PITTSBURGH--(BUSINESS WIRE)--EQT Corporation (NYSE: EQT) today announced 2011 earnings of $479.8 million, 111% higher than the $227.7 million earned in 2010. Full-year results include a $113.8 million after-tax gain on the sale of the Big Sandy Pipeline (Big Sandy) in the third quarter, a $14.4 million after-tax gain on the sale of the Langley Natural Gas Processing Complex (Langley) in the first quarter and other items listed in our non-GAAP reconciliation table. Adjusting for the asset sales, a $10.1 million gain on the ANPI transaction in the second quarter, adjustments to non-income tax reserves in the first quarter and $8.5 million of gains on sales of available-for-sale securities during the year, earnings per diluted share (EPS) were $2.21 for 2011; up from the $1.57 reported in 2010, as a result of higher annual production sales volume and higher gathering and transmission revenues. Operating cash flow was $885.9 million in 2011, 36% higher than 2010. Adjusted cash flow per share was $5.93, compared to $4.51 last year. See “Non-GAAP Disclosures” below for information concerning the non-GAAP disclosures contained in this press release.
Highlights for 2011 include:
- Record annual production sales volumes of 194.4 Bcfe, 44% higher than in 2010;
- Marcellus proved reserves increased by 19%, as detailed in a separate press release issued today;
- Unit lease operating expense, excluding production taxes (LOE), decreased 17% in 2011, to $0.20 per Mcfe. Including production taxes, LOE was $0.40 per Mcfe; and
- Record EQT Midstream throughput and operating income.
In 2011, EQT’s operating income was $861.3 million and included a $202.9 million gain on dispositions of Big Sandy and Langley; compared to operating income of $470.5 million in 2010. In addition to the gains on the dispositions, the company realized higher revenues from increased production, gathering and transmission volumes, which were partially offset by lower storage and marketing margins and lower revenues from Big Sandy and Langley, as a result of the asset sales, and lower wellhead price to EQT Corporation. Net operating expenses increased $74.0 million to $725.1 million, as higher depreciation, depletion and amortization expense (DD&A), selling, general and administrative expense (SG&A) and production expenses were partially offset by a decrease in operating and maintenance expense (O&M). O&M decreased as a result of the absence of costs associated with Big Sandy and Langley and reductions to certain non-income tax reserves.
Fourth quarter 2011 earnings were $90.8 million, 24% higher than the fourth quarter 2010. EPS were $0.60 for the fourth quarter 2011, up from the $0.49 per share reported last year, largely resulting from higher production sales volumes. Operating cash flow was $242.6 million in the quarter, 25% higher than last year; and cash flow per share was $1.62, compared to $1.31 last year.
In the fourth quarter of 2011, EQT’s operating income was $172.8 million, representing a 28% increase from the same quarter in 2010. Higher revenues attributed to increased production, gathering and transmission volumes were partially offset by lower marketing and other net revenues and higher costs associated with increased volumes. In total, net operating revenues rose 20% to $369.9 million in the quarter. Net operating expenses were $197.2 million, $23.1 million higher than the fourth quarter last year, consistent with the growth of EQT Production and EQT Midstream.
Results by Business
EQT Production
Driven by horizontal drilling in the Marcellus shale play, EQT Production achieved production sales volumes of 194.4 Bcfe for 2011, representing a 44.4% increase over 2010. Approximately 42.0% of EQT’s 2011 production sales volumes came from Marcellus wells, up from 18.9% last year. Production sales volumes totaled 53.0 Bcfe in the fourth quarter 2011, 37.0% higher than the fourth quarter 2010, and 3.4% higher sequentially. The 2012 production sales volume forecast was reduced by 5 Bcfe to reflect the decision to suspend drilling in the Huron play, in the current price environment. Production sales volumes in 2012 are now projected to be between 250 and 255 Bcfe, 30% higher than in 2011.
Production operating income totaled $387.1 million in 2011, $163.6 million higher than 2010. Operating revenue was $791.3 million, 47% higher than in 2010. Increased revenue and operating income resulted from the growth in produced natural gas sales, as well as a higher average wellhead sales price to EQT Production. The average wellhead sales price to EQT Corporation was $5.37 per Mcfe, with $4.04 per Mcfe allocated to EQT Production and $1.33 per Mcfe allocated to EQT Midstream.
EQT Corporation realized an average premium over the NYMEX natural gas price of $1.11 per Mcfe as a result of its liquids rich production. EQT Production‘s production sales volume consisted of approximately 7% NGLs and oil, excluding ethane.
