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EXCEL - IDEA: XBRL DOCUMENT - Titan Energy, LLCFinancial_Report.xls

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

x

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

For the quarterly period ended March 31, 2015

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: 001-35317

 

ATLAS RESOURCE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

 

 

Delaware

 

45-3591625

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification No.)

 

Park Place Corporate Center One
1000 Commerce Drive, Suite 400
Pittsburgh, Pennsylvania

 

15275

(Address of principal executive office)

 

(Zip code)

Registrant’s telephone number, including area code: (800) 251-0171

 

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

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

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

 

Large accelerated filer

 

x

  

Accelerated filer

 

¨

 

 

 

 

Non-accelerated filer

 

¨  (Do not check if smaller reporting company)

  

Smaller reporting company

 

¨

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

The number of outstanding common limited partner units of the registrant on May 5, 2015 was 87,204,616.

 

 

 

 

 


 

ATLAS RESOURCE PARTNERS, L.P.

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

TABLE OF CONTENTS

 

 

 

 

PAGE

 

PART I. FINANCIAL INFORMATION

 

 

 

 

 

 

 

Item 1.

 

 

Financial Statements (Unaudited)

 

3

 

 

 

 

 

 

 

 

Consolidated Balance Sheets as of March 31, 2015 and December 31, 2014

 

3

 

 

 

 

 

 

 

 

Consolidated Statements of Operations for the Three Months Ended March 31, 2015 and 2014

 

4

 

 

 

 

 

 

 

 

Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2015 and 2014

 

5

 

 

 

 

 

 

 

 

Consolidated Statement of Partners’ Capital for the Three Months Ended March 31, 2015

 

6

 

 

 

 

 

 

 

 

Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014

 

7

 

 

 

 

 

 

 

 

Notes to Consolidated Financial Statements

 

8

 

 

 

 

 

Item 2.

 

 

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

 

38

 

 

 

 

 

Item 3.

 

 

Quantitative and Qualitative Disclosures About Market Risk

 

60

 

 

 

 

 

Item 4.

 

 

Controls and Procedures

 

63

 

 

 

 

 

PART II. OTHER INFORMATION

 

 

 

 

 

 

 

Item 6.

 

 

Exhibits

 

64

 

 

 

 

 

SIGNATURES

 

69

 

 

 

2


 

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

 

 

March 31,

 

 

December 31,

 

 

2015

 

 

2014

 

ASSETS

 

 

 

  

 

 

 

Current assets:

 

 

 

  

 

 

 

Cash and cash equivalents

$

2,582

 

  

$

15,247

  

Accounts receivable

 

94,150

 

  

 

112,038

  

Advances to affiliates

 

21,328

 

 

 

 

Current portion of derivative asset

 

145,499

 

  

 

141,366

  

Subscriptions receivable

 

 

  

 

32,398

  

Prepaid expenses and other

 

27,856

 

  

 

26,011

  

Total current assets

 

291,415

 

  

 

327,060

  

 

Property, plant and equipment, net

 

2,198,436

 

  

 

2,208,171

 

Goodwill and intangible assets, net

 

14,271

 

 

 

14,330

 

Long-term derivative asset

 

186,718

 

  

 

127,933

  

Other assets, net

 

56,736

 

  

 

50,081

  

 

$

2,747,576

 

  

$

2,727,575

  

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

  

 

 

 

Current liabilities:

 

 

 

  

 

 

 

Accounts payable

$

93,548

 

  

$

109,049

  

Advances from affiliates

 

 

  

 

4,271

  

Liabilities associated with drilling contracts

 

16,956

 

  

 

40,611

  

Current portion of derivative payable to Drilling Partnerships

 

1,526

 

 

 

932

 

Accrued well drilling and completion costs

 

42,552

 

  

 

80,404

  

Accrued interest

 

11,424

 

 

 

26,452

 

Distribution payable

 

12,405

 

  

 

20,876

  

Accrued liabilities

 

28,795

 

  

 

56,463

  

Total current liabilities

 

207,206

 

  

 

339,058

  

 

Long-term debt

 

1,500,178

 

  

 

1,394,460

  

Asset retirement obligations

 

107,899

 

  

 

106,528

  

Other long-term liabilities

 

2,663

 

  

 

2,033

  

 

Commitments and contingencies

 

 

 

  

 

 

 

 

Partners’ Capital:

 

 

 

  

 

 

 

General partner’s interest

 

(13,842

)

  

 

(13,697

)

Preferred limited partners’ interests

 

182,968

 

  

 

163,522

  

Class C common limited partner warrants

 

1,176

 

  

 

1,176

  

Common limited partners’ interests

 

600,015

 

  

 

548,586

  

Accumulated other comprehensive income

 

159,313

 

  

 

185,909

  

Total partners’ capital

 

929,630

 

  

 

885,496

  

 

$

2,747,576

 

  

$

2,727,575

  

 

 

 

 

See accompanying notes to consolidated financial statements.

 

 

 

3


 

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

 

 

Three Months Ended
March 31,

 

 

2015

 

 

2014

 

Revenues:

 

 

 

 

 

 

 

Gas and oil production

$

100,972

  

 

$

96,245

 

Well construction and completion

 

23,655

  

 

 

49,377

 

Gathering and processing

 

2,184

  

 

 

4,468

 

Administration and oversight

 

1,259

  

 

 

1,729

 

Well services

 

6,624

  

 

 

5,479

 

Gain on mark-to-market derivatives

 

104,523

 

 

 

 

Other, net

 

30

  

 

 

47

 

Total revenues

 

239,247

  

 

 

157,345

 

 

 

 

 

 

 

 

 

Costs and expenses:

 

 

 

 

 

 

 

Gas and oil production

 

44,220

  

 

 

36,792

 

Well construction and completion

 

20,570

  

 

 

42,936

 

Gathering and processing

 

2,417

  

 

 

4,413

 

Well services

 

2,198

  

 

 

2,482

 

General and administrative

 

17,131

  

 

 

16,455

 

Depreciation, depletion and amortization

 

41,866

  

 

 

50,237

 

Total costs and expenses

 

128,402

  

 

 

153,315

 

 

 

 

 

 

 

 

 

Operating income

 

110,845

 

 

 

4,030

 

Interest expense

 

(25,197

)

 

 

(13,187

)

Loss on asset sales and disposal

 

(11

)

 

 

(1,603

)

 

Net income (loss)

 

85,637

 

 

 

(10,760

)

Preferred limited partner dividends

 

(3,653

)

 

 

(4,399

)

Net income (loss) attributable to common limited partners and the general partner

$

81,984

 

 

$

(15,159

)

 

 

 

 

 

 

 

 

Allocation of net income (loss) attributable to common limited partners and the general partner:

 

 

 

 

 

 

 

Common limited partners’ interest

$

80,344

 

 

$

(17,163

)

General partner’s interest

 

1,640

 

 

 

2,004

 

Net income (loss) attributable to common limited partners and the general partner

$

81,984

 

 

$

(15,159

)

Net income (loss) attributable to common limited partners per unit:

 

 

 

 

 

 

 

Basic

$

0.93

 

  

$

(0.28

)

Diluted

$

0.91

 

 

$

(0.28

)

Weighted average common limited partner units outstanding:

 

 

 

 

 

 

 

Basic

 

85,505

  

  

 

61,219

 

Diluted

 

89,985

 

 

 

61,219

 

 

 

 

 

See accompanying notes to consolidated financial statements.

 

 

 

4


 

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)

 

 

Three Months Ended

March 31,

 

 

2015

 

 

2014

 

Net income (loss)

$

85,637

 

 

$

(10,760

)

Other comprehensive income (loss):

 

 

 

 

 

 

 

Changes in fair value of derivative instruments accounted for as cash flow hedges

 

  

 

 

(34,844

)

Less: reclassification adjustment for realized (gains) losses of cash flow hedges in net income (loss)

 

(26,596

 

 

14,043

 

Total other comprehensive income (loss)

 

(26,596

)  

 

 

(20,801

)

Comprehensive income (loss) attributable to common and preferred limited partners and the general partner

$

59,041

 

 

$

(31,561

)

 

 

 

 

See accompanying notes to consolidated financial statements.

