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EX-32.2 - EX-32.2 - REX ENERGY CORPrexx-ex322_7.htm
EX-32.1 - EX-32.1 - REX ENERGY CORPrexx-ex321_9.htm
EX-31.2 - EX-31.2 - REX ENERGY CORPrexx-ex312_8.htm
EX-31.1 - EX-31.1 - REX ENERGY CORPrexx-ex311_6.htm
EX-10.1 - EX-10.1 - REX ENERGY CORPrexx-ex101_293.htm
EX-2.1 - EX-2.1 - REX ENERGY CORPrexx-ex21_294.htm

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

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

For the quarterly period ended March 31, 2017

OR

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

For the transition period from              to             .

Commission file number: 001-33610

 

REX ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

 

 

Delaware

 

20-8814402

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. employer

identification number)

366 Walker Drive

State College, Pennsylvania 16801

(Address of principal executive offices) (Zip Code)

(814) 278-7267

(Registrant’s telephone number, including area code) 

 

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      No  

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

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

 

Large accelerated filer

 

  

Accelerated filer

 

 

 

 

 

Non-accelerated filer

 

  (Do not check if a smaller reporting company)

  

Smaller reporting company

 

 

 

 

 

 

 

 

Emerging growth company

 

 

 

 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  

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

99,024,707 shares of common stock were outstanding on May 5, 2017.

 

 


 

REX ENERGY CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2017

INDEX

 

 

 

 

PAGE

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

3

PART I. FINANCIAL INFORMATION

 

 

Item 1.

  

Financial Statements

5

 

 

  

Consolidated Balance Sheets As of March 31. 2017 (Unaudited) and December 31, 2016

 5

 

 

  

Consolidated Statements of Operations (Unaudited) for the three-month periods ended March 31, 2017 and March 31, 2016

 6

 

 

  

Consolidated Statement of Changes in Stockholders’ Equity (Unaudited) for the three-month period ended March 31, 2017

 7

 

 

  

Consolidated Statements of Cash Flows (Unaudited) for the three-month periods ended March 31, 2017 and March 31, 2016

 8

 

 

  

Notes to Consolidated Financial Statements (Unaudited)

 9

 

Item 2.

  

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

 37

 

Item 3.

  

Quantitative and Qualitative Disclosure About Market Risk

  48

 

Item 4.

  

Controls and Procedures

49

PART II. OTHER INFORMATION

 51

 

Item 1.

  

Legal Proceedings

 51

 

Item 1A.

  

Risk Factors

 51

 

Item 6.

  

Exhibits

 51

SIGNATURES

 52

EXHIBIT INDEX

 53

 

 

 

2


 

 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Some of the information, including all of the estimates and assumptions, in this report contains forward-looking statements within the meaning of sections 27A of the Securities Act of 1933, as amended, and 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this report, including, but not limited to, statements regarding our future financial position, business strategy, budgets, projected costs, savings and plans and objectives of management for future operations, are forward-looking statements. Forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “estimate,” “anticipate,” “believe” or “continue” or the negative thereof or variations thereon or similar terminology.

These forward-looking statements are subject to numerous assumptions, risks, and uncertainties. Factors that may cause our actual results, performance, or achievements to be materially different from those anticipated in forward-looking statements include, among others, the following:

 

economic conditions in the United States and globally;

 

domestic and global supply and demand for oil, NGLs and natural gas;

 

realized prices for oil, natural gas and NGLs and volatility of those prices;

 

the adequacy and availability of capital resources, credit and liquidity, including, but not limited to, access to additional borrowing capacity and our inability to generate sufficient cash flow from operations to fund our capital expenditures and meeting working capital needs;

 

our ability to comply with restrictions imposed by our senior credit facility and other existing and future financing arrangements;

 

our ability to service our outstanding indebtedness;

 

impairments of our natural gas, NGL and condensate asset values due to declines in commodity prices;

 

conditions in the domestic and global capital and credit markets and their effect on us;

 

new or changing government regulations, including those relating to environmental matters, permitting or other aspects of our operations;

 

the willingness and ability of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain oil price and production controls;

 

the geologic quality of our properties with regard to, among other things, the existence of hydrocarbons in economic quantities;

 

uncertainties inherent in the estimates of our natural gas, NGL and condensate reserves;

 

our ability to increase natural gas, NGL and condensate production and income through exploration and development;

 

drilling and operating risks;

 

counterparty credit risks;

 

the success of our drilling techniques in both conventional and unconventional reservoirs;

 

the success of the secondary and tertiary recovery methods we utilize or plan to employ in the future;

 

the number of potential well locations to be drilled, the cost to drill, and the time frame within which they will be drilled;

 

the ability of contractors to timely and adequately perform their drilling, construction, well stimulation, completion and production services;

 

the availability of equipment, such as drilling rigs, and infrastructure, such as transportation, pipelines, processing and midstream services;

 

the effects of adverse weather or other natural disasters on our operations;

 

competition in the oil and gas industry in general, and specifically in our areas of operations;

 

changes in our drilling plans and related budgets;

 

the success of prospect development and property acquisitions;

 

the success of our business and financial strategies, and hedging strategies;

3


 

 

uncertainties related to the legal and regulatory environment for our industry and our own legal proceedings and their outcome;

 

our ability to cure the deficiencies with respect to the continued listing standards of The NASDAQ Capital Market or any other exchange on which our securities trade; and

 

other factors discussed under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2016 filed with the Securities and Exchange Commission.

Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by such statements. You are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. Other unknown or unpredictable factors may cause actual results to differ materially from those projected by the forward-looking statements. Most of these factors are difficult to anticipate and may be beyond our control. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements.

4


 

 

 

 

Item 1.

Financial Statements.

REX ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

($ in Thousands, Except Share and per Share Data)

 

 

March 31, 2017 (unaudited)

 

 

December 31, 2016

 

 

ASSETS

 

 

 

 

 

 

 

 

Current Assets

 

 

 

 

 

 

 

 

Cash and Cash Equivalents

$

5,075

 

 

$

3,697

 

 

Accounts Receivable

 

25,264

 

 

 

25,448

 

 

Taxes Receivable

 

48

 

 

 

211

 

 

Short-Term Derivative Instruments

 

3,430

 

 

 

1,873

 

 

Inventory, Prepaid Expenses and Other

 

2,124

 

 

 

2,546

 

 

Total Current Assets

 

35,941

 

 

 

33,775

 

 

Property and Equipment (Successful Efforts Method)

 

 

 

 

 

 

 

 

Evaluated Oil and Gas Properties

 

963,481

 

 

 

1,053,461

 

 

Unevaluated Oil and Gas Properties

 

207,821

 

 

 

215,794

 

 

Other Property and Equipment

 

21,863

 

 

 

21,401

 

 

Wells and Facilities in Progress

 

40,740

 

 

 

21,964

 

 

Pipelines

 

21,262

 

 

 

18,029

 

 

Total Property and Equipment

 

1,255,167

 

 

 

1,330,649

 

 

Less: Accumulated Depreciation, Depletion and Amortization

 

(419,500

)

 

 

(475,205

)

 

Net Property and Equipment

 

835,667

 

 

 

855,444

 

 

Other Assets

 

2,495

 

 

 

2,492

 

 

Long-Term Derivative Instruments

 

3,292

 

 

 

2,212

 

 

Total Assets

$

877,395

 

 

$

893,923

 

 

LIABILITIES AND EQUITY

 

 

 

 

 

 

 

 

Current Liabilities

 

 

 

 

 

 

 

 

Accounts Payable

$

36,838

 

 

$

40,712

 

 

Current Maturities of Long-Term Debt

 

801

 

 

 

764

 

 

Accrued Liabilities

 

31,922

 

 

 

37,207

 

 

Short-Term Derivative Instruments

 

12,801

 

 

 

25,025

 

 

Total Current Liabilities

 

82,362

 

 

 

103,708

 

 

Long-Term Derivative Instruments

 

10,265

 

 

 

7,227

 

 

Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs

 

106,573

 

 

 

113,785

 

 

Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges

 

650,758

 

 

 

641,762

 

 

Discount on Senior Notes, Net

 

(7,389

)

 

 

(3,601

)

 

Other Long-Term Debt

 

3,849

 

 

 

3,409

 

 

Other Deposits and Liabilities

 

8,262

 

 

 

8,671

 

 

Future Abandonment Cost

 

9,465

 

 

 

8,736

 

 

Total Liabilities

$

864,145

 

 

$

883,697

 

 

Commitments and Contingencies (See Note 12)

 

 

 

 

 

 

 

 

Stockholders’ Equity

 

 

 

 

 

 

 

 

Preferred Stock, $.001 par value per share, 100,000 shares authorized and 3,987

   issued and outstanding on March 31, 2017 and December 31, 2016

$

1

 

 

$

1

 

 

Common Stock, $.001 par value per share, 200,000,000 shares authorized and

   99,024,368 shares issued and outstanding on March 31, 2017 and 97,870,608

   shares issued and outstanding on December 31, 2016

 

96

 

 

 

95

 

 

Additional Paid-In Capital

 

650,924

 

 

 

650,584

 

 

Accumulated Deficit

 

(637,771

)

 

 

(640,454

)

 

Total Stockholders’ Equity

 

13,250

 

 

 

10,226

 

 

Total Liabilities and Stockholders’ Equity

$

877,395

 

 

$

893,923

 

 

See accompanying notes to the unaudited consolidated financial statements

 

 

5


 

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, $ in Thousands, Except per Share Data)

 

 

For the Three Months Ended March 31,

 

 

 

2017

 

 

2016

 

 

OPERATING REVENUE

 

 

 

 

 

 

 

 

Natural Gas, NGL and Condensate Sales

$

52,065

 

 

$

25,673

 

 

Other Operating Revenue

 

6

 

 

 

13

 

 

TOTAL OPERATING REVENUE

 

52,071

 

 

 

25,686

 

 

OPERATING EXPENSES

 

 

 

 

 

 

 

 

Production and Lease Operating Expense

 

28,934

 

 

 

24,451

 

 

General and Administrative Expense

 

4,534

 

 

 

5,284

 

 

(Gain) Loss on Disposal of Assets

 

(1,834

)

 

 

11

 

 

Impairment Expense

 

1,546

 

 

 

10,641

 

 

Exploration Expense

 

220

 

 

 

936

 

 

Depreciation, Depletion, Amortization and Accretion

 

15,468

 

 

 

16,511

 

 

Other Operating (Income) Expense

 

(21

)

 

 

327

 

 

TOTAL OPERATING EXPENSES

 

48,847

 

 

 

58,161

 

 

INCOME (LOSS) FROM OPERATIONS

 

3,224

 

 

 

(32,475

)

 

OTHER INCOME (EXPENSE)

 

 

 

 

 

 

 

 

Interest Expense

 

(9,143

)

 

 

(13,030

)

 

Gain on Derivatives, Net

 

8,381

 

 

 

4,049

 

 

Other Expense

 

(28

)

 

 

-

 

 

Debt Exchange Expense

 

-

 

 

 

(8,480

)

 

Gain on Extinguishments of Debt

 

249

 

 

 

 

 

TOTAL OTHER EXPENSE

 

(541

)

 

 

(17,461

)

 

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX

 

2,683

 

 

 

(49,936

)

 

Income Tax Expense

 

-

 

 

 

(2,715

)

 

NET INCOME (LOSS) FROM CONTINUING OPERATIONS

 

2,683

 

 

 

(52,651

)

 

Loss From Discontinued Operations, Net of Income Taxes

 

 

 

 

(7,490

)

 

NET INCOME (LOSS)

 

2,683

 

 

 

(60,141

)

 

Preferred Stock Dividends

 

(598

)

 

 

(2,105

)

 

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS

$

2,085

 

 

$

(62,246

)

 

Earnings per common share:

 

 

 

 

 

 

 

 

Basic - Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders

$

0.02

 

 

$

(0.98

)

 

Basic - Net Loss From Discontinued Operations Attributable to Rex Energy Common Shareholders

 

-

 

 

 

(0.13

)

 

Basic - Net Income (Loss) Attributable to Rex Energy Common Shareholders

$

0.02

 

 

$

(1.11

)

 

Basic - Weighted Average Shares of Common Stock Outstanding

 

97,687

 

 

 

56,003

 

 

Diluted - Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders

$

0.02

 

 

$

(0.98

)

 

Diluted - Net Loss From Discontinued Operations Attributable to Rex Energy Common Shareholders

 

-

 

 

 

(0.13

)

 

Diluted - Net Income (Loss) Attributable to Rex Energy Common Shareholders

$

0.02

 

 

$

(1.11

)

 

Diluted - Weighted Average Shares of Common Stock Outstanding

 

97,687

 

 

 

56,003

 

 

 

 

 

See accompanying notes to the unaudited consolidated financial statements

 

 

 

6


 

REX ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

FOR THE THREE-MONTHS ENDED MARCH 31, 2017

(Unaudited, in Thousands)

 

 

Common Stock

 

 

Preferred Stock

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Shares

 

 

Par Value

 

 

Shares

 

 

Par Value

 

 

Additional Paid-In Capital

 

 

Accumulated Deficit

 

 

Total Stockholders’ Equity

 

BALANCE December 31, 2016

 

97,871

 

 

$

95

 

 

 

4

 

 

$

1

 

 

$

650,584

 

 

$

(640,454

)

 

$

10,226

 

Non-Cash Compensation

 

 

 

 

 

 

 

 

 

 

 

 

 

60

 

 

 

 

 

 

60

 

Issuance of Common Stock for Debt Extinguishments

 

333

 

 

 

1

 

 

 

 

 

 

 

 

 

280

 

 

 

 

 

 

281

 

Issuance of Restricted Stock, Net of

   Forfeitures

 

820

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2,683

 

 

 

2,683

 

BALANCE March 31, 2017

 

99,024

 

 

$

96

 

 

 

4

 

 

$

1

 

 

$

650,924

 

 

$

(637,771

)

 

$

13,250

 

See accompanying notes to the unaudited consolidated financial statements

 

 

 

7


 

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, $ in Thousands)

 

 

For the Three Months Ended March 31,

 

 

2017

 

 

2016

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

 

 

Net Income (Loss)

$

2,683

 

 

$

(60,141

)

Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities

 

 

 

 

 

 

 

Depreciation, Depletion, Amortization and Accretion

 

15,468

 

 

 

19,408

 

Gain on Derivatives

 

(8,381

)

 

 

(4,049

)

Cash Settlements of Derivatives

 

(3,443

)

 

 

12,994

 

Equity-based Compensation Expense

 

71

 

 

 

(21

)

Non-cash Exploration Expenses

 

11

 

 

 

843

 

Impairment Expense

 

1,546

 

 

 

14,184

 

Amortization of net Bond Discount and Deferred Debt Issuance Costs

 

 

 

 

547

 

Non-cash Interest Expense related to Debt Restructurings and Exchanges

 

6,081

 

 

 

 

Gain on Extinguishments of Debt

 

(249

)

 

 

 

Gain on Sale of Assets

 

(1,834

)

 

 

(30

)

Other Non-cash Income

 

(66

)

 

 

(29

)

Deferred Income Tax Expense

 

 

 

 

2,092

 

Changes in operating assets and liabilities

 

 

 

 

 

 

 

Accounts Receivable

 

5,341

 

 

 

(4,873

)

Inventory, Prepaid Expenses and Other Assets

 

422

 

 

 

660

 

Accounts Payable and Accrued Liabilities

 

(6,989

)

 

 

(308

)

Other Assets and Liabilities

 

(139

)

 

 

(170

)

NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES

 

10,522

 

 

 

(18,893

)

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

 

 

Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets

 

24,329

 

 

 

71

 

Proceeds from Joint Venture for Reimbursement of Capital Costs

 

 

 

 

19,461

 

Acquisitions of Undeveloped Acreage

 

(299

)

 

 

(5,266

)

Capital Expenditures for Development of Oil & Gas Properties and Equipment

 

(25,476

)

 

 

(15,068

)

NET CASH USED IN INVESTING ACTIVITIES

 

(1,446

)

 

 

(802

)

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

 

 

Proceeds from Long-Term Debt and Line of Credit

 

21,500

 

 

 

46,500

 

Repayments of Long-Term Debt and Line of Credit

 

(28,500

)

 

 

 

Repayments of Loans and Other Notes Payable

 

(131

)

 

 

(184

)

Debt Issuance Costs

 

(567

)

 

 

(2,821

)

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES

 

(7,698

)

 

 

43,495

 

NET INCREASE IN CASH

 

1,378

 

 

 

23,800

 

CASH – BEGINNING

 

3,697

 

 

 

1,091

 

CASH – ENDING

$

5,075

 

 

$

24,891

 

CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO CONTINUING OPERATIONS

$

5,075

 

 

$

24,891

 

SUPPLEMENTAL DISCLOSURES

 

 

 

 

 

 

 

Interest Paid, net of capitalized interest

$

1,541

 

 

$

22,479

 

Cash Received for Income Taxes

$

(163

)

 

 

 

Capital Expenditures for Development of Oil & Gas Properties and

    Equipment Attributable to Discontinued Operations

 

 

 

$

566

 

NON-CASH ACTIVITIES

 

 

 

 

 

 

 

Change in fair value of contingent consideration receivable - sale of Illinois Basin

$

(1,417

)

 

 

 

Proceeds held in Escrow - non-cash component of Gain on Sale of Assets

$

5,000

 

 

 

 

 

Increase (Decrease) in Accrued Liabilities for Capital Expenditures

$

(3,040

)

 

$

2,830

 

Increase Long Term Debt - Equipment Financing

$

607

 

 

 

 

Increase in Senior Notes carrying value net of Issuance Costs, Deferred Gain on

     Exchanges, and Net Discount due to Debt to Equity Conversions

$

5,208

 

 

 

 

Decrease in  Bond Interest Payable due to Debt to Equity Conversions

$

(11

)

 

 

 

Increase in Common Stock outstanding due to Debt to Equity Conversions

$

281

 

 

$

6,476

 

See accompanying notes to the unaudited consolidated financial statements

 

 

 

8


 

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

 

1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION

Rex Energy Corporation, together with our subsidiaries (the “Company”), is an independent condensate, natural gas liquid (“NGL”) and natural gas company with operations currently focused in the Appalachian Basin. We are focused on Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties.

The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all of our wholly owned subsidiaries. We report our interests in natural gas, NLG and condensate properties using the proportional consolidation method of accounting. All intercompany balances and transactions have been eliminated. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together. In preparing the accompanying Consolidated Financial Statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies.

The interim Consolidated Financial Statements of the Company are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented. Actual results may differ from those estimates and results for interim periods are not necessarily indicative of results to be expected for a full year or for previously reported periods due in part, but not limited to, the volatility in prices for crude oil, NGLs and natural gas, future impact of financial derivative instruments, interest rates, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of acquisitions, product demand, market consumption, interruption in production, our ability to obtain additional capital, and the success of oil, NGL and natural gas recovery techniques.

Certain amounts and disclosures have been condensed or omitted from these Consolidated Financial Statements pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Therefore, these interim financial statements should be read in conjunction with the audited Consolidated Financial Statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2016.

Discontinued Operations

In 2016, we divested all of our Illinois Basin assets and operations. The sale closed in August 2016, with an effective date of July 1, 2016. As a result of this transaction, the 2016 results of operations of our Illinois Basin operations have been classified as Discontinued Operations in the accompanying Consolidated Statements of Operations for the year ended December 31, 2016.  

Unless otherwise noted, all disclosures and tables reflect the results of continuing operations and exclude any assets, liabilities or results from our discontinued operations. For additional information see Note 3, Discontinued Operations/Assets Held for Sale, to our Consolidated Financial Statements.

 

2. FUTURE ABANDONMENT COST

Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. If the fair value of a recorded future abandonment cost changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost.

9


 

Accretion expense totaled $0.6 million and $0.2 million for the three months ended March 31, 2017 and 2016, respectively. These amounts are recorded as depreciation, depletion, amortization and accretion (“DD&A”) expense on our Consolidated Statements of Operations. We account for future abandonment costs that relate to wells that are drilled jointly based on our working interest in those wells.

 

($ in Thousands)

March 31, 2017

 

Beginning Balance at January 1, 2017

$

9,865

 

Future Abandonment Obligation Incurred

$

1,034

 

Future Abandonment Obligation Settled

$

(112

)

Future Abandonment Obligation Cancelled or Sold

$

(262

)

Future Abandonment Obligation Revision of Estimated Obligation

$

57

 

Future Abandonment Obligation Accretion Expense

$

570

 

Total Future Abandonment Cost1

$

11,152

 

 

1 Includes approximately $1.7 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

 

 

3. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE

 

Illinois Basin Operations

On June 14, 2016, we, through our wholly owned subsidiaries, Penntex Resources Illinois, LLC, Rex Energy I, LLC, Rex Energy IV, LLC, Rex Energy Marketing, LLC, R. E. Ventures Holdings, LLC, and Rex Energy Operating Corp. (collectively, “Rex”), entered into a Purchase and Sale Agreement (the “Agreement”) with Campbell Development Group, LLC (“Campbell”). Pursuant to the Agreement, Campbell agreed to purchase, subject to certain parameters and provisions for adjustment customary for transactions of this type, all of our oil and gas-related properties and assets, both operated and non-operated, in the Illinois Basin on an as-is, where-is basis. Closing occurred on August 18, 2016, with an effective date for the transaction of July 1, 2016. We received a purchase deposit of $2.5 million from Campbell in June and received the additional proceeds of approximately $38.0 million during the third and fourth quarters of 2016. An addendum executed in conjunction with the Agreement allowed for the Company to receive from Campbell potential additional proceeds of up $9.9 million, in installments of $0.9 million per quarter, over the period beginning with the quarter ended December 31, 2016, and ending with the quarter ending June 30, 2019.  For the proceeds to become payable by Campbell in any of the eleven individual quarters, the average spot price of West Texas Intermediate (“WTI”) as published by the New York Mercantile Exchange must be in excess of the amount shown in the table below for the applicable quarter. As of March 31, 2017, the first two of the eleven quarterly measurement periods have expired with the calculated average spot price of WTI below the threshold price stipulated in the agreement. Consequently, we did not receive any additional proceeds related to those measurement periods.  As of March 31, 2017, we have the potential to receive up to $8.1 million of additional proceeds, during the nine remaining measurement periods. For additional information, see Note 8, Derivative Instruments and Fair Value Measurements, to our Consolidated Financial Statements.

