Exhibit 99.1
JONES ENERGY, INC. ANNOUNCES 2014 SECOND QUARTER FINANCIAL AND OPERATING RESULTS
Austin, TX — August 6, 2014 — Jones Energy, Inc. (NYSE: JONE) (“Jones Energy” or “the Company”) today announced financial and operating results for the quarter ended June 30, 2014. For the quarter ended June 30, 2014, the Company reported a net loss of $9.2 million, adjusted net income of $20.5 million, and EBITDAX of $77.1 million.
2014 Second Quarter Highlights
· Successful frack trial outcome in the Cleveland with average oil uplift of more than 30%; increased 2014 capital expenditure budget to incorporate new Cleveland frack design for all remaining 2014 wells
· Increased average net production to a record 23.6 MBoe/d, up 41% compared to the same period in 2013
· Increased average net oil production to 7.2 MBbl/d, up 59% compared to the same period in 2013
· Increased Cleveland average net production to 16.8 MBoe/d, up 74% compared to the same period in 2013
· Raising full-year production guidance to 23.0 to 24.0 MBoe/d
· Increased EBITDAX to $77.1 million, up 45% compared to the same period in 2013
· Acquired more than 10,000 net acres of leasehold primarily in the Texas panhandle, effectively replacing all 2014 Cleveland drilling locations
· Initiated the Tonkawa drilling program with the first two wells in-line with budget and will allocate additional capital to maintain a full-time rig line during the second half of 2014
Jonny Jones, the Company’s Founder, Chairman and CEO commented, “The second quarter of 2014 was highlighted by a significant oil uplift from our 20 Cleveland frack trial wells. The compelling economics provided by the trial have led us to increase the capital budget for 2014 in order to employ an enhanced frack technique for all Cleveland wells budgeted for the remainder of the year. We have also had a very successful first six months in our current leasing program, replacing all of the 2014 Cleveland drilling locations by the end of the second quarter while spending barely half of our $22 million leasehold budget.” Mr. Jones went on to say, “At this time last year, we were still celebrating the initial public offering of our common stock. A brief twelve months later we have seen our rig count nearly double, our EBITDAX increase 45%, our oil production has grown 59%, and our overall production has increased more than 40%. We are excited about our current growth trajectory and our outlook for the second half of 2014.”
Financial Results
Total operating revenues for the three months ended June 30, 2014 increased by $41.9 million to $106.4 million as compared to $64.5 million for the three months ended June 30, 2013. The majority of the increase was due to increased oil production volumes with the remainder of the increase attributable to higher natural gas production volumes combined with higher prices for all products.
Total operating expenses for the three months ended June 30, 2014 increased by $23.4 million to $67.7 million as compared to $44.3 million for the three months ended June 30, 2013, primarily due to the increase in production volumes. Specifically, lease operating expenses for the quarter were $12.4 million for the three months ended June 30, 2014 compared to $6.2 million for the three months ended June 30, 2013. In addition to the effects of our significant oil production growth, the Company incurred approximately $0.7 million in non-recurring expenses associated with accrual adjustments stemming from our acquisition of properties from Sabine Mid-Continent, LLC and one-time costs related to wildlife habitat surveys for our Anadarko properties. The Company has also continued to incur higher workover expenses associated with returning wells to production that were knocked off-line by offset frack operations.
Adjusted net income for the three months ended June 30, 2014 increased by $3.4 million to $20.5 million as compared to $17.1 million for the three months ended June 30, 2013, primarily due to the increase in production volumes and a small increase in the average realized price, partially offset by an increase in lease operating expenses and depletion, depreciation and amortization expense.
Operational Results
Cleveland
The Company spud 23 wells and completed 34 wells in the Cleveland in the second quarter of 2014. As of June 30, 2014, 7 wells were in various stages of completion, and 7 wells were drilling.
Daily net production in the Cleveland was 16.8 MBoe/d in the second quarter of 2014, up 8% from the first quarter of 2014 and up 74% from the second quarter of 2013. In addition to the increase in overall Cleveland production volumes, oil volumes increased by 11% when compared to the first quarter and were up 90% from the same period in 2013.
