JONES ENERGY, INC., 10-K filed on 2/28/2019
Annual Report
v3.10.0.1
Document and Entity Information - USD ($)
$ / shares in Units, $ in Millions
12 Months Ended
Dec. 31, 2018
Feb. 20, 2019
Jun. 29, 2018
Document Information [Line Items]      
Entity Registrant Name Jones Energy, Inc.    
Entity Central Index Key 0001573166    
Document Type 10-K    
Document Period End Date Dec. 31, 2018    
Amendment Flag false    
Current Fiscal Year End Date --12-31    
Entity Well-known Seasoned Issuer No    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Filer Category Non-accelerated Filer    
Entity Small Business true    
Entity Emerging Growth Company false    
Entity Shell Company false    
Entity Public Float     $ 20.3
Entity Listing, Par Value Per Share $ 0.001    
Document Fiscal Year Focus 2018    
Document Fiscal Period Focus FY    
Class A common stock      
Document Information [Line Items]      
Entity Common Stock, Shares Outstanding   5,826,217  
Class B common stock      
Document Information [Line Items]      
Entity Common Stock, Shares Outstanding   172,193  
v3.10.0.1
Consolidated Balance Sheets - USD ($)
$ in Thousands
Dec. 31, 2018
Dec. 31, 2017
Current assets    
Cash and cash equivalents $ 58,464 $ 19,472
Accounts receivable, net    
Oil and gas sales 33,954 34,492
Joint interest owners 23,997 31,651
Other 614 1,236
Commodity derivative assets 5,003 3,474
Other current assets 8,099 14,376
Total current assets 130,131 104,701
Oil and gas properties, net, under the successful efforts method 271,846 1,597,040
Other property, plant and equipment, net 1,639 2,719
Commodity derivative assets 1,415 172
Deferred tax assets 129  
Other assets 415 5,431
Total assets 405,575 1,710,063
Current liabilities    
Trade accounts payable 32,506 72,663
Oil and gas sales payable 34,035 31,462
Accrued liabilities 37,799 21,604
Commodity derivative liabilities 370 36,709
Other current liabilities 4,927 4,049
Total current liabilities 109,637 166,487
Long-term debt 982,157 759,316
Deferred revenue 4,118 5,457
Commodity derivative liabilities   8,788
Asset retirement obligations 20,432 19,652
Liability under tax receivable agreement   59,596
Other liabilities 495 811
Deferred tax liabilities   14,281
Total liabilities 1,116,839 1,034,388
Commitments and contingencies (Note 17)
Mezzanine equity    
Series A preferred stock, $0.001 par value; 1,804,478 shares issued and outstanding at December 31, 2018 and 1,839,995 shares issued and outstanding at December 31, 2017 93,719 89,539
Stockholders' equity    
Treasury stock, at cost: 1,141 shares at December 31, 2018 and December 31, 2017 (358) (358)
Additional paid-in-capital 638,108 606,414
Retained (deficit) / earnings (1,435,050) (136,274)
Stockholders' equity (deficit) (797,295) 469,787
Non-controlling interest (7,688) 116,349
Total stockholders’ equity (804,983) 586,136
Total liabilities and stockholders' equity 405,575 1,710,063
Class A common stock    
Stockholders' equity    
Common stock $ 5 $ 5
v3.10.0.1
Consolidated Balance Sheets (Parenthetical) - $ / shares
Dec. 31, 2018
Sep. 07, 2018
Sep. 06, 2018
Dec. 31, 2017
Mezzanine equity        
Series A preferred stock, par value (in dollars per share) $ 0.001     $ 0.001
Series A preferred stock, shares issued 1,804,478     1,839,995
Series A preferred stock, shares outstanding 1,804,478     1,839,995
Treasury stock        
Treasury stock, shares 1,141     1,141
Class A common stock        
Common stock        
Common stock, par value (in dollars per share) $ 0.001     $ 0.001
Common stock, shares issued 5,025,632     4,506,991
Common stock, shares outstanding 5,024,491 4,901,986 98,039,826 4,505,861
Class B common stock        
Common stock        
Common stock, par value (in dollars per share) $ 0.001     $ 0.001
Common stock, shares issued 172,193     481,391
Common stock, shares outstanding 172,193 241,251 4,825,038 481,391
v3.10.0.1
Consolidated Statements of Operations - USD ($)
shares in Thousands, $ in Thousands
12 Months Ended
Dec. 31, 2018
Dec. 31, 2017
Dec. 31, 2016
Operating revenues      
Oil and gas sales $ 236,873 $ 186,393 $ 124,877
Other revenues, Net (516) 2,180 2,970
Total operating revenues 236,357 188,573 127,847
Operating costs and expenses      
Lease operating 44,921 36,636 32,640
Production and ad valorem taxes 12,087 6,874 7,768
Transportation and processing costs 3,368    
Exploration 8,157 14,145 6,673
Depletion, depreciation and amortization 173,904 167,224 153,930
Impairment of oil and gas properties 1,331,785 149,648  
Accretion of ARO liability 1,066 960 1,263
General and administrative 31,204 29,892 29,640
Other operating 250   199
Total operating expenses 1,606,742 405,379 232,113
Operating income (loss) (1,370,385) (216,806) (104,266)
Other income (expense)      
Interest expense (89,328) (51,651) (53,127)
Gain on debt extinguishment     99,530
Net gain (loss) on commodity derivatives (2,757) (17,985) (51,264)
Other income (expense) 53,935 56,952 536
Other income (expense), net (38,150) (12,684) (4,325)
Income (loss) before income tax (1,408,535) (229,490) (108,591)
Income tax provision (benefit)      
Current (5) (3,585) 3,981
Deferred (61,836) (47,082) (27,767)
Total income tax provision (benefit) (61,841) (50,667) (23,786)
Net income (loss) (1,346,694) (178,823) (84,805)
Net income (loss) attributable to non-controlling interests (55,655) (77,331) (42,253)
Net income (loss) attributable to controlling interests (1,291,039) (101,492) (42,552)
Dividends and accretion on preferred stock (7,737) (7,924) (2,669)
Net income (loss) attributable to common shareholders $ (1,298,776) $ (109,416) $ (45,221)
Earnings (loss) per share:      
Basic - Net income (loss) attributable to common shareholders (in dollars per share) [1] $ (271.94) $ (30.22) $ (20.79)
Diluted - Net income (loss) attributable to common shareholders (in dollars per share) [1] $ (271.94) $ (30.22) $ (20.79)
Weighted average Class A shares outstanding:      
Basic (in shares) [1] 4,776 3,621 2,175
Diluted (in shares) [1] 4,776 3,621 2,175
[1] All share and earnings per share information presented has been recast to retrospectively adjust for the effects of the Special Stock Dividend distributed on March 31, 2017 and the Reverse Stock Split effective on September 7, 2018, as defined in Note 14, “Stockholders’ and Mezzanine Equity”.
v3.10.0.1
Statement of Changes in Stockholders' Equity - USD ($)
shares in Thousands, $ in Thousands
Common Stock
Class A common stock
Common Stock
Class B common stock
Treasury Stock
Class A common stock
Additional Paid-in-Capital
Retained Earnings
Non-controlling Interest
Total
Balance at Dec. 31, 2015 $ 2 $ 1 $ (358) $ 363,782 $ 36,569 $ 536,856 $ 936,852
Balance (in shares) at Dec. 31, 2015 [1] 1,527 1,563 1        
Increase (Decrease) Stockholders' Equity              
Stock-compensation expense       7,425     7,425
Vested restricted shares (in shares) [1] 19            
Distributions paid to JEH unitholders           (17,319) (17,319)
Sale of common stock $ 1     65,445     65,446
Sale of common stock (in shares) [1] 1,232            
Exchange of Class B shares for Class A shares       10,568   (24,047) (13,479)
Exchange of Class B shares for Class A shares (in shares) [1] 72 (72)          
Dividends and accretion on preferred stock         (2,669)   (2,669)
Net income (loss)         (42,552) (42,253) (84,805)
Balance at Dec. 31, 2016 $ 3 $ 1 $ (358) 447,220 (8,652) 453,237 891,451
Balance (in shares) at Dec. 31, 2016 [1] 2,850 1,491 1        
Increase (Decrease) Stockholders' Equity              
Cumulative effect of adoption of ASU 2014-09 and ASU 2015-14       706 (706)    
Stock-compensation expense       5,798     5,798
Stock-compensation expense (in shares) [1] 40            
Distributions paid to JEH unitholders           (562) (562)
Sale of common stock       8,334     8,334
Sale of common stock (in shares) [1] 185            
Stock dividends on common stock $ 1     17,499 (17,500)    
Stock dividends on common stock (in shares) [1] 250            
Exchange of Class B shares for Class A shares $ 1 $ (1)   122,864   (258,995) (136,131)
Exchange of Class B shares for Class A shares (in shares) [1] 1,010 (1,010)          
Dividends and accretion on preferred stock       3,993 (7,924)   (3,931)
Dividends and accretion on preferred stock (in shares) [1] 170            
Net income (loss)         (101,492) (77,331) (178,823)
Balance at Dec. 31, 2017 $ 5   $ (358) 606,414 (136,274) 116,349 586,136
Balance (in shares) at Dec. 31, 2017 [1] 4,505 481 1        
Increase (Decrease) Stockholders' Equity              
Stock-compensation expense       914     914
Stock-compensation expense (in shares) [1] 69            
Exchange of Class B shares for Class A shares       27,225   (68,382) (41,157)
Exchange of Class B shares for Class A shares (in shares) [1] 309 (309)          
Conversion of preferred shares for Class A shares       1,717     1,717
Conversion of preferred shares for Class A shares (in shares) [1] 51            
Dividends and accretion on preferred stock       1,838 (7,737)   (5,899)
Dividends and accretion on preferred stock (in shares) [1] 89            
Net income (loss)         (1,291,039) (55,655) (1,346,694)
Balance at Dec. 31, 2018 $ 5   $ (358) $ 638,108 $ (1,435,050) $ (7,688) $ (804,983)
Balance (in shares) at Dec. 31, 2018 [1] 5,023 172 1        
[1] All share information presented has been recast to retrospectively adjust for the effects of the Reverse Stock Split, as defined in Note 14, “Stockholders’ and Mezzanine Equity”, effective on September 7, 2018.
v3.10.0.1
Consolidated Statements of Cash Flows - USD ($)
$ in Thousands
12 Months Ended
Dec. 31, 2018
Dec. 31, 2017
Dec. 31, 2016
Cash flows from operating activities      
Net income (loss) $ (1,346,694) $ (178,823) $ (84,805)
Adjustments to reconcile net income (loss) to net cash provided by operating activities      
Depletion, depreciation, and amortization 173,904 167,224 153,930
Exploration (dry hole and lease abandonment) 4,191 11,017 6,261
Impairment of oil and gas properties 1,331,785 149,648  
Accretion of ARO liability 1,066 960 1,263
Amortization of debt issuance costs 10,649 3,955 4,060
Stock compensation expense 1,381 6,260 7,425
Deferred and other non-cash compensation expense 56 208 804
Amortization of deferred revenue (1,555) (1,854) (2,384)
Loss on commodity derivatives 2,757 17,985 51,264
(Gain) loss on sales of assets 748 127 (14)
Gain on debt extinguishment     (99,530)
Deferred income tax provision (61,835) (47,082) (27,767)
Change in liability under tax receivable agreement (54,936) (59,492)  
Other - net 400 2,044 418
Changes in operating assets and liabilities      
Accounts receivable 8,897 (34,615) 2,276
Other assets 7,150 (12,330) (675)
Accrued interest expense 11,841 (1,422) (4,727)
Accounts payable and accrued liabilities (25,697) 35,198 17,901
Net cash provided by operations 64,108 59,008 25,700
Cash flows from investing activities      
Additions to oil and gas properties (198,468) (245,364) (264,462)
Net adjustments to purchase price of properties acquired   2,391  
Proceeds from sales of assets 11,082 61,290 1,645
Acquisition of other property, plant and equipment (360) (586) (310)
Current period settlements of matured derivative contracts (53,147) 72,265 132,265
Net cash used in investing (240,893) (110,004) (130,862)
Cash flows from financing activities      
Proceeds from issuance of long-term debt 20,000 162,000 130,000
Repayment of long-term debt (231,000) (129,000) (62,000)
Proceeds from senior notes 438,867    
Purchase of senior notes     (84,589)
Payment of debt issuance costs (11,624) (1,115)  
Payment of cash dividends on preferred stock   (3,368) (1,615)
Net distributions paid to JEH unitholders   (562) (17,319)
Net payments for share based compensation (466) (462)  
Proceeds from sale of common stock   8,333 65,446
Proceeds from sale of preferred stock     87,988
Net cash provided by financing 215,777 35,826 117,911
Net increase (decrease) in cash and cash equivalents 38,992 (15,170) 12,749
Cash and cash equivalents      
Beginning of period 19,472 34,642 21,893
End of period 58,464 19,472 34,642
Supplemental disclosure of cash flow information      
Cash paid for interest, net of capitalized interest 68,561 49,101 53,816
Cash paid for income taxes   2,318  
Change in accrued additions to oil and gas properties (3,377) 3,921 9,325
Asset retirement obligations incurred, including changes in estimate $ 695 $ 924 $ (1,276)
v3.10.0.1
Organization and Description of Business
12 Months Ended
Dec. 31, 2018
Disclosure Text Block  
Organization and Description of Business