 

Calendar Quarter Ending

 

West Texas Intermediate ("WTI")  Average Price per Bbl (a)

 

3/31/2017

 

$

56.25

 

6/30/2017

 

$

58.25

 

9/30/2017

 

$

60.25

 

12/31/2017

 

$

60.75

 

3/31/2018

 

$

61.25

 

6/30/2018

 

$

61.75

 

9/30/2018

 

$

62.25

 

12/31/2018

 

$

62.75

 

3/31/2019

 

$

63.25

 

6/30/2019

 

$

63.75

 

 

 

(a)

Calculated as the sum of the closing spot price of the West Texas Intermediate of the New York Mercantile Exchange for each day during the quarter (excluding weekends and holidays), divided by the number of days on which those prices are published (excluding weekends and holidays).

Included in the sale were approximately 76,000 net acres in Illinois, Indiana and Kentucky and production of approximately 1,700 net barrels per day.  The sale transaction resulted in a full divestiture of our Illinois Basin assets, and an exit from our Illinois Basin operations.  As of March 31, 2017 and December 31 2016, we had no remaining assets or liabilities related to our former Illinois

10


 

Basin operations. The results of operations of our Illinois Basin operations are reported as Discontinued Operations for the three month period ended March 31, 2016, in our Consolidated Statements of Operations.

Summarized financial information for Discontinued Operations related to our Illinois Basin operations is set forth in the tables below, and does not reflect the costs of certain services provided. Such indirect costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support. The sale of our Illinois assets and operations does not include any of our derivative contracts or positions related to our Illinois Basin revenues or production.  No derivative positions or activity has been attributed to or included in Discontinued Operations for the three month periods ended March 31, 2017 and 2016.

 

 

 

For the Three Months Ended March 31,

 

($ in Thousands)

 

2017

 

 

2016

 

Revenues:

 

 

 

 

 

 

 

 

Oil Sales

 

$

 

 

$

4,821

 

Total Operating Revenue

 

 

 

 

 

4,821

 

Costs and Expenses:

 

 

 

 

 

 

 

 

Production and Lease Operating Expense

 

 

 

 

 

5,698

 

General and Administrative Expense

 

 

 

 

 

778

 

Gain on Disposal of Assets

 

 

 

 

 

(42

)

Impairment Expense

 

 

 

 

 

3,543

 

Exploration Expense

 

 

 

 

 

58

 

Depreciation, Depletion, Amortization and Accretion

 

 

 

 

 

2,897

 

Interest Expense

 

 

 

 

 

2

 

Other Income

 

 

 

 

 

(1

)

Total Costs and Expenses

 

 

 

 

 

12,933

 

Loss From Discontinued Operations, Before Income Taxes

 

 

 

 

 

(8,112

)

Income Tax Benefit

 

 

 

 

 

622

 

Loss From Discontinued Operations, Net of Taxes

 

$

 

 

$

(7,490

)

Production:

 

 

 

 

 

 

 

 

Crude Oil (Bbls)

 

 

 

 

 

158,304

 

 

 

4. BUSINESS AND OIL AND GAS PROPERTY DISPOSITIONS

Benefit Street Partners, LLC

On March 1, 2016, we entered into a joint exploration and development agreement with an affiliate of Benefit Street Partners, LLC (“BSP”) to jointly develop 58 specifically designated wells in our Moraine East and Warrior North operated areas. BSP agreed to participate in and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, all of which have already been drilled, completed, placed in sales and paid for by BSP. BSP also agreed to participate in and fund 65.0% of the estimated well costs for six designated wells in Warrior North, Ohio, all of which have been drilled, completed, placed in sales and paid for by BSP. BSP also has the option to participate in the development of 36 additional wells and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. To date, BSP has exercised its option to participate in 23 of these additional wells. Consideration for this transaction could be up to $175.0 million with approximately $134.0 million committed as of March 31, 2017. BSP has paid approximately $86.7 million for its interest in elected wells as of March 31, 2017. The remainder of the proceeds will be received as additional wells are drilled to total depth or placed in sales.  BSP earns an assignment of 15%-20% working interest in acreage located within each of the units in which it participates. As of March 31, 2017, 30 of the 45 committed wells were in line and producing and 15 wells were drilled and awaiting completion.

The BSP transaction constitutes a pooling of assets in a joint undertaking to develop these specific properties for which there is substantial uncertainty about the ability to recover the costs applicable to our interest in the properties. Under the terms of the agreement, we hold a substantial obligation for future performance, which may not be proportionally reimbursed by BSP. Due to the uncertainty that exists on the recoverability of costs associated with our retained interest, proceeds received from BSP are considered a recovery of costs and no gain or loss is recognized.

Diversified Oil & Gas, LLC

On May 20, 2016, we entered into a Purchase and Sale Agreement (the “PSA”) with Diversified Oil and Gas, LLC (“DOG”). Pursuant to the PSA, DOG purchased all of our conventional operated oil and gas-related properties and related pipeline assets located in Pennsylvania and assumed all future abandonment liability associated with the assets. Closing occurred on May 20, 2016, with an effective date for the transaction of May 1, 2016. We received proceeds at closing of approximately $0.1 million. Included in the sale were approximately 300 wells, pipelines and support equipment. The sale of well properties generated approximately $4.6 million of gain in the second quarter of 2016 due to the elimination of our future abandonment liability associated with wells and pipelines sold

11


 

to DOG.  The gain, which is included in Gain on Disposal of Assets on our Consolidated Statement of Operations, is reported net of approximately $0.2 million of uncollectible accounts receivable written off in conjunction with the sale.

Illinois Basin Operations

As described in Note 3, Discontinued Operations/Assets Held for Sale, we sold our Illinois Basin assets and operations pursuant to a purchase and sale agreement with Campbell in August 2016.

Sale of Warrior South Assets

On January 11, 2017, we, together with MFC Drilling, Inc. (“MFC”), and ABARTA Oil & Gas Co., Inc. (“ABARTA”) (together, the “Sellers”) sold substantially all of our jointly owned oil and gas interests in Noble, Guernsey, and Belmont Counties, Ohio, to Antero Resources Corporation (“Antero”). These interests comprised our Warrior South development area. The effective date for the transaction is October 1, 2016. The sales agreement includes representations, warranties, covenants and agreements as well as various provisions for purchase price and post-closing adjustments customary for transactions of this type. Total consideration for the transaction was approximately $50.0 million, with approximately $29.1 million net to Rex, subject to customary closing and post-closing adjustments. We received approximately $24.1 million of proceeds on January 11, 2017.  Approximately $5.0 million of the total proceeds due to us will be held in escrow and will be released in January 2018, net of post-closing adjustments. The proceeds held in escrow are classified as accounts receivable on our Consolidated Balance Sheet as of March 31, 2017. The sale of assets resulted in a gain on disposal of assets of approximately $1.8 million in January 2017. This gain includes the additional proceeds held in escrow, that we anticipate receiving in January 2018. The sale of assets included 14 gross wells with associated production of 15 Mmcfe/d, with 9 Mmcfe/d net to us, and approximately 6,200 gross acres, with 4,100 acres net to us. This acreage was considered non-core to us. We used the proceeds from the transaction to pay down our revolving line of credit and for general corporate purposes.

 

5. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In May 2014, the Financial Accounting Standards Board (the “FASB”) issued ASU 2014-09, Revenue from Contracts with Customers. The amendments in this ASU affects any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards. This ASU will supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services by following five steps:

1) Identify the contract(s) with a customer.

2) Identify the performance obligations in the contract.

3) Determine the transaction price.

4) Allocate the transaction price to the performance obligations in the contract.

5) Recognize revenue when (or as) the entity satisfies a performance obligation.

An entity should apply the amendments in this ASU using one of the following two methods:

1) Retrospectively to each prior reporting period presented.

2) Retrospectively with the cumulative effect of initially applying this ASU recognized at the date of the initial applications.

 

In March 2016, ASU 2014-09 was updated with ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (ASU 2016-08), which provides further clarification on the principal versus agent evaluation. ASU 2014-09 is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet and is effective for annual reporting periods, and interim periods within that reporting period, after December 15, 2017. Early adoption is not permitted. We continue to evaluate the available adoption methods. We are currently analyzing the potential impact of the standard on each of our revenue contracts by identifying differences between current recognition policies and the guidance set forth in the standard. As of March 31, 2017, we were still evaluating the potential impact of this standard on our results of operations and internal control environment.

In February 2016, the FASB issued ASU 2016-02, Leases. Under the new guidance, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date:

12


 

 

A lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and

 

A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term.

Public business entities are required to apply the amendment of this update for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. We are currently evaluating the potential impact of this standard on our results of operations and internal control environment.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. The amendments in the update provide guidance regarding the presentation in the statement of cash flows of eight specific cash flow disclosure issues:

 

debt prepayment or debt extinguishment costs;

 

settlement of zero-coupon debt instruments or other instruments with coupon rates that are insignificant in relation to the effective interest rate of borrowing;

 

contingent consideration payments made after a business combination;

 

proceeds from the settlement of insurance claims;

 

proceeds from the settlement of corporate-owned life insurance policies;

 

distributions received from equity method investees;

 

beneficial interest in securitization transactions; and

 

separately identifiable cash flows and application of the Predominance Principle.

Public business entities are required to apply the amendments of this update for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The amendments should be applied using a retrospective transition method to each period presented. We are currently evaluating this guidance to assess its impact on our current cash flow reporting processes.

 

6. CONCENTRATIONS OF CREDIT RISK

By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparties to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. Our counterparties are investment grade financial institutions and lenders in our Senior Credit Facility (see Note 7, Long-Term Debt, to our Consolidated Financial Statements). We have a master netting agreement in place with our counterparties that provides for the offsetting of payables against receivables from separate derivative contracts. None of our derivative contracts have a collateral provision that would require funding prior to the scheduled cash settlement date. For additional information, see Note 8, Derivative Instruments and Fair Value Measurements, to our Consolidated Financial Statements.

We also depend on a relatively small number of purchasers for a substantial portion of our revenue. For the three months ended March 31, 2017, approximately 95.8% of our commodity sales came from five purchasers, with the largest single purchaser accounting for 51.0% of commodity sales. We believe the growth in our Appalachian estimated proved reserves will help us to minimize our future risks by diversifying our ratio of condensate and gas sales as well as the quantity of purchasers.   

7. LONG-TERM DEBT

Senior Credit Facility and Term Loan

As of March 31, 2017, we maintained a revolving credit facility, evidenced by a credit agreement dated March 27, 2013 and most recently amended on April 28, 2017 (the “Senior Credit Facility”) with Royal Bank of Canada, as Administrative Agent and the

13


 

lenders from time to time parties thereto. Borrowings under the Senior Credit Facility were limited by a borrowing base that was determined in regard to our oil and gas properties. As of March 31, 2017, we had $110.7 million borrowings outstanding, and approximately $46.3 million in outstanding undrawn letters of credit on our borrowing base of $190.0 million. We had $117.7 million borrowings outstanding as of December 31, 2016. On April 28, 2017, we entered a first lien delayed-draw term loan (the “Term Loan”) and subsequently terminated and repaid the amounts outstanding under the Senior Credit Facility (see Note 18, Subsequent Event, to our Consolidated Financial Statements for additional information).    

The Term Loan requires we meet certain financial requirements, on a quarterly basis, including a maximum “Ratio of Net Senior Secured Debt to EBITDAX”, a minimum “Ratio of EBITDAX to Interest Expense” and a minimum “PDP Coverage Ratio” (all terms in quotations as defined in the Term Loan). EBITDAX is a non-GAAP financial measure used by our management team and by other users of our financial statements, including our lenders, which adds to or subtracts from net income the following expenses or income for a given period to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, unrealized gains and losses from derivatives, exploration expense and other similar non-cash or non-recurring activities. The Term Loan requires that as of the last day of any fiscal quarter, beginning with the quarter ending June 30, 2017, our “Ratio of Net Senior Secured Debt to EBITDAX” for the four fiscal quarters then ending to be greater than 3.25 to 1.00; provided that EBITDAX for the four fiscal quarters ending on June 30, 2017 shall be the EBITDAX for the two fiscal quarters then ending multiplied by two. Additionally, as of the last day of any fiscal quarter, beginning September 30, 2017 our “Ratio of EBITDAX to Interest Expense” for the trailing twelve months must be less than 1.0 to 1.0. Effective for the quarter ending March 31, 2018, the minimum “Ratio of EBITDAX to Interest Expense” will be 1.3 to 1.0. We will also be required to meet a minimum “PDP Coverage Ratio” which stipulates that our PDP PV-10 value as of the last day of any fiscal quarter ending on or after December 31, 2017 may not be less than 1.65 to 1.00. Management currently anticipates being in compliance with these financial covenants for at least the next twelve months.    

In order to improve our liquidity positions to meet the financial requirements under our Term Loan and to meet other outstanding obligations, we are currently pursuing or considering a number of actions, which in certain cases may involve current investors, affiliates of the Company, and/or other financing or strategic counterparties, which may include refinancing of existing debt, debt-for-debt or debt-for-equity exchanges, or other in- and out-of-court restructuring transactions. There can be no assurance that sufficient liquidity will be raised from any such transactions or that any such transactions can or will be consummated within the period needed to meet our obligations.

Senior Notes

On March 31, 2016, we completed an exchange offer and consent solicitation related to our 8.875% Senior Notes due 2020 (the “2020 Notes”) and 6.25% Senior Notes due 2022 (the “2022 Notes” and, together with the 2020 Notes, the “Existing Notes”). We offered to exchange (the “Exchange”) any and all of the Existing Notes held by eligible holders for up to (i) $675.0 million aggregate principal amount of our new Senior Secured Second Lien Notes (the “New Notes”) and (ii) 10.1 million shares of our common stock (the “Shares”). We accounted for these transactions as troubled debt restructurings. As a result of the troubled debt exchanges, the future undiscounted cash flows of the New Notes are greater than the net carrying value of the Existing Notes. As such, no gain has been recognized within our GAAP basis financial statements and a new effective interest rate has been established.  See Note 9, Income Taxes, to our Consolidated Financial Statements, for information regarding the tax treatment and impact of the Exchange for federal and state income tax purposes.

In exchange for $324.0 million in aggregate principal amount of the 2020 Notes, representing approximately 92.6% of the outstanding aggregate principal amount of the 2020 Notes, and $309.1 million in aggregate principal amount of the 2022 Notes, representing approximately 95.1% of the outstanding aggregate principal amount of the 2022 Notes, we issued (i) $633.2 million aggregate principal amount of New Notes and (ii) 8.4 million Shares, which had a fair value of $6.5 million upon issuance. An additional $0.5 million aggregate principal amount of New Notes were issued to holders who were ineligible to accept Shares. In addition, upon closing, we paid in cash accrued and unpaid interest on the Existing Notes accepted in the Exchange from the applicable last interest payment date totaling approximately $12.8 million. The remaining Existing Notes will continue to accrue interest at their historical rates. The New Notes will bear interest at a rate of 1.0% per annum for the first three semi-annual interest payments after issuance and 8.0% per annum thereafter, payable in cash. Interest payments are due on April 1 and October 1 of each year, beginning October 1, 2016 and ending October 1, 2020. In connection with the Exchange, we incurred approximately $9.1 million in third-party debt issuance costs during the year ended December 31, 2016. These costs were recorded as Debt Exchange Expense in our Consolidated Statement of Operations.

Following the completion of the Exchange, we entered into debt-for equity exchanges during the remainder of 2016, with certain holders of our Existing Notes, as well as holders of our New Notes, in exchange for unrestricted shares of our common stock.  These exchanges resulted in the retirement of $27.7 million of our remaining Existing Notes and $45.7 million of our outstanding New Notes, in exchange for the issuance of a total of approximately 22.7 million shares of unrestricted common stock during the year ended December 31, 2016. In the three months ended March 31, 2017, we completed debt-for equity exchanges with certain holders of

14


 

our Existing Notes.  These exchanges resulted in the retirement of approximately $0.5 million of our remaining Existing Notes, in exchange for approximately 0.3 million shares of unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in a gain to the Company for the three months ended March 31, 2017 of approximately $0.2 million, presented as Gain on Extinguishments of Debt in our Consolidated Statements of Operations.

We may redeem, at specified redemption prices, some or all of the New Notes at any time on or after April 1, 2018. We may also redeem up to 35% of the New Notes using the proceeds of certain equity offerings completed before April 1, 2018. If we sell certain of our assets or experience specific kinds of changes in control, we may be required to offer to purchase the Existing Notes and the New Notes from the holders.

Our Existing Notes and New Notes (collectively, the “Senior Notes”) are recorded as Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges on our Consolidated Balance Sheets.    

The Senior Notes are governed by indentures (the “Indentures”), which contain affirmative and negative covenants that are customary for instruments of this nature, including restrictions or limitations on our ability to incur additional debt, pay dividends, purchase or redeem stock or subordinated indebtedness, make investments, create liens, sell assets, merge with or into other companies or transfer substantially all of our assets, unless those actions satisfy the terms and conditions of the Indentures or are otherwise excepted or permitted.  Certain of the limitations in the Indentures, including our ability to incur debt, pay dividends or make other restricted payments, become more restrictive in the event our ratio of consolidated cash flow to fixed charges for the most recent trailing four quarters (the “Fixed Charge Coverage Ratio”) is less than 2.25 to 1.00.  As of March 31, 2017, our Fixed Charge Coverage Ratio was 1.26 to 1.00.  We expect our Fixed Charge Coverage Ratio to improve based on our projections of decreased interest expense related to the New Notes. As of March 31, 2017, we were limited to incurring approximately $112.2 million of additional debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default. In certain circumstances, the individual Trustees or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.  

As of March 31, 2017 and December 31, 2016, we had recorded on our Consolidated Balance Sheets approximately $7.4 million and $3.6 million, respectively, of net discount related to the Senior Notes. The amortization of our net premium during the three months ended March 31, 2017, which follows the effective interest method, was approximately $3.8 million, and was recorded as a credit to Interest Expense on our Consolidated Statements of Operations. Interest is payable semi-annually on our Existing Notes. Interest on the 2020 Notes is paid at a rate of 8.875% per annum on June 1 and December 1 of each year, while interest on the 2022 Notes is paid at a rate of 6.25% per annum on February 1 and August 1 of each year.

In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at March 31, 2017 and December 31, 2016:

 

($ in Thousands)

March 31, 2017 (unaudited)

 

 

December 31, 2016

 

Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges (a)(c)

$

650,758

 

 

$

641,762

 

Discount on Senior Notes, Net

 

(7,389

)

 

 

(3,601

)

Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs (b)(d)

 

106,573

 

 

 

113,785

 

Capital Leases and Other Obligations (d)

 

4,650

 

 

 

4,173

 

Total Debt

 

754,592

 

 

 

756,119

 

Less Current Portion of Long-Term Debt

 

(801

)

 

 

(764

)

Total Long-Term Debt

$

753,791

 

 

$

755,355

 

 

(a)

Includes unamortized debt issuance costs of approximately ($17.3)  million and ($7.9)  million as of March 31, 2017 and December 31, 2016, respectively.

 

 

(b)

Includes unamortized debt issuance costs of approximately $4.1 million and $3.9 million as of March 31, 2017 and December 31, 2016, respectively.

 

 

(c)

Includes unamortized deferred gain on debt exchange of approximately $32.8 million and $32.7 million as of March 31, 2017 and December 31, 2016, respectively, as a result of debt exchange transactions completed subsequent to the March 31, 2016 Exchange.

 

 

(d) 

The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. The weighted average interest rate on borrowings under our Senior Credit Facility for the three months ended March 31, 2017 was approximately 3.7 %. The average interest rate on our capital leases and other obligations for the three months ended March 31, 2017 was approximately 10.0%.

 

 

15


 

The following is the principal maturity schedule for debt outstanding as of March 31, 2017:

 

2017

$

587

 

2018

 

908

 

2019

 

111,746

 

2020

 

596,565

 

2021

 

802

 

Thereafter

 

5,364

 

Total(a)

$

715,972

 

 

(a)

Excludes $7.4 million net discount on Senior Notes, $32.8 million of deferred gain on Senior Notes, and ($13.2) million of debt issuance costs

 

 

8. DERIVATIVE INSTRUMENTS AND FAIR VALUE MEASUREMENTS

Our results of operations and operating cash flows are impacted by changes in market prices for oil, natural gas and NGLs. To mitigate a portion of the exposure to adverse market changes, we enter into oil, natural gas and NGL commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling, we make payments to our counterparties. We do not enter into these arrangements for speculative trading purposes. As of March 31, 2017 and December 31, 2016, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, swaptions, deferred put spreads, cap swaps, calls, basis swaps and three-way collars. We did not designate these instruments as cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly as Gain on Derivatives, Net.

We enter into the majority of our derivative arrangements with five counterparties and have a netting agreement in place with these counterparties. We do not obtain collateral to support the agreements, but we believe our credit risk is currently minimal on these transactions. For additional information on the credit risk regarding our counterparties, see Note 6, Concentrations of Credit Risk, to our Consolidated Financial Statements.

None of our commodity derivatives are designated for hedge accounting but are, to a degree, an economic offset to our commodity price exposure. We utilize the mark-to-market accounting method to account for these contracts. We recognize all gains and losses related to these contracts in the Consolidated Statements of Operations as Gain on Derivatives, Net under Other Expense. We paid net cash settlements of $3.4 million and received net cash settlements of $13.0 million in relation to our commodity derivatives during the three months ended March 31, 2017 and 2016, respectively.

