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EX-32.2 - EXHIBIT 32.2 - Breitburn Energy Partners LPq3201610-qex322.htm
EX-32.1 - EXHIBIT 32.1 - Breitburn Energy Partners LPq3201610-qex321.htm
EX-31.2 - EXHIBIT 31.2 - Breitburn Energy Partners LPq3201610-qex312.htm
EX-31.1 - EXHIBIT 31.1 - Breitburn Energy Partners LPq3201610-qex311.htm
EX-10.5 - EXHIBIT 10.5 - Breitburn Energy Partners LPq3201610-qex105.htm
EX-10.4 - EXHIBIT 10.4 - Breitburn Energy Partners LPq3201610-qex104.htm
EX-10.3 - EXHIBIT 10.3 - Breitburn Energy Partners LPq3201610-qex103.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, 2016
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)
 
 
707 Wilshire Boulevard, Suite 4600
 
Los Angeles, California
90017
(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 7, 2016, the registrant had 213,789,296 Common Units outstanding.

 
 
 
 
 
 



INDEX

 
 
Page No.
 
 
 
 
 
 
PART I
 
 
FINANCIAL INFORMATION
 
 
 
 
 
 
 Consolidated Balance Sheets (Unaudited) at September 30, 2016 and December 31, 2015
 
Consolidated Statements of Operations (Unaudited) for the Three Months and Nine Months Ended September 30, 2016 and 2015
 
– Consolidated Statements of Comprehensive Loss (Unaudited) for the Three Months and Nine Months Ended September 30, 2016 and 2015
 
 Consolidated Statements of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2016 and 2015
 
– Condensed Notes to the Consolidated Financial Statements
 
 
 
 
PART II
 
 
OTHER INFORMATION
 
 
 
 
 
 
 
 
 



CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are changes in crude oil, natural gas liquids (“NGL”) and natural gas prices, including further or sustained declines in the prices we receive for our production; risks and uncertainties associated with the restructuring process, including our inability to develop, confirm and consummate a plan under Chapter 11 of the Bankruptcy Code or an alternative restructuring transaction; inability to maintain our relationships with suppliers, customers, other third parties or our employees as a result of the restructuring process; 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; ability to continue to borrow under our debtor-in-possession credit agreement; ability to generate sufficient cash flows from operations to meet the internally funded portion of any capital expenditures budget; changes in our business strategy; ability to obtain external capital to finance exploitation and development operations and acquisitions; the potential need to sell certain assets, restructure our debt or raise additional capital; our future levels of indebtedness, liquidity, compliance with financial covenants and our ability to continue as a going concern; 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, 2015 (our “2015 Annual Report”), under Part II—Item 1A of our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2016 and June 30, 2016 and under 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


GLOSSARY AND DESCRIPTION OF REFERENCES

Unless the context otherwise requires, references in this report to the following terms have the meanings set forth below. This “Glossary and Description of References” should be read in conjunction with the “Glossary of Oil and Gas Terms; Description of References” included in our Annual Report on Form 10-K for the year ended December 31, 2015.  

Bankruptcy Code: United States Bankruptcy Code

Bankruptcy Court: United States Bankruptcy Court for the Southern District of New York

Chapter 11: Chapter 11 of the United States Bankruptcy Code

Debtors: Breitburn Energy Partners LP and certain of its affiliates, including Breitburn Management Company LLC, Breitburn Operating GP LLC, Breitburn Operating LP, Breitburn Finance Corporation, Breitburn GP LLC, Breitburn Sawtelle LLC, Breitburn Oklahoma LLC, Phoenix Production Company, QR Energy, LP, QRE GP, LLC, QRE Operating, LLC, Breitburn Transpetco LP LLC, Breitburn Transpetco GP LLC, Transpetco Pipeline Company, L.P., Terra Energy Company LLC, Terra Pipeline Company LLC, Breitburn Florida LLC, Mercury Michigan Company, LLC, Beaver Creek Pipeline, L.L.C., GTG Pipeline LLC and Alamitos Company, who filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code on May 15, 2016

DIP Credit Agreement: Debtor-in-Possession Credit Agreement, dated as of May 19, 2016, by and among Breitburn Operating LP, as borrower, Breitburn Energy Partners LP, as parent guarantor, the financial institutions from time to time party thereto and Wells Fargo Bank, National Association, as administrative agent, swing line lender and issuing lender

Non-Debtors: East Texas Salt Water Disposal Company (“ETSWDC”) and Breitburn Collingwood Utica LLC



2


PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements
Breitburn Energy Partners LP and Subsidiaries (Debtor-in-Possession)
Consolidated Balance Sheets
(Unaudited)
Thousands of dollars
 
September 30,
2016
 
December 31,
2015
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash
 
$
99,403

 
$
10,464

Accounts and other receivables, net (note 4)
 
538,381

 
128,589

Derivative instruments (note 4)
 

 
439,627

Related party receivables (note 5)
 
899

 
2,274

Inventory
 
1,363

 
926

Prepaid expenses
 
9,561

 
6,447

Total current assets
 
649,607

 
588,327

Equity investments
 
6,932

 
6,567

Property, plant and equipment
 
 
 
 
Oil and natural gas properties (note 3)
 
7,890,335

 
7,898,117

Other property, plant and equipment (note 3)
 
194,782

 
188,795

 
 
8,085,117

 
8,086,912

Accumulated depletion, depreciation, and impairment (note 6)
 
(4,614,159
)
 
(4,154,030
)
Net property, plant and equipment
 
3,470,958

 
3,932,882

Other long-term assets
 
 
 
 
Derivative instruments (note 4)
 

 
226,764

Other long-term assets (note 7)
 
62,357

 
80,847

Total assets
 
$
4,189,854

 
$
4,835,387

LIABILITIES AND EQUITY
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable
 
$
39,931

 
$
50,412

Current portion of long-term debt (note 8)
 
1,198,259

 
154,000

Derivative instruments (note 4)
 

 
4,462

Distributions payable
 

 
733

Current portion of asset retirement obligation
 
3,915

 
2,341

Revenue and royalties payable
 
36,156

 
35,462

Wages and salaries payable
 
12,552

 
21,654

Accrued interest payable
 
20,889

 
19,517

Production and property taxes payable
 
19,371

 
24,292

Other current liabilities
 
18,111

 
5,133

Total current liabilities
 
1,349,184

 
318,006

 
 
 
 
 
Liabilities subject to compromise (note 2)
 
1,878,940

 

 
 
 
 
 
Credit facility
 

 
1,075,000

Senior notes, net
 

 
1,752,194

Other long-term debt
 
3,094

 
3,148

Total long-term debt (note 8)
 
3,094

 
2,830,342

Deferred income taxes
 
3,040

 
3,844

Asset retirement obligation (note 10)
 
255,514

 
252,037

Derivative instruments (note 4)
 

 
255

Other long-term liabilities
 
22,211

 
25,008

Total liabilities
 
3,511,983

 
3,429,492

Commitments and contingencies (note 11)
 


 


Equity
 
 
 
 
Series A preferred units, 8.0 million units issued and outstanding at each of September 30, 2016 and December 31, 2015 (note 12)
 
193,215

 
193,215

Series B preferred units, 49.6 million and 48.8 million units issued and outstanding at September 30, 2016 and December 31, 2015, respectively (note 12)
 
359,611

 
353,471

Common units, 213.8 million and 213.5 million units issued and outstanding at September 30, 2016 and December 31, 2015, respectively (note 12)
 
118,367

 
852,114

Accumulated other comprehensive loss (note 13)
 
(74
)
 
(229
)
Total partners' equity
 
671,119

 
1,398,571

Noncontrolling interest
 
6,752

 
7,324

Total equity
 
677,871

 
1,405,895

Total liabilities and equity
 
$
4,189,854

 
$
4,835,387


See accompanying notes to consolidated financial statements.

3


Breitburn Energy Partners LP and Subsidiaries (Debtor-In-Possession)
Consolidated Statements of Operations
(Unaudited)

 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
Thousands of dollars, except per unit amounts
 
2016
 
2015
 
2016
 
2015
Revenues and other income items
 
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquid sales
 
$
129,259

 
$
153,325

 
$
361,991

 
$
505,584

Gain (loss) on commodity derivative instruments, net (note 4)
 

 
253,012

 
(54,287
)
 
296,772

Other revenue, net
 
4,310

 
5,922

 
13,265

 
18,895

Total revenues and other income items
 
133,569

 
412,259

 
320,969

 
821,251

 
 
 
 
 
 
 
 
 
Operating costs and expenses
 
 
 
 
 
 
 
 
Operating costs
 
90,135

 
115,135

 
268,904

 
348,950

Depletion, depreciation and amortization
 
81,083

 
117,464

 
246,766

 
336,735

Impairment of oil and natural gas properties (note 6)
 
274,968

 
1,440,167

 
277,761

 
1,499,280

Impairment of goodwill (note 6)
 

 

 

 
95,947

General and administrative expenses
 
21,897

 
23,276

 
59,581

 
78,400

Restructuring costs (note 15)
 
(959
)
 
(278
)
 
4,289

 
6,413

Loss (gain) on sale of assets
 
413

 
(7,459
)
 
(11,849
)
 
(7,322
)
Total operating costs and expenses
 
467,537

 
1,688,305

 
845,452

 
2,358,403

 
 
 
 
 
 
 
 
 
Operating loss
 
(333,968
)
 
(1,276,046
)
 
(524,483
)
 
(1,537,152
)
 
 
 
 
 