In the fourth quarter of 2013, the Company initiated a 20 well frack trial in the Cleveland formation utilizing a “plug and perf” completion technique with a design that utilized 20 stages and three perforation clusters per stage. The purpose of the trial was to test the technical limits of frack density in the Cleveland formation. The production figures thus far indicate well level economics that clearly support increased capital spending to achieve higher frack density in the Cleveland formation.
Our results indicate that the average frack trial well will yield a greater than 30% uplift in oil production, producing roughly 7,200 incremental barrels, through the first six months of production when compared to our historic 20 stage open-hole performance. This additional oil production will provide a similar or better internal
rate of return (IRR) on incremental completion capital when compared to the overall IRR calculated for the 20 stage open-hole completion. As a result, we believe that this completion technique has caused the value of our entire Cleveland drilling portfolio to increase significantly.
Based upon various factors observed during the completion and initial production phases of the wells in the frack trial, we do not believe that a frack was successfully initiated in all 60 perforation clusters. In order to increase the certainty of frack initiation in all stages moving forward, the Company has already begun utilizing an enhanced frack technique. Since transitioning to the enhanced frack technique, we have deployed over 180 independent frack stages with a near 100% frack initiation success rate. In addition to the change in frack technique, the spacing between stages is expected to be normalized at roughly 100 feet, which equates to approximately 43 frack stages in the standard Cleveland lateral design. Incremental completion costs per well, as compared to our historic 20 stage open hole design, are projected at approximately $0.9 million. This will initially result in total costs of roughly $4.3 million to drill and complete wells using the new design and spacing, which is closely aligned with the company’s expectations at the outset of the Cleveland frack trial. Utilizing our new design and enhanced frack technique we expect to meet or exceed the successful production results from our frack trial wells.
Tonkawa
The Company initiated its previously announced plan to drill a three well pilot program to test the Tonkawa formation in the second quarter of 2014. Our target well cost for the Tonkawa is $3.5 million, $1 million less than the estimated industry average cost of $4.5 million. At this time, we have reached TD and should be fracking the first of these wells by the middle of August. We have spud the second well and are currently drilling. Drilling costs for both wells appear to be in-line with our expectations. At this time, the company is encouraged by the early drilling results and has decided to add additional capital to the Tonkawa program during the second half of the year. The Company expects to maintain a dedicated rig line and drill five to six wells in the Tonkawa by year end.
Woodford
The Company spud 6 wells and completed 4 wells in the Woodford in the second quarter of 2014. As of June 30, 2014, 7 wells were in various stages of completion, and 2 wells were drilling.
Net production in the Woodford was 4.2 MBoe/d in the second quarter of 2014 compared to 4.2 MBoe/d in the second quarter of 2013 and 3.2 MBoe/d in the first quarter of 2014. Production was lower during the latter portion of 2013 and the first quarter of 2014 due to a pause in the drilling program during the middle of 2013.
The Company had previously disclosed its ongoing frack optimization tests in the Woodford involving more frack stages (16-20 vs. previous 10-14 stages) earlier this year. While the Company has seen a modest increase in production due to the increase in frack stages, the production results have not been sufficient to justify the incremental capital to complete the additional frack stages. In addition, due to several factors including
subsurface faulting, reservoir complexity, and fluid losses, our costs have exceeded our expectations. We expect to spud the remaining 6 wells under our BP joint development agreement, however, we have agreed with Vanguard Natural Resources to suspend drilling on our Vanguard JDA while we further evaluate well results and methods to reduce well costs.
Under the terms of its agreement with Vanguard Natural Resources, the Company will need to drill three additional wells prior to April 2016 to retain future development opportunities covering the 10 township area of mutual interest (AMI).
