Exhibit 99.1
JONES ENERGY, INC. ANNOUNCES 2014 THIRD QUARTER FINANCIAL AND OPERATING RESULTS
Austin, TX — November 5, 2014 — Jones Energy, Inc. (NYSE: JONE) (“Jones Energy” or “the Company”) today announced financial and operating results for the quarter and nine months ended September 30, 2014. For the quarter ended September 30, 2014, the Company reported net income of $52.2 million, adjusted net income of $16.3 million, and EBITDAX of $78.8 million.
2014 Third Quarter Highlights
· Average daily net production for the quarter was 24.5 MBoe/d (top end of guidance range).
· Cleveland 20x3 frack trial wells have now produced on average 9,800 incremental barrels of oil through the first 300 days of production. Early indications from the new cemented sliding sleeve wells show oil production which is at or above the frack trial oil production curve.
· Leased an additional 6,924 net acres since June 30th providing approximately 50 additional Cleveland net drilling locations. Average leasehold acquisition cost for the year is less than $1,500 per net acre. Cleveland net drilling locations acquired year to date now total approximately 130, which is nearly double the number of budgeted locations to be drilled in 2014.
· Signed a 10-year oil gathering and transportation agreement to transport our oil to both Plains and Valero market points. The gathering system is expected to begin operations during the second quarter of 2015.
· Increased borrowing base for senior secured revolving credit facility from $550 to $625 million.
· Increased hedge positions for crude oil to 150% of proved developed producing (“PDP”) reserves in 2015 and roughly 200% in 2016. For both oil and natural gas, approximately 60% of forecasted production from proved reserves is hedged through year-end 2016.
Jonny Jones, the Company’s Founder, Chairman and CEO commented, “During the third quarter, we were very active with eleven rigs running in the Anadarko and Arkoma basins. We continued to implement our new cemented sliding sleeve technique for the completions on all Anadarko wells and have deployed more than 1,000 frack stages with a 99% success rate thus far. During the fourth quarter, we are bringing in an additional frack crew to help reduce the backlog of drilled wells awaiting completion that were carried over from the third quarter. As we catch up on completions, we expect the impact of our new technique should begin to become more apparent as we move into early 2015. Our early drilling results in the Tonkawa have shown that we are on track to meet and potentially beat the target AFE of $3.5 million we established for the program. We also continued to be very active in our leasing program, adding another 50 net drilling locations in the Cleveland at very competitive
prices.” Mr. Jones went on to say, “The market reaction to the recent decline in oil prices reflects investor uncertainty regarding the growth and profitability of the entire sector. We believe Jones is well positioned moving forward due to our very strong hedge book, significant liquidity and our commitment to operational excellence. We have always tried to take price risk off the table and during times like these, we are well prepared with more than 150% of our forecasted production from PDP reserves hedged through 2016. In addition, we continue to maintain solid liquidity and do not plan to access capital markets unless the right situations arise. As we begin our 2015 budgeting process, our opportunities are ample and we will be judicous in selecting the uses of capital we believe provide our investors with the best return for their investment. We have historically thrived during times like these and we expect that will continue to be the case.”
Financial Results
Total operating revenues for the three months ended September 30, 2014 increased by $31.4 million to $100.3 million as compared to $68.9 million for the three months ended September 30, 2013. The increase was due to increased production volumes for all commodities.
Total operating expenses for the three months ended September 30, 2014 increased by $14.8 million to $71.6 million as compared to $56.8 million for the three months ended September 30, 2013, primarily due to the increase in production volumes.
Adjusted net income for the three months ended September 30, 2014 increased by $3.2 million to $16.3 million as compared to $13.1 million for the three months ended September 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 27 wells and completed 19 wells in the Cleveland in the third quarter of 2014. As of September 30, 2014, 11 wells were in various stages of completion, and 9 wells were drilling.