Consistent with EQT Production’s growth, operating expenses rose to $404.2 million, a $90.0 million increase over 2010. DD&A was $73.4 million higher; LOE was $6.6 million higher; production taxes were $6.9 million higher; and SG&A was $3.5 million higher than 2010, primarily as a result of increases in produced volumes. Per unit LOE was 17% lower year-over-year at $0.20 per Mcfe, resulting from production sales volumes growing significantly faster than operating costs. LOE including production taxes totaled $0.40 per Mcfe.
Operating income for the fourth quarter of 2011 was $106.1 million, compared to $53.7 million in the same period last year. Production operating revenues for the quarter were $213.9 million, 50% higher, driven by a 37% increase in production sales volumes and a higher average wellhead sales price to EQT Production. Operating expenses for the quarter were $107.9 million, $19.1 million higher, consistent with the increase in produced volumes.
The company drilled (spud) 222 gross wells during 2011; 105 targeted the Marcellus play with an average length of pay of 4,730 feet; and 115 targeted the Huron play with an average length of pay of 4,750 feet. As detailed in a separate press release issued today, proved reserves increased by 145 Bcfe to 5.4 Tcfe for 2011, resulting in a reserve to production (R/P) ratio of 27 years.
EQT Midstream
EQT Midstream’s operating income totaled $416.6 million and included a $202.9 million gain on dispositions of Big Sandy and Langley; compared to operating income of $178.9 million in 2010. In addition to the gains on the dispositions, the company realized higher gathered volumes and an increase in firm transportation revenues. Net operating revenues for 2011 totaled $404.6 million, representing an $8.2 million increase over 2010. Net gathering revenues were $249.6 million in 2011, up 18% from 2010, as a result of a 32% increase in gathered volumes, partially offset by lower gathering rates. Net transmission revenues increased by $6.2 million to $90.4 million in 2011, mainly driven by increased capacity associated with the Equitrans Marcellus expansion project; partially offset by the absence of revenues from the recently sold Big Sandy pipeline. Net storage, marketing and other net revenues totaled $64.6 million in 2011, down 35% from 2010, as a result of lower marketed volumes and lower seasonal price spread, combined with the loss of processing revenues from the now sold Langley natural gas processing plant.
Operating expenses for 2011 totaled $190.9 million, down 12% from 2010. The decrease was mainly attributable to a $23.7 million decrease in O&M and a $4.7 million decrease in DD&A. The decreases in O&M and DD&A were primarily due to the absence of expenses associated with the Big Sandy and Langley assets and reductions to non-income tax reserves, offset by higher costs from the growth in the EQT Midstream business, including Marcellus compressor O&M and labor to operate the expanded gathering and transmission infrastructure. On a per unit basis, gathering and compression expenses were 19% lower than last year.
EQT Midstream had fourth quarter 2011 operating income of $53.1 million, a 9% increase over the same period in 2010. Net gathering revenues increased 13% to $66.1 million in the fourth quarter 2011, primarily as a result of a 30% increase in gathered volumes. Net transmission revenues totaled $21.1 million, a 16% decrease from the same quarter of 2010, mainly due to the sale of Big Sandy, partially offset by increased sales associated with the Equitrans Marcellus expansion project. Net storage, marketing and other revenues totaled $19.1 million, a 26% decrease from the fourth quarter 2010. Operating expenses for the quarter were $53.1 million, or 12% lower than in the fourth quarter of 2010, as a result of the absence of expenses to operate Big Sandy and Langley, partially offset by increases in growth-related operating expenses.
Distribution
Distribution’s operating income totaled $86.9 million in 2011, 4% higher than reported in 2010. Net operating revenues for the year were $187.6 million, essentially unchanged from 2010. Operating expenses for the year decreased to $100.7 million in 2011, from $104.2 million in 2010, resulting from lower bad debt expense.
Distribution’s fourth quarter 2011 operating income totaled $22.1 million, compared to $30.8 million for the same period in 2010. Total net operating revenues for the fourth quarter 2011 were $49.8 million, 13% lower than last year, primarily as a result of warmer weather.
Other Business
2011 Capital Expenditures
EQT invested $1,367 million in capital projects during 2011. This included $1,088 million for EQT Production, including $13 million for acreage acquisitions and $93 million for the ANPI transaction; $243 million for EQT Midstream; and $36 million for distribution infrastructure projects and other corporate items.
2012 Capital Expenditures Forecast
In response to lower natural gas prices, the company will suspend drilling Huron wells after the wells currently in progress are completed and turned in line. As a result, the company decreased its 2012 CAPEX forecast by $135 million to $1,465 million. Operating cash flow is now projected to be approximately $900 million in 2012, at current NYMEX natural gas prices.
Sale of Big Sandy Pipeline
On July 1, 2011, EQT completed the sale of its Big Sandy pipeline to Spectra Energy Partners, LP for $390.0 million. EQT recognized a pre-tax gain of $180.1 million on the transaction in the third quarter 2011.