 

 

 

5


 

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in thousands, except unit data)

(Unaudited)

 

 

General
Partners’ Interest

 

 

Preferred Limited
Partners’ Interest

 

 

Common Limited
Partners’ Interests

 

 

Class C Common
Limited
Partner Warrants

 

 

Accumulated
Other Comprehensive
Income

 

 

Total
Partners’ Capita

 

 

Class A
Units

 

 

Amount

 

 

Class B
Units

 

 

Amount

 

 

Class C
Units

 

 

Amount

 

 

Class D
Units

 

 

Amount

 

 

Units

 

 

Amount

 

 

Warrants

 

 

Amount

 

 

 

 

 

Balance at December 31, 2014

 

1,819,113

 

 

$

(13,697

)

 

 

39,654

 

 

$

983

 

 

 

3,749,986

 

 

$

85,501

 

 

 

3,200,000

 

 

$

77,038

 

 

 

85,346,941

 

 

$

548,586

 

 

 

562,497

 

 

$

1,176

 

 

 

185,909

 

 

 

885,496

 

Issuance of units

 

14,243

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

800,000

 

 

 

19,980

 

 

 

420,586

 

 

 

3,327

 

 

 

 

 

 

 

 

 

 

 

 

23,307

 

Net issued and unissued units under incentive plans

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

277,307

 

 

 

3,435

 

 

 

 

 

 

 

 

 

 

 

 

3,435

 

Distributions payable

 

 

 

 

1,174

 

 

 

 

 

 

2

 

 

 

 

 

 

100

 

 

 

 

 

 

(182

)

 

 

 

 

 

7,433

 

 

 

 

 

 

 

 

 

 

 

 

8,527

 

Distributions paid to common and preferred limited partners and the general partner

 

 

 

 

(2,959

)

 

 

 

 

 

(21

)

 

 

 

 

 

(2,112

)

 

 

 

 

 

(1,974

)

 

 

 

 

 

(42,845

)

 

 

 

 

 

 

 

 

 

 

 

(49,911

)

Distribution equivalent rights paid on unissued units under incentive plan

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(265

)

 

 

 

 

 

 

 

 

 

 

 

(265

)

Net income

 

 

 

 

1,640

 

 

 

 

 

 

16

 

 

 

 

 

 

1,912

 

 

 

 

 

 

1,725

 

 

 

 

 

 

80,344

 

 

 

 

 

 

 

 

 

 

 

 

85,637

 

Other comprehensive loss

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(26,596

 

)

 

(26,596

)

Balance at March 31, 2015

 

1,833,356

 

 

$

(13,842

)

 

 

39,654

 

 

$

980

 

 

 

3,749,986

 

 

$

85,401

 

 

 

4,000,000

 

 

$

96,587

 

 

 

86,044,834

 

 

$

  600,015          

 

 

 

562,497

 

 

$

1,176

 

 

 

159,313

 

 

 

929,630

 

 

 

 

 

See accompanying notes to consolidated financial statements.

 

 

 

6


 

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

 

 

Three Months Ended March 31,

 

 

2015

 

 

2014

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

 

Net income (loss)

$

85,637

 

 

$

(10,760

)

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

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

41,866

 

 

 

50,237

 

Gain on mark-to-market derivatives

 

(104,523

)

 

 

 

Loss on asset sales and disposal

 

11

 

 

 

1,603

 

Non-cash compensation expense

 

3,344

 

 

 

2,343

 

Amortization of deferred financing costs

 

6,981

 

 

 

1,758

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Accounts receivable, prepaid expenses and other

 

38,393

 

 

 

16,111

 

Accounts payable and accrued liabilities

 

(82,548

)

 

 

(38,611

)

Net cash provided by (used in) operating activities

 

(10,839

)

 

 

22,681

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

 

 

Capital expenditures

 

(42,498

)

 

 

(39,897

)

Net cash paid for acquisitions

 

(4,602

)

 

 

 

Other

 

130

 

 

 

(514

)

Net cash used in investing activities

 

(46,970

)

 

 

(40,411

)

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

 

 

Borrowings under credit facilities

 

161,000

 

 

 

162,000

 

Borrowings under term loan facilities

 

242,500

 

 

 

 

Repayments under credit facilities

 

(298,000

)

 

 

(215,000

)

Distributions paid to unitholders

 

(49,911

)

 

 

(57,020

)

Net proceeds from issuance of common limited partner units

 

3,327

 

 

 

129,011

 

Deferred financing costs, distribution equivalent rights and other

 

(13,772

)

 

 

(1,124

)

Net cash provided by financing activities

 

45,144

  

 

 

17,867

 

Net change in cash and cash equivalents

 

(12,665

)

 

 

137

 

Cash and cash equivalents, beginning of year

 

15,247

  

 

 

1,828

 

Cash and cash equivalents, end of period

$

2,582

  

 

$

1,965

 

 

 

 

 

See accompanying notes to consolidated financial statements.

 

 

 

7


 

ATLAS RESOURCE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2015

(Unaudited)

 

NOTE 1 – BASIS OF PRESENTATION

Atlas Resource Partners, L.P. (the “Partnership”) is a publicly traded Delaware master-limited partnership (NYSE: ARP) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”) with operations in basins across the United States. The Partnership sponsors and manages tax-advantaged investment partnerships (the “Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas, crude oil and NGL production activities.

On February 27, 2015, the Partnership’s general partner, Atlas Energy Group, LLC (“Atlas Energy Group”; NYSE:  ATLS) distributed 100% of its common units to existing unitholders of its then parent, Atlas Energy, L.P. (“Atlas Energy”), which was a publicly traded master-limited partnership (NYSE: ATLS) (Atlas Energy and Atlas Energy Group are collectively referred to as “ATLS”).  Atlas Energy Group manages the Partnership’s operations and activities through its ownership of the Partnership’s general partner interest.  Concurrent with Atlas Energy Group’s unit distribution, Atlas Energy and its midstream ownership interests merged into Targa Resources Corp. (“Targa”; NYSE:  TRGP) and ceased trading.  At March 31, 2015, Atlas Energy Group owned 100% of the Partnership’s general partner Class A units, all of the incentive distribution rights through which it manages and effectively controls the Partnership and an approximate 27.5% limited partner interest (20,962,485 common and 3,749,986 preferred limited partner units) in the Partnership.

The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2014 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014. Certain amounts in the prior year’s financial statements have been reclassified to conform to the current year presentation. The results of operations for the three months ended March 31, 2015 may not necessarily be indicative of the results of operations for the full year ending December 31, 2015.

 

 

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The Partnership’s consolidated balance sheets at March 31, 2015 and December 31, 2014 and the consolidated statements of operations for the three months ended March 31, 2015 and 2014 include the accounts of the Partnership and its wholly-owned subsidiaries. Transactions between the Partnership and other ATLS operations have been identified in the consolidated financial statements as transactions between affiliates, where applicable. All material intercompany transactions have been eliminated.

In accordance with established practice in the oil and gas industry, the Partnership’s consolidated financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Drilling Partnerships in which the Partnership has an interest. Such interests generally approximate 30%. The Partnership’s consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships. Rather, the Partnership calculates these items specific to its own economics as further explained under the heading “Property, Plant and Equipment” elsewhere within this note.

Use of Estimates

The preparation of the Partnership’s consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired and liabilities assumed. Actual results could differ from those estimates.

8


 

The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three months ended March 31, 2015 and 2014 represent actual results in all material respects (see “Revenue Recognition”).

