UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

 

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

EQUITABLE RESOURCES, INC.

(Exact name of registrant as specified in its charter)

 

 

 

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 Nine Months Ended September 30, 2003 and 2002
		Statements of Condensed Consolidated Cash Flows for the Three and Nine Months Ended September 30, 2003 and 2002
		Condensed Consolidated Balance Sheets as of September 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 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 September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
		(Thousands, except per share amounts)
Operating revenues		$	185,515		$	214,418		$	746,333		$	735,132
Cost of sales		57,089			96,051			297,485			331,871
Net operating revenues		128,426			118,367			448,848			403,261
Operating expenses:
Operation and maintenance		18,848			18,833			56,304			54,829
Production and exploration		8,430			6,746			26,216			19,587
Selling, general and administrative		27,315			24,300			88,380			73,248
Impairment of long-lived assets		—			—			—			5,320
Depreciation, depletion and amortization		19,656			17,613			57,634			51,151
Total operating expenses		74,249			67,492			228,534			204,135
Operating income		54,177			50,875			220,314			199,126
Charitable contribution expense		—			—			(9,279		)	—
Equity earnings (losses) from nonconsolidated investments:
Westport		—			231			3,614			(4,642		)
Other		203			823			2,954			2,886
		203			1,054			6,568			(1,756		)
Minority interest		(277		)	(1,781		)	(1,148		)	(5,180		)
Interest expense		11,355			9,344			34,458			28,182
Income from continuing operations before income taxes and cumulative effect of accounting change		42,748			40,804			181,997			164,008
Income taxes		14,536			14,118			57,911			55,761
Income from continuing operations before cumulative effect of accounting change		28,212			26,686			124,086			108,247
Income from discontinued operations		—			—			—			9,000
Cumulative effect of accounting change, net of tax		—			—			(3,556		)	(5,519		)
Net income		$	28,212		$	26,686		$	120,530		$	111,728
Earnings (loss) per share of common stock:
Basic:
Weighted average common shares outstanding		62,053			62,326			62,051			63,023
Income from continuing operations before cumulative effect of accounting change		$	0.45		$	0.43		$	2.00		$	1.72
Income from discontinued operations		—			—			—			0.14
Cumulative effect of accounting change, net of tax		—			—			(0.06		)	(0.09		)
Net income		$	0.45		$	0.43		$	1.94		$	1.77
Diluted:
Weighted average common shares outstanding		63,336			63,668			63,364			64,541
Income from continuing operations before cumulative effect of accounting change		$	0.45		$	0.42		$	1.96		$	1.68
Income from discontinued operations		—			—			—			0.14
Cumulative effect of accounting change, net of tax		—			—			(0.06		)	(0.09		)
Net income		$	0.45		$	0.42		$	1.90		$	1.73
Dividends declared per common share		$	0.30		$	0.17		$	0.80		$	0.50

 

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 September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
		(Thousands)
Cash flows from operating activities:
Income from continuing operations before cumulative effect of accounting change		$	28,212		$	26,686		$	124,086		$	108,247
Adjustments to reconcile income from continuing operations before cumulative effect of accounting change to net cash (used in) provided by operating activities:
Provision for doubtful accounts		2,128			551			11,007			5,580
Depreciation, depletion, and amortization		19,656			17,613			57,634			51,151
Impairment of assets		—			—			—			5,320
Charitable contribution		—			—			9,279			—
Deferred income tax provision		(281		)	6,857			40,028			19,112
Recognition of monetized production revenue		(14,040		)	(14,040		)	(41,664		)	(41,664		)
Pension contribution		(48,740		)	—			(49,640		)	—
(Increase) decrease in undistributed earnings from nonconsolidated investments		(203		)	(1,152		)	(6,568		)	2,384
(Increase) decrease in inventory		(76,510		)	(32,402		)	(97,836		)	2,336
Changes in other assets and liabilities		25,723			9,001			35,125			37,199
Total adjustments		(92,267		)	(13,572		)	(42,635		)	81,418
Net cash (used in) provided by operating activities		(64,055		)	13,114			81,451			189,665
Cash flows from investing activities:
Capital expenditures		(62,223		)	(68,519		)	(152,858		)	(155,235		)
Purchase of minority interest in ABP		—			—			(44,200		)	—
Decrease in restricted cash		—			—			—			62,956
Decrease in equity of unconsolidated entities		—			77			—			1,050
Proceeds from sale of property		—			—			6,550			—
Net cash (used in) investing activities		(62,223		)	(68,442		)	(190,508		)	(91,229		)
Cash flows from financing activities:
Issuance of long-term debt		—			—			200,000			—
Dividends paid		(18,492		)	(10,474		)	(41,340		)	(31,257		)
Proceeds from exercises under employee compensation plans		4,587			4,784			23,114			14,487
Purchase of treasury stock		(10,143		)	(34,403		)	(44,975		)	(79,270		)
Loans against construction contracts		13,503			9,927			23,773			18,156
Repayments and retirement of long-term debt		(9,439		)	(162		)	(24,607		)	(477		)
Redemption of Trust Preferred Capital Securities		—			—			(125,000		)	—
Increase (decrease) in short-term loans		134,600			85,864			91,800			(43,047		)
Net cash provided by (used in) financing activities		114,616			55,536			102,765			(121,408		)
Net (decrease) increase in cash and cash equivalents		(11,662		)	208			(6,292		)	(22,972		)
Cash and cash equivalents at beginning of period		23,118			6,442			17,748			29,622
Cash and cash equivalents at end of period		$	11,456		$	6,650		$	11,456		$	6,650
Cash paid during the period for:
Interest, net of amount capitalized		$	13,045		$	12,480		$	35,527		$	30,469
Income taxes paid, net of refund		$	—		$	13		$	10,045		$	11,720

 

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

 

3

 

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

 

Condensed Consolidated Balance Sheets (Unaudited)

 

 

		September 30, 2003			December 31, 2002
		(Thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	11,456		$	17,748
Accounts receivable (less accumulated provision for doubtful accounts:  2003, $14,432; 2002, $15,294)		125,184			160,778
Unbilled revenues		105,700			130,348
Inventory		175,808			74,735
Derivative commodity instruments, at fair value		37,392			38,512
Prepaid expenses and other		20,222			7,930
Total current assets		475,762			430,051
Equity in nonconsolidated investments		104,674			245,792
Property, plant and equipment		2,727,926			2,545,138
Less accumulated depreciation and depletion		1,008,195			983,323
Net property, plant and equipment		1,719,731			1,561,815
Investments, available-for-sale		323,894			16,098
Other assets		179,153			183,135
Total		$	2,803,214		$	2,436,891

 

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

 

4

 

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

 

Condensed Consolidated Balance Sheets (Unaudited)

 

		September 30, 2003			December 31, 2002
		(Thousands)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt		$	21,255		$	24,250
Current portion of nonrecourse project financing		—			16,055
Short-term loans		197,800			106,000
Accounts payable		140,785			136,478
Prepaid gas forward sale		29,641			55,705
Derivative commodity instruments, at fair value		103,574			46,768
Current portion of project financing obligations		81,986			73,032
Other current liabilities		94,702			93,452
Total current liabilities		669,743			551,740
Long-term debt:
Debentures and medium-term notes		632,284			447,000
Deferred and other credits:
Deferred income taxes		435,395			350,690
Deferred investment tax credits		12,405			13,210
Prepaid gas forward sale		26,039			41,591
Project financing obligations		13,772			13,684
Other credits		103,731			115,337
Total deferred and other credits		591,342			534,512
Preferred trust securities		—			125,000
Capitalization:
Common stockholders’ equity:
Common stock, no par value, authorized 160,000 shares;  shares issued: September 30, 2003 and December 31, 2002, 74,504		339,973			287,597
Treasury stock, shares at cost: September 30, 2003, 12,247; December 31, 2002, 12,162 (net of shares and cost held in trust for deferred compensation of 616, $11,655 and 642, $12,273)		(293,635		)	(271,930		)
Retained earnings		866,695			787,505
Accumulated other comprehensive loss, net of tax		(3,188		)	(24,533		)
Total common stockholders’ equity		909,845			778,639
Total		$	2,803,214		$	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 September 30, 2003, and the results of its operations and cash flows for the three and nine month periods ended September 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 nine month periods ended September 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/A for the year ended December 31, 2002 as well as in “Information Regarding Forward Looking Statements” on page 20 of this document.

 

As previously disclosed, the Securities and Exchange Commission (SEC) conducted 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.  The SEC declared the Registration Statement effective on September 30, 2003.

 

As part of the Company’s discussions with the SEC, the Company reviewed its accounting for certain items, and changed its accounting treatment.  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 was unchanged, but the increase in common stock value will prospectively reduce any realized gains on the sale of Westport stock by increasing the 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.  This adjustment did not impact the total stockholder’s equity.

