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EX-31.1 - EXHIBIT 31.1 - Breitburn Energy Partners LPq3201510-qex311.htm
EX-32.2 - EXHIBIT 32.2 - Breitburn Energy Partners LPq3201510-qex322.htm
EX-31.2 - EXHIBIT 31.2 - Breitburn Energy Partners LPq3201510-qex312.htm
EX-32.1 - EXHIBIT 32.1 - Breitburn Energy Partners LPq3201510-qex321.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 September 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 November 4, 2015, the registrant had 211,884,150 Common Units outstanding.

 
 
 
 
 
 



INDEX

 
 
Page No.
 
 
 
 
 
PART I
 
 
FINANCIAL INFORMATION
 
 
 
 
 
 
 Consolidated Balance Sheets (Unaudited) at September 30, 2015 and December 31, 2014
 
Consolidated Statements of Operations (Unaudited) for the Three Months and Nine Months Ended September 30, 2015 and 2014
 
 
 Consolidated Statements of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2015 and 2014
 
– Condensed Notes to the 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 Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 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
 
September 30,
2015
 
December 31,
2014
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash
 
$
12,091

 
$
12,628

Accounts and other receivables, net
 
135,479

 
166,436

Derivative instruments (note 3)
 
400,857

 
408,151

Related party receivables (note 4)
 
2,069

 
2,462

Inventory
 
3,371

 
3,727

Prepaid expenses
 
12,654

 
7,304

Total current assets
 
566,521

 
600,708

Equity investments
 
6,473

 
6,463

Property, plant and equipment
 
 
 
 
Oil and natural gas properties
 
7,908,709

 
7,736,409

Other property, plant and equipment (note 2)
 
141,047

 
60,533

 
 
8,049,756

 
7,796,942

Accumulated depletion and depreciation (note 5)
 
(3,161,636
)
 
(1,342,741
)
Net property, plant and equipment
 
4,888,120

 
6,454,201

Other long-term assets
 
 
 
 
Intangibles, net
 
1,538

 
8,336

Goodwill (note 5)
 

 
92,024

Derivative instruments (note 3)
 
267,681

 
319,560

Other long-term assets (note 6)
 
119,715

 
157,042

Total assets
 
$
5,850,048

 
$
7,638,334

LIABILITIES AND EQUITY
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable
 
$
63,921

 
$
129,270

Current portion of long-term debt (note 7)
 
603

 
105,000

Derivative instruments (note 3)
 
5,289

 
5,457

Distributions payable
 
733

 
733

Current portion of asset retirement obligation (note 9)
 
2,390

 
4,948

Revenue and royalties payable
 
42,454

 
40,452

Wages and salaries payable
 
22,264

 
22,322

Accrued interest payable
 
42,989

 
20,672

Production and property taxes payable
 
30,838

 
25,207

Other current liabilities
 
6,644

 
7,495

Total current liabilities
 
218,125

 
361,556

Credit facility
 
1,253,000

 
2,089,500

Senior notes, net
 
1,788,466

 
1,156,560

Other long-term debt
 
2,397

 
1,100

Total long-term debt (note 7)
 
3,043,863

 
3,247,160

Deferred income taxes
 
2,269

 
2,575

Asset retirement obligation (note 9)
 
247,317

 
233,463

Derivative instruments (note 3)
 
1,421

 
2,269

Other long-term liabilities (note 10)
 
24,615

 
25,135

Total liabilities
 
3,537,610

 
3,872,158

Commitments and contingencies (note 11)
 


 


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

 
193,215

Series B preferred units, 48.0 million and 0 units issued and outstanding at September 30, 2015 and December 31, 2014, respectively (note 12)
 
347,454

 

Common units, 211.8 million and 210.9 million units issued and outstanding at September 30, 2015 and December 31, 2014, respectively (note 12)
 
1,765,689

 
3,566,468

Accumulated other comprehensive loss (note 13)
 
(576
)
 
(392
)
Total partners' equity
 
2,305,782

 
3,759,291

Noncontrolling interest
 
6,656

 
6,885

Total equity
 
2,312,438

 
3,766,176

Total liabilities and equity
 
$
5,850,048

 
$
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
 
Nine Months Ended
 
 
September 30,
 
September 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
 
$
153,325

 
$
216,146

 
$
505,584

 
$
658,753

Gain (loss) on commodity derivative instruments, net (note 3)
 
