10-Q 1 bbep6301210q.htm BBEP 6.30.12 10Q


 
 
 
 
 

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

x
Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the quarterly period ended June 30, 2012
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 L.P.
(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

As of August 7, 2012, the registrant had 69,144,046 Common Units outstanding.

 
 
 
 
 
 
INDEX

 
 
Page No.
 
 
 
 
 
PART I
 
 
FINANCIAL INFORMATION
 
 
 
 
 
 
 
 
 
 
 
 
 
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,” “future,” “affect,” “result,” “engage,” “will,” 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 and natural gas prices; a continuation of depressed natural gas prices; delays in planned or expected drilling; changes in costs and availability of drilling, completion and production equipment, and related services and labor; the discovery of previously unknown environmental issues; 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; changes in governmental regulations, including the regulation of derivatives and the oil and natural gas industry; the effects of changes in accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; integration and other risks associated with our acquisitions; 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, 2011, Part II—Item 1A of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2012 and in Part II—Item 1A of this report.  Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.

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

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


1


PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements

BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Balance Sheets
Thousands
 
June 30,
2012
 
December 31,
2011
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash
 
$
4,066

 
$
5,328

Accounts and other receivables, net
 
55,575

 
73,018

Derivative instruments (note 3)
 
79,616

 
83,452

Related party receivables (note 4)
 
2,075

 
4,245

Inventory (note 5)
 
5,267

 
4,724

Prepaid expenses
 
2,404

 
2,053

Total current assets
 
149,003

 
172,820

Equity investments
 
7,182

 
7,491

Property, plant and equipment
 
 
 
 
Oil and gas properties
 
2,719,580

 
2,583,993

Other assets
 
13,695

 
13,431

 
 
2,733,275

 
2,597,424

Accumulated depletion and depreciation (note 7)
 
(592,825
)
 
(524,665
)
Net property, plant and equipment
 
2,140,450

 
2,072,759

Other long-term assets
 
 
 
 
Derivative instruments (note 3)
 
87,161

 
55,337

Other long-term assets
 
47,694

 
22,442

 
 
 
 
 
Total assets
 
$
2,431,490

 
$
2,330,849

 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable
 
$
36,949

 
$
33,494

Derivative instruments (note 3)
 
2,487

 
8,881

Revenue and royalties payable
 
16,059

 
19,641

Salaries and wages payable
 
7,998

 
13,655

Accrued liabilities
 
14,732

 
14,218

Total current liabilities
 
78,225

 
89,889

 
 
 
 
 
Credit facility (note 8)
 
225,000

 
520,000

Senior notes, net (note 8)
 
548,841

 
300,613

Deferred income taxes (note 10)
 
2,929

 
2,803

Asset retirement obligation (note 11)
 
84,802

 
82,397

Derivative instruments (note 3)
 
1,104

 
3,084

Other long-term liabilities
 
4,823

 
4,849

Total liabilities
 
945,724

 
1,003,635

Commitments and contingencies (note 12)
 
 
 
 
Equity
 
 
 
 
Partners' equity (note 13)
 
1,485,766

 
1,326,764

Noncontrolling interest (note 14)
 

 
450

Total equity
 
1,485,766

 
1,327,214

 
 
 
 
 
Total liabilities and equity
 
$
2,431,490

 
$
2,330,849

 
 
 
 
 
Common units issued and outstanding
 
69,144

 
59,864


See accompanying notes to consolidated financial statements.

2


BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Statements of Operations

 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
Thousands of dollars, except per unit amounts
 
2012

2011
 
2012
 
2011
Revenues and other income items
 
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquid sales
 
$
94,981

 
$
94,742

 
$
188,988

 
$
187,317

Gain (loss) on commodity derivative instruments, net (note 3)
 
107,288

 
46,483

 
71,283

 
(59,694
)
Other revenue, net
 
907

 
1,143

 
2,052

 
2,041

    Total revenues and other income items
 
203,176

 
142,368

 
262,323

 
129,664

Operating costs and expenses
 
 
 
 

 
 
 


Operating costs
 
48,894

 
36,208

 
92,155

 
73,019

Depletion, depreciation and amortization (note 7)
 
33,517

 
25,025

 
71,798

 
49,666

General and administrative expenses
 
12,926

 
11,656

 
26,600

 
24,127

Loss on sale of assets
 
29

 
40

 
154

 
54

Total operating costs and expenses
 
95,366

 
72,929

 
190,707

 
146,866

 
 
 
 
 
 
 
 


Operating income (loss)
 
107,810

 
69,439

 
71,616

 
(17,202
)
 
 
 
 
 
 
 
 


Interest expense, net of capitalized interest
 
14,069

 
9,080

 
27,869

 
18,500

Loss on interest rate swaps (note 3)
 
190

 
2,220

 
684

 
1,877

Other expense (income), net
 
23

 

 
19

 
(3
)
 
 
 
 
 
 
 
 


Income (loss) before taxes
 
93,528

 
58,139

 
43,044

 
(37,576
)
 
 
 
 
 
 
 
 


Income tax expense (benefit) (note 10)
 
1,005

 
616

 
446

 
(386
)
 
 
 
 
 
 
 
 


Net income (loss)
 
92,523

 
57,523

 
42,598

 
(37,190
)
 
 
 
 
 
 
 
 


Less: Net income attributable to noncontrolling interest
 
(17
)
 
(68
)
 
(62
)
 
(102
)
 
 
 
 
 
 
 
 


Net income (loss) attributable to the partnership
 
$
92,506

 
$
57,455

 
$
42,536

 
$
(37,292
)
 
 
 
 
 
 
 
 


Basic net income (loss) per unit (note 13)
 
$
1.29

 
$
0.93

 
$
0.61

 
$
(0.64
)
Diluted net income (loss) per unit (note 13)
 
$
1.29

 
$
0.92

 
$
0.61

 
$
(0.64
)

See accompanying notes to consolidated financial statements.