 
 
 
 
Interest expense, net of capitalized interest
 
20,982

 
50,919

 
126,888

 
151,988

Loss on interest rate swaps (note 4)
 
211

 
996

 
2,021

 
3,411

Other income, net
 
(173
)
 
(137
)
 
(21
)
 
(579
)
Reorganization items, net (note 2)
 
10,665

 

 
77,562

 

 
 
 
 
 
 
 
 
 
Loss before taxes
 
(365,653
)
 
(1,327,824
)
 
(730,933
)
 
(1,691,972
)
 
 
 
 
 
 
 
 
 
Income tax (benefit) expense
 
(830
)
 
14

 
(554
)
 
365

 
 
 
 
 
 
 
 
 
Net loss
 
(364,823
)
 
(1,327,838
)
 
(730,379
)
 
(1,692,337
)
 
 
 
 
 
 
 
 
 
Less: Net (loss) income attributable to noncontrolling interest
 
(223
)
 
91

 
(678
)
 
124

 
 
 
 
 
 
 
 
 
Net loss attributable to the partnership
 
(364,600
)
 
(1,327,929
)
 
(729,701
)
 
(1,692,461
)
 
 
 
 
 
 
 
 
 
Less: Distributions to Series A preferred unitholders
 

 
4,125

 
6,142

 
12,375

Less: Non-cash distributions to Series B preferred unitholders
 
621

 
7,145

 
11,744

 
13,553

Less: Distributions on participating units in excess of earnings
 

 
428

 

 
1,731

 
 
 
 
 
 
 
 
 
Net loss used to calculate basic and diluted net loss per unit
 
$
(365,221
)
 
$
(1,339,627
)
 
$
(747,587
)
 
$
(1,720,120
)
 
 
 
 
 
 
 
 
 
Basic net loss per common unit (note 12)
 
$
(1.71
)
 
$
(6.33
)
 
$
(3.50
)
 
$
(8.14
)
Diluted net loss per common unit (note 12)
 
$
(1.71
)
 
$
(6.33
)
 
$
(3.50
)
 
$
(8.14
)
 
 
 
 
 
 
 
 
 
Weighted average number of units used to calculate basic and diluted net loss per unit (in thousands):
 
 
 
 
 
 
 
 
Basic
 
213,789

 
211,766

 
213,743

 
211,369

Diluted
 
213,789

 
211,766

 
213,743

 
211,369


See accompanying notes to consolidated financial statements.

4


Breitburn Energy Partners LP and Subsidiaries (Debtor-In-Possession)
Consolidated Statements of Comprehensive Loss
(Unaudited)

 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
Thousands of dollars, except per unit amounts
 
2016
 
2015
 
2016
 
2015
Net loss
 
$
(364,823
)
 
$
(1,327,838
)
 
$
(730,379
)
 
$
(1,692,337
)
 
 
 
 
 
 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
 
Change in fair value of available-for-sale securities (a)
 
321

 
(636
)
 
1,054

 
(537
)
Pension and post-retirement benefits actuarial loss (b)
 
(12
)
 

 
(793
)
 

Total other comprehensive income (loss)
 
309

 
(636
)
 
261

 
(537
)
 
 
 
 
 
 
 
 
 
Total comprehensive loss
 
(364,514
)
 
(1,328,474
)
 
(730,118
)
 
(1,692,874
)
 
 
 
 
 
 
 
 
 
Less: Comprehensive loss attributable to noncontrolling interest
 
(96
)
 
(303
)
 
(571
)
 
(229
)
 
 
 
 
 
 
 
 
 
Comprehensive loss attributable to the partnership
 
$
(364,418
)
 
$
(1,328,171
)
 
$
(729,547
)
 
$
(1,692,645
)

(a) Net of income tax expense of $0.2 million and income tax benefit of $0.4 million for the three months ended September 30, 2016 and 2015, respectively. Net of income tax expense of $0.5 million and income tax benefit of $0.3 million for the nine months ended September 30, 2016 and 2015, respectively.
(b) Net of income tax benefit of zero and $0.4 million for the three months and nine months ended September 30, 2016, respectively.

See accompanying notes to consolidated financial statements.

5


Breitburn Energy Partners LP and Subsidiaries (Debtor-In-Possession)
Consolidated Statements of Cash Flows
(Unaudited)

 
 
Nine Months Ended
 
 
September 30,
Thousands of dollars
 
2016
 
2015
Cash flows from operating activities
 
 
 
 
Net loss
 
$
(730,379
)
 
$
(1,692,337
)
Adjustments to reconcile to cash flows from operating activities:
 
 
 
 
Depletion, depreciation and amortization
 
246,766

 
336,735

Impairment of oil and natural gas properties
 
277,761

 
1,499,280

Impairment of goodwill
 

 
95,947

Unit-based compensation expense
 
12,649

 
20,714

Loss (gain) on derivative instruments
 
56,308

 
(293,361
)
Derivative instrument settlement receipts
 
172,199

 
351,518

Income from equity affiliates, net
 
(365
)
 
(10
)
Deferred income taxes
 
(804
)
 
(306
)
Gain on sale of assets
 
(11,849
)
 
(7,322
)
Non-cash reorganization items
 
49,148

 

Amortization and write-off of debt issuance costs
 
24,943

 
19,478

Other
 
3,441

 
(5,130
)
Changes in net assets and liabilities
 
 
 
 
Accounts receivable and other assets
 
15,047

 
22,251

Inventory
 
(437
)
 
356

Net change in related party receivables and payables
 
1,375

 
393

Accounts payable and other liabilities
 
68,603

 
2,978

Net cash provided by operating activities
 
184,406

 
351,184

Cash flows from investing activities
 
 
 
 
Property acquisitions
 
(7,525
)
 
(17,160
)
Capital expenditures
 
(59,001
)
 
(226,718
)
Proceeds from sale of assets
 
11,882

 
9,441

Proceeds from sale of available-for-sale securities
 
6,367

 
3,631

Purchases of available-for-sale securities
 
(6,959
)
 
(3,803
)
Other
 

 
(853
)
Net cash used in investing activities
 
(55,236
)
 
(235,462
)
Cash flows from financing activities
 
 
 
 
Proceeds from issuance of preferred units, net
 

 
337,895

Proceeds from issuance of common units, net
 

 
4,768

Distributions to preferred unitholders
 
(5,501
)
 
(12,375
)
Distributions to common unitholders
 

 
(108,283
)
Proceeds from issuance of long-term debt, net
 
38,260

 
1,203,400

Repayments of long-term debt
 
(69,001
)
 
(1,512,500
)
Principal payments on capital lease obligations
 
(39
)
 

Change in bank overdraft
 
(75
)
 
(39
)
Debtor-in-possession financing costs
 
(3,872
)
 

Debt issuance costs
 
(3
)
 
(29,125
)
Net cash used in financing activities
 
(40,231
)
 
(116,259
)
Increase (decrease) in cash
 
88,939

 
(537
)
Cash beginning of period
 
10,464

 
12,628

Cash end of period
 
$
99,403

 
$
12,091


See accompanying notes to consolidated financial statements.

6


Condensed Notes to Consolidated Financial Statements

1.  Organization and Basis of Presentation

The accompanying unaudited condensed consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2015 (“2015 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, 2016, our operating results for the three months and nine months ended September 30, 2016 and 2015 and our cash flows for the nine months ended September 30, 2016 and 2015 have been included.  Operating results for the three months and nine months ended September 30, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016.  The consolidated balance sheet at December 31, 2015 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 2015 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.

Chapter 11 Cases

On May 15, 2016 (the “Chapter 11 Filing Date”), we and certain of our subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York. See Note 2 for a discussion of the Chapter 11 Cases (as defined in Note 2).

Presentation

Certain reclassifications were made to the prior year’s consolidated financial statements to conform to the 2016 presentation. Other long-term debt on the consolidated balance sheet at December 31, 2015 was reported in our 2015 Annual Report as $2.9 million compared to $3.1 million in this report due to $0.2 million in capital lease obligations that were segregated from other long-term liabilities and reclassified to other long-term debt.

See Note 2 for a discussion of our liquidity and ability to continue as a going concern.

Changes in Accounting Principles

In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-03, Simplifying the Presentation of Debt Issuance Costs.  The objective of ASU 2015-03 is to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset.  In August 2015, the FASB issued ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. Under ASU 2015-15, a company may defer debt issuance costs associated with line-of-credit arrangements and present such costs as an asset, subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. Effective January 1, 2016, we adopted these standards, which required retroactive application and represented changes in accounting principles. The unamortized debt issuance costs of approximately $37.0 million associated with our outstanding Senior Notes (as defined in Note 8), which were formerly presented as a component of other long-term assets on the consolidated balance sheets, were reflected as a reduction to the carrying liability of our Senior Notes. Debt issuance costs associated with our Credit Agreement (as defined in Note 8) remained classified in other long-term assets.


7


As a result of these changes in accounting principles, the consolidated balance sheet at December 31, 2015 was adjusted as follows:
 
 
December 31, 2015
 
 
Previously
 
Effect of Adoption of
 
 
Thousands of dollars
 
Reported
 
Accounting Principle
 
As Adjusted
Assets:
 
 
 
 
 
 
Other long-term assets
 
$
117,872

 
$
(37,025
)
 
$
80,847

Total assets
 
4,872,412

 
(37,025
)
 
4,835,387

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Senior notes, net
 
$
1,789,219

 
$
(37,025
)
 
$
1,752,194

Total long-term debt
 
2,867,367

 
(37,025
)
 
2,830,342

Total liabilities
 
3,466,517

 
(37,025
)
 
3,429,492

Total liabilities and equity
 
4,872,412

 
(37,025
)
 
4,835,387


During the three months ended June 30, 2016, the unamortized debt issuance costs associated with our outstanding Senior Notes were expensed to reorganization items, net on the consolidated statement of operations (see Note 2 and Note 8).

