JONES ENERGY, INC., 10-K filed on 2/28/2018
Annual Report
Document and Entity Information (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Jun. 30, 2017
Feb. 21, 2018
Class A common stock
Feb. 21, 2018
Class B common stock
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, 2017 
 
 
 
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
Accelerated Filer 
 
 
 
Entity Public Float
 
$ 102.4 
 
 
Entity Common Stock, Shares Outstanding
 
 
92,030,282 
9,627,821 
Document Fiscal Year Focus
2017 
 
 
 
Document Fiscal Period Focus
FY 
 
 
 
Consolidated Balance Sheets (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2017
Dec. 31, 2016
Current assets
 
 
Cash
$ 19,472 
$ 34,642 
Accounts receivable, net
 
 
Oil and gas sales
34,492 
26,568 
Joint interest owners
31,651 
5,267 
Other
1,236 
6,061 
Commodity derivative assets
3,474 
24,100 
Other current assets
14,376 
2,684 
Total current assets
104,701 
99,322 
Oil and gas properties, net, at cost under the successful efforts method
1,597,040 
1,743,588 
Other property, plant and equipment, net
2,719 
2,996 
Commodity derivative assets
172 
34,744 
Other assets
5,431 
6,050 
Total assets
1,710,063 
1,886,700 
Current liabilities
 
 
Trade accounts payable
72,663 
36,527 
Oil and gas sales payable
31,462 
28,339 
Accrued liabilities
21,604 
25,707 
Commodity derivative liabilities
36,709 
14,650 
Other current liabilities
4,049 
2,584 
Total current liabilities
166,487 
107,807 
Long-term debt
759,316 
724,009 
Deferred revenue
5,457 
7,049 
Commodity derivative liabilities
8,788 
1,209 
Asset retirement obligations
19,652 
19,458 
Liability under tax receivable agreement
59,596 
43,045 
Other liabilities
811 
792 
Deferred tax liabilities
14,281 
2,905 
Total liabilities
1,034,388 
906,274 
Commitments and contingencies (Note 15)
   
   
Mezzanine equity
 
 
Series A preferred stock, $0.001 par value; 1,839,995 shares issued and outstanding at December 31, 2017 and 1,840,000 shares issued and outstanding at December 31, 2016
89,539 
88,975 
Stockholders' equity
 
 
Treasury stock, at cost: 22,602 shares at December 31, 2017 and December 31, 2016
(358)
(358)
Additional paid-in-capital
606,319 
447,137 
Retained (deficit) / earnings
(136,274)
(8,652)
Stockholders' equity
469,787 
438,214 
Non-controlling interest
116,349 
453,237 
Total stockholders’ equity
586,136 
891,451 
Total liabilities and stockholders' equity
1,710,063 
1,886,700 
Class A common stock
 
 
Stockholders' equity
 
 
Common stock
90 
57 
Class B common stock
 
 
Stockholders' equity
 
 
Common stock
$ 10 
$ 30 
Consolidated Balance Sheets (Parenthetical) (USD $)
Dec. 31, 2017
Dec. 31, 2016
Mezzanine equity
 
 
Series A preferred stock, par value (in dollars per share)
$ 0.001 
$ 0.001 
Series A preferred stock, shares issued
1,839,995 
1,840,000 
Series A preferred stock, shares outstanding
1,839,995 
1,840,000 
Treasury stock
 
 
Treasury stock, shares
22,602 
22,602 
Class A common stock
 
 
Common stock
 
 
Common stock, par value (in dollars per share)
$ 0.001 
$ 0.001 
Common stock, shares issued
90,139,840 
57,048,076 
Common stock, shares outstanding
90,117,238 
57,025,474 
Class B common stock
 
 
Common stock
 
 
Common stock, par value (in dollars per share)
$ 0.001 
$ 0.001 
Common stock, shares issued
9,627,821 
29,832,098 
Common stock, shares outstanding
9,627,821 
29,832,098 
Consolidated Statements of Operations (USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Operating revenues
 
 
 
Oil and gas sales
$ 186,393 
$ 124,877 
$ 194,555 
Other revenues
2,180 
2,970 
2,844 
Total operating revenues
188,573 
127,847 
197,399 
Operating costs and expenses
 
 
 
Lease operating
36,636 
32,640 
41,027 
Production and ad valorem taxes
6,874 
7,768 
12,130 
Exploration
14,145 
6,673 
6,551 
Depletion, depreciation and amortization
167,224 
153,930 
205,498 
Impairment of oil and gas properties
149,648 
 
 
Accretion of ARO liability
960 
1,263 
1,087 
General and administrative
29,892 
29,640 
33,388 
Other operating
 
199 
4,188 
Total operating expenses
405,379 
232,113 
303,869 
Operating income (loss)
(216,806)
(104,266)
(106,470)
Other income (expense)
 
 
 
Interest expense
(51,651)
(53,127)
(64,458)
Gain on debt extinguishment
 
99,530 
 
Net gain (loss) on commodity derivatives
(17,985)
(51,264)
158,753 
Other income (expense)
56,952 
536 
317 
Other income (expense), net
(12,684)
(4,325)
94,612 
Income (loss) before income tax
(229,490)
(108,591)
(11,858)
Income tax provision (benefit)
 
 
 
Current
(3,585)
3,981 
113 
Deferred
(47,082)
(27,767)
(2,894)
Total income tax provision (benefit)
(50,667)
(23,786)
(2,781)
Net income (loss)
(178,823)
(84,805)
(9,077)
Net income (loss) attributable to non-controlling interests
(77,331)
(42,253)
(6,696)
Net income (loss) attributable to controlling interests
(101,492)
(42,552)
(2,381)
Dividends and accretion on preferred stock
(7,924)
(2,669)
 
Net income (loss) attributable to common shareholders
$ (109,416)
$ (45,221)
$ (2,381)
Earnings (loss) per share:
 
 
 
Basic - Net income (loss) attributable to common shareholders (in dollars per share)
$ (1.51)1
$ (1.04)1
$ (0.08)1
Diluted - Net income (loss) attributable to common shareholders (in dollars per share)
$ (1.51)1
$ (1.04)1
$ (0.08)1
Weighted average Class A shares outstanding (1) :
 
 
 
Basic (in shares)
72,411 1
43,506 1
29,161 1
Diluted (in shares)
72,411 1
43,506 1
29,161 1
Consolidated Statements of Operations (Parenthetical) (Class A common stock)
Mar. 31, 2017
Class A common stock
 
Weighted average Class A shares outstanding (1) :
 