1. Organization and Description of Business

Organization

Jones Energy, Inc. (the “Company”) was formed in March 2013 as a Delaware corporation to become a publicly-traded entity and the holding company of Jones Energy Holdings, LLC (“JEH”). As the sole managing member of JEH, the Company is responsible for all operational, management and administrative decisions relating to JEH’s business and consolidates the financial results of JEH and its subsidiaries.

JEH was formed as a Delaware limited liability company on December 16, 2009 through investments made by the Jones family, certain members of management and through private equity funds managed by Metalmark Capital, among others. JEH acts as a holding company of operating subsidiaries that own and operate assets that are used in the exploration, development, production and acquisition of oil and natural gas properties.

The Company’s certificate of incorporation authorizes two classes of common stock, Class A common stock and Class B common stock. The Class B common stock is held by the remaining owners of JEH prior to the initial public offering (“IPO”) of the Company (collectively, the “Class B shareholders”) and can be exchanged (together with a corresponding number of common units representing membership interests in JEH (“JEH Units”)) for shares of Class A common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions. The Class B common stock has no economic rights but entitles its holders to one vote on all matters to be voted on by the Company’s stockholders generally. As of December 31, 2018, the Company held 5,024,491 JEH Units and all of the preferred units representing membership interests in JEH, and the remaining 172,193 JEH Units are held by the Class B shareholders. The Class B shareholders have no voting rights with respect to their economic interest in JEH, resulting in the Company reporting this ownership interest as a non-controlling interest.

The Company’s certificate of incorporation also authorizes the Board of Directors of the Company (the “Board”) to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action. Rights and privileges associated with shares of preferred stock are subject to authorization by the Board and may differ from those of any and all other series at any time outstanding.

 

On August 25, 2016, the Company issued 1,840,000 shares of its 8.0% Series A Perpetual Convertible Preferred Stock, par value $0.001 per share (the “Series A preferred stock”), pursuant to a registered public offering at $50 per share, of which 1,804,478 remained issued and outstanding as of December 31, 2018. See Note 14, “Stockholders’ and Mezzanine Equity”.

On September 7, 2018, the Company effected a 1-for-20 reverse stock split of its Class A common stock and its Class B common stock. See Note 14, “Stockholders’ and Mezzanine Equity”.

Description of Business

The Company is engaged in the exploration, development, production and acquisition of oil and natural gas properties in the mid-continent United States, spanning areas of Oklahoma and Texas. The Company’s assets are located within the Eastern Anadarko Basin, targeting the liquids rich Woodford shale and Meramec formations in the Merge area of the STACK/SCOOP plays, and the Western Anadarko Basin, targeting the liquids rich Cleveland, Granite Wash, Tonkawa and Marmaton formations, and are owned by JEH and its operating subsidiaries. The Company is headquartered in Austin, Texas.

v3.10.0.1
Significant Accounting Policies
12 Months Ended
Dec. 31, 2018
Disclosure Text Block  
Significant Accounting Policies

2. Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and in accordance with the rules and regulations of the Securities and Exchange Commission. All significant intercompany transactions and balances have been eliminated in consolidation. The Company’s financial position as of December 31, 2018 and 2017 and the financial statements reported for each of the three years in the period ended December 31, 2018 include the Company and all of its subsidiaries

Certain prior period amounts have been reclassified to conform to the current presentation.