Leasing
As of June 30, 2014, the Company had added just over 10,000 net acres, primarily in the Texas panhandle. Having spent approximately 50% of the leasing budget thus far, our realized lease price has hovered just above $1,000 per acre. Based upon five wells per section, the additional acreage provides 78 new drilling locations in the Cleveland formation alone. This effectively replenishes all 2014 Cleveland drilling locations. In addition, we have identified 56 new drilling locations spread across the Tonkawa and Marmaton formations. Altogether, this provides 134 new drilling locations in multiple stacked formations across our core operating area. The Company will continue with its leasing program during the second half of the year and expects to exhaust the remainder of the $22 million dollar leasing budget.
Capital Expenditures
During the second quarter of 2014, the Company spent $129.5 million, of which $117.5 million was related to drilling and completing wells, representing 91% of total capital expenditures in the quarter. The table below summarizes the Company’s capital investment by area for 2Q14:
2Q14 Capital Expenditure Summary ($mm)
| | 2Q14 | |
Cleveland | | $ | 94.2 | |
Woodford | | 21.9 | |
Other Areas and Non-Op | | 1.4 | |
Total Drilling and Completion | | 117.5 | |
| | | |
Leasehold and Other | | 12.0 | |
Total Capital Expenditures | | $ | 129.5 | |
The Company recently increased its 2014 drilling and completion capital budget by approximately $110 million. We now expect full year capital spending of $460 million. The upward revision of the full year budget reflects the Company’s decision to move forward with the implementation of the enhanced frack technique for all remaining 2014 Cleveland wells, an increase to account for higher working interests in wells drilled in 2014, a
slightly faster than budgeted drilling and completion pace, and various cost overages experienced thus far in both the Cleveland and Woodford drilling programs.
Guidance
The Company is providing guidance for the third quarter and updated guidance for the full year 2014 as follows:
| | 3Q14E | | Updated Full
Year 2014E | | Previous Full
Year 2014E | |
Total Production (MMBoe) | | 2.2 – 2.3 | | 8.4 – 8.8 | | 8.0 – 8.4 | |
| | | | | | | |
Average Daily Production (MBoe/d) | | 24.0 – 24.5 | | 23.0 – 24.0 | | 22.0 – 23.0 | |
| | | | | | | |
Lease Operating Expenses ($/Boe) | | $5.00 - $5.50 | | $5.00 - $5.50 | | $4.25 - $4.75 | |
| | | | | | | |
Capital Spending ($ in millions) | | | | $460 | | $350 | |
Liquidity
On April 1, 2014, the Company issued $500 million in aggregate principal amount of 6.75% senior unsecured notes due 2022 at an offering price equal to 100% of par. The Company received net proceeds of approximately $489 million, of which $160 million was used to repay all of the outstanding borrowings under its second lien term loan facility, with the remaining proceeds used to pay down borrowings under its senior secured revolving credit facility and increase working capital. After giving effect to this offering, the Company’s borrowing base on its senior secured revolving credit facility automatically decreased by $25 million to $550 million. As of June 30, 2014, the Company held $31.8 million in unrestricted cash and had an undrawn credit facility balance of $300 million.
Conference Call Details
Jones Energy will host a conference call for investors and analysts to discuss the results for the quarter on Thursday, August 7, 2014 at 10:00 a.m. ET (9:00 a.m. CT). The conference call can be accessed via webcast through the Investor Relations section of Jones Energy’s website, www.jonesenergy.com, or by dialing (877) 201-0168 (for domestic U.S.) or (647) 788-4901 (International) and entering conference code 70194786. If you are not able to participate in the conference call, a telephonic replay will be available approximately two hours after the call on August 7, 2014 through Thursday, August 14, 2014. Participants may access this replay by dialing (855) 859-2056 (for domestic U.S.) or (404) 537-3406 (International), and entering conference code 70194786. A replay of the conference call may also be found on the Company’s website.
About Jones Energy
Jones Energy, Inc. is an independent oil and natural gas company engaged in the development and acquisition of oil and natural gas properties in the Anadarko and Arkoma basins of Texas and Oklahoma. Additional information about Jones Energy may be found on the Company’s website at: www.jonesenergy.com.
