News Release Details

EQT Corporation (NYSE: EQT) today announced year-end earnings of $156.9 million, or $1.19 per diluted share (EPS) and operating cash flow of $584.3 million. This compares with earnings of $255.6 million, or $2.00 EPS and operating cash flow of $651.6 million in 2008. After adjusting for the company's long-term incentive compensation expense and several other items, EQT has adjusted EPS of $1.54 in 2009, relative to $1.90 in 2008.

For the fourth quarter 2009, earnings were $55.4 million, or EPS of $0.42, and operating cash flow of $251.3 million. This compares with earnings of $33.5 million, or EPS of $0.26, and operating cash flow of $135.7 million in the fourth quarter 2008. Having adjusted for the long-term incentive compensation expenses as well as other items, EQT has adjusted EPS of $0.52 in the fourth quarter 2009, compared to $0.34 in 2008.

Highlights for 2009 include:

• Record annual sales of produced natural gas of 100.1 Bcfe, 19.5% higher than in 2008;
• Proved reserves increased by 31% to 4.1 Tcfe;
• Drilled 800th horizontal Huron/Berea well, 33% of fourth quarter sales were produced from horizontal Huron/Berea wells;
• Drilled 46 horizontal Marcellus wells, including what EQT believes to be the most prolific well in the entire play based on a 30-day average production rate of 14 MMcfe per day;
• Unit development costs for EQT's major plays are projected to be reduced to less than $0.85 per Mcfe in the Marcellus play and less than $0.90 per Mcfe in the Huron/Berea play;
• Unit lease operating expense, excluding production taxes (LOE), decreased 14% in 2009, to $0.30 per Mcfe. Including production taxes, LOE was $0.59 per Mcfe, an industry leading result;
• Record EQT Midstream throughput and operating income; and
• Record Distribution operating income of $78.9 million, 32% higher than 2008.

In 2009, EQT's operating income was $356.8 million, representing a 23% decrease from 2008. While the company saw higher revenues from increased production, gathering and processing volumes, those gains were more than offset by lower commodity prices and higher long-term incentive compensation expense. Lower commodity prices reduced operating income by $141.1 million in 2009 compared with 2008.

In the fourth quarter of 2009, EQT's operating income reached $113.2 million, representing a 39% increase from the same quarter in 2008. Lower commodity prices and higher long-term incentive compensation expense were more than offset by the higher revenues EQT earned from greater production, gathering and processing volumes, higher natural gas liquids (NGL) prices and increased utility rates. In total, net operating revenues rose 20% to $281.8 million in the quarter.

Results by Business

EQT Production

Driven by aggressive horizontal air drilling in the Huron/Berea play, EQT Production achieved sales of produced natural gas of 100.1 Bcfe for 2009, representing a 19.5% increase after adjusting for the extra day in 2008. Sales of produced natural gas totaled 27.6 Bcfe in the fourth quarter 2009, 19.5% higher than the fourth quarter 2008.

Production operating income totaled $151.1 million in 2009; $101.7 million lower than 2008. Operating revenue was $384.6 million, $72.6 million lower than in 2008. Increased revenue and operating income from increased sales of produced natural gas was more than offset by lower wellhead natural gas prices. Due to lower NYMEX prices, average wellhead natural gas sales price to EQT Corporation in 2009 was $5.44 per Mcfe, representing a 20% decrease from 2008. The average wellhead natural gas sales price to EQT Production was $3.75 per Mcfe with $1.69 per Mcfe reported at EQT Midstream.

The company drilled 702 gross wells during 2009. Of these wells, 403 were horizontal wells, 347 targeting the Huron/Berea play and 46 targeting the Marcellus play. The company also drilled 217 vertical wells in the coalbed methane play, mostly in the Nora Field. The company was successful on more than 99% of the wells drilled in 2009, despite 79% being drilled on locations described as probable and possible. As detailed in a separate release today, proved reserves increased by 31% to 4.1 Tcfe.