253,012

 
146,171

 
296,772

 
(21,057
)
Other revenue, net
 
5,922

 
1,585

 
18,895

 
4,240

    Total revenues and other income items
 
412,259

 
363,902

 
821,251

 
641,936

Operating costs and expenses
 
 
 
 
 
 
 
 
Operating costs
 
115,135

 
82,904

 
348,950

 
248,161

Depletion, depreciation and amortization
 
117,464

 
72,671

 
336,735

 
204,417

Impairment of oil and natural gas properties (note 5)
 
1,440,167

 
29,434

 
1,499,280

 
29,434

Impairment of goodwill (note 5)
 

 

 
95,947

 

General and administrative expenses
 
23,276

 
18,737

 
78,400

 
53,886

Restructuring costs (note 15)
 
(278
)
 

 
6,413

 

(Gain) loss on sale of assets
 
(7,459
)
 
(63
)
 
(7,322
)
 
357

Total operating costs and expenses
 
1,688,305

 
203,683

 
2,358,403

 
536,255

 
 
 
 
 
 
 
 
 
Operating (loss) income
 
(1,276,046
)
 
160,219

 
(1,537,152
)
 
105,681

 
 
 
 
 
 
 
 
 
Interest expense, net of capitalized interest
 
50,919

 
29,494

 
151,988

 
90,360

Loss on interest rate swaps (note 3)
 
996

 

 
3,411

 

Other income, net
 
(137
)
 
(450
)
 
(579
)
 
(1,223
)
 
 
 
 
 
 
 
 
 
(Loss) income before taxes
 
(1,327,824
)
 
131,175

 
(1,691,972
)
 
16,544

 
 
 
 
 
 
 
 
 
Income tax expense
 
14

 
532

 
365

 
384

 
 
 
 
 
 
 
 
 
Net (loss) income
 
(1,327,838
)
 
130,643

 
(1,692,337
)
 
16,160

 
 
 
 
 
 
 
 
 
Less: Net income attributable to noncontrolling interest
 
91

 

 
124

 

 
 
 
 
 
 
 
 
 
Net (loss) income attributable to the partnership
 
(1,327,929
)
 
130,643

 
(1,692,461
)
 
16,160

 
 
 
 
 
 
 
 
 
Less: Distributions to Series A preferred unitholders
 
4,125

 
4,125

 
12,375

 
5,958

Less: Non-cash distributions to Series B preferred unitholders
 
7,145

 

 
13,553

 

Less: Net (loss) income attributable to participating units
 
(31,662
)
 
1,868

 
(40,612
)
 
40

 
 
 
 
 
 
 
 
 
Net (loss) income attributable to common unitholders
 
$
(1,307,537
)
 
$
124,650

 
$
(1,677,777
)
 
$
10,162

 
 
 
 
 
 
 
 
 
Basic net (loss) income per common unit (note 12)
 
$
(6.17
)
 
$
1.03

 
$
(7.94
)
 
$
0.08

Diluted net (loss) income per common unit (note 12)
 
$
(6.17
)
 
$
1.03

 
$
(7.94
)
 
$
0.08

 
 
 
 
 
 
 
 
 
Weighted average number of units used to calculate basic and diluted net (loss) income per unit (in thousands):
 
 
 
 
 
 
 
 
Basic
 
211,766

 
120,473

 
211,369

 
119,806

Diluted
 
211,766

 
121,250

 
211,369

 
120,544


See accompanying notes to consolidated financial statements.

3


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

 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
Thousands of dollars, except per unit amounts
 
2015
 
2014
 
2015
 
2014
Net (loss) income
 
$
(1,327,838
)
 
$
130,643

 
$
(1,692,337
)
 
$
16,160

 
 
 
 
 
 
 
 
 
Other comprehensive loss, net of tax:
 
 
 
 
 
 
 
 
Change in fair value of available-for-sale securities (a)
 
(636
)
 

 
(537
)
 

Total other comprehensive loss
 
(636
)
 

 
(537
)
 

 
 
 
 
 
 
 
 
 
Total comprehensive (loss) income
 
(1,328,474
)
 
130,643

 
(1,692,874
)
 
16,160

 
 
 
 
 
 
 
 
 
Less: Comprehensive loss attributable to noncontrolling interest
 
(303
)
 

 
(229
)
 

 
 
 
 
 
 
 
 
 
Comprehensive (loss) income attributable to the partnership
 
$
(1,328,171
)
 
$
130,643

 
$
(1,692,645
)
 
$
16,160


(a) Net of income tax benefit of $0.4 million and $0.3 million for the three months and nine months ended September 30, 2015.

