Form 8-K Approach Resources Inc For: Aug 05
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 OR 15(d)
of The Securities Exchange Act of 1934
Date of Report (Date of earliest event reported)
August 5, 2015
APPROACH RESOURCES INC.
(Exact name of registrant as specified in its charter)
Delaware | 001-33801 | 51-0424817 | ||
(State or other jurisdiction of incorporation) |
(Commission File Number) |
(IRS Employer Identification No.) | ||
One Ridgmar Centre 6500 West Freeway, Suite 800 Fort Worth, Texas |
76116 | |||
(Address of principal executive offices) | (Zip Code) |
(817) 989-9000
(Registrants telephone number, including area code)
Not Applicable
(Former name or former address, if changed since last report.)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):
¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
¨ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
¨ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Item 2.02 | Results of Operations and Financial Condition. |
On August 5, 2015, the Company issued a press release announcing financial and operational results for the three and six months ended June 30, 2015 (the Earnings Release). The Earnings Release contains certain non-GAAP financial information. The reconciliation of such non-GAAP financial information to GAAP financial measures is included in the Earnings Release and in the Investor Relations Non-GAAP Financials section of the Companys website at www.approachresources.com. A copy of the Earnings Release is furnished herewith as Exhibit 99.1.
Item 7.01 | Regulation FD Disclosure. |
On August 5, 2015, the Company issued the Earnings Release discussed above in Item 2.02 of this current report on Form 8-K. The Earnings Release contains certain non-GAAP financial information. The reconciliation of such non-GAAP financial information to GAAP financial measures is included in the Earnings Release and in the Investor Relations Non-GAAP Financials section of the Companys website at www.approachresources.com. A copy of the Earnings Release is furnished herewith as Exhibit 99.1.
On August 5, 2015, the Company posted a new presentation titled Approach Resources Inc. Second Quarter 2015 Results under the Investor Relations Presentations section of the Companys website, www.approachresources.com. For the benefit of all investors, the presentation is attached hereto as Exhibit 99.2.
Item 9.01 | Financial Statements and Exhibits. |
(d) Exhibits.
Exhibit |
Description | |
99.1 | Earnings Release dated August 5, 2015. | |
99.2 | Corporate presentation titled, Approach Resources Inc. Second Quarter 2015 Results. |
In accordance with General Instruction B.2 of Form 8-K, the information in Items 2.02 and 7.01, including the attached Exhibits 99.1 and 99.2, shall not be deemed filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the Exchange Act), or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference into any registration statement or other filing under the Securities Act of 1933, as amended, or the Exchange Act, except as otherwise expressly stated in such filing.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
APPROACH RESOURCES INC. | ||
By: | /s/ J. Curtis Henderson | |
J. Curtis Henderson | ||
Chief Administrative Officer and Corporate Secretary |
Date: August 6, 2015
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EXHIBIT INDEX
Exhibit No. |
Description | |
99.1 | Earnings Release dated August 5, 2015. | |
99.2 | Corporate presentation titled, Approach Resources Inc. Second Quarter 2015 Results. |
4
Exhibit 99.1
News Release |
Approach Resources Inc.
Reports Second Quarter 2015 Results
Fort Worth, Texas, August 5, 2015 Approach Resources Inc. (NASDAQ: AREX) today reported results for second quarter 2015. Highlights for second quarter 2015 include:
| Record quarterly production of 1,391 MBoe, or 15.3 MBoe/d, an 8% increase over the prior-year quarter and an 8% increase over first quarter 2015 |
| EBITDAX was $32.6 million, or $0.80 per diluted share |
| Revenues totaled $38.6 million. Including realized hedge gains, revenues were $47.9 million |
| Per-unit lease operating expense decreased 20% from the prior year-year quarter, and 10% from first quarter 2015, to $4.97 per Boe |
| Per-unit cash operating expenses decreased 26% from the prior-year quarter, and 11% from first quarter 2015, to $11.02 per Boe |
| Adjusted net loss was $2.8 million, or $0.07 per diluted share |
| Average IP for wells completed since last update was 869 Boe/d (58% oil and 81% liquids) |
Adjusted net (loss) income, EBITDAX and cash operating expenses are non-GAAP measures. See Supplemental Non-GAAP Measures below for our definitions and reconciliations of adjusted net (loss) income and EBITDAX to net (loss) income and cash operating expenses to operating expenses.
Management Comment
J. Ross Craft, Approachs Chairman, CEO and President, commented, We have continued to make great strides in reducing our cost structure. Our large-scale water recycling center became fully operational and helped to reduce our lease operating expense by 20% from the prior-year quarter to below $5.00 per Boe. We recognized double-digit percentage declines across all of our per-unit cash cost metrics, including corporate overhead. In addition, our costs for a standard lateral horizontal well decreased during the quarter to an average of $4.5 million. This quarter solidifies our position as one of the lowest-cost Permian operators in the horizontal Wolfcamp play.
As the outlook for commodity prices remains challenging and uncertain, we have made a decision to reduce our capital expenditure budget for 2015 from $160 million to $150 million to preserve capital and maintain flexibility to take advantage of opportunities that this industry environment may present. We have demonstrated our commitment to capital discipline in prior price cycles, most recently in 2009. We took the time to evaluate and discover a new shale play, which is now known as the Wolfcamp shale play. I believe this price cycle can provide similar opportunities for Approach to grow and deliver long-term value to our shareholders.
