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EX-32.1 - EXHIBIT 32.1 - Breitburn Energy Partners LPq2201510-qex321.htm
EX-32.2 - EXHIBIT 32.2 - Breitburn Energy Partners LPq2201510-qex322.htm
EX-31.1 - EXHIBIT 31.1 - Breitburn Energy Partners LPq2201510-qex311.htm
EX-31.2 - EXHIBIT 31.2 - Breitburn Energy Partners LPq2201510-qex312.htm
 
 
 
 
 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q

x
Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the quarterly period ended June 30, 2015
or
o
Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the transition period from ___ to ___

Commission File Number 001-33055

Breitburn Energy Partners LP
(Exact name of registrant as specified in its charter)

Delaware
74-3169953
(State or other jurisdiction of
(I.R.S. Employer
incorporation or organization)
Identification Number)
 
 
515 South Flower Street, Suite 4800
 
Los Angeles, California
90071
(Address of principal executive offices)
(Zip Code)

Registrant’s telephone number, including area code: (213) 225-5900

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. 
Large accelerated filer x
Accelerated filer o  
Non-accelerated filer o (Do not check if a smaller reporting company)
Smaller reporting company o

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

As of August 5, 2015, the registrant had 211,720,836 Common Units outstanding.

 
 
 
 
 
 



INDEX

 
 
Page No.
 
 
 
 
 
PART I
 
 
FINANCIAL INFORMATION
 
 
 
 
 
 
 Consolidated Balance Sheets at June 30, 2015 and December 31, 2014
 
Consolidated Statements of Operations for the Three Months and Six Months Ended June 30, 2015 and 2014

 
 Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2015 and 2014
 
– Condensed Notes to Consolidated Financial Statements
 
 
 
 
PART II
 
 
OTHER INFORMATION
 
 
 
 
 
 
 
 
 



CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Forward-looking statements are included in this report and may be included in other public filings, press releases, our website and oral and written presentations by management.  Statements other than historical facts are forward-looking and may be identified by words such as “believe,” “estimate,” “impact,” “intend,” “future,” “affect,” “expect,” “will,” “projected,” “plan,” “anticipate,” “should,” “could,” “would,” variations of such words and words of similar meaning.  These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict.  Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements.  The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report.

Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are changes in crude oil, natural gas liquids (“NGL”) and natural gas prices, including further or sustained declines in the prices we receive for our production; delays in planned or expected drilling; changes in costs and availability of drilling, completion and production equipment and related services and labor; the ability to obtain sufficient quantities of carbon dioxide (“CO2”) necessary to carry out enhanced oil recovery projects; the discovery of previously unknown environmental issues; federal, state and local initiatives and efforts relating to the regulation of hydraulic fracturing; the competitiveness of alternate energy sources or product substitutes; technological developments; potential disruption or interruption of our net production due to accidents or severe weather; the level of success in exploitation, development and production activities; the timing of exploitation and development expenditures; inaccuracies of reserve estimates or assumptions underlying them; revisions to reserve estimates as a result of changes in commodity prices; impacts to financial statements as a result of impairment write-downs; risks related to level of indebtedness and periodic redeterminations of the borrowing base under our credit agreement; ability to generate sufficient cash flows from operations to meet the internally funded portion of any capital expenditures budget; ability to obtain external capital to finance exploitation and development operations and acquisitions; the impacts of hedging on results of operations; failure of properties to yield oil or natural gas in commercially viable quantities; ability to integrate successfully the businesses we acquire; uninsured or underinsured losses resulting from oil and natural gas operations; inability to access oil and natural gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing oil and natural gas operations; changes in governmental regulations, including the regulation of derivative instruments and the oil and natural gas industry; ability to replace oil and natural gas reserves; any loss of senior management or technical personnel; competition in the oil and natural gas industry; risks arising out of hedging transactions; the effects of changes in accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under “Cautionary Statement Regarding Forward-Looking Information” and Part I—Item 1A “—Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2014 (our “2014 Annual Report”) in Part II—Item 1A of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 and in Part II—Item 1A of this report.  Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.

All forward-looking statements, expressed or implied, included in this report and attributable to us are expressly qualified in their entirety by this cautionary statement.  This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

We undertake no obligation to update the forward-looking statements in this report to reflect future events or circumstances.



1


PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements
Breitburn Energy Partners LP and Subsidiaries
Consolidated Balance Sheets
(Unaudited)
Thousands of dollars
 
June 30,
2015
 
December 31,
2014
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash
 
$
9,525

 
$
12,628

Accounts and other receivables, net
 
154,309

 
166,436

Derivative instruments (note 3)
 
309,239

 
408,151

Related party receivables (note 4)
 
297

 
2,462

Inventory
 
1,342

 
3,727

Prepaid expenses
 
7,439

 
7,304

Total current assets
 
482,151

 
600,708

Equity investments
 
6,310

 
6,463

Property, plant and equipment
 
 
 
 
Oil and natural gas properties
 
7,866,044

 
7,736,409

Other property, plant and equipment (note 2)
 
140,054

 
60,533

 
 
8,006,098

 
7,796,942

Accumulated depletion and depreciation (note 5)
 
(1,609,796
)
 
(1,342,741
)
Net property, plant and equipment
 
6,396,302

 
6,454,201

Other long-term assets
 
 
 
 
Intangibles, net
 
2,044

 
8,336

Goodwill (note 5)
 

 
92,024

Derivative instruments (note 3)
 
235,554

 
319,560

Other long-term assets (note 6)
 
123,182

 
157,042

Total assets
 
$
7,245,543

 
$
7,638,334

LIABILITIES AND EQUITY
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable
 
$
77,722

 
$
129,270

Current portion of long-term debt (note 7)
 
421

 
105,000

Derivative instruments (note 3)
 
5,388

 
5,457

Distributions payable
 
732

 
733

Current portion of asset retirement obligation (note 9)
 
3,912

 
4,948

Revenue and royalties payable
 
46,838

 
40,452

Wages and salaries payable
 
20,146

 
22,322

Accrued interest payable
 
19,772

 
20,672

Production and property taxes payable
 
25,214

 
25,207

Other current liabilities
 
6,805

 
7,495

Total current liabilities
 
206,950

 
361,556

Credit facility
 
1,309,000

 
2,089,500

Senior notes, net
 
1,787,887

 
1,156,560

Other long-term debt
 
2,579

 
1,100

Total long-term debt (note 7)
 
3,099,466

 
3,247,160

Deferred income taxes
 
2,743

 
2,575

Asset retirement obligation (note 9)
 
243,243

 
233,463

Derivative instruments (note 3)
 
2,082

 
2,269

Other long-term liabilities (note 10)
 
24,711

 
25,135

Total liabilities
 
3,579,195

 
3,872,158

Commitments and contingencies (note 11)
 


 


Equity
 
 
 
 
Series A preferred units, 8.0 million units issued and outstanding at each of June 30, 2015 and December 31, 2014 (note 12)
 
193,215

 
193,215

Series B preferred units, 47.2 million and 0 units issued and outstanding at June 30, 2015 and December 31, 2014, respectively (note 12)
 
341,700

 

Common units, 211.7 million and 210.9 million units issued and outstanding at June 30, 2015 and December 31, 2014, respectively (note 12)
 
3,124,808

 
3,566,468

Accumulated other comprehensive income (loss) (note 13)
 
(333
)
 
(392
)
Total partners' equity
 
3,659,390

 
3,759,291

Noncontrolling interest
 
6,958

 
6,885

Total equity
 
3,666,348

 
3,766,176

Total liabilities and equity
 
$
7,245,543

 
$
7,638,334

See accompanying notes to consolidated financial statements.

2


Breitburn Energy Partners LP and Subsidiaries
Consolidated Statements of Operations
(Unaudited)

 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
Thousands of dollars, except per unit amounts
 
2015

2014
 
2015
 
2014
Revenues and other income items
 
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquid sales
 
$
189,636

 
$
219,051

 
$
352,259

 
$
442,607

(Loss) gain on commodity derivative instruments, net (note 3)
 
(93,432
)
 
(127,000
)
 
43,760

 
(167,228
)
Other revenue, net
 
6,504

 
1,071

 
12,973

 
2,655

    Total revenues and other income items
 
102,708

 
93,122

 
408,992

 
278,034

Operating costs and expenses
 
 
 
 
 
 
 
 
Operating costs
 
115,837

 
83,060

 
233,815

 
165,257

Depletion, depreciation and amortization
 
109,447

 
68,245

 
219,271

 
131,746

Impairment of oil and natural gas properties (note 5)
 

 

 
59,113

 

Impairment of goodwill (note 5)
 
95,947

 

 
95,947

 

General and administrative expenses
 
22,862

 
16,420

 
55,124

 
35,149

Restructuring costs (note 15)
 
1,773

 

 
6,691

 

Loss on sale of assets
 
122

 
334

 
137

 
420

Total operating costs and expenses
 
345,988

 
168,059

 
670,098

 
332,572

 
 
 
 
 
 
 
 
 
Operating loss
 
(243,280
)
 
(74,937
)
 
(261,106
)
 
(54,538
)
 
 
 
 
 
 
 
 
 
Interest expense, net of capitalized interest
 
61,404

 
30,208

 
101,069

 
60,866

Loss on interest rate swaps (note 3)
 
603

 

 
2,415

 

Other expense (income), net
 
35

 
(261
)
 
(442
)
 
(773
)
 
 
 
 
 
 
 
 
 
Loss before taxes
 
(305,322
)
 
(104,884
)
 
(364,148
)
 
(114,631
)
 
 
 
 
 
 
 
 
 
Income tax expense (benefit)
 
259

 
(159
)
 
351

 
(148
)
 
 
 
 
 
 
 
 
 
Net loss
 
(305,581
)
 
(104,725
)
 
(364,499
)
 
(114,483
)
 
 
 
 
 
 
 
 
 
Less: Net income attributable to noncontrolling interest
 
126

 

 
33

 

 
 
 
 
 
 
 
 
 
Net loss attributable to the partnership
 
(305,707
)
 
(104,725
)
 
(364,532
)
 
(114,483
)
 
 
 
 
 
 
 
 
 
Less: Distributions to Series A preferred unitholders
 
4,125

 
1,833

 
8,250

 
1,833

Less: Non-cash distributions to Series B preferred unitholders
 
6,408

 

 
6,408

 

 
 
 
 
 
 
 
 
 
Net loss attributable to common unitholders
 
$
(316,240
)
 
$
(106,558
)
 
$
(379,190
)
 
$
(116,316
)
 
 
 
 
 
 
 
 
 
Basic net loss per unit (note 12)
 
$
(1.46
)
 
$
(0.89
)
 
$
(1.75
)
 
$
(0.97
)
Diluted net loss per unit (note 12)
 
$
(1.46
)
 
$
(0.89
)
 
$
(1.75
)
 
$
(0.97
)

See accompanying notes to consolidated financial statements.


3


Breitburn Energy Partners LP and Subsidiaries
Consolidated Statements of Comprehensive Loss
(Unaudited)

 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
Thousands of dollars, except per unit amounts
 
2015
 
2014
 
2015
 
2014
Net loss
 
$
(305,581
)
 
$
(104,725
)
 
$
(364,499
)
 
$
(114,483
)
 
 
 
 
 
 
 
 
 
Other comprehensive (loss) income, net of tax:
 
 
 
 
 
 
 
 
Change in fair value of available-for-sale securities (a)
 
(74
)
 

 
99

 

Total other comprehensive (loss) income
 
(74
)
 

 
99

 

 
 
 
 
 
 
 
 
 
Total comprehensive loss
 
(305,655
)
 
(104,725
)
 
(364,400
)
 
(114,483
)
 
 
 
 
 
 
 
 
 
Less: Comprehensive income attributable to noncontrolling interest
 
97

 

 
74

 

 
 
 
 
 
 
 
 
 
Comprehensive loss attributable to the partnership
 
$
(305,752
)
 
$
(104,725
)
 
$
(364,474
)
 
$
(114,483
)

(a) Net of income tax benefit of $0.1 million and income tax expense of $0.1 million for the three months and six months ended June 30, 2015, respectively.

See accompanying notes to consolidated financial statements.

4


Breitburn Energy Partners LP and Subsidiaries
Consolidated Statements of Cash Flows
(Unaudited)

 
 
Six Months Ended
 
 
June 30,
Thousands of dollars
 
2015
 
2014
Cash flows from operating activities
 
 
 
 
Net loss
 
$
(364,499
)
 
$
(114,483
)
Adjustments to reconcile to cash flows from operating activities:
 
 
 
 
Depletion, depreciation and amortization
 
219,271

 
131,746

Impairment of oil and natural gas properties
 
59,113

 

Impairment of goodwill
 
95,947

 

Unit-based compensation expense
 
14,545

 
12,647

(Gain) loss on derivative instruments
 
(41,345
)
 
167,228

Derivative instrument settlement receipts (payments)
 
224,007

 
(30,524
)
Income from equity affiliates, net
 
153

 
281

Deferred income taxes
 
168

 
(281
)
Loss on sale of assets
 
137

 
420

Other
 
12,818

 
3,487

Changes in net assets and liabilities
 
 
 
 
Accounts receivable and other assets
 
8,656

 
2,097

Inventory
 
2,385

 
(5,347
)
Net change in related party receivables and payables
 
2,165

 
1,322

Accounts payable and other liabilities
 
(18,576
)
 
22,516

Net cash provided by operating activities
 
214,945

 
191,109

Cash flows from investing activities
 
 
 
 
Property acquisitions
 
(17,663
)
 
(2,684
)
Capital expenditures
 
(170,634
)
 
(188,758
)
Proceeds from sale of assets
 

 
542

Proceeds from sale of available-for-sale securities
 
3,480

 

Purchases of available-for-sale securities
 
(3,637
)
 

Other
 
(853
)
 
(5,706
)
Net cash used in investing activities
 
(189,307
)
 
(196,606
)
Cash flows from financing activities
 
 
 
 
Proceeds from issuance of preferred units, net
 
337,895

 
193,397

Proceeds from issuance of common units, net
 
4,925

 
20,273

Distributions to preferred unitholders
 
(8,250
)
 

Distributions to common unitholders
 
(81,183
)
 
(120,059
)
Proceeds from issuance of long-term debt, net
 
1,043,400

 
466,000

Repayments of long-term debt
 
(1,296,500
)
 
(543,500
)
Change in bank overdraft
 
126

 
(2,425
)
Debt issuance costs
 
(29,154
)
 
(1,632
)
Net cash (used in) provided by financing activities
 
(28,741
)
 
12,054

(Decrease) increase in cash
 
(3,103
)
 
6,557

Cash beginning of period
 
12,628

 
2,458

Cash end of period
 
$
9,525

 
$
9,015


See accompanying notes to consolidated financial statements.

5


Condensed Notes to Consolidated Financial Statements

1.  Organization and Basis of Presentation

The accompanying unaudited consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our 2014 Annual Report.  The financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X.  In the opinion of management, all adjustments considered necessary for a fair statement of our financial position at June 30, 2015, our operating results for the three months and six months ended June 30, 2015 and 2014 and our cash flows for the six months ended June 30, 2015 and 2014 have been included.  Operating results for the three months and six months ended June 30, 2015 are not necessarily indicative of the results that may be expected for the year ended December 31, 2015.  The consolidated balance sheet at December 31, 2014 has been derived from the audited consolidated financial statements at that date but does not include all of the information and notes required by GAAP for complete financial statements.  For further information, refer to the consolidated financial statements and notes thereto included in our 2014 Annual Report.

We follow the successful efforts method of accounting for oil and natural gas activities.  Depletion, depreciation and amortization (“DD&A”) of proved oil and natural gas properties is computed using the units-of-production method, net of any estimated residual salvage values.

Accounting Standards

In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-03, Simplifying the Presentation of Debt Issuance Costs, which simplifies the presentation of debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. This presentation is consistent with debt discounts. The ASU does not affect guidance for recognition and measurement for debt issuance costs. The requirements of the guidance are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. We are evaluating the impact that ASU 2015-03 will have on our financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. ASU 2014-09 will supersede most of the existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which it expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires disclosures sufficient to enable users to understand an entity’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. These new requirements become effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for annual and interim reporting periods beginning after December 15, 2016. We are assessing the impact of these new requirements on our financial statements.

