Exhibit 99.1
JONES ENERGY, INC. ANNOUNCES 2014 FOURTH QUARTER AND FULL-YEAR FINANCIAL AND OPERATING RESULTS
Austin, TX — March 4, 2015 — Jones Energy, Inc. (NYSE: JONE) (“Jones Energy” or “the Company”) today announced financial and operating results for the quarter and full-year ended December 31, 2014. For the year ended December 31, 2014, the Company reported net income of $224.1 million, adjusted net income of $64.2 million, and EBITDAX of $301.4 million.
Highlights
· Increased net production for the full-year 2014 to 8.5 MMBoe (23.2 MBoe/d), up 36% from 2013
· Increased EBITDAX for the full-year 2014 by 47% to $301.4 million, up from $205.0 million in 2013
· Increased the pre-tax present value (“PV-10”) of the Company’s proved reserves to a record $1.5 billion at SEC prices(1), up 48% from year-end 2013
· Reserve additions replaced production by 409% (329% through the drill-bit(2))
· Increased total proved reserves by 29% from year-end 2013 to 115.3 MMBoe; proved oil reserves increased 66% from year-end 2013
· Increased Cleveland proved reserves by 44% from year-end 2013 to 83.0 MMBoe
· Achieved additional Cleveland well cost savings during February 2015, bringing current AFE to $2.9 million per well, down 24% from the December 2014 AFE of $3.8 million
· Raised gross proceeds of approximately $377 million in February 2015; pro-forma liquidity of approximately $509 million as of March 2, 2015
Jonny Jones, the Company’s Founder, Chairman and CEO commented, “2015 is off to a great start for Jones Energy. We are well-hedged, well-capitalized, and well-positioned with an operating plan that maximizes returns for our invested capital and provides us with the opportunity to grow the company via multiple avenues. We have resolved our production issues that negatively impacted our fourth quarter production and as a result, have seen production increase by roughly 3,000 barrels of oil equivalent per day in January 2015. In addition, we are continuing to see drilling and completion costs come down in our core Cleveland play and are prepared to ramp
(1) SEC prices for 2014 year-end proved reserves were $94.99 per barrel for oil and $4.35 per MMBtu for natural gas based on the average of such prices for 2014. SEC prices for 2013 year-end proved reserves were $96.78 per barrel for oil and $3.67 per MMBtu for natural gas based on the average of such prices for 2013.
(2) Drill-bit replacement percentage calculated as extensions and discoveries divided by full year production.
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activity from three rigs to five rigs assuming we achieve additional targeted cost savings by mid-year.” Mr. Jones went on to say, “Over the past 26 years since I founded Jones Energy, we have experienced multiple commodity price cycles. I believe that this is the kind of environment where Jones Energy thrives.”
Financial Results
Total operating revenues for the three months ended December 31, 2014 increased by $5.3 million, or 8%, to $75.6 million as compared to $70.3 million for the three months ended December 31, 2013. The increase was due to increased production volumes for all commodities. For the full-year 2014, operating revenues increased by $121.4 million, or 47%, to $380.6 million as compared to $259.2 million for the full-year 2013, primarily due to increased production volumes for all commodities.
Total operating expenses for the three months ended December 31, 2014 were unchanged at $65.0 million as compared to $65.0 million for the three months ended December 31, 2013. Increased production would have resulted in higher operating costs year over year, but the impairment charge related to the termination of the Southridge joint development agreement which occurred during the three month period ended December 31, 2013 did not recur during the same period in 2014. For the full-year 2014, operating expenses increased by $70.2 million, or 35%, to $273.6 million as compared to $203.4 million for the full-year 2013, primarily due to increased production volumes.
Adjusted net income for the three months ended December 31, 2014 increased by $3.4 million, or 31%, to $14.3 million as compared to $10.9 million for the three months ended December 31, 2013, with increased production volumes primarily responsible for the increase in both revenues and operating expenses. Adjusted net income for the full-year 2014 increased by $9.4 million, or 17%, to $64.2 million as compared to $54.8 million for the full-year 2013.
