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 Months Ended March 31, 2004 and 2003
	Statements of Condensed Consolidated Cash Flows for the Three Months Ended March 31, 2004 and 2003
	Condensed Consolidated Balance Sheets as of March 31, 2004 and December 31, 2003
	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 2	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities
Item 6.	Exhibits and Reports on Form 8-K
Signature
Index to Exhibits

 

 

PART I.  FINANCIAL INFORMATION

 

Item 1.    Financial Statements

 

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

 

Statements of Consolidated Income (Unaudited)

 

		Three Months Ended March 31,
		2004			2003
		(Thousands, except per share amounts)
Operating revenues		$	400,427		$	342,322
Cost of sales		197,596			153,970
Net operating revenues		202,831			188,352
Operating expenses:
Operation and maintenance		18,698			18,855
Production		10,087			9,162
Selling, general and administrative		32,752			32,262
Depreciation, depletion and amortization		21,767			18,753
Total operating expenses		83,304			79,032
Operating income		119,527			109,320
Charitable foundation contribution		—			(9,279		)
Equity in earnings of nonconsolidated investments:
Westport		—			3,614
Other		901			1,232
		901			4,846
Minority interest		(370		)	(871		)
Interest expense		12,259			12,321
Income from continuing operations before income taxes and cumulative effect of accounting change		107,799			91,695
Income taxes		37,729			27,216
Income from continuing operations before cumulative effect of accounting change		70,070			64,479
Cumulative effect of accounting change, net of tax		—			(3,556		)
Net income		$	70,070		$	60,923
Earnings (loss) per share of common stock:
Basic:
Weighted average common shares outstanding		62,256			62,063
Income from continuing operations before cumulative effect of accounting change		$	1.13		$	1.04
Cumulative effect of accounting change, net of tax		—			(0.06		)
Net income		$	1.13		$	0.98
Diluted:
Weighted average common shares outstanding		63,531			63,333
Income from continuing operations before cumulative effect of accounting change		$	1.10		$	1.02
Cumulative effect of accounting change, net of tax		—			(0.06		)
Net income		$	1.10		$	0.96
Dividends declared per common share		$	0.38		$	0.20

 

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 March 31,
		2004			2003
		(Thousands)
Cash flows from operating activities:
Income from continuing operations before cumulative effect of accounting change		$	70,070		$	64,479
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for losses on accounts receivable		6,481			7,665
Depreciation, depletion, and amortization		21,767			18,753
Charitable contribution		—			9,279
Deferred income taxes		2,706			11,119
Recognition of monetized production revenue		(5,182		)	(13,736		)
Change in undistributed earnings from nonconsolidated investments		(901		)	(4,846		)
Increase in accounts receivable and unbilled revenues		(31,492		)	(59,265		)
Decrease in inventory		83,535			10,653
Changes in other assets and liabilities		(1,421		)	33,920
Total adjustments		75,493			13,542
Net cash provided by operating activities		145,563			78,021
Cash flows from investing activities:
Capital expenditures		(35,870		)	(32,850		)
Purchase of minority interest in Appalachian Basin Partners, LP		—			(44,200		)
Proceeds from sale of property		—			6,550
Distributions from nonconsolidated investments		498			—
Net cash used in investing activities		(35,372		)	(70,500		)
Cash flows from financing activities:
Issuance of long-term debt		—			200,000
Dividends paid		(18,743		)	(10,585		)
Proceeds from exercises under employee compensation plans		7,573			8,783
Purchase of treasury stock		(15,076		)	(16,180		)
Loans against construction contracts		12,760			3,969
Repayments and retirement of long-term debt		(10,129		)	(15,167		)
Decrease in short-term loans		(118,601		)	(50,006		)
Net cash (used in) provided by financing activities		(142,216		)	120,814
Net (decrease) increase in cash and cash equivalents		(32,025		)	128,335
Cash and cash equivalents at beginning of period		37,334			17,748
Cash and cash equivalents at end of period		$	5,309		$	146,083
Cash paid during the period for:
Interest, net of amount capitalized		$	15,280		$	11,987
Income taxes paid, net of refund		$	9		$	(1,103	)

 

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

 

3

 

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

 

Condensed Consolidated Balance Sheets (Unaudited)

 

ASSETS		March 31, 2004			December 31, 2003
		(Thousands)
Current assets:
Cash and cash equivalents		$	5,309		$	37,334
Accounts receivable (less accumulated provision for doubtful accounts: 2004, $32,395; 2003, $18,041)		200,210			176,574
Unbilled revenues		123,712			129,758
Inventory		75,067			162,090
Derivative commodity instruments, at fair value		40,775			34,657
Prepaid expenses and other		7,245			9,648
Total current assets		452,318			550,061
Equity in nonconsolidated investments		89,625			89,175
Property, plant and equipment		2,815,872			2,791,799
Less accumulated depreciation and depletion		1,039,986			1,025,017
Net property, plant and equipment		1,775,886			1,766,782
Investments, available-for-sale		399,726			363,280
Other assets		179,729			170,594
Total		$	2,897,284		$	2,939,892

 

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

 

4

 

LIABILITIES AND STOCKHOLDERS’ EQUITY		March 31, 2004			December 31, 2003
		(Thousands)
Current liabilities:
Current portion of long-term debt		$	11,044		$	21,267
Short-term loans		80,999			199,600
Accounts payable		139,379			146,086
Prepaid gas forward sale		20,783			20,840
Derivative commodity instruments, at fair value		217,981			137,636
Current portion of project financing obligations		73,401			56,368
Other current liabilities		132,980			121,030
Total current liabilities		676,567			702,827
Long-term debt:
Debentures and medium-term notes		628,211			632,147
Deferred and other credits:
Deferred income taxes		449,162			459,877
Deferred investment tax credits		11,854			12,125
Prepaid gas forward sale		15,658			20,783
Project financing obligations		41,529			48,972
Other credits		92,703			97,821
Total deferred and other credits		610,906			639,578
Common stockholders’ equity:
Common stock, no par value, authorized 160,000 shares; shares issued: March 31, 2004 and December 31, 2003, 74,504		347,200			348,133
Treasury stock, shares at cost: March 31, 2004, 12,180; December 31, 2003, 12,137 (net of shares and cost held in trust for deferred compensation of 633, $12,045 and 636, $12,111)		(302,121		)	(295,145		)
Retained earnings		948,414			897,087
Accumulated other comprehensive (loss) income		(11,893		)	15,265
Total common stockholders’ equity		981,600			965,340
Total		$	2,897,284		$	2,939,892

 

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 accounting principles generally accepted in the United States 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 accounting principles generally accepted in the United States 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 March 31, 2004, and the results of its operations and cash flows for the three-month periods ended March 31, 2004 and 2003.

 

The balance sheet at December 31, 2003 has been derived from the audited financial statements at that date, but does not include all of the information and footnotes required by accounting principles generally accepted in the United States 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 month period ended March 31, 2004 are not necessarily indicative of the results that may be expected for the year ending December 31, 2004.

 

For further information, refer to the consolidated financial statements and footnotes thereto included in Equitable Resources’ Annual Report on Form 10-K for the year ended December 31, 2003, as well as in “Information Regarding Forward Looking Statements” on page 16 of this document.

 

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 performance contracting, energy efficiency programs, combined heat and power and central boiler/chiller plant development, design, construction, ownership and operation.

 

Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income, equity in earnings of 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.

 

Substantially all of the Company’s operating revenues, income from continuing operations and assets are generated or located in the United States.

 

6

 

		Three Months Ended March 31,
		2004			2003
		(Thousands)
Revenues from external customers:
Equitable Utilities		$	281,374		$	236,109
Equitable Supply		99,244			81,697
NORESCO		33,926			45,518
Less: intersegment revenues (a)		(14,117		)	(21,002		)
Total		$	400,427		$	342,322
Depreciation, depletion and amortization:
Equitable Utilities		$	7,326		$	6,735
Equitable Supply		14,043			11,582
NORESCO		251			349
Headquarters		147			87
Total		$	21,767		$	18,753
Operating income:
Equitable Utilities (b)		$	55,960		$	59,027
Equitable Supply		61,530			48,413
NORESCO		3,786			3,921
Unallocated expenses		(1,749		)	(2,041		)
Total operating income		$	119,527		$	109,320
Reconciliation of operating income to net income:
Equity in earnings of nonconsolidated investments, excluding Westport:
Equitable Supply		$	143		$	239
NORESCO		720			937
Unallocated earnings		38			56
Total		$	901		$	1,232
Minority interest:
Equitable Supply		$	—		$	(871	)
NORESCO		(370		)	—
Total		$	(370	)	$	(871	)
Charitable foundation contribution		—			(9,279		)
Westport equity earnings		—			3,614
Interest expense		12,259			12,321
Income taxes		37,729			27,216
Income from continuing operations before cumulative effect of accounting change		70,070			64,479
Cumulative effect of accounting change, net of tax (c)		—			(3,556		)
Net income		$	70,070		$	60,923

 

		March 31, 2004			December 31, 2003
		(Thousands)
Segment Assets:
Equitable Utilities		$	1,037,797		$	1,120,708
Equitable Supply		1,370,132			1,338,702
NORESCO (d)		223,647			323,569
Total operating segments		2,631,576			2,782,979
Headquarters assets		265,708			156,913
Total		$	2,897,284		$	2,939,892

 

7

 

		Three Months Ended March 31,
		2004			2003
		(Thousands)
Expenditures for segment assets:
Equitable Utilities		$	14,600		$	8,668
Equitable Supply (e)		21,053			67,738
NORESCO		28			48
Unallocated expenditures		189			596
Total		$	35,870		$	77,050

 

(a)   Intersegment revenues represent sales from Equitable Supply to the unregulated marketing affiliate of Equitable Utilities.

