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EX-31.1 - EXHIBIT 31.1 - Breitburn Energy Partners LPq1201510-qex311.htm
EX-32.1 - EXHIBIT 32.1 - Breitburn Energy Partners LPq1201510-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 March 31, 2015
or
o
Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the transition period from ___ to ___

Commission File Number 001-33055

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

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

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

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

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

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

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

As of May 4, 2015, the registrant had 210,951,820 Common Units outstanding.

 
 
 
 
 
 



INDEX

 
 
Page No.
 
 
 
 
 
PART I
 
 
FINANCIAL INFORMATION
 
 
 
 
 
 
 Consolidated Balance Sheets at March 31, 2015 and December 31, 2014
 

 
 Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014
 
– Notes to Consolidated Financial Statements
 
 
 
 
PART II
 
 
OTHER INFORMATION
 
 
 
 
 
 
 
 
 



CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are changes in crude oil, natural gas liquids (“NGL”) and natural gas prices; delays in planned or expected drilling; changes in costs and availability of drilling, completion and production equipment and related services and labor; the ability to obtain sufficient quantities of carbon dioxide (“CO2”) necessary to carry out enhanced oil recovery projects; the discovery of previously unknown environmental issues; federal, state and local initiatives and efforts relating to the regulation of hydraulic fracturing; the competitiveness of alternate energy sources or product substitutes; technological developments; potential disruption or interruption of our net production due to accidents or severe weather; the level of success in exploitation, development and production activities; the timing of exploitation and development expenditures; inaccuracies of reserve estimates or assumptions underlying them; revisions to reserve estimates as a result of changes in commodity prices; impacts to financial statements as a result of impairment write-downs; risks related to level of indebtedness and periodic redeterminations of the borrowing base under our credit agreement; ability to generate sufficient cash flows from operations to meet the internally funded portion of any capital expenditures budget; ability to obtain external capital to finance exploitation and development operations and acquisitions; the impacts of hedging on results of operations; failure of properties to yield oil or natural gas in commercially viable quantities; ability to integrate successfully the businesses we acquire; uninsured or underinsured losses resulting from oil and natural gas operations; inability to access oil and natural gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing oil and natural gas operations; changes in governmental regulations, including the regulation of derivative instruments and the oil and natural gas industry; ability to replace oil and natural gas reserves; any loss of senior management or technical personnel; competition in the oil and natural gas industry; risks arising out of hedging transactions; the effects of changes in accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under “Cautionary Statement Regarding Forward-Looking Information” and Part I—Item 1A “—Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2014 (our “2014 Annual Report”) 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
 
March 31,
2015
 
December 31,
2014
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash
 
$
8,690

 
$
12,628

Accounts and other receivables, net
 
136,360

 
166,436

Derivative instruments (note 3)
 
411,391

 
408,151

Related party receivables (note 4)
 

 
2,462

Inventory
 
3,912

 
3,727

Prepaid expenses
 
3,532

 
7,304

Total current assets
 
563,885

 
600,708

Equity investments
 
6,138

 
6,463

Property, plant and equipment
 
 
 
 
Oil and natural gas properties
 
7,804,213

 
7,736,409

Other property, plant and equipment (note 2)
 
133,429

 
60,533

 
 
7,937,642

 
7,796,942

Accumulated depletion and depreciation (note 5)
 
(1,505,141
)
 
(1,342,741
)
Net property, plant and equipment
 
6,432,501

 
6,454,201

Other long-term assets
 
 
 
 
Intangibles (note 6)
 
7,616

 
8,336

Goodwill (note 2)
 
95,947

 
92,024

Derivative instruments (note 3)
 
326,788

 
319,560

Other long-term assets (note 6)
 
108,194

 
157,042

Total assets
 
$
7,541,069

 
$
7,638,334

LIABILITIES AND EQUITY
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable
 
$
102,448

 
$
129,270

Current portion of long-term debt (note 7)
 

 
105,000

Derivative instruments (note 3)
 
5,339

 
5,457

Distributions payable
 
734

 
733

Current portion of asset retirement obligation (note 9)
 
4,388

 
4,948

Revenue and royalties payable
 
36,065

 
40,452

Wages and salaries payable
 
14,178

 
22,322

Accrued interest payable
 
42,882

 
20,672

Production and property taxes payable
 
25,980

 
25,207

Other current liabilities
 
6,422

 
7,495

Total current liabilities
 
238,436

 
361,556

Credit facility
 
2,218,000

 
2,089,500

Senior notes, net
 
1,156,532

 
1,156,560

Other long-term debt
 
2,700

 
1,100

Total long-term debt (note 7)
 
3,377,232

 
3,247,160

Deferred income taxes
 
2,743

 
2,575

Asset retirement obligation (note 9)
 
239,039

 
233,463

Derivative instruments (note 3)
 
2,378

 
2,269

Other long-term liabilities (note 10)
 
25,122

 
25,135

Total liabilities
 
3,884,950

 
3,872,158

Commitments and contingencies (note 11)
 


 


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

 
193,215

Common units, 210.9 million units issued and outstanding at each of March 31, 2015 and December 31, 2014 (note 12)
 
3,456,330

 
3,566,468

Accumulated other comprehensive income (loss) (note 13)
 
(289
)
 
(392
)
Total partners' equity
 
3,649,256

 
3,759,291

Noncontrolling interest
 
6,863

 
6,885

Total equity
 
3,656,119

 
3,766,176

 
 
 
 
 
Total liabilities and equity
 
$
7,541,069

 
$
7,638,334


See accompanying notes to consolidated financial statements.