Operational Results and Updates
Cleveland
The Company spud 31 wells and completed 28 wells in the Cleveland in the fourth quarter of 2014. As of December 31, 2014, 18 wells were in various stages of completion, and eight wells were drilling. Full-year production in the Cleveland was 17.0 MBoe/d for 2014, an increase of 7.0 MBoe/d, or 70%, from 2013 full-year production of 10.0 MBoe/d.
Daily net production in the Cleveland was 17.2 MBoe/d in the fourth quarter of 2014, down 6% from the third quarter of 2014 and up 59% from the fourth quarter of 2013. Fourth quarter production was negatively impacted by continued delays in well completions and sand flow back issues. In addition, December production was impacted by more than 1,000 Boe per day due to field production issues, including an outage at a third party processing facility.
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During January 2015, the Company achieved record single day wellhead production reaching over 29,000 Boe/d. Average daily production for January 2015 was approximately 3,000 Boe/d higher than December of 2014. The significant jump in average daily production between December 2014 and January 2015 was primarily attributable to closing the timing gap between drilled wells and completed wells.
Tonkawa
The Company spud two wells and completed two wells in the Tonkawa in the fourth quarter of 2014. As of December 31, 2014, two wells were being completed, and zero wells were being drilled. Under the Company’s current 2015 budget and operating plan, Jones Energy does not plan to drill any additional Tonkawa wells in 2015.
Woodford
The Company spud one well and completed four wells in the Woodford in the fourth quarter of 2014. As of December 31, 2014, four wells were being completed, but no wells were being drilled, as we released our last Woodford rig in November 2014. Under the Company’s current 2015 budget and operating plan, Jones Energy does not plan to drill any Woodford wells in 2015.
Net production in the Woodford was 4.5 MBoe/d in the fourth quarter of 2014, up 13% from the third quarter of 2014 and up 8% from the fourth quarter of 2013. Full-year production in the Woodford was 4.0 MBoe/d, a slight decrease of 0.1 MBoe/d, or 2%, from 2013 full-year production of 4.1 MBoe/d.
Capital Expenditures
During the fourth quarter of 2014, the Company spent $152.9 million, of which $130.1 million was related to drilling and completing wells, representing 85% of total capital expenditures in the quarter. The table below summarizes the Company’s capital investment by area for 2014:
2014 Capital Expenditure Summary ($mm)
| | 1Q14 | | 2Q14 | | 3Q14 | | 4Q14 | | 2014 | |
Cleveland | | $ | 83.3 | | $ | 93.8 | | $ | 96.7 | | $ | 107.8 | | $ | 381.6 | |
Woodford | | 13.5 | | 21.9 | | 17.6 | | 17.1 | | 70.1 | |
Other Areas and Non-Op | | 3.3 | | 1.9 | | 5.7 | | 5.2 | | 16.1 | |
Total Drilling and Completion | | 100.1 | | 117.6 | | 120.0 | | 130.1 | | 467.8 | |
| | | | | | | | | | | |
Leasehold and Other | | 10.6 | | 11.6 | | 10.8 | | 22.8 | | 55.8 | |
Total Capital Expenditures | | $ | 110.7 | | $ | 129.2 | | $ | 130.8 | | $ | 152.9 | | $ | 523.6 | |
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2015 Capital Budget and Operating Plan
The Company has established a capital budget of $210 million for 2015, with approximately $190 million dedicated to Cleveland drilling and completion activity and the remainder allocated to capital work-overs and field maintenance projects. This budget represents a nearly 60% reduction in capital expenditures from 2014 and provides for a development program which keeps capital spending within expected cash flow. The Company will continue at its current three rig pace during the first portion of the year, and assuming targeted additional cost reductions for drilling and completions are achieved, will deploy two additional rigs to the Cleveland to reach a five rig pace by mid-year. The Company’s average estimated cost to drill and complete a Cleveland well with its 33 stage open-hole design has been reduced to approximately $2.9 million, creating $900,000 in cost savings, or a 24% cost decrease, compared to the $3.8 million estimate provided during December 2014. The Company continues to actively negotiate with its various service providers and expects that additional cost savings can be attained.
