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Table of Contents

 

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 


 

FORM 10-Q

 

(Mark One)

 

x      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the Quarterly Period Ended June 30, 2015

 

or

 

o         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

Commission file number 001-36006

 

Jones Energy, Inc.

(Exact name of registrant as specified in its charter)

 

Delaware

 

1311

 

80-0907968

(State or other Jurisdiction of

 

(Primary Standard Industrial

 

(IRS Employer

Incorporation or Organization)

 

Classification Code Number)

 

Identification Number)

 

807 Las Cimas Parkway, Suite 350
Austin, Texas 78746
(512) 328-2953
(Address, including zip code, and telephone number, including area code, of Registrant’s principal executive offices)

 

Robert J. Brooks

807 Las Cimas Parkway, Suite 350
Austin, Texas 78746
(512) 328-2953

(Address, including zip code, and telephone number, including area code, of Agent for service)

 


 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  x    No  o

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  x    No  o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer o

 

Accelerated filer x

 

 

 

Non-accelerated filer o

 

Smaller reporting company o

(Do not check if a smaller reporting company)

 

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  o  No  x

 


 

On July 31, 2015, the Registrant had 30,508,676 shares of Class A common stock outstanding and 31,283,607 shares of Class B common stock outstanding.

 

 

 



Table of Contents

 

JONES ENERGY, INC.

TABLE OF CONTENTS

 

PART 1—FINANCIAL INFORMATION

1

 

 

Item 1. Financial Statements

1

 

 

Unaudited Consolidated Financial Statements

 

 

 

Balance Sheets

1

 

 

Statements of Operations

2

 

 

Statement of Changes in Stockholders’ Equity

3

 

 

Statements of Cash Flows

4

 

 

Notes to the Consolidated Financial Statements

5

 

 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

27

 

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

34

 

 

Item 4. Controls and Procedures

35

 

 

PART II—OTHER INFORMATION

36

 

 

Item 1. Legal Proceedings

36

 

 

Item 1A. Risk Factors

36

 

 

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

36

 

 

Item 3. Defaults Upon Senior Securities

36

 

 

Item 4. Mine Safety Disclosures

36

 

 

Item 5. Other Information

36

 

 

Item 6. Exhibits

36

 

 

SIGNATURES

37

 

i



Table of Contents

 

PART 1—FINANCIAL INFORMATION

 

Item 1. Financial Statements

 

Jones Energy, Inc.

Consolidated Balance Sheets (Unaudited)

 

 

 

June 30,

 

December 31,

 

(in thousands of dollars)

 

2015

 

2014

 

Assets

 

 

 

 

 

Current assets

 

 

 

 

 

Cash

 

$

22,875

 

$

13,566

 

Restricted cash

 

272

 

149

 

Accounts receivable, net

 

 

 

 

 

Oil and gas sales

 

31,025

 

51,482

 

Joint interest owners

 

16,413

 

41,761

 

Other

 

10,681

 

12,512

 

Commodity derivative assets

 

90,448

 

121,519

 

Other current assets

 

2,227

 

3,374

 

Total current assets

 

173,941

 

244,363

 

Oil and gas properties, net, at cost under the successful efforts method

 

1,665,153

 

1,638,860

 

Other property, plant and equipment, net

 

3,827

 

4,048

 

Commodity derivative assets

 

70,979

 

87,055

 

Other assets

 

20,001

 

20,352

 

Deferred tax assets

 

2,554

 

171

 

Total assets

 

$

1,936,455

 

$

1,994,849

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

Current liabilities

 

 

 

 

 

Trade accounts payable

 

$

41,999

 

$

136,337

 

Oil and gas sales payable

 

47,251

 

70,469

 

Accrued liabilities

 

29,027

 

19,401

 

Deferred tax liabilities

 

434

 

718

 

Asset retirement obligations

 

3,246

 

3,074

 

Total current liabilities

 

121,957

 

229,999

 

Long-term debt

 

100,000

 

360,000

 

Senior notes

 

737,066

 

500,000

 

Deferred revenue

 

12,349

 

13,377

 

Commodity derivative liabilities

 

370

 

28

 

Asset retirement obligations

 

11,706

 

10,536

 

Liability under tax receivable agreement

 

39,873

 

803

 

Deferred tax liabilities

 

15,451

 

26,756

 

Total liabilities

 

1,038,772

 

1,141,499

 

Commitments and contingencies (Note 8)

 

 

 

 

 

Stockholders’ equity

 

 

 

 

 

Class A common stock, $0.001 par value; 30,458,790 shares issued and 30,436,188 shares outstanding at June 30, 2015 and 12,672,260 shares issued and 12,649,658 shares outstanding at December 31, 2014

 

31

 

13

 

Class B common stock, $0.001 par value; 31,288,715 shares issued and outstanding at June 30, 2015 and 36,719,499 shares issued and outstanding at December 31, 2014

 

31

 

37

 

Treasury stock, at cost: 22,602 shares at June 30, 2015 and December 31, 2014

 

(358

)

(358

)

Additional paid-in-capital

 

360,697

 

178,763

 

Retained earnings

 

22,695

 

38,950

 

Stockholders’ equity

 

383,096

 

217,405

 

Non-controlling interest

 

514,587

 

635,945

 

Total stockholders’ equity

 

897,683

 

853,350

 

Total liabilities and stockholders’ equity

 

$

1,936,455

 

$

1,994,849

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

1



Table of Contents

 

Jones Energy, Inc.

Consolidated Statements of Operations (Unaudited)

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

(in thousands of dollars except per share data)

 

2015

 

(Restated)
2014

 

2015

 

(Restated)
2014

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

 

 

 

 

 

 

 

 

Oil and gas sales

 

$

53,222

 

$

105,796

 

$

110,456

 

$

203,663

 

Other revenues

 

695

 

594

 

1,557

 

971

 

Total operating revenues

 

53,917

 

106,390

 

112,013

 

204,634

 

Operating costs and expenses

 

 

 

 

 

 

 

 

 

Lease operating

 

11,796

 

10,779

 

24,058

 

19,123

 

Production and ad valorem taxes

 

3,071

 

6,772

 

6,779

 

13,204

 

Exploration

 

464

 

191

 

628

 

3,012

 

Depletion, depreciation and amortization

 

51,302

 

45,799

 

103,385

 

86,999

 

Accretion of ARO liability

 

206

 

197

 

400

 

367

 

General and administrative

 

9,433

 

6,538

 

17,944

 

11,798

 

Other operating

 

1,176

 

 

4,188

 

 

Total operating expenses

 

77,448

 

70,276

 

157,382

 

134,503

 

Operating income (loss)

 

(23,531

)

36,114

 

(45,369

)

70,131

 

Other income (expense)

 

 

 

 

 

 

 

 

 

Interest expense

 

(16,702

)

(14,767

)

(30,831

)

(22,810

)

Net gain (loss) on commodity derivatives

 

(25,075

)

(33,698

)

21,231

 

(50,948

)

Other income (expense)

 

675

 

2

 

(1,624

)

67

 

Other income (expense), net

 

(41,102

)

(48,463

)

(11,224

)

(73,691

)

Income (loss) before income tax

 

(64,633

)

(12,349

)

(56,593

)

(3,560

)

 

 

 

 

 

 

 

 

 

 

Income tax provision (benefit)

 

(13,453

)

(895

)

(11,109

)

186

 

Net income (loss)

 

(51,180

)

(11,454

)

(45,484

)

(3,746

)

Net income (loss) attributable to non-controlling interests

 

(32,737

)

(9,397

)

(29,229

)

(3,058

)

Net income (loss) attributable to controlling interests

 

$

(18,443

)

$

(2,057

)

$

(16,255

)

$

(688

)

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per share:

 

 

 

 

 

 

 

 

 

Basic

 

$

(0.66

)

$

(0.16

)

$

(0.70

)

$

(0.05

)

Diluted

 

$

(0.66

)

$

(0.16

)

$

(0.70

)

$

(0.05

)

Weighted average shares outstanding:

 

 

 

 

 

 

 

 

 

Basic

 

27,904

 

12,500

 

23,131

 

12,500

 

Diluted

 

27,904

 

12,500

 

23,131

 

12,500

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

2



Table of Contents

 

Jones Energy, Inc.

Consolidated Statement of Changes In Stockholders’ Equity (Unaudited)

 

 

 

Common Stock

 

Treasury
Stock

 

Additional

 

Retained

 

 

 

Total

 

 

 

Class A

 

Class B

 

Class A

 

Paid-in

 

(Deficit)/

 

Non-controlling

 

Stockholders’

 

(amounts in thousands)

 

Shares

 

Value

 

Shares

 

Value

 

Shares

 

Value

 

Capital

 

Earnings

 

Interest

 

Equity

 

Balance at December 31, 2014

 

12,622

 

$

13

 

36,719

 

$

37

 

23

 

$

(358

)

$

178,763

 

$

38,950

 

$

635,945

 

$

853,350

 

Sale of common stock

 

12,263

 

12

 

 

 

 

 

123,189

 

 

 

123,201

 

Exchange of Class B shares for Class A shares

 

5,431

 

6

 

(5,431

)

(6

)

 

 

55,497

 

 

(92,129

)

(36,632

)

Stock-compensation expense

 

 

 

 

 

 

 

3,248

 

 

 

3,248

 

Vested restricted shares

 

94

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

 

 

 

 

 

 

 

(16,255

)

(29,229

)

(45,484

)

Balance at June 30, 2015

 

30,410

 

$

31

 

31,288

 

$

31

 

23

 

$

(358

)

$

360,697

 

$

22,695

 

$

514,587

 

$

897,683

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

3



Table of Contents

 

Jones Energy, Inc.

Consolidated Statements of Cash Flows (Unaudited)

 

 

 

Six Months Ended June 30,

 

(in thousands of dollars)

 

2015

 

(Restated)
2014

 

 

 

 

 

 

 

Cash flows from operating activities

 

 

 

 

 

Net income (loss)

 

$

(45,484

)

$

(3,746

)

Adjustments to reconcile net income (loss) to net cash provided by operating activities

 

 

 

 

 

Depletion, depreciation, and amortization

 

103,385

 

86,999

 

Accretion of ARO liability

 

400

 

367

 

Amortization of debt issuance costs

 

2,159

 

5,282

 

Stock compensation expense

 

3,248

 

1,386

 

Other non-cash compensation expense

 

218

 

253

 

Amortization of deferred revenue

 

(1,028

)

(526

)

(Gain) loss on commodity derivatives

 

(21,231

)

50,948

 

(Gain) loss on sales of assets

 

6

 

(67

)

Deferred income tax provision

 

(11,109

)

(355

)

Other - net

 

760

 

3,023

 

Changes in assets and liabilities

 

 

 

 

 

Accounts receivable

 

47,947

 

(13,365

)

Other assets

 

1,118

 

(85

)

Accrued interest expense

 

8,368

 

7,612

 

Accounts payable and accrued liabilities

 

(15,713

)

17,581

 

Net cash provided by operations

 

73,044

 

155,307

 

 

 

 

 

 

 

Cash flows from investing activities

 

 

 

 

 

Additions to oil and gas properties

 

(229,060

)

(229,582

)

Net adjustments to purchase price of properties acquired

 

 

13,681

 

Proceeds from sales of assets

 

21

 

67

 

Acquisition of other property, plant and equipment

 

(382

)

(639

)

Current period settlements of matured derivative contracts

 

67,646

 

(11,255

)

Change in restricted cash

 

(123

)

(52

)

Net cash used in investing

 

(161,898

)

(227,780

)

 

 

 

 

 

 

Cash flows from financing activities

 

 

 

 

 

Proceeds from issuance of long-term debt

 

75,000

 

60,000

 

Repayment under long-term debt

 

(335,000

)

(468,000

)

Proceeds from senior notes

 

236,475

 

500,000

 

Purchases of treasury stock

 

 

(352

)

Payment of debt issuance costs

 

(1,513

)

(11,204

)

Proceeds from sale of common stock

 

123,201

 

 

Net cash provided by financing

 

98,163

 

80,444

 

Net increase in cash

 

9,309

 

7,971

 

 

 

 

 

 

 

Cash

 

 

 

 

 

Beginning of period

 

13,566

 

23,820

 

End of period

 

$

22,875

 

$

31,791

 

 

 

 

 

 

 

Supplemental disclosure of cash flow information

 

 

 

 

 

Cash paid for interest

 

$

19,517

 

$

9,348

 

Change in accrued additions to oil and gas properties

 

(100,927

)

7,218

 

Current additions to ARO

 

931

 

844

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

4



Table of Contents

 

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

 

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 and through private equity funds managed by Metalmark Capital and Wells Fargo Energy Capital (collectively, the “Pre-IPO owners”). 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 owners of JEH prior to the Company’s initial public offering (“IPO”) and can be exchanged (together with a corresponding number of 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 a result of the IPO and as of July 31, 2015, the Pre-IPO owners had 74.7% and 50.6%, respectively, of the total economic interest in JEH, but with no voting rights or management power over JEH, resulting in the Company reporting this ownership interest as a non-controlling interest.