Receivables

Accounts receivable on the consolidated balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of accounts receivable, the Partnership’s management performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness, as determined by management’s review of the Partnership’s customers’ credit information. The Partnership extends credit on sales on an unsecured basis to many of its customers. At March 31, 2015 and December 31, 2014, the Partnership had recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets.

Inventory

The Partnership had $8.1 million and $8.6 million of inventory at March 31, 2015 and December 31, 2014, respectively, which was included within prepaid expenses and other current assets on the Partnership’s consolidated balance sheets. The Partnership values inventories at the lower of cost or market. The Partnership’s inventories, which consist of materials, pipes, supplies and other inventories, were principally determined using the average cost method.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Partnership’s results of operations.

The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and NGLs are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. Mcf is defined as one thousand cubic feet.

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include the Partnership’s costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by the Partnership for its interests, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Partnership’s consolidated statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its consolidated balance sheets. Upon the Partnership’s sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Partnership’s consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Impairment of Long-Lived Assets

The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not

9


 

be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published future prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, the Partnership’s reserve estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include the Partnership’s actual capital contributions, a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

 

The Partnership’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to the Partnership operating and administrative fees in addition to their proportionate share of external operating expenses. These assumptions could result in the Partnership’s calculation of depletion and impairment being different than its proportionate share of the Drilling Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods.

The Partnership’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships, which the Partnership sponsors and owns an interest in but does not control. The Partnership’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which the Partnership may be unable to recover due to the Drilling Partnerships’ legal structure. The Partnership may have to pay additional consideration in the future as a Drilling Partnership’s wells become uneconomic to the Drilling Partnership under the terms of the Drilling Partnership’s drilling and operating agreement in order to recover these excess reserves, in addition to the Partnership becoming responsible for paying associated future operating, development and plugging costs of the well interests acquired, and to acquire any additional residual interests in the wells held by the Drilling Partnership’s limited partners. The acquisition of any such uneconomic well interest from the Drilling Partnership by the Partnership is governed under the Drilling Partnership’s limited partnership agreement. In general, the Partnership will seek consent from the Drilling Partnership’s limited partners to acquire the well interests from the Drilling Partnership based upon the Partnership’s determination of fair market value.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate the Partnership will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. There were no impairments of unproved gas and oil properties recorded by the Partnership for the three months ended March 31, 2015 and 2014.

Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2014, the Partnership recognized $555.7 million of asset impairment related to oil and gas properties within property, plant and equipment, net on its consolidated balance sheet for its Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014. There were no impairments of proved gas and oil properties recorded by the Partnership for the three months ended March 31, 2015 and 2014.

The impairment of proved properties during the year ended December 31, 2014 related to the carrying amounts of these gas and oil properties being in excess of the Partnership’s estimate of their fair values at December 31, 2014. The estimate of

10


 

the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of commodity prices at the date of measurement.  

Capitalized Interest

The Partnership capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rate used to capitalize interest on borrowed funds by the Partnership was 6.1% and 5.6% for the three months ended March 31, 2015 and 2014, respectively. The aggregate amount of interest capitalized by the Partnership was $3.9 million and $2.6 million for the three months ended March 31, 2015 and 2014, respectively.

Intangible Assets

The Partnership recorded its intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. The Partnership amortizes contracts acquired on a declining balance method over their respective estimated useful lives.

The following table reflects the components of intangible assets being amortized at March 31, 2015 and December 31, 2014 (in thousands):

 

 

March 31,

 

 

December 31,

 

 

Estimated
Useful Lives

 

 

2015

 

 

2014

 

 

In Years

 

Gross Carrying Amount

$

14,344

   

   

$

14,344

   

 

 

13

 

Accumulated Amortization

 

(13,712

)

 

 

(13,653

)

 

 

 

 

Net Carrying Amount

$

632

 

 

$

691

   

 

 

 

 

 

Amortization expense on intangible assets was $0.1 million for both the three months ended March 31, 2015 and 2014, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2015 - $0.2 million; 2016 - $0.1 million; 2017 - $0.1 million; 2018 - $0.1 million; and 2019 - $0.1 million.

Goodwill

At March 31, 2015 and December 31, 2014, the Partnership had $13.6 million of goodwill recorded in connection with its prior consummated acquisitions. No changes in the carrying amount of goodwill were recorded for the three months ended March 31, 2015 and 2014.  

The Partnership tests goodwill for impairment at each year end by comparing its reporting units’ estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, the Partnership’s management must apply judgment in determining the estimated fair value of these reporting units. The Partnership’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the Partnership’s assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to the Partnership’s market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including the Partnership’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, the Partnership’s management also considers the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in the Partnership’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in the Partnership’s industry to determine whether those valuations appear reasonable in management’s judgment. Management will continue to evaluate goodwill at least annually or when impairment indicators arise.

As a result of its goodwill impairment evaluation at December 31, 2014, the Partnership recognized an $18.1 million non-cash impairment charge within asset impairments on its consolidated statement of operations for the year ended December 31, 2014. The goodwill impairment resulted from the reduction in the Partnership’s estimated fair value of its gas

11


 

and oil production reporting unit in comparison to its carrying amount at December 31, 2014. The Partnership’s estimated fair value of its gas and oil production reporting unit was impacted by a decline in overall commodity prices during the fourth quarter of 2014.

Derivative Instruments

The Partnership enters into certain financial contracts to manage its exposure to movement in commodity prices and interest rates (see Note 8). The derivative instruments recorded in the consolidated balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s consolidated statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Partnership discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 will be reclassified to the consolidated statements of operations in the periods in which those respective derivative contracts settle. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within partners’ capital on the Partnership’s consolidated balance sheets and reclassified to the Partnership’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings.

Asset Retirement Obligations

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 6). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depreciation, depletion and amortization.

Income Taxes

The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the accompanying consolidated financial statements. Certain corporate subsidiaries of the Partnership are subject to federal and state income tax. The federal and state income taxes related to the Partnership and these corporate subsidiaries were immaterial to the consolidated financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the accompanying consolidated financial statements.

The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its consolidated financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Partnership has not recognized any potential interest or penalties in its consolidated financial statements for the three months ended March 31, 2015 and 2014.

The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of March 31, 2015.

Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of the general partner’s and the preferred unitholders’ interests, by the weighted average number of common limited partner units outstanding during the period. Net income (loss) attributable to common limited partners is determined by deducting net income attributable to participating securities, if applicable, income (loss) attributable to preferred limited partners and net income (loss) attributable to the general partner’s Class A units. The general partner’s interest in net income (loss) is calculated on a quarterly basis based upon its Class A units and incentive distributions to be distributed for the quarter (see Note 13), with a priority allocation of net income to the general partner’s incentive distributions, if any, in accordance with the partnership agreement, and the remaining net income (loss) allocated with respect to the general partner’s and limited partners’ ownership interests.

12


 

The Partnership presents net income (loss) per unit under the two-class method for master limited partnerships, which considers whether the incentive distributions of a master limited partnership represent a participating security when considered in the calculation of earnings per unit under the two-class method. The two-class method considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, management of the Partnership believes the partnership agreement contractually limits cash distributions to available cash; therefore, undistributed earnings are not allocated to the incentive distribution rights.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. Phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plan (see Note 14), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights would result in a non-contingent transfer of value each time the Partnership declares a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis.

The following is a reconciliation of net income (loss) allocated to the common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except unit data):

 

 

 

Three Months Ended
March 31,

 

 

 

2015

 

 

2014

 

Net income (loss)

 

$

85,637

 

 

$

(10,760

)

Preferred limited partner dividends

 

 

(3,653

)

 

 

(4,399

)

Net income (loss) attributable to common limited partners and the general partner

 

 

81,984

 

 

 

(15,159

)

Less: General partner’s interest

 

 

(1,640

)

 

 

(2,004

)

Net income (loss) attributable to common limited partners

 

 

80,344

 

 

 

(17,163

)

Less: Net income attributable to participating securities – phantom units(1)

 

 

(644

)

 

 

 

Net income (loss) utilized in the calculation of net loss attributable to common limited partners per unit - Basic

 

$

79,700

 

 

$

(17,163

)

Plus: Convertible preferred limited partner dividends

 

 

1,928

 

 

 

 

Net income (loss) utilized in the calculation of net loss attributable to common limited partners per unit - Diluted

 

$

81,628

 

 

$

(17,163

)

 

 

(1)

Net income attributable to common limited partners’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding).  For the three months ended March 31, 2014, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 820,000 phantom units because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.

Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, convertible preferred units and warrants, as calculated by the treasury stock or if converted methods, as applicable. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Partnership’s long-term incentive plan (see Note 14).

13


 

The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands):

 

 

 

Three Months Ended
March 31,

 

 

 

2015

 

 

2014

 

Weighted average number of common limited partner units - basic

 

 

85,505

 

 

 

61,219

 

Add effect of dilutive incentive awards(1)

 

 

691

 

 

 

 

Add effect of dilutive convertible preferred limited partner units and warrants(2)

 

 

3,789

 

 

 

 

Weighted average number of common limited partner units - diluted

 

 

89,985

 

 

 

61,219

 

 

 

(1)

For the three months ended March 31, 2014, 820,000 phantom units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive.

(2)

For the three months ended March 31, 2014, potential common limited partner units issuable upon conversion of the Partnership’s Class B preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. For the three months ended March 31, 2014, potential common limited partner units issuable upon (a) conversion of the Partnership’s Class C preferred units and (b) exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. At March 31, 2015, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. As the Class D preferred units are convertible only upon a change of control event, they are not considered dilutive securities for earnings per unit purposes.

Revenue Recognition

Natural gas and oil production. The Partnership generally sells natural gas, crude oil and NGLs at prevailing market prices. Typically, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.

Drilling Partnerships. Certain energy activities are conducted by the Partnership through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by the Partnership is deployed to drill and complete wells included within the partnership. As the Partnership deploys Drilling Partnership investor capital, it recognizes certain management fees it is entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if the Partnership has Drilling Partnership investor capital that has not yet been deployed, it will recognize a current liability titled “Liabilities Associated with Drilling Contracts” on the Partnership’s consolidated balance sheets. After the Drilling Partnership well is completed and turned in line, the Partnership is entitled to receive additional operating and management fees, which are included within well services and administration and oversight revenue, respectively, on a monthly basis while the well is operating. In addition to the management fees it is entitled to receive for services provided, the Partnership is also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which generally approximates 30%. The Partnership recognizes its Drilling Partnership management fees in the following manner:

·

Well construction and completion. For each well that is drilled by a Drilling Partnership, the Partnership receives a 15% mark-up on those costs incurred to drill and complete wells included within the partnership. Such fees are earned, in accordance with the partnership agreement, and recognized as the services are performed, typically between 60 and 270 days, using the percentage of completion method.

·

Administration and oversight. For each well drilled by a Drilling Partnership, the Partnership receives a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which is earned in accordance with the partnership agreement and recognized at the initiation of the well. Additionally, the Drilling Partnership pays the

14


 

Partnership a monthly per well administrative fee of $75 for the life of the well. The well administrative fee is earned on a monthly basis as the services are performed.

·

Well services. Each Drilling Partnership pay the Partnership a monthly per well operating fee, currently $1,000 to $2,000, depending on the type of well, for the life of the well. Such fees are earned on a monthly basis as the services are performed.

While the historical structure has varied, the Partnership has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically from 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. The Partnership periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, the Partnership recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which the Partnership has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, the Partnership will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized.

Gathering and processing revenue. Gathering and processing revenue includes gathering fees the Partnership charges to the Drilling Partnership wells for the Partnership’s processing plants in the New Albany and the Chattanooga Shales. Generally, the Partnership charges a gathering fee to the Drilling Partnership wells equivalent to the fees the Partnership remits. In Appalachia, a majority of the Drilling Partnership wells are subject to a gathering agreement, whereby the Partnership remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, the Partnership charges the Drilling Partnership wells a 13% gathering fee. As a result, some of the Partnership’s gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%.

The Partnership’s gas and oil production operations accrue unbilled revenue due to timing differences between the delivery of natural gas, NGLs and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” for further description). The Partnership had unbilled revenues at March 31, 2015 and December 31, 2014 of $53.2 million and $82.3 million, respectively, which were included in accounts receivable within the Partnership’s consolidated balance sheets.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s consolidated financial statements, and for all periods presented, only include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges (see Note 8). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss).  

Recently Issued Accounting Standards

In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (“Update 2015-06”). Under Topic 260, Earnings per Share, master limited partnerships (“MLPs”) apply the two-class method to calculate earnings per unit (“EPU”) because the general partner, limited partners, and incentive distribution rights holders each participate differently in the distribution of available cash. When a general partner transfers (or “drops down”) net assets to a master limited partnership and that transaction is accounted for as a transaction between entities under common control, the statements of operations of the master limited partnership are adjusted retrospectively to reflect the drop down transaction as if it occurred on the earliest date during which the entities were under common control. The amendments in Update 2015-06 specify that for purposes of calculating historical EPU under the two-class method, the earnings (losses) of a transferred business before the date of a drop down transaction should be allocated entirely to the

15


 

general partner interest, and previously reported EPU of the limited partners would not change as a result of a drop down transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the drop down transaction occurs also are required. The amendments in Update 2015-06 are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted and amendments in Update 2015-06 should be applied retrospectively for all financial statements presented. The Partnership will adopt the requirements of Update 2015-06 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In March 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30) (“Update 2015-03”). The amendments in Update 2015-03 are intended to simplify presentation of debt issuance costs and require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discountsThe recognition and measurement guidance for debt issuance costs would not be affected by the amendments in Update 2015-03. The amendments in Update 2015-03 are effective for periods beginning after December 15, 2015, and interim periods within those periods. Early adoption is permitted, including adoption in an interim period, and an entity should apply the new guidance on a retrospective basis. The Partnership will adopt the requirements of Update 2015-03 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“Update 2015-02”). The amendments in Update 2015-02 are intended to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures.  The amendments simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The amendments in Update 2015-02 are effective for periods beginning after December 31, 2015. Early adoption is permitted, including adoption in an interim period. The Partnership will adopt the requirements of Update 2015-02 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The Partnership will adopt the requirements of Update 2015-01 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815) – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity (“Update 2014-16”). Certain classes of shares include features that entitle the holders to preferences and rights (such as conversion rights, redemption rights, voting powers, and liquidation and dividend payment preferences) over the other shareholders. Shares that include embedded derivative features are referred to as hybrid financial instruments, which must be separated from the host contract and accounted for as a derivative if certain criteria are met under Subtopic 815-10. One criterion requires evaluating whether the nature of the host contract is more akin to debt or to equity and whether the economic characteristics and risks of the embedded derivative feature are “clearly and closely related” to the host contract. In making that evaluation, an issuer or investor may consider all terms and features in a hybrid financial instrument including the embedded derivative feature that is being evaluated for separate accounting or may consider all terms and features in the hybrid financial instrument except for the embedded derivative feature that is being evaluated for separate accounting. The use of different methods can result in different accounting outcomes for economically similar hybrid financial instruments. Additionally, there is diversity in practice with respect to the consideration of redemption features in relation to other features when determining whether the nature of a host contract is more akin to debt or to equity. The amendments in Update 2014-16 clarify how current U.S. GAAP should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. The effects of initially adopting the amendments in Update 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in the form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. The amendments in Update 2014-16 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption, including adoption in an interim period, is permitted. The Partnership will adopt the requirements of Update 2014-16 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

16


 

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date in 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In June 2014, the FASB issued ASU 2014-12, Compensation – Stock Compensation (Topic 718) (“Update 2014-12”). The amendments in Update 2014-12 require that a performance target that affects vesting and that could be achieved after the requisite service period, be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in Update 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. The Partnership will adopt the requirements of Update 2014-12 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to 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. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. On April 1, 2015, the FASB tentatively decided to defer the effective date of ASU 2014-09 by one year. As a result, public entities would apply the new revenue standard to annual reporting periods beginning after December 15, 2017, and to interim periods within that reporting period, with early adoption permitted.

