Attached files

file filename
EX-10.2 - EXHIBIT - Breitburn Energy Partners LPq3201410-qex102.htm
EX-10.1 - EXHIBIT - Breitburn Energy Partners LPq3201410-qex101.htm
EX-10.3 - EXHIBIT - Breitburn Energy Partners LPq3201410-qex103.htm
EXCEL - IDEA: XBRL DOCUMENT - Breitburn Energy Partners LPFinancial_Report.xls
EX-31.2 - EXHIBIT - Breitburn Energy Partners LPq3201410-qex312.htm
EX-31.1 - EXHIBIT - Breitburn Energy Partners LPq3201410-qex311.htm
EX-32.2 - EXHIBIT - Breitburn Energy Partners LPq3201410-qex322.htm
EX-32.1 - EXHIBIT - Breitburn Energy Partners LPq3201410-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, 2014
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, 2014, the registrant had 138,773,366 Common Units outstanding.

 
 
 
 
 
 



INDEX

 
 
Page No.
 
 
 
 
 
PART I
 
 
FINANCIAL INFORMATION
 
 
 
 
 
 
 

 
 
– Notes to Consolidated Financial Statements
 
 
 
 
PART II
 
 
OTHER INFORMATION
 
 
 
 
 
 
 
 
Exhibit Index
 
 



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 is the ability to obtain unitholder approval of the proposed merger with QR Energy, LP (“QR Energy”); the ability to complete the proposed merger with QR Energy on anticipated terms and timetable; our ability to successfully integrate the business and operations of QR Energy with our own after the transaction and achieve anticipated benefits from the proposed merger; the possibility that various closing conditions for the merger may not be satisfied or waived; risks relating to any unforeseen liabilities of QR Energy; changes in crude oil, natural gas liquids (“NGL”) and natural gas prices; 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; 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, 2013 (our “2013 Annual Report”), in Part II—Item 1A of our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2014 and June 30, 2014 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,
2014
 
December 31,
2013
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash
 
$
3,227

 
$
2,458

Accounts and other receivables, net
 
98,360

 
96,862

Derivative instruments (note 3)
 
44,256

 
7,914

Related party receivables (note 4)
 
1,509

 
2,604

Inventory (note 5)
 
4,418

 
3,890

Prepaid expenses
 
3,831

 
3,334

Total current assets
 
155,601

 
117,062

Equity investments
 
6,551

 
6,641

Property, plant and equipment
 
 
 
 
Oil and natural gas properties
 
5,102,392

 
4,818,639

Non-oil and natural gas assets
 
36,138

 
21,338

 
 
5,138,530

 
4,839,977

Accumulated depletion and depreciation (note 6)
 
(1,148,185
)
 
(924,601
)
Net property, plant and equipment
 
3,990,345

 
3,915,376

Other long-term assets
 
 
 
 
Intangibles (note 7)
 
9,286

 
11,679

Derivative instruments (note 3)
 
25,863

 
71,319

Other long-term assets (note 7)
 
76,008

 
74,205

Total assets
 
$
4,263,654

 
$
4,196,282

LIABILITIES AND EQUITY
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable
 
$
64,199

 
$
69,809

Derivative instruments (note 3)
 
7

 
24,876

Distributions payable
 
733

 

Revenue and royalties payable
 
32,401

 
26,233

Wages and salaries payable
 
12,173

 
15,359

Accrued interest payable
 
42,856

 
19,690

Accrued liabilities
 
32,604

 
26,922

Total current liabilities
 
184,973

 
182,889

Credit facility (note 8)
 
719,000

 
733,000

Senior notes, net (note 8)
 
1,156,589

 
1,156,675

Deferred income taxes (note 10)
 
2,902

 
2,749

Asset retirement obligation (note 11)
 
133,216

 
123,769

Derivative instruments (note 3)
 
5,145

 
2,560

Other long-term liabilities
 
5,530

 
4,820

Total liabilities
 
2,207,355

 
2,206,462

Commitments and contingencies (note 12)
 


 


Equity
 
 
 
 
Series A cumulative redeemable preferred units, 8.0 million units issued and outstanding at September 30, 2014 and 0 at December 31, 2013 (note 13)
 
193,215

 

Common units, 120.5 million units issued and outstanding at September 30, 2014 and 119.2 million at December 31, 2013 (note 13)
 
1,863,084

 
1,989,820

Total equity
 
2,056,299

 
1,989,820

 
 
 
 
 
Total liabilities and equity
 
$
4,263,654

 
$
4,196,282


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
 
2014

2013
 
2014
 
2013
Revenues and other income items
 
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquid sales
 
$
216,146

 
$
197,413

 
$
658,753

 
$
467,061

Gain (loss) on commodity derivative instruments, net (note 3)
 
146,171

 
(54,765
)
 
(21,057
)
 
(11,948
)
Other revenue, net
 
1,585

 
737

 
4,240

 
2,197

    Total revenues and other income items
 
363,902

 
143,385

 
641,936

 
457,310

Operating costs and expenses
 
 
 
 
 
 
 
 
Operating costs
 
82,904

 
68,502

 
248,161

 
181,889

Depletion, depreciation and amortization
 
72,671

 
59,764

 
204,417

 
154,095

Impairments (note 6)
 
29,434

 
361

 
29,434

 
361

General and administrative expenses
 
18,737

 
16,116

 
53,886

 
44,695

Loss (gain) on sale of assets
 
(63
)
 
77

 
357

 
139

Total operating costs and expenses
 
203,683

 
144,820

 
536,255

 
381,179

 
 
 
 
 
 
 
 
 
Operating income (loss)
 
160,219

 
(1,435
)
 
105,681

 
76,131

 
 
 
 
 
 
 
 
 
Interest expense, net of capitalized interest
 
29,494

 
23,548

 
90,360

 
60,387

Other expense (income), net
 
(450
)
 
4

 
(1,223
)
 
(5
)
 
 
 
 
 
 
 
 
 
Income (loss) before taxes
 
131,175

 
(24,987
)
 
16,544

 
15,749

 
 
 
 
 
 
 
 
 
Income tax expense (note 10)
 
532

 
24

 
384

 
628

 
 
 
 
 
 
 
 
 
Net income (loss)
 
130,643

 
(25,011
)
 
16,160

 
15,121

 
 
 
 
 
 
 
 
 
Less: distributions to preferred unitholders
 
4,125

 

 
5,958

 

 
 
 
 
 
 
 
 
 
Net income (loss) attributable to common unitholders
 
$
126,518

 
$
(25,011
)
 
$
10,202

 
$
15,121

 
 
 
 
 
 
 
 
 
Basic net income (loss) per unit (note 13)
 
$
1.03

 
$
(0.25
)
 
$
0.08

 
$
0.15

Diluted net income (loss) per unit (note 13)
 
$
1.03

 
$
(0.25
)
 
$
0.08

 
$
0.15


See accompanying notes to consolidated financial statements.