Segment Information

The Company operates in one industry segment, which is the exploration, development and production of oil and natural gas, and all of its operations are conducted in one geographic area of the United States.

Use of Estimates

In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent liabilities, and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from these estimates. Changes in estimates are recorded prospectively.

Significant assumptions are required in the valuation of proved and unproved oil and natural gas reserves, which affect the Company’s estimates of depletion expense, impairment, and the allocation of value in our business combinations. Significant assumptions are also required in the Company’s estimates of the net gain or loss on commodity derivative assets and liabilities, fair value associated with business combinations, and asset retirement obligations (“ARO”).

Cash

Cash and cash equivalents include highly liquid investments with a maturity of three months or less. At times, the amount of cash on deposit in financial institutions exceeds federally insured limits. Management monitors the soundness of the financial institutions it does business with, and believes the Company’s risk is not significant.

Accounts Receivable

Accounts receivable—Oil and gas sales consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. Accounts receivable—Joint interest owners consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable—Other consists at December 31, 2018 and at December 31, 2017 of derivative positions not settled as of the balance sheet date. No interest is charged on past‑due balances. The Company routinely assesses the recoverability of all material trade, joint interest and other receivables to determine their collectability, and reduces the carrying amounts by a valuation allowance that reflects management’s best estimate of the amounts that may not be collected. As of December 31, 2018 and 2017, the Company did not have significant allowances for doubtful accounts.

Concentration of Risk

Substantially all of the Company’s accounts receivable are related to the oil and gas industry. This concentration of entities may affect the Company’s overall credit risk in that these entities may be affected similarly by changes in economic and other conditions, including declines in commodity prices. As of December 31, 2018, 73% of Accounts receivable—Oil and gas sales were due from four purchasers and 35% of Accounts receivable‑Joint interest owners were due from six working interest owner. As of December 31, 2017, 71% of Accounts receivable—Oil and gas sales were due from three purchasers and 59% of Accounts receivable‑Joint interest owners were due from five working interest owners. As of December 31, 2016, 77% of Accounts receivable—Oil and gas sales are due from four purchasers and 48% of Accounts receivable—Joint interest owners are due from five working interest owners. If any or all of these significant counterparties were to fail to pay amounts due to the Company, the Company’s financial position and results of operations could be materially and adversely affected.

Financial instruments that potentially subject the Company to concentration of credit risk consist principally of cash deposits. Accounts at each institution are insured by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000. As of December 31, 2018 and 2017, the Company had $62.9 million and $24.2 million in excess of the FDIC insured limit, respectively.

Dependence on Major Customers

The Company maintains a portfolio of crude oil and natural gas marketing contracts with large, established refiners and oil and gas purchasers. During the year ended December 31, 2018, the largest purchasers of our production were Plains Marketing LP (“Plains Marketing”), ETC Field Services LLC and CVR Energy, Inc., which accounted for approximately 26%, 20% and 19% of consolidated oil and gas sales, respectively. During the year ended December 31, 2017, the largest purchasers of our production were Plains Marketing LP (“Plains Marketing”) and ETC Field Services LLC, which accounted for approximately 40% and 22% of consolidated oil and gas sales, respectively. During the year ended December 31, 2016, the largest purchasers of our production were Plains Marketing LP (“Plains Marketing”) and ETC Field Services LLC, which accounted for approximately 37% and 24% of consolidated oil and gas sales, respectively.

Management believes that there are alternative purchasers and that it may be necessary to establish relationships with such new purchasers. However, there can be no assurance that the Company can establish such relationships and that those relationships will result in an increased number of purchasers. Although the Company is exposed to a concentration of credit risk, management believes that all of the Company’s purchasers are credit worthy.

Dependence on Suppliers

The Company’s industry is cyclical, and from time to time, there can be an imbalance between the supply of and demand for drilling rigs, equipment, services, supplies and qualified personnel. During periods of oversupply, there can be financial pressure on suppliers. If the financial pressure leads to work interruptions or stoppages, the Company could be materially and adversely affected. Management believes that there are adequate alternative providers of drilling and completion services although it may become necessary to establish relationships with new contractors. However, there can be no assurance that the Company can establish such relationships and that those relationships will result in increased availability of drilling rigs or other services, or that they could be obtained on the same terms.

Oil and Gas Properties

The Company accounts for its oil and natural gas exploration and production activities under the successful efforts method of accounting.

Costs to acquire mineral interests in oil and natural gas properties are capitalized. Costs to drill and equip development wells and the related asset retirement costs are capitalized. The costs to drill and equip exploratory wells are capitalized pending determination of whether the Company has discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are charged to expense. In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the anticipated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made.

The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use.

On the sale or retirement of a proved field, the cost and related accumulated depletion, depreciation and amortization are eliminated from the field accounts, and the resultant gain or loss is recognized.

Capitalized amounts attributable to proved oil and gas properties are depleted by the unit‑of‑production method over the life of proved reserves, using the unit conversion ratio of six thousand cubic feet of gas to one barrel of oil equivalent. Depletion of the costs of wells and related equipment and facilities, including capitalized asset retirement costs, net of salvage values, is computed using proved developed reserves. The reserve base used to calculate depreciation, depletion, and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves.

The Company reviews its proved oil and natural gas properties, including related wells and equipment, for impairment by comparing expected undiscounted future cash flows at a producing field level to the net capitalized cost of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future commodity prices, operating costs, and production, are lower than the net capitalized cost, the capitalized cost is reduced to fair value. See Note 9, “Fair Value Measurement,” for further information regarding the method used to determine the fair value of oil and gas properties.

The Company evaluates its unproved properties for impairment on a property‑by‑property basis. The Company’s unproved property consists of acquisition costs related to its undeveloped acreage. The Company reviews the unproved property for indicators of impairment based on the Company’s current exploration plans with consideration given to commodity prices, lease expiration dates, results of any drilling and geo science activity during the period, and known information regarding exploration and development activity by other companies on adjacent blocks. See Note 9, “Fair Value Measurement,” for further information regarding impairment of unproved properties.

On the sale of an entire interest in an unproved property, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Other Property, Plant and Equipment

Other property, plant and equipment is depreciated on a straight‑line basis over the estimated useful lives of the property, plant and equipment, which range from three years to ten years.

Oil and Gas Sales Payable

Oil and gas sales payable represents amounts collected from purchasers for oil and gas sales, which are due to other revenue interest owners. Generally, the Company is required to remit amounts due under these liabilities within 60 days of receipt.

Accrued Liabilities

Accrued liabilities consisted of the following at December 31, 2018 and 2017:

 

 

 

 

 

 

 

 

 

 

December 31, 

 

December 31, 

 

(in thousands of dollars)

    

2018

    

2017

    

Accrued interest expense

 

$

23,949

 

$

12,109

 

Joint interest owners prepayments

 

 

8,000

 

 

4,061

 

Commodity derivative liabilities

 

 

2,475

 

 

14

 

Other accrued liabilities

 

 

3,375

 

 

5,420

 

Total accrued liabilities

 

$

37,799

 

$

21,604

 

 

Commodity Derivatives

The Company records its commodity derivative instruments on the Consolidated Balance Sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized currently in earnings, unless specific hedge accounting criteria are met. During the years ended December 31, 2018, 2017 and 2016, the Company elected not to designate any of its commodity price risk management activities as cash flow or fair value hedges. The changes in the fair values of outstanding financial instruments are recognized as gains or losses in the period of change.

Although the Company does not designate its commodity derivative instruments as cash‑flow hedges, management uses those instruments to reduce the Company’s exposure to fluctuations in commodity prices related to its natural gas and oil production. Net gains and losses, at fair value, are included on the Consolidated Balance Sheet as current or noncurrent assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of commodity derivative contracts are recorded in earnings as they occur and are included in other income (expense) on the Consolidated Statement of Operations. See Note 9, “Fair Value Measurement,” for disclosure about the fair values of commodity derivative instruments.