2. Acquisitions

We account for all business combinations using the acquisition method of accounting. The initial accounting applied to our acquisitions at the time of the purchase may not be complete and adjustment to provisional accounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition date prior to concluding the final purchase price of an acquisition.

Our purchase price allocations are based on discounted cash flows, quoted market prices and estimates made by management, and the most significant assumptions are those related to the estimated fair values assigned to oil and natural gas properties with proved reserves. To estimate the fair values of acquired properties, estimates of oil and natural gas reserves are prepared by management in consultation with independent engineers. We apply estimated future prices to the estimated reserve quantities acquired and estimate future operating and development costs to arrive at estimates of future net revenues. For estimated reserves, the future net revenues are discounted using a market-based weighted average cost of capital. We also periodically employ third-party valuation firms to assist in the valuation of complex facilities, including pipelines, gathering lines and processing facilities.


6


We conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions are expensed as incurred.

The fair value measurements of oil and natural gas properties, other assets and asset retirement obligations (“ARO”) are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties, other assets and ARO were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and a market-based weighted average cost of capital rate. ARO assumptions include inputs such as expected economic recoveries of oil and natural gas and time to abandonment. These inputs require significant judgments and estimates by management at the time of the valuation and are subject to change.

2015 Acquisitions

In May 2015, we completed the acquisition of additional interests in our existing fields located in Ark-La-Tex for a total preliminary purchase price of $3.4 million, which is primarily reflected in oil and natural gas properties on the consolidated balance sheet.
On March 31, 2015, we completed the acquisition of certain CO2 producing properties located in Harding County, New Mexico (“CO2 Assets”), for a total preliminary purchase price of $70.2 million (the “CO2 Acquisition”), subject to customary purchase price adjustments, of which $14.3 million was paid in cash during the three months ended March 31, 2015 and $0.2 million was paid in cash during the three months ended June 30, 2015. The preliminary purchase price included $70.5 million reflected in other property, plant and equipment on the consolidated balance sheet (including $49.9 million of CO2 supply advances and deposits paid in 2014 and reclassed from other long-term assets to other property, plant and equipment during the six months ended June 30, 2015 and $5.1 million of intangibles reclassed from intangibles to other property, plant and equipment during the six months ended June 30, 2015) and $0.3 million of ARO reflected in asset retirement obligation on the consolidated balance sheet.

2014 Acquisitions

QR Energy, LP
    
On November 19, 2014, we completed the previously announced transactions contemplated by the Agreement and Plan of Merger, dated as of July 23, 2014 (the “Merger Agreement”) with QR Energy, LP, a Delaware limited partnership (“QRE”). Pursuant to the terms of the Merger Agreement, QRE merged with a subsidiary of the Partnership, with QRE continuing as the surviving entity and as a direct wholly-owned subsidiary of the Partnership (the “QRE Merger”). Immediately thereafter, the Partnership transferred 100% of the limited partner interests of QRE to Breitburn Operating LP (“BOLP”), its wholly-owned subsidiary. In connection with the QRE Merger, we acquired a 59% controlling interest in East Texas Salt Water Disposal Company (“ETSWDC”) and have consolidated ETSWDC into our consolidated financial statements. The main purpose of ETSWDC is to dispose of salt water generated as a by-product from oil produced in certain East Texas oil fields.

Under the terms of the Merger Agreement, we issued a total of approximately 71.5 million common units representing limited partner interests (“Common Units”) to holders of outstanding QRE common units and QRE Class B Units. In addition, we paid a total of $350 million to holders of QRE Class C Units.

    

7


The initial purchase price, subject to customary purchase price adjustments, for the QRE Merger was allocated to the assets acquired and liabilities assumed as follows at June 30, 2015:

Thousands of dollars
 
 
Cash
 
$
5,121

Accounts and other receivables
 
113,398

Current derivative instrument assets
 
70,362

Prepaid expenses
 
3,123

Oil and gas properties
 
2,397,967

Non-oil and gas assets
 
17,866

Goodwill
 
95,947

Long-term derivative instrument assets
 
72,998

Other long-term assets
 
50,619

Accounts payable and accrued liabilities
 
(157,916
)
Current derivative instrument liabilities
 
(6,512
)
Current asset retirement obligation
 
(2,618
)
Credit facility debt
 
(790,000
)
Senior notes at fair value
 
(344,129
)
Long-term asset retirement obligation
 
(91,465
)
Long-term derivative instrument liabilities
 
(8,877
)
Other long-term liabilities
 
(10,277
)
Noncontrolling interest
 
(7,173
)
 
 
$
1,408,434


The initial purchase price allocation was determined by management with the assistance of outside valuation consulting firms. While the initial valuation and purchase price allocation have been completed, circumstances may arise in the future that could lead to adjustments to the valuation and/or allocation. If adjustments are required, they would be recorded no later than one year from the acquisition date.

We recognized goodwill of $95.9 million as part of the initial purchase price allocation. See Note 5 for a discussion of impairment of goodwill.

Acquisition-related costs for the QRE Merger for the three months and six months ended June 30, 2015 were zero and $0.1 million, respectively, and are reflected in general and administrative (“G&A”) expenses on the consolidated statements of operations.

In connection with the QRE Merger, on November 19, 2014, we entered into a Transition Services Agreement (“TSA”) with Quantum Resources Management, LLC.  Under the terms of the TSA, each party agreed to provide certain land, administrative accounting, IT and marketing services to the other party. The term of the TSA commenced on November 19, 2014 and terminated on May 19, 2015.
 
Antares Acquisition
On October 24, 2014, we completed the acquisition of certain oil and gas properties located in the Midland Basin, Texas from Antares Energy Company, a Delaware corporation, in exchange for 4.3 million Common Units and $50.0 million in cash (the “Antares Acquisition”), subject to customary purchase price adjustments, for a total preliminary purchase price of $122.3 million, which was allocated to oil and natural gas assets ($110.9 million to unproved properties, $13.1 million to proved properties and $1.7 million to ARO). The number of Common Units being issued as partial consideration will not be adjusted to account for changes in the unit price or for purchase price adjustments. We expect to finalize the valuation and complete the purchase price allocation as soon as practicable but no later than one year from the acquisition date. Acquisition-related costs for the Antares Acquisition were zero for the six months ended June 30, 2015.


8


Pro Forma (unaudited)
    
The following unaudited pro forma financial information presents a summary of our combined statements of operations for the three months and six months ended June 30, 2014 assuming the QRE Merger was completed on January 1, 2014. The pro forma results include adjustments for (1) the assumption of ARO and accretion expense for the properties acquired, (2) depletion and depreciation expense applied to the adjusted purchase price of the properties acquired, (3) interest expense on additional borrowings necessary to finance the acquisition, including the amortization of debt issuance costs, and (4) the effect on the denominator for calculating net income (loss) per unit of common unit issuances necessary to finance the acquisition. The pro forma financial information is not necessarily indicative of the results of operations if the acquisition had been effective January 1, 2014. The Antares Acquisition in 2014 and the CO2 Acquisition in 2015 were not included in the pro forma information as their results for the periods presented were immaterial.
 
 
 2014 Pro Forma
 
 
Three Months Ended
 
Six Months Ended
Thousands of dollars, except per unit amounts
 
June 30, 2014
 
June 30, 2014
Revenues
 
$
160,671

 
$
445,041

Net loss attributable to the partnership
 
(148,570
)
 
(166,070
)
 
 
 
 
 
Net loss per common unit:
 
 
 
 
Basic
 
$
(0.73
)
 
$
(0.81
)
Diluted
 
$
(0.73
)
 
$
(0.81
)

3.  Financial Instruments and Fair Value Measurements
 
Our risk management programs are intended to reduce our exposure to commodity price volatilities and to assist with stabilizing cash flows and distributions.  Routinely, we utilize derivative financial instruments to reduce this volatility. To the extent we have entered into economic hedges for a significant portion of our expected production through commodity derivative instruments and the cost for goods and services increases, our margins would be adversely affected.

Commodity Activities

The derivative instruments we utilize are based on index prices that may and often do differ from the actual crude oil and natural gas prices realized in our operations.  These differentials often result in a lack of adequate correlation to enable these derivative instruments to qualify as cash flow hedges under FASB Accounting Standards.  Accordingly, we do not attempt to account for our derivative instruments as cash flow hedges for financial reporting purposes, and instead we recognize changes in fair value immediately in earnings. 


9


We had the following commodity derivative contracts in place at June 30, 2015:

 
 
Year

 
2015

2016

2017

2018
 
2019
Oil Positions:
 
 
 
 
 
 
 
 
 
 
Fixed Price Swaps - NYMEX WTI
 
 
 
 
 
 
 
 
 
 
Volume (Bbl/d)
 
20,043

 
15,504

 
13,519

 
493

 

Average Price ($/Bbl)
 
$
93.27

 
$
88.07

 
$
85.05

 
$
82.20

 
$

Fixed Price Swaps - ICE Brent
 
 
 
 
 
 
 
 
 
 
Volume (Bbl/d)
 
3,300

 
4,300

 
298

 

 

Average Price ($/Bbl)
 
$
97.73

 
$
95.17

 
$
97.50

 
$

 
$

Collars - NYMEX WTI
 
 
 
 
 
 
 
 
 
 
Volume (Bbl/d)
 
2,025

 
1,500

 

 

 

Average Floor Price ($/Bbl)
 
$
90.00

 
$
80.00

 
$

 
$

 
$

Average Ceiling Price ($/Bbl)
 
$
111.73

 
$
102.00

 
$

 
$

 
$

Collars - ICE Brent
 
 
 
 
 
 
 
 
 
 
Volume (Bbl/d)
 
500

 
500

 

 

 

Average Floor Price ($/Bbl)
 
$
90.00

 
$
90.00

 
$

 
$

 
$

Average Ceiling Price ($/Bbl)
 
$
109.50

 
$
101.25

 
$

 
$

 
$

Puts - NYMEX WTI
 
 
 
 
 
 
 
 
 
 
Volume (Bbl/d)
 
500

 
1,000

 

 

 

Average Price ($/Bbl)
 
$
90.00

 
$
90.00

 
$

 
$

 
$

Total:
 
 
 
 
 
 
 
 
 
 
Volume (Bbl/d)
 
26,368

 
22,804

 
13,817

 
493

 

Average Price ($/Bbl)
 
$
93.46

 
$
89.01

 
$
85.32

 
$
82.20

 
$

 
 
 
 
 
 
 
 
 
 
 
Natural Gas Positions:
 
 
 
 
 
 
 
 
 
 
Fixed Price Swaps - MichCon City-Gate
 
 
 
 
 
 
 
 
 
 
Volume (MMBtu/d)
 
12,500

 
21,000

 
15,000

 
3,500

 
2,000

Average Price ($/MMBtu)
 
$
4.80

 
$
4.21

 
$
4.06

 
$
3.24

 
$
3.28

Fixed Price Swaps - Henry Hub
 
 
 
 
 
 
 
 
 
 
Volume (MMBtu/d)
 
54,891

 
36,050

 
19,016

 
1,870

 

Average Price ($/MMBtu)
 
$
4.84

 
$
4.24

 
$
4.43

 
$
4.15

 
$

Collars - Henry Hub
 
 
 
 
 
 
 
 
 
 
Volume (MMBtu/d)
 
18,000

 
630

 
595

 

 

Average Floor Price ($/MMBtu)
 
$
5.00

 
$
4.00

 
$
4.00

 

 

Average Ceiling Price ($/MMBtu)
 
$
7.48

 
$
5.55

 
$
6.15

 
$

 
$

Puts - Henry Hub
 
 
 
 
 
 
 
 
 
 
Volume (MMBtu/d)
 
1,920

 
11,350

 
10,445

 

 

Average Price ($/MMBtu)
 
$
4.78

 
$
4.00

 
$
4.00

 
$

 
$

Deferred Premium ($/MMBtu)
 
$
0.64

 (a)
$
0.66

 
$
0.69

 
$

 
$

Total:
 
 
 
 
 
 
 
 
 
 
Volume (MMBtu/d)
 
87,311

 
69,030

 
45,056

 
5,370

 
2,000

Average Price ($/MMBtu)
 
$
4.87

 
$
4.19

 
$
4.20

 
$
3.56

 
$
3.28

 
 
 
 
 
 
 
 
 
 
 
Basis Swaps - Henry Hub
 
 
 
 
 
 
 
 
 
 
Volume (MMBtu/d)
 
14,400

 

 

 

 

Average Price ($/MMBtu)
 
$
(0.19
)
 
$

 
$

 
$

 
$


(a) Deferred premiums of $0.64 apply to 420 MMBtu/d of the 2015 volume.    


10


During the three months and six months ended June 30, 2015 and 2014, we did not enter into any derivative instruments that required pre-paid premiums.
    
As of June 30, 2015, premiums paid in 2012 related to oil and natural gas derivatives to be settled beyond June 30, 2015 were as follows:
 
 
Year
Thousands of dollars
 
2015
 
2016
 
2017
 
Oil
 
$
2,361

 
$
7,438

 
$
734

 
Natural gas
 
$
1,003

 
$
952

 
$

 

Interest Rate Activities

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. To fix a portion of our floating LIBOR-base debt under our credit facility, we had the following interest rate swaps in place at June 30, 2015 and December 31, 2014. These contracts were novated to us in November 2014 in connection with the QRE Merger:
 
 
Year
 
 
2015
 
2016
Fixed Rate Swaps - LIBOR
 
 
 
 
Notional Amount (thousands of dollars)
 
$
393,520

 
$
410,000

Average Fixed Rate
 
1.60
%
 
1.72
%

We do not currently designate any of our interest rate derivatives as hedges for financial accounting purposes.

Fair Value of Financial Instruments
 
The following table presents the fair value of our derivative instruments not designated as hedging instruments:
Balance sheet location, thousands of dollars
 
Oil Commodity Derivatives
 
Natural Gas
Commodity Derivatives
 
Interest Rate Derivatives
 
Commodity Derivatives Netting (a)
 
Total Financial Instruments
As of June 30, 2015
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
Current assets - derivative instruments
 
$
266,504

 
$
44,352

 
$

 
$
(1,617
)
 
$
309,239

Other long-term assets - derivative instruments
 
211,014

 
28,686

 
3

 
(4,149
)
 
235,554

Total assets
 
477,518

 
73,038

 
3

 
(5,766
)
 
544,793

Liabilities
 
 
 
 
 
 
 
 
 
 
Current liabilities - derivative instruments
 
(140
)
 
(1,779
)
 
(5,086
)
 
1,617

 
(5,388
)
Long-term liabilities - derivative instruments
 
(263
)
 
(4,376
)
 
(1,592
)
 
4,149

 
(2,082
)
Total liabilities
 
(403
)
 
(6,155
)
 
(6,678
)
 
5,766

 
(7,470
)
Net assets (liabilities)
 
$
477,115

 
$
66,883

 
$
(6,675
)
 
$

 
$
537,323

 
 
 
 
 
 
 
 
 
 
 
As of December 31, 2014
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
Current assets - derivative instruments
 
$
350,351

 
$
58,246

 
$

 
$
(446
)
 
$
408,151

Other long-term assets - derivative instruments
 
296,441

 
29,649

 
210

 
(6,740
)
 
319,560

Total assets
 
646,792

 
87,895

 
210

 
(7,186
)
 
727,711

Liabilities
 
 
 
 
 
 
 
 
 
 
Current liabilities - derivative instruments
 
(214
)
 
(563
)
 
(5,126
)
 
446

 
(5,457
)
Long-term liabilities - derivative instruments
 
(1,520
)
 
(5,220
)
 
(2,269
)
 
6,740

 
(2,269
)
Total liabilities
 
(1,734
)
 
(5,783
)
 
(7,395
)
 
7,186

 
(7,726
)
Net assets (liabilities)
 
$
645,058

 
$
82,112

 
$
(7,185
)
 
$

 
$
719,985


(a) Represents counterparty netting under derivative master agreements. The agreements allow for netting of oil and natural gas commodity derivative instruments. These derivative instruments are reflected net on the consolidated balance sheets.