 

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. The Company’s assets are located within two distinct basins in the Texas Panhandle and Oklahoma, the Anadarko Basin and the Arkoma Basin, and are owned by JEH and its operating subsidiaries. The Company is headquartered in Austin, Texas.

 

Restatement of Previously Issued Financial Statements

 

In conjunction with our 2014 year-end audit and the preparation of our annual Form 10-K, we identified an error in our previously issued 2014 quarterly financial statements which would have been material to such statements if not restated. We recorded the adjustments on a quarterly basis in the prior periods. The Consolidated Statement of Operations for the three and six months ended June 30, 2014 were restated to record $2.6 million and $4.4 million, respectively, of additional depletion, depreciation and amortization expense and net income was reduced by $2.3 million and $4.0 million accordingly. The impact of the restatement to the three and six month periods ended June 30, 2014 are summarized in the table below:

 

 

 

2014 Three Months Ended

 

2014 Six Months Ended

 

 

 

As
Reported

 

As
Restated

 

As
Reported

 

As
Restated

 

(in thousands)

 

Second
Quarter

 

Second
Quarter

 

Second
Quarter

 

Second
Quarter

 

Oil and gas properties

 

$

1,449,765

 

$

1,445,322

 

$

1,449,765

 

$

1,445,322

 

Depletion, depreciation and amortization

 

$

43,211

 

$

45,799

 

$

82,556

 

$

86,999

 

Operating income

 

$

38,702

 

$

36,114

 

$

74,574

 

$

70,131

 

Net income (loss)

 

$

(9,184

)

$

(11,454

)

$

204

 

$

(3,746

)

Net income (loss) attributable to non-controlling interests

 

$

(7,537

)

$

(9,397

)

$

178

 

$

(3,058

)

Net income (loss) attributable to controlling interests

 

$

(1,647

)

$

(2,057

)

$

26

 

$

(688

)

Basic earnings (loss) per share

 

$

(0.13

)

$

(0.16

)

$

0.00

 

$

(0.05

)

Diluted earnings (loss) per share

 

$

(0.13

)

$

(0.16

)

$

0.00

 

$

(0.05

)

 

5



Table of Contents

 

Revision of Previously Issued Financial Statements

 

During the first quarter of 2015, we identified an error in our previously issued financial statements related to the over accrual for production taxes which would have been material to the first quarter and could be material to projected 2015 annual results if recorded as an out of period adjustment in such period. Therefore we will revise our Consolidated Statement of Operations for the year and quarter ended December 31, 2014 in the December 31, 2015 Form 10-K to reduce Production Taxes by $1.6 million and increase Income Tax Provision by $0.1 million related to an accrual for production taxes that was not properly reversed at December 31, 2014. As a result, net income will be increased for the year and quarter ended December 31, 2014 by $1.5 million, resulting in an increase in earnings per share of $0.02. The balance sheet impacts of the revision, which are reflected in this Form 10-Q, are included in the table below. This revision had no impact on our net cash provided by operations in our Consolidated Statement of Cash Flows for the six months ended June 30, 2014. We have determined that this error is not material to the consolidated financial statements of any prior period presented.

 

In addition, we identified an error in our previously issued financial statements related to the exchange of Class B shares for Class A shares. Therefore we revised our Consolidated Balance Sheet and Statement of Changes in Stockholders’ Equity for the year ended December 31, 2014 as noted in the table below. This revision had no impact on Class A or Class B shares outstanding at December 31, 2014. We have determined that this error is not material to the consolidated financial statements of any prior period presented.

 

 

 

December 31,
2014

 

 

 

Exchange
of Class B

 

December 31,
2014

 

 

 

As Reported

 

Production tax

 

shares

 

As Revised

 

Accounts Receivable, Oil and gas sales

 

$

49,861

 

$

1,621

 

 

 

$

51,482

 

Deferred tax liabilities

 

$

26,612

 

$

144

 

 

 

$

26,756

 

Additional paid in capital

 

$

177,133

 

 

 

$

1,630

 

$

178,763

 

Retained earnings

 

$

38,682

 

$

268

 

 

 

$

38,950

 

Non-controlling interest

 

$

636,366

 

$

1,209

 

$

(1,630

)

$

635,945

 

 

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”). All significant intercompany transactions and balances have been eliminated in consolidation. The financial statements reported for June 30, 2015, and the three and six month periods then ended include the Company and all of its subsidiaries.

 

Certain prior period amounts have been reclassified to conform to the current presentation. These reclassifications include the reclassification of ad valorem taxes of $1.6 million and $3.3 million from Lease Operating Expense to Production and Ad Valorem Taxes in the Consolidated Statement of Operations for the three and six months ended June 30, 2014, respectively.

 

These interim financial statements have not been audited. However, in the opinion of management, all adjustments necessary for a fair statement of the financial statements have been included. As these are interim financial statements, they do not include all disclosures required for financial statements prepared in conformity with GAAP. Interim period results are not necessarily indicative of results of operations or cash flows for a full year.

 

These consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Accordingly, they do not include all disclosures required by GAAP and should be read in conjunction with our most recent audited consolidated financial statements included in Jones Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2014.

 

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”).

 

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Table of Contents

 

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 June 30, 2015 and December 31, 2014:

 

 

 

June 30,

 

December 31,

 

(in thousands of dollars)

 

2015

 

2014

 

 

 

 

 

 

 

Mineral interests in properties

 

 

 

 

 

Unproved

 

$

79,089

 

$

94,526

 

Proved

 

1,018,431

 

1,001,194

 

Wells and equipment and related facilities

 

1,221,477

 

1,094,202

 

 

 

2,318,997

 

2,189,922

 

Less: Accumulated depletion and impairment

 

(653,844

)

(551,062

)

Net oil and gas properties

 

$

1,665,153

 

$

1,638,860

 

 

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. During the six months ended June 30, 2015 we had no material capitalized costs associated with exploratory wells.

 

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. The Company did not capitalize any interest during the six months ended June 30, 2015 as no projects lasted more than six months. Depletion of oil and gas properties amounted to $51.0 million and $102.8 million for the three and six months ended June 30, 2015, respectively, and $45.6 million and $86.4 million for the three and six months ended June 30, 2014, respectively.

 

Other Property, Plant and Equipment

 

Other property, plant and equipment consisted of the following at June 30, 2015 and December 31, 2014:

 

 

 

June 30,

 

December 31,

 

(in thousands of dollars)

 

2015

 

2014

 

 

 

 

 

 

 

Leasehold improvements

 

$

1,280

 

$

1,218

 

Furniture, fixtures, computers and software

 

3,796

 

3,727

 

Vehicles

 

1,184

 

988

 

Aircraft

 

910

 

910

 

Other

 

225

 

219

 

 

 

7,395

 

7,062

 

Less: Accumulated depreciation and amortization

 

(3,568

)

(3,014

)

Net other property, plant and equipment

 

$

3,827

 

$

4,048

 

 

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. Depreciation and amortization of other property, plant and equipment amounted to $0.3 million and $0.6 million during the three and six months ended June 30, 2015, respectively, and $0.2 million and $0.6 million during the three and six months ended June 30, 2014, respectively.

 

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 six month periods ended June 30, 2015 and 2014, 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.

 

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Table of Contents

 

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 the Other Income (Expense) caption on the Consolidated Statement of Operations. See Note 3, “Fair Value Measurement,” for disclosure about the fair values of commodity derivative instruments.

 

Asset Retirement Obligations

 

The Company’s asset retirement obligations consist of future plugging and abandonment expenses on oil and natural gas properties.

 

A summary of the Company’s ARO for the six months ended June 30, 2015 is as follows:

 

(in thousands of dollars)

 

 

 

Balance at December 31, 2014

 

$

13,610

 

 

 

 

 

Liabilities incurred

 

931

 

Accretion of ARO liability

 

400

 

Change in estimate

 

11

 

 

 

 

 

Balance at June 30, 2015

 

14,952

 

 

 

 

 

Less: Current portion of ARO

 

(3,246

)

 

 

 

 

Total long-term ARO at June 30, 2015

 

$

11,706

 

 

Tax Receivable Agreement

 

In connection with the IPO, the Company entered into a Tax Receivable Agreement (the “TRA”) which obligates the Company to make payments to certain current and former owners equal to 85% of the applicable cash savings that the Company realizes as a result of tax attributes arising from exchanges of JEH Units and shares of the Company’s Class B common stock held by those owners for shares of the Company’s Class A common stock. The Company will retain the benefit of the remaining 15% of these tax savings.

 

As a result of exchanges made through June 30, 2015, the Company has accrued future tax benefits of $46.9 million and has accounted for this amount as a reduction of deferred tax liabilities on its consolidated balance sheet. As of June 30, 2015, the Company has recorded a liability of $39.9 million associated with its future obligations under the TRA. The actual amount and timing of payments made under the TRA will depend upon a number of factors, including the amount and timing of taxable income generated in the future, changes in future tax rates, the use of loss carryovers, and the portion of the Company’s payments under the TRA constituting imputed interest. To the extent the Company does not realize all of the tax benefits in future years or in the event of a change in future tax rates, this liability may change.

 

As of June 30, 2015, the Company has made no payments under the TRA and does not anticipate making a material payment under the TRA in 2015.

 

Stock Compensation

 

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”). The management unit grants awarded prior to the initial filing of the IPO registration statement in March 2013 had a dual vesting schedule. Grants awarded after the filing of the initial IPO registration statement have a single vesting structure with equal annual installments and were valued at the IPO price, adjusted for equivalent shares. In connection with the IPO, both the vested and unvested management units were converted into the right to receive an indirect interest in JEH Units and shares of Class B common stock.

 

Under the Jones Energy, Inc. 2013 Omnibus Incentive Plan (the “LTIP”), established in conjunction with the Company’s IPO, the Company reserved 3,850,000 shares of Class A common stock for director and employee stock-based compensation awards.

 

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Table of Contents

 

The Company granted performance unit and restricted stock unit awards to certain officers and employees under the LTIP during 2014 and 2015. The fair value of the performance units was based on the grant date fair value (using a Monte Carlo simulation model) and is expensed on a straight-line basis over the applicable three-year performance period. The number of shares of Class A common stock issuable upon vesting of the performance unit awards ranges from zero to 200% based on the Company’s total shareholder return relative to an industry peer group over the applicable three-year performance period. The fair value of the restricted stock unit awards was 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.

 

The Company granted each of the outside members of the Board of Directors shares of restricted Class A common stock under the LTIP in 2014. The fair value of the restricted stock grants was 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.

 

Refer to Note 6, “Stock-based Compensation,” for additional information regarding director and employee stock-based compensation awards.

 

Recent Accounting Pronouncements

 

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers,” which creates a new topic in the ASC, topic 606, “Revenue from Contracts with Customers.” This ASU 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. The amendments are 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. We are currently evaluating the effect that the adoption of this ASU will have on our financial statements.

 

In August 2014, the FASB issued ASU No. 2014-15, “Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.” This ASU requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a “going concern” and to provide disclosures when certain criteria are met. Substantial doubt exists when relevant conditions and events, considered in the aggregate, indicate that it is probable that the entity will be unable to meet its obligations as they become due within one year after the date that the financial statements are issued (or available to be issued). The amendments are effective for interim and annual reporting periods beginning after December 15, 2016. Early adoption is permitted. We do not expect the adoption of these disclosures to have a significant impact on the Company’s consolidated financial statements.

 

In January 2015, the FASB issued ASU No. 2015- 01, Income Statement—Extraordinary and Unusual Items. This ASU removes the concept of extraordinary items from GAAP. Under existing guidance, an entity is required to separately disclose extraordinary items, net of tax, in the income statement after income from continuing operations if an event or transaction is of an unusual nature and occurs infrequently. This separate, net-of-tax presentation will no longer be allowed. The amendments are effective for interim and annual reporting periods beginning after December 15, 2015. The Company does not expect the adoption of this guidance to have a material impact on its financial position, cash flows or results of operations.

 

In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. Entities that have historically presented debt issuance costs as an asset, related to a recognized debt liability, will be required to present those costs as a direct deduction from the carrying amount of that debt liability. The ASU does not change the recognition, measurement, or subsequent measurement guidance for debt issuance costs. Adoption of this ASU will be applied retrospectively. The amendments are effective for interim and annual reporting periods beginning after December 15, 2015. We are currently evaluating the effect that the adoption of this ASU will have on our financial statements.

 

3.                            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.

 

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Table of Contents

 

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. The Company does not classify any of its financial instruments as Level 1.

 

 

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 June 30, 2015 and December 31, 2014, by consolidated balance sheet caption and by valuation hierarchy as described above, are as follows:

 

 

 

June 30, 2015

 

(in thousands of dollars)

 

Fair Value Measurements

 

Commodity Derivative Instruments

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

Total

 

 

 

 

 

 

 

 

 

 

 

Current assets

 

$

 

$

89,864

 

$

584

 

$

90,448

 

Long-term assets

 

 

70,807

 

172

 

70,979

 

Current liabilities

 

 

 

 

 

Long-term liabilities

 

 

(198

)

(172

)

(370

)

 

 

 

December 31, 2014

 

(in thousands of dollars)

 

Fair Value Measurements

 

Commodity Derivative Instruments

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

Total

 

 

 

 

 

 

 

 

 

 

 

Current assets

 

$

 

$

120,604

 

$

915

 

$

121,519

 

Long-term assets

 

 

85,162

 

1,893

 

87,055

 

Current liabilities

 

 

 

 

 

Long-term liabilities

 

 

 

(28

)

(28

)

 

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Table of Contents

 

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 June 30, 2015.