 

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

 

The Company 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 September 30, 2003, Hunterdon had $8.5 million of total assets, and $3.7 million of total liabilities, including $2.6 million of nonrecourse long-term debt of which $0.5 million is current.

 

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 September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
		(Thousands)
Revenues from external customers: (a)
Equitable Utilities		$	77,043		$	129,496		$	428,772		$	502,207
Equitable Supply		83,011			72,032			244,093			206,462
NORESCO		41,379			54,209			129,477			136,142
Less: intersegment revenues (b)		(15,918		)	(41,319		)	(56,009		)	(109,679		)
Total		$	185,515		$	214,418		$	746,333		$	735,132
Depreciation, depletion and amortization:
Equitable Utilities		$	6,784		$	6,876		$	20,308		$	19,981
Equitable Supply		12,363			10,301			35,964			29,771
NORESCO		396			367			1,086			1,248
Headquarters		113			69			276			151
Total		$	19,656		$	17,613		$	57,634		$	51,151
Operating income:
Equitable Utilities		$	5,333		$	3,340		$	77,088		$	71,895
Equitable Supply		50,605			42,692			144,785			122,048
NORESCO		4,761			5,072			11,114			6,715
Unallocated expenses		(6,522		)	(229		)	(12,673		)	(1,532		)
Total operating income		$	54,177		$	50,875		$	220,314		$	199,126
Reconciliation of operating income to net income:
Equity earnings in nonconsolidated investments, excluding Westport:
Equitable Supply		$	139		$	64		$	401		$	182
NORESCO		42			715			2,431			2,660
Unallocated earnings		22			44			122			44
Total		$	203		$	823		$	2,954		$	2,886
Minority interest:
Equitable Supply		$	—		$	(1,781	)	$	(871	)	$	(5,180	)
NORESCO		(277		)	—			(277		)	—
Total		$	(277	)	$	(1,781	)	$	(1,148	)	$	(5,180	)
Charitable contribution expense		—			—			(9,279		)	—
Westport equity earnings (losses)		—			231			3,614			(4,642		)
Interest expense		11,355			9,344			34,458			28,182
Income tax expense		14,536			14,118			57,911			55,761
Income from continuing operations before cumulative effect of accounting change		28,212			26,686			124,086			108,247
Income from discontinued operations		—			—			—			9,000
Cumulative effect of accounting change, net of tax (c)		—			—			(3,556		)	(5,519		)
Net income		$	28,212		$	26,686		$	120,530		$	111,728

 

8

 

		September 30, 2003			December 31, 2002
		(Thousands)
Segment Assets:
Equitable Utilities		$	994,343		$	929,718
Equitable Supply		1,139,422			1,079,924
NORESCO (d)		269,178			269,707
Total operating segments		2,402,943			2,279,349
Headquarters assets		400,271			157,542
Total		$	2,803,214		$	2,436,891

 

		Three Months Ended September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
		(Thousands)
Expenditures for segment assets:
Equitable Utilities		$	17,723		$	25,865		$	41,099		$	48,170
Equitable Supply (e)		44,114			41,483			154,619			105,530
NORESCO		108			271			254			635
Unallocated expenditures		278			900			1,086			900
Total		$	62,223		$	68,519		$	197,058		$	155,235

 

(a)          Revenues from external customers for prior periods have been reduced to conform with EITF No. 02-3.  See Note J.

(b)         Intersegment revenues represent 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 nine months ended September 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.

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

(e)          For the nine months ended September 30, 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 September 30, 2003, the Company had recorded a current liability of $82.0 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 three months ended September 30, 2003, no contract receivables met the criteria for sales treatment.  For the nine months ended September 30, 2003, 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 $37.0 million asset and a $100.4 million liability as of September 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 September 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 374.5 Bcf and 265.1 Bcf as of September 30, 2003 and December 31, 2002, respectively, and primarily relate to natural gas swaps.  The open swaps at September 30, 2003 have maturities extending through December 2010.

 

The Company deferred a net loss of $36.3 million and a gain of $2.8 million in accumulated other comprehensive loss, net of tax, as of September 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 $12.0 million of unrealized losses on its derivative commodity instruments reflected in accumulated other comprehensive loss, net of tax, as of September 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 September 30, 2003 and 2002, ineffectiveness associated with the Company’s derivative commodity instruments designated as cash flow hedges (decreased) increased earnings by approximately ($0.7 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 September 30, 2003, the absolute notional quantities of the futures and swaps held for trading purposes totaled 1.3 Bcf and 5.6 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 nine months ended September 30, 2003 (in thousands).  The fair value of these contracts as of September 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		(62		)
Other changes in fair value (a)		(6,225		)
Fair value of contracts outstanding as of September 30, 2003		$	336

 

(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 nine months ended September 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 September 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)		$	157		$	(50	)	$	—		$	107
Prices provided by other external sources (2)		159			32			38			229
Net derivative assets		$	316		$	(18	)	$	38		$	336

 

(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 19.3% 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 $306.1 million as of September 30, 2003 and was calculated based upon the quoted market price of Westport stock on that date.  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 $172.0 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 was 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.

 

Murry Gerber, Chairman, President and Chief Executive Officer of Equitable, resigned from the Westport’s Board of Directors, effective October 1, 2003.

 

The investments classified by the Company as available-for-sale also include approximately $17.7 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 September 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 nine months ended September 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 third quarter 2003.

 

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F.                          Comprehensive Income (Loss)

 

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

 

		Three Months Ended September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
		(Thousands)
Net income		$	28,212		$	26,686		$	120,530		$	111,728
Other comprehensive (loss) income:
Net change in cash flow hedges:
Natural gas (Note D)		57,731			10,334			(39,107		)	(69,748		)
Interest rate		30			(909		)	102			(909		)
Unrealized (loss) gain on investments, available-for-sale (Note E):
Westport		6,678			—			59,007		(a)	—
Other		57			(669		)	1,343			(1,243		)
Total comprehensive income		$	92,708		$	35,442		$	141,875		$	39,828

 

(a)  The nine-months ended September 30, 2003 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:

 

		September 30, 2003			December 31, 2002
		(Thousands)
Net unrealized (loss) gain from hedging transactions		$	(37,389	)	$	1,617
Unrealized gain (loss) on available-for-sale securities		58,857			(1,494		)
Minimum pension liability adjustment		(24,663		)	(24,663		)
Foreign currency translation adjustment		7			7
		$	(3,188	)	$	(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 (2003 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).

 

AGL Resources Inc.	MDU Resources Group Inc.	Piedmont Natural Gas Co., Inc.
ATMOS Energy Corp.	National Fuel Gas Co.	Questar Corp.
Cascade Natural Gas Corp.	New Jersey Resources Corp.	Sempra Energy
CMS Energy Corp.	NICOR, Inc.	Southern Union Co.
Dynegy Inc.	NISOURCE Inc.	Southwest Gas Corp.
El Paso Corp.	Northwest Natural Gas Co.	Southwestern Energy Co.
Energen Corp.	NUI Corp.	UGI Corp.
Keyspan Corp.	OGE Energy Corp.	Westar Energy Inc.
Kinder Morgan Inc.	ONEOK Inc.	WGL Holdings, Inc.
Laclede Group, Inc.	Peoples Energy Corp.	The Williams Companies, Inc.

 

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 nine month periods ended September 30, 2003 was $3.9 million and $10.4 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 nine month periods ended September 30, 2003 was $0.1 million and $0.3 million, respectively, and is classified as selling, general and administrative expense.

 

Additionally, 0.5 million stock options were awarded during the nine months ended September 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 September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
		(Thousands)
Net income, as reported		$	28,212		$	26,686		$	120,530		$	111,728
Add:  Stock-based employee compensation expense included in reported net income, net of related tax effects		3,807			386			10,701			1,105
Deduct: Total stock-based employee compensation expense determined by the fair value method for all awards, net of related tax effects		(5,493		)	(2,342		)	(15,732		)	(6,552		)
Pro forma net income		$	26,526		$	24,730		$	115,499		$	106,281
Earnings per share:
Basic, as reported		$	0.45		$	0.43		$	1.94		$	1.77
Basic, pro forma		$	0.43		$	0.40		$	1.86		$	1.69
Diluted, as reported		$	0.45		$	0.42		$	1.90		$	1.73
Diluted, pro forma		$	0.42		$	0.39		$	1.82		$	1.65

 

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 $1.8 million for the three months ended September 30, 2002, and $0.9 million and $5.2 million for the nine months ended September 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 nine months ended September 30, 2003 to the Company’s 31.8% estimated effective income tax rate recorded during that period.

 

J.                          Recently Issued 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 nine months ended September 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 September 30, 2003			Nine months ended September 30, 2003
		(Thousands)
Asset retirement obligation as of beginning of period		$	29,718		$	28,690
Accretion expense		494			1,459
Liabilities incurred		284			393
Liabilities settled		(500		)	(546		)
Asset retirement obligation as of end of period		$	29,996		$	29,996

 

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 nine month periods ended September 30, 2002.  Long-term liabilities, assuming retroactive application of the change in accounting principle as of January 1, 2002 and September 30, 2002, would have increased by $26.9 million and $28.2 million, respectively.