As of March 31, 2017, we had over 100.0% of our annualized condensate production hedged through the remainder of 2017, over 100.0% of our annualized natural gas production hedged through the remainder of 2017, and over 100.0% of our annualized NGL production hedged through the remainder of 2017. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future drilling and completion or the natural decline of our natural gas, condensate and NGL production.

Contingent Consideration – Sale of Illinois Basin Operations

In conjunction with the sale of our Illinois Basin operations, we executed a contract with the buyer that would allow us to receive future cash payments from the buyer if index pricing targets as defined in the contract are achieved at specified future dates.  See Note3, Discontinued Operations / Assets Held for Sale, to our Consolidated Financial Statements for additional information regarding the terms of the contract. We have evaluated the contract and concluded that it meets the definition and requirements for accounting treatment as a derivative instrument, as prescribed in ASC 815-10-15-83. We recorded the contract at its initial fair value of approximately $1.2 million as additional consideration in the calculation of the gain on the sale of the assets. Fair value was determined through application of mathematical models designed to provide fair value estimates utilizing probability measures and the market index measures underlying the contract. The fair value will be adjusted at each future reporting period for the duration of the contract, which concludes June 30, 2019. As of March 31, 2017 and December 31, 2016, the contingent consideration contract was valued at $1.5 million and $2.9 million, respectively.

Interest Rate Derivatives

We are exposed to interest rate risk on our long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in the market interest rates which are lower than our current fixed rate. Variable rate debt, where the interest rate fluctuates, exposes us to changes in market interest rates, which may increase over time. As of March 31, 2017, and December 31, 2016, we had $110.7 million and $117.7 million outstanding under our Senior

16


 

Credit Facility, respectively, which is subject to variable rates of interest and $600.7 million and $601.2 million, respectively, of Senior Notes outstanding subject to fixed interest rates. See Note 7, Long-Term Debt, to our Consolidated Financial Statements for additional information on our Senior Credit Facility and Senior Notes.

As of March 31, 2017 and December 31, 2016, we did not have any interest rate derivatives outstanding. We utilize the mark-to-market accounting method to account for interest rate swap and swaptions. We recognize all gains and losses related to interest rate derivatives in the Consolidated Statements of Operations as Gain on Derivatives, Net under Other Expense.

The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three months ended March 31, 2017 and 2016:

 

 

 

For the Three Months Ended March 31,

 

($ in Thousands)

 

2017

 

 

2016

 

Oil

 

$

1,137

 

 

$

325

 

Natural Gas

 

 

(59

)

 

 

5,363

 

NGLs

 

 

8,720

 

 

 

(1,621

)

Refined Products

 

 

 

 

 

(18

)

Contingent Consideration

 

 

(1,417

)

 

 

 

Gain on Derivatives, Net

 

$

8,381

 

 

$

4,049

 

 

Our derivative instruments are recorded on the balance sheet as either an asset or a liability, in either case measured at fair value. The fair value associated with our derivative instruments was a net liability of approximately $16.3 million and approximately $28.2 million at March 31, 2017 and December 31, 2016, respectively.

17


 

Our open asset/(liability) financial commodity derivative instrument positions at March 31, 2017 consisted of:

Period

 

Volume

 

Put Option

 

 

Floor

 

 

Ceiling

 

 

Swap

 

 

Fair Market Value ($ in Thousands)

 

Oil

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2017 - Swaps

 

 

81,000

 

Bbls

 

$

 

 

$

 

 

$

 

 

$

53.00

 

 

$

94

 

2017 - Deferred Put Spreads

 

 

15,000

 

Bbls

 

 

51.00

 

 

 

51.00

 

 

 

 

 

 

 

 

 

 

2017 - Collars

 

 

48,000

 

Bbls

 

 

 

 

 

45.00

 

 

 

57.20

 

 

 

 

 

 

 

2017 - Three-Way Collars

 

 

93,000

 

Bbls

 

 

40.16

 

 

 

49.68

 

 

 

61.50

 

 

 

 

 

 

108

 

2018 - Swaps

 

 

60,000

 

Bbls

 

 

 

 

 

 

 

 

 

 

 

54.00

 

 

 

186

 

2018 - Collars

 

 

18,000

 

Bbls

 

 

 

 

 

53.00

 

 

 

60.00

 

 

 

 

 

 

 

2018 - Three-Way Collars

 

 

60,000

 

Bbls

 

 

43.00

 

 

 

52.00

 

 

 

62.30

 

 

 

 

 

 

92

 

 

 

 

375,000

 

Bbls

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

480

 

Natural Gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2017 - Swaps

 

 

11,000,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

3.11

 

 

$

(1,332

)

2017 - Swaptions

 

 

2,400,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

3.33

 

 

 

36

 

2017 - Cap Swaps

 

 

3,900,000

 

Mcf

 

 

2.35

 

 

 

 

 

 

 

 

 

2.81

 

 

 

(1,591

)

2017 - Collars

 

 

1,700,000

 

Mcf

 

 

 

 

 

2.54

 

 

 

3.20

 

 

 

 

 

 

(382

)

2017 - Three-Way Collars

 

 

17,510,000

 

Mcf

 

 

2.33

 

 

 

3.01

 

 

 

3.87

 

 

 

 

 

 

(133

)

2017 - Calls

 

 

8,380,100

 

Mcf

 

 

 

 

 

 

 

 

4.51

 

 

 

 

 

 

(338

)

2017 - Basis Swaps - Dominion South

 

 

16,405,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

(0.80

)

 

 

(2,467

)

2017 - Basis Swaps - Texas Gas

 

 

14,600,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

(0.13

)

 

 

46

 

2018 - Swaps

 

 

12,585,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

3.14

 

 

 

289

 

2018 - Swaptions

 

 

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(200

)

2018 - Three-Way Collars

 

 

8,775,000

 

Mcf

 

 

2.30

 

 

 

2.89

 

 

 

3.58

 

 

 

 

 

 

(509

)

2018 - Calls

 

 

16,489,900

 

Mcf

 

 

 

 

 

 

 

 

4.64

 

 

 

 

 

 

(753

)

2018 - Collars

 

 

450,000

 

Mcf

 

 

 

 

 

3.20

 

 

 

3.65

 

 

 

 

 

 

(33

)

2018 - Basis Swaps - Dominion South

 

 

18,980,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

(0.80

)

 

 

(3,417

)

2018 - Basis Swaps - Texas Gas

 

 

14,600,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(0.13

)

 

 

62

 

2019 - Swaps

 

 

900,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

3.00

 

 

 

60

 

2019 - Basis Swaps - Dominion South

 

 

18,980,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

(0.81

)

 

 

(3,190

)

2020 - Basis Swaps - Dominion South

 

 

13,542,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

(0.80

)

 

 

(1,551

)

2021 - Basis Swaps - Dominion South

 

 

6,234,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

(0.73

)

 

 

(461

)

2022 - Basis Swaps - Dominion South

 

 

3,650,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

(0.72

)

 

 

(460

)

2023 - Basis Swaps - Dominion South

 

 

3,650,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

(0.72

)

 

 

(461

)

2024 - Basis Swaps - Dominion South

 

 

3,650,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

(0.72

)

 

 

(460

)

 

 

 

198,381,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

(17,245

)

NGLs

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2017 - C3+ NGL Swaps

 

 

1,689,000

 

Bbls

 

 

 

 

 

 

 

 

 

 

 

0.71

 

 

$

(2,455

)

2017 - Ethane Swaps

 

 

840,000

 

Bbls

 

 

 

 

 

 

 

 

 

 

 

0.25

 

 

 

(237

)

2018 - C3+ NGL Swaps

 

 

1,068,000

 

Bbls

 

 

 

 

 

 

 

 

 

 

 

0.76

 

 

 

1,684

 

2018 - Ethane Swaps

 

 

660,000

 

Bbls

 

 

 

 

 

 

 

 

 

 

 

0.31

 

 

 

(15

)

2019 - Ethane Swaps

 

 

240,000

 

Bbls

 

 

 

 

 

 

 

 

 

 

 

0.31

 

 

 

(75

)

 

 

 

4,497,000

 

Bbls

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

(1,098

)

 

 

 

 

 

 

18


 

The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016 is summarized below: 

 

 

March 31,

 

 

December 31,

 

($ in Thousands)

2017

 

 

2016

 

Short-Term Derivative Assets:

 

 

 

 

 

 

 

Crude Oil—Three-Way Collars

 

131

 

 

 

 

Crude Oil—Swaps

 

175

 

 

 

 

NGL—Swaps

 

1,291

 

 

 

 

Natural Gas—Swaps

 

453

 

 

 

206

 

Natural Gas—Cap Swaps

 

 

 

 

61

 

Natural Gas—Basis Swaps

 

132

 

 

 

232

 

Natural Gas—Three-Way Collars

 

523

 

 

 

151

 

Natural Gas—Swaption

 

170

 

 

 

 

Contingent Consideration - Sale of Illinois Basin

 

555

 

 

 

1,223

 

Total Short-Term Derivative Assets

$

3,430

 

 

$

1,873

 

Long-Term Derivative Assets:

 

 

 

 

 

 

 

Crude Oil—Three-Way Collars

$

69

 

 

$

 

Crude Oil—Swaps

$

143

 

 

 

 

 

NGL—Swaps

 

1,177

 

 

 

 

Natural Gas—Swaps

 

707

 

 

 

206

 

Natural Gas—Basis Swaps

 

99

 

 

 

293

 

Natural Gas—Three-Way Collars

 

133

 

 

 

 

Contingent Consideration - Sale of Illinois Basin

 

964

 

 

 

1,713

 

Total Long-Term Derivative Assets

$

3,292

 

 

$

2,212

 

Total Derivative Assets

$

6,722

 

 

$

4,085

 

Short-Term Derivative Liabilities:

 

 

 

 

 

 

 

Crude Oil—Collars

 

 

 

 

(86

)

Crude Oil—Deferred Put Spread

 

 

 

 

(9

)

Crude Oil—Three-Way Collars

 

 

 

 

 

(132

)

Crude Oil—Swaps

 

(19

)

 

 

(220

)

NGL—Swaps

 

(3,566

)

 

 

(9,895

)

Natural Gas—Three-Way Collars

 

(889

)

 

 

(2,397

)

Natural Gas—Cap Swaps

 

(1,591

)

 

 

(3,364

)

Natural Gas—Collars

 

(415

)

 

 

(873

)

Natural Gas—Basis Swaps

 

(3,561

)

 

 

(640

)

Natural Gas—Call

 

(527

)

 

 

(1,478

)

Natural Gas—Swaption

 

(184

)

 

 

(1,258

)

Natural Gas—Swaps

 

(2,049

)

 

 

(4,673

)

Total Short - Term Derivative Liabilities

$

(12,801

)

 

$

(25,025

)

Long-Term Derivative Liabilities:

 

 

 

 

 

 

 

Crude Oil—Three-Way Collars

 

 

 

 

 

(58

)

Crude Oil—Swaps

 

(19

)

 

 

(146

)

NGL—Swaps

 

 

 

 

(2,200

)

Natural Gas—Swaps

 

(94

)

 

 

(1,004

)

Natural Gas—Swaption

 

(150

)

 

 

(167

)

Natural Gas—Basis Swaps

 

(9,028

)

 

 

(1,260

)

Natural Gas—Collars

 

 

 

 

(115

)

Natural Gas—Call

 

(565

)

 

 

(491

)

Natural Gas—Three-Way Collars

 

(409

)

 

 

(1,786

)

Total Long-Term Derivative Liabilities

$

(10,265

)

 

$

(7,227

)

Total Derivative Liabilities

$

(23,066

)

 

$

(32,252

)

 

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. We utilize a fair value hierarchy that gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:

Level 1—Observable inputs, such as quoted prices in active markets for identical assets or liabilities as of the reporting date.

Level 2—Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard

19


 

models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars and other like derivative contracts, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

Level 3—Unobservable inputs that are supported by little or no market activity. Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Our Level 2 fair value measurements are comprised of our derivative contracts and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, interest rates and discount rates, or can be confirmed from other active markets. The fair values recorded as of March 31, 2017 and December 31, 2016, were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party.

We had no Level 3 commodity derivative contracts outstanding as of March 31, 2017 or December 31, 2016.

The fair value of our derivative instruments may be different from the settlement value based on company-specific inputs, such as credit ratings, futures markets and forward curves, and readily available buyers and sellers for such assets and liabilities. During the three months ended March 31, 2017 and 2016, there were no transfers into or out of Level 1 or Level 2 measurements. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value:

 

 

 

 

 

 

Fair Value Measurements at March 31, 2017

 

($ in Thousands)

Total Carrying Value as of March 31, 2017

 

 

Quoted Prices in Active Markets for Identical Assets (Level 1)

 

 

Significant Other Observable Inputs (Level 2)

 

 

Significant Unobservable Inputs (Level 3)

 

Commodity Derivatives

$

(16,344

)

 

$

 

 

$

(16,344

)

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair Value Measurements at December 31, 2016

 

($ in Thousands)

Total Carrying Value as of December 31, 2016

 

 

Quoted Prices in Active Markets for Identical Assets (Level 1)

 

 

Significant Other Observable Inputs (Level 2)

 

 

Significant Unobservable Inputs (Level 3)

 

Commodity Derivatives

$

(28,167

)

 

$

 

 

$

(28,167

)

 

$

 

 

Net derivative asset values are determined primarily by quoted futures and options prices and utilization of the counterparties’ credit default risk and net derivative liabilities are determined primarily by quoted futures and options prices and utilization of our credit default risk. The credit default risk of our counterparties and us are based on metrics such as interest coverage, operating cash flow and leverage ratios that calculate the likelihood that a firm will be unable to repay its lenders or fulfill payment obligations.

The value of our oil derivatives are comprised of three-way collar, call protected swap and deferred put spread contracts for notional barrels of oil at interval New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) oil prices. The fair values attributable to our oil derivatives as of March 31, 2017 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our gas derivatives are comprised of swap, collars, swaption, three way collar, basis swap, cap swap, call and put spread contracts for notional volumes of gas contracted at NYMEX Henry Hub (“HH”). The fair values attributable to our gas derivative contracts as of March 31, 2017 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our NGL derivatives are comprised of swaps for notional volumes of NGLs contracted at NYMEX Mont Belvieu. The fair values attributable to our NGL derivative contracts as of March 31, 2017 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for Mont Belvieu, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. We classify our derivatives as Level 2 if the inputs used in the valuation models are directly observable for substantially the full term of the instrument; however, if the significant inputs were not observable for substantially the full term of the instrument, we would classify those derivatives as Level 3. We categorize our measurements as Level 2 because the valuation of our derivative instruments are based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instruments.

20


 

Future Abandonment Cost

We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Future Abandonment Costs, to our Consolidated Financial Statements for further information on asset retirement obligations, which includes a reconciliation of the beginning and ending balances.

Financial Instruments Not Recorded at Fair Value

The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements:

 

March 31, 2017

 

 

December 31, 2016

 

($ in Thousands)

Carrying Amount

 

 

Fair Value

 

 

Carrying Amount

 

 

Fair Value

 

Senior Notes, Net of Issuance Costs

$

650,758

 

 

$

253,796

 

 

$

641,762

 

 

$

147,605

 

Secured Line of Credit, Net of Issuance Costs

 

106,573

 

 

 

106,573

 

 

 

113,785

 

 

 

113,785

 

Capital Leases and Other Obligations

 

4,650

 

 

 

3,129

 

 

 

4,173

 

 

 

3,234

 

Total

$

761,981

 

 

$

363,498

 

 

$

759,720

 

 

$

264,624

 

 

The fair value of the secured lines of credit approximates carrying value based on borrowing rates available to us for bank loans with similar terms and maturities and would be classified as Level 2 in the fair value hierarchy.

The fair value of the Senior Notes uses pricing that is readily available in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 1 in the fair value hierarchy. The fair value of our capital leases and other obligations are determined using a discounted cash flow approach based on the interest rate and payment terms of the obligations and assumed discount rate. The fair values of the obligations could be significantly influenced by the discount rate assumptions, which is unobservable. Accordingly, the fair value of the capital leases and other obligations would be classified as Level 3 in the fair value hierarchy.

The carrying values of all classes of cash and cash equivalents, accounts receivables and accounts payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.

Other Fair Value Measurements

During the three months ended March 31, 2017 and 2016, we recorded other than temporary impairments of $1.5 million and $10.6 million, respectively, related to proved and unproved properties. We utilize quoted futures prices and other observable market data in determining the fair value. The inputs used in determining fair value as a part of the impairment expense calculation are considered to be Level 3 within the fair value hierarchy. For additional information on our impairment expense, see Note 15, Impairment Expense, to our Consolidated Financial Statements.

 

 

9. INCOME TAXES

We recognize deferred income taxes for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value.

Income tax included in continuing operations was as follows:

 

 

Three Months Ended March 31, 2017

 

($ in Thousands)

2017

 

 

2016

 

Income Tax Benefit

$

 

 

$

(2,715

)

Effective Tax Rate

 

0.0

%

 

 

-5.4

%

 

 

Management estimates the annual effective income tax rate quarterly, based on current annual forecasted results. Items unrelated to current year ordinary income are recognized entirely in the period identified as a discrete item of tax. The quarterly

21


 

income tax provision is comprised of tax on ordinary income provided at the most recent estimated annual effective tax rate, adjusted for the tax effect of these discrete items. The Company accounts for the tax effects of discontinued operations as a discrete item and therefore recognizes the full tax effects of discontinued operations in the same period that the pretax income or loss from discontinued operations is recognized. As a result of having a full valuation allowance on deferred taxes on the Company’s entire operations, this approach results in a tax benefit being recorded in continuing operations to offset the tax charge on the gain recorded in discontinued operations.

For the three months ended March 31, 2017, the estimated annual effective tax rate applied to ordinary losses from continuing operations was 0.0% due to the recording of full valuation allowances against the tax benefits generated by pretax losses, resulting in recognition of no tax benefit for the period. The estimated annual effective tax rate differs from the U.S. statutory rate of 35.0% primarily due to the effect of having full valuation allowances recorded against our deferred tax assets.     

For the three months ended March 31, 2016, the estimated annual effective tax rate applied to ordinary losses from continuing operations was -5.4%.  The estimated annual effective tax rate differs from the U.S. statutory rate of 35.0% primarily due to the effect of having full valuation allowances recorded against our deferred tax assets coupled with recognizing tax benefits in continuing operations for the effect of taxable income generated by our discontinued operations. To a lesser extent, the annual effective rate is also influenced by alternative minimum tax with no corresponding deferred tax benefit due to the full valuation allowance, and state taxes in certain tax paying jurisdictions.  The Company’s alternative minimum tax due for 2016 is driven primarily by cancellation of debt income of $543.2 million related to the Senior Note exchanges discussed in Note 7, Long-Term Debt, to our Consolidated Financial Statements. The Company recorded an expense for income taxes from continuing operations of $2.7 million, for federal and state income taxes for the three months ended March 31, 2016.

Income tax payments made during the three months ended March 31, 2017 and 2016 were negligible.  Tax refunds received during the three months ended March 31, 2017 were approximately $0.2 million, and refunds received during the three months ended March 31, 2016 were negligible.

 

10. CAPITAL STOCK

Common Stock

On May 27, 2016, the Company’s common shareholders approved an increase in the number of authorized shares from 100,000,000 to 200,000,000 common shares.  As of March 31, 2017, we have authorized capital stock of 200,000,000 shares of common stock and 100,000 shares of preferred stock. As of March 31, 2017 and December 31, 2016, shares of common stock issued and outstanding totaled 99,024,368 and 97,870,608, respectively.  During the three months ended March 31, 2017, we issued approximately 0.3 million shares of our common stock in conjunction with debt for equity exchanges completed with certain holders of our Senior Notes.  See Note 7, Long-Term Debt, to our Consolidated Financial Statements for additional information regarding our debt and equity exchanges.

Preferred Stock

As of March 31, 2017 and December 31, 2016, shares of our 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (“Series A Preferred Stock”), issued and outstanding totaled 3,987 and 3,987, respectively. During the three months ended March 31, 2016, 3,264 shares of Series A Preferred Stock were converted into approximately 1.8 million shares of common stock pursuant to the terms of the Series A Preferred Stock, and through negotiated exchanges with certain holders of the Series A Preferred Shares. See Note 13, Earnings Per Common Share, to our Consolidated Financial Statements, for additional information regarding the effect of the preferred stock conversions on Net Income (Loss) Attributable to Common Shareholders.

The annual dividend on each share of the Series A Preferred Stock is 6.0% per annum on the liquidation preference of $10,000 per share and is payable quarterly, in arrears, on February 15, May 15, August 15 and November 15 of each year.

We pay cumulative dividends, when and if declared, in cash, stock or a combination thereof, on a quarterly basis at a rate of $600 per share, or 6.0%, per year. Dividends that are not declared and paid in accordance with the quarterly schedule will accumulate from the most recent date upon which dividends were paid but will not bear interest. In February 2016, we suspended our quarterly dividend payment. No dividend was declared by our board of directors in 2016. As of March 31, 2017, accumulated dividends in arrears totaled $3.0 million.  While the accumulation does not result in the presentation of a liability on the Consolidated Balance Sheets, the accumulation of unpaid dividends during the current reporting period are included in our Net Income (Loss) in the determination of Net Income (Loss) Attributable to Common Shareholders and related earnings per share calculations.

If dividends are in arrears and unpaid for six or more quarterly periods (whether or not consecutive), the holders of the shares of Series A Preferred Stock will have the right to elect two additional directors to serve on our board of directors.