Consistent with the company's growth, operating expenses rose to $233.5 million, marking a 14% increase over 2008. Depreciation, depletion and amortization (DD&A) expenses were $39.2 million higher in 2009 than in 2008 due to increases in the depletion rate and produced volumes. Exploration expense was $17.9 million in 2009, $8.8 million higher than in 2008. Several items contributed to partially offsetting the cost increases: a $17.0 million decrease in commodity-based production taxes; a $1.4 million decrease in selling, general and administrative (SG&A) expense resulting from an $8.6 million reversal of certain legal reserves in the fourth quarter, offsetting otherwise higher SG&A expenses; and a $0.5 million reduction in LOE. LOE was 2% lower year-over-year and 14% lower on a unit basis at $0.30. The combination of lower LOE plus lower production taxes yielded a unit rate of $0.59 per Mcfe; an industry leading result.

Operating income for the fourth quarter of 2009 was $41.5 million, representing a 19% decrease from $51.0 million earned in the same period last year. Production operating revenues were essentially unchanged in the fourth quarter 2009 compared with the fourth quarter 2008, as lower commodity prices offset the 19.5% volume increase in sales of produced natural gas.

Operating expenses for the quarter were $63.5 million. This was 17% higher than reported for the fourth quarter of 2008. DD&A was $12.2 million higher, due mainly to increases in the depletion rate and produced volumes. Exploration expense was $5.7 million in the quarter; $1.5 million dollars higher than last year. Commodity-based production taxes were $7.0 million, $2.4 million lower than last year and SG&A expense was $7.7 million, $0.9 million lower, partially offsetting the increases.

Huron/Berea Play

Huron/Berea horizontal air drilling continued to drive growth in sales of produced natural gas. In the fourth quarter, approximately 33% of EQT's sales of produced natural gas came from horizontal Huron/Berea wells, a 99% increase over the fourth quarter of 2008. The company drilled 110 horizontal Huron/Berea wells in the fourth quarter, bringing the total to more than 800 horizontal wells since the play's inception.

In the fourth quarter, EQT drilled four multi-lateral wells with a total lateral length per well ranging between 13,000 and 24,000 feet. EQT also drilled nine extended lateral wells, the longest reaching 6,700 feet in length and having twice the amount of pay as a typical horizontal Huron/Berea well, at a cost of $1.4 million or 40% more than a typical horizontal Huron/Berea well. Early results are consistent with EQT's expectations, and the company will to continue to experiment with both multi-lateral and extended lateral wells. This technology is expected to lower unit development costs to less than $0.90 per Mcfe. EQT expects extended lateral wells to become the preferred standard operating procedure by the end of 2010, which should further increase estimated ultimate recoveries (EURs) per well and decrease unit development costs going forward.

Marcellus Play

EQT drilled 19 and turned-in-line (TIL) six horizontal Marcellus wells in the fourth quarter of 2009. One well in Greene County, Pennsylvania produced at an average rate of 14 MMcfe per day for the first 30 days of production. Two adjacent wells, shut-in due to temporary takeaway constraints, had similar initial flow test results. Within a 2-mile radius of these wells, EQT has three multi-well pads, totaling 12 wells, which two are currently being drilled. The 9 MMcfe per day 30-day initial production well, announced in the third quarter, is located eight miles away and there are currently seven offsets that are cleared to drill.

EQT has now drilled 53 horizontal wells in the Marcellus play since 2008, of which 17 wells have been on-line for more than 30 days. Total sales of produced natural gas from the Marcellus play at year-end were 37 MMcfe per day. EQT expects this rate to more than double by the end of 2010. Takeaway capacity in the Marcellus is currently 50 MMcfe per day and is anticipated to be 100 MMcfe per day by the end of 2010.

EQT estimates the average EUR across its approximately 445,000 Marcellus acres to be between 3.5 and 4 Bcfe per well, at a cost per well of $3.0 million. Unit development costs for this play are projected to average less than $0.85 per Mcfe. In Greene County, Pennsylvania, the average EUR per well is 4.5 Bcfe. In Doddridge County, West Virginia, the average EUR per well is 3.6 Bcfe.

Coalbed Methane (CBM) Play

In the fourth quarter 2009, EQT drilled 39 vertical CBM wells. Total sales of produced natural gas of CBM at year-end reached 34 MMcfe per day. The average EUR of the company's CBM wells is 0.3 Bcfe, at a cost per well of $0.4 million.