Second Quarter 2015 Results
Production for second quarter 2015 totaled 1,391 MBoe (15.3 MBoe/d), compared to production of 1,286 MBoe (14.1 MBoe/d) in second quarter 2014, an 8% increase. Oil production for the second quarter was 499 MBbls (5.5 MBbls/d). Production for second quarter 2015 was 65% liquids and 35% natural gas.
INVESTOR CONTACT Sergei Krylov Executive Vice President & Chief Financial Officer 817.989.9000 |
APPROACH RESOURCES INC. One Ridgmar Centre 6500 West Freeway, Suite 800 Fort Worth, Texas 76116 www.approachresources.com |
Due to sustained, low commodity prices, the Company reported a net loss for second quarter 2015 of $11.9 million, or $0.29 per diluted share, on revenues of $38.6 million. This compares to net income for second quarter 2014 of $3.8 million, or $0.10 per diluted share, on revenues of $73.4 million. Second quarter 2015 revenues represented a decrease of 47% from the prior-year quarter, but an increase of 16% compared to the first quarter of 2015. Net income for second quarter 2015 included an unrealized loss on commodity derivatives of $13.9 million and a realized gain on commodity derivatives of $9.3 million.
Excluding the unrealized loss on commodity derivatives and related income taxes, adjusted net loss (non-GAAP) for second quarter 2015 was $2.8 million, or $0.07 per diluted share, compared to adjusted net income of $8.7 million, or $0.22 per diluted share, for second quarter 2014. EBITDAX (non-GAAP) for second quarter 2015 was $32.6 million, or $0.80 per diluted share, compared to $50.6 million, or $1.29 per diluted share, for second quarter 2014. See Supplemental Non-GAAP Financial and Other Measures below for our definitions and reconciliations of adjusted net (loss) income and EBITDAX to net (loss) income.
Our average realized commodity price for second quarter 2015, before the effect of commodity derivatives, was $27.76 per Boe. This compares to an average realized price of $57.06 per Boe in second quarter 2014. Our average realized price, including the effect of commodity derivatives, was $34.44 per Boe for second quarter 2015.
Lease operating expense continued to decline, averaging $4.97 per Boe for second quarter 2015. This represents a 20% decrease from the prior-year quarter and a 10% decrease from first quarter 2015. Production and ad valorem taxes averaged $2.14 per Boe, or 7.7% of oil, NGL and gas sales. Exploration costs were $0.84 per Boe. Cash general and administrative expense averaged $3.91 per Boe, a 20% decline compared to the prior-year quarter. Non-cash general and administrative expense averaged $1.49 per Boe. Depletion, depreciation and amortization expense averaged $20.43 per Boe, representing an 8% year-over-year decline. Interest expense totaled $6.2 million.
Operations Update
During second quarter 2015, we drilled nine horizontal wells, completed 10 horizontal wells and had two additional horizontal wells in the final stages of completion. The average initial production (IP) rate for all wells completed since our last report was 869 Boe/d (58% oil and 81% liquids). This includes four longer lateral wells. We continued to improve our operational efficiency, reducing our drilling time by an additional 20% compared to a record-setting low average drilling time in 2014. Our spud to total depth (TD) has been reduced to an average of eight days per well.
In addition, we recycled 1.3 million barrels of flowback and produced water during the quarter, which not only helped drive down our drilling and completion costs to $4.5 million per well, but also helped reduce our LOE cost to below $5.00 per Boe. Since the beginning of our water recycling program, we have recycled more than 2 million barrels of flowback and produced water.
Capital expenditures incurred during second quarter 2015 totaled $56.9 million, and included $53.5 million for drilling and completion activities, and $3.4 million for infrastructure projects, equipment and land. As planned, our capital spending for 2015 was largely incurred in the first half of the year. Given the prolonged low commodity price outlook, we have suspended our drilling and completion activities for the remainder of the year. Although we experienced three winter storms, two DCP plant shut-ins and have suspended drilling and completion activities for the remainder of the year, we still project overall production growth of approximately 8% for 2015.
2
Liquidity Update
At June 30, 2015, we had a $1 billion revolving credit facility with $450 million in lender commitments and $257 million of outstanding borrowings. At June 30, 2015, our liquidity and long-term debt-to-capital ratio were approximately $193 million and 40%, respectively. See Supplemental Non-GAAP Financial and Other Measures below for our definitions and calculation of liquidity and long-term debt-to-capital ratio.
Commodity Derivatives Update
We enter into commodity derivatives positions to reduce the risk of commodity price fluctuations. The table below is a summary of our current derivatives positions.
Commodity and Period |
Contract Type |
Volume Transacted | Contract Price | |||
Crude Oil |
||||||
July 2015 December 2015 |
Collar | 1,600 Bbls/d | $84.00/Bbl - $91.00/Bbl | |||
July 2015 December 2015 |
Collar | 1,000 Bbls/d | $90.00/Bbl - $102.50/Bbl | |||
July 2015 December 2015 |
Three-Way Collar | 500 Bbls/d | $75.00/Bbl - $84.00/Bbl - $94.00/Bbl | |||
July 2015 December 2015 |
Three-Way Collar | 500 Bbls/d | $75.00/Bbl - $84.00/Bbl - $95.00/Bbl | |||
July 2015 December 2016 |
Swap | 750 Bbls/d | $62.52/Bbl | |||
Natural Gas |
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July 2015 December 2015 |
Swap | 200,000 MMBtu/month | $4.10/MMBtu | |||
July 2015 December 2015 |
Collar | 130,000 MMBtu/month | $4.00/MMBtu - $4.25/MMBtu |
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Guidance Update
The table below sets forth the Companys updated production and operating costs and expenses guidance for 2015. The guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Companys control.