 

22


 

 

11. EMPLOYEE BENEFIT AND EQUITY PLANS

Equity Plans

We recognize all share-based payments to employees, including grants of employee stock options, in our Consolidated Statements of Operations based on their grant-date fair values, using prescribed option-pricing models where applicable. The fair value is expensed over the requisite service period of the individual grantees, which generally equals one vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as cash flows from financing activities, rather than as cash flows from operating activities.

Stock Options

During the three months ended March 31, 2017, no new options to purchase shares of our common stock were granted. During the three months ended March 31, 2016, we issued 851,422 options to purchase shares of our common stock to 29 employees.  Stock-based compensation expense from continuing operations relating to stock options outstanding for the three months ended March 31, 2017 was $0.1 million. Stock-based compensation expense from continuing operations relating to stock options outstanding for the three months ended March 31, 2016 was negligible. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative Expense. There were no stock options exercised during the three months ended March 31, 2017. There was no tax benefit related to stock option exercises for each of the three-month periods ended March 31, 2017 and 2016.

A summary of the status of our issued and outstanding stock options as of March 31, 2017 is as follows:

 

 

 

 

 

Outstanding

 

 

Exercisable

 

Exercise Price

 

 

Number Outstanding at March 31, 2017

 

 

Weighted-Average Exercise Price

 

 

Number Exercisable at March 31, 2017

 

 

Weighted-Average Exercise Price

 

$

0.97

 

 

 

27,500

 

 

$

0.97

 

 

 

 

 

$

0.97

 

$

1.69

 

 

 

753,428

 

 

$

1.69

 

 

 

251,135

 

 

$

1.69

 

$

4.05

 

 

 

40,000

 

 

$

4.05

 

 

 

 

 

$

4.05

 

$

4.90

 

 

 

40,000

 

 

$

4.90

 

 

 

6,666

 

 

$

4.90

 

$

5.04

 

 

 

46,041

 

 

$

5.04

 

 

 

46,041

 

 

$

5.04

 

$

9.50

 

 

 

75,000

 

 

$

9.50

 

 

 

75,000

 

 

$

9.50

 

$

9.99

 

 

 

129,583

 

 

$

9.99

 

 

 

129,583

 

 

$

9.99

 

$

10.42

 

 

 

29,548

 

 

$

10.42

 

 

 

29,548

 

 

$

10.42

 

$

22.34

 

 

 

30,000

 

 

$

22.34

 

 

 

30,000

 

 

$

22.34

 

 

 

 

 

 

1,171,100

 

 

$

4.16

 

 

 

567,973

 

 

$

6.47

 

The weighted average remaining contractual term for options outstanding at March 31, 2017 was 4.5 years and there was no aggregate intrinsic value. The weighted average remaining contractual term for options exercisable at March 31, 2017 was 3.2 years and there was no aggregate intrinsic value.  As of March 31, 2017, unrecognized compensation expense related to stock options was $0.2 million.  

Restricted Stock Awards

During the three-month period ended March 31, 2017, the Compensation Committee approved the issuance of an aggregate of 1,012,242 shares of restricted common stock to 28 employees. During the three-month period ended March 31, 2016, the Compensation Committee approved the issuance of an aggregate of 420,901 shares of restricted stock to 22 employees. Certain of our outstanding restricted stock awards granted in 2015 are subject to market-based vesting through a calculation of total shareholder return (“TSR”) of our common stock relative to a pre-defined peer group over a three-year period.

 

23


 

The weighted average fair value of the TSR awards granted as of December 31, 2015 was $2.56 per share. There have been no TSR awards granted subsequent to December 31, 2015.  Average fair values were estimated on the date of each grant using a Monte Carlo Simulation model that estimates the most likely outcome based on the terms of the award and used the following assumptions:

 

 

Year Ended December 31, 2015

 

Expected Dividend Yield

 

0.0

%

Risk-Free Interest Rate

 

1.0

%

Expected Volatility – Rex Energy

 

58.6

%

Expected Volatility – Peer Group

29.8%-85.0%

 

Market Index

 

35.6

%

Expected Life

Three Years

 

 

 

During the three months ended March 31, 2017, 179,519 performance stock awards were forfeited due to not meeting specified targets, which resulted in a net reversal of prior compensation expense of approximately $0.1 million for the quarter. Compensation expense from restricted stock awards associated with our continuing operations totaled $0.9 million and $1.8 million for the three months ended March 31, 2017 and 2016, respectively. During the first quarter of 2016, 235,573 performance stock awards were forfeited due to not meeting specified targets, which resulted in a net reversal of prior compensation expense of approximately $0.2 million for the quarter. As of March 31, 2017, total unrecognized compensation cost related to restricted common stock grants was approximately $1.4 million, which will be recognized over a weighted average period of 1.6 years.

 

A summary of the restricted stock activity for the three months ended March 31, 2017 is as follows: 

 

Number of Shares

 

 

Weighted-Average Grant Date Fair Value

 

Restricted stock awards, as of December 31, 2016

 

2,427,494

 

 

$

2.63

 

Awards

 

1,012,242

 

 

 

0.52

 

Forfeitures

 

(191,353

)

 

 

8.69

 

Vested

 

(384,236

)

 

 

2.13

 

Restricted stock awards, as of March 31, 2017

 

2,864,147

 

 

$

1.55

 

 

 

12. COMMITMENTS AND CONTINGENCIES

Legal Reserves

We are involved in various legal proceedings that arise in the ordinary course of our business. Although we cannot predict the outcome of these proceedings with certainty, we do not currently expect these matters to have a material adverse effect on our consolidated financial position or results of operations.

The accrual of reserves for legal matters is included in Accrued Liabilities on our Consolidated Balance Sheets. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we believe that these reserves are adequate, there are uncertainties associated with legal proceedings and we can give no assurance that our estimate of any related liability will not increase or decrease in the future. The reserved and unreserved exposures for our legal proceedings could change based upon developments in those proceedings or changes in the facts and circumstances. It is possible that we could incur losses in excess of the amounts currently accrued. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed our current accruals by an amount that would have a material adverse effect on our consolidated financial position, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.

Other than as set forth below, there have been no significant changes with respect to the legal matters disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016.  

In October 2011, we were named as defendants in a proposed class action lawsuit filed in the Court of Common Pleas of Clearfield County, Pennsylvania (the “Cardinale case”). The named plaintiffs are two individuals who have sued on behalf of themselves and all persons who are alleged to be similarly situated. The complaint in the Cardinale case generally asserts that a binding contract to lease oil and gas interests was formed between the Company and each proposed class member when representatives of Western Land Services, Inc. (“Western”), a leasing agent that we engaged, presented a form of proposed oil and gas lease and an order for payment to each person in 2008, and each person signed the proposed oil and gas lease form and order for payment and delivered the documents to representatives of Western. We rejected these leases and never signed them on behalf of the Company. The plaintiffs seek a judgment declaring the rights of the parties with respect to those proposed leases, as well as damages and other relief as may be established by plaintiffs at trial, together with interest, costs, expenses and attorneys’ fees. We filed

24


 

affirmative defenses and preliminary objections to the plaintiff’s claims, and the parties each made various responsive filings throughout the first quarter of 2012. In May 2012, the trial court dismissed the Cardinale case with prejudice on the grounds that there was no contract formed between us and the plaintiffs. The plaintiffs appealed the dismissal during the second half of 2012. In May 2013, the Superior Court reversed the decision of the Common Pleas Court and remanded the case for further proceedings.

In July 2012, while the Cardinale case was in the midst of the appeals process, counsel for the plaintiffs in the Cardinale case filed two additional lawsuits against us in the Court of Common Pleas of Clearfield County, Pennsylvania: one a proposed class action lawsuit with a different named plaintiff (the “Billotte case”) and another on behalf of a group of individually named plaintiffs (the “Meeker case”). The complaint for the Billotte case contained the same claims as those set forth in the Cardinale case. The Meeker case is not a class action, but the claims are similar to those in Cardinale and the plaintiffs would be included in a class under Cardinale and Billotte if one were certified. These two additional lawsuits were filed for procedural reasons in light of the dismissal of the Cardinale case and the pendency of the appeal. Proceedings in both the Billotte and Meeker cases were stayed pending the outcome of the appeal in the Cardinale case. When the Cardinale case was remanded, we agreed to consolidate the Billotte and Cardinale cases; the cases have proceeded as Cardinale. The Meeker case remains stayed, and has not been consolidated.

In June 2015, the trial court conducted a hearing on plaintiff’s motion for certification of a class in the Cardinale case.  In July 2015, the trial court denied plaintiffs’ motion for class certification.  Plaintiffs appealed the denial of class certification in September 2015.  In June 2016, the parties each presented arguments on the appeal before a three-judge panel of the Pennsylvania Superior Court (the “Superior Court”). In January 2017, the three-judge panel vacated the trial court’s denial of class certification and remanded the case to the trial court. We promptly applied for reconsideration or reargument with the entire Superior Court (en banc); however, that application was denied in March 2017.  In April 2017, we petitioned the Pennsylvania Supreme Court for an allowance of appeal to appeal the Superior Court’s decision.  As of the date of this filing, we have not received notice as to whether the Pennsylvania Supreme Court will allow the appeal.

We continue to vigorously defend against each of these claims. At this time we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses, if any.

Environmental

Due to the nature of the oil and natural gas business, we are exposed to possible environmental risks. We have implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. We conduct periodic reviews of our policies and properties to identify changes in the environmental risk profile. In these reviews we evaluate whether there is a probable liability, its amount and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort.

We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. As of March 31, 2017, we know of no significant probable or possible environmental contingent liabilities.

Letters of Credit

As of March 31, 2017, we have posted $46.3 million in various letters of credit to secure our drilling and related operations.

Lease Commitments

As of March 31, 2017, we have lease commitments for various real estate leases. Rent expense is recognized on a straight-line basis and has been recorded in General and Administrative expense on our Consolidated Statements of Operations. Rent expense for the three months ended March 31, 2017 and 2016, was approximately $0.2 million and $0.3 million, respectively. Lease commitments by year for each of the next five years are presented in the table below:

($ in Thousands)

 

 

 

 

2017

 

$

749

 

2018

 

 

565

 

2019

 

 

563

 

2020

 

 

422

 

2021

 

 

 

Thereafter

 

 

 

Total

 

$

2,299

 

 

25


 

Capacity Reservation

We have a capacity reservation arrangement with a subsidiary of MarkWest Energy Partners, L.P. (“MarkWest”) to ensure sufficient capacity at the cryogenic gas processing plants owned by MarkWest in Butler County, Pennsylvania to process our produced natural gas. In the event that we do not utilize the plants to process quantities of gas sufficient to meet specified volume commitments, we may be obligated to pay approximately $14.1 million in 2017, $16.3 million in 2018, $16.3 million in 2019, $16.4 million in 2020, $16.3 million in 2021 and $80.4 million thereafter, assuming our average net revenue interest in the region of approximately 52%. Charges incurred for unutilized processing capacity with MarkWest during the three months ended March 31, 2017 and 2016 were $1.6 million and $0.6 million, respectively.

Operational Commitments

We have contracted drilling rig services for one rig to support our Appalachian Basin operations. The minimum cost to retain the rig would require gross payments of approximately $2.1 million in 2017 and $1.8 million in 2018, which would be partially offset by other working interest owners, which vary from well to well. We also have agreements for contracted completion services in the Appalachian Basin. The minimum gross cost to retain the completion services is approximately $0.5 million in 2017, which would be partially offset by other working interest owners, which vary from well to well.

Natural Gas Gathering, Processing and Sales Agreements

During the normal course of business, we have entered into certain agreements to ensure the gathering, transportation, processing and sales of specified quantities of our natural gas, NGLs and condensate. In some instances, we are obligated to pay shortfall fees, whereby we would pay a fee for any difference between actual volumes provided as compared to volumes that have been committed. In other instances, we are obligated to pay a fee on all volumes that are subject to the related agreement. In connection with our entry into certain of these agreements, we concurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $396.7 million through 2029.

For the three months ended March 31, 2017 and 2016, we incurred expenses related to the transportation, processing and marketing of our natural gas, condensate and NGLs of approximately $26.3 million and $21.5 million, respectively.  Expense related to these agreements makes up a substantial portion of our Lease Operating Expense, which we expect to continue as existing agreements commence and new transportation, processing and marketing agreements are entered that will enable us to sell our product. During the three months ended March 31, 2017 and 2016, we incurred approximately $0.7 million and $0.4 million, respectively, in fees related to unutilized capacity commitments. The unutilized commitment fees are related to undeveloped properties that we acquired during 2014. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows:

 

($ in Thousands)

 

 

 

 

2017

 

$

32,822

 

2018

 

 

47,350

 

2019

 

 

47,522

 

2020

 

 

46,226

 

2021

 

 

43,285

 

Thereafter

 

 

479,768

 

Total

 

$

696,973

 

Pennsylvania Impact Fee

In 2012, Pennsylvania instituted a natural gas impact fee on producers of unconventional natural gas. The fee is imposed on every producer of unconventional gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. The fee for each unconventional gas well is determined using the following matrix, with vertical unconventional gas wells being charged 20% of the applicable rates:

 

 

<$2.25(a)

 

 

$2.26 - $2.99(a)

 

 

$3.00 - $4.99(a)

 

 

$5.00 - $5.99(a)

 

 

>$5.99(a)

 

Year One

$

40,200

 

 

$

45,300

 

 

$

50,300

 

 

$

55,300

 

 

$

60,400

 

Year Two

$

30,200

 

 

$

35,200

 

 

$

40,200

 

 

$

45,300

 

 

$

55,300

 

Year Three

$

25,200

 

 

$

30,200

 

 

$

30,200

 

 

$

40,200

 

 

$

50,300

 

Year 4 – 10

$

10,100

 

 

$

15,100

 

 

$

20,100

 

 

$

20,100

 

 

$

20,100

 

Year 11 – 15

$

5,000

 

 

$

5,000

 

 

$

10,100

 

 

$

10,100

 

 

$

10,100

 

(a) Pricing utilized for determining annual fee is based on the arithmetic mean of the NYMEX settled price for the near-month contract as reported by the Wall Street Journal for the last trading day of each month of a calendar year for the 12-month period ending December 31.

26


 

All fees owed are due on April 1 of each year. For the three months ended March 31, 2017 and 2016, we recorded expense of approximately $0.8 million and $0.5 million, respectively. We record expenses related to the impact fees as Production and Lease Operating Expense. As of March 31, 2017, approximately $1.1 million was accrued for the 2016 impact fees and a portion of 2017 impact fees.

 

13. EARNINGS PER COMMON SHARE

Basic income (loss) per common share is calculated based on the weighted average number of common shares outstanding at the end of the period, excluding restricted stock with performance-based and market-based vesting criteria. Diluted income per common share includes the speculative exercise of stock options and performance-based restricted stock which contain conditions that are not earnings or market-based, given that the hypothetical effect is not anti-dilutive. For the three months ended March 31, 2017,, we excluded stock options to purchase 1.2 million shares of our common stock, due to exercise price of all exercisable outstanding options exceeding the average market price of our common shares during the period. For the three months ended March 31, 2016, we excluded stock options to purchase 1.3 million shares of our common stock, due to our Net Loss from Continuing Operations. For the three months ended March 31, 2017 and 2016, we excluded performance-based restricted stock of 0.4 million shares and 0.7 million shares, respectively, due to performance metrics that have not yet been attained (for additional information on our non-cash compensation plans, see Note 11, Employee Benefit and Equity Plans, to our Consolidated Financial Statements). We utilize the if-converted method for calculating the impact of our 6.0% Convertible Perpetual Preferred Stock on diluted earnings per share. Under the if-converted method, convertible preferred stock is assumed as converted to common shares for the weighted average period outstanding. For the three months ended March 31, 2017, we excluded the assumed conversion of preferred stock equating to approximately 2.2 million shares due to the antidilutive effect caused by the assumed conversion. During the three months ended March 31, 2016, we excluded the assumed conversion of preferred stock equating to approximately 7.1 million shares, due to our Net Loss from Continuing Operations. The following table sets forth the computation of basic and diluted earnings per common share:

 

(in thousands, except per share amounts)

Three Months Ended March 31,

 

Numerator:

2017

 

 

2016

 

Net Income (Loss) From Continuing Operations

$

2,683

 

 

$

(52,651

)

Net Loss From Discontinued Operations

 

 

 

 

(7,490

)

Less: Preferred Stock Dividends

 

(598

)

 

 

(2,105

)

Net Income (Loss) Attributable to Common Shareholders

$

2,085

 

 

$

(62,246

)

Denominator:

 

 

 

 

 

 

 

Weighted Average Common Shares Outstanding - Basic

 

97,687

 

 

 

56,003

 

Effect of Dilutive Securities:

 

 

 

 

 

 

 

Employee Stock Options

 

 

 

 

 

Employee Performance-Based Restricted Stock Awards

 

 

 

 

 

Effect of Assumed Conversions of Preferred Stock

 

 

 

 

 

Weighted Average Common Shares Outstanding - Diluted

 

97,687

 

 

 

56,003

 

Earnings per Common Share Attributable to Rex Energy Common Shareholders:

 

 

 

 

 

 

 

Basic  —  Net Income (Loss) From Continuing Operations

$

0.02

 

 

$

(0.98

)

—  Net Loss From Discontinued Operations

 

 

 

 

(0.13

)

—  Net Income (Loss) Attributable to Common Shareholders

$

0.02

 

 

$

(1.11

)

Diluted  —  Net Income (Loss) From Discontinued Operations

$

0.02

 

 

$

(0.98

)

—  Net Loss From Discontinued Operations

 

 

 

 

(0.13

)

—  Net Income (Loss) Attributable to Common Shareholders

$

0.02

 

 

$

(1.11

)

 

 

 

14. EQUITY METHOD INVESTMENTS

RW Gathering, LLC

We own a 40% non-operated interest in RW Gathering, LLC (“RW Gathering”), which owns gas-gathering assets to facilitate development in our natural gas operations. We did not make any capital contributions to RW Gathering during the first three months of 2017 and 2016.  RW Gathering recorded net losses from continuing operations of $0.5 million during each of the three months ended March 31, 2017 and 2016. The losses incurred were due to insurance fees, bank fees, rent expenses and depreciation expense. Historically, we recorded our share of the net losses on the Statements of Operations as Loss on Equity Method Investments. As of June 30, 2015, we discontinued applying the equity method of accounting for our share of net losses due to our investment being reduced to zero.

During the three months ended March 31, 2017 and 2016, we incurred approximately $0.2 million in compression expenses that were charged to us from Williams Production Appalachia, LLC. These costs are in relation to compression costs incurred by RW

27


 

Gathering and are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of March 31, 2017 and December 31, 2016, there were no receivables or payables due between RW Gathering and us.

15. IMPAIRMENT EXPENSE

For the three months ended March 31, 2017 and 2016, impairment expenses for continuing operations incurred were approximately $1.5 million and $10.6 million, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment. The expense incurred during the three months ended March 31, 2017 included approximately $0.8 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which are in Butler County, Pennsylvania, and Warrior North in Ohio.  Impairments of unconventional proved properties in our Butler County operations totaled approximately $0.7 million during the first three months of 2017. The impairments were identified through an analysis of market conditions and future development plans that were in existence as of each period end, related to these properties, which indicated that the carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets and future development plans.  Our estimates of future cash flows attributable to our properties could decline if commodity prices decline, which may result in our incurrence of additional impairment expense. As of March 31, 2017, we continued to carry the costs of undeveloped properties of approximately $207.8 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale and for which we have development, trade or lease extension plans.

The expense incurred during the first three months of 2016 included proved properties of approximately $10.6 million in impairment related to undeveloped leases that expired or are expected to expire without being developed, the majority of which are in Butler County, Pennsylvania and Warrior North in Ohio.

16. EXPLORATION EXPENSE

For the three months ended March 31, 2017 and 2016, exploration expenses for continuing operations incurred were approximately $0.2 million and $0.9 million, respectively. Approximately $0.1 million of the expense incurred in 2017 was due to geological and geophysical type expenditures and the remaining $0.1 million was due to delay rentals. Approximately $0.8 million of the expense incurred in 2016 was due to two exploratory wells that were abandoned at various stages, resulting in dry hole expense and the remaining 2016 expense of $0.1 million was due to geological and geophysical type expenditures.  

 

17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

As of March 31, 2017, we had $600.7 million aggregate principal amount of outstanding Senior Notes, as shown in Note 7, Long-Term Debt, to our Consolidated Financial Statements. The Senior Notes are guaranteed by certain of our wholly-owned subsidiaries, or guarantor subsidiaries. Unless otherwise noted below, each of the following guarantor subsidiaries are wholly-owned by Rex Energy Corporation and have provided guarantees of the Senior Notes that are joint and several and full and unconditional as of March 31, 2017:

Rex Energy I, LLC

Rex Energy Operating Corporation

Rex Energy IV, LLC

PennTex Resources Illinois, Inc.

R.E. Gas Development, LLC

The non-guarantor subsidiaries include certain consolidated subsidiaries, including R.E. Disposal, LLC, Rex Energy Marketing, LLC and R.E. Ventures Holdings, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of March 31, 2017, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries.

The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of March 31, 2017 and December 31, 2016, the condensed consolidating statements of operations for the three-month periods ended March 31, 2017 and 2016, and the condensed consolidating statements of cash flows for the three-month periods ended March 31, 2017 and 2016.