3


BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Statements of Cash Flows

 
 
Six Months Ended
 
 
June 30,
Thousands of dollars
 
2012
 
2011
Cash flows from operating activities
 
 
 
 
Net income (loss)
 
$
42,598

 
$
(37,190
)
Adjustments to reconcile to cash flow from operating activities:
 


 


Depletion, depreciation and amortization
 
71,798

 
49,666

Unit-based compensation expense
 
11,203

 
10,858

Unrealized (gain) loss on derivative instruments
 
(29,406
)
 
64,175

Income from equity affiliates, net
 
309

 
159

Deferred income taxes
 
126

 
(518
)
Loss on sale of assets
 
154

 
54

Other
 
2,367

 
(244
)
Changes in net assets and liabilities
 


 


Accounts receivable and other assets
 
9,970

 
4,171

Inventory
 
(543
)
 
(21
)
Net change in related party receivables and payables
 
2,170

 
1,713

Accounts payable and other liabilities
 
(10,195
)
 
(5,306
)
Net cash provided by operating activities
 
100,551

 
87,517

Cash flows from investing activities
 


 
 
Capital expenditures
 
(37,382
)
 
(35,136
)
Proceeds from sale of assets
 
674

 
110

Deposit for oil and gas properties
 
(21,954
)
 

Property acquisitions
 
(92,837
)
 

Net cash used in investing activities
 
(151,499
)
 
(35,026
)
Cash flows from financing activities
 


 
 
Issuance of common units
 
166,044

 
100,204

Distributions
 
(60,750
)
 
(49,470
)
Proceeds from long-term debt
 
538,885

 
133,500

Repayments of long-term debt
 
(586,000
)
 
(234,500
)
Change in bank overdraft
 
(2,785
)
 
5

Debt issuance costs
 
(5,708
)
 
(3,113
)
Net cash provided by (used in) financing activities
 
49,686

 
(53,374
)
Decrease in cash
 
(1,262
)
 
(883
)
Cash beginning of period
 
5,328

 
3,630

Cash end of period
 
$
4,066

 
$
2,747


See accompanying notes to consolidated financial statements.


4


Notes to Consolidated Financial Statements

1.  Organization and Basis of Presentation

The accompanying unaudited consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our Annual Report on Form 10-K for the year ended December 31, 2011 (the "Annual Report").  The financial statements have been prepared in accordance with accounting principles generally accepted in the United States ("GAAP") for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X.  In the opinion of management, all adjustments considered necessary for a fair statement of our financial position at June 30, 2012, our operating results for the three months and six months ended June 30, 2012 and 2011, and our cash flows for the six months ended June 30, 2012 and 2011, have been included.  Operating results for the three months and six months ended June 30, 2012 are not necessarily indicative of the results that may be expected for the year ended December 31, 2012.  The consolidated balance sheet at December 31, 2011 has been derived from the audited consolidated financial statements at that date but does not include all of the information and footnotes required by GAAP for complete financial statements.  For further information, refer to the consolidated financial statements and footnotes thereto included in our Annual Report.

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

2.  Accounting Standards

In May 2011, the Financial Accounting Standards Board ("FASB") issued an Accounting Standards Update ("ASU") to improve comparability between GAAP and International Financial Reporting Standards fair value measurement and disclosure requirements. This amendment changes the wording used to describe many of the requirements in GAAP for measuring fair value and for disclosing information about fair value measurements, particularly for Level 3 fair value measurements. For many of the requirements, the FASB does not intend for the amendments to result in a change in the application of the fair value measurement and disclosure requirements. Some of the amendments clarify the FASB's intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. This ASU is effective for interim and annual periods beginning after December 15, 2011 and requires prospective application. We adopted this ASU on January 1, 2012. The adoption of this ASU, which expanded our fair value disclosures, did not have a material impact on our financial position, results of operations or cash flows.

In December 2011, the FASB issued an ASU that requires companies to disclose information about financial instruments that have been offset and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. Companies will be required to provide both net (offset amounts) and gross information in the notes to the financial statements for relevant assets and liabilities that are offset. This update is effective for interim and annual periods beginning on or after January 1, 2013 and requires retrospective application. We do not expect the adoption of this ASU to have a material impact on our financial position, results of operations or cash flows.

3.  Financial Instruments
 
Our risk management programs are intended to reduce our exposure to commodity prices and interest rates and to assist with stabilizing cash flow and distributions.  Routinely, we utilize derivative financial instruments to reduce this volatility. To the extent we have hedged a significant portion of our expected production through commodity derivative instruments and the cost for goods and services increases, our margins would be adversely affected.

Commodity Activities

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


5


We had the following commodity derivative contracts in place at June 30, 2012:

 
Year
 
2012
 
2013
 
2014
 
2015
 
2016
 
2017
Oil Positions:
 
 
 
 
 
 
 
 
 
 
 
Fixed Price Swaps - NYMEX WTI
 
 
 
 
 
 
 
 
 
 
 
Hedged Volume (Bbl/d)
2,700

 
2,580

 
2,500

 
3,000

 
1,000

 

Average Price ($/Bbl)
$
86.12

 
$
87.13

 
$
92.62

 
$
98.90

 
$
93.08

 
$

Fixed Price Swaps - IPE Brent
 
 
 
 
 
 
 
 
 
 
 
 Hedged Volume (Bbl/d)
2,339

 
3,900

 
3,500

 
2,000

 
500

 

Average Price ($/Bbl)
$
105.37

 
$
97.23

 
$
96.86

 
$
96.46

 
$
95.55

 
$

Collars - NYMEX WTI
 
 
 
 
 
 
 
 
 
 
 
Hedged Volume (Bbl/d)
2,384

 
500

 
1,000

 
1,000

 

 

Average Floor Price ($/Bbl)
$
110.00

 
$
77.00

 
$
90.00

 
$
90.00

 
$

 
$

Average Ceiling Price ($/Bbl)
$
145.37

 
$
103.10

 
$
112.00

 
$
113.50

 
$

 
$

Collars - IPE Brent
 
 
 
 
 
 
 
 
 
 
 
Hedged Volume (Bbl/d)

 

 

 
500

 
500

 

Average Floor Price ($/Bbl)
$

 
$

 
$

 
$
90.00

 
$
90.00

 
$

Average Ceiling Price ($/Bbl)
$

 
$

 
$

 
$
109.50

 
$
101.25

 
$

Swaptions - NYMEX WTI
 
 
 
 
 
 
 
 
 
 
 
 Hedged Volume (Bbl/d)
886

 
791

 
645

 
546

 
484

 
222

Average Price ($/Bbl)
$
100.84

 
$
99.45

 
$
95.13

 
$
91.63

 
$
89.28

 
$
88.12

Total:
 
 
 
 
 
 
 
 
 
 
 
Hedged Volume (Bbl/d)
8,309

 
7,771

 
7,645

 
7,046

 
2,484

 
222

Average Price ($/Bbl)
$
99.96

 
$
92.80

 
$
94.43

 
$
95.75

 
$
92.21

 
$
88.12


 
 
 
 
 
 
 
 
 
 
 
Gas Positions:
 
 
 
 
 
 
 
 
 
 
 
Fixed Price Swaps - Mich Con City-Gate
 
 
 
 
 
 
 
 
 
 
 
Hedged Volume (MMBtu/d)
18,730

 
37,000

 
7,500

 
7,500

 

 

Average Price ($/MMBtu)
$
7.10

 
$
6.50

 
$
6.00

 
$
6.00

 
$

 
$

Fixed Price Swaps - Henry Hub
 
 
 
 
 
 
 
 
 
 
 
Hedged Volume (MMBtu/d)
16,000

 
19,000

 
36,000

 
40,500

 
13,000

 