Accounting Standards

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. ASU 2014-09 will supersede most of the existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which it expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires disclosures sufficient to enable users to understand an entity’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). The update provides clarifications in the assessment of principal versus agent considerations in the new revenue standard. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients. The update reduces the potential for diversity in practice at initial application of Topic 606 and the cost and complexity of applying Topic 606. In May 2016, the FASB issued ASU 2016-11, Revenue Recognition and Derivatives and Hedging: Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. This update rescinds certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities-Oil and Gas, effective upon adoption of Topic 606. These ASUs are effective for annual and interim periods beginning after December 15, 2017. We are assessing the impact that the adoption of these standards will have on our consolidated financial statements.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements — Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The amendments require management to perform interim and annual assessments of whether there are conditions or events that raise substantial doubt of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. Certain disclosures are required if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The guidance is effective for annual periods ending after December 15, 2016, and interim periods thereafter, and with early adoption permitted. The amendments will not impact our financial position or results of operations but will require management to perform a formal going concern assessment. We are reviewing our policies and procedures to ensure compliance with this new guidance.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The amendments provide guidance on financial instruments specifically related to (i) the classification and measurement of investments in equity securities, (ii) the presentation of certain fair value changes for financial liabilities measured at fair value and (iii) certain disclosure requirements associated with the fair value of financial instruments. ASU 2016-01 is effective for annual and interim periods beginning after December 15, 2017, with early adoption permitted. A cumulative-effect adjustment to beginning retained earnings is required as of the beginning of the fiscal year in which this ASU is adopted. The adoption of this ASU will not have a significant impact on our consolidated financial statements.


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In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires recognizing a right-of-use lease asset and a lease liability on the balance sheet. Lessees are permitted to make an accounting policy to elect not to recognize lease assets and lease liabilities for leases with a term of 12 months or less, and to recognize lease expense on a straight-line basis over the lease term. These new requirements become effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. We are assessing the impact that ASU 2016-02 will have on our consolidated financial statements.

In March 2016, the FASB issued ASU 2016-09, Compensation — Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The amendments simplify certain areas of accounting for share-based payment transactions, including classification of awards as either equity or liability, classification on the statement of cash flows, and election of accounting policy to estimate forfeitures or recognize forfeitures when they occur. The amendments are effective for annual and interim periods beginning after December 15, 2016. Early adoption is permitted, however, adoption of all of the amendments are required in the same period of adoption. We are assessing the impact that ASU 2016-09 will have on our consolidated financial statements.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses: Measurement of Credit Losses on Financial Instruments. The objective of this update is to provide more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. The amendments in this update replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. ASU 2016-13 is effective for annual and interim periods beginning after December 15, 2019, with early adoption permitted. We are assessing the impact that ASU 2016-13 will have on our consolidated financial statements.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. This update was issued to reduce diversity in practice of how certain cash receipts and cash payments are presented and classified in the statement of cash flows, including debt prepayment or debt extinguishment costs, proceeds from the settlement of insurance claims and distributions received from equity method investees. ASU 2016-15 is effective for annual and interim periods beginning after December 15, 2017, with early adoption permitted. We are assessing the impact that ASU 2016-15 will have on our consolidated financial statements.

2.  Chapter 11 Cases and Liquidity

Chapter 11 Cases

On May 15, 2016, we and 21 of our subsidiaries filed voluntary petitions for relief (collectively, the “Chapter 11 Petitions” and, the cases commenced thereby, the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court”). The Chapter 11 Cases are being jointly administered under the caption In re Breitburn Energy Partners LP, et al, Case No. 16-11390. No trustee has been appointed and we continue to manage ourselves and our affiliates and operate our businesses as “debtors in possession” subject to the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. To assure ordinary course operations, we received approval from the Bankruptcy Court on a variety of “first day” motions, including motions that authorize us to maintain our existing cash management system, to secure debtor-in-possession financing and other customary relief. In connection with the Chapter 11 Cases, Breitburn Operating LP (“BOLP”) entered into the Debtor-in-Possession Credit Agreement, dated as of May 19, 2016, among itself, as borrower, Breitburn Energy Partners LP, as parent guarantor, the financial institutions from time to time party thereto and Wells Fargo Bank, National Association, as administrative agent, swing line lender and issuing lender (the “DIP Credit Agreement”). See Note 8 for a discussion of the DIP Credit Agreement.

ASC 852-10, Reorganizations, applies to entities that have filed a petition for relief under Chapter 11 of the Bankruptcy Code. In accordance with ASC 852-10, transactions and events directly associated with the reorganization are required to be distinguished from the ongoing operations of the business. In addition, the guidance requires changes in the accounting and presentation of liabilities, as well as expenses and income directly associated with the Chapter 11 Cases.

The commencement of the Chapter 11 Cases resulted in the acceleration of the Debtors’ obligations under the Third Amended and Restated Credit Agreement, dated as of May 19, 2016, among BOLP, as borrower, Breitburn Energy Partners

9


LP, as parent guarantor, the lenders from time to time party thereto and Wells Fargo Bank, National Association, as administrative agent, swing line lender and issuing lender (as amended, the “Credit Agreement”), and the indentures governing our 9.25% Senior Secured Second Lien Notes due 2020 (“Senior Secured Notes”), our 8.625% Senior Notes due 2020 (“2020 Senior Notes”) and our 7.875% Senior Notes due 2022 (“2022 Senior Notes,” and together with the 2020 Senior Notes, the “Senior Unsecured Notes”). Any efforts to enforce such obligations are automatically stayed as a result of the filing of the Chapter 11 Petitions and the holders’ rights of enforcement in respect of these obligations are subject to the applicable provisions of the Bankruptcy Code. See Note 8 for a discussion of our Credit Agreement (which has been reclassified from long-term debt to current portion of long-term debt on our consolidated balance sheets) and our Senior Secured Notes and Senior Unsecured Notes (which have been reclassified from long-term debt to liabilities subject to compromise on our consolidated balance sheets).

We are making adequate protection payments with respect to the Credit Agreement, reflected in interest expense, net of capitalized interest on the consolidated statements of operations, consisting of the payment of interest (at the default rate) and the payment of all reasonable fees and expenses provided for in the Credit Agreement. We are also making adequate protection payments with respect to the Senior Secured Notes in the form of the payment of all reasonable fees and expenses of professionals retained by the holders of the Senior Secured Notes.

The commencement of the Chapter 11 Cases also resulted in a termination right by our counterparties on our commodity and interest rate derivative instruments. See Note 4 for a discussion of the derivative instruments, which were terminated, and resulted in $458.8 million in estimated hedge settlements receivable and $4.1 million in estimated hedge settlements payable, reflected in accounts and other receivables, net and other current liabilities on the consolidated balance sheet at September 30, 2016, respectively.

Effect of Filing on Creditors and Unitholders

On April 14, 2016, we elected to suspend the declaration of any further distributions on our Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”) and Series B Perpetual Convertible Preferred Units (“Series B Preferred Units”). In addition, we elected to defer a $33.5 million interest payment due with respect to our 2022 Senior Notes and a $13.2 million interest payment due with respect to our 2020 Senior Notes, with each such interest payment due on April 15, 2016 and subject to a 30-day grace period. As a consequence of the commencement of the Chapter 11 Cases, such interest payments have not been made, and are classified as liabilities subject to compromise on the consolidated balance sheet at September 30, 2016.

On May 15, 2016, we filed the Chapter 11 Petitions. Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities and post-petition liabilities must be satisfied in full before the holders of our Series A Preferred Units, Series B Preferred Units and common units representing limited partner interests in us (“Common Units”) are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or unitholders, if any, will not be determined until confirmation and implementation of a plan of reorganization. No assurance can be given as to what distributions, if any, will be made to each of these constituencies or the nature thereof. As discussed below, if certain requirements of the Bankruptcy Code are met, a plan of reorganization can be confirmed notwithstanding its rejection or deemed rejection by the holders of our Series A Preferred Units, Series B Preferred Units and Common Units and notwithstanding the fact that such holders do not receive or retain any property on account of their equity interests under the plan. Because of such possibilities, the value of our securities, including our Series A Preferred Units, Series B Preferred Units and Common Units, is highly speculative. There can be no assurance that the holders of our Series A Preferred Units, Series B Preferred Units and Common Units will retain any value under a plan of reorganization.

Executory Contracts. Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases, subject to the approval of the Bankruptcy Court. The rejection of an executory contract or unexpired lease is generally treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease, but may give rise to a pre-petition general unsecured claim for damages caused by such deemed breach. The assumption of an executory contract or unexpired lease generally requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance.

Process for Plan of Reorganization. In order to successfully emerge from Chapter 11, the Debtors will need to obtain confirmation by the Bankruptcy Court of a plan of reorganization that satisfies the requirements of the Bankruptcy Code. A plan of reorganization generally provides for how pre-petition obligations and equity interests will be treated in satisfaction and discharge thereof, and provides for the means by which the plan of reorganization will be implemented.