3


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

 
 
Nine Months Ended
 
 
September 30,
Thousands of dollars
 
2014
 
2013
Cash flows from operating activities
 
 
 
 
Net income
 
$
16,160

 
$
15,121

Adjustments to reconcile to cash flows from operating activities:
 
 
 
 
Depletion, depreciation and amortization
 
204,417

 
154,095

Impairments
 
29,434

 
361

Unit-based compensation expense
 
18,440

 
14,700

Loss on derivative instruments
 
21,057

 
11,948

Derivative instrument settlement receipts (payments)
 
(34,228
)
 
3,633

Income from equity affiliates, net
 
90

 
(122
)
Deferred income taxes
 
153

 
252

Loss on sale of assets
 
357

 
139

Other
 
5,172

 
3,989

Changes in net assets and liabilities
 
 
 
 
Accounts receivable and other assets
 
(3,345
)
 
(62,882
)
Inventory
 
(528
)
 
(8,032
)
Net change in related party receivables and payables
 
1,095

 
883

Accounts payable and other liabilities
 
36,642

 
32,857

Net cash provided by operating activities
 
294,916

 
166,942

Cash flows from investing activities
 
 
 
 
Property acquisitions
 
(6,422
)
 
(861,601
)
Capital expenditures
 
(293,275
)
 
(191,472
)
Proceeds from sale of assets
 
366

 
226

Other
 
(9,242
)
 

Net cash used in investing activities
 
(308,573
)
 
(1,052,847
)
Cash flows from financing activities
 
 
 
 
Proceeds from issuance of preferred units, net
 
193,215

 

Proceeds from issuance of common units, net
 
25,917

 
285,011

Distributions to preferred unitholders
 
(5,225
)
 

Distributions to common unitholders
 
(181,430
)
 
(137,447
)
Proceeds from long-term debt
 
693,000

 
1,381,000

Repayments of long-term debt
 
(707,000
)
 
(636,000
)
Change in bank overdraft
 
(2,417
)
 
(316
)
Debt issuance costs
 
(1,634
)
 
(8,032
)
Net cash provided by financing activities
 
14,426

 
884,216

Increase (decrease) in cash
 
769

 
(1,689
)
Cash beginning of period
 
2,458

 
4,507

Cash end of period
 
$
3,227

 
$
2,818


See accompanying notes to consolidated financial statements.

4


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 2013 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, 2014, our operating results for the three months and nine months ended September 30, 2014 and 2013 and our cash flows for the nine months ended September 30, 2014 and 2013 have been included.  Operating results for the three months and nine months ended September 30, 2014 are not necessarily indicative of the results that may be expected for the year ended December 31, 2014.  The consolidated balance sheet at December 31, 2013 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 2013 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.

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers. The ASU 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. The pronouncement is effective for annual and interim reporting periods beginning after December 15, 2016, and is to be applied retrospectively, with early application not permitted. We are evaluating the impact, if any, that ASU 2014-09 will have 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 proved 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

5


abandonment. These inputs require significant judgments and estimates by management at the time of the valuation and are subject to change.

Pending Merger with QR Energy

On July 23, 2014, we, Breitburn GP LLC (our “General Partner”) and Boom Merger Sub, LLC, a direct wholly owned subsidiary of the Partnership (“Merger Sub”), entered into an Agreement and Plan of Merger (the “Merger Agreement”) with QR Energy and QRE GP, LLC. Pursuant to the Merger Agreement, we will acquire QR Energy in exchange for common units representing limited partner interests in Breitburn Energy Partners LP (“Breitburn” or the “Partnership”) (“Common Units”), including the assumption of approximately $1.01 billion of QR Energy’s existing net debt and the payment of $350 million in cash to the holders of the outstanding Class C Convertible Preferred Units of QR Energy (each, a “Class C Unit”). The Merger Agreement provides that, upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will be merged with and into QR Energy, with QR Energy continuing as the surviving entity and a direct wholly owned subsidiary of the Partnership (the “Merger”).

Under the terms of the Merger Agreement, each outstanding common unit representing a limited partner interest in QR Energy (a “QR Energy Common Unit”) and each Class B Unit representing a limited partner interest in QR Energy (a “Class B Unit”) will be converted into the right to receive 0.9856 newly issued Common Units (the “Merger Consideration”). A number of Class B Units issuable upon a change of control of QR Energy equal to (i) 6,748,067, minus (ii) the excess of (A) the number of performance units that vest and are settled in QR Energy Common Units in connection with the Merger over (B) 383,900 will be issued and treated as outstanding Class B Units and converted into the right to receive the Merger Consideration. Each outstanding Class C Unit of QR Energy will be converted into the right to receive cash in an amount equal to $350 million divided by the number of Class C Units outstanding immediately prior to the effective time of the Merger. In no event will we be obligated to issue in excess of 72,001,686 Common Units as part of the Merger Consideration.
On July 23, 2014, we also entered into a Registration Rights Agreement (“Registration Rights Agreement”) with each of QR Energy 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 (the “QR Energy Unitholders”). Under the Registration Rights Agreement, we are required to file or cause to be filed with the Securities and Exchange Commission (the “SEC”) a registration statement with respect to the public resale of our Common Units issued to the QR Energy Unitholders as part of the Merger Consideration. We are required to file or cause to be filed the registration statement within 90 days following the closing under the Merger Agreement and are required to cause the registration statement to become effective as soon as reasonably practicable thereafter but in no event later than 120 days after the closing under the Merger Agreement.

The completion of the Merger is subject to satisfaction or waiver of customary closing conditions, including (1) the adoption of the Merger Agreement by holders of a majority of the outstanding QR Energy Common Units, Class B Units and Class C Units, voting as a single class, (2) the approval for listing of the Common Units issued as a part of the Merger Consideration on the NASDAQ Global Select Market (the “NASDAQ”), and (3) other customary conditions. On August 19, 2014, we received notification of early termination of the waiting period under the Hart-Scott-Rodino Act for the Merger.
A special meeting of QR Energy unitholders to vote on the adoption of the Merger Agreement is scheduled to be held on November 18, 2014. The Merger Agreement requires that the Merger close within three business days of the meeting of QR Energy unitholders.
Merger-related costs for the QR Energy Merger of $1.5 million for the three months and nine months ended September 30, 2014, were included in general and administrative (“G&A”) expenses on the consolidated statements of operations.

2013 Acquisitions

Oklahoma Panhandle Acquisitions

On July 15, 2013, we completed the acquisition of certain oil and natural gas and midstream assets located in Oklahoma, New Mexico and Texas, certain CO2 supply contracts, certain crude oil swaps and interests in certain entities from Whiting Oil and Gas Corporation (“Whiting”) for approximately $845 million in cash (the “Whiting Acquisition”), including post-closing adjustments.


6


The purchase price for this acquisition was allocated to the assets acquired and liabilities assumed as follows:

Thousands of dollars
 
 
Oil and natural gas properties - proved
 
$
700,963

Oil and natural gas properties - unproved
 
43,492

Pipeline and processing facilities
 
74,537

Derivative assets - current
 
15

Intangibles
 
14,739

Derivative assets - long-term
 
16,183

Other long-term assets
 
10,936

Derivative liabilities - current
 
(6,347
)
Accrued liabilities
 
(1,115
)
Asset retirement obligations
 
(8,102
)
 
 
$
845,301


Whiting novated to us derivative contracts, with a counterparty that is a participant in our current credit facility, consisting of NYMEX West Texas Intermediate (“WTI”) fixed price crude oil swaps covering a total of approximately 5.4 million barrels of future production in 2013 through 2016 at a weighted average hedge price of $95.44 per Bbl, which were valued as a net asset of $9.9 million at the acquisition date. The purchase price allocation also included finite-lived intangibles valued at $14.7 million relating to two CO2 purchase contracts that we received in the acquisition.  We amortize the CO2 contracts based on the amount of CO2 purchases made in each period over the contracts’ respective lives.
During the three months and nine months ended September 30, 2014, we recorded $1.0 million and $3.0 million, respectively, in amortization for these contracts. We were also novated a $10.9 million long-term advance relating to future CO2 supply contract arrangements.

We also completed the acquisition of additional interests in certain of the acquired assets in the Oklahoma Panhandle from other sellers for an additional $30 million in July 2013, subject to customary post-closing adjustments (together with the Whiting Acquisition, the “Oklahoma Panhandle Acquisitions”). The additional interests were allocated $17.8 million to oil and natural gas properties and $12.4 million to pipeline facilities.

We used borrowings under our credit facility to fund the Oklahoma Panhandle Acquisitions.

Acquisition-related costs for the Oklahoma Panhandle Acquisitions of $3.3 million ($3.2 million recorded in 2013), were included in G&A expenses on the consolidated statements of operations. During the three months and nine months ended September 30, 2014, we recorded approximately $50.4 million and $159.9 million, respectively, in revenue and approximately $15.7 million and $48.2 million, respectively, in lease operating expenses, including production and property taxes, from our Oklahoma Panhandle Acquisitions.