EQT Midstream

EQT Midstream earned $189.0 million of operating income during 2009, compared to $134.8 million in 2008, primarily due to revenues generated by new infrastructure projects exceeding the increased costs required to operate these assets. Net operating revenues for 2009 totaled $386.2 million representing a 27% increase over 2008. Net gathering revenues increased $25.4 million in 2009, up 18% from 2008, as a result of an 11% increase in gathering volumes as well as higher gathering rates. Net processing revenues totaled $57.7 million for 2009, representing an increase of 62% from 2008. Natural gas liquids (NGL) sold increased by 55%, while the average NGL sales price decreased by 35%. Net transmission revenues increased by $25.2 million, or 49%, in 2009. This increase was driven by greater firm transportation revenues from EQT's Big Sandy pipeline. Net storage, marketing and other revenues totaled $86.3 million in 2009, up 13% from 2008, due to higher marketing revenues generated from Big Sandy capacity and higher industrial demand, which more than offset lower storage activity.

Operating expenses for 2009 totaled $197.2 million, up from the $168.6 million reported in 2008. The increase was mainly attributable to a $12.2 million increase in operating and maintenance costs (O&M) and an $18.5 million increase in DD&A. The increases in O&M and DD&A were primarily due to the growth in the EQT Midstream business, including increased electric costs, property taxes and labor to operate the expanded gathering, processing and transmission infrastructure. However, the increases were partially offset by the absence of a 2008 charge for settlement of pension and other post-retirement benefits.

EQT Midstream had fourth quarter 2009 operating income of $69.3 million, a 238% increase over the same period of 2008. Net processing revenues during the fourth quarter 2009 totaled $25.9 million, a 651% increase over fourth quarter 2008, due to a significant increase in NGL prices. Net gathering revenues increased 18% to $43.3 million in the fourth quarter 2009. Net transmission revenues totaled $21.2 million, a 27% increase over the same quarter of 2008. Net storage, marketing and other revenues totaled $34.5 million, 61% higher than the fourth quarter 2008, primarily due to the timing of contract settlements.

Operating expenses for the quarter were $55.6 million, 3% lower than in the fourth quarter of 2008, as increases in growth-related operating expenses, including higher DD&A, electricity, labor, compressor maintenance and property tax expenses were more than offset by the absence of a $10.7 million charge for pension and other post-retirement benefits in the fourth quarter 2008.

Distribution

Distribution's operating income totaled $78.9 million in 2009, 32% higher than the $59.9 million reported in 2008. This increase resulted mainly from higher rates approved by the Pennsylvania Public Utility Commission in February 2009 and lower SG&A expenses. Net operating revenues for the year were $180.0 million, compared to $170.9 million in 2008, a $9.1 million increase primarily attributable to higher base rates. Operating expenses for the year decreased to $101.1 million in 2009 from $111.0 million in 2008. Less bad debt, a smaller rent expense and less SG&A expense contributed to the decrease.

Distribution's fourth quarter 2009 operating income totaled $22.5 million compared to $21.7 million for the same period in 2008. Total net operating revenues for the fourth quarter 2009 were essentially unchanged relative to the same period in 2008. Higher 2009 rates were offset by lower off-system and energy services net revenues, warmer weather and the absence of a 2008 non-recurring increase in customer assistance program activities. Operating expenses during the fourth quarter 2009 decreased from $30.6 million to $29.4 million, as lower bad debt expense more than offset an increase in maintenance activity.

Other Business

2009 Capital Expenditures

EQT invested $964 billion in capital projects during 2009. This included $717 million for well development, $201 million for midstream projects and $46 million for distribution infrastructure projects and other corporate items.

2010 Capital Budget

EQT's capital expenditure plan is $850 million in 2010, which includes $565 million for well development, $245 million for midstream projects, including the first phase of the Equitrans expansion project, and $40 million for distribution infrastructure projects and other corporate items.

