Exhibit 99.1
EQT Reports Third Quarter 2011 Earnings;
Production Sales Volume Growth of 51%
PITTSBURGH--(BUSINESS WIRE)--October 27, 2011--EQT Corporation (NYSE: EQT) today announced third quarter 2011 earnings of $178.9 million, $142.4 million higher than the third quarter 2010. Earnings per diluted share (EPS) were $1.19 for the quarter, up from the $0.24 reported in 2010. Operating cash flow was $189.9 million; 44% higher than the third quarter 2010. Cash flow per share was $1.26, compared to $0.88 last year. The quarter included a $180.1 million pre-tax gain on the sale of the Big Sandy Pipeline; adjusting for the gain, EPS was $0.45.
Highlights for the third quarter 2011 include:
- Production sales volumes were 51% higher than the third quarter 2010;
- Marcellus production was 252% higher than the third quarter 2010; and
- EQT Midstream’s gathered volumes increased by 35% to a record 67.3 TBtus.
EQT’s third quarter 2011 operating income was $134.8 million, representing a $46.7 million increase from the same quarter in 2010. Higher revenues attributed to increased production and midstream volumes were partially offset by lower storage, marketing and other net revenues, and higher operating expenses. Net operating revenues rose 32% to $328.5 million in the quarter, while net operating expenses only rose by 21% to $193.7 million.
Results by Business
EQT Production
EQT Production recorded sales volumes of 51.3 Bcfe; or 558 MMcfe per day, in the third quarter 2011; 51% higher than the third quarter 2010, due to a 252% increase in Marcellus Shale volumes. Adjusting for 2.0 Bcfe of production from other vertical non-CBM wells acquired in connection with the ANPI transaction, which closed in the second quarter 2011, production sales volumes were 45% higher. Marcellus Shale wells accounted for 44% of EQT’s production sales volumes, up from 19% in the third quarter 2010. Average daily sales from Marcellus wells were 243 MMcfe per day for the quarter and are expected to exit 2011 at 285 MMcfe per day. EQT expects sales of produced natural gas in 2011 to be 195 Bcfe; the high end of our previous guidance of between 190 and 195 Bcfe. The company also reiterates the 2012 guidance of more than 250 Bcfe.
EQT Production operating income for the third quarter of 2011 was $98.9 million, compared with $55.7 million in the same period last year. Production operating revenues for the quarter were $207.5 million, 57% higher, driven by the 51% volume increase, higher natural gas liquid (NGL) prices and lower per unit midstream costs. EQT Production‘s sales volumes consisted of approximately 6% liquids, excluding ethane. EQT Corporation realized an average unhedged premium of $1.19 per Mcfe over the NYMEX natural gas price, as a result of its liquids-rich production and positive basis to Henry Hub.
Consistent with EQT Production’s growth, operating expenses for the quarter were $32.4 million higher at $108.6 million. Depreciation, depletion and amortization (DD&A) expense was $20.3 million higher, due to increased volumes. Lease operating expense (LOE), including production taxes, was $24.9 million, $8.9 million higher. Per unit LOE, including production taxes, increased by $0.02 per Mcfe to $0.47 per Mcfe as a result of higher production taxes. Excluding production taxes, per unit LOE was flat at $0.22 per Mcfe. Selling, general and administrative (SG&A) expense was $15.9 million for the quarter; $3.4 million higher than the third quarter 2010. Per unit SG&A decreased 14% to $0.30 per Mcfe.
The company drilled (spud) 66 gross horizontal wells during the third quarter 2011; 36 targeting the Marcellus play with an average length of pay of 4,615 feet; and 30 targeting the Huron play with an average length of pay of 4,940 feet. The company drilled 178 gross horizontal wells during the first nine months of 2011; 87 targeting the Marcellus play and 91 targeting the Huron play.
EQT Midstream
EQT Midstream achieved third quarter 2011 operating income of $41.7 million, 16% higher than the same period of 2010. Increased gathering and Equitrans transmission revenues more than offset the loss of revenues associated with the sales of the Langley natural gas processing complex and the Big Sandy Pipeline, and lower storage and marketing net revenues. Net gathering revenues increased 17% to $63.3 million in the third quarter 2011, driven primarily by a 35% increase in gathered volumes. Marcellus gathered volumes increased by 217% over last year. Net transmission revenues decreased by $1.2 million to $18.3 million, as $8.5 million of Big Sandy revenues were partially replaced by an increase in contracted Equitrans capacity.