11



The following table presents gains and losses on derivative instruments not designated as hedging instruments:

Thousands of dollars
 
Oil Commodity
Derivatives (a)
 
Natural Gas
Commodity Derivatives (a)
 
Interest Rate Derivatives (b)
 
Total Financial Instruments
Three Months Ended June 30, 2015
 
 
 
 
 
 
 
 
Net loss
 
$
(91,312
)
 
$
(2,120
)
 
$
(603
)
 
$
(94,035
)
Three Months Ended June 30, 2014
 
 
 
 
 
 
 
 
Net loss
 
$
(121,326
)
 
$
(5,674
)
 
$

 
$
(127,000
)
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2015
 
 
 
 
 
 
 
 
Net gain (loss)
 
$
27,202

 
$
16,558

 
$
(2,415
)
 
$
41,345

Six Months Ended June 30, 2014
 
 
 
 
 
 
 
 
Net loss
 
$
(149,219
)
 
$
(18,009
)
 
$

 
$
(167,228
)

(a) Included in (loss) gain on commodity derivative instruments, net on the consolidated statements of operations.
(b) Included in loss on interest rate swaps on the consolidated statements of operations.

Fair Value Measurements

FASB Accounting Standards define fair value, establish a framework for measuring fair value and establish required disclosures about fair value measurements.  They also establish a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are.  We use valuation techniques that maximize the use of observable inputs and obtain the majority of our inputs from published objective sources or third-party market participants.  We incorporate the impact of nonperformance risk, including credit risk, into our fair value measurements.  The fair value hierarchy gives the highest priority of Level 1 to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority of Level 3 to unobservable inputs.  We categorize our fair value financial instruments based upon the objectivity of the inputs and how observable those inputs are.  The three levels of inputs are described further as follows:

Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date.  Level 2 – Inputs that are observable other than quoted prices that are included within Level 1.  Level 2 includes financial instruments that are actively traded but are valued using models or other valuation methodologies.  We consider the over-the-counter (“OTC”) commodity and interest rate swaps in our portfolio to be Level 2.  Level 3 – Inputs that are not directly observable for the asset or liability and are significant to the fair value of the asset or liability.  Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models.  Certain OTC derivative instruments that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3.  As of June 30, 2015, and December 31, 2014, our Level 3 derivative assets and liabilities consisted entirely of OTC commodity put and call options.

Financial assets and liabilities that are categorized in Level 3 may later be reclassified to the Level 2 category at the point we are able to obtain sufficient binding market data.  We had no transfers in or out of Levels 1, 2 or 3 during the three months and six months ended June 30, 2015 and 2014. Our policy is to recognize transfers between levels as of the end of the period.

 Our assessment of the significance of an input to its fair value measurement requires judgment and can affect the valuation of the assets and liabilities as well as the category within which they are classified.

12



Derivative Instruments

Our Treasury/Risk Management group calculates the fair value of our commodity and interest rate swaps and options.  We compare these fair value amounts to the fair value amounts we receive from counterparties on a monthly basis and also use a third-party validation firm for a portion of our portfolio.  Any differences are resolved and any required changes are recorded prior to the issuance of our financial statements.

The model we utilize to calculate the fair value of our Level 2 and Level 3 commodity derivative instruments is a standard option pricing model. Level 2 inputs to the option pricing models include fixed monthly commodity strike prices and volumes from each specific contract, commodity prices from commodity futures price curves, volatility and interest rate factors and time to expiry. Model inputs are obtained from our counterparties and third party data providers and are verified to published data where available (e.g., NYMEX). Additional inputs to our Level 3 derivatives include option volatility, futures commodity prices and risk-free interest rates for present value discounting. We use the standard swap contract valuation method to value our interest rate derivatives, and inputs include LIBOR forward interest rates, one-month LIBOR rates and risk-free interest rates for present value discounting.

Assumed credit risk adjustments, based on published credit ratings and credit default swap rates, are applied to our derivative instruments.

The fair value of the commodity and interest rate derivative instruments that were novated to us in connection with the QRE Merger are estimated using a combined income and market valuation methodology based upon futures commodity prices and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes. We validate the data provided by independent pricing services by comparing such pricing against other third party pricing data.

Available-for-Sale Securities

The fair value of our available for sale securities are estimated using actual trade data, broker/dealer quotes, and other similar data, which are obtained from quoted market prices, independent pricing vendors, or other sources. We validate the data provided by independent pricing services to make assessments and determinations as to the ultimate valuation of its investment portfolio by comparing such pricing against other third party pricing data. We consider the inputs to the valuation of our available for sale securities to be Level 1.


13


Fair Value Hierarchy

The following tables set forth, by level within the hierarchy, the fair value of our financial instrument assets and liabilities that were accounted for at fair value on a recurring basis. All fair values reflected below and on the consolidated balance sheets have been adjusted for nonperformance risk.

Thousands of dollars
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
 
 
 
 
 
 
 
As of June 30, 2015
 
 
 
 
 
 
 
 
Assets (liabilities)
 
 
 
 
 
 
 
 
Crude Oil
 
 
 
 
 
 
 
 
Crude oil swaps
 
$

 
$
436,114

 
$

 
$
436,114

Crude oil collars
 

 

 
27,788

 
27,788

Crude oil puts
 

 

 
13,213

 
13,213

Natural Gas
 
 
 
 
 
 
 
 
Natural gas swaps
 

 
51,873

 

 
51,873

Natural gas collars
 

 

 
7,323

 
7,323

Natural gas puts
 

 

 
7,687

 
7,687

Interest rate swaps
 
 
 
 
 
 
 
 
Interest rate swaps
 

 
(6,675
)
 

 
(6,675
)
Available-for-sale securities
 
 
 
 
 
 
 
 
Equities
 
2,612

 

 

 
2,612

Mutual funds
 
13,110

 

 

 
13,110

Exchange traded funds
 
3,787

 

 

 
3,787

Net assets
 
$
19,509

 
$
481,312

 
$
56,011

 
$
556,832

Thousands of dollars
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
 
 
 
 
 
 
 
As of December 31, 2014
 
 
 
 
 
 
 
 
Assets (liabilities)
 
 
 
 
 
 
 
 
Crude Oil
 
 
 
 
 
 
 
 
Crude oil swaps
 
$

 
$
583,648

 
$

 
$
583,648

Crude oil collars
 

 

 
44,405

 
44,405

Crude oil puts
 

 

 
17,005

 
17,005

Natural gas commodity derivatives
 
 
 
 
 
 
 
 
Natural gas swaps
 

 
62,220

 

 
62,220

Natural gas collars
 

 

 
13,256

 
13,256

Natural gas puts
 

 

 
6,636

 
6,636

Interest rate swaps
 
 
 
 
 
 
 
 
Interest rate swaps
 

 
(7,185
)
 

 
(7,185
)
Available-for-sale securities
 
 
 
 
 
 
 
 
Equities
 
4,138

 

 

 
4,138

Mutual funds
 
10,577

 

 

 
10,577

Exchange traded funds
 
4,630

 

 

 
4,630

Net assets
 
$
19,345

 
$
638,683

 
$
81,302

 
$
739,330



14


The following tables set forth a reconciliation of changes in fair value of our derivative instruments classified as Level 3:

 
 
Three Months Ended June 30,
 
 
2015
 
2014
Thousands of dollars
 
Oil
 
Natural Gas
 
Oil
 
Natural Gas
Assets (a):
 
 
 
 
 
 
 
 
Beginning balance
 
$
59,101

 
$
19,671

 
$
7,093

 
$
1,152

Derivative instrument settlements (b)
 
8,564

 
4,237

 

 
99

Loss (b)(c)
 
(26,664
)
 
(8,898
)
 
(5,553
)
 
(411
)
Ending balance
 
$
41,001

 
$
15,010

 
$
1,540

 
$
840

 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30,
 
 
2015
 
2014
Thousands of dollars
 
Oil
 
Natural Gas
 
Oil
 
Natural Gas
Assets (a):
 
 
 
 
 
 
 
 
Beginning balance
 
$
61,410

 
$
19,892

 
$
8,957

 
$
1,848

Derivative instrument settlements (b)
 
19,551

 
7,804

 

 
42

Loss (b)(c)
 
(39,960
)
 
(12,686
)
 
(7,417
)
 
(1,050
)
Ending balance
 
$
41,001

 
$
15,010

 
$
1,540

 
$
840


(a) We had no changes in fair value of our derivative instruments classified as Level 3 related to sales, purchases or issuances.
(b) Included in (loss) gain on commodity derivative instruments, net on the consolidated statements of operations.
(c) Represents loss on mark-to-market of derivative instruments.

For Level 3 derivative instruments measured at fair value on a recurring basis as of June 30, 2015, the significant unobservable inputs used in the fair value measurements were as follows:

 
 
Fair Value at
 
Valuation
 
 
 
 
Thousands of dollars
 
June 30, 2015
 
Technique
 
Unobservable Input
 
Range
Oil Options
 
$
41,001

 
Option Pricing Model
 
Oil forward commodity prices
 
$59.47/Bbl - $69.19/Bbl
 
 
 
 
 
 
Oil volatility
 
19.51% - 33.23%
 
 
 
 
 
 
Own credit risk
 
5%
Natural Gas Options
 
15,010

 
Option Pricing Model
 
Gas forward commodity prices
 
$2.77/MMBtu - $3.55/MMBtu
 
 
 
 
 
 
Gas volatility
 
19.68% - 50.10%
 
 
 
 
 
 
Own credit risk
 
5%
Total
 
$
56,011

 
 
 
 
 
 

    

15


For Level 3 derivative instruments measured at fair value on a recurring basis as of December 31, 2014, the significant unobservable inputs used in the fair value measurements were as follows:

 
 
Fair Value at
 
Valuation
 
 
 
 
Thousands of dollars
 
December 31, 2014
 
Technique
 
Unobservable Input
 
Range
Oil Options
 
$
61,410

 
Option Pricing Model
 
Oil forward commodity prices
 
$53.27/Bbl - $71.66/Bbl
 
 
 
 
 
 
Oil volatility
 
29.21% - 46.16%
 
 
 
 
 
 
Own credit risk
 
5%
Natural Gas Options
 
19,892

 
Option Pricing Model
 
Gas forward commodity prices
 
$2.88/MMBtu - $3.99/MMBtu
 
 
 
 
 
 
Gas volatility
 
18.59% - 63.51%
 
 
 
 
 
 
Own credit risk
 
5%
Total
 
$
81,302

 
 
 
 
 
 

Credit and Counterparty Risk

Financial instruments, which potentially subject us to concentrations of credit risk, consist principally of derivatives and accounts receivable. Our derivatives expose us to credit risk from counterparties. As of June 30, 2015, our derivative counterparties were Bank of Montreal, Barclays Bank PLC, BNP Paribas, Canadian Imperial Bank of Commerce, Citibank, N.A, Citizens Bank, National Association, Comerica Bank, Credit Agricole Corporate and Investment Bank, Credit Suisse Energy LLC, Credit Suisse International, ING Capital Markets LLC, JP Morgan Chase Bank N.A., Merrill Lynch Commodities, Inc., Royal Bank of Canada, The Bank of Nova Scotia, The Toronto-Dominion Bank, Union Bank N.A. and Wells Fargo Bank, N.A. Our counterparties are all lenders under our Third Amended and Restated Credit Agreement. Our Third Amended and Restated Credit Agreement is secured by our oil, NGL and natural gas reserves, so we are not required to post any collateral, and we conversely do not receive collateral from our counterparties. On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits and monitor the appropriateness of these limits on an ongoing basis. We periodically obtain credit default swap information on our counterparties. Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to fail to perform in accordance with the terms of the contract. This risk is managed by diversifying our derivatives portfolio.  As of June 30, 2015, each of these financial institutions had an investment grade credit rating.  As of June 30, 2015, our largest derivative asset balances were with Wells Fargo Bank, N.A., Credit Suisse Energy LLC and JP Morgan Chase Bank N.A., which accounted for approximately 21%, 19% and 13% of our net derivative asset balances, respectively. 

4.  Related Party Transactions

Breitburn Management Company LLC (“Breitburn Management”), our wholly-owned subsidiary, operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering.  All of our employees, including our executives, are employees of Breitburn Management.

Breitburn Management also provides administrative services to Pacific Coast Energy Company LP, formerly named BreitBurn Energy Company L.P. (“PCEC”), our predecessor, under an administrative services agreement, in exchange for a monthly fee for indirect expenses and reimbursement for all direct expenses, including incentive compensation plan costs and direct payroll and administrative costs related to PCEC properties and operations.  For each of the three months and six months ended June 30, 2015 and 2014, the monthly fee paid by PCEC for indirect expenses was $700,000. On May 1, 2015, Breitburn Management and PCEC entered into Amendment No. 5 to the Administrative Services Agreement (“ASA”), extending the term of the ASA to December 31, 2016; provided, however, in the event PCEC has not received certain permits by December 31, 2015, PCEC may terminate the ASA effective as of June 30, 2016 by giving prior written notice to Breitburn Management of its intention to terminate the ASA by December 31, 2015. At December 31, 2016, the ASA is subject to renegotiation.

Effective on April 8, 2015, the closing date of private offerings of senior secured second lien notes and perpetual convertible preferred units (see Note 7 and Note 12, respectively), Kurt A. Talbot, Vice Chairman and Co-Head of the

16


Investment Committee of EIG Global Energy Partners (“EIG”), was appointed to the board of directors of Breitburn GP LLC, our general partner (our “General Partner”). We paid EIG Management Company, LLC, an affiliate of EIG, a transaction fee of $13 million with respect to the purchase of the senior secured second lien notes and a transaction fee of $7 million with respect to the purchase of the perpetual convertible preferred units.

At June 30, 2015 and December 31, 2014, we had a current receivable of $0.1 million and $2.4 million, respectively, due from PCEC related to the administrative services agreement, employee-related costs and oil and natural gas sales made by PCEC on our behalf from certain properties.  For the three months ended June 30, 2015 and 2014, the monthly charges to PCEC for indirect expenses totaled $2.1 million in each period, and charges for direct expenses including payroll and administrative costs totaled $2.2 million and $2.6 million, respectively. For the six months ended June 30, 2015 and 2014, the monthly charges to PCEC for indirect expenses totaled $4.2 million in each period, and charges for direct expenses including payroll and administrative costs totaled $5.0 million and $5.1 million, respectively. At June 30, 2015 and December 31, 2014, we had receivables of $0.2 million and $0.1 million due from certain of our other affiliates, primarily representing investments in natural gas processing facilities, for management fees due from them and operational expenses incurred on their behalf.

5. Impairments

Oil and Natural Gas Properties

We review our oil and gas properties for impairment periodically or when events or circumstances indicate that their carrying value may not be recoverable. Generally, management does not view temporarily low commodity prices as a sole indicator that an impairment event has occurred as crude oil and natural gas prices have a history of significant volatility. Determination as to whether and how much an asset is impaired involves subjectivity and management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles, the outlook for market supply and demand conditions for oil and natural gas, and other factors. 

        For purposes of assessing our oil and gas properties for potential impairment, management reviews the expected undiscounted future cash flows for our total proved and risk-adjusted probable and possible reserves. The undiscounted cash flow review includes inputs such as applicable NYMEX strip prices, estimated basis price differentials, expenses and capital estimates, and escalation factors.  Management also considers the impact future price changes are likely to have on our future operating plans.

        If we determine that an impairment charge for a property is warranted, an impairment charge is recorded for the amount that the property’s carrying value exceeds the amount of its estimated discounted future cash flows. For purposes of calculating an impairment charge, estimated discounted future cash flows are determined by using applicable basis adjusted five-year NYMEX strip prices and escalated along with expenses and capital starting in year six and thereafter at 2% per year.  Production and development cost estimates (e.g. operating expenses and development capital) are conformed to reflect the commodity price strip used.  The associated property’s expected future net cash flows are discounted using a market-based weighted average cost of capital rate that currently approximates 9%.  We consider the inputs for our impairment calculations to be Level 3 inputs.  The impairment reviews and calculations are based on assumptions that are consistent with our business plans.