Sale of Langley Natural Gas Processing Complex
On February 1, 2011, EQT completed the sale of its Langley natural gas processing complex to MarkWest Energy Partners, LP for $230.5 million. EQT realized a $22.8 million pre-tax gain on the transaction in the first quarter 2011.
ANPI Transaction
In May 2011, the company purchased all outstanding equity interests in the Appalachian Basin trust. The company recorded a $10.1 million non-cash gain as a result of the transaction in the second quarter 2011.
Hedging
EQT has hedged approximately 50% of its 2012 sales of produced natural gas, excluding liquids. The company had recently added to its hedge position for 2012 through 2016. The company’s total hedge positions for 2012 through 2014 production are:
| 2012 | 2013 | 2014 | ||||||||||||||
| Swaps | ||||||||||||||||
| Total Volume (Bcfe) | 101 | 70 | 42 | |||||||||||||
| Average Price per Mcf (NYMEX)* | $ | 5.20 | $ | 5.15 | $ | 4.82 | ||||||||||
| Collars | ||||||||||||||||
| Total Volume (Bcfe) | 21 | 15 | 14 | |||||||||||||
| Average Floor Price per Mcf (NYMEX)* | $ | 6.51 | $ | 6.12 | $ | 6.37 | ||||||||||
| Average Cap Price per Mcf (NYMEX)* | $ | 11.83 | $ | 11.80 | $ | 11.55 | ||||||||||
* 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. Interest, income taxes and unallocated (expense)/income are controlled on a consolidated, corporate-wide basis and are not allocated to the segments. The company’s management reviews and reports segment results for operating revenues and purchase gas costs net of third party transportation costs. For the year ended December 31, 2011, the company determined that consolidated results for these line items will be reported on a gross basis. The consolidated operating revenues, purchased gas costs and total operating expenses for all periods presented have been reclassified to conform to this gross presentation. This reclassification had no impact on consolidated net income, consolidated operating income or on the segment results for any period presented.
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
December 31, |
Year Ended
December 31, |
|||||||||||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||||
| Operating income (thousands): | ||||||||||||||||||||||||||||
| EQT Production | $ | 106,074 | $ | 53,690 | $ | 387,098 | $ | 223,487 | ||||||||||||||||||||
| EQT Midstream | 53,134 | 48,603 | 416,611 | 178,866 | ||||||||||||||||||||||||
| Distribution | 22,140 | 30,829 | 86,898 | 83,182 | ||||||||||||||||||||||||
| Unallocated (expense)/income | (8,595 | ) | 1,533 | (29,288 | ) | (15,056 | ) | |||||||||||||||||||||
| Operating income | $ | 172,753 | $ | 134,655 | $ | 861,319 | $ | 470,479 | ||||||||||||||||||||
Unallocated (expense)/income is primarily due to certain incentive compensation and administrative costs in excess of budget that are not allocated to the operating segments.
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 prices for the three and twelve months ended December 31, 2011 and 2010 were as follows:
|
Three Months Ended
December 31, |
Year Ended
December 31, |
|||||||||||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||||
| Revenues ($ / Mcfe) | ||||||||||||||||||||||||||||
| Average NYMEX price | $ | 3.55 | $ | 3.80 | $ | 4.04 | $ | 4.39 | ||||||||||||||||||||
| Hedge impact | 0.77 | 0.65 | 0.52 | 0.50 | ||||||||||||||||||||||||
| Average basis | 0.06 | 0.12 | 0.13 | 0.13 | ||||||||||||||||||||||||
| Average net liquids revenue | 1.13 | 1.11 | 1.11 | 1.02 | ||||||||||||||||||||||||
| Hedge adjusted price | $ | 5.51 | $ | 5.68 | $ | 5.80 | $ | 6.04 | ||||||||||||||||||||
| Midstream Revenue Deductions ($ / Mcfe) | ||||||||||||||||||||||||||||
| Gathering to EQT Midstream | $ | (1.07 | ) | $ | (1.34 | ) | $ | (1.11 | ) | $ | (1.32 | ) | ||||||||||||||||
| Transmission and processing to EQT Midstream | (0.14 | ) | (0.33 | ) | (0.22 | ) | (0.37 | ) | ||||||||||||||||||||
| Third party gathering, processing and transmission | (0.29 | ) | (0.39 | ) | (0.43 | ) | (0.42 | ) | ||||||||||||||||||||
| Total midstream revenue deductions | (1.50 | ) | $ | (2.06 | ) | $ | (1.76 | ) | $ | (2.11 | ) | |||||||||||||||||
| Average wellhead sales price to EQT Production | $ | 4.01 | $ | 3.62 | $ | 4.04 | $ | 3.93 | ||||||||||||||||||||
| EQT Revenue ($ / Mcfe) | ||||||||||||||||||||||||||||
| Revenues to EQT Midstream | $ | 1.21 | $ | 1.67 | $ | 1.33 | $ | 1.69 | ||||||||||||||||||||
| Revenues to EQT Production | 4.01 | 3.62 | 4.04 | 3.93 | ||||||||||||||||||||||||
| Average wellhead sales price to EQT Corporation | $ | 5.22 | $ | 5.29 | $ | 5.37 | $ | 5.62 | ||||||||||||||||||||
Third party gathering, processing and transmission rates were reduced by $0.12 per Mcfe for the fourth quarter and by $0.03 per Mcfe for the full year, resulting from the sale of unused capacity on the El Paso 300 line not under long-term resale agreements.