Investor Contacts:
Mark Brewer, 512-493-4833
Investor Relations Manager
Or
Robert Brooks, 512-328-2953
Executive Vice President & CFO
Forward-Looking 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 the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including guidance regarding the timing and location of our anticipated drilling activity, results of the 20 well frack trial in the Cleveland formation and the potential impact on the value of our Cleveland drilling portfolio, our target well cost for the Tonkawa formation, our ability to successfully execute our 2014 development plan and guidance for the third quarter and full year 2014. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. 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. These include, but are not limited to, changes in oil and natural gas prices, weather and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, customers’ elections to reject ethane and include it as part of the natural gas stream for the remainder of 2014, the condition of the capital markets generally, as well as the Company’s ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting the Company’s business and other important factors
that could cause actual results to differ materially from those projected as described in the Company’s reports filed with the SEC.
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.
Explanatory Note
The historical financial information contained in this report relates to periods that ended both prior to and after the completion of the initial public offering (“the Offering”) of 12,500,000 shares of Class A common stock of Jones Energy, Inc. (the “Company”) at a price of $15.00 per share. The Company’s Class A common stock began trading on the New York Stock Exchange (“NYSE”) under the symbol “JONE” on July 24, 2013, and the Offering closed on July 29, 2013. The consolidated financial statements and related discussion of financial condition and results of operations contained in this report relating to periods prior to the Offering pertain to Jones Energy Holdings LLC (“JEH”). In connection with the completion of the Offering, the Company became a holding company whose sole material asset consists of JEH LLC Units. As the sole managing member of JEH LLC, the Company is responsible for all operational, management and administrative decisions relating to JEH LLC’s business and consolidates the financial results of JEH LLC and its subsidiaries.
Jones Energy, Inc.
Consolidated Statement of Operations
| | Three Months Ended June 30, | | Six Months Ended June 30, | |
(in thousands of dollars except per share data) | | 2014 | | 2013 | | 2014 | | 2013 | |
| | | | | | | | | |
Operating revenues | | | | | | | | | |
Oil and gas sales | | $ | 105,795 | | $ | 64,300 | | $ | 203,663 | | $ | 119,559 | |
Other revenues | | 595 | | 226 | | 971 | | 447 | |
Total operating revenues | | 106,390 | | 64,526 | | 204,634 | | 120,006 | |
Operating costs and expenses | | | | | | | | | |
Lease operating | | 12,378 | | 6,201 | | 22,391 | | 11,546 | |
Production taxes | | 5,174 | | 3,182 | | 9,936 | | 5,634 | |
Exploration | | 191 | | 479 | | 3,012 | | 605 | |
Depletion, depreciation and amortization | | 43,211 | | 26,922 | | 82,556 | | 52,023 | |
Accretion of discount | | 197 | | 166 | | 367 | | 263 | |
General and administrative (including non-cash compensation expense) | | 6,537 | | 7,325 | | 11,798 | | 11,637 | |
Total operating expenses | | 67,688 | | 44,275 | | 130,060 | | 81,708 | |
Operating income | | 38,702 | | 20,251 | | 74,574 | | 38,298 | |
Other income (expense) | | | | | | | | | |
Interest expense | | (14,767 | ) | (8,092 | ) | (22,810 | ) | (16,279 | ) |
Net gain (loss) on commodity derivatives | | (33,698 | ) | 36,555 | | (50,948 | ) | 25,172 | |
Gain (loss) on sales of assets | | 1 | | (45 | ) | 67 | | 25 | |
Other income (expense), net | | (48,464 | ) | 28,418 | | (73,691 | ) | 8,918 | |
Income (loss) before income tax | | (9,762 | ) | 48,669 | | 883 | | 47,216 | |
| | | | | | | | | |
Income tax provision (benefit) | | (578 | ) | 252 | | 679 | | 251 | |
Net income (loss) | | (9,184 | ) | 48,417 | | 204 | | 46,965 | |
Net income (loss) attributable to non-controlling interests | | (7,537 | ) | — | | 178 | | — | |
Net income (loss) attributable to controlling interests | | $ | (1,647 | ) | $ | 48,417 | | $ | 26 | | $ | 46,965 | |
| | | | | | | | | |
Earnings per share: | | | | | | | | | |
Basic | | $ | (0.13 | ) | | | $ | 0.00 | | | |
Diluted | | $ | (0.13 | ) | | | $ | 0.00 | | | |
Weighted average shares outstanding: | | | | | | | | | |
Basic | | 12,500 | | | | 12,500 | | | |
Diluted | | 12,530 | | | | 12,521 | | | |
Jones Energy, Inc.