Daily net production in the Cleveland was 18.3 MBoe/d in the third quarter of 2014, up 9% from the second quarter of 2014 and up 73% from the third quarter of 2013. Oil production volumes were relatively flat compared to the previous quarter due to temporary operational issues. During the quarter, the Company encountered batch frack scheduling issues, a delay in bringing an additional frack crew online in the Cleveland, and sand flow back issues which delayed initial production on certain wells. We have recently secured two full time frack crews and are bringing in a third crew in December to reduce the back log of wells awaiting frack operations. We expect to be caught up sometime near the end of the year. Altogether, these factors resulted in the delay of initial production for 10 Cleveland wells for an average of two weeks each. Seven of those wells were deferred until after the end of the quarter. While less impactful, the first five wells completed during the quarter using the cemented sliding sleeve technique only incorporated 20 sleeves in order to provide a comparable to our previous
20 stage open-hole technique and thus did not provide the expected oil uplift of our new increased frack density. Our realized average drilling and completion cost since implementing the new cemented sliding sleeve design has been very close to our target AFE of $4.3 million with a few early exceptions. As more wells are drilled and completed, we expect to achieve, on average, our target well cost.
During the third quarter, deployment of the new sliding sleeve completion technique continued with nearly 1,500 sleeves now installed and more than 1,000 individual stages completed. Our frack initiation success rate continues to be 99%. As mentioned in the last quarterly earnings update, our expectations are that wells completed utilizing the new cemented sliding sleeve technique will yield greater than 30% uplift in oil production when compared to our historic 20 stage open-hole performance. Although we have limited data at this time, early results from the cemented sliding sleeve wells suggest equal or better results when compared to the oil decline curve plotted for the 20x3 Cleveland frack trial wells. As a reminder, the 20x3 frack trial wells have now produced on average 9,800 incremental barrels of oil through the first 300 days when compared to our historic 20 stage open-hole performance. As previously stated, we believe that the oil uplift resulting from increased frack density in our new completion design has caused the value of our entire Cleveland drilling portfolio to increase significantly.
Tonkawa
During the third quarter, the Company drilled four wells targeting the Tonkawa formation. The first two Tonkawa wells began producing, the third well was fracked and placed on flow back, and the fourth well reached TD and was awaiting completion. Well costs have improved with the third and fourth wells expected to average just over $3.6 million versus $4.0 million for the first Tonkawa well drilled. Our target well cost for the Tonkawa is still $3.5 million, which is $1 million less than the estimated industry average cost of $4.5 million. Plans at this time are to continue the Tonkawa drilling program through year end and provide an updated look at 2015 activity once the budgeting process has been completed.
Woodford
The Company spud 4 wells and completed 6 wells in the Woodford in the third quarter of 2014. As of September 30, 2014, 5 wells were in various stages of completion, and 2 wells were drilling.
Net production in the Woodford was 4.0 MBoe/d in the third quarter of 2014 compared to 4.0 MBoe/d in the third quarter of 2013 and 4.2 MBoe/d in the second quarter of 2014. As noted in our second quarter 2014 earnings release, certain wells drilled during the second quarter, which began producing in the third quarter, saw greater geologic complexity resulting in shorter laterals in the productive zone. These wells brought online early in the third quarter were the primary factor driving lower than expected production from the Woodford.
The Company has seen measurable improvements in the drilling costs of the most recent five Woodford wells. The average well cost is projected to be just under $4.1 million beating the average pre-drill AFE of $4.4 million. The lower cost is primarily due to improved drilling operations, less geologic complexity of the sections drilled,
minor changes to well design, and some improvement in process efficiencies. The company is currently drilling the final planned Woodford well for 2014 which is expected to reach TD during November.
Oil Gathering and Transportation Agreement
The Company recently signed a 10-year oil gathering and transportation agreement with Monarch Oil Pipeline LLC, which will build at its expense a new oil gathering system and connect to all dedicated Jones lease locations. The system is expected to begin service during the second quarter of 2015 and will provide transport to both Plains and Valero market points. The agreement provides pipeline gathering services at Jones well pads, provides greater flow assurance (versus trucking) during inclement weather, reduces the need for truck hauling services, and lessens the burden of operational coordination of those services. In addition, the wells tied to the gathering system are expected to see an improvement in net oil pricing. The gathering system provides connectivity to both the regional refinery market as well as the Cushing market hub. Jones Energy has reserved capacity of up to 12,000 barrels per day on the system with the potential to increase throughput at a future date.