Special stock dividend declared per share (in shares)
0.087423 
Statement of Changes in Stockholders' Equity (USD $)
In Thousands, except Share data, unless otherwise specified
Common Stock
Class A common stock
USD ($)
Common Stock
Class B common stock
USD ($)
Treasury Stock
Class A common stock
USD ($)
Additional Paid-in-Capital
USD ($)
Retained Earnings
USD ($)
Non-controlling Interest
USD ($)
Class A common stock
Total
USD ($)
Balance at Dec. 31, 2014
$ 13 
$ 37 
$ (358)
$ 178,763 
$ 38,950 
$ 635,945 
 
$ 853,350 
Balance (in shares) at Dec. 31, 2014
12,622,000 
36,719,000 
23,000 
 
 
 
 
 
Increase (Decrease) Stockholders' Equity
 
 
 
 
 
 
 
 
Stock-compensation expense
 
 
 
7,562 
 
 
 
7,562 
Stock-compensation expense (in shares)
67,000 
 
 
 
 
 
 
 
Vested restricted shares (in shares)
153,000 
 
 
 
 
 
 
 
Sale of common stock
12 
 
 
123,189 
 
 
 
123,201 
Sale of common stock (in shares)
12,263,000 
 
 
 
 
 
 
 
Exchange of Class B Shares for Class A Shares
(6)
 
54,209 
 
(92,393)
 
(38,184)
Exchange of Class B shares for Class A shares (in shares)
5,446,000 
(5,446,000)
 
 
 
 
 
 
Net income (loss)
 
 
 
 
(2,381)
(6,696)
 
(9,077)
Balance at Dec. 31, 2015
31 
31 
(358)
363,723 
36,569 
536,856 
 
936,852 
Balance (in shares) at Dec. 31, 2015
30,551,000 
31,273,000 
23,000 
 
 
 
 
 
Increase (Decrease) Stockholders' Equity
 
 
 
 
 
 
 
 
Stock-compensation expense
 
 
 
7,425 
 
 
 
7,425 
Vested restricted shares (in shares)
385,000 
 
 
 
 
 
 
 
Distributions paid to JEH unitholders
 
 
 
 
 
(17,319)
 
(17,319)
Sale of common stock
25 
 
 
65,421 
 
 
 
65,446 
Sale of common stock (in shares)
24,648,000 
 
 
 
 
 
 
 
Exchange of Class B Shares for Class A Shares
(1)
 
10,568 
 
(24,047)
 
(13,479)
Exchange of Class B shares for Class A shares (in shares)
1,441,000 
(1,441,000)
 
 
 
 
 
 
Dividends and accretion on preferred stock
 
 
 
 
(2,669)
 
 
(2,669)
Net income (loss)
 
 
 
 
(42,552)
(42,253)
 
(84,805)
Balance at Dec. 31, 2016
57 
30 
(358)
447,137 
(8,652)
453,237 
 
891,451 
Balance (in shares) at Dec. 31, 2016
57,025,000 
29,832,000 
23,000 
 
 
 
 
 
Increase (Decrease) Stockholders' Equity
 
 
 
 
 
 
 
 
Cumulative effect of adoption of ASU 2016-09
 
 
 
706 
(706)
 
 
 
Stock-compensation expense
 
 
5,797 
 
 
 
5,798 
Stock-compensation expense (in shares)
763,000 
 
 
 
 
 
 
 
Distributions paid to JEH unitholders
 
 
 
 
 
(562)
 
(562)
Sale of common stock
 
 
8,329 
 
 
 
8,333 
Sale of common stock (in shares)
3,716,000 
 
 
 
 
 
3,700,000 
 
Stock dividends on common stock
 
 
17,495 
(17,500)
 
 
 
Stock dividends on common stock (in shares)
5,000,000 
 
 
 
 
 
 
 
Exchange of Class B Shares for Class A Shares
20 
(20)
 
122,865 
 
(258,995)
 
(136,130)
Exchange of Class B shares for Class A shares (in shares)
20,204,000 
(20,204,000)
 
 
 
 
 
 
Dividends and accretion on preferred stock
 
 
3,990 
(7,924)
 
 
(3,931)
Dividends and accretion on preferred stock (in shares)
3,409,000 
 
 
 
 
 
 
 
Net income (loss)
 
 
 
 
(101,492)
(77,331)
 
(178,823)
Balance at Dec. 31, 2017
$ 90 
$ 10 
$ (358)
$ 606,319 
$ (136,274)
$ 116,349 
 
$ 586,136 
Balance (in shares) at Dec. 31, 2017
90,117,000 
9,628,000 
23,000 
 
 
 
 
 
Consolidated Statements of Cash Flows (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Cash flows from operating activities
 
 
 
Net income (loss)
$ (178,823)
$ (84,805)
$ (9,077)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
 
 
 
Depletion, depreciation, and amortization
167,224 
153,930 
205,498 
Exploration (dry hole and lease abandonment)
11,017 
6,261 
5,250 
Impairment of oil and gas properties
149,648 
 
 
Accretion of ARO liability
960 
1,263 
1,087 
Amortization of debt issuance costs
3,955 
4,060 
6,043 
Stock compensation expense
6,260 
7,425 
7,562 
Deferred and other non-cash compensation expense
208 
804 
455 
Amortization of deferred revenue
(1,854)
(2,384)
(1,960)
(Gain) loss on commodity derivatives
17,985 
51,264 
(158,753)
(Gain) loss on sales of assets
127 
(14)
(Gain) on debt extinguishment
 
(99,530)
 
Deferred income tax provision
(47,082)
(27,767)
(2,892)
Change in liability under tax receivable agreement
(59,492)
 
 
Other - net
2,044 
418 
(961)
Changes in operating assets and liabilities
 
 
 
Accounts receivable
(34,615)
2,276 
64,510 
Other assets
(12,330)
(675)
(432)
Accrued interest expense
(1,422)
(4,727)
7,050 
Accounts payable and accrued liabilities
35,198 
17,901 
(54,534)
Net cash provided by operations
59,008 
25,700 
68,849 
Cash flows from investing activities
 
 
 
Additions to oil and gas properties
(245,364)
(264,462)
(311,305)
Net adjustments to purchase price of properties acquired
2,391 
 
 
Proceeds from sales of assets
61,290 
1,645 
41 
Acquisition of other property, plant and equipment
(586)
(310)
(1,101)
Current period settlements of matured derivative contracts
72,265 
132,265 
144,145 
Net cash (used in) investing
(110,004)
(130,862)
(168,220)
Cash flows from financing activities
 
 
 