Long-term Incentive Compensation Programs

The company has executive long-term incentive compensation programs designed to align management's long-term incentive compensation with the absolute and relative returns earned by the company's shareholders. The expense of these programs has been driven primarily by changes in EQT's stock price and EQT's performance relative to a previously disclosed peer group. The increase in stock price during 2009 resulted in a total pre-tax long-term incentive compensation expense of $61.8 million, which reduced after tax net income by approximately $48.2 million. In 2008, the decline in stock price resulted in a reversal of previously recorded long-term incentive compensation expense of $33.1 million before taxes, resulting in a year-over-year increase of $94.9 million before taxes. In the fourth quarter 2009, long-term incentive compensation totaled $20.9 million, $16.3 million higher than 2008.

Office Relocation

In 2009, to accommodate EQT's continuing growth, the company completed its relocation from Pittsburgh's North Shore to an office building located in downtown Pittsburgh. The company recognized an accounting charge of $5.2 million related to the move in 2009, with $1.1 million recorded in the fourth quarter.

Hedging

The company's sales of produced natural gas and oil are approximately 36% hedged for 2010. There were no changes to the company's production hedge position in the quarter. The company's total hedge positions for 2010 through 2012 production are:

		2010		2011		2012
Swaps
Total Volume (Bcfe)		23		19		-
Average Price per Mcf (NYMEX)*		$5.12		$5.10		$-
Puts
Total Volume (Bcfe)		3		3		-
Average Floor Price per Mcf (NYMEX)*		$7.35		$7.35		$-
Collars
Total Volume (Bcfe)		17		14		14
Average Floor Price per Mcf (NYMEX)*		$7.28		$7.11		$7.11
Average Cap Price per Mcf (NYMEX)*		$14.05		$14.12		$14.07

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

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						Year Ended
		December 31,						December 31,
		2009			2008			2009			2008
Operating income
(thousands):
EQT Production		$41,494			$50,979			$151,081			$252,784
EQT Midstream		69,324			20,518			188,984			134,772
Distribution		22,483			21,652			78,918			59,859
Unallocated
(expenses)/income		(20,092	)		(11,625	)		(62,192	)		17,391
Operating income		$113,209			$81,524			$356,791			$464,806

Unallocated (expenses) / income are primarily the result of long-term incentive compensation and administrative costs. 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.

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. EQT Production's average wellhead sales price for the three and twelve months ended December 31, 2009 and 2008 were as follows:

		Three Months Ended						Year Ended
		December 31,						December 31,
		2009			2008			2009			2008
Average NYMEX price
($/MMBtu)		$4.17			$6.94			$3.99			$9.03
Average Btu premium		0.40			0.69			0.38			0.94
Average NYMEX price
($/Mcfe)		$4.57			$7.63			$4.37			$9.97
Average basis		0.12			0.08			0.11			0.19
Hedge impact		1.15			(1.36	)		1.32			(2.91	)
Average hedge adjusted
price ($/Mcfe)		$5.84			$6.35			$5.80			$7.25
Revenues to EQT Midstream
($/Mcfe)		$(1.69	)		$(1.60	)		$(1.69	)		$(1.50	)
Third-party gathering,
processing and
transportation		(0.43	)		(0.31	)		(0.36	)		(0.43	)
Total revenue deductions		$(2.12	)		$(1.91	)		$(2.05	)		$(1.93	)
Average wellhead sales
price to EQT Production
($/Mcfe)		$3.72			$4.44			$3.75			$5.32
EQT Revenue ($/Mcfe)
Revenues to EQT Midstream		$1.69			$1.60			$1.69			$1.50
Revenues to EQT Production		3.72			4.44			3.75			5.32
Average wellhead sales
price to EQT Corporation		$5.41			$6.04			$5.44			$6.82

Unit Costs

EQT's unit costs to produce, gather, process and transport EQT's produced natural gas were:

		Three Months Ended				Year Ended
		December 31,				December 31,
		2009		2008		2009		2008
Production segment costs:
($/Mcfe)
LOE		$0.33		$0.42		$0.30		$0.35
Production taxes		0.25		0.38		0.29		0.52
SG&A		0.27		0.35		0.35		0.42
		$0.85		$1.15		$0.94		$1.29
Midstream segment costs:
($/Mcfe)
Gathering, processing
and transmission (a)		$0.44		$0.39		$0.44		$0.38
SG&A		0.17		0.16		0.15		0.14
		0.61		0.55		0.59		0.52
Total ($/Mcfe)		$1.46		$1.70		$1.53		$1.81

(a) Fourth quarter and full-year 2008 exclude a $9.5 million charge for pension and other post-retirement benefits.