Asset Retirement Obligations

The Company's asset retirement obligations ("ARO") consist of future plugging and abandonment expenses on oil and natural gas properties. The Company estimates an ARO for each well in the period in which it is incurred based on estimated present value of plugging and abandonment costs, increased by an inflation factor to the estimated date that the well would be plugged. The resulting liability is recorded by increasing the carrying amount of the related long- lived asset. The liability is then accreted to its then-present value each period and the capitalized cost is depleted over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The ARO is classified as current or noncurrent based on the expect timing of payments.

Revenue Recognition

Revenue is measured based on a consideration specified in a contract with a customer, and excludes any amounts collected on behalf of third parties. The Company recognizes revenue when it satisfies a performance obligation by transferring control over a product or service to a customer. We generally consider the delivery of each unit (Bbl or MMBtu) to be separately identifiable and represents a distinct performance obligation that is satisfied at a point-in-time once control of the product has been transferred to the customer upon delivery to an agreed upon delivery point. Transfer of control typically occurs when the products are delivered to the purchaser, and title has transferred.

Revenue is recognized at a point in time as a result of not meeting any of the three criteria required for recognition over time.

Certain transportation and processing costs associated with fixed fee contracts where title transfers to the customer at the tailgate of the processing plant and we pay a gathering and processing fee are recognized at the time of title transfer. These costs are presented as Transportation and processing costs on the Consolidated Statement of Operations.

The Company enters into marketing agreements with our non-operating partners to market and sell their share of production to third parties. Under these arrangements, we record revenue for our share of the production (i.e. we, as the operator, record revenue on a net basis). Distributions are made to our non-operating partners for their share of the revenue.

As part of our adoption of ASC 606, we used practical expedients permitted by the standard when applicable. These practical expedients included:

·

Applying the new guidance only to contracts that are not completed as of January 1, 2018;

·

Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction, that are collected by the Company from a customer, are excluded from revenue;

·

The Company recognizes the incremental cost of obtaining contracts as an expense when incurred if the amortization period of the assets that the Company otherwise would have recognized is one year or less. These costs are included in General and administrative expenses;

·

For our product sales that have a contact term greater than one year, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our product sales contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required; and

·

For our product sales that have a contract term of one year or less, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of the contract that has an original expected duration of one year or less.     

Income Taxes

The Company records a federal and state income tax liability associated with its status as a corporation. The Company recognizes a tax liability on its share of pre-tax book income, exclusive of the non-controlling interest.

Income taxes are accounted for under the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which differences are expected to be recovered or settled pursuant to the provisions of ASC 740—Income Taxes. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

On December 22, 2017, the US Congress enacted the Tax Cuts and Jobs Act (Tax Reform Legislation), which made significant changes to US federal income tax law affecting us. See Note 13, “Income Taxes.”

The Company records a valuation allowance if it is deemed more likely than not that all or a portion of its deferred income tax assets will not be realized. In addition, income tax rules and regulations are subject to interpretation and the application of those rules and regulations require judgment by the Company and may be challenged by the taxation authorities. The Company follows a two‑step approach for recognizing and measuring tax benefits taken or expected to be taken in a tax return and disclosures regarding uncertainties in income tax positions. Only tax positions that meet the more likely than not recognition threshold are recognized. The Company’s policy is to include any interest and penalties recorded on uncertain tax positions as a component of income tax expense. The Company’s unrecognized tax benefits or related interest and penalties are immaterial.

Comprehensive Income

The Company has no elements of comprehensive income other than net income.

Recent Accounting Pronouncements

Adopted in the current year:

 

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” which creates a new topic in the Accounting Standards Codification (“ASC”), topic 606, “Revenue from Contracts with Customers.” This standard sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14, which deferred the effective date of ASU 2014-09 by one year. The amendments may be applied on either a full or modified retrospective basis and are now effective for interim and annual reporting periods beginning after December 15, 2017. Therefore, the Company has adopted Update 2014-09 and Update 2015-14 effective as of January 1, 2018. The change was applied on a modified retrospective basis, which did not result in a cumulative effect adjustment to retained earnings. However, adoption did result in certain changes in presentation of gross revenues and expenses on the Company’s Consolidated Statement of Operations; such costs were historically offset against revenues. Upon adoption, we have also expanded disclosures related to revenue recognition. See Note 5, “Revenue Recognition.”

 

In January 2017, the FASB issued ASU 2017-01, “Business Combinations” (Topic 805). The amendments under this ASU provide guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions/disposals or business combinations by providing a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired, or disposed of, is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business, therefore reducing the number of transactions that need to be further evaluated for treatment as a business combination. This new guidance is effective for annual periods beginning after December 15, 2017. Therefore, the Company adopted ASU 2017-01 effective as of January 1, 2018 applied prospectively, which did not have a material impact on our financial statements; however these amendments could result in the recording of fewer business combinations in future periods.

 

To be adopted in a future period:

 

In February 2016, the FASB issued ASU 2016-02, “Leases” (Topic 842). This amendment requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases and mineral leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. In July 2018, the FASB issued ASU 2018-11, “Leases” (Topic 842) Targeted Improvements, which allows issuers an additional (and optional) transition method of adoption. Under the original standard issued in 2016, lessees and lessors were required to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, under the new transition method allowed for in the standard released in 2018, an entity may elect to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption with no adjustment to previously reported results. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018.

 

We adopted ASU 2016-02 effective as of January 1, 2019 using a modified retrospective transition method applied at the adoption date. No cumulative-effect adjustment to the opening balance of retained earnings was required as a result of adoption. Upon adoption, we recognized a right of use asset and lease liability of approximately $1.6 million associated with two real estate leases. We elected to apply the package of practical expedients provided in the standards update that allow, among other things, the carry forward of historical lease classification, as well as additional practical expedients related to land easements, short-term leases, and non-lease components. The Company did not elect the practical expedient related to hindsight.

 

In June 2018, the FASB issued ASU 2018-07 "Compensation-Stock Compensation" (Topic 718). The amendments under this ASU provide an expanded scope of Topic 718, to include share-based payment transactions for acquiring goods and services from non-employees. The new standards update is effective for interim and annual periods beginning after December 15, 2018.  We adopted ASU 2018-07 effective as of January 1, 2019. No cumulative-effect adjustment to the opening balance of retained earnings was required as a result of adoption.

 

In August 2018, the FASB issued ASU 2018-13, “Fair Value Measurement” (Topic 820). The amendments under this ASU provide additional disclosure requirements that eliminates the requirement to disclose transfers between Level 1 and Level 2 of the fair value hierarchy and provides for additional disclosures for Level 3 fair value measurements. This new standards update is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. The Company is currently evaluating the impacts of the amendments to our financial statements and accounting practices for fair value measurement, as well as the method of adoption. We anticipate adoption of ASU 2018-13 effective as of January 1, 2020.

v3.10.0.1
Going Concern
12 Months Ended
Dec. 31, 2018
Disclosure Text Block  
Going Concern

3. Liquidity and Going Concern

The Company has incurred losses from operations in each of the years ended December 31, 2018, 2017 and 2016. As a result of the current low commodity prices and the Company’s significant indebtedness , the Company may not be able to generate sufficient cash from operations to satisfy the interest obligations on its Secured and Unsecured notes as they become due. Pursuant to the Company's indebtedness under the Secured and Unsecured Notes, it will owe a total of approximately $84 million for the year ending December 31, 2019. See Note 7 “Long Term Debt” for further information.

 

The Company’s ability to continue as a going concern is subject to, among other factors, its ability to monetize assets, its ability to obtain financing or refinance existing indebtedness, its ability to continue its cost cutting efforts for long–term rig and support services, the production rates achieved from current projects, oil and natural gas prices, the number of commercially viable hydrocarbon discoveries made and the quantities of hydrocarbons discovered, the speed and cost with which the Company can bring such discoveries to production and the actual cost of exploration, appraisal and development of its prospects.