2015 Guidance | ||
Production: |
||
Oil (MBbls) |
1,900 1,975 | |
NGLs (MBbls) |
1,575 1,625 | |
Gas (MMcf) |
11,550 11,700 | |
Total (MBoe) |
5,400 5,550 | |
Operating costs and expenses (per Boe): |
||
Lease operating |
$5.50 6.50 | |
Production and ad valorem taxes |
7.5% of oil & gas revenues | |
Cash general and administrative |
$3.75 4.25 | |
Exploration (non-cash) |
$0.50 1.00 | |
Depletion, depreciation and amortization |
$20.00 22.00 | |
Capital expenditures (in millions) |
Approximately $150 |
Conference Call Information and Summary Presentation
The Company will host a conference call on Thursday, August 6, 2014, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss financial and operational results for second quarter 2015. The conference call may be accessed via the Companys website at www.approachresources.com or by phone:
Dial in: |
(877) 201-0168 | |
Intl. dial in: |
(647) 788-4901 | |
Passcode: |
Approach / 89055164 |
A replay of the call will be available on the Companys website or by dialing (855) 859-2056 (passcode: 89055164).
In addition, a second quarter 2015 summary presentation is available on the Companys website.
About Approach Resources
Approach Resources Inc. is an independent energy company focused on the exploration, development, production and acquisition of unconventional oil and gas reserves in the Midland Basin of the greater Permian Basin in West Texas. 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.
4
Forward-Looking and Cautionary Statements
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 expectations of anticipated financial and operating results. These statements are based on certain assumptions made by the Company based on managements 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 Companys Securities and Exchange Commission (SEC) filings. The Companys SEC filings are available on the Companys 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.
5
UNAUDITED RESULTS OF OPERATIONS
Three Months Ended June 30, |
Six Months Ended June 30, |
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2015 | 2014 | 2015 | 2014 | |||||||||||||
Revenues (in thousands): |
||||||||||||||||
Oil |
$ | 25,627 | $ | 51,570 | $ | 46,930 | $ | 93,315 | ||||||||
NGLs |
5,603 | 11,560 | 10,755 | 21,858 | ||||||||||||
Gas |
7,375 | 10,278 | 14,218 | 20,162 | ||||||||||||
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Total oil, NGL and gas sales |
38,605 | 73,408 | 71,903 | 135,335 | ||||||||||||
Realized gain (loss) on commodity derivatives |
9,281 | (3,320 | ) | 25,182 | (4,659 | ) | ||||||||||
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Total oil, NGL and gas sales including derivative impact |
$ | 47,886 | $ | 70,088 | $ | 97,085 | $ | 130,676 | ||||||||
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Production: |
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Oil (MBbls) |
499 | 525 | 993 | 975 | ||||||||||||
NGLs (MBbls) |
408 | 370 | 778 | 665 | ||||||||||||
Gas (MMcf) |
2,897 | 2,348 | 5,436 | 4,282 | ||||||||||||
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Total (MBoe) |
1,391 | 1,286 | 2,677 | 2,353 | ||||||||||||
Total (MBoe/d) |
15.3 | 14.1 | 14.8 | 13.0 | ||||||||||||
Average prices: |
||||||||||||||||
Oil (per Bbl) |
$ | 51.31 | $ | 98.28 | $ | 47.27 | $ | 95.73 | ||||||||
NGLs (per Bbl) |
13.72 | 31.21 | 13.82 | 32.87 | ||||||||||||
Gas (per Mcf) |
2.55 | 4.38 | 2.62 | 4.71 | ||||||||||||
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Total (per Boe) |
$ | 27.76 | $ | 57.06 | $ | 26.86 | $ | 57.51 | ||||||||
Realized gain (loss) on commodity derivatives (per Boe) |
6.68 | (2.58 | ) | 9.41 | (1.99 | ) | ||||||||||
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Total including derivative impact (per Boe) |
$ | 34.44 | $ | 54.48 | $ | 36.27 | $ | 55.52 | ||||||||
Costs and expenses (per Boe): |
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Lease operating |
$ | 4.97 | $ | 6.18 | $ | 5.25 | $ | 6.71 | ||||||||
Production and ad valorem taxes |
2.14 | 3.83 | 2.17 | 3.86 | ||||||||||||
Exploration |
0.84 | 1.53 | 0.84 | 1.15 | ||||||||||||
General and administrative(1) |
5.40 | 5.75 | 5.83 | 6.77 | ||||||||||||
Depletion, depreciation and amortization |
20.43 | 22.21 | 20.51 | 22.17 | ||||||||||||
(1) Below is a summary of general and administrative expense: |
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General and administrative cash component |
$ | 3.91 | $ | 4.89 | $ | 4.23 | $ | 5.17 | ||||||||
General and administrative noncash component (share-based compensation) |
1.49 | 0.86 | 1.60 | 1.60 |
6
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, |
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2015 | 2014 | 2015 | 2014 | |||||||||||||
REVENUES: |
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Oil, NGL and gas sales |
$ | 38,605 | $ | 73,408 | $ | 71,903 | $ | 135,335 | ||||||||
EXPENSES: |
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Lease operating |
6,917 | 7,946 | 14,063 | 15,797 | ||||||||||||
Production and ad valorem taxes |
2,974 | 4,925 | 5,802 | 9,094 | ||||||||||||
Exploration |
1,165 | 1,966 | 2,255 | 2,704 | ||||||||||||
General and administrative |
7,510 | 7,402 | 15,612 | 15,937 | ||||||||||||
Depletion, depreciation and amortization |