Leasing
For the year to date, the Company has added a total of 16,924 net acres, nearly all of which is in the Company’s primary area of operations in the Anadarko basin. The Company has spent a total of approximately $22 million on leasehold acquisition, resulting in a cost per acre of less than $1,500. The recent additions bring the new total acquired net drilling locations in the Cleveland formation to 130 for the year. This is nearly double the number of net Cleveland wells budgeted for drilling during 2014. The Company continues to see additional lease opportunities and expects to continue to acquire additional acreage during the remainder of the year.
Liquidity and Hedging
As of September 30, 2014, the Company held $32.8 million in unrestricted cash and had an undrawn credit facility balance of $280 million. On November 5, 2014, the Company’s borrowing base on its senior secured revolving credit facility was increased to $625 million.
As part of its normal course of business, the Company has continued to add additional hedge positions. Currently, 150% of the 2015 and nearly 200% of the 2016 forecasted production from proved developed producing oil reserves has been hedged. A table providing the latest summary hedge positions is shown below.
Commodity Hedge Positions (1) |
| 2015 |
| 2016 |
| ||
|
|
|
|
|
| ||
Oil (Mbbls) |
| 2,066 |
| 1,786 |
| ||
NGL (Mbbls) (2) |
| 1,500 |
| 238 |
| ||
Natural Gas (MMcf) |
| 15,283 |
| 11,880 |
| ||
|
|
|
|
|
| ||
Oil ($/bbl) |
| $ | 85.89 |
| $ | 83.90 |
|
NGL ($/bbl) (2) |
| $ | 40.90 |
| $ | 49.82 |
|
Natural Gas ($/Mcf) |
| $ | 4.63 |
| $ | 4.73 |
|
(1) All hedges shown are swaps and prices represent weighted average contract price for the year denoted
(2) Hedging levels by product vary from year to year
Capital Expenditures
During the third quarter of 2014, the Company spent $131.2 million, of which $120.0 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:
Capital Expenditure Summary
|
| Three months ended |
| Nine months ended |
| ||
Cleveland |
| $ | 96.7 |
| $ | 273.6 |
|
Woodford |
| 17.6 |
| 52.9 |
| ||
Other Areas & Non-Op |
| 5.7 |
| 8.2 |
| ||
Total Drilling and Completion |
| 120.0 |
| 334.7 |
| ||
|
|
|
|
|
| ||
Leasehold & Other |
| 11.2 |
| 34.0 |
| ||
Total Capital Expenditures |
| $ | 131.2 |
| $ | 368.7 |
|
Guidance
The Company is providing guidance for the fourth quarter and affirming guidance for the full year 2014 as follows:
|
| 4Q14E |
| Full Year 2014E |
|
Total Production (MMBoe) |
| 2.25 – 2.30 |
| 8.4 – 8.8 |
|
Average Daily Production (MBoe/d) |
| 24.5 – 25.0 |
| 23.0 – 24.0 |
|
Lease Operating Expenses ($/Boe) |
| $5.00 - $5.50 |
| $5.00 - $5.50 |
|
Capital Spending ($ in millions) |
|
|
| $460 |
|
Conference Call Details
Jones Energy will host a conference call for investors and analysts to discuss its results for the third quarter on Thursday, November 6, 2014 at 10:30 a.m. ET (9:30 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 21669762. A telephonic replay will be available approximately two hours after the call on November 6, 2014 through Thursday, November 13, 2014. Participants may access this replay by dialing (855) 859-2056 (for domestic U.S.) or (404) 537-3406 (International) and entering conference code 21669762. 