Average Price ($/MMBtu)
$
4.88

 
$
4.90

 
$
4.86

 
$
4.88

 
$
4.18

 
$

Collars - Mich Con City-Gate
 
 
 
 
 
 
 
 
 
 
 
Hedged Volume (MMBtu/d)
18,732

 

 

 

 

 

Average Floor Price ($/MMBtu)
$
9.00

 
$

 
$

 
$

 
$

 
$

Average Ceiling Price ($/MMBtu)
$
11.60

 
$

 
$

 
$

 
$

 
$

Puts - Henry Hub
 
 
 
 
 
 
 
 
 
 
 
Hedged Volume (MMBtu/d)

 

 
6,000

 
1,500

 

 

Average Price ($/MMBtu)
$

 
$

 
$
5.00

 
$
5.00

 
$

 
$

Total:
 
 
 
 
 
 
 
 
 
 
 
Hedged Volume (MMBtu/d)
53,462

 
56,000

 
49,500

 
49,500

 
13,000

 

Average Price ($/MMBtu)
$
7.10

 
$
5.96

 
$
5.05

 
$
5.05

 
$
4.18

 
$

 
 
 
 
 
 
 
 
 
 
 
 
 Calls - Henry Hub
 
 
 
 
 
 
 
 
 
 
 
Hedged Volume (MMBtu/d)

 
30,000

 
15,000

 

 

 

Average Price ($/MMBtu)
$

 
$
8.00

 
$
9.00

 
$

 
$

 
$

Premium ($/MMBtu)
$

 
$
0.08

 
$
0.12

 
$

 
$

 
$

    


6


Included in the above table are natural gas swaps and put options we entered into in June 2012, hedging a total of 18,628 BBtu from January 1, 2014 to December 31, 2016 at a weighted average Henry Hub price of $4.30 per MMBtu, for which we paid premiums of approximately $7.0 million.

The following swaption contracts are also included in the table above. In April 2012, we entered into swaption contracts that provide options to hedge a total of 510,168 barrels of future crude oil production associated with the NiMin Energy Corp. ("NiMin") acquisition (see Note 6 and Note 16 for a discussion of this acquisition and exercise of related swaption contracts) at then-current NYMEX WTI market prices, ranging from $104.80 per barrel in 2012 to $88.45 per barrel in 2017. These contracts have an option expiration date and premium due date of July 31, 2012 and total deferred premiums of $2.5 million. In May 2012, we also entered into swaption contracts that provide options to hedge a total of 634,485 barrels of future crude oil production associated with the Element Petroleum, LP (“Element”) and CrownRock, L.P. (“CrownRock”) acquisitions (see Note 6 and Note 16 for a discussion of these two acquisitions and exercise of related swaption contracts) at then-current NYMEX WTI prices, ranging from $98.35 per barrel in 2012 to $87.80 per barrel in 2017. These contracts have an option expiration date and premium due date of July 16, 2012 and total deferred premiums of $2.6 million.

Interest Rate Activities

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates.  As of June 30, 2012, our total debt outstanding under our credit facility was $225.0 million.  In order to mitigate our interest rate exposure, we had the following interest rate derivative contracts in place at June 30, 2012 that fixed rates for the floating LIBOR-based portion of debt under our credit facility:

Notional amounts in thousands of dollars
 
Notional Amount
 
Fixed Rate
Period Covered
 
 
 
 
July 1, 2012 to December 20, 2012
 
$
100,000

 
1.1550
%
July 1, 2012 to January 20, 2014
 
$
100,000

 
2.4800
%

Fair Value of Financial Instruments
 
Fair value of derivative instruments not designated as hedging instruments:
Balance sheet location, thousands of dollars
 
Oil Commodity Derivatives
 
Natural Gas
Commodity Derivatives
 
Interest Rate
Derivatives
 
Commodity Derivatives Netting (a)
 
Total Financial Instruments
 
 
 
 
 
 
 
 
 
 
 
As of June 30, 2012
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
Current assets - derivative instruments
 
$
18,094

 
$
62,637

 
$

 
$
(1,115
)
 
$
79,616

Other long-term assets - derivative instruments
 
30,340

 
56,821

 

 

 
87,161

Total assets
 
48,434

 
119,458

 

 
(1,115
)
 
166,777

 
 
 
 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
 
 
 
Current liabilities - derivative instruments
 
(1,115
)
 

 
(2,487
)
 
1,115

 
(2,487
)
Long-term liabilities - derivative instruments
 

 

 
(1,104
)
 

 
(1,104
)
Total liabilities
 
(1,115
)
 

 
(3,591
)
 
1,115

 
(3,591
)
 
 
 
 
 
 
 
 
 
 
 
Net assets (liabilities)
 
$
47,319

 
$
119,458

 
$
(3,591
)
 
$

 
$
163,186

 
 
 
 
 
 
 
 
 
 
 
As of December 31, 2011
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
Current assets - derivative instruments
 
$
11,795

 
$
73,312

 
$

 
$
(1,655
)
 
$
83,452

Other long-term assets - derivative instruments
 
6,032

 
58,605

 

 
(9,300
)
 
55,337

Total assets
 
17,827

 
131,917

 

 
(10,955
)
 
138,789

 
 
 
 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
 
 
 
Current liabilities - derivative instruments
 
(8,032
)
 

 
(2,504
)
 
1,655

 
(8,881
)
Long-term liabilities - derivative instruments
 
(10,520
)
 

 
(1,864
)
 
9,300

 
(3,084
)
Total liabilities
 
(18,552
)
 

 
(4,368
)
 
10,955

 
(11,965
)
 
 
 
 
 
 
 
 
 
 
 
Net assets (liabilities)
 
$
(725
)
 
$
131,917

 
$
(4,368
)
 
$

 
$
126,824

 
 
 
 
 
 
 
 
 
 
 
(a) Represents counterparty netting under derivative netting agreements. These contracts are reflected net on the balance sheet.