Unit Costs
EQT’s unit costs to produce, gather, process and transport EQT's produced natural gas were:
|
Three Months Ended
December 31, |
Year Ended
December 31, |
|||||||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||
| Production segment costs: ($ / Mcfe) | ||||||||||||||||||||||||
| LOE | $ | 0.20 | $ | 0.25 | $ | 0.20 | $ | 0.24 | ||||||||||||||||
| Production taxes | 0.18 | 0.22 | 0.20 | 0.24 | ||||||||||||||||||||
| SG&A | 0.29 | 0.40 | 0.31 | 0.41 | ||||||||||||||||||||
| $ | 0.67 | $ | 0.87 | $ | 0.71 | $ | 0.89 | |||||||||||||||||
| Midstream segment costs: ($ / Mcfe) | ||||||||||||||||||||||||
| Gathering, transmission and processing | $ | 0.40 | $ | 0.54 | $ | 0.37 | $ | 0.53 | ||||||||||||||||
| SG&A | 0.19 | 0.22 | 0.17 | 0.19 | ||||||||||||||||||||
| $ | 0.59 | $ | 0.76 | $ | 0.54 | $ | 0.72 | |||||||||||||||||
| Total ($ / Mcfe) | $ | 1.26 | $ | 1.63 | $ | 1.25 | $ | 1.61 | ||||||||||||||||
Marcellus Horizontal Well Status (cumulatively since inception)
|
As of |
As of |
As of |
As of |
As of |
|||||||||||||||||
| Wells spud | 248 | 230 | 194 | 166 | 143 | ||||||||||||||||
| Wells online | 159 | 137 | 119 | 86 | 66 | ||||||||||||||||
| Wells complete, not online | 22 | 4 | 5 | 8 | 17 | ||||||||||||||||
| Frac stages (spud wells)* | 3,796 | 3,530 | 2,809 | 2,387 | 1,940 | ||||||||||||||||
| Frac stages online | 2,171 | 1,873 | 1,578 | 1,047 | 773 | ||||||||||||||||
| Frac stages complete, not online | 331 | 65 | 74 | 127 | 241 |
*Includes planned stages for spud wells that have not yet been frac’d.
Non-GAAP Disclosures
Adjusted Net Income and Adjusted Earnings Per Diluted Share
The results for 2011 were impacted by gains on the sales of Big Sandy and Langley, a gain on the ANPI transaction, adjustments to non-income tax reserves and $8.5 million of gains on sales of available-for-sale securities during the year. Adjusted net income and adjusted earnings per diluted share, which exclude these items, are presented because they are important measures used by management to evaluate period-to-period comparisons of earnings trends.
| Year Ended | |||||||
| December 31, | |||||||
| 2011 | |||||||
| Net income as reported | $ | 479,769 | |||||
| (Deduct) / add back: | |||||||
| Gain on dispositions | (202,928 | ) | |||||
| Adjustments to non-income tax reserves | (13,300 | ) | |||||
| Gain on ANPI Transaction | (10,129 | ) | |||||
| Gain on sale of available-for-sale securities | (8,474 | ) | |||||
| Tax impact at 36.8% | $ | 86,418 | |||||
| Adjusted net income | $ | 331,356 | |||||
| Diluted weighted average common shares outstanding | 150,209 | ||||||
| Diluted EPS, as adjusted | $ | 2.21 | |||||
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 dispositions 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 tax gains in 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 statement of cash flows to be included in the company’s annual report on Form 10-K for the years ended December 31, 2011 and 2010.