 

 

NOTE 3 – ACQUISITIONS

Rangely Acquisition

On June 30, 2014, the Partnership completed an acquisition of a 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado from Merit Management Partners I, L.P., Merit Energy Partners III, L.P. and Merit Energy Company, LLC (collectively, “Merit Energy”) for approximately $408.9 million in cash, net of purchase price adjustments (the “Rangely Acquisition”). The purchase price was funded through borrowings under the Partnership’s revolving credit facility, the issuance of an additional $100.0 million of its 7.75% senior notes due 2021 (“7.75% Senior Notes”) (see Note 7) and the issuance of 15,525,000 common limited partner units (see Note 12). The Rangely Acquisition had an effective date of April 1, 2014. The Partnership’s consolidated financial statements reflected the operating results of the acquired business commencing June 30, 2014 with the transaction closing.

17


 

The Partnership accounted for this transaction under the acquisition method of accounting. Accordingly, the Partnership evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9). In conjunction with the issuance of common limited partner units associated with the acquisition, the Partnership recorded $11.6 million of transaction fees, which were included with common limited partners’ interests for the year ended December 31, 2014 on the Partnership’s consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as the Partnership continues to evaluate the facts and circumstances that existed as of the acquisition date.

The following table presents the preliminary values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

 

Assets:

 

 

 

Prepaid expenses and other

$

4,041

 

Property, plant and equipment

 

405,416

 

Other assets, net

 

2,888

 

Total assets acquired

$

412,345

 

 

 

 

 

Liabilities:

 

 

 

Accrued liabilities

 

2,117

 

Asset retirement obligation

 

1,305

 

Total liabilities assumed

 

3,422

 

Net assets acquired

$

408,923

 

 

Other Acquisitions

On November 5, 2014, the Partnership and the general partner’s private development subsidiary (the “Development Subsidiary”) completed an acquisition of oil and natural gas liquid interests in the Eagle Ford Shale in Atascosa County, Texas from Cima Resources, LLC and Cinco Resources, Inc. (together “Cinco”) for $339.2 million, net of purchase price adjustments (the “Eagle Ford Acquisition”). Approximately $179.5 million was paid in cash by the Partnership and $19.7 million was paid by the Development Subsidiary at closing, and approximately $140.0 million was to be paid in four quarterly installments beginning December 31, 2014. On December 31, 2014, the Development Subsidiary made its first installment payment of $35.0 million related to its Eagle Ford Acquisition. Prior to the March 31, 2015 installment, the Partnership, the Development Subsidiary, and Cinco amended the purchase and sale agreement to alter the timing and amount of the quarterly payments beginning with the March 31, 2015 payment and ending December 31, 2015, with no change to the overall purchase price. On March 31, 2015, the Development Subsidiary paid $28.3 million and the Partnership issued $20.0 million of its Class D Preferred Units (see Note 12) to satisfy the second installment related to the Eagle Ford Acquisition. At March 31, 2015, the Partnership’s remaining deferred portion of the purchase price was $4.2 million, which consisted of $1.3 million, $1.3 million, and $1.6 million on June 30, 2015, September 30, 2015, and December 31, 2015, respectively.  The Partnership’s issuance of Class D Preferred Units represents a non-cash transaction for statement of cash flow purposes during the three months ended March 31, 2015.

On May 12, 2014, the Partnership completed the acquisition of certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $97.9 million in cash, net of purchase price adjustments, with an effective date of January 1, 2014. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia.

 

 

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NOTE 4 – PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment at the dates indicated (in thousands):

 

 

March 31,

 

 

December 31,

 

 

Estimated
Useful Lives

 

 

2015

 

 

2014

 

 

in Years

 

Natural gas and oil properties:

 

 

 

 

 

 

 

 

 

 

 

Proved properties:

 

 

 

 

 

 

 

 

 

 

 

Leasehold interests

$

444,035

 

 

$

441,548

 

 

 

 

 

Pre-development costs

 

8,912

 

 

 

7,223

 

 

 

 

 

Wells and related equipment

 

2,981,128

 

 

 

2,962,202

 

 

 

 

 

Total proved properties

 

3,434,075

 

 

 

3,410,973

 

 

 

 

 

Unproved properties

 

220,094

 

 

 

217,174

 

 

 

 

 

Support equipment

 

40,687

 

 

 

37,062

 

 

 

 

 

Total natural gas and oil properties

 

3,694,856

 

 

 

3,665,209

 

 

 

 

 

Pipelines, processing and compression facilities

 

50,493

 

 

 

49,462

 

 

 

2 – 40

 

Rights of way

 

829

 

 

 

830

 

 

 

20 – 40

 

Land, buildings and improvements

 

9,201

 

 

 

9,160

 

 

 

3 – 40

 

Other

 

18,055

 

 

 

17,932

 

 

 

3 – 10

 

 

 

3,773,434

 

 

 

3,742,593

 

 

 

 

 

Less – accumulated depreciation, depletion and amortization

 

(1,574,998

)

 

 

(1,534,422

)

 

 

 

 

 

$

2,198,436

 

 

$

2,208,171

 

 

 

 

 

 

During the three months ended March 31, 2015, the Partnership recognized approximately $11,000 of loss on asset sales and disposals. During the three months ended March 31, 2014, the Partnership recognized $1.6 million of loss on asset sales and disposals primarily related to the sale of producing wells in the Niobrara Shale in connection with the settlement of a third party farmout agreement.

There were no asset impairments for the three months ended March 31, 2015 and 2014. During the year ended December 31, 2014, the Partnership recognized $555.7 million of asset impairment related to oil and gas properties within property, plant and equipment, net on its consolidated balance sheet for its Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014.  This impairment related to the carrying amounts of gas and oil properties being in excess of the Partnership’s estimate of their fair values at December 31, 2014. The estimates of fair values of these gas and oil properties were impacted by, among other factors, the deterioration of commodity prices at the date of measurement.

During the three months ended March 31, 2015 and 2014, the Partnership recognized $16.3 million and $13.4 million, respectively, of non-cash property, plant and equipment additions, which were included within the changes in accounts payable and accrued liabilities on the Partnership’s consolidated statements of cash flows.

 

 

NOTE 5 – OTHER ASSETS

The following is a summary of other assets at the dates indicated (in thousands):

 

 

March 31,

 

 

December 31,

 

 

2015

 

  

2014

 

Deferred financing costs, net of accumulated amortization of $25,603 and $18,622 at March 31, 2015 and December 31, 2014, respectively

$

47,381

 

 

$

40,637

 

Notes receivable

 

3,926

 

 

 

3,866

 

Other

 

5,429

 

 

 

5,578

 

 

$

56,736

 

 

$

50,081

 

 

Deferred financing costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 7). Amortization expense of deferred financing costs was $2.7 million and $1.8 million for the three months ended March 31, 2015 and 2014, respectively, which was recorded within interest expense on the Partnership’s consolidated statements of

19


 

operations. During the three months ended March 31, 2015, the Partnership recognized $4.3 million for accelerated amortization of deferred financing costs associated with a reduction of the borrowing base under the revolving credit facility. There was no accelerated amortization of deferred financing costs during the three months ended March 31, 2014.