28


 

 

 

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

AS OF MARCH 31, 2017

($ in Thousands)

 

 

Guarantor Subsidiaries

 

 

Non-

Guarantor Subsidiaries

 

 

Rex Energy Corporation (Note Issuer)

 

 

Eliminations

 

 

Consolidated Balance

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and Cash Equivalents

$

5,072

 

 

$

 

 

$

3

 

 

$

 

 

$

5,075

 

Accounts Receivable

 

25,264

 

 

 

 

 

 

 

 

 

 

 

 

25,264

 

Taxes Receivable

 

 

 

 

 

 

 

48

 

 

 

 

 

 

48

 

Short-Term Derivative Instruments

 

2,875

 

 

 

 

 

 

555

 

 

 

 

 

 

3,430

 

Inventory, Prepaid Expenses and Other

 

2,112

 

 

 

 

 

 

12

 

 

 

 

 

 

2,124

 

Total Current Assets

 

35,323

 

 

 

 

 

 

618

 

 

 

 

 

 

35,941

 

Property and Equipment (Successful Efforts Method)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Evaluated Oil and Gas Properties

 

963,481

 

 

 

 

 

 

 

 

 

 

 

 

963,481

 

Unevaluated Oil and Gas Properties

 

207,821

 

 

 

 

 

 

 

 

 

 

 

 

207,821

 

Other Property and Equipment

 

21,863

 

 

 

 

 

 

 

 

 

 

 

 

21,863

 

Wells and Facilities in Progress

 

40,740

 

 

 

 

 

 

 

 

 

 

 

 

40,740

 

Pipelines

 

21,262

 

 

 

 

 

 

 

 

 

 

 

 

21,262

 

Total Property and Equipment

 

1,255,167

 

 

 

 

 

 

 

 

 

 

 

 

1,255,167

 

Less: Accumulated Depreciation, Depletion and Amortization

 

(419,500

)

 

 

 

 

 

 

 

 

 

 

 

(419,500

)

Net Property and Equipment

 

835,667

 

 

 

 

 

 

 

 

 

 

 

 

835,667

 

Other Assets

 

2,495

 

 

 

 

 

 

 

 

 

 

 

 

2,495

 

Intercompany Receivables

 

 

 

 

 

 

 

1,027,360

 

 

 

(1,027,360

)

 

 

 

Investment in Subsidiaries – Net

 

(2,484

)

 

 

 

 

 

(272,261

)

 

 

274,745

 

 

 

 

Long-Term Derivative Instruments

 

2,329

 

 

 

 

 

 

963

 

 

 

 

 

 

3,292

 

Total Assets

$

873,330

 

 

$

 

 

$

756,680

 

 

$

(752,615

)

 

$

877,395

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts Payable

$

36,838

 

 

$

 

 

$

 

 

$

 

 

$

36,838

 

Current Maturities of Long-Term Debt

 

801

 

 

 

 

 

 

 

 

 

 

 

 

801

 

Accrued Liabilities

 

25,311

 

 

 

421

 

 

 

6,190

 

 

 

 

 

 

31,922

 

Short-Term Derivative Instruments

 

12,801

 

 

 

 

 

 

 

 

 

 

 

 

12,801

 

Total Current Liabilities

 

75,751

 

 

 

421

 

 

 

6,190

 

 

 

 

 

 

82,362

 

Long-Term Derivative Instruments

 

10,265

 

 

 

 

 

 

 

 

 

 

 

 

10,265

 

Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs

 

 

 

 

 

 

 

106,573

 

 

 

 

 

 

106,573

 

Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges

 

 

 

 

 

 

 

650,758

 

 

 

 

 

 

650,758

 

Discount on Senior Notes, Net

 

 

 

 

 

 

 

(7,389

)

 

 

 

 

 

(7,389

)

Other Long-Term Debt

 

3,849

 

 

 

 

 

 

 

 

 

 

 

 

3,849

 

Other Deposits and Liabilities

 

8,262

 

 

 

 

 

 

 

 

 

 

 

 

8,262

 

Future Abandonment Cost

 

9,465

 

 

 

 

 

 

 

 

 

 

 

 

9,465

 

Intercompany Payables

 

1,023,697

 

 

 

3,663

 

 

 

 

 

 

(1,027,360

)

 

 

 

Total Liabilities

 

1,131,289

 

 

 

4,084

 

 

 

756,132

 

 

 

(1,027,360

)

 

 

864,145

 

Stockholders’ Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Preferred Stock

 

 

 

 

 

 

 

1

 

 

 

 

 

 

1

 

Common Stock

 

 

 

 

 

 

 

96

 

 

 

 

 

 

96

 

Additional Paid-In Capital

 

177,144

 

 

 

 

 

 

650,924

 

 

 

(177,144

)

 

 

650,924

 

Accumulated Deficit

 

(435,103

)

 

 

(4,084

)

 

 

(650,473

)

 

 

451,889

 

 

 

(637,771

)

Total Stockholders’ Equity

 

(257,959

)

 

 

(4,084

)

 

 

548

 

 

 

274,745

 

 

 

13,250

 

Total Liabilities and Stockholders’ Equity

$

873,330

 

 

$

 

 

$

756,680

 

 

$

(752,615

)

 

$

877,395

 

 

29


 

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31, 2017

($ in Thousands)

 

 

Guarantor Subsidiaries

 

 

Non-Guarantor Subsidiaries

 

 

Rex Energy Corporation (Note Issuer)

 

 

Eliminations

 

 

Consolidated Balance

 

OPERATING REVENUE

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas, NGL and Condensate Sales

$

52,065

 

 

$

 

 

$

 

 

$

 

 

$

52,065

 

Other Operating Revenue

 

6

 

 

 

 

 

 

 

 

 

 

 

 

6

 

TOTAL OPERATING REVENUE

 

52,071

 

 

 

 

 

 

 

 

 

 

 

 

52,071

 

OPERATING EXPENSES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production and Lease Operating Expense

 

28,934

 

 

 

 

 

 

 

 

 

 

 

 

28,934

 

General and Administrative Expense

 

4,461

 

 

 

 

 

 

73

 

 

 

 

 

 

4,534

 

Gain on Disposal of Assets

 

(1,834

)

 

 

 

 

 

 

 

 

 

 

 

(1,834

)

Impairment Expense

 

1,546

 

 

 

 

 

 

 

 

 

 

 

 

1,546

 

Exploration Expense

 

220

 

 

 

 

 

 

 

 

 

 

 

 

220

 

Depreciation, Depletion, Amortization and Accretion

 

15,468

 

 

 

 

 

 

 

 

 

 

 

 

15,468

 

Other Operating Expense

 

(21

)

 

 

 

 

 

 

 

 

 

 

 

(21

)

TOTAL OPERATING EXPENSES

 

48,774

 

 

 

 

 

 

73

 

 

 

 

 

 

48,847

 

INCOME (LOSS) FROM OPERATIONS

 

3,297

 

 

 

 

 

 

(73

)

 

 

 

 

 

3,224

 

OTHER INCOME (EXPENSE)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense

 

(365

)

 

 

 

 

 

(8,778

)

 

 

 

 

 

(9,143

)

Gain (Loss) on Derivatives, Net

 

9,798

 

 

 

 

 

 

(1,417

)

 

 

 

 

 

8,381

 

Other Expense

 

(28

)

 

 

 

 

 

 

 

 

 

 

 

(28

)

Gain on Extinguishment of Debt

 

 

 

 

 

 

 

249

 

 

 

 

 

 

249

 

Income From Equity in Consolidated Subsidiaries

 

 

 

 

 

 

 

12,702

 

 

 

(12,702

)

 

 

 

TOTAL OTHER INCOME (EXPENSE)

 

9,405

 

 

 

 

 

 

2,756

 

 

 

(12,702

)

 

 

(541

)

INCOME BEFORE INCOME TAX

 

12,702

 

 

 

 

 

 

2,683

 

 

 

(12,702

)

 

 

2,683

 

Income Tax Expense

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NET INCOME ATTRIBUTABLE TO REX ENERGY

$

12,702

 

 

$

 

 

$

2,683

 

 

$

(12,702

)

 

$

2,683

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

30


 

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

FOR THE THREE MONTHS ENDED MARCH 31, 2017

($ in Thousands)

 

 

Guarantor Subsidiaries

 

 

Non-Guarantor Subsidiaries

 

 

Rex Energy Corporation (Note Issuer)

 

 

Eliminations

 

 

Consolidated Balance

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income

$

12,702

 

 

$

 

 

$

2,683

 

 

$

(12,702

)

 

$

2,683

 

Adjustments to Reconcile Net Income to Net Cash Provided

      by Operating Activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation, Depletion, Amortization and Accretion

 

15,468

 

 

 

 

 

 

 

 

 

 

 

 

15,468

 

(Gain) Loss on Derivatives

 

(9,798

)

 

 

 

 

 

1,417

 

 

 

 

 

 

(8,381

)

Cash Settlements of Derivatives

 

(3,443

)

 

 

 

 

 

 

 

 

 

 

 

(3,443

)

Equity-based Compensation Expense

 

11

 

 

 

 

 

 

60

 

 

 

 

 

 

71

 

Non-cash Exploration Expense

 

11

 

 

 

 

 

 

 

 

 

 

 

 

11

 

Gain on Disposal of Assets

 

(1,834

)

 

 

 

 

 

 

 

 

 

 

 

(1,834

)

Gain on Extinguishment Debt

 

 

 

 

 

 

 

(249

)

 

 

 

 

 

(249

)

Non-cash Interest Expense related to Debt Restructurings

    and Exchanges

 

 

 

 

 

 

 

6,081

 

 

 

 

 

 

6,081

 

Impairment Expense

 

1,546

 

 

 

 

 

 

 

 

 

 

 

 

1,546

 

Other Non-cash Income

 

(66

)

 

 

 

 

 

 

 

 

 

 

 

(66

)

Changes in operating assets and liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts Receivable

 

5,174

 

 

 

 

 

 

167

 

 

 

 

 

 

5,341

 

Inventory, Prepaid Expenses and Other Assets

 

410

 

 

 

 

 

 

12

 

 

 

 

 

 

422

 

Accounts Payable and Accrued Liabilities

 

(8,298

)

 

 

 

 

 

1,309

 

 

 

 

 

 

(6,989

)

Other Assets and Liabilities

 

(139

)

 

 

 

 

 

 

 

 

 

 

 

(139

)

NET CASH PROVIDED BY OPERATING ACTIVITIES

 

11,744

 

 

 

 

 

 

11,480

 

 

 

(12,702

)

 

 

10,522

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Intercompany loans to subsidiaries

 

(8,789

)

 

 

 

 

 

(3,913

)

 

 

12,702

 

 

 

 

Proceeds from the Sale of Oil and Gas Properties, Prospects

     and Other Assets

 

24,329

 

 

 

 

 

 

 

 

 

 

 

 

24,329

 

Acquisitions of Undeveloped Acreage

 

(299

)

 

 

 

 

 

 

 

 

 

 

 

(299

)

Capital Expenditures for Development of Oil and Gas

     Properties and Equipment

 

(25,476

)

 

 

 

 

 

 

 

 

 

 

 

(25,476

)

NET CASH USED IN INVESTING ACTIVITIES

 

(10,235

)

 

 

 

 

 

(3,913

)

 

 

12,702

 

 

 

(1,446

)

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proceeds from Long-Term Debt and Lines of Credit

 

 

 

 

 

 

 

21,500

 

 

 

 

 

 

21,500

 

Repayments of Long-Term Debt and Lines of Credit

 

 

 

 

 

 

 

(28,500

)

 

 

 

 

 

(28,500

)

Repayments of Loans and Other Long-Term Debt

 

(131

)

 

 

 

 

 

 

 

 

 

 

 

(131

)

Debt Issuance Costs

 

 

 

 

 

 

 

(567

)

 

 

 

 

 

(567

)

NET CASH USED IN FINANCING ACTIVITIES

 

(131

)

 

 

 

 

 

(7,567

)

 

 

 

 

 

(7,698

)

NET INCREASE IN CASH

 

1,378

 

 

 

 

 

 

 

 

 

 

 

 

1,378

 

CASH – BEGINNING

 

3,694

 

 

 

 

 

 

3

 

 

 

 

 

 

3,697

 

CASH - ENDING

$

5,072

 

 

$

 

 

$

3

 

 

$

 

 

$

5,075

 

31


 

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

AS OF DECEMBER 31, 2016

($ in Thousands)

 

 

Guarantor Subsidiaries

 

 

Non-Guarantor Subsidiaries

 

 

Rex Energy Corporation (Note Issuer)

 

 

Eliminations

 

 

Consolidated Balance

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and Cash Equivalents

$

3,694

 

 

$

 

 

$

3

 

 

$

 

 

$

3,697

 

Accounts Receivable

 

22,609

 

 

 

 

 

 

2,839

 

 

 

 

 

 

25,448

 

Taxes Receivable

 

 

 

 

 

 

 

211

 

 

 

 

 

 

211

 

Short-Term Derivative Instruments

 

650

 

 

 

 

 

 

1,223

 

 

 

 

 

 

1,873

 

Inventory, Prepaid Expenses and Other

 

2,521

 

 

 

 

 

 

25

 

 

 

 

 

 

2,546

 

Total Current Assets

 

29,474

 

 

 

 

 

 

4,301

 

 

 

 

 

 

33,775

 

Property and Equipment (Successful Efforts Method)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Evaluated Oil and Gas Properties

 

1,053,461

 

 

 

 

 

 

 

 

 

 

 

 

1,053,461

 

Unevaluated Oil and Gas Properties

 

215,794

 

 

 

 

 

 

 

 

 

 

 

 

215,794

 

Other Property and Equipment

 

21,401

 

 

 

 

 

 

 

 

 

 

 

 

21,401

 

Wells and Facilities in Progress

 

21,964

 

 

 

 

 

 

 

 

 

 

 

 

21,964

 

Pipelines

 

18,029

 

 

 

 

 

 

 

 

 

 

 

 

18,029

 

Total Property and Equipment

 

1,330,649

 

 

 

 

 

 

 

 

 

 

 

 

1,330,649

 

Less: Accumulated Depreciation, Depletion and Amortization

 

(475,205

)

 

 

 

 

 

 

 

 

 

 

 

(475,205

)

Net Property and Equipment

 

855,444

 

 

 

 

 

 

 

 

 

 

 

 

855,444

 

Other Assets

 

2,492

 

 

 

 

 

 

 

 

 

 

 

 

2,492

 

Intercompany Receivables

 

 

 

 

 

 

 

1,035,713

 

 

 

(1,035,713

)

 

 

 

Investment in Subsidiaries – Net

 

(2,388

)

 

 

 

 

 

(127,974

)

 

 

130,362

 

 

 

 

Long-Term Derivative Instruments

 

500

 

 

 

 

 

 

1,712

 

 

 

 

 

 

2,212

 

Total Assets

$

885,522

 

 

$

 

 

$

913,752

 

 

$

(905,351

)

 

$

893,923

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts Payable

$

40,712

 

 

$

 

 

$

 

 

$

 

 

$

40,712

 

Current Maturities of Long-Term Debt

 

764

 

 

 

 

 

 

 

 

 

 

 

 

764

 

Accrued Liabilities

 

32,328

 

 

 

421

 

 

 

4,458

 

 

 

 

 

 

37,207

 

Short-Term Derivative Instruments

 

25,025

 

 

 

 

 

 

 

 

 

 

 

 

25,025

 

Total Current Liabilities

 

98,829

 

 

 

421

 

 

 

4,458

 

 

 

 

 

 

103,708

 

Long-Term Derivative Instruments

 

7,227

 

 

 

 

 

 

 

 

 

 

 

 

7,227

 

Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs

 

 

 

 

 

 

 

113,785

 

 

 

 

 

 

113,785

 

Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges

 

 

 

 

 

 

 

641,762

 

 

 

 

 

 

641,762

 

Discount on Senior Notes – Net

 

 

 

 

 

 

 

(3,601

)

 

 

 

 

 

(3,601

)

Other Long-Term Debt

 

3,409

 

 

 

 

 

 

 

 

 

 

 

 

3,409

 

Other Deposits and Liabilities

 

8,671

 

 

 

 

 

 

 

 

 

 

 

 

8,671

 

Future Abandonment Cost

 

8,736

 

 

 

 

 

 

 

 

 

 

 

 

8,736

 

Intercompany Payables

 

1,032,050

 

 

 

3,663

 

 

 

 

 

 

(1,035,713

)

 

 

 

Total Liabilities

 

1,158,922

 

 

 

4,084

 

 

 

756,404

 

 

 

(1,035,713

)

 

 

883,697

 

Stockholders’ Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Preferred Stock

 

 

 

 

 

 

 

1

 

 

 

 

 

 

1

 

Common Stock

 

 

 

 

 

 

 

95

 

 

 

 

 

 

95

 

Additional Paid-In Capital

 

177,144

 

 

 

 

 

 

650,584

 

 

 

(177,144

)

 

 

650,584

 

Accumulated Deficit

 

(450,544

)

 

 

(4,084

)

 

 

(493,332

)

 

 

307,506

 

 

 

(640,454

)

Total Stockholders’ Equity

 

(273,400

)

 

 

(4,084

)

 

 

157,348

 

 

 

130,362

 

 

 

10,226

 

Total Liabilities and Stockholders’ Equity

$

885,522

 

 

$

 

 

$

913,752

 

 

$

(905,351

)

 

$

893,923

 

32


 

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED March 31, 2016  

($ in Thousands)

 

 

Guarantor Subsidiaries

 

 

Non-Guarantor Subsidiaries

 

 

Rex Energy Corporation (Note Issuer)

 

 

Eliminations

 

 

Consolidated Balance

 

OPERATING REVENUE

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas, NGL and Condensate Sales

$

25,673

 

 

$

 

 

$

 

 

$

 

 

$

25,673

 

Other Operating Revenue

 

13

 

 

 

 

 

 

 

 

 

 

 

 

13

 

TOTAL OPERATING REVENUE

 

25,686

 

 

 

 

 

 

 

 

 

 

 

 

25,686

 

OPERATING EXPENSES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production and Lease Operating Expense

 

24,451

 

 

 

 

 

 

 

 

 

 

 

 

24,451

 

General and Administrative Expense

 

5,299

 

 

 

 

 

 

(15

)

 

 

 

 

 

5,284

 

Loss on Disposal of Assets

 

11

 

 

 

 

 

 

 

 

 

 

 

 

11

 

Impairment Expense

 

10,641

 

 

 

 

 

 

 

 

 

 

 

 

10,641

 

Exploration Expense

 

936

 

 

 

 

 

 

 

 

 

 

 

 

936

 

Depreciation, Depletion, Amortization and Accretion

 

16,501

 

 

 

10

 

 

 

 

 

 

 

 

 

16,511

 

Other Operating Expense

 

327

 

 

 

 

 

 

 

 

 

 

 

 

327

 

TOTAL OPERATING EXPENSES

 

58,166

 

 

 

10

 

 

 

(15

)

 

 

 

 

 

58,161

 

INCOME (LOSS) FROM OPERATIONS

 

(32,480

)

 

 

(10

)

 

 

15

 

 

 

 

 

 

(32,475

)

OTHER INCOME (EXPENSE)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense

 

(270

)

 

 

 

 

 

(12,760

)

 

 

 

 

 

(13,030

)

Gain on Derivatives, Net

 

4,049

 

 

 

 

 

 

 

 

 

 

 

 

4,049

 

Debt Exchange Expense

 

 

 

 

 

 

 

(8,480

)

 

 

 

 

 

(8,480

)

Loss From Equity in Consolidated Subsidiaries

 

(8

)

 

 

 

 

 

(38,151

)

 

 

38,159

 

 

 

 

TOTAL OTHER INCOME (EXPENSE)

 

3,771

 

 

 

 

 

 

(59,391

)

 

 

38,159

 

 

 

(17,461

)

LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX

 

(28,709

)

 

 

(10

)

 

 

(59,376

)

 

 

38,159

 

 

 

(49,936

)

Income Tax Expense

 

(1,950

)

 

 

 

 

 

(765

)

 

 

 

 

 

(2,715

)

LOSS FROM CONTINUING OPERATIONS

 

(30,659

)

 

 

(10

)

 

 

(60,141

)

 

 

38,159

 

 

 

(52,651

)

Income (Loss) From Discontinued Operations, Net of Income Tax

 

(7,492

)

 

 

2

 

 

 

 

 

 

 

 

 

(7,490

)

NET LOSS

 

(38,151

)

 

 

(8

)

 

 

(60,141

)

 

 

38,159

 

 

 

(60,141

)

Preferred Stock Dividends

 

 

 

 

 

 

 

(2,105

)

 

 

 

 

 

(2,105

)

NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS

$

(38,151

)

 

$

(8

)

 

$

(62,246

)

 

$

38,159

 

 

$

(62,246

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

33


 

 

 

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

FOR THE THREE MONTHS ENDED MARCH 31, 2016

($ in Thousands)

 

 

Guarantor Subsidiaries

 

 

Non-Guarantor Subsidiaries

 

 

Rex Energy Corporation (Note Issuer)

 

 

Eliminations

 

 

Consolidated Balance

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Loss

$

(38,151

)

 

$

(8

)

 

$

(60,141

)

 

$

38,159

 

 

$

(60,141

)

Adjustments to Reconcile Net Loss to Net Cash Provided by

   Operating Activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation, Depletion, Amortization and Accretion

 

19,379

 

 

 

29

 

 

 

 

 

 

 

 

 

19,408

 

Gain on Derivatives, Net

 

(4,049

)

 

 

 

 

 

 

 

 

 

 

 

(4,049

)

Cash Settlements of Derivatives

 

12,994

 

 

 

 

 

 

 

 

 

 

 

 

12,994

 

Equity-based Compensation Expense

 

6

 

 

 

 

 

 

(27

)

 

 

 

 

 

(21

)

Non-cash Exploration Expense

 

843

 

 

 

 

 

 

 

 

 

 

 

 

843

 

Gain on Disposal of Assets

 

(30

)

 

 

 

 

 

 

 

 

 

 

 

(30

)

Amortization of net Bond Discount and Deferred Financing Costs

 

 

 

 

 

 

 

547

 

 

 

 

 

 

547

 

Deferred Income Tax Expense

 

1,326

 

 

 

1

 

 

 

765

 

 

 

 

 

 

2,092

 

Impairment Expense

 

14,184

 

 

 

 

 

 

14,184

 

 

 

(14,184

)

 

 

14,184

 

Other Non-cash Income

 

(29

)

 