2015 Guidance
We are reiterating our 2015 guidance for the first quarter and full-year. We project full-year 2015 average daily production of between 21,700 and 23,700 Boe/d. First quarter 2015 production is projected between 24,000 and 25,000 Boe/d. Under the current operating plan, production will peak during the first quarter and flatten during the second half of the year. Assuming targeted cost reductions are achieved and additional rigs are deployed, capital spending is expected to be $210 million for the full-year. First quarter capital expenditures are expected to be higher than the rest of the year, much like production, due to carry-over activity from late 2014, primarily well completions. For 2015, the company expects to drill between 60 and 70 gross wells with an average working interest of approximately 80%. Due to carry-over of drilled but uncompleted wells from 2014, the Company expects to complete between 70 and 80 wells during 2015, also with an average working interest of approximately 80%.
A table has been provided below with full-year and first quarter 2015 guidance by category:
2015 Guidance
| | 2015E | | 1Q15E | |
Total Production (MMBoe) | | 7.9 – 8.7 | | 2.15 – 2.25 | |
Average Daily Production (MBoe/d) | | 21.7 – 23.7 | | 24.0 – 25.0 | |
| | | | | |
Oil (MBbls/d) | | 6.6 – 7.1 | | 7.4 – 7.6 | |
Natural Gas (MMcf/d) | | 54.8 – 60.3 | | 60.0 – 65.0 | |
NGLs (MBbls/d) | | 6.0 – 6.6 | | 6.6 – 6.8 | |
| | | | | |
Lease Operating Expense ($/Boe) | | $4.75 – $5.25 | | | |
Production/Ad Valorem Taxes (% of Revenue) | | 6.5% – 7.5% | | | |
Cash G&A Expense ($mm) | | $25.0 – $28.0 | | | |
| | | | | |
Total Capital Expenditures | | $210.0 | | | |
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Liquidity and Hedging
In February 2015, the Company completed three transactions which substantially improved its liquidity: a public offering of approximately $77 million of common stock, a private placement of $50 million of common stock, and a private placement of $250 million principal amount of senior notes. As a result of the debt offering, the Company’s borrowing base was reduced to $562.5 million. As of March 2, 2015, the Company held $26.9 million in unrestricted cash and had an undrawn credit facility balance of $482.5 million, resulting in pro-forma liquidity of $509.4 million.
The Company has provided updated hedge positions. The estimated market value of our hedges was $208.5 million as of December 31, 2014. The following table summarizes the Company’s commodity derivative contracts outstanding as of December 31, 2014:
| | Fiscal Year Ending December 31, | |
| | 2015 | | 2016 | | 2017 | | 2018 | |
Oil, Natural Gas and NGL Swaps | | | | | | | | | |
Oil (MBbl) | | 2,322 | | 1,809 | | 769 | | 581 | |
Natural Gas (MMcf) | | 19,543 | | 16,230 | | 11,660 | | 8,980 | |
| | | | | | | | | |
Ethane (MBbl) | | 422 | | 53 | | — | | — | |
Propane (MBbl) | | 643 | | 48 | | — | | — | |
Iso Butane (MBbl) | | 60 | | 16 | | 7 | | — | |
Butane (MBbl) | | 178 | | 38 | | 17 | | — | |
Natural Gasoline (MBbl) | | 233 | | 83 | | 18 | | — | |
Total NGLs (MBbl) | | 1,536 | | 238 | | 42 | | — | |
| | | | | | | | | |
Weighted Average Prices | | | | | | | | | |
Oil ($ / Bbl) | | $ | 84.71 | | $ | 83.81 | | $ | 84.56 | | $ | 82.75 | |
Natural Gas ($ / Mcf) | | 4.47 | | 4.49 | | 4.35 | | 4.29 | |
| | | | | | | | | |
Ethane ($ / Gal) | | $ | 0.27 | | $ | 0.21 | | — | | — | |
Propane ($ / Gal) | | 0.98 | | 0.90 | | — | | — | |
Iso Butane ($ / Gal) | | 1.25 | | 1.32 | | 1.42 | | — | |
Butane ($ / Gal) | | 1.21 | | 1.28 | | 1.37 | | — | |
Natural Gasoline ($ / Gal) | | 1.94 | | 1.90 | | 1.73 | | — | |
| | | | | | | | | | | | | |
Conference Call Details
Jones Energy will host a conference call for investors and analysts to discuss its results for the quarter on Thursday, March 5, 2015 at 3:00 p.m. ET (2:00 p.m. CT). Participants may join the conference call by dialing (877) 201-0168 (for domestic U.S.) or (647) 788-4901 (International) and entering conference code 92843469. If you are not able to participate in the conference call, an audio replay will be available through March 12, 2015, by dialing (855) 859-2056 for domestic U.S., or (404) 537-3406 for international participants, and entering conference code 92843469. A replay of the conference call may also be found on the Company’s website, www.jonesenergy.com.