(b)   For the three months ended March 31, 2004, operating income includes the reduction of a regulatory reserve due to higher than anticipated recoveries for the Balance Reduction Program.

(c)   Net income for the three months ended March 31, 2003 has been adjusted to reflect the cumulative effect of accounting change related to the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”  See Note K.

(d)   The Company’s goodwill balance as of March 31, 2004 and December 31, 2003 totaled $51.8 million and is entirely related to the NORESCO segment.

(e)   For the three months ended March 31, 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 Statement of Financial Accounting Standards (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 or obligation with respect to the contract receivables once the sale is complete.  As of March 31, 2004 the Company had recorded current liabilities of $73.4 million classified as current portion of project financing obligations and long-term liabilities of $41.5 million classified as project financing obligations on the Condensed Consolidated Balance Sheets.  The current portion of project financing obligations represents 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 March 31, 2004, approximately $3.6 million of the contract receivables met the criteria for sales treatment, generating a gain of $0.2 million.  The de-recognition of the $3.6 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.

 

8

 

D.        Derivative Commodity 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 Audit Committee of the Company’s Board of Directors and is comprised of the chief executive officer, the chief financial officer and other officers and employees of the Company.

 

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, 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), SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” (Statement No. 138) and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (Statement No. 149).  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 determined to be appropriate by the Company’s CRC.  The Company reports all gains and losses on its energy trading contracts net on its Statements of Consolidated Income in accordance with Emerging Issues Task Force (EITF) No. 02-3, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10 and 00-17” (EITF No. 02-3).

 

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 $40.6 million asset and a $218.0 million liability as of March 31, 2004, and a $34.5 million asset and a $137.6 million liability as of December 31, 2003.  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, 2003 to March 31, 2004 is primarily the result of the increase in natural gas prices.  The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as cash flow hedges total 344.6 Bcf and 347.2 Bcf as of March 31, 2004 and December 31, 2003, respectively, and primarily relate to natural gas swaps.  The open swaps at March 31, 2004 have maturities extending through December 2010.

 

The Company deferred net losses of $109.2 million and $58.4 million in accumulated other comprehensive loss, net of tax, as of March 31, 2004 and December 31, 2003, 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 $47.1 million of unrealized losses on its derivative commodity instruments reflected in accumulated other comprehensive loss, net of tax, as of March 31, 2004 will be recognized in earnings during the next twelve months due to the physical settlement of hedged transactions.

 

For the three months ended March 31, 2004 and 2003, ineffectiveness associated with the Company’s derivative commodity instruments designated as cash flow hedges decreased earnings by approximately $0.1 million and $1.0 million, respectively.  These amounts are included in operating revenues in the Statements of Consolidated Income.

 

The Company conducts trading activities 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.

 

9

 

At March 31, 2004, the absolute notional quantities of the futures and swaps held for trading purposes totaled 1.9 Bcf and 46.8 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 three months ended March 31, 2004 (in thousands).

 

Fair value of contracts outstanding as of December 31, 2003		$	173
Contracts realized or otherwise settled		(523		)
Other changes in fair value		561
Fair value of contracts outstanding as of March 31, 2004		$	211

 

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 March 31, 2004.

 

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

 

Source of Fair Value		Maturity Less than 1 Year			Maturity 1-3 Years			Maturity 4-5 Years			Maturity in Excess of 5 Years			Total Fair Value
		(Thousands)
Prices actively quoted (NYMEX) (1)		$	116		$	18		$	—		$	—		$	134
Prices provided by other external sources (2)		20			38			19			—			77
Net derivative assets		$	136		$	56		$	19		$	—		$	211

 

(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.

 

E.             Investments

 

As of March 31, 2004, the investments classified by the Company as available-for-sale include approximately $19.4 million of debt and equity securities intended to fund plugging and abandonment and other liabilities for which the Company self-insures and a $380.3 million investment in Westport Resources Corporation (Westport).  The Company owns approximately 11.53 million shares, or 17.0% of Westport.  On April 7, 2004, Westport announced a merger with Kerr-McGee Corporation (Kerr-McGee).  Westport and Kerr-McGee expect the merger will close in the third quarter of 2004.  Under the terms of the merger agreement, the Company will receive 0.71 shares of Kerr-McGee for each Westport share.

 

The Company utilizes the specific identification method to determine the cost of securities sold.  There were no realized gains or losses associated with the investments for the three months ended March 31, 2004 and 2003.  Any unrealized gains or losses are recognized within the Condensed Consolidated Balance Sheets as a component of equity, accumulated other comprehensive income.  As of December 31, 2003, the Company performed an impairment analysis in accordance with SFAS No. 115 “Accounting for Certain Investments in Debt and Equity Securities” (Statement No. 115) and concluded that all declines below cost were temporary.  Factors and considerations the Company used to support this conclusion have not changed in the first quarter 2004.

 

On March 31, 2003, the Company donated 905,000 shares of Westport stock to a community giving foundation.  The foundation was established by the Company and is projected to facilitate the Company’s charitable giving program for

 

10

 

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.

 

F.             Comprehensive Income (Loss)

 

Total comprehensive income, net of tax, was as follows:

 

		Three Months Ended March 31,
		2004			2003
		(Thousands)
Net income		$	70,070		$	60,923
Other comprehensive income:
Net change in cash flow hedges:
Natural gas (Note D)		(50,825		)	(25,060		)
Interest rate		(59		)	43
Unrealized gain (loss) on investments, available-for-sale (Note E):
Westport		23,454			83,459
Other		272			(169		)
Total comprehensive income		$	42,912		$	119,196

 

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

 

		March 31, 2004			December 31, 2003
		(Thousands)
Net unrealized loss from hedging transactions		$	(110,539	)	$	(59,656	)
Unrealized gain on available-for-sale securities		124,171			100,446
Minimum pension liability adjustment		(25,532		)	(25,532		)
Foreign currency translation adjustment		7			7
		$	(11,893	)	$	15,265

 

G.            Stock-Based Compensation

 

Restricted stock grants in the aggregate amount of 136,000 shares were awarded to various employees during the first quarter of 2004.  The related expense recognized during the three-month period ended March 31, 2004 was $0.3 million and is classified as selling, general and administrative expense.

 

No new stock options were awarded during the three months ended March 31, 2004.  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.

 

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 March 31,
		2004			2003
		(Thousands)
Net income, as reported		$	70,070		$	60,923
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects		2,525			2,904
Deduct: Total stock-based employee compensation expense determined by the fair value method for all awards, net of related tax effects		(3,689		)	(4,004		)
Pro forma net income		$	68,906		$	59,823
Earnings per share:
Basic, as reported		$	1.13		$	0.98
Basic, pro forma		$	1.11		$	0.96
Diluted, as reported		$	1.10		$	0.96
Diluted, pro forma		$	1.08		$	0.94

 

11

 

H.            Appalachian Basin Partners, LP

 

In February 2003, the Company purchased the remaining 31% limited partnership interest in Appalachian Basin Partners, LP (ABP) from the minority interest holders for $44.2 million.  The 31% limited partnership interest represents approximately 60.2 Bcf of reserves.  The ABP partnership was formed in November 1995 when the Company monetized Appalachian gas properties qualifying for the nonconventional fuels tax credit.  The Company retained a partnership interest in the properties that increased substantially based on the attainment of a performance target, which was met near the end of 2001.  The Company consequently consolidated the partnership starting in 2002, and the remaining portion not owned by the Company was recorded as minority interest.  As a result of the acquisition of the 31% interest, effective February 1, 2003, the Company no longer recognized minority interest expense associated with ABP, which totaled $0.9 million for the three months ended March 31, 2003.

 

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 and any other separately reported net income items, such as discontinued operations, extraordinary items and cumulative effects of accounting changes.  The Company currently estimates the annual effective income tax rate from continuing operations to be 35.0%.