2


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

 
 
Three Months Ended
 
 
March 31,
Thousands of dollars, except per unit amounts
 
2015

2014
Revenues and other income items
 
 
 
 
Oil, natural gas and natural gas liquid sales
 
$
162,623

 
$
223,556

Gain (loss) on commodity derivative instruments, net (note 3)
 
137,192

 
(40,228
)
Other revenue, net
 
6,469

 
1,584

    Total revenues and other income items
 
306,284

 
184,912

Operating costs and expenses
 
 
 
 
Operating costs
 
117,978

 
82,197

Depletion, depreciation and amortization
 
109,824

 
63,501

Impairments (note 5)
 
59,113

 

General and administrative expenses
 
32,262

 
18,729

Restructuring costs (note 15)
 
4,918

 

Loss on sale of assets
 
15

 
86

Total operating costs and expenses
 
324,110

 
164,513

 
 
 
 
 
Operating income (loss)
 
(17,826
)
 
20,399

 
 
 
 
 
Interest expense, net of capitalized interest
 
39,665

 
30,658

Loss on interest rate swaps (note 3)
 
1,812

 

Other income, net
 
(477
)
 
(512
)
 
 
 
 
 
Loss before taxes
 
(58,826
)
 
(9,747
)
 
 
 
 
 
Income tax expense
 
92

 
11

 
 
 
 
 
Net loss
 
(58,918
)
 
(9,758
)
 
 
 
 
 
Less: Net loss attributable to noncontrolling interest
 
(93
)
 

 
 
 
 
 
Net loss attributable to the partnership
 
(58,825
)
 
(9,758
)
 
 
 
 
 
Less: distributions to preferred unitholders
 
4,125

 

 
 
 
 
 
Net loss attributable to common unitholders
 
$
(62,950
)
 
$
(9,758
)
 
 
 
 
 
Basic net loss per unit (note 12)
 
$
(0.29
)
 
$
(0.08
)
Diluted net loss per unit (note 12)
 
$
(0.29
)
 
$
(0.08
)

See accompanying notes to consolidated financial statements.


3


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

 
 
Three Months Ended
 
 
March 31,
Thousands of dollars, except per unit amounts
 
2015
 
2014
Net loss
 
$
(58,918
)
 
$
(9,758
)
 
 
 
 
 
Other comprehensive income, net of tax:
 
 
 
 
Change in fair value of available-for-sale securities (a)
 
173

 

Pension and post-retirement benefits actuarial loss
 

 

Total other comprehensive income
 
173

 

 
 
 
 
 
Total comprehensive loss
 
(58,745
)
 
(9,758
)
 
 
 
 
 
Less: Comprehensive income attributable to noncontrolling interest
 
(23
)
 

 
 
 
 
 
Comprehensive loss attributable to the partnership
 
$
(58,722
)
 
$
(9,758
)

(a) Net of income taxes of $0.1 million for the three months ended March 31, 2015.

See accompanying notes to consolidated financial statements.

4


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

 
 
Three Months Ended
 
 
March 31,
Thousands of dollars
 
2015
 
2014
Cash flows from operating activities
 
 
 
 
Net loss
 
$
(58,918
)
 
$
(9,758
)
Adjustments to reconcile to cash flows from operating activities:
 
 
 
 
Depletion, depreciation and amortization
 
109,824

 
63,501

Impairments
 
59,113

 

Unit-based compensation expense
 
7,741

 
6,549

(Gain) loss on derivative instruments
 
(135,380
)
 
40,228

Derivative instrument settlement receipts (payments)
 
124,904

 
(13,500
)
Income from equity affiliates, net
 
325

 
(107
)
Deferred income taxes
 
168

 
(33
)
Loss on sale of assets
 
15

 
86

Other
 
(41
)
 
1,800

Changes in net assets and liabilities
 
 
 
 
Accounts receivable and other assets
 
30,043

 
(20,752
)
Inventory
 
(185
)
 
5

Net change in related party receivables and payables
 
2,462

 
1,669

Accounts payable and other liabilities
 
1,078

 
46,623

Net cash provided by operating activities
 
141,149

 
116,311

Cash flows from investing activities
 
 
 
 
Property acquisitions
 
(13,993
)
 
(2,464
)
Capital expenditures
 
(97,230
)
 
(93,075
)
Other
 
(853
)
 
(2,037
)
Proceeds from sale of assets
 

 
1

Net cash used in investing activities
 
(112,076
)
 
(97,575
)
Cash flows from financing activities
 
 
 
 
Proceeds from issuance of common units, net
 
(63
)
 
180

Distributions to preferred unitholders
 
(4,125
)
 

Distributions to common unitholders
 
(54,122
)
 
(59,638
)
Proceeds from issuance of long-term debt, net
 
193,600

 
199,000

Repayments of long-term debt
 
(168,500
)
 
(157,000
)
Change in bank overdraft
 
199

 
(1,683
)
Debt issuance costs
 

 
(232
)
Net cash used in financing activities
 
(33,011
)
 
(19,373
)
Decrease in cash
 
(3,938
)
 
(637
)
Cash beginning of period
 
12,628

 
2,458

Cash end of period
 
$
8,690

 
$
1,821


See accompanying notes to consolidated financial statements.

5


Notes to Consolidated Financial Statements

1.  Organization and Basis of Presentation

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

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

Accounting Standards

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

In May 2014, the FASB issued 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 reserves, the future net revenues are discounted using a market-based weighted average cost of capital. We also periodically employ third-party valuation firms to assist in the valuation of complex facilities, including pipelines, gathering lines and processing facilities.


6


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

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

2015 Acquisitions
On March 31, 2015, we completed the acquisition of certain CO2 properties located in Harding County, New Mexico (“CO2 Assets”), for a total preliminary purchase price of $64.2 million (the “CO2 Acquisition”), subject to customary purchase price adjustments, of which, $14.3 million was paid during the three months ended March 31, 2015. The preliminary purchase price included $64.5 million reflected in other property, plant and equipment on the consolidated balance sheet and $0.3 million of ARO reflected in asset retirement obligation on the consolidated balance sheet.

2014 Acquisitions

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

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

    

7


The initial purchase price, subject to customary purchase price adjustments, for the QRE Merger was allocated to the assets acquired and liabilities assumed as follows at March 31, 2015:

Thousands of dollars
 
 
Cash
 
$
5,121

Accounts and other receivables
 
113,398

Current derivative instrument assets
 
70,362

Prepaid expenses
 
3,123

Oil and gas properties
 
2,397,967

Non-oil and gas assets
 
17,866

Goodwill
 
95,947

Long-term derivative instrument assets
 
72,998

Other long-term assets
 
50,619

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


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

Acquisition-related costs for the QRE Merger were $0.1 million for the three months ended March 31, 2015 and are reflected in G&A expenses on the consolidated statements of operations.

In connection with the QRE Merger, on November 19, 2014, we entered into a Transition Services Agreement (“TSA”) with Quantum Resources Management, LLC (“QRM”).  Under the terms of the TSA, each party agreed to provide certain land, administrative, accounting, IT and marketing services to the other party. The term of the TSA commenced on November 19, 2014 and terminates on the earlier of (i) six months following November 19, 2014 and (ii)(A) with respect to QRM, the date upon which we provide written notice to QRM of our desire to terminate the TSA and (B) with respect to us, the date upon which QRM provides us with written notice of its desire to terminate the TSA.
 