Consolidated Balance Sheet
| | June 30, | | December 31, | |
(in thousands of dollars) | | 2014 | | 2013 | |
| | | | | |
Assets | | | | | |
Current assets | | | | | |
Cash | | $ | 31,791 | | $ | 23,820 | |
Restricted Cash | | 97 | | 45 | |
Accounts receivable, net | | | | | |
Oil and gas sales | | 78,238 | | 51,233 | |
Joint interest owners | | 30,080 | | 42,481 | |
Other | | 1,824 | | 16,782 | |
Commodity derivative assets | | 5,408 | | 8,837 | |
Other current assets | | 3,098 | | 2,392 | |
Deferred tax assets | | 12 | | 12 | |
Total current assets | | 150,548 | | 145,602 | |
Oil and gas properties, net, at cost | | | | | |
under the successful efforts method | | 1,449,765 | | 1,297,228 | |
Other property, plant and equipment, net | | 3,591 | | 3,444 | |
Commodity derivative assets | | 10,584 | | 25,398 | |
Other assets | | 20,307 | | 15,006 | |
Deferred tax assets | | 1,766 | | 1,301 | |
Total assets | | $ | 1,636,561 | | $ | 1,487,979 | |
Liabilities and Stockholders’ Equity | | | | | |
Current liabilities | | | | | |
Trade accounts payable | | $ | 87,978 | | $ | 89,430 | |
Oil and gas sales payable | | 81,703 | | 66,179 | |
Accrued liabilities | | 31,038 | | 10,805 | |
Commodity derivative liabilities | | 20,761 | | 10,664 | |
Asset retirement obligations | | 2,870 | | 2,590 | |
Total current liabilities | | 224,350 | | 179,668 | |
Long-term debt | | 250,000 | | 658,000 | |
Senior notes | | 500,000 | | — | |
Deferred revenue | | 14,004 | | 14,531 | |
Commodity derivative liabilities | | 9,904 | | 190 | |
Asset retirement obligations | | 9,245 | | 8,373 | |
Deferred tax liabilities | | 3,696 | | 3,093 | |
Total liabilities | | 1,011,199 | | 863,855 | |
Commitments and contingencies | | | | | |
Stockholders’ equity | | | | | |
Class A common stock, $0.001 par value; 12,548,878 shares issued and 12,526,580 shares outstanding at June 30, 2014 and 12,526,580 shares issued and outstanding at December 31, 2013 | | 13 | | 13 | |
Class B common stock, $0.001 par value; 36,814,035 and 36,836,333 shares issued and outstanding at June 30, 2014 and December 31, 2013 | | 37 | | 37 | |
Treasury stock, at cost: 22,298 Class A shares at June 30, 2014 and 0 shares at December 31, 2013 | | (352 | ) | — | |
Additional paid-in-capital | | 174,555 | | 173,169 | |
Retained earnings (deficit) | | (2,160 | ) | (2,186 | ) |
Stockholders’ equity | | 172,093 | | 171,033 | |
Non-controlling interest | | 453,269 | | 453,091 | |
Total stockholders’ equity | | 625,362 | | 624,124 | |
Total liabilities and stockholders’ equity | | $ | 1,636,561 | | $ | 1,487,979 | |
Jones Energy, Inc.