Proceeds from issuance of long-term debt
162,000 
130,000 
85,000 
Repayment of long-term debt
(129,000)
(62,000)
(335,000)
Proceeds from senior notes
 
 
236,475 
Purchase of senior notes
 
(84,589)
 
Payment of debt issuance costs
(1,115)
 
(1,556)
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
(462)
 
 
Proceeds from sale of common stock
8,333 
65,446 
122,779 
Proceeds from sale of preferred stock
 
87,988 
 
Net cash provided by financing
35,826 
117,911 
107,698 
Net increase (decrease) in cash
(15,170)
12,749 
8,327 
Cash
 
 
 
Beginning of period
34,642 
21,893 
13,566 
End of period
19,472 
34,642 
21,893 
Supplemental disclosure of cash flow information
 
 
 
Cash paid for interest, net of capitalized interest
49,101 
53,816 
52,796 
Cash paid for income taxes
2,318 
 
(155)
Change in accrued additions to oil and gas properties
3,921 
9,325 
(111,210)
Asset retirement obligations incurred, including changes in estimate
$ 924 
$ (1,276)
$ 6,371 
Organization and Description of Business
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, 2017, the Company held 90,117,238 JEH Units and all of the preferred units representing membership interests in JEH, and the remaining 9,627,821 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 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 of Directors of the Company 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 1,839,995 remained issued and outstanding as of December 31, 2017. See Note 12, “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.

Significant Accounting Policies
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, 2017 and 2016 and the financial statements reported for each of the three years in the period ended December 31, 2017 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, 2017 and at December 31, 2016 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, 2017 and 2016, 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, 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 were due from four purchasers and 48% of Accounts receivable‑Joint interest owners were due from five working interest owners. As of December 31, 2015, 68% of Accounts receivable—Oil and gas sales are due from four purchasers and 80% 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.

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, 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. During the year ended December 31, 2015, the largest purchasers of our production were Valero Energy Corp. (“Valero”), ETC Field Services LLC, Plains Marketing LP, and NGL Energy Partners LP, which accounted for approximately 18%,  17%,  16%, and 15% 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. Fair value is calculated by discounting the future cash flows at an appropriate risk‑adjusted discount rate.

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.

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, 2017 and 2016:

 

 

 

 

 

 

 

 

 

 

December 31, 

 

December 31, 

 

(in thousands of dollars)

    

2017

    

2016

    

Accrued interest

 

$

12,109

 

$

13,531

 

Other accrued liabilities

 

 

9,495

 

 

12,176

 

Total accrued liabilities

 

$

21,604

 

$

25,707

 

 

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, 2017, 2016 and 2015, 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 7, “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

Revenues from the sale of crude oil, natural gas, and natural gas liquids are valued at the estimated sales price and recognized when the product is delivered at a fixed or determinable price, title has transferred, collectability is reasonably assured and evidenced by a contract. The Company follows the “sales method” of accounting for its oil and natural gas revenue, so it recognizes revenue on all crude oil, natural gas, and natural gas liquids sold to purchasers. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. The Company had no significant imbalances as of December 31, 2017, 2016, and 2015.

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 11. “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 March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, “Compensation—Stock Compensation” (Topic 718). This amendment is intended to simplify the accounting for share-based payment awards to employees, specifically in regard to (1) the income tax consequences, (2) classification of awards as either equity or liabilities, and (3) classification on the statement of cash flows. The amendments are effective for interim and annual reporting periods beginning after December 15, 2016. Therefore, the Company has adopted ASU 2016-09 effective as of January 1, 2017. Upon adoption of ASU 2016-09, the Company elected to change its accounting policy to account for forfeitures as they occur. The change was applied on a modified retrospective basis with a cumulative effect adjustment to retained earnings for forfeitures of $0.7 million as of January 1, 2017. As a result of the valuation allowance against the Company’s deferred tax assets, there was no net adjustment to retained earnings for the change in accounting for unrecognized windfall tax benefits.

 

In May 2017, the FASB issued ASU 2017-09, “Scope of Modification Accounting” as it relates to “Compensation—Stock Compensation” (Topic 718). This amendment clarifies when changes to the terms or conditions of a share-based payment award must be accounted for as modifications. The new guidance is expected to reduce diversity in practice and result in fewer changes to the terms of an award being accounted for as modifications. Under ASU 2017-09, an entity will not apply modification accounting to a share-based payment award if the award’s fair value, vesting conditions and classification as an equity or liability instrument are the same immediately before and after the change. The amendments are effective for interim and annual reporting periods beginning after December 15, 2017. Early adoption is permitted and the Company chose to early adopt ASU 2017-09 beginning April 1, 2017. The change was applied prospectively to awards modified on or after the adoption date. Adoption did not have a material impact on the financial position, cash flows or results of operations.

 

To be adopted in a future period:

 

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 are now effective for interim and annual reporting periods beginning after December 15, 2017 and may be applied on either a full or modified retrospective basis. Early adoption is permitted.

 

During 2017, the Company performed a comparison of our current revenue recognition policies in effect through December 31, 2017 to the new requirements upon adoption of ASU 2014-09 and ASU 2015-14 for each of our revenue categories based upon review of our current contracts by product category and homogenous groupings. Upon completion of the assessment, the analysis of these homogenous groupings did not indicate any material change to our current revenue recognition methodology, although we do expect some changes in presentation of gross revenues and expenses upon adoption of the standard; such costs are currently offset against revenues. The Company adopted ASU 2014-09 and ASU 2015-14 effective as of January 1, 2018 applied on a modified retrospective basis, which did not result in a material cumulative effect adjustment as of the date of adoption. Adoption did not have a material impact on the financial position, cash flows or results of operations. In addition to changes in the presentation of the Company’s Consolidated Statement of Operations, we expect to expand disclosures related to revenue recognition. The Company will continue to further evaluate the effect that the adoption of ASU 2014-09 and ASU 2015-14 will have on our disclosures as we prepare for our first quarter 2018 Form 10-Q filing.

 

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) 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. Lessees and lessors must 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. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. Early adoption is permitted. The Company is currently evaluating the impacts of the amendments to our financial statements and accounting practices for leases. We anticipate adoption of ASU 2016-02 effective as of January 1, 2019.

 

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. Early adoption is permitted. 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.

 

In August 2017, the FASB issued ASU 2017-12, “Derivatives and Hedging” (Topic 815). The amendments in this update apply to any entity that elects to apply hedge accounting in accordance with current GAAP. This standard expands an entity’s ability to apply hedge accounting for nonfinancial and financial risk components and allows for a simplified approach for fair value hedging of interest rate risk. The standard also eliminates the need to separately measure and report hedge ineffectiveness and generally requires the entire change in fair value of a hedging instrument to be presented in the same income statement line as the hedged item. Additionally, the standard simplifies the hedge documentation and effectiveness assessment requirements under the previous guidance. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. Early adoption is permitted.