Antares Acquisition
On October 24, 2014, we completed the acquisition of certain oil and gas properties located in the Midland Basin, Texas from Antares Energy Company, a Delaware corporation, in exchange for 4.3 million Common Units and $50.0 million in cash (the “Antares Acquisition”), subject to customary purchase price adjustments, for a total preliminary purchase price of $122.3 million, which was allocated to oil and natural gas assets ($110.9 million to unproved properties, $13.1 million to proved properties and $1.7 million to ARO). The number of Common Units being issued as partial consideration will not be adjusted to account for changes in the unit price or for purchase price adjustments. We expect to finalize the valuation and complete the purchase price allocation as soon as practicable but no later than one year from the acquisition date. Acquisition-related costs for the Antares Acquisition were zero for the three months ended March 31, 2015.


8


Pro Forma (unaudited)
    
The following unaudited pro forma financial information presents a summary of our combined statements of operations for the three months ended March 31, 2014 assuming the QRE Merger was completed on January 1, 2014. The pro forma results include adjustments for (1) the assumption of ARO and accretion expense for the properties acquired, (2) depletion and depreciation expense applied to the adjusted purchase price of the properties acquired, (3) interest expense on additional borrowings necessary to finance the acquisition, including the amortization of debt issuance costs, and (4) the effect on the denominator for calculating net income (loss) per unit of common unit issuances necessary to finance the acquisition. The pro forma financial information is not necessarily indicative of the results of operations if the acquisition had been effective January 1, 2014. The Antares Acquisition in 2014 and the CO2 Acquisition in 2015 were not included in the pro forma information as they are considered immaterial.
 
 
Pro Forma
 
 
Three Months Ended
Thousands of dollars, except per unit amounts
 
March 31, 2014
Revenues
 
284,370

Net loss attributable to the partnership
 
(17,500
)
 
 
 
Net loss per common unit:
 
 
Basic
 
(0.08
)
Diluted
 
(0.08
)

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

Commodity Activities

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


9


We had the following commodity derivative contracts in place at March 31, 2015:

 
 
Year

 
2015

2016

2017

2018
Oil Positions:
 
 
 
 
 
 
 
 
Fixed Price Swaps - NYMEX WTI
 
 
 
 
 
 
 
 
Volume (Bbl/d)
 
20,044

 
15,504

 
13,519

 
493

Average Price ($/Bbl)
 
$
93.28

 
$
88.07

 
$
85.05

 
$
82.20

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

 
4,300

 
298

 

Average Price ($/Bbl)
 
$
97.73

 
$
95.17

 
$
97.50

 
$

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

 
1,500

 

 

Average Floor Price ($/Bbl)
 
$
90.00

 
$
80.00

 
$

 
$

Average Ceiling Price ($/Bbl)
 
$
111.73

 
$
102.00

 
$

 
$

Collars - ICE Brent
 
 
 
 
 
 
 
 
Volume (Bbl/d)
 
500

 
500

 

 

Average Floor Price ($/Bbl)
 
$
90.00

 
$
90.00

 
$

 
$

Average Ceiling Price ($/Bbl)
 
$
109.50

 
$
101.25

 
$

 
$

Puts - NYMEX WTI
 
 
 
 
 
 
 
 
Volume (Bbl/d)
 
500

 
1,000

 

 

Average Price ($/Bbl)
 
$
90.00

 
$
90.00

 
$

 
$

Total:
 
 
 
 
 
 
 
 
Volume (Bbl/d)
 
26,369

 
22,804

 
13,817

 
493

Average Price ($/Bbl)
 
$
93.46

 
$
89.01

 
$
85.32

 
$
82.20

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

 
17,000

 
10,000

 

Average Price ($/MMBtu)
 
$
6.00

 
$
4.46

 
$
4.48

 
$

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

 
36,050

 
19,016

 
1,870

Average Price ($/MMBtu)
 
$
4.84

 
$
4.24

 
$
4.43

 
$
4.15

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

 
630

 
595

 

Average Floor Price ($/MMBtu)
 
$
5.00

 
$
4.00

 
$
4.00

 

Average Ceiling Price ($/MMBtu)
 
$
7.48

 
$
5.55

 
$
6.15

 
$

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

 
11,350

 
10,445

 

Average Price ($/MMBtu)
 
$
4.78

 
$
4.00

 
$
4.00

 
$

Deferred Premium ($/MMBtu)
 
$
0.64

(a)
$
0.66

 
$
0.69

 
$

Total:
 
 
 
 
 
 
 
 
Volume (MMBtu/d)
 
82,311

 
65,030

 
40,056

 
1,870

Average Price ($/MMBtu)
 
$
4.98

 
$
4.25

 
$
4.33

 
$
4.15

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

 

 

 

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

 
$

 
$


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

During the three months ended March 31, 2015 and 2014, we did not enter into any derivative instruments that required pre-paid premiums.

10


    
As of March 31, 2015, premiums paid in 2012 related to oil and natural gas derivatives to be settled beyond March 31, 2015 were as follows:
 
 
Year
Thousands of dollars
 
2015
 
2016
 
2017
 
2018
Oil
 
$
3,528

 
$
7,438

 
$
734

 
$

Natural gas
 
$
1,499

 
$
952

 
$

 
$


Interest Rate Activities

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. To fix a portion of our floating LIBOR-base debt under our credit facility, we had the following interest rate swaps in place at March 31, 2015 and December 31, 2014. These contracts were novated to us in November 2014 in connection with the QRE Merger:
 
 
Year
 
 
2015
 
2016
Fixed Rate Swaps - LIBOR
 
 
 
 
Notional Amount (thousands of dollars)
 
$
401,933

 
$
410,000

Average Fixed Rate
 
1.59
%
 
1.72
%

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

Fair Value of Financial Instruments
 
The following table presents the fair value of our derivative instruments, none of which are designated as hedging instruments:
Balance sheet location, thousands of dollars
 
Oil Commodity Derivatives
 
Natural Gas
Commodity Derivatives
 
Interest Rate Derivatives
 
Commodity Derivatives Netting (a)
 
Total Financial Instruments
As of March 31, 2015
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
Current assets - derivative instruments
 
$
356,587

 
$
55,720

 
$

 
$
(916
)
 