        There were no impairments of proved properties during the three months ended June 30, 2015. Impairments of proved properties totaled $59.1 million for the three months ended March 31, 2015, including $33.1 million for our Permian properties, $16.7 million for our Rockies natural gas properties and $9.3 million for our Mid-Continent properties, primarily due to the impact that the decrease in oil and natural gas prices during the three months ended March 31, 2015 had on certain of our low operating margin properties.
       
Given the number of assumptions involved in the estimates, an estimate as to the sensitivity to earnings for these periods if other assumptions had been used in impairment reviews and calculations is not practicable. Favorable changes to some assumptions might have avoided the need to impair any assets in this period, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.


17


Goodwill

Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is not amortized, but is tested for impairment annually or whenever indicators of impairment exist and charged to impairment. The analysis of the potential impairment of goodwill is a two-step process. Step one of the impairment test consists of comparing the fair value of the reporting unit with the aggregate carrying value, including goodwill. If the carrying value of a reporting unit exceeds the reporting unit’s fair value, step two must be performed to determine the amount, if any, of the goodwill impairment.

If the fair value of the reporting unit is less than its carrying value, step two of the goodwill impairment test is performed. Step two consists of comparing the implied fair value of the reporting unit’s goodwill against the carrying value of the goodwill. Determining the implied fair value of goodwill requires the valuation of a reporting unit’s identifiable tangible and intangible assets and liabilities as if the reporting unit had been acquired in a business combination on the testing date. The fair value of the tangible and intangible assets and liabilities is based upon various assumptions including a discounted cash flow approach to value our oil and gas reserves (the “Income Approach”). The Income Approach valuation method requires projections of revenue and operating costs over a multi-year period. The valuation of assets and liabilities in step two is performed only for purposes of assessing goodwill for impairment.

As of March 31, 2015, we had $95.9 million of goodwill related to the QRE Merger (see Note 2). Due to a decrease in the price of our Common Units during the second quarter of 2015, we performed a qualitative goodwill impairment assessment. In the first step of the goodwill impairment test, we determined that the fair value of our goodwill was less than the carrying amount, primarily due to the decrease in the price of our Common Units. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there was no remaining implied fair value attributable to goodwill.  Based on this assessment, we recorded a non-cash goodwill impairment charge of $95.9 million during the three months ended June 30, 2015, to reduce the carrying value of goodwill to zero.

6. Other Assets

As of June 30, 2015, and December 31, 2014, our other long-term assets were $123.2 million and $157.0 million, respectively, consisting of the following:
 
 
As of
Thousands of dollars
 
June 30, 2015
 
December 31, 2014
Debt issuance costs
 
$
65,060

 
$
52,787

Available-for-sale securities
 
19,509

 
19,345

Deposit for Jay Field net profit interest obligation
 
18,262

 
18,263

Property reclamation deposit
 
10,735

 
10,735

CO2 supply advances and deposits
 

 
50,792

Other
 
9,616

 
5,120

Total
 
$
123,182

 
$
157,042

    
The $65.1 million of debt issuance costs at June 30, 2015 included $22.3 million in debt issuance costs relating to the Senior Secured Notes (as defined below) issued on April 8, 2015, partially offset by the write-off of $10.6 million of debt issuance costs relating to the reduction of our borrowing base from $2.5 billion to $1.8 billion in connection with the EIG financing. See Note 7 for a discussion of the Senior Secured Notes and the EIG financing.

At each of June 30, 2015 and December 31, 2014, we had a deposit for a net profits interest obligation for the Jay Field in Florida of $18.3 million (assumed in the QRE Merger) and a property reclamation deposit for future abandonment and remediation obligations for the Jay Field of $10.7 million, and zero and $50.8 million, respectively, in CO2 supply advances and deposits for our Mid-Continent properties. In connection with the CO2 Acquisition, during the six months ended June 30, 2015, we reclassified $50.8 million of CO2 supply advances and deposits from other long-term assets to other property, plant and equipment on the consolidated balance sheet. See Note 2 for a discussion of the CO2 Acquisition.


18


7.  Long-Term Debt
    
Our long-term debt is detailed in the following table:

 
 
As of
Thousands of dollars
 
June 30, 2015
 
December 31, 2014
Credit facility
 
$
1,309,000

 
$
2,194,500

Promissory note
 
3,000

 
1,100

9.25% Senior Secured Notes due 2020
 
650,000

 

8.625% Senior Unsecured Notes due 2020
 
305,000

 
305,000

7.875% Senior Unsecured Notes due 2022
 
850,000

 
850,000

Net (discount) premium on Senior Notes
 
(17,113
)
 
1,560

Total debt
 
3,099,887

 
3,352,160

Less: current portion of long-term debt
 
(421
)
 
(105,000
)
Total long-term debt
 
$
3,099,466

 
$
3,247,160


Credit Facility

On April 8, 2015, in connection with financing and related party transactions with EIG Global Energy Partners, we entered into the First Amendment to the Third Amended and Restated Credit Agreement (the “First Amendment”). Among other changes, the First Amendment: (i) established a borrowing base of $1.8 billion until the April 1, 2016 scheduled redetermination date subject, starting with the October 1, 2015 scheduled redetermination date, to our having liquidity (inclusive of borrowing base availability) of 10% of the borrowing base; (ii) permitted $650 million of second lien indebtedness; (iii) increased the base rate and LIBOR margins by 0.25%; (iv) added a requirement that we have liquidity (inclusive of borrowing base availability) of 10% of the borrowing base after giving effect to any distribution on our Common Units or voluntary prepayment of second lien indebtedness; and (v) added a requirement that we have liquidity (inclusive of borrowing base availability) of 5% of the borrowing base after giving effect to any distribution on our Series B Preferred Units (as defined below).

As of June 30, 2015, BOLP, our wholly-owned subsidiary, as borrower, and we and our wholly-owned subsidiaries, as guarantors, had a $5.0 billion revolving credit facility with Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and Issuing Lender, and a syndicate of banks with a maturity date of November 19, 2019.

Our credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria. Historically, our borrowing base has been redetermined semi-annually. As of June 30, 2015 and December 31, 2014, our borrowing base was $1.8 billion and $2.5 billion, respectively. Our next borrowing base redetermination is scheduled for April 2016.

As of June 30, 2015 and December 31, 2014, we had $1.31 billion and $2.19 billion, respectively, in indebtedness outstanding under our credit facility. At June 30, 2015, the 1-month LIBOR interest rate plus an applicable spread was 2.4359% on the 1-month LIBOR portion of $1.30 billion and the prime rate plus an applicable spread was 4.50% on the prime portion of $5.0 million. At June 30, 2015 and December 31, 2014, we had $25.0 million and $33.5 million, respectively, of unamortized debt issuance costs related to our credit facility. During the three months and six months ended June 30, 2015, we had a write-off of $10.6 million of debt issuance costs, included in interest expense, net of capitalized interest on the consolidated statements of operations, relating to the reduction of our credit facility borrowing base from $2.5 billion to $1.8 billion in connection with the EIG financing.

As of June 30, 2015 and December 31, 2014, we were in compliance with our credit facility’s covenants.


19


Senior Secured Notes

On April 8, 2015, we issued $650 million of 9.25% senior secured second lien notes due 2020 (“Senior Secured Notes”) in a private offering to EIG Redwood Debt Aggregator, LP and certain other purchasers at a purchase price of 97% of the principal amount. We received approximately $606.9 million from this offering, net of fees and estimated expenses, which we primarily used to repay borrowings under our credit facility. Interest on our Senior Secured Notes is payable quarterly in March, June, September and December. As of June 30, 2015, our Senior Secured Notes had a carrying value of $631.4 million, net of unamortized discount of $18.6 million.

As of June 30, 2015, the fair value of our Senior Secured Notes was estimated to be approximately $629 million, based on quoted yields for similarly rated debt instruments currently available in the market, and we consider the valuation of our Senior Secured Notes to be Level 3.

At June 30, 2015 and December 31, 2014, we had $22.3 million and zero, respectively, of unamortized debt issuance costs related to our Senior Secured Notes.

Senior Unsecured Notes

As of June 30, 2015, we had $305 million in aggregate principal amount of 8.625% senior notes due 2020 (the “2020 Senior Notes”), which had a carrying value of $302.4 million, net of unamortized discount of $2.6 million. In addition, as of June 30, 2015, we had $850 million in aggregate principal amount of 7.875% senior notes due 2022 (the “2022 Senior Notes”), which had a carrying value of $854.2 million, net of unamortized premium of $4.2 million. Interest on the 2020 Senior Notes and the 2022 Senior Notes is payable twice a year in April and October.

At June 30, 2015 and December 31, 2014, we had $17.8 million and $19.3 million, respectively, of unamortized debt issuance costs related to our 2020 Senior Notes and 2022 Senior Notes (together the “Senior Unsecured Notes”).

As of June 30, 2015, the fair value of our 2020 Senior Notes and 2022 Senior Notes were estimated to be approximately $277 million, and $708 million, respectively, based on prices quoted from third-party financial institutions. We consider the inputs to the valuation of our Senior Notes to be Level 2, as fair value was estimated based on prices quoted from third-party financial institutions.

As of June 30, 2015 and December 31, 2014, we were in compliance with the covenants under our Senior Unsecured Notes.

Interest Expense

Our interest expense is detailed as follows:
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
Thousands of dollars
 
2015
 
2014
 
2015
 
2014
Credit agreement (including commitment fees)
 
$
9,629

 
$
5,087

 
$
23,594

 
$
10,347

Senior Unsecured Notes
 
23,311

 
23,311

 
46,622

 
46,622

Senior Secured Notes
 
13,862

 

 
13,862

 

Amortization of net discount/premium and deferred issuance costs (a)
 
14,680

 
1,866

 
17,069

 
4,014

Capitalized interest
 
(78
)
 
(56
)
 
(78
)
 
(117
)
Total
 
$
61,404

 
$
30,208

 
$
101,069

 
$
60,866


(a) The three months and six months ended June 30, 2015 include a write-off of $10.6 million of debt issuance costs relating to the reduction of our borrowing base in the credit facility.


20


8. Condensed Consolidating Financial Statements

We and Breitburn Finance Corporation (and BOLP, with respect to the Senior Secured Notes), as co-issuers, and certain of our subsidiaries, as guarantors, issued the Senior Secured Notes and the Senior Unsecured Notes (collectively, the “Senior Notes”). All but two of our subsidiaries have guaranteed the Senior Notes, and our only non-guarantor subsidiaries, Breitburn Collingwood Utica LLC and ETSWDC, are minor subsidiaries.

In accordance with Rule 3-10 of Regulation S-X, we are not presenting condensed consolidating financial statements as we have no independent assets or operations; Breitburn Finance Corporation, the subsidiary co-issuer that does not guarantee the Senior Notes, is a wholly-owned finance subsidiary; all of our material subsidiaries are wholly-owned and have guaranteed the Senior Notes; and all of the guarantees are full, unconditional, joint and several.
    
Each guarantee of each of the Senior Notes is subject to release in the following customary circumstances except as noted:

(1)
a disposition of all or substantially all the assets of the guarantor subsidiary (including by way of merger or consolidation) to a third person, provided the disposition complies with the applicable indenture,
(2)
a disposition of the capital stock of the guarantor subsidiary to a third person, if the disposition complies with the applicable indenture and as a result the guarantor subsidiary ceases to be our subsidiary,            
(3)
the designation by us of the guarantor subsidiary as an Unrestricted Subsidiary as defined in the applicable indenture (applicable to the Senior Unsecured Notes only),
(4)
legal or covenant defeasance of such series of senior notes or satisfaction and discharge of the related indenture,
(5)
the liquidation or dissolution of the guarantor subsidiary, provided no default under the applicable indenture exists, or
(6)
the guarantor subsidiary ceases both (a) to guarantee any other indebtedness of ours or any other guarantor subsidiary and (b) to be an obligor under any bank credit facility (applicable to the Senior Unsecured Notes only).

9.  Asset Retirement Obligations

ARO is based on our net ownership in wells and facilities and our estimate of the costs to abandon and remediate those wells and facilities together with our estimate of the future timing of the costs to be incurred.  Payments to settle ARO occur over the operating lives of the assets, estimated to range from less than one year to 50 years.  Estimated cash flows have been discounted at our credit-adjusted risk-free rate of approximately 8% and adjusted for inflation using a rate of 2%.  Our credit-adjusted risk-free rate is calculated based on our cost of borrowing adjusted for the effect of our credit standing and specific industry and business risk.

We consider the inputs to our ARO valuation to be Level 3, as fair value is determined using discounted cash flow methodologies based on standardized inputs that are not readily observable in public markets.

Changes in ARO for the period ended June 30, 2015, and the year ended December 31, 2014 are presented in the following table:
 
 
Six Months Ended
 
Year Ended
Thousands of dollars
 
June 30, 2015
 
December 31, 2014
Carrying amount, beginning of period
 
$
238,411

 
$
123,769

Acquisitions
 
733

 
95,800

Liabilities incurred
 
1,950

 
4,020

Liabilities settled
 
(4,396
)
 
(1,708
)
Revisions
 
2,128

 
6,770

Accretion expense
 
8,329

 
9,760

Carrying amount, end of period
 
247,155

 
238,411

Less: current portion of ARO
 
(3,912
)
 
(4,948
)
Non-current portion of ARO
 
$
243,243

 
$
233,463


21


10.  Pensions and Postretirement Benefits

We acquired ETSWDC on November 19, 2014 in connection with the QRE Merger. ETSWDC sponsors a non-contributory defined benefit pension plan and a contributory postretirement benefit plan covering substantially all ETSWDC employees who were employed prior to March 31, 2008.

The components of net periodic benefit costs reflected in our consolidated statements of operations for the three months and six months ended June 30, 2015 consist of the following:

 
 
Three Months Ended
June 30, 2015
 
Six Months Ended
June 30, 2015
Thousands of dollars
 
Pension Benefits
 
Postretirement Benefits
 
Pension Benefits
 
Postretirement Benefits
Service cost
 
$
68

 
$
8

 
$
135

 
$
17

Interest cost
 
253

 
39

 
507

 
78

Expected return on plan assets
 
(335
)
 
(25
)
 
(671
)
 
(50
)
Net periodic (income) benefit costs
 
$
(14
)
 
$
22

 
$
(29
)
 
$
45


11.  Commitments and Contingencies

In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily relate to abandonments, environmental and other responsibilities where governmental and other organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon.  At June 30, 2015 and December 31, 2014, we had approximately $25.4 million and $21.1 million, respectively, of surety bonds. At each of June 30, 2015 and December 31, 2014, we had approximately $26.5 million in letters of credit outstanding.

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings.

12.  Partners’ Equity

Preferred Units

On April 8, 2015, we issued in private offerings $350 million of 8.0% Series B Perpetual Convertible Preferred Units (“Series B Preferred Units”) to EIG Redwood Equity Aggregator, LP (“EIG Equity”), ACMO BBEP Corp. (“ACMO”) and certain other purchasers at an issue price of $7.50 per unit. We received approximately $337.4 million from this offering, net of fees and estimated expenses, which we primarily used to repay borrowings under our credit facility. The Series B Preferred Units rank senior to the Common Units and on parity with the Series A Preferred Units (as defined below) with respect to the payment of current distributions.

For the three months and six months ended June 30, 2015, we elected to pay our Series B Preferred Unit distributions in kind by issuing additional Series B Preferred Units (or, if elected by the unitholder, by issuing Common Units in lieu of such Series B Preferred Units) in lieu of cash. On April 24, 2015 and May 28, 2015, we declared distributions on our Series B Preferred Units of 0.008222 and 0.006666 Series B Preferred Units per unit, respectively, which were paid on May 15, 2015 and June 15, 2015, respectively, in the form of 316,543 and 258,748 Series B Preferred Units, respectively, and 67,146 and 54,438 Common Units, respectively. During each of the three months and six months ended June 30, 2015, we recognized $6.4 million of accrued distributions on the Series B Preferred Units, which are included in non-cash distributions to Series B preferred unitholders on the consolidated statements of operations.