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 and completion activity and ability to acquire additional acreage, results of our new cemented sliding sleeve technique in the Cleveland formation, including projected uplifts in oil production and the potential impact on the value of our Cleveland drilling portfolio, our ability to mitigate commodity price risk through our hedging program, our expected average well cost for the Tonkawa and Woodford formations, expected improvements in net oil pricing as a result of the Monarch oil gathering and transportation agreement, 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, natural gas liquids, 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 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 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 September 30, |
| Nine Months Ended September 30, |
| ||||||||
(in thousands of dollars except per share data) |
| 2014 |
| 2013 |
| 2014 |
| 2013 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Operating revenues |
|
|
|
|
|
|
|
|
| ||||
Oil and gas sales |
| $ | 99,707 |
| $ | 68,625 |
| $ | 303,370 |
| $ | 188,184 |
|
Other revenues |
| 639 |
| 226 |
| 1,610 |
| 673 |
| ||||
Total operating revenues |
| 100,346 |
| 68,851 |
| 304,980 |
| 188,857 |
| ||||
Operating costs and expenses |
|
|
|
|
|
|
|
|
| ||||
Lease operating |
| 11,244 |
| 7,761 |
| 33,635 |
| 19,308 |
| ||||
Production taxes |
| 4,983 |
| 3,469 |
| 14,919 |
| 9,103 |
| ||||
Exploration |
| 266 |
| 853 |
| 3,278 |
| 1,458 |
| ||||
Depletion, depreciation and amortization |
| 47,965 |
| 30,529 |
| 130,521 |
| 82,552 |
| ||||
Accretion of discount |
| 206 |
| 170 |
| 573 |
| 434 |
| ||||
General and administrative (including non-cash compensation expense) |
| 6,925 |
| 13,974 |
| 18,723 |
| 25,611 |
| ||||
Total operating expenses |
| 71,589 |
| 56,756 |
| 201,649 |
| 138,466 |
| ||||
Operating income |
| 28,757 |
| 12,095 |
| 103,331 |
| 50,391 |
| ||||
Other income (expense) |
|
|
|
|
|
|
|
|
| ||||
Interest expense |
| (11,849 | ) | (7,148 | ) | (34,659 | ) | (23,427 | ) | ||||
Net gain (loss) on commodity derivatives |
| 41,163 |
| (20,728 | ) | (9,785 | ) | 4,444 |
| ||||
Gain (loss) on sales of assets |
| 30 |
| (55 | ) | 97 |
| (30 | ) | ||||
Other income (expense), net |
| 29,344 |
| (27,931 | ) | (44,347 | ) | (19,013 | ) | ||||
Income (loss) before income tax |
| 58,101 |
| (15,836 | ) | 58,984 |
| 31,378 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Income tax provision (benefit) |
| 5,871 |
| (344 | ) | 6,550 |
| (93 | ) | ||||
Net income (loss) |
| 52,230 |
| (15,492 | ) | 52,434 |
| 31,471 |
| ||||
Net income (loss) attributable to non-controlling interests |
| 42,701 |
| (14,623 | ) | 42,879 |
| 32,340 |
| ||||
Net income (loss) attributable to controlling interests |
| $ | 9,529 |
| $ | (869 | ) | $ | 9,555 |
| $ | (869 | ) |
|
|
|
|
|
|
|
|
|
| ||||
Earnings per share: |
|
|
|
|
|
|
|
|
| ||||
Basic |
| $ | 0.76 |
| $ | (0.07 | ) | $ | 0.76 |
| $ | (0.07 | ) |
Diluted |
| $ | 0.76 |
| $ | (0.07 | ) | $ | 0.76 |
| $ | (0.07 | ) |
Weighted average shares outstanding: |
|
|
|
|
|
|
|
|
| ||||
Basic |
| 12,508 |
| 12,500 |
| 12,503 |
| 12,500 |
| ||||
Diluted |
| 12,573 |
| 12,500 |
| 12,540 |
| 12,500 |
| ||||
Jones Energy, Inc.