7


Gains and losses on derivative instruments not designated as hedging instruments:

Thousands of dollars
 
Oil Commodity
Derivatives (a)
 
Natural Gas
Commodity Derivatives (a)
 
Interest Rate
Derivatives (b)
 
Total Financial Instruments
Three Months Ended June 30, 2012
 
 
 
 
 
 
 
 
Realized gain (loss)
 
$
1,778

 
$
23,285

 
$
(803
)
 
$
24,260

Unrealized gain (loss)
 
112,065

 
(29,840
)
 
613

 
82,838

Net gain (loss)
 
$
113,843

 
$
(6,555
)
 
$
(190
)
 
$
107,098

 
 
 
 
 
 
 
 
 
Three Months Ended June 30, 2011
 
 
 
 
 
 
 
 
Realized gain (loss)
 
$
(11,922
)
 
$
10,171

 
$
(1,065
)
 
$
(2,816
)
Unrealized gain (loss)
 
52,595

 
(4,361
)
 
(1,155
)
 
47,079

Net gain (loss)
 
$
40,673

 
$
5,810

 
$
(2,220
)
 
$
44,263

 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2012
 
 
 
 
 
 
 
 
Realized gain (loss)
 
$
(2,850
)
 
$
45,504

 
$
(1,461
)
 
$
41,193

Unrealized gain (loss)
 
48,042

 
(19,413
)
 
777

 
29,406

Net gain (loss)
 
$
45,192

 
$
26,091

 
$
(684
)
 
$
70,599

 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2011
 
 
 
 
 
 
 
 
Realized gain (loss)
 
$
(20,545
)
 
$
25,237

 
$
(2,088
)
 
$
2,604

Unrealized gain (loss)
 
(43,941
)
 
(20,445
)
 
211

 
(64,175
)
Net gain (loss)
 
$
(64,486
)
 
$
4,792

 
$
(1,877
)
 
$
(61,571
)

(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.

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 other than quoted prices that are included in 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 derivatives that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3.  As of June 30, 2012 and December 31, 2011, our Level 3 derivative assets and liabilities consisted entirely of OTC commodity put and call options.

Financial assets and liabilities that are categorized in Level 3 may later be reclassified to the Level 2 category at the point we are able to obtain sufficient binding market data.  We had no transfers in or out of Levels 1, 2 or 3 during the three months and six months ended June 30, 2012 and June 30, 2011. Our policy is to recognize transfers between levels as of the end of the period.
 

8


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

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

Our assessment of the significance of an input to its fair value measurement requires judgment and can affect the valuation of the assets and liabilities as well as the category within which they are classified. Financial assets and liabilities carried at fair value on a recurring basis are presented in the following table.  

Thousands of dollars
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
 
 
 
 
 
 
 
As of June 30, 2012
 
 
 
 
 
 
 
 
Assets (liabilities):
 
 
 
 
 
 
 
 
Commodity derivatives (swaps, put and call options)
 
$

 
$
122,473

 
$
44,304

 
$
166,777

Other derivatives (interest rate swaps)
 

 
(3,591
)
 

 
(3,591
)
Total
 
$

 
$
118,882

 
$
44,304

 
$
163,186

 
 
 
 
 
 
 
 
 
As of December 31, 2011
 
 
 
 
 
 
 
 
Assets (liabilities):
 
 
 
 
 
 
 
 
Commodity derivatives (swaps, put and call options)
 
$

 
$
85,634

 
$
45,558

 
$
131,192

Other derivatives (interest rate swaps)
 

 
(4,368
)
 

 
(4,368
)
Total
 
$

 
$
81,266

 
$
45,558

 
$
126,824


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

 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
Thousands of dollars
 
2012
 
2011
 
2012
 
2011
Assets:
 
 
 
 
 
 
 
 
Beginning balance
 
$
36,755

 
$
69,071

 
$
45,558

 
$
86,253

Realized gain (a)
 
15,475

 
11,765

 
28,085

 
16,490

Unrealized loss (a)
 
(11,704
)
 
(17,155
)
 
(33,117
)
 
(39,062
)
Purchases (b)
 
3,778

 

 
3,778

 

Ending balance
 
$
44,304

 
$
63,681

 
$
44,304

 
$
63,681


(a) Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations.
(b) Relates to premiums paid for natural gas put options entered into in June 2012.

During the periods presented, we had no changes in the fair value of our derivative instruments classified as Level 3 related to sales, issuances or settlements.

9


    
For Level 3 derivatives measured at fair value on a recurring basis as of June 30, 2012, the significant unobservable inputs used in the fair value measurements were as follows:

 
 
Fair Value at
 
Valuation
 
 
 
 
Thousands of dollars
 
June 30, 2012
 
 Technique
 
Unobservable Input
 
Range
Oil Collars
 
$
17,927

 
Option Pricing Model
 
Oil forward commodity prices
 
$85.09/Bbl - $97.84/Bbl
Oil Swaptions
 
4,135

 
 
 
Oil volatility
 
21.14% -32.25%
 
 
 
 
 
 
Own credit risk
 
5%
Natural Gas Collars
 
20,116

 
Option Pricing Model
 
Gas forward commodity prices
 
$2.77/MMBtu - $4.69/MMBtu
Natural Gas Calls
 
(1,328
)
 
 
 
Gas volatility
 
22.45%-57.10%
Natural Gas Puts
 
3,454

 
 
 
Own credit risk
 
5%
Total
 
$
44,304

 
 
 
 
 
 

Credit and Counterparty Risk

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of derivatives and accounts receivable.  Our derivatives expose us to credit risk from counterparties.  As of June 30, 2012, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia, BNP Paribas, U.S Bank National Association and Toronto-Dominion Bank.  We periodically obtain credit default swap information on our counterparties.  As of June 30, 2012, each of these financial institutions had an investment grade credit rating.  Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default.  As of June 30, 2012, our largest derivative asset balances were with JP Morgan Chase Bank N.A., Credit Suisse Energy LLC and Wells Fargo Bank National Association, which accounted for approximately 19%, 16% and 15% of our derivative asset balances, respectively.  As of June 30, 2012, our largest derivative liability balance was with The Royal Bank of Scotland plc, which accounted for approximately 90% of our derivative liability balances.

4.  Related Party Transactions

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

BreitBurn Management also provides administrative services to Pacific Coast Energy Company L.P., formerly named BreitBurn Energy Company L.P. ("PCEC"), our predecessor, under an administrative services agreement, in exchange for a monthly fee for indirect expenses and reimbursement for all direct expenses, including incentive compensation plan costs and direct payroll and administrative costs related to PCEC properties and operations.  

On May 8, 2012, Pacific Coast Oil Trust (the "Trust"), which was formed by PCEC, completed its initial public offering (the "Trust IPO").  We have no direct or indirect ownership interest in PCEC or the Trust.  As part of the Trust IPO, PCEC conveyed net profits interests in its oil and natural gas production from certain of its properties to the Trust in exchange for Trust units.  PCEC's assets consist primarily of producing and non-producing crude oil reserves located in Santa Barbara, Los Angeles and Orange Counties in California, including certain interests in the East Coyote and Sawtelle Fields (as described below). 