Operating expenses for the quarter were $52.3 million; $4.3 million lower than in the third quarter of 2010, resulting from the absence of $9.5 million of operating expenses associated with the sales of Langley and Big Sandy. Labor and other costs associated with the growth of the business were $5.2 million higher. EQT Midstream’s unit costs to gather and transport EQT Production sales volumes were 26% lower, at $0.39 per Mcfe, as EQT Midstream continues to realize economies of scale in the Marcellus play.
On July 17, 2011, the company commissioned its 150 MMcfe per day Callisto Compressor Station in Greene County, Pennsylvania, to further expand its Marcellus gathering capacity.
Distribution
Distribution’s third quarter 2011 operating income totaled $2.5 million, compared with $0.6 million for the same period in 2010. Net operating revenues for the third quarter 2011 were $27.0 million, $2.8 million higher than last year. Operating expenses were $1.0 million higher year-over-year.
Other Business
Sale of Big Sandy Pipeline
On July 1, 2011, EQT completed the sale of its Big Sandy Pipeline to Spectra Energy Partners, LP for $390 million. EQT recognized a pre-tax gain of $180.1 million on the transaction in the third quarter 2011. This transaction resulted in tax expenses of approximately $69 million. Transmission revenues associated with the sale were $8.5 million; operating and maintenance expenses were $1.2 million; and DD&A was $0.9 million in the third quarter 2011.
Hedging
As of October 26, 2011, the company’s production sales volumes are approximately 40% hedged for 2012, with a weighted average price of $5.56 per Mcf. The company’s total hedge positions for the fourth quarter 2011 through 2014 production are:
| | | 2011** | | 2012 | | 2013 | | 2014 |
| Swaps | | | | | | | | | |
| Total Volume (Bcf) | | | | 23 | | | 80 | | | 29 | | | – |
| Average Price per Mcf (NYMEX)* | | | $ | 4.88 | | $ | 5.31 | | $ | 5.64 | | $ | – |
| | | | | | | | | |
| Puts | | | | | | | | | |
| Total Volume (Bcf) | | | | 1 | | | – | | | – | | | – |
| Average Floor Price per Mcf (NYMEX)* | | | $ | 7.35 | | $ | – | | $ | – | | $ | – |
| | | | | | | | | |
| Collars | | | | | | | | | |
| Total Volume (Bcf) | | | | 5 | | | 21 | | | 15 | | | 14 |
| Average Floor Price per Mcf (NYMEX)* | | | $ | 6.51 | | $ | 6.51 | | $ | 6.12 | | $ | 6.37 |
| Average Cap Price per Mcf (NYMEX)* | | | $ | 11.83 | | $ | 11.83 | | $ | 11.80 | | $ | 11.55 |
| | | | | | | | | | | | | |
* Based on a conversion rate of 1.05 MMBtu / Mcf
**September through December
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. Unallocated expenses are due primarily to certain incentive compensation and administrative costs in excess of budget that are not allocated to the operating segments.