Permian Basin Acquisitions

On December 30, 2013, we completed acquisitions of oil and natural gas properties located in the Permian Basin in Texas from CrownRock, L.P. for approximately $282 million in cash (the “CrownRock III Acquisition”). We also completed the acquisition of additional interests in certain of the acquired assets in the Permian Basin from other sellers for an additional $20 million in December 2013 (together with the CrownRock III Acquisition, the “Permian Basin Acquisitions”).

The purchase price for the Permian Basin Acquisitions was allocated to the assets acquired and liabilities assumed as follows:
Thousands of dollars
 
 
Oil and natural gas properties - proved
 
$
258,728

Oil and natural gas properties - unproved
 
44,451

Asset retirement obligation
 
(1,069
)
 
 
$
302,110



7


During the three months and nine months ended September 30, 2014, we recorded acquisition-related costs for the Permian Basin Acquisitions of $0.1 million and $0.6 million, respectively, which were included in G&A expenses on the consolidated statements of operations. During the three months and nine months ended September 30, 2014, we recorded approximately $17.1 million and $48.6 million, respectively, in sales revenue and approximately $4.1 million and $11.0 million, respectively, in lease operating expenses, including production and property taxes, from the Permian Basin Acquisitions.

Pro Forma

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, 2013, assuming the Oklahoma Panhandle Acquisitions and the Permian Basin Acquisitions had been completed on January 1, 2013. The pro forma results reflect the results of combining our statements of operations with the results of operations from all of our 2013 acquisitions, adjusted 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 acquisitions, 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 acquisitions.  The pro forma financial information is not necessarily indicative of the results of operations if these acquisitions had been effective January 1, 2013.
 
 
2013 Pro Forma
 
 
Three Months Ended
 
Nine Months Ended
Thousands of dollars, except per unit amounts
 
September 30, 2013
 
September 30, 2013
Revenues
 
$
174,550

 
$
631,809

Net income
 
(11,392
)
 
77,694

 
 
 
 
 
Net income per common unit:
 
  
 
 
Basic
 
$
(0.11
)
 
$
0.78

Diluted
 
$
(0.11
)
 
$
0.78


3.  Financial Instruments
 
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. 


8


We had the following commodity derivative contracts in place at September 30, 2014:

 
Year

2014

2015

2016

2017

2018
Oil Positions:
 
 
 
 
 
 
 
 
 
Fixed Price Swaps - NYMEX WTI
 
 
 
 
 
 
 
 
 
 Hedged Volume (Bbl/d)
14,811

 
13,059

 
9,211

 
7,971

 
493

Average Price ($/Bbl)
$
92.59

 
$
93.05

 
$
86.73

 
$
84.23

 
$
82.20

Fixed Price Swaps - ICE Brent
 
 
 
 
 
 
 
 
 
 Hedged Volume (Bbl/d)
4,950

 
3,374

 
4,300

 
298

 

Average Price ($/Bbl)
$
98.89

 
$
97.89

 
$
95.17

 
$
97.50

 
$

Collars - NYMEX WTI
 
 
 
 
 
 
 
 
 
Hedged Volume (Bbl/d)
1,000

 
1,000

 

 

 

Average Floor Price ($/Bbl)
$
90.00

 
$
90.00

 
$

 
$

 
$

Average Ceiling Price ($/Bbl)
$
112.00

 
$
113.50

 
$

 
$

 
$

Collars - ICE Brent
 
 
 
 
 
 
 
 
 
Hedged Volume (Bbl/d)

 
500

 
500

 

 

Average Floor Price ($/Bbl)
$

 
$
90.00

 
$
90.00

 
$

 
$

Average Ceiling Price ($/Bbl)
$

 
$
109.50

 
$
101.25

 
$

 
$

Puts - NYMEX WTI
 
 
 
 
 
 
 
 
 
Hedged Volume (Bbl/d)
500

 
500

 
1,000

 

 

Average Price ($/Bbl)
$
90.00

 
$
90.00

 
$
90.00

 
$

 
$

Total:
 
 
 
 
 
 
 
 
 
Hedged Volume (Bbl/d)
21,261

 
18,433

 
15,011

 
8,269

 
493

Average Price ($/Bbl)
$
93.87

 
$
93.61

 
$
89.48

 
$
84.71

 
$
82.20

 
 
 
 
 
 
 
 
 
 
Natural Gas Positions:
 
 
 
 
 
 
 
 
 
Fixed Price Swaps - MichCon City-Gate
 
 
 
 
 
 
 
 
 
Hedged Volume (MMBtu/d)
7,500

 
7,500

 
17,000

 
10,000

 

Average Price ($/MMBtu)
$
6.00

 
$
6.00

 
$
4.46

 
$
4.48

 
$

Fixed Price Swaps - Henry Hub
 
 
 
 
 
 
 
 
 
Hedged Volume (MMBtu/d)
41,600

 
47,700

 
24,700

 
8,571

 
1,870

Average Price ($/MMBtu)
$
4.75

 
$
4.77

 
$
4.23

 
$
4.39

 
$
4.15

Puts - Henry Hub
 
 
 
 
 
 
 
 
 
Hedged Volume (MMBtu/d)
6,000

 
1,500

 

 

 

Average Price ($/MMBtu)
$
5.00

 
$
5.00

 
$

 
$

 
$

Total:
 
 
 
 
 
 
 
 
 
Hedged Volume (MMBtu/d)
55,100

 
56,700

 
41,700

 
18,571

 
1,870

Average Price ($/MMBtu)
$
4.95

 
$
4.94

 
$
4.32

 
$
4.44

 
$
4.15

 
 
 
 
 
 
 
 
 
 
 Calls - Henry Hub
 
 
 
 
 
 
 
 
 
Hedged Volume (MMBtu/d)
15,000

 

 

 

 

Average Price ($/MMBtu)
$
9.00

 
$

 
$

 
$

 
$

Deferred Premium ($/MMBtu)
$
0.12

 
$

 
$

 
$

 
$


During the three months and nine months ended September 30, 2014 and 2013, we did not enter into any derivative instruments that required pre-paid premiums.
    
As of September 30, 2014, premiums paid in 2012 related to oil and natural gas derivatives to be settled in the fourth quarter of 2014 and beyond were as follows:
 
 
Year
Thousands of dollars
 
2014
 
2015
 
2016
 
2017
 
2018
Oil
 
$
1,129

 
$
4,683

 
$
7,438

 
$
734

 
$

Natural gas
 
$
1,012

 
$
1,989

 
$
952

 
$

 
$



9


Fair Value of Financial Instruments
 
The following table presents the fair value of our derivative instruments, none of which are designated as hedging instruments:
Balance sheet location, thousands of dollars
 
Oil Commodity Derivatives
 
Natural Gas
Commodity Derivatives
 
Commodity Derivatives Netting (a)
 
Total Financial Instruments
 
 
 
 
 
 
 
 
 
As of September 30, 2014
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
Current assets - derivative instruments
 
$
30,334

 
$
18,529

 
$
(4,607
)
 
$
44,256

Other long-term assets - derivative instruments
 
22,656

 
10,362

 
(7,155
)
 
25,863

Total assets
 
52,990

 
28,891

 
(11,762
)
 
70,119

 
 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
 
Current liabilities - derivative instruments
 
(4,304
)
 
(310
)
 
4,607

 
(7
)
Long-term liabilities - derivative instruments
 
(11,964
)
 
(336
)
 
7,155

 
(5,145
)
Total liabilities
 
(16,268
)
 
(646
)
 
11,762

 
(5,152
)
 
 
 
 
 
 
 
 
 
Net assets
 
$
36,722

 
$
28,245

 
$

 
$
64,967

 
 
 
 
 
 
 
 
 
As of December 31, 2013
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
Current assets - derivative instruments
 
$
4,373

 
$
15,419

 
$
(11,878
)
 
$
7,914

Other long-term assets - derivative instruments
 
59,412

 
23,750

 
(11,843
)
 
71,319

Total assets
 
63,785

 
39,169

 
(23,721
)
 
79,233

 
 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
 
Current liabilities - derivative instruments
 
(35,634
)
 
(1,120
)
 
11,878

 
(24,876
)
Long-term liabilities - derivative instruments
 
(13,620
)
 
(783
)
 
11,843

 
(2,560
)
Total liabilities
 
(49,254
)
 
(1,903
)
 
23,721

 
(27,436
)
 
 
 
 
 
 
 
 
 
Net assets
 
$
14,531

 
$
37,266

 
$

 
$
51,797


(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 balance sheet.