Prior to April 1, 2012, we owned the limited partner interest (99%) of BreitBurn Energy Partners I, L.P. ("BEPI").  See Note 14 for additional discussion of BEPI. BEPI's general partner interest was held by PCEC, and PCEC also held a 35% reversionary interest under the limited partnership agreement applicable to the East Coyote and Sawtelle properties, which was expected to result in an increase in PCEC's ownership in the properties during the second quarter of 2012.  PCEC operated the Sawtelle and East Coyote Fields until April 1, 2012 for the benefit of itself and the Partnership.  We and PCEC a

10


greed to dissolve the BEPI partnership and liquidate the properties and assets of the BEPI partnership as of April 1, 2012. As a result of such agreement, effective April 1, 2012, PCEC's ownership interest in both of these fields increased, and our ownership in both fields was reduced from approximately 95% to approximately 62%. In addition, we became the operator of both of these fields and now no longer pay an operating fee to PCEC. PCEC agreed to pay a development fee equal to 5% of the cost of development of the properties, and upon termination of the Third Amended and Restated Services Agreement (as described below), an operating fee of 15% of the cost of operating the properties.

On May 8, 2012, BreitBurn Management entered into the Third Amended and Restated Administrative Services Agreement (the "Third Amended and Restated Administrative Services Agreement") with PCEC, pursuant to which the parties agreed to increase the monthly fee charged by BreitBurn Management to PCEC for indirect costs. For the first three months of 2012, the monthly fee charged by BreitBurn Management to PCEC for indirect costs was set at $571,000, and the two parties agreed to increase that monthly fee to $700,000, effective April 1, 2012. In connection with the PCEC transactions and the Third Amended and Restated Administrative Services Agreement, PCEC also paid us a $250,000 fee.

In connection with the Trust IPO, we, BreitBurn GP, LLC and BreitBurn Management entered into the First Amendment to Omnibus Agreement, dated as of May 8, 2012, with PCEC, Pacific Coast Energy Holdings LLC, formerly known as BreitBurn Energy Holdings, LLC, and PCEC (GP) LLC, formerly known as BEC (GP) LLC (the “First Amendment to Omnibus Agreement ”). Pursuant to the First Amendment to Omnibus Agreement, the parties agreed to amend the Omnibus Agreement among the parties, dated as of August 26, 2008 (the “ Omnibus Agreement ”), to remove Article III of the Omnibus Agreement, which contained our right of first offer with respect to the sale of assets by PCEC and its affiliates.

At June 30, 2012 and December 31, 2011, we had current receivables of $1.0 million and $2.8 million, respectively, due from PCEC related to the applicable administrative services agreement and employee related costs and oil and gas sales made by PCEC on our behalf from certain properties.  For the three months and six months ended June 30, 2012, the monthly charges to PCEC for indirect expenses totaled $2.1 million and $3.8 million, respectively, and charges for direct expenses including direct payroll and administrative costs totaled $2.0 million and $4.0 million, respectively. For the three months and six months ended June 30, 2011, the monthly charges to PCEC for indirect expenses totaled $1.5 million and $2.9 million, respectively, and charges for direct expenses including direct payroll and administrative costs totaled $1.9 million and $3.7 million, respectively.  For the three months ended June 30, 2012, total net oil and gas sales made by us on PCEC's behalf were approximately $1.8 million and for the six months ended June 30, 2012, total net oil and gas sales made by PCEC on our behalf were approximately $1.2 million. For the three months and six months ended June 30, 2011, total net oil and gas sales made by PCEC on our behalf were approximately $3.3 million and $6.8 million, respectively.

At June 30, 2012 and December 31, 2011, we had receivables of $1.1 million and $1.4 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.

5.  Inventory

Our crude oil inventory from our Florida operations was $5.3 million at June 30, 2012 and $4.7 million at December 31, 2011.  During the six months ended June 30, 2012, we sold 384 gross MBbls and produced 416 gross MBbls of crude oil from our Florida operations.  Crude oil sales are a function of the number and size of crude oil shipments in each quarter and thus crude oil sales do not always coincide with volumes produced in a given quarter.  Crude oil inventory additions are valued at the lower of cost or market, with cost based on our actual production costs.  We match production expenses with crude oil sales.  Production expenses associated with unsold crude oil inventory are recorded to inventory.

6. Acquisitions

On June 28, 2012, we completed the acquisition of oil properties located in Park County in the Big Horn Basin of Wyoming from Legacy Energy, Inc., a wholly-owned subsidiary of NiMin, with an effective date of April 1, 2012 (the "NiMin Acquisition"). We used borrowings under our credit facility to fund the acquisition. The properties are 100% oil and produced approximately 500 Boe/d in the three months ended June 30, 2012. This acquisition was accounted for under the acquisition method of accounting.


11


The preliminary purchase price for this acquisition was approximately $92.8 million in cash, and was allocated to the assets acquired and liabilities assumed as follows:

Thousands of dollars
 
 
 
 
 
Oil and gas properties
 
$
96,308

Accrued liabilities
 
(1,863
)
Asset retirement obligation
 
(1,609
)
 
 
$
92,836


We conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred. Acquisition related costs for the NiMin Acquisition were $0.1 million and were reflected in general and administrative expenses on the consolidated statements of operations. The initial accounting for the acquisition is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition date. Revenues and expenses from the NiMin properties are reflected in our consolidated statements of operations beginning June 28, 2012.

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

On May 10, 2012, we signed two separate agreements to acquire oil and natural gas properties located in the Permian Basin in Texas from Element and CrownRock for $150 million and $70 million, respectively, subject to customary post-closing conditions and purchase price adjustments. In connection with these agreements, we paid performance guarantee deposits of 10% of the unadjusted purchase price to each of Element and CrownRock. The properties are 56% oil and produced approximately 1,940 Boe/day in the three months ended June 30, 2012. The acquisitions closed on July 2, 2012 (see Note 16).

On October 6, 2011, we completed the acquisition of oil and gas properties from Cabot Oil & Gas Corporation located primarily in the Evanston and Green River Basins in southwestern Wyoming (the "Cabot Acquisition"), with an effective date of September 1, 2011. The following unaudited pro forma financial information presents a summary of our combined statement of operations for the three months and six months ended June 30, 2011, assuming the Cabot Acquisition had been completed on January 1, 2011, including adjustments to reflect the allocation of the preliminary purchase price to the acquired net assets. The pro forma financial information is not necessarily indicative of the results of operations if the acquisition had been effective January 1, 2011.

  
 
 Pro Forma
 Thousands of dollars, except per unit amounts
 
 Three Months Ended June 30, 2011
 
 Six Months Ended June 30, 2011
 Revenues
 
$
157,083

 
$
157,280

 Net income (loss) attributable to the partnership
 
62,062

 
(30,256
)
 
 
 
 
 
 Net income per unit:
 
  
 
  
 Basic
 
$
1.00

 
$
(0.52
)
 Diluted
 
$
1.00

 
$
(0.52
)


12


7.  Impairments

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

Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles, and the outlook for market supply and demand conditions for crude oil and natural gas. For purposes of performing an impairment test, the undiscounted future cash flows are based on total proved and risk-adjusted probable and possible reserves, and are forecast using five-year NYMEX forward strip prices at the end of the period and escalated along with expenses and capital starting year six and thereafter at 2.5% per year. For impairment charges, the associated property’s expected future net cash flows are discounted using a market-based weighted average cost of capital rate that approximates 10%. Additional inputs include crude oil and natural gas reserves, future operating and development costs and future commodity prices. We consider the inputs for our impairment calculations to be Level 3 inputs. The impairment reviews and calculations are based on assumptions that are consistent with our business plans.

