Unassociated Document

EX-99.1 2 v191777_ex99-1.htm Unassociated Document

625 Liberty Avenue

Suite 1700

Pittsburgh, PA 15222	Contact:	Patrick Kane
		(412) 553-7833
		pkane@eqt.com

EQT Reports Second Quarter 2010 Earnings

PITTSBURGH, July 29, 2010/ PRNewswire-FirstCall/ — EQT Corporation (NYSE: EQT) today announced second quarter 2010 earnings of $30.0 million, 13% higher than the $26.6 million earned in the second quarter 2009 (quarter-over-quarter). Operating cash flow was $112.6 million; 17% higher quarter-over-quarter. Earnings per diluted share were $0.20 for the second quarter 2010, unchanged from the $0.20 reported last year.

Highlights include:

Sales of produced natural gas have increased 31% quarter-over-quarter;

Operating cash flow increased 17% quarter-over-quarter;

The forecast for 2010 sales of produced natural gas increased to 129 – 131 Bcfe, representing approximately 30% growth over 2009; and

Updated cost estimates and well designs increase Marcellus after-tax IRRs to 63%, at $6 NYMEX.

EQT’s second quarter 2010 operating income was $78.5 million, representing a 16% increase quarter-over-quarter. The company’s net operating revenues, which exclude purchased gas cost, increased by $38.1 million to $241.5 million, as a result of higher sales volumes at EQT Production and higher gathered volumes and liquids prices at EQT Midstream. Net operating expenses increased by $27.1 million to $163.0 million, attributed to higher depreciation, depletion and amortization expense (DD&A) and selling, general and administrative expense (SG&A). EQT’s unit costs to produce, gather, process and transport EQT’s produced natural gas and natural gas liquids (NGLs), excluding a contract termination charge, were 8% lower quarter-over-quarter.

Quarterly Results by Business

EQT Production

EQT Production achieved sales of produced natural gas of 31.9 Bcfe, representing a 31% increase quarter-over-quarter, driven by horizontal drilling in the Marcellus and Huron / Berea plays. Approximately 45% of EQT’s sales of produced natural gas came from horizontal shale wells, up from 28% in the second quarter last year. Daily production from Marcellus wells averaged 55 MMcfd for the second quarter and is expected to exceed 140 MMcfd by year-end 2010.

Production operating income for the quarter totaled $23.8 million; 29% lower quarter-over-quarter. Operating revenues were $101.0 million, $11.1 million higher quarter-over-quarter, as a result of increased sales of produced natural gas, partially offset by lower average wellhead sales prices. The average wellhead sales price was $3.10 per Mcfe; 14% lower than the $3.59 realized a year ago, as a result of lower hedge gains for the quarter, partially offset by higher NYMEX prices for unhedged natural gas sales.

Operating expenses rose $20.9 million to $77.2 million in the second quarter 2010. Consistent with the company’s growth, DD&A was $16.0 million higher; SG&A was $7.0 million higher; and lease operating expense, excluding production taxes (LOE), was $1.2 million higher. Partially offsetting these increases was a decrease of $3.3 million in exploration expense. Per unit LOE was $0.26; 7% lower than last year, as a result of production growth outpacing cost increases. The increase in SG&A resulted primarily from a $4.5 million charge related to the termination of contractual capacity for the processing and disposal of recovered frac water. This processing and disposal capacity is no longer required as a result of the implementation development of innovative procedures to recycle approximately 90% of the recovered water and use it to frac new wells, a reflection of the company’s continuing commitment to safe and environmentally responsible operations. The new recycling procedures have resulted in lower well costs and LOE, reflected in the updated Marcellus well economics, which will more than offset the charge incurred for termination of contractual capacity.

The company drilled 164 gross wells during the second quarter 2010. Of these wells, 128 were horizontal wells; 87 targeting the Huron / Berea play with an average length of pay of 3,920 feet; and 41 targeting the Marcellus play with an average length of pay of 3,700 feet. The company also drilled 23 vertical wells in its coalbed methane play.

Marcellus Economics

EQT has begun to extend the lateral length of its Marcellus wells. The increase in well length reduces the estimated development costs to approximately $0.73 per Mcfe; a 10% improvement in productivity. Furthermore, the midstream cost estimates are declining, driven by pad drilling and lower midstream capital investment requirements per well. EQT’s expected after-tax internal rates of return (ATAX IRRs) have improved as a result of both increased productivity from longer lateral wells and lower transportation costs. After-tax internal rate of return are now estimated to be 63%, at $6 NYMEX.