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2011 | | 2010 | | 2011 | | 2010 |
| Operating income (thousands): | | | | | | | | |
| EQT Production | | $ | 98,936 | | | $ | 55,651 | | | $ | 281,024 | | | $ | 169,797 | |
| EQT Midstream | | | 41,673 | | | | 35,858 | | | | 160,549 | | | | 130,263 | |
| Distribution | | | 2,463 | | | | 644 | | | | 64,758 | | | | 52,353 | |
| Unallocated expenses | | | (8,231 | ) | | | (3,971 | ) | | | (20,693 | ) | | | (16,589 | ) |
| Operating income | | $ | 134,841 | | | $ | 88,182 | | | $ | 485,638 | | | $ | 335,824 | |
| | | | | | | | | | | | | | | | |
Price Reconciliation
EQT Production's average wellhead sales price is calculated by allocating some revenues to EQT Midstream for the gathering and transmission of the produced gas, after deductions for third party gathering, processing and transmission. The impact of the sale of the Big Sandy Pipeline increased EQT Production’s third party gathering, processing and transmission revenue deductions by $0.14 per Mcfe and decreased the transmission and processing revenue deductions allocated to EQT Midstream by $0.14 per Mcfe. EQT’s average wellhead sales price for the three and nine months ended September 30, 2011 and 2010 were as follows:
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2011 | | 2010 | | 2011 | | 2010 |
| Revenues ($ / Mcfe) | | | | | | | | |
| Average NYMEX price | | $ | 4.19 | | | $ | 4.38 | | | $ | 4.21 | | | $ | 4.59 | |
| Hedge impact | | | 0.44 | | | | 0.53 | | | | 0.42 | | | | 0.44 | |
| Average basis | | | 0.08 | | | | 0.05 | | | | 0.15 | | | | 0.13 | |
| Average net liquids revenue | | | 1.11 | | | | 0.97 | | | | 1.12 | | | | 1.02 | |
| Hedge adjusted price | | $ | 5.82 | | | $ | 5.93 | | | $ | 5.90 | | | $ | 6.18 | |
| | | | | | | | |
| Midstream Revenue Deductions ($ / Mcfe) | | | | | | | | |
| Gathering to EQT Midstream | | $ | (1.09 | ) | | $ | (1.34 | ) | | $ | (1.13 | ) | | $ | (1.31 | ) |
| Transmission and processing to EQT Midstream | | | (0.14 | ) | | | (0.37 | ) | | | (0.24 | ) | | | (0.39 | ) |
| Third party gathering, processing and transmission | | | (0.57 | ) | | | (0.41 | ) | | | (0.48 | ) | | | (0.43 | ) |
| Total midstream revenue deductions | | $ | (1.80 | ) | | $ | (2.12 | ) | | $ | (1.85 | ) | | $ | (2.13 | ) |
| Average wellhead sales price to EQT Production | | $ | 4.02 | | | $ | 3.81 | | | $ | 4.05 | | | $ | 4.05 | |
| | | | | | | | |
| EQT Revenue ($ / Mcfe) | | | | | | | | |
| Revenues to EQT Midstream | | $ | 1.23 | | | $ | 1.71 | | | $ | 1.37 | | | $ | 1.70 | |
| Revenues to EQT Production | | | 4.02 | | | | 3.81 | | | | 4.05 | | | | 4.05 | |
| Average wellhead sales price to EQT Corporation | | $ | 5.25 | | | $ | 5.52 | | | $ | 5.42 | | | $ | 5.75 | |
| | | | | | | | | | | | | | | | |
Unit Costs
EQT’s unit costs to produce, gather and transport EQT's produced natural gas excluding third party gathering, processing and transmission fees, which were deducted from revenues, were:
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2011 | | 2010 | | 2011 | | 2010 |
| Production segment costs: ($ / Mcfe) | | | | | | | |
| LOE | $ | 0.22 | | $ | 0.22 | | $ | 0.21 | | $ | 0.24 |
| Production taxes | | 0.25 | | | 0.23 | | | 0.21 | | | 0.25 |
| G&A | | 0.30 | | | 0.35 | | | 0.31 | | | 0.42 |
| $ | 0.77 | | $ | 0.80 | | $ | 0.73 | | $ | 0.91 |
| Midstream segment costs: ($ / Mcfe) | | | | | | | |
| Gathering and transmission | $ | 0.39 | | $ | 0.53 | | $ | 0.36 | | $ | 0.51 |
| SG&A | | 0.18 | | | 0.19 | | | 0.17 | | | 0.18 |
| $ | 0.57 | | $ | 0.72 | | $ | 0.53 | | $ | 0.69 |
| Total ($ / Mcfe) | $ | 1.34 | | $ | 1.52 | | $ | 1.26 | | $ | 1.60 |
| | | | | | | | | | | |
Marcellus Horizontal Well Status (cumulatively since inception)
| | As of
9/30/11 | | As of
6/30/11 | | As of
3/31/11 | | As of
12/31/10 | | As of
9/30/10 |
| Wells spud | | 230 | | 194 | | 166 | | 143 | | 131 |
| Wells online | | 137 | | 119 | | 86 | | 66 | | 48 |
| Wells complete, not online | | 4 | | 5 | | 8 | | 17 | | 15 |
| Frac stages (spud wells)* | | 3,530 | | 2,809 | | 2,387 | | 1,940 | | 1,706 |
| Frac stages online | | 1,873 | | 1,578 | | 1,047 | | 773 | | 512 |
| Frac stages complete, not online | | 65 | | 74 | | 127 | | 241 | | 208 |
| | | | | | | | | | |
*Includes planned stages for spud wells that have not yet been frac’d.