 

Historically, the Company has elected not to designate any of its commodity price risk management activities as cash flow or fair value hedges. After concluding our assessment of the amendments in this update, Management has determined we will continue not to designate any of our commodity price risk management activities as cash flow or fair value hedges. Therefore, adoption is not expected to have a material impact on the financial position, cash flows or results of operations. We anticipate adoption of ASU 2017-12 effective as of January 1, 2019.

Acquisitions and Divestitures
Acquisitions

3. Acquisitions and Divestitures

During the three year period ended December 31, 2017, 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, 2017 and 2015.

 

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 12, “Stockholders’ and Mezzanine equity”.

 

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. As of December 31, 2017, the measurement-period has closed. 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.

 

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. No amounts have been recorded related to this contingent payment as of December 31, 2017.

Properties, Plant and Equipment
Properties, Plant and Equipment

4. 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, 2017 and 2016:

 

 

 

 

 

 

 

 

 

 

December 31, 

 

December 31, 

 

(in thousands of dollars)

    

2017

    

2016

 

Mineral interests in properties

 

   

 

 

   

 

 

Unproved

 

$

164,087

 

$

213,153

 

Proved

 

 

893,246

 

 

1,054,683

 

Wells and equipment and related facilities

 

 

1,434,383

 

 

1,395,291

 

 

 

 

2,491,716

 

 

2,663,127

 

Less: Accumulated depletion and impairment

 

 

(894,676)

 

 

(919,539)

 

Net oil and gas properties

 

$

1,597,040

 

$

1,743,588

 

 

There were no exploratory wells drilled during the year ended December 31, 2017 and, as such, no associated costs were capitalized. One exploratory well was drilled during the year ended December 31, 2016, for which associated costs of $1.3 million were capitalized. No exploratory wells resulted in exploration expense during either year.

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 year ended December 31, 2017, the Company capitalized $0.4 million associated with such in progress projects. The Company did not capitalize any interest during the year ended December 31, 2016 as no projects lasted more than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

Depletion of oil and gas properties amounted to $166.2 million, $152.7 million, and $204.2 million for the years ended December 31, 2017, 2016, and 2015, respectively.

The Company continues to monitor its proved and unproved properties for impairment. During the year ended December 31, 2017, the Company recognized an impairment charge of $1.6 million related to minor properties, which we are not currently developing. Additionally, as noted in Note 3, “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. No impairments of proved or unproved properties were recorded during the years ended December 31, 2016 and 2015.

Other Property, Plant and Equipment

Other property, plant and equipment consisted of the following at December 31, 2017 and 2016:

 

 

 

 

 

 

 

 

 

 

December 31, 

 

December 31, 

 

(in thousands of dollars)

    

2017

    

2016

 

Leasehold improvements

 

$

1,186

 

$

1,213

 

Furniture, fixtures, computers and software

 

 

4,410

 

 

4,170

 

Vehicles

 

 

1,922

 

 

1,677

 

Aircraft

 

 

910

 

 

910

 

Other

 

 

210

 

 

284

 

 

 

 

8,638

 

 

8,254

 

Less: Accumulated depreciation and amortization

 

 

(5,919)

 

 

(5,258)

 

Net other property, plant and equipment

 

$

2,719

 

$

2,996

 

 

Depreciation and amortization of other property, plant and equipment amounted to $1.0 million, $1.2 million, and $1.3 million during the years ended December 31, 2017, 2016 and 2015, respectively.

Long-Term Debt
Long-Term Debt

 

5. Long‑Term Debt

Long-term debt consisted of the following at December 31, 2017 and 2016:

 

 

 

 

 

 

 

 

(in thousands of dollars)

    

December 31, 2017

    

December 31, 2016

 

Revolver

 

$

211,000

 

$

178,000

 

2022 Notes

 

 

409,148

 

 

409,148

 

2023 Notes

 

 

150,000

 

 

150,000

 

Total principal amount

 

 

770,148

 

 

737,148

 

Less: unamortized discount

 

 

(5,228)

 

 

(6,240)

 

Less: debt issuance costs, net

 

 

(5,604)

 

 

(6,899)

 

Total carrying amount

 

$

759,316

 

$

724,009

 

 

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 is 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.

 

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, 2017, 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. See Note 16, “Subsequent Events.”

Other Long-Term Debt

The Company has a Senior Secured Revolving Credit Facility (the “Revolver”) with a syndicate of banks. At the beginning of 2017, the borrowing base under the Revolver was $425.0 million, which was reaffirmed on May 15, 2017 during the semi-annual borrowing base re-determination. Upon closing of the Arkoma Divestiture on August 1, 2017, the Company’s borrowing base was reduced to $375.0 million. Effective November 26, 2017, the borrowing base was further reduced to $350.0 million during the semi-annual borrowing base re-determination. 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.

On November 26, 2017, the Company entered into an amendment to the Revolver to, among other things (a) modify certain financial ratio covenants, which are more fully described below, (b) reduce the borrowing base to $350.0 million until the next redetermination thereof, (c) increase the margin applicable to borrowings under the Revolver by 0.75% if the total leverage ratio is at or below 4.00 to 1.00 and 1.25% if the total leverage ratio is above 4.00 to 1.00, in each case determined as of the last day of the most recently ended fiscal quarter, (d) add a covenant limiting the ability of JEH and its subsidiaries to repurchase or redeem certain indebtedness prior to maturity thereof, subject to certain exceptions, (e) permit JEH to raise up to $350.0 million of junior lien debt, subject to covenant compliance and other customary conditions and (f) increase the Company’s hedge limits to permit, at any time, hedging of up to (i) 100% of projected production from proved reserves over the period of 24 months following such time and (ii) 85% of projected production from proved reserves for the subsequent period of 36 months thereafter.

On February 14, 2018, the Company further amended the Revolver in connection with the offering of the 2023 First Lien Notes. Please see Note 16, “Subsequent Events.”

The terms of the Revolver require the Company to make periodic payments of interest on the loans outstanding thereunder, 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. The borrowing base will be re-determined by the lenders at least semi-annually on or about April 1 and October 1 of each year, with such re-determination based primarily on reserve reports using lender commodity price expectations at such time. Any reduction in the borrowing base will reduce our liquidity, and, if the reduction results in the outstanding amount under our Revolver exceeding the borrowing base, we will be required to repay the deficiency within a short period of time.