10


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)
 
Total Financial Instruments
Three Months Ended September 30, 2014
 
 
 
 
 
 
Net gain
 
$
133,666

 
$
12,505

 
$
146,171

Three Months Ended September 30, 2013
 
 
 
 
 
 
Net gain (loss)
 
$
(62,770
)
 
$
8,005

 
$
(54,765
)
Nine Months Ended September 30, 2014
 
 
 
 
 
 
Net loss
 
$
(15,553
)
 
$
(5,504
)
 
$
(21,057
)
Nine Months Ended September 30, 2013
 
 
 
 
 
 
Net gain (loss)
 
$
(22,072
)
 
$
10,124

 
$
(11,948
)

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

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, 2014, and December 31, 2013, 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, 2014 and 2013. Our policy is to recognize transfers between levels as of the end of the period.
 
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.  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 commodity derivative instruments is a standard option pricing model.  Inputs to the option pricing model include fixed monthly commodity strike prices and volumes from each specific contract, commodity prices from commodity forward price curves, volatility, interest rate factors and time to expiry.  Model inputs are obtained from our counterparties and third-party data providers and are verified against published data when available (e.g., NYMEX).  Additional inputs to our Level 3 derivative instruments include option volatility, forward commodity prices and risk-free interest rates for present value discounting.  We use the standard swap contract valuation method to value our interest rate derivative instruments, and inputs include LIBOR forward interest rates, 1-month LIBOR rates and risk-free interest rates for present value discounting.


11


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

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. Financial assets and liabilities carried at fair value on a recurring basis are presented in the following table:  

Thousands of dollars
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
 
 
 
 
 
 
 
As of September 30, 2014
 
 
 
 
 
 
 
 
Assets (liabilities)
 
 
 
 
 
 
 
 
Crude Oil
 
 
 
 
 
 
 
 
Crude oil swaps
 
$

 
$
29,653

 
$

 
$
29,653

Crude oil collars
 

 

 
2,407

 
2,407

Crude oil puts
 

 

 
4,662

 
4,662

Natural Gas
 
 
 
 
 
 
 
 
Natural gas swaps
 

 
27,280

 

 
27,280

Natural gas calls
 

 

 
(157
)
 
(157
)
Natural gas puts
 

 

 
1,122

 
1,122

Net assets
 
$

 
$
56,933

 
$
8,034

 
$
64,967

 
 
 
 
 
 
 
 
 
As of December 31, 2013
 
 
 
 
 
 
 
 
Assets (liabilities)
 
 
 
 
 
 
 
 
Crude Oil
 
 
 
 
 
 
 
 
Crude oil swaps
 
$

 
$
5,573

 
$

 
$
5,573

Crude oil collars
 

 

 
2,683

 
2,683

Crude oil puts
 

 

 
6,275

 
6,275

Natural Gas
 
 
 
 
 
 
 
 
Natural gas swaps
 

 
35,419

 

 
35,419

Natural gas calls
 

 

 
(650
)
 
(650
)
Natural gas puts
 

 

 
2,497

 
2,497

Net assets
 
$

 
$
40,992

 
$
10,805

 
$
51,797



12


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

 
 
Three Months Ended September 30,
 
 
2014
 
2013
Thousands of dollars
 
Oil
 
Natural Gas
 
Oil
 
Natural Gas
Assets (a):
 
 
 
 
 
 
 
 
Beginning balance
 
$
1,540

 
$
840

 
$
15,412

 
$
2,054

Derivative instrument settlements (b)
 

 
347

 
(125
)
 
(225
)
Gain (loss) (b)(c)
 
5,529

 
(222
)
 
(4,744
)
 
528

Ending balance
 
$
7,069

 
$
965

 
$
10,543

 
$
2,357

 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30,
 
 
2014
 
2013
Thousands of dollars
 
Oil
 
Natural Gas
 
Oil
 
Natural Gas
Assets (a):
 
 
 
 
 
 
 
 
Beginning balance
 
$
8,957

 
$
1,848

 
$
15,169

 
$
1,672

Derivative instrument settlements (b)
 

 
389

 
(125
)
 
(667
)
Gain (loss) (b)(c)
 
(1,888
)
 
(1,272
)
 
(4,501
)
 
1,352

Ending balance
 
$
7,069

 
$
965

 
$
10,543

 
$
2,357


(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 gain (loss) on commodity derivative instruments, net on the consolidated statements of operations.
(c) Represents gain (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, 2014, the significant unobservable inputs used in the fair value measurements were as follows:

 
 
Fair Value at
 
Valuation
 
 
 
 
Thousands of dollars
 
September 30, 2014
 
Technique
 
Unobservable Input
 
Range
Oil Options
 
$
7,069

 
Option Pricing Model
 
Oil forward commodity prices
 
$85.32/Bbl - $97.48/Bbl
 
 
 
 
 
 
Oil volatility
 
14.98% - 20.70%
 
 
 
 
 
 
Own credit risk
 
5%
Natural Gas Options
 
965

 
Option Pricing Model
 
Gas forward commodity prices
 
$3.85/MMBtu - $4.25/MMBtu
 
 
 
 
 
 
Gas volatility
 
24.80% - 40.08%
 
 
 
 
 
 
Own credit risk
 
5%
Total
 
$
8,034

 
 
 
 
 
 

    

13


For Level 3 derivative instruments measured at fair value on a recurring basis as of December 31, 2013, the significant unobservable inputs used in the fair value measurements were as follows:

 
 
Fair Value at
 
Valuation
 
 
 
 
Thousands of dollars
 
December 31, 2013
 
Technique
 
Unobservable Input
 
Range
Oil Options
 
$
8,957

 
Option Pricing Model
 
Oil forward commodity prices
 
$81.95/Bbl - $105.14/Bbl
 
 
 
 
 
 
Oil volatility
 
15.51% - 17.59%
 
 
 
 
 
 
Own credit risk
 
5%
Natural Gas Options
 
1,848

 
Option Pricing Model
 
Gas forward commodity prices
 
$4.01/MMBtu - $4.41/MMBtu
 
 
 
 
 
 
Gas volatility
 
18.87% - 35.13%
 
 
 
 
 
 
Own credit risk
 
5%
Total
 
$
10,805

 
 
 
 
 
 

Credit and Counterparty Risk

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 September 30, 2014, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank, National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia, BNP Paribas, Royal Bank of Canada and Toronto-Dominion Bank.  We periodically obtain credit default swap information on our counterparties.  As of September 30, 2014, 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 September 30, 2014, our largest derivative asset balances were with Wells Fargo Bank, Credit Suisse Energy LLC and Citibank, which accounted for approximately 38%, 22% 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 the three months and nine months ended September 30, 2014, the monthly fee paid by PCEC for indirect expenses was $700,000. In August 2014, the expiration of the term for the current monthly fee of $700,000 was extended to June 30, 2015, and thereafter, the monthly fee will be redetermined biannually. 

At September 30, 2014 and December 31, 2013, we had current receivables of $1.3 million and $2.5 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, 2014 and 2013, the monthly charges to PCEC for indirect expenses totaled $2.1 million and $2.1 million, respectively, and charges for direct expenses including payroll and administrative costs totaled $3.8 million and $2.9 million, respectively. For the nine months ended September 30, 2014 and 2013, the monthly charges to PCEC for indirect expenses totaled $6.3 million and $6.3 million, respectively, and charges for direct expenses including payroll and administrative costs totaled $8.9 million and $7.3 million, respectively.