Non-GAAP Disclosures
Operating Cash Flow
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. The gain on disposition of assets is calculated after consideration of the increase in current federal alternative minimum tax and state income taxes payable in 2011, which are a direct result of the tax gains on the dispositions. 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 cash flows to be included in the company’s Form 10-Q for the nine months ending September 30, 2011 and 2010.
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| (thousands) | | 2011 | | 2010 | | 2011 | | 2010 |
| Net Income | | $ | 178,914 | | | $ | 36,522 | | | $ | 388,923 | | | $ | 154,587 | |
| Add back (deduct): | | | | | | | | |
| Deferred income taxes | | | 86,392 | | | | 32,774 | | | | 190,330 | | | | 99,205 | |
| Depreciation, depletion, and amortization | | | 87,343 | | | | 68,548 | | | | 247,627 | | | | 195,644 | |
| Gain on disposition, net of current taxes | | | (159,560 | ) | | | – | | | | (166,657 | ) | | | – | |
| Other items, net | | | (3,179 | ) | | | (6,054 | ) | | | (16,911 | ) | | | (46 | ) |
| Operating cash flow: | | $ | 189,910 | | | $ | 131,790 | | | $ | 643,312 | | | $ | 449,390 | |
| | | | | | | | |
| Add back (deduct): | | | | | | | | |
| Changes in operating assets and liabilities | | | 81,424 | | | | 12,678 | | | | 106,294 | | | | 171,657 | |
| Current taxes on disposition | | | (20,583 | ) | | | – | | | | (36,271 | ) | | | – | |
| Net cash provided by operating activities | | $ | 250,751 | | | $ | 144,468 | | | $ | 713,335 | | | $ | 621,047 | |
| | | | | | | | | | | | | | | | |
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 September 30, | | Nine Months Ended September 30, |
| (thousands) | | 2011 | | 2010 | | 2011 | | 2010 |
| Net operating revenues | | $ | 328,523 | | $ | 248,497 | | $ | 1,013,521 | | $ | 812,721 |
| Plus: purchased gas cost | | | 8,197 | | | 8,838 | | | 127,870 | | | 138,769 |
| Operating revenues | | $ | 336,720 | | $ | 257,335 | | $ | 1,141,391 | | $ | 951,490 |
| | | | | | | | |
| Net operating expenses, excluding purchased gas cost | | $ | 193,682 | | $ | 160,315 | | $ | 527,883 | | $ | 476,897 |
| Plus: purchased gas cost | | | 8,197 | | | 8,838 | | | 127,870 | | | 138,769 |
| Operating expenses | | $ | 201,879 | | $ | 169,153 | | $ | 655,753 | | $ | 615,666 |
| | | | | | | | | | | | |
EQT's conference call with securities analysts, which begins at 10:30 a.m. Eastern Time today will cover third quarter 2011 financial and operational results and other matters, and will be broadcast live via EQT's website, http://www.eqt.com and on the Investor information page from the company’s website 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 website. 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, 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.
Daily sales are the total sales volumes per day (or daily production). Forecasted daily sales is an operational estimate of the daily sales volume on a typical day (excluding curtailments).
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. This is due to uncertainties associated with projecting future net income and changes in assets and liabilities.