Marcellus Well Statistics

	Q1 Design	Q3 Design
Feet of pay	3,000	3,800
Cost per well	$3.3 – $3.5 MM	$3.8– $4.2 MM
EUR per well	4 – 4.5 Bcfe	5 – 6 Bcfe
Unit development cost / Mcfe	~$0.80	~$0.73

Midstream cost / Mcfe	$1.98	$1.29
ATAX IRRs:
$4 NYMEX	10%	23%
$5 NYMEX	20%	40%
$6 NYMEX	32%	63%

EQT published a Marcellus decline curve on the company’s web site at http://ir.eqt.com.

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EQT Midstream

EQT Midstream earned $59.0 million of operating income, 80% higher quarter-over-quarter. Net operating revenues for the second quarter were $111.4 million, representing a 37% increase. Processing net revenues were $25.6 million, or $15.5 million higher, as a result of a 70% increase in the average NGL sales price and a 12% increase in liquids volume, nearly all of which was produced by EQT Production’s horizontal Huron / Berea drilling. Net gathering revenues increased by $10.3 million, or 25%, driven by a 20% increase in gathering volumes associated with EQT Production’s horizontal drilling program and a 6% increase in average gathering fees. Storage, marketing and other revenues rose by $4.2 million.

Operating expenses increased quarter-over-quarter to $52.4 million, compared to $48.4 million. The increase is primarily attributable to a $2.8 million increase in DD&A and $1.1 million increase in O&M costs. Per unit gathering and compression expense decreased 7% quarter-over-quarter, as volumes increased at a faster rate than growth-related operational costs.

DCP Joint Venture

On May 27, 2010, EQT announced a non-binding letter of intent with DCP Midstream, LLC and its affiliate to create a natural gas processing and related NGL infrastructure joint venture to serve EQT and third party producers in the Appalachian basin. Terms and conditions are being finalized and signing is expected to occur in the third quarter of 2010.

Distribution

Distribution’s operating income totaled $4.3 million; a 54% decrease quarter-over-quarter. Net operating revenues were $29.2 million, compared with $32.4 million, primarily as a result of weather being 41% warmer than normal and 25% warmer quarter-over-quarter, in addition to lower off-system and energy services revenues.

Operating expenses totaled $24.9 million, or $1.9 million higher quarter-over-quarter, mainly attributable to an increase in SG&A resulting from higher bad debt expense, as federal energy assistance funding for low-income customers decreased from 2009 levels.

Hedging

EQT increased its hedge position in the second quarter for periods October 2010 through September 2015. The new hedges, covering approximately 19 MMcfd of natural gas sales volumes, were collars with a floor of $5.32 per Mcf and a ceiling of $7.35 per Mcf. The company’s total hedge position for 2010 through 2012 production is:

		2010**	2011		2012
Swaps
Total Volume (Bcf)		11		19		–
Average Price per Mcf (NYMEX)*	$	5.12	$	5.10	$	–

Puts
Total Volume (Bcf)		2		3		–
Average Floor Price per Mcf (NYMEX)*	$	7.35	$	7.35	$	–

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		2010**	2011		2012
Collars
Total Volume (Bcf)		11		21		21
Average Floor Price per Mcf (NYMEX)*	$	6.95	$	6.53	$	6.51
Average Cap Price per Mcf (NYMEX)*	$	12.93	$	11.91	$	11.83

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

**July through December

Natural Gas Liquids

EQT Production‘s sales of produced natural gas consisted of approximately 11% NGLs in the second quarter. EQT Midstream bought the NGLs from EQT Production at natural gas market prices and sold the NGLs at higher NGL market prices, capturing a higher margin to EQT Corporation. EQT Corporation realized an average premium over the NYMEX natural gas price of $1.19 per Mcfe as a result of its liquids rich production; $0.48 per Mcfe is recognized as production revenue and $0.71 per Mcfe as processing net revenue at EQT Midstream.