 

(in thousands of dollars)
Commodity Derivative

 

Quantitative Information About Level 3 Fair Value Measurements

 

Instruments

 

Fair Value

 

Valuation Technique

 

Unobservable Input

 

Range

 

 

 

 

 

 

 

 

 

 

 

Natural gas liquid swaps

 

$

723

 

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

 

Natural gas liquid futures prices

 

$8.09 - $71.30
per barrel

 

Natural gas basis swaps

 

$

(139

)

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

 

Forward basis prices

 

$(0.11) – $(0.17)
per MMBtu

 

 

Significant increases/decreases in natural gas liquid futures 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 six months ended June 30, 2015. 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.

 

(in thousands of dollars)

 

 

 

 

 

 

 

Balance at December 31, 2014, net

 

$

2,780

 

Purchases

 

(880

)

Settlements

 

(483

)

Transfers to Level 2

 

(772

)

Transfers to Level 3

 

 

Changes in fair value

 

(61

)

Balance at June 30, 2015, net

 

$

584

 

 

Transfers from Level 3 to Level 2 represent the Company’s natural gas liquid swaps for which observable forward curve pricing information has become readily available.

 

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

 

The following table provides the fair value of financial instruments which may not be recorded at fair value in the consolidated financial statements:

 

 

 

June 30, 2015

 

December 31, 2014

 

(in thousands of dollars)

 

Principal
Amount

 

Fair Value

 

Principal
Amount

 

Fair Value

 

 

 

 

 

 

 

 

 

 

 

Debt:

 

 

 

 

 

 

 

 

 

Revolver

 

$

100,000

 

$

100,000

 

$

360,000

 

$

360,000

 

2022 Notes

 

500,000

 

481,250

 

500,000

 

384,375

 

2023 Notes

 

250,000

 

268,595

 

 

 

 

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.

 

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Table of Contents

 

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.

 

The Company reviews its proved and unproved oil and gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. As such, the fair value of oil and gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. The Company assessed its proved and unproved properties for impairment as of June 30, 2015 and no impairment charges were recorded. However, future price declines, or a period of sustained low commodity prices, could result in a significant impairment charge in future periods. Furthermore, in addition to commodity prices, our production rates, levels of proved reserves, future development costs, and other factors affect our impairment analyses and may lead to an impairment charge in future periods.

 

4.                            Commodity Derivative Instruments

 

The Company had various commodity derivatives in place as of June 30, 2015 and December 31, 2014, as follows:

 

Hedging Positions

 

 

 

June 30, 2015

 

 

 

 

 

 

 

 

 

Weighted

 

Final

 

 

 

 

 

Low

 

High

 

Average

 

Expiration

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil swaps

 

Exercise price

 

$

54.53

 

$

100.89

 

$

80.85

 

 

 

 

 

Barrels per month

 

55,000

 

197,904

 

112,671

 

March 2019

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas swaps

 

Exercise price

 

$

2.82

 

$

6.45

 

$

4.34

 

 

 

 

 

mmbtu per month

 

700,000

 

1,651,666

 

1,112,131

 

March 2019

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis swaps

 

Contract differential

 

$

(0.39

)

$

(0.11

)

$

(0.25

)

 

 

 

 

mmbtu per month

 

320,000

 

760,000

 

611,111

 

March 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas liquids swaps

 

Exercise price

 

$

8.09

 

$

95.24

 

$

34.78

 

 

 

 

 

Barrels per month

 

2,000

 

164,000

 

71,433

 

December 2017

 

 

 

 

December 31, 2014

 

 

 

 

 

 

 

 

 

Weighted

 

Final

 

 

 

 

 

Low

 

High

 

Average

 

Expiration

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil swaps

 

Exercise price

 

$

75.05

 

$

100.95

 

$

84.20

 

 

 

 

 

Barrels per month

 

45,000

 

184,054

 

113,852

 

December 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas swaps

 

Exercise price

 

$

3.37

 

$

6.45

 

$

4.40

 

 

 

 

 

mmbtu per month

 

710,000

 

1,772,584

 

1,175,275

 

December 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis swaps

 

Contract differential

 

$

(0.39

)

$

(0.11

)

$

(0.21

)

 

 

 

 

mmbtu per month

 

320,000

 

980,000

 

716,667

 

March 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas liquids swaps

 

Exercise price

 

$

8.09

 

$

95.24

 

$

42.46

 

 

 

 

 

Barrels per month

 

2,000

 

143,000

 

50,444

 

December 2017

 

 

The Company recognized net losses on derivative instruments of $25.1 million and net gains of $21.2 million for the three and six months ended June 30, 2015, respectively, and net losses on derivative instruments of $33.7 million and $50.9 million for the three and six months ended June 30, 2014.

 

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Table of Contents

 

Offsetting Assets and Liabilities

 

As of June 30, 2015, the counterparties to our commodity derivative contracts consisted of seven financial institutions. All of our counterparties or their affiliates are also lenders under our credit facility. Therefore, 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 which are netted on our Consolidated Balance Sheet as of June 30, 2015 and December 31, 2014:

 

(in thousands)

 

Gross Amounts
of Recognized
Assets /
Liabilities

 

Gross Amounts
Offset in the
Balance Sheet

 

Net Amounts of
Assets / Liabilities
Presented in the
Balance Sheet

 

Gross Amounts
Not Offset in the
Balance Sheet

 

Net Amount

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2015

 

 

 

 

 

 

 

 

 

 

 

Commodity derivative contracts

 

 

 

 

 

 

 

 

 

 

 

Assets

 

$

164,307

 

$

(2,880

)

$

161,427

 

$

 

$

161,427

 

Liabilities

 

(3,250

)

2,880

 

(370

)

 

(370

)

December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

Commodity derivative contracts

 

 

 

 

 

 

 

 

 

 

 

Assets

 

$

208,646

 

$

(72

)

$

208,574

 

$

 

$

208,574

 

Liabilities

 

(100

)

72

 

(28

)

 

(28

)

 

5.                            Long-Term Debt

 

Senior Unsecured Notes

 

Senior notes consisted of the following at June 30, 2015 and December 31, 2014:

 

(in thousands of dollars)

 

June 30,2015

 

December 31, 2014

 

 

 

 

 

 

 

2022 Notes

 

$

500,000

 

$

500,000

 

2023 Notes

 

250,000

 

 

Total principal amount

 

750,000

 

500,000

 

Less: unamortized discount

 

(12,934

)

 

Total carrying amount

 

$

737,066

 

$

500,000

 

 

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 (together 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 all outstanding borrowings under the Term Loan ($160.0 million), a portion of the outstanding borrowings under the Revolver ($308.0 million) and for working capital and general corporate purposes. The Company subsequently terminated the Term Loan in accordance with its terms. 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. As of June 30, 2015, the Company had $8.4 million in interest accrued related to the 2022 Notes. Total interest expense related to the 2022 Notes amounted to $8.4 million and $16.9 million for the three and six months ended June 30, 2015, respectively.

 

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 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. As of June 30, 2015, the Company had $8.1 million in interest accrued related to the 2023 Notes. Total interest expense related to the 2023 Notes amounted to $5.8 million and $8.1 million for the three and six months ended June 30, 2015, respectively.

 

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The 2022 and 2023 Notes are guaranteed on a senior unsecured basis by the Company and by all of its significant subsidiaries. The 2022 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 and 2023 Notes are substantially similar 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. However, many of these covenants will be suspended if the Notes are rated investment grade.

 

Other Long-Term Debt

 

The Company entered into two credit agreements dated December 31, 2009, with Wells Fargo Bank N.A.: the Senior Secured Revolving Credit Facility (the “Revolver”) and the Second Lien Term Loan (the “Term Loan”), each of which have been or were amended periodically. On April 1, 2014, the Term Loan was repaid in full and terminated in connection with the issuance of the 2022 Notes. On November 6, 2014, the Company amended the Revolver to, among other things, increase the borrowing base under the Revolver from $550.0 million to $625.0 million until the next redetermination thereof, and extend the maturity date of the Revolver to November 6, 2019. The Company’s oil and gas properties are pledged as collateral to secure its obligations under the Revolver. The borrowing base on the Revolver was subsequently adjusted to $562.5 million in accordance with its terms as a result of the issuance of the 2023 Notes in February 2015 and was reaffirmed at this level effective April 1, 2015.

 

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 redetermined by the lenders at least semi-annually on or about April 1 and October 1 of each year. 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 1.50% to 2.50% 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 0.50% to 1.50% based on the level of borrowing base utilization at such time. For the three and six months ended June 30, 2015, the average interest rates under the Revolver were 2.35% and 2.43%, respectively, on average outstanding balances of $100.0 million and $185.5 million, respectively. For the three and six months ended June 30, 2014, the average interest rates under the Revolver were 2.24% and 2.67%, respectively, on average outstanding balances of $235.1 million and $372.0 million, respectively.

 

Total interest and commitment fees under the Revolver were $1.0 million and $3.0 million for the three and six months ended June 30, 2015 and $1.3 million and $4.9 million for the three and six months ended June 30, 2014. Total interest and commitment fees under the Term Loan were $3.6 million for the six months ended June 30, 2014. No interest and commitment fees were incurred under the Term Loan for the three months ended June 30, 2014. $3.8 million in unamortized deferred financing costs were written off to interest expense during the three months ended June 30, 2014 in connection with the repayment of the Term Loan.

 

We are subject to certain covenants under the Revolver which include, but are not limited to, restrictions on asset sales, distributions to members, and incurrence of additional indebtedness, and financial covenants which require the maintenance of certain financial ratios, including a maximum leverage ratio, and a minimum current ratio. The Company was in compliance with these covenants at June 30, 2015.

 

6.                            Stock-based Compensation

 

Management Unit Awards

 

Prior to the IPO, JEH granted management units to certain officers and employees under a previously existing management incentive plan. 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. No new JEH Units or shares of Class B common stock are created upon a vesting event. The JEH Units (together with a corresponding number of shares of Class B common stock) will become

 

14



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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. Grants listed below reflect the transfer of JEH units that occurred upon forfeiture.

 

The following table summarizes information related to the vesting of JEH Units as of June 30, 2015:

 

 

 

JEH Units

 

Weighted Average
Grant Date Fair Value
per Share

 

 

 

 

 

 

 

Unvested at January 1, 2015

 

274,385

 

$

15.00

 

Granted

 

1,909

 

15.00

 

Forfeited

 

(1,909

)

15.00

 

Vested

 

(73,837

)

15.00

 

Unvested at June 30, 2015

 

200,548

 

$

15.00

 

 

Stock compensation expense associated with the JEH Units was $0.3 million and $0.6 million for the three and six months ended June 30, 2015, respectively, and $0.4 million and $0.8 million for the three and six months ended June 30, 2014, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

 

The Company has granted Restricted Stock Unit awards and Performance Unit awards to certain employees and Restricted Stock awards to its non-employee directors under its 2013 Omnibus Incentive Plan.

 

Restricted Stock Unit Awards

 

The Company has outstanding restricted stock unit awards granted to certain officers and employees of the Company. The fair value of the restricted stock unit awards was 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.

 

The following table summarizes information related to the total number of units awarded to officers and employees as of June 30, 2015:

 

 

 

Restricted
Stock Unit
Awards

 

Weighted Average
Grant Date Fair Value
per Share

 

 

 

 

 

 

 

Unvested at January 1, 2015

 

324,897

 

$

17.33

 

Granted

 

565,738

 

9.63

 

Forfeited

 

(10,108

)

14.82

 

Vested

 

(93,842

)

17.11

 

Unvested at June 30, 2015

 

786,685

 

$

11.85

 

 

Stock compensation expense associated with the employee restricted stock unit awards was $0.8 million and $1.3 million for the three and six months ended June 30, 2015, respectively, and $0.1 million and $0.2 million for the three and six months ended June 30, 2014, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

 

Performance Unit Awards

 

The Company has outstanding performance unit awards granted to certain officers of the Company. Upon the completion of the applicable three-year performance period, each officer will vest in a number of performance units. The percent of awarded performance units in which each officer vests at such time 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 unit is exchangeable for one share of the Company’s Class A common stock. The grant date fair value of the performance units was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance units earned. The fair value of the performance 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 units awarded to the officers as of June 30, 2015:

 

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Performance
Unit Awards

 

Weighted Average
Grant Date Fair Value
per Share

 

 

 

 

 

 

 

Unvested at January 1, 2015

 

192,998

 

$

21.65

 

Granted

 

361,422

 

10.27

 

Forfeited

 

 

 

Vested

 

 

 

Unvested at June 30, 2015

 

554,420

 

$

14.23

 

 

Stock compensation expense associated with the performance unit awards was $0.6 million and $1.1 million for the three and six months ended June 30, 2015, respectively, and $0.2 million and $0.2 million for the three and six months ended June 30, 2014, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

 

Restricted Stock Awards

 

The Company has outstanding restricted stock awards granted to non-employee members of the Board of Directors. The restricted stock will vest upon the director serving as a director of the Company for a one-year service period in accordance with the terms of the award. The fair value of the awards was based on the price of the Company’s Class A common stock on the date of grant.