Non-GAAP Disclosures

Adjusted EPS, operating cash flow, net operating revenues and net operating expenses should not be considered in isolation or as substitutes for net income, EPS, net cash provided by operating activities, operating revenues or operating expenses prepared in accordance with GAAP. The tables below reconcile the non-GAAP disclosures to the most directly comparable GAAP numbers.

Adjusted EPS

The results of 2009 were impacted by long-term incentive compensation and office relocation expenses and the reversal of certain litigation reserves. The results for 2008 were impacted by income from long-term incentive compensation expense reversals, Lehman bad debt and an other than temporary impairment of available-for-sale securities. Adjusted EPS is presented because it is an important measure used by management to evaluate period-to-period comparisons of earnings trends.

		Three Months Ended					Year Ended
		December 31,					December 31,
		2009			2008		2009			2008
Net income as
reported:		$55,382			$33,495		$156,929			$255,604
Long-term
incentive
compensation
expense		17,246			2,806		48,168			(20,198	)
Office relocation
expense		661			-		3,223			-
Lehman bad debt
expense		-			3,172		-			3,172
Other-than-
temporary-
impairment of
available-for-
sale securities		-			4,779		-			4,779
Litigation reserve
adjustment		(5,364	)		-		(5,364	)		-
Adjusted net
income		$67,925			$44,252		$202,956			$243,357
Diluted weighted
average common
shares outstanding:		131,567			131,298		131,482			128,106
Adjusted EPS		$0.52			$0.34		$1.54			$1.90

(a) The tax impact of long-term incentive compensation was calculated by applying the annual effective tax rate excluding discrete items and the rate impact of non-deductible compensation expense to deductible compensation expense. The tax impact of all other adjustments was calculated at the annual effective rate excluding discrete items and the rate impact of non-deductible compensation expense.

Adjustments to EPS were reported net of income tax expense/(benefit)for the three months and years ended December 31, 2009 and 2008, respectively of: Long-term incentive compensation expense $3,685, $1,795, $13,676 and $(12,915); office relocation expense $398, $0, $1,945 and $0; Lehman bad debt expense $0, $2,028, $0 and $2,028; other-than-temporary-impairment of available-for-sale securities $0, $3,056, $0, and $3,056; and litigation reserve adjustment $(3,236), $0, $(3,236), and $0.

Operating Cash Flow

Operating cash flow is presented because of its acceptance as an 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 which the company may not control and may not relate to the period in which the operating activities occurred.

		Three Months Ended						Year Ended
		December 31,						December 31,
(thousands)		2009			2008			2009			2008
Net Income:		$55,382			$33,495			$156,929			$255,604
Add back (deduct):
Deferred income taxes		139,977			50,420			234,776			245,801
Depreciation,
depletion, and
amortization		55,595			39,731			196,078			136,816
Other items, net		302			12,029			(3,481	)		13,386
Operating cash flow:		$251,256			$135,675			$584,302			$651,607
Add back (deduct):
Reimbursements for
tenant improvements		12,212			-			12,212			-
Changes in margin
deposits		3,888			26,238			11,330			1,496
Other changes in
operating assets and
liabilities		(94,200	)		20,373			117,897			(143,946	)
Net cash provided by
operating activities		$173,156			$182,286			$725,741			$509,157
Net cash used in
investing activities		$(340,054	)		$(390,234	)		$(985,520	)		$(1,375,996	)
Net cash provided by
financing activities		$(25,606	)		$197,314			$259,779			$785,128
Net increase
(decrease) in cash
and cash equivalents		$(192,504	)		$(10,634	)		$-			$(81,711	)

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				Year Ended
		December 31,				December 31,
(thousands)		2009		2008		2009		2008
Net operating revenues		$281,829		$235,386		$950,458		$931,352
Plus: Purchased gas cost		62,198		173,492		319,369		645,136
Operating revenues		$344,027		$408,878		$1,269,827		$1,576,488
Net operating expenses		$168,620		$153,862		$593,667		$466,546
Plus: Purchased gas cost		62,198		173,492		319,369		645,136
Operating expenses		$230,818		$327,354		$913,036		$1,111,682

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.