Consolidated Balance Sheet
|
| September 30, |
| December 31, |
| ||
(in thousands of dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
Assets |
|
|
|
|
| ||
Current assets |
|
|
|
|
| ||
Cash |
| $ | 32,790 |
| $ | 23,820 |
|
Restricted Cash |
| 97 |
| 45 |
| ||
Accounts receivable, net |
|
|
|
|
| ||
Oil and gas sales |
| 62,146 |
| 51,233 |
| ||
Joint interest owners |
| 36,009 |
| 42,481 |
| ||
Other |
| 2,313 |
| 16,782 |
| ||
Commodity derivative assets |
| 13,077 |
| 8,837 |
| ||
Other current assets |
| 3,120 |
| 2,392 |
| ||
Deferred tax assets |
| — |
| 12 |
| ||
Total current assets |
| 149,552 |
| 145,602 |
| ||
Oil and gas properties, net, at cost under the successful efforts method |
| 1,533,704 |
| 1,297,228 |
| ||
Other property, plant and equipment, net |
| 3,863 |
| 3,444 |
| ||
Commodity derivative assets |
| 15,125 |
| 25,398 |
| ||
Other assets |
| 18,950 |
| 15,006 |
| ||
Deferred tax assets |
| — |
| 1,301 |
| ||
Total assets |
| $ | 1,721,194 |
| $ | 1,487,979 |
|
Liabilities and Stockholders’ Equity |
|
|
|
|
| ||
Current liabilities |
|
|
|
|
| ||
Trade accounts payable |
| $ | 118,687 |
| $ | 89,430 |
|
Oil and gas sales payable |
| 73,343 |
| 66,179 |
| ||
Accrued liabilities |
| 43,506 |
| 10,805 |
| ||
Commodity derivative liabilities |
| 988 |
| 10,664 |
| ||
Deferred tax liabilities |
| 68 |
| — |
| ||
Asset retirement obligations |
| 3,026 |
| 2,590 |
| ||
Total current liabilities |
| 239,618 |
| 179,668 |
| ||
Long-term debt |
| 270,000 |
| 658,000 |
| ||
Senior notes |
| 500,000 |
| — |
| ||
Deferred revenue |
| 13,669 |
| 14,531 |
| ||
Commodity derivative liabilities |
| 1,010 |
| 190 |
| ||
Asset retirement obligations |
| 9,642 |
| 8,373 |
| ||
Deferred tax liabilities |
| 8,348 |
| 3,093 |
| ||
Total liabilities |
| 1,042,287 |
| 863,855 |
| ||
Commitments and contingencies |
|
|
|
|
| ||
Stockholders’ equity |
|
|
|
|
| ||
Class A common stock, $0.001 par value; 12,576,612 shares issued and 12,554,010 shares outstanding at September 30, 2014 and 12,526,580 shares issued and outstanding at December 31, 2013 |
| 13 |
| 13 |
| ||
Class B common stock, $0.001 par value; 36,813,731 shares issued and outstanding at September 30, 2014 and and 36,836,333 shares issued and outstanding at December 31, 2013 |
| 37 |
| 37 |
| ||
Treasury stock, at cost: 22,602 Class A shares at September 30, 2014 and 0 shares at December 31, 2013 |
| (358 | ) | — |
| ||
Additional paid-in-capital |
| 175,876 |
| 173,169 |
| ||
Retained earnings (deficit) |
| 7,369 |
| (2,186 | ) | ||
Stockholders’ equity |
| 182,937 |
| 171,033 |
| ||
Non-controlling interest |
| 495,970 |
| 453,091 |
| ||
Total stockholders’ equity |
| 678,907 |
| 624,124 |
| ||
Total liabilities and stockholders’ equity |
| $ | 1,721,194 |
| $ | 1,487,979 |
|
Jones Energy, Inc.