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 (i) 2.25% to 3.25% if the Company’s total leverage ratio is less than or equal to 4.00 to 1.00 as of the last day of the previous fiscal quarter or (ii) 2.75% to 3.75% if the Company’s total leverage ratio is greater than 4.00 to 1.00 as of the last day of the previous fiscal quarter, in each case 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 (x) 1.25% to 2.25% if the Company’s total leverage ratio is less than or equal to 4.00 to 1.00 as of the last day of the previous fiscal quarter or (y) 1.75% to 2.75% if the Company’s total leverage ratio is greater than 4.00 to 1.00 as of the last day of the previous fiscal quarter, in each case based on the level of borrowing base utilization at such time. For the year ended December 31, 2017, the average interest rate under the Revolver was 3.04% on an average outstanding balance of $189.0 million. For the year ended December 31, 2016, the average interest rate under the Revolver was 2.40% on an average outstanding balance of $172.3 million.

Total interest and commitment fees under the Revolver were $6.6 million, $5.3 million, and $5.1 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Jones Energy, Inc. and its consolidated subsidiaries are subject to certain covenants under the Revolver, including the requirement to maintain the following financial ratios:

 

·

commencing with the fiscal quarter ending March 31, 2019, a senior secured leverage ratio, consisting of consolidated secured funded debt to EBITDAX, of not greater than 2.25 to 1.00 as of the last day of any fiscal quarter;

 

·

commencing with the fiscal quarter ending March 31, 2019, a total leverage ratio, consisting of consolidated debt to EBITDAX, of not greater than (i) 5.25 to 1.00 as of March 31, 2019, (ii) 5.00 to 1.00 as of June 30, 2019, (iii) 4.75 to 1.00 as of September 30, 2019, (iv) 4.50 to 1.00 as of December 31, 2019 and (v) 4.00 to 1.00 as of the last day of each fiscal quarter ending thereafter; and

 

·

a current ratio, consisting of consolidated current assets, including the unused amounts of the total commitments, to consolidated current liabilities, of not less than 1.00 to 1.00 as of the last day of any fiscal quarter.

 

As of December 31, 2017, our senior secured leverage ratio was approximately 1.18x, our total leverage ratio was approximately 4.29x and our current ratio was approximately 1.85x, as calculated based on the requirements in our indenture. We were in compliance with all terms of our Revolver at December 31, 2017, and we expect to maintain compliance throughout 2018. However, factors including those outside of our control, such as commodity price declines, may prevent us from maintaining compliance with these covenants, at future measurement dates in 2018 and beyond. In the event it were to become necessary, we believe we have the ability to take actions that would prevent us from failing to comply with our covenants, such as paying off and terminating the Revolver. If an event of default exists under the Revolver, the lenders will be able to accelerate the obligations outstanding under the Revolver and exercise other rights and remedies. Our Revolver contains customary events of default, including the occurrence of a change of control, as defined in the Revolver.

Derivative Instruments and Hedging Activities
Derivative Instruments and Hedging Activities

6. 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, 2017: 

Hedging Positions

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2017

 

 

    

 

    

 

 

    

 

 

    

Weighted

    

Final

 

 

 

 

 

Low

 

High

 

Average

 

Expiration

 

Oil swaps

 

Exercise price

 

$

49.70

 

$

54.18

 

$

50.64

 

December 2020

 

 

 

Net barrels per month

 

 

55,000

 

 

216,000

 

 

112,333

 

 

 

Natural gas swaps

 

Exercise price

 

$

2.76

 

$

3.10

 

$

2.89

 

December 2020

 

 

 

Net MMbtu per month

 

 

700,000

 

 

1,890,000

 

 

1,118,889

 

 

 

Natural gas liquids swaps

 

Exercise price

 

$

22.89

 

$

45.26

 

$

29.79

 

December 2018

 

 

 

Barrels per month

 

 

130,000

 

 

145,000

 

 

138,750

 

 

 

Natural gas basis swaps

 

Exercise price

 

$

(0.50)

 

$

(0.30)

 

$

(0.41)

 

October 2018

 

 

 

Net MMbtu per month

 

 

800,000

 

 

800,000

 

 

800,000

 

 

 

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 barrels per month

 

 

950,000

 

 

1,050,000

 

 

990,833

 

 

 

 

 

The Company recognized net losses on derivative instruments of $18.0 million and $51.3 million for the years ended December 31, 2017 and 2016, respectively. The Company recognized net gains on derivative instruments of $158.8 million for the year ended December 31, 2015.

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, respectively, 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, 2017, 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, 2017 and 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    

 

 

    

 

 

    

Net Amounts

    

 

 

    

 

 

 

 

 

 

 

 

Gross

 

of Assets /

 

Gross Amounts

 

 

 

 

 

 

Gross Amounts

 

Amounts

 

Liabilities

 

Not

 

 

 

 

 

 

of Recognized

 

Offset in the

 

Presented in

 

Offset in the

 

 

 

 

 

 

Assets /

 

Balance

 

the Balance

 

Balance

 

 

 

 

(in thousands of dollars)

 

Liabilities

 

Sheet

 

Sheet

 

Sheet

 

Net Amount

 

December 31, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivative contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets

 

$

8,572

 

$

(4,926)

 

$

3,646

 

$

 —

 

$

3,646

 

Liabilities

 

 

(50,423)

 

 

4,926

 

 

(45,497)

 

 

 —

 

 

(45,497)

 

December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivative contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets

 

$

79,649

 

$

(20,805)

 

$

58,844

 

$

 —

 

$

58,844

 

Liabilities

 

 

(36,664)

 

 

20,805

 

 

(15,859)

 

 

 —

 

 

(15,859)

 

 

Fair Value Measurement
Fair Value Measurement

7. Fair Value Measurement

Fair Value of Financial Instruments

The Company determines fair value amounts using available market information and appropriate valuation methodologies. Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.

The Company enters into a variety of derivative financial instruments, which may include over-the-counter instruments, such as natural gas, crude oil, and natural gas liquid contracts. The Company utilizes valuation techniques that maximize the use of observable inputs, where available. If listed market prices or quotes are not published, fair value is determined based upon a market quote, adjusted by other market-based or independently sourced market data, such as trading volume, historical commodity volatility, and counterparty-specific considerations. These adjustments may include amounts to reflect counterparty credit quality, the time value of money, and the liquidity of the market.

Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have low default rates and equal credit quality. Therefore, an adjustment may be necessary to reflect the quality of a specific counterparty to determine the fair value of the instrument. The Company currently has all derivative positions placed and held by members of its lending group, which have high credit quality.