 

The Company has substantial debt obligations requiring significant interest payments semi-annually. The ongoing capital and operating expenditures, including the debt interest payments, will vastly exceed the revenue expected to be generated from operations in the near term. There can be no assurance that the Company will be able to obtain additional funding on satisfactory terms or at all.  In addition, no assurance can be given that any such financing, if obtained, will be adequate to meet the Company’s capital needs and support its growth.  If additional funding cannot be obtained on a timely basis and on satisfactory terms, then the Company’s operations would be materially negatively impacted.

   

If the Company becomes unable to continue as a going concern, the Company may find it necessary to file a voluntary petition for reorganization under the United States Bankruptcy Code in order to provide it additional time to identify an appropriate solution to its financial situation and implement a plan of reorganization aimed at improving our capital structure.

The accompanying consolidated financial statements have been prepared under the assumption that the Company will continue as a going concern, which contemplates the continuity of operations and the realization of assets and the satisfaction of liabilities as they come due in the normal course of business.  The Company’s current circumstances raise substantial doubt about its ability to continue to operate as a going concern.  The accompanying consolidated financial statements do not include any adjustments that might be necessary should the Company be unable to continue as a going concern.

 

v3.10.0.1
Acquisitions and Divestitures
12 Months Ended
Dec. 31, 2018
Disclosure Text Block  
Acquisitions

4. Acquisitions and Divestitures

During the three year period ended December 31, 2018, the Company entered into several purchase and sale agreements (as described below). One business combination occurred during the twelve months ended December 31, 2016. However, no business combinations occurred during the twelve months ended December 31, 2018 and 2017.

 

Western Anadarko Acquisition

 

On August 25, 2016, JEH acquired producing and undeveloped oil and gas assets in the Western Anadarko Basin (the “Anadarko Acquisition”) for final consideration of $25.9 million. This transaction was accounted for as a business combination. The Company allocated $32.3 million to “Oil and gas properties,” with $3.0 million allocated to “Unproved” properties, $17.0 million allocated to “Proved” properties, and $12.3 million allocated to “Wells and equipment and related facilities”, based on the respective fair values of the assets acquired. Additionally, the Company allocated $6.4 million to our ARO liability associated with those proved properties. The Anadarko Acquisition did not result in a significant impact to revenues or net income and as such, pro forma financial information is not included. The Company funded the Anadarko Acquisition with cash on hand.

 

The assets acquired in the Anadarko Acquisition included interests in 174 wells, 59% of which were operated by the company, and approximately 25,000 net acres in Lipscomb and Ochiltree Counties in the Texas Panhandle. As of the closing date, the acquired acreage was producing approximately 900 barrels of oil equivalent per day.

 

Merge Acquisition

 

On September 22, 2016, JEH acquired oil and gas properties located in the Merge area of the STACK/SCOOP plays (the “Merge”) in Central Oklahoma (the “Merge Acquisition”) from SCOOP Energy Company, LLC for cash consideration of $134.4 million, net of the final working capital settlement of $2.4 million received in the first quarter of 2017. The oil and gas properties acquired in the Merge Acquisition, on a closed and funded basis, principally consist of 16,975 undeveloped net acres in Canadian, Grady and McClain Counties, Oklahoma. This transaction has been accounted for as an asset acquisition. The Company used proceeds from our equity offerings to fund the purchase. See Note 14 “Stockholders’ and Mezzanine Equity”.

 

Arkoma Divestiture

 

As of June 30, 2017, the Arkoma Assets and related liabilities (the “Held for sale assets”) were classified as held for sale due to the pending Arkoma Divestiture. Upon the classification change occurring on June 30, 2017, the Company ceased recording depletion on the Held for sale assets. Based on the Company’s sales price, the Company recognized an estimated impairment charge of $148.0 million at June 30, 2017 which has been included in Impairment of oil and gas properties on the Company’s Consolidated Statement of Operations.

 

On August 1, 2017, JEH closed its previously announced agreement to sell its Arkoma Basin properties (the “Arkoma Assets”) for a sale price of $65.0 million, prior to customary effective date adjustments of $7.3 million, and subject to customary post-close adjustments (the “Arkoma Divestiture”). JEH may also receive up to $2.5 million in contingent payments based on natural gas prices through the period ending October 1, 2019. As of December 31, 2018, $0.3  million has been recorded related to this contingent payment. The contingent payment was recorded as a gain in Other income (expense) on the Company’s Consolidated Statement of Operations of $0.3 million during the year ended December 31, 2018. No contingent payment gains were recorded during the year ended December 31, 2017.

 

Year Ended December 31, 2018

 

Sales of non-core assets resulted in net gains of $0.8 million during the year ended December 31, 2018 which have been included in Other income (expense) on the Company’s Consolidated Statement of Operations.

v3.10.0.1
Revenue Recognition
12 Months Ended
Dec. 31, 2018
Disclosure Text Block  
Revenue Recognition

5. Revenue Recognition

 

Adoption of ASC Topic 606, Revenue from Contracts with Customers

 

On January 1, 2018, the Company adopted ASC Topic 606 (“ASC 606”), Revenue from Contracts with Customers, using the modified retrospective approach, which was applied to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning January 1, 2018, are presented in accordance with ASC 606, while prior period amounts are reported in accordance with ASC Topic 605, Revenue Recognition.

 

In accordance with ASC 606, the Company now records transportation and processing costs that are incurred before control of its product has transferred to the customer (i.e. fixed fee contracts) as a separate expense line item on the Consolidated Statement of Operations. Prior to the adoption of ASC 606, these transportation and processing costs were recorded as a reduction of Oil and gas sales on the Consolidated Statement of Operations. See further discussion below in “Nature of revenue” related to transportation and processing costs associated with fixed fee contracts. Revenue under ASC 606 is recognized at the same point in time at which revenue was recognized under ASC Topic 605, thus there was no impact to net income (loss) or opening retained earnings as a result of adopting ASC 606.

 

The following table presents the impact to the Consolidated Statement of Operations as a result of adopting ASC 606.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2018

 

(in thousands of dollars except

 

Amounts under

 

Adoption

 

Amounts under

 

per share data)

    

ASC 606

    

impact

 

ASC 605 (1)

    

Operating revenues

 

 

 

 

 

 

 

 

 

 

Oil and gas sales

 

$

236,873

 

$

(3,368)

 

$

233,505

 

Other revenues, net

 

 

(516)

 

 

 —

 

 

(516)

 

Total operating revenues

 

 

236,357

 

 

(3,368)

 

 

232,989

 

Operating costs and expenses

 

 

 

 

 

 

 

 

 

 

Lease operating

 

 

44,921

 

 

 —

 

 

44,921

 

Production and ad valorem taxes

 

 

12,087

 

 

 —

 

 

12,087

 

Transportation and processing costs

 

 

3,368

 

 

(3,368)

 

 

 —

 

Exploration

 

 

8,157

 

 

 —

 

 

8,157

 

Depletion, depreciation and amortization

 

 

173,904

 

 

 —

 

 

173,904

 

Impairment of oil and gas properties

 

 

1,331,785

 

 

 —

 

 

1,331,785

 

Accretion of ARO liability

 

 

1,066

 

 

 —

 

 

1,066

 

General and administrative

 

 

31,204

 

 

 —

 

 

31,204

 

Other operating

 

 

250

 

 

 —

 

 

199

 

Total operating expenses

 

 

1,606,742

 

 

(3,368)

 

 

1,603,323

 

Operating income (loss)

 

 

(1,370,385)

 

 

 —

 

 

(1,370,334)

 

Other income (expense)

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

(89,328)

 

 

 —

 

 

(89,328)

 

Net gain (loss) on commodity derivatives

 

 

(2,757)

 

 

 —

 

 

(2,757)

 

Other income (expense)

 

 

53,935

 

 

 —

 

 

53,935

 

Other income (expense), net

 

 

(38,150)

 

 

 —

 

 

(38,150)

 

Income (loss) before income tax

 

 

(1,408,535)

 

 

 —

 

 

(1,408,484)

 

Income tax provision (benefit)

 

 

(61,841)

 

 

 —

 

 

(61,841)

 

Net income (loss)

 

 

(1,346,694)

 

 

 —

 

 

(1,346,643)

 

Net income (loss) attributable to non-controlling interests

 

 

(55,655)

 

 

 —

 

 

(55,604)

 

Net income (loss) attributable to controlling interests

 

$

(1,291,039)

 

$

 —

 

$

(1,291,039)

 

Dividends and accretion on preferred stock

 

 

(7,737)

 

 

 —

 

 

(7,737)

 

Net income (loss) attributable to common shareholders

 

$

(1,298,776)

 

$

 —

 

$

(1,298,776)

 

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per share (2) :

 

 

 

 

 

 

 

 

 

 

Basic - Net income (loss) attributable to common shareholders

 

$

(271.94)

 

$

 —

 

$

(271.94)

 

Diluted - Net income (loss) attributable to common shareholders

 

$

(271.94)

 

$

 —

 

$

(271.94)

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average Class A shares outstanding (2) :

 

 

 

 

 

 

 

 

 

 

Basic

 

 

4,776

 

 

 —

 

 

4,776

 

Diluted

 

 

4,776

 

 

 —

 

 

4,776

 


(1)

This column excludes the impact of adopting ASC 606 and is consistent with the presentation prior to January 1, 2018.