See accompanying notes to consolidated financial statements.

4


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

 
 
Nine Months Ended
 
 
September 30,
Thousands of dollars
 
2015
 
2014
Cash flows from operating activities
 
 
 
 
Net (loss) income
 
$
(1,692,337
)
 
$
16,160

Adjustments to reconcile to cash flows from operating activities:
 
 
 
 
Depletion, depreciation and amortization
 
336,735

 
204,417

Impairment of oil and natural gas properties
 
1,499,280

 
29,434

Impairment of goodwill
 
95,947

 

Unit-based compensation expense
 
20,714

 
18,440

(Gain) loss on derivative instruments
 
(293,361
)
 
21,057

Derivative instrument settlement receipts (payments)
 
351,518

 
(34,228
)
Income from equity affiliates, net
 
(10
)
 
90

Deferred income taxes
 
(306
)
 
153

(Gain) loss on sale of assets
 
(7,322
)
 
357

Other
 
14,348

 
5,172

Changes in net assets and liabilities
 
 
 
 
Accounts receivable and other assets
 
22,251

 
(3,345
)
Inventory
 
356

 
(528
)
Net change in related party receivables and payables
 
393

 
1,095

Accounts payable and other liabilities
 
2,978

 
36,642

Net cash provided by operating activities
 
351,184

 
294,916

Cash flows from investing activities
 
 
 
 
Property acquisitions
 
(17,160
)
 
(6,422
)
Capital expenditures
 
(226,718
)
 
(293,275
)
Proceeds from sale of assets
 
9,441

 
366

Proceeds from sale of available-for-sale securities
 
3,631

 

Purchases of available-for-sale securities
 
(3,803
)
 

Other
 
(853
)
 
(9,242
)
Net cash used in investing activities
 
(235,462
)
 
(308,573
)
Cash flows from financing activities
 
 
 
 
Proceeds from issuance of preferred units, net
 
337,895

 
193,215

Proceeds from issuance of common units, net
 
4,768

 
25,917

Distributions to preferred unitholders
 
(12,375
)
 
(5,225
)
Distributions to common unitholders
 
(108,283
)
 
(181,430
)
Proceeds from issuance of long-term debt, net
 
1,203,400

 
693,000

Repayments of long-term debt
 
(1,512,500
)
 
(707,000
)
Change in bank overdraft
 
(39
)
 
(2,417
)
Debt issuance costs
 
(29,125
)
 
(1,634
)
Net cash (used in) provided by financing activities
 
(116,259
)
 
14,426

(Decrease) increase in cash
 
(537
)
 
769

Cash beginning of period
 
12,628

 
2,458

Cash end of period
 
$
12,091

 
$
3,227


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 September 30, 2015, our operating results for the three months and nine months ended September 30, 2015 and 2014 and our cash flows for the nine months ended September 30, 2015 and 2014 have been included.  Operating results for the three months and nine months ended September 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.  The objective of ASU 2015-03 is to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset.  In August 2015, the FASB issued ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.  This ASU amends ASU 2015-03 which had not addressed the balance sheet presentation of debt issuance costs incurred in connection with line-of-credit arrangements.  Under ASU 2015-15, a company may defer debt issuance costs associated with line-of-credit arrangements and present such costs as an asset, subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings.  ASU 2015-03 and ASU 2015-15 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015 and should be applied retrospectively.  Early adoption is permitted.  The adoption of these standards will not have an impact on our consolidated financial statements, other than balance sheet reclassifications.
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 consolidated 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.

6


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.

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 & Other Transactions

In September 2015, we entered into an agreement to exchange certain of our non-contiguous acres in Martin County, Texas for non-operated producing assets in Weld County, Colorado and cash consideration of $4.8 million. We recorded a gain of $7.5 million on this transaction. The trade was for all future horizontal and vertical development rights in the oil and gas leases exchanged. We reserved all existing wellbores and the production therefrom in these Martin County, Texas acres.

In August 2015, we granted a three-year term assignment of our interests in certain oil and gas leases in the Mississippian, Woodford, and Hunton formations in Kingfisher County, Oklahoma for cash consideration of $3.2 million. We reserved all existing wellbores and the production therefrom and reserved an overriding royalty interest equal to the difference between existing lease burdens appearing of record and 20%.