$
411,391

Other long-term assets - derivative instruments
 
295,526

 
36,146

 
11

 
(4,895
)
 
326,788

Total assets
 
652,113

 
91,866

 
11

 
(5,811
)
 
738,179

Liabilities
 
 
 
 
 
 
 
 
 
 
Current liabilities - derivative instruments
 
(82
)
 
(996
)
 
(5,177
)
 
916

 
(5,339
)
Long-term liabilities - derivative instruments
 
(338
)
 
(4,557
)
 
(2,378
)
 
4,895

 
(2,378
)
Total liabilities
 
(420
)
 
(5,553
)
 
(7,555
)
 
5,811

 
(7,717
)
Net assets (liabilities)
 
$
651,693

 
$
86,313

 
$
(7,544
)
 
$

 
$
730,462

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

 
$
58,246

 
$

 
$
(446
)
 
$
408,151

Other long-term assets - derivative instruments
 
296,441

 
29,649

 
210

 
(6,740
)
 
319,560

Total assets
 
646,792

 
87,895

 
210

 
(7,186
)
 
727,711

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

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

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

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

 
$
82,112

 
$
(7,185
)
 
$

 
$
719,985


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


11


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

Thousands of dollars
 
Oil Commodity
Derivatives (a)
 
Natural Gas
Commodity Derivatives (a)
 
Interest Rate Derivatives (b)
 
Total Financial Instruments
Three Months Ended March 31, 2015
 
 
 
 
 
 
 
 
Net gain (loss)
 
$
118,514

 
$
18,678

 
$
(1,812
)
 
$
135,380

Three Months Ended March 31, 2014
 
 
 
 
 
 
 
 
Net loss
 
$
(27,892
)
 
$
(12,336
)
 
$

 
$
(40,228
)

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

Fair Value Measurements

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

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

Financial assets and liabilities that are categorized in Level 3 may later be reclassified to the Level 2 category at the point we are able to obtain sufficient binding market data.  We had no transfers in or out of Levels 1, 2 or 3 during the three months and three months ended March 31, 2015 and 2014. Our policy is to recognize transfers between levels as of the end of the period.

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

Derivative Instruments

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

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

12


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 derivatives, and inputs include LIBOR forward interest rates, one-month LIBOR rates and risk-free interest rates for present value discounting.

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

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

Available for Sale Securities

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

Fair Value Hierarchy

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

Thousands of dollars
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
 
 
 
 
 
 
 
As of March 31, 2015
 
 
 
 
 
 
 
 
Assets (liabilities)
 
 
 
 
 
 
 
 
Crude Oil
 
 
 
 
 
 
 
 
Crude oil swaps
 
$

 
$
592,592

 
$

 
$
592,592

Crude oil collars
 

 

 
42,095

 
42,095

Crude oil puts
 

 

 
17,006

 
17,006

Natural Gas
 
 
 
 
 
 
 
 
Natural gas swaps
 

 
66,642

 

 
66,642

Natural gas collars
 

 

 
11,351

 
11,351

Natural gas puts
 

 

 
8,320

 
8,320

Interest rate swaps
 
 
 
 
 
 
 
 
Interest rate swaps
 

 
(7,544
)
 

 
(7,544
)
Available-for-sale securities
 
 
 
 
 
 
 
 
Equities
 
4,197

 

 

 
4,197

Mutual funds
 
10,679

 

 

 
10,679

Exchange traded funds
 
4,733

 

 

 
4,733

Net assets
 
$
19,609

 
$
651,690

 
$
78,772

 
$
750,071


13


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

 
$
583,648

 
$

 
$
583,648

Crude oil collars
 

 

 
44,405

 
44,405

Crude oil puts
 

 

 
17,005

 
17,005

Natural gas commodity derivatives
 
 
 
 
 
 
 
 
Natural gas swaps
 

 
62,220

 

 
62,220

Natural gas collars
 

 

 
13,256

 
13,256

Natural gas puts
 

 

 
6,636

 
6,636

Interest rate swaps
 
 
 
 
 
 
 
 
Interest rate swaps
 

 
(7,185
)
 

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

 

 

 
4,138

Mutual funds
 
10,577

 

 

 
10,577

Exchange traded funds
 
4,630

 

 

 
4,630

Net assets
 
$
19,345

 
$
638,683

 
$
81,302

 
$
739,330


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

 
 
Three Months Ended March 31,
 
 
2015
 
2014
Thousands of dollars
 
Oil
 
Natural Gas
 
Oil
 
Natural Gas
Assets (a):
 
 
 
 
 
 
 
 
Beginning balance
 
$
61,410

 
$
19,892

 
$
8,957

 
$
1,848

Derivative instrument settlements (b)
 
10,987

 
3,567

 

 
(57
)
Loss (b)(c)
 
(13,296
)
 
(3,788
)
 
(1,864
)
 
(639
)
Ending balance
 
$
59,101

 
$
19,671

 
$
7,093

 
$
1,152


(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 loss on mark-to-market of derivative instruments.


14


For Level 3 derivative instruments measured at fair value on a recurring basis as of March 31, 2015, the significant unobservable inputs used in the fair value measurements were as follows:

 
 
Fair Value at
 
Valuation
 
 
 
 
Thousands of dollars
 
March 31, 2015
 
Technique
 
Unobservable Input
 
Range
Oil Options
 
$
59,101

 
Option Pricing Model
 
Oil forward commodity prices
 
$47.60/Bbl - $66.68/Bbl
 
 
 
 
 
 
Oil volatility
 
22.92% - 54.89%
 
 
 
 
 
 
Own credit risk
 
5%
Natural Gas Options
 
19,671

 
Option Pricing Model
 
Gas forward commodity prices
 
$2.59/MMBtu - $3.55/MMBtu
 
 
 
 
 
 
Gas volatility
 
18.52% - 45.86%
 
 
 
 
 
 
Own credit risk
 
5%
Total
 
$
78,772

 
 
 
 
 
 

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

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

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

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

 
 
 
 
 
 

