FORT WORTH, Texas--(BUSINESS WIRE)--Approach Resources Inc. (NASDAQ: AREX) today reported financial and operating results for the second quarter of 2011. Highlights for second quarter 2011, compared to second quarter 2010, include:
- Total production increased 63% to 608 MBoe (6.7 MBoe/d)
- Oil and NGL production increased 203% to 340 MBbls
- Revenues increased 121% to $29.1 million
- Net income increased 415% to $8 million, or $0.28 per diluted share
- Adjusted net income (non-GAAP) increased 132% to $6.5 million, or $0.23 per diluted share
- EBITDAX (non-GAAP) increased 103% to $21 million, or $0.73 per diluted share
Approach also provided an update on proved reserves and operations. Highlights include:
- Proved reserves increased 32% to 66.8 MMBoe
- Oil and NGL reserves increased 44% to 36.9 MMBbls
- PV-10 (non-GAAP) increased 60% to $521.2 million
- University 45 A 701H well produced at an initial rate of 693 Boe/d
- Cinco Terry G 701H well produced at an initial rate of 328 Boe/d
Production for second quarter 2011 totaled 608 MBoe (6.7 MBoe/d), compared to 372 MBoe (4.1 MBoe/d) in second quarter 2010, a 63% increase over the prior year period. Oil and NGL production for second quarter 2011 increased 203% to 340 MBbls, compared to 112 MBbls produced in second quarter 2010. Compared to first quarter 2011, total production increased 30% and oil and NGL production increased 76%. Production for second quarter 2011 was 56% oil and NGLs and 44% natural gas, compared to 30% oil and NGLs and 70% natural gas in second quarter 2010. Oil and NGL production increased during second quarter 2011 due to continued development of the Wolffork oil shale resource play, the acquisition of additional working interest in northwest Project Pangea in first quarter 2011 and processing gas in the southeast portion of Project Pangea, which began on April 1, 2011.
Management Comment
J. Ross Craft, Approach President and CEO, commented “Oil and NGLs dominated our production mix in second quarter 2011 for the first time in Company history. The benefit of this shift is reflected in our increase in revenues, EBITDAX and net income. We also continued to make progress with our horizontal Wolfcamp pilot program, and I am encouraged by the results from our third and forth horizontal Wolfcamp wells. With our strong performance in the first half of 2011, I believe we are well positioned to continue delivering growth in the second half of the year and beyond.”
Second Quarter 2011 Financial Results
Net income for second quarter 2011 was $8 million, or $0.28 per diluted share, on revenues of $29.1 million. This compares to net income for second quarter 2010 of $1.6 million, or $0.07 per diluted share, on revenues of $13.2 million, which included a $1.9 million unrealized loss on commodity derivatives. The $16 million increase in revenues in the second quarter of 2011 was attributable to an increase in oil and NGL production volumes ($14.4 million) and an increase in oil and NGL prices ($1.6 million).
Second quarter 2011 net income included an unrealized gain on commodity derivatives of $2.2 million. Excluding the unrealized gain on commodity derivatives and related income taxes, adjusted net income (non-GAAP) for second quarter 2011 was $6.5 million, or $0.23 per diluted share, compared to $2.8 million, or $0.13 per diluted share, for second quarter 2010. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net income to net income.
EBITDAX (non-GAAP) for second quarter 2011 was $21 million, or $0.73 per diluted share, compared to $10.3 million, or $0.49 per diluted share, for second quarter 2010. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of EBITDAX to net income.
Average realized prices for second quarter 2011, before the effect of commodity derivatives, were $97.89 per Bbl of oil, $51.88 per Bbl of NGLs and $4.16 per Mcf of natural gas, compared to $73.26 per Bbl of oil, $40.33 per Bbl of NGLs and $4.41 per Mcf of natural gas, for second quarter 2010. Our average realized price, including the effect of commodity derivatives, was $48.01 per Boe for second quarter 2011, compared to $40.11 per Boe for second quarter 2010.
Lease operating expense (“LOE”) for second quarter 2011 was $3.6 million, or $5.93 per Boe, compared to $2.2 million, or $5.93 per Boe, in second quarter 2010. The increase in total LOE was primarily attributable to the increase in working interest in northwest Project Pangea. In February 2011, we acquired the remaining 38% working interest in northwest Project Pangea, which increased our working interest to approximately 100%. We also experienced an increase in repair and maintenance expenses as well as increased service costs.