On April 8, 2015, we entered into a registration rights agreement (“Registration Rights Agreement”) with purchasers of the Series B Preferred Units, including EIG Equity, relating to the registered resale of (1) the Series B Preferred Units,

22


including paid in kind units, and (2) Common Units issuable upon conversion of the Series B Preferred Units, including paid in kind units. In certain circumstances, the purchasers of Series B Preferred Units will have piggyback registration rights and rights to request an underwritten offering as described in the Registration Rights Agreement.

On May 21, 2014, we sold 8.0 million 8.25% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”) in a public offering at a price of $25.00 per Series A Preferred Unit, resulting in proceeds of $193.2 million net of underwriting discount and offering expenses of $6.8 million. The Series A Preferred Units rank senior to the Common Units and on parity with the Series B Preferred Units with respect to the payment of current distributions. We pay cumulative distributions in cash on the Series A Preferred Units on a monthly basis at a monthly rate of $0.171875 per Series A Preferred Unit. During the three months and six months ended June 30, 2015, we recognized $4.1 million and $8.3 million, respectively, of accrued distributions on the Series A Preferred Units, which are included in distributions to Series A preferred unitholders on the consolidated statements of operations. During each of the three months and six months ended June 30, 2014, we recognized $1.8 million of accrued distributions on the Series A Preferred Units.

Common Units

At each of June 30, 2015 and December 31, 2014, we had approximately 211.7 million and 210.9 million, respectively, of Common Units outstanding.  
    
Pursuant to an Equity Distribution Agreement dated as of March 19, 2014 (the “Equity Distribution Agreement”), we may sell, from time to time up to $200 million in Common Units. We intend to use the net proceeds of any sales pursuant to the Equity Distribution Agreement, after deducting commissions and offering expenses, for general purposes, which may include, among other things, repayment of indebtedness, acquisitions, capital expenditures and additions to working capital. The Common Units to be issued are registered under a previously filed shelf registration statement on Form S-3, which was declared effective by the SEC on January 22, 2014.  During the three months ended March 31, 2015 and June 30, 2015, we sold zero and 543,845 Common Units, respectively, under the Equity Distribution Agreement for net proceeds of zero and $3.4 million, respectively. During the three months ended March 31, 2014 and June 30, 2014, we sold 25,300 and 976,611 Common Units, respectively, under the Equity Distribution Agreement for net proceeds of $0.5 million and $19.7 million, respectively.

During each of the three months and six months ended June 30, 2015, we issued 121,584 Common Units to a Series B Preferred unitholder that elected to receive its paid in kind distributions in Common Units. During the three months and six months ended June 30, 2014, we issued zero Common Units related to the Series B Preferred Units paid in kind distribution.

During the three months and six months ended June 30, 2015, we issued zero and less than 0.1 million Common Units, respectively, to non-employee directors for Restricted Phantom Units (“RPUs”) that vested in January 2015. During the three months and six months ended June 30, 2014, we issued zero Common Units and less than 0.1 million Common Units, respectively, to non-employee directors for RPUs that vested in January 2014.

At June 30, 2015 and December 31, 2014, there were approximately 5.9 million and 1.8 million, respectively, of units outstanding under our long-term incentive plan (“LTIP”) that were eligible to be paid in Common Units upon vesting.

During the three months ended June 30, 2015, we paid three monthly cash distributions totaling approximately $26.4 million, or $0.1250 per Common Unit. During the six months ended June 30, 2015, we paid six monthly cash distributions totaling approximately $79.1 million, or $0.3749 per Common Unit.

During the three months ended June 30, 2014, we paid cash distributions of approximately $59.5 million, or $0.4974 per Common Unit. During the six months ended June 30, 2014, we paid cash distributions of approximately $118.2 million, or $0.9900 per Common Unit.

During the three months and six months ended June 30, 2015, in addition to the distributions paid to holders of our Common Units, we paid $0.7 million and $2.1 million, respectively, in cash at a rate equal to the distributions paid to our holders of Common Units to holders of outstanding unvested RPUs issued under our LTIP. During the three months and six months ended June 30, 2014, we paid $1.0 million and $1.9 million, respectively, in cash at a rate equal to the distributions paid to our holders of Common Units to holders of outstanding unvested RPUs issued under our LTIP.


23


Earnings per Common Unit

FASB Accounting Standards require use of the “two-class” method of computing earnings per unit for all periods presented.  The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of common unit and participating security as if all earnings for the period had been distributed.  Unvested restricted unit awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation.  Our unvested RPUs and Convertible Phantom Units (“CPUs”) participate in distributions on an equal basis with Common Units.  Accordingly, the presentation below is prepared on a combined basis and is presented as net loss per common unit.

The following is a reconciliation of net loss and weighted average units for calculating basic net loss per common unit and diluted net loss per common unit.
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
Thousands, except per unit amounts
 
2015
 
2014
 
2015
 
2014
Net loss attributable to the partnership
 
$
(305,707
)
 
$
(104,725
)
 
$
(364,532
)
 
$
(114,483
)
Less:
 
 
 
 
 
 
 
 
Net loss attributable to participating units
 
(7,858
)
 
(1,690
)
 
(9,044
)
 
(1,763
)
Distributions to Series A preferred unitholders
 
4,125

 
1,833

 
8,250

 
1,833

Non-cash distributions to Series B preferred unitholders
 
6,408

 

 
6,408

 

Net loss attributable to Common Unitholders
 
$
(308,382
)
 
$
(104,868
)
 
$
(370,146
)
 
$
(114,553
)
 
 
 
 
 
 
 
 
 
Weighted average number of units used to calculate basic and diluted net loss per unit:
 
 
 
 
 
 
 
 
Common Units
 
211,401

 
119,724

 
211,167

 
119,466

Dilutive units (a)
 

 

 

 

Denominator for diluted net loss per unit
 
211,401

 
119,724

 
211,167

 
119,466

 
 
 
 
 
 
 
 
 
Net loss per common unit
 
 
 
 
 
 
 
 
Basic
 
$
(1.46
)
 
$
(0.89
)
 
$
(1.75
)
 
$
(0.97
)
Diluted
 
$
(1.46
)
 
$
(0.89
)
 
$
(1.75
)
 
$
(0.97
)

(a) The three months ended June 30, 2015 and 2014, exclude 724 and 757, respectively, of weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit, as we were in a loss position. The six months ended June 30, 2015 and 2014, exclude 715 and 719, respectively, of weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit, as we were in a loss position.


24


13. Accumulated Other Comprehensive Loss

Changes in accumulated other comprehensive loss by component, net of tax, for the three months and six months ended June 30, 2015 were as follows:
 
 
Three Months Ended June 30, 2015
 
 
Gain (loss) on
 
 
Thousands of dollars
 
Available-For-Sale Securities
 
Postretirement Benefits
 
Total
Accumulated comprehensive loss attributable to the partnership as of March 31, 2015
 
$
(9
)
 
$
(280
)
 
$
(289
)
 
 
 
 
 
 
 
Other comprehensive income before reclassification
 
52

 

 
52

Amounts reclassified from accumulated other comprehensive loss (a)
 
(125
)
 

 
(125
)
Net current period other comprehensive loss
 
(73
)
 

 
(73
)
Less: noncontrolling interest
 
(29
)
 

 
(29
)
Accumulated comprehensive loss attributable to the partnership as of June 30, 2015
 
$
(53
)
 
$
(280
)
 
$
(333
)

 
 
Six Months Ended June 30, 2015
 
 
Gain (loss) on
 
 
Thousands of dollars
 
Available-For-Sale Securities
 
Postretirement Benefits
 
Total
Accumulated comprehensive loss attributable to the partnership as of December 31, 2014
 
$
(112
)
 
$
(280
)
 
$
(392
)

 


 


 


Other comprehensive income before reclassification
 
247

 

 
247

Amounts reclassified from accumulated other comprehensive loss (a)
 
(147
)
 

 
(147
)
Net current period other comprehensive income
 
100

 

 
100

Less: noncontrolling interest
 
41

 

 
41

Accumulated comprehensive loss attributable to the partnership as of June 30, 2015
 
$
(53
)
 
$
(280
)
 
$
(333
)

(a) Amounts were reclassified from accumulated other comprehensive loss to other expense (income), net on the consolidated statements of operations.

14.  Unit Based Compensation Plans

Unit-based compensation expense for the three months ended June 30, 2015 and 2014 was $6.8 million and $6.1 million, respectively, and for the six months ended June 30, 2015 and 2014 was $14.5 million and $12.6 million respectively. Unit based compensation expense of $6.1 million for the three months ended June 30, 2015 was included in general and administrative expenses and $0.7 million was included in restructuring costs. Unit-based compensation expense of $13.0 million for the six months ended June 30, 2015 was included in general and administrative expenses and $1.5 million was included in restructuring costs. See Note 15 for a discussion of restructuring costs.

During the three months and six months ended June 30, 2015, the board of directors of our General Partner approved the grant of less than 0.1 million and 4.6 million RPUs and CPUs to employees of Breitburn Management under our LTIP, respectively. During the three months and six months ended June 30, 2015, our outside directors were issued zero and 0.2 million RPUs under our LTIP, respectively.  The fair market value of the RPUs granted during 2015 for computing compensation expense under FASB Accounting Standards averaged $6.56 per unit.

During each of the three months ended June 30, 2015 and 2014, we paid zero for taxes withheld on RPUs. During the six months ended June 30, 2015 and 2014, we paid $0.7 million and $0.9 million for taxes withheld on RPUs.

25



As of June 30, 2015, we had $35.8 million of unrecognized compensation costs for all outstanding awards, which is expected to be recognized over the period from July 1, 2015 to December 31, 2017.

For detailed information on our various compensation plans, see Note 18 to the consolidated financial statements included in our 2014 Annual Report.

15.  Restructuring Costs

In the first quarter of 2015, we executed a workforce reduction plan as part of a company-wide reorganization effort intended to reduce costs, due in part to lower commodity prices. The reduction was communicated to affected employees on various dates, and all such notifications were completed by March 31, 2015. The plan resulted in a reduction of approximately 37 employees. In connection with the reduction, we incurred a total cost of approximately $5.6 million, of which $4.9 million was recognized in the first quarter of 2015, which includes severance cash payments, accelerated vesting of LTIP grants for certain individuals and other employee-related termination costs. In April 2015, we communicated further reductions to an additional 8 employees and incurred a total cost of approximately $1.1 million, which was recognized in the second quarter of 2015.  Total workforce reductions in 2015 as a result of the workforce reduction plan, voluntary resignations and early retirement exceed 60 positions.
 
 
Three Months Ended
 
Six Months Ended
Thousands of dollars
 
June 30, 2015
 
June 30, 2015
Severance payments
 
953

 
4,768

Unit-based compensation expense
 
720

 
1,534

Other termination costs
 
100

 
389

Total
 
1,773

 
6,691


16.  Subsequent Events
    
On July 1, 2015, we announced a cash distribution to holders of Common Units for the first monthly payment attributable to the second quarter of 2015 at the rate of $0.04166 per Common Unit, which was paid on July 17, 2015 to the unitholders of record at the close of business on July 14, 2015. On July 31, 2015, we announced a cash distribution to holders of Common Units for the second monthly payment attributable to the second quarter of 2015 at the rate of $0.04166 per Common Unit, to be paid on August 14, 2015 to the unitholders of record at the close of business on August 11, 2015.

On July 1, 2015, we also declared a cash distribution for our Series A Preferred Units of $0.171875 per Series A Preferred Unit, which is expected to be paid on August 17, 2015, to record holders of our Series A Preferred Units at the close of business on July 31, 2015. On July 31, 2015, we declared a cash distribution for our Series A Preferred Units of $0.171875 per Series A Preferred Unit, which is expected to be paid on September 15, 2015 to record holders of our Series A Preferred Units at the close of business on August 31, 2015. The monthly distribution rate is equal to an annual distribution of $2.0625 per Series A Preferred Unit.

On July 1, 2015 and July 31, 2015 we declared distributions on our Series B Preferred Units, which we elected to pay in kind by issuing additional Series B Preferred Units (or, if elected by the unitholder, by issuing Common Units in lieu of such Series B Preferred Units) of 0.006666 Series B Preferred Unit per unit, payable on July 15, 2015 and August 17, 2015, respectively, to record holders of Series B Preferred Units at the close of business on June 30, 2015 and July 31, 2015, respectively.

In July 2015, we entered into a MichCon natural gas swap contract for 5,000 MMBtu/day for 2015 at $2.91 per MMBtu, a MichCon natural gas swap contract for 4,000 MMBtu/day for 2016 at $3.10 per MMBtu, a MichCon natural gas swap contract for 5,000 MMBtu/day for 2017 at $3.16 per MMBtu, a MichCon natural gas swap contract for 3,500 MMBtu/day for 2018 at $3.22 per MMBtu and a MichCon natural gas swap contract for 2,000 MMBtu/day for 2019 at $3.33 per MMBtu.

26


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

You should read the following discussion and analysis in conjunction with Management’s Discussion and Analysis in Part II—Item 7 of our 2014 Annual Report and the consolidated financial statements and related notes therein.  Our 2014 Annual Report contains a discussion of other matters not included herein, such as disclosures regarding critical accounting policies and estimates and contractual obligations.  You should also read the following discussion and analysis together with Part II—Item 1A “—Risk Factors” of this report, the “Cautionary Statement Regarding Forward-Looking Information” in this report and in our 2014 Annual Report and Part I—Item 1A “—Risk Factors” of our 2014 Annual Report.

Overview

We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil, natural gas liquids (“NGL”) and natural gas properties in the United States. Our objective is to manage our oil and natural gas producing properties for the purpose of generating cash flows and making distributions to our unitholders. Our assets consist primarily of producing and non-producing oil, NGL and natural gas reserves located in seven producing areas:

Ark-La-Tex (Arkansas, Louisiana, Alabama and East Texas);
Michigan, Indiana and Kentucky (“MI/IN/KY”);
Permian Basin in Texas and New Mexico;
Mid-Continent (Oklahoma, Kansas and the Texas Panhandle);
Rockies (Wyoming);
Florida; and
California.

2015 Highlights

On March 31, 2015, we completed the acquisition of certain CO2 producing properties located in Harding County, New Mexico for a total preliminary purchase price of $70.2 million, subject to customary purchase price adjustments. See Note 2 to the consolidated financial statements within this report for a discussion of this acquisition.

On April 8, 2015, we issued $350 million of Series B Perpetual Convertible Preferred Units (“Series B Preferred Units”) and $650 million of 9.25% Senior Secured Second Lien Notes due 2020 (“Senior Secured Notes”) in private offerings to investment funds managed by EIG and other purchasers. We received approximately $944 million from these offerings, net of fees and estimated expenses.

On April 8, 2015, in connection with the offerings mentioned above, we entered into the First Amendment to the Third Amended and Restated Credit Agreement, to allow for the issuance of the Senior Secured Notes and to establish a revised borrowing base of $1.8 billion through April 2016, subject to limited exceptions.

In May 2015, we completed the acquisition of additional interests in our existing fields located in Ark-La-Tex for a total preliminary purchase price of $3.4 million, which is primarily reflected in oil and natural gas properties on the consolidated balance sheet.
In July 2015, we entered into an agreement to exchange non-contiguous acres in Martin and Midland Counties, Texas for other acreage in Martin County, creating a contiguous block giving us six operated surface locations with an average 89% working interest. The trade, which was our first in the Midland Basin, affords us more strategic flexibility to realize potential horizontal development value from the acreage. 