(2)

All share and earnings per share information presented has been recast to retrospectively adjust for the effects of the Reverse Stock Split, as defined in Note 14, “Stockholders’ and Mezzanine Equity”, effective on September 7, 2018.

 

Nature of revenue

 

Our revenues are primarily derived from the sale of oil and natural gas production, and from the sale of NGLs that are extracted from our natural gas. Sales of oil, natural gas, and NGLs from our interests in producing wells are recognized when we satisfy a performance obligation by transferring control of a product to a customer. Our oil and gas production is sold to purchasers under either short-term or long-term contracts at market-based prices. The sales prices for oil, natural gas, and NGLs are adjusted for transportation and other related deductions. These deductions are based on contractual data and do not require significant judgment. The revenue deductions reflect actual charges based on purchaser statements. Since there is a ready market for oil and natural gas, we sell the majority of production soon after it is produced at various locations. Payment is generally received one month after the sale has occurred.

 

Under our oil sales contracts, we generally sell oil to the purchaser from storage tanks near the wellhead and collect a contractually agreed upon index price, net of pricing differentials. We transfer control of the product from the storage tanks to the purchaser and recognize revenue based on the contract price. For pipeline sales, title transfers upon oil passing the inlet or delivery point.

 

Under our natural gas sales contracts, we deliver natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from our wellheads to delivery points specified under sales contracts. To deliver natural gas to these points, the Company or third parties gather, compress, process and transport our natural gas. We maintain ownership and control of the natural gas during gathering, compression, processing, and transportation. Our sales contracts provide that we receive a specific index price adjusted for pricing differentials. We transfer ownership and control of the product at the delivery point and recognize revenue based on the contract price. The sales prices for natural gas is adjusted for transportation and other related deductions. The revenue deductions reflect actual charges based on purchaser statements. The costs to gather, compress, process, and transport the natural gas are separately presented as Transportation and processing costs on the Consolidated Statement of Operations.

 

NGLs, which are extracted from natural gas through processing, are either sold by us directly or by the processor under processing contracts. For NGLs sold by us directly, our sales contracts provide that we deliver the product to the purchaser at an agreed upon delivery point and that we receive a specific index price adjusted for pricing differentials. We transfer control of the product to the purchaser at the delivery point and recognize revenue based on the contract price. Several of our revenue contracts are fixed fee where title transfers to the customer at the tailgate of the processing plant and we pay a gathering and processing fee. Gathering and processing costs associated with fixed fee contracts have a distinct service payable and, as a result of the adoption of ASC 606, these costs are reported as a separate expense line item titled Transportation and processing costs on the Consolidated Statement of Operations. Prior to the adoption of ASC 606, these transportation and processing costs were recorded as a reduction of Oil and gas sales on the Consolidated Statement of Operations. There is no impact to the current method of recognizing revenue for percentage of recovery contracts for gathering and processing costs which, in accordance with ASC 606, remain deducted from sales proceeds and are recorded as a reduction of Oil and gas sales on the Consolidated Statement of Operations.

 

Significant accounting policy

 

Revenue is measured based on a consideration specified in a contract with a customer, and excludes any amounts collected on behalf of third parties. The Company recognizes revenue when it satisfies a performance obligation by transferring control over a product or service to a customer. We generally consider the delivery of each unit (Bbl or MMBtu) to be separately identifiable and represents a distinct performance obligation that is satisfied at a point-in-time once control of the product has been transferred to the customer upon delivery to an agreed upon delivery point. Transfer of control typically occurs when the products are delivered to the purchaser, and title has transferred.

 

Revenue is recognized at a point in time as a result of not meeting any of the three criteria required for recognition over time.

 

Certain transportation and processing costs associated with fixed fee contracts where title transfers to the customer at the tailgate of the processing plant and we pay a gathering and processing fee are recognized at the time of title transfer. These costs are presented as Transportation and processing costs on the Consolidated Statement of Operations.

 

The Company enters into marketing agreements with our non-operating partners to market and sell their share of production to third parties. Under these arrangements, we record revenue for our share of the production (i.e. we, as the operator, record revenue on a net basis). Distributions are made to our non-operating partners for their share of the revenue, in accordance with the governing states’ remittance policy.

 

As part of our adoption of ASC 606, we used practical expedients permitted by the standard when applicable. These practical expedients included:

 

·

Applying the new guidance only to contracts that are not completed as of January 1, 2018;

 

·

Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction, that are collected by the Company from a customer, are excluded from revenue;

 

·

The Company recognizes the incremental cost of obtaining contracts as an expense when incurred if the amortization period of the assets that the Company otherwise would have recognized is one year or less. These costs are included in General and administrative expenses;

 

·

For our product sales that have a contact term greater than one year, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our product sales contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required; and

 

·

For our product sales that have a contract term of one year or less, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of the contract that has an original expected duration of one year or less.

 

Disaggregation of revenue

 

The following tables present quantitative information about disaggregated revenues from contracts with customers by commodity and region of production for the year ended December 31, 2018 as presented under ASC 606.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2018

 

(in thousands of dollars)

    

Oil

 

Natural gas

 

NGLs

 

Total

    

Eastern Anadarko

 

$

57,171

 

$

8,661

 

$

23,840

 

$

89,672

 

Western Anadarko

 

 

84,048

 

 

26,033

 

 

37,120

 

 

147,201

 

Total

 

$

141,219

 

$

34,694

 

$

60,960

 

$

236,873

 

 

The following tables present quantitative information about disaggregated revenues from contracts with customers by commodity and region of production for the years ended December 31, 2017 and 2016 as presented under ASC 605 since the Company adopted ASC 606 under the modified retrospective method which does not require adjustment of prior period amounts.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2017 (1)

 

(in thousands of dollars)

    

Oil

 

Natural gas

 

NGLs

 

Total

    

Eastern Anadarko

 

$

16,339

 

$

3,265

 

$

7,173

 

$

26,777

 

Western Anadarko

 

 

76,868

 

 

38,926

 

 

43,822

 

 

159,616

 

Total

 

$

93,207

 

$

42,191

 

$

50,995

 

$

186,393

 


(1)

Prior period amounts have not been adjusted under the modified retrospective method.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2016 (1)

(in thousands of dollars)

    

Oil

 

Natural gas

 

NGLs

 

Total

Eastern Anadarko

 

$

12

 

$

 2

 

$

 2

 

$

16

Western Anadarko

 

 

63,724

 

 

31,432

 

 

29,705

 

 

124,861

Total

 

$

63,736

 

$

31,434

 

$

29,707

 

$

124,877


(1)

Prior period amounts have not been adjusted under the modified retrospective method.

 

During the three years ended December 31, 2018, the timing of revenue recognition for all products was transferred at a point in time. No products and/or services were transferred over time.

 

Contract balances

 

The following table provides information about receivables, contract assets, and contract liabilities from contracts with customers at December 31, 2018 and 2017.