Consolidated Statement of Cash Flow Data
| | Six Months Ended June 30, | |
(in thousands of dollars) | | 2014 | | 2013 | |
| | | | | |
Cash flows from operating activities | | | | | |
Net income | | $ | 204 | | $ | 46,965 | |
Adjustments to reconcile net income to net cash | | | | | |
provided by operating activities | | | | | |
Exploration expense | | 2,983 | | — | |
Depletion, depreciation, and amortization | | 82,556 | | 52,023 | |
Accretion of discount | | 367 | | 263 | |
Amortization of debt issuance costs | | 5,282 | | 1,327 | |
Accrued interest expense | | 7,612 | | 689 | |
Stock compensation expense | | 1,386 | | 473 | |
Other non-cash compensation expense | | 253 | | 2,465 | |
Amortization of deferred revenue | | (526 | ) | — | |
Net (gain) loss on commodity derivatives | | 50,948 | | (25,172 | ) |
Gain on sales of assets | | (67 | ) | (25 | ) |
Deferred income taxes | | 138 | | 217 | |
Other - net | | 40 | | 310 | |
Changes in assets and liabilities | | | | | |
Accounts receivable | | (13,365 | ) | (17,456 | ) |
Other assets | | (85 | ) | (2,885 | ) |
Accounts payable and accrued liabilities | | 17,581 | | 7,616 | |
Net cash provided by operations | | 155,307 | | 66,810 | |
Cash flows from investing activities | | | | | |
Additions to oil and gas properties | | (229,582 | ) | (63,545 | ) |
Net adjustments to purchase price of properties acquired | | 13,681 | | — | |
Proceeds from sales of assets | | 67 | | 423 | |
Acquisition of other property, plant and equipment | | (639 | ) | (290 | ) |
Current period settlements of matured derivative contracts | | (11,255 | ) | 7,267 | |
Change in restricted cash | | (52 | ) | — | |
Net cash used in investing | | (227,780 | ) | (56,145 | ) |
Cash flows from financing activities | | | | | |
Proceeds from issuance of long-term debt | | 60,000 | | — | |
Repayment under long-term debt | | (468,000 | ) | (5,000 | ) |
Proceeds from senior notes | | 500,000 | | | |
Purchases of treasury stock | | (352 | ) | — | |
Payment of debt issuance costs | | (11,204 | ) | (25 | ) |
Net cash provided by (used in) financing | | 80,444 | | (5,025 | ) |
Net increase in cash | | 7,971 | | 5,640 | |
Cash | | | | | |
Beginning of period | | 23,820 | | 23,726 | |
End of period | | $ | 31,791 | | $ | 29,366 | |
Supplemental disclosure of cash flow information | | | | | |
Cash paid for interest | | $ | 9,348 | | $ | 13,818 | |
Cash paid for income taxes | | 155 | | — | |
Change in accrued additions to oil and gas properties | | 7,218 | | 26,312 | |
Current additions to ARO | | 844 | | 263 | |
Deferred offering costs | | — | | 3,479 | |
Noncash distribution to members | | — | | 10,000 | |
Jones Energy, Inc.