 

 

 

 

 

 

 

 

 

 

(29

)

Changes in operating assets and liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts Receivable

 

15,852

 

 

 

10

 

 

 

(20,735

)

 

 

 

 

 

(4,873

)

Inventory, Prepaid Expenses and Other Assets

 

648

 

 

 

 

 

 

12

 

 

 

 

 

 

660

 

Accounts Payable and Accrued Liabilities

 

1,921

 

 

 

21

 

 

 

(2,250

)

 

 

 

 

 

(308

)

Other Assets and Liabilities

 

(170

)

 

 

 

 

 

 

 

 

 

 

 

(170

)

NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES

 

24,724

 

 

 

53

 

 

 

(67,645

)

 

 

23,975

 

 

 

(18,893

)

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Intercompany loans to subsidiaries

 

29

 

 

 

(21

)

 

 

23,967

 

 

 

(23,975

)

 

 

 

Proceeds from the Sale of Oil and Gas Properties, Prospects

    and Other Assets

 

71

 

 

 

 

 

 

 

 

 

 

 

 

71

 

Proceeds from Joint Venture

 

19,461

 

 

 

 

 

 

 

 

 

 

 

 

19,461

 

Acquisitions of Undeveloped Acreage

 

(5,266

)

 

 

 

 

 

 

 

 

 

 

 

(5,266

)

Capital Expenditures for Development of Oil and Gas

    Properties and Equipment

 

(15,036

)

 

 

(32

)

 

 

 

 

 

 

 

 

(15,068

)

NET CASH PROVIDED BY (USED) IN INVESTING ACTIVITIES

 

(741

)

 

 

(53

)

 

 

23,967

 

 

 

(23,975

)

 

 

(802

)

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proceeds from Long-Term Debt and Lines of Credit

 

 

 

 

 

 

 

46,500

 

 

 

 

 

 

46,500

 

Repayments of Loans and Other Long-Term Debt

 

(184

)

 

 

 

 

 

 

 

 

 

 

 

(184

)

Debt Issuance Costs

 

 

 

 

 

 

 

(2,821

)

 

 

 

 

 

(2,821

)

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES

 

(184

)

 

 

 

 

 

43,679

 

 

 

 

 

 

43,495

 

NET INCREASE IN CASH

 

23,799

 

 

 

 

 

 

1

 

 

 

 

 

 

23,800

 

CASH – BEGINNING

 

1,089

 

 

 

 

 

 

2

 

 

 

 

 

 

1,091

 

CASH - ENDING

$

24,888

 

 

$

 

 

$

3

 

 

$

 

 

$

24,891

 

 

 


34


 

 

 

18. SUBSEQUENT EVENTS

Term Loan and Retirement of Revolving Line of Credit

On April 28, 2017 (the “Effective Date”), we entered into the Term Loan with Angelo, Gordon Energy Servicer, LLC (“AGES”), as administrative agent (in such capacity, the “Administrative Agent”), AGES, as collateral agent (in such capacity, the “Collateral Agent”), Macquarie Bank Limited, as issuing bank (in such capacity, the “Issuing Bank”) and the lenders from time to time party thereto. The Term Loan amended and restated our existing amended and restated senior secured revolving credit agreement (the “Existing Credit Agreement”).  The Term Loan provides for (x) a $143,500,000 secured term loan facility (the “Term Facility”) and (y) a $156,500,000 secured delayed draw term loan facility (the “Delayed Draw Term Facility”), which includes a letter of credit subfacility (the “Letter of Credit Subfacility”).  The proceeds of the initial loans under the Term Loan were used for refinancing of loans under the Existing Credit Agreement and payment of fees and expenses related thereto; the proceeds of future loans under the Delayed Draw Term Facility may be used for cash collateralizing letters of credit under the Letter of Credit Subfacility and general corporate purposes.  The maximum commitments of the lenders under the Term Loan are currently limited to $300,000,000.  Amounts borrowed and repaid may not be reborrowed. The maturity date for the loans under the Term Facility and the loans drawn under the Delayed Draw Term Facility is the earlier of (a) April 28, 2021 and (b) the date that is six months prior to the maturity of the Company’s 1.00/8.00% Senior Secured Second Lien Notes due 2020 (the “Second Lien Notes”) unless less than $25,000,000 Second Lien Notes are then outstanding and no Event of Default (as defined in the Term Loan) exists on such date.  The commitments under the Delayed Draw Term Facility expire if not drawn prior to the earlier of (a) April 28, 2018 (which date may be extended for one year with lender consent) and (b) the date upon which the Borrower terminates such commitments.

Borrowings under the Term Loan bear interest at a rate per annum equal to the “Adjusted LIBO Rate” (subject to a 1.00% floor) plus an 8.75% per annum margin. The “Adjusted LIBO Rate” is equal to the product of: (i) three month LIBOR multiplied by (ii) the statutory reserve rate.  Upon the occurrence and continuance of an Event of Default all outstanding loans shall bear interest at a rate equal to 4.00% per annum plus the then-effective rate of interest. Interest is payable on the last Business Day of each March, June, September and December.

The Term Loan requires us to prepay the loans with 100% of the net cash proceeds received from certain asset sales, swap terminations, incurrences of borrowed money indebtedness, casualty events and equity issuances, subject to certain exceptions and specified reinvestment rights.  Prepayments based on 75% of excess cash flow are required until no more than $287,950,000 in Second Lien Notes remain outstanding, at which time, prepayments based on 50% of excess cash flow will be required.  Prepayments (including mandatory prepayments), terminations, refinancing, reductions and accelerations under the Term Loan are subject to (x) a yield maintenance amount equal to the interest which would have accrued on such prepaid, terminated, refinanced, reduced or accelerated amount during the period beginning on the date of such prepayment, termination, refinancing, reduction or acceleration and ending on the date that is 30 months after the Effective Date and (y) a call protection amount (a) during the period commencing on the Effective Date and ending on the date that is 30 months thereafter, in an amount equal to 3.0% of such prepaid, terminated, refinanced, reduced or accelerated amount and (b) during the period commencing on the date that is 30 months and 1 day after the Effective Date and ending on the date that is 36 months after the Effective Date, an amount equal to 1.0% of such prepaid, terminated, refinanced, reduced or accelerated amount.

The Term Loan contains covenants that restrict our ability to, among other things, materially change the nature of our business, make dividends, enter into transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens, and enter into agreements regarding swap and other derivative transactions.

The Term Loan also requires that we comply with the following financial covenants: (1) as of the last day of any fiscal quarter ending on or after December 31, 2017, the PDP Coverage Ratio (as defined in the Term Loan) will not be less than 1.65 to 1.00; (2) as of the last day of any fiscal quarter ending on or after March 31, 2017, the ratio of Net Senior Secured Debt (as defined in the Term Loan) as of such date to EBITDAX  (as defined in the Term Loan) for the period of four fiscal quarters then ending on such day will not be greater than 3.25 to 1.00 (provided that EBITDAX for the four fiscal quarters ending on (i) March 31, 2017 shall be EBITDAX for the fiscal quarter then ending multiplied by four and (ii) June 30, 2017 shall be EBITDAX for the two fiscal quarters then ending multiplied by two); and (3) as of the last day of any fiscal quarter ending on or after September 30, 2017, the ratio EBITDAX for the four fiscal quarters then ending to cash interest expense will not be less than (i) 1.00 to 1.00 for any fiscal quarter ending on or before December 31, 2017 and (ii) 1.30 to 1.00 for each fiscal quarter thereafter.

Our obligations under the Credit Agreement may be accelerated upon the occurrence of an Event of Default (as such term is defined in the Term Loan). Events of Default include customary events for a financing agreement of this type, including, without

35


 

limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness, bankruptcy or related defaults, defaults related to judgments and the occurrence of a Change of Control (as such term is defined in the Term Loan).

Obligations under the Term Loan are secured by mortgages on our oil and gas properties. In connection with the Term Loan, we, including our wholly owned subsidiaries, Rex Energy I, LLC, Rex Energy Operating Corp., PennTex Resources Illinois, Inc., Rex Energy IV, LLC, and R.E. Gas Development, LLC (collectively, the “Guarantors” and together with us, the “Grantors”), entered into an amended and restated guaranty and collateral agreement, dated as of April 28, 2017, in favor of the Collateral Agent for the lenders from time to time party to the Term Loan, the secured swap parties and the Issuing Bank (the “Guaranty and Collateral Agreement”).  Pursuant to the Guaranty and Collateral Agreement, each of the Guarantors, jointly and severally, guaranteed the prompt and complete payment of our obligations under the Term Loan. In addition, each Grantor granted, as security for the prompt and complete payment and performance when due of such Grantor’s obligations, a security interest in substantially all of its assets, including equity interests in other Guarantors, as applicable.

The foregoing descriptions of the Term Loan and the Guaranty and Collateral Agreement do not purport to be complete and are qualified in their entirety by reference to the complete text of these agreements. A copy of the Term Loan Credit Agreement and the Amended and Restated Guaranty and Collateral Agreement will be filed with the our Periodic Report on Form 10-Q for the quarter ending June 30, 2017.

 

 

 

 

 

 

 

 

 

 

 

36


 

Item 2.

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

The following is management’s discussion and analysis of certain significant factors that have affected aspects of our financial position and results of operations during the periods included in the accompanying unaudited financial statements. You should read this in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited financial statements for the year ended December 31, 2016 included in our Annual Report on Form 10-K and the unaudited financial statements included elsewhere herein.

We use a variety of financial and operational measurements at interim periods to analyze our performance. These measurements include an analysis of production and sales revenue for the period; EBITDAX, a non-GAAP financial measurement; lease operating expenses per Mcf equivalent (“LOE per Mcfe”); and general and administrative (“G&A”) expenses per Mcfe.

Overview of Our Business

We are an independent natural gas, NGL and condensate company operating in the Appalachian Basin, where we are focused on our Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties. We are headquartered in State College, Pennsylvania, with a regional office in Cranberry, Pennsylvania.

We believe the outlook for our business is favorable despite the continued uncertainty of oil and gas prices. Our resource base, risk management, including an active hedging program, and disciplined investment of capital provide us with an opportunity to exploit and develop our positions and maximize efficiency in our key operating areas. We continue to focus on maintaining financial flexibility while pursuing an active, technology-driven drilling program to develop and maximize the value of our existing acreage as market conditions continue to evolve.

However, a prolonged period of depressed commodity prices could have a significant impact on the value and volumetric quantities of our proved reserves, and may result in write-downs of the carrying values of our oil and natural gas properties and revisions to our capital budget or development program. We discuss these matters in further detail under, among other places, “Commodity Prices,” “Impairment Expense,” “Capital Resources and Liquidity,” and “Volatility of Oil, NGL and Natural Gas Prices” below as well as in Note 15, “Impairment Expense”, to our Consolidated Financial Statements.

In June 2016, we entered into a purchase and sale agreement to divest all of our assets in the Illinois Basin. As of June 14, 2016, the Illinois Basin assets became classified as “Held for Sale” and our assets and operations of the Illinois Basin are reported as Discontinued Operations. Closing occurred on August 18, 2016, with an effective date for the transaction of July 1, 2016 in exchange for approximately $40.5 million in proceeds.

2017 Activity

During the three months ended March 31, 2017, we produced 15,604 MMcfe. Overall, our production for the three months ended March 31, 2017 averaged 173 MMcfe per day. As of March 31, 2017, we had 12.0 gross (5.5 net) wells drilled and awaiting completion. We had no wells resting or awaiting pipeline connection as of March 31, 2017. Our drilling and completion activity for the period indicated is set forth in the table below.

Three Months Ended March 31, 2017 and 2016

Three Months Ended March 31, 2017

 

Wells Drilled

 

 

Wells Completed

 

 

Wells Placed In Service

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

7.0

 

 

 

3.3

 

 

 

4.0

 

 

 

1.4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31, 2016

 

Wells Drilled

 

 

Wells Completed

 

 

Wells Placed In Service

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

2.0

 

 

 

0.7

 

 

 

5.0

 

 

 

3.0

 

 

 

16.0

 

 

 

8.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

37


 

 

Commodity Prices

Our development plans are sensitive to current and projected commodity prices which have been and are expected to continue to be volatile. Our realized price, before derivative settlements, for natural gas during the three months ended March 31, 2017, averaged approximately $3.16 per Mcf, as compared to $1.37 per Mcf for the same period in 2016. Our realized price, before derivative settlements, for condensate during the three months ended March 31, 2017, averaged approximately $46.07 per barrel, as compared to $24.32 per barrel for the same period in 2016. Our realized price, before derivative settlements, for C3+ NGLs during the three months ended March 31, 2017, averaged approximately $30.84 per barrel, as compared to $12.20 per barrel for the same period in 2016. Our realized price, before derivative settlements, for ethane during the three months ended March 31, 2017, averaged approximately $9.48 per barrel, as compared to $6.04 per barrel for the same period in 2015.  

For the three months ended March 31, 2017, we recorded impairment expense of approximately $1.5 million. Further decreases in commodity prices will decrease our natural gas, condensate and NGL revenues and could reduce the amount of natural gas, condensate and NGL reserves that we can economically produce. A prolonged period of depressed commodity prices or further declines in projected future commodity prices could require additional write-downs of the carrying values of our properties.

Because we follow the successful efforts method of accounting our impairment tests are largely based on estimates of future commodity prices, changes in development and operating costs, taxes, operational efficiencies, changes in technology and access to capital, which makes predicting any future write-downs difficult and uncertain. In an effort to quantify the impact of continued low commodity pricing levels or further declines in future prices, we offer the following: as of March 31, 2017, approximately 83.4% of our evaluated oil and natural gas properties were located in our Butler Marcellus operating area.  Based on estimates of future cash flows, substantial further decreases in commodity prices combined with a lack of access to capital or a detrimental change to costs or operating efficiencies would need to occur in order for us to experience a write-down. Our remaining evaluated properties outside of the Butler Marcellus operating area are more sensitive to the current commodity price environment. These properties could experience additional write-downs if estimates of future commodity prices decline further. The net book value of these remaining evaluated properties totaled approximately $470.8 million as March 31, 2017.

Debt for Equity Exchanges

During the first quarter of 2017, we entered into privately negotiated debt-to-equity exchanges with certain holders of our 8.875% Senior Notes due 2020 (the “2020 Notes”) and 6.25% Senior Notes due 2022 (the “2022 Notes” and, together with the 2020 Notes, the “Existing Notes”) in exchange for unrestricted shares of our common stock.  These exchanges resulted in the retirement of $0.2 million of our Existing Notes, in exchange for the issuance of approximately 0.3 million shares of unrestricted common stock.  The exchanged notes were subsequently cancelled, resulting in a gain to the company of approximately $0.2 million, presented as Gain on Extinguishments of Debt in our Consolidated Statement of Operations for the three months ended March 31, 2017.

Benefit Street Partners, LLC Joint Venture

On March 1, 2016, we entered into a joint exploration and development agreement with an affiliate of Benefit Street Partners, LLC (“BSP”) to jointly develop 58 specifically designated wells in our Moraine East and Warrior North operated areas. BSP agreed to participate in and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, 12 of which have already been drilled, completed, placed in sales and paid for by BSP. BSP also agreed to participate in and fund 65.0% of the estimated well costs for six designated wells in Warrior North, Ohio, all of which have been drilled, completed, placed in sales and paid for by BSP. BSP also has the option to participate in the development of 36 additional wells and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. To date, BSP has exercised its option to participate in 23 of these additional wells. Total consideration for this transaction could be up to $175.0 million with approximately $134.0 million committed as of March 31, 2017. BSP has paid approximately $86.7 million for its interest in elected wells as of March 31, 2017. The remainder of the proceeds will be received as additional wells are drilled to total depth or placed in sales.  BSP earns an assignment of 15%-20% working interest in acreage located within each of the units it participates. As of March 31, 2017, 30 of the 45 committed wells were in line and producing, and 15 wells were drilled and awaiting completion.

 

38


 

Results of Continuing Operations

The following table sets forth summary information regarding NGL, condensate and natural gas production and product prices for the three months ended March 31, 2017.

 

 

For the Three Months Ended March 31,

 

 

2017

 

 

2016

 

Production:

 

 

 

 

 

 

 

Natural Gas (Mcf)

 

9,911,742

 

 

 

11,304,519

 

Condensate (Bbls)

 

74,240

 

 

 

63,063

 

C3+ NGLs (Bbls)

 

421,705

 

 

 

489,753

 

Ethane (Bbls)

 

452,687

 

 

 

438,213

 

Total (Mcfe)(a)

 

15,603,534

 

 

 

17,250,693

 

Average daily production:

 

 

 

 

 

 

 

Natural Gas (Mcf)

 

110,130

 

 

 

124,225

 

Condensate (Bbls)

 

825

 

 

 

693

 

C3+ NGLs (Bbls)

 

4,686

 

 

 

5,382

 

Ethane (Bbls)

 

5,030

 

 

 

4,816

 

Total (Mcfe)(a)

 

173,373

 

 

 

189,568

 

Average sales price(b):

 

 

 

 

 

 

 

Natural Gas (per Mcf)

$

3.16

 

 

$

1.37

 

Condensate (per Bbl)

$

46.07

 

 

$

24.32

 

C3+ NGLs (per Bbl)

$

30.84

 

 

$

12.20

 

Ethane (per Bbl)

$

9.48

 

 

$

6.04

 

Total (per Mcfe)(a)

$

3.34

 

 

$

1.49

 

Average NYMEX prices(c):

 

 

 

 

 

 

 

Oil (per Bbl)

$

51.91

 

 

$

33.45

 

Natural Gas (per Mcf)

$

3.00

 

 

$

1.99

 

 

 

(a)

Condensate, Ethane and C3+ NGLs are converted at the rate of one barrel of oil equivalent (“BOE”) to six Mcfe.

 

(b)

Does not include the effects of cash settled derivatives.

 

(c)

Based upon the average of bid week prompt month prices.

The following table sets forth summary information regarding NGL, condensate and natural gas revenues, production volumes, average product prices and average production costs for the three months ended March 31, 2017

 

 

Production and Revenue by Product

 

 

For the Three Months Ended March 31,

 

 

2017

 

 

2016

 

Revenue – Natural Gas(a)

$

31,344,632

 

 

$

15,515,677

 

Volumes (Mcf)

 

9,911,742

 

 

 

11,304,519

 

Average Price

$

3.16

 

 

$

1.37

 

Revenue – Condensate (a)

$

3,420,173

 

 

$

1,533,754

 

Volumes (Bbl)

 

74,240

 

 

 

63,063

 

Average Price

$

46.07

 

 

$

24.32

 

Revenue – C3+ NGLs(a)

$

13,007,428

 

 

$

5,975,206

 

Volumes (Bbl)

 

421,705

 

 

 

489,753

 

Average Price

$

30.84

 

 

$

12.20

 

Revenue – Ethane(a)

$

4,293,001

 

 

$

2,648,685

 

Volumes (Bbl)

 

452,687

 

 

 

438,213

 

Average Price

$

9.48

 

 

$

6.04

 

Average Production Cost per Mcfe(b)

$

1.85

 

 

$

1.39

 

 

 

(a)

Does not include the effects of cash settled derivatives.

 

(b)

Excludes ad valorem and severance taxes.

General Overview

Operating revenue for the three months ended March 31, 2017 increased 102.7% when compared to the same periods in 2016. The increase in operating revenue can be primarily attributed to higher natural gas, condensate and NGL prices, partially offset by lower natural gas production volumes. Our production decreased to 15,604 MMcfe for the three-month period ended March 31, 2017, from 17,251 MMcfe for the same period in 2016, or approximately 9.5%. For the three month period ended March 31, 2017, our realized sales price for natural gas increased to $3.16 per Mcf from $1.37 per Mcf, condensate increased to $46.07 per barrel from $24.32 per barrel, C3+ NGLs increased to $30.84 per barrel from $12.20 per barrel, and ethane increased to $9.48 per barrel from $6.04 per barrel, respectively, when compared to the same period in 2016.

39


 

Operating expenses decreased $9.3 million for the three months ended March 31, 2017, as compared to the same periods in 2016. Operating expenses primarily comprise: Production and Lease Operating Expenses, G&A Expenses, Other Operating Expense, Exploration Expenses, Impairment Expense and DD&A Expenses. The decreases in operating expenses were largely attributable to fewer impairment charges, reduced DD&A expense, gain on the disposal of assets, net of higher Lease Operating Expenses. The decrease of many of these operating expenses is consistent with the overall decrease in activity within the industry in conjunction with a decrease in the cost of goods and services and other cost control measures that we have implemented. The decrease in impairment was largely indicative of the increase in commodity prices as compared to prices realized during the three months ended March 31, 2016.