 

15

 

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 $0.09 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 September 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 nine months ended September 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 nine months ended September 30, 2002 of $31.2 million and $124.8 million, respectively.

 

16

 

Guarantees

 

In November 2002, the FASB issued FASB 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 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 set forth 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.  The Company has received a market-based fee for providing the guarantee.  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.

 

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 adoption of EITF No. 00-21 did not have a material impact on the Company’s financial position or 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.  Prior to FIN 46, entities were generally consolidated by an enterprise when it had a controlling financial interest through ownership of a majority voting interest in the entity.  FIN 46 is effective for all new variable interest entities created or acquired after January 31, 2003.  The Company adopted FIN 46 for variable interest entities created or acquired prior to February 1, 2003 as of July 1, 2003.  The adoption of FIN 46 required the consolidation of Plymouth Cogeneration Limited Partnership (Plymouth), a joint venture entered into by NORESCO, and the deconsolidation of EAL/ERI Cogeneration Partners LP (Jamaica), which is the partnership that holds the Jamaican power plant.

 

During 1992, NORESCO entered into the Plymouth joint venture to construct, own and operate a cogeneration facility and provide electricity and steam to Plymouth State College.  NORESCO originally recorded its interest in Plymouth on the Condensed Consolidated Balance Sheet as equity in unconsolidated investments. Under FIN 46, NORESCO is the primary beneficiary of Plymouth and began consolidating Plymouth in the accompanying condensed consolidated financial statements July 1, 2003.  The equity interests in Plymouth not owned by NORESCO are reported as a minority interest in the accompanying consolidated financial statements.

 

The consolidation of Plymouth removes the equity investment in Plymouth of $0.1 million and increases minority interest by $0.7 million in the Condensed Consolidated Balance Sheet.  As of July 1, 2003, the Company consolidated $5.0 million

 

17

 

in assets and $4.2 million in total liabilities, including nonrecourse long-term debt of $4.0 million of which $0.2 million was current.

 

NORESCO has a 91.24% interest in Jamaica and has historically consolidated Jamaica in the Company’s financial statements.  In the second quarter of 2002, the Company wrote off its entire investment in Jamaica due to poor performance.  In the second quarter of 2003, ERI JAM, LLC, the entity that holds the Company’s 91% interest in Jamaica declared bankruptcy and Jamaica stopped operations.

 

Upon adoption of FIN 46, it was determined that Jamaica was a variable interest entity and that the Company was not the primary beneficiary.  As a result, the Company deconsolidated Jamaica effective July 1, 2003.  The deconsolidation of Jamaica removes $17.8 million of assets and $18.0 million of total liabilities, including nonrecourse project financing of $15.8 million, all of which was current.  The Company did not establish an equity method investment in Jamaica upon deconsolidation, as the amount of such investment would be less than zero and there is no recourse against the Company beyond its investment in Jamaica.

 

The Company also has an interest in a variable interest entity, ANPI, in which Equitable was not deemed to be the primary beneficiary.  As of September 30, 2003, ANPI had $263.3 million of total assets and $265.0 million of liabilities (including $191.7 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.

 

In September 2003, the FASB issued proposed Staff Positions on FIN 46.  The Company does not expect the proposed FASB Staff Positions on FIN 46 will have a material impact on the conclusions reached in Company’s adoption of FIN 46 or the Company’s consolidated financial statements.  However, the Company will apply the proposed FASB Staff Positions on FIN 46, as applicable, in the period in which they become effective.

 

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 Implementation Group (DIG) and in other FASB projects or deliberations.  Statement No. 149 is effective for contracts entered into or modified after September 30, 2003, and for hedging relationships designated after September 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.  The adoption of this Statement did not have a material impact on the Company’s consolidated financial statements for the nine months ended September 30, 2003.

 

Accounting for Certain Costs and Activities Related to Property, Plant and Equipment

 

The American Institute of Certified Public Accountants issued an exposure draft Statement of Position (SOP) “Accounting for Certain Costs and Activities Related to Property, Plant, and Equipment (PP&E).”  This proposed SOP applies to all nongovernmental entities that “acquire, construct or replace tangible property, plant and equipment including lessors and lessees.”  A significant element of the SOP requires that entities use component accounting retroactively for all PP&E assets to the extent future component replacement will be capitalized.  At adoption, entities would have the option to apply component accounting retroactively for all PP&E assets, to the extent applicable, or to apply component accounting as an entity incurs capitalizable costs that replace all or a portion of PP&E.  It is uncertain at this time when a final SOP will be issued. The Company cannot evaluate the ultimate impact of this exposure draft until it becomes final.

 

18

 

K.                        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.  Effective September 30, 2003, the Company is offering all holders of its 5.15% Notes due 2018 the opportunity to exchange their Notes for a new issue of registered Notes pursuant to a Registration Statement on Form S-4. The exchange Notes will be identical in all material respects to the Notes being exchanged, except that the exchange Notes will not have terms restricting their transfer or any terms related to registration rights.

 

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 EAL/ERI Cogeneration Partners LP, an international infrastructure project, filed for bankruptcy protection under Chapter 11 in U.S. Bankruptcy Court (Delaware) in April 2003.  In the third quarter 2003, ERI JAM, LLC transferred control of the international infrastructure project under the partnership agreement to the other general partner.  The international infrastructure project was deconsolidated in accordance with FIN 46 (see Note J).  In September 2003, project-level counterparties, Jamaica Broilers Group Limited (JBG) and Energy Associated Limited (EAL), filed a claim against ERI JAM LLC as Debtor-in-Possession in the Chapter 11 case.  EAL is a limited partner in EAL/ERI Cogeneration Partners LP.  In October 2003, JBG and EAL also filed a multi-count complaint against Equitable and certain of its affiliates in U.S. District Court (Western District of PA).  Equitable and its affiliates intend to vigorously defend this litigation, which they view as without merit.  Global settlement discussions led by the managing general partner and the project lender are continuing in parallel.  Resolution within the Chapter 11 proceedings pursuant to a global settlement is sought.

 

L.                         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.

 

19

 

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 losses 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 or rate cases; 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 amount and source of funding for the Company’s capital expenditure program; the ability of the Company to cause its subsidiary to sell a portion of the Westport Shares; the improvements which may result from operational changes in the Supply segment 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

 

Three Months Ended September 30, 2003
vs. Three Months Ended September 30, 2002

 

Equitable Resources’ consolidated income from continuing operations before cumulative effect of accounting change for the quarter ended September 30, 2003 totaled $28.2 million, or $0.45 per diluted share, compared to $26.7 million, or $0.42 per diluted share, reported for the same period a year ago.  The third quarter 2003 earnings from continuing operations before cumulative effect of accounting change increased from the third quarter 2002 primarily due to higher realized selling prices, an increase in sales volumes from production, and higher margins and volumes on off-system sales at Equitable Marketing.  These factors were partially offset by costs associated with the 2003 Executive Performance Incentive Share Plan and the termination of a demand side management program in the NORESCO segment that was recognized in the third quarter 2002.

 

Nine Months Ended September 30, 2003
vs. Nine Months Ended September 30, 2002

 

Equitable Resources’ consolidated income from continuing operations before cumulative effect of accounting change for the nine months ended September 30, 2003 totaled $124.1 million, or $1.96 per diluted share, compared to $108.2 million, or $1.68 per diluted share, reported for the same period a year ago.  The increase of $15.9 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.

 

20

 

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 September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
OPERATIONAL DATA
Capital expenditures (thousands)		$	17,723		$	25,865		$	41,099		$	48,170
Total operating expenses as a % of net operating revenues		84.81		%	90.23		%	56.32		%	56.62		%
FINANCIAL RESULTS (Thousands)
Utility revenues (regulated)		$	36,504		$	35,081		$	283,314		$	226,933
Marketing revenues		40,539			94,415			145,458			275,274
Total operating revenues		77,043			129,496			428,772			502,207
Utility purchased gas costs (regulated)		6,301			3,565			126,293			78,144
Marketing purchased gas costs		35,643			91,736			125,982			258,336
Net operating revenues		35,099			34,195			176,497			165,727
Operating expenses:
Operating and maintenance expense		12,548			13,079			38,373			37,299
Selling, general and administrative expense		10,434			10,900			40,728			36,552
Depreciation, depletion and amortization		6,784			6,876			20,308			19,981
Total operating expenses		29,766			30,855			99,409			93,832
Operating income		$	5,333		$	3,340		$	77,088		$	71,895

 

Three Months Ended September 30, 2003
vs. Three Months Ended September 30, 2002

 

Net operating revenues increased $0.9 million, or 3%, for the three months ended September 30, 2003 compared to the prior year third quarter.  The increase in net operating revenues is primarily attributable to an increase in wholesale volumes and margins at Equitable Marketing offset by a decrease in storage related revenue in the Pipeline operations.  Total operating expenses for the quarter were $29.8 million compared to the $30.9 million reported during the same period last year.  The decrease in total operating expenses of $1.1 million, or 4%, is due mainly to lower pipeline maintenance costs, offset by increased insurance, legal and benefit costs for third quarter of 2003.