28,404 | 28,573 | 54,924 | 52,179 | ||||||||||||
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Total expenses |
46,970 | 50,812 | 92,656 | 95,711 | ||||||||||||
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OPERATING (LOSS) INCOME |
(8,365 | ) | 22,596 | (20,753 | ) | 39,624 | ||||||||||
OTHER: |
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Interest expense, net |
(6,243 | ) | (5,357 | ) | (12,165 | ) | (10,494 | ) | ||||||||
Equity in losses of investee |
| (186 | ) | | (186 | ) | ||||||||||
Realized gain (loss) on commodity derivatives |
9,281 | (3,320 | ) | 25,182 | (4,659 | ) | ||||||||||
Unrealized loss on commodity derivatives |
(13,904 | ) | (7,678 | ) | (23,225 | ) | (13,604 | ) | ||||||||
Other income (expense) |
12 | (109 | ) | 38 | (109 | ) | ||||||||||
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(LOSS) INCOME BEFORE INCOME TAX (BENEFIT) PROVISION |
(19,219 | ) | 5,946 | (30,923 | ) | 10,572 | ||||||||||
INCOME TAX (BENEFIT) PROVISION: |
(7,369 | ) | 2,153 | (11,365 | ) | 3,834 | ||||||||||
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NET (LOSS) INCOME |
$ | (11,850 | ) | $ | 3,793 | $ | (19,558 | ) | $ | 6,738 | ||||||
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(LOSS) EARNINGS PER SHARE: |
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Basic |
$ | (0.29 | ) | $ | 0.10 | $ | (0.48 | ) | $ | 0.17 | ||||||
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Diluted |
$ | (0.29 | ) | $ | 0.10 | $ | (0.48 | ) | $ | 0.17 | ||||||
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WEIGHTED AVERAGE SHARES OUTSTANDING: |
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Basic |
40,554,758 | 39,368,606 | 40,357,059 | 39,306,296 | ||||||||||||
Diluted |
40,554,758 | 39,384,613 | 40,357,059 | 39,322,392 |
7
UNAUDITED SELECTED FINANCIAL DATA
Unaudited Consolidated Balance Sheet Data |
June 30, | December 31, | ||||||
(in thousands) | 2015 | 2014 | ||||||
Cash and cash equivalents |
$ | 752 | $ | 432 | ||||
Other current assets |
35,319 | 60,647 | ||||||
Property and equipment, net, successful efforts method |
1,407,047 | 1,331,659 | ||||||
Other assets |
10 | | ||||||
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Total assets |
$ | 1,443,128 | $ | 1,392,738 | ||||
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Current liabilities |
$ | 67,472 | $ | 106,852 | ||||
Long-term debt(1) |
499,098 | 391,311 | ||||||
Other long-term liabilities |
117,597 | 120,248 | ||||||
Stockholders equity |
758,961 | 774,327 | ||||||
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Total liabilities and stockholders equity |
$ | 1,443,128 | $ | 1,392,738 | ||||
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(1) | Long-term debt is net of debt issuance costs of $7.9 million and $8.7 million as of June 30, 2015 and December 31, 2014, respectively. |
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 Financials page in the Investor Relations section of our website at www.approachresources.com.
Adjusted Net (Loss) Income
This release contains the non-GAAP financial measures adjusted net (loss) income and adjusted net (loss) income per diluted share, which excludes (1) unrealized loss on commodity derivatives, (2) a rig termination fee, and (3) related income tax effect. The amounts included in the calculation of adjusted net (loss) income and adjusted net (loss) income per diluted share below were computed in accordance with GAAP. We believe adjusted net (loss) income and adjusted net (loss) 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.
8
The table below provides a reconciliation of adjusted net (loss) income and adjusted net (loss) income per diluted share to net (loss) income for the three and six months ended June 30, 2015 and 2014 (in thousands, except per-share amounts).
Three Months Ended June 30, |
Six Months Ended June 30, |
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2015 | 2014 | 2015 | 2014 | |||||||||||||
Net (loss) income |
$ | (11,850 | ) | $ | 3,793 | $ | (19,558 | ) | $ | 6,738 | ||||||
Adjustments for certain items: |
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Unrealized loss on commodity derivatives |
13,904 | 7,678 | 23,225 | 13,604 | ||||||||||||
Rig termination fee |
| | 498 | | ||||||||||||
Related income tax effect |
(4,866 | ) | (2,780 | ) | (8,303 | ) | (4,934 | ) | ||||||||
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Adjusted net (loss) income |
$ | (2,812 | ) | $ | 8,691 | $ | (4,138 | ) | $ | 15,408 | ||||||
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Adjusted net (loss) income per diluted share |
$ | (0.07 | ) | $ | 0.22 | $ | (0.10 | ) | $ | 0.39 | ||||||
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EBITDAX
We define EBITDAX as net (loss) income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss on commodity derivatives, (5) interest expense, net, and (6) income tax (benefit) provision. 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 companys 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 table below provides a reconciliation of EBITDAX and EBITDAX per diluted share to net (loss) income for the three and six months ended June 30, 2015 and 2014 (in thousands, except per-share amounts).