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Fresh Start Accounting. We may be required to adopt fresh start accounting upon emergence from Chapter 11. Adopting fresh start accounting would result in the allocation of the reorganization value to individuals assets based on their estimated fair values. The enterprise value of the equity of the emerging company is based on several assumptions and inputs contemplated in the future projections of the plan of reorganization and are subject to significant uncertainties. We currently cannot estimate the potential financial effect of fresh start accounting on our consolidated financial statements upon the emergence from Chapter 11, although we would expect to recognize material adjustments upon implementation of fresh-start accounting guidance upon emergence pursuant to a plan of reorganization. The assumptions for which there is a reasonable possibility of material impact affecting the reorganization value include management’s assumptions and capital expenditure plans related to the estimation of our oil and gas reserves.

Debtors Condensed Combined Financial Statements. Two of our subsidiaries, ETSWDC and Breitburn Collingwood Utica LLC, are non-debtors (“Non-Debtors”). Accordingly, these entities will be accounted for under GAAP for entities not in bankruptcy and outside the scope of ASC 852. The Non-Debtors are minor subsidiaries, and, as such, we have not presented Debtors Condensed Combined Financial Statements.

Costs of Reorganization

The Debtors have incurred and will continue to incur significant costs associated with the Chapter 11 Cases. The amount of these costs, which are being expensed as incurred, are expected to significantly affect our results. The following table summarizes the components included in reorganization items, net on our consolidated statements of operations for the three and nine months ended September 30, 2016:    
 
 
Three Months Ended
 
Nine Months Ended
Thousands of dollars
 
September 30, 2016
 
September 30, 2016
Debt discounts/premiums and issuance costs
 
$
2

 
$
48,831

Advisory and professional fees
 
10,047

 
24,010

DIP Credit Agreement debt issuance costs
 

 
4,172

Other
 
616

 
549

Reorganization items, net
 
$
10,665

 
$
77,562


We use this category to reflect the net expenses and gains and losses that are the result of the reorganization and restructuring of the business. Professional fees included in reorganization items, net represent professional fees for post-petition expenses. Deferred financing costs and unamortized discounts are related to the Senior Secured Notes and Senior Unsecured Notes (together, the “Senior Notes”), and are included in reorganization items, net as we believe these debt instruments will be impacted by the Chapter 11 Cases. As of September 30, 2016, we had $6.7 million of accrued reorganization costs included in accounts payable on the consolidated balance sheet, consisting primarily of advisory and professional fees.

Liabilities Subject to Compromise

Liabilities subject to compromise in our consolidated financial statements include pre-petition liabilities that may be affected by the plan of reorganization at the amounts expected to be allowed, even if they may be settled for lesser amounts. 
If there is uncertainty about whether a secured claim is under-secured, or will be impaired under the plan of reorganization, the entire amount of the claim is included in liabilities subject to compromise. Differences between liabilities we have estimated and the claims to be filed will be investigated and resolved in connection with the claims resolution process. We will continue to evaluate these liabilities throughout the Chapter 11 Cases and adjust amounts as necessary. Such adjustments may be material.

Our consolidated financial statements include amounts classified as liabilities subject to compromise that we believe the Bankruptcy Court will allow as claim amounts resulting from the Debtors’ rejection of various executory contracts and unexpired leases and defaults under the debt agreements. Additional amounts may be included in liabilities subject to compromise in future periods if other executory contracts and unexpired leases are rejected. Conversely, the Debtors expect that the assumption of certain executory contracts and unexpired leases may convert certain liabilities currently shown in our financial statements as subject to compromise to post-petition liabilities. Due to the uncertain nature of many of the potential claims, the magnitude of such claims is not reasonably estimable at this time. Such claims may be material.


11


The following table summarizes the components of liabilities subject to compromise included in our consolidated balance sheet as of September 30, 2016:

 
 
As of
Thousands of dollars
 
September 30, 2016
Senior Unsecured Notes
 
$
1,155,000

Senior Secured Notes
 
650,000

Accrued interest payable
 
61,908

Accounts payable
 
5,058

Distributions payable
 
6,974

Total liabilities subject to compromise
 
$
1,878,940


Liquidity and Ability to Continue as a Going Concern

As a result of sustained losses and the Chapter 11 Cases, the realization of assets and satisfaction of liabilities, without substantial adjustments and/or changes in ownership, are subject to uncertainty. Given uncertainty surrounding the Chapter 11 Cases, there is substantial doubt about our ability to continue as a going concern. The accompanying consolidated interim financial statements do not purport to reflect or provide for the consequences of the Chapter 11 Cases. In particular, the consolidated financial statements do not purport to show (i) as to assets, their realizable value on a liquidation basis or their fair value or their availability to satisfy liabilities; (ii) as to pre-petition liabilities, the amounts that may be allowed for claims or contingencies, or the status and priority thereof; (iii) as to unitholders’ equity accounts, the effect of any changes that may be made in our capitalization; or (iv) as to operations, the effect of any changes that may be made to our business.

While operating as debtors in possession under Chapter 11 of the Bankruptcy Code, the Debtors may sell or otherwise dispose of or liquidate assets or settle liabilities in amounts other than those reflected in our consolidated interim financial statements, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business. Further, a plan of reorganization could materially change the amounts and classifications in our historical consolidated interim financial statements.

Pursuant to an order of the Bankruptcy Court, we are making adequate protection payments with respect to the Credit Agreement consisting of the payment of interest (at the default rate), included in interest expense, net of capitalized interest on the consolidated statements of operations, and the payment of all reasonable fees and expenses provided for in the Credit Agreement. Pursuant to such order, we are also making adequate protection payments with respect to the Senior Secured Notes in the form of the payment of all reasonable fees and expenses of professionals retained by the holders of the Senior Secured Notes.

3. Acquisitions and Dispositions

2016 Acquisitions and Dispositions

On September 23, 2016, the Bankruptcy Court issued an order authorizing us to consummate the sale of certain non-essential assets including a non-monetary exchange with JPM EOC OPAL, LLC of certain oil and gas properties in Howard County, Texas, which was completed on October 3, 2016, a pending non-monetary exchange with Double Eagle Lone Star LLC of certain oil and gas properties in Howard and Martin Counties, TX, and a pending exchange with Energen of certain oil and gas properties in Howard County, TX and additional cash consideration of $0.3 million.

In March 2016, we completed the sale of certain of our Mid-Continent assets (the “Mid-Continent Sale”) for net proceeds of $11.8 million. The sale included all Mid-Continent properties acquired in the merger with QR Energy, LP (“QRE”) in 2014, excluding five wells for which we have asset retirement obligations and over-riding royalty interests and royalty interests in an additional 42 wells. This transaction was effective January 1, 2016. We recognized a gain of $12.3 million from the Mid-Continent Sale.

In January 2016, we entered into an agreement to purchase CO2 assets in Harding County, New Mexico for a total purchase price of $3.9 million. We acquired compression, dehydration, and electrical sub-station facilities, all associated surface leases and contracts related to the facilities, and six existing producing wells associated with the leases and gathering lines.

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2015 Acquisitions

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

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

In May 2015, we completed the acquisition of additional interests in our existing fields located in Ark-La-Tex for a total purchase price of $3.4 million, which is primarily reflected in oil and natural gas properties on the consolidated balance sheet.
In March 2015, we completed the acquisition of certain CO2 producing properties located in Harding County, New Mexico, primarily reflected in property, plant and equipment on the consolidated balance sheets, for a total purchase price of $70.5 million, of which $13.7 million was paid in cash during the three months ended March 31, 2015.

4.  Financial Instruments and Fair Value Measurements
 
Our risk management programs were intended to reduce our exposure to commodity price volatilities and to assist with stabilizing cash flows and distributions.  Routinely in the past, we utilized derivative financial instruments to reduce this volatility. To the extent we entered into economic hedges for a significant portion of our expected production through commodity derivative instruments and the cost for goods and services increased, our margins would have been adversely affected. As discussed below, our commodity derivative transactions were terminated in the second quarter of 2016.

Chapter 11 Cases

The filing of the Chapter 11 Petitions triggered an event of default under each of the agreements governing our derivative transactions (“ISDA Agreements”). As a result, our counterparties were permitted to terminate, and did terminate, all outstanding transactions governed by the ISDA Agreements. The termination date for each outstanding transaction is the termination date specified to us by our counterparties.

The derivative transactions are no longer accounted for at fair value under ASC 815, because they were terminated in connection with our filing of the Chapter 11 Petitions and have been evaluated as receivables or payables at termination value. At the termination dates, expected settlement receipts on terminated contracts were reclassified from current and long-term derivative instrument assets to accounts and other receivables, net on the consolidated balance sheets and expected settlement payments on terminated contracts were reclassified from current and long-term derivative instrument liabilities to other current liabilities on the consolidated balance sheets. As of September 30, 2016, we had $458.8 million of estimated hedge settlements receivable and $4.1 million in estimated hedge settlements payable, reflected in accounts and other receivables, net and other current liabilities on the consolidated balance sheet, respectively.

All of our derivative counterparties are also lenders, or affiliates of lenders, under our Credit Agreement (see Note 8). In accordance with the interim order approving the DIP Credit Agreement (the “Interim DIP Order”), our counterparties were permitted to terminate any outstanding derivative transactions and to calculate the amounts due to or from the Debtors as a result of such terminations, in accordance with the terms of the governing agreements. However, each such counterparty was required to hold any proceeds due to the Debtors in a book entry account maintained by the counterparty until the date that is the earlier of (the “Standstill Termination Date”) (i) the date the Bankruptcy Court approves in a final order a mutually acceptable resolution among the parties involved with regard to the disposition of the proceeds, (ii) three business days after the date counsel to the administrative agent under the Credit Agreement notifies in writing counsel to the Debtors that the administrative agent intends to provide consent to the counterparties to set off any obligations under the Credit Agreement and (c) the date that is 60 days from the date of entry of the Interim DIP Order.