During the three months ended June 30, 2012, we recorded non-cash impairment charges of approximately $3.3 million related to uneconomic proved properties in Michigan and California due to lower crude oil and natural gas prices. During the six months ended June 30, 2012, we recorded non-cash impairment charges of approximately $11.6 million related to uneconomic proved properties primarily in Michigan, Indiana and Kentucky due to lower natural gas prices and the Alamitos field due to lower crude oil prices. During the year ended December 31, 2011, we recorded non-cash impairment charges of approximately $0.6 million related to uneconomic proved properties in Michigan primarily due to a decrease in natural gas prices.

An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in impairment reviews and calculations is not practicable, given the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.

8.  Long-Term Debt

Senior Notes Due 2020

On October 6, 2010, we and BreitBurn Finance Corporation (the "Issuers"), and certain of our subsidiaries as guarantors (the "Guarantors"), issued $305 million in aggregate principal amount of 8.625% Senior Notes due 2020 (the "2020 Senior Notes"). The 2020 Senior Notes were offered at a discount price of 98.358%, or $300 million. The $5 million discount is being amortized over the life of the 2020 Senior Notes. As of June 30, 2012, the 2020 Senior Notes had a carrying value of $300.8 million, net of unamortized discount of $4.2 million. Interest on the 2020 Senior Notes is payable twice a year in April and October.

As of June 30, 2012, the fair value of the 2020 Senior Notes was estimated to be $322.5 million, based on prices quoted from third party financial institutions. We consider the inputs to the valuation of our 2020 Senior Notes to be Level 2, as fair value was estimated based on prices quoted from third party financial institutions.

Senior Notes Due 2022

On January 10, 2012, the Issuers, and certain of our subsidiaries as Guarantors, issued $250 million in aggregate principal amount of 7.875% Senior Notes due 2022 (the "2022 Senior Notes") which were purchased by the initial purchasers as defined in the purchase agreement (the "Initial Purchasers"). The 2022 Senior Notes have not been registered under the Securities Act of 1933, as amended (the "Securities Act"), or any state securities laws, and unless so registered, the securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The 2022 Senior Notes were resold by the Initial Purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the

13


United States pursuant to Regulation S under the Securities Act. The 2022 Senior Notes were issued at a discount of 99.154%, or $247.9 million. The $2.1 million discount will be amortized over the life of the 2022 Senior Notes. In connection with the 2022 Senior Notes, our estimated financing fees and expenses were approximately $5.6 million, which will be amortized over the life of the 2022 Senior Notes.

In connection with the issuance of the 2022 Senior Notes, we entered into a Registration Rights Agreement (the "Registration Rights Agreement") with the Guarantors and Initial Purchasers. Under the Registration Rights Agreement, the Issuers and the Guarantors agreed to cause to be filed with the Securities and Exchange Commission a registration statement with respect to an offer to exchange the 2022 Senior Notes for substantially identical notes that are registered under the Securities Act. The Issuers and the Guarantors agreed to use their commercially reasonable efforts to cause such exchange offer registration statement to become effective under the Securities Act. In addition, the Issuers and the Guarantors agreed to use their commercially reasonable efforts to cause the exchange offer to be consummated not later than 400 days after January 13, 2012.  If the offer to exchange is not completed on or before the 400th day following January 13, 2012, the annual interest rate borne by the notes will increase by 1% per annum until the exchange offer is completed.

As of June 30, 2012, the 2022 Senior Notes had a carrying value of $248.0 million, net of unamortized discount of $2.0 million. Interest on the 2022 Senior Notes is payable twice a year in April and October. As of June 30, 2012, the fair value of the 2022 Senior Notes was estimated to be $249.4 million, based on prices quoted from third-party financial institutions. We consider the inputs to the valuation of our 2022 Senior Notes to be Level 2, as fair value was estimated based on prices quoted from third-party financial institutions.

Credit Facility

BreitBurn Operating L.P. ("BOLP"), as borrower, and we and our wholly-owned subsidiaries, as guarantors have a $1.5 billion revolving credit facility with Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and Issuing Lender, and a syndicate of banks (the "Second Amended and Restated Credit Agreement") with a maturity date of May 9, 2016. Borrowings under the Second Amended and Restated Credit Agreement are secured by first-priority liens on and security interests in substantially all of our and certain of our subsidiaries' assets, representing not less than 80% of the total value of our oil and gas properties.

The Second Amended and Restated Credit Agreement contains customary covenants, including restrictions on our ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to our unitholders or repurchase units (including the restriction on our ability to make distributions unless, after giving effect to such distribution, we remain in compliance with all terms and conditions of our credit facility); make dispositions or enter into sales and leasebacks; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries.

The events that constitute an Event of Default (as defined in the Second Amended and Restated Credit Agreement) include: payment defaults, misrepresentations, breaches of covenants, cross-default and cross-acceleration to certain other indebtedness, adverse judgments against us in excess of a specified amount, changes in management or control, loss of permits, certain insolvency events and assertion of certain environmental claims.

As of June 30, 2012 and December 31, 2011, we were in compliance with our credit facility's covenants.

As of December 31, 2011 our borrowing base was $850 million. In January 2012, in connection with the issuance of the 2022 Senior Notes, our borrowing base was automatically reduced to $787.5 million in accordance with the terms of our credit facility. In April 2012, our borrowing base was redetermined and increased from $787.5 million to $850.0 million. Our next semi-annual borrowing base redetermination is scheduled for October 2012.

On May 25, 2012, we entered into the Fifth Amendment to the Second Amended and Restated Credit Agreement, which increased the permitted amount of senior unsecured notes we may issue from $700 million to $1 billion.

As of June 30, 2012 and December 31, 2011, we had $225 million and $520 million, respectively, in indebtedness outstanding under our credit facility. At June 30, 2012, the one-month LIBOR interest rate plus an applicable spread was 2.120% on the one-month LIBOR portion of $225 million.


14


The amounts reported on our consolidated balance sheets for our credit facility debt approximate fair value due to the variable nature of our interest rates. Our credit facility can be repaid at any time without penalty. Interest is generally fixed for 30-day increments at LIBOR plus a stipulated margin for the amount utilized and at a stipulated percentage as a commitment fee for the portion not utilized or fixed daily at the Prime rate plus a stipulated margin. We use a market approach to ensure the terms of our credit facility are in line with market rates for similar credit facilities, which are considered to be Level 2 inputs.
 