 

J.             Pension and Other Postretirement Benefit Plans

 

The Company has defined benefit pension and other postretirement benefit plans covering union members that generally provide benefits of stated amounts for each year of service.  Prior to December 31, 2003, the Company provided benefits to certain salaried employees through defined benefit plans that used a benefit formula based upon employee compensation.  Effective December 31, 2003, the pension benefits provided through this plan were frozen and the covered salaried employees were converted to a defined contribution plan.  All other salaried employees are participants in a defined contribution plan.

 

The Company’s costs related to its defined benefit pension and other postretirement benefit plans for the three months ended March 31, 2004 and 2003 were as follows:

 

		Pension Benefits						Other Benefits
		Three Months Ended March 31,
		2004			2003			2004			2003
		(Thousands)
Components of net periodic benefit cost
Service cost		$	397		$	671		$	121		$	78
Interest cost		1,742			1,889			819			867
Expected return on plan assets		(2,457		)	(2,165		)	—			—
Amortization of prior service cost		235			322			(11		)	(11		)
Recognized net actuarial loss		186			5			500			457
Settlement loss		476			552			—			—
Net periodic benefit cost		$	579		$	1,274		$	1,429		$	1,391

 

Consistent with the disclosure made in its Form 10-K for the fiscal year ended December 31, 2003, the Company expects that it will not make a contribution to its defined benefit plan in 2004.

 

On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act).  The Act expanded Medicare to include, for the first time, coverage for prescription drugs.  The Company sponsors retiree medical programs for certain of its locations and expects that this legislation will reduce the Company’s costs for some of these programs in the future.

 

In January 2004, Financial Accounting Standards Board (FASB) Staff Position 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-1) was issued which permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Act.  The Company is awaiting guidance from various governmental and regulatory agencies concerning the requirements that must be met to obtain these cost reductions as well as the manner in which such savings should be measured.  Based on the Company’s preliminary analysis, it appears that some of the Company’s retiree

 

12

 

medical plans may need to be revised in order to qualify for beneficial treatment under the Act, while other plans can continue unchanged.

 

Due to various uncertainties related to the Act and the appropriate accounting methodology for this event, the Company has elected to defer financial recognition with respect to the effects of the Act until the FASB issues final accounting guidance.  When issued, that final guidance may require the Company to change previously reported information.  In accordance with FSP FAS 106-1, measures of the accumulated postretirement benefit obligation or net periodic postretirement benefit cost in the condensed consolidated financial statements or accompanying notes do not reflect the effects of the Act on the Company’s plan.

 

K.            Asset Retirement Obligations

 

In June 2001, the 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 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 are recorded as liabilities when they are incurred, which is typically at the time the wells are drilled.  Amounts recorded for the related assets are 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 three months ended March 31, 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 related 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 costs 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 March 31, 2004
		(Thousands)
Asset retirement obligation as of beginning of period		$	29,780
Accretion expense		522
Liabilities incurred		33
Liabilities settled		(328		)
Asset retirement obligation as of end of period		$	30,007

 

L.            Recently Issued Accounting Standards

 

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 No. 46).  FIN No. 46 required certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity did not have the characteristics of a controlling financial interest or did not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties.  Prior to FIN No. 46, an entity was generally consolidated by an enterprise when the enterprise had a controlling financial interest through ownership of a majority voting interest in the entity.  FIN No. 46 was effective for all new variable interest entities created or acquired after January 31, 2003.  The Company adopted FIN No. 46 for variable interest entities created or acquired prior to February 1, 2003 as of July 1, 2003.  The adoption of FIN No. 46 required the consolidation of Plymouth Cogeneration Limited Partnership (Plymouth), a joint venture entered into by

 

13

 

NORESCO, and the deconsolidation of EAL/ERI Cogeneration Partners LP (Jamaica), which is the partnership that holds the Jamaican power plant.

 

In December 2003, the FASB issued a revision to FIN No. 46 (FIN No. 46R) that modified some of the provisions of FIN No. 46 and provided exemptions to certain entities from the original guidance.  The Company adopted FIN No. 46R in the first quarter of 2004.  The adoption of FIN No. 46R required the Company to deconsolidate Plymouth as of January 1, 2004, due to certain modifications of the original FIN No. 46 provisions.

 

This deconsolidation returns Plymouth to the equity method of accounting for investments.  The Company restored the equity investment in Plymouth of $0.1 million and decreased minority interest by $0.6 million in the Condensed Consolidated Balance Sheet.  As of January 1, 2004, $4.9 million of assets and $4.9 million of liabilities, including nonrecourse debt of $4.0 million, were removed from the Condensed Consolidated Balance Sheet.

 

The Company also has an interest in a variable interest entity, Appalachian NPI (ANPI), in which Equitable was not deemed to be the primary beneficiary.  As of March 31, 2004, ANPI had $265.3 million of total assets and $235.8 million of total liabilities (including $191.7 million of long-term debt, including current maturities), excluding minority interest.  The Company’s maximum exposure to a loss as a result of its involvement with ANPI is estimated to be $29.0 million.

 

Employers’ Disclosures about Pensions and Other Postretirement Benefits

 

In December 2003, the FASB issued SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (Statement No. 132).  This Statement revises employers’ disclosures about pension plans and other postretirement benefits.  It retains the original disclosure requirements contained in SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” and requires additional disclosures about the assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans.  This Statement was effective for financial statements with fiscal years ending after December 15, 2003.  Accordingly, the additional disclosures required by the revised Statement No. 132 were included in the Company’s 2003 Form 10-K.  Interim period disclosures required by revised Statement No. 132 are effective for interim periods beginning after December 15, 2003 and have been included in Note J.

 

On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act).  The Act expanded Medicare to include, for the first time, coverage for prescription drugs.  In January 2004, the FASB issued Staff Position 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-1).  This position permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Act.  As permitted by FSP FAS 106-1, the Company has elected to defer financial recognition with respect to the effects of the Act until the FASB issues final accounting guidance.  In accordance with FSP FAS 106-1, appropriate disclosures related to the deferral election have been made in Note J.

 

Stock Compensation

 

On March 31, 2004, the FASB issued an exposure draft, “Share-Based Payment, an Amendment of FASB Statements No. 123 and 95.”  The proposed change in accounting would replace existing requirements under SFAS 123, “Accounting for Stock-Based Compensation,” and APB Opinion No 25, “Accounting for Stock Issued to Employees.”  The exposure draft covers a wide range of equity-based compensation arrangements. Under the FASB’s proposal, all forms of share-based payments to employees, including employee stock options, would be treated the same as other forms of compensation by recognizing the related cost in the income statement.  The expense of the award would generally be measured at fair value at the grant date.  The comment period for the exposure draft ends on June 30, 2004 and final rules are expected to be issued in late 2004.  The standard would be applicable for fiscal years beginning after December 15, 2004.  The Company will evaluate the impact of any change in accounting standard on the Company’s financial position and results of operations when the final rules are issued.

 

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

 

The American Institute of Certified Public Accountants has issued an exposure draft Statement of Position (SOP), “Accounting for Certain Costs and Activities Related to Property, Plant, and Equipment (PP&E).”  The SOP was presented for FASB clearance in April 2004.  The FASB voted not to clear the proposed SOP and deferred consideration of the

 

14

 

exposure draft until consideration of its short term convergence project on property, plant and equipment, including depreciation which is currently scheduled to take place during the 2005-2006 time frame.  The Company will evaluate the impact of any change in accounting standard on the Company’s financial position and results of operations when the final rules are issued.

 

M.           Other Events

 

After an extended period of troubled operations, 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 No. 46.  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.  A mediation held in April 2004 did not resolve the litigation.

 

N.            Reclassification

 

Certain previously reported amounts have been reclassified to conform to the 2004 presentation.  These reclassifications did not affect reported net income or cash flows.

 

O.            Subsequent Events

 

On April 14, 2004, the Company settled a disputed insurance coverage claim involving the Kentucky West Virginia unit of the Supply segment.  As a result of the settlement, Equitable will recognize income of approximately $6.1 million in the second quarter 2004.