Severance and production taxes for second quarter 2011 were $1.7 million, or $2.80 per Boe, compared to $610,000, or $1.64 per Boe, in second quarter 2010. Severance and production taxes were approximately 5.8% and 4.6% of oil, NGL and gas sales for second quarter 2011 and 2010, respectively. The increase in severance and production taxes was primarily due to the increase in oil, NGL and gas sales over second quarter 2010.
Exploration expense for second quarter 2011 was $280,000, or $0.46 per Boe, compared to $187,000, or $0.50 per Boe, in second quarter 2010. We expect exploration expense to be $4.00 per Boe - $5.00 per Boe through the remainder of 2011.
General and administrative expense (“G&A”) for second quarter 2011 was $4.6 million, or $7.55 per Boe, compared to $2.2 million, or $5.87 per Boe, for second quarter 2010. The increase in G&A was primarily due to higher share-based compensation, salaries and benefits and professional fees.
Depletion, depreciation and amortization expense (“DD&A”) for second quarter 2011 was $8 million, or $13.14 per Boe, compared to $5 million, or $13.47 per Boe, for second quarter 2010. The decrease in DD&A per Boe was primarily attributable to an increase in estimated proved developed reserves, partially offset by an increase in production and capitalized costs over second quarter 2010.
Operations Update
During the second quarter of 2011, we drilled a total of 15 wells, completed 16 wells and recompleted three wells. During the six months ended June 30, 2011, we drilled 32 gross (28.2 net) wells, completed 32 gross (26.7 net) wells and recompleted four gross (four net) wells. At June 30, 2011, we had five wells waiting on completion. Exploration and development drilling expenditures totaled $44.8 million for the second quarter of 2011, and $77 million for the first half of 2011.
Approach currently has two vertical rigs and one horizontal rig running in the Southern Midland Basin. The Company has entered into an 18-month contract for a dedicated, third-party fracture stimulation fleet. Approach will have a 24-hour crew for a minimum of ten days per month.
Horizontal Wolfcamp Oil Shale Program
During the second quarter of 2011, we completed two horizontal wells targeting the Wolfcamp oil shale. Our fourth horizontal pilot well, the University 45 A 701H, a 6,859-foot lateral, was completed with a 21-stage fracture stimulation. The University 45 A 701H flowed at an initial 24-hour rate of 693 Boe/d, consisting of 613 Bbls of oil (“BO”), 41 Bbls of NGLs and 237 Mcf of gas.
Our third horizontal well, the Cinco Terry G 701H, a 7,609-foot lateral, was completed with a 23-stage fracture stimulation. The Cinco Terry G 701H flowed at an initial 24-hour rate of 328 Boe/d, consisting of 168 BO, 81 Bbls of NGLs and 473 Mcf of gas.
We plan to complete our fifth and sixth horizontal wells targeting the Wolfcamp oil shale in mid-August 2011. The University 45 D 901H and University 45 D 902H were drilled to a total lateral length of 7,614 feet and 7,770 feet, respectively. Our seventh horizontal well, the University 45 C 803H, a 7,358-foot lateral, is waiting on completion, and we currently are drilling the University 45 B 240 1H, our eighth horizontal well.
Proved Reserves Update
Mid-year 2011 estimated proved reserves totaled 66.8 MMBoe, an increase of 32% compared to year-end 2010 proved reserves of 50.7 MMBoe. Approach’s mid-year 2011 proved reserves are 55% oil and NGLs, 45% natural gas and 50% proved developed. At June 30, 2011, 97% of our proved reserves were located in our core operating area in the Permian Basin. Mid-year 2011 proved reserves included 8.4 MMBoe attributable to our emerging Wolffork oil shale resource play.