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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
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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 additional rigs, results of the Company’s drilling program, the 2015 capital budget and operating plan, the ability to achieve targeted drilling and completion cost savings by mid-year and the resultant impact on 2015 capital budget and ability to increase drilling activity to five rigs, the ability to fund the Company’s 2015 capital expenditure budget largely with free cash, the ability to attain additional cost savings from the Company’s service providers, projections regarding total production, average daily production, number of wells drilled, lease operating expenses, production taxes as a percentage of revenue, cash G&A expenses and capital expenditure levels for 2015. 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 and amount of planned capital expenditures, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, 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.
Information Concerning Proved Reserves
Proved reserves volumes and related PV-10 values as of December 31, 2014 contained herein are based on SEC mandated first-day-of-the-month unweighted average prices for 2014 and costs as of December 31, 2014. These prices and costs are not representative of current market values and do not fully reflect declines in such prices and costs which have occurred since mid-year 2014. PV-10 is a non-GAAP financial measure and generally differs
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from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effect of income taxes on discounted future net cash flows. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. The oil and gas industry uses PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. See “Reconciliation of PV-10 to Standardized Measure” below.
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Jones Energy, Inc.
Consolidated Statements of Operations
| | Three Months Ended December 31, | | Twelve Months Ended December 31, | |
(in thousands of dollars except per share data) | | 2014 | | 2013 | | 2014 | | 2013 | |
| | | | | | | | | |
Operating revenues | | | | | | | | | |
Oil and gas sales | | $ | 75,031 | | $ | 69,879 | | $ | 378,401 | | $ | 258,063 | |
Other revenues | | 586 | | 433 | | 2,196 | | 1,106 | |
Total operating revenues | | 75,617 | | 70,312 | | 380,597 | | 259,169 | |
Operating costs and expenses | | | | | | | | | |
Lease operating | | 10,208 | | 8,474 | | 43,843 | | 27,781 | |
Production taxes | | 3,175 | | 3,763 | | 18,094 | | 12,865 | |
Exploration | | 175 | | 252 | | 3,453 | | 1,710 | |
Depletion, depreciation and amortization | | 44,179 | | 31,584 | | 181,669 | | 114,136 | |
Impairment of oil and gas properties | | — | | 14,415 | | — | | 14,415 | |
Accretion of discount | | 197 | | 174 | | 770 | | 608 | |
General and administrative (including non-cash compensation expense) | | 7,040 | | 6,291 | | 25,763 | | 31,902 | |
Total operating expenses | | 64,974 | | 64,953 | | 273,592 | | 203,417 | |
Operating income | | 10,643 | | 5,359 | | 107,005 | | 55,752 | |
Other income (expense) | | | | | | | | | |
Interest expense | | (12,067 | ) | (7,348 | ) | (46,726 | ) | (30,774 | ) |
Net gain (loss) on commodity derivatives | | 199,426 | | (7,009 | ) | 189,641 | | (2,566 | ) |
Gain (loss) on sales of assets | | 200 | | (48 | ) | 297 | | (78 | ) |
Other income (expense), net | | 187,559 | | (14,405 | ) | 143,212 | | (33,418 | ) |
Income (loss) before income tax | | 198,202 | | (9,046 | ) | 250,217 | | 22,334 | |
| | | | | | | | | |
Income tax provision (benefit) | | 20,336 | | 31 | | 26,074 | | (71 | ) |
Net income (loss) | | 177,866 | | (9,077 | ) | 224,143 | | 22,405 | |
Net income (loss) attributable to non-controlling interests | | 145,441 | | (7,751 | ) | 183,275 | | 24,591 | |
Net income (loss) attributable to controlling interests | | $ | 32,425 | | $ | (1,326 | ) | $ | 40,868 | | $ | (2,186 | ) |
| | | | | | | | | |
Earnings per share: | | | | | | | | | |
Basic | | $ | 2.58 | | $ | (0.10 | ) | $ | 3.26 | | $ | (0.17 | ) |
Diluted | | $ | 2.58 | | $ | (0.10 | ) | $ | 3.26 | | $ | (0.17 | ) |
Weighted average shares outstanding: | | | | | | | | | |
Basic | | 12,598 | | 12,500 | | 12,526 | | 12,500 | |
Diluted | | 12,598 | | 12,500 | | 12,535 | | 12,500 | |
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Jones Energy, Inc.