At March 31, 2015 and December 31, 2014, the Partnership had notes receivable with certain investors of its Drilling Partnerships, which were included within other assets, net on the Partnership’s consolidated balance sheets. The notes have a maturity date of March 31, 2022, and a 2.25% per annum interest rate. The maturity date of the notes can be extended to March 31, 2027, subject to certain conditions, including an extension fee of 1.0% of the outstanding principal balance. For the three months ended March 31, 2015 and 2014, approximately $21,000 and $23,000, respectively, of interest income was recognized within other, net on the Partnership’s consolidated statements of operations. At March 31, 2015 and December 31, 2014, the Partnership recorded no allowance for credit losses within its consolidated balance sheets based upon payment history and ongoing credit evaluations associated with the notes receivable.

 

 

NOTE 6 – ASSET RETIREMENT OBLIGATIONS

The Partnership recognized an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities. The Partnership also recognized a liability for its future asset retirement obligations where a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability for asset retirement obligations was based on the Partnership’s historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its gas and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets.

The Partnership proportionately consolidates its ownership interest of the asset retirement obligations of its Drilling Partnerships. At March 31, 2015, the Drilling Partnerships had $45.1 million of aggregate asset retirement obligation liabilities recognized on their combined balance sheets allocable to the limited partners, exclusive of the Partnership’s proportional interest in such liabilities. Under the terms of the respective partnership agreements, the Partnership maintains the right to retain a portion or all of the distributions to the limited partners of its Drilling Partnerships to cover the limited partners’ share of the plugging and abandonment costs up to a specified amount per month. As of March 31, 2015, the Partnership has withheld $2.1 million of limited partner distributions related to the asset retirement obligations of certain Drilling Partnerships. The Partnership’s historical practice and continued intention is to retain distributions from the limited partners as the wells within each Drilling Partnership near the end of their useful life. On a partnership-by-partnership basis, the Partnership assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity price trends, the natural decline in the production of the wells, and current and future costs. Generally, the Partnership’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon the Partnership’s decision to retain all future distributions to the limited partners of its Drilling Partnerships, the Partnership will assume the related asset retirement obligations of the limited partners.

A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):

 

 

  

Three Months Ended
March 31,

 

 

  

2015

 

  

2014

 

Asset retirement obligations, beginning of year

  

$

106,528

 

  

$

89,776

  

Liabilities incurred

  

 

165

 

  

 

529

 

Liabilities settled

  

 

(347

)

  

 

(217

)

Accretion expense

  

 

1,553

 

  

 

1,301

  

Asset retirement obligations, end of period

  

$

107,899

 

  

$

91,389

  

 

20


 

The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated statements of operations.  During the year ended December 31, 2014, the Partnership incurred $7.0 million of future plugging and abandonment costs related to acquisitions it consummated (see Note 3). No future plugging and abandonment liabilities related to consummated acquisitions were incurred during the three months ended March 31, 2015 and 2014.

 

 

NOTE 7 - DEBT

Total debt consists of the following at the dates indicated (in thousands):

 

 

March 31,

 

 

December 31,

 

 

2015

 

 

2014

 

Revolving credit facility

$

559,000

 

 

$

696,000

 

Term loan facility

 

242,658

 

 

 

 

7.75 % Senior Notes – due 2021

 

374,563

 

 

 

374,544

 

9.25 % Senior Notes – due 2021

 

323,957

 

 

 

323,916

 

Total debt

 

1,500,178

 

 

 

1,394,460

 

Less current maturities

 

 

 

 

 

Total long-term debt

$

1,500,178

 

 

$

1,394,460

 

 

Credit Facility

On February 23, 2015, the Partnership entered into a Sixth Amendment to its Second Amended and Restated Credit Agreement dated July 31, 2013 with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (the “Credit Agreement”).  Among other things, the Sixth Amendment:

·

reduces the borrowing base under the Credit Agreement from $900.0 million to $750.0 million;

·

permits the incurrence of second lien debt in an aggregate principal amount up to $300.0 million;

·

reschedules the Partnership’s May 1, 2015 borrowing base redetermination for July 1, 2015;

·

if the borrowing base utilization (as defined in the Credit Agreement) is less than 90%, increases the applicable margin on Eurodollar loans and ABR loans by 0.25% from previous levels;

·

following the next scheduled redetermination of the borrowing base, upon the issuance of senior notes or the incurrence of second lien debt, reduces the borrowing base by 25% of the stated amount of such senior notes or additional second lien debt; and

·

revises the maximum ratio of Total Funded Debt to EBITDA to be (i) 5.25 to 1.0 as of the last day of the quarters ended on March 31, 2015, June 30, 2015, September 30, 2015, December 31, 2015 and March 31, 2016, (ii) 5.00 to 1.0 as of the last day of the quarters ended on June 30, 2016, September 30, 2016 and December 31, 2016, (iii) 4.50 to 1.0 as of the last day of the quarter ended on March 31, 2017 and (iv) 4.00 to 1.0 as of the last day of each quarter thereafter.

The Partnership’s borrowing base is scheduled for semi-annual redeterminations on May 1 and November 1 of each year. At March 31, 2015, $559.0 million was outstanding under the credit facility. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which $4.3 million was outstanding at March 31, 2015. The Partnership’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of the Partnership’s material subsidiaries, and any non-guarantor subsidiaries of the Partnership are minor. Borrowings under the credit facility bear interest, at the Partnership’s election, at either an adjusted LIBOR rate plus an applicable margin between 1.50% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.50% and 1.75% per annum. The Partnership is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.375% per annum if less than 50% of the borrowing base is utilized and 0.5% if 50% or more of the borrowing base is utilized, which is included within interest expense on the Partnership’s consolidated statements of operations. At March 31, 2015, the weighted average interest rate on outstanding borrowings under the credit facility was 2.8%.

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The Credit Agreement contains customary covenants that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. The Partnership was in compliance with these covenants as of March 31, 2015. The Credit Agreement also requires the Partnership to maintain a ratio of Total Funded Debt (as defined in the Credit Agreement) to EBITDA (as defined in the Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than (i) 5.25 to 1.0 as of the last day of the quarters ended on March 31, 2015, June 30, 2015, September 30, 2015, December 31, 2015 and March 31, 2016, (ii) 5.00 to 1.0 as of the last day of the quarters ended on June 30, 2016, September 30, 2016 and December 31, 2016, (iii) 4.50 to 1.0 as of the last day of the quarter ended on March 31, 2017 and (iv) 4.00 to 1.0 as of the last day of each quarter thereafter, and a ratio of current assets (as defined in the Credit Agreement) to current liabilities (as defined in the Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. Based on the definitions contained in the Partnership’s Credit Agreement, at March 31, 2015, the Partnership’s ratio of current assets to current liabilities was 1.6 to 1.0, and its ratio of Total Funded Debt to EBITDA was 4.2 to 1.0.

Term Loan Facility

On February 23, 2015, the Partnership entered into a Second Lien Credit Agreement with certain lenders and Wilmington Trust, National Association, as administrative agent. The Second Lien Credit Agreement provides for a second lien term loan in an original principal amount of $250.0 million (the “Term Loan Facility”).  The Term Loan Facility matures on February 23, 2020.  The Term Loan Facility is presented net of unamortized discount of $7.3 million at March 31, 2015.

The Partnership has the option to prepay the Term Loan Facility at any time, and is required to offer to prepay the Term Loan Facility with 100% of the net cash proceeds from the issuance or incurrence of any debt and 100% of the excess net cash proceeds from certain asset sales and condemnation recoveries. The Partnership is also required to offer to prepay the Term Loan Facility upon the occurrence of a change of control. All prepayments are subject to the following premiums, plus accrued and unpaid interest:

·

the make-whole premium (plus an additional amount if such prepayment is optional and funded with proceeds from the issuance of equity) for prepayments made during the first 12 months after the closing date;

·

4.5% of the principal amount prepaid for prepayments made between 12 months and 24 months after the closing date;

·

2.25% of the principal amount prepaid for prepayments made between 24 months and 36 months after the closing date; and

·

no premium for prepayments made following 36 months after the closing date.