 

21

 

Nine Months Ended September 30, 2003
vs. Nine Months Ended September 30, 2002

 

Net operating revenues increased by $10.8 million in for the nine months ended September 30, 2003 compared to the nine months ended September 30, 2002. The increase in net operating revenues is primarily due to colder weather in the first quarter 2003 offset by warmer weather in the second quarter 2003 and a decrease in storage-related revenue in the Pipeline operations during the second and third quarter 2003.  Operating income increased 7% to $77.1 million for the current period compared to $71.9 million for the same period in 2002 due primarily to colder weather.  Total operating expenses increased $5.6 million from $93.8 million to $99.4 million. The majority of the increase is due to increased provisions for doubtful accounts in the Distribution operations ($4.0 million), colder weather than in the prior year and increased insurance, legal and benefit costs.

 

Other

 

Capital expenditures decreased to $41.1 million from $48.2 million for the nine months ended September 30, 2003 and 2002, respectively.  Inclement weather in the nine months ended September 30, 2003 caused delays in several major infrastructure improvement projects.  The Company expects that capital expenditures for the full year will be approximately $5 million less than originally forecasted, but this shortfall will be committed for projects that will carry into 2004.

 

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 fixed credit to purchased gas cost credit, while enabling Equitable Gas to retain all revenues 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 was issued in September 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, appealed the PA PUC order authorizing the new service to the Commonwealth Court of Pennsylvania.  In September 2003, the Commonwealth Court of Pennsylvania issued an order affirming the PA PUC decision granting Equitable Gas authority to implement the new Fixed Sales Service.  Equitable Gas is analyzing the feasibility of a Fixed Sales Service offering prior to the end of 2003.

 

22

 

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 to 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 PA PUC Audit Bureau has commenced an audit of the 2000-2001 purchased gas cost period.  The on-site audit is expected to conclude in the fourth quarter of 2003.  A final audit report for the 2000-2001 period is expected by the end of the second quarter of 2004.  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 $9.7 million of capital expenditures from project inception through September 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 September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
OPERATIONAL DATA
Degree days (normal = Qtr – 124, YTD – 3,759) (a)		91			35			3,760			3,076
O&M per customer (b)		$	59.41		$	58.69		$	217.24		$	189.89
Volumes (MMcf)
Residential sales and transportation		1,542			1,772			19,174			16,864
Commercial and industrial		3,996			4,778			20,551			21,340
Total throughput		5,538			6,550			39,725			38,204
FINANCIAL RESULTS (Thousands)
Net operating revenues:
Residential		$	13,001		$	13,442		$	79,465		$	72,700
Commercial and industrial		5,363			5,212			36,191			31,504
Other		1,103			784			3,580			2,978
Total net operating revenues		19,467			19,438			119,236			107,182
Operating expenses		21,567			21,557			75,402			68,372
Operating income		$	(2,100	)	$	(2,119	)	$	43,834		$	38,810

 

(a)                    The 30-year normal degree days’ figure is derived from the National Oceanic and Atmospheric Administration’s (NOAA) 30-year normal figures.  In the first quarter 2003, the NOAA released updated normal degree day figures for the period 1971 to 2000 and accordingly, Equitable Gas’ degree days increased to 124 from 120 for the three month periods ended September 30 and decreased to 3,759 from 3,848 for the nine month periods ended September 30.

(b)                   O&M is defined for this calculation as Operating Expenses less DD&A less Other Taxes.  DD&A for the three and nine months ended September 30, 2003 and 2002 totaled $5.0 million and $14.9 million, and $5.1 million and $14.8 million, respectively.  Other taxes for the three and nine months ended September 30, 2003 and 2002 totaled $0.6 million and $1.9 million, and $0.7 million and $2.3 million, respectively.  There were approximately 270,000 customers during the periods covered.

 

23

 

Three Months Ended September 30, 2003
vs. Three Months Ended September 30, 2002

 

Net operating revenues for the third quarter 2003 were consistent with the third quarter 2002.  Commercial and industrial volumes decreased 16% 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 for the 2003 third quarter and the 2002 third quarter were consistent at $21.6 million.

 

Nine Months Ended September 30, 2003
vs. Nine Months Ended September 30, 2002

 

Weather in the distribution service territory for the nine months ended September 30, 2003, was equal to normal and 22% colder than last year, primarily associated with cold temperatures in the first quarter 2003 which was partially offset by warmer second quarter 2003 weather.  Residential volumes increased 14% from prior year, while commercial and industrial volumes decreased slightly.

 

Net operating revenues for the nine months ended September 30, 2003, increased to $119.2 million from $107.2 million, or 11% from the same period last year. The increase is attributable to colder weather during the first quarter 2003 and increased delivery margins during the first and second quarter 2003.

 

Operating expenses of $75.4 million for the nine months ended September 30, 2003 increased $7.0 million compared to $68.4 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 1997 rate case was resolved through a FERC-approved settlement among all parties.  The 1997 settlement, as amended by a subsequent FERC order, required Equitrans to file a rate case with new rates to be effective no later than August 1, 2003.

 

In the second quarter 2002, Equitrans filed an application with the FERC to merge its assets and operations with the assets and operations of Carnegie Pipeline.  In April 2003, Equitrans filed a proposed settlement with FERC related to the application to merge its assets with the assets of Carnegie Pipeline.  The settlement also provided for a deferral to April 2005 of the August 1, 2003 rate case filing requirement.  This proposed settlement was broadly supported by most parties, however, on July 1, 2003, Equitrans received an order from the FERC approving the merger of Equitrans and Carnegie Pipeline but denying the request for deferral of the requirement to file a rate case by August 1, 2003.  Under the order, the merger of Equitrans and Carnegie Pipeline should be effectuated by July 1, 2004.  In response to the order, Equitrans filed for and received an extension of time for its filing deadline from August 1, 2003 until December 1, 2003.  Equitrans is in the process of preparing its rate case which will address several issues including establishing an appropriate return on the Company’s capital investments, addressing the Company’s pension funding levels, accruing for post-retirement benefits other than pensions, restructuring its storage services and replenishing certain storage gas declines.  The Company will continue to explore and evaluate settlement options throughout the pendency of the case.

 

24

 

		Three Months Ended September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
OPERATIONAL DATA
Transportation throughput (BBtu)		17,846			18,035			54,661			56,725
FINANCIAL RESULTS (Thousands)
Net operating revenues		$	10,737		$	12,079		$	37,786		$	41,607
Operating expenses		7,382			8,364			22,309			22,561
Operating income		$	3,355		$	3,715		$	15,477		$	19,046

 

Three Months Ended September 30, 2003
vs. Three Months Ended September 30, 2002

 

Total transportation throughput decreased 189 BBtu, or 1%, over the prior year quarter.  The decreased throughput is primarily attributable to the decrease in distribution throughput, a decrease in demand associated with 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 $1.4 million from $12.1 million in 2002 to $10.7 million in 2003.  The decrease in net revenues from the prior year quarter is due almost entirely to a decrease in storage related revenues.  The high prices and lack of demand resulted in the segment’s inability to take advantage of commercial opportunities that typically exist.

 

Operating expenses decreased quarter over quarter as a result of maintenance charges in third quarter 2002 and on-going cost reduction initiatives that were slightly offset by increased legal, insurance and employee benefit costs.

 

Nine Months Ended September 30, 2003
vs. Nine Months Ended September 30, 2002

 

Net operating revenues for the nine months ended September 30, 2003, were $37.8 million compared to $41.6 million for the same period in 2002. The decrease in net revenues from the prior year quarter is due almost entirely to a decrease in storage related revenue 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 and third quarter resulted in the inability to take advantage of commercial opportunities that typically exist.

 

Operating expenses decreased by $0.3 million to $22.3 million. The decrease in operating costs is primarily due to maintenance charges in the third quarter 2002 combined with ongoing cost reduction initiatives, which were partially offset by increased legal, insurance and employee benefit costs.

 

25

 

Equitable Marketing

 

		Three Months Ended September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
OPERATIONAL DATA
Total throughput (BBtu)		6,712			37,400			26,768			125,473
Net operating revenues/Mmbtu		$	0.73		$	0.07		$	0.73		$	0.13
FINANCIAL RESULTS (Thousands)
Net operating revenues		$	4,895		$	2,678		$	19,475		$	16,938
Operating expenses		817			934			1,698			2,899
Operating income		$	4,078		$	1,744		$	17,777		$	14,039

 

Three Months Ended September 30, 2003
vs. Three Months Ended September 30, 2002

 

Net operating revenues increased by $2.2 million, or 83%, from the prior year quarter due almost entirely to increased wholesale volumes and margins.  The corresponding volumes for these sales increased approximately 3,000 BBtu from third quarter 2002 to third quarter 2003.  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 34,000 BBtu for the three months ended September 30, 2003, had been marketed by Equitable Marketing at very low margins.  Although the marketing of these volumes by Equitable Supply did not have a significant impact on Equitable Marketing’s net revenues for the three months ended September 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 decreased slightly from the third quarter 2002.  The decrease was due to continued cost reduction initiatives associated with the Company’s decision to de-emphasize low margin trading-oriented activities.