Consolidated Balance Sheets
| | December 31, | | December 31, | |
(in thousands of dollars) | | 2014 | | 2013 | |
| | | | | |
Assets | | | | | |
Current assets | | | | | |
Cash | | $ | 13,566 | | $ | 23,820 | |
Restricted Cash | | 149 | | 45 | |
Accounts receivable, net | | | | | |
Oil and gas sales | | 49,861 | | 51,233 | |
Joint interest owners | | 41,761 | | 42,481 | |
Other | | 12,512 | | 16,782 | |
Commodity derivative assets | | 121,519 | | 8,837 | |
Other current assets | | 3,374 | | 2,392 | |
Deferred tax assets | | — | | 12 | |
Total current assets | | 242,742 | | 145,602 | |
Oil and gas properties, net, at cost under the successful efforts method | | 1,638,860 | | 1,297,228 | |
Other property, plant and equipment, net | | 4,048 | | 3,444 | |
Commodity derivative assets | | 87,055 | | 25,398 | |
Other assets | | 20,352 | | 15,006 | |
Deferred tax assets | | 171 | | 1,301 | |
Total assets | | $ | 1,993,228 | | $ | 1,487,979 | |
| | | | | |
Liabilities and Stockholders’ Equity | | | | | |
Current liabilities | | | | | |
Trade accounts payable | | $ | 136,337 | | $ | 89,430 | |
Oil and gas sales payable | | 70,469 | | 66,179 | |
Accrued liabilities | | 19,401 | | 10,805 | |
Commodity derivative liabilities | | — | | 10,664 | |
Deferred tax liabilities | | 718 | | — | |
Asset retirement obligations | | 3,074 | | 2,590 | |
Total current liabilities | | 229,999 | | 179,668 | |
Long-term debt | | 360,000 | | 658,000 | |
Senior notes | | 500,000 | | — | |
Deferred revenue | | 13,377 | | 14,531 | |
Commodity derivative liabilities | | 28 | | 190 | |
Asset retirement obligations | | 10,536 | | 8,373 | |
Liability under the tax receivable agreement | | 803 | | — | |
Deferred tax liabilities | | 26,612 | | 3,093 | |
Total liabilities | | 1,141,355 | | 863,855 | |
Commitments and contingencies | | | | | |
Members’ equity | | — | | — | |
Class A common stock, $0.001 par value; 12,672,260 shares issued and 12,649,658 shares outstanding at December 31, 2014 and 12,526,580 shares issued and outstanding at December 31, 2013 | | 13 | | 13 | |
Class B common stock, $0.001 par value; 36,719,499 shares issued and outstanding as of December 31, 2014 and 36,836,333 shares issued and outstanding at December 31, 2013 | | 37 | | 37 | |
Treasury stock, at cost: 22,602 Class A shares at December 31, 2014 and 0 shares at December 31, 2013 | | (358 | ) | — | |
Additional paid-in-capital | | 177,133 | | 173,169 | |
Retained earnings (deficit) | | 38,682 | | (2,186 | ) |
Stockholders’ equity | | 215,507 | | 171,033 | |
Non-controlling interest | | 636,366 | | 453,091 | |
| | 851,873 | | 624,124 | |
Total liabilities and stockholders’ equity | | $ | 1,993,228 | | $ | 1,487,979 | |
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Jones Energy, Inc.