Disclosures in this news release and/or made during the third quarter earnings conference call 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 news 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 impact of oilfield inflation on the cost of drilling services, Equitrans Marcellus expansion project, such as the amount of the expected additional capital investment in and additional capacity and operating income resulting from, such project) and technology, transactions, including asset sales, MLPs, and/or joint ventures involving the company’s assets, the expected use of proceeds from the sales of the Big Sandy Pipeline and the Langley natural gas processing complex, revenue projections, including the expected reduction in revenue, EBITDA and operating income as a result of the sale of the Big Sandy Pipeline, production and sales volumes, reserves, the estimated percentage of the Company’s acreage containing liquids, EUR, internal rates of return (IRR), return on total capital (ROTC), midstream costs, F&D costs, operating costs, expected gathering rates, including the impact of continued Marcellus production growth on the average gathering rate, well costs, the expected decline curve, the expected feet of pay, capital expenditures, financing requirements and availability, projected operating cash flows, hedging strategy, the effects of government regulation, 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, 2010, 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, transmission and distribution. Additional information about the company can be obtained through the company’s website, http://www.eqt.com. Investor information is available on EQT’s website at http://ir.eqt.com. EQT uses its website 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 |
| | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2011 | | 2010 | | 2011 | | 2010 |
| OPERATIONAL DATA | | | | | | | | |
Average wellhead sales price to EQT Corporation: | | | | | | | | |
| Natural gas excluding hedges ($/Mcf) | | $ | 4.21 | | $ | 4.40 | | $ | 4.37 | | $ | 4.68 |
| Hedge impact ($/Mcf of natural gas) (a) | | $ | 0.47 | | $ | 0.58 | | $ | 0.46 | | $ | 0.48 |
| Natural gas including hedges ($/Mcf) | | $ | 4.68 | | $ | 4.98 | | $ | 4.83 | | $ | 5.16 |
| NGLs ($/Bbl) | | $ | 52.56 | | $ | 43.89 | | $ | 52.12 | | $ | 46.69 |
| Crude oil ($/Bbl) | | $ | 81.66 | | $ | 62.39 | | $ | 83.52 | | $ | 70.37 |
| Total ($/Mcfe) | | $ | 5.25 | | $ | 5.52 | | $ | 5.42 | | $ | 5.75 |
| Less revenues to EQT Midstream ($/Mcfe) | | $ | 1.23 | | $ | 1.71 | | $ | 1.37 | | $ | 1.70 |
Average wellhead sales price to EQT Production ($/Mcfe) | | $ | 4.02 | | $ | 3.81 | | $ | 4.05 | | $ | 4.05 |
| NYMEX natural gas ($/Mcf) | | $ | 4.19 | | $ | 4.38 | | $ | 4.21 | | $ | 4.59 |
| Natural gas sales volumes (MMcf) | | | 48,070 | | | 31,087 | | | 132,035 | | | 87,746 |
| NGL sales volumes (MBbls) | | | 759 | | | 697 | | | 2,259 | | | 1,982 |
| Crude oil sales volumes (MBbls) | | | 61 | | | 36 | | | 141 | | | 86 |
| Total production sales volumes (MMcfe) (b) | | | 51,298 | | | 33,988 | | | 141,375 | | | 95,903 |
| Capital expenditures (thousands) (c) | | $ | 347,645 | | $ | 340,151 | | $ | 985,171 | | $ | 1,093,689 |
| | | | | | | | |
| STATEMENTS OF CONSOLIDATED INCOME (UNAUDITED) |
| (Thousands, except per share amounts) |
| | | | | | | | |
| Operating revenues | | $ | 336,720 | | $ 257,335 | | $ 1,141,391 | | $ | 951,490 |