Comparison of the Three Months Ended March 31, 2017 to the Three Months Ended March 31, 2016

Gas, condensate and NGL revenue, including the effects of cash settled derivatives, for the three-month periods ended March 31, 2017 and 2016 is summarized in the following table:  

 

For the Three Months Ended March 31,

 

($ in Thousands, except total Mcfe production and price per Mcfe)

2017

 

 

2016

 

 

Change

 

 

%

 

Gas sales revenue

$

31,345

 

 

$

15,516

 

 

$

15,829

 

 

 

102.0

%

Gas derivatives realized(a)

$

(1,172

)

 

$

8,223

 

 

$

(9,395

)

 

 

(114.2

)%

Total gas revenue and derivatives realized

$

30,173

 

 

$

23,739

 

 

$

6,434

 

 

 

27.1

%

Condensate sales revenue

$

3,420

 

 

$

1,534

 

 

$

1,886

 

 

 

122.9

%

Oil and condensate derivatives realized(a)

$

5

 

 

$

1,787

 

 

$

(1,782

)

 

 

(99.7

)%

Total condensate revenue and derivatives realized

$

3,425

 

 

$

3,321

 

 

$

104

 

 

 

3.1

%

C3+ NGL revenue

$

13,007

 

 

$

5,975

 

 

$

7,032

 

 

 

117.7

%

C3+ NGL derivatives realized(a)

$

(2,384

)

 

$

2,956

 

 

$

(5,340

)

 

 

(180.6

)%

Total C3+ NGL revenue

$

10,623

 

 

$

8,931

 

 

$

1,692

 

 

 

18.9

%

Ethane revenue

$

4,293

 

 

$

2,648

 

 

$

1,645

 

 

 

62.1

%

Ethane derivatives realized(a)

$

108

 

 

$

144

 

 

$

(36

)

 

 

(25.0

)%

Total Ethane revenue

$

4,401

 

 

$

2,792

 

 

$

1,609

 

 

 

57.6

%

Consolidated sales

$

52,065

 

 

$

25,673

 

 

$

26,392

 

 

 

102.8

%

Consolidated derivatives realized(a)

$

(3,443

)

 

$

13,110

 

 

$

(16,553

)

 

 

(126.3

)%

Total NGL, condensate and gas revenue and derivatives realized

$

48,622

 

 

$

38,783

 

 

$

9,839

 

 

 

25.4

%

Total Mcfe Production

 

15,603,534

 

 

 

17,250,693

 

 

 

(1,647,159

)

 

 

(9.5

)%

Average Realized Price per Mcfe

$

3.12

 

 

$

2.25

 

 

$

0.87

 

 

 

38.7

%

 

(a)

Realized derivatives are included in Other Income (Expense) on our Consolidated Statements of Operations.  

Average realized price received for natural gas, condensate and NGLs during the first quarter of 2017, after the effect of derivative activities, was $3.12 per Mcfe, an increase of 38.7%, or $0.87 per Mcfe, from the same period in 2016. This increase was primarily due to an increase in commodity prices during the quarter, partially offset by cash-settled losses on derivatives. The average price for natural gas, after the effect of derivative activities, increased 44.8%, or $0.94 per Mcf, to $3.04per Mcf. The average price for condensate, after the effect of derivative activities, decreased 12.4%, or $6.53 per barrel, to $46.13 per barrel. The average price for C3+ NGLs, after the effect of derivative activities, increased 38.1%, or $6.95 per barrel, to $25.19 per barrel. The average price for ethane, after the effect of derivative activities, increased 52.6%, or $3.35 per barrel, to $9.72 per barrel. Our derivative activities effectively decreased net realized prices by $0.22 per Mcfe in the first quarter of 2017 and increased net realized prices by $0.76 per Mcfe in the first quarter of 2016.

Our realized sales price for natural gas differed from the average Henry Hub NYMEX pricing by approximately $0.16 per Mcf during the first quarter of 2017 primarily due to basis differentials in the northeastern United States, which were partially offset by sales on the Texas Eastern pipeline receiving M3 pricing, a New York area index. We have been able to stabilize the impact of basis differentials to an extent by utilizing basis swaps in our derivatives program. In addition, we have been targeting sales points outside of the northeastern United States and have executed capacity agreements to transport natural gas volumes to the Midwest and the Gulf Coast, including transportation of 100,000 Mcf per day to the Gulf Coast that began during the fourth quarter of 2016.

Production volumes in the first quarter of 2017 decreased 9.5% or 1,647.2 MMcfe from the first quarter of 2016 primarily due to the sale of our Warrior South assets during first quarter of 2017. Natural gas production decreased approximately 12.3%, condensate production increased approximately 17.7%, C3+ NGL production decreased approximately 13.9% and our ethane production increased approximately 3.3%. Contributing to the decrease in natural gas production volumes was the increase in ethane production volumes, as the amount of ethane extraction from produced natural gas is controlled at the processing plant.  The product blend is optimized for pricing and demand conditions.

Overall, our production for the first quarter of 2017 averaged 173,373 Mcfe per day, of which 63.5% was attributable to natural gas, 2.9% to condensate, 16.2% to C3+ NGLs and 17.4% was a result of ethane production.

40


 

Statements of Operations for the three months ended March 31, 2017 and 2016 are as follows:

 

 

For the Three Months Ended March 31,

 

($ in Thousands)

2017

 

 

2016

 

 

Change

 

 

%

 

OPERATING REVENUE

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas, NGL and Condensate Sales

$

52,065

 

 

$

25,673

 

 

$

26,392

 

 

 

102.8

%

Other Operating Revenue

 

6

 

 

 

13

 

 

 

(7

)

 

 

(53.8

)%

TOTAL OPERATING REVENUE

 

52,071

 

 

 

25,686

 

 

 

26,385

 

 

 

102.7

%

OPERATING EXPENSES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production and Lease Operating Expense

 

28,934

 

 

 

24,451

 

 

 

4,483

 

 

 

18.3

%

General and Administrative Expense

 

4,534

 

 

 

5,284

 

 

 

(750

)

 

 

(14.2

)%

(Gain) Loss on Disposal of Assets

 

(1,834

)

 

 

11

 

 

 

(1,845

)

 

 

100.0

%

Impairment Expense

 

1,546

 

 

 

10,641

 

 

 

(9,095

)

 

 

(85.5

)%

Exploration Expense

 

220

 

 

 

936

 

 

 

(716

)

 

 

(76.5

)%

Depreciation, Depletion, Amortization and Accretion

 

15,468

 

 

 

16,511

 

 

 

(1,043

)

 

 

(6.3

)%

Other Operating (Income) Expense

 

(21

)

 

 

327

 

 

 

(348

)

 

 

(106.4

)%

TOTAL OPERATING EXPENSES

 

48,847

 

 

 

58,161

 

 

 

(9,314

)

 

 

(16.0

)%

INCOME (LOSS) FROM OPERATIONS

 

3,224

 

 

 

(32,475

)

 

 

35,699

 

 

 

(109.9

)%

OTHER INCOME (EXPENSE)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense

 

(9,143

)

 

 

(13,030

)

 

 

3,887

 

 

 

(29.8

)%

Gain on Derivatives, Net

 

8,381

 

 

 

4,049

 

 

 

4,332

 

 

 

107.0

%

Other Expense

 

(28

)

 

 

 

 

 

(28

)

 

 

100.0

%

Debt Exchange Expense

 

 

 

 

(8,480

)

 

 

8,480

 

 

 

(100.0

)%

Gain on Extinguishment of Debt

 

249

 

 

 

 

 

 

249

 

 

 

100.0

%

TOTAL OTHER EXPENSE

 

(541

)

 

 

(17,461

)

 

 

16,920

 

 

 

(96.9

)%

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX

 

2,683

 

 

 

(49,936

)

 

 

52,619

 

 

 

(105.4

)%

Income Tax Expense

 

 

 

 

(2,715

)

 

 

2,715

 

 

 

100.0

%

NET INCOME (LOSS) FROM CONTINUING OPERATIONS

 

2,683

 

 

 

(52,651

)

 

 

55,334

 

 

 

(105.1

)%

Loss From Discontinued Operations, Net of Income Taxes

 

 

 

 

(7,490

)

 

 

7,490

 

 

 

(100.0

)%

NET INCOME (LOSS)

$

2,683

 

 

$

(60,141

)

 

$

62,824

 

 

 

(104.5

)%

 

Production and Lease Operating Expense increased approximately $4.5 million, or 18.3%, in the first quarter of 2017 from the same period in 2016. We experienced Production and Lease Operating Expense increases that are commensurate with the increase in producing wells and related production as they relate to variable type costs such as transportation, marketing, processing and gathering. Transportation, marketing, processing and gathering fees accounted for approximately 90.7% of our total Production and Lease Operating Expense in the first quarter of 2017, as compared to 87.8% from the same period in 2016. As we continue to develop our core areas of operation we expect that fees incurred from unutilized commitments will decrease. These types of agreements typically have a term of several years and we expect fees associated with these agreements to continue to comprise a significant portion of our Production and Lease Operating Expense. On a per unit of production basis, our lifting costs were $1.85 and $1.42 per Mcfe in each of the three months ended March 31, 2017 and 2016, respectively. The increase on a per unit basis is related to the commencement of our Gulf Coast transportation agreement.

G&A Expense for the first quarter of 2017 decreased approximately $0.8 million, or 14.2%, to $4.5 million from the same period in 2016. The decrease was mostly due to decrease in transactional fees associated with the BSP transaction of $0.4 million during first quarter 2017 as compared to $1.4 million during same period in 2016.

Impairment Expense for the first quarter of 2017 was approximately $1.5 million. We evaluate impairment of our properties when events occur that indicates that the carrying value of these properties may not be recoverable. The expense incurred during the first quarter of 2017 included $0.8 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which are in Butler County, Pennsylvania, and Warrior North in Ohio. Based on the current commodity price environment, we do not expect to develop these properties prior to expiration of the associated leases. Impairment of proved properties in our Butler County operations totaled approximately $0.7 million during the first quarter of 2017. The impairments were identified through an analysis of market conditions and future development plans related to these properties that were in existence as of March 31, 2017, which indicated that the carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets. Any amount of future impairments are difficult to predict, however, if commodity prices decline, downward revisions of proved reserves may be significant and could result in additional impairment expense.

Exploration Expense for the first quarter of 2017 was approximately $0.2 million, as compared to $0.9 million for same period in 2016. The expense incurred in 2017 was mostly due to delay rental payments. Approximately $0.1 million of the expense incurred

41


 

in 2016 was due to geological and geophysical type expenditures and $0.8 million was due to two exploratory wells that were abandoned at various stages that resulted in dry hole expense. As a result of the decrease in commodity prices, we have decreased our levels of spending with regards to geological and geophysical activities.

DD&A Expense for the first quarter of 2017 decreased approximately $1.0 million, or 6.3%, from $16.5 million for the same period in 2016. Contributing to the decrease in DD&A expense were lower depreciable asset values from the impact of 2016 impairments and the sale of Warrior South assets during 2017 when compared to the same period in 2016.

Other Operating Expense for the first quarter of 2017 decreased approximately $0.3 million from $0.3 million for the same period in 2016. The expense in 2016 was primarily related to a firm transportation contract associated with an area west of our core assets in Butler County, Pennsylvania.

Interest Expense for the first quarter of 2017 was approximately $9.1 million as compared to $13.0 million for the same period in 2016. The decrease in interest expense is primarily due to reduced bond interest expense as a result of the Senior Notes exchange completed on March 31, 2016.  The decrease is partially offset by increased amortization of bond costs as a result of the Senior Notes exchange, and increased interest expense due to increased borrowing on our revolving credit facility. We discuss our Senior Notes and revolving credit facility in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

Gain on Derivatives, net included a gain of approximately $8.4 million for the first quarter of 2017 as compared to a gain of $4.0 million for the same period in 2016. The gain recorded for the first quarter of 2017 included cash payments for commodity derivatives of $3.4 million while the gain incurred in the first quarter of 2016 included cash receipts of approximately $13.0 million for commodity and interest rate derivatives. Changes were attributable to the volatility of oil, NGL and natural gas commodity prices along with changes in our portfolio of outstanding derivatives. Losses from derivative activities generally reflect higher oil, NGL and natural gas prices in the marketplace than were in effect at the end of the last period while gains generally reflect the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of oil, NGL and gas production volumes given the highly volatile oil, NGL and gas commodities market.

We believe oil, NGL and natural gas prices will remain volatile and could decline further. Although we have entered into derivative contracts covering a portion of our production volumes for the remainder of 2017 and 2018, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices that we can enter into derivative contracts for additional volumes in the future.

Gain on Extinguishment of Debt for the first quarter of 2017 totaled approximately $0.2 million.  The gain in 2017 resulted from debt to equity exchanges approximately $0.5 million of outstanding Senior Notes were reacquired by the company in exchange for approximately 0.3 million shares of our common stock.  We discuss the debt to equity exchanges in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

Income Tax Expense for continuing operations for the first quarter of 2017 was $0.0 million, or 0.0% of pretax income, due to the full valuation allowances we maintain against our net deferred tax assets.

For the first quarter of 2016, income tax expense was $2.7 million, or 5.4% of pretax loss. Our estimated annual effective tax rate for 2016 differed from the U.S. statutory rate of 35.0% primarily due to the effect of having full valuation allowances recorded against our deferred tax assets coupled with recognizing tax benefits in continuing operations for the effect of taxable income generated by our discontinued operations. To a lesser extent, the annual effective rate is also influenced by alternative minimum tax with no corresponding deferred tax benefit due to the full valuation allowance, and state taxes in certain tax paying jurisdictions.  The Company’s alternative minimum tax due for 2016 was driven primarily by cancellation of debt income of $543.2 million related to the Senior Note exchanges.   

Net Income (Loss) Attributable to Rex Energy for the first quarter of 2017 was income of approximately $2.3 million, as compared to a loss of $60.1 million for the same period in 2016 as a result of factors discussed above.

 

 

Other Performance Measurements

 

 

For the Three Months Ended March 31,

 

 

2017

 

 

2016

 

EBITDAX from Continuing Operations ($ in Thousands) (a)

$

15,577

 

 

$

8,470

 

LOE per Mcfe

$

1.85

 

 

$

1.42

 

G&A per Mcfe

$

0.29

 

 

$

0.31

 

 

 

(a)

EBITDAX is a non-GAAP measure. See “Non-GAAP Financial Measures” for our reconciliation of EBITDAX to net income.

42


 

EBITDAX (Non-GAAP)

 

EBITDAX (Non-GAAP) from continuing operations increased approximately $7.1 million to $15.6 million for the three-month period ended March 31, 2017, as compared to the same period in 2016.  The increase in EBITDAX can be primarily attributed to increased average sales prices for natural gas, NGLs and condensate, resulting in increased operating revenues.

LOE per Mcfe

LOE per Mcfe measures the average cost of extracting natural gas, condensate and NGLs from our reserves during the period. This measurement is also commonly referred to in the industry as our “lifting cost”. It represents the average cost of extracting one Mcf of natural gas equivalent from our natural gas and NGL reserves in the ground. LOE per Mcfe increased $0.43 to $1.85 for the three months ended March 31, 2017, as compared to $1.42 for the same period in 2016. Our LOE is largely comprised of variable type costs such as transportation, marketing, processing and gathering. For the first quarter of 2017, transportation, capacity and processing fees accounted for approximately 90.9% of our total Production and Lease Operating Expense as compared to 87.8% during the same period of 2016. These agreements typically have a term of several years, and we expect them to continue to comprise a significant portion of our Production and Lease Operating Expense. Various agreements that we have entered include firm capacity rights, for which we may incur a fee for unused capacity. As we continue to grow our operations, we expect our lifting cost to decrease as we gain additional efficiencies of scale and utilize all of our firm capacity and transportation commitments.

G&A Expenses per Mcfe

Our G&A expenses include fees for well operating services, marketing, non-field level employee compensation and related benefits, office and lease expenses, insurance costs and professional fees, as well as other costs and expenses not directly related to field operations. Our management continually evaluates the level of our G&A expenses in relation to our production because these expenses have a direct impact on our profitability. G&A expenses per Mcfe decreased to approximately $0.29 for the three-month period ended March 31, 2017, as compared to $0.31 for the same period in 2016. The decreases are predominately due to reduced transactional costs during the first three months of 2017 as compared to transactional costs associated with BSP transaction during same period in 2016.

Capital Resources and Liquidity

Our primary needs for cash are for the exploration, development and acquisition of oil and gas properties. During the three months ended March 31, 2017, we spent $25.8 million of capital on asset acquisitions, drilling projects, facilities and related equipment and acquisitions of unproved acreage. We expect to be reimbursed by joint venture partners for approximately $11.0 million of costs incurred during the first quarter of 2017 that were not billed until the second quarter. We funded our capital program with proceeds from the sale of our Warrior South Assets, cash from operations and joint venture reimbursements received from BSP. The remainder of our 2017 capital budget is expected to be funded primarily by cash on hand, cash flows from operations, proceeds from the Term Loan and potential future asset sales and joint ventures.

Our cash flows from operations are driven by commodity prices and production volumes. Prices for oil, NGLs and gas are driven by, among other things, seasonal influences of weather, national and international economic and political environments and, increasingly, from national and global supply and demand for hydrocarbons. Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices could decrease our exploration and development expenditures. Historically, we have primarily used cash flows from operations, borrowings from lines of credit and net proceeds from debt and equity offerings to fund the exploration and development of our oil and gas interests. As of March 31, 2017, we had approximately $5.1 million of cash on hand and outstanding borrowings under our then existing $190.0 million revolving credit facility of approximately $110.7 million with an additional $46.3 million of undrawn letters of credit outstanding. On April 28, 2017, we entered into a Term Loan Credit Agreement (the “Term Loan”) and subsequently terminated and repaid amounts outstanding under our revolving credit facility (for additional information, see Note 18, Subsequent Events, to our Consolidated Financial Statements).

Our ability to fund our capital expenditure program is dependent upon the level of commodity prices and the success of our exploration programs in replacing our existing natural gas, NGL and condensate reserves. If commodity prices decrease, our operating cash flows may decrease, which could reduce funds available to fund our capital expenditure program. The effects of commodity prices on cash flows can be mitigated through the use of commodity derivatives. If we are unable to replace our natural gas, NGL and condensate reserves through acquisitions and our development and exploration programs, we may also suffer a reduction in our operating cash flows and access to funds under our Term Loan. At March 31, 2017, we expected to be in compliance with all required debt covenants for at least the next twelve months.

43


 

Due to the depressed commodity price environment, in January 2016, we suspended payment of our quarterly dividend on shares of our Series A Convertible, Perpetual Preferred Stock (“Preferred Stock”). We have the ability to continue to suspend dividend payments and will continue to evaluate the payment of these dividends on a quarterly basis. In April 2017, we declared a quarterly dividend of $150.00 per share on our Preferred Stock ($1.50 per depositary share, each representing 1/100 interest in a share of Preferred Stock) payable on May 15, 2017; this dividend payment will be applied to the earliest dividend in arrears at the time of payment. As a result of having dividends in arrears on our Preferred Stock, we are not currently eligible to use Form S-3 registration statements. Until we are again eligible to use Form S-3, we will be required to use a registration statement on Form S-1 to register securities with the SEC (for initial issuance or resale) or issue securities in private placements, which could increase the cost of raising capital.

We may need to take additional actions in the future to address current industry trends and maintain our ability to pay expenses and service our indebtedness, including, but not limited to, selling assets or raising capital by issuing additional debt or equity securities.

We have Existing Notes and New Notes (together, the “Senior Notes”) that are governed by indentures with substantially similar terms and provisions (the “Indentures”).  The Indentures contain affirmative and negative covenants that are customary for instruments of this nature, including restrictions or limitations on our ability to incur additional debt, pay dividends, purchase or redeem stock or subordinated indebtedness, make investments, create liens, sell assets, merge with or into other companies or transfer substantially all of our assets, unless those actions satisfy the terms and conditions of the Indentures or are otherwise excepted or permitted.  Certain of the limitations in the Indentures, including our ability to incur debt, pay dividends or make other restricted payments, become more restrictive in the event our ratio of consolidated cash flow to fixed charges for the most recent trailing four quarters (the “Fixed Charge Coverage Ratio”) is less than 2.25 to 1.00.  As of March 31, 2017, our Fixed Charge Coverage Ratio was 1.26 to 1.00.  We expect our Fixed Charge Coverage Ratio to improve in 2017 based on our projections of decreased interest expense related to our Senior Notes.  As of March 31, 2017, we were limited to incurring approximately $112.2 million in additional debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default, including cross-default features with any other indebtedness. In certain circumstances, the Trustee or the holders of the Senior Notes may declare all outstanding notes to be due and payable immediately.

We were not restricted as to our borrowings under our revolving credit facility; however we are subject to the minimum financial requirements detailed in Note 7, Long-Term Debt, to our Consolidated Financial Statements. If we are unable to comply with these financial requirements, an event of default could result which would permit acceleration of outstanding debt and could permit our lenders to foreclose on our mortgaged properties.

Future Liquidity Considerations

In connection with certain marketing, transportation and processing agreements that we have entered into, we may be obligated to pay minimum fees in connection with these agreements of $217.2 million over the next five years, depending on our levels of production. In connection with certain of these agreements, we concurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $396.7 million over the life of the agreements. These guarantees will decrease over time as the commitments are satisfied.

Our former revolving credit facility and our new Term Loan contain a number of restrictive covenants and limitations that impose significant operating and financial restrictions on us. In particular, our financial covenants require us to maintain a maximum “Ratio of Net Senior Secured Debt to EBITDAX” of 3.25 to 1.0, a minimum “Ratio of EBITDAX to Interest Expense” of 1.0 to 1.0, increasing to 1.3 to 1.0 for quarterly periods ending on or after March 31, 2018 and a minimum “PDP Coverage Ratio” of 1.65 to 1.00. Failure to comply with these covenants could have a material adverse effect on our business. If an event of default under our Term Loan occurs and remains uncured, among other things, the lenders thereunder:

 

 

Would not be required to lend any additional amounts to us;

 

Could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;

 

May have the ability to require us to apply all of our available cash to repay these borrowings; or

 

May prevent us from making debt service payments under our other agreements.

 

In order to improve our liquidity positions to meet the financial requirements under our Term Loan and to meet other outstanding obligations, we are currently pursuing or considering a number of actions, which in certain cases may involve current investors, affiliates of the Company, or other financing or strategic counterparties, including (i) debt-for-debt or debt-for-equity exchanges, (ii) joint venture opportunities, (iii) minimizing capital expenditures, (iv) improving cash flows from operations, (v) effectively managing working capital, (vi) adding hedging positions, (vii) asset sales, and (viii) in- and out-of-court restructuring

44


 

transactions. There can be no assurance that sufficient liquidity can be raised from any one or more of these transactions or that these transactions can be consummated within the period needed to meet our obligations.