Consolidated Statement of Cash Flow Data
|
| Nine Months Ended September 30, |
| ||||
(in thousands of dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
Cash flows from operating activities |
|
|
|
|
| ||
Net income |
| $ | 52,434 |
| $ | 31,471 |
|
Adjustments to reconcile net income to net cash provided by operating activities |
|
|
|
|
| ||
Depletion, depreciation, and amortization |
| 130,521 |
| 82,552 |
| ||
Dry hole costs |
| 2,952 |
| — |
| ||
Accretion of discount |
| 573 |
| 434 |
| ||
Amortization of debt issuance costs |
| 6,129 |
| 2,003 |
| ||
Accrued interest expense |
| 16,611 |
| — |
| ||
Stock compensation expense |
| 2,707 |
| 10,379 |
| ||
Other non-cash compensation expense |
| 380 |
| 2,592 |
| ||
Amortization of deferred revenue |
| (862 | ) | (114 | ) | ||
Net loss (gain) on commodity derivatives |
| 9,785 |
| (4,444 | ) | ||
Gain on sales of assets |
| (97 | ) | 30 |
| ||
Deferred income taxes |
| 6,637 |
| (141 | ) | ||
Other - net |
| 241 |
| 227 |
| ||
Changes in assets and liabilities |
|
|
|
|
| ||
Accounts receivable |
| (4,961 | ) | (23,359 | ) | ||
Other assets |
| 631 |
| 643 |
| ||
Accounts payable and accrued liabilities |
| 28,151 |
| 16,292 |
| ||
Net cash provided by operations |
| 251,832 |
| 118,565 |
| ||
Cash flows from investing activities |
|
|
|
|
| ||
Additions to oil and gas properties |
| (343,405 | ) | (127,478 | ) | ||
Net adjustments to purchase price of properties acquired |
| 15,709 |
| — |
| ||
Proceeds from sales of assets |
| 99 |
| 629 |
| ||
Acquisition of other property, plant and equipment |
| (1,196 | ) | (440 | ) | ||
Current period settlements of matured derivative contracts |
| (14,228 | ) | 7,680 |
| ||
Change in restricted cash |
| (52 | ) | — |
| ||
Net cash used in investing |
| (343,073 | ) | (119,609 | ) | ||
Cash flows from financing activities |
|
|
|
|
| ||
Proceeds from issuance of long-term debt |
| 80,000 |
| — |
| ||
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 |
| — |
| 172,422 |
| ||
Purchases of treasury stock |
| (358 | ) | — |
| ||
Payment of debt issuance costs |
| (11,431 | ) | (49 | ) | ||
Net cash provided by (used in) financing |
| 100,211 |
| 373 |
| ||
Net increase in cash |
| 8,970 |
| (671 | ) | ||
Cash |
|
|
|
|
| ||
Beginning of period |
| 23,820 |
| 23,726 |
| ||
End of period |
| $ | 32,790 |
| $ | 23,055 |
|
Supplemental disclosure of cash flow information |
|
|
|
|
| ||
Cash paid for interest |
| $ | 9,076 |
| $ | 19,442 |
|
Change in accrued additions to oil and gas properties |
| 58,501 |
| 26,826 |
| ||
Current additions to ARO |
| 1,205 |
| 499 |
| ||
Deferred offering costs |
| — |
| 60 |
| ||
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 September 30, |
| Nine Months Ended September 30, |
| ||||||||||||||
|
| 2014 |
| 2013 |
| Change |
| 2014 |
| 2013 |
| Change |
| ||||||
Net production volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Oil (MBbls) |
| 639 |
| 401 |
| 238 |
| 1,869 |
| 1,126 |
| 743 |