The following table is a reconciliation of the changes in our proved reserves between December 31, 2010, and June 30, 2011.
|
Oil
(MBbl) |
NGLs
(MBbl) |
Natural Gas |
Total
(MBoe) |
|||||||||
| Balance – December 31, 2010 | 4,951 | 20,699 | 150,389 | 50,715 | ||||||||
| Extensions and discoveries | 3,164 | 3,005 | 16,448 | 8,910 | ||||||||
| Purchases of minerals in place | 2,200 | 4,283 | 24,083 | 10,497 | ||||||||
| Production | (193 | ) | (341 | ) | (3,260 | ) | (1,077 | ) | ||||
| Revisions to previous estimates | ||||||||||||
| Price-related revisions | 17 | 130 | 766 | 275 | ||||||||
| Performance-related revisions |
(12 |
) | (986 | ) | (8,837 | ) | (2,471 | ) | ||||
| Balance – June 30, 2011 | 10,127 | 26,790 | 179,589 | 66,849 | ||||||||
| Proved developed reserves at June 30, 2011 | 4,418 | 14,202 | 89,355 | 33,512 |
The standardized after-tax measure of discounted future net cash flows (the “Standardized Measure”) for our proved reserves at June 30, 2011, was $328.7 million. The pre-tax present value of our proved reserves discounted at 10% (“PV-10”), was estimated at $521.2 million. For the six months ended June 30, 2011, we engaged DeGolyer and MacNaughton, independent, third-party reserves engineers, to prepare independent estimates of our proved reserves. Estimates of the PV-10 of our proved reserves were prepared by the Company’s internal reservoir engineers. Proved reserves volumes and PV-10 were prepared using $85.92 per Bbl of oil, $44.96 per Bbl of NGLs and $3.98 per Mcf of natural gas, and. See “Supplemental Non-GAAP Measures” below for our definition of PV-10 and a reconciliation to the Standardized Measure.
Finding and Development Costs
Preliminary, unaudited estimates of costs incurred during the first six months of 2011 totaled $162.7 million, and included $77 million for exploration and development drilling, $70.2 million for the purchase of additional working interest in the northwest area of Project Pangea and $15.5 million for acreage acquisitions. Based on total costs incurred at June 30, 2011, of $162.7 million and net proved reserve additions of 17.2 MMBoe, all-in finding and development (“F&D”) costs were $9.45 per Boe. Based on exploration and development costs incurred at June 30, 2011, of $77 million and proved reserve extensions and discoveries of 8.9 MMBoe, drill-bit F&D costs were $8.64 per Boe. F&D cost is a non-GAAP measure. See “Supplemental Non-GAAP Measures” below for our definition of F&D costs and reconciliation to the information required by ASC 932-235.
Financial Update
At June 30, 2011, we had a $300 million revolving credit agreement with a $200 million borrowing base and $93.6 million outstanding. Our liquidity at June 30, 2011, was $106.9 million. See “Supplemental Non-GAAP Financial and Other Measures” below for our calculation of “liquidity.”
We believe we have adequate liquidity from cash generated from operations and unused borrowing capacity under our revolving credit facility for current working capital needs and maintenance of our current drilling program. However, we may determine to access the public or private equity or debt markets for future development of reserves, acquisitions, expansion of our current drilling program, additional working capital or other liquidity needs, if such financing is available on acceptable terms. We cannot guarantee that financing will be available on acceptable terms, or at all.
Commodity Derivatives Positions
The following table sets forth our commodity derivative volumes and prices as of June 30, 2011.
| Period | Contract Type | Volume Transacted | Contract Price | |||
| Natural Gas | ||||||
| 2011 | Swap | 230,000 MMBtu/month | $4.86 | |||
| June 2011 – December 2011 | Swap | 200,000 MMBtu/month | $4.74 | |||
| 2012 | Call | 230,000 MMBtu/month | $6.00 | |||
| Natural Gas – Basis Differential | ||||||
| 2011 | Swap | 300,000 MMBtu/month | $(0.53) | |||
| Crude Oil | ||||||
| May 2011 – December 2011 | Collar | 1,000 Bbls/day | $100.00 - $127.00 |
2011 Capital Program and Guidance
Total capital expenditures are expected to be approximately $220 million, with approximately $130 million allocated to drilling and recompletion projects in the Permian Basin and approximately $90 million allocated to the acquisition of the remaining 38% working interest in northwest Project Pangea, lease extensions, renewals and acquisitions in the Permian Basin and the acquisition of 3-D seismic in the Permian Basin.
Our 2011 capital budget is subject to change depending upon a number of factors, including additional data on our Wolffork oil shale resource play, results of Wolfcamp Shale and Wolffork drilling and recompletions, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil, NGLs and gas, the availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms.