On August 19, 2016, the Bankruptcy Court entered a final order approving the DIP Credit Agreement (the “Final DIP Order”) extending the Standstill Termination Date. Pursuant to the Final DIP Order, each of our derivative counterparties is required to hold any proceeds due to the Debtors in a book entry account maintained by the counterparty until the date that is the earlier of (i) the date the Bankruptcy Court approves in a final order a mutually acceptable resolution among the parties

13


involved with regard to the disposition of the proceeds, (ii) three business days after the date counsel to the administrative agent under the Credit Agreement notifies in writing counsel to the Debtors that the administrative agent intends for the Standstill Termination Date to occur and that it may provide consent to the counterparties to set off any Credit Agreement obligations and (iii) September 12, 2016. On September 12, 2016, the Standstill Termination Date was extended to October 25, 2016, pursuant to a letter agreement between counsel to the Debtors and counsel to the administrative agent. On October 21, 2016, the Standstill Termination Date was extended again to November 30, 2016.
 
Pursuant to the Final DIP Order, the rights of all of the parties are reserved as to the ultimate disposition of the proceeds. The Credit Agreement is fully collateralized, and excluded from liabilities subject to compromise. Therefore, settlement payables due to our counterparties are reflected in accounts payable on the consolidated balance sheets rather than in liabilities subject to compromise.

As discussed above, our derivative instruments were terminated during the nine months ended September 30, 2016, and reclassified to accounts and other receivables, net and other current liabilities on the consolidated balance sheet at September 30, 2016. The following table presents the fair value of our derivative instruments not designated as hedging instruments at December 31, 2015:
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 December 31, 2015
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
Current assets - derivative instruments
 
$
397,748

 
$
44,426

 
$
222

 
$
(2,769
)
 
$
439,627

Other long-term assets - derivative instruments
 
202,140

 
27,105

 
216

 
(2,697
)
 
226,764

Total assets
 
599,888

 
71,531

 
438

 
(5,466
)
 
666,391

Liabilities
 
 
 
 
 
 
 
 
 
 
Current liabilities - derivative instruments
 
(15
)
 
(2,740
)
 
(4,476
)
 
2,769

 
(4,462
)
Long-term liabilities - derivative instruments
 

 
(2,865
)
 
(87
)
 
2,697

 
(255
)
Total liabilities
 
(15
)
 
(5,605
)
 
(4,563
)
 
5,466

 
(4,717
)
Net assets (liabilities)
 
$
599,873

 
$
65,926

 
$
(4,125
)
 
$

 
$
661,674

(a) Represents counterparty netting under our ISDA Agreements, which allow for netting of oil and natural gas commodity derivative instruments. These derivative instruments are reflected net on the consolidated balance sheets.

The following table presents gains and losses on derivative instruments not designated as hedging instruments:
Thousands of dollars
 
Oil Commodity
Derivatives (a)
 
Natural Gas
Commodity Derivatives (a)
 
Interest Rate Derivatives (b)
 
Total Financial Instruments
Three Months Ended September 30, 2016
 
 
 
 
 
 
 
 
Net loss
 
$

 
$

 
$
(211
)
 
$
(211
)
 
 
 
 
 
 
 
 
 
Three Months Ended September 30, 2015
 
 
 
 
 
 
 
 
Net gain (loss)
 
$
234,158

 
$
18,854

 
$
(996
)
 
$
252,016

 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2016
 
 
 
 
 
 
 
 
Net loss
 
$
(43,345
)
 
$
(10,942
)
 
$
(2,021
)
 
$
(56,308
)
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2015
 
 
 
 
 
 
 
 
Net gain (loss)
 
$
261,360

 
$
35,412

 
$
(3,411
)
 
$
293,361

(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.


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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 December 31, 2015, 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, 2016 and 2015. 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

We calculate 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 models we utilize to calculate the fair value of our Level 2 and Level 3 commodity derivative instruments are standard pricing models. Level 2 inputs to the pricing models include the terms of our derivative contracts, commodity prices from commodity forward price curves, volatility and interest rate factors and time to expiry. Model inputs are obtained from independent third party data providers and our counterparties and are verified to published data where available (e.g., NYMEX). Additional inputs to our Level 3 derivatives include option volatilities, 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 our merger with QRE are estimated using a combined income and market valuation methodology based upon futures commodity prices and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes. We validate the data provided by independent pricing services by comparing such pricing against other third party pricing data.

Available-for-Sale Securities

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

15


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

Thousands of dollars
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
 
 
 
 
 
 
 
As of September 30, 2016
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
Available-for-sale securities
 
 
 
 
 
 
 
 
Equities
 
$
1,472

 
$

 
$

 
$
1,472

Mutual funds
 
11,509

 

 

 
11,509

Exchange traded funds
 
7,434

 

 

 
7,434

Net assets
 
$
20,415

 
$

 
$

 
$
20,415

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

 
$
552,552

 
$

 
$
552,552

Crude oil collars
 

 

 
29,737

 
29,737

Crude oil puts
 

 

 
17,584

 
17,584

Natural gas commodity derivatives
 
 
 
 
 
 
 
 
Natural gas swaps
 

 
54,182

 

 
54,182

Natural gas collars
 

 

 
618

 
618

Natural gas puts
 

 

 
11,126

 
11,126

Interest rate swaps
 
 
 
 
 
 
 
 
Interest rate swaps
 

 
(4,125
)
 

 
(4,125
)
Available-for-sale securities
 
 
 
 
 
 
 
 
Equities
 
2,524

 

 

 
2,524

Mutual funds
 
11,190

 

 

 
11,190

Exchange traded funds
 
4,977

 

 

 
4,977

Net assets
 
$
18,691

 
$
602,609

 
$
59,065

 
$
680,365



16


The following tables set forth a reconciliation of changes in fair value of our derivative instruments classified as Level 3:
 
 
Three Months Ended September 30,
 
 
2016
 
2015
Thousands of dollars
 
Oil
 
Natural Gas
 
Oil
 
Natural Gas
Assets (a):
 
 
 
 
 
 
 
 
Beginning balance
 
$

 
$

 
$
41,001

 
$
15,010

Derivative instrument settlements (b)
 

 

 
11,903

 
4,050

Loss (b)(c)
 

 

 
(2,592
)
 
(4,931
)
Ending balance
 
$

 
$

 
$
50,312

 
$
14,129

 
 
Nine Months Ended September 30,
 
 
2016
 
2015
Thousands of dollars
 
Oil
 
Natural Gas
 
Oil
 
Natural Gas
Assets (a):
 
 
 
 
 
 
 
 
Beginning balance
 
$
47,321

 
$
11,744

 
$
61,410

 
$
19,892

Derivative instrument settlements (b)
 
26,834

 
2,580

 
31,454

 
11,854

Loss (b)(c)
 
(74,155
)
 
(14,324
)
 
(42,552
)
 
(17,617
)
Ending balance
 
$

 
$

 
$
50,312

 
$
14,129


(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. Includes gains and losses resulting from the difference between the mark-to-market value of our level 3 derivative instruments at their termination dates and the expected settlement amounts.
(c) Represents loss on mark-to-market of derivative instruments.

For Level 3 derivative instruments measured at fair value on a recurring basis as of December 31, 2015, the significant unobservable inputs used in the fair value measurements were as follows:
 
 
Fair Value at
 
Valuation
 
 
 
 
Thousands of dollars
 
December 31, 2015
 
Technique
 
Unobservable Input
 
Range
Oil Options
 
$
47,321

 
Option Pricing Model
 
Oil forward commodity prices
 
$37.04/Bbl - $47.79/Bbl
 
 
 
 
 
 
Oil volatility
 
32.24% - 44.95%
 
 
 
 
 
 
Own credit risk
 
5%
Natural Gas Options
 
11,744

 
Option Pricing Model
 
Gas forward commodity prices
 
$2.34/MMBtu - $2.99/MMBtu
 
 
 
 
 
 
Gas volatility
 
23.44% - 73.05%
 
 
 
 
 
 
Own credit risk
 
5%
Total
 
$
59,065

 
 
 
 
 
 

Credit and Counterparty Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of accounts receivable, including hedge settlements receivable. Our hedge settlements receivable expose us to credit risk from counterparties. As of September 30, 2016, our hedge settlements receivable were due from Bank of Montreal, Barclays Bank PLC, BNP Paribas, Canadian Imperial Bank of Commerce, Citibank, N.A, Comerica Bank, Credit Suisse Energy LLC, Credit Suisse International, ING Capital Markets LLC, Fifth Third Bank, JP Morgan Chase Bank N.A., Merrill Lynch Commodities, Inc., Morgan Stanley Capital Group Inc., PNC Bank, N.A, Royal Bank of Canada, The Bank of Nova Scotia, The Toronto-Dominion Bank, MUFG Union Bank N.A. and Wells Fargo Bank, N.A. Our counterparties are all lenders, or affiliates of lenders, that participate in our 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

17


condition and obtain credit default swap information on our counterparties. This risk was managed by diversifying our derivatives portfolio.  As of September 30, 2016, each of these financial institutions and/or their parent company had an investment grade credit rating from Moody’s Investors Service and Standard & Poor’s.  