At September 30, 2014 and December 31, 2013, we had receivables of $0.2 million and $0.1 million, respectively, 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.    

14


5.  Inventory

Our crude oil inventory from our Florida operations was $4.4 million and $3.9 million at September 30, 2014 and December 31, 2013, respectively.  In the nine months ended September 30, 2014, we sold 514 gross MBbls and produced 522 gross MBbls of crude oil from our Florida operations.  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.  Crude oil inventory additions are valued at the lower of cost or market, with cost based on our actual production costs.  We match production expenses with crude oil sales.  Production expenses associated with unsold crude oil inventory are recorded to inventory.

6. Impairments

We assess our developed and undeveloped oil and natural gas properties and other long-lived assets for possible impairment periodically and whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. Such indicators include changes in business plans, changes in commodity prices and, for oil and natural gas properties, significant downward revisions of estimated proved reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its estimated fair value.

Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for market supply and demand conditions for oil and natural gas. For purposes of performing an impairment test, the undiscounted future cash flows are based on total proved and risk-adjusted probable and possible reserves and are forecast using five-year NYMEX forward strip prices at the end of the period and escalated along with expenses and capital starting year six and thereafter at 2.5% per year. For impairment charges, 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%. Additional inputs include oil and natural gas reserves, future operating and development costs and future commodity prices. 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.

Impairments of proved properties 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 Wyoming. The Florida impairments are due to reserve adjustments primarily related to well performance and lower crude oil prices. The Michigan impairments relate to the write-off of investments associated with expiring leases that we have elected not to renew. The Wyoming impairments are due to reserve adjustments related to a combination of well performance, lower commodity prices and higher expense projections. Impairments totaled $0.4 million for the three months and nine months ended September 30, 2013, including $0.2 million in Florida and $0.2 million in Michigan.

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 these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.

7. Other Assets

Intangible Assets

In connection with the Whiting Acquisition in July 2013, we acquired two CO2 purchase contracts, priced below market, which were valued at $14.7 million at the acquisition date. These contracts were recorded as finite-lived intangibles. We amortize intangible assets with finite lives over their estimated useful lives. We are amortizing these contracts based on the amount of CO2 purchases made in each period over the contracts’ respective lives. The contracts expire in December 2015 and September 2023, respectively. For the three months and nine months ended September 30, 2014, we recorded $1.0 million and $3.0 million respectively, in amortization expense related to these contracts. As of September 30, 2014, and December 31, 2013, we had a remaining unamortized value of $8.2 million and $11.2 million, respectively.

In connection with our compliance with the California Greenhouse Gas (“GHG”) Cap-and-Trade Regulation, as of September 30, 2014 and December 31, 2013, we had $1.1 million and $0.5 million, respectively, of GHG allowances,

15


purchased at auction.  We recognize the purchase of these allowances as intangibles until they are surrendered in compliance with regulations promulgated by the California Air Resources Board.
    
Other long-term assets
    
As of September 30, 2014, and December 31, 2013, our other long-term assets were $76.0 million and $74.2 million, respectively, including $31.3 million and $35.6 million, respectively, in debt issuance costs, $43.3 million and $36.6 million, respectively, in CO2 supply advances and deposits for our Oklahoma properties and $1.4 million and $2.0 million, respectively, in other long-term assets.

8.  Long-Term Debt

Credit Facility

As of September 30, 2014, Breitburn Operating LP (“BOLP”), our wholly-owned subsidiary, as borrower, and we and our wholly-owned subsidiaries, as guarantors, had a $3.0 billion revolving credit facility with Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and Issuing Lender, and a syndicate of banks (as amended, the “Second Amended and Restated Credit Agreement”).

On April 25, 2014, in connection with the regularly scheduled borrowing base redetermination, we entered into the Twelfth Amendment to the Second Amended and Restated Credit Agreement, which provides for an increased borrowing base of $1.6 billion with a total lender commitment of $1.4 billion and an extension of the term of the credit facility for one year until May 9, 2017.

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. The borrowing base is redetermined semi-annually. As of September 30, 2014, our borrowing base for our credit facility was $1.6 billion and the aggregate commitment of all lenders was $1.4 billion, with the ability to increase our total commitments up to the $1.6 billion borrowing base upon lender approval. At December 31, 2013, our borrowing base was $1.5 billion, and the aggregate commitment of all lenders was $1.4 billion.

As of September 30, 2014, and December 31, 2013, we had $719.0 million and $733.0 million, respectively, in indebtedness outstanding under our credit facility. At September 30, 2014, the 1-month LIBOR interest rate plus an applicable spread was 2.4041% on the 1-month LIBOR portion of $714 million and the prime rate plus an applicable spread was 4.50% on the prime portion of $5 million. At September 30, 2014, we had $11.4 million of unamortized debt issuance costs related to our credit facility.

As of September 30, 2014, and December 31, 2013, we were in compliance with our credit facility’s covenants.

In connection with the pending Merger with QR Energy, we received a firm commitment from Wells Fargo Bank, N.A. to increase the borrowing base under our credit facility to $2.5 billion.  We expect our next regularly scheduled borrowing base redetermination under our new amended and restated credit facility to be in April 2015.

Senior Notes

We have $305 million in aggregate principal amount of 8.625% senior notes due 2020 (the “2020 Senior Notes”), which had a carrying value of $302.0 million, net of unamortized discount of $3.0 million, as of September 30, 2014. In addition, we have $850 million in aggregate principal amount of 7.875% senior notes due 2022 (the “2022 Senior Notes” and together with the 2020 Notes, the “Senior Notes”), which had a carrying value of $854.6 million, net of unamortized premium of $4.6 million, as of September 30, 2014. At September 30, 2014, we had $19.9 million of unamortized debt issuance costs related to the Senior Notes.

Interest on our Senior Notes is payable twice a year in April and October.

As of September 30, 2014, the fair value of our 2020 Senior Notes and 2022 Senior Notes was estimated to be $319.0 million and $862.0 million, respectively, based on prices quoted from third-party financial institutions. We consider the

16


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, 2014 and December 31, 2013, we were in compliance with the covenants under our Senior Notes.

Interest Expense

Our interest expense is detailed as follows:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
Thousands of dollars
 
2014
 
2013
 
2014
 
2013
Credit agreement (including commitment fees)
 
$
4,539

 
$
6,313

 
$
14,886

 
$
9,718

Senior notes
 
23,311

 
15,436

 
69,933

 
46,308

Amortization of net premium and deferred issuance costs
 
1,765

 
1,826

 
5,779

 
4,423

Capitalized interest
 
(121
)
 
(27
)
 
(238
)
 
(62
)
Total
 
$
29,494

 
$
23,548

 
$
90,360

 
$
60,387


9. Condensed Consolidating Financial Statements

We and Breitburn Finance Corporation, as co-issuers, and certain of our subsidiaries, as guarantors, issued the 2020 Senior Notes and the 2022 Senior Notes. All but one of our subsidiaries have guaranteed our Senior Notes, and our only non-guarantor subsidiary, Breitburn Collingwood Utica LLC, is a minor subsidiary.

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 our Senior Notes, is a 100% owned finance subsidiary; all of our material subsidiaries are 100% owned and have guaranteed our Senior Notes; and all of the guarantees are full, unconditional, joint and several.
    
Each guarantee of each of the 2020 Senior Notes and the 2022 Senior Notes is subject to release in the following customary circumstances:

(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,
(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.

10.  Income Taxes

We, and all of our subsidiaries, with the exception of Phoenix Production Company (“Phoenix”), Alamitos Company, Breitburn Management and Breitburn Finance Corporation, are partnerships or limited liability companies treated as partnerships for federal and state income tax purposes. Essentially all of our taxable income or loss, which may differ considerably from the net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our partners. As such, we have not recorded any federal income tax expense for those pass-through entities.


