10-Q 1 rexx-10q_20170331.htm 10-Q Q1 2017 rexx-10q_20170331.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.

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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