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December 31, |
Year Ended
December 31, |
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| (thousands) | 2011 | 2010 | 2011 | 2010 | ||||||||||||||||||||||||
| Net income | $ | 90,846 | $ | 73,113 | $ | 479,769 | $ | 227,700 | ||||||||||||||||||||
| Add back (deduct): | ||||||||||||||||||||||||||||
| Deferred income taxes | 43,689 | 54,707 | 234,019 | 153,912 | ||||||||||||||||||||||||
|
Depreciation, depletion, and |
91,670 | 74,641 | 339,297 | 270,285 | ||||||||||||||||||||||||
|
Gain on disposition, net of current taxes |
11,994 | – | (154,663 | ) | – | |||||||||||||||||||||||
| Other items, net | 4,434 | (8,143 | ) | (12,477 | ) | (2,760 | ) | |||||||||||||||||||||
| Operating cash flow | $ | 242,633 | $ | 194,318 | $ | 885,945 | $ | 649,137 | ||||||||||||||||||||
| Add back (deduct): | ||||||||||||||||||||||||||||
|
Changes in operating assets and |
$ | (52,210 | ) | $ | (25,625 | ) | $ | 54,084 | $ | 140,603 | ||||||||||||||||||
| Current taxes on disposition | (11,994 | ) | – | (48,265 | ) | – | ||||||||||||||||||||||
|
Net cash provided by operating |
$ | 178,429 | $ | 168,693 | $ | 891,764 | $ | 789,740 | ||||||||||||||||||||
Adjusted Cash Flow Per Share
Adjusted cash flow per share is presented because it is a capital efficiency metric used by the investors and analysts to evaluate oil and gas companies. Adjusted cash flow per share is not a measure of financial performance under GAAP and should not be considered as an alternative to net cash provided by operating activities or net income per share, both as defined by GAAP, or as a measure of liquidity.
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Three Months Ended
December 31, |
Year Ended
December 31, |
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| (thousands) | 2011 | 2010 | 2011 | 2010 | ||||||||||||||||||||
|
Operating cash flow (a non-GAAP |
$ | 242,633 | $ | 194,318 | $ | 885,945 | $ | 649,137 | ||||||||||||||||
| Add back: | ||||||||||||||||||||||||
| Exploration expense | 1,545 | 2,014 | 4,932 | 5,368 | ||||||||||||||||||||
|
Operating cash flow and exploration |
$ | 244,178 | $ | 196,332 | $ | 890,877 | $ | 654,505 | ||||||||||||||||
|
Diluted weighted average common |
150,378 | 149,935 | 150,209 | 145,232 | ||||||||||||||||||||
|
Adjusted cash flow per share |
$ | 1.62 | $ | 1.31 | $ | 5.93 | $ | 4.51 | ||||||||||||||||
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.
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Year Ended
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| (thousands) | 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||
| Net operating revenues | $ | 369,946 | $ | 308,790 | $ | 1,383,467 | $ | 1,121,511 | |||||||||||||||
| Plus: purchased gas cost | 128,597 | 114,115 | 256,467 | 252,884 | |||||||||||||||||||
| Operating revenues | $ | 498,543 | $ | 422,905 | $ | 1,639,934 | $ | 1,374,395 | |||||||||||||||
| Net operating expenses | $ | 197,193 | $ | 174,135 | $ | 725,076 | $ | 651,032 | |||||||||||||||
| Plus: purchased gas cost | 128,597 | 114,115 | 256,467 | 252,884 | |||||||||||||||||||
| Total operating expenses | $ | 325,790 | $ | 288,250 | $ | 981,543 | $ | 903,916 | |||||||||||||||
EQT's conference call with securities analysts, which begins at 10:30 a.m. Eastern Time today will cover 2011 year-end financials and operational and other matters and 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 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, 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 production or 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, 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 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 program (including the number, type, feet of pay and location of wells to be drilled) and infrastructure program (including the Equitrans Marcellus expansion project and gathering expansion projects); transactions, including asset sales, joint ventures