EQT management speaks to investors from time to time. 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 at period end is an operational estimate of the daily sales volume on a typical day (excluding curtailments) at the end of the applicable period.

Unit development costs are calculated as the costs to drill a well divided by the gross expected EUR of the well.

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, production and sales volumes, reserves, EUR, F&D costs, the expected decline curve, 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, 2008 and in the company's Form 10-K for the year ended December 31, 2009 to be filed with the SEC, 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.

EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME (UNAUDITED)
(Thousands except per share amounts)
		Three Months Ended					Year Ended
		December 31,					December 31,
		2009		2008			2009		2008
Operating revenues		$344,027		$408,878			$1,269,827		$1,576,488
Operating expenses:
Purchased gas costs		62,198		173,492			319,369		645,136
Operation and maintenance		38,482		44,965			139,524		129,502
Production		17,424		20,103			63,457		80,068
Exploration		5,653		4,163			17,905		9,064
Selling, general and
administrative		51,466		44,900			176,703		111,096
Depreciation, depletion and
amortization		55,595		39,731			196,078		136,816
Total operating expenses		230,818		327,354			913,036		1,111,682
Operating income		113,209		81,524			356,791		464,806
Other than temporary
impairment of available-
for-sale securities		-		(7,835	)		-		(7,835	)
Other income		277		524			2,076		6,233
Equity in earnings of
nonconsolidated
investments		1,827		1,166			6,509		5,714
Interest expense		33,683		17,402			111,779		58,394
Income before income taxes		81,630		57,977			253,597		410,524
Income taxes		26,248		24,482			96,668		154,920
Net income		$55,382		$33,495			$156,929		$255,604
Earnings per share of
common stock:
Basic:
Weighted average common
shares outstanding		130,864		130,595			130,820		127,234
Net income		$0.42		$0.26			$1.20		$2.01
Diluted:
Weighted average common
shares outstanding		131,567		131,298			131,482		128,106
Net income		$0.42		$0.26			$1.19		$2.00

EQT PRODUCTION
OPERATIONAL AND FINANCIAL REPORT
		Three Months Ended						Year Ended
		December 31,						December 31,
		2009			2008			2009			2008
OPERATIONAL DATA
Natural gas and oil
production (MMcfe)		28,223			24,772			104,928			90,585
Company usage, line
loss (MMcfe)		(621	)		(1,672	)		(4,828	)		(6,577	)
Total sales volumes (MMcfe)		27,602			23,100			100,100			84,008
Average (wellhead)
sales price ($/Mcfe)		$3.72			$4.44			$3.75			$5.32
Sales of Produced
Natural Gas detail (MMcfe)
Horizontal Huron /
Berea Play		8,989			4,512			26,783			10,555
Horizontal Marcellus Play		1,633			317			2,933			532
CBM Play		3,169			3,061			12,313			11,866
Other (vertical non-CBM)		13,811			15,210			58,071			61,055
Total sales of produced
natural gas		27,602			23,100			100,100			84,008
Lease operating
expenses, excluding
production taxes ($/Mcfe)		$0.33			$0.42			$0.30			$0.35
Production taxes ($/Mcfe)		$0.25			$0.38			$0.29			$0.52
Production depletion ($/Mcfe)		$1.14			$0.81			$1.06			$0.81
Production depletion
(thousands)		$32,206			$19,973			$111,371			$73,362
Other depreciation,
depletion and
amortization
(thousands)		1,494			1,504			6,053			4,872
Total depreciation,
depletion and
amortization
(thousands)		$33,700			$21,477			$117,424			$78,234
Capital expenditures
(thousands)		$270,543			$207,811			$717,356			$700,745
FINANCIAL DATA
(Thousands)
Total operating revenues		$105,006			$105,035			$384,576			$457,144
Operating expenses:
Lease operating expense
excluding production
taxes		9,383			10,324			31,228			31,719
Production taxes		7,041			9,434			30,123			47,158
Exploration expense		5,653			4,163			17,905			9,064
Selling, general and
administrative		7,735			8,658			36,815			38,185
Depreciation, depletion
and amortization		33,700			21,477			117,424			78,234
Total operating
expenses		63,512			54,056			233,495			204,360
Operating income		$41,494			$50,979			$151,081			$252,784

* Average wellhead sales price is calculated as market price adjusted for hedging activities less deductions for gathering, processing and transmission included in EQT Midstream revenues. These deductions totaled $1.69 and $1.60/Mcfe for the three months ended December 31, 2009 and 2008, respectively and $1.69/Mcfe and $1.50/Mcfe for the year ended December 31, 2009 and 2008, respectively.