5.  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 provided administrative services to Pacific Coast Energy Company LP, formerly named BreitBurn Energy Company L.P. (“PCEC”), our predecessor, under an administrative services agreement (“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 year ended December 31, 2015 and the six months ended June 30, 2016, the monthly fee paid by PCEC for indirect expenses was $700,000. On February 5, 2016, PCEC provided written notice to Breitburn Management of its intention to terminate the Administrative Services Agreement, which became effective on June 30, 2016.

At September 30, 2016 and December 31, 2015, we had a current receivable of zero and $1.7 million, respectively, due from PCEC, related to the administrative services agreement and employee-related costs.  For the three months ended September 30, 2016 and 2015, the monthly charges to PCEC for indirect expenses totaled zero and $2.1 million, respectively, and charges for direct expenses including payroll and administrative costs totaled $0.5 million and $2.3 million, respectively. For the nine months ended September 30, 2016 and 2015, the monthly charges to PCEC for indirect expenses totaled $4.2 million and $6.3 million, respectively, and charges for direct expenses including payroll and administrative costs totaled $4.9 million and $7.3 million, respectively. At September 30, 2016 and December 31, 2015, we had receivables of $0.9 million and $0.7 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.

6. Impairments

Long-Lived Assets

We review our oil and gas properties for impairment periodically or when events or circumstances indicate that their carrying amounts may exceed their fair values and may not be recoverable. Under the successful efforts method of accounting, the carrying amount of an oil and gas property to be held and used is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the property. Due to the nature of the recoverability test, certain oil and gas properties may have carrying values which exceed their fair values, but an impairment charge is not recognized because their carrying values are less than their undiscounted cash flows. 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 and expected reserve lives, the outlook for market supply and demand conditions for oil and natural gas, management’s intent to hold and use the properties 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, in certain instances, risk-adjusted probable and possible reserves on a held and used basis based in large part on future capital and operating plans. The undiscounted cash flow review includes inputs such as applicable NYMEX forward strip prices, estimated basis price differentials, expenses and capital estimates, and escalation factors.  Management also considers the impact future price changes are likely to have on our future operating plans.

        If we determine that an impairment charge for a property is warranted because net book value exceeds undiscounted cash flows, an impairment charge is recorded for the amount that the property’s carrying value exceeds the amount of its estimated discounted future net cash flows. Beginning in the first quarter of 2016, the estimated discounted future cash flows were determined by using applicable basis adjusted (i) nine-year NYMEX forward strip prices for oil, and (ii) ten-year NYMEX forward strip prices for natural gas, in each case, at the end of the reporting period, and escalated along with expenses and capital starting in (i) year ten for oil and (ii) year eleven for natural gas, and thereafter at 2% per year.  Production and development cost estimates (e.g. operating expenses and development capital) are conformed to reflect the

18


commodity price strip used.  The associated property’s expected future net cash flows were discounted using a market-based weighted average cost of capital rate, which approximated 11% and 13%, at March 31, 2016 and September 30, 2016, respectively. There were no impairments from the prescribed impairment method during the three months ended June 30, 2016.  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.

During the three months ended September 30, 2016, we began updating our annual business plan (“updated business plan”). At September 30, 2016, we incorporated the assumptions from our updated business plan into our impairment reserves analysis. For certain impaired fields, recent operating results incorporated in the updated business plan resulted in lower production estimates and higher operating cost estimates than previously forecast. Our updated business plan was prepared with the assumption that we emerge from Chapter 11 and continue to hold and use our assets for their economic lives up to and including final dispositions. There are no material asset sales planned or contemplated in this business plan. Other assumptions and or revisions in our business plan could result in material changes to the undiscounted cash flows used in our impairment analysis. We are in the process of reviewing our business plan with our creditors. Accordingly, we cannot estimate what impact, if any, other assumptions or courses of action or their probabilities of occurrence could have on our undiscounted cash flows at September 30, 2016.

Non-cash impairment charges totaled $275.0 million and $277.8 million for the three months and nine months ended September 30, 2016, respectively. For the three months ended September 30, 2016, we had non-cash impairments of $177.1 million in the Permian Basin, $88.4 million in the Rockies, $5.3 million in the Midwest and $4.2 million in Ark-La-Tex, primarily related to revisions in our updated business plan for future production and cost estimates at certain of our lower margin oil properties, as well as the impact that the drop in natural gas prices in the out years had on projected future revenues for certain of our lower margin natural gas properties. For the nine months ended September 30, 2016, we had non-cash impairments of $177.6 million in the Permian Basin, $88.6 million in the Rockies, $5.3 million in the Midwest, $4.2 million in Ark-La-Tex, and $2.1 million in the Southeast.

Non-cash impairments totaled $1.4 billion and $1.5 billion for the three months and nine months ended September 30, 2015, respectively. For the three months ended September 30, 2015, we had non-cash impairments of $605.4 million in the Midwest, $420.2 million in the Southeast, $262.1 million in Ark-La-Tex, $73.1 million in California, $49.7 million for our Permian properties, $17.4 million in the Rockies and $12.2 million for our Mid-Continent properties, primarily related to the impact of the drop in commodity strip prices on our projected future net revenues. For the nine months ended September 30, 2015, we had non-cash impairments of $605.4 million in the Midwest, $420.2 million in the Southeast, $262.1 million in Ark-La-Tex, $82.8 million in the Permian Basin, $73.1 million in California, $34.1 million in the Rockies and $21.5 million in Mid-Continent.
       
Management prepared its undiscounted cash flow estimates on a held and used basis which assumes oil and gas properties will be held and used for their economic lives. If a decision is reached to sell a particular asset, that asset would be classified as held for sale and could potentially be impaired if the carrying value exceeded the estimated sales value less the costs of disposal. It is also possible that further periods of prolonged lower commodity prices, future declines in commodity prices, changes to our future plans in response to a final plan of reorganization, or increases in operating costs could result in future impairments. For example, during the third quarter, had the undiscounted cash flows for one of our oil and gas properties in Ark-La-Tex been lower by 10%, the estimated non-cash impairment charges would have been approximately $220 million higher for the three months ended September 30, 2016. Given the number of assumptions involved in the estimates, estimates as to other sensitivities to earnings for these periods if other assumptions had been used in impairment reviews and calculations is not practicable. Favorable changes to some assumptions could have increased the undiscounted cash flows thus further avoiding the need to impair any assets in this period, whereas other unfavorable changes could have caused an unknown number of assets to become impaired. Additionally the oil and gas assets may be further adjusted in the future due to the outcome of Chapter 11 Cases or adjusted to fair value due to the application of fresh start accounting upon emergence from Chapter 11.


19


7. Other Long-Term Assets

As of September 30, 2016, and December 31, 2015, our other long-term assets were as follows:
 
 
As of
Thousands of dollars
 
September 30, 2016
 
December 31, 2015
Debt issuance costs
 
$

 
$
22,142

Available-for-sale securities
 
20,415

 
18,691

Deposit for Jay Field net profit interest obligation
 
18,263

 
18,263

Property reclamation deposit
 
10,737

 
10,736

Other
 
12,942

 
11,015

Total
 
$
62,357

 
$
80,847

    
During the three months and nine months ended September 30, 2016, we wrote off zero and $20.4 million, respectively, of unamortized debt issuance costs associated with our Credit Agreement in connection with the commencement of the Chapter 11 Cases and reduction of the elected commitment amount under our Credit Agreement. The write-offs were recognized in interest expense, net of capitalized interest on the consolidated statements of operations. See Note 8 for a discussion of the Credit Agreement.

8.  Debt
    
Our debt is detailed in the following table:
 
 
As of
Thousands of dollars
 
September 30, 2016
 
December 31, 2015
Credit Agreement
 
$
1,198,259

 
$
1,229,000

Promissory note
 
2,938

 
2,938

Senior Secured Notes
 
650,000

 
650,000

2020 Senior Notes
 
305,000

 
305,000

2022 Senior Notes
 
850,000

 
850,000

Unamortized debt issuance costs and net (discount) premium on Senior Notes (a)
 

 
(52,806
)
Capital lease obligations
 
156

 
210

Total debt
 
3,006,353

 
2,984,342

Less: Current portion of long-term debt
 
(1,198,259
)
 
(154,000
)
Less: Amounts reclassified to liabilities subject to compromise
 
(1,805,000
)
 

Total long-term debt
 
$
3,094

 
$
2,830,342

(a) In connection with the adoption of ASU 2015-03, unamortized debt issuance costs associated with the Senior Notes at December 31, 2015 of $37.0 million were reclassified from other long-term assets to debt. See Note 1 for a detailed discussion of the adoption of the change in accounting principle. In connection with the Chapter 11 Cases, unamortized debt issuance costs, discounts and premiums on the Senior Notes as of the Chapter 11 Filing Date of May 15, 2016 were expensed and recognized in reorganization items, net on the consolidated statement of operations. See below for more information.

DIP Credit Agreement

In connection with the Chapter 11 Cases, BOLP entered into the DIP Credit Agreement as borrower with the lenders party thereto (the “DIP Lenders”) and Wells Fargo, National Association, as administrative agent. The Debtors have guaranteed all obligations under the DIP Credit Agreement. Pursuant to the terms of the DIP Credit Agreement, the DIP Lenders have made available a revolving credit facility in an aggregate principal amount of $75 million (and the DIP Lenders have offered to arrange an additional $75 million of financing under the DIP Credit Agreement at the borrower’s request), which includes a letter of credit facility available for the issuance of letters of credit in an aggregate principal amount not to exceed a sub-limit of $50 million, and a swingline facility in an aggregate principal amount not to exceed a sub-limit of $5 million, in each case, to mature on the earlier to occur of (A) the effective date of a plan of reorganization in the Chapter 11 Cases or (B) the stated maturity of the DIP Credit Agreement of January 15, 2017. In addition, the maturity date may be accelerated upon the occurrence of certain events as set forth in the DIP Credit Agreement.