Three Months Ended June 30, |
Six Months Ended June 30, |
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2015 | 2014 | 2015 | 2014 | |||||||||||||
Net (loss) income |
$ | (11,850 | ) | $ | 3,793 | $ | (19,558 | ) | $ | 6,738 | ||||||
Exploration |
1,165 | 1,966 | 2,255 | 2,704 | ||||||||||||
Depletion, depreciation and amortization |
28,404 | 28,573 | 54,924 | 52,179 | ||||||||||||
Share-based compensation |
2,075 | 1,107 | 4,292 | 3,761 | ||||||||||||
Unrealized loss on commodity derivatives |
13,904 | 7,678 | 23,225 | 13,604 | ||||||||||||
Interest expense, net |
6,243 | 5,357 | 12,165 | 10,494 | ||||||||||||
Income tax (benefit) provision |
(7,369 | ) | 2,153 | (11,365 | ) | 3,834 | ||||||||||
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EBITDAX |
$ | 32,572 | $ | 50,627 | $ | 65,938 | $ | 93,314 | ||||||||
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EBITDAX per diluted share |
$ | 0.80 | $ | 1.29 | $ | 1.63 | $ | 2.37 | ||||||||
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9
Cash Operating Expenses
We define cash operating expenses as operating expenses, excluding (1) exploration expense, (2) depletion, depreciation and amortization expense, and (3) share-based compensation expense. Cash operating expenses is not a measure of operating expenses as determined by GAAP. The amounts included in the calculation of cash operating expenses were computed in accordance with GAAP. Cash operating expenses is presented herein and reconciled to the GAAP measure of operating expenses. We use cash operating expenses as an indicator of the Companys ability to manage its operating expenses and cash flows. 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 table below provides a reconciliation of cash operating expenses to operating expenses for the three and six months ended June 30, 2015 and 2014 (in thousands, except per-Boe amounts).
Three Months Ended June 30, |
Six Months Ended June 30, |
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2015 | 2014 | 2015 | 2014 | |||||||||||||
Operating expenses |
$ | 46,970 | $ | 50,812 | $ | 92,656 | $ | 95,711 | ||||||||
Exploration |
(1,165 | ) | (1,966 | ) | (2,255 | ) | (2,704 | ) | ||||||||
Depletion, depreciation and amortization |
(28,404 | ) | (28,573 | ) | (54,924 | ) | (52,179 | ) | ||||||||
Share-based compensation |
(2,075 | ) | (1,107 | ) | (4,292 | ) | (3,761 | ) | ||||||||
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Cash operating expenses |
$ | 15,326 | $ | 19,166 | $ | 31,185 | $ | 37,067 | ||||||||
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Cash operating expenses per Boe |
$ | 11.02 | $ | 14.90 | $ | 11.65 | $ | 15.75 | ||||||||
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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 Companys 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 companys 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 at June 30, 2015 (in thousands).
Liquidity at June 30, 2015 |
||||
Lender commitments |
$ | 450,000 | ||
Cash and cash equivalents |
752 | |||
Senior secured credit facility outstanding borrowings |
(257,000 | ) | ||
Outstanding letters of credit |
(325 | ) | ||
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Liquidity |
$ | 193,427 | ||
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10
Long-Term Debt-to-Capital
Long-term debt-to-capital ratio is calculated by dividing long-term debt (GAAP) by the sum of total stockholders equity (GAAP) and long-term debt (GAAP). We use the long-term debt-to-capital ratio as a measurement of our overall financial leverage. However, this ratio has limitations. This ratio can vary from year-to-year for the Company and can vary among companies based on what is or is not included in the ratio on a companys financial statements. This ratio 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 long-term debt-to-capital ratio at June 30, 2015, and December 31, 2014 (in thousands).
June 30, 2015 | December 31, 2014 | |||||||
Long-term debt(1) |
$ | 499,098 | $ | 391,311 | ||||
Total stockholders equity |
758,961 | 774,327 | ||||||
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$ | 1,258,059 | $ | 1,165,638 | |||||
Long-term debt-to-capital |
39.7 | % | 33.6 | % | ||||
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(1) | Long-term debt is net of debt issuance costs of $7.9 million and $8.7 million as of June 30, 2015 and December 31, 2014, respectively. |
11
Second Quarter 2015 Results AUGUST 5, 2015 Exhibit 99.2 |
Forward-looking statements 2 This presentation 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 presentation 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 presentation specifically include the expectations of management regarding plans, strategies, objectives, anticipated financial and operating results of the Company, including as to the Companys Wolfcamp shale resource play, estimated resource potential and recoverability of the oil and gas, estimated reserves and drilling locations, capital expenditures, typical well results and well profiles, type curve, and production and operating expenses guidance included in the presentation. These statements are based on certain assumptions made by the Company based on management's experience and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and believed to be reasonable by management. When used in this presentation, the words will, potential, believe, intend, expect, may, should, anticipate, could, estimate, plan, predict, project, target, 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. In particular, careful consideration should be given to the cautionary statements and risk factors described in the Company's most recent Annual Report on Form 10-K and Quarterly Reports on Form 10-Q. 