or other transactions involving the company’s assets; total resource potential, reserves, EUR, expected decline curve, reserve replacement ratio and production and sales volumes and growth rate; internal rate of return (IRR); F&D costs, operating costs, unit costs, well costs and EQT Midstream costs; capital expenditures, capital budget and sources of funds for capital expenditures; financing plans 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 and in the company’s Form 10-K for the year ended December 31, 2011 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, 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 | |||||||||||||||||||||||||
| Three Months Ended | Twelve Months Ended | ||||||||||||||||||||||||
| December 31, | December 31, | ||||||||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | ||||||||||||||||||||||
| OPERATIONAL DATA | |||||||||||||||||||||||||
| Average wellhead sales price to EQT Corporation: | |||||||||||||||||||||||||
| Natural gas excluding hedges ($/Mcf) | $ | 3.77 |
$ |
|
3.86 |
$ |
4.21 |
$ | 4.44 | ||||||||||||||||
| Hedge impact ($/Mcf of natural gas) (a) | $ | 0.83 |
$ |
|
0.70 |
$ |
0.55 |
$ | 0.55 | ||||||||||||||||
| Natural gas including hedges ($/Mcf) | $ | 4.60 |
$ |
|
4.56 |
$ |
4.76 |
$ | 4.99 | ||||||||||||||||
| NGLs ($/Bbl) | $ | 53.77 |
$ |
|
54.39 |
$ |
52.56 |
$ | 48.76 | ||||||||||||||||
| Crude oil ($/Bbl) | $ | 77.48 |
$ |
|
69.91 |
$ |
81.58 |
$ | 70.23 | ||||||||||||||||
| Total ($/Mcfe) | $ | 5.22 |
$ |
|
5.29 |
$ |
5.37 |
$ | 5.62 | ||||||||||||||||
| $/Mcfe: | |||||||||||||||||||||||||
| Less revenues to EQT Midstream | $ | 1.21 |
$ |
|
1.67 |
$ |
1.33 |
$ | 1.69 | ||||||||||||||||
| Average wellhead sales price to EQT Production | $ | 4.01 |
$ |
|
3.62 |
$ |
4.04 |
$ | 3.93 | ||||||||||||||||
| NYMEX natural gas ($/Mcf) | $ | 3.55 |
$ |
|
3.80 |
$ |
4.04 |
$ | 4.39 | ||||||||||||||||
| Natural gas sales volumes (MMcf) | 49,531 | 35,695 | 181,566 | 123,440 | |||||||||||||||||||||
| NGL sales volumes (MBbls) | 817 | 730 | 3,076 | 2,712 | |||||||||||||||||||||
| Crude oil sales volumes (MBbls) | 67 | 34 | 208 | 120 | |||||||||||||||||||||
| Total production sales volumes (MMcfe) (b) | 53,018 | 38,711 | 194,393 | 134,614 | |||||||||||||||||||||
| Capital expenditures (thousands) (c) | $ | 381,723 |
$ |
|
383,921 |
$ |
1,366,894 |
$ | 1,477,619 | ||||||||||||||||
| STATEMENTS OF CONSOLIDATED INCOME (UNAUDITED) | |||||||||||||||||||||||||
| (Thousands, except per share amounts) | |||||||||||||||||||||||||
| Operating revenues | $ | 498,543 |
$ |
422,905 |
$ |
1,639,934 |
$ | 1,374,395 | |||||||||||||||||
| Operating expenses: | |||||||||||||||||||||||||
| Purchased gas costs | 128,597 | 114,115 | 256,467 | 252,884 | |||||||||||||||||||||
| Operation and maintenance | 36,129 | 41,639 | 127,642 | 152,414 | |||||||||||||||||||||
| Production | 20,127 | 18,251 | 80,911 | 67,414 | |||||||||||||||||||||
| Exploration | 1,545 | 2,014 | 4,932 | 5,368 | |||||||||||||||||||||
| Selling, general and administrative | 47,722 | 37,590 | 172,294 | 155,551 | |||||||||||||||||||||
| Depreciation, depletion and amortization | 91,670 | 74,641 | 339,297 | 270,285 | |||||||||||||||||||||
| Total operating expenses | 325,790 | 288,250 | 981,543 | 903,916 | |||||||||||||||||||||
| Gain on dispositions | - | - | 202,928 | - | |||||||||||||||||||||
| Operating income | 172,753 | 134,655 | 861,319 | 470,479 | |||||||||||||||||||||
| Other income | 6,190 | 4,347 | 34,138 | 12,898 | |||||||||||||||||||||
| Interest expense | 37,686 | 26,082 | 136,328 | 128,157 | |||||||||||||||||||||
| Income before income taxes | 141,257 | 112,920 | 759,129 | 355,220 | |||||||||||||||||||||
| Income taxes | 50,411 | 39,807 | 279,360 | 127,520 | |||||||||||||||||||||
| Net income | $ | 90,846 |
$ |
73,113 |
$ |
479,769 |
$ | 227,700 | |||||||||||||||||
| Earnings per share of common stock: | |||||||||||||||||||||||||
| Basic: | |||||||||||||||||||||||||