| ||||||
Natural gas (MMcf) |
| 5,812 |
| 4,418 |
| 1,394 |
| 16,371 |
| 12,822 |
| 3,549 |
| ||||||
NGLs (MBbls) |
| 644 |
| 462 |
| 182 |
| 1,733 |
| 1,287 |
| 446 |
| ||||||
Total (MBoe) |
| 2,252 |
| 1,599 |
| 653 |
| 6,331 |
| 4,550 |
| 1,781 |
| ||||||
Average net (Boe/d) |
| 24,478 |
| 17,380 |
| 7,098 |
| 23,190 |
| 16,667 |
| 6,523 |
| ||||||
Average sales price, unhedged: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Oil (per Bbl), unhedged |
| $ | 94.76 |
| $ | 101.07 |
| $ | (6.31 | ) | $ | 95.78 |
| $ | 93.05 |
| $ | 2.73 |
|
Natural gas (per Mcf), unhedged |
| 3.33 |
| 3.04 |
| 0.29 |
| 3.91 |
| 3.21 |
| 0.70 |
| ||||||
NGLs (per Bbl), unhedged |
| 30.77 |
| 31.73 |
| (0.96 | ) | 34.82 |
| 32.85 |
| 1.97 |
| ||||||
Combined (per Boe) realized, unhedged |
| 44.27 |
| 42.92 |
| 1.35 |
| 47.92 |
| 41.36 |
| 6.56 |
| ||||||
Average sales price, hedged: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Oil (per Bbl), hedged |
| $ | 90.80 |
| $ | 89.40 |
| $ | 1.40 |
| $ | 89.51 |
| $ | 87.56 |
| $ | 1.95 |
|
Natural gas (per Mcf), hedged |
| 3.82 |
| 3.87 |
| (0.05 | ) | 4.06 |
| 3.99 |
| 0.07 |
| ||||||
NGLs (per Bbl), hedged |
| 30.27 |
| 31.88 |
| (1.61 | ) | 32.74 |
| 33.91 |
| (1.17 | ) | ||||||
Combined (per Boe) realized, hedged |
| 44.27 |
| 42.33 |
| 1.94 |
| 45.88 |
| 42.52 |
| 3.36 |
| ||||||
Average costs (per Boe): |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Lease operating |
| $ | 4.99 |
| $ | 4.85 |
| $ | 0.14 |
| $ | 5.31 |
| $ | 4.24 |
| $ | 1.07 |
|
Production taxes |
| 2.21 |
| 2.17 |
| 0.04 |
| 2.36 |
| 2.00 |
| 0.36 |
| ||||||
Depletion, depreciation and amortization |
| 21.30 |
| 19.09 |
| 2.21 |
| 20.62 |
| 18.14 |
| 2.48 |
| ||||||
General and administrative |
| 3.08 |
| 8.74 |
| (5.66 | ) | 2.96 |
| 5.63 |
| (2.67 | ) | ||||||
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 September 30, |
| Nine Months Ended September 30, |
| ||||||||
(in thousands of dollars) |
| 2014 |
| 2013 |
| 2014 |
| 2013 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Reconciliation of EBITDAX to net income |
|
|
|
|
|
|
|
|
| ||||
Net income (loss) |
| $ | 52,230 |
| $ | (15,492 | ) | $ | 52,434 |
| $ | 31,471 |
|
Interest expense (excluding amortization of deferred financing costs) |
| 11,002 |
| 6,473 |
| 28,530 |
| 21,424 |
| ||||
Exploration expense |
| 266 |
| 853 |
| 3,278 |
| 1,458 |
| ||||
Income taxes |
| 5,871 |
| (344 | ) | 6,550 |
| (93 | ) | ||||
Amortization of deferred financing costs |
| 847 |
| 675 |
| 6,129 |
| 2,003 |
| ||||
Depreciation and depletion |
| 47,965 |
| 30,529 |
| 130,521 |
| 82,552 |
| ||||
Accretion expense |
| 206 |
| 170 |
| 573 |
| 434 |
| ||||
Other non-cash charges (benefits) |
| 201 |
| (83 | ) | 241 |
| 227 |
| ||||
Stock compensation expense |
| 1,321 |
| 9,906 |
| 2,707 |
| 10,379 |
| ||||
Other non-cash compensation expense |
| 127 |
| 127 |
| 380 |
| 2,592 |
| ||||
Net loss (gain) on commodity derivatives |
| (41,163 | ) | 20,728 |
| 9,785 |