Our interest and other financing costs, as reflected in interest expense, net of capitalized interest on the consolidated statements of operations, are detailed in the following table:

 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
Thousands of dollars
 
2012
 
2011
 
2012
 
2011
Credit agreement (including commitment fees)
 
$
1,282

 
$
1,327

 
$
3,042

 
$
3,017

Senior notes
 
11,498

 
6,504

 
22,286

 
13,007

Amortization of discount and deferred issuance costs
 
1,289

 
1,249

 
2,541

 
2,553

Capitalized interest
 

 

 

 
(77
)
Total
 
$
14,069

 
$
9,080

 
$
27,869

 
$
18,500


9. Condensed Consolidating Financial Statements

We and BreitBurn Finance Corporation, and certain of our subsidiaries as guarantors, issued the 2020 Senior Notes and the 2022 Senior Notes. Effective April 1. 2012, we and PCEC agreed to dissolve BEPI (see Note 14 for additional discussion of BEPI). With the dissolution of BEPI, all but one of our subsidiaries have guaranteed our senior notes and our only remaining non-guarantor subsidiary, BreitBurn Collingwood Utica LLC, is a minor subsidiary.

In accordance with Rule 3-10 of Regulation S-X, we are not presenting condensed consolidation financial statements as we have no independent assets or operations, BreitBurn Finance Corporation, the subsidiary issuer, is a 100% owned finance subsidiary, all of our material subsidiaries other than the subsidiary issuer have guaranteed our senior notes and all of the guarantees are full, unconditional, joint and several.

10.  Income Taxes

Our deferred income tax liability was $2.9 million and $2.8 million at June 30, 2012 and December 31, 2011, respectively.  The following table presents our income tax expense (benefit) for the three months and six months ended June 30, 2012 and 2011
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
Thousands of dollars
 
2012
 
2011
 
2012
 
2011
Federal income tax expense (benefit)
 
 
 
 
 
 
 
 
Current
 
$
88

 
$
98

 
$
264

 
$
126

Deferred (a)
 
905

 
514

 
126

 
(518
)
State income tax expense (b)
 
12

 
4

 
56

 
6

Total
 
$
1,005

 
$
616

 
$
446

 
$
(386
)

(a) Related to Phoenix Production Company, a tax-paying corporation and our wholly-owned subsidiary.
(b) Primarily in California and Michigan.


15


11.  Asset Retirement Obligation

Our asset retirement obligation 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 asset retirement obligations occur over the operating lives of the assets, estimated to be from less than one year to 50 years.  Estimated cash flows have been discounted at our average credit-adjusted risk free rate which approximates 7% and adjusted for inflation using a rate of 2%.  Our credit-adjusted risk free rate is calculated based on our cost of borrowing adjusted for the effect of our credit standing and specific industry and business risk.

We consider the inputs to our asset retirement obligation 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 the asset retirement obligation for the six months ended June 30, 2012 and the year ended December 31, 2011 are presented in the following table:

 
 
Six Months Ended
 
Year Ended
Thousands of dollars
 
June 30, 2012
 
December 31, 2011
Carrying amount, beginning of period
 
$
82,397

 
$
47,429

Acquisitions (a)
 
1,609

 
10,980

Liabilities incurred
 
716

 
5,701

Liabilities settled
 
(525
)
 
(5,301
)
Revisions (b)
 
(2,266
)
 
20,005

Accretion expense
 
2,871

 
3,583

Carrying amount, end of period
 
$
84,802

 
$
82,397


(a) Primarily relates to the NiMin Acquisition in 2012 and the Cabot Acquisition in 2011.
(b) 2011 revisions relate to increased cost estimates and revisions to reserve life. 2012 revisions relate to the dissolution of BEPI.

12.  Commitments and Contingencies

Surety Bonds and Letters of Credit

In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit.  These obligations primarily cover self-insurance and other programs where governmental organizations require such support.  These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon.  At June 30, 2012 and December 31, 2011, we had surety bonds for $18.8 million and $22.1 million, respectively.  At each of June 30, 2012 and December 31, 2011, we had approximately $0.3 million in letters of credit outstanding.

13.  Partners’ Equity

In February 2012, we sold 9.2 million of our limited partnership units ("Common Units") at a price to the public of $18.80 per Common Unit, resulting in proceeds net of underwriting discount and offering expenses of $166.0 million.

During the first six months of 2012, we issued less than 0.1 million Common Units to outside directors for phantom units and Restricted Phantom Units ("RPUs") that were granted in 2009 and 2011 and vested in January 2012.

At June 30, 2012 and December 31, 2011, we had approximately 69.1 million and 59.9 million Common Units outstanding, respectively.  At June 30, 2012 and December 31, 2011, there were approximately 2.6 million and 1.7 million, respectively, of units outstanding under the First Amended and Restated 2006 Long-Term Incentive Plan ("LTIP") that were eligible to be paid in Common Units upon vesting.


16


Cash Distributions

On February 14, 2012, we paid a cash distribution of approximately $27.0 million to our common unitholders of record as of the close of business on February 6, 2012. The distribution that was paid to unitholders was $0.4500 per Common Unit. On May 14, 2012, we paid a cash distribution of approximately $31.5 million to our common unitholders of record as of the close of business on May 7, 2012. The distribution that was paid to unitholders was $0.4550 per Common Unit.

During the three months and six months ended June 30, 2012, we also paid $1.2 million and $2.3 million in cash at a rate equal to the distributions paid to our unitholders, to holders of outstanding unvested RPUs and Convertible Phantom Units ("CPUs"), issued under our LTIP.

On February 11, 2011, we paid a cash distribution of approximately $22.4 million to our common unitholders of record as of the close of business on February 8, 2011. The distribution that was paid to unitholders was $0.4125 per Common Unit. On May 13, 2011, we paid a cash distribution of approximately $24.6 million to our common unitholders of record as of the close of business on May 10, 2011. The distribution that was paid to unitholders was $0.4175 per Common Unit.

During the three months and six months ended June 30, 2011, we also paid $1.3 million and $2.5 million in cash, at a rate equal to the distributions paid to our unitholders, to holders of outstanding unvested RPUs and CPUs.