Price Reconciliation

EQT Production's average wellhead sales price is calculated by allocating some revenues to EQT Midstream for the gathering, processing and transportation of the produced gas and NGLs. EQT Production’s average wellhead sales price for the three and six months ended June 30, 2010 and 2009 were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009

Average NYMEX price ($ / MMBtu)	$	4.09		$	3.50		$	4.70		$	4.19
Average Btu premium		0.41			0.34			0.44			0.38
Average NYMEX price ($ / Mcfe)		4.50			3.84			5.14			4.57
Average net liquids revenue		0.78			0.36			0.74			0.28
Average basis		0.14			0.05			0.18			0.11
Hedge impact		0.55			1.71			0.39			1.16
Average hedge adjusted price ($ / Mcfe)		5.97			5.96			6.45			6.12

Gathering, processing and transportation revenues to EQT Midstream ($ / Mcfe)		(1.68	)		(1.66	)		(1.72	)		(1.69	)
Average net liquids revenues to EQT Midstream ($ / Mcfe)		(0.71	)		(0.32	)		(0.68	)		(0.25	)
Third party gathering, processing and transportation ($ / Mcfe)		(0.48	)		(0.39	)		(0.41	)		(0.31	)
Total revenue deductions ($ / Mcfe)		(2.87	)		(2.37	)		(2.81	)		(2.25	)
Average wellhead sales price to EQT Production ($ / Mcfe)		3.10			3.59			3.64			3.87

EQT Revenue ($/ Mcfe)
Revenues to EQT Midstream		2.39			1.98			2.40			1.94
Revenues to EQT Production		3.10			3.59			3.64			3.87
Average wellhead sales price to EQT Corporation	$	5.49		$	5.57		$	6.04		$	5.81

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Unit Costs

EQT’s unit costs to produce, gather, process and transport EQT's produced natural gas and NGLs, excluding contract termination charge, were:

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009

Production segment costs: ($ / Mcfe)
LOE	$	0.26	$	0.28	$	0.25	$	0.26
Production taxes		0.22		0.29		0.24		0.32
SG&A, excluding contract termination charge		0.38		0.39		0.39		0.37
		0.86		0.96		0.88		0.95
Midstream segment costs: ($ / Mcfe)
Gathering, processing and transmission		0.54		0.58		0.53		0.55
SG&A		0.18		0.18		0.18		0.18
		0.72		0.76		0.71		0.73
Total	$	1.58	$	1.72	$	1.59	$	1.68

Operating Income

The company reports operating income by segment in this press release. Both interest and income taxes are controlled on a consolidated, corporate-wide basis, and are not allocated to the segments.

The following table reconciles operating income by segment as reported in this press release to the consolidated operating income reported in the company’s financial statements:

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Operating income (thousands):
EQT Production	$	23,777		$	33,648		$	82,270		$	78,065
EQT Midstream		58,966			32,802			126,281			81,782
Distribution		4,290			9,353			51,709			53,205
Unallocated expenses		(8,504	)		(8,289	)		(12,618	)		(9,402	)
Operating income	$	78,529		$	67,514		$	247,642		$	203,650

Unallocated expenses are primarily due to certain incentive compensation and administrative costs in excess of budget that are not allocated to the operating segments. For each period presented, the difference between equity in earnings of nonconsolidated investments as reported on the company's statements of consolidated income and on EQT Midstream’s operational and financial report is the earnings from the company's ownership interest in Appalachian Natural Gas Trust. Other segment financial measures identified in this press release are reconciled to the most comparable financial measures calculated in accordance with generally accepted accounting principles (GAAP) below and on the attached operational and financial reports.

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Non-GAAP Reconciliations

Operating Cash Flows

Operating cash flow is presented as an accepted indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt. The company has also included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements that the company may not control and may not relate to the period in which the operating activities occurred. Operating cash flow should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with GAAP. The table below reconciles operating cash flow with net cash provided by operating activities as derived from the statements of condensed consolidated cash flows to be included in the company's Form 10-Q for the six months ended June 30, 2010 and 2009.

	Three Months Ended June 30,					Six Months Ended June 30,
(thousands)	2010		2009			2010		2009
Net Income:	$	30,000	$	26,645		$	118,065	$	98,638
Add back (deduct):
Deferred income taxes		16,281		26,461			66,431		82,878
Depreciation, depletion, and amortization		65,217		46,188			127,096		90,777
Other items, net		1,112		(2,837	)		5,795		(1,474	)
Operating cash flow:	$	112,610	$	96,457		$	317,387	$	270,819
Add back (deduct):
Changes in operating assets and liabilities		88,556		159,215			159,192		197,626
Net cash provided by operating activities	$	201,166	$	255,672		$	476,579	$	468,445

Net Operating Revenues and Net Operating Expenses

Net operating revenues and net operating expenses, both of which exclude purchased gas costs, are presented because they are important analytical measures used by management to evaluate period-to-period comparisons of revenue and operating expenses. Purchased gas cost, which is subject to commodity price volatility and a significant portion of which is passed on to customers with no income impact, is typically excluded by management in such analyses.