Credit and Counterparty Risk

Financial instruments, which potentially subject us to concentrations of credit risk, consist principally of derivatives and accounts receivable. Our derivatives expose us to credit risk from counterparties. As of March 31, 2015, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC and Credit Suisse International, Union Bank N.A, Wells Fargo Bank, N.A., JP Morgan Chase Bank N.A., The Bank of Nova Scotia, BNP Paribas, Royal Bank of Canada, The Toronto-Dominion Bank, Merrill Lynch Commodities, Inc., Canadian Imperial Bank of Commerce, Comerica Bank, ING Capital Markets LLC, Credit Agricole Corporate and Investment Bank, and Citizens Bank, National Association. Our counterparties are all lenders under our Third Amended and Restated Credit Agreement. Our credit agreement is secured by our oil, NGL and natural gas reserves, so we are not required to post any collateral, and we conversely do not receive collateral from our counterparties. On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits and monitor the appropriateness of these limits on an ongoing basis. We periodically obtain credit default swap information on our counterparties. Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to fail to perform in accordance with the terms of the contract. This risk is managed by diversifying our derivatives portfolio.  As of March 31, 2015, each of these financial institutions had an investment grade credit rating.  As of March 31, 2015, our largest derivative asset balances were with Wells Fargo Bank, Credit Suisse Energy LLC and JP Morgan, which accounted for approximately 23%, 20% and 14% of our net derivative asset balances, respectively.  


15


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 ended March 31, 2015 and 2014, the monthly fee paid by PCEC for indirect expenses was $700,000. As of March 31, 2015, the term of the Agreement was set to expire on June 30, 2015. On May 1 2015, the term of the Agreement was extended to December 31, 2016, at which time, the agreement is subject to renegotiation.

At March 31, 2015, we had a current payable of $0.2 million and at December 31, 2014, we had a current receivable of $2.4 million, respectively, due from PCEC related to the administrative services agreement, employee-related costs and oil and natural gas sales made by PCEC on our behalf from certain properties.  For the three months ended March 31, 2015 and 2014, 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 $2.8 million and $2.5 million, respectively. At each of March 31, 2015 and December 31, 2014, we had receivables of $0.1 million due from certain of our other affiliates, primarily representing investments in natural gas processing facilities, for management fees due from them and operational expenses incurred on their behalf. The net related party payable at March 31, 2015 of $0.1 million is included in accounts payable on the consolidated balance sheet, and the net related party receivable at December 31, 2014 of $2.5 million is included in related party receivables on the consolidated balance sheet.    

5. Impairments

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

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

        If we determine that an impairment charge for a property is warranted, an impairment charge is recorded for the amount that the property’s carrying value exceeds the amount of its estimated discounted future cash flows. For purposes of calculating an impairment charge, estimated discounted future cash flows are determined by using applicable basis adjusted five-year NYMEX forward strip prices and escalated along with expenses and capital starting in year six and thereafter at 2% per year.  Production and development cost estimates (e.g. operating expenses and development capital) are conformed to reflect the commodity price strip used.  The associated property’s expected future net cash flows are discounted using a market-based weighted average cost of capital rate that currently approximates 10%.  We consider the inputs for our impairment calculations to be Level 3 inputs.  The impairment reviews and calculations are based on assumptions that are consistent with our business plans.

        Impairments of proved properties totaled $59.1 million for the three months ended March 31, 2015, including $33.1 million for our Permian properties, $16.7 million for our Rockies natural gas properties and $9.3 million for our Mid-Continent properties, primarily due to the impact that the decrease in oil and natural gas prices during three months ended March 31, 2015 had on certain of our low margin properties.
       
        Given the number of assumptions involved in the estimates, an estimate as to the sensitivity to earnings for these periods if other assumptions had been used in impairment reviews and calculations is not practicable. Favorable changes to some

16


assumptions might have avoided the need to impair any assets in this period, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.

6. Other Assets

As of March 31, 2015, and December 31, 2014, our other long-term assets were $108.2 million and $157.0 million, respectively, including $50.5 million and $52.8 million, respectively, in debt issuance costs, $19.6 million and $19.3 million, respectively, in available-for-sale securities and $9.1 million and $5.1 million, respectively in other long-term assets. At each of March 31, 2015 and December 31, 2014, we had a net profits interest obligation for the Jay Field in Florida of $18.3 million (assumed in the QRE Merger) and a property reclamation deposit for future abandonment and remediation obligations for the Jay Field of $10.7 million. In addition, we had zero and $50.8 million, respectively, in CO2 supply advances and deposits for our Mid-Continent properties as of March 31, 2015, and December 31, 2014. In connection with the CO2 Acquisition, we reclassified the $50.8 million of CO2 supply advances and deposits from other long-term assets to other property, plant and equipment on the consolidated balance sheet. See Note 2 for a discussion of the CO2 Acquisition.

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

 
 
As of
Thousands of dollars
 
March 31, 2015
 
December 31, 2014
Credit facility
 
$
2,218,000

 
$
2,194,500

Promissory note
 
2,700

 
1,100

8.625% Senior Notes due 2020
 
305,000

 
305,000

7.875% Senior Notes due 2022
 
850,000

 
850,000

Net premium on Senior Notes
 
1,532

 
1,560

Total debt
 
3,377,232

 
3,352,160

Less: current portion of long-term debt
 

 
(105,000
)
Total long-term debt
 
$
3,377,232

 
$
3,247,160


Credit Facility

As of March 31, 2015, BOLP, our wholly-owned subsidiary, as borrower, and we and our wholly-owned subsidiaries, as guarantors, had a $5.0 billion revolving credit facility with Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and Issuing Lender, and a syndicate of banks (the “Third Amended and Restated Credit Agreement”) with a maturity date of November 19, 2019.

Our credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria. Historically, our borrowing base has been redetermined semi-annually. As of March 31, 2015, our borrowing base was $2.5 billion. At December 31, 2014, our borrowing base was $2.5 billion. Our next borrowing base redetermination was scheduled for April 2015. See Note 16 for a discussion of the First Amendment to the Third Amended and Restated Credit Agreement, which established a revised borrowing base of $1.8 billion.

As of March 31, 2015 and December 31, 2014, we had $2.22 billion and $2.19 billion, respectively, in indebtedness outstanding under our credit facility. At March 31, 2015, the 1-month LIBOR interest rate plus an applicable spread was 2.4135% on the 1-month LIBOR portion of $2.196 billion and the prime rate plus an applicable spread was 4.50% on the prime portion of $22.0 million. At March 31, 2015 and December 31, 2014, we had $32.0 million and $33.5 million, respectively, of unamortized debt issuance costs related to our credit facility.