 

15

 

Equitable Resources, Inc. and Subsidiaries

 

Item 2. 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, as amended.  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 expected amount and timing of the Company’s plugging and abandonment obligations; the description of the Company’s hedging strategy and the effectiveness of that strategy, including the impact on earnings of a change in NYMEX; 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 expected increase in depletion rates; the expected impact of new accounting pronouncements; the resolution of issues surrounding implementation of the Company’s new customer information and billing system; the ability of the Company to divest its international projects in 2004; the adequacy of legal reserves and therefore the belief that the ultimate outcome of any matter currently pending will not materially affect the financial position of the Company; the amount of Company’s pension plan funding obligations; the amount of or increase in future dividends; the ultimate outcome of rate cases, regulatory reviews and other regulatory action, including the amounts that the Company expects to recover as a consequence of such events; the ability to realize value from the investment in Westport Resources Corporation and the anticipated closing of the announced Westport/Kerr-McGee merger;  the amount of the cost to implement the Environmental Protection Agency rules regarding Spill Prevention, Control and Countermeasures; the expectation that the lack of enabling legislation for performance contracting work is only temporary and that the passage of the Medicare Prescription, Drug, Improvement and Modernization Act of 2003 will reduce certain of the Company’s medical costs; the possibility of the passage of energy legislation; 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 approvals and legislative action, 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 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

 

In this report, Equitable (which includes Equitable Resources, Inc. and unless the context otherwise requires, all of our subsidiaries) is at times referred to as “the Company”.

 

Equitable Resources’ consolidated income from continuing operations before cumulative effect of accounting change for the quarter ended March 31, 2004 totaled $70.1 million, or $1.10 per diluted share, compared to $64.5 million, or $1.02 per diluted share, reported for the same period a year ago.  The first quarter 2004 earnings from continuing operations before cumulative effect of accounting change increased 9% from 2003 due to an increase in average natural gas prices, an increase in sales volumes from production and the establishment of a community giving foundation in 2003.  These factors were partially offset by a reduction in equity earnings due to the Company’s 2003 change in accounting treatment for its investment in Westport Resources Corporation (Westport), an increase in depreciation, depletion and amortization resulting from an increase in the unit depletion rate and increased production volumes and warmer weather in 2004.

 

16

 

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.

 

		Three Months Ended March 31,
		2004			2003
OPERATIONAL DATA
Total operating expenses as a% of net operating revenues		40.32		%	39.28		%
Capital expenditures (thousands)		$	14,600		$	8,668
FINANCIAL RESULTS (Thousands)
Utility revenues (regulated)		$	195,689		$	184,325
Marketing revenues		85,685			51,784
Total operating revenues		281,374			236,109
Utility purchased gas costs (regulated)		112,368			97,219
Marketing purchased gas costs		75,240			41,671
Net operating revenues		93,766			97,219
Operating expenses:
Operating and maintenance expense		12,117			13,103
Selling, general and administrative expense		18,363			18,354
Depreciation, depletion and amortization		7,326			6,735
Total operating expenses		37,806			38,192
Operating income		$	55,960		$	59,027

 

Three Months Ended March 31, 2004
vs. Three Months Ended March 31, 2003

 

Net operating revenues for the three months ended March 31, 2004 were $93.8 million compared to $97.2 million for the same quarter in 2003.  The 4% decrease in net operating revenues is a result of 6% warmer weather in the first quarter of 2004.  Total expenses for the quarter slightly decreased by 1% from $38.2 million in 2003 to $37.8 million in 2004.  A reduction of a regulatory reserve and on-going cost reduction initiatives were offset by increases in legal, insurance, bad debt and depreciation expenses.

 

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 from a well or gathering pipeline) in eastern Kentucky.  The distribution operations provide natural gas services to approximately 275,500 customers, comprising 256,500 residential customers and 19,000 commercial and industrial customers.  Equitable Gas is subject to rate regulation by state regulatory commissions in Pennsylvania, West Virginia and Kentucky.

 

Pennsylvania law requires that local distribution companies develop and implement programs to assist low-income customers with paying their gas bills.  Ostensibly the costs of these programs are recovered through rates charged to other residential customers.  Equitable Gas has several such programs.  In August 2003, Equitable Gas submitted revisions to those programs for Pennsylvania Public Utility Commission (PA PUC) approval.  The revisions were designed to make participation in the low-income programs more accessible and to improve participants’ ability to

 

17

 

pay their bills.  In October 2003, the PA PUC approved Equitable Gas’ revised programs and instructed the various stakeholders to ascertain if additional funding was necessary to implement the revised programs.  Initially the stakeholders argued that the full cost of the programs was already being collected by Equitable Gas in its base rates and through various surcharges.  Ultimately, consensus was reached to allow the Company to collect an additional $.30 per Mcf to fund the programs.  Based on recent billing volumes this would equate to approximately $7.0 million in additional annual revenue.  By PA PUC Order of April 1, 2004, the funding mechanism was approved for all residential consumption beginning April 2, 2004, and will remain in place until Equitable Gas seeks authority to change the funding mechanism.  This funding mechanism is not expected to have a significant impact on 2004 results given that it was approved at the end of the highest volume quarter and during the remainder of 2004 the Company plans to increase spending and focus it efforts internally on improving analytical resources and its collection efforts.  In the future, it is expected that this mechanism will become a key component to the Company’s efforts to reduce bad debt expense.

 

A PA PUC mandated asset life study is expected to be filed with the PA PUC by Equitable Gas in May 2004.  This study will change the estimated useful lives for Equitable Gas’ main lines and service lines as a result of installing plastic pipe.  If the study is retroactively approved to January 1, 2004, as requested by Equitable Gas, then the study will result in a decrease of depreciation expense of approximately $3.0 million in 2004.

 

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 PA PUC to implement a performance-based incentive that provides to customers a purchased gas cost credit which is fixed in amount, 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 cost credit 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 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 is fully funded through customer contributions and a surcharge in rates.

 

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.  To date, Equitable Gas has not offered Fixed Sales Service but will continue to analyze the feasibility of a Fixed Sales Service in the future.

 

Equitable Gas submits quarterly purchased gas cost filings with the PA PUC that are subject to quarterly reviews and annual audits by the PA PUC.  The PA PUC Bureau of Audits’ most recent annual purchased gas-cost audit for the 2000-2001 purchased gas period concluded in the fourth quarter of 2003.  A final audit report for the 2000-2001 period was received in the first quarter of 2004.  No adverse audit findings were included in the report. The Company’s purchased gas costs for 2002-2003 are currently unaudited by the PA PUC Bureau of Audits, but have received a final prudency review by the PA PUC through 2002 in which no material issues have been noted.

 

18

 

Other

 

In the first quarter of 2004, Equitable Gas implemented a new customer information and billing system for which it incurred $12.4 million of capital expenditures from project inception through March 31, 2004.  The system is being depreciated over a fifteen-year period.  The new system will help the Company better segment customer information, thereby making it easier for the Company to identify customers eligible for the energy assistance programs and customers for which additional collection efforts are necessary.  The Company has experienced some conversion issues which have been addressed for financial reporting purposes.  The Company has incurred additional costs in connection with resolving the conversion issues, but it expects to resolve all conversion issues by the end of 2004.

 

Equitable Gas’ contract with the members of the local United Steelworkers union representing 208 employees expired on April 15, 2003.  The union has continued to work under the terms and conditions of the expired contract while negotiating a new contract.

 

		Three Months Ended March 31,
		2004			2003
OPERATIONAL DATA
Heating Degree days (30 year normal YTD average – 2,930) (a)		2,925			3,115
O&M per customer (b)		$	85.10		$	89.71
Volumes (MMcf):
Residential sales and transportation		13,080			14,165
Commercial and industrial		11,666			11,590
Total throughput		24,746			25,755
FINANCIAL DATA (Thousands)
Net operating revenues:
Residential net operating revenues		$	44,966		$	48,146
Commercial and industrial net operating revenues		20,773			21,481
Other net operating revenues		1,564			1,566
Total net operating revenues		67,303			71,193
Operating expenses (total operating expenses excluding depreciation)		24,065			25,428
Depreciation, depletion and amortization		5,319			4,950
Operating income		$	37,919		$	40,815

 

(a)       A heating degree day is computed by taking the average temperature on a given day in the operating region and subtracting it from 65 degrees Fahrenheit.  Each degree day by which the average daily temperature falls below 65 degrees represents one heating degree day.

 

(b)      O&M is defined for this calculation as the sum of operating expenses (total operating expenses excluding depreciation) less other taxes.  Other taxes for the three months ended March 31, 2004 and 2003 totaled $0.6 million and $0.7 million, respectively.  As of March 31, 2004 and 2003, Equitable Gas had approximately 275,500 customers and 276,000 customers, respectively.

 

Three Months Ended March 31, 2004
vs. Three Months Ended March 31, 2003

 

The 5% decrease in net operating revenues and the 4% decrease in throughput is primarily due to warmer weather in the first quarter of 2004 compared to the prior year quarter.  Heating degree days were 2,925, which is 6% warmer than the 3,115 degree days reported in 2003.

 

The 3% decrease in total operating expenses is due to the reduction of a regulatory asset reserve ($7.3 million) and on-going cost initiatives offset by increased bad debt expense ($5.7 million), and insurance, legal and benefits expense ($0.9 million).  The reduction in the regulatory asset reserve was due to Equitable Gas having higher than anticipated recoveries for the Balance Reduction Program through payments and rates.