	Three Months Ended June 30,				Six Months Ended June 30,
(thousands)	2010		2009		2010		2009
Net operating revenues		241,546		203,449		564,224		463,845
Plus: purchased gas cost		15,969		34,591		129,931		243,598
Operating revenues		257,515		238,040		694,155		707,443

Net operating expenses,		163,017		135,935		316,582		260,195
Plus: purchased gas cost		15,969		34,591		129,931		243,598
Operating expenses		178,986		170,526		446,513		503,793

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Production Segment SG&A, excluding contract termination charge

Production Segment SG&A, excluding contract termination charge, is presented because it is an analytical measure used by management to evaluate period-to-period comparisons of costs associated with EQT's produced natural gas and NGLs. Production Segment SG&A, excluding contract termination charge, should not be considered in isolation or as a substitute for Production Segment SG&A. The table below reconciles Production Segment SG&A, excluding contract termination charge, to Production Segment SG&A as derived from the EQT Production Operational and Financial Report included in this release on both a total and a per unit basis.

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2010		2010
Production segment costs:
SG&A, excluding contract termination charge ($ / Mcfe)	$	0.38	$	0.39
Produced Volumes (Mcfe)		32,789		64,186
SG&A, excluding contract termination charge (thousands)		12,421		24,801
Plus: contract termination charge (thousands)		4,500		4,500
SG&A (thousands)		16,921		29,301
SG&A ($/Mcfe)		0.52		0.46

EQT's conference call with securities analysts, which begins at 10:30 a.m. Eastern Time today, will be broadcast live via EQT's web site, http://www.eqt.com and on the Investor information page from the company’s web site which is available at http://ir.eqt.com, and will be available for seven days.

From time to time, EQT management speaks to investors. Slides for these discussions will be available online via EQT's web site. The slides may be updated periodically.

Cautionary Statements

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that a company anticipates as of a given date to be economically and legally producible and deliverable by application of development projects to known accumulations. We use certain terms in this press release, such as “EUR” (estimated ultimate recovery), that the SEC’s guidelines prohibit us from including in filings with the SEC. This measure is by its nature more speculative than estimates of reserves prepared in accordance with SEC definitions and guidelines and accordingly is less certain.

Total sales volumes per day (or daily production) is an operational estimate of the daily sales volume on a typical day (excluding curtailments).

Unit development costs (or unit costs) are calculated as the direct costs to drill a well (or costs per well) divided by the gross expected EUR of the well. Direct well costs do not include capitalized overhead.

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Midstream costs used under the caption “Marcellus Well Statistics” include costs related to the gathering, transmission, compression, processing, shrinkage of natural gas and return on capital incurred to deliver gas from the wellhead to the sales meter.

The company is unable to provide a reconciliation of its projected operating cash flow to projected net cash provided by operating activities, the most comparable financial measure calculated in accordance with generally accepted accounting principles, because of uncertainties associated with projecting future net income and changes in assets and liabilities.

Disclosures in this press release contain certain forward-looking statements. Statements that do not relate strictly to historical or current facts are forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include the expectations of plans, strategies, objectives, and growth and anticipated financial and operational performance of the company and its subsidiaries, including guidance regarding the company’s drilling and infrastructure programs (including the Equitrans expansion project) and technology, the timing of the signing and the terms of the natural gas processing and natural gas liquids infrastructure joint venture, the timing of construction of public-access natural gas refueling stations, production and sales volumes, revenue projections, reserves, EUR, internal rates of return (IRR), the expected ATAX returns per well, midstream costs, F&D costs, unit costs, direct well costs, the expected decline curve, the expected feet of pay, capital expenditures, financing requirements, projected operating cash flows, hedging strategy and tax position. These statements involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The company has based these forward-looking statements on current expectations and assumptions about future events. While the company considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the company’s control. 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, those set forth under Item 1A, “Risk Factors” of the company’s Form 10-K for the year ended December 31, 2009, as updated by any subsequent Form 10-Qs.