17


Our deferred federal income tax liability was $2.9 million and $2.7 million as of September 30, 2014, and December 31, 2013, respectively.  The following table presents our income tax expense (benefit) for the three months and nine months ended September 30, 2014 and 2013
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
Thousands of dollars
 
2014
 
2013
 
2014
 
2013
Federal income tax expense (benefit)
 
 
 
 
 
 
 
 
Current
 
$
87

 
$
41

 
$
243

 
$
67

Deferred (a)
 
434

 
(45
)
 
153

 
252

State income tax expense (benefit) (b)
 
11

 
28

 
(12
)
 
309

Total
 
$
532

 
$
24

 
$
384

 
$
628


(a) Related to Phoenix, our wholly-owned subsidiary.
(b) Primarily in California and Michigan.

11.  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 7% 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 September 30, 2014, and the year ended December 31, 2013 are presented in the following table:
 
 
Nine Months Ended
 
Year Ended
Thousands of dollars
 
September 30, 2014
 
December 31, 2013
Carrying amount, beginning of period
 
$
123,769

 
$
98,480

Acquisitions
 

 
9,287

Liabilities incurred
 
3,391

 
5,313

Liabilities settled
 
(584
)
 
(893
)
Revisions
 

 
4,299

Accretion expense
 
6,640

 
7,283

Carrying amount, end of period
 
$
133,216

 
$
123,769


12.  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 cover self-insurance and other programs where governmental 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 September 30, 2014 and December 31, 2013, we had approximately $17.4 million and $17.5 million, respectively, of surety bonds and approximately $3.0 million and $2.8 million, respectively, in letters of credit outstanding.

Purchase Contracts

On July 15, 2013, we completed the acquisition of the Whiting Assets.  The Whiting Assets include the Postle Field, which currently has active CO2 enhanced recovery projects, and the Northeast Hardesty Unit, both of which are located in

18


Texas County, Oklahoma. We have a contracted supply of CO2 in the Bravo Dome Field in New Mexico, with step-in rights, for 129 Bcf over 10 to 15 years, which we expect to provide volumes in excess of those required to produce our estimated proved reserves when coupled with recycled CO2. Under the take-or-pay provisions of these purchase agreements, we are committed to buying certain volumes of CO2 for use in our enhanced recovery project being carried out at the Postle field. We are obligated to purchase a minimum daily volume of CO2 (as calculated on an annual basis) or else pay for any deficiencies at the price in effect when the minimum delivery was to have occurred. The CO2 volumes planned for use in our enhanced recovery projects in the Postle Field currently exceed the minimum daily volumes specified in these agreements. Therefore, we expect to avoid any payments for deficiencies.  The table below shows our future minimum commitments under these purchase agreements as of September 30, 2014:

 
 
Three Months Ending
 
Year Ending December 31,
 
 
 
 
Thousands of dollars
 
December 31, 2014
 
2015
 
2016
 
2017
 
2018
 
Thereafter
 
Total
Purchase contracts
 
$
3,844

 
$
28,942

 
$
14,638

 
$
15,663

 
$
21,487

 
$
45,353

 
$
129,927


13.  Partners’ Equity

Preferred Units

On May 21, 2014, we sold 8.0 million 8.25% Series A Cumulative Redeemable Perpetual Preferred Units (“Preferred Units”) in a public offering at a price of $25.00 per Preferred Unit, resulting in proceeds of $193.2 million net of underwriting discount and offering expenses of $6.8 million. We used the net proceeds from this offering to repay indebtedness outstanding under our credit facility.

The Preferred Units rank senior to the Common Units with respect to the payment of current distributions. Distributions on Preferred Units are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by our board of directors out of legally available funds for such purpose. We will pay cumulative distributions in cash on the Preferred Units on a monthly basis at a monthly rate of $0.171875 per Preferred Unit. During the three months and nine months ended September 30, 2014, we recognized $4.1 million and $6.0 million, respectively, of accrued distributions on the Preferred Units, which are included in the distributions to preferred unitholders on the consolidated statements of operations.

The Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by the Partnership or converted into Common Units in connection with a change in control. At any time on or after May 15, 2019, we may, at our option, redeem the Preferred Units, in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption. In addition, we may redeem the Preferred Units at the same redemption price following certain changes of control, as described in the Partnership Agreement (as defined below); if we do not exercise this option, then the holders of the Preferred Units have the option to convert the Series A Preferred Units into a number of Common Units per Preferred Unit as set forth in the Partnership Agreement. If we exercise the right to redeem all outstanding Preferred Units, the holders of Preferred Units will not have the conversion right described above.

Common Units

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, 2014, June 30, 2014 and September 30, 2014, we sold 25,300 Common Units, 976,611 Common Units and 269,774 Common Units, respectively, under the Equity Distribution Agreement for net proceeds of $0.5 million, $19.7 million and $6.0 million, respectively.

During the three months and nine months ended September 30, 2014, we issued no Common Units and less than 0.1 million Common Units, respectively, to non-employee directors for Restricted Phantom Units (“RPUs”) that vested in January 2014.

19



At September 30, 2014 and December 31, 2013, we had approximately 120.5 million and 119.2 million Common Units outstanding, respectively.  At September 30, 2014 and December 31, 2013, there were approximately 2.7 million and 1.3 million, respectively, of units outstanding under our Long-Term Incentive Plan (“LTIP”) that were eligible to be paid in Common Units upon vesting.

Pursuant to our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”), we may pay distributions on our Common Units within 45 days following the end of each quarter or in three equal monthly payments 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 September 30, 2014, we paid three monthly cash distributions totaling approximately $60.5 million, or $0.503 per Common Unit. During the nine months ended September 30, 2014, we paid nine monthly cash distributions totaling approximately $178.7 million, or $1.493 per Common Unit.

During the three months ended September 30, 2013, we paid cash distributions of approximately $47.8 million, or $0.480 per Common Unit. During the nine months ended September 30, 2013, we paid cash distributions of approximately $135.0 million, or $1.425 per Common unit.

During the three months and nine months ended September 30, 2014, we paid $0.9 million and $2.8 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 nine months ended September 30, 2013, we paid $0.8 million and $2.4 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.

Income per 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 income (loss) per common unit.


20


The following is a reconciliation of net income (loss) and weighted average units for calculating basic net income (loss) per common unit and diluted net income (loss) per common unit.

 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
Thousands, except per unit amounts
 
2014
 
2013
 
2014
 
2013
 
 
 
 
 
 
 
 
 
Net income (loss)
 
$
130,643

 
$
(25,011
)
 
$
16,160

 
$
15,121

Distributions on participating units not expected to vest
 
76

 
4

 
113

 
15

Distributions to preferred unitholders
 
(4,125
)
 

 
(5,958
)
 

Net income (loss) attributable to holders of Common Units and participating securities
 
$
126,594

 
$
(25,007
)
 
$
10,315

 
$
15,136

Weighted average number of units used to calculate basic and diluted net income per unit:
 
 
 
 
 
 
 
 
Common Units
 
120,473

 
99,680

 
119,806

 
97,982

Participating securities (a)
 
1,880

 

 
1,826

 
1,652

Denominator for basic income (loss) per common unit
 
122,353

 
99,680

 
121,632

 
99,634

Dilutive units (b)
 
777

 

 
738

 
355

Denominator for diluted income (loss) per common unit
 
123,130

 
99,680

 
122,370

 
99,989

Net income (loss) per common unit
 
 
 
 
 
 
 
 
Basic
 
$
1.03

 
$
(0.25
)
 
$
0.08

 
$
0.15

Diluted
 
$
1.03

 
$
(0.25
)
 
$
0.08

 
$
0.15


(a) The three months ended September 30, 2013 exclude 1,729 of potentially issuable weighted average RPUs from participating securities, as we were in a loss position.
(b) The three months ended September 30, 2013 exclude 384 of weighted average units from the calculation of the denominator for diluted earnings per common unit, as we were in a loss position.