Liquidity valuation adjustments are necessary when the Company is not able to observe a recent market price for financial instruments that trade in less active markets. Exchange traded contracts are valued at market value without making any additional valuation adjustments; therefore, no liquidity reserve is applied.

Valuation Hierarchy

Fair value measurements are grouped into a three-level valuation hierarchy. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. A financial instrument’s categorization within the hierarchy is based upon the input that requires the highest degree of judgment in the determination of the instrument’s fair value. The three levels are defined as follows:

Level 1

    

Pricing inputs are based on published prices in active markets for identical assets or liabilities as of the reporting date.

Level 2

 

Pricing inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, as of the reporting date. Contracts that are not traded on a recognized exchange or are tied to pricing transactions for which forward curve pricing is readily available are classified as Level 2 instruments. These include natural gas, crude oil and some natural gas liquids price swaps and natural gas basis swaps.

Level 3

 

Pricing inputs include significant inputs that are generally unobservable from objective sources. The Company classifies natural gas liquid swaps and basis swaps for which future pricing is not readily available as Level 3. The Company obtains estimates from independent third parties for its open positions and subjects those to the credit adjustment criteria described above.

 

The financial instruments carried at fair value as of December 31, 2017 and 2016, by consolidated balance sheet caption and by valuation hierarchy, as described above are as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(in thousands of dollars)

 

December 31, 2017

 

 

 

Fair Value Measurements Using

 

Commodity Price Hedges

    

(Level 1)

    

   (Level 2)   

    

  (Level 3)  

    

  Total  

 

Current assets

 

$

 —

 

$

3,474

 

$

 —

 

$

3,474

 

Long-term assets

 

 

 —

 

 

56

 

 

116

 

 

172

 

Current liabilities

 

 

 —

 

 

28,946

 

 

7,763

 

 

36,709

 

Long-term liabilities

 

 

 —

 

 

7,860

 

 

928

 

 

8,788

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(in thousands of dollars)

 

December 31, 2016

 

 

 

Fair Value Measurements Using

 

Commodity Price Hedges

    

(Level 1)

    

(Level 2)

    

(Level 3)

    

Total

 

Current assets

 

$

 —

 

$

24,100

 

$

 —

 

$

24,100

 

Long-term assets (1)

 

 

 —

 

 

36,384

 

 

(1,640)

 

 

34,744

 

Current liabilities

 

 

 —

 

 

13,636

 

 

1,014

 

 

14,650

 

Long-term liabilities

 

 

 —

 

 

892

 

 

317

 

 

1,209

 


(1)

Level 3 long-term assets are negative as a result of the netting of our commodity derivatives reflected on our Consolidated Balance Sheet as of December 31, 2016. Our agreements include set-off provisions, as noted in Note 6, “Derivative Instruments and Hedging Activities - Offsetting Assets and Liabilities”.

 

The following table represents quantitative information about Level 3 inputs used in the fair value measurement of the Company’s commodity derivative contracts as of December 31, 2017.

 

 

 

 

 

 

 

 

 

 

 

 

 

Quantitative Information About Level 3 Fair Value Measurements

 

 

    

Fair Value

    

 

    

Unobservable

    

 

 

Commodity Price Hedges

 

(000’s)

 

Valuation Technique

 

Input

 

Range

 

Natural gas liquid swaps

 

$

(7,763)

 

Use a discounted cash flow approach using inputs including forward price statements from counterparties

 

Natural gas liquid futures

 

$27.93 - $44.00 per barrel

 

Crude oil collars

 

$

(654)

 

Use a discounted option model approach using inputs including interpolated volatilities for certain settlement months where market volatility quotes were unavailable for the option strike price

 

Market volatility quotes at the option strike for certain settlement months in 2019

 

$45.00 - $61.00 per barrel

 

Natural gas collars

 

$

(158)

 

Use a discounted option model approach using inputs including interpolated volatilities for certain settlement months where market volatility quotes were unavailable for the option strike price

 

Market volatility quotes at the option strike for certain settlement months in 2019

 

$2.55 - $3.41 per barrel

 

 

Significant increases/decreases in natural gas liquid prices in isolation would result in a significantly lower/higher fair value measurement. The following table presents the changes in the Level 3 financial instruments for the years ended December 31, 2017 and 2016. Changes in fair value of Level 3 instruments represent changes in gains and losses for the periods that are reported in other income (expense). New contracts entered into during the year are generally entered into at no cost with changes in fair value from the date of agreement representing the entire fair value of the instrument. Transfers between levels are evaluated at the end of the reporting period.

The following table summarizes the Company’s commodity derivative contract activity involving Level 3 instruments, by year, is as follows:

 

 

 

 

 

(in thousands of dollars)

    

 

 

 

Balance at December 31, 2015, net

 

$

1,428

 

Purchases

 

 

(5,208)

 

Settlements

 

 

(171)

 

Transfers to Level 2

 

 

 —

 

Transfers to Level 3

 

 

2,363

 

Changes in fair value

 

 

(1,383)

 

Balance at December 31, 2016, net

 

$

(2,971)

 

Purchases

 

 

(1,236)

 

Settlements

 

 

1,606

 

Transfers to Level 2

 

 

 —

 

Transfers to Level 3

 

 

(6,527)

 

Changes in fair value

 

 

553

 

Balance at December 31, 2017, net

 

$

(8,575)

 

 

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated financial statements:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2017

 

December 31, 2016

 

 

 

Principal

 

 

 

 

Principal

 

 

 

 

(in thousands of dollars)

    

Amount

    

Fair Value

    

Amount

    

Fair Value

 

Debt:

 

   

 

 

   

 

 

   

 

 

   

 

 

Revolver

 

$

211,000

 

$

211,000

 

$

178,000

 

$

178,000

 

2022 Notes

 

 

409,148

 

 

305,404

 

 

409,148

 

 

393,150

 

2023 Notes

 

 

150,000

 

 

114,750

 

 

150,000

 

 

153,375

 

 

The Revolver (as defined in Note 5) is categorized as Level 3 in the valuation hierarchy as the debt is not publicly traded and no observable market exists to determine the fair value; however, the carrying value of the Revolver approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to the Company for those periods.

The fair value of the 2022 Notes (as defined in Note 5) is based on pricing that is readily available in the public market. Accordingly, the 2022 Notes are classified as Level 1 in the valuation hierarchy as the pricing is based on quoted market prices for the debt securities and is actively traded.