| Weighted average common shares outstanding | 149,450 | 149,152 | 149,392 | 144,458 | |||||||||||||||||||||
| Net income | $ | 0.61 |
$ |
0.49 |
$ |
3.21 |
$ | 1.58 | |||||||||||||||||
| Diluted: | |||||||||||||||||||||||||
| Weighted average common shares outstanding | 150,378 | 149,935 | 150,209 | 145,232 | |||||||||||||||||||||
| Net income | $ | 0.60 |
$ |
0.49 |
$ |
3.19 |
$ | 1.57 | |||||||||||||||||
| (a) | All hedges are related to natural gas. | |
| (b) | NGLs were converted to Mcfe at a rate of 3.78 Mcfe per barrel and 3.86 Mcfe per barrel for the three months ended December 31, 2011 and 2010, respectively, and a rate of 3.76 Mcfe per barrel and 3.86 Mcfe per barrel for the twelve months ended December 31, 2011 and 2010, respectively, based on the liquids content, 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 in the second quarter of 2011 and $230.7 million of undeveloped property which was acquired with EQT common stock in 2010. |
|
EQT PRODUCTION RESULTS OF OPERATIONS |
|||||||||||||||||||||||||||
| Three Months Ended | Twelve Months Ended | ||||||||||||||||||||||||||
| December 31, | December 31, | ||||||||||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | ||||||||||||||||||||||||
| OPERATIONAL DATA | |||||||||||||||||||||||||||
|
Natural gas, NGL and crude oil production |
53,800 | 39,501 | 198,821 | 139,021 | |||||||||||||||||||||||
| Company usage, line loss (MMcfe) | (782 | ) | (790 | ) | (4,428 | ) | (4,407 | ) | |||||||||||||||||||
| Total production sales volumes (MMcfe) | 53,018 | 38,711 | 194,393 | 134,614 | |||||||||||||||||||||||
| Average daily sales volumes (MMcfe/d) | 576 | 421 | 533 | 369 | |||||||||||||||||||||||
| Sales volume detail (MMcfe): | |||||||||||||||||||||||||||
| Horizontal Marcellus Play | 24,706 | 10,340 | 81,602 | 25,474 | |||||||||||||||||||||||
| Horizontal Huron Play | 9,906 | 10,741 | 40,081 | 38,816 | |||||||||||||||||||||||
| CBM Play | 3,428 | 3,486 | 13,682 | 13,493 | |||||||||||||||||||||||
| Other (vertical non-CBM) | 14,978 | 14,144 | 59,028 | 56,831 | |||||||||||||||||||||||
| Total production sales volumes | 53,018 | 38,711 | 194,393 | 134,614 | |||||||||||||||||||||||
| Average wellhead sales price ($/Mcfe) | $ | 4.01 | $ | 3.62 |
$ |
4.04 |
$ | 3.93 | |||||||||||||||||||
|
Lease operating expenses, excluding
|
$ | 0.20 | $ | 0.25 |
$ |
0.20 |
$ | 0.24 | |||||||||||||||||||
| Production taxes ($/Mcfe) | $ | 0.18 | $ | 0.22 |
$ |
0.20 |
$ | 0.24 | |||||||||||||||||||
| Production depletion ($/Mcfe) | $ | 1.27 | $ | 1.28 |
$ |
1.25 |
$ | 1.26 | |||||||||||||||||||
|
Depreciation, depletion and amortization |
|||||||||||||||||||||||||||
| Production depletion | $ | 68,223 | $ | 50,516 |
$ |
248,286 |
$ | 175,629 | |||||||||||||||||||
| Other DD&A | 2,241 | 2,147 | 8,858 | 8,070 | |||||||||||||||||||||||
| Total DD&A | $ | 70,464 | $ | 52,663 |
$ |
257,144 |
$ | 183,699 | |||||||||||||||||||
| Capital expenditures (thousands) (b) | $ | 287,811 | $ | 316,689 |
$ |
1,087,840 |
$ | 1,245,914 | |||||||||||||||||||
| FINANCIAL DATA (Thousands) | |||||||||||||||||||||||||||
| Total operating revenues | $ | 213,933 | $ | 142,475 |
$ |
791,285 |
$ | 537,657 | |||||||||||||||||||
| Operating expenses: | |||||||||||||||||||||||||||
| LOE | 10,609 | 9,728 | 40,369 | 33,784 | |||||||||||||||||||||||
| Production taxes (c) | 9,519 | 8,523 | 40,543 | 33,630 | |||||||||||||||||||||||
| Exploration expense | 1,545 | 2,014 | 4,932 | 5,368 | |||||||||||||||||||||||
|
Selling, general and administrative (SG&A) |
15,722 | 15,857 | 61,199 | 57,689 | |||||||||||||||||||||||
| DD&A | 70,464 | 52,663 | 257,144 | 183,699 | |||||||||||||||||||||||
| Total operating expenses | 107,859 | 88,785 | 404,187 | 314,170 | |||||||||||||||||||||||
| Operating income | $ | 106,074 | $ | 53,690 |
$ |
387,098 |
$ | 223,487 | |||||||||||||||||||
| (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 $230.7 million of undeveloped property which was acquired with EQT common stock in 2010. | |