| Operating expenses: | | | | | | | | |
| Purchased gas costs | | | 8,197 | | 8,838 | | 127,870 | | | 138,769 |
| Operation and maintenance | | | 35,872 | | 40,483 | | 91,513 | | | 110,775 |
| Production | | | 24,908 | | 16,010 | | 60,784 | | | 49,163 |
| Exploration | | | 814 | | 941 | | 3,387 | | | 3,354 |
| Selling, general and administrative | | | 44,745 | | 34,333 | | 124,572 | | | 117,961 |
| Depreciation, depletion and amortization | | | 87,343 | | 68,548 | | 247,627 | | | 195,644 |
| Total operating expenses | | | 201,879 | | 169,153 | | 655,753 | | | 615,666 |
| Operating income | | | 134,841 | | 88,182 | | 485,638 | | | 335,824 |
| Gain on dispositions | | | 180,143 | | - | | 202,928 | | | - |
| Other income | | | 3,098 | | 2,924 | | 27,948 | | | 8,551 |
| Interest expense | | | 32,503 | | 33,861 | | 98,642 | | | 102,075 |
| Income before income taxes | | | 285,579 | | 57,245 | | 617,872 | | | 242,300 |
| Income taxes | | | 106,665 | | 20,723 | | 228,949 | | | 87,713 |
| Net income | | $ | 178,914 | | $ 36,522 | | $ 388,923 | | $ | 154,587 |
| Earnings per share of common stock: | | | | | | | | |
| Basic: | | | | | | | | |
| Weighted average common shares outstanding | | | 149,441 | | 149,133 | | 149,373 | | | 143,048 |
| Net income | | $ | 1.20 | | $ 0.24 | | $ 2.60 | | $ | 1.08 |
| Diluted: | | | | | | | | |
| Weighted average common shares outstanding | | | 150,301 | | 149,775 | | 150,144 | | | 143,806 |
| Net income | | $ | 1.19 | | $ 0.24 | | $ 2.59 | | $ | 1.07 |
| Dividends declared per common share | | $ | 0.22 | | $ 0.22 | | $ 0.66 | | $ | 0.66 |
| | | | | | | | |
| (a) | | All hedges are related to natural gas. |
| (b) | | NGLs were converted to Mcfe at the rate of 3.76 Mcfe per barrel and 3.86 Mcfe per barrel based on the liquids content for the three and nine months ended September 30, 2011 and 2010, respectively, and crude oil was converted to Mcfe at the rate of six Mcfe per barrel for all periods. |
| (c) | | Capital expenditures in the EQT Production segment include $92.6 million of liabilities assumed in exchange for producing properties as part of the ANPI transaction and $230.7 million of undeveloped property which was acquired with EQT common stock in 2010. |
| | |
EQT PRODUCTION
RESULTS OF OPERATIONS |
| | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2011 | | 2010 | | 2011 | | 2010 |
| OPERATIONAL DATA | | | | | | | | |
| | | | | | | | |
| Natural gas, NGL and crude oil production (MMcfe) (a) | | | 52,456 | | | | 35,334 | | | | 145,021 | | | | 99,520 | |
| Company usage, line loss (MMcfe) | | | (1,158 | ) | | | (1,346 | ) | | | (3,646 | ) | | | (3,617 | ) |
| Total production sales volumes (MMcfe) | | | 51,298 | | | | 33,988 | | | | 141,375 | | | | 95,903 | |
| | | | | | | | |
| Average daily sales volumes (MMcfe/d) | | | 558 | | | | 369 | | | | 518 | | | | 351 | |
| | | | | | | | |
| Sales volume detail (MMcfe): | | | | | | | | |
| Horizontal Marcellus Play | | | 22,401 | | | | 6,372 | | | | 56,896 | | | | 15,134 | |
| Horizontal Huron Play | | | 9,815 | | | | 9,953 | | | | 30,175 | | | | 28,075 | |
| CBM Play | | | 3,479 | | | | 3,513 | | | | 10,254 | | | | 10,007 | |
| Other (vertical non-CBM) | | | 15,603 | | | | 14,150 | | | | 44,050 | | | | 42,687 | |
| Total production sales volumes | | | 51,298 | | | | 33,988 | | | | 141,375 | | | | 95,903 | |
| | | | | | | | |
| Average wellhead sales price ($/Mcfe) | | $ | 4.02 | | | $ | 3.81 | | | $ | 4.05 | | | $ | 4.05 | |