Selected Financial and Operating Statistics
The following table sets forth summary data regarding production volumes, average prices and average production costs associated with our sale of oil and natural gas for the periods indicated:
| | Three Months Ended June 30, | | Six Months Ended June 30, | |
| | 2014 | | 2013 | | Change | | 2014 | | 2013 | | Change | |
Net production volumes: | | | | | | | | | | | | | |
Oil (MBbls) | | 655 | | 413 | | 242 | | 1,230 | | 725 | | 505 | |
Natural gas (MMcf) | | 5,550 | | 4,138 | | 1,412 | | 10,559 | | 8,404 | | 2,155 | |
NGLs (MBbls) | | 566 | | 419 | | 147 | | 1,089 | | 825 | | 264 | |
Total (MBoe) | | 2,146 | | 1,522 | | 624 | | 4,079 | | 2,951 | | 1,128 | |
Average net (Boe/d) | | 23,582 | | 16,725 | | 6,857 | | 22,536 | | 16,304 | | 6,232 | |
| | | | | | | | | | | | | |
Average sales price, unhedged: | | | | | | | | | | | | | |
Oil (per Bbl), unhedged | | $ | 98.51 | | $ | 88.80 | | $ | 9.71 | | $ | 96.30 | | $ | 88.62 | | $ | 7.68 | |
Natural gas (per Mcf), unhedged | | 4.20 | | 3.60 | | 0.60 | | 4.23 | | 3.29 | | 0.94 | |
NGLs (per Bbl), unhedged | | 31.76 | | 30.37 | | 1.39 | | 37.22 | | 33.48 | | 3.74 | |
Combined (per Boe) realized, unhedged | | 49.30 | | 42.25 | | 7.05 | | 49.93 | | 40.51 | | 9.42 | |
| | | | | | | | | | | | | |
Average sales price, hedged: | | | | | | | | | | | | | |
Oil (per Bbl), hedged | | $ | 89.97 | | $ | 86.75 | | $ | 3.22 | | $ | 88.85 | | $ | 86.54 | | $ | 2.31 | |
Natural gas (per Mcf), hedged | | 4.31 | | 4.11 | | 0.20 | | 4.19 | | 4.06 | | 0.13 | |
NGLs (per Bbl), hedged | | 29.99 | | 30.58 | | (0.59 | ) | 34.20 | | 33.59 | | 0.61 | |
Combined (per Boe) realized, hedged | | 46.51 | | 43.12 | | 3.39 | | 46.77 | | 42.21 | | 4.56 | |
| | | | | | | | | | | | | |
Average costs (per Boe): | | | | | | | | | | | | | |
Lease operating | | $ | 5.77 | | $ | 4.07 | | $ | 1.70 | | $ | 5.49 | | $ | 3.91 | | $ | 1.58 | |
Production taxes | | 2.41 | | 2.09 | | 0.32 | | 2.44 | | 1.91 | | 0.53 | |
Depletion, depreciation and amortization | | 20.14 | | 17.69 | | 2.45 | | 20.24 | | 17.63 | | 2.61 | |
General and administrative | | 3.05 | | 4.81 | | (1.76 | ) | 2.89 | | 3.94 | | (1.05 | ) |
Jones Energy, Inc.
Non-GAAP Financial Measures and Reconciliations
EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.
We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion and amortization, exploration expense, net gains (losses) on commodity derivatives (excluding current period settlements of matured derivative contracts), and other items. EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP. Management believes EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. EBITDAX has limitations as an analytical tool and should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historical costs of depreciable assets. Our presentation of EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items and should not be viewed as a substitute for GAAP. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table sets forth a reconciliation of net income (loss) as determined in accordance with GAAP to EBITDAX for the periods indicated:
| | Three Months Ended June 30, | | Six Months Ended June 30, | |
(in thousands of dollars) | | 2014 | | 2013 | | 2014 | | 2013 | |
| | | | | | | | | |
Reconciliation of EBITDAX to net income | | | | | | | | | |
Net income (loss) | | $ | (9,184 | ) | $ | 48,417 | | $ | 204 | | $ | 46,965 | |
Interest expense (excluding amortization of deferred financing costs) | | 10,184 | | 7,428 | | 17,528 | | 14,952 | |
Exploration expense | | 191 | | 479 | | 3,012 | | 605 | |
Income taxes | | (578 | ) | 240 | | 679 | | 217 | |
Amortization of deferred financing costs | | 4,583 | | 664 | | 5,282 | | 1,327 | |
Depreciation and depletion | | 43,211 | | 26,922 | | 82,556 | | 52,023 | |
Accretion expense | | 197 | | 166 | | 367 | | 263 | |
Other non-cash charges (benefits) | | (26 | ) | 145 | | 40 | | 310 | |
Stock compensation expense | | 929 | | 352 | | 1,386 | | 473 | |
Other non-cash compensation expense | | 127 | | 2,465 | | 253 | | 2,465 | |
Net loss (gain) on commodity derivatives | | 33,698 | | (36,555 | ) | 50,948 | | (25,172 | ) |
Current period settlements of matured derivative contracts | | (5,985 | ) | 2,457 | | (12,895 | ) | 6,205 | |
Amortization of deferred revenue | | (282 | ) | — | | (526 | ) | — | |
Loss (gain) on sales of assets | | (1 | ) | 45 | | (67 | ) | (25 | ) |
EBITDAX | | $ | 77,064 | | $ | 53,225 | | $ | 148,767 | | $ | 100,608 | |
Jones Energy, Inc.