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


17


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 $302.2 million, net of unamortized discount of $2.8 million, as of March 31, 2015. 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 $854.3 million, net of unamortized premium of $4.3 million, as of March 31, 2015. At March 31, 2015 and December 31, 2014, we had $18.5 million and $19.3 million, respectively, 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 March 31, 2015, the fair value of our 2020 Senior Notes and 2022 Senior Notes were estimated to be $229.0 million and $615.5 million, respectively, based on prices quoted from third-party financial institutions. We consider the inputs to the valuation of our Senior Notes to be Level 2, as fair value was estimated based on prices quoted from third-party financial institutions.

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

See Note 16 for a discussion of our senior secured second lien notes issued in April 2015.

Interest Expense

Our interest expense is detailed as follows:
 
 
Three Months Ended
 
 
March 31,
Thousands of dollars
 
2015
 
2014
Credit agreement (including commitment fees)
 
$
13,965

 
$
5,260

Senior notes
 
23,311

 
23,311

Amortization of net premium and deferred issuance costs
 
2,389

 
2,148

Capitalized interest
 

 
(61
)
Total
 
$
39,665

 
$
30,658


8. 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 two of our subsidiaries have guaranteed our Senior Notes, and our only non-guarantor subsidiaries, Breitburn Collingwood Utica LLC and ETSWDC, are minor subsidiaries.

In accordance with Rule 3-10 of Regulation S-X, we are not presenting condensed consolidating financial statements as we have no independent assets or operations; Breitburn Finance Corporation, the subsidiary co-issuer that does not guarantee 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,

18


(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.

9.  Asset Retirement Obligations

ARO is based on our net ownership in wells and facilities and our estimate of the costs to abandon and remediate those wells and facilities together with our estimate of the future timing of the costs to be incurred.  Payments to settle ARO occur over the operating lives of the assets, estimated to range from less than one year to 50 years.  Estimated cash flows have been discounted at our credit-adjusted risk-free rate of approximately 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 March 31, 2015, and the year ended December 31, 2014 are presented in the following table:
 
 
Three Months Ended
 
Year Ended
Thousands of dollars
 
March 31, 2015
 
December 31, 2014
Carrying amount, beginning of period
 
$
238,411

 
$
123,769

Acquisitions
 
267

 
95,800

Liabilities incurred
 
1,882

 
4,020

Liabilities settled
 
(2,436
)
 
(1,708
)
Revisions
 
1,184

 
6,770

Accretion expense
 
4,119

 
9,760

Carrying amount, end of period
 
243,427

 
238,411

Less: current portion of ARO
 
(4,388
)
 
(4,948
)
Non-current portion of ARO
 
$
239,039

 
$
233,463


10.  Pensions and Postretirement Benefits

ETSWDC sponsors a non-contributory defined benefit pension plan and a contributory postretirement benefit plan covering substantially all ETSWDC employees who were employed prior to March 31, 2008.

The components of net periodic benefit costs are reflected in our consolidated statements of operations for the three months ended March 31, 2015 consist of the following:

Thousands of dollars
 
Pension Benefits
 
Postretirement Benefits
Service cost
 
$
67

 
$
9

Interest cost
 
254

 
39

Expected return on plan assets
 
(336
)
 
(25
)
Net periodic benefit costs (income)
 
$
(15
)
 
$
23


11.  Commitments and Contingencies

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

19


approximately $22.5 million and $21.1 million, respectively, of surety bonds. At each of March 31, 2015 and December 31, 2014, we had approximately $26.5 million in letters of credit outstanding.

Legal Proceedings

On January 31, 2014, BOLP received a Notice of Violation from the South Coast Air Quality Management District (“District”) alleging violations of the District’s truck loading limits for crude oil at our Santa Fe Springs facility. We have been engaged in discussions with the District to reach a resolution of this matter and expect to settle the matter for the payment of no more than $170,000. We do not believe that the outcome of this matter will materially impact the Partnership’s liquidity, financial position or future results of operations. Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings.

12.  Partners’ Equity

Preferred Units

On May 21, 2014, we sold 8.0 million 8.25% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”) in a public offering at a price of $25.00 per Series A Preferred Unit, resulting in proceeds of $193.2 million net of underwriting discount and offering expenses of $6.8 million. The Series A Preferred Units rank senior to the Common Units with respect to the payment of current distributions. We pay cumulative distributions in cash on the Series A Preferred Units on a monthly basis at a monthly rate of $0.171875 per Series A Preferred Unit. During the three months ended March 31, 2015, we recognized $4.1 million of accrued distributions on the Series A Preferred Units, which are included in distributions to preferred unitholders on the consolidated statements of operations.

See Note 16 for a discussion of Series B perpetual convertible preferred units issued in April 2015.

Common Units

At each of March 31, 2015 and December 31, 2014, we had approximately 210.9 million Common Units outstanding.  
    
Pursuant to an Equity Distribution Agreement dated as of March 19, 2014 (the “Equity Distribution Agreement”), we may sell, from time to time up to $200 million in Common Units. We intend to use the net proceeds of any sales pursuant to the Equity Distribution Agreement, after deducting commissions and offering expenses, for general purposes, which may include, among other things, repayment of indebtedness, acquisitions, capital expenditures and additions to working capital. The Common Units to be issued are registered under a previously filed shelf registration statement on Form S-3, which was declared effective by the SEC on January 22, 2014.  During the three months ended March 31, 2014, we sold 25,300 Common Units under the Equity Distribution Agreement for net proceeds of $0.5 million. We did not sell any common units under this agreement during the three months ended March 31, 2015.

During each of the three months ended March 31, 2015 and 2014, we issued less than 0.1 million Common Units, respectively, to non-employee directors for Restricted Phantom Units (“RPUs”) that vested in January 2015 and January 2014, respectively.

At March 31, 2015 and December 31, 2014, there were approximately 6.3 million and 1.8 million, respectively, of units outstanding under our Long-Term Incentive Plan (“LTIP”) that were eligible to be paid in Common Units upon vesting.

During the three months ended March 31, 2015, we paid three monthly cash distributions totaling approximately $52.7 million, or $0.2499 per Common Unit.

During the three months ended March 31, 2014, we paid cash distributions of approximately $58.7 million, or $0.4926 per Common Unit.

During the three months ended March 31, 2015, we paid $1.4 million 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 ended March 31, 2014, we paid $0.9 million 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.

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Earnings per Common Unit

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

The following is a reconciliation of net loss and weighted average units for calculating basic net loss per common unit and diluted net loss per common unit.
 