 

 

 

 

 

 

 

 

 

 

 

December 31, 

 

December 31, 

 

(in thousands of dollars)

    

2018

    

2017

    

Accounts receivable, net

 

 

 

 

 

 

 

Oil and gas sales

 

$

33,954

 

$

34,492

 

Other current liabilities

 

 

 

 

 

 

 

Contract liabilities

 

$

1,079

 

$

 —

 

 

Accounts receivable – Oil and gas sales consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. Under our sales contracts, payment is unconditional after our performance obligations have been satisfied under ASC 606. Accordingly, unconditional rights to consideration are presented separately as a receivable. Since our sales contracts are not conditional on factors other than the passage of time, the contracts do not give rise to contract assets under ASC 606.

 

Other current liabilities – contract liabilities represent estimated fees for minimum volume and drilling commitments associated with certain revenue contracts with customers.

v3.10.0.1
Properties, Plant and Equipment
12 Months Ended
Dec. 31, 2018
Disclosure Text Block  
Properties, Plant and Equipment

6. Properties, Plant and Equipment

Oil and Gas Properties

The Company accounts for its oil and natural gas exploration and production activities under the successful efforts method of accounting. Oil and gas properties consisted of the following at December 31, 2018 and 2017:

 

 

 

 

 

 

 

 

 

 

December 31, 

 

December 31, 

 

(in thousands of dollars)

    

2018

    

2017

 

Mineral interests in properties

 

   

 

 

   

 

 

Unproved

 

$

96,770

 

$

164,087

 

Proved

 

 

961,314

 

 

893,246

 

Wells and equipment and related facilities

 

 

1,617,330

 

 

1,434,383

 

 

 

 

2,675,414

 

 

2,491,716

 

Less: Accumulated depletion and impairment

 

 

(2,403,568)

 

 

(894,676)

 

Net oil and gas properties

 

$

271,846

 

$

1,597,040

 

 

There were no exploratory wells drilled during the years ended December 31, 2018 and 2017 and, as such, no associated costs were capitalized. No exploratory wells resulted in exploration expense during the three years ended December 31, 2018.

The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. During the years ended December 31, 2018 and 2017, the Company capitalized $0.2 million and $0.4 million, respectively, associated with such in progress projects. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

Depletion of oil and gas properties amounted to $172.9 million, $166.2 million, and $152.7 million for the years ended December 31, 2018, 2017, and 2016, respectively.

The Company continues to monitor its proved and unproved properties for impairment. Impairment charges of $1,332.0 million were recognized during the year ended December 31, 2018. See Note 9, “Fair Value Measurement,” for further information. During the year ended December 31, 2017, as noted in Note 4, “Acquisitions and Divestitures - Arkoma Divestiture,” the Company recognized an impairment charge of $148.0 million during the second quarter of 2017 based on the Company’s negotiated selling price of the Arkoma Basin oil and gas property assets and related liabilities. Additionally, the Company recognized an impairment charge of $1.6 million during the fourth quarter of 2017 related to minor properties, which we are not currently developing. No impairments of proved or unproved properties were recorded during the year ended December 31, 2016.

Other Property, Plant and Equipment

Other property, plant and equipment consisted of the following at December 31, 2018 and 2017:

 

 

 

 

 

 

 

 

 

 

December 31, 

 

December 31, 

 

(in thousands of dollars)

    

2018

    

2017

 

Leasehold improvements

 

$

1,186

 

$

1,186

 

Furniture, fixtures, computers and software

 

 

4,411

 

 

4,410

 

Vehicles

 

 

1,922

 

 

1,922

 

Aircraft

 

 

 —

 

 

910

 

Land

 

 

261

 

 

 —

 

Other

 

 

238

 

 

210

 

 

 

 

8,018

 

 

8,638

 

Less: Accumulated depreciation and amortization

 

 

(6,379)

 

 

(5,919)

 

Net other property, plant and equipment

 

$

1,639

 

$

2,719

 

 

Depreciation and amortization of other property, plant and equipment amounted to $1.0 million, $1.0 million, and $1.2 million during the years ended December 31, 2018, 2017 and 2016, respectively.

v3.10.0.1
Long-Term Debt
12 Months Ended
Dec. 31, 2018
Disclosure Text Block  
Long-Term Debt

7. Long‑Term Debt

Long-term debt consisted of the following at December 31, 2018 and 2017:

 

 

 

 

 

 

 

 

(in thousands of dollars)

    

December 31, 2018

    

December 31, 2017

 

Revolver

 

$

 —

 

$

211,000

 

2022 Notes

 

 

409,148

 

 

409,148

 

2023 Notes

 

 

150,000

 

 

150,000

 

2023 First Lien Notes

 

 

450,000

 

 

 —

 

Total principal amount

 

 

1,009,148

 

 

770,148

 

Less: unamortized discount

 

 

(13,342)

 

 

(5,228)

 

Less: debt issuance costs, net

 

 

(13,649)

 

 

(5,604)

 

Total carrying amount

 

$

982,157

 

$

759,316

 

 

Senior Unsecured Notes

On April 1, 2014, JEH and Jones Energy Finance Corp., JEH’s wholly owned subsidiary formed for the sole purpose of co-issuing certain of JEH’s debt (collectively, the “Issuers”), sold $500.0 million in aggregate principal amount of the Issuers’ 6.75% senior notes due 2022 (the “2022 Notes”). The Company used the net proceeds from the issuance of the 2022 Notes to repay certain indebtedness and for working capital and general corporate purposes. The 2022 Notes bear interest at a rate of 6.75% per year, payable semi-annually on April 1 and October 1 of each year beginning October 1, 2014. The 2022 Notes were registered in March 2015. The 2022 Notes mature on April 1, 2022.

On February 23, 2015, the Issuers sold $250.0 million in aggregate principal amount of 9.25% senior notes due 2023 (the “2023 Notes”) in a private placement to affiliates of GSO Capital Partners LP and Magnetar Capital LLC. The 2023 Notes were issued at a discounted price equal to 94.59% of the principal amount. The Company used the $236.5 million net proceeds from the issuance of the 2023 Notes to repay outstanding borrowings under the Revolver (as defined below) and for working capital and general corporate purposes. The 2023 Notes bear interest at a rate of 9.25% per year, payable semi-annually on March 15 and September 15 of each year beginning September 15, 2015. The 2023 Notes were registered in February 2016. The 2023 Notes mature on March 15, 2023.

During 2016, the Company purchased an aggregate principal amount of $190.9 million of its senior unsecured notes through several open-market and privately negotiated purchases. The Company purchased $90.9 million principal amount of its 2022 Notes for $38.1 million, and $100.0 million principal amount of its 2023 Notes for $46.5 million, in each case excluding accrued interest and including any associated fees. The Company used cash on hand and borrowings from its Revolver to fund the note purchases. In conjunction with the extinguishment of this debt, JEH recognized cancellation of debt income of $99.5 million during the year ended December 31, 2016, on a pre-tax basis. This income was recorded in Gain on debt extinguishment on the Company’s Consolidated Statement of Operations. Of the Company’s total repurchases, $20.3 million principal amount of its 2022 Notes were not cancelled and are available for future reissuance, subject to applicable securities laws. No additional purchases were made during 2017 and 2018.

 

The 2022 Notes and 2023 Notes are guaranteed on a senior unsecured basis by the Company and by all of its significant subsidiaries. The 2022 Notes and 2023 Notes will be senior in right of payment to any future subordinated indebtedness of the Issuers.

 

The Company may redeem the 2022 Notes at any time on or after April 1, 2017 and the 2023 Notes at any time on or after March 15, 2018 at a declining redemption price set forth in the respective indentures, plus accrued and unpaid interest.

The indentures governing the 2022 Notes and 2023 Notes are substantially identical and contain covenants that, among other things, limit the ability of the Company to incur additional indebtedness or issue certain preferred stock, pay dividends on capital stock, transfer or sell assets, make investments, create certain liens, enter into agreements that restrict dividends or other payments from the Company’s restricted subsidiaries to the Company, consolidate, merge or transfer all of the Company’s assets, engage in transactions with affiliates or create unrestricted subsidiaries. If at any time when the 2022 Notes or 2023 Notes are rated investment grade and no default or event of default (as defined in the indenture) has occurred and is continuing, many of the foregoing covenants pertaining to the 2022 Notes or 2023 Notes, as applicable, will be suspended. If the ratings on the 2022 Notes or 2023 Notes, as applicable, were to decline subsequently to below investment grade, the suspended covenants would be reinstated.