20



At September 30, 2016, we had no borrowings outstanding under the DIP Credit Agreement.

The proceeds of the DIP Credit Agreement may be used: (i) to pay the costs and expenses of administering the Chapter 11 Cases, (ii) to fund our working capital needs, capital improvements, and other general corporate purposes, in each case, in accordance with an agreed budget and (iii) to provide adequate protection to existing secured creditors.

Acceleration of Debt Obligations

The commencement of the Chapter 11 Cases resulted in the acceleration of the Debtors’ obligations under the Credit Agreement and the acceleration of all obligations with respect to the Senior Secured Notes and the Senior Notes. Any efforts to enforce such obligations are automatically stayed as a result of the filing of the Chapter 11 Petitions and the holders’ rights of enforcement in respect of these obligations are subject to the applicable provisions of the Bankruptcy Code.

Credit Agreement

At each of September 30, 2016 and December 31, 2015, we had $1.2 billion in indebtedness outstanding under the Credit Agreement.

As of September 30, 2016 and December 31, 2015, our borrowing base was $1.8 billion. On March 28, 2016, we entered into a Consent (the “Consent”) to the Credit Agreement, which delayed the scheduled borrowing base redetermination from April 1, 2016 to May 1, 2016 and reduced the elected commitment amount under the Credit Agreement from $1.8 billion to $1.4 billion. During the three months and nine months ended September 30, 2016, we recognized zero and $20.4 million write-off of debt issuance costs, respectively, associated with our Credit Agreement in connection with the commencement of the Chapter 11 Cases and reduction of the elected commitment amount under our Credit Agreement. The write-offs are reflected in our interest expense totals.
 
At the Chapter 11 Filing Date, we had $1.197 billion in unpaid principal outstanding under the Credit Agreement. The Credit Agreement is secured by a first priority security interest in and lien on substantially all of the Debtors’ assets, including the proceeds thereof and after-acquired property. Therefore, upon the acceleration as a consequence of the commencement of the Chapter 11 Cases, we reclassified the Credit Agreement balance to current portion of long-term debt, as the principal became immediately due and payable. However, any efforts to enforce such payment obligations are automatically stayed as a result of the filing of the Chapter 11 Petitions. At the Chapter 11 Filing Date, we recognized $15.7 million for the full write-off of unamortized debt issuance costs related to the Credit Agreement.

We are required to make adequate protection payments to the lenders under the Credit Agreement, which includes interest at the default rate as provided in the Credit Agreement. We are recognizing the default interest accrued on the Credit Agreement as interest expense, net of capitalized interest on the consolidated statements of operations, and we are recognizing the adequate protection payments as accrued interest payable on the consolidated balance sheets, rather than in liabilities subject to compromise. At September 30, 2016, the default interest rate on the Credit Agreement was 6.75%.

Senior Secured Notes

As of March 31, 2016, we had $650 million of Senior Secured Notes, issued on April 5, 2015, which had a carrying value of $614.1 million, net of unamortized discount of $16.5 million and unamortized debt issuance costs of $19.4 million. Interest on our Senior Secured Notes is payable quarterly in March, June, September and December.

Since the commencement of the Chapter 11 Cases on May 15, 2016, no interest has been paid to the holders of the Senior Secured Notes. As of September 30, 2016, the Senior Secured Notes were reflected as liabilities subject to compromise on the consolidated balance sheet, with the carrying value equal to the face value of the notes. The unamortized discount of $16.1 million and the unamortized debt issuance costs of $18.9 million as of the Chapter 11 Filing Date were expensed and recognized in reorganization items, net on the consolidated statements of operations. In addition, as of the Chapter 11 Filing Date, the accrued but unpaid interest expense on the Senior Secured Notes of $7.5 million was reflected as liabilities subject to compromise. No interest expense was recognized on the Senior Secured Notes after the commencement of the Chapter 11 Cases. Unrecognized, contractual interest expense on the Senior Secured Notes for the three months and nine months ended September 30, 2016 was $15.0 million and $22.5 million, respectively.


21


Senior Unsecured Notes

As of March 31, 2016, we had $305 million in aggregate principal amount of 2020 Senior Notes, which had a carrying value of $298.2 million, net of unamortized discount of $2.8 million and unamortized debt issuance costs of $4.0 million. In addition, as of March 31, 2016, we had $850 million in aggregate principal amount of 2022 Senior Notes, which had a carrying value of $842.6 million, net of unamortized premium of $4.3 million and unamortized debt issuance costs of $11.7 million. Interest on the 2020 Senior Notes and the 2022 Senior Notes is payable twice a year in April and October.

On April 14, 2016, we elected to defer a $33.5 million interest payment due with respect to our 2022 Senior Notes and a $13.2 million interest payment due with respect to our 2020 Senior Notes, with each such interest payment due on April 15, 2016 and subject to a 30-day grace period. As a consequence of the commencement of the Chapter 11 Cases, such interest payments have not been made, and are classified as liabilities subject to compromise on the consolidated balance sheet at September 30, 2016.

Since the commencement of the Chapter 11 Cases on May 15, 2016, no interest has been paid to the holders of the Senior Unsecured Notes. As of September 30, 2016, the Senior Unsecured Notes were reflected as liabilities subject to compromise on the consolidated balance sheet, with the carrying values equal to the face values of the notes. The unamortized premium of $1.5 million and the unamortized debt issuance costs of $15.4 million as of the Chapter 11 Filing Date were recognized in reorganization items, net on the consolidated statements of operations. In addition, as of the Chapter 11 Filing Date, the accrued but unpaid interest expense on the Senior Unsecured Notes of $54.4 million was reflected as liabilities subject to compromise. No interest expense was recognized on the Senior Unsecured Notes after the filing of the Chapter 11 Petitions. Unrecognized contractual interest expense on the Senior Unsecured Notes for the three months and nine months ended September 30, 2016 was $23.3 million and $35.0 million, respectively.

Interest Expense

Our interest expense is detailed as follows:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
Thousands of dollars
 
2016
 
2015
 
2016
 
2015
Credit agreements (including commitment fees) and other long-term debt
 
$
21,051

 
$
8,828

 
$
43,385

 
$
32,422

Senior Secured Notes (a)
 

 
15,031

 
22,548

 
28,893

Senior Unsecured Notes (a)
 

 
23,311

 
34,966

 
69,933

Amortization of net discount/premium and debt issuance costs (b)
 

 
3,816

 
26,138

 
20,885

Capitalized interest
 
(69
)
 
(67
)
 
(149
)
 
(145
)
Total
 
$
20,982

 
$
50,919

 
$
126,888

 
$
151,988

(a) Reflects interest through the Chapter 11 Filing Date.
(b) The three months and nine months ended September 30, 2016 included the write-off of zero and $20.4 million, respectively, of debt issuance costs. The three months and nine months ended September 30, 2015 included the write-off of zero and $10.6 million, respectively, of debt issuance costs.


22


9. Condensed Consolidating Financial Statements

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

In accordance with Rule 3-10 of Regulation S-X, we are not presenting condensed consolidating financial statements as we have no independent assets or operations; Breitburn Finance Corporation, the subsidiary co-issuer that does not guarantee the Senior Notes, is a wholly-owned finance subsidiary; all of our material subsidiaries are wholly-owned and have guaranteed the Senior Notes; and all of the guarantees are full, unconditional, joint and several.
    
Under the indentures governing the Senior Notes, each guarantee of each of the 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,
(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.  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 for any new additions or revisions have been discounted at a credit-adjusted risk-free rate of approximately 14% and adjusted for inflation using a rate of 2% for the nine months ended September 30, 2016. Our credit-adjusted risk-free rate at December 31, 2015 was 14%, 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, 2016, and the year ended December 31, 2015 are presented in the following table:
 
 
Nine Months Ended
 
Year Ended
Thousands of dollars
 
September 30, 2016
 
December 31, 2015
Carrying amount, beginning of period
 
$
254,378

 
$
238,411

Liabilities added from acquisitions
 
78

 
796

Liabilities related to divested properties
 
(8,380
)
 
(261
)
Liabilities incurred from drilling
 
91

 
2,268

Liabilities settled
 
(1,775
)
 
(7,744
)
Revision of estimates
 
1,879

 
3,954

Accretion expense
 
13,158

 
16,954

Carrying amount, end of period
 
259,429

 
254,378

Less: Current portion of ARO
 
(3,915
)
 
(2,341
)
Non-current portion of ARO
 
$
255,514

 
$
252,037



23


11.  Commitments and Contingencies

In the ordinary 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 September 30, 2016 and December 31, 2015, we had approximately $26.4 million and $27.1 million, respectively, of surety bonds outstanding. At September 30, 2016 and December 31, 2015, we had approximately $43.9 million and $25.8 million, respectively, in letters of credit outstanding under our Credit Agreement. The increase in letters of credit during the nine months ended September 30, 2016 was primarily due to the Chapter 11 filing.  At September 30, 2016 and December 31, 2015, we had approximately $1.8 million and zero, respectively, in letters of credit outstanding under our DIP Credit Agreement.