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 $3.0 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 and no amount was paid in cash during the three months ended September 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 reclassified from other long-term assets to other property, plant and equipment during the nine months ended September 30, 2015 and $5.1 million of intangibles reclassified from intangibles to other property, plant and equipment during the nine months ended September 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.


7


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.
    
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:

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.

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”), for a total purchase price of $122.3 million. The final purchase price was allocated to oil and natural gas assets as follows: $110.9 million to unproved properties, $13.1 million to proved properties and $1.7 million to ARO.


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 nine months ended September 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
 
Nine Months Ended
Thousands of dollars, except per unit amounts
 
September 30, 2014
 
September 30, 2014
Revenues
 
$
564,321

 
$
1,009,362

Net income attributable to the partnership
 
211,356

 
45,286

 
 
 
 
 
Net income per common unit:
 
 
 
 
Basic
 
$
1.00

 
$
0.19

Diluted
 
$
0.99

 
$
0.19


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 September 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)
 
17,500

 
29,000

 
24,000

 
14,000

 
8,000

Average Price ($/MMBtu)
 
$
4.26

 
$
3.91

 
$
3.71

 
$
3.15

 
$
3.20

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

(b)
$
0.69

(c)
$

 
$

Total:
 
 
 
 
 
 
 
 
 
 
Volume (MMBtu/d)
 
92,311

 
77,030

 
54,056

 
15,870

 
8,000

Average Price ($/MMBtu)
 
$
4.76

 
$
4.08

 
$
4.02

 
$
3.26

 
$
3.20

 
 
 
 
 
 
 
 
 
 
 

(a) Deferred premiums of $0.64 apply to 420 MMBtu/d of the 2015 volume.    
(b) Deferred premiums of $0.66 apply to 11,350 MMBtu/d of the 2016 volume.
(c) Deferred premiums of $0.69apply to 10,445 MMBtu/d of the 2017 volume.

During the three months and nine months ended September 30, 2015 and 2014, we did not enter into any derivative instruments that required pre-paid premiums.
    

10


As of September 30, 2015, premiums paid in 2012 related to oil and natural gas derivatives to be settled beyond September 30, 2015 were as follows:
 
 
Year
Thousands of dollars
 
2015
 
2016
 
2017
Oil
 
$
1,180

 
$
7,438

 
$
734

Natural gas
 
$
501

 
$
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 September 30, 2015. 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)
 
$
374,031

 
$
410,000

Average Fixed Rate
 
1.64
%
 
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 September 30, 2015
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
Current assets - derivative instruments
 
$
358,741

 
$
44,281

 
$

 
$
(2,165
)
 
$
400,857

Other long-term assets - derivative instruments
 
240,177

 
30,886

 

 
(3,382
)
 
267,681

Total assets
 
598,918

 
75,167

 

 
(5,547
)
 
668,538

Liabilities
 
 
 
 
 
 
 
 
 
 
Current liabilities - derivative instruments
 
(40
)
 
(2,214
)
 
(5,200
)
 
2,165

 
(5,289
)
Long-term liabilities - derivative instruments
 
(43
)
 
(3,748
)
 
(1,012
)
 
3,382

 
(1,421
)
Total liabilities
 
(83
)
 
(5,962
)
 
(6,212
)
 
5,547

 
(6,710
)
Net assets (liabilities)
 
$
598,835

 
$
69,205

 
$
(6,212
)
 
$

 
$
661,828

 
 
 
 
 
 
 
 
 
 
 
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.

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


11


Thousands of dollars
 
Oil Commodity
Derivatives (a)
 
Natural Gas
Commodity Derivatives (a)
 
Interest Rate Derivatives (b)
 
Total Financial Instruments
Three Months Ended September 30, 2015
 
 
 
 
 
 
 
 
Net gain (loss)
 
$
234,158

 
$
18,854

 
$
(996
)
 
$
252,016

Three Months Ended September 30, 2014
 
 
 
 
 
 
 
 
Net gain
 
$
133,666

 
$
12,505

 
$

 
$
146,171

 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2015
 
 
 
 
 
 
 
 
Net gain (loss)
 
$
261,360

 
$
35,412

 
$
(3,411
)
 
$
293,361

Nine Months Ended September 30, 2014
 
 
 
 
 
 
 
 
Net loss
 
$
(15,553
)
 
$
(5,504
)
 
$

 
$
(21,057
)

(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 September 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 nine months ended September 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.