 

Nine Months Ended September 30, 2003
vs. Nine Months Ended September 30, 2002

 

Net operating revenues for the nine months ended September 30, 2003 increased to $19.5 million from $16.9 million, or 15%, due to increased sales for resale of the Equitable Utilities’ systems and increased unit marketing margins.  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 102,000 BBtu for the nine months ended September 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 nine months ended September 30, 2003, it was the primary reason for the significant increase in the unit marketing margins during that same period.

 

Operating expenses decreased by $1.2 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.

 

26

 

EQUITABLE SUPPLY

 

Equitable Supply operates Equitable Production and Equitable Gathering 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 an aggregate of approximately 0.8 Bcf annually.  The Company did not recognize a gain or a loss as a result of this disposition.

 

Other

 

The Company’s existing collective bargaining agreement with Paper, Allied-Industrial, Chemical and Energy Workers Industrial Union Local 5-512 expired October 16, 2003.  On October 15, 2003, the Company and the union reached agreement on a new five-year contract. The union workforce provides pipeline and compression services and contract well tending services to Equitable Supply in Kentucky.

 

27

 

Operational and Financial Data

 

		Three Months Ended September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
OPERATIONAL DATA
Total sales volumes (MMcfe) (a)		16,376			15,677			47,456			45,391
Total operated volumes (MMcfe) (b)		23,574			23,366			68,575			68,163
Volumes handled (MMcfe) (c)		34,558			34,181			101,975			99,349
Selling, general, and administrative ($/Mcfe handled)		$	0.15		$	0.19		$	0.19		$	0.18
Capital expenditures (thousands) (d)		$	44,114		$	41,483		$	154,619		$	105,530
FINANCIAL DATA (Thousands)
Production revenues		$	65,190		$	56,067		$	192,161		$	160,464
Gathering revenues		17,821			15,965			51,932			45,998
Total operating revenues		83,011			72,032			244,093			206,462
Operating expenses:
Lease operating expense, excluding severance taxes		5,569			4,525			15,497			13,534
Severance tax		2,700			2,045			10,086			5,425
Land and leasehold maintenance		161			176			633			628
Gathering and compression expense		6,300			5,754			17,931			17,530
Selling, general and administrative		5,313			6,539			19,197			17,526
Depreciation, depletion and amortization (DD&A)		12,363			10,301			35,964			29,771
Total operating expenses		32,406			29,340			99,308			84,414
Operating income		$	50,605		42,692			$	144,785		$	122,048
Equity from nonconsolidated investments		$	139		$	64		$	401		$	182
Minority interest		$	—		$	(1,781	)	$	(871	)	$	(5,180	)

 

(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 nine months ended September 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.

 

Three Months Ended September 30, 2003
vs. Three Months Ended September 30, 2002

 

Equitable Supply’s operating income for the three months ended September 30, 2003 was $50.6 million, 18% higher than the $42.7 million earned for the three months ended September 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 third quarter 2003 increased 15% to $83.0 million compared to $72.0 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 third quarter was $3.82 per Mcfe compared to $3.40 per Mcfe for the same period last year.  The $0.42 per Mcfe increase in the

 

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weighted average well-head sales price was attributable to higher NYMEX prices, higher hedged prices and increased basis (“basis” is the difference between the spot price of gas where it is physically sold and the price of gas at the delivery point specified in the hedging instrument) over the third 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 September 30, 2003 were $32.4 million compared to $29.3 million in last year’s third quarter.  The main factors for the increase were depreciation, depletion and amortization ($2.1 million), lease operating expense ($1.0 million), gathering and compression expense ($0.5 million) and severance tax ($0.7 million) offset by a decrease in selling, general and administrative costs ($1.2 million).  The increase in DD&A was due to a $0.09 increase in the unit depletion rate and increased production volumes.  The $0.09 increase is made up of a $0.03 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 increased severance tax was a direct function of market prices, as severance taxes are calculated as a percentage of market prices. The increased lease operating expense was a result of increased well maintenance and well surveillance costs and increased road maintenance costs due to weather conditions in 2003. Selling, general and administrative expenses decreased due to the reduction of short-term incentive compensation expense and professional service fees.  Gathering and compression expenses were slightly higher due to increased maintenance costs and third party processing charges.

 

Nine Months Ended September 30, 2003
vs. Nine Months Ended September 30, 2002

 

Equitable Supply’s operating income for the nine months ended September 30, 2003 was $144.8 million, 19% higher than the $122.0 million earned for the nine months ended September 30, 2002.  The segment’s results were favorably impacted by higher commodity prices, increased natural gas sales volumes and increased gathering revenues, somewhat offset by increased operating expenses.

 

Operating revenues for the nine months ended September 30, 2003, increased 18%  to $244.1 million compared to $206.5 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 nine months ended September 30, 2003 was $3.88 per Mcfe compared to $3.36 per Mcfe for the same period last year.  The $0.52 per Mcfe increase in the weighted average well-head sales price was attributable to higher NYMEX prices, increased volumes at higher hedged prices and increased basis over the same period in 2002.

 

Total operating expenses were $99.3 million for the nine months ended September 30, 2003, compared to $84.4 million for the nine months ended September 30, 2002.  This increase was primarily due to increased DD&A costs ($6.2 million), severance taxes attributable to higher natural gas prices ($4.7 million), increased lease operating expenses due to increased property tax, liability insurance premiums, and road maintenance costs due to severe weather and flooding in 2003 ($2.0 million), selling, general and administrative expense relating to increases in legal costs, insurance premiums and staffing costs ($1.7 million), and increased ad valorem taxes due to higher natural gas prices.

 

Operated volumes for the three and nine months ended September 30, 2003 have increased approximately 200 Mmcfe and 400 Mmcfe, respectively compared to the three and nine months ended September 30, 2002.  While operated volumes have increased, the amount of the increase has not met the Company’s expectations primarily due to volume shortfalls in the southern West Virginia region.  Some of this shortfall versus the Company’s expectations is related to well performance issues caused by wells drilled in 2002 in less productive areas of the region and negative impacts related to new automation technology and well surveillance.  The remaining shortfall is due to more pipeline system curtailments than were forecast and delays in project timing.  The Company has executed organizational changes that include assigning more engineers directly to operating districts to address production and well performance issues.  In addition, the Company has taken actions, in the form of adding more

 

29

 

firm transportation on the interstate pipeline systems and implementing new pipeline projects, to increase the pipeline take away capacity and reliability. The Company has also shifted drilling capital to areas where overall results are more predictable.  The 2004 capital budget may be affected by the poor performance in southern West Virginia this year.

 

Equitable Production

 

		Three Months Ended September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
OPERATIONAL DATA
Net equity sales (MMcfe) (a)		12,827			12,128			36,926			34,861
Average (well-head) sales price ($/Mcfe)		$	3.98		$	3.44		$	4.06		$	3.39
Monetized sales (MMcfe) (b)		3,549			3,549			10,530			10,530
Average (well-head) sales price ($/Mcfe)		$	3.23		$	3.27		$	3.23		$	3.26
Average of net equity and monetized (well-head) sales price ($/Mcfe)		$	3.82		$	3.40		$	3.88		$	3.36
Company usage, line loss (MMcfe) (a)		1,510			1,944			4,055			4,731
Lease operating expense (LOE),  excluding severance tax ($/Mcfe)		$	0.31		$	0.26		$	0.30		$	0.27
Severance tax ($/Mcfe)		$	0.15		$	0.12		$	0.20		$	0.11
Production depletion ($/Mcfe)		$	0.48		$	0.39		$	0.48		$	0.39
Depreciation, depletion and amortization (in thousands):
Production depletion		$	8,601		$	6,941		$	24,902		$	19,718
Other depreciation, depletion and amortization		546			334			1,516			1,018
Total depreciation, depletion and amortization		$	9,147		$	7,275		$	26,418		$	20,736
Total operated volumes (MMcfe) (c)		23,574			23,366			68,575			68,163
FINANCIAL DATA (Thousands)
Net equity sales		$	51,033		$	41,668		$	149,997		$	118,042
Monetized sales		11,474			11,603			34,048			34,372
Other revenue		2,683			2,796			8,116			8,050
Total production revenues		65,190			56,067			192,161			160,464
Operating expenses:
Lease operating expense, excluding severance taxes		5,569			4,525			15,497			13,534
Severance tax		2,700			2,045			10,086			5,425
Land and leasehold maintenance		161			176			633			628
Selling, general and administrative (SG&A)		3,506			4,315			12,669			11,567
Depreciation, depletion and amortization (DD&A)		9,147			7,275			26,418			20,736
Total operating expenses		21,083			18,336			65,303			51,890
Operating income		$	44,107		$	37,731		$	126,858		$	108,574
Equity from nonconsolidated investments		$	139		$	64		$	401		$	182
Minority interest		$	—		$	(1,781	)	$	(871	)	$	(5,180	)

 

(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 third 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.