Consolidated Statements of Cash Flows
| | Twelve Months Ended December 31, | |
(in thousands of dollars) | | 2014 | | 2013 | |
| | | | | |
Cash flows from operating activities | | | | | |
Net income | | $ | 224,143 | | $ | 22,405 | |
Adjustments to reconcile net income to net cash provided by operating activities | | | | | |
Depletion, depreciation, and amortization | | 181,669 | | 114,136 | |
Exploration expense | | 2,952 | | — | |
Impairment of oil and gas properties | | — | | 14,415 | |
Accretion of discount | | 770 | | 608 | |
Amortization of debt issuance costs | | 6,878 | | 2,677 | |
Accrued interest expense | | 7,823 | | 1,891 | |
Stock compensation expense | | 4,040 | | 10,838 | |
Other non-cash compensation expense | | 758 | | 2,719 | |
Amortization of deferred revenue | | (1,154 | ) | (469 | ) |
Net loss (gain) on commodity derivatives | | (189,641 | ) | 2,566 | |
Gain on sales of assets | | (297 | ) | 78 | |
Deferred income taxes | | 26,021 | | (156 | ) |
Other - net | | 376 | | 79 | |
Changes in assets and liabilities | | | | | |
Accounts receivable | | (832 | ) | (56,804 | ) |
Other assets | | (565 | ) | 163 | |
Accounts payable and accrued liabilities | | 2,482 | | 33,427 | |
Net cash provided by operations | | 265,423 | | 148,573 | |
Cash flows from investing activities | | | | | |
Additions to oil and gas properties | | (474,619 | ) | (197,618 | ) |
Acquisition of properties | | — | | (178,173 | ) |
Net adjustments to purchase price of properties acquired | | 15,709 | | — | |
Proceeds from sales of assets | | 448 | | 1,607 | |
Acquisition of other property, plant and equipment | | (1,683 | ) | (1,634 | ) |
Current period settlements of matured derivative contracts | | (3,654 | ) | 7,586 | |
Change in restricted cash | | (104 | ) | (45 | ) |
Net cash used in investing | | (463,903 | ) | (368,277 | ) |
Cash flows from financing activities | | | | | |
Proceeds from issuance of long-term debt | | 170,000 | | 220,000 | |
Repayment under long-term debt | | (468,000 | ) | (172,000 | ) |
Proceeds from senior notes | | 500,000 | | — | |
Proceeds from sale of common stock, net of expenses of $15.1 million | | — | | 172,481 | |
Purchases of treasury stock | | (358 | ) | — | |
Payment of debt issuance costs | | (13,416 | ) | (683 | ) |
Net cash provided by financing | | 188,226 | | 219,798 | |
Net increase (decrease) in cash | | (10,254 | ) | 94 | |
Cash | | | | | |
Beginning of period | | 23,820 | | 23,726 | |
End of period | | $ | 13,566 | | $ | 23,820 | |
Supplemental disclosure of cash flow information | | | | | |
Cash paid for interest | | $ | 29,560 | | $ | 25,414 | |
Cash paid for income taxes | | 155 | | — | |
Change in accrued additions to oil and gas properties | | 49,025 | | 41,945 | |
Current additions to ARO | | 1,995 | | 1,516 | |
Noncash distribution to members | | — | | 10,000 | |
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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 December 31, | | Twelve Months Ended December 31, | |
| | 2014 | | 2013 | | Change | | 2014 | | 2013 | | Change | |
Net production volumes: | | | | | | | | | | | | | |
Oil (MBbls) | | 606 | | 431 | | 175 | | 2,475 | | 1,557 | | 918 | |
Natural gas (MMcf) | | 5,551 | | 4,753 | | 798 | | 21,922 | | 17,575 | | 4,347 | |
NGLs (MBbls) | | 612 | | 437 | | 175 | | 2,345 | | 1,724 | | 621 | |
Total (MBoe) | | 2,143 | | 1,660 | | 483 | | 8,474 | | 6,210 | | 2,264 | |