 
Three Months Ended
 
 
March 31,
Thousands, except per unit amounts
 
2015
 
2014
Net loss attributable to the partnership
 
$
(58,825
)
 
$
(9,758
)
Less:
 
 
 
 
Net loss attributable to participating units
 
(1,432
)
 
(138
)
Distributions to preferred unitholders
 
4,125

 

Net loss attributable to Common Unitholders
 
$
(61,518
)
 
$
(9,620
)
 
 
 
 
 
Weighted average number of units used to calculate basic and diluted net loss per unit:
 
 
 
 
Common Units
 
210,931

 
119,206

Dilutive units (a)
 

 

Denominator for diluted net loss per unit
 
210,931

 
119,206

 
 
 
 
 
Net loss per common unit
 
 
 
 
Basic
 
$
(0.29
)
 
$
(0.08
)
Diluted
 
$
(0.29
)
 
$
(0.08
)

(a) The three months ended March 31, 2015 and 2014, exclude 706 and 680, respectively, of weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit, as we were in a loss position.

13. Accumulated Other Comprehensive Loss

Changes in accumulated other comprehensive loss by component, net of tax, were as follows:
 
 
Gain (loss) on
 
 
Thousands of dollars
 
Available-For-Sale Securities
 
Postretirement Benefits
 
Total
Accumulated comprehensive loss attributable to the partnership as of December 31, 2014
 
$
(112
)
 
$
(280
)
 
$
(392
)
 
 
 
 
 
 
 
Other comprehensive income before reclassification
 
195

 

 
195

Amounts reclassified from accumulated other comprehensive loss (a)
 
(22
)
 

 
(22
)
Net current period other comprehensive income
 
173

 

 
173

Less: noncontrolling interest
 
70

 

 
70

Accumulated comprehensive loss attributable to the Partnership
 
$
(9
)
 
$
(280
)
 
$
(289
)

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

21



14.  Unit Based Compensation Plans

Unit-based compensation expense for the three months ended March 31, 2015 and 2014 was $7.7 million and $6.5 million, respectively. Unit based compensation expense for the three months ended March 31, 2015 included $6.9 million included in general and administrative expenses and $0.8 million included in restructuring costs (see Note 15).

During the three months ended March 31, 2015, the board of directors of Breitburn GP LLC, our general partner (“General Partner”) approved the grant of approximately 4.6 million RPUs and CPUs to employees of Breitburn Management under our LTIP.  Our outside directors were issued 0.2 million RPUs under our LTIP during the three months ended March 31, 2015.  The fair market value of the RPUs granted during 2015 for computing compensation expense under FASB Accounting Standards averaged $6.56 per unit.

During the three months ended March 31, 2015 and 2014, we paid $0.7 million and $0.9 million for taxes withheld on RPUs. 

As of March 31, 2015, we had $44.5 million of unrecognized compensation costs for all outstanding awards, which is expected to be recognized over the period from April 1, 2015 to December 31, 2017.

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

15.  Restructuring Costs

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

Thousands of dollars
 
2015
Beginning Balance
 
$

Severance payments
 
3,815

Unit-based compensation expense
 
814

Other termination costs
 
289

Ending Balance
 
$
4,918


16.  Subsequent Events

Financing and Related Party Transactions with EIG Global Energy Partners

On April 8, 2015 (the “Closing Date”), we issued in private offerings $350 million of 8.0% Series B perpetual convertible preferred units (“Series B Preferred Units”) to EIG Redwood Equity Aggregator, LP (“EIG Equity”), ACMO BBEP Corp. (“ACMO”) and certain other purchasers at an issue price of $7.50 per unit and $650 million of 9.25% senior secured second lien notes due 2020 (“Senior Secured Notes”) to EIG Redwood Debt Aggregator, LP and certain other purchasers at a purchase price of 97% of the principal amount. We received approximately $946 million from these offerings, net of fees and estimated expenses, $930 million of which we used to repay borrowings under our credit facility.

Effective on the Closing Date, Kurt A. Talbot, Vice Chairman and Co-Head of the Investment Committee of EIG Global Energy Partners (“EIG”), was appointed to the board of our General Partner. We paid EIG Management Company, LLC, an

22


affiliate of EIG, a transaction fee of $7 million with respect to the purchase of the Series B Preferred Units and a transaction fee of $13 million with respect to the purchase of the Senior Secured Notes.

On the Closing Date, the Partnership entered into a registration rights agreement (“Registration Rights Agreement”) with purchasers of the Series B Preferred Units, including EIG Equity, relating to the registered resale of (1) the Series B Preferred Units, including paid in kind units, and (2) common units issuable upon conversion of the Series B Preferred Units, including paid in kind units. In certain circumstances, the purchasers of Series B Preferred Units will have piggyback registration rights and rights to request an underwritten offering as described in the Registration Rights Agreement.

First Amendment to Third Amended and Restated Credit Agreement

In connection with these offerings, on the Closing Date, we entered into the First Amendment to the Third Amended and Restated Credit Agreement. Among other changes, the First Amendment: (i) establishes a borrowing base of $1.8 billion until the April 1, 2016 scheduled redetermination date subject, starting with the October 1, 2015 scheduled redetermination date, to our having liquidity (inclusive of borrowing base availability) of 10% of the borrowing base; (ii) permits $650 million of second lien indebtedness; (iii) increases the base rate and LIBOR margins by 0.25%; (iv) adds a requirement that we have liquidity (inclusive of borrowing base availability) of 10% of the borrowing base after giving effect to any distribution on our common units or voluntary prepayment of second lien indebtedness; and (v) adds a requirement that we have liquidity (inclusive of borrowing base availability) of 5% of the borrowing base after giving effect to any distribution on our Series B Preferred Units. Our credit facility borrowings as of May 4, 2015 were $1.32 billion.

Distributions

On April 1, 2015, we announced a cash distribution to holders of Common Units for the first monthly payment attributable to the first quarter of 2015 at the rate of $0.04166 per Common Unit, which was paid on April 17, 2015 to the unitholders of record at the close of business on April 13, 2015. On April 24, 2015, we announced a cash distribution to unitholders for the second monthly payment attributable to the first quarter of 2015 at the rate of $0.04166 per Common Unit, to be paid on May 15, 2015 to the unitholders of record at the close of business on May 11, 2015.