 

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Three Months Ended September 30, 2003
vs. Three Months Ended September 30, 2002

 

Equitable Production’s operating income for the three months ended September 30, 2003 was $44.1 million, a 17% increase over the prior year’s third quarter operating income of $37.7 million.  Production revenues were up $9.1 million from $56.1 million in the third quarter 2002 to $65.2 million in the third quarter 2003.  This increase results from an effective sales price of $3.82 per Mcfe compared to $3.40 per Mcfe in the prior year quarter and a 0.7 Bcf increase in net equity sales volumes resulting from new wells drilled in the past 12 months.  Included in the increased revenues was a $0.2 million positive impact from basis overeffectiveness.

 

Operating expenses were up $2.8 million over the prior year quarter from $18.3 million to $21.1 million.  The increase is a result of increased depreciation, depletion and amortization costs ($1.9 million), higher severance taxes attributable to higher natural gas prices ($0.7 million), and increased lease operating expenses ($1.0 million).  These increases were offset by lower selling, general and administrative costs ($0.8 million), due to the reduction of short-term incentive compensation expense and professional service fees.  Depreciation, depletion and amortization increased as a result of increased production volumes and a $0.09 increase in the unit depletion rate, from $0.39 in the 2002 third quarter to $0.48 in the 2003 third quarter.  Of the total $0.09 per Mcfe increase in the unit depletion rate, $0.03 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 expense is primarily a result of increased well maintenance and surveillance costs and increased road maintenance costs due to severe weather and flooding in 2003.

 

Nine Months Ended September 30, 2003
vs. Nine Months Ended September 30, 2002

 

Equitable Production’s operating income for the nine months ended September 30, 2003 was $126.9 million, a 17% increase over the prior year’s nine months operating income $108.6 million.  Production revenues were up $31.7 million, largely due to an increase in the effective sales price and increased sales volumes.

 

Operating expenses increased $13.4 million over the prior year quarter from $51.9 million to $65.3 million.  This increase was primarily due to increased DD&A costs ($5.7 million), severance taxes attributable to higher natural gas prices ($4.7 million), lease operating expense due to increases in ad valorem taxes resulting from increased natural gas sales prices, liability insurance premiums and road maintenance costs due to severe weather and flooding in 2003 ($2.0 million) and SG&A ($1.1 million) due to higher insurance premiums and legal costs and increased staffing.

 

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Equitable Gathering

 

Operational and Financial Data

 

		Three Months Ended September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
OPERATIONAL DATA
Gathered volumes (MMcfe)		31,266			30,726			92,995			90,258
Average gathering fee ($/Mcfe) (a)		$	0.57		$	0.52		$	0.56		$	0.51
Gathering and compression expense ($/Mcfe)		$	0.20		$	0.19		$	0.19		$	0.19
Gathering and compression depreciation ($/Mcfe)		$	0.09		$	0.09		$	0.09		$	0.09
Depreciation, depletion and amortization (in thousands):
Gathering and compression depreciation		$	2,935		$	2,855		$	8,766		$	8,510
Other depreciation, depletion and amortization		281			171			780			525
Total depreciation, depletion and amortization		$	3,216		$	3,026		$	9,546		$	9,035
FINANCIAL DATA (Thousands)
Gathering revenues		$	17,774		$	15,830		$	51,670		$	45,837
Other revenues		47			135			262			161
Total operating revenues		17,821			15,965			51,932			45,998
Operating expenses:
Gathering and compression expense		6,300			5,754			17,931			17,530
Selling, general and administrative (SG&A)		1,807			2,224			6,528			5,959
Depreciation, depletion and amortization (DD&A)		3,216			3,026			9,546			9,035
Total operating expenses		11,323			11,004			34,005			32,524
Operating income		$	6,498		$	4,961		$	17,927		$	13,474

 

(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 September 30, 2003
vs. Three Months Ended September 30, 2002

 

Equitable Gathering’s operating income for the three months ended September 30, 2003 of $6.5 million increased $1.5 million or 31% over the prior year’s third quarter operating income of $5.0 million.  Gathering revenues were $17.8 million compared to $16.0 million in the third quarter 2002, a 11% increase.

 

Operating revenues increased $1.8 million in the third quarter of 2003 versus the same quarter last year.  The main factors in the increase were an increase in gathering rates ($1.3 million) and an increase in equity volumes ($0.5 million).

 

Operating expenses were $11.3 million in the third quarter of 2003, a $0.3 million increase over the $11.0 million in the same quarter last year.  Gathering and compression expenses were slightly higher due to increased maintenance costs and third party processing charges.

 

32

 

Nine Months Ended September 30, 2003
vs. Nine Months Ended September 30, 2002

 

Equitable Gathering’s operating income for the nine months ended September 30, 2003 of $17.9 million increased $4.4 million over the prior year’s nine months ended September 30, 2002 operating income of $13.5 million.  Operating revenues increased $5.9 million year over year, due to increased throughput ($1.4 million) and 10% higher average rates ($4.5 million).

 

Operating expenses were up $1.5 million to $34.0 million for the nine months ended September 30, 2003 from $32.5 million for the nine months ended September 30, 2002. Gathering and compression expenses were higher due to increased staffing costs ($0.4 million) and SG&A expenses ($0.6 million) were increased due to higher insurance premiums, legal costs and staffing.

 

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 September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
OPERATIONAL DATA
Revenue backlog, end of period (thousands)		$	157,783		$	148,769		$	157,783		$	148,769
Construction completed (thousands)		$	26,210		$	36,601		$	86,726		$	88,823
Capital expenditures (thousands)		$	108		$	271		$	254		$	635
Gross profit margin		24.9		%	22.4		%	21.8		%	22.8		%
SG&A as a % of revenue		12.5		%	12.4		%	12.4		%	13.1		%
FINANCIAL RESULTS (Thousands)
Energy service contract revenues		$	41,379		$	54,209		$	129,477		$	136,142
Energy service contract costs		31,063			42,069			101,219			105,070
Net operating revenues (gross profit margin)		10,316			12,140			28,258			31,072
Operating expenses:
Selling, general and administrative		5,159			6,701			16,058			17,789
Impairment of long-lived assets		—			—			—			5,320
Depreciation		396			367			1,086			1,248
Total operating expenses		5,555			7,068			17,144			24,357
Operating income		$	4,761		$	5,072		$	11,114		$	6,715
Equity earnings from nonconsolidated investments		$	42		$	715		$	2,431		$	2,660
Minority interest		$	(277	)	$	—		$	(277	)	$	—

 

33

 

Three Months Ended September 30, 2003
vs. Three Months Ended September 30, 2002

 

NORESCO’s operating income was $4.8 million for the three months ended September 20, 2003 compared to $5.1 million for the same period in 2002, a decrease of $0.3 million.  The decrease was primarily due to the net effect of $2.4 million in 2002 gross profit margin resulting from the termination of a demand side management program.  This decrease was partially offset by lower SG&A of $1.5 million, primarily due a $1.0 million reduction in force and office closure charge in 2002, and better gross profit margins on 2003 third quarter projects.

 

Total revenue for the third quarter 2003 decreased by $12.8 million to $41.4 million from $54.2 million in the third quarter 2002, primarily due to a reduction in construction activity related to lower backlog at the start of the third quarter 2003.

 

Revenue backlog in the current year increased by $9.0 million from $148.8 million on September 30, 2002 to a record $157.8 million on September 30, 2003, due to an increase in new executed performance contracts.

 

NORESCO’s third quarter 2003 gross profit margin decreased to $10.3 million compared to $12.1 million during the third quarter 2002.  The decrease was primarily due to the $2.4 million in 2002 gross profit margin from the termination of a demand side management program, which was partially offset by a $1.1 million increase in gross profit margin due to the consolidation of the Hunterdon and Plymouth projects in the third quarter 2003.  The full impact of the consolidation is described in the notes to the consolidated financial statements.  Gross profit margin increased as a percentage of revenue from 22.4% in the third quarter 2002 to 24.9% in the third quarter 2003.  The increase in gross profit margin was due to an increase in the construction activity gross profit margin and the gross profit margin percentage of the Hunterdon and Plymouth projects.