| (4,444 | ) | ||||
Current period settlements of matured derivative contracts |
| 285 |
| (943 | ) | (12,610 | ) | 5,262 |
| ||||
Amortization of deferred revenue |
| (336 | ) | (114 | ) | (862 | ) | (114 | ) | ||||
Loss (gain) on sales of assets |
| (30 | ) | 55 |
| (97 | ) | 30 |
| ||||
EBITDAX |
| $ | 78,792 |
| $ | 52,540 |
| $ | 227,559 |
| $ | 153,181 |
|
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 September 30, |
| Nine Months Ended September 30, |
| ||||||||
(in thousands of dollars except per share data) |
| 2014 |
| 2013 |
| 2014 |
| 2013 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Net income (loss) |
| $ | 52,230 |
| $ | (15,492 | ) | $ | 52,434 |
| $ | 31,471 |
|
Net (gain)/ loss on commodity derivatives |
| (41,163 | ) | 20,728 |
| 9,785 |
| (4,444 | ) | ||||
Current period settlements of matured derivative contracts |
| 285 |
| (943 | ) | (12,610 | ) | 5,262 |
| ||||
Non-cash stock compensation expense |
| 1,321 |
| 9,906 |
| 2,707 |
| 10,379 |
| ||||
Other non-cash compensation expense |
| 127 |
| 127 |
| 380 |
| 2,592 |
| ||||
Net unamortized capitalized loan costs associated with Term Loan |
| — |
| — |
| 3,761 |
| — |
| ||||
Tax impact(1) |
| 3,464 |
| (1,239 | ) | (444 | ) | (1,239 | ) | ||||
Adjusted net income |
| 16,264 |
| $ | 13,087 |
| 56,013 |
| $ | 44,021 |
| ||
|
|
|
|
|
|
|
|
|
| ||||
Adjusted net income attributable to non-controlling interests |
| 13,273 |
|
|
| 45,818 |
|
|
| ||||
Adjusted net income attributable to controlling interests |
| $ | 2,991 |
|
|
| $ | 10,195 |
|
|
| ||
|
|
|
|
|
|
|
|
|
| ||||
Effective tax rate on net income attributable to controlling interests |
| 32.9 | % |
|
| 32.9 | % |
|
| ||||
(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.
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 |
| Nine Months Ended |
| ||
|
| 2014 |
| 2014 |
| ||
|
|
|
|
|
| ||
Earnings per share (basic) |
| $ | 0.76 |
| $ | 0.76 |
|
Net (gain)/ loss on commodity derivatives |
| (0.83 | ) | 0.20 |
| ||
Current period settlements of matured derivative contracts |
| — |
| (0.26 | ) | ||
Non-cash stock compensation expense |
| 0.03 |
| 0.06 |
| ||
Other non-cash compensation expense |
| — |
| 0.01 |
| ||
Net unamortized capitalized loan costs associated with Term Loan |
| — |
| 0.08 |
| ||
Tax impact |
| 0.28 |
| (0.03 | ) | ||
Adjusted earnings per share (basic) |
| $ | 0.24 |
| $ | 0.82 |
|
|
|
|
|
|
| ||
Earnings per share (diluted) |
| $ | 0.76 |
| $ | 0.76 |
|
Net (gain)/ loss on commodity derivatives |
| (0.83 | ) | 0.20 |
| ||
Current period settlements of matured derivative contracts |
| — |
| (0.26 | ) | ||
Impairment of oil and gas properties |
| — |
| — |
| ||
Non-cash stock compensation expense |
| 0.02 |
| 0.05 |
| ||
Other non-cash compensation expense |
| — |
| 0.01 |
| ||
Net unamortized capitalized loan costs associated with Term Loan |
| — |
| 0.08 |
| ||
Tax impact |
| 0.28 |
| (0.03 | ) | ||
Adjusted earnings per share (diluted) |
| $ | 0.23 |
| $ | 0.81 |
|