On April 1, 2015, we declared a cash distribution for our Series A Preferred Units of $0.171875 per Series A Preferred Unit, which is expected to be paid on May 15, 2015 to record holders of our Series A Preferred Units at the close of business on April 30, 2015. On April 24, 2015, we declared a cash distribution for our Series A Preferred Units of $0.171875 per Series A Preferred Unit, which is expected to be paid on June 15, 2015 to record holders of our Series A Preferred Units at the close of business on May 29, 2015. The monthly distribution rate is equal to an annual distribution of $2.0625 per Series A Preferred Unit. On April 24, 2015, we also declared a distribution on our Series B Preferred Units (which we elected to pay in kind by issuing additional Series B Preferred Units) of 0.008222 Series B Preferred Unit per unit, payable on May 15, 2015, to record holders of our Series B Preferred Units at the close of business on April 30, 2015.

Amendment No. 5 to Administrative Services Agreement

On May 1, 2015, Breitburn Management and PCEC entered into Amendment No. 5 to the Administrative Services Agreement (“ASA”), extending the term of the ASA to December 31, 2016; provided, however, in the event PCEC has not received certain permits by December 31, 2015, PCEC may terminate the ASA effective as of June 30, 2016 by giving prior written notice to Breitburn Management of its intention to terminate the ASA by December 31, 2015.



23


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

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

Overview

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

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

2015 Highlights

During the three months ended March 31, 2015, we paid three monthly cash distributions at the rate of $0.0833 per Common Unit per month, totaling approximately $52.7 million, or $0.2499 per Common Unit. On April 1, 2015 and April 24, 2015, we announced cash distribution to holders of Common Units for the first and second monthly payments attributable to the first quarter of 2015, respectively, at the rate of $0.04166 per Common Unit per month.
    
During the three months ended March 31, 2015, we recognized $4.1 million of accrued distributions on the Series A Preferred Units. On April 1, 2015 and April 24, 2015, we declared cash distributions for our Series A Preferred Units of $0.171875 per Series A Preferred Unit, which are expected to be paid on May 15, 2015 and June 15, 2015, respectively.

On March 31, 2015, we completed the acquisition of certain CO2 properties located in Harding County, New Mexico for a total preliminary purchase price of $64.2 million, subject to customary purchase price adjustments, of which, $14.3 million was paid during the three months ended March 31, 2015.

On April 8, 2015, we issued $350 million of Series B Perpetual Convertible Preferred Units (“Series B Preferred Units”) and $650 million of 9.25% Senior Secured Second Lien Notes due 2020 (“Senior Secured Notes”) in private offerings to investment funds managed by EIG and other purchasers. We received approximately $946 million from these offerings, net of fees and estimated expenses, $930 million of which we used to repay borrowings under our credit facility. On April 24, 2015, we declared a distribution on our Series B Preferred Units (which we elected to pay in kind by issuing additional Series B Preferred Units) of 0.008222 Series B Preferred Unit per unit.

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

Operational Focus and Capital Expenditures

In the first three months of 2015, our oil, NGL and natural gas capital expenditures, including capitalized engineering costs, totaled $73 million, compared to approximately $79 million in the first three months of 2014.  We spent approximately $28 million in the Permian Basin, $16 million in Florida, $15 million in Ark-La-Tex, $6 million in Mid-Continent, $6 million in California, $1 million in the Rockies and $1 million in MI/IN/KY.  In the first three months of 2015, we drilled and completed four operated productive wells and participated in the drilling of 16 non-operated wells in the Permian Basin,

24


drilled and completed seven productive wells in Ark-La-Tex, five productive wells in California, two productive wells in the Rockies and one productive well in Mid-Continent. We also performed workovers on 14 wells in Ark-La-Tex, two wells in California, two wells in Florida and one well in the Permian Basin.

In 2015, our crude oil, NGL and natural gas capital spending program, including capitalized engineering costs and excluding acquisitions, is expected to be approximately $200 million. This compares with approximately $389 million in 2014. In 2015, we anticipate spending approximately 89% principally on oil projects in Mid-Continent, Ark-La-Tex, Florida and the Permian Basin and approximately 11% principally on oil projects in California, the Rockies and MI/IN/KY. We anticipate 84% of our total capital spending will be focused on drilling and rate-generating projects and CO2 purchases that are designed to increase or add to production or reserves. In 2015, we plan to drill 53 wells in Mid-Continent, Ark-La-Tex, Florida and the Permian Basin.

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

Commodity Prices

In the first quarter of 2015, the NYMEX WTI spot price averaged $48 per barrel, compared with approximately $99 per barrel in the first quarter of 2014.  In the first three months of 2015, the NYMEX WTI spot price ranged from a low of $43 per barrel to a high of $54 per barrel. The NYMEX WTI spot price decreased from $108 per barrel at June 20, 2014 to $43 per barrel at March 17, 2015. 
 
In the first quarter of 2015, the Henry Hub natural gas spot price averaged $2.90 per MMBtu compared with approximately $5.18 per MMBtu in the first quarter of 2014.  In the first three months of 2015, the Henry Hub natural gas spot price ranged from a low of $2.62 per MMBtu to a high of $3.32 per MMBtu.  In the first quarter of 2015, the MichCon natural gas spot price averaged $3.29 per MMBtu compared with approximately $7.68 per MMBtu in the first quarter of 2014.  The Henry Hub natural gas spot price decreased from $8.15 per barrel at February 10, 2014 to $2.62 per barrel at February 9, 2015.

Lower crude oil and natural gas prices prices may not only decrease our revenues, but may also reduce the amount of crude oil and natural gas that we can produce economically and therefore potentially lower our crude oil reserves.

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 ended March 31, 2015, the monthly fee paid by PCEC for indirect expenses was $700,000. The term of the Agreement is set to expire on December 31, 2016, at which time, the agreement is subject to renegotiation.



25


Results of Operations

The table below summarizes certain of our results of operations for the periods indicated.  The data for the periods reflect our results as they are presented in our unaudited consolidated financial statements included elsewhere in this report.

 
 
Three Months Ended March 31,
 
Increase/
 
 
Thousands of dollars, except as indicated
 
2015
 
2014
 
(Decrease)
 
%

Total production (MBoe)
 
5,051

 
3,219

 
1,832

 
57
 %
     Oil (MBbl)
 
2,890

 
1,799

 
1,091

 
61
 %
     NGLs (MBbl)
 
459

 
258

 
201

 
78
 %
     Natural gas (MMcf)
 
10,211

 
6,971

 
3,240

 
46
 %