Average net (Boe/d) | | 23,293 | | 18,043 | | 5,250 | | 23,216 | | 17,014 | | 6,202 | |
Average sales price, unhedged: | | | | | | | | | | | | | |
Oil (per Bbl), unhedged | | $ | 67.80 | | $ | 93.66 | | $ | (25.86 | ) | $ | 88.93 | | $ | 93.22 | | $ | (4.29 | ) |
Natural gas (per Mcf), unhedged | | 3.41 | | 3.03 | | 0.38 | | 3.78 | | 3.16 | | 0.62 | |
NGLs (per Bbl), unhedged | | 24.53 | | 34.61 | | (10.08 | ) | 32.14 | | 33.30 | | (1.16 | ) |
Combined (per Boe) realized, unhedged | | 35.01 | | 42.10 | | (7.09 | ) | 44.65 | | 41.56 | | 3.09 | |
Average sales price, hedged: | | | | | | | | | | | | | |
Oil (per Bbl), hedged | | $ | 83.53 | | $ | 88.65 | | $ | (5.12 | ) | $ | 88.16 | | $ | 87.86 | | $ | 0.30 | |
Natural gas (per Mcf), hedged | | 3.92 | | 3.77 | | 0.15 | | 4.02 | | 3.93 | | 0.09 | |
NGLs (per Bbl), hedged | | 32.23 | | 31.34 | | 0.89 | | 32.60 | | 33.26 | | (0.66 | ) |
Combined (per Boe) realized, hedged | | 42.97 | | 42.07 | | 0.90 | | 45.18 | | 42.40 | | 2.78 | |
Average costs (per Boe): | | | | | | | | | | | | | |
Lease operating | | $ | 4.76 | | $ | 5.10 | | $ | (0.34 | ) | $ | 5.17 | | $ | 4.47 | | $ | 0.70 | |
Production taxes | | 1.48 | | 2.27 | | (0.79 | ) | 2.14 | | 2.07 | | 0.07 | |
Depletion, depreciation and amortization | | 20.62 | | 19.03 | | 1.59 | | 21.44 | | 18.38 | | 3.06 | |
General and administrative | | 3.29 | | 3.79 | | (0.50 | ) | 3.04 | | 5.14 | | (2.10 | ) |
12
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 December 31, | | Twelve Months Ended December 31, | |
(in thousands of dollars) | | 2014 | | 2013 | | 2014 | | 2013 | |
| | | | | | | | | |
Reconciliation of EBITDAX to net income | | | | | | | | | |
Net income (loss) | | $ | 177,866 | | $ | (9,077 | ) | $ | 224,143 | | $ | 22,405 | |
Interest expense (excluding amortization of deferred financing costs) | | 11,318 | | 6,674 | | 39,848 | | 28,097 | |
Exploration expense | | 175 | | 252 | | 3,453 | | 1,710 | |
Income taxes | | 20,336 | | 31 | | 26,074 | | (71 | ) |
Amortization of deferred financing costs | | 749 | | 674 | | 6,878 | | 2,677 | |
Depreciation and depletion | | 44,179 | | 31,584 | | 181,669 | | 114,136 | |
Impairment of oil and natural gas properties | | — | | 14,415 | | — | | 14,415 | |
Accretion expense | | 197 | | 174 | | 770 | | 608 | |
Other non-cash charges (benefits) | | 135 | | (148 | ) | 376 | | 79 | |
Stock compensation expense | | 1,333 | | 459 | | 4,040 | | 10,838 | |
Other non-cash compensation expense | | 378 | | 127 | | 758 | | 2,719 | |
Net loss (gain) on commodity derivatives | | (199,426 | ) | 7,010 | | (189,641 | ) | 2,566 | |
Current period settlements of matured derivative contracts | | 17,086 | | (53 | ) | 4,476 | | 5,209 | |
Amortization of deferred revenue | | (292 | ) | (355 | ) | (1,154 | ) | (469 | ) |
Loss (gain) on sales of assets | | (200 | ) | 48 | | (297 | ) | 78 | |
EBITDAX | | $ | 73,834 | | $ | 51,815 | | $ | 301,393 | | $ | 204,997 | |
13
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 December 31, | | Twelve Months Ended December 31, | |
(in thousands of dollars except per share data) | | 2014 | | 2013 | | 2014 | | 2013 | |
| | | | | | | | | |
Net income (loss) | | $ | 177,866 | | $ | (9,077 | ) | $ | 224,143 | | $ | 22,405 | |
Net (gain)/ loss on commodity derivatives | | (199,426 | ) | 7,010 | | (189,641 | ) | 2,566 | |