The Company is targeting approximately 50% production growth in 2011, based on the midpoint of current 2011 production guidance, or 2,375 MBoe. The table below sets forth the Company’s current 2011 production and operating costs and expenses guidance. The guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company’s control.
| Current 2011 | Prior 2011 | |||||
| Guidance | Guidance | |||||
| Production: | ||||||
| Total (MBoe) | 2,300 – 2,450 | 2,300 – 2,450 | ||||
| Percent oil and NGLs | 55% | 55% | ||||
| Operating costs and expenses (per Boe): | ||||||
| Lease operating | $ | 4.25 – 5.50 | $ | 4.25 – 5.50 | ||
| Severance and production taxes | $ | 2.35 – 3.00 | $ | 2.00 – 2.30 | ||
|
Exploration |
$ | 4.00 – 5.00 | $ | 4.00 – 5.00 | ||
| General and administrative | $ | 6.25 – 6.75 | $ | 5.00 – 6.00 | ||
| Depletion, depreciation and amortization | $ | 12.00 – 15.00 | $ | 12.00 – 15.00 | ||
| Capital expenditures (in millions) | Approximately $220 | Approximately $220 |
Conference Call Information
The Company will host a conference call on Wednesday, August 3, 2011, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss second quarter 2011 financial and operating results. To participate in the conference call, domestic participants should dial (866) 713-8566 and international participants should dial (617) 597-5325 approximately 15 minutes before the scheduled conference time. To access the simultaneous webcast of the conference call, please visit the Investor Events page under the Investor Relations section of the Company’s website, www.approachresources.com, 15 minutes before the scheduled conference time to register for the webcast and install any necessary software. The webcast will be archived for replay on the Company’s website until November 3, 2011. An accompanying slide presentation also is available on the Company’s website.
Approach Resources Inc. is an independent oil and gas company with core operations, production and reserves located in the Permian Basin in West Texas. The Company targets multiple oil and liquids-rich formations in the Permian Basin, where the Company operates approximately 140,400 net acres. The Company’s estimated proved reserves total 66.8 million Boe, comprised of 55% oil and NGLs and 45% natural gas. For more information about the Company, please visit www.approachresources.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website.
This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include the expectations of management regarding the Company’s capital budget, production, revenues and operating costs. These statements are based on certain assumptions made by the Company based on management's experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this press release, the words “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. Further information on such assumptions, risks and uncertainties is available in the Company’s Securities and Exchange Commission (“SEC”) filings. The Company’s SEC filings are available on the Company’s website at www.approachresources.com. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
For a glossary of oil and gas terms and abbreviations used in this release, please see our Annual Report on Form 10-K filed with the SEC on March 11, 2011.
|
UNAUDITED RESULTS OF OPERATIONS |
|||||||||||||||
|
Three Months Ended
June 30, |
Six Months Ended
June 30, |
||||||||||||||
| 2011 | 2010 | 2011 | 2010 | ||||||||||||
| Revenues (in thousands) | |||||||||||||||
| Oil | $ | 10,201 | $ | 3,940 | $ | 18,224 | $ | 7,495 | |||||||
| NGLs | 12,235 | 2,351 | 17,289 | 4,334 | |||||||||||
| Gas | 6,687 | 6,864 | 13,793 | 14,546 | |||||||||||
| Total oil, NGL and gas sales | 29,123 | 13,155 | 49,306 |
26,375 |
|||||||||||
| Realized gain on commodity derivatives | 66 | 1,768 | 262 | 1,998 | |||||||||||
| Total oil, NGL and gas sales including derivative impact | $ | 29,189 | $ | 14,923 | $ | 49,568 | $ | 28,373 | |||||||
| Production | |||||||||||||||
| Oil (MBbls) | 104 | 54 | 193 | 101 | |||||||||||