The fair value of the 2023 Notes (as defined in Note 5) is based on indicative pricing that is available in the public market. Accordingly, the 2023 Notes are classified as Level 2 in the valuation hierarchy as the pricing is based on quoted market prices for the debt securities but is not actively traded.

Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of the Company’s AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Company’s ARO represent a nonrecurring Level 3 measurement.

Asset Retirement Obligations
Asset Retirement Obligations

8. Asset Retirement Obligations

A summary of the Company’s ARO for the years ended December 31, 2017 and 2016 is as follows:

 

 

 

 

 

 

 

 

(in thousands of dollars)

    

2017

    

2016

 

ARO liability at beginning of year

 

$

20,058

 

$

20,980

 

Liabilities incurred (1)

 

 

1,062

 

 

6,947

 

Accretion of ARO liability

 

 

960

 

 

1,263

 

Liabilities settled due to sale of related properties

 

 

(1,231)

 

 

(446)

 

Liabilities settled due to plugging and abandonment

 

 

(339)

 

 

(463)

 

Change in estimate (2)

 

 

(138)

 

 

(8,223)

 

ARO liability at end of year

 

 

20,372

 

 

20,058

 

Less: Current portion of ARO at end of year

 

 

(720)

 

 

(600)

 

Total long-term ARO at end of year

 

$

19,652

 

$

19,458

 


(1)    The 2016 amount includes $6.4 million related to wells acquired in the Anadarko Acquisition. See Note 3,   “Acquisitions and Divestitures—Anadarko Acquisition”.

(2)    The 2016 amount reflects a reduction in the estimated cost per well, consistent with the decline in actual costs experienced by the Company.

Stock-based Compensation
Stock-based Compensation

9. Stock‑based Compensation

Management Unit Awards

Effective January 1, 2010, JEH implemented a management incentive plan that provided indirect awards of membership interests in JEH to members of senior management (“Management Units”). These awards had various vesting schedules, and a portion of the Management Units vested in a lump sum at the IPO date. In connection with the IPO, both the vested and unvested Management Units were converted into the right to receive JEH Units and shares of Class B common stock. The JEH Units (together with a corresponding number of shares of Class B common stock) will become exchangeable under this plan into a like number of shares of Class A common stock upon vesting or forfeiture. No new Management Units have been awarded since the IPO and no new JEH Units or shares of Class B common stock are created upon a vesting event. Grants listed below reflect the transfer of JEH Units that occurred upon forfeiture.

The following table summarizes information related to the vesting of Management Units as of December 31, 2017:

 

 

 

 

 

 

 

 

    

 

    

Weighted Average

 

 

 

 

 

Grant Date Fair Value

 

 

 

JEH Units

 

per Share

 

Unvested at December 31, 2016

 

90,762

 

$

15.00

 

Granted

 

13,066

 

 

15.00

 

Forfeited

 

(13,066)

 

 

15.00

 

Vested

 

(58,447)

 

 

15.00

 

Unvested at December 31, 2017

 

32,315

 

$

15.00

 

 

Stock compensation expense associated with the Management Units for the years ended December 31, 2017, 2016 and 2015 was $0.6 million, $1.2 million, and $1.3 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. The weighted average grant date fair value of management units was $15.00 per share for the years ended December 31, 2017 and 2016. Unrecognized expense as of December 31, 2017 for all outstanding management units was $0.1 million and will be recognized over a weighted-average remaining period of 0.3 years.

2013 Omnibus Incentive Plan

Under the Amended and Restated Jones Energy, Inc. 2013 Omnibus Incentive Plan (the “LTIP”), established in conjunction with the Company’s IPO and restated on May 4, 2016 following approval by the Company’s stockholders, the Company has reserved a total of 8,340,211 shares of Class A common stock for non-employee director, consultant, and employee stock-based compensation awards, as adjusted for the effects of the Special Stock Dividend and the preferred stock dividends paid in shares, as described in Note 12 “Stockholders’ and Mezzanine equity”.

The Company granted (i) performance share unit and restricted stock unit awards to certain officers and employees and (ii) restricted shares of Class A common stock to the Company’s non-employee directors under the LTIP during 2015, 2016 and 2017. During 2016 and 2017, the Company also granted performance unit awards to certain members of the senior management team under the LTIP.

All share and earnings per share information presented for awards made under the LTIP has been recast to retrospectively adjust for the effects of the 0.087423 per share Special Stock Dividend, as defined in Note 12, “Stockholders’ and Mezzanine equity”, distributed on March 31, 2017.

Restricted Stock Unit Awards

The Company has outstanding restricted stock unit awards granted to certain officers and employees of the Company under the LTIP. The fair value of the restricted stock unit awards is based on the value of the Company’s Class A common stock on the date of grant and is expensed on a straight-line basis over the applicable vesting period, which is typically three years.

The following table summarizes information related to the total number of units awarded to officers and employees as of December 31, 2017:

 

 

 

 

 

 

 

 

    

Restricted

    

Weighted Average

 

 

 

Stock Unit

 

Grant Date Fair Value

 

 

 

Awards

 

per Share

 

Unvested at December 31, 2016

 

1,359,142

 

$

5.60

 

Adjustment (1)

 

130,871

 

 

 —

 

Granted

 

2,394,290

 

 

2.32

 

Forfeited

 

(543,803)

 

 

3.00

 

Vested

 

(577,729)

 

 

6.62

 

Unvested at December 31, 2017

 

2,762,771

 

$

2.79

 


(1)  Increase of 0.002195 units for each unvested restricted stock unit awards at the time of the Company’s May 15, 2017 preferred stock dividend for the portion of such dividend paid in shares of the Company’s Class A common stock and of 0.021931 units for each unvested restricted stock unit award at the time of the Company’s August 15, 2017 preferred stock dividend paid entirely in shares of the Company’s Class A common stock and of 0.018867 units for each unvested restricted stock unit award at the time of the Company’s November 15, 2017 preferred stock dividend paid entirely in shares of the Company’s Class A common stock, as described in Note 12 “Stockholders’ and Mezzanine equity,” in accordance with the terms of the original awards. This increase is in addition to the adjustment for the effects of the Special Stock Dividend previously disclosed in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017.

 

Stock compensation expense associated with the employee restricted stock unit awards for the years ended December 31, 2017, 2016, and 2015 was $3.8 million, $3.0 million, and $3.1 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. The weighted average grant date fair value of restricted stock units was $2.32 per share, $3.67 per share, and $8.81 per share for the years ended December 31, 2017, 2016, and 2015, respectively.

Unrecognized expense as of December 31, 2017 for all outstanding restricted stock unit awards was $5.3 million and will be recognized over a weighted-average remaining period of 2.0 years.