Any forward-looking statement applies only as of the date on which such statement is made and the company does not intend to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.

EQT is an integrated energy company with emphasis on Appalachian area natural gas production, gathering, processing, transmission and distribution. Additional information about the company can be obtained through the company’s web site, http://www.eqt.com. Investor information is available on EQT’s web site at http://ir.eqt.com. EQT uses its web site as a channel of distribution of important information about the company, and routinely posts financial and other important information regarding the company and its financial condition and operations on the Investors web pages.

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EQT CORPORATION AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED INCOME (UNAUDITED)

(Thousands except per share amounts)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009

Operating revenues	$	257,515	$	238,040	$	694,155	$	707,443

Operating expenses:
Purchased gas costs		15,969		34,591		129,931		243,598
Operation and maintenance		35,567		34,892		69,906		66,482
Production		16,739		14,860		33,539		29,880
Exploration		1,078		4,414		2,413		7,725
Selling, general and administrative		44,416		35,581		83,628		65,331
Depreciation, depletion and amortization		65,217		46,188		127,096		90,777
Total operating expenses		178,986		170,526		446,513		503,793

Operating income		78,529		67,514		247,642		203,650

Other income		153		698		680		1,288
Equity in earnings of nonconsolidated investments		2,420		1,610		4,947		2,732
Interest expense		34,080		26,460		68,214		45,703
Income before income taxes		47,022		43,362		185,055		161,967
Income taxes		17,022		16,717		66,990		63,329
Net income	$	30,000	$	26,645	$	118,065	$	98,638

Earnings per share of common stock:
Basic:
Weighted average common shares outstanding		147,575		130,830		140,440		130,784
Net income	$	0.20	$	0.20	$	0.84	$	0.75

Diluted:
Weighted average common shares outstanding		148,289		131,443		141,270		131,421
Net income	$	0.20	$	0.20	$	0.84	$	0.75

(A)	Due to the seasonal nature of the Company's natural gas distribution and storage businesses, and the volatility of commodity prices, the interim statements for the three and six month periods are not indicative of results for a full year.

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EQT PRODUCTION

OPERATIONAL AND FINANCIAL REPORT

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009

OPERATIONAL DATA

Natural gas and oil production (MMcfe)		32,789			25,505			64,186			49,983
Company usage, line loss (MMcfe)		(874	)		(1,139	)		(2,271	)		(2,641	)
Total sales volumes (MMcfe)		31,915			24,366			61,915			47,342

Average (well-head) sales price ($/Mcfe) (a)	$	3.10		$	3.59		$	3.64		$	3.87

Sales of Produced Natural Gas detail (MMcfe)
Horizontal Huron / Berea Play		9,345			6,289			18,122			11,772
Horizontal Marcellus Play		4,997			454			8,762			752
CBM Play		3,310			3,034			6,494			6,016
Other (vertical non-CBM)		14,263			14,589			28,537			28,802
Total sales of produced natural gas		31,915			24,366			61,915			47,342

Lease operating expenses, excluding production taxes ($/Mcfe)	$	0.26		$	0.28		$	0.25		$	0.26
Production taxes ($/Mcfe)	$	0.22		$	0.29		$	0.24		$	0.32
Production depletion ($/Mcfe)	$	1.27		$	1.03		$	1.25		$	1.03

Production depletion (thousands)	$	41,527		$	26,226		$	80,504		$	51,431
Other depreciation, depletion and amortization (thousands)		1,941			1,209			3,874			2,437
Total depreciation, depletion and amortization (thousands)	$	43,468		$	27,435		$	84,378		$	53,868

Capital expenditures (thousands) (b)	$	483,656		$	164,880		$	662,071		$	302,316

FINANCIAL DATA (Thousands)

Total operating revenues	$	100,955		$	89,885		$	229,945		$	187,648

Operating expenses:
Lease operating expense (LOE), excluding production taxes		8,397			7,170			16,200			13,212
Production taxes		7,314			7,326			15,383			16,150
Exploration expense		1,078			4,414			2,413			7,725
Selling, general and administrative (SG&A)		16,921			9,892			29,301			18,628
Depreciation, depletion and amortization		43,468			27,435			84,378			53,868
Total operating expenses		77,178			56,237			147,675			109,583

Operating income	$	23,777		$	33,648		$	82,270		$	78,065

(a)

Average wellhead sales price is calculated as market price adjusted for hedging activities less deductions for gathering, processing, transmission and NGL revenues included in EQT Midstream revenues. These deductions totaled $2.39 and $1.98/Mcfe for the three months ended June 30, 2010 and 2009, respectively; and $2.40 and $1.94/Mcfe for the six months ended June 30, 2010 and 2009, respectively.