The Partnership’s obligations under the Term Loan Facility are secured on a second priority basis by security interests in all of its assets and those of its restricted subsidiaries (the “Loan Parties”) that guarantee the Partnership’s existing first lien revolving credit facility. In addition, the obligations under the Term Loan Facility are guaranteed by the Partnership’s material restricted subsidiaries.  Borrowings under the Term Loan Facility bear interest, at the Partnership’s option, at either (i) LIBOR plus 9.0% or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 8.0% (an “ABR Loan”).  Interest is generally payable at the applicable maturity date for Eurodollar loans and quarterly for ABR loans. At March 31, 2015, the weighted average interest rate on outstanding borrowings under the term loan facility was 10.0%.

The Second Lien Credit Agreement contains customary covenants that limit the Partnership’s ability to make restricted payments, take on indebtedness, issue preferred stock, grant liens, conduct sales of assets and subsidiary stock, make distributions from restricted subsidiaries, conduct affiliate transactions and engage in other business activities.  In addition, the Second Lien Credit Agreement contains covenants substantially similar to those in the Partnership’s existing first lien revolving credit facility, including, among others, restrictions on swap agreements, debt of unrestricted subsidiaries, drilling and operating agreements and the sale or discount of receivables. The Partnership was in compliance with these covenants as of March 31, 2015.

Under the Second Lien Credit Agreement, the Partnership may elect to add one or more incremental term loan tranches to the Term Loan Facility so long as the aggregate outstanding principal amount of the Term Loan Facility plus the principal amount of any incremental term loan does not exceed $300.0 million and certain other conditions are adhered to.  Any such incremental term loans may not mature on a date earlier than February 23, 2020.

22


 

Senior Notes

At March 31, 2015, the Partnership had $374.6 million outstanding of its 7.75% senior unsecured notes due 2021 (“7.75% Senior Notes”). The 7.75% Senior Notes were presented net of a $0.4 million unamortized discount as of March 31, 2015. Interest on the 7.75% Senior Notes is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% Senior Notes are redeemable for up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, the Partnership may redeem the 7.75% Senior Notes in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (as defined in the governing indenture), plus accrued and unpaid interest and additional interest, if any. On and after January 15, 2017, the 7.75% Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019.  Under certain conditions, including if the Partnership sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, the Partnership must offer to repurchase the 7.75% Senior Notes.

At March 31, 2015, the Partnership had $324.0 million outstanding of its 9.25% senior unsecured notes due 2021 (“9.25% Senior Notes”). The 9.25% Senior Notes were presented net of a $1.0 million unamortized discount as of March 31, 2015. Interest on the 9.25% Senior Notes is payable semi-annually on February 15 and August 15. At any time prior to August 15, 2017, the Partnership may redeem the 9.25% Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (as defined in the governing indenture), plus accrued and unpaid interest, if any. At any time on or after August 15, 2017, the Partnership may redeem some or all of the 9.25% Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, the Partnership may redeem some or all of the 9.25% Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, the Partnership may redeem some or all of the 9.25% Senior Notes at the redemption price of 100.0%. Under certain conditions, including if the Partnership sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, the Partnership must offer to repurchase the 9.25% Senior Notes.

In connection with the issuance of $75.0 million of 9.25% Senior Notes on October 14, 2014, the Partnership entered into a registration rights agreement whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by July 11, 2015. On April 15, 2015, the registration statement relating to the exchange offer for the 9.25% Senior Notes was declared effective, and the exchange offer was subsequently launched on April 15, 2015.

The 7.75% Senior Notes and 9.25% Senior Notes are guaranteed by certain of the Partnership’s material subsidiaries. The guarantees under the 7.75% Senior Notes and 9.25% Senior Notes are full and unconditional and joint and several and any subsidiaries of the Partnership, other than the subsidiary guarantors, are minor. There are no restrictions on the Partnership’s ability to obtain cash or any other distributions of funds from the guarantor subsidiaries.

The indentures governing the 7.75% Senior Notes and 9.25% Senior Notes contain covenants, including limitations of the Partnership’s ability to incur certain liens, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of the Partnership’s assets. The Partnership was in compliance with these covenants as of March 31, 2015.

Total cash payments for interest by the Partnership were $36.7 million and $26.5 million for the three months ended March 31, 2015 and 2014, respectively.

 

 

NOTE 8 – DERIVATIVE INSTRUMENTS

The Partnership uses a number of different derivative instruments, principally swaps, collars and options, in connection with its commodity and interest rate price risk management activities. Management enters into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. To manage the risk of regional commodity price differences, the Partnership occasionally enters into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to NYMEX, the Partnership receives or pays a payment from the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. Commodity-

23


 

based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.

On January 1, 2015, the Partnership discontinued hedge accounting for its qualified commodity derivatives. As such, changes in fair value of these derivatives after December 31, 2014 are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated statements of operations. The fair values of these commodity derivative instruments at December 31, 2014, which were recognized in accumulated other comprehensive income within partners’ capital on the Partnership’s consolidated balance sheet, will be reclassified to the Partnership’s consolidated statements of operations in the future at the time the originally hedged physical transactions settle.

The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s consolidated balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s consolidated balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its consolidated balance sheets of $332.2 million and $269.3 million at March 31, 2015 and December 31, 2014, respectively. Of the $159.3 million of deferred gains in accumulated other comprehensive income on the Partnership’s consolidated balance sheet at March 31, 2015, the Partnership will reclassify $81.9 million of gains to its consolidated statement of operations over the next twelve month period as these contracts expire with the remaining gains of $77.4 million being reclassified to the Partnership’s consolidated statements of operations in later periods as the remaining contracts expire. During the three months ended March 31, 2014, no amounts were reclassified from other comprehensive income related to derivative instruments entered into during that period.

 

The following table summarizes the commodity derivative activity for the three months ended March 31, 2015 (in thousands):  

 

 

  

Three Months Ended
March 31,

 

 

  

2015

Portion of settlements associated  with gains previously recognized within accumulated other comprehensive income, net of prior year offsets(1)

  

$

(26,596

)

Portion of settlements attributable to subsequent mark to market gains

 

 

(15,203

)

Total cash settlements on commodity derivative contracts

 

 

(41,799

)

 

 

 

 

 

2015 Unrealized gains prior to settlement(2)

 

 

3,203

 

Unrealized gain on open derivative contracts at March 31, 2015, net of amounts recognized in income in prior year(2)

 

 

101,320

 

  

$

104,523

 

 

 

(1)

Recognized in gas and oil production revenue.

(2)

Recognized in gain on mark-to-market derivatives.

 

The Partnership had $41.8 million of cash settlements during the three months ended March 31, 2015.  As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three months ended March 31, 2015 and 2014 for hedge ineffectiveness.

24


 

The following table summarizes the gross fair values of the Partnership’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s consolidated balance sheets for the periods indicated (in thousands):

 

Offsetting Derivative Assets

  

Gross
Amounts of
Recognized
Assets

 

  

Gross
Amounts
Offset in the
Consolidated
Balance Sheets

 

 

Net Amount of
Assets 
Presented in the
Consolidated
Balance Sheets

 

As of March 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

Current portion of derivative assets

 

$

145,520

 

 

$

(21

)

 

$

145,499

 

Long-term portion of derivative assets

 

 

186,916

 

 

 

(198

)

 

 

186,718

 

Total derivative assets

 

$

332,436

 

 

$

(219

)

 

$

332,217

 

As of December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

Current portion of derivative assets

 

$

141,464

 

 

$

(98

)

 

$

141,366

 

Long-term portion of derivative assets

 

 

128,303

 

 

 

(370

)

 

 

127,933

 

Total derivative assets

 

$

269,767

 

 

$

(468

)

 

$

269,299

 

 

Offsetting Derivative Liabilities

  

Gross
Amounts of
Recognized
Liabilities

 

 

Gross
Amounts
Offset in the
Consolidated
Balance Sheets

 

  

Net Amount of
Liabilities
Presented in the
Consolidated
Balance Sheets

 

As of March 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

Current portion of derivative liabilities

 

$

(21

)

 

$

21

 

 

$

 

Long-term portion of derivative liabilities

 

 

(198

)

 

 

198

 

 

 

 

Total derivative liabilities

 

$

(219

)

 

$

219

 

 

$

 

As of December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

Current portion of derivative liabilities

 

$

(98

)

 

$

98

 

 

$

 

Long-term portion of derivative liabilities

 

 

(370

)

 

 

370

 

 

 

 

Total derivative liabilities

 

$

(468

)

 

$

468

 

 

$

 

 

The Partnership enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index, while ethane, propane, butane and iso butane contracts are priced based on the respective Mt. Belvieu price. These contracts were recorded at their fair values.