 

The following table summarizes information related to the total value of the awards to the officers and employees as of June 30, 2015:

 

 

 

Restricted
Stock Awards

 

Weighted Average
Grant Date Fair Value
per Share

 

 

 

 

 

 

 

Unvested at January 1, 2015

 

27,430

 

$

18.77

 

Granted

 

 

 

Forfeited

 

 

 

Vested

 

 

 

Unvested at June 30, 2015

 

27,430

 

18.77

 

 

Stock compensation expense associated with the Board of Directors awards was $0.3 million and $0.2 million for the three and six months ended June 30, 2015, respectively, and $0.2 million and $0.2 million for the three and six months ended June 30, 2014, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

 

7.                            Earnings (loss) per Share

 

Basic earnings per share (“EPS”) is computed by dividing net income (loss) attributable to controlling interests by the weighted-average number of shares of Class A common stock outstanding during the period. Shares of Class B common stock are not included in the calculation of earnings per share because they are not participating securities and have no economic interest in the Company. Diluted earnings per share takes into account the potential dilutive effect of shares that could be issued by the Company in conjunction with stock awards that have been granted to directors and employees. In accordance with ASC 260, Earnings Per Share, awards of nonvested shares shall be considered outstanding as of the respective grant dates for purposes of computing diluted EPS even though the award is contingent upon vesting. For the three and six months ended June 30, 2015, 786,685 restricted stock units, 27,430 shares of restricted stock, and 554,420 performance units were excluded from the calculation as they would have had an anti-dilutive effect. The following is a calculation of the basic and diluted weighted-average number of shares of Class A common stock outstanding and EPS for the three and six months ended June 30, 2015.

 

 

 

Three Months Ended
June 30, 2015

 

Six Months Ended
June 30, 2015

 

(in thousands, except per share data)

 

2015

 

2014

 

2015

 

2014

 

Income (numerator):

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to controlling interests

 

$

(18,443

)

$

(2,057

)

$

(16,255

)

$

(688

)

 

 

 

 

 

 

 

 

 

 

Weighted-average shares (denominator):

 

 

 

 

 

 

 

 

 

Weighted-average number of shares of Class A common stock - basic

 

27,904

 

12,500

 

23,131

 

12,500

 

Weighted-average number of shares of Class A common stock - diluted

 

27,904

 

12,500

 

23,131

 

12,500

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per share:

 

 

 

 

 

 

 

 

 

Basic

 

$

(0.66

)

$

(0.16

)

$

(0.70

)

$

(0.05

)

Diluted

 

$

(0.66

)

$

(0.16

)

$

(0.70

)

$

(0.05

)

 

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The sum of the first and second quarter earnings (loss) per share amounts differ from the total earnings (loss) per share for the six months ended June 30, 2015 due to the change in weighted-average shares outstanding.

 

8.                            Commitments and Contingencies

 

The Company is subject to legal proceedings and claims that arise in the ordinary course of its business. The Company believes that the final disposition of such matters will not have a material adverse effect on its financial position, results of operations, or liquidity.

 

9.                            Income Taxes

 

Following its IPO, the Company began recording federal and state income tax liabilities associated with its status as a corporation. Prior to the IPO, the Company only recorded a provision for Texas franchise tax as the Company’s taxable income or loss was includable in the income tax returns of the individual partners and members. The Company will recognize a tax liability on its share of pre-tax book income, exclusive of the non-controlling interest. JEH is not subject to income tax at the federal level and only recognizes Texas franchise tax expense.

 

The Company’s effective tax rate for the three and six months ended June 30, 2015 was 20.8% and 19.6%, respectively. The effective rate differs from the statutory rate of 35% due to net income allocated to the non-controlling interest, percentage depletion, state income taxes, and other permanent differences between book and tax accounting.

 

The Company’s income tax provision was a benefit of $13.5 million and $11.1 million for the three and six months ended June 30, 2015, respectively, and a benefit of $0.9 million and an expense of $0.2 million for the three and six months ended June 30, 2014, respectively. See the table below for the allocation of the income tax provision between the controlling and non-controlling interests.

 

 

 

Three months ended June 30,

 

Six months ended June 30,

 

(in thousands of dollars)

 

2015

 

(Restated)
2014

 

2015

 

(Restated)
2014

 

 

 

 

 

 

 

 

 

 

 

Jones Energy, Inc.

 

$

(10,792

)

$

(1,073

)

$

(10,351

)

$

(215

)

Non-controlling interest

 

(2,661

)

178

 

(758

)

401

 

Total tax provision (benefit)

 

$

(13,453

)

$

(895

)

$

(11,109

)

$

186

 

 

The Company had deferred tax assets for its federal and state loss carryforwards at June 30, 2015 recorded in non-current deferred taxes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. As of June 30, 2015, management determined that a valuation allowance was not required for the tax loss carryforwards as they are expected to be fully utilized before expiration.

 

10.                     Subsidiary Guarantors

 

On April 1, 2014, the Issuers sold $500.0 million in aggregate principal amount of the 2022 Notes. On February 23, 2015, the Issuers sold $250.0 million in aggregate principal amount of the 2023 Notes.

 

The 2022 Notes and the 2023 Notes are guaranteed on a senior unsecured basis by the Company and by all of JEH’s current subsidiaries (except Jones Energy Finance Corp. and two immaterial subsidiaries) and certain future subsidiaries, including any future subsidiaries that guarantee any indebtedness under the Revolver. Each subsidiary guarantor is 100% owned by JEH, and

 

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all guarantees are full, unconditional, and joint and several with all other subsidiary guarantees and the parent guarantee. Any subsidiaries of JEH other than the subsidiary guarantors and Jones Energy Finance Corp. are minor.

 

The Company is a holding company whose sole material asset is an equity interest in JEH. The Company is the sole managing member of JEH and is responsible for all operational, management and administrative decisions related to JEH’s business. In accordance with JEH’s limited liability company agreement, the Company may not be removed as the sole managing member of JEH.

 

As of June 30, 2015, the Company held approximately 49.3% of the economic interest in JEH, with the remaining 50.7% economic interest held by a group of investors that owned interests in JEH prior to the Company’s IPO (the “Existing Owners”). The Existing Owners have no voting rights with respect to their economic interest in JEH.

 

The Company has two classes of common stock, Class A common stock, which was sold to investors in the IPO, and Class B common stock. Pursuant to the Company’s certificate of incorporation, each share of Class A common stock is entitled to one vote per share, and the shares of Class A common stock are entitled to 100% of the economic interests in the Company. Each share of Class B common stock has no economic rights in the Company, but entitles its holder to one vote on all matters to be voted on by the Company’s stockholders generally.

 

In connection with a reorganization that occurred immediately prior to the IPO, each Existing Owner was issued a number of shares of Class B common stock that was equal to the number of JEH Units that such Existing Owner held. Holders of the Company’s Class A common stock and Class B common stock generally vote together as a single class on all matters presented to the Company’s stockholders for their vote or approval. Accordingly, the Existing Owners collectively have a number of votes in the Company equal to the aggregate number of JEH Units that they hold.

 

The Existing Owners have the right, pursuant to the terms of an Exchange Agreement by and among the Company, JEH and each of the Existing Owners, to exchange their JEH Units (together with a corresponding number of shares of Class B common stock) 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. As a result, the Company expects that over time the Company will have an increasing economic interest in JEH as Class B common stock and JEH Units are exchanged for Class A common stock. Moreover, any transfers of JEH Units outside of the Exchange Agreement (other than permitted transfers to affiliates) must be approved by the Company. The Company intends to retain full voting and management control over JEH.

 

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Table of Contents

 

Jones Energy, Inc.

Condensed Consolidating Balance Sheet

 

June 30, 2015

 

(in thousands of dollars)

 

JEI (Parent)

 

Issuers

 

Guarantor
Subsidiaries

 

Non-
Guarantor
Subsidiaries

 

Eliminations

 

Consolidated

 

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash

 

$

100

 

$

9,767

 

$

12,978

 

$

30

 

$

 

$

22,875

 

Restricted cash

 

 

 

272

 

 

 

272

 

Accounts receivable, net

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas sales

 

 

 

31,025

 

 

 

31,025

 

Joint interest owners

 

 

 

16,413

 

 

 

16,413

 

Other

 

101

 

9,861

 

719

 

 

 

10,681

 

Commodity derivative assets

 

 

90,448

 

 

 

 

90,448

 

Other current assets

 

 

148

 

2,079

 

 

 

2,227

 

Intercompany receivable

 

8,444

 

1,119,913

 

 

 

(1,128,357

)

 

Total current assets

 

8,645

 

1,230,137

 

63,486

 

30

 

(1,128,357

)

173,941

 

Oil and gas properties, net, at cost under the successful efforts method

 

 

 

1,665,153

 

 

 

1,665,153

 

Other property, plant and equipment, net

 

 

 

3,076

 

751

 

 

3,827

 

Commodity derivative assets

 

 

70,979

 

 

 

 

70,979

 

Other assets

 

 

19,747

 

254

 

 

 

20,001

 

Deferred tax assets

 

2,554

 

 

 

 

 

2,554

 

Investment in subsidiaries

 

422,730

 

 

 

 

(422,730

)

 

Total assets

 

$

433,929

 

$

1,320,863

 

$

1,731,969

 

$

781

 

$

(1,551,087

)

$

1,936,455

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

Trade accounts payable

 

$

 

$

555

 

$

41,444

 

$

 

$

 

$

41,999

 

Oil and gas sales payable

 

 

 

47,251

 

 

 

47,251

 

Accrued liabilities

 

 

16,588

 

12,439

 

 

 

29,027

 

Deferred tax liabilities

 

 

434

 

 

 

 

434

 

Asset retirement obligations

 

 

 

3,246

 

 

 

3,246

 

Intercompany payable

 

 

 

1,345,127

 

2,375

 

(1,347,502

)

 

Total current liabilities

 

 

17,577

 

1,449,507

 

2,375

 

(1,347,502

)

121,957

 

Long-term debt

 

 

100,000

 

 

 

 

100,000

 

Senior notes

 

 

737,066

 

 

 

 

737,066

 

Deferred revenue

 

 

12,349

 

 

 

 

12,349

 

Commodity derivative liabilities

 

 

370

 

 

 

 

370

 

Asset retirement obligations

 

 

 

11,706

 

 

 

11,706

 

Liability under tax receivable agreement

 

39,873

 

 

 

 

 

39,873

 

Deferred tax liabilities

 

10,960

 

4,491

 

 

 

 

15,451

 

Total liabilities

 

50,833

 

871,853

 

1,461,213

 

2,375

 

(1,347,502

)

1,038,772

 

Stockholders’ / members’ equity

 

 

 

 

 

 

 

 

 

 

 

 

 

Members’ equity

 

 

449,010

 

270,756

 

(1,594

)

(718,172

)

 

Class A common stock, $0.001 par value; 30,458,790 shares issued and 30,436,188 shares outstanding

 

31

 

 

 

 

 

31

 

Class B common stock, $0.001 par value; 31,288,715 shares issued and outstanding

 

31

 

 

 

 

 

31

 

Treasury stock, at cost; 22,602 shares

 

(358

)

 

 

 

 

(358

)

Additional paid-in-capital

 

360,697

 

 

 

 

 

360,697

 

Retained earnings

 

22,695

 

 

 

 

 

22,695

 

Stockholders’ equity

 

383,096

 

449,010

 

270,756

 

(1,594

)

(718,172

)

383,096

 

Non-controlling interest

 

 

 

 

 

514,587

 

514,587

 

Total stockholders’ equity

 

383,096

 

449,010

 

270,756

 

(1,594

)

(203,585

)

897,683

 

Total liabilities and stockholders’ equity

 

$

433,929

 

$

1,320,863

 

$

1,731,969

 

$

781

 

$

(1,551,087

)

$

1,936,455

 

 

19



Table of Contents

 

Jones Energy, Inc.