Current period settlements of matured derivative contracts | | 17,086 | | (53 | ) | 4,476 | | 5,209 | |
Impairment of oil and gas properties | | — | | 14,415 | | — | | 14,415 | |
Non-cash stock compensation expense | | 1,333 | | 459 | | 4,040 | | 10,838 | |
Other non-cash compensation expense | | 378 | | 127 | | 758 | | 2,719 | |
Net unamortized capitalized loan costs associated with Term Loan | | — | | — | | 3,761 | | — | |
Tax impact(1) | | 17,112 | | (1,993 | ) | 16,668 | | (3,360 | ) |
Adjusted net income | | 14,349 | | 10,888 | | 64,205 | | 54,792 | |
Adjusted net income attributable to non-controlling interests | | 11,650 | | 8,715 | | 52,423 | | 51,182 | |
Adjusted net income attributable to controlling interests | | $ | 2,699 | | $ | 2,173 | | $ | 11,782 | | $ | 3,610 | |
| | | | | | | | | |
Effective tax rate on net income attributable to controlling interests | | | | | | 35.7 | % | 36.9 | % |
(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.
14
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 December 31, | | Twelve Months Ended December 31, | |
| | 2014 | | 2013 | | 2014 | | 2013 | |
| | | | | | | | | |
Earnings per share (basic) | | $ | 2.58 | | $ | (0.10 | ) | $ | 3.26 | | $ | (0.17 | ) |
Net (gain)/ loss on commodity derivatives | | (4.05 | ) | 0.14 | | (3.85 | ) | 0.43 | |
Current period settlements of matured derivative contracts | | 0.35 | | — | | 0.09 | | (0.01 | ) |
Impairment of oil and gas properties | | — | | 0.29 | | — | | 0.29 | |
Non-cash stock compensation expense | | 0.02 | | 0.01 | | 0.08 | | 0.02 | |
Other non-cash compensation expense | | 0.01 | | — | | 0.02 | | — | |
Net unamortized capitalized loan costs associated with Term Loan | | — | | — | | 0.08 | | — | |
Tax impact | | 1.29 | | (0.17 | ) | 1.26 | | (0.27 | ) |
Adjusted earnings per share (basic) | | $ | 0.20 | | $ | 0.17 | | $ | 0.94 | | $ | 0.29 | |
| | | | | | | | | |
Earnings per share (diluted) | | $ | 2.58 | | $ | (0.10 | ) | $ | 3.26 | | $ | (0.17 | ) |
Net (gain)/ loss on commodity derivatives | | (4.05 | ) | 0.14 | | (3.85 | ) | 0.43 | |
Current period settlements of matured derivative contracts | | 0.35 | | — | | 0.09 | | (0.01 | ) |
Impairment of oil and gas properties | | — | | 0.29 | | — | | 0.29 | |
Non-cash stock compensation expense | | 0.02 | | 0.01 | | 0.08 | | 0.02 | |
Other non-cash compensation expense | | 0.01 | | — | | 0.02 | | — | |
Net unamortized capitalized loan costs associated with Term Loan | | — | | — | | 0.08 | | — | |
Tax impact | | 1.29 | | (0.17 | ) | 1.26 | | (0.27 | ) |
Adjusted earnings per share (diluted) | | $ | 0.20 | | $ | 0.17 | | $ | 0.94 | | $ | 0.29 | |
15
Jones Energy, Inc.
Non-GAAP Financial Measures and Reconciliations
PV-10 is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the Standardized Measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure of discounted future net cash flows. Our PV-10 measure and the Standardized Measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.
The following table provides a reconciliation of PV-10 to the Standardized Measure of discounted future net cash flows at December 31, 2014 and December 31, 2013.
| | As of December 31, | |
| | 2014 | | 2013 | |
| | ($ in millions) | |
| | | | | |
PV-10 | | $ | 1,502 | | $ | 1,017 | |
Present value of future income taxes discounted at 10% | | 114 | | 76 | |
Standardized measure | | $ | 1,388 | | $ | 941 | |
16