 

19

 

Pipeline Operations

 

Interstate Pipeline

 

The interstate pipeline operations of Equitrans and Carnegie Pipeline are subject to rate regulation by the Federal Energy Regulatory Commission (FERC).  In 1997, Equitrans filed a general change application (rate case).  The rate case was resolved through a FERC approved settlement among all parties.  The settlement provided, with certain limited exceptions, that Equitrans not file a general rate increase with an effective date before August 1, 2001, and must file a general rate case application to take effect no later than August 1, 2003.  In the second quarter 2002, Equitrans filed with the FERC to merge its assets and operations with the assets and operations of Carnegie Pipeline.  In April 2003, Equitrans filed a proposed settlement with the 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.  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.  In response to the July 1, 2003 order Equitrans filed for and received an extension of time for its rate case filing deadline from August 1, 2003 until December 1, 2003.  Also in response to the July 1, 2003 order, on January 1, 2004, the merger of Equitrans and Carnegie Pipeline was effectuated with Equitrans surviving the merger.

 

Equitrans timely filed its rate case application on December 1, 2003.  On December 31, 2003, in accordance with the Natural Gas Act, the FERC issued an order accepting in part and rejecting in part Equitrans’ general rate application.  Certain of Equitrans’ proposed tariff sheets have been accepted subject to a 5-month suspension period, but Equitrans’ requests for revenue relief were denied.  The increase was rejected in large part because Equitrans did not provide cost and revenue data for Carnegie Pipeline.  Equitrans filed a rehearing request on January 30, 2004, seeking reconsideration of the FERC’s December 31, 2003 order, including the FERC’s order requiring a certificate filing to replenish certain storage base gas volumes.

 

In the interest of avoiding unnecessary delay, Equitrans re-filed its rate case application on March 1, 2004, complete with cost and revenue data for Carnegie Pipeline.  Consistent with the Company’s original December 1, 2003 filing, Equitrans’ rate case application addresses several issues including establishing an appropriate return on the Company’s capital investments, addressing the Company’s pension funding levels and accruing for post-retirement benefits other than pensions.  The Company’s filed request for rate relief is for an annual amount of approximately $17.2 million.  On March 31, 2004, in accordance with the Natural Gas Act, the FERC issued an order accepting Equitrans’ rate application, suspending its tariff sheets until September 1, 2004, and establishing certain procedural parameters for the case.  Equitrans will continue to explore and evaluate settlement options throughout the pendency of the proceeding.

 

Other

 

Equitrans’ collective bargaining agreement with Paper, Allied-Industrial, Chemical and Energy Workers Industrial Union Local 5-0843 representing 26 employees expired April 19, 2004.  The union has continued to work under the terms and conditions of the expired contract while negotiating a new contract.

 

		Three Months Ended March 31,
		2004			2003
OPERATIONAL DATA
Transportation throughput (BBtu)		18,961			20,428
FINANCIAL DATA (Thousands)
Net operating revenues		$	16,018		$	15,913
Operating expenses (Total operating expenses excluding depreciation)		5,398			5,673
Depreciation, depletion and amortization		1,965			1,707
Operating income		$	8,655		$	8,533

 

20

 

Three Months Ended March 31, 2004
vs. Three Months Ended March 31, 2003

 

Total transportation throughput decreased 1.5 million MMbtu, or 7%, over the prior year quarter due primarily to warmer weather in the first quarter of 2004.  Those volumes were partially offset by increased volumes with a single third party customer.  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 negatively impact net revenues.

 

Operating expenses decreased from $5.7 million in 2003 to $5.4 million in 2004 as a result of on-going cost reduction initiatives.

 

21

Energy Marketing

 

		Three Months Ended March 31,
		2004			2003
OPERATIONAL DATA
Total throughput (BBtu)		21,934			14,157
FINANCIAL DATA (Thousands)
Net operating revenues		$	10,445		$	10,113
Operating expenses (Total operating expenses excluding depreciation)		1,017			356
Depreciation, depletion and amortization		42			78
Operating income		$	9,386		$	9,679

 

Three Months Ended March 31, 2004
vs. Three Months Ended March 31, 2003

 

Net operating revenues in the first quarter of 2004 increased slightly to $10.4 million, or 3%, from $10.1 million in 2003.  Volumes for the same time period increased approximately 7.8 million MMbtu, of which 5.6 million MMbtu related to sales for resale off the Equitable Utilities’ systems.  Commercial and industrial and trading and utility volumes also increased over the prior year, however, net operating revenues did not increase proportionately due to relatively low margins on these volumes.

 

Operating expenses, excluding depreciation, depletion and amortization, increased approximately $0.7 million to $1.0 million from the first quarter of 2003 to the first quarter of 2004.  The majority of this increase was the result of costs associated with legal claims and reserves and an increase in bad debt expense.  These increases were partially offset by the Company’s continued focus on cost reduction initiatives.

 

EQUITABLE SUPPLY

 

Equitable Supply consists of two activities, production and gathering, with operations in the Appalachian Basin region of the United States.  Equitable Production develops, produces and sells natural gas (and minor amounts of associated crude oil and its associated by-products).  Equitable Gathering engages in natural gas gathering and the processing of natural gas liquids.

 

Purchase and Sale of Gas Properties

 

In February 2003, the Company purchased the remaining 31% limited partnership interest in Appalachian Basin Partners, LP (ABP) from the minority interest holders for $44.2 million.  This amount was included in the total capital spending of the first quarter of 2003.  Effective February 1, 2003, the Company no longer recognized minority interest expense associated with ABP, which totaled $0.9 million for the three months ended March 31, 2003.  The 31% limited partner interest represents approximately 60.2 Bcf of reserves.

 

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 approximately 13 Bcf of net reserves for proceeds of approximately $6.6 million.  The wells produced an aggregate of approximately 0.2 Bcf during the first quarter of 2003.  The Company did not recognize a gain or a loss as a result of this disposition.

 

Other

 

In the first quarter of 2004, Equitable Supply implemented a significant change to its business model.  Previously, Equitable Supply followed the typical model for an Appalachian Basin E&P Company.  The typical model suggests

 

22

 

that growth occurs from drilling and then subsequently tending to the base wells and the infrastructure that supports that drilling, in the most inexpensive possible manner.  The current strategy employed by Equitable Supply is to continue to drill wells, but to spend more time and resources tending aggressively to the improvement of the base infrastructure.  This change is intended to accelerate sales from existing wells and reduce the Company’s long-term requirement for maintenance capital with respect to these wells.  The execution of this new model will be challenging and will result in higher operating expense, but the Company is committed to improving outcomes through actions such as: (1) functional specialization of the Company’s organization; (2) significantly increase the Company’s focus on management; (3) accelerate implementation and installation of compressor stations; (4) increase the sense of accountability, ownership and attention to detail in the field and engineering areas; and (5) develop and maintain an expectation of success in our employee base.

 

		Three Months Ended March 31,
		2004			2003
OPERATIONAL DATA
Total sales volumes (MMcfe)		17,042			15,517
Capital expenditures (thousands) (a)		$	21,053		$	67,738
FINANCIAL DATA (Thousands)
Production revenues		$	79,429		$	64,679
Gathering revenues		19,815			17,018
Total net operating revenues		99,244			81,697
Operating expenses:
Lease operating expense, excluding severance taxes		6,085			5,275
Severance tax		4,002			3,887
Gathering and compression (operation and maintenance)		6,587			5,752
Selling, general and administrative (SG&A)		6,997			6,788
Depreciation, depletion and amortization (DD&A)		14,043			11,582
Total operating expenses		37,714			33,284
Operating income		$	61,530		$	48,413
Equity in earnings of nonconsolidated investments		$	143		$	239
Minority interest		$	—		$	(871	)

 

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

 

Three Months Ended March 31, 2004
vs. Three Months Ended March 31, 2003

 

Equitable Supply’s operating income for the 2004 first quarter totaled $61.5 million, 27% higher than the $48.4 million earned in the same period last year.  Total net operating revenues were $99.2 million, $17.5 million higher than the previous year’s total net operating revenues of $81.7 million.  Production revenues increased $14.7 million quarter over quarter to $79.4 million in 2004 from $64.7 million in 2003.  The revenue increase was a result of both a sales volume increase of 1.5 Bcf and an average well-head sales price increase of $0.51 per Mcfe.  Gathering revenues were $2.8 million higher at $19.8 million, compared with $17.0 million in 2003.  The increased gathering revenue was primarily due to an increase in gathering rates.

 

Total operating expenses for the 2004 first quarter totaled $37.7 million compared to $33.3 million in the 2003 first quarter.  The increase in total operating expenses was due to increases of $2.5 million in depreciation, depletion and amortization expense and $1.9 million in other expenses.