14.  Unit Based Compensation Plans

Unit-based compensation expense for the three months ended September 30, 2014 and 2013 was $5.8 million and $4.9 million, respectively, and for the nine months ended September 30, 2014 and 2013 was $18.4 million and $14.7 million, respectively. Unit based compensation expense for the three months ended March 31, 2014 included $0.6 million related to an increase in the performance factor for the 2013 CPU grants from 1.0 to 1.25. The current multiplier was achieved based on the actual distribution made to common unitholders during the quarter.

During the nine months ended September 30, 2014, the board of directors of our General Partner approved the grant of approximately 1.3 million RPUs and CPUs to employees of Breitburn Management under our LTIP.  Our outside directors were issued less than 0.1 million RPUs under our LTIP during the nine months ended September 30, 2014.  The fair market value of the RPUs granted during 2014 for computing compensation expense under FASB Accounting Standards averaged $20.30 per unit.

During the three months ended September 30, 2014 and 2013, we paid nothing for taxes withheld on RPUs, which was the result of no units vesting during the periods.  During the nine months ended September 30, 2014 and 2013, we paid nothing and $0.6 million, respectively, for taxes withheld on RPUs that vested during the period.

As of September 30, 2014, we had $33.1 million of unrecognized compensation costs for all outstanding awards, which is expected to be recognized over the period from October 1, 2014 to December 31, 2016.

For detailed information on our various compensation plans, see Note 17 to the consolidated financial statements included in our 2013 Annual Report.

21


15.  Subsequent Events

On October 1, 2014, we announced a cash distribution to holders of Common Units for the first monthly payment attributable to the third quarter of 2014 at the rate of $0.1675 per Common Unit, which was paid on October 16, 2014 to the unitholders of record at the close of business on October 13, 2014. On October 29, 2014, we announced a cash distribution to unitholders for the second monthly payment attributable to the third quarter of 2014 at the rate of $0.1675 per Common Unit, to be paid on November 14, 2014 to the unitholders of record at the close of business on November 10, 2014.

On October 1, 2014, we declared a cash distribution for our Preferred Units of $0.171875 per Preferred Unit, which is expected to be paid on November 17, 2014 to preferred unitholders of record at the close of business on October 31, 2014. On October 29, 2014, we declared a cash distribution for our Preferred Units of $0.171875 per Preferred Unit, which is expected to be paid on December 15, 2014 to preferred unitholders of record at the close of business on November 28, 2014. The monthly distribution rate is equal to an annual distribution of $2.0625 per Preferred Unit.

On October 10, 2014, we sold 14 million Common Units at a price to the public of $18.64 per Common Unit. We used the net proceeds, net of underwriting discount and offering expenses, of $251.6 million to reduce outstanding borrowings under our credit facility.
On October 17, 2014, our registration statement on Form S-4 filed pursuant to the Merger Agreement was declared effective by the SEC. A special meeting of QR Energy unitholders is scheduled to be held on November 18, 2014.
On October 24, 2014, BOLP 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 $50.0 million in cash and 4.3 million Common Units, subject to customary purchase price adjustments, for a total preliminary purchase price of $122.7 million. 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.




22


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 2013 Annual Report and the consolidated financial statements and related notes therein.  Our 2013 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 2013 Annual Report and Part I—Item 1A “—Risk Factors” of our 2013 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 crude oil, NGL and natural gas reserves located primarily in:

•     the Antrim Shale and several non-Antrim formations in Michigan;
•    the Oklahoma Panhandle;
•     the Permian Basin in Texas;
•     the Evanston, Green River, Wind River, Big Horn and Powder River Basins in Wyoming;
•     the Los Angeles and San Joaquin Basins in California;
•     the Sunniland Trend in Florida; and
•     the New Albany Shale in Indiana and Kentucky.

2014 Highlights

Preferred Units

In May 2014, we sold 8.0 million 8.25% Series A Cumulative Redeemable Perpetual Preferred Units (“Preferred Units”) in a public offering at a price of $25.00 per Preferred Unit, resulting in proceeds of $193.2 million, net of underwriting discount and offering expenses. The Preferred Units rank senior to the Common Units with respect to the payment of current distributions. We used the net proceeds from this offering to repay indebtedness outstanding under our credit facility.

Distributions on the Preferred Units are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by our board of directors out of legally available funds for such purpose. We will pay cumulative distributions in cash on the Preferred Units on a monthly basis at a monthly rate of $0.171875 per unit. The initial distribution on the Preferred Units of $0.309375 was paid on July 15, 2014. Regular monthly distributions of $0.171875 per Preferred Unit began with the August 15, 2014 payment. The monthly distribution rate is equal to an annual distribution of $2.0625 per Preferred Unit. During the three months and nine months ended September 30, 2014, we recognized $4.1 million and $6.0 million, respectively, of accrued distributions on the Preferred Units, which are included in the distributions to preferred unitholders on the consolidated statements of operations.

Common Units

During the three months ended March 31, 2014, we paid three monthly cash distributions at the rate of $0.1642 per Common Unit per month, totaling approximately $58.7 million, or $0.4926 per Common Unit. During the three months ended June 30, 2014, we paid three monthly cash distributions at the rate of $0.1658 per Common Unit per month, totaling approximately $59.5 million, or $0.4974 per Common Unit. During the three months ended September 30, 2014, we paid three monthly cash distributions at the rate of $0.1675 per Common Unit per month, totaling approximately $60.5 million, or $0.5025 per Common Unit.

On October 1, 2014, we announced a cash distribution to unitholders for the first monthly payment attributable to the third quarter of 2014 at the rate of $0.1675 per Common Unit, which was paid on October 16, 2014 to the unitholders of record at the close of business on October 13, 2014. On October 29, 2014, we announced a cash distribution to unitholders for the second monthly payment attributable to the third quarter of 2014 at the rate of $0.1675 per Common Unit, to be paid on November 14, 2014 to the unitholders of record at the close of business on November 10, 2014.


23


On October 10, 2014, we sold 14 million Common Units at a price to the public of $18.64 per Common Unit. We used the net proceeds, net of underwriting discount and offering expenses, of $251.6 million to reduce outstanding borrowings under our credit facility.

On October 24, 2014, in connection with the Antares Acquisition (as defined below), we issued 4.3 million Common Units to Antares (as defined below) as partial consideration for the Antares Assets (as defined below).

Credit Facility

In April 2014, in connection with the regularly scheduled borrowing base redetermination, we entered into the Twelfth Amendment to the Second Amended and Restated Credit Agreement, which provides for an increased borrowing base of $1.6 billion with total lender commitments of $1.4 billion and an extension of the term of the credit facility for one year until May 9, 2017. Concurrently with the closing of the Merger, we expect to amend and restate our existing credit facility to increase the borrowing base and the aggregate commitment of all lenders under our credit facility to $2.5 billion, consistent with the commitment from Wells Fargo Bank, N.A..

Pending Merger with QR Energy

On July 23, 2014, we, our General Partner and Boom Merger Sub, LLC, a direct wholly owned subsidiary of the Partnership (“Merger Sub”), entered into an Agreement and Plan of Merger (the “Merger Agreement”) with QR Energy, LP (“QR Energy”) and QRE GP, LLC (“QRE”). Pursuant to the Merger Agreement, we will acquire QR Energy in exchange for our Common Units, including the assumption of approximately $1.01 billion of QR Energy’s existing net debt and the payment of $350 million in cash to the holders of the outstanding Class C Convertible Preferred Units of QR Energy (each, a “Class C Unit”). The Merger Agreement provides that, upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will be merged with and into QR Energy, with QR Energy continuing as the surviving entity and a direct wholly owned subsidiary of the Partnership (the “Merger”).