 

Total operating expenses decreased by $1.5 million to $5.6 million for the third quarter 2003 versus $7.1 million for the same period in 2002, primarily due to a $1.0 million charge for a reduction in force and office closure during the third quarter of 2002 and reduced labor expenses in 2003.  SG&A as a percentage of revenue was relatively unchanged at 12.5% for the third quarter 2003 as compared to 12.4% for the same period last year.  Total operating expenses included approximately $1.2 million in bad debt expense, which was offset by the reversal of the excess losses absorbed by NORESCO from the Jamaica project.  Both of these items were recognized due to the deconsolidation of Jamaica in the third quarter of 2003.

 

Equity in earnings from power plant investments during the third quarter 2003 decreased to $0.04 million from $0.7 million during the third quarter 2002.  This decrease is primarily due to a decrease in earnings from one of the Panamanian power plants because of the expiration of its power purchase agreement.  Revenue from a replacement agreement has been lower than under prior agreements.

 

The minority interest of $0.3 million is attributable to the consolidation of Hunterdon and Plymouth projects beginning in the third quarter 2003.

 

Nine Months Ended September 30, 2003
vs. Nine Months Ended September 30, 2002

 

NORESCO’s operating income for the nine months ended September 30, 2003 increased $4.4 million to $11.1 million from $6.7 million for the same period last year.  This increase was primarily attributable to a write-off of $5.3 million for the Jamaica power plant during 2002.  Revenue for the first nine months of 2003 was $129.5 million compared to $136.1 million in the same period in 2002, which decrease was primarily due to a reduction in construction activity related to lower construction backlog.

 

NORESCO’s gross profit margin for the nine months ended September 30, 2003 decreased to $28.3 million compared to $31.1 million during the nine months ending September 30, 2002, a $2.8 million reduction due to $2.4 million in gross profit margin in 2002 from the termination of a demand side management program, the gross profit margin mix of construction completed for the period offset by the gross profit margin increase due to the consolidation of the Hunterdon and Plymouth projects.  Gross profit margin was 21.8% versus 22.8% during the same period in 2002, again, primarily due to the aforementioned factors.

 

34

 

Total operating expenses for the first nine months in 2003 decreased $7.3 million to $17.1 million as compared to $24.4 million for the same period in 2002.  Net of the Jamaica write-down of $5.3 million and $1.0 million reduction in force charges in 2002, operating expenses decreased $1.0 million, primarily due to reduced direct labor expenses.  SG&A as a percentage of revenue for the first nine months of 2003 decreased to 12.4% as compared to 13.1% for the same period in 2002.

 

Equity in earnings from power plant investments during the nine months ended September 30, 2003 decreased to $2.4 million from $2.7 million during the same period in 2002.  This decrease is primarily due to a decrease in earnings from one of the Panamanian power plants because of the expiration of its power purchase agreement.  Revenue from a replacement agreement has been lower than under the prior agreement.

 

EQUITY IN NONCONSOLIDATED INVESTMENTS

 

On April 10, 2000, Equitable Resources merged its Gulf of Mexico operations with Westport Oil and Gas Company for debt repayment of 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 19.3% 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 $306.1 million as of September 30, 2003 and was calculated based upon the quoted market price of Westport as of September 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 $172.0 million represents an unrealized gain recorded net of tax in accumulated other comprehensive income.  As previously 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 was unchanged, but the increase in the 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. Equitable has announced its desire to sell approximately 3,000,000 shares of Westport in a registered, negotiated transaction within the next six months. The Company is engaged in discussions with Westport regarding the appropriate means of effecting this registration and transaction.  The foregoing is subject to the terms of a Registration Rights Agreement with Westport. This Form 10-Q does not constitute an offer of any securities for sale. The sale of any Westport common stock by the subsidiary will be made only by means of a prospectus or pursuant to an exemption from registration.

 

In the second quarter 2003, the Company reevaluated its interest in Hunterdon concluded that the Company effectively controls this equity investment for consolidation purposes.  Further, the Company is the primary beneficiary of Plymouth under the rules of FIN 46.  As a result, the Company began consolidating the financial positions, results of operations and cash flows of Hunterdon effective June 30, 2003 and Plymouth effective July 1, 2003.  Hunterdon and Plymouth are considered to be part of the NORESCO segment.

 

35

 

The consolidation of Hunterdon removed the equity investment in Hunterdon of $2.5 million and increased minority interest by $2.5 million in the Condensed Consolidated Balance Sheet.  As of September 30, 2003, Hunterdon had $8.5 million of total assets, and $3.7 million of total liabilities, including $2.6 million of nonrecourse long-term debt of which $0.5 million was classified as current. The consolidation of Plymouth removed the equity investment in Plymouth of $0.1 million and increased minority interest by $0.7 million in the Condensed Consolidated Balance Sheet.  As of September 30, 2003, Plymouth had $5.0 million of total assets, and $4.2 million of total liabilities, including $4.0 million of nonrecourse long-term debt of which $0.2 million was classified as current.

 

Four NORESCO projects are held through equity in nonconsolidated entities that 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 in these projects since April 2001 and has a cumulative investment in these four projects of $42.8 million as of September 30, 2003.  The Company’s share of the earnings for the third quarter of 2003 and 2002 related to these projects were $0.04 million and $0.7 million, respectively.  These projects generally are financed with non-recourse financings at the project level.

 

As previously disclosed, at September 30, 2003 the Company owned 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 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 the tenant’s 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. NORESCO’s equity interest in this non-recourse financed project was $4.2 million as of September 30, 2003.  On October 31, 2003, the Company sold its interest in the project entities to the mall owner.  The Company recorded an immaterial gain on the sale.

 

The Company owns a 50% interest in a Panamanian electric generation project, IGC/ERI Pan-Am Thermal Limited.  The loan agreement required the project company 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 evaluated a land acquisition/rezoning proposal, which, if accepted and executed, would eliminate the need for a retrofit requirement.  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.  Legislation has been introduced which would have the affect of applying the less restrictive noise standard to all properties in a manner the Company believes would not violate the June 2003 Supreme Court ruling.  In October 2003, the creditor sponsor advised the project company that the less restrictive noise standards are made applicable to the plant; the project company should execute portions of the land acquisition/rezoning proposal and work with a noise control contractor to achieve a partial technical resolution to the noise condition.  If the plant is made compliant with the less restrictive noise standard, the credit sponsor has indicated that it will issue a waiver from the loan agreement requirement and/or deem the borrower to be in compliance.  The expected cost to the project company of achieving resolution of this issue 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 project company has been actively coordinating with the creditor sponsor on this matter and during the second half of 2002 and the nine months 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.

 

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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, equity earnings from nonconsolidated investments, excluding Westport, and minority interest by segment and by operations within each segment in the MD&A section of this Form 10-Q.  Interest charges and income taxes are managed on a consolidated basis and are not allocated to the 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, equity earnings from nonconsolidated investments, excluding Westport, and minority interest to the Company’s consolidated operating income, equity earnings from nonconsolidated investment, excluding Westport, and minority interest totals in Note B to the Notes to the Condensed Consolidated Financial Statements.  Additionally, these subtotals are reconciled to the Company’s consolidated net income in Note 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 a measure was derived.  Equitable’s management believes that presentation of this non-GAAP information provides useful information to management and investors regarding the financial condition, operations and trends of each of Equitable’s segments without being obscured by the financial condition, operations and trends for the other segments or by the effects of corporate allocations of interest and income taxes.  In addition, management uses these measures for budget planning purposes

 

CAPITAL RESOURCES AND LIQUIDITY

 

Operating Activities

 

Cash flows provided by operating activities totaled $81.5 million, a $108.2 million decrease from the $189.7 million recorded in the prior year period.  The decreased cash flow is primarily the result of the decrease in cash provided from working capital due to a large increase in inventory during the nine months ended September 30, 2003 as compared to a slight decrease in inventory during the nine months ended September 30, 2002.  The increase in the use of cash for inventory was mainly due to increased natural gas prices and volumes stored in the current year compared to prior year.  In addition, the Company made $49.6 million in pension contributions in the nine months ended September 30, 2003.  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.  Two cash flow adjustments to reconcile income from continuing operations before cumulative effect of accounting change to net cash provided by operations of note were made.  The deferred income tax provision was a positive adjustment to net cash provided by operating activities primarily due to the increase in drilling and development costs expensed for income tax reporting.  In addition, the increased collections in accounts receivable in the third quarter provided a positive adjustment to net cash provided by operating activities.

 

When the prepaid gas forward sale transactions were consummated, the Company reviewed the specific facts and circumstances related to our transactions to determine if the appropriate Statement of Cash Flows presentation was an operating activity or a financing activity.  The Company concluded that the appropriate accounting presentation of the prepaid gas forward sales was 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 September 30, 2003 and 2002 is $14.0 million and is $41.7 million for the nine months then ended.