| NGLs (MBbls) | 236 | 58 | 341 | 104 | |||||||||||
| Gas (MMcf) | 1,608 | 1,558 | 3,260 | 2,982 | |||||||||||
| Total (MBoe) | 608 | 372 | 1,077 | 702 | |||||||||||
| Total (MBoe/d) | 6.7 | 4.1 | 6.0 | 3.9 | |||||||||||
| Average prices | |||||||||||||||
| Oil (per Bbl) | $ | 97.89 | $ | 73.26 | $ | 94.57 | $ | 74.27 | |||||||
| NGLs (per Bbl) | 51.88 | 40.33 | 50.70 | 41.65 | |||||||||||
| Gas (per Mcf) | 4.16 | 4.41 | 4.23 | 4.88 | |||||||||||
| Total (per Boe) | $ | 47.90 | $ | 35.36 | $ | 45.78 | $ | 37.57 | |||||||
| Realized gain on commodity derivatives (per Boe) | 0.11 | 4.75 | 0.24 | 2.85 | |||||||||||
| Total including derivative impact (per Boe) | $ | 48.01 | $ | 40.11 | $ | 46.02 | $ | 40.42 | |||||||
| Costs and expenses (per Boe) | |||||||||||||||
| Lease operating (1) | $ | 5.93 | $ | 5.93 | $ | 5.81 | $ | 5.76 | |||||||
| Severance and production taxes | 2.80 | 1.64 | 2.60 | 1.86 | |||||||||||
| Exploration | 0.46 | 0.50 | 4.56 | 2.39 | |||||||||||
| General and administrative | 7.55 | 5.87 | 7.51 | 6.68 | |||||||||||
| Depletion, depreciation and amortization | 13.14 | 13.47 | 13.04 | 15.45 | |||||||||||
|
(1) Lease operating expense per Boe includes ad valorem taxes. |
|||||||||||||||
|
APPROACH RESOURCES INC. AND SUBSIDIARIES UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except shares and per-share amounts) |
||||||||||||||||
|
|
Three Months Ended
June 30, |
Six Months Ended
June 30, |
||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| REVENUES: | ||||||||||||||||
| Oil, NGL and gas sales | $ | 29,123 | $ | 13,155 | $ | 49,306 | $ | 26,375 | ||||||||
| EXPENSES: | ||||||||||||||||
| Lease operating | 3,609 | 2,203 | 6,256 | 4,043 | ||||||||||||
| Severance and production taxes | 1,701 | 610 | 2,804 | 1,304 | ||||||||||||
| Exploration | 280 | 187 | 4,908 | 1,677 | ||||||||||||
| General and administrative | 4,593 | 2,181 | 8,093 | 4,690 | ||||||||||||
| Depletion, depreciation and amortization | 7,987 | 5,010 | 14,039 | 10,845 | ||||||||||||
| Total expenses | 18,170 | 10,191 | 36,100 | 22,559 | ||||||||||||
| OPERATING INCOME | 10,953 | 2,964 | 13,206 | 3,816 | ||||||||||||
| OTHER: | ||||||||||||||||
| Interest expense, net | (863 | ) | (550 | ) | (1,375 | ) | (1,016 | ) | ||||||||
| Realized gain on commodity derivatives | 66 | 1,768 | 262 | 1,998 | ||||||||||||
| Unrealized gain (loss) on commodity derivatives | 2,231 | (1,901 | ) | 2,082 | 3,194 | |||||||||||
| Gain on sale of oil and gas properties | 3 |
― |
491 | ― | ||||||||||||
| INCOME BEFORE INCOME TAX PROVISION | 12,390 | 2,281 | 14,666 | 7,992 | ||||||||||||
| INCOME TAX PROVISION | 4,400 | 730 | 5,213 | 2,878 | ||||||||||||
| NET INCOME | $ | 7,990 | $ | 1,551 | $ | 9,453 | $ | 5,114 | ||||||||
| EARNINGS PER SHARE: | ||||||||||||||||
| Basic | $ | 0.28 | $ | 0.07 | $ | 0.33 | $ | 0.24 | ||||||||
| Diluted | $ | 0.28 | $ | 0.07 | $ | 0.33 | $ | 0.24 | ||||||||
| WEIGHTED AVERAGE SHARES OUTSTANDING: | ||||||||||||||||
| Basic | 28,458,270 | 21,059,413 | 28,376,414 | 21,027,982 | ||||||||||||
| Diluted | 28,687,457 | 21,184,331 | 28,615,647 | 21,154,647 | ||||||||||||
|
UNAUDITED SELECTED FINANCIAL DATA |
||||||
| Unaudited Consolidated Balance Sheet Data | June 30, | December 31, | ||||
| (in thousands) | 2011 | 2010 | ||||
| Cash and cash equivalents | $ | 831 | $ | 23,465 | ||
| Other current assets | 12,986 | 17,865 | ||||
| Property and equipment, net, successful efforts method | 513,505 | 369,210 | ||||
| Other assets | 3,242 | 2,549 | ||||
| Total assets | $ | 530,564 | $ | 413,089 | ||
| Current liabilities | $ | 36,325 | $ | 29,240 | ||
| Long-term debt | 93,550 | ― | ||||
| Other long-term liabilities | 55,887 | 50,903 | ||||
| Stockholders’ equity | 344,802 | 332,946 | ||||
| Total liabilities and stockholders’ equity | $ | 530,564 | $ | 413,089 | ||
|
Unaudited Consolidated Cash Flow Data |
Six Months Ended
June 30, |
||||||
| (in thousands) | 2011 | 2010 | |||||
| Net cash provided (used) by: | |||||||
| Operating activities | $ | 46,067 | $ | 18,332 | |||