During the three months ended March 31, 2015, we paid three monthly cash distributions at the rate of $0.0833 per Common Unit per month, totaling approximately $52.7 million, or $0.2499 per Common Unit. During the three months ended June 30, 2015, we paid three monthly cash distributions at the rate of $0.0417 per Common Unit per month, totaling approximately $26.4 million, or $0.1250 per Common Unit. On July 1, 2015 and July 31, 2015, we announced cash distributions to holders of Common Units for the first and second monthly payments attributable to the second quarter of 2015, at the rate of $0.0417 per Common Unit per month, paid on July 17, 2015 and payable on August 14, 2015, respectively.
    

27


During each of the three months ended March 31, 2015 and June 30, 2015, we recognized $4.1 million of accrued distributions on the Series A Preferred Units. On July 1, 2015 and July 31, 2015, we declared cash distributions for our Series A Preferred Units of $0.171875 per Series A Preferred Unit, which are expected to be paid on August 17, 2015 and September 15, 2015, respectively.

On April 24, 2015 and May 28, 2015, we declared distributions on our Series B Preferred Units, which we elected to pay in kind by issuing additional Series B Preferred Units (or, if elected by the unitholder, by issuing Common Units in lieu of such Series B Preferred Units) in lieu of cash of 0.008222 and 0.006666 Series B Preferred Unit per unit, which were paid on May 15, 2015 and June 15, 2015, respectively. On July 1, 2015 and July 31, 2015, we declared distributions on our Series B Preferred Units, which we elected to pay in kind by issuing additional Series B Preferred Units (or, if elected by the unitholder, by issuing Common Units in lieu of such Series B Preferred Units) of 0.006666 Series B Preferred Unit per unit, payable on July 15, 2015 and August 17, 2015 respectively.

Operational Focus and Capital Expenditures

In the first six months of 2015, our oil, NGL and natural gas capital expenditures, including capitalized engineering costs, totaled $132 million, compared to approximately $168 million in the first six months of 2014.  We spent approximately $51 million in the Permian Basin, $33 million in Florida, $24 million in Ark-La-Tex, $13 million in Mid-Continent, $8 million in California, $2 million in MI/IN/KY and $1 million in the Rockies.  In the first six months of 2015, we drilled and completed seven operated productive wells and participated in the drilling of 16 non-operated wells in the Permian Basin, drilled and completed nine productive wells in Ark-La-Tex, five productive wells in California, two productive wells in the Rockies, one productive well in Mid-Continent and one productive well in Florida. We also performed workovers on 41 wells in Ark-La-Tex, seven wells in California, six wells in Florida, two wells in MI/IN/KY and one well in the Permian Basin.

In 2015, our crude oil, NGL and natural gas capital spending program, including capitalized engineering costs and excluding acquisitions, is expected to be approximately $200 million. This compares with approximately $389 million in 2014. In 2015, we anticipate spending approximately 90% principally on oil projects in Mid-Continent, Ark-La-Tex, Florida and the Permian Basin and approximately 10% principally on oil projects in California, the Rockies and MI/IN/KY. We anticipate 79% of our total capital spending will be focused on drilling and rate-generating projects and CO2 purchases that are designed to increase or add to production or reserves. In 2015, we plan to drill 53 wells in Mid-Continent, Ark-La-Tex, Florida and the Permian Basin.

In the second quarter of 2015, there were a number of areas across the U.S. that experienced a combination of electrical storms, heavy rainfall and flooding and a number of our operating areas were affected. Ark-La-Tex was the area most impacted by the weather. In addition, we had several wells that were either shut-in or not repaired during the quarter due to being uneconomic at current commodity prices.  The combined impact on production for weather and shut-in wells for the quarter was not material and was offset by strong performance from both our base production, particularly in the Midland Basin, our enhanced oil recovery projects in Mid-Continent, and our capital program through the second quarter.  In addition, with weather conditions improving in a number of areas, we are bringing production back on line.

In the first quarter of 2015, we completed a workforce reduction plan as part of a company-wide reorganization effort intended to reduce costs, due in part to lower commodity prices. The reduction was communicated to affected employees on various dates during March, and all such notifications were completed by March 31, 2015. The plan resulted in a reduction of approximately 37 employees, primarily in administrative and support positions. In April 2015, we communicated further reductions to an additional 8 employees. Total workforce reductions in 2015 as a result of the workforce reduction plan, voluntary resignations and early retirement exceed 60 positions.

Commodity Prices

Our revenues and net income are sensitive to oil, NGL and natural gas prices which have been and are expected to continue to be highly volatile.

In the second quarter of 2015, the NYMEX WTI spot price averaged $58 per barrel, compared with approximately $103 per barrel in the second quarter of 2014.  In the first six months of 2015, the NYMEX WTI spot price ranged from a low of $43 per barrel to a high of $61 per barrel. In the first six months of 2014, the NYMEX WTI spot price averaged $101 per barrel and ranged from a low of $91 per barrel to a high of $108 per barrel. 

28


 
In the second quarter of 2015, the Henry Hub natural gas spot price averaged $2.75 per MMBtu compared with approximately $4.61 per MMBtu in the second quarter of 2014.  In the first six months of 2015, the Henry Hub natural gas spot price averaged $2.82 and ranged from a low of $2.50 per MMBtu to a high of $3.32 per MMBtu. In the first six months of 2014, the Henry Hub spot price averaged $4.83 and ranged from a low of $3.95 per MMBtu to a high of $8.15 per MMBtu. In the second quarter of 2015, the MichCon natural gas spot price averaged $2.78 per MMBtu compared with approximately $4.99 per MMBtu in the second quarter of 2014.  

We expect that further or sustained crude oil and natural gas prices will not only decrease our revenues, but will also reduce the amount of crude oil and natural gas that we can produce economically and therefore lower our crude oil and natural gas reserves.

The recent significant decline in oil and natural gas prices increases the uncertainty as to the impact of commodity prices on our estimated proved reserves. We are unable to predict future commodity prices with any greater precision than the futures market.  A prolonged period of depressed commodity prices may have a significant impact on the volumetric quantities of our proved reserve portfolio.  The impact of commodity prices on our estimated proved reserves can be illustrated as follows: if the SEC-mandated 2014 beginning of the prior 12 months average prices used for our December 31, 2014 reserve report had been replaced with the NYMEX strip prices for the applicable commodity as of June 30, 2015 (without regard to our commodity derivative positions and without assuming any change in development plans or costs, which has historically not been the case in periods of prolonged depressed commodity prices), then the estimated proved reserves volumes as of December 31, 2014 would have decreased by approximately 12%. The prices assumed in this example were derived using NYMEX strip prices at June 30, 2015 through December 31, 2021 and then held flat thereafter. We believe that the use of this NYMEX strip price may help provide investors with an understanding of the impact of sustained lower commodity price conditions on our proved reserves through an assumed period. However, the use of this pricing example does not necessarily indicate management’s overall view on future commodity prices. In addition, if revisions of proved reserves occur in the future, we could have further increases in our DD&A rates. We are unable to predict the timing and amount of future reserve revisions, nor the impact such revisions may have on our future DD&A rates.

Breitburn Management

Breitburn Management Company LLC, our wholly-owned subsidiary (“Breitburn Management”), operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering.  All of our employees, including our executives, are employees of Breitburn Management.

Breitburn Management also manages the operations of Pacific Coast Energy Company LP (“PCEC”), our predecessor, and provides administrative services to PCEC under an administrative services agreement. These services include operational functions, such as exploitation and technical services, petroleum and reserves engineering and executive management, and administrative services, such as accounting, information technology, audit, human resources, land, business development, finance and legal. These services are provided in exchange for a monthly fee for indirect expenses and reimbursement for all direct expenses, including incentive compensation plan costs and direct payroll and administrative costs related to PCEC properties and operations.  For the three months and six months ended June 30, 2015, the monthly fee paid by PCEC for indirect expenses was $700,000. The term of the agreement is set to expire on December 31, 2016, at which time, the agreement is subject to renegotiation.


29


Results of Operations

The table below summarizes certain of our results of operations for the periods indicated.  The data for the periods reflect our results as they are presented in our unaudited consolidated financial statements included elsewhere in this report.
Thousands of dollars,
 
Three Months Ended June 30,
 
Increase/
 
 
 
Six Months Ended June 30,
 
Increase/
 
 
except as indicated
 
2015
 
2014
 
(Decrease)
 
%

 
2015
 
2014
 
(Decrease)
 
%

Total production (MBoe)
 
5,015

 
3,373

 
1,642

 
49
 %
 
10,066

 
6,592

 
3,474

 
53
 %
     Oil (MBbl)
 
2,822

 
1,901

 
921

 
48
 %
 
5,712

 
3,700

 
2,012

 
54
 %
     NGLs (MBbl)
 
483

 
279

 
204

 
73
 %
 
942

 
537

 
405

 
75
 %
     Natural gas (MMcf)
 
10,264

 
7,163

 
3,101

 
43
 %
 
20,475

 
14,134

 
6,341

 
45
 %
Average daily production (Boe/d)
 
55,110

 
37,069

 
18,041

 
49
 %
 
55,613

 
36,422

 
19,191

 
53
 %
Sales volumes (MBoe)
 
5,089

 
3,289

 
1,800

 
55
 %
 
10,087

 
6,522

 
3,565

 
55
 %
Average realized sales price (per Boe) (a)(b)
 
$
37.24

 
$
66.59

 
$
(29.35
)
 
(44
)%
 
$
34.90

 
$
67.83

 
$
(32.93
)
 
(49
)%
     Oil (per Bbl) (a)(b)
 
53.29

 
95.74

 
(42.45
)
 
(44
)%
 
48.50

 
93.91

 
(45.41
)
 
(48
)%
     NGLs (per Bbl)
 
18.35

 
38.26

 
(19.91
)
 
(52
)%
 
17.46

 
40.48

 
(23.02
)
 
(57
)%
     Natural gas (per Mcf) (b)
 
2.57

 
4.81

 
(2.24
)
 
(47
)%
 
2.81

 
5.65

 
(2.84
)
 
(50
)%
Oil sales
 
154,425

 
173,948

 
(19,523
)
 
(11
)%
 
278,268

 
341,034

 
(62,766
)
 
(18
)%
NGL sales
 
8,861

 
10,675

 
(1,814
)
 
(17
)%
 
16,452

 
21,740

 
(5,288
)
 
(24
)%
Natural gas sales
 
26,350

 
34,428

 
(8,078
)
 
(23
)%
 
57,539

 
79,833

 
(22,294
)
 
(28
)%
(Loss) gain on commodity derivative instruments
 
(93,432
)
 
(127,000
)
 
33,568

 
n/a

 
43,760

 
(167,228
)
 
210,988

 
(126
)%
Other revenues, net (c)
 
6,504

 
1,071

 
5,433

 
n/a

 
12,973

 
2,655

 
10,318

 
389
 %
Total revenues
 
102,708

 
93,122

 
9,586

 
10
 %
 
408,992

 
278,034

 
130,958

 
47
 %
Lease operating expenses before taxes (d)
 
93,858

 
70,923

 
22,935

 
32
 %
 
193,937

 
137,913

 
56,024

 
41
 %
Production and property taxes (e)
 
15,348

 
16,001

 
(653
)
 
(4
)%
 
28,892

 
31,660

 
(2,768
)
 
(9
)%
Total lease operating expenses
 
109,206

 
86,924

 
22,282

 
26
 %
 
222,829

 
169,573

 
53,256

 
31
 %
Purchases and other operating costs
 
421

 
110

 
311

 
283
 %
 
579

 
324

 
255

 
79
 %
Salt water disposal costs
 
4,053

 

 
4,053

 
n/a

 
8,074

 

 
8,074

 
n/a

Change in inventory
 
2,157

 
(3,974
)
 
6,131

 
n/a

 
2,333

 
(4,640
)
 
6,973

 
(150
)%
Total operating costs
 
115,837

 
83,060

 
32,777

 
39
 %
 
233,815

 
165,257

 
68,558

 
41
 %
Lease operating expenses before taxes per Boe
 
18.72

 
21.03

 
(2.31
)
 
(11
)%
 
19.27

 
20.92

 
(1.65
)
 
(8
)%
Production and property taxes per Boe
 
3.06

 
4.74

 
(1.68
)
 
(35
)%
 
2.87

 
4.80

 
(1.93
)
 
(40
)%
Total lease operating expenses per Boe
 
21.78

 
25.77

 
(3.99
)
 
(15
)%
 
22.14

 
25.72

 
(3.58
)
 
(14
)%
Depletion, depreciation and amortization (“DD&A”)
 
109,447

 
68,245

 
41,202

 
60
 %
 
219,271

 
131,746

 
87,525

 
66
 %
DD&A per Boe
 
21.82

 
20.23

 
1.59

 
8
 %
 
21.78

 
19.99

 
1.79

 
9
 %
Impairment of oil and natural gas properties
 

 

 

 
n/a

 
59,113

 

 
59,113

 
n/a

Impairment of goodwill
 
95,947

 

 
95,947

 
n/a

 
95,947

 

 
95,947

 
n/a

G&A excluding unit based compensation
 
16,778

 
10,322

 
6,456

 
63
 %
 
42,113

 
22,502

 
19,611

 
87
 %
G&A excluding unit based compensation per Boe
 
$
3.35

 
$
3.06

 
$
0.29

 
9
 %
 
4.18

 
$
3.41

 
$
0.77

 
23
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a) Includes the per Boe price effect of crude oil purchases.
 
 
 
 
 
 
 
 
(b) Excludes the effect of commodity derivative settlements.
 
 
 
 
 
 
 
 
(c) Includes salt water disposal revenues, gas processing fees, earnings from equity investments and other operating revenues.
(d) Includes district expenses, transportation expenses and processing fees.
 
 
 
 
(e) Includes ad valorem and severance taxes.

30


Comparison of Results for the Three Months and Six Months Ended June 30, 2015 and 2014

The variances in our results were due to the following components:

Production

For the three months ended June 30, 2015, total production was 5,015 MBoe compared to 3,373 MBoe for the three months ended June 30, 2014, an increase of 49%, primarily due to 1,879 MBoe of production from our properties acquired in the QRE Merger in November 2014 (the “QRE properties”), partially offset by lower production from our legacy properties, primarily in the Permian Basin, MI/IN/KY and the Rockies due to natural field declines.

For the six months ended June 30, 2015, total production was 10,066 MBoe compared to 6,592 MBoe for the six months ended June 30, 2014, an increase of 3,474 MBoe, primarily due to 3,746 MBoe of production from the QRE properties, partially offset by lower production from our legacy properties, primarily in Mid-Continent, the Permian Basin and MI/IN/KY due to natural field declines.

Oil, NGL and natural gas sales

Total oil, NGL and natural gas sales revenues decreased $29.4 million for the three months ended June 30, 2015, compared to the three months ended June 30, 2014. Crude oil revenues decreased $19.5 million due to lower average crude oil prices, partially offset by production from the QRE properties. NGL revenues decreased $1.8 million due to lower average NGL prices, partially offset by production from the QRE properties. Natural gas revenues decreased $8.1 million, primarily due to lower average natural gas prices, partially offset by production from the QRE properties.
 
Realized prices for crude oil, excluding the effect of derivative instruments, decreased $42.45 per Boe, or 44%, for the three months ended June 30, 2015 compared to the three months ended June 30, 2014. Realized prices for NGLs, excluding the effect of derivative instruments, decreased $19.91 per Boe, or 52% for the three months ended June 30, 2015 compared to the three months ended June 30, 2014. Realized prices for natural gas, excluding the effect of derivative instruments, decreased $2.24 per Mcf, or 47%, for the three months ended June 30, 2015 compared to the three months ended June 30, 2014.

Total oil, NGL and natural gas sales revenues decreased $90.3 million for the six months ended June 30, 2015, compared to the six months ended June 30, 2014. Crude oil revenues decreased $62.8 million due to lower average crude oil prices, partially offset by production from the QRE properties. NGL revenues decreased $5.3 million due to lower average NGL prices, partially offset by production from the QRE properties. Natural gas revenues decreased $22.3 million, primarily due to lower average natural gas prices, partially offset by production from the QRE properties.
 