Non-GAAP Financial Measures and Reconciliations
Adjusted Net Income is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements. We define Adjusted Net Income as net income excluding the impact of certain non-cash items including gains or losses on commodity derivative instruments not yet settled, impairment of oil and gas properties, and non-cash compensation expense. We believe adjusted net income and adjusted earnings per share are useful to investors because they provide readers with a more meaningful measure of our profitability before recording certain items for which the timing or amount cannot be reasonably determined. However, these measures are provided in addition to, not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP. The following table provides a reconciliation of net income (loss) as determined in accordance with GAAP to adjusted net income for the periods indicated:
| | Three Months Ended June 30, | | Six Months Ended June 30, | |
(in thousands of dollars except per share data) | | 2014 | | 2013 | | 2014 | | 2013 | |
| | | | | | | | | |
Net income (loss) | | $ | (9,184 | ) | $ | 48,417 | | $ | 204 | | $ | 46,965 | |
Net loss (gain) on commodity derivatives | | 33,698 | | (36,555 | ) | 50,948 | | (25,172 | ) |
Current period settlements of matured derivative contracts | | (5,985 | ) | 2,457 | | (12,895 | ) | 6,205 | |
Non-cash stock compensation expense | | 929 | | 352 | | 1,386 | | 473 | |
Other non-cash compensation expense | | 127 | | 2,465 | | 253 | | 2,465 | |
Net unamortized capitalized loan costs associated with Term Loan | | 3,761 | | — | | 3,761 | | — | |
Tax impact(1) | | (2,888 | ) | — | | (3,908 | ) | — | |
Adjusted net income | | 20,458 | | $ | 17,136 | | 39,749 | | $ | 30,936 | |
Adjusted net income attributable to non-controlling interests | | 16,727 | | | | 32,545 | | | |
Adjusted net income attributable to controlling interests | | $ | 3,731 | | | | $ | 7,204 | | | |
| | | | | | | | | |
Effective tax rate on net income attributable to controlling interests | | 36.4 | % | | | 36.4 | % | | |
(1) In arriving at adjusted net income, the tax impact of the adjustments to net income is determined by applying the appropriate tax rate to each adjustment and then allocating the tax impact between the controlling and non-controlling interests.
Jones Energy, Inc.
Non-GAAP Financial Measures and Reconciliations
Adjusted Earnings per Share is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements. We believe adjusted earnings per share is useful to investors because it provides readers with a more meaningful measure of our profitability before recording certain items for which the timing or amount cannot be reasonably determined. However, these measures are provided in addition to, not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP. The following table provides a reconciliation of earnings per share to adjusted earnings per share for the period indicated:
| | Three Months
Ended June 30, | | Six Months
Ended June 30, | |
| | 2014 | | 2014 | |
| | | | | |
Earnings per share (basic and diluted) | | $ | (0.13 | ) | $ | — | |
Net loss on commodity derivatives | | 0.68 | | 1.03 | |
Current period settlements of matured derivative contracts | | (0.12 | ) | (0.26 | ) |
Non-cash stock compensation expense | | 0.02 | | 0.03 | |
Other non-cash compensation expense | | — | | 0.01 | |
Net unamortized capitalized loan costs associated with Term Loan | | 0.08 | | 0.08 | |
Tax impact | | (0.23 | ) | (0.31 | ) |
Adjusted earnings per share (basic and diluted) | | $ | 0.30 | | $ | 0.58 | |