 

23

 

Equitable Production

 

		Three Months Ended March 31,
		2004			2003
OPERATIONAL DATA
Total sales volumes (MMcfe)		17,042			15,517
Average (well-head) sales price ($/Mcfe)		$	4.50		$	3.99
Company usage, line loss (MMcfe)		1,199			1,057
Natural gas inventory usage, net (MMcfe)		(112		)	—
Natural gas and oil production (MMcfe) (a)		18,129			16,574
Operated volumes – third parties (MMcfe) (b)		5,355			5,782
Lease operating expense (LOE), excluding severance tax ($/Mcfe)		$	0.34		$	0.32
Severance tax ($/Mcfe)		$	0.22		$	0.23
Production depletion ($/Mcfe)		$	0.54		$	0.48
Depreciation, depletion and amortization (in thousands):
Production depletion		$	9,822		$	7,955
Other depreciation, depletion and amortization		574			475
Total depreciation, depletion and amortization		$	10,396		$	8,430

 

(a)     Natural gas and oil production represents the Company’s interest in gas and oil production measured at the well-head. It is equal to the sum of total sales volumes, Company usage, line loss, and natural gas inventory usage, net.

 

(b)    Includes volumes in which interests were sold but which the Company still operates for third parties for a fee.

 

		Three Months Ended March 31,
		2004			2003
FINANCIAL DATA (Thousands)
Production revenues		$	76,648		$	61,902
Other revenues		2,781			2,777
Total production revenues		79,429			64,679
Operating expenses:
Lease operating expense, excluding severance taxes		6,085			5,275
Severance tax		4,002			3,887
Selling, general and administrative (SG&A)		4,618			4,480
Depreciation, depletion and amortization (DD&A)		10,396			8,430
Total operating expenses		25,101			22,072
Operating income		$	54,328		$	42,607
Equity in earnings of nonconsolidated investments		$	143		$	239
Minority interest		$	—		$	(871	)

 

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Three Months Ended March 31, 2004
vs. Three Months Ended March 31, 2003

 

Equitable Production’s revenues, which are derived primarily from the sale of produced natural gas, increased $14.7 million from the first quarter of 2003 to the 2004 first quarter.  The increase is primarily the result of a higher average well-head sales price of $4.50 per Mcfe compared to $3.99 per Mcfe in the prior year ($8.2 million) and a 1.5 Bcf increase in sales volume ($6.5 million).  Equitable Production was able to realize a higher average well-head sales price, in a quarter where the average NYMEX gas price was down by $0.91 per MMbtu, as a result of higher average hedge price and the satisfaction of a prepaid contract at the end of 2003.  The increase in sales volumes is the result of new wells drilled in 2003 and 2004 and improved pipeline system management, partially offset by the natural production decline in the Company’s wells and the Company’s sales in February 2003 of approximately 500 of its low-producing wells within two of its non-strategic districts in two separate transactions.

 

Operating expenses increased $3.0 million or 14% over the prior year from $22.1 million to $25.1 million.  This increase was primarily due to increased DD&A ($2.0 million) and increased lease operating expenses ($0.8 million).  The increase in DD&A was due to a $0.06 per Mcf increase in the unit depletion rate ($1.0 million) and increased production volumes and other depreciation ($1.0 million).  The $0.06 per Mcf increase in the unit depletion rate is primarily the result of the net development capital additions in 2003 on a relatively consistent proved reserve base.  Given Equitable Production’s projected capital program and the fact that the total proved reserve base is expected to remain consistent, with reserve additions being offset by production, the Company expects the per unit depletion expense to increase by approximately $0.05 per Mcf each year.  The increase in lease operating expenses is primarily the result of an increase in property taxes and liability insurance premiums and an increase in well maintenance and well surveillance costs.

 

Equitable Gathering

 

		Three Months Ended March 31,
		2004			2003
OPERATIONAL DATA
Gathered volumes (MMcfe)		32,568			32,522
Average gathering fee ($/Mcfe) (a)		$	0.61		$	0.52
Gathering and compression expense ($/Mcfe)		$	0.20		$	0.18
Gathering and compression depreciation ($/Mcfe)		$	0.10		$	0.09
Depreciation, depletion and amortization (in thousands):
Gathering and compression depreciation		$	3,352		$	2,907
Other depreciation, depletion and amortization		295			245
Total depreciation, depletion and amortization		$	3,647		$	3,152
FINANCIAL DATA (Thousands)
Gathering revenues		$	19,815		$	17,018
Operating expenses:
Gathering and compression expense		6,587			5,752
Selling, general and administrative (SG&A)		2,379			2,308
Depreciation, depletion and amortization (DD&A)		3,647			3,152
Total operating expenses		12,613			11,212
Operating income		$	7,202		$	5,806

 

(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

 

25

 

blended gas commodity and gathering price, in which case the Company utilizes standard measures in order to split the price into its two components.

 

26

 

Three Months Ended March 31, 2004
vs. Three Months Ended March 31, 2003

 

Equitable Gathering’s revenues increased $2.8 million, or 16%, from $17.0 million in the first quarter of 2003 to $19.8 million in the first quarter of 2004.  The increase was primarily attributable to the $0.09 per Mcfe increase in the average gathering fee billed to equity and third party customers.

 

Total operating expenses increased $1.4 million to $12.6 million in the 2004 first quarter from $11.2 million in the same quarter last year.  The increase resulted from a $0.8 million increase in gathering and compression costs and a $0.5 million increase in depreciation relating to capital expenditures for gathering system improvements and extensions.  The $0.8 million increase in gathering and compression costs is primarily attributable to increased compressor electricity charges resulting from newly installed electric compressors, increased field line maintenance costs, and higher compressor station operation and repair costs.

 

NORESCO

 

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

 

		Three Months Ended March 31,
		2004			2003
OPERATIONAL DATA
Revenue backlog, end of period (thousands)		$	118,261		$	88,992
Gross profit margin		28.9		%	20.7		%
SG&A as a% of revenue		17.0		%	11.4		%
Capital expenditures (thousands)		$	28		$	48
FINANCIAL RESULTS (Thousands)
Energy service contract revenues		$	33,926		$	45,518
Energy service contract costs		24,105			36,082
Net operating revenue (gross profit margin)		9,821			9,436
Operating expenses:
Selling, general and administrative (SG&A)		5,784			5,166
Depreciation, depletion and amortization		251			349
Total operating expenses		6,035			5,515
Operating income		$	3,786		$	3,921
Equity in earnings of nonconsolidated investments		$	720		$	937
Minority interest		$	(370	)	$	—

 

Three Months Ended March 31, 2004
vs. Three Months Ended March 31, 2003

 

NORESCO’s operating income was $3.8 million in the first quarter of 2004 compared to $3.9 million in the same period in 2003, a decrease of $0.1 million.  The decrease was primarily due to an increase in SG&A expenses of $0.6 million partially offset by an increase in net operating revenues of $0.4 million.  This increase in SG&A expenses was due in part to an increase in project development expenses related to the increase in sales activities in the performance contracting group.

 

27

 

Revenue backlog increased by $29.3 million from $89.0 million on March 31, 2003 to $118.3 million on March 31, 2004.  This increase was primarily due to the award of federal government contracts in the fourth quarter of 2003.

 

Total revenue for the first quarter 2004 decreased by $11.6 million to $33.9 million from $45.5 million in the first quarter of 2003, primarily due to decreased construction activity of energy infrastructure projects versus the prior year.  NORESCO’s first quarter 2004 gross margin increased to $9.8 million compared to $9.4 million during the first quarter 2003.  This increase was due in part to the consolidation of Hunterdon Cogeneration, LP (Hunterdon) as of July 1, 2003.  Gross profit margin as a percentage of revenue increased from 20.7% in the first quarter 2003 to 28.9% in the first quarter 2004 due to an increase in the construction activity gross profit margin and the gross profit margin of Hunterdon.

 

Equity in earnings from power plant investments during the first quarter 2004 declined to $0.7 million from $0.9 million during the first quarter 2003.  This reduction was primarily due to the consolidation of Hunterdon offset by increased equity in earnings from the power plants in Panama and Costa Rica.  The consolidation of Hunterdon required NORESCO to recognize minority interest of $0.4 million in the first quarter 2004.  As discussed in Note L to the condensed consolidated financial statements, Plymouth Cogeneration Limited Partnership (Plymouth) was deconsolidated by the Company as of January 1, 2004, therefore, equity in earnings of Plymouth are recorded in the statements of consolidated income for the three months ended March 31, 2004 and 2003.

 

EQUITY IN NONCONSOLIDATED INVESTMENTS

 

In June 2003, the Company reevaluated its interest in Hunterdon Cogeneration LP (Hunterdon) and concluded that the Company effectively controlled Hunterdon for consolidation purposes.  As a result, the Company began consolidating Hunterdon’s financial condition, results of operations and cash flows as of June 30, 2003 in the NORESCO segment.