| | | | | | | | |
| Lease operating expenses, excluding production taxes (LOE) ($/Mcfe) | | $ | 0.22 | | | $ | 0.22 | | | $ | 0.21 | | | $ | 0.24 | |
| Production taxes ($/Mcfe) | | $ | 0.25 | | | $ | 0.23 | | | $ | 0.21 | | | $ | 0.25 | |
| Production depletion ($/Mcfe) | | $ | 1.23 | | | $ | 1.26 | | | $ | 1.24 | | | $ | 1.26 | |
| | | | | | | | |
Depreciation, depletion and amortization (DD&A) (thousands): | | | | | | | | |
| Production depletion | | $ | 64,742 | | | $ | 44,609 | | | $ | 180,063 | | | $ | 125,113 | |
| Other DD&A | | | 2,205 | | | | 2,049 | | | | 6,617 | | | | 5,923 | |
| Total DD&A | | $ | 66,947 | | | $ | 46,658 | | | $ | 186,680 | | | $ | 131,036 | |
| | | | | | | | |
| Capital expenditures (thousands) (b) | | $ | 255,151 | | | $ | 267,154 | | | $ | 800,029 | | | $ | 929,225 | |
| | | | | | | | |
| | | | | | | | |
| FINANCIAL DATA (Thousands) | | | | | | | | |
| | | | | | | | |
| Total operating revenues | | $ | 207,500 | | | $ | 131,791 | | | $ | 577,352 | | | $ | 395,182 | |
| | | | | | | | |
| Operating expenses: | | | | | | | | |
| LOE | | | 11,612 | | | | 7,857 | | | | 29,760 | | | | 24,056 | |
| Production taxes (c) | | | 13,296 | | | | 8,153 | | | | 31,024 | | | | 25,107 | |
| Exploration expense | | | 814 | | | | 941 | | | | 3,387 | | | | 3,354 | |
| Selling, general and administrative (SG&A) | | | 15,895 | | | | 12,531 | | | | 45,477 | | | | 41,832 | |
| DD&A | | | 66,947 | | | | 46,658 | | | | 186,680 | | | | 131,036 | |
| Total operating expenses | | | 108,564 | | | | 76,140 | | | | 296,328 | | | | 225,385 | |
| Operating income | | $ | 98,936 | | | $ | 55,651 | | | $ | 281,024 | | | $ | 169,797 | |
| | | | | | | | | | | | | | | | |
| (a) | | Natural gas, NGL and oil production represents the Company’s interest in natural gas, NGL and oil production measured at the wellhead. It is equal to the sum of total sales volumes and Company usage and line loss. |
| (b) | | Capital expenditures in the EQT Production segment include $92.6 million of liabilities assumed in exchange for producing properties as part of the ANPI transaction in 2011 and $230.7 million of undeveloped property which was acquired with EQT common stock in 2010. |
| (c) | | Production taxes include severance and production-related ad valorem and other property taxes. |
| | |
EQT MIDSTREAM
RESULTS OF OPERATIONS |
| | | | |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| | 2011 | | 2010 | | 2011 | | 2010 |
| OPERATIONAL DATA | | | | | | | | |
| | | | | | | | |
| Gathered volumes (BBtu) | | | 67,304 | | | 49,990 | | | 188,492 | | | 142,074 | |
| Average gathering fee ($/MMBtu) | | $ | 0.94 | | $ | 1.08 | | $ | 0.97 | | $ | 1.10 | |
| Gathering expense ($/MMBtu) | | $ | 0.33 | | $ | 0.40 | | $ | 0.26 | | $ | 0.38 | |
| Transmission pipeline throughput (BBtu) | | | 38,121 | | | 27,138 | | | 117,122 | | | 76,196 | |
| Net operating revenues (thousands): | | | | | | | | |
| Gathering | | $ | 63,285 | | $ | 54,014 | | $ | 183,523 | | $ | 153,777 | |
| Transmission | | | 18,339 | | | 19,497 | | | 69,294 | | | 59,057 | |
| Storage, marketing and other | | | 12,380 | | | 18,975 | | | 45,547 | | | 74,423 | |
| Total net operating revenues | | $ | 94,004 | | $ | 92,486 | | $ | 298,364 | | $ | 287,257 | |
| Unrealized gains (losses) on derivatives and inventory (thousands) (a) | | $ | 1,396 | | $ | 28 | | $ | 1,850 | | $ | (794 | ) |