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.


12


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 September 30, 2015
 
 
 
 
 
 
 
 
Assets (liabilities)
 
 
 
 
 
 
 
 
Crude Oil
 
 
 
 
 
 
 
 
Crude oil swaps
 
$

 
$
548,524

 
$

 
$
548,524

Crude oil collars
 

 

 
33,477

 
33,477

Crude oil puts
 

 

 
16,835

 
16,835

Natural Gas
 
 
 
 
 
 
 
 
Natural gas swaps
 

 
55,075

 

 
55,075

Natural gas collars
 

 

 
4,490

 
4,490

Natural gas puts
 

 

 
9,639

 
9,639

Interest rate swaps
 
 
 
 
 
 
 
 
Interest rate swaps
 

 
(6,212
)
 

 
(6,212
)
Available-for-sale securities
 
 
 
 
 
 
 
 
Equities
 
2,419

 

 

 
2,419

Mutual funds
 
11,304

 

 

 
11,304

Exchange traded funds
 
4,805

 

 

 
4,805

Net assets
 
$
18,528

 
$
597,387

 
$
64,441

 
$
680,356

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 September 30,
 
 
2015
 
2014
Thousands of dollars
 
Oil
 
Natural Gas
 
Oil
 
Natural Gas
Assets (a):
 
 
 
 
 
 
 
 
Beginning balance
 
$
41,001

 
$
15,010

 
$
1,540

 
$
840

Derivative instrument settlements (b)
 
11,903

 
4,050

 

 
347

(Loss) gain (b)(c)
 
(2,592
)
 
(4,931
)
 
5,529

 
(222
)
Ending balance
 
$
50,312

 
$
14,129

 
$
7,069

 
$
965

 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 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)
 
31,454

 
11,854

 

 
389

Loss (b)(c)
 
(42,552
)
 
(17,617
)
 
(1,888
)
 
(1,272
)
Ending balance
 
$
50,312

 
$
14,129

 
$
7,069

 
$
965


(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 September 30, 2015, the significant unobservable inputs used in the fair value measurements were as follows:

 
 
Fair Value at
 
Valuation
 
 
 
 
Thousands of dollars
 
September 30, 2015
 
Technique
 
Unobservable Input
 
Range
Oil Options
 
$
50,312

 
Option Pricing Model
 
Oil forward commodity prices
 
$45.09/Bbl - $56.04/Bbl
 
 
 
 
 
 
Oil volatility
 
27.94% - 44.82%
 
 
 
 
 
 
Own credit risk
 
5%
Natural Gas Options
 
14,129

 
Option Pricing Model
 
Gas forward commodity prices
 
$2.52/MMBtu - $3.29/MMBtu
 
 
 
 
 
 
Gas volatility
 
22.58% - 58.91%
 
 
 
 
 
 
Own credit risk
 
5%
Total
 
$
64,441

 
 
 
 
 
 

    

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 September 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., Morgan Stanley Capital Group 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 September 30, 2015, each of these financial institutions had an investment grade credit rating.  As of September 30, 2015, our largest derivative asset balances were with Wells Fargo Bank, N.A., Credit Suisse Energy LLC, JP Morgan Chase Bank N.A. and Barclays Bank PLC, which accounted for approximately 19%, 11%, 11% and 11% 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 nine months ended September 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.


16


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 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 September 30, 2015 and December 31, 2014, we had a current receivable of $1.6 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 September 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 $2.3 million and $3.8 million, respectively. For the nine months ended September 30, 2015 and 2014, the monthly charges to PCEC for indirect expenses totaled $6.3 million in each period, and charges for direct expenses including payroll and administrative costs totaled $7.3 million and $8.9 million, respectively. At September 30, 2015 and December 31, 2014, we had receivables of $0.5 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 10%.  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.