Condensed Consolidating Balance Sheet

 

December 31, 2014

 

(in thousands of dollars)

 

JEI(Parent)

 

Issuers

 

Guarantor
Subsidiaries

 

Non-Guarantor
Subsidiaries

 

Eliminations

 

Consolidated

 

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash

 

$

100

 

$

1,000

 

$

12,436

 

$

30

 

$

 

$

13,566

 

Restricted Cash

 

 

 

149

 

 

 

149

 

Accounts receivable, net

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas sales

 

 

 

51,482

 

 

 

51,482

 

Joint interest owners

 

 

 

41,761

 

 

 

41,761

 

Other

 

102

 

8,788

 

3,622

 

 

 

12,512

 

Commodity derivative assets

 

 

121,519

 

 

 

 

121,519

 

Other current assets

 

 

451

 

2,923

 

 

 

3,374

 

Intercompany receivable

 

4,576

 

1,203,978

 

 

 

(1,208,554

)

 

Total current assets

 

4,778

 

1,335,736

 

112,373

 

30

 

(1,208,554

)

244,363

 

Oil and gas properties, net, at cost under the successful efforts method

 

 

 

1,638,860

 

 

 

1,638,860

 

Other property, plant and equipment, net

 

 

 

3,252

 

796

 

 

4,048

 

Commodity derivative assets

 

 

87,055

 

 

 

 

87,055

 

Other assets

 

 

20,098

 

254

 

 

 

20,352

 

Deferred tax assets

 

171

 

 

 

 

 

171

 

Investment in subsidiaries

 

233,496

 

 

 

 

(233,496

)

 

Total assets

 

$

238,445

 

$

1,442,889

 

$

1,754,739

 

$

826

 

$

(1,442,050

)

$

1,994,849

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

Trade accounts payable

 

$

 

$

288

 

$

136,049

 

$

 

$

 

$

136,337

 

Oil and gas sales payable

 

 

 

70,469

 

 

 

70,469

 

Accrued liabilities

 

 

8,914

 

10,487

 

 

 

19,401

 

Deferred tax liabilities

 

 

718

 

 

 

 

718

 

Asset retirement obligations

 

 

 

3,074

 

 

 

3,074

 

Intercompany payable

 

 

 

1,210,042

 

2,328

 

(1,212,370

)

 

Total current liabilities

 

 

9,920

 

1,430,121

 

2,328

 

(1,212,370

)

229,999

 

Long-term debt

 

 

360,000

 

 

 

 

360,000

 

Senior notes

 

 

500,000

 

 

 

 

500,000

 

Deferred revenue

 

 

13,377

 

 

 

 

13,377

 

Commodity derivative liabilities

 

 

28

 

 

 

 

28

 

Asset retirement obligations

 

 

 

10,536

 

 

 

10,536

 

Liability under tax receivable agreement

 

803

 

 

 

 

 

803

 

Deferred tax liabilities

 

20,237

 

6,519

 

 

 

 

26,756

 

Total liabilities

 

21,040

 

889,844

 

1,440,657

 

2,328

 

(1,212,370

)

1,141,499

 

Stockholders’ / members’ equity

 

 

 

 

 

 

 

 

 

 

 

 

 

Members’ equity

 

 

553,045

 

314,082

 

(1,502

)

(865,625

)

 

Class A common stock, $0.001 par value; 12,672,260 shares issued and 12,649,658 shares outstanding

 

13

 

 

 

 

 

13

 

Class B common stock, $0.001 par value; 36,719,499 shares issued and 36,719,499 shares outstanding

 

37

 

 

 

 

 

37

 

Treasury stock, at cost: 22,602 shares

 

(358

)

 

 

 

 

(358

)

Additional paid-in-capital

 

178,763

 

 

 

 

 

178,763

 

Retained earnings

 

38,950

 

 

 

 

 

38,950

 

Stockholders’equity

 

217,405

 

553,045

 

314,082

 

(1,502

)

(865,625

)

217,405

 

Non-controlling interest

 

 

 

 

 

635,945

 

635,945

 

Total stockholders’ equity

 

217,405

 

553,045

 

314,082

 

(1,502

)

(229,680

)

853,350

 

Total liabilities and stockholders’ equity

 

$

238,445

 

$

1,442,889

 

$

1,754,739

 

$

826

 

$

(1,442,050

)

$

1,994,849

 

 

20



Table of Contents

 

Jones Energy, Inc.

Condensed Consolidating Statement of Operations and Comprehensive Income

 

Six Months Ended June 30, 2015

 

(in thousands)

 

JEI (Parent)

 

Issuers

 

Guarantor
Subsidiaries

 

Non-
Guarantor
Subsidiaries

 

Eliminations

 

Consolidated

 

Operating revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas sales

 

$

 

$

 

$

110,456

 

$

 

$

 

$

110,456

 

Other revenues

 

 

1,028

 

529

 

 

 

1,557

 

Total operating revenues

 

 

1,028

 

110,985

 

 

 

112,013

 

Operating costs and expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

 

 

24,058

 

 

 

24,058

 

Production and ad valorem taxes

 

 

 

6,779

 

 

 

6,779

 

Exploration

 

 

 

628

 

 

 

628

 

Depletion, depreciation and amortization

 

 

 

103,340

 

45

 

 

103,385

 

Accretion of ARO liability

 

 

 

400

 

 

 

400

 

General and administrative

 

 

2,985

 

14,912

 

47

 

 

17,944

 

Other operating

 

 

 

4,188

 

 

 

4,188

 

Total operating expenses

 

 

2,985

 

154,305

 

92

 

 

157,382

 

Operating income (loss)

 

 

(1,957

)

(43,320

)

(92

)

 

(45,369

)

Other income (expense)

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

(30,148

)

(683

)

 

 

(30,831

)

Net gain on commodity derivatives

 

 

21,231

 

 

 

 

21,231

 

Other income (expense)

 

 

(2,301

)

677

 

 

 

(1,624

)

Other income (expense), net

 

 

(11,218

)

(6

)

 

 

(11,224

)

Income (loss) before income tax

 

 

(13,175

)

(43,326

)

(92

)

 

(56,593

)

Equity interest in income

 

(26,096

)

 

 

 

26,096

 

 

Income tax provision

 

(9,841

)

(1,268

)

 

 

 

(11,109

)

Net income (loss)

 

$

(16,255

)

$

(11,907

)

$

(43,326

)

$

(92

)

$

26,096

 

$

(45,484

)

Net income (loss) attributable to non-controlling interests

 

 

 

 

 

(29,229

)

(29,229

)

Net income (loss) attributable to controlling interests

 

$

(16,255

)

$

 

$

 

$

 

$

 

$

(16,255

)

 

21



Table of Contents

 

Jones Energy, Inc.

Condensed Consolidating Statement of Operations and Comprehensive Income

 

Three Months Ended June 30, 2015

 

(in thousands)

 

JEI (Parent)

 

Issuers

 

Guarantor
Subsidiaries

 

Non-
Guarantor
Subsidiaries

 

Eliminations

 

Consolidated

 

Operating revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas sales

 

$

 

$

 

$

53,222

 

$

 

$

 

$

53,222

 

Other revenues

 

 

503

 

192

 

 

 

695

 

Total operating revenues

 

 

503

 

53,414

 

 

 

53,917

 

Operating costs and expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

 

 

11,796

 

 

 

11,796

 

Production and ad valorem taxes

 

 

 

3,071

 

 

 

3,071

 

Exploration

 

 

 

464

 

 

 

464

 

Depletion, depreciation and amortization

 

 

 

51,280

 

22

 

 

51,302

 

Accretion of ARO liability

 

 

 

206

 

 

 

206

 

General and administrative

 

 

158

 

9,251

 

24

 

 

9,433

 

Other operating

 

 

 

1,176

 

 

 

1,176

 

Total operating expenses

 

 

158

 

77,244

 

46

 

 

77,448

 

Operating income (loss)

 

 

345

 

(23,830

)

(46

)

 

(23,531

)

Other income (expense)

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

(16,464

)

(238

)

 

 

(16,702

)

Net gain on commodity derivatives

 

 

(25,075

)

 

 

 

(25,075

)

Other income (expense)

 

 

(28

)

703

 

 

 

675

 

Other income (expense), net

 

 

(41,567

)

465

 

 

 

(41,102

)

Income (loss) before income tax

 

 

(41,222

)

(23,365

)

(46

)

 

(64,633

)

Equity interest in income

 

(28,725

)

 

 

 

28,725

 

 

Income tax provision

 

(10,282

)

(3,171

)

 

 

 

(13,453

)

Net income (loss)

 

$

(18,443

)

$

(38,051

)

$

(23,365

)

$

(46

)

$

28,725

 

$

(51,180

)

Net income (loss) attributable to non-controlling interests

 

 

 

 

 

(32,737

)

(32,737

)

Net income (loss) attributable to controlling interests

 

$

(18,443

)

$

 

$

 

$

 

$

 

$

(18,443

)

 

22



Table of Contents

 

Jones Energy, Inc.

Condensed Consolidating Statement of Operations and Comprehensive Income

 

Six Months Ended June 30, 2014

 

(in thousands)

 

JEI (Parent)

 

Issuers

 

Guarantor
Subsidiaries

 

Non-
Guarantor
Subsidiaries

 

Eliminations

 

Consolidated

 

Operating revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas sales

 

$

 

$

 

$

203,663

 

$

 

$

 

$

203,663

 

Other revenues

 

 

526

 

445

 

 

 

971

 

Total operating revenues

 

 

526

 

204,108

 

 

 

204,634

 

Operating costs and expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

 

 

19,123

 

 

 

19,123

 

Production and ad valorem taxes

 

 

 

13,204

 

 

 

13,204

 

Exploration

 

 

 

3,012

 

 

 

3,012

 

Depletion, depreciation and amortization

 

 

 

86,954

 

45

 

 

86,999

 

Accretion of ARO liability

 

 

 

367

 

 

 

367

 

General and administrative

 

 

3,320

 

8,433

 

45

 

 

11,798

 

Total operating expenses

 

 

3,320

 

131,093

 

90

 

 

134,503

 

Operating income (loss)

 

 

(2,794

)

73,015

 

(90

)

 

70,131

 

Other income (expense)

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

(22,634

)

(176

)

 

 

(22,810

)

Net gain on commodity derivatives

 

 

(50,948

)

 

 

 

(50,948

)

Other income (expense)

 

 

 

67

 

 

 

67

 

Other income (expense), net

 

 

(73,582

)

(109

)

 

 

(73,691

)

Income (loss) before income tax

 

 

(76,376

)

72,906

 

(90

)

 

(3,560

)

Equity interest in income

 

(991

)

 

 

 

991

 

 

Income tax provision

 

(303

)

489

 

 

 

 

186

 

Net income (loss)

 

$

(688

)

$

(76,865

)

$

72,906

 

$

(90

)

$

991

 

$

(3,746

)

Net income (loss) attributable to non-controlling interests

 

 

 

 

 

(3,058

)

(3,058

)

Net income (loss) attributable to controlling interests

 

$

(688

)

$

 

$

 

$

 

$

 

$

(688

)

 

23



Table of Contents

 

Jones Energy, Inc.

Condensed Consolidating Statement of Operations and Comprehensive Income

 

Three Months Ended June 30, 2014

 

(in thousands)

 

JEI (Parent)

 

Issuers

 

Guarantor
Subsidiaries

 

Non-
Guarantor
Subsidiaries

 

Eliminations

 

Consolidated

 

Operating revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas sales

 

$

 

$

 

$

105,796

 

$

 

$

 

$

105,796

 

Other revenues

 

 

282

 

312

 

 

 

594

 

Total operating revenues

 

 

282

 

106,108

 

 

 

106,390

 

Operating costs and expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

 

 

10,779

 

 

 

10,779

 

Production and ad valorem taxes

 

 

 

6,772

 

 

 

6,772

 

Exploration

 

 

 

191

 

 

 

191

 

Depletion, depreciation and amortization

 

 

 

45,777

 

22

 

 

45,799

 

Accretion of ARO liability

 

 

 

197

 

 

 

197

 

General and administrative

 

 

1,704

 

4,811

 

23

 

 

6,538

 

Total operating expenses

 

 

1,704

 

68,527

 

45

 

 

70,276

 

Operating income (loss)

 

 

(1,422

)

37,581

 

(45

)

 

36,114

 

Other income (expense)

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

(14,642

)

(125

)

 

 

(14,767

)

Net gain on commodity derivatives

 

 

(33,698

)

 

 

 

(33,698

)

Other income (expense)

 

 

 

2

 

 

 

2

 

Other income (expense), net

 

 

(48,340

)

(123

)

 

 

(48,463

)

Income (loss) before income tax

 

 

(49,762

)

37,458

 

(45

)

 

(12,349

)

Equity interest in income

 

(3,218

)

 

 

 

3,218

 

 

Income tax provision

 

(1,161

)

266

 

 

 

 

(895

)

Net income (loss)

 

$

(2,057

)

$

(50,028

)

$

37,458

 

$

(45

)

$

3,218

 

$

(11,454

)

Net income (loss) attributable to non-controlling interests

 

 

 

 

 

(9,397

)

(9,397

)

Net income (loss) attributable to controlling interests

 

$

(2,057

)

$

 

$

 

$

 

$

 

$

(2,057

)

 

24



Table of Contents

 

Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows

 

Six Months Ended June 30, 2015

 

(in thousands of dollars)

 

JEI (Parent)

 

Issuers

 

Guarantor
Subsidiaries

 

Non-
Guarantor
Subsidiaries

 

Eliminations

 

Consolidated

 

Cash flows from operating activities

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(16,255

)

$

(11,907

)

$

(43,326

)

$

(92

)

$

26,096

 

$

(45,484

)

Adjustments to reconcile net income (loss) to net cash provided by operating activities

 

(106,946

)

(21,934

)

273,412

 

92

 