| Investing activities | $ | (161,883 | ) | $ | (30,234 | ) | |
| Financing activities | $ | 93,180 | $ | 9,512 | |||
| Effect of foreign currency translation | $ | 2 | $ | (2 | ) | ||
Supplemental Non-GAAP Financial and Other Measures
This release contains certain financial measures that are non-GAAP measures. We have provided reconciliations below of the non-GAAP financial measures to the most directly comparable GAAP financial measures and on the Non-GAAP Financial Information page in the Investor Relations section of our website at www.approachresources.com.
Adjusted Net Income
This release contains the non-GAAP financial measures adjusted net income and adjusted net income per diluted share, which exclude the following items:
(i) Unrealized (gain) loss on commodity derivatives,
(ii) Gain on sale of oil and gas properties, and
(iii) Related income taxes.
The amounts included in the calculation of adjusted net income and adjusted net income per diluted share below were computed in accordance with GAAP. We believe adjusted net income and adjusted net income per diluted share are useful to investors because they provide readers with a more meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.
The following table provides a reconciliation of adjusted net income to net income for the three and six months ended June 30, 2011 and 2010, respectively (in thousands, except per-share amounts).
|
Three Months Ended
June 30, |
Six Months Ended
June 30, |
|||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| Net income | $ | 7,990 | $ | 1,551 | $ | 9,453 | $ | 5,114 | ||||||||
| Adjustments for certain items: | ||||||||||||||||
| Unrealized (gain) loss on commodity derivatives | (2,231 | ) | 1,901 | (2,082 | ) | (3,194 | ) | |||||||||
| Gain on sale of oil and gas properties | (3 | ) | ― | (491 | ) | ― | ||||||||||
| Related income tax effect | 760 | (646 | ) | 875 | 1,086 | |||||||||||
| Adjusted net income | $ | 6,516 | $ | 2,806 | $ | 7,755 | $ | 3,006 | ||||||||
| Adjusted net income per diluted share | $ | 0.23 | $ | 0.13 | $ | 0.27 | $ | 0.14 | ||||||||
EBITDAX
We define EBITDAX as net income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized (gain) loss on commodity derivatives, (5) gain on sale of oil and gas properties, (6) interest expense and (7) income taxes. EBITDAX is not a measure of net income or cash flow as determined by GAAP. The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. EBITDAX is presented herein and reconciled to the GAAP measure of net income because of its wide acceptance by the investment community as a financial indicator of a company's ability to internally fund development and exploration activities. This measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.
The following table provides a reconciliation of EBITDAX to net income for the three and six months ended June 30, 2011 and 2010, respectively (in thousands, except per-share amounts).
|
Three Months Ended
June 30, |
Six Months Ended
June 30, |
|||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| Net income | $ | 7,990 | $ | 1,551 | $ | 9,453 | $ | 5,114 | ||||||||
| Exploration | 280 | 187 | 4,908 | 1,677 | ||||||||||||
| Depletion, depreciation and amortization | 7,987 | 5,010 | 14,039 | 10,845 | ||||||||||||
| Share-based compensation | 1,713 | 416 | 2,548 | 996 | ||||||||||||
| Unrealized (gain) loss on commodity derivatives | (2,231 | ) | 1,901 | (2,082 | ) | (3,194 | ) | |||||||||
| Gain on sale of oil and gas properties | (3 | ) |
― |
(491) |
― |
|||||||||||
| Interest expense, net | 863 | 550 | 1,375 | 1,016 | ||||||||||||
| Income tax provision | 4,400 | 730 | 5,213 | 2,878 | ||||||||||||
| EBITDAX | $ | 20,999 | $ | 10,345 | $ | 34,963 | $ | 19,332 | ||||||||
| EBITDAX per diluted share | $ | 0.73 | $ | 0.49 | $ | 1.22 | $ | 0.91 | ||||||||
PV-10
The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at $521.2 million at June 30, 2011, and was calculated based on the first-of-the-month, twelve-month average prices of $85.92 per Bbl of oil, $44.96 per Bbl of NGLs and $3.98 per Mcf of natural gas,.
PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating the Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry.
The following table reconciles PV-10 to the Standardized Measure, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 should not be considered as an alternative to the Standardized Measure as computed under GAAP.
| As of June 30, 2011 | ||||
| (in thousands) | ||||
| PV-10 | $ | 521,160 | ||
| Less income taxes: | ||||
| Undiscounted future income taxes | (470,075 | ) | ||
| 10% discount factor | 277,579 | |||
| Future discounted income taxes | (192,496 | ) | ||
| Standardized measure of discounted future net cash flows | $ | 328,664 | ||
Finding and Development Costs
All-in finding and development (“F&D”) costs are calculated by dividing the sum of property acquisition costs, exploration costs and development costs for the year by the sum of reserve extensions and discoveries, purchases of minerals in place and total revisions for the year.
Drill-bit F&D costs are calculated by dividing the sum of exploration costs and development costs for the year by the total of reserve extensions and discoveries for the year.
We believe that providing the above measures of F&D cost is useful to assist in an evaluation of how much it costs the Company, on a per Boe basis, to add proved reserves. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our previous SEC filings and to be included in our annual report on Form 10-K to be filed with the SEC on or before March 15, 2012. Due to various factors, including timing differences, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods before the periods in which related increases in reserves are recorded, and development costs may be recorded in periods after the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases (or decreases) in reserves independent of the related costs of such increases.
As a result of the above factors and various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, including factors disclosed in our filings with the SEC, we cannot assure you that the Company’s future F&D costs will not differ materially from those set forth above. Further, the methods used by us to calculate F&D costs may differ significantly from methods used by other companies to compute similar measures. As a result, our F&D costs may not be comparable to similar measures provided by other companies.
The following table reconciles our estimated F&D costs for the first six months of 2011 to the information required by paragraphs 11 and 21 of ASC 932-235.
| Cost summary (in thousands) | ||||
| Property acquisition costs | ||||
| Unproved properties | $ | 15,440 | ||
| Proved properties | 93 | |||
| Exploration costs | 4,914 | |||
| Development costs | 72,061 | |||
| Working interest acquisition costs | 70,181 | |||
| Total costs incurred | $ | 162,689 | ||
| Reserve summary (MBoe) | ||||
| Balance―December 31, 2010 | 50,715 | |||
| Extensions and discoveries | 8,910 | |||
| Purchases of minerals in place | 10,497 | |||
| Production | (1,077 | ) | ||
| Revisions to previous estimates | ||||
| Price-related revisions | 275 | |||
| Performance-related revisions | (2,471 | ) | ||
| Total revisions to previous estimates | (2,196 | ) | ||
| Balance―June 30, 2011 | 66,849 | |||
| Finding and development costs ($/Boe) | ||||
| All-in F&D cost | $ | 9.45 | ||
| Drill-bit F&D cost | $ | 8.64 |
Liquidity
Liquidity is calculated by adding the net funds available under our revolving credit facility and cash and cash equivalents. We use liquidity as an indicator of the Company’s ability to fund development and exploration activities. However, this measurement has limitations. This measurement can vary from year to year for the Company and can vary among companies based on what is or is not included in the measurement on a company’s financial statements. This measurement is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.
The table below summarizes our liquidity position at June 30, 2011 (dollars in thousands).
|
Liquidity at
June 30, 2011 |
||||
| Borrowing base | $ | 200,000 | ||
| Cash and cash equivalents | 831 | |||
| Long-term debt | (93,550 | ) | ||
| Unused letters of credit | (350 | ) | ||
| Liquidity | $ | 106,931 | ||