Under the terms of the Merger Agreement, each outstanding common unit representing a limited partner interest in QR Energy (a “QR Energy Common Unit”) and Class B Unit representing a limited partner interest in QR Energy (a “Class B Unit”) will be converted into the right to receive 0.9856 newly issued Common Units (the “Merger Consideration”). A number of Class B Units issuable upon a change of control of QR Energy equal to (i) 6,748,067, minus (ii) the excess of (A) the number of performance units that vest and are settled in QR Energy Common Units in connection with the Merger over (B) 383,900 will be issued and treated as outstanding Class B Units and converted into the right to receive the Merger Consideration. Each outstanding Class C Unit of QR Energy will be converted into the right to receive cash in an amount equal to $350 million divided by the number of Class C Units outstanding immediately prior to the effective time of the Merger. In no event will we be obligated to issue in excess of 72,001,686 Common Units as part of the Merger Consideration.
The completion of the Merger is subject to satisfaction or waiver of customary closing conditions, including (1) the adoption of the Merger Agreement by holders of a majority of the outstanding QR Energy Common Units, Class B Units and Class C Units, voting as a single class, (2) the approval for listing of the Common Units issuable as part of the Merger Consideration on the NASDAQ, and (3) other customary conditions. On August 19, 2014, we received notification of early termination of the waiting period under the Hart-Scott-Rodino Act pursuant to the Merger.

On July 23, 2014, we also entered into a Transaction, Voting and Support Agreement (the “Voting Agreement”) with each of Quantum Resources A1, LP, Quantum Resources B, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC (collectively, the “Fund Unitholders”), and each of QR Holdings (QRE), LLC and QR Energy Holdings, LLC (collectively, the “Management Unitholders” and, together with the Fund Unitholders, the “QR Energy Unitholders”) with respect to the Merger Agreement. The Voting Agreement generally requires that the QR Energy Unitholders vote or cause to be voted all QR Energy Common Units, Class B Units and Class C Units owned by such QR Energy Unitholder in favor of the merger and against alternative transactions. The Voting Agreement also provides that, upon termination of the Merger Agreement and QR Energy’s acceptance of an alternative transaction, each QR Energy Unitholder may be required to pay the Partnership a termination fee equal to the lesser of (1) such QR Energy Unitholder’s pro rata share of 2% of the equity value of such alternative transaction or (2) the excess of the aggregate consideration paid to such QR Energy Unitholder in such alternative transaction over the aggregate consideration that would have been received by such QR Energy Unitholder under the Merger Agreement. Subject to certain exceptions, the Voting Agreement will terminate upon the earlier of (i) the consummation of the Merger and (ii) the termination of the Merger Agreement.

24


On July 23, 2014, we also entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with each of the QR Energy Unitholders. Under the Registration Rights Agreement, we are required to file or cause to be filed with the Securities and Exchange Commission (the “SEC”) a registration statement with respect to the public resale of our Common Units issued to the QR Energy Unitholders as part of the Merger Consideration. We are required to file or cause to be filed the registration statement within 90 days following the closing under the Merger Agreement and are required to cause the registration statement to become effective as soon as reasonably practicable thereafter but in no event later than 120 days after the closing under the Merger Agreement.

In connection with the closing of the Merger, we intend to refinance the outstanding debt of QR Energy under its credit facility, which was approximately $755 million as of September 30, 2014, and QR Energy’s 9.25% senior notes due in 2020 with an aggregate principal amount of $300 million.  We have received a firm commitment from Wells Fargo Bank, N.A. to increase the borrowing base under our credit facility to $2.5 billion in connection with the Merger. Concurrently with the closing of the Merger, we expect to amend and restate our existing credit facility to increase the borrowing base and the aggregate commitment of all lenders under our credit facility to $2.5 billion, consistent with the commitment from Wells Fargo Bank, N.A.

On October 17, 2014, our registration statement on Form S-4 filed pursuant to the Merger Agreement was declared effective by the SEC. A special meeting of QR Energy unitholders to vote on the adoption of the Merger Agreement is scheduled to be held on November 18, 2014. The Merger Agreement requires that the Merger close within three business days of the meeting of QR Energy unitholders.

Antares Acquisition
On October 24, 2014, we completed the acquisition of certain oil and gas properties located in the Midland Basin, Texas (“Antares Assets”) from Antares Energy Company, a Delaware corporation, in exchange for $50.0 million in cash and 4.3 million Common Units, subject to customary purchase price adjustments, for a total preliminary purchase price of $122.7 million (the “Antares Acquisition”). 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.

Operational Focus and Capital Expenditures

In the first nine months of 2014, our oil, NGL and natural gas capital expenditures, including capitalized engineering costs, totaled $275 million, compared to approximately $198 million in the first nine months of 2013.  We spent approximately $172 million in Texas, $56 million in California, $26 million in Oklahoma, $11 million in Florida, $5 million in Wyoming and $5 million in Michigan.  In the first nine months of 2014, we drilled and completed 73 productive wells in Texas, 39 productive wells in California, six productive wells in Wyoming and three productive wells in Michigan. We also performed workovers on 14 wells in Michigan, 11 wells in Oklahoma, ten wells in California, two wells in Wyoming, three wells in Florida and one well in Texas.

In 2014, our crude oil, NGL and natural gas capital spending program, including capitalized engineering costs and excluding the QR Energy Merger, is expected to be between $360 million and $370 million. This compares with approximately $295 million in 2013. In 2014, we anticipate spending approximately 92% principally on oil projects in Texas, California and Oklahoma and approximately 8% principally on oil projects in Florida, Wyoming and Michigan. We anticipate 88% of our total capital spending will be focused on drilling and rate-generating projects that are designed to increase or add to production or reserves. We plan to drill 187 wells with 172 wells expected in Texas and California and 15 wells expected in Wyoming and Michigan. Without considering the QR Energy Merger, we expect our full year production to be approximately 13.3 MMBoe.

Our Texas production for the third quarter was down slightly from the previous quarter due to curtailment and steeper than anticipated production declines in recently drilled wells.  To improve production results and rates of return from our Texas properties, we plan to transition to a horizontal well program and begin drilling those wells in the first quarter of 2015. However, in order to hold acreage on both our legacy and acquired Antares assets, we expect to drill 15 additional vertical wells in the Permian Basin by the end of the first quarter of 2015.  We currently plan to fund the initial horizontal drilling program ourselves and will consider various options involving third parties for additional future horizontal wells.  Our recently acquired Antares Assets include acreage adjacent to our existing properties in Howard County in the Permian Basin, which we believe will enhance our ability to drill horizontal wells in the area.


25


Commodity Prices

In the third quarter of 2014, the NYMEX WTI spot price averaged $98 per barrel, compared with approximately $106 per barrel in the third quarter of 2013.  In the first nine months of 2014, the NYMEX WTI spot price averaged $100 per barrel and ranged from a low of $91 per barrel to a high of $108 per barrel. In 2013, the NYMEX WTI spot price averaged approximately $98 per barrel. In recent months, there has been a decline in crude oil prices. The NYMEX WTI spot price decreased from $106 per barrel at June 30, 2014 to $79 per barrel at November 3, 2014.  Lower crude oil prices may not only decrease our revenues, but may also reduce the amount of crude oil that we can produce economically and therefore potentially lower our crude oil reserves.
 
In the third quarter of 2014, the Henry Hub natural gas spot price averaged $3.96 per MMBtu compared with approximately $3.55 per MMBtu in the third quarter of 2013.  In the first nine months of 2014, the Henry Hub spot price averaged $4.57 and ranged from a low of $3.77 per MMBtu to a high of $8.15 per MMBtu.  In 2013, the Henry Hub natural gas spot price averaged approximately $3.73 per MMBtu. In the third quarter of 2014, the MichCon natural gas spot price averaged $4.21 per MMBtu compared with approximately $3.79 per MMBtu in the third quarter of 2013.  

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 L.P. (“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 nine months ended September 30, 2014, the monthly fee paid by PCEC for indirect expenses was $700,000. In August 2014, the expiration of the term for the current monthly fee of $700,000 was extended to June 30, 2015, and thereafter, the monthly fee will be redetermined biannually.