(26,096

)

118,528

 

Net cash (used in) / provided by operations

 

(123,201

)

(33,841

)

230,086

 

 

 

73,044

 

Cash flows from investing activities

 

 

 

 

 

 

 

 

 

 

 

 

 

Additions to oil and gas properties

 

 

 

(229,060

)

 

 

(229,060

)

Net adjustments to purchase price of properties acquired

 

 

 

 

 

 

 

Proceeds from sales of assets

 

 

 

21

 

 

 

21

 

Acquisition of other property, plant and equipment

 

 

 

(382

)

 

 

(382

)

Current period settlements of matured derivative contracts

 

 

67,646

 

 

 

 

67,646

 

Change in restricted cash

 

 

 

(123

)

 

 

(123

)

Net cash (used in) / provided by investing

 

 

67,646

 

(229,544

)

 

 

(161,898

)

Cash flows from financing activities

 

 

 

 

 

 

 

 

 

 

 

 

 

Proceeds from issuance of long-term debt

 

 

75,000

 

 

 

 

75,000

 

Repayment under long-term debt

 

 

(335,000

)

 

 

 

(335,000

)

Proceeds from senior notes

 

 

236,475

 

 

 

 

236,475

 

Payment of debt issuance costs

 

 

(1,513

)

 

 

 

(1,513

)

Proceeds from sale of common stock, net of expense

 

123,201

 

 

 

 

 

123,201

 

Purchase of treasury stock

 

 

 

 

 

 

 

Net cash (used in) / provided by financing

 

123,201

 

(25,038

)

 

 

 

98,163

 

Net increase (decrease) in cash

 

 

8,767

 

542

 

 

 

9,309

 

Cash

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning of period

 

100

 

1,000

 

12,436

 

30

 

 

13,566

 

End of period

 

$

100

 

$

9,767

 

$

12,978

 

$

30

 

$

 

$

22,875

 

 

25



Table of Contents

 

Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows

 

Six Months Ended June 30, 2014

 

(in thousands of dollars)

 

JEI (Parent)

 

Issuers

 

Guarantor
Subsidiaries

 

Non-
Guarantor
Subsidiaries

 

Eliminations

 

Consolidated

 

Cash flows from operating activities

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(688

)

$

(76,865

)

$

72,906

 

$

(90

)

$

991

 

$

(3,746

)

Adjustments to reconcile net income (loss) to net cash provided by operating activities

 

1,040

 

2,466

 

156,448

 

90

 

(991

)

159,053

 

Net cash (used in) / provided by operations

 

352

 

(74,399

)

229,354

 

 

 

155,307

 

Cash flows from investing activities

 

 

 

 

 

 

 

 

 

 

 

 

 

Additions to oil and gas properties

 

 

 

(229,582

)

 

 

(229,582

)

Net adjustments to purchase price of properties acquired

 

 

 

13,681

 

 

 

13,681

 

Proceeds from sales of assets

 

 

 

67

 

 

 

67

 

Acquisition of other property, plant and equipment

 

 

 

(639

)

 

 

(639

)

Current period settlements of matured derivative contracts

 

 

(11,255

)

 

 

 

(11,255

)

Change in restricted cash

 

 

 

(52

)

 

 

(52

)

Net cash (used in) / provided by investing

 

 

(11,255

)

(216,525

)

 

 

(227,780

)

Cash flows from financing activities

 

 

 

 

 

 

 

 

 

 

 

 

 

Proceeds from issuance of long-term debt

 

 

60,000

 

 

 

 

60,000

 

Repayment under long-term debt

 

 

(468,000

)

 

 

 

(468,000

)

Proceeds from senior notes

 

 

500,000

 

 

 

 

500,000

 

Payment of debt issuance costs

 

 

(11,204

)

 

 

 

(11,204

)

Purchase of treasury stock

 

(352

)

 

 

 

 

(352

)

Net cash (used in) / provided by financing

 

(352

)

80,796

 

 

 

 

80,444

 

Net increase (decrease) in cash

 

 

(4,858

)

12,829

 

 

 

7,971

 

Cash

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning of period

 

100

 

6,000

 

17,650

 

70

 

 

23,820

 

End of period

 

$

100

 

$

1,142

 

$

30,479

 

$

70

 

$

 

$

31,791

 

 

26



Table of Contents

 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section and audited consolidated financial statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2014, filed on March 6, 2015 with the Securities and Exchange Commission, as well as the unaudited consolidated financial statements and related notes thereto presented in this Quarterly Report and in our quarterly report for the quarter ended March 31, 2015, filed on May 8, 2015 with the Securities and Exchange Commission. Unless indicated otherwise in this Quarterly Report or the context requires otherwise, all references to “Jones Energy,” the “Company,” “our company,” “we,” “our” and “us” refer to Jones Energy, Inc. and its subsidiaries, including Jones Energy Holdings, LLC (“JEH”). Jones Energy, Inc. (“JONE”) is a holding company whose sole material asset is an equity interest in JEH.

 

Overview

 

We are an independent oil and gas company engaged in the exploration, development, production and acquisition of oil and natural gas properties in the Anadarko and Arkoma basins of Texas and Oklahoma. Our Chairman and CEO, Jonny Jones, founded our predecessor company in 1988 in continuation of his family’s long history in the oil and gas business, which dates back to the 1920’s. We have grown rapidly by leveraging our focus on low cost drilling and completion methods and our horizontal drilling expertise to develop our inventory and execute several strategic acquisitions. We have accumulated extensive knowledge and experience in developing the Anadarko and Arkoma basins, having concentrated our operations in the Anadarko basin for over 25 years and applied our knowledge to the Arkoma basin since 2011. We have drilled over 805 total wells, including over 620 horizontal wells, since our formation and delivered compelling rates of return over various commodity price cycles. Our operations are focused on horizontal drilling and completions within two distinct basins in the Texas Panhandle and Oklahoma:

 

·                  the Anadarko Basin—targeting the liquids rich Cleveland, Granite Wash, Tonkawa and Marmaton formations; and

·                  the Arkoma Basin—targeting the Woodford shale formation.

 

We optimize returns through a disciplined emphasis on controlling costs and promoting operational efficiencies, and we believe we are recognized as one of the lowest cost drilling and completion operators in the Cleveland and Woodford shale formations.

 

Second Quarter 2015 Highlights:

 

·                  Liquidity of more than $485 million as of June 30, 2015

 

·                  Mark-to-market hedge value of approximately $220 million as of late July with estimated oil and gas volumes over 85% hedged through 2016; natural gas liquids (“NGLs”) estimated volumes hedged roughly 80% in the second half of 2015 and nearly 55% in 2016

 

·                  Average daily net production for the quarter was 25.3 MBoe/d

 

·                  Initiated 2015 leasing program

 

·                  Deployed two additional rigs in the Cleveland after achieving greater than 30% cost savings since December 2014; currently running five Cleveland rigs with $2.6 million AFE

 

·                  Spud 33 of the thirty-three stage open-hole wells as of August 4, 2015, 25 of which have been completed and placed on production

 

·                  Results from thirty-three stage open-hole wells tracking uplift in oil production

 

Updated Capital Expenditures Outlook

 

In our Annual Report on Form 10-K for the year ended December 31, 2014, we provided an overview of our 2015 capital expenditures budget, which was approximately $210 million, of which $190 million was expected to be used to drill and complete wells. The updated outlook provided as of July 31, 2015 for our capital expenditures for the full year 2015 reflects total projected capital expenditures of $240 million, incorporating additional working interests and leasing.

 

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Table of Contents

 

Results of Operations

 

The following table summarizes our revenues, expenses and production data for the periods indicated.

 

(in thousands of dollars except for production, sales price

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

and average cost data)

 

2015

 

2014

 

Change

 

2015

 

2014

 

Change

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

$

33,316

 

64,527

 

$

(31,211

)

$

66,665

 

$

118,452

 

$

(51,787

)

Natural gas

 

10,596

 

23,293

 

(12,696

)

25,103

 

44,677

 

(19,574

)

NGLs

 

9,310

 

17,976

 

(8,666

)

18,688

 

40,534

 

(21,846

)

Total oil and gas

 

53,222

 

105,796

 

(52,573

)

110,456

 

203,663

 

(93,207

)

Other

 

695

 

594

 

100

 

1,557

 

971

 

586

 

Total operating revenues

 

53,917

 

106,390

 

(52,473

)

112,013

 

204,634

 

(92,621

)

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

11,796

 

10,779

 

1,017

 

24,058

 

19,123

 

4,935

 

Production and ad valorem taxes

 

3,071

 

6,772

 

(3,701

)

6,779

 

13,204

 

(6,425

)

Exploration

 

464

 

191

 

273

 

628

 

3,012

 

(2,384

)

Depletion, depreciation and amortization

 

51,302

 

45,799

 

5,503

 

103,385

 

86,999

 

16,386

 

Accretion of ARO liability

 

206

 

197

 

9

 

400

 

367

 

33

 

General and administrative

 

9,433

 

6,538

 

2,895

 

17,944

 

11,798

 

6,146

 

Other operating

 

1,176

 

 

1,176

 

4,188

 

 

4,188

 

Total costs and expenses

 

77,448

 

70,276

 

7,172

 

157,382

 

134,503

 

22,879

 

Operating income (loss)

 

(23,531

)

36,114

 

(59,645

)

(45,369

)

70,131

 

(115,500

)

Other income (expenses):

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

(16,702

)

(14,767

)

(1,935

)

(30,831

)

(22,810

)

(8,021

)

Net gain (loss) on commodity derivatives

 

(25,075

)

(33,698

)

8,623

 

21,231

 

(50,948

)

72,179

 

Other income (expense)

 

675

 

2

 

673

 

(1,624

)

67

 

(1,691

)

Total other income (expense)

 

(41,102

)

(48,463

)

7,361

 

(11,224

)

(73,691

)

62,467

 

Income (loss) before income tax

 

(64,633

)

(12,349

)

(52,284

)

(56,593

)

(3,560

)

(53,033

)

Income tax provision

 

(13,453

)

(895

)

(12,583

)

(11,109

)

186

 

(11,320

)

Net income (loss)

 

(51,180

)

(11,454

)

(39,701

)

(45,484

)

(3,746

)

(41,713

)

Net income (loss) attributable to non-controlling interests

 

(32,737

)

(9,397

)

(23,237

)

(29,229

)

(3,058

)

(26,068

)

Net income (loss) attributable to controlling interests

 

$

(18,443

)

$

(2,057

)

$

(16,464

)

$

(16,255

)

$

(688

)

$

(15,645

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

644

 

655

 

(11

)

1,400

 

1,230

 

170

 

Natural gas (MMcf)

 

6,138

 

5,550

 

588

 

12,103

 

10,559

 

1,544

 

NGLs (MBbls)

 

637

 

566

 

71

 

1,264

 

1,089

 

175

 

Total (MBoe)

 

2,304

 

2,146

 

158

 

4,681

 

4,079

 

602

 

Average net (Boe/d)

 

25,319

 

23,582

 

1,737

 

25,862

 

22,536

 

3,326

 

Average sales price, unhedged:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl), unhedged

 

$

51.73

 

$

98.51

 

$

(46.78

)

$

47.62

 

$

96.30

 

$

(48.68

)

Natural gas (per Mcf), unhedged

 

1.73

 

4.20

 

(2.47

)

2.07

 

4.23

 

(2.16

)

NGLs (per Bbl), unhedged

 

14.62

 

31.76

 

(17.14

)

14.78

 

37.22

 

(22.44

)

Combined (per Boe), unhedged

 

23.10

 

49.30

 

(26.20

)

23.60

 

49.93

 

(26.33

)

Average sales price, hedged:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl), hedged

 

$

75.59

 

$

89.97

 

$

(14.38

)

$

73.64

 

$

88.85

 

$

(15.21

)

Natural gas (per Mcf), hedged

 

3.20

 

4.31

 

(1.11

)

3.44

 

4.19

 

(0.75

)

NGLs (per Bbl), hedged

 

27.09

 

29.99

 

(2.90

)

27.25

 

34.20

 

(6.95

)

Combined (per Boe), hedged

 

37.14

 

46.51

 

(9.37

)

38.28

 

46.77

 

(8.49

)

Average costs (per Boe):

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

$

5.12

 

$

5.02

 

$

0.10

 

$

5.14

 

$

4.69

 

$

0.45

 

Production and ad valorem taxes

 

1.33

 

3.16

 

(1.83

)

1.45

 

3.24

 

(1.79

)

Depletion, depreciation and amortization

 

22.27

 

21.34

 

0.93

 

22.09

 

21.33

 

0.76

 

General and administrative

 

4.09

 

3.05

 

1.04

 

3.83

 

2.89

 

0.94

 

 

28



Table of Contents

 

Non-GAAP financial measures

 

EBITDAX is a supplemental non GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion and amortization, exploration expense, gains and losses from derivatives less the current period settlements of matured derivative contracts and the other items described below, however, we may modify our definition of EBITDAX in the future. EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP. Management believes EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to financing methods or capital structure. We exclude the items listed above from net income in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. EBITDAX has limitations as an analytical tool and should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historical costs of depreciable assets. Our presentation of EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies. The following table sets forth a reconciliation of net income (loss) as determined in accordance with GAAP to EBITDAX for the periods indicated:

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

(in thousands of dollars)

 

2015

 

2014

 

2015

 

2014

 

 

 

 

 

 

 

 

 

 

 

Reconciliation of EBITDAX to net income

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(51,180

)

$

(11,454

)

$

(45,484

)

$

(3,746

)

Interest expense

 

15,902

 

10,184

 

29,263

 

17,528

 

Exploration expense

 

 

191

 

 

3,012

 

Income taxes

 

(13,453

)

(895

)

(11,109

)

186

 

Amortization of deferred financing costs

 

800

 

822

 

1,568

 

1,521

 

Depreciation and depletion

 

51,302

 

45,799

 

103,385

 

86,999

 

Accretion of ARO liability

 

206

 

197

 

400

 

367

 

Other non-cash charges (benefits)

 

353

 

(26

)

760

 

40

 

Stock compensation expense

 

1,824

 

928

 

3,248

 

1,386

 

Other non-cash compensation expense

 

109

 

127

 

218

 

253

 

Net (gain) loss on commodity derivatives

 

25,075

 

33,698

 

(21,231

)

50,948

 

Current period settlements of matured derivative contracts

 

32,344

 

(5,985

)

68,719

 

(12,895

)

Amortization of deferred revenue

 

(503

)

(282

)

(1,028

)

(526

)

(Gain) loss on sales of assets

 

(20

)

(1

)

6

 

(67

)

Stand-by rig costs

 

1,176

 

 

4,188

 

 

Financing expenses and other loan fees

 

28

 

3,761

 

2,301

 

3,761

 

EBITDAX

 

$

63,963

 

$

77,064

 

$

135,204

 

$

148,767

 

 

Adjusted Net Income is a supplemental non GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements. We define Adjusted Net Income as net income excluding the impact of certain non-cash items — including gains or losses on commodity derivative instruments not yet settled, impairment of oil and gas properties, and non-cash compensation expense — and certain unusual or non-recurring items. We believe adjusted net income is useful to investors because it provides readers with a more meaningful measure of our profitability before recording certain items for which the timing or amount cannot be reasonably determined. However, this measure is provided in addition to, not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP. Our computations of adjusted net income may not be comparable to other similarly titled measures of other companies. The following tables provide a reconciliation of net income (loss) as determined in accordance with GAAP to adjusted net income for the periods indicated:

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

(in thousands of dollars, except per share data)

 

2015

 

2014

 

2015

 

2014

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(51,180

)

$

(11,454

)

$

(45,484

)

$

(3,746

)

Net (gain) loss on commodity derivatives

 

25,075

 

33,698

 

(21,231

)

50,948

 

Current period settlements of matured derivative contracts

 

32,344

 

(5,985

)

68,719

 

(12.895

)

Non-cash stock compensation expense

 

1,824

 

928

 

3,248

 

1,386

 

Other non-cash compensation expense

 

109

 

127

 

218

 

253

 

Stand-by rig costs

 

1,176

 

 

4,188

 

 

Financing expenses

 

 

3,761

 

2,250

 

3,761

 

Tax impact(1)

 

(9,517

)

(2,888

)

(9,177

)

(3,908

)

Adjusted net income (loss)

 

(169

)

18,187

 

2,731

 

35,799

 

 

 

 

 

 

 

 

 

 

 

Adjusted net income (loss) attributable to non-controlling interests

 

645

 

14,867

 

2,030

 

29,308

 

Adjusted net income (loss) attributable to controlling interests

 

$

(814

)

$

3,320

 

$

701

 

$

6,491

 

 

29



Table of Contents

 

 

 

Three Months
Ended June 30,

 

Six Months
Ended June 30,

 

 

 

2015

 

2014

 

2015

 

2014

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per share (basic and diluted)

 

$

(0.66

)

$

(0.16

)

$

(0.70

)

$

(0.05

)

Net (gain) loss on commodity derivatives

 

0.41

 

0.68

 

(0.16

)

1.03

 

Current period settlements of matured derivative contracts

 

0.52

 

(0.12

)

1.15

 

(0.26

)

Non-cash stock compensation expense

 

0.03

 

0.02

 

0.06

 

0.03

 

Other non-cash compensation expense

 

 

 

 

0.01

 

Stand-by rig costs

 

0.02

 

 

0.05

 

 

Financing expenses

 

 

0.08

 

0.04

 

0.08

 

Tax impact(1)

 

(0.35

)

(0.23

)

(0.41

)

(0.31

)

Adjusted earnings (loss) per share (basic and diluted)

 

$

(0.03

)

$

0.27

 

$

0.03

 

$

0.53

 

 

 

 

 

 

 

 

 

 

 

Effective tax rate on net income (loss) attributable to controlling interests

 

37.0

%

36.4

%

37.0

%

36.4

%

 


(1) In arriving at adjusted net income, the tax impact of the adjustments to net income is determined by applying the appropriate tax rate to each adjustment and then allocating the tax impact between the controlling and non-controlling interests.

 

Results of Operations - Three months ended June 30, 2015 as compared to three months ended June 30, 2014

 

Operating revenues

 

Oil and gas sales. Oil and gas sales decreased $52.6 million, or 49.7%, to $53.2 million for the three months ended June 30, 2015, as compared to $105.8 million for the three months ended June 30, 2014. The decrease is attributable to decreases in average prices for all products, partially offset by increases in production. The average realized oil price, excluding the effects of commodity derivative instruments, decreased from $98.51 per Bbl for the three months ended June 30, 2014 to $51.73 per Bbl for the three months ended June 30, 2015, or 47.5%. The average realized natural gas price, excluding the effects of commodity derivative instruments, decreased from $4.20 per Mcf for the three months ended June 30, 2014 to $1.73 per Mcf for the three months ended June 30, 2015, or 58.8%. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, decreased from $31.76 per Bbl for the three months ended June 30, 2014 to $14.62 per Bbl for the three months ended June 30, 2015, or 54.0%. Partially offsetting the decrease in prices, average daily production increased 7.4% to 25,319 Boe per day for the three months ended June 30, 2015 as compared to 23,582 Boe per day for the three months ended June 30, 2014. The increase in production was driven by the year-over-year increase in producing wells due to continued drilling activity as well as changes in completion techniques.

 

Costs and expenses

 

Lease operating. Lease operating expenses increased $1.0 million, or 9.3%, to $11.8 million for the three months ended June 30, 2015, as compared to $10.8 million for the three months ended June 30, 2014. The increase in lease operating expenses is partially attributable to the increase in production volumes and number of producing wells. On a per unit basis, lease operating expenses increased $0.10 per Boe, or 2.0%, from $5.02 per Boe in the three months ended June 30, 2014 to $5.12 per Boe in the three months

 

30



Table of Contents

 

ended June 30, 2015. The increase is principally attributable to residual costs related to the sliding-sleeve completion technique and remedial work to enhance or maintain production.

 

Production and ad valorem taxes. Production and ad valorem taxes decreased by $3.7 million, or 54.4%, to $3.1 million for the three months ended June 30, 2015, as compared to $6.8 million for the three months ended June 30, 2014. Overall Production and ad valorem taxes decreased in conjunction with the decrease in oil and gas revenues. Estimated ad valorem taxes accounted for $0.6 million of the decrease from $1.6 million for the three months ended June 30, 2014 to $1.0 million for the three months ended June 30, 2015, reflecting anticipated lower property assessments due to lower commodity prices. The average effective rate excluding the impact of ad valorem taxes decreased from 4.9% for the three months ended June 30, 2014 to 3.8% for the three months ended June 30, 2015 partly due to tax refunds in the three months ended June 30, 2015. Production tax rates vary between states, products, and production levels; therefore, the overall blended rate is impacted by numerous factors and the mix of producing wells at any given time.

 

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $5.5 million, or 12.0%, to $51.3 million for the three months ended June 30, 2015, as compared to $45.8 million for the three months ended June 30, 2014. The increase was primarily the result of continued drilling activity. On a per unit basis, depletion expense increased $0.93 per Boe or 4.4% from $21.34 per Boe for the three months ended June 30, 2014 as compared to $22.27 per Boe for the three months June 30, 2015.

 

General and administrative. General and administrative expenses increased by $2.9 million, or 44.6%, to $9.4 million for the three months ended June 30, 2015, as compared to $6.5 million for the three months ended June 30, 2014. Salary and compensation accounted for $1.9 million of the increase from $4.4 million for the three months ended June 30, 2014 to $6.3 million for the three months ended June 30, 2015. This increase is attributable to increases in headcount and to accrued cash and stock compensation expense associated with our incentive programs. The remainder of the increase was primarily attributable to increases in professional fees including higher accounting, legal and other fees associated with the Company’s financing activity and status as a new public entity. Excluding non-cash compensation expense, general and administrative expense increased $0.71, on a per unit basis, from $2.55 per Boe for the three months ended June 30, 2014 to $3.26 for the three months ended June 30, 2015.

 

Other operating expense. Other operating expense of $1.2 million for the three months ended June 30, 2015 represents stand-by rig costs associated with the charges assessed on early termination of drilling rig contracts. This is a non-recurring charge for which all related costs have been recognized as of June 30, 2015.

 

Interest expense. Interest expense increased by $1.9 million, or 12.8%, to $16.7 million for the three months ended June 30, 2015, as compared to $14.8 million for the three months ended June 30, 2014. The increase is driven by the issuance of the 2023 Notes on February 23, 2015.

 

Net gain (loss) on commodity derivatives. The gain (loss) on commodity derivatives was a net loss of $25.1 million for the three months ended June 30, 2015. The loss was driven by higher average crude oil and natural gas prices ($57.85 and $2.75, respectively) for the three months ended June 30, 2015, as compared to the crude oil and natural gas prices as of March 31, 2015 ($47.72 and $2.65, respectively).

 

Other income/ (expense). Our other income/(expense) for the three months ended June 30, 2015 was income of $0.7 million related to the receipt of dividend income from our investment in Monarch Natural Gas Holdings, LLC.

 

Income taxes. The provision for federal and state income taxes for the three months ended June 30, 2015 was a benefit of $13.5 million as compared to a benefit of $0.9 million for the three months ended June 30, 2014. Our effective tax rate is based on the statutory rate applicable to the U.S. and the blended rate of the states in which we conduct business and is adjusted from the enacted rates for the share of net income allocated to the non-controlling interest.

 

Results of Operations - Six months ended June 30, 2015 as compared to six months ended June 30, 2014

 

Operating revenues

 

Oil and gas sales. Oil and gas sales decreased $93.2 million, or 45.8%, to $110.5 million for the six months ended June 30, 2015, as compared to $203.7 million for the six months ended June 30, 2014. The decrease is attributable to decreases in average prices for all products, partially offset by increases in production. The average realized oil price, excluding the effects of commodity derivative instruments, decreased from $96.30 per Bbl for the six months ended June 30, 2014 to $47.62 per Bbl for the six months ended June 30, 2015, or 50.6%. The average realized natural gas price, excluding the effects of commodity derivative instruments, decreased from $4.23 per Mcf for the six months ended June 30, 2014 to $2.07 per Mcf for the six months ended June 30, 2015, or 51.1%. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, decreased from $37.22 per Bbl

 

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Table of Contents

 

for the six months ended June 30, 2014 to $14.78 per Bbl for the six months ended June 30, 2015, or 60.3%. Partially offsetting the decrease in prices, average daily production increased 14.8% to 25,862 Boe per day for the six months ended June 30, 2015 as compared to 22,536 Boe per day for the six months ended June 30, 2014. The increase in production was driven by the year-over-year increase in producing wells due to continued drilling activity as well as changes in completion techniques.

 

Costs and expenses

 

Lease operating. Lease operating expenses increased $5.0 million, or 26.2%, to $24.1 million for the six months ended June 30, 2015, as compared to $19.1 million for the six months ended June 30, 2014. The increase in lease operating expenses is partially attributable to the increase in production volumes and number of producing wells. On a per unit basis, lease operating expenses increased $0.45 per Boe, or 9.6%, from $4.69 per Boe in the six months ended June 30, 2014 to $5.14 per Boe in the six months ended June 30, 2015. The increase is principally attributable to residual costs related to the sliding-sleeve completion technique and remedial work to enhance or maintain production.

 

Production and ad valorem taxes. Production and ad valorem taxes decreased by $6.4 million, or 48.5%, to $6.8 million for the six months ended June 30, 2015, as compared to $13.2 million for the six months ended June 30, 2014. Overall Production and ad valorem taxes decreased in conjunction with the decrease in oil and gas revenues. Estimated ad valorem taxes accounted for $1.5 million of the decrease from $3.3 million for the six months ended June 30, 2014 to $1.8 million for the six months ended June 30, 2015, reflecting anticipated lower property assessments due to lower commodity prices. The average effective rate excluding the impact of ad valorem taxes decreased from 4.9% for the six months ended June 30, 2014 to 4.5% for the six months ended June 30, 2015. Production tax rates vary between states, products, and production levels; therefore, the overall blended rate is impacted by numerous factors and the mix of producing wells at any given time.