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. The 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 meet the SECs definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. The Company uses the terms estimated ultimate recovery or EUR, reserve or resource potential, and other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SECs rules may prohibit the Company from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized by the Company. EUR estimates, identified drilling locations and resource potential estimates have not been risked by the Company. Actual locations drilled and quantities that may be ultimately recovered from the Companys interest may differ substantially from the Companys estimates. There is no commitment by the Company to drill all of the drilling locations that have been attributed these quantities. Factors affecting ultimate recovery include the scope of the Companys drilling project, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approval and actual drilling results, as well as geological and mechanical factors. Estimates of unproved reserves, type/decline curves, per well EUR and resource potential may change significantly as development of the Companys oil and gas assets provides additional data. Type/decline curves, estimated EURs, resource potential, recovery factors and well costs represent Company estimates based on evaluation of petrophysical analysis, core data and well logs, well performance from limited drilling and recompletion results and seismic data, and have not been reviewed by independent engineers. These are presented as hypothetical recoveries if assumptions and estimates regarding recoverable hydrocarbons, recovery factors and costs prove correct. The Company has limited production experience with this project, and accordingly, such estimates may change significantly as results from more wells are evaluated. Estimates of resource potential and EURs do not constitute reserves, but constitute estimates of contingent resources which the SEC has determined are too speculative to include in SEC filings. Unless otherwise noted, IRR estimates are before taxes and assume NYMEX forward-curve oil and gas pricing and Company-generated EUR and decline curve estimates based on Company drilling and completion cost estimates that do not include land, seismic or G&A costs. Cautionary statements regarding oil & gas quantities Second Quarter 2015 Results August 2015 |
Company overview AREX OVERVIEW ASSET OVERVIEW Enterprise value $671MM High-quality reserve base 146 MMBoe proved reserves 66% Liquids, 38% oil $1.4 BN proved PV-10 Permian core operating area 143,000 gross (130,000 net) acres ~1+ BnBoe gross, unrisked resource potential ~2,000 Identified HZ drilling locations targeting Wolfcamp A/B/C 2015 Capital program focused on flexibility and returns - Running an average of 1 HZ rig in the Wolfcamp shale play with a reduced capital budget of approximately $150 MM - Completed drilling activities and commitments ahead of schedule - Deferred three completions to post-2015 Note: Proved reserves as of 12/31/2014 and acreage as of 6/30/2015. All Boe and Mcfe calculations are based on a 6 to 1 conversion ratio. Enterprise value is equal to market capitalization using the closing share price of $4.25 per share on 7/29/2015, plus net debt as of 6/30/2015. See PV-10 (unaudited) slide. 3 Second Quarter 2015 Results August 2015 |
2Q15 Key highlights 4 2Q15 HIGHLIGHTS Drilled 9 and completed 10 HZ wells Continued improvement on already best- in-class HZ well costs Increased 2Q15 production 8% YoY to 15.3 MBoe/d Reduced cash operating cost 26% YoY to $11.02/Boe Reduced LOE 20% YoY to $4.97/Boe 2Q15 SUMMARY RESULTS Production (MBoe/d) 15.3 % Oil 36% % Total liquids 65% Average realized price ($/Boe) Average realized price, excluding commodity derivatives impact $ 27.76 Average realized price, including commodity derivatives impact 34.44 Costs and expenses ($/Boe) LOE $ 4.97 Production and ad valorem taxes 2.14 Exploration 0.84 General and administrative 5.40 G&A cash component 3.91 G&A noncash component 1.49 DD&A 20.43 Note: See Cash operating expenses slide. Second Quarter 2015 Results August 2015 |
2Q15 Operating highlights OPERATING HIGHLIGHTS Maximizing Returns Successfully implemented cost reduction initiatives, current HZ well costs now averaging
$4.5 MM per well, down 15+% from 2014 average of $5.5 MM
D&C cost savings includes $450,000 per well of permanent savings from water recycling
LOE of $4.97/Boe, improved 20% YoY Tracking Development Plan Drilled 9 HZ wells and completed 10
HZ wells, with 2 additional wells in final stages of
completion Wolfcamp B 5 wells and Wolfcamp C 5 wells 2Q15 HZ Wolfcamp average IP 869 Boe/d (58% oil, 81% liquids) Delivering Production Growth Total record quarterly production 15.3 MBoe/d (up 8% QoQ) Oil production 499 MBbl (up 1% QoQ) 5 Second Quarter 2015 Results August 2015 |
2Q15 Financial highlights FINANCIAL HIGHLIGHTS Preserving Cash Flow Quarterly EBITDAX (non-GAAP) of $32.6 MM, or $0.80 per diluted share Capital expenditures of $56.9 MM ($53.5 MM for D&C) Remain well-hedged for the balance of 2015, added 2016 oil hedges Reduced 2015 capex from $160 MM to $150 MM Stable Financial Position Liquidity of $193MM at June 30 th Lenders reaffirmed $450 MM commitment amount following Spring 2015 redetermination
Heightened Focus on Cutting Costs Revenues (pre-hedge) of $38.6 MM, $47.9 MM with hedges Adjusted net loss (non-GAAP) of $2.8 MM, or $0.07 per diluted share Every per-unit cash cost metric has improved since 2Q14 2Q15 Cash operating costs totaled $11.02/Boe, a 26% decrease compared to 2Q14 and an
11% improvement over 1Q15
Note: See Adjusted Net Income, EBITDAX, Strong, Simple
Balance Sheet, and Cash operating expenses slides.