At March 31, 2015, the Partnership had the following commodity derivatives:

Natural Gas – Fixed Price Swaps

 

Production
Period Ending
December 31,

 

 

 

  

Volumes

 

  

Average
Fixed Price

 

  

Fair Value
Asset

 

 

  

 

 

  

(MMBtu)(1)

 

  

(per MMBtu)(1)

 

  

(in thousands)(2)

 

2015

  

 

 

  

 

40,053,400

  

  

$

4.210

  

  

$

56,994

 

2016

  

 

 

  

 

53,546,300

  

  

$

4.229

  

  

 

59,049

 

2017

  

 

 

  

 

49,920,000

  

  

$

4.219

  

  

 

42,447

 

2018

  

 

 

  

 

40,800,000

  

  

$

4.170

  

  

 

28,182

 

2019

  

 

 

  

 

15,960,000

  

  

$

4.017

  

  

 

7,319

 

 

  

 

 

  

 

 

 

  

 

 

 

  

$

193,991

 

 

25


 

Natural Gas – Costless Collars

 

Production
Period Ending
December 31,

  

Option Type

 

  

Volumes

 

  

Average Floor
and Cap

 

  

Fair Value
Asset/
(Liability)

 

 

  

 

 

  

(MMBtu)(1)

 

  

(per MMBtu)(1)

 

  

(in thousands)(2)

 

2015

  

Puts purchased

 

  

 

2,520,000

  

  

$

4.210

  

  

3,670

  

2015

  

Calls sold

 

  

 

2,520,000

  

  

$

5.090

  

  

 

(16

)

 

  

 

 

  

 

 

 

  

 

 

 

  

$

3,654

  

 

Natural Gas – Put Options – Drilling Partnerships

 

Production
Period Ending
December 31,

  

Option Type

 

  

Volumes

 

  

Average
Fixed Price

 

  

Fair Value
Asset

 

 

  

 

 

  

(MMBtu)(1)

 

  

(per MMBtu)(1)

 

  

(in thousands)(2)

 

2015

  

Puts purchased

  

  

 

1,080,000

  

  

$

4.000

  

  

 $

1,328

  

2016

  

Puts purchased

  

  

 

1,440,000

  

  

$

4.150

  

  

 

1,633

  

 

  

 

 

  

 

 

 

  

 

 

 

  

$

2,961

  

 

Natural Gas – WAHA Basis Swaps

 

Production
Period Ending
December 31,

 

 

 

  

Volumes

 

  

Average
Fixed Price

 

  

Fair Value
Asset

 

 

  

 

 

  

(MMBtu)(1)

 

  

(per MMBtu)(1)

 

  

(in thousands)(7)

 

2015

 

 

 

 

 

3,600,000

 

 

$

(0.090

)

 

$

239

 

 

  

 

 

  

 

 

 

  

 

 

 

  

$

239

 

 

Natural Gas Liquids – Natural Gasoline Fixed Price Swaps

 

Production
Period Ending
December 31,

 

 

 

  

Volumes

 

  

Average
Fixed Price

 

  

Fair Value
Asset

 

 

   

 

 

  

(Gal)(1)

 

  

(per Gal)(1)

 

  

(in thousands)(8)

 

2015

 

 

  

  

 

3,780,000

  

  

$

1.956

  

  

$

3,122

 

 

 

 

 

  

 

 

 

  

 

 

 

  

$

3,122

 

 

Natural Gas Liquids – Propane Fixed Price Swaps

 

Production
Period Ending
December 31,

   

 

 

  

Volumes

 

  

Average
Fixed Price

 

  

Fair Value
Asset

 

 

 

 

 

  

(Gal)(1)

 

  

(per Gal)(1)

 

  

(in thousands)(4)

 

2015

 

 

 

  

 

6,048,000

  

  

$

1.016

  

  

2,896

 

 

 

 

 

  

 

 

 

  

 

 

 

  

$

2,896

 

 

Natural Gas Liquids – Butane Fixed Price Swaps

 

Production
Period Ending
December 31,

   

 

 

  

Volumes

 

  

Average
Fixed Price

 

  

Fair Value
Asset

 

 

 

 

   

  

(Gal)(1)

 

  

(per Gal)(1)

 

  

(in thousands)(5)

 

2015

 

 

 

  

 

1,134,000

  

  

$

1.248

  

  

$

676

 

 

 

 

 

  

 

 

 

  

 

 

 

  

$

676

 

 

26


 

Natural Gas Liquids – Iso Butane Fixed Price Swaps

 

Production
Period Ending
December 31,

   

 

   

  

Volumes

 

  

Average
Fixed Price

 

  

Fair Value
Asset

 

 

 

 

 

  

(Gal)(1)

 

  

(per Gal)(1)

 

  

(in thousands)(6)

 

2015

 

 

 

  

 

1,134,000

  

  

$

1.263

  

  

$

689

 

 

 

 

 

  

 

 

 

  

 

 

 

  

$

689

 

 

Natural Gas Liquids – Crude Fixed Price Swaps

 

Production
Period Ending
December 31,

 

 

 

  

Volumes

 

  

Average
Fixed Price

 

  

Fair Value
Asset

 

 

   

 

 

  

(Bbl)(1)

 

  

(per Bbl)(1)

 

  

(in thousands)(3)

 

2016

 

 

 

  

 

84,000

  

  

$

85.651

  

  

2,274

 

2017

 

 

  

  

 

60,000

  

  

$

83.780

  

  

 

1,315

 

 

 

 

 

  

 

 

 

  

 

 

 

  

$

3,589

 

 

Crude Oil – Fixed Price Swaps

 

Production
Period Ending
December 31,

   

 

   

  

Volumes

 

  

Average
Fixed Price

 

  

Fair Value
Asset

 

 

 

 

 

  

(Bbl)(1)

 

  

(per Bbl)(1)

 

  

(in thousands)(3)

 

2015

 

 

 

  

 

        1,444,500

  

  

$

87.585

  

  

$

50,453

 

2016

 

 

 

  

 

          1,425,000

  

  

$

83.496

  

  

 

35,544

 

2017

 

 

 

  

 

          1,140,000

  

  

$

77.285

  

  

 

17,766

 

2018

 

 

 

 

 

          1,080,000

 

 

$

76.281

 

 

 

13,804

 

2019

 

 

 

 

 

             540,000

 

 

$

     68.371

 

  

 

2,196

 

 

 

 

 

  

 

 

 

 

 

 

 

 

$

119,763

 

 

Crude Oil – Costless Collars

 

Production
Period Ending
December 31,

  

Option Type

 

  

Volumes

 

  

Average
Floor
and Cap

 

  

Fair Value
Asset/
(Liability)

 

 

  

 

 

  

(Bbl)(1)

 

  

(per Bbl)(1)

 

  

(in thousands)(3)

 

2015

  

Puts purchased

 

  

 

19,500

  

  

$

83.846

  

  

638

 

2015

  

Calls sold

 

  

 

19,500

  

  

$

110.654

  

  

 

(1

)

 

  

 

 

  

 

 

 

  

 

 

 

  

$

637

 

 

  

 

 

  

 

 

 

  

 

Total net assets