| (c) | Production taxes include severance and production-related ad valorem and other property taxes. |
| EQT MIDSTREAM | |||||||||||||||
| RESULTS OF OPERATIONS | |||||||||||||||
| Three Months Ended | Twelve Months Ended | ||||||||||||||
| December 31, | December 31, | ||||||||||||||
| 2011 | 2010 | 2011 | 2010 | ||||||||||||
| OPERATIONAL DATA | |||||||||||||||
| Gathered volumes (BBtu) | 69,687 | 53,568 | 258,179 | 195,642 | |||||||||||
| Average gathering fee ($/MMBtu) | $ | 0.95 | $ | 1.09 | $ | 0.97 | $ | 1.11 | |||||||
| Gathering and compression expense ($/MMBtu) (a) | $ | 0.33 | $ | 0.34 | $ | 0.30 | $ | 0.37 | |||||||
| Transmission pipeline throughput (BBtu) | 42,262 | 32,969 | 159,384 | 109,165 | |||||||||||
| Net operating revenues (thousands): | |||||||||||||||
| Gathering | $ | 66,084 | $ | 58,393 | $ | 249,607 | $ | 212,170 | |||||||
| Transmission | 21,111 | 25,133 | 90,405 | 84,190 | |||||||||||
| Storage, marketing and other | 19,067 | 25,674 | 64,614 | 100,097 | |||||||||||
| Total net operating revenues | $ | 106,262 | $ | 109,200 | $ | 404,626 | $ | 396,457 | |||||||
|
Unrealized (losses) gains on derivatives and
and inventory (thousands) (b) |
$ | (2,605 | ) | $ | 415 | $ | (755 | ) | $ | (379 | ) | ||||
| Capital expenditures (thousands) | $ | 86,054 | $ | 54,649 | $ | 242,886 | $ | 193,128 | |||||||
| FINANCIAL DATA (Thousands) | |||||||||||||||
| Total operating revenues | $ | 129,868 | $ | 144,473 | $ | 525,345 | $ | 580,698 | |||||||
| Purchased gas costs | 23,606 | 35,273 | 120,719 | 184,241 | |||||||||||
| Total net operating revenues | 106,262 | 109,200 | 404,626 | 396,457 | |||||||||||
| Operating expenses: | |||||||||||||||
| Operating and maintenance (O&M) | 24,199 | 30,226 | 83,907 | 107,601 | |||||||||||
| SG&A | 14,891 | 14,748 | 49,901 | 48,127 | |||||||||||
| DD&A | 14,038 | 15,623 | 57,135 | 61,863 | |||||||||||
| Total operating expenses | 53,128 | 60,597 | 190,943 | 217,591 | |||||||||||
| Gain on dispositions | - | - | 202,928 | - | |||||||||||
| Operating income | $ | 53,134 | $ | 48,603 | $ | 416,611 | $ | 178,866 | |||||||
| (a) | Gathering and compression expense for the full year 2011 excludes $7.1 million of favorable adjustments to certain | |
| non-income tax reserves. | ||
| (b) | Included within storage, marketing and other net operating revenues. |
| DISTRIBUTION | ||||||||||||
| RESULTS OF OPERATIONS | ||||||||||||
| Three Months Ended | Twelve Months Ended | |||||||||||
| December 31, | December 31, | |||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||
| OPERATIONAL DATA | ||||||||||||
|
Heating degree days (30 year average: |
1,681 | 2,166 | 5,189 | 5,516 | ||||||||
|
Residential sales and transportation |
6,440 |
7,898 |
22,333 |
23,132 |
||||||||
| Commercial and industrial volumes (MMcf) | 7,612 | 6,304 | 28,752 | 27,124 | ||||||||
| Total throughput (MMcf) – Distribution | 14,052 | 14,202 | 51,085 | 50,256 | ||||||||
|
Net operating revenues (thousands): |
||||||||||||
| Residential | $ | 32,176 | $ | 36,813 | $ | 115,912 | $ | 117,418 | ||||
| Commercial & industrial | 13,009 | 14,752 | 48,968 | 48,614 | ||||||||
| Off-system and energy services | 4,565 | 5,549 | 22,672 | 21,365 | ||||||||
| Total net operating revenues | $ | 49,750 | $ | 57,114 | $ | 187,552 | $ | 187,397 | ||||
| Capital expenditures (thousands) | $ | 6,134 | $ | 15,512 | $ | 31,313 | $ | 36,619 | ||||
|
FINANCIAL DATA (Thousands) |
||||||||||||
| Total operating revenues | $ | 106,312 | $ | 135,331 | $ | 419,678 | $ | 474,143 | ||||
| Purchased gas costs | 56,562 | 78,217 | 232,126 | 286,746 | ||||||||
| Net operating revenues | 49,750 | 57,114 | 187,552 | 187,397 | ||||||||
| Operating expenses: | ||||||||||||
| O&M | 11,917 | 11,440 | 43,383 | 44,047 | ||||||||
| SG&A | 8,360 | 8,738 | 31,524 | 35,994 | ||||||||
| DD&A | 7,333 | 6,107 | 25,747 | 24,174 | ||||||||
| Total operating expenses | 27,610 | 26,285 | 100,654 | 104,215 | ||||||||
| Operating income | $ | 22,140 | $ | 30,829 | $ | 86,898 | $ |
83,182 |
||||