Legal Proceedings

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

12.  Partners’ Equity

Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities and post-petition liabilities must be satisfied in full before the holders of our Series A Preferred Units, Series B Preferred Units and common units representing limited partner interests in us (“Common Units”) are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or unitholders, if any, will not be determined until confirmation and implementation of a plan of reorganization. No assurance can be given as to what distributions, if any, will be made to each of these constituencies or the nature thereof. As discussed below, if certain requirements of the Bankruptcy Code are met, a plan of reorganization can be confirmed notwithstanding its rejection or deemed rejection by the holders of our Series A Preferred Units, Series B Preferred Units and Common Units and notwithstanding the fact that such holders do not receive or retain any property on account of their equity interests under the plan. Because of such possibilities, the value of our securities, including our Series A Preferred Units, Series B Preferred Units and Common Units, is highly speculative. There can be no assurance that the holders of our Series A Preferred Units, Series B Preferred Units and Common Units will retain any value under a plan of reorganization.

Preferred Units

On May 21, 2014, we sold 8.0 million 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 discounts and offering expenses of $6.8 million. The Series A Preferred Units rank senior to our Common Units and on parity with the Series B Preferred Units with respect to the payment of distributions. Through March 31, 2016, we paid 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, totaling $4.1 million for the three months ended March 31, 2016.

On April 8, 2015, we issued in a private offering $350 million of Series B Preferred Units at an issue price of $7.50 per unit. We received approximately $337.2 million from this offering, net of fees and estimated expenses, which we primarily used to repay borrowings under our Credit Agreement. The Series B Preferred Units rank senior to our Common Units and on parity with the Series A Preferred Units with respect to the payment of distributions.

On April 14, 2016, we elected to suspend the declaration of any further distributions on our Series A Preferred Units and Series B Preferred Units. In the event we fail to make any distribution on the Series B Preferred Units as required under the partnership agreement, the annual distribution rate is increased by 2.00% effective as of such date until the date on which all required distributions have been made. As of the Chapter 11 Filing Date, we had 8.0 million Series A Preferred Units issued and outstanding and 49.6 million Series B Preferred Units issued and outstanding. We will continue to account for our Series A Preferred Units and Series B Preferred Units at their carrying value until a plan of reorganization is confirmed by the Bankruptcy Court and becomes effective. We accrued for earned but undeclared distributions on each series of Preferred Units for the period from April 1, 2016 to the Chapter 11 Filing Date. As of September 30, 2016, total accrued but unpaid distributions on our Series A Preferred Units and Series B Preferred Units of $7.0 million were reflected as liabilities subject to compromise.


24


Through the three months ended March 31, 2016, we elected to pay our Series B Preferred Unit distributions in kind by issuing additional Series B Preferred Units (or, when elected by the unitholder, by issuing Common Units in lieu of such Series B Preferred Units) instead of cash. During the three months ended March 31, 2016, we declared distributions on our Series B Preferred Units at a monthly rate of 0.006666 Series B Preferred Units per unit, in the form of a total of 818,626 Series B Preferred Units and 163,314 Common Units. During each of the three months and nine months ended September 30, 2015, we declared distributions on our Series B Preferred Units at a monthly rate of 0.006666 Series B Preferred Units per unit, in the form of a total of 786,634 Series B Preferred Units and 163,314 Common Units.

During the three months and nine months ended September 30, 2016 and September 30, 2015, we recognized zero, $6.1 million, $4.1 million and $12.4 million, respectively, of accrued distributions on the Series A Preferred Units, which were included in distributions to Series A preferred unitholders on the consolidated statements of operations. During the three months and nine months ended September 30, 2016 and September 30, 2015, we recognized $0.6 million, $11.7 million, $7.1 million and $13.6 million, respectively, of accrued distributions on the Series B Preferred Units, which were included in non-cash distributions to Series B preferred unitholders on the consolidated statements of operations. The accrued distributions on Series B Preferred Units recognized during the three months ended September 30, 2016 of $0.6 million reflect the 2.00% default distribution rate increase attributable to the earned but undeclared distributions effective April 15, 2016 through the Chapter 11 Filing Date.

Common Units

As of the Chapter 11 Filing Date, we had 213.8 million Common Units outstanding. We will continue to account for our Common Units at their carrying value until a plan of reorganization is confirmed by the Bankruptcy Court and becomes effective.

At each of September 30, 2016 and December 31, 2015, we had approximately 213.8 million and 213.5 million, respectively, of Common Units outstanding.

In 2016, we declared no cash distributions to holders of our Common Units and our restricted phantom units (“RPUs”). In response to current commodity and financial market conditions, the Board of Directors of our general partner (the “Board”) suspended distributions on Common Units effective with the third monthly payment attributable to the third quarter of 2015. During the three months and nine months ended September 30, 2015, we paid cash distributions of approximately $26.5 million, or $0.1250 per Common Unit, and $105.6 million, or $0.4999 per Common Unit, respectively.

During the three months and nine months ended September 30, 2016, we issued zero and 163,314 Common Units, respectively, to a Series B Preferred unitholder that elected to receive its paid in kind distributions in Common Units. During the three months and nine months ended September 30, 2015, we issued 163,314 and 284,898 Common Units to a Series B Preferred unitholder that elected to receive its paid in kind distributions in Common Units.

During each of the three months ended September 30, 2016 and 2015, we issued zero Common Units to non-employee directors for RPUs. During each of the nine months ended September 30, 2016 and 2015, we issued 0.1 million Common Units to non-employee directors for RPUs that vested in January 2016 and January 2015, respectively.

At September 30, 2016 and December 31, 2015, there were approximately 20.6 million and 3.6 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 and nine months ended September 30, 2016, we paid zero 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, 2015, we paid $0.6 million and $2.7 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.


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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
 
Nine Months Ended
 
 
September 30,
 
September 30,
Thousands, except per unit amounts
 
2016
 
2015
 
2016
 
2015
Net loss attributable to the partnership
 
$
(364,600
)
 
$
(1,327,929
)
 
$
(729,701
)
 
$
(1,692,461
)
Less:
 
 
 
 
 
 
 
 
Distributions on participating units in excess of earnings (a)
 

 
428

 

 
1,731

Distributions to Series A preferred unitholders
 

 
4,125

 
6,142

 
12,375

Non-cash distributions to Series B preferred unitholders
 
621

 
7,145

 
11,744

 
13,553

Net loss used to calculate basic and diluted net loss per unit
 
$
(365,221
)
 
$
(1,339,627
)
 
$
(747,587
)
 
$
(1,720,120
)
 
 
 
 
 
 
 
 
 
Weighted average number of units used to calculate basic and diluted net loss per unit (in thousands):
 
 
 
 
 
 
 
 
Common Units (b)
 
213,789

 
211,766

 
213,743

 
211,369

Dilutive units (c)
 

 

 

 

Denominator for diluted net loss per unit
 
213,789

 
211,766

 
213,743

 
211,369

 
 
 
 
 
 
 
 
 
Net loss per common unit
 
 
 
 
 
 
 
 
Basic
 
$
(1.71
)
 
$
(6.33
)
 
$
(3.50
)
 
$
(8.14
)
Diluted
 
$
(1.71
)
 
$
(6.33
)
 
$
(3.50
)
 
$
(8.14
)
(a) The previously reported 2015 net loss allocated to participating units was adjusted to correct an error in the allocation to participating units resulting in a change to basic and diluted loss per unit from $6.17 to $6.33 for the three months ended September 30, 2015, and from $7.94 to $8.14 for the nine months ended September 30, 2015; the correction to the 2015 EPU calculation was determined to not be material.
(b) The three months and nine months ended September 30, 2016 exclude 20,279 and 19,578, respectively, of weighted average anti-dilutive units from the calculation of the denominator for basic earnings per common unit, as we were in a loss position.
(c) The three months ended September 30, 2016 and 2015 exclude 413 and 749, respectively, of weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit, as we were in a loss position. The nine months ended September 30, 2016 and 2015 exclude 413 and 724, 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.


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13. Accumulated Other Comprehensive Loss

Changes in accumulated other comprehensive loss by component, net of tax, were as follows:
 
 
Three Months Ended September 30,
 
 
2016
 
2015
 
 
Gain (loss) on
 
Loss on
Thousands of dollars
 
Available-For-Sale Securities
 
Post retirement Benefits
 
Total
 
Available-For-Sale Securities
 
Post retirement Benefits
 
Total
Carrying amount, beginning of period
 
$
84

 
$
(341
)
 
$
(257
)
 
$
(53
)
 
$
(280
)
 
$
(333
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Other comprehensive income (loss) before reclassification
 
312

 
(12
)
 
300

 
(637
)
 

 
(637
)
Amounts reclassified from accumulated other comprehensive loss (a)
 
9

 

 
9

 

 

 

Net current period other comprehensive income (loss)
 
321

 
(12
)
 
309

 
(637
)
 

 
(637
)
Less: Noncontrolling interest
 
131

 
(5
)
 
126

 
(394
)
 

 
(394
)
Carrying amount, end of period
 
$
274

 
$
(348
)
 
$
(74
)
 
$
(296
)
 
$
(280
)
 
$
(576
)

 
 
Nine Months Ended September 30,
 
 
2016
 
2015
 
 
Gain (loss) on
 
Loss on
Thousands of dollars
 
Available-For-Sale Securities
 
Post retirement Benefits
 
Total
 
Available-For-Sale Securities
 
Post retirement Benefits
 
Total
Carrying amount, beginning of period
 
$