to Rule 13a-14(a) or Rule 15d-14(a)		Filed Herewith
31.2		Certification by David L. Porges pursuant to Rule 13a-14(a) or Rule 15d-14(a)		Filed Herewith
32		Certification by Murry S. Gerber and David L. Porges pursuant to 18 U.S.C Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002		Filed Herewith

 

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