As of December 31, 2018, the Company was in compliance with the indentures governing the 2022 Notes and 2023 Notes.

Senior Secured First Lien Notes due 2023

On February 14, 2018, the Issuers sold $450.0 million of 9.25% senior secured first lien notes due 2023 (the “2023 First Lien Notes”) at an offering price equal to 97.526% of par in an offering exempt from registration under the Securities Act. The 2023 First Lien Notes are senior secured first lien obligations of JEH and Jones Energy Finance Corp. and are guaranteed on a senior secured first lien basis by the Company and each of the existing and future restricted subsidiaries of JEH and Jones Energy Finance Corp. The Company used the net proceeds from the offering to repay all but $25.0 million of the outstanding borrowings under the Revolver, to fund drilling and completion activities, and for other general corporate purposes. The Notes bear interest at a rate of 9.25% per year, payable semi-annually on March 15 and September 15 of each year beginning September 15, 2018.  During the year ended December 31, 2018, the Company capitalized $11.4 million of loan costs associated with the issuance of the 2023 First Lien Notes.

As of December 31, 2018, the Company was in compliance with the indenture governing the 2023 First Lien Notes.

Other Long-Term Debt

The Company has a Senior Secured Revolving Credit Facility (the “Revolver”) with a syndicate of banks. At the beginning of 2018, the borrowing base under the Revolver was $350.0 million. In connection with the offering of the 2023 First Lien Notes, the borrowing base was reduced to $50.0 million effective February 14, 2018. On June 27, 2018, in connection with an amendment described below, the borrowing base was further reduced to $25.00. The Company’s oil and gas properties are pledged as collateral to secure its obligations under the Revolver. The Revolver matures on November 6, 2019.

In connection with the offering of the 2023 First Lien Notes, on February 14, 2018, JEH amended the Revolver to, among other things, (a) permit the issuance of the 2023 First Lien Notes and additional senior secured notes in an aggregate principal amount, together with the notes issued pursuant to this offering, not to exceed $700.0 million, (b) permit the incurrence of liens securing the 2023 First Lien Notes pursuant to the terms of a collateral trust agreement, (c) reduce the borrowing base under the Revolver to $50.0 million and (d) suspend testing of our senior secured leverage ratio until March 31, 2019.

On June 27, 2018, the Company entered into an amendment to the Revolver to, among other things (a) remove the financial maintenance covenants contained therein, including the current ratio, total leverage ratio and senior secured leverage ratio, (b) align certain of the other covenants contained therein to be consistent with the terms of the indenture governing the 2023 First Lien Notes, (c) reduce lender commitments to $25.00, and (d) reduce the borrowing base to $25.00 for the remainder of the life of the facility. Additionally, outstanding borrowings of $25.0 million were repaid in connection with the closing of the amendment. The Company does not currently have any borrowings under the Revolver.

The Company recognized accelerated amortization of debt issuance costs of $3.8 million during the year ended December 31, 2018 associated with the modification of the Revolver, which was recorded as Interest expense on the Company’s Consolidated Statement of Operations.

The terms of the Revolver require the Company to make periodic payments of interest on the loans outstanding thereunder, if any, with all outstanding principal and interest under the Revolver due on the maturity date. The Revolver is subject to a borrowing base, which limits the amount of borrowings which may be drawn thereunder.

 

Interest on the Revolver is calculated, at the Company’s option, at either (a) the London Interbank Offered (“LIBO”) rate for the applicable interest period plus a margin of 2.75% to 3.75% based on the level of borrowing base utilization at such time or (b) the greatest of the federal funds rate plus 0.50%, the one month adjusted LIBO rate plus 1.00%, or the prime rate announced by Wells Fargo Bank, N.A. in effect on such day, in each case plus a margin of 1.75% to 2.75% based on the level of borrowing base utilization at such time. The average interest rate under the Revolver was 4.46% on an average outstanding balance of $74.3 million through June 27, 2018.

 

Total interest and commitment fees under the Revolver were $1.8 million, $6.6 million, and $5.3 million for the years ended December 31, 2018, 2017 and 2016, respectively.

 

Jones Energy, Inc. and its consolidated subsidiaries are subject to certain covenants under the Revolver, which are substantially similar to those set forth in the indenture governing the 2023 First Lien Notes or are otherwise customary for facilities of this type and which limit our ability to, among other things: borrow money or issue guarantees; pay dividends, redeem capital stock or make other restricted payments; incur liens to secure indebtedness; sell certain assets; enter into transactions with our affiliates; or merge with another person or sell substantially all of our assets.

 

As of December 31, 2018, the Company was in compliance with all terms of our Revolver.

v3.10.0.1
Derivative Instruments and Hedging Activities
12 Months Ended
Dec. 31, 2018
Disclosure Text Block  
Derivative Instruments and Hedging Activities

8. Derivative Instruments and Hedging Activities

The Company uses derivative instruments to mitigate volatility in commodity prices. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our hedging positions.

 

The following tables summarize our hedging positions as of December 31, 2018: 

Hedging Positions

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2018

 

 

    

 

    

 

 

    

 

 

    

Weighted

    

Final

 

 

 

 

 

Low

 

High

 

Average

 

Expiration

 

Oil swaps

 

Exercise price

 

$

49.85

 

$

50.12

 

$

49.98

 

December 2020

 

 

 

Barrels per month

 

 

40,000

 

 

60,000

 

 

50,000

 

 

 

Natural gas swaps

 

Exercise price

 

$

2.76

 

$

2.86

 

$

2.81

 

December 2020

 

 

 

MMbtu per month

 

 

700,000

 

 

1,100,000

 

 

865,833

 

 

 

Oil collars

 

Puts (floors)

 

$

45.00

 

$

50.00

 

$

48.52

 

December 2019

 

 

 

Calls (ceilings)

 

$

56.60

 

$

61.00

 

$

59.64

 

 

 

 

 

Net barrels per month

 

 

65,000

 

 

73,000

 

 

67,500

 

 

 

Natural gas collars

 

Puts (floors)

 

$

2.55

 

$

2.55

 

$

2.55

 

December 2019

 

 

 

Calls (ceilings)

 

$

3.08

 

$

3.41

 

$

3.19

 

 

 

 

 

Net MMbtu per month

 

 

950,000

 

 

1,050,000

 

 

990,833

 

 

 

 

 

The Company recognized net losses on derivative instruments of $2.8 million, $18.0 million and $51.3 million for the years ended December 31, 2018, 2017 and 2016, respectively.

The Company routinely enters into oil and natural gas swap contracts as seller, thus resulting in a fixed price. During 2016 and 2017, the Company realized certain mark-to-market gains associated with oil and natural gas hedges the Company had in place for years 2018 and 2019. The gains were effectively realized by purchasing, as opposed to selling, oil and natural gas swap contracts for an equal volume that was associated with the initial hedge transaction. Therefore, as prices fluctuate, the loss (or gain) on any single contract in 2018 and 2019 will be offset by an equal gain (or loss). This essentially left the underlying production open to fluctuations in market prices prior to the point when the Company began to re-hedge the unhedged production. Based on the original contract terms of these purchased swaps, the gains would have been recognized as the hedge contracts mature in 2018 and 2019. However, during the year ended December 31, 2017, the Company unwound all of its realized 2018 and 2019 hedges resulting in approximately $42.8 million of recognized gains which have been included in Net gain (loss) on commodity derivatives on the Company’s Consolidated Statement of Operations.

Offsetting Assets and Liabilities

As of December 31, 2018, the counterparties to our commodity derivative contracts consisted of six financial institutions. All of our counterparties or their affiliates are also lenders under the Revolver. We are not generally required to post additional collateral under our derivative agreements.

Our derivative agreements contain set-off provisions that state that in the event of default or early termination, any obligation owed by the defaulting party may be offset against any obligation owed to the defaulting party.

The following table presents information about our commodity derivative contracts that are netted on our Consolidated Balance Sheet as of December 31, 2018 and 2017:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    

 

 

    

 

 

    

Net Amounts