 

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Investing Activities

 

Cash flows used in investing activities during the first nine months of 2003 totaled $190.5 million, a $99.3 million increase from the $91.2 million recorded in the prior year period.  The change from the prior year is attributable to two factors (i) an increase in capital expenditures of $44.2 million related to the purchase of the remaining limited partnership interest in ABP and (ii) in 2002, the Company received a one time benefit of an additional $63.0 million, which occurred as a result of restrictions lapsing on proceeds relating to the sale in 2001 of oil-dominated fields within the Supply segment.  These two factors are offset by the proceeds of $6.6 million received from the sale of wells in Ohio during 2003.  In October 2003, the Company increased its 2003 capital budget by $10.0 million.  Specifically, the capital budget of the Supply segment was increased $10.0 million for additional costs associated with the 2003 drilling program due to increases in drilling and service company costs.

 

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 provided by financing activities during the first nine months of 2003 totaled $102.8 million compared to cash flows used in financing activities during the first nine months of 2002 totaling $121.4 million.  The change is primarily the result of increased borrowing.  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.  The proceeds from this 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.  The remaining cash inflows are mainly due to increased short-term debt borrowings and a reduction in the repurchase of shares of the Company’s outstanding stock.  The cash inflows were partially offset by increased dividends and increased repayments of long-term debt.

 

During the first quarter of 2001, a Jamaican energy infrastructure project, owned by a consolidated subsidiary, ERI JAM, LLC, 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 had 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 plant shut down its engines and terminated most of the staff in order to preserve available cash while discussions among the various parties involved in the project continued, seeking a global settlement.  In April of 2003, ERI JAM, LLC filed for bankruptcy protection under Chapter 11 in U.S. Bankruptcy Court (Delaware).  In the third quarter 2003, ERI JAM, LLC transferred control under the partnership agreement to the other general partner.  In September 2003, project-level counterparties, Jamaica Broilers Group Limited (JBG) and Energy Associated Limited (EAL), filed a claim against ERI JAM LLC as Debtor-in-Possession in the Chapter 11 case.  EAL is a limited partner in EAL/ERI Cogeneration Partners LP.  In October 2003, JBG and EAL also filed a multi-count complaint against Equitable and certain of its affiliates in U.S. District Court (Western District of PA).  Equitable and its affiliates intend to vigorously defend this litigation, which they view as without merit.  Global settlement discussions led by the managing general partner and the project lender are continuing in parallel.  Resolution within the Chapter 11 proceedings pursuant to a global settlement is sought.

 

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.  As of September 30, 2003, the Company maintained, 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 September 30, 2003, the Company has the authority to arrange for a commercial paper program up to $650 million.  The two credit agreements have historically been used to provide credit support for the commercial paper program.

 

On October 30, 2003, the Company replaced its existing credit agreements with a $500 million 364 day credit facility, which will automatically extend to a three year facility upon receipt of an approval of the Pennsylvania Public Utility Commission (PA PUC).  The Company anticipates receipt of the PA PUC approval in the first quarter of 2004.  The 2003 credit agreement may be used for, among other things, credit support for the Company’s commercial paper program.

 

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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 protect earnings from undue exposure to the risk of changing commodity prices.  During the quarter ended September 30, 2003, the Company hedged approximately 5.6 Bcf of natural gas basis exposure through October 2005.

 

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 September 30, 2003, which relate to natural gas distribution and production operations.  However, approximately $19.5 million of these costs are recoverable in customer rates.

 

In the third quarter, the Company signed a long-term lease for office space with Continental Real Estate Companies, who will own and construct the building.  Plans call for the building to be complete in late 2004 or early 2005.  The term of the lease is 20 years and nine months and the base rent is approximately $2 million per year.  The office space is located at the North Shore in Pittsburgh, Pennsylvania and will allow Equitable to consolidate its Pittsburgh office operations and increase efficiencies.  Relocation of operations from locations that utilize space under long-term leases will likely cause additional expense late in 2004 and 2005.

 

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.  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.  There has been no change in the status of this matter since the Company’s second quarter Form 10-Q disclosure.

 

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In July 2002, the United States Environmental Protection Agency 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 to 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.

 

In addition to the SPCC, the Company is subject to other federal state and local environmental and environmentally related 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 Company made cash contributions totaling $49.6 million to its pension plan during the nine months ended September 30, 2003.  In accordance with current funding guidelines, these contributions were designated as 2002 plan year contributions and in the aggregate, represent the maximum allowable contribution that the Company could make to its pension plan for that plan year.  As a result of the $49.6 million contribution, the Company’s minimum funding requirement is zero for the 2003 plan year and based upon current assumptions, is expected to continue to be zero through the 2006 plan year.

 

The Company’s net periodic benefit cost totaled $1.4 million and $4.7 million, and $1.4 million and $2.4 million, for the three and nine months ended September 30, 2003 and 2002, respectively.  The increase in the Company’s net periodic benefit cost for the nine months ended September 30, 2003 is primarily a result of an increase in settlements (i.e., retirements settled by a one-time lump sum payment) as compared to the prior year in addition to a decrease in the expected long-term rate of return assumption from 9.75% to 8.75%.

 

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 nine months ended September 30, 2003 consistent with the methodology prescribed in Statement No. 123 net income and diluted earnings per share for the nine months ended September 30, 2003 would have been reduced by an estimated $5.0 million or $0.08 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.

 

40

 

Energy Bill

 

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 continue to work on a compromise of the two bills to provide for comprehensive energy policy legislation.  Any extension of the nonconventional fuels tax credit continues to be uncertain.

 

On September 30, 2003, the enabling legislation for the performance contracting work that NORESCO performs for the federal government under the Department of Energy contracts lapsed and is pending extension in Congress. The Company believes the extension is a non-controversial element of the currently delayed Energy Bill.  While the Company believes that this is a temporary situation, until it is resolved, the NORESCO segment’s ability to sign new contracts under the Department of Energy master agreements is affected.  However, the Department of Defense has informed NORESCO that it is not interpreting the statutory lapse as prohibiting new awards under existing master agreements.

 

Dividend

 

On October 16, 2003, the Board of Directors of the Company declared a regular quarterly cash dividend of 30 cents per share, payable December 1, 2003 to shareholders of record on November 14, 2003.  The Company has targeted dividend growth at a rate similar to the rate of its earnings per share growth.

 

Purchase of Treasury Stock

 

During the three and nine months ended September 30, 2003, the Company repurchased approximately 251,000 and 1,182,000 shares of Equitable Resources, Inc. stock, respectively.  The total number of shares repurchased since October 1998 is approximately 16.4 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 $1.8 million for the three months ended September 30, 2002, and $0.9 million and $5.2 million for the nine months ended September 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 an aggregate of approximately 0.8 Bcf annually.  These reserves were not material to the Company’s reserve base.

 

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/A.  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 September 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.

 

41

 

Schedule of Certain Contractual Obligations

 

Below is a table that details the future projected payments for the Company’s significant contractual obligations as of September 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		$	559,089		$	10,092		$	77,884		$	75,444		$	395,669
Long-term debt		653,539			—			30,500			13,000			610,039
Unconditional purchase obligations		210,917			13,302			62,374			55,365			79,876
Total contractual obligations		$	1,423,545		$	23,394		$	170,758		$	143,809		$	1,085,584

 

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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 224.7 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 $115.9 million at September 30, 2003.

 

With respect to derivative contracts held by the Company for trading purposes, as of September 30, 2003, a decrease of 10% in the market price of natural gas would decrease the fair market value by approximately $0.1 million.  An increase of 10% in the market price would increase the fair market value by approximately $0.1 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 Note 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 September 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 Note 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 investment, available-for-sale.  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 third 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 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		$	77,043
Equitable Supply		81,697			79,385			83,011
NORESCO		45,518			42,580			41,379
Intersegment revenues		(21,002		)	(19,089		)	(15,918		)
Total		$	342,322		$	218,496		$	185,515
2002
Operating Revenues:
Equitable Utilities		$	223,751		$	148,960		$	129,496		$	252,066
Equitable Supply		66,402			68,028			72,032			82,531
NORESCO		35,439			46,494			54,209			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. $500,000,000 Revolving Credit Agreement dated October 30, 2003

 

10.2                                 Equitable Resources, Inc. 2003 Short-term Incentive Plan (as of January 1, 2003)

 

10.3                                 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 September 30, 2003:

 

(i)             Form 8-K dated July 23, 2003 disclosing the Company’s issuance of a press release announcing the results of its second quarter 2003 earnings

 

(ii)          Form 8-K dated September 30, 2003 disclosing the commencement of the exchange offering of the Company’s 5.15% Notes due 2018

 

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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:  November 6, 2003

 

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INDEX TO EXHIBITS

 

Exhibit No.		Document Description
10.1		Equitable Resources, Inc. $500,000,000 Revolving Credit Agreement dated October 30, 2003		Filed Herewith
10.2		Equitable Resources, Inc. 2003 Short-term Incentive Plan (as of January 1, 2003)		Filed Herewith
10.3		Equitable Resources, Inc. Directors’ Deferred Compensation Plan (as amended and restated May 15, 2003)		Filed previously as Exhibit 10.10 to Form 10-Q filed on August 14, 2003
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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