Realized prices for crude oil, excluding the effect of derivative instruments, decreased $45.41 per Boe, or 48%, for the six months ended June 30, 2015 compared to the six months ended June 30, 2014. Realized prices for NGLs, excluding the effect of derivative instruments, decreased $23.02 per Boe, or 57%, for the six months ended June 30, 2015 compared to the six months ended June 30, 2014. Realized prices for natural gas, excluding the effect of derivative instruments, decreased $2.84 per Mcf, or 50%, for the six months ended June 30, 2015 compared to the six months ended June 30, 2014.

(Loss) gain on commodity derivative instruments

Loss on commodity derivative instruments for the three months ended June 30, 2015 was $93.4 million compared to a loss of $127.0 million during the three months ended June 30, 2014. Oil and natural gas derivative instrument settlement receipts net of payments totaled $100.6 million for the three months ended June 30, 2015 due to significantly lower commodity prices compared to our average hedge prices. Oil and natural gas derivative instrument settlement payments net of receipts for the three months ended June 30, 2014 totaled $17.0 million due to higher commodity prices compared to our average hedge prices.

Mark-to-market loss on commodity derivative instruments for the three months ended June 30, 2015 was $194.0 million compared to a mark-to-market loss of $110.0 million for the three months ended June 30, 2014, primarily due to a decrease in commodity future prices during the three months ended June 30, 2015 and 2014.


31


Gain on commodity derivative instruments for the six months ended June 30, 2015 was $43.8 million compared to a loss of $167.2 million during the six months ended June 30, 2014. Oil and natural gas derivative instrument settlement receipts net of payments totaled $226.9 million for the six months ended June 30, 2015 due to significantly lower commodity prices compared to our average hedge prices. Oil and natural gas derivative instrument settlement payments net of receipts for the six months ended June 30, 2014 totaled $30.5 million due to higher commodity prices compared to our average hedge prices.

Mark-to-market loss on commodity derivative instruments for the six months ended June 30, 2015 was $183.2 million compared to a mark-to-market loss of $136.7 million for the six months ended June 30, 2014, primarily due to a decrease in commodity future prices during the six months ended June 30, 2015 and 2014.

Other revenues, net

Other revenues increased $5.4 million for the three months ended June 30, 2015, compared to the three months ended June 30, 2014, primarily due to $4.0 million of salt water disposal revenue and $0.5 million of sulfur sales revenue related to the QRE properties.

Other revenues increased $10.3 million for the six months ended June 30, 2015, compared to the six months ended June 30, 2014, primarily due to $8.1 million of salt water disposal revenue and $1.1 million of sulfur sales revenue related to the QRE properties.

Lease operating expenses

Pre-tax lease operating expenses, including district expenses, transportation expenses and processing fees, for the three months ended June 30, 2015 increased $22.9 million compared to the three months ended June 30, 2014.  The increase in pre-tax lease operating expenses primarily reflects lease operating costs for the QRE properties. On a per Boe basis, pre-tax lease operating expenses were 11% lower than the three months ended June 30, 2014 at $18.72 per Boe, primarily due to lower commodity prices and lower well service expenses.

Production and property taxes for the three months ended June 30, 2015 totaled $15.3 million, which was $0.7 million lower than the three months ended June 30, 2014, primarily due to lower crude oil and natural gas prices, partially offset by higher production.  On a per Boe basis, production and property taxes for the three months ended June 30, 2015 were $3.06 per Boe, which was 35% lower than the three months ended June 30, 2014, due to lower commodity prices.

Pre-tax lease operating expenses, including district expenses, transportation expenses and processing fees, for the six months ended June 30, 2015 increased $56.0 million compared to the six months ended June 30, 2014.  The increase in pre-tax lease operating expenses primarily reflects lease operating costs for the QRE properties. On a per Boe basis, pre-tax lease operating expenses were 8% lower than the six months ended June 30, 2014 at $19.27 per Boe, primarily due to lower commodity prices and lower well service expenses.

Production and property taxes for the six months ended June 30, 2015 totaled $28.9 million, which was $2.8 million lower than the six months ended June 30, 2014, primarily due to lower crude oil and natural gas prices, partially offset by higher production.  On a per Boe basis, production and property taxes for the six months ended June 30, 2015 were $2.87 per Boe, which was 40% lower than the six months ended June 30, 2014, due to lower commodity prices.

Change in inventory

In Florida, our crude oil sales are a function of the number and size of crude oil shipments in each quarter, and thus crude oil sales do not always coincide with volumes produced in a given quarter.  Sales occur on average every six to eight weeks.  We match production expenses with crude oil sales.  Production expenses associated with unsold crude oil inventory are credited to operating costs through the change in inventory account.  Production expenses are charged to operating costs through the change in inventory account when they are sold.  

For the three months ended June 30, 2015, the change in inventory account amounted to a charge of $2.2 million compared to a credit of $4.0 million during the same period in 2014.  The charge to inventory during the three months ended June 30, 2015 primarily reflects higher volume of crude oil sold than produced during the quarter. The credit during the three months ended June 30, 2014 reflects lower volume of crude oil sold than produced during the quarter.  In the three months ended June 30, 2015, we sold 252 gross MBbls and produced 165 gross MBbls of crude oil from our Florida operations.

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For the six months ended June 30, 2015, the change in inventory account amounted to a charge of $2.3 million compared to a credit of $4.6 million during the same period in 2014.  The charge to inventory during the six months ended June 30, 2015 primarily reflects the higher volume of crude oil sold than produced during the period. The credit during the six months ended June 30, 2014 reflects the lower volume of crude oil sold than produced during the period.  In the six months ended June 30, 2015, we sold 383 gross MBbls and produced 348 gross MBbls of crude oil from our Florida operations.

Depletion, depreciation and amortization

DD&A totaled $109.4 million, or $21.82 per Boe, during the three months ended June 30, 2015, an increase of approximately 8% per Boe from the same period a year ago.  The increase in DD&A per Boe compared to the three months ended June 30, 2014 was primarily due to lower oil and natural gas prices, and the effect those prices had on our reserve volumes, as well as the addition of QRE properties acquired at higher values and capital expenditures incurred during the twelve months ended June 30, 2015.

DD&A totaled $219.3 million, or $21.78 per Boe, during the six months ended June 30, 2015, an increase of approximately 9% per Boe from the same period a year ago.  The increase in DD&A per Boe compared to the six months ended June 30, 2014 was primarily due to lower oil and natural gas prices, and the effect those prices had on our reserve volumes, as well the addition of QRE properties acquired at higher values and capital expenditures incurred during the twelve months ended June 30, 2015.

Impairments
    
There were no impairments of proved properties during the three months ended June 30, 2015. Impairments of proved properties totaled $59.1 million for the three months ended March 31, 2015, including $33.1 million for our Permian properties, $16.7 million for our Rockies natural gas properties and $9.3 million for our Mid-Continent properties, primarily due to the impact that the decrease in oil and natural gas prices during the three months ended March 31, 2015 had on certain of our low operating margin properties. There were no impairments of proved properties during the three months and six months ended June 30, 2014.    
      
As of March 31, 2015, we had $95.9 million of goodwill related to the QRE Merger (see Note 2). Due to a decrease in the price of our Common Units during the second quarter of 2015, we performed a qualitative goodwill impairment assessment. In the first step of the goodwill impairment test, we determined that the fair value of our goodwill was less than the carrying amount, primarily due to the decrease in the price of our Common Units. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there was no remaining implied fair value attributable to goodwill.  We therefore recorded a non-cash goodwill impairment charge of $95.9 million during the three months ended June 30, 2015, to reduce the carrying value of goodwill to zero.
    
    General and administrative expenses

Our G&A expenses totaled $22.9 million and $16.4 million for the three months ended June 30, 2015 and 2014, respectively.  This included $6.1 million in non-cash unit-based compensation expense related to employee incentive plans for each of the three months ended June 30, 2015 and 2014.  G&A expenses, excluding non-cash unit-based compensation, were $16.8 million and $10.3 million for the three months ended June 30, 2015 and 2014, respectively.  The increase was primarily due to $2.7 million of integration costs and additional costs attributable to the QRE Merger. On a per Boe basis, G&A expenses excluding non-cash unit-based compensation were $3.35 and $3.06 for the three months ended June 30, 2015 and 2014, respectively, due to higher integration costs.

Our G&A expenses totaled $55.1 million and $35.1 million for the six months ended June 30, 2015 and 2014, respectively.  This included $13.0 million and $12.6 million, respectively, in non-cash unit-based compensation expense related to employee incentive plans.  G&A expenses, excluding non-cash unit-based compensation, were $42.1 million and $22.5 million for the six months ended June 30, 2015 and 2014, respectively.  The increase was primarily due to integration costs of $7.4 million and additional costs attributable to the QRE Merger, particularly higher payroll expenses, office building rent and legal costs. On a per Boe basis, G&A expenses excluding non-cash unit-based compensation were $4.18 and $3.41 for the six months ended June 30, 2015 and 2014, respectively. The increase in G&A expenses per Boe was primarily due to higher integration costs. The increase in unit-based compensation expense was primarily due to additional personnel attributable to the QRE Merger.

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Restructuring costs

In the first quarter of 2015, we completed a workforce reduction plan as part of a company-wide reorganization effort intended to reduce costs, due in part to lower commodity prices. The reduction was communicated to affected employees on various dates during March, and all such notifications were completed by March 31, 2015. The plan resulted in a reduction of approximately 37 employees, primarily in administrative and support positions. In connection with the reduction, we incurred a total cost of approximately $5.6 million which included severance cash payments, accelerated vesting of LTIP grants for certain individuals and other employee-related termination costs. Of the $5.6 million in restructuring costs, $4.9 million were recognized in the first quarter of 2015 and $0.7 million were recognized in the second quarter of 2015. In April 2015, we communicated further reductions to an additional 8 employees and incurred a total cost of approximately $1.1 million, which was recognized in the second quarter of 2015.  Total workforce reductions in 2015 as a result of the workforce reduction plan, voluntary resignations and early retirement exceed 60 positions.

Interest expense, net of amounts capitalized

Our interest expense totaled $61.4 million and $30.2 million for the three months ended June 30, 2015 and 2014, respectively.  The increase in interest expense was primarily due to $13.9 million of interest on our Senior Secured Notes, $10.6 million write-off of debt issuance costs associated with the reduction of our credit facility borrowing base in April 2015 and $4.5 million higher credit facility interest expense as a result of higher borrowings related to the QRE Merger. Interest expense, excluding debt amortization, totaled $46.7 million and $28.3 million for the three months ended June 30, 2015 and 2014, respectively. 

Our interest expense totaled $101.1 million and $60.9 million for the six months ended June 30, 2015 and 2014, respectively.  The increase in interest expense was primarily due to $13.9 million of interest on our Senior Secured Notes, $13.2 million higher credit facility interest expense as a result of higher borrowings related to the QRE Merger and $10.6 million write-off of debt issuance costs associated with the reduction of our credit facility borrowing base in April 2015. Interest expense, excluding debt amortization, totaled $84.0 million and $56.9 million for the six months ended June 30, 2015 and 2014, respectively. 

Loss on interest rate swaps

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. In order to mitigate our interest rate exposure, as of June 30, 2015, we had interest rate swaps, indexed to 1-month LIBOR, to fix a portion of floating LIBOR-based debt under our credit facility for 2015 and 2016, for notional amounts of $393.5 million and $410.0 million, respectively, with average fixed rates of 1.60% and 1.72%, respectively, that were assumed as part of the QRE Merger. As of June 30, 2014, we had no interest rate swaps in place. Loss on interest swaps for the three months ended June 30, 2015 and 2014 were $0.6 million and zero, respectively. The loss on interest rate swaps for the three months ended June 30, 2015 included settlement payments of $1.5 million and a mark-to-market gain of $0.9 million. Loss on interest swaps for the six months ended June 30, 2015 and 2014 were $2.4 million and zero, respectively. The loss on interest rate swaps for the six months ended June 30, 2015 included settlement payments of $2.9 million and a mark-to-market gain of $0.5 million.

Liquidity and Capital Resources

Overview

As of June 30, 2015, we had approximately $464 million of available borrowing capacity under our credit facility (including the impact of outstanding letters of credit), which has a borrowing base of $1.8 billion, and we had approximately $1.31 billion of indebtedness outstanding under our credit facility. We have historically funded our operations, acquisitions and cash distributions primarily through cash generated from operations, amounts available under our credit facility and equity and debt offerings.  Future cash flow is subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2015. These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position.

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During the second quarter of 2015, we took actions to improve our liquidity position. On April 8, 2015, we completed private offerings of $650 million of Senior Secured Notes and $350 million of Series B Preferred Units with combined net proceeds of approximately $944 million, which we used primarily to repay borrowings under our credit facility. Concurrently with those transactions, we also amended our credit facility to establish a borrowing base of $1.8 billion until April 1, 2016, subject, starting with the October 1, 2015 borrowing base redetermination date, to our having liquidity (inclusive of borrowing base availability) of 10% of the borrowing base.

Our ability to access the public or private debt or equity capital markets on economic terms in the future will be affected by general economic conditions, the domestic and global financial markets, our operational and financial performance, the value and performance of our debt or equity securities, prevailing commodity prices and other macroeconomic factors outside of our control.

Cash Flows
 
Operating activities.  Our cash flows from operating activities for the six months ended June 30, 2015 were $214.9 million compared to $191.1 million for the six months ended June 30, 2014. The increase in cash flows from operating activities was primarily due to higher operating income in 2015 from a 55% increase in sales volume primarily due to the QRE properties, which increased sales revenue by approximately $242 million and $257 million higher commodity derivative settlement receipts primarily due to lower commodity prices, which was partially offset by lower physical sales revenue driven by lower commodity prices, which decrease sales revenue by approximately $332 million, $69 million of additional operating costs primarily for the QRE properties and $30 million higher cash interest paid due to higher debt levels. Cash flow from working capital changes during the six months ended June 30, 2015 was $26 million lower than the six months ended June 30, 2014, primarily due to lower commodity prices, which impacted our payable balances for lease operating expenses, royalties, and production taxes.

Investing activities.  Net cash flows used in investing activities during the six months ended June 30, 2015 and 2014 were $189.3 million and $196.6 million, respectively. During the six months ended June 30, 2015, we paid $170.6 million for capital expenditures, primarily for drilling and completion activities, $17.7 million on property acquisitions, primarily for CO2 producing properties, $3.6 million on purchases of available-for-sale securities and $0.9 million on CO2 advances, partially offset by $3.5 million in proceeds from the sale of available-for-sale securities. During the six months ended June 30, 2014, we spent $188.8 million on capital expenditures, primarily for drilling and completion activities, $2.7 million on property acquisitions and $5.7 million on CO2 advances and GHG emission allowances.

Financing activities.  Net cash flows used in financing activities for the six months ended June 30, 2015 were $28.7 million, and net cash flows provided by financing activities for the six months ended June 30, 2014 were $12.1 million. During the six months ended June 30, 2015, we decreased our outstanding borrowings under our credit facility by approximately $780.5 million. We had total outstanding borrowings, net of unamortized discount on our Senior Notes, of approximately $3.10 billion at June 30, 2015 and $3.35 billion at December 31, 2014.  During the six months ended June 30, 2015, we received net proceeds of $337.9 million and $4.9 million from issuance of Series B Preferred Units and Common Units, respectively, we made cash distributions of $81.2 million and $8.3 million on Common Units and Series A Preferred Units, respectively, borrowed $1.04 billion, repaid $1.30 billion on our credit facility and other long-term debt and paid $29.2 million of debt issuance costs.  During the six months ended June 30, 2014, we received net proceeds of $193.4 million and $20.3 million on Series A Preferred Units and Common Units, respectively, made cash distributions of $120.1 million on Common Units, borrowed $466.0 million and repaid $543.5 million under our credit facility.  

Preferred Units

In May 2014, we sold 8.0 million Series A Preferred Units at a price to the public of $25.00 per Series A Preferred Unit, resulting in proceeds of $193.2 million, net of underwriting discount and offering expenses of $6.8 million. The monthly distribution rate is $0.171875 per Series A Preferred Unit, which is equal to an annual distribution of $2.0625 per Series A Preferred Unit.