(b)

Capital expenditures for the three and six month periods ended June 30, 2010 and 2009 include $278.8 million and $2.1 million, respectively, for undeveloped property acquisitions, primarily within the Marcellus play. The 2010 amount includes $230.7 million of undeveloped property, which was acquired with EQT stock in the second quarter 2010.

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EQT MIDSTREAM

OPERATIONAL AND FINANCIAL REPORT

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009

OPERATIONAL DATA

Gathered volumes (BBtu)		47,461		39,590		92,084		78,069
Average gathering fee ($/MMBtu)	$	1.10	$	1.04	$	1.10	$	1.04
Gathering and compression expense ($/MMBtu)	$	0.39	$	0.42	$	0.38	$	0.41
NGLs Sold (Mgal) (a)		36,515		32,514		69,729		59,888
Average NGL sales price ($/gal)	$	1.07	$	0.63	$	1.11	$	0.65
Transmission pipeline throughput (BBtu)		24,065		22,313		49,058		39,531

Net operating revenues (thousands):
Gathering	$	51,029	$	40,775	$	99,763	$	79,454
Processing		25,607		10,127		48,341		16,747
Transmission		18,007		17,735		39,560		37,545
Storage, marketing and other		16,726		12,574		40,553		40,021
Total net operating revenues	$	111,369	$	81,211	$	228,217	$	173,767

Capital expenditures (thousands)	$	44,293	$	53,344	$	78,980	$	115,517

FINANCIAL DATA (Thousands)

Total operating revenues	$	168,074	$	119,500	$	353,539	$	242,874
Purchased gas costs		56,705		38,289		125,322		69,107
Total net operating revenues		111,369		81,211		228,217		173,767

Operating expenses:
Operating and maintenance		25,577		24,440		49,554		45,641
Selling, general and administrative (SG&A)		11,215		11,182		21,847		21,319
Depreciation and amortization		15,611		12,787		30,535		25,025
Total operating expenses		52,403		48,409		101,936		91,985

Operating income	$	58,966	$	32,802	$	126,281	$	81,782

Other income	$	64	$	355	$	259	$	905
Equity in earnings of nonconsolidated investments	$	2,401	$	1,595	$	4,865	$	2,662

(a)

NGLs sold includes NGLs recovered at the Company’s processing plant and transported to a fractionation plant owned by a third-party for separation into commercial components, net of volumes retained, as well as equivalent volumes sold at liquid component prices under the Company’s contractual processing arrangements with third parties.

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DISTRIBUTION

OPERATIONAL AND FINANCIAL REPORT

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009

OPERATIONAL DATA

Heating degree days (30 year average: Qtr. 705; YTD 3,635)		417		553		3,277		3,440

Residential sales and transportation volume (MMcf)		2,238		2,672		14,103		14,633
Commercial and industrial volume (MMcf)		5,394		6,445		16,830		16,635
Total throughput (MMcf) - Distribution		7,632		9,117		30,933		31,268

Net operating revenues (thousands):
Residential	$	17,333	$	18,816	$	66,963	$	62,995
Commercial & industrial		7,665		8,207		27,488		27,817
Off-system and energy services		4,222		5,330		11,610		11,933
Total net operating revenues	$	29,220	$	32,353	$	106,061	$	102,745

Capital expenditures (thousands)	$	7,750	$	8,717	$	11,725	$	15,493

FINANCIAL DATA (Thousands)

Total operating revenues	$	63,349	$	78,094	$	285,604	$	371,266
Purchased gas costs		34,129		45,741		179,543		268,521
Net operating revenues		29,220		32,353		106,061		102,745

Operating expenses:
Operating and maintenance		10,980		10,651		21,580		20,430
Selling, general and administrative		7,934		6,863		20,762		18,186
Depreciation and amortization		6,016		5,486		12,010		10,924
Total operating expenses		24,930		23,000		54,352		49,540

Operating income	$	4,290	$	9,353	$	51,709	$	53,205

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