EQT MIDSTREAM
OPERATIONAL AND FINANCIAL REPORT
		Three Months Ended				Year Ended
		December 31,				December 31,
		2009		2008		2009		2008
OPERATIONAL DATA
Gathered volumes (BBtu)		42,562		39,899		161,480		145,031
Average gathering fee ($/MMBtu)		$1.04		$0.96		$1.04		$0.98
Gathering and compression expense
($/MMBtu) (a)		$0.42		$0.39		$0.42		$0.37
NGLs Sold (Mgal)		36,754		26,366		126,590		81,856
Average NGL sales price ($/gal)		$1.07		$0.72		$0.80		$1.24
Transmission pipeline throughput
(BBtu)		23,129		22,525		84,132		76,270
Net operating revenues
(thousands):
Gathering		$43,341		$36,611		$165,519		$140,118
Processing		25,867		3,446		57,690		35,523
Transmission		21,198		16,659		76,749		51,563
Storage, marketing and other		34,496		21,363		86,254		76,136
Total net operating revenues		$124,902		$78,079		$386,212		$303,340
Capital expenditures (thousands)		$45,748		$161,046		$201,082		$593,564
FINANCIAL DATA (Thousands)
Total operating revenues		$176,625		$120,259		$543,564		$681,475
Purchased gas costs		51,723		42,180		157,352		378,135
Total net operating revenues		124,902		78,079		386,212		303,340
Operating expenses:
Operating and maintenance		26,194		32,008		96,791		84,558
Selling, general and
administrative		14,595		14,419		47,146		49,208
Depreciation and amortization		14,789		11,134		53,291		34,802
Total operating expenses		55,578		57,561		197,228		168,568
Operating income		$69,324		$20,518		$188,984		$134,772
Other income		$110		$371		$1,357		$5,678
Equity in earnings of
nonconsolidated investments		$1,768		$1,064		$6,376		$5,053

(a) The calculation of gathering and compression expense ($/MMBtu) for fourth quarter and full-year 2008 excludes a $9.5 million charge for pension and other post-retirement benefits.

DISTRIBUTION
OPERATIONAL AND FINANCIAL REPORT
		Three Months Ended				Year Ended
		December 31,				December 31,
		2009		2008		2009		2008
OPERATIONAL DATA
Heating degree days (30
year average: Qtr -2070;
YTD -5,829)		1,953		2,120		5,474		5,622
Residential sales and
transportation volume (MMcf)		7,183		7,836		23,098		23,824
Commercial and industrial
volume (MMcf)		8,708		6,676		30,521		27,503
Total throughput (MMcf) -
Distribution		15,891		14,512		53,619		51,327
Net operating revenues
(thousands):
Residential		$33,968		$33,343		$111,007		$105,059
Commercial & industrial		13,262		13,176		47,432		46,394
Off-system and energy
services		4,691		5,753		21,545		19,415
Total net operating
revenues		$51,921		$52,272		$179,984		$170,868
Capital expenditures
(thousands)		$8,370		$13,608		$33,707		$45,770
FINANCIAL DATA (Thousands)
Total operating revenues		$134,418		$238,903		$560,283		$698,385
Purchased gas costs		82,497		186,631		380,299		527,517
Net operating revenues		51,921		52,272		179,984		170,868
Operating expenses:
Operating and maintenance		13,075		11,768		43,663		44,161
Selling, general and
administrative		10,437		12,212		35,028		44,793
Depreciation and
amortization		5,926		6,640		22,375		22,055
Total operating expenses		29,438		30,620		101,066		111,009
Operating income		$22,483		$21,652		$78,918		$59,859