 

Certain NORESCO projects are held through equity in nonconsolidated entities that consist of private power generation, cogeneration and central plant facilities located in select international locations.  The Company is actively seeking divestment of its international projects in 2004.  The Company reviewed its equity investment related to Petroelectrica de Panama, an independent power plant in Panama, during the fourth quarter of 2003.  As a result of the analysis performed, an impairment of $11.1 million was recorded which represented the full value of NORESCO’s equity investment in the project.  The Company also performed an impairment analysis on its equity interest in another Panamanian electric generation project, IGC/ERI Pan-Am Thermal General Limited (IGC/ERI), as of December 31, 2003 concluding that no impairment was required.  Factors and considerations that the Company used to support this conclusion (as more fully described in the Company’s 2003 Form 10-K) have not changed in the first quarter 2004.

 

NON-GAAP DISCLOSURES

 

The SEC’s final rule regarding the use of non-Generally Accepted Accounting Principals (GAAP) financial measures by public companies was effective after March 2003.  The rule defined 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)        Excludes 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 in earnings of 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.  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.

 

28

 

The Company has reconciled the segments’ operating income, equity in earnings of nonconsolidated investments, excluding Westport, and minority interest to the Company’s consolidated operating income, equity in earnings of nonconsolidated investments, excluding Westport, and minority interest totals in Note B 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 information 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 in the first quarter 2004 totaled $145.6 million, a $67.6 million increase from the $78.0 million recorded in the prior year period.  The increase is primarily the result of the increase in cash provided from working capital in the first quarter 2004 due to a large decrease in inventory during the three months ended March 31, 2004 compared to a slight decrease in inventory during the three months ended March 31, 2003.  The decrease in inventory is the result of an increase in natural gas prices combined with an increase in volumes stored at the end of 2003 compared to the prior year period.  The increase in volumes stored was primarily attributable to additional storage capacity in 2003 and higher throughput volumes in the fourth quarter of 2002 that decreased the amount of inventory stored at the end of 2002.

 

When the prepaid forward gas sale transactions were consummated, the Company reviewed the specific facts and circumstances related to these transactions to determine if the appropriate Statement of Cash Flows presentation would be as an operating activity or a financing activity.  The Company concluded that the appropriate accounting presentation of the prepaid forward gas sales transactions 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.  One of the Company’s two prepaid forward gas sales contracts expired on December 31, 2003 resulting in the recognition of $8.6 million less monetized production revenue in 2004 compared to the prior year period.

 

Investing Activities

 

Cash flows used in investing activities in the first three months of 2004 were $35.4 million compared to $70.5 million in the prior year.  The change from the prior year is primarily attributable to a decrease in capital expenditures of $41.2 million primarily related to the purchase of the remaining limited partnership interest in ABP in 2003, offset by proceeds from the sale of wells in Ohio in 2003.

 

Financing Activities

 

Cash flows used in financing activities during the first three months of 2004 were $142.2 million compared to cash flows provided by financing activities of $120.8 million in the prior year period.  The decrease is primarily the result of the $200 million issuance of notes in February 2003, with a stated interest rate of 5.15% and a maturity date of March 2018.  The remaining cash outflows in 2004 were due to a reduction in short-term debt borrowings and an increase in dividends paid.  The cash outflows were partially offset by an increase in loans against construction contracts and decreased repayments of long-term debt.

 

The Company has adequate borrowing capacity to meet its financing requirements.  Bank loans and commercial paper, supported by available credit, are used to meet short-term financing requirements.  The Company maintains, with a group of banks, a three-year revolving credit agreement providing $500 million of available credit that expires in 2006.  The credit agreement may be used for, among other things, credit support for the Company’s commercial paper program.  As of March 31, 2004, the Company has the authority to arrange for a commercial paper program up to $650 million.

 

29

 

Risk Management

 

The Company’s overall objective in its hedging program is to protect earnings from undue exposure to the risk of changing commodity prices.  The Company hedges natural gas through financial instruments including forward contracts, swap agreements, which may require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for the commodity, options and other contractual agreements.

 

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 2004 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 average NYMEX is $0.01 per diluted share in 2004 and is approximately $0.02 per diluted share in 2005 and 2006.  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.

 

The approximate volumes and prices of the Company’s hedges and fixed price contracts for 2004 through 2006 are:

 

		2004**			2005			2006
Volume (Bcf)		35.7			51.0			51.9
Average Price per Mcf (NYMEX)*		$	4.62		$	4.69		$	4.54

 

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

** April through December

 

Commitments and Contingencies

 

The Company has annual commitments of approximately $26.6 million for demand charges under existing long-term contracts with various pipeline suppliers for periods extending up to 9 years, as of March 31, 2004, which relate to natural gas distribution and production operations.  However, approximately $20.5 million of these costs are recoverable in customer rates.

 

In the third quarter of 2003, the Company signed a long-term lease for office space with Continental Real Estate Companies, which will own and construct the building in which the office space will be located.  Plans call for the building to be complete early in 2005.  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.  The term of the lease is 20 years and nine months and the base rent is approximately $2 million per year.  Relocation of operations from locations that utilize space under long-term leases will likely cause additional expense in 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.

 

After an extended period of troubled operations, 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 No. 46.  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.  A mediation held in April 2004 did not resolve the litigation.

 

30

 

The various regulatory authorities that oversee Equitable’s operations will, from time to time, make inquiries or investigations into the activities of the Company.  As previously disclosed, the Company received informal requests for information from the CFTC regarding the reporting of prices to industry publications.  The Company cooperated fully with the CFTC as the Company always does when regulatory bodies make requests.  The CFTC has advised the Company that its inquiry has been closed.

 

In July 2002, the United States Environmental Protection Agency (EPA) published a final rule that amends the Oil Pollution Prevention Regulation.  The effective date of the rule was August 16, 2002.  Under the final rule, Owners/Operators of existing facilities were to revise their Spill Prevention, Control and Countermeasure (SPCC) plans on or before February 17, 2003 and were required to implement the amended plans as soon as possible but not later than August 18, 2003.  On April 17, 2003, the EPA extended the deadline to adopt a plan amendment to August 17, 2004 and the deadline to comply with the amended plan to February 18, 2005.  In March 2004, the EPA resolved various lawsuits related to the final rule and held a public meeting to clarify certain aspects of the final rule.  Based on this clarification, the Company has amended its plan of compliance resulting in a downward adjustment in the Company’s estimate of total costs of compliance to a range of $4.0 million to $6.0 million.  The Company expects approximately one-half to two-thirds of these costs to be capitalized, but it did not include these amounts in the 2004 capital budget.

 

In addition to the SPCC requirement, 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 to 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.

 

Investment in Westport Resources Corporation

 

The Company currently owns 11.53 million shares, or 17.0%, of Westport Resources Corporation (Westport).  The Company accounts for its investment as available-for-sale in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (Statement No. 115).  On April 7, 2004, Westport announced a merger with Kerr-McGee Corporation (Kerr-McGee).  While the merger agreement contains customary conditions, Westport and Kerr-McGee expect that the merger will close in the third quarter of 2004.  Under the terms of the merger agreement, the Company will receive 0.71 shares of Kerr-McGee for each Westport share it owns.  The Company, along with other large shareholders of Westport, entered into a voting agreement with Kerr-McGee to vote in favor of the merger.  As part of this agreement, the Company agreed to refrain from selling Westport shares through the expected closing date.  The Company will be subject to the limitations of SEC Rule 145 for any potential sales during the first year after the closing of the proposed merger, absent a registration of the Kerr-McGee shares received in the proposed merger.  Kerr-McGee has agreed to file a shelf registration statement for the sale of the shares of Kerr-McGee stock the Company receives in the merger.  Since the Company’s earnings conference call on April 15, 2004, the Company has done further analysis regarding the Company’s accounting treatment of the Westport/Kerr-McGee investment.  If and when the transaction closes, the Company will establish a new cost basis for the investment and recognize any gain in earnings.  The new cost basis may be discounted from quoted market price.  The merger will have a significant impact on liquidity of the Company’s investment as Kerr-McGee’s trading volume is approximately five times that of Westport.  The Company has previously announced its intent to divest it’s investment in Westport and is currently evaluating practical and reliable hedging and tax deferral strategies to maximize the value received from any future sale of these securities.  The proceeds from a Westport share monetization could be used in a variety of ways to increase shareholder value, including share repurchases, increased dividends, retirement of financial liabilities such as debt and prepaid forwards and the acquisition of other core assets.

 

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Benefit Plans

 

The Company made cash contributions totaling $51.8 million to its pension plan during the year ended December 31, 2003.  As a result of the $51.8 million contribution, the Company’s minimum funding requirement is zero and is expected to be zero through the 2006 plan year.