6 Second Quarter 2015 Results August 2015 |
Lowest cost structure in the Permian Basin 7 $7.36 $6.18 $5.87 $6.65 $5.55 $4.97 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 AREX LOE Historical Track Record ($/Boe) Permian Peer LOE ($/Boe) AREX D&C Historical Track Record ($ MM) Permian Peer D&C Cost ($ MM) $13.26 $11.23 $9.63 $9.03 $8.78 $8.14 $7.83 $7.58 $4.97 $0.0 $2.0 $4.0 $6.0 $8.0 $10.0 $12.0 $14.0 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 AREX $8.6 $7.0 $5.8 $5.5 $4.5 $4.3 $0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 $8.0 $9.0 2011 2012 2013 2014 Current 2Q15 Best Well $8.5 $7.0 $6.6 $6.5 $6.3 $6.3 $6.1 $6.0 $4.5 $0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 $8.0 $9.0 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 AREX Second Quarter 2015 Results August 2015 Source: Company presentations and public filings, peer data as of 1Q15. Peers include CPE, CWEI, EGN, FANG, LPI, PE, PXD, and RSPP. |
8 AREX Flowback and Produced Water Recycle Facility 2 MM Bbls flowback and produced water recycled since inception Second Quarter 2015 Results August 2015 |
Strong, simple balance sheet 9 AREX Liquidity and Capitalization At June 30, 2015, we had a $1 billion senior secured revolving credit facility in place, with aggregate lender commitments of $450 MM and borrowing base of $525 MM Following the Spring 2015 redetermination, our lenders reaffirmed the commitment amount of $450 MM, while reducing the borrowing base to $525 MM A $75 MM cushion remains against more conservative bank lending framework Manageable Debt / LTM EBITDAX of 3.1x LTM EBITDAX / LTM Interest of 6.9x, well above minimum 2.5x covenant requirement No near-term debt maturities AREX Debt Maturity Schedule ($ MM) AREX Capitalization as of 6/30/2015 ($ MM) Cash $0.8 Credit Facility 254.4 7.0% Senior Notes due 2021 244.7 Total Long-Term Debt 1 $499.1 Shareholders Equity 758.9 Total Book Capitalization $1,258.0 AREX Liquidity as of 6/30/2015 Aggregate Commitment $450.0 Cash and Cash Equivalents 0.8 Borrowings under Credit Facility (257.0) Undrawn Letters of Credit (0.3) Liquidity $193.4 $257.0 $250.0 $0.0 $50.0 $100.0 $150.0 $200.0 $250.0 $300.0 $350.0 $400.0 $450.0 2015 2016 2017 2018 2019 2020 2021 $193 MM undrawn borrowing capacity 7.0% Senior Notes Second Quarter 2015 Results August 2015 1. Long-term debt is net of debt issuance costs of $7.9 million as of June 30, 2015 |
Valuation and leverage well supported by proved reserve base
10 12/31/2014 reserve summary prepared by DeGolyer and MacNaughton Replaced 819% of produced reserves at a drill-bit F&D cost of $8.94 per Boe
1 Total proved reserves up 27% YoY, proved oil reserves up 20% YoY PV-10 up 25% YoY to a record $1.4 billion Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Total (MBoe) PV-10 ($ MM) 2 PDP 17,599 18,319 133,583 58,181 $870.0 PDNP 379 763 5,378 2,039 $12.4 PUD 37,360 21,825 161,059 86,028 $530.6 Total Proved 55,338 40,907 300,020 146,248 $1,413.0 Total Proved Reserves Reserves by Commodity Proved PV-10 38% 28% 34% Oil NGLs Natural Gas 40% 1% 59% PDP PDNP PUD 62% < 1% 38% PDP PDNP PUD 1. 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. 2. PV-10 calculated based on the first-of-the-month, 12-month average prices for oil, NGLs and natural gas, of $94.56 per Bbl of oil, $31.50 per Bbl of NGLs and $4.55 per MMBtu of natural gas. Second Quarter 2015 Results August 2015 |
D&C Cost reductions will significantly improve profitability
11 Note: HZ Wolfcamp economics assume $4.00/Mcf realized natural gas price and NGL price based on 40% of realized oil price. 0% 10% 20% 30% 40% 50% 60% 70% $40 $50 $60 $70 $80 $90 Realized Oil Price ($/Bbl) $4.0MM D&C $4.5MM D&C $5.0MM D&C Second Quarter 2015 Results August 2015 |
Established infrastructure in place is critical to low cost
structure
12 Benefits of water recycling Reduce D&C cost Reduce LOE Increase project profit margin Minimize fresh water use, truck traffic and surface disturbance Pangea West North & Central Pangea South Pangea Schleicher Crockett Irion Reagan Sutton Recently completed water recycling facility 329,000 Bbl Capacity Second Quarter 2015 Results August 2015 |
Current hedge position 13 Commodity & Period Contract Type Volume Contract Price Crude Oil July 2015 December 2015 Collar 1,600 Bbls/d $84.00/Bbl - $91.00/Bbl July 2015 December 2015 Collar 1,000 Bbls/d $90.00/Bbl - $102.50/Bbl July 2015 December 2015 3-way Collar 500 Bbls/d $75.00/Bbl - $84.00/Bbl - $94.00/Bbl July 2015 December 2015 3-way Collar 500 Bbls/d $75.00/Bbl - $84.00/Bbl - $95.00/Bbl July 2015 December 2016 Swap 750 Bbls/d $62.52/Bbl Natural Gas July 2015 December 2015 Swap 200,000 MMBtu/month $4.10/MMBtu July 2015 December 2015 Collar 130,000 MMBtu/month $4.00/MMBtu - $4.25/MMBtu Based on the midpoint of updated 2015 guidance, approximately 85% of forecasted 3Q15-4Q15 oil production and 32% of forecasted natural gas production are hedged at weighted average floor prices of $75.93/Bbl and $4.06/MMBtu, respectively. Second Quarter 2015 Results August 2015 |