 

Exploration. Exploration expense decreased from $3.0 million for the six months ended June 30, 2014 to $0.6 million for the six months ended June 30, 2015. The decrease was related to dry hole costs in 2014 as the Company drilled an unsuccessful exploratory well. There were no exploratory wells drilled in 2015.

 

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $16.4 million, or 18.9%, to $103.4 million for the six months ended June 30, 2015, as compared to $87.0 million for the six months ended June 30, 2014. The increase was primarily the result of continued drilling activity. On a per unit basis, depletion expense increased $0.76 per Boe or 3.6% from $21.33 per Boe for the six months ended June 30, 2014 as compared to $22.09 per Boe for the six months June 30, 2015.

 

General and administrative. General and administrative expenses increased by $6.1 million, or 51.7%, to $17.9 million for the six months ended June 30, 2015, as compared to $11.8 million for the six months ended June 30, 2014. Salary and compensation accounted for $3.7 million of the increase from $8.7 million for the six months ended June 30, 2014 to $12.4 million for the six months ended June 30, 2015. This increase is attributable to increases in headcount and to accrued cash and stock compensation expense associated with our incentive programs. The remainder of the increase was primarily attributable to increases in professional fees including higher accounting, legal and other fees associated with the Company’s financing activity and status as a new public entity. Excluding non-cash compensation expense, general and administrative expense increased $0.60, on a per unit basis, from $2.49 per Boe for the six months ended June 30, 2014 to $3.09 for the six months ended June 30, 2015.

 

Other operating expense. Other operating expense of $4.2 million for the six months ended June 30, 2015 represents stand-by rig costs associated with the charges assessed on early termination of drilling rig contracts. This is a non-recurring charge for which all costs have been recognized as of June 30, 2015.

 

Interest expense. Interest expense increased by $8.0 million, or 35.1%, to $30.8 million for the six months ended June 30, 2015 as compared to $22.8 million for the six months ended June 30, 2014. The increase is driven by the issuance of the 2022 Notes and 2023 Notes on April 1, 2014 and February 23, 2015, respectively.

 

Net gain (loss) on commodity derivatives. The gain (loss) on commodity derivatives was a net gain of $21.2 million for the six months ended June 30, 2015. The gain was driven by lower natural gas prices which averaged $2.82 for the six months ended June 30, 2015, as compared to the natural gas price at December 31, 2014 of $3.14.

 

Other income/ (expense). Other income/(expense) for the six months ended June 30, 2015 was a net expense of $1.7 million. Financing costs resulted in expenses of $2.4 million, partially offset by the receipt of a $0.7 million distribution of dividend income from our investment in Monarch Natural Gas Holdings, LLC.

 

Income taxes. The provision for federal and state income taxes for the six months ended June 30, 2015 was a benefit of $11.1 million as compared to an expense of $0.2 million for the six months ended June 30, 2014. Our effective tax rate is based on the statutory rate

 

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applicable to the U.S. and the blended rate of the states in which we conduct business and is adjusted from the enacted rates for the share of net income allocated to the non-controlling interest.

 

Liquidity and Capital Resources

 

Historically, our primary sources of liquidity have been private and public equity sales and debt offerings, borrowings under bank credit facilities and cash flows from operations. Our primary use of capital has been for the exploration, development and acquisition of oil and gas properties. As we pursue reserves and production growth, we continually consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. We strive to maintain financial flexibility in order to maintain substantial borrowing capacity under our senior secured revolving credit facility, facilitate drilling on our undeveloped acreage positions and permit us to selectively expand our acreage positions. Depending on the timing and concentration of the development of our non-proved locations, we may be required to generate or raise significant amounts of capital to develop all of our potential drilling locations should we endeavor to do so. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending. Our balance sheet at June 30, 2015 reflects a positive working capital balance largely due to the reduction in accounts payable. We have historically and in the future expect to maintain a negative working capital balance, and we use our Revolver to help manage our working capital. On April 17, 2015, the borrowing base was re-affirmed by our lenders under the Revolver during the semi-annual borrowing base re-determination. Our borrowing base at June 30, 2015 was $562.5 million, of which $100 million was utilized and $462.5 million was available.

 

On February 23, 2015, the Company sold $250.0 million in aggregate principal amount of 9.25% senior unsecured notes due 2023 (or the “2023 Notes”) in a private placement to affiliates of GSO Capital Partners LP and Magnetar Capital LLC. The Company used the net proceeds from the issuance of the 2023 Notes to repay outstanding borrowings under the Revolver and for working capital and general corporate purposes. The borrowing base on the Revolver was subsequently adjusted to $562.5 million in accordance with its terms as a result of the issuance of the 2023 Notes. The foregoing description of the 2023 Notes does not purport to be complete and is qualified in its entirety by reference to the full text of the Indenture pursuant to which the 2023 Notes were issued and the Registration Rights Agreement related thereto, which are filed with this report as Exhibits 4.1 and 4.2, respectively, and are incorporated herein by reference.

 

On February 17, 2015, we completed the issuance and sale of 7,500,000 shares of Class A common stock to the public at a price of $10.25 per share under our registration statement on Form S-3, which we refer to as the Public Equity Offering. On February 23, 2015, we completed the sale of an aggregate of $50.0 million of Class A common stock to certain affiliates of GSO Capital Partners LP and Magnetar Capital LLC in a direct placement of registered shares under our registration statement on Form S-3, which we refer to as the Private Equity Offering.

 

The sum of these capital transactions enabled the Company to substantially improve its near-term liquidity. The combination of cash on hand and availability under the Revolver was over $485 million at June 30, 2015.

 

Our capital budget is primarily focused on the development of the Cleveland formation through exploitation and development. The amount of capital we expend may fluctuate materially based on market conditions, the economic returns being realized and the success of our drilling results.

 

The amount, timing and allocation of capital expenditures are largely discretionary and within management’s control. If oil and gas prices decline below our acceptable levels or costs increase above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods in order to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We consistently monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

 

The following table summarizes our cash flows for the six months ended June 30, 2015 and 2014:

 

 

 

Six Months Ended June 30,

 

(in thousands of dollars)

 

2015

 

2014

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

73,044

 

$

155,307

 

Net cash used in investing activities

 

(161,898

)

(227,780

)

Net cash provided by financing activities

 

98,163

 

80,444

 

Net increase in cash

 

$

9,309

 

$

7,971

 

 

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Cash flow provided by operating activities

 

Net cash provided by operating activities was $73.0 million during the six months ended June 30, 2015 as compared to net cash provided by operating activities of $155.3 million during the six months ended June 30, 2014. The decrease in operating cash flows was primarily due to the $93.2 million decrease in oil and gas revenues for the six months ended June 30, 2015 as compared to the six months ended June 30, 2014, driven by declines in prices for all products.

 

Cash flow used in investing activities

 

Net cash used in investing activities was $161.9 million during the six months ended June 30, 2015 as compared to net cash used in investing activities of $227.8 million during the six months ended June 30, 2014. The decrease was primarily driven by a decrease in capital expenditures as a result of our decreased drilling program from ten rigs at June 30, 2014 to three rigs running at March, 31, 2015, and then to four rigs running at June 30, 2015.

 

Cash flow provided by financing activities

 

Net cash provided by financing activities was $98.2 million during the six months ended June 30, 2015 as compared to net cash provided by financing activities of $80.4 million during the six months ended June 30, 2014. The increase in cash flows provided by financing activities was primarily due to net equity offerings of $123.2 million and borrowings of $236.5 million under the senior notes, offset by repayments net of advances of $260 million on the Revolver during the six months ended June 30, 2015.

 

Contractual Obligations

 

Other than the stand-by rig costs related to the termination of certain drilling contracts, there have been no material changes in our contractual obligations as reported in our Annual Report on Form 10-K for the year ended December 31, 2014.

 

Off-Balance Sheet Arrangements

 

We do not have any off-balance sheet arrangements.

 

Critical Accounting Policies and Estimates

 

There have been no changes to our critical accounting policies and estimates from those set forth in our Annual Report.

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

 

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the year ended December 31, 2014, as well as with the unaudited consolidated financial statements and notes included in this Quarterly Report.

 

We are exposed to certain market risks that are inherent in our financial statements that arise in the normal course of business. We may enter into derivative instruments to manage or reduce market risk, but do not enter into derivative agreements for speculative purposes. We do not designate these or future derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings.

 

Potential Impairment of Oil and Gas Properties

 

Oil and natural gas prices are inherently volatile and have decreased significantly over the latter half of 2014 and the first half of 2015.  In applying the prescribed impairment test under the successful efforts method at June 30, 2015, no impairment charge was indicated.  The undiscounted cash flows of our proved properties are still greater than the carrying cost of those properties, but the difference has narrowed significantly since 2014. Future price declines, or a period of sustained low commodity prices, could result in a significant impairment charge in future periods. Furthermore, in addition to commodity prices, our production rates, levels of proved reserves, future development costs, and other factors affect our impairment analyses and may lead to an impairment charge in future periods.

 

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Commodity price risk and hedges

 

Our principal market risk exposure is to oil, natural gas and NGL prices, which are inherently volatile. As such, future earnings are subject to change due to fluctuations in such prices. Realized prices are primarily driven by the prevailing prices for oil and regional spot prices for natural gas and NGLs. We have used, and expect to continue to use, oil, natural gas and NGL derivative contracts to reduce our risk of price fluctuations of these commodities. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with projected production levels. The fair value of our oil, natural gas and NGL derivative contracts at June 30, 2015 was a net asset of $161.1 million.

 

Counterparty and customer credit risk

 

Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we drill. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. The inability or failure of these significant customers to meet their obligations or their insolvency or liquidation may adversely affect our financial results. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties.

 

While we do not typically require our partners, customers and counterparties to post collateral, and we do not have a formal process in place to evaluate and assess the credit standing of our partners or customers for oil and gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such parties as we deem appropriate under the circumstances. This evaluation may include reviewing a party’s credit rating, latest financial information and, in the case of a customer with which we have receivables, their historical payment record, and undertaking the due diligence necessary to determine creditworthiness. The counterparties on our derivative instruments currently in place are lenders under the revolving credit facility with investment grade ratings.

 

Interest rate risk

 

We are subject to market risk exposure related to changes in interest rates on our indebtedness. The terms of the Revolver provide for interest on borrowings at a floating rate equal to prime, LIBOR or the federal funds rate plus margins ranging from 0.50% to 2.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. During the three and six months ended June 30, 2015, borrowings under the senior secured revolving credit facility bore interest at a weighted average rate of 2.35% and 2.43%, respectively.

 

Item 4. Controls and Procedures

 

Changes in Internal Control over Financial Reporting

 

There have been no changes in internal control over financial reporting during the quarter ended June 30, 2015 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

Evaluation of Disclosure Controls and Procedures

 

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

 

Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were not effective as of June 30, 2015 because of the material weakness in internal control over financial reporting described in our Annual Report.

 

Management’s Assessment of Internal Control over Financial Reporting

 

The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules requiring every public company that files reports with the SEC to include a management report on such company’s internal control over financial reporting in its annual report. Pursuant to the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for up to five years or through such earlier date that we are no longer an “emerging growth company” as defined in the

 

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JOBS Act. Our Annual Report on Form 10-K for the year ended December 31, 2014 included a report of management’s assessment regarding internal control over financial reporting.

 

PART II—OTHER INFORMATION

 

Item 1. Legal Proceedings

 

For a discussion of legal proceedings, see Note 8 to the Consolidated Financial Statements appearing in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated in this item by reference.

 

Item 1A. Risk Factors

 

Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings, including our Annual Report on Form 10-K for the year ended December 31, 2014, could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

 

There have been no material changes in our risk factors from those described in our Annual Report. For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our Annual Report.

 

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

 

None.

 

Item 3. Defaults Upon Senior Securities

 

None.

 

Item 4. Mine Safety Disclosures

 

Not applicable.

 

Item 5. Other Information

 

Not applicable.

 

Item 6. Exhibits

 

Exhibit No.

 

Description

31.1*

 

Rule 13a-14(a)/15d-14(a) Certification of Jonny Jones (Principal Executive Officer).

31.2*

 

Rule 13a-14(a)/15d-14(a) Certification of Robert J. Brooks (Principal Financial Officer).

32.1**

 

Section 1350 Certification of Jonny Jones (Principal Executive Officer).

32.2**

 

Section 1350 Certification of Robert J. Brooks (Principal Financial Officer).

101.INS*

 

XBRL Instance Document.

101.SCH*

 

XBRL Taxonomy Extension Schema Document.

101.CAL*

 

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*

 

XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*

 

XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*

 

XBRL Taxonomy Extension Presentation Linkbase Document.

 


* - filed herewith

** - furnished herewith

 

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

 

 

Jones Energy, Inc.

 

 

 

 

 

(registrant)

 

 

 

 

 

 

Date: August 7, 2015

 

By:

/s/ Jonny Jones

 

 

 

Name:

Jonny Jones

 

 

 

Title:

Chief Executive Officer

 

Signature Page to Form 10-Q (Q2 2015)

 

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