 

In the fourth quarter of 2003, the Company froze the pension benefit provided through a defined benefit plan to approximately 340 salaried employees.  The Company now provides benefits to these employees under a defined contribution plan that covers all other salaried employees of the Company.  The decrease in service cost related to the conversion of this benefit plan, coupled with the cash contributions made by the Company in 2003, will decrease the amount of pension expense, exclusive of any special termination benefits and curtailment losses, to be recognized by the Company in future years.  This decrease in pension expense will be partially offset by increased defined contribution plan expense.  The Company’s pension expense, exclusive of any special termination benefits and curtailment losses, totaled $0.6 million and $1.3 million for the three months ended March 31, 2004 and 2003, respectively.

 

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Stock-Based Compensation

 

The Company applies Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees,” and related interpretations in accounting for its stock-based compensation and has consequently not recognized any compensation cost for its stock option awards.  Had compensation cost been determined based upon the fair value at the grant date for the prior years’ stock option grants consistent with the methodology prescribed in Statement No. 123 net income and diluted earnings per share for the three months ended March 31, 2004 would have been reduced by an estimated $1.2 million or $0.02 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.

 

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 attributable to ABP.  This resulted in a reduction of the Company’s effective tax rate during 2002.  The nonconventional fuels tax credit expired at the end of 2002, and it is currently unclear whether legislation will be enacted to allow this tax benefit to exist in the future.  On November 18, 2003, the Energy Policy Act of 2003 (H.R. 6) was passed by the House of Representatives.  This comprehensive energy policy legislation, as reported by conferees from the House of Representatives and the Senate, included an extension of the nonconventional fuels tax credit for existing qualifying wells and for newly drilled qualifying wells.  The Senate was unable to pass H.R. 6 before adjourning for the year due to a lack of votes needed to avoid a threatened filibuster.  Energy tax legislation is expected to be addressed by the Senate and House of Representatives again during 2004, but any extension of the nonconventional fuels tax credit continues to remain 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.  Until this issue is resolved, the NORESCO segment’s ability to sign new contracts under the Department of Energy master agreements is affected.  While some agencies within the Department of Defense have advised NORESCO that they do not interpret the statutory lapse as prohibiting new awards under existing master agreements, other agencies have taken a contrary position.

 

Dividend

 

On April 14, 2004, the Board of Directors of the Company declared a regular quarterly cash dividend of 38 cents per share, payable June 1, 2004 to shareholders of record on May 7, 2004.  This is a 27% increase over the March 1, 2004 dividend and is the third increase in the last five quarters.  Going forward, 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 months ended March 31, 2004, the Company repurchased approximately 350,000 shares of Equitable Resources, Inc. stock, respectively.  The total number of shares repurchased since October 1998 is approximately 17.0 million.  On April 14, 2004, the Board of Directors of the Company increased the share repurchase authorization by 3 million shares to 21.8 million.

 

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, 2003 contained in the Company’s Annual Report on Form 10-K.  Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been discussed in the notes to the Company’s condensed consolidated financial statements for the period ended March 31, 2004.  The application of the Company’s critical accounting policies may require management to make judgments and estimates about the amounts reflected in the consolidated financial

 

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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.

 

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Equitable Resources, Inc. and Subsidiaries

 

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

 

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

 

For commodity price derivatives used to hedge forecasted Company production, Equitable sets policy limits relative to the expected production and sales levels, which are exposed to price risk. These financial instruments include forward contracts, swap agreements, which may require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for the commodity, options and other contractual agreements.  The level of price exposure is limited by the value at risk limits allowed by this policy.  Management monitors price and production levels on a continuous basis and will make adjustments to quantities hedged as warranted.  The goal of these actions is to earn a return above the cost of capital and to lower the cost of capital by reducing cash flow volatility.

 

For commodity price derivatives held for trading positions, the marketing group will engage in financial transactions also subject to policies that limit the net positions to specific value at risk limits.  These financial instruments include forward contracts, swap agreements, which may require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for the commodity, options and other contractual agreements.

 

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 235.7 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 have increased the fair value of natural gas instruments by approximately $130.0 million at March 31, 2004.  An increase of 10% in market price of natural gas would have decreased the fair market value by the same amount.

 

With respect to derivative contracts held by the Company for trading purposes, as of March 31, 2004, a decrease of 10% in the market price of natural gas would have increased the fair market value by approximately $0.2 million.  An increase of 10% in the market price would have decreased the fair market value by approximately $0.2 million.  The Company determined the change in the fair value of the natural gas instruments using 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 March 31, 2004.  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 Commodity Instruments in the notes to the condensed consolidated financial statements and the Risk Management 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.

 

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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.  During the first quarter of 2004, the Company’s Equitable Gas division implemented a new customer information and billing system.  There were no other significant changes in internal controls over financial reporting that occurred during the first quarter of 2004 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

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PART II.  OTHER INFORMATION

 

Item 2.  Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

 

The following table sets forth the Company’s repurchases of equity securities registered under Section 12 of the Exchange Act that have occurred in the three months ended March 31, 2004.

 

Period		Total number of shares (or units) purchased		Average price paid per share			Total number of shares (or units) purchased as part of publicly announced plans or programs		Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs (a), (b)
January 2004 (January 1 – January 31)		—		—			—		2,126,700
February 2004 (February 1 – February 29)		—		—			—		2,126,700
March 2004 (March 1 – March 31)		350,000		$	43.04		350,000		1,776,700
Total		350,000					350,000

 

(a)  On October 2, 1998, the Company’s Board of Directors authorized share repurchases, without an expiration date, of up to 11.2 million shares of common stock (publicly announced on October 7, 1998).  On October 27, 1999 the Company’s Board of Directors increased the repurchase amount by 2.2 million shares to 13.4 million shares (increase in authorization was publicly announced on November 12, 1999).  On July 19, 2000, the Company’s Board of Directors increased the repurchase amount by 5.4 million shares to 18.8 million shares (increase in authorization was publicly announced on July 20, 2000).

 

(b)  On April 14, 2004, the Company’s Board of Directors increased the share repurchase authorization by 3.0 million shares to 21.8 million shares (increase in authorization was publicly announced on April 15, 2004).

 

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Item 6.  Exhibits and Reports on Form 8-K

 

(a)          Exhibits:

 

10.1           Bylaws of the Company (amended through April 14, 2004 and approved January 14, 2004)

 

10.2           1999 Equitable Resources, Inc. Long-Term Incentive Plan (amended and restated February 25, 2004)

 

10.3           Termination Agreement, dated as of April 6, 2004, by and among Westport Resources Corporation, Westport Energy LLC, EQT Investments, LLC (a successor-in-interest to ERI Investments, Inc.), Medicor Foundation, and certain stockholders named therein

 

10.4           Voting Agreement, dated as of April 6, 2004, by and among Kerr-McGee Corporation and each stockholder named on schedule 1 thereto

 

10.5           Registration Rights Agreement, dated as of April 6, 2004, by and among Kerr-McGee Corporation, Westport Energy LLC, EQT Investments, LLC (a successor-in-interest to ERI Investments, Inc.), Medicor Foundation, and certain stockholders named therein

 

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 March 31, 2004:

 

 (i) Form 8-K dated January 30, 2004 disclosing the Company’s issuance of a press release announcing the results of its fourth quarter and full year 2003 earnings

 

(ii) Form 8-K dated March 24, 2004 disclosing the exercise of stock options by the Company’s Chief Executive Officer

 

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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:  May 6, 2004

 

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INDEX TO EXHIBITS

 

Exhibit No.		Document Description
10.1		Bylaws of the Company (amended through April 14, 2004 and approved January 14, 2004)		Filed Herewith
10.2		1999 Equitable Resources, Inc. Long-Term Incentive Plan (amended and restated February 25, 2004)		Filed Herewith
10.3		Termination Agreement, dated as of April 6, 2004, by and among Westport Resources Corporation, Westport Energy LLC, EQT Investments, LLC (a successor-in-interest to ERI Investments, Inc.), Medicor Foundation, and certain stockholders named therein		Filed as Exhibit 10.1 to amendment No. 5 of Schedule 13D dated April 13, 2004
10.4		Voting Agreement, dated as of April 6, 2004, by and among Kerr-McGee Corporation and each stockholder named on schedule 1 thereto		Filed as Exhibit 10.2 to amendment No. 5 of Schedule 13D dated April 13, 2004
10.5		Registration Rights Agreement, dated as of April 6, 2004, by and among Kerr-McGee Corporation, Westport Energy LLC, EQT Investments, LLC (a successor-in-interest to ERI Investments, Inc.), Medicor Foundation, and certain stockholders named therein		Filed as Exhibit 10.3 to amendment No. 5 of Schedule 13D dated April 13, 2004
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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