Production and expense guidance 14 Updated 2015 Guidance Production Oil (MBbls) 1,900 1,975 NGLs (MBbls) 1,575 1,625 Natural Gas (MMcf) 11,550 11,700 Total (MBoe) 5,400 5,550 Operating costs and expenses (per Boe) Lease operating $5.50 - $6.50 Production and ad valorem taxes 7.50% of oil & gas revenues Cash general and administrative $3.75 - $4.25 Exploration (non-cash) $0.50 - $1.00 Depletion, depreciation and amortization $20.00 - $22.00 Capital expenditures (in millions) ~$150 Second Quarter 2015 Results August 2015 |
Appendix |
Adjusted net (loss) income (unaudited) 16 (in thousands, except per-share amounts) Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Net (loss) income $ (11,850) $ 3,793 $ (19,558) $ 6,738 Adjustments for certain items: Unrealized loss on commodity derivatives 13,904 7,678 23,225 13,604 Rig termination fees - - 498 - Related income tax effect (4,866) (2,780) (8,303) (4,934) Adjusted net (loss) income $ (2,812) $ 8,691 $ (4,138) $ 15,408 Adjusted net (loss) income per diluted share $ (0.07) $ 0.22 $ (0.10) $ 0.39 The amounts included in the calculation of adjusted net (loss) income and adjusted net (loss) 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 (loss) income to net (loss) income for the three and six months ended June 30, 2015 and 2014. ADJUSTED NET (LOSS) INCOME (UNAUDITED) Second Quarter 2015 Results August 2015 |
EBITDAX (unaudited) 17 EBITDAX (UNAUDITED) The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. EBITDAX is not a measure of net income or cash flow as determined by 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 (loss) income for the three and six months ended June 30, 2015 and 2014. (in thousands, except per-share amounts) Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Net (loss) income $ (11,850) $ 3,793 $ (19,558) $ 6,738 Exploration 1,165 1,966 2,255 2,704 Depletion, depreciation and amortization 28,404 28,573 54,924 52,179 Share-based compensation 2,075 1,107 4,292 3,761 Unrealized loss on commodity derivatives 13,904 7,678 23,225 13,604 Interest expense, net 6,243 5,357 12,165 10,494 Income tax (benefit) provision (7,369) 2,153 (11,365) 3,834 EBITDAX $ 32,572 $ 50,627 $ 65,938 $ 93,314 EBITDAX per diluted share $ 0.80 $ 1.29 $ 1.63 $ 2.37 Second Quarter 2015 Results August 2015 |
Cash operating expenses 18 Cash operating expenses We define cash operating expenses as operating expenses, excluding (1) exploration expense, (2) depletion, depreciation and amortization expense and (3) share-based compensation expense. Cash operating expenses is not a measure of operating expenses as determined by GAAP. The amounts included in the calculation of cash operating expenses were computed in accordance with GAAP. Cash operating expenses is presented herein and reconciled to the GAAP measure of operating expenses. We use cash operating expenses as an indicator of the Companys ability to manage its operating expenses and cash flows. 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 cash operating expenses to operating expenses for the three and six months ended June 30, 2015 and 2014. (in thousands, except per-Boe amounts) Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Operating expenses $ 46,970 $ 50,812 $ 92,656 $ 95,711 Exploration (1,165) (1,966) (2,255) (2,704) Depletion, depreciation and amortization (28,404) (28,573) (54,924) (52,179) Share-based compensation (2,075) (1,107) (4,292) (3,761) Cash operating expenses $ 15,326 $ 19,166 $ 31,185 $ 37,067 Cash operating expenses per Boe $ 11.02 $ 14.90 $ 11.65 $ 15.75 Second Quarter 2015 Results August 2015 |
F&D costs (unaudited) 19 F&D Cost reconciliation Cost summary (in thousands) Property acquisition costs Unproved properties $ 4,578 Proved properties - Exploration costs 3,831 Development costs 382,995 Total costs incurred $ 391,404 Reserves summary (MBoe) Balance 12/31/2013 114,661 Extensions & discoveries 43,247 Production (1) (5,281) Revisions to previous estimates (6,379) Balance 12/31/2014 146,248 F&D cost ($/Boe) All-in F&D cost $ 10.62 Drill-bit F&D cost 8.94 Reserve replacement ratio Drill-bit 819% 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 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 February 26, 2015. 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 Companys 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 2014 to the information required by paragraphs 11 and 21 of ASC 932-235. (1) Production includes 1,390 MMcf related to field fuel. Second Quarter 2015 Results August 2015 |
PV-10 (unaudited) 20 The present value of our proved reserves, discounted at 10% (PV-10),was estimated at $1.4 billion at December 31, 2014, and was calculated based on the first-of-the-month, twelve-month average prices for oil, NGLs and gas, of $94.56 per Bbl of oil, $31.50 per Bbl of NGLs and $4.55 per MMBtu 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 our standardized measure of discounted future net cash flows, 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. (in millions) December 31, 2014 PV-10 $ 1,413 Less income taxes: Undiscounted future income taxes (1,267) 10% discount factor 910 Future discounted income taxes (357) Standardized measure of discounted future net cash flows $ 1,056 Second Quarter 2015 Results August 2015 |
Contact information SERGEI KRYLOV Executive Vice President & Chief Financial Officer 817.989.9000 ir@approachresources.com www.approachresources.com |
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