Financial Condition and Cash Flows for the three months ended March 31, 2017 and 2016

The following table summarizes our sources and uses of funds for the periods noted:  

 

Three Months Ended March 31,

 

($ in Thousands)

2017

 

 

2016

 

Cash flows provided by (used in) operations

$

10,522

 

 

$

(18,893

)

Cash flows used in investing activities

 

(1,446

)

 

 

(802

)

Cash flows provided by (used in) financing activities

 

(7,698

)

 

 

43,495

 

Net increase in cash and cash equivalents

$

1,378

 

 

$

23,800

 

Net cash provided by operating activities during the first three months of 2017 increased $29.4 million from net cash used by operating activities during the same period in 2016. This was primarily due to increases in realized prices of our natural gas, condensate and C3+ NGL sales, and decreased cash interest outflow of approximately $10.1 million as a result of our debt restructuring events in 2016.

 

Net cash used in investing activities during the first three months of 2017 increased $0.6 million from net cash used by investing activities during the same period in 2016. This was due to increased capital development expenditures of approximately $24.9 million in the first three months of 2017 compared to the first three months of 2016, due in part to joint venture capital cost reimbursements of approximately $19.5 million we received in the first three months of 2016, reducing net cash used in investing activities during that period. The increase in capital development expenditures during the first three months of 2017 was offset by cash proceeds of approximately $24.3 million received in January 2017, from the sale of our Warrior South assets.

Net cash used in financing activities during the first three months of 2017 increased by approximately $51.2 million from net cash provided by financing activities during the same period in 2016, primarily due to repayments of our revolving credit facility borrowings.

As market conditions warrant and subject to our contractual restrictions in the Senior Credit Facility, our Indentures or otherwise, liquidity position and other factors, we may from time to time seek to recapitalize, refinance or otherwise restructure our capital structure in open market or privately negotiated transactions, which may include, among other things, repurchases of outstanding equity securities or outstanding debt, including our Senior Notes, by tender offer, exchange or otherwise. The amounts involved in any such transaction, individually or in the aggregate, may be material.

Effects of Inflation and Changes in Price

Our results of operations and cash flows are affected by changing oil, NGL and natural gas prices. If the price of oil, NGLs and natural gas increases or decreases, there could be a corresponding increase or decrease in the operating cost that we are required to bear for operations, as well as an increase or decrease in revenues.

Critical Accounting Policies and Recently Adopted Accounting Pronouncements

During the quarter ended March 31, 2017, there were no material changes to the critical accounting policies previously reported by us in our Annual Report on Form 10-K for the year ended December 31, 2016. We describe critical recently adopted and issued accounting standards in Part I, Item 1. Financial Statements—Note 5, “Recently Issued Accounting Pronouncements.”

45


 

Non-GAAP Financial Measures

EBITDAX

“EBITDAX” means, for any period, the sum of net income for such period plus the following expenses, charges or income to the extent deducted from or added to net income in such period: interest, income taxes, DD&A, unrealized losses from financial derivatives, exploration expenses and other similar non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives, added to net income. EBITDAX, as defined above, is used as a financial measure by our management team and by other users of its financial statements, such as our commercial bank lenders to analyze such things as:

 

Our operating performance and return on capital in comparison to those of other companies in our industry, without regard to financial or capital structure;

 

The financial performance of our assets and valuation of the entity without regard to financing methods, capital structure or historical cost basis;

 

Our ability to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our stockholders; and

 

The viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) (the most directly comparable GAAP financial measure) in measuring our performance, nor should it be used as an exclusive measure of cash flows, because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions, and other sources and uses of cash, which are disclosed in our consolidated statements of cash flows.

We have reported EBITDAX because it is a financial measure used by our existing commercial lenders, and because this measure is commonly reported and widely used by investors as an indicator of a company’s operating performance and ability to incur and service debt. You should carefully consider the specific items included in our computations of EBITDAX. While we have disclosed EBITDAX to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, you are cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for management’s discretionary use, due to requirements to conserve funds for capital expenditures, debt service and other commitments.

We believe that EBITDAX assists our lenders and investors in comparing our performance on a consistent basis without regard to certain expenses, which can vary significantly depending upon accounting methods. Because we may borrow money to finance our operations, interest expense is a necessary element of our costs. In addition, because we use capital assets, DD&A are also necessary elements of our costs. Finally, we are required to pay federal and state taxes, which are necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations.

To compensate for these limitations, we believe it is important to consider both net income determined under GAAP and EBITDAX to evaluate our performance.

46


 

The following table presents a reconciliation of our net income to EBITDAX for each of the periods presented:

 

 

Three Months Ended March 31,

 

($ in Thousands)

2017

 

 

2016

 

Net Income (Loss) From Continuing Operations

$

2,683

 

 

$

(52,651

)

Add Back Non-Recurring Costs1

 

110

 

 

 

8,480

 

Add Back Depletion, Depreciation, Amortization and Accretion

 

15,468

 

 

 

16,511

 

Add Back Non-Cash Compensation Expense

 

60

 

 

 

(148

)

Add Back Interest Expense

 

9,148

 

 

 

13,030

 

Add Back Impairment Expense

 

1,546

 

 

 

10,641

 

Add Back Exploration Expenses

 

220

 

 

 

936

 

Add Back (Less) (Gain) Loss on Disposal of Assets

 

(1,834

)

 

 

11

 

Less Gain on Financial Derivatives

 

(8,381

)

 

 

(4,049

)

Add Back (Less) Cash Settlement of Derivatives

 

(3,443

)

 

 

12,994

 

Add Back Tax Expense

 

 

 

 

2,715

 

EBITDAX From Continuing Operations

$

15,577

 

 

$

8,470

 

Net Loss From Discontinued Operations

$

 

 

$

(7,490

)

Add Back Depletion, Depreciation, Amortization and Accretion

 

 

 

 

2,897

 

Add Back Non-Cash Compensation Expense

 

 

 

 

120

 

Add Back Interest Expense

 

 

 

 

2

 

Add Back Impairment Expense

 

 

 

 

3,543

 

Add Back Exploration Expenses

 

 

 

 

58

 

Less Gain on Disposal of Assets

 

 

 

 

(42

)

Less Income Tax Benefit

 

 

 

 

(622

)

Add EBITDAX From Discontinued Operations

$

 

 

$

(1,534

)

EBITDAX (Non-GAAP)

$

15,577

 

 

$

6,936

 

 

1

For the three months ended March 31, 2017, includes a net $0.3 million of advisory services related to our joint venture drilling programs, and $0.2 million in gains on the extinguishment of debt. For the three months ended March 31, 2016, includes approximately $8.5 million in debt exchange expenses.

 

Volatility of Oil, NGL and Natural Gas Prices

Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil, NGLs and natural gas. We account for our natural gas and oil exploration and production activities under the successful efforts method of accounting. To mitigate some of our commodity price risk, we engage periodically in certain other limited derivative activities including price swaps and costless collars in order to establish some price floor protection.

For the three months ended March 31, 2017, we paid net settlements on oil, NGL and natural gas derivatives of approximately $3.4 million, as compared to receiving net settlements of approximately $13.0 million for the same period in 2016. These gains and losses are reported as Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations. As of March 31, 2017, we had over 100.0% of our annualized condensate production hedged through the remainder of 2017, over 100.0% of our annualized natural gas production hedged through the remainder of 2017, and over 100.0% of our annualized NGL production hedged through the remainder of 2017. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future drilling and completion activity or the natural decline of our natural gas, condensate and NGL production.

Our primary sources of production and revenue are located in the Appalachian Basin. Natural gas prices in the Appalachian Basin are exposed to regional basis differentials when compared to NYMEX pricing. During the three months ended March 31, 2017, our average realized prices for natural gas were higher than the average NYMEX prices over the same period by approximately $0.16 per Mcf. We have been able to stabilize the impact of basis differentials to an extent by utilizing basis swaps in our derivatives program. We have Dominion South basis swaps in place for 16,405 MMcf at an average differential to Henry Hub NYMEX of $0.80 per Mcf for the remainder of 2017 in addition to Dominion South basis swaps for 18,980 MMcf at an average differential to Henry Hub NYMEX of $0.80 per Mcf for 2018. For the three months ended March 31, 2017, we paid cash settlements on our basis differential derivatives of approximately $3.4 million.

While the use of derivative arrangements limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of oil, NGLs and natural gas. We have historically entered into all of our derivatives transactions with five counterparties and have a netting agreement in place with our counterparties. While we do not obtain collateral to support the agreements, we do monitor the financial viability of our counterparties and believe our credit risk is minimal on these transactions. Under these arrangements, payments are received or made based on the differential between a fixed and a variable commodity price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. In the event of nonperformance, we would be exposed again to price risk. We have additional risk of financial loss because the price received for the product at the actual

47


 

physical delivery point may differ from the prevailing price at the delivery point required for settlement of the derivative transaction. Moreover, our derivatives arrangements generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our derivatives will vary from time to time.

For a summary of our oil, NGL and natural gas derivative positions at March 31, 2017, refer to Part I, Item 1. Financial Statements - Note 8, “Derivative Instruments and Fair Value Measurements”.

Contractual Obligations

In addition to our capital expenditure program, we are committed to making cash payments in the future on various types of contracts and obligations. Our contractual obligations include long-term debt, operating leases, operational commitments, other loans and notes payable, derivative obligations, firm commitments under sales, gathering and processing agreements and asset retirement obligations. Since December 31, 2016, there have been no material changes to our contractual obligations, other than an increase in long-term debt due to our borrowings under the former Senior Credit Facility and current Term Loan. See Part I, Item 1. Financial Statements—Note 7, “Long-Term Debt” and Note 18, “Subsequent Events”, for additional information on the Senior Credit Facility and Term Loan.

Off-Balance Sheet Arrangements

We do not currently use any off-balance sheet arrangements to enhance our liquidity or capital resource position, or for any other purpose.

Item 3.

Quantitative and Qualitative Disclosures about Market Risk.

We are exposed to various market risks, including energy commodity price risk. We expect energy prices to remain volatile and unpredictable. If energy prices were to decrease for a substantial period of time or decline significantly, revenues and cash flows would significantly decline, and our ability to borrow to finance our operations could be adversely impacted. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil, NGLs and natural gas. Conversely, increases in the market prices for oil, NGLs and natural gas can have a favorable impact on our financial condition, results of operations and capital resources. Based on production through March 31, 2017, we project that a 10% decline in the price per barrel of oil and NGLs and the price per Mcf of gas from the first three months of 2017 average would reduce our gross revenues, before the effects of derivatives, for the remaining nine months of 2017 by approximately $15.6 million.

We have designed our hedging program to reduce the risk of price volatility for our production in the oil, NGL and natural gas markets. Our risk management policy provides for the use of derivative instruments to manage these risks. The types of derivative instruments that we use include swaps, collars, put spreads, put options, basis swaps, swaptions and three way collars. The volume of derivative instruments that we may use are governed by the risk management policy and can vary from year to year, but under most circumstances will apply to only a portion of our current and anticipated production, and will provide only partial price protection against declines in oil, NGL and natural gas prices. We are exposed to market risk on our open contracts, to the extent of changes in market prices of oil, NGLs and natural gas. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged. Further, if our counterparties should default, this protection might be limited as we might not receive the benefits of the hedges.

48


 

At March 31, 2017, we had the following commodity derivative contracts outstanding:

Period

 

Volume

 

Put Option

 

 

Floor

 

 

Ceiling

 

 

Swap

 

 

Fair Market Value ($ in Thousands)

 

Oil

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2017 - Swaps

 

 

81,000

 

Bbls

 

$

 

 

$

 

 

$

 

 

$

53.00

 

 

$

94

 

2017 - Deferred Put Spreads

 

 

15,000

 

Bbls

 

 

51.00

 

 

 

51.00

 

 

 

 

 

 

 

 

 

 

2017 - Collars

 

 

48,000

 

Bbls

 

 

 

 

 

45.00

 

 

 

57.20

 

 

 

 

 

 

 

2017 - Three-Way Collars

 

 

93,000

 

Bbls

 

 

40.16

 

 

 

49.68

 

 

 

61.50

 

 

 

 

 

 

108

 

2018 - Swaps

 

 

60,000

 

Bbls

 

 

 

 

 

 

 

 

 

 

 

54.00

 

 

 

186

 

2018 - Collars

 

 

18,000

 

Bbls

 

 

 

 

 

53.00

 

 

 

60.00

 

 

 

 

 

 

 

2018 - Three-Way Collars

 

 

60,000

 

Bbls

 

 

43.00

 

 

 

52.00

 

 

 

62.30

 

 

 

 

 

 

92

 

 

 

 

375,000

 

Bbls

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

480

 

Natural Gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2017 - Swaps

 

 

11,000,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

3.11

 

 

$

(1,332

)

2017 - Swaptions

 

 

2,400,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

3.33

 

 

 

36

 

2017 - Cap Swaps

 

 

3,900,000

 

Mcf

 

 

2.35

 

 

 

 

 

 

 

 

 

2.81

 

 

 

(1,591

)

2017 - Collars

 

 

1,700,000

 

Mcf

 

 

 

 

 

2.54

 

 

 

3.20

 

 

 

 

 

 

(382

)

2017 - Three-Way Collars

 

 

17,510,000

 

Mcf

 

 

2.33

 

 

 

3.01

 

 

 

3.87

 

 

 

 

 

 

(133

)

2017 - Calls

 

 

8,380,100

 

Mcf

 

 

 

 

 

 

 

 

4.51

 

 

 

 

 

 

(338

)

2017 - Basis Swaps - Dominion South

 

 

16,405,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

(0.80

)

 

 

(2,467

)

2017 - Basis Swaps - Texas Gas

 

 

14,600,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

(0.13

)

 

 

46

 

2018 - Swaps

 

 

12,585,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

3.14

 

 

 

289

 

2018 - Swaptions

 

 

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(200

)

2018 - Three-Way Collars

 

 

8,775,000

 

Mcf

 

 

2.30

 

 

 

2.89

 

 

 

3.58

 

 

 

 

 

 

(509

)

2018 - Calls

 

 

16,489,900

 

Mcf

 

 

 

 

 

 

 

 

4.64

 

 

 

 

 

 

(753

)

2018 - Collars

 

 

450,000

 

Mcf

 

 

 

 

 

3.20

 

 

 

3.65

 

 

 

 

 

 

(33

)

2018 - Basis Swaps - Dominion South

 

 

18,980,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

(0.80

)

 

 

(3,417

)

2018 - Basis Swaps - Texas Gas

 

 

14,600,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(0.13

)

 

 

62

 

2019 - Swaps

 

 

900,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

3.00

 

 

 

60

 

2019 - Basis Swaps - Dominion South

 

 

18,980,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

(0.81

)

 

 

(3,190

)

2020 - Basis Swaps - Dominion South

 

 

13,542,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

(0.80

)

 

 

(1,551

)

2021 - Basis Swaps - Dominion South

 

 

6,234,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

(0.73

)

 

 

(461

)

2022 - Basis Swaps - Dominion South

 

 

3,650,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

(0.72

)

 

 

(460

)

2023 - Basis Swaps - Dominion South

 

 

3,650,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

(0.72

)

 

 

(461

)

2024 - Basis Swaps - Dominion South

 

 

3,650,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

(0.72

)

 

 

(460

)

 

 

 

198,381,000

 

Mcf

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

(17,245

)

NGLs

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2017 - C3+ NGL Swaps

 

 

1,689,000

 

Bbls

 

 

 

 

 

 

 

 

 

 

 

0.71

 

 

$

(2,455

)

2017 - Ethane Swaps

 

 

840,000

 

Bbls

 

 

 

 

 

 

 

 

 

 

 

0.25

 

 

 

(237

)

2018 - C3+ NGL Swaps

 

 

1,068,000

 

Bbls

 

 

 

 

 

 

 

 

 

 

 

0.76

 

 

 

1,684

 

2018 - Ethane Swaps

 

 

660,000

 

Bbls

 

 

 

 

 

 

 

 

 

 

 

0.31

 

 

 

(15

)

2019 - Ethane Swaps

 

 

240,000

 

Bbls

 

 

 

 

 

 

 

 

 

 

 

0.31

 

 

 

(75

)

 

 

 

4,497,000

 

Bbls

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

(1,098

)

We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and prime rate based, as determined by our lenders, and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on our obligations. As of March 31, 2017, we did not have any interest rate derivatives in place, however we do from time to time enter interest rate derivatives to manage our interest rate exposure. We did not have any interest rate derivatives in place as of December 31, 2016. Based on our total debt as of March 31, 2017, of approximately $754.6 million, a 0.1% change in interest rates would impact our interest expense by approximately $0.8 million.

Item 4.

Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Such controls include those designed to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), to allow timely decisions regarding required disclosure.

Our management (with the participation of our CEO and CFO) has evaluated the effectiveness 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.

49


 

Based on this evaluation, our CEO and CFO have concluded that, as of March 31, 2017, our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) were effective to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) promulgated under the Exchange Act) during the quarter ended March 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Limitations Inherent in All Controls

Our management, including our CEO and CFO, recognizes that the disclosure controls and procedures and internal controls (discussed above) cannot prevent all errors or all attempts at fraud. Any controls system, no matter how well-crafted and operated, can only provide reasonable, and not absolute, assurance of achieving the desired control objectives. Because of the inherent limitations in any control system, no evaluation or implementation of a control system can provide complete assurance that all control issues and all possible instances of fraud have been, or will be, detected.

 

 

 

50


 

PART II

OTHER INFORMATION

 

Item 1.

Legal Proceedings.

The information set forth under the subsections Legal Reserves and Environmental in Note 12, Commitments and Contingencies, to our Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q is incorporated herein by reference.

Item 1A.

Risk Factors.

During the quarter ended March 31, 2017, there were no material changes to the risk factors previously reported in our Annual Report on Form 10-K for the year ended December 31, 2016.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 3.

Defaults upon Senior Securities.

None.

Item 4.

Mine Safety Disclosures.

None.

Item 5.

Other Information.

None.

Item 6.Exhibits.

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this Quarterly Report on Form 10-Q and incorporated herein by reference.

 

 

 

51


 

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.

 

 

 

 

 

REX ENERGY CORPORATION

(Registrant)

 

Date: May 10, 2017

 

 

 

By:

/s/ Thomas C. Stabley

 

 

 

 

 

Thomas C. Stabley

 

 

 

 

 

Chief Executive Officer

(Principal Executive Officer)

 

Date: May 10, 2017

 

 

 

By:

/s/ Thomas Rajan

 

 

 

 

 

Thomas Rajan

 

 

 

 

 

Chief Financial Officer

(Principal Financial Officer)

 

 

 

52


 

EXHIBIT INDEX

 

Exhibit
Number

 

Exhibit Title

 

2.1*+

 

 

Purchase and Sale Agreement by and among R.E. Gas Development, LLC, MFC Drilling, Inc., and ABARTA Oil & Gas Co., Inc., dated as of January 3, 2017.

 

3.1

 

 

Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007). 

 

3.2

 

 

Certificate of Amendment to Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007). 

 

3.3

 

 

Certificate of Designations, Preferences, Rights and Limitations of 6.00% Convertible Perpetual Preferred Stock, Series A, of Rex Energy Corporation (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K as filed with the SEC on August 18, 2014).

 

3.4

 

 

Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K as filed with the SEC on May 11, 2012).

 

3.5

 

 

Amendment to the Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K as filed with the SEC on August 18, 2014).

3.6

 

Amendment to the Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K as filed with the SEC on April 28, 2017).

 

4.1

 

 

Form of Specimen Common Stock Certificate of Rex Energy Corporation (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

 

4.2

 

 

Indenture dated as of December 12, 2012 among Rex Energy Corporation, the Guarantors named therein and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on December 12, 2012).

 

4.3

 

 

Form of 8.875% Senior Notes due 2020 (included in Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on December 12, 2012, and incorporated herein by reference).

 

4.4

 

 

Indenture dated as of July 17, 2014 among Rex Energy Corporation, the Guarantors named therein and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on July 17, 2014).

 

4.5

 

 

Form of 6.250% Senior Notes due 2022 (included in Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on July 17, 2014, and incorporated herein by reference).

 

4.6

 

 

Deposit Agreement, dated August 18, 2014, by and among the Company, Computershare Trust Company, N.A. and Computershare Inc., together as depositary, and holders from time to time of the depositary receipts described therein (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on August 18, 2014).

 

4.7

 

 

Form of Depositary Receipt Representing the Depositary Shares (included as Exhibit A to Exhibit 4.10) (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed with the SEC on August 18, 2014).

4.8

 

Indenture, dated as of March 31, 2016, among Rex Energy Corporation, the Guarantors and Wilmington Savings Fund Society, FSB, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed with SEC on March 31, 2016).

4.9

 

Form of 1.00%/8.00% Senior Secured Second Lien Notes Due 2020 (included in Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on March 31, 2016, and incorporated herein by reference).

4.10

 

First Supplemental Indenture, dated as of March 31, 2016, to the Indenture dated as of December 12, 2012, among Rex Energy Corporation, the Guarantors, and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.4 to our Current Report on Form 8-K filed with SEC on March 31, 2016).

4.11

 

First Supplemental Indenture, dated as of March 31, 2016, to the Indenture dated as of July 17, 2014, among Rex Energy Corporation, the Guarantors, and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.5 to our Current Report on Form 8-K filed with SEC on March 31, 2016).

10.1*

 

Twelfth Amendment to Amended and Restated Credit Agreement, effective as of January 11, 2017, by and among Rex Energy Corporation, Royal Bank of Canada, as Administrative Agent, and other lenders signatory thereto.

 

31.1*

 

 

Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.

 

31.2*

 

 

Certification of Chief Financial Officer (Principal Financial Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.

53


 

Exhibit
Number

 

Exhibit Title

 

32.1*

 

 

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the

Sarbanes-Oxley Act.

 

32.2*

 

 

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act.

 

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

 

 

* These exhibits are filed herewith.

+Confidential treatment has been requested with respect to certain portions of this exhibit. Omitted portions have been filed separately with the Securities and Exchange Commission.

 

54