| Capital expenditures (thousands) | | $ | 81,227 | | $ | 59,499 | | $ | 156,832 | | $ | 138,479 | |
| | | | | | | | |
| FINANCIAL DATA (Thousands) | | | | | | | | |
| | | | | | | | |
| Total operating revenues | | $ | 122,614 | | $ | 144,634 | | $ | 395,477 | | $ | 436,225 | |
| Purchased gas costs | | | 28,610 | | | 52,148 | | | 97,113 | | | 148,968 | |
| Total net operating revenues | | | 94,004 | | | 92,486 | | | 298,364 | | | 287,257 | |
| | | | | | | | |
| Operating expenses: | | | | | | | | |
| Operating and maintenance (O&M) | | | 25,348 | | | 29,391 | | | 59,708 | | | 77,375 | |
| SG&A | | | 12,890 | | | 11,532 | | | 35,010 | | | 33,379 | |
| DD&A | | | 14,093 | | | 15,705 | | | 43,097 | | | 46,240 | |
| Total operating expenses | | | 52,331 | | | 56,628 | | | 137,815 | | | 156,994 | |
| Operating income | | $ | 41,673 | | $ | 35,858 | | $ | 160,549 | | $ | 130,263 | |
| | | | | | | | | | | | | |
| (a) | | Included within storage, marketing and other net operating revenues. |
| | |
DISTRIBUTION
RESULTS OF OPERATIONS |
| | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2011 | | 2010 | | 2011 | | 2010 |
| | | | | | | | |
| OPERATIONAL DATA | | | | | | | | |
Heating degree days (30 year average: Qtr - 114; YTD – 3,649) (a) | | | 85 | | | 73 | | | 3,508 | | | 3,350 |
| Residential sales and transportation volumes (MMcf) | | | 1,175 | | | 1,131 | | | 15,893 | | | 15,234 |
| Commercial and industrial volumes (MMcf) | | | 4,398 | | | 3,990 | | | 21,140 | | | 20,820 |
| Total throughput (MMcf) – Distribution | | | 5,573 | | | 5,121 | | | 37,033 | | | 36,054 |
| | | | | | | | |
| Net operating revenues (thousands): | | | | | | | | |
| Residential | | $ | 13,640 | | $ | 13,642 | | $ | 83,736 | | $ | 80,605 |
| Commercial & industrial | | | 6,543 | | | 6,374 | | | 35,959 | | | 33,862 |
| Off-system and energy services | | | 6,837 | | | 4,206 | | | 18,107 | | | 15,816 |
| Total net operating revenues | | $ | 27,020 | | $ | 24,222 | | $ | 137,802 | | $ | 130,283 |
| Capital expenditures (thousands) | | $ | 10,149 | | $ | 9,382 | | $ | 25,179 | | $ | 21,107 |
| | | | | | | | |
| FINANCIAL DATA (thousands) | | | | | | | | |
| Total operating revenues | | $ | 49,175 | | $ | 53,208 | | $ | 313,366 | | $ | 338,812 |
| Purchased gas costs | | | 22,155 | | | 28,986 | | | 175,564 | | | 208,529 |
| Net operating revenues | | | 27,020 | | | 24,222 | | | 137,802 | | | 130,283 |
| | | | | | | | |
| Operating expenses: | | | | | | | | |
| O&M | | | 10,414 | | | 11,027 | | | 31,466 | | | 32,607 |
| SG&A | | | 7,609 | | | 6,494 | | | 23,164 | | | 27,256 |
| DD&A | | | 6,534 | | | 6,057 | | | 18,414 | | | 18,067 |
| Total operating expenses | | | 24,557 | | | 23,578 | | | 73,044 | | | 77,930 |
| Operating income | | $ | 2,463 | | $ | 644 | | $ | 64,758 | | $ | 52,353 |
| | | | | | | | | | | | |
| (a) | | The 30-year heating degree days figures are derived from the National Oceanic and Atmospheric Administration’s (NOAA) 30-year normal figures. In the second quarter 2011, the NOAA released updated heating degree days figures for the period 1981 to 2010 and accordingly, the 30-year heating degree days decreased from 124 and 3,759 for the three and nine months ended September 30, 2010 to 114 and 3,649 for the three and nine months ended September 30, 2011. |
CONTACT:
EQT Corporation
Analysts:
Patrick Kane, Chief Investor Relations Officer, 412-553-7833
pkane@eqt.com
or
Media:
Karla Olsen, Public Relations Manager, 412-553-5726
kolsen@eqt.com