        Non-cash impairments of proved properties totaled $1.4 billion and $1.5 billion for the three months and nine months ended September 30, 2015, respectively. For the three months ended September 30, 2015, we had non-cash impairments of $605.4 million in Michigan, $420.2 million in Florida, $262.1 million in Ark-La-Tex, $73.1 million in California, $49.7 million for our Permian properties, $17.4 million in the Rockies and $12.2 million for our Mid-Continent properties, primarily related to the impact of the drop in commodity strip prices on our projected future net revenues. For the nine months ended September 30, 2015, we had non-cash impairments of $605.4 million in Michigan, $420.2 million in Florida, $262.1 million in Ark-La-Tex, $73.1 million in California, $82.8 million for our Permian properties, $34.1 million for our Rockies natural gas properties and $21.5 million for our Mid-Continent properties primarily due to the impact of the drop in commodity strip prices on our projected future net revenues during the third quarter and the impact of the decrease in oil and natural gas prices on certain of our low operating margin properties during the first quarter. Impairments totaled $29.4 million for the three months and nine months ended September 30, 2014, including $19.9 million in Florida, $6.5 million in Michigan and $3.0 million in the Rockies. The carrying values of the properties were reduced to their estimated fair values

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using level 3 inputs. Additional impairments may be recognized in the fourth quarter of 2015 should commodity prices decline further.
       
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.

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.


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6. Other Assets

As of September 30, 2015, and December 31, 2014, our other long-term assets were $119.7 million and $157.0 million, respectively, consisting of the following:
 
 
As of
Thousands of dollars
 
September 30, 2015
 
December 31, 2014
Debt issuance costs
 
$
62,341

 
$
52,787

Available-for-sale securities
 
18,528

 
19,345

Deposit for Jay Field net profit interest obligation
 
18,263

 
18,263

Property reclamation deposit
 
10,735

 
10,735

CO2 supply advances and deposits
 

 
50,792

Other
 
9,848

 
5,120

Total
 
$
119,715

 
$
157,042

    
The $62.3 million of debt issuance costs at September 30, 2015 included $21.6 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 September 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.

At September 30, 2015 and December 31, 2014, we had 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 nine months ended September 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.


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

 
 
As of
Thousands of dollars
 
September 30, 2015
 
December 31, 2014
Credit facility
 
$
1,253,000

 
$
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
 
(16,534
)
 
1,560

Total debt
 
3,044,466

 
3,352,160

Less: current portion of long-term debt
 
(603
)
 
(105,000
)
Total long-term debt
 
$
3,043,863

 
$
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 September 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 September 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 September 30, 2015 and December 31, 2014, we had $1.25 billion and $2.19 billion, respectively, in indebtedness outstanding under our credit facility. At September 30, 2015, the 1-month LIBOR interest rate plus an applicable spread was 2.4511% 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 September 30, 2015 and December 31, 2014, we had $23.6 million and $33.5 million, respectively, of unamortized debt issuance costs related to our credit facility. During the three and nine months ended September 30, 2015, we had a write-off of zero and $10.6 million, respectively, 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 September 30, 2015 and December 31, 2014, we were in compliance with our credit facility’s covenants.

Although we currently expect our sources of capital to be sufficient to meet our near-term liquidity needs, there can be no assurance that the lenders under our credit facility will not reduce the borrowing base to an amount below our outstanding borrowings or that our liquidity requirements will continue to be satisfied, given current oil prices and the discretion of our lenders to decrease our borrowing base. Due to the steep decline in commodity prices, we may not be able to obtain funding

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in the equity or capital markets on terms we find acceptable. The cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, and reduced and, in some cases, ceased to provide any new funding. If the borrowing base determination in April 2016 results in a borrowing base deficiency and we cannot access the capital markets and repay debt under our credit facility, we may be unable to continue to pay distributions to our unitholders and may take other actions to reduce costs and to raise funds to repay debt, such as selling assets or monetizing derivative contracts.

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 September 30, 2015, our Senior Secured Notes had a carrying value of $631.9 million, net of unamortized discount of $18.1 million.

As of September 30, 2015, the fair value of our Senior Secured Notes was estimated to be approximately $612 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 September 30, 2015 and December 31, 2014, we had $21.6 million and zero, respectively, of unamortized debt issuance costs related to our Senior Secured Notes.

Senior Unsecured Notes

As of September 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 $301.9 million, net of unamortized discount of $3.1 million. In addition, as of September 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 $854.6 million, net of unamortized premium of $4.6 million. Interest on the 2020 Senior Notes and the 2022 Senior Notes is payable twice a year in April and October.

At September 30, 2015 and December 31, 2014, we had $17.1 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 September 30, 2015, the fair value of our 2020 Senior Notes and 2022 Senior Notes were estimated to be approximately $138 million and $302 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 September 30, 2015 and December 31, 2014, we were in compliance with the covenants under our Senior Unsecured Notes.

















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Interest Expense

Our interest expense is detailed as follows:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
Thousands of dollars
 
2015
 
2014
 
2015