Performance Share Unit Awards

The Company has outstanding performance share unit awards granted to certain members of the senior management team of the Company under the LTIP. Prior to the second quarter of 2016, the performance share unit awards were described in the Company’s filings as performance unit awards. During the second quarter of 2016, the Company created a new class of equity award, described below as a performance unit award, that is settled in cash rather than shares of the Company’s Class A common stock. As a result, references to performance unit awards in the Company’s filings prior to the second quarter of 2016 refer to this description of performance share unit awards.  

Upon the completion of the applicable three-year performance period, each recipient may vest in a number of performance share units. The percent of awarded performance share units in which each recipient vests at such time, if any, will range from 0% to 200% based on the Company’s total shareholder return relative to an industry peer group over the applicable three-year performance period. Each vested performance share unit is exchangeable for one share of the Company’s Class A common stock. The grant date fair value of the performance share units was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance share units earned. The fair value of the performance share units is expensed on a straight-line basis over the applicable three-year performance period.

The following table summarizes information related to the total number of performance share units awarded to the senior management team as of December 31, 2017:

 

 

 

 

 

 

 

 

    

Performance

    

Weighted Average

 

 

 

Share Unit

 

Grant Date Fair Value

 

 

 

Awards

 

per Share

 

Unvested at December 31, 2016

 

942,073

 

$

6.25

 

Adjustment (1)

 

63,712

 

 

 —

 

Granted

 

519,562

 

 

2.24

 

Forfeited

 

(274,524)

 

 

5.29

 

Vested

 

(293,645)

 

 

8.22

 

Unvested at December 31, 2017

 

957,178

 

$

4.64

 


(1)  Increase of 0.002195 units for each unvested performance share unit awards at the time of the Company’s May 15, 2017 preferred stock dividend for the portion of such dividend paid in shares of the Company’s Class A common stock and of 0.021931 units for each unvested performance share unit award at the time of the Company’s August 15, 2017 preferred stock dividend paid entirely in shares of the Company’s Class A common stock and of 0.018867 units for each unvested performance share unit award at the time of the Company’s November 15, 2017 preferred stock dividend paid entirely in shares of the Company’s Class A common stock, as described in Note 12 “Stockholders’ and Mezzanine equity,” in accordance with the terms of the original awards. This increase is in addition to the adjustment for the effects of the Special Stock Dividend previously disclosed in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017.

 

At the time the performance share units vest, the results of the the Company’s total share return relative to the industry peer group must be certified by the compensation committee of the board of directors before the corresponding shares of Class A common stock are issued. As of December 31, 2017 the 293,645 performance share units that vested during 2017 were awaiting certification by the compensation committee. The Class A shares corresponding to these uncertified awards are not included in the Company’s total outstanding Class A shares reported within stockholder’s equity on the Company’s Consolidated Balance Sheets. The estimated fair value of performance share units vested during the year ended December 31, 2017 was $0.2 million, which will be distributed to recipients during the first quarter of 2018. The fair value of performance share units vested during the year ended December 31, 2016 was $0.8 million, the shares of which were distributed to recipients during the first quarter of 2017. No performance share units vested during the year ended December 31, 2015.

Stock compensation expense associated with the performance share unit awards for the years ended December 31, 2017, 2016, and 2015 was $1.5 million, $2.7 million, and $2.6 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. The weighted average grant date fair value of performance share unit awards was $2.24 per share, $4.37 per share, and $9.51 per share for the years ended December 31, 2017, 2016, and 2015, respectively. Unrecognized expense as of December 31, 2017 for all outstanding performance share unit awards was $1.5 million and will be recognized over a weighted-average remaining period of 1.5 years.

The Monte Carlo simulation process is a generally accepted statistical technique used, in this instance, to simulate future stock prices for the Company and the components of the peer group. The simulation uses a risk- neutral framework along with the risk-free rate of return, the volatility of each entity, and the stock price trading correlations of each entity with the other entities in the peer group. A stock price path has been simulated for the Company and the industry peer group and is used to determine the payout percentages and the stock price of the Company’s common stock as of the vesting date. The ending stock price is multiplied by the payout percentage to determine the projected payout, which is then discounted using the risk-free rate of return to the grant date to determine the grant date fair value for that simulation. When enough simulations are generated, the resulting distribution gives a reasonable estimate of the range of future expected stock prices.

The following assumptions were used for the Monte Carlo simulation model to determine the grant date fair value and associated stock-based compensation expense during the periods presented:

 

 

 

 

 

 

 

 

 

 

 

 

 

Performance Share Unit Awards

 

 

 

2017

 

2016

 

2015

 

Forecast period (years)

 

 

2.71

    

 

2.60

    

 

2.67

    

Risk-free interest rate

 

 

1.34

%  

 

1.00

%  

 

0.79

%  

Jones stock price volatility

 

 

78.93

%  

 

71.47

%  

 

52.87

%  

 

The average historical combined volatilities for the Company and the peer group was 39.97%,  70.45%, and 55.13% for the awards made in 2017, 2016, and 2015, respectively. Based on these assumptions, the Monte Carlo simulation model resulted in an expected percentage of performance share units earned of 97.25%, 123.84%, and 101.61% for the 2017, 2016, and 2015 awards, respectively.

Performance Unit Awards

 

The Company has outstanding performance unit awards, granted initially in 2016, to certain members of the senior management team of the Company under the LTIP. References to performance unit awards in prior filings do not correspond to these newly created performance unit awards. Upon the completion of the applicable three-year performance period, each recipient may vest in a number of performance units. The value of awarded performance units in which each recipient vests at such time, if any, will range from $0.00 to $200.00 per performance unit based on the Company’s total shareholder return relative to an industry peer group over the applicable three-year performance period. For accounting purposes, the performance units are treated as a liability award with the liability being re-measured at the end of each reporting period. Therefore, the expense associated with these awards is subject to volatility until the payout is finally determined at the end of the performance period. The value of the performance units was determined at award using a Monte Carlo simulation model, as of the grant date, which resulted in an estimated final value upon vesting of $0.3 million and $1.1 million for the awards made in 2017 and 2016, respectively, as adjusted for forfeitures. The fair value measured as of December 31, 2017 was $0.1 million and $0.1 million for the awards made in 2017 and 2016, respectively.

 

The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated stock-based compensation expense of the performance unit awards granted during the periods presented:

 

 

 

 

 

 

 

 

Performance Unit Awards

 

2017

 

2016

Forecast period (years)

 

2.71

 

2.60

    

Risk-free interest rate