On April 8, 2015, we issued $350 million of 8.0% Series B Preferred Units in a private offering to an investment fund managed by EIG and other purchasers. On April 24, 2015 and May 28, 2015, we declared a per unit distribution on our Series B Preferred Units, which we elected to pay in kind by issuing additional Series B Preferred Units (or, if elected by the unitholder, by issuing Common Units in lieu of such Series B Preferred Units) in lieu of cash of 0.008222 and 0.006666

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Series B Preferred Unit per unit, paid on May 15, 2015 and June 15, 2015, respectively, to record holders of Series B Preferred Units at the close of business on April 30, 2015 and May 29, 2015, respectively. On July 1, 2015 and July 31, 2015 we declared distributions on our Series B Preferred Units of 0.006666 Series B Preferred Unit per unit, payable on July 15, 2014 and August 17, 2015, respectively, to record holders of Series B Preferred Units at the close of business on June 30, 2015 and July 31, 2015, respectively.

Common Units
    
Our Partnership Agreement provides that, at the discretion of our General Partner, we may pay quarterly distributions on our Common Units within 45 days following the end of each quarter or in three installments within 17, 45 and 75 days following the end of each quarter. We changed our Common Unit distribution payment policy from a quarterly payment schedule to a monthly payment schedule beginning with the distributions relating to the fourth quarter of 2013.

During the three months ended June 30, 2015, we paid three monthly cash distributions at the rate of $0.0417 per Common Unit per month, totaling approximately $26.4 million, or $0.1250 per Common Unit. During the six months ended June 30, 2015, we paid six monthly cash distributions, totaling approximately $79.1 million, or $0.3749 per Common Unit.

On July 1, 2015, we announced a cash distribution of $0.04166 per Common Unit for the first monthly payment attributable to the second quarter of 2015, which was paid on July 17, 2015, to record holders of Common Units at the close of business on July 14, 2015. On July 31, 2015, we announced a cash distribution to unitholders of the second monthly payment attributable to the second quarter of 2015 at the rate of $0.04166 per Common Unit, payable on August 14, 2015 to the unitholders of record at the close of business on August 11, 2015. These monthly distributions are equal to a distribution of $0.50 per Common Unit on an annualized basis.

Senior Notes

On April 8, 2015, we issued $650 million of Senior Secured Notes in a private offering to an investment fund managed
by EIG and other purchasers. See Note 7 to the consolidated financial statements within this report for a discussion of our
Senior Secured Notes.

As of June 30, 2015, we had $305 million in 2020 Senior Notes and $850 million in 2022 Senior Notes in addition to the Senior Secured Notes. See Note 7 to the consolidated financial statements within this report for a discussion of our Senior Unsecured Notes.

Credit Agreement

At each of June 30, 2015 and December 31, 2014, we had a $5.0 billion credit facility with a maturity date of November 19, 2019. At June 30, 2015 and December 31, 2014, our borrowing base was $1.8 billion and $2.5 billion respectively.

In connection with the Series B Preferred Units and Senior Secured Notes offerings, on April 8, 2015, we entered into the First Amendment. Among other changes, the First Amendment: (i) established a borrowing base of $1.8 billion until the April 1, 2016 scheduled redetermination date subject, starting with the October 1, 2015 scheduled redetermination date, to our having liquidity (inclusive of borrowing base availability) of 10% of the borrowing base; (ii) permitted $650 million of second lien indebtedness; (iii) increased the base rate and LIBOR margins by 0.25%; (iv) added a requirement that we have liquidity (inclusive of borrowing base availability) of 10% of the borrowing base after giving effect to any distribution on our common units or voluntary prepayment of second lien indebtedness; and (v) added a requirement that we have liquidity (inclusive of borrowing base availability) of 5% of the borrowing base after giving effect to any distribution on our Series B Preferred Units. Our credit facility borrowing as of August 5, 2015 and June 30, 2015, were $1.29 billion and $1.31 billion, respectively.
        
Our borrowing base is automatically reduced by an amount equal to 25% of the principal of newly issued senior unsecured notes and second lien indebtedness, except if the proceeds of such indebtedness are used to refinance certain existing indebtedness. Loans under the Third Amended and Restated Credit Agreement will bear interest by reference to a Base Rate, LIBOR or a LIBOR Market Index Rate (each as defined in the Third Amended and Restated Credit Agreement), plus an applicable margin that is determined pursuant to a pricing grid which varies between 75 and 175 basis points (in the case of Base Rate loans) and between 175 and 275 basis points (in the case of LIBOR and LIBOR Market Index Rate loans) based on a ratio of loans and letters of credit outstanding to the borrowing base.

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As of June 30, 2015, the lending group under the Third Amended and Restated Credit Agreement included 35 banks.  Of the $1.8 billion in total commitments under our credit facility, Wells Fargo Bank, National Association held approximately 5% of the commitments, with the remaining 34 banks holding between 1% and 4.2% of the commitments. In addition to our relationships with these institutions under the credit facility, from time to time we engage in other transactions with a number of these institutions.  Such institutions or their affiliates may serve as underwriter or initial purchaser of our debt and equity securities and/or serve as counterparties to our commodity and interest rate derivative agreements.

The Third Amended and Restated Credit Agreement contains customary covenants, including restrictions on our ability to: incur additional indebtedness; make certain investments, loans or advances; permit the interest coverage ratio (defined as the ratio of EBITDAX to Consolidated Interest Expense) to be less than 2.50 to 1.00; make distributions to our unitholders or repurchase units; make dispositions or enter into sales and leasebacks; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries.

The Third Amended and Restated Credit Agreement includes a restriction on our ability to make a distribution unless, after giving effect to such distribution, we remain in compliance with all terms and conditions of our credit facility. As of June 30, 2015 and August 5, 2015, we were in compliance with our debt covenants.

The events that constitute an event of default under the Third Amended and Restated Credit Agreement include: payment defaults; misrepresentations; breaches of covenants; cross-default and cross-acceleration to certain other indebtedness; adverse judgments against us in excess of a specified amount; changes in management or control; loss of permits; certain insolvency events; and assertion of certain environmental claims.

EBITDAX is not a defined US GAAP measure. The Third Amended and Restated Credit Agreement defines EBITDAX as consolidated net income plus exploration expense, interest expense, income tax provision, DD&A, unrealized loss or gain on derivative instruments, non-cash charges, including non-cash unit-based compensation expense, loss or gain on sale of assets (excluding gain or loss on monetization of derivative instruments for the following twelve months), cumulative effect of changes in accounting principles, cash distributions received from our unrestricted entities (as defined in the Third Amended and Restated Credit Agreement) and excluding income from our unrestricted entities. If any acquisition or disposition was consummated during an applicable quarter, all calculations of EBITDAX shall be determined on a pro forma basis.
 
Contractual Obligations and Commitments

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of derivative instruments and accounts receivable.  Our derivative instruments expose us to credit risk from counterparties.  As of June 30, 2015, our derivative counterparties were Bank of Montreal, Barclays Bank PLC, BNP Paribas, Canadian Imperial Bank of Commerce, Citibank, N.A, Citizens Bank, National Association, Comerica Bank, Credit Agricole Corporate and Investment Bank, Credit Suisse Energy LLC, Credit Suisse International, ING Capital Markets LLC, JP Morgan Chase Bank N.A., Merrill Lynch Commodities, Inc., Royal Bank of Canada, The Bank of Nova Scotia, The Toronto-Dominion Bank, Union Bank N.A. and Wells Fargo Bank, N.A. Our counterparties are all lenders who participate in our Third Amended and Restated Credit Agreement. Future volatility could adversely affect the financial condition of our derivative counterparties. On all transactions where we are exposed to counterparty risks, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits and monitor the appropriateness of these limits on an ongoing basis. We periodically obtain credit default swap information on our counterparties.  As of June 30, 2015, each of these financial institutions had an investment grade credit rating.  Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default.  As of June 30, 2015, our largest derivative asset balances were with Wells Fargo Bank, N.A., Credit Suisse Energy LLC and JP Morgan Chase Bank N.A., which accounted for approximately 21%, 19% and 13% of our derivative asset balances, respectively.  

Except as discussed above, we had no material changes to our financial contractual obligations during the six months ended June 30, 2015.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of June 30, 2015 and December 31, 2014.  


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New Accounting Standards

See Note 1 to the consolidated financial statements within this report for a discussion of new accounting standards applicable to us.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

The following should be read in conjunction with “Quantitative and Qualitative Disclosures About Market Risk” included under Part II—Item 7A in our 2014 Annual Report.  Also, see Note 3 to the consolidated financial statements within this report for additional discussion related to our financial instruments, including a summary of our derivative instruments as of June 30, 2015.

Changes in Fair Value

The fair value of our outstanding oil and natural gas commodity derivative instruments was a net asset of approximately $544.0 million and $727.2 million at June 30, 2015 and December 31, 2014, respectively.  With a $10.00 per barrel increase in the price of oil, and a corresponding $1.00 per Mcf increase in natural gas, our net commodity derivative instrument asset at June 30, 2015 would have decreased by approximately $231 million. With a $10.00 per barrel decrease in the price of oil, and a corresponding $1.00 per Mcf decrease in natural gas, our net commodity derivative instrument asset at June 30, 2015 would have increased by approximately $245 million.

Price risk sensitivities were calculated by assuming across-the-board increases in price of $10.00 per barrel for oil and $1.00 per Mcf for natural gas regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price.  In the event of actual changes in prompt month prices equal to the assumptions, the fair value of our derivative instrument portfolio would typically change by less than the amounts given due to lower volatility in out-month prices.

The fair value of our outstanding interest rate derivative instruments was a net liability of approximately $6.7 million and $7.2 million at June 30, 2015 and December 31, 2014, respectively. With a 100 basis point increase in the LIBOR rate, our outstanding interest rate derivative instruments net liability at June 30, 2015 would have decreased by approximately $6 million. With a 100 basis points decrease in the LIBOR rate to a minimum rate of zero, our net liability at June 30, 2015 would have increased by approximately $4 million.

Item 4.  Controls and Procedures

Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our General Partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our General Partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. Based upon the evaluation, our General Partner’s principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of June 30, 2015 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2015 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings.

Item 1A.  Risk Factors

There have been no material changes to the Risk Factors disclosed in Part I—Item 1A “—Risk Factors” of our 2014 Annual Report.

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

On April 8, 2015, we issued 46.7 million of 8.0% Series B Preferred Units.

Item 3.  Defaults Upon Senior Securities

None.

Item 4.  Mine Safety Disclosures

Not applicable.

Item 5.  Other Information

None.


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Item 6.  Exhibits
NUMBER
 
DOCUMENT
3.1
 
Certificate of Limited Partnership of Breitburn Energy Partners LP (incorporated herein by reference to Exhibit 3.1 to Amendment No. 1 to Form S-1 (File No. 333-134049) filed on July 13, 2006).
3.2
 
Certificate of Amendment to Certificate of Limited Partnership of Breitburn Energy Partners LP (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q (File No. 001-33055) filed on May 5, 2015.
3.3
 
Third Amended and Restated Agreement of Limited Partnership of Breitburn Energy Partners LP (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 14, 2015).
3.4
 
Fourth Amended and Restated Limited Liability Company Agreement of Breitburn GP LLC dated as of April 5, 2010 (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2011).
3.5
 
Amendment No. 1 to the Fourth Amended and Restated Limited Liability Company Agreement of Breitburn GP LLC dated as of December 30, 2010 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011).
3.6
 
Amendment No. 2 to the Fourth Amended and Restated Limited Liability Company Agreement of Breitburn GP LLC (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on July 2, 2014).
4.1
 
Indenture, dated as of October 6, 2010, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2010).
4.2
 
Indenture, dated as of January 13, 2012, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 13, 2012).
4.3
 
Indenture, dated as of April 8, 2015, by and among Breitburn Energy Partners LP, Breitburn Operating LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-33055) filed on April 14, 2015).
4.4
 
First Supplemental Indenture, dated as of August 8, 2013, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association, to the Indenture, dated as of October 6, 2010 (incorporated herein by reference to Exhibit 4.3 to the Current Report on Form 8-K (File No. 001-33055) filed on November 22, 2013).
4.5
 
First Supplemental Indenture, dated as of August 8, 2013, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association, to the Indenture dated as of January 13, 2012 (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on November 22, 2013).
4.6
 
Second Supplemental Indenture, dated as of November 24, 2014, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association, to the Indenture, dated as of October 6, 2010 (incorporated herein by reference to Exhibit 4.8 to Post-Effective Amendment No. 2 to Form S-3 (File No. 001-181531) filed on November 24, 2014).
4.7
 
Second Supplemental Indenture, dated as of November 24, 2014, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association, to the Indenture dated as of January 13, 2012 (incorporated herein by reference to Post-Effective Amendment No. 2 to Form S-3 (File No. 001-181531) filed on November 24, 2014).
4.8
 
Registration Rights Agreement, dated July 23, 2014, by and among Breitburn Energy Partners LP, QR Holdings (QRE), LLC, QR Energy Holdings, LLC, Quantum Resources B, LP, Quantum Resources A1, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by QR Energy, LP on July 29, 2014).
4.9
 
Registration Rights Agreement, dated April 8, 2015, by and among Breitburn Energy Partners LP and the purchasers listed on Schedule A thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on April 14, 2015).
10.1
 
Amendment No. 5 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company LLC dated May 1, 2015.
10.2
 
Amended and Restated Series B Preferred Unit Purchase Agreement, dated as of April 8, 2015, by and among Breitburn Energy Partners LP,  EIG Redwood Equity Aggregator, LP, ACMO BBEP Corp. and the other purchasers listed on Schedule A thereto (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 14, 2015).

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10.3
 
Board Representation and Standstill Agreement, dated as of April 8, 2015, by and among Breitburn GP LLC, Breitburn Energy Partners LP and EIG Redwood Equity Aggregator, LP (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on April 14, 2015).
10.4
 
Amended and Restated Purchase Agreement, dated as of April 8, 2015, by and among Breitburn Energy Partners LP, Breitburn Operating LP, Breitburn Finance Corporation, the guarantors party thereto and the purchasers listed on Schedule I thereto (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K (File No. 001-33055) filed on April 14, 2015).
10.5
 
Security Agreement, dated as of April 8. 2015, by and among Breitburn Operating LP, Breitburn Energy Partners LP, Breitburn Finance Corporation, each of the subsidiary entities named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K (File No. 001-33055) filed on April 14, 2015).
10.6
 
Intercreditor Agreement, dated as of April 8, 2015, by and among Wells Fargo Bank, National Association, U.S. Bank National Association, Breitburn Energy Partners LP, Breitburn Finance Corporation, Breitburn Operating LP and each of the subsidiary entities named therein (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K (File No. 001-33055) filed on April 14, 2015).
10.7
 
First Amendment to Third Amended and Restated Credit Agreement, dated as of April 8. 2015, by and among Breitburn Operating LP, as borrower, Breitburn Energy Partners LP, as parent guarantor, Breitburn GP LLC, Breitburn Operating GP LLC, the subsidiary guarantors named therein, each lender signatory thereto and Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 10.7 to the Current Report on Form 8-K (File No. 001-33055) filed on April 14, 2015).
10.8
 
Second Amendment to First Amended and Restated BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan effective as of June 18, 2015 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 18, 2015).
31.1*
 
Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
 
Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**
 
Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**
 
Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.
101*
 
Interactive Data Files.
*
 
Filed herewith.
**
 
Furnished herewith.
 
Management contract or compensatory plan or arrangement.

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SIGNATURES

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

 
 
BREITBURN ENERGY PARTNERS LP
 
 
 
 
 
 
By:
BREITBURN GP LLC,
 
 
 
its General Partner
 
 
 
 
Dated:
August 6, 2015
By:
/s/ Halbert S. Washburn
 
 
 
Halbert S. Washburn
 
 
 
Chief Executive Officer
 
 
 
 
Dated:
August 6, 2015
By:
/s/ James G. Jackson
 
 
 
James G. Jackson
 
 
 
Chief Financial Officer





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