Earnings per Unit

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

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

 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
Thousands, except per unit amounts
 
2012
 
2011
 
2012
 
2011
 
 
 
 
 
 
 
 
 
Net income (loss) attributable to the partnership
 
$
92,506

 
$
57,455

 
$
42,536

 
$
(37,292
)
Distributions on participating units not expected to vest
 

 
1

 

 
1

Net income (loss) attributable to common unitholders and participating securities
 
$
92,506

 
$
57,456

 
$
42,536

 
$
(37,291
)
Weighted average number of units used to calculate basic and diluted net income (loss) per unit:
 
 

 
 

 
 
 
 
Common Units
 
69,144

 
59,040

 
67,577

 
57,920

Participating securities (a)
 
2,556

 
3,023

 
2,491

 

Denominator for basic earnings per common unit
 
71,700

 
62,063

 
70,068

 
57,920

Dilutive units (b)
 
57

 
133

 
57

 

Denominator for diluted earnings per common unit
 
71,757

 
62,196

 
70,125

 
57,920

Net income (loss) per common unit
 
 

 
 

 
 
 
 
Basic
 
$
1.29

 
$
0.93

 
$
0.61

 
$
(0.64
)
Diluted
 
$
1.29

 
$
0.92

 
$
0.61

 
$
(0.64
)

(a) The six months ended June 30, 2011 excludes 2,956 of potentially issuable weighted average RPUs and CPUs from participating securities, as we were in a loss position.
(b) The six months ended June 30, 2011 excludes 132 of weighted average anti-dilutive units from the calculation of the

17


denominator for diluted earnings per common unit.

14.  Noncontrolling Interest

FASB Accounting Standards require that noncontrolling interests be classified as a component of equity and establish reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.

On May 25, 2007, we acquired the limited partner interest (99%) of BEPI.  As such, we were fully consolidating the results of BEPI and were recognizing a noncontrolling interest representing the book value of BEPI's general partner’s interests.  BEPI’s general partner interest was held by a wholly owned subsidiary of PCEC. At each of March 31, 2012 and December 31, 2011, the amount of this noncontrolling interest was $0.5 million.  

Prior to April 1, 2012, BEPI's general partner interest was held by PCEC, and PCEC held a 35% reversionary interest under the limited partnership agreement applicable to the East Coyote and Sawtelle properties, which was expected to result in an increase in PCEC's ownership and a corresponding decrease in our ownership in the properties during the second quarter of 2012.  PCEC operated the Sawtelle and East Coyote Fields until April 1, 2012 for the benefit of itself and us.  We and PCEC agreed to dissolve BEPI and liquidate the properties and assets of the BEPI partnership as of April 1, 2012. As a result of such agreement, effective April 1, 2012, PCEC's ownership interest in both of these fields increased, and our ownership in both fields has decreased from approximately 95% to approximately 62%. As of June 30, 2012, the amount of the noncontrolling interest was zero.

15.  Unit and Other Valuation-Based Compensation Plans

Unit-based compensation expense for the three months and six months ended June 30, 2012 was $5.6 million and $11.2 million, respectively, and for the three months and six months ended June 30, 2011 was $5.4 million and $10.8 million, respectively. During the six months ended June 30, 2012, the board of directors of BreitBurn GP, LLC (our "General Partner") granted approximately 0.9 million RPUs to employees of BreitBurn Management under the LTIP.  Our outside directors were granted less than 0.1 million RPUs under our LTIP during the six months ended June 30, 2012.  The fair market value of the RPUs granted during 2012 for computing compensation expense under FASB Accounting Standards averaged $19.62 per unit.

During the three months and six months ended June 30, 2012, we paid nothing for taxes withheld on RPUs vested during the period.  During the three months and six months ended June 30, 2011, we paid nothing and $1.4 million, respectively, for taxes withheld on RPUs vested during the period.  

As of June 30, 2012, we had $28.4 million of total unrecognized compensation costs for all outstanding awards.  This amount is expected to be recognized over the period from July 1, 2012 to December 31, 2014. For detailed information on our various compensation plans, see Note 17 to the consolidated financial statements included in our Annual Report.

On May 18, 2012, we filed a registration statement on Form S-8 to register approximately 3.0 million Common Units available for issuance under our LTIP that were not previously registered.

16.  Subsequent Events

Acquisitions

On July 2, 2012, we completed the Element and CrownRock acquisitions to acquire oil and natural gas properties located in the Permian Basin in Texas with an effective date of March 1, 2012 for approximately $150 million and $70 million, respectively, subject to customary post-closing adjustments.

Distribution

On July 31, 2012, we announced a cash distribution to unitholders for the second quarter of 2012 at the rate of $0.4600 per Common Unit, to be paid on August 14, 2012 to our common unitholders of record as of the close of business on August 10, 2012.


18


Commodity Derivatives

In July 2012, we exercised contracts and paid premiums of $2.5 million for swaption contracts entered into in April 2012 that provided options to hedge a total of 510,168 barrels of future crude oil production associated with the NiMin Acquisition at then-current NYMEX WTI market prices, ranging from $104.80 per barrel in 2012 to $88.45 per barrel in 2017. 

In July 2012, we exercised contracts and paid premiums of $2.6 million for swaption contracts entered into in May 2012 that provided options to hedge a total of 634,485 barrels of future crude oil production associated with the Element and CrownRock acquisitions at then-current NYMEX WTI market prices, ranging from $98.35 per barrel in 2012 to $87.80 per barrel in 2017.

19


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

You should read the following discussion and analysis in conjunction with Management’s Discussion and Analysis in Part II—Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2011 (the "Annual Report") and the consolidated financial statements and related notes therein.  Our Annual Report contains a discussion of other matters not included herein, such as disclosures regarding critical accounting policies and estimates and contractual obligations.  You should also read the following discussion and analysis together with Part II—Item 1A “—Risk Factors” of this report, the “Cautionary Statement Regarding Forward-Looking Information” in this report and in our Annual Report and Part I—Item 1A “—Risk Factors” of our Annual Report.

Overview

We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil and gas properties in the United States.  Our assets consist primarily of producing and non-producing crude oil and natural gas reserves located primarily in the Antrim Shale and other non-Antrim formations in Michigan, the Evanston and Green River Basins in southwestern Wyoming, the Wind River and Big Horn Basins in central Wyoming, the Powder River Basin in eastern Wyoming, the Los Angeles Basin in California, the Permian Basin in Texas, the Sunniland Trend in Florida and the New Albany Shale in Indiana and Kentucky.

Our objective is to manage our oil and gas producing properties for the purpose of generating cash flow and making distributions to our unitholders.  

Our core investment strategies include:

Acquire long-lived assets with low-risk exploitation and development opportunities;
Use our technical expertise and state-of-the-art technologies to identify and implement successful exploitation techniques to optimize reserve recovery;
Reduce cash flow volatility through commodity price and interest rate derivatives; and
Maximize asset value and cash flow stability through our operating and technical expertise.

Consistent with our long-term business strategy, we intend to continue to actively pursue oil and natural gas acquisition opportunities in 2012.

2012 Highlights

In January 2012, we and BreitBurn Finance Corporation, and certain of our subsidiaries, as guarantors, issued $250 million in aggregate principal amount of 7.875% Senior Notes due 2022 (the "2022 Senior Notes") at a price of 99.154%. We received net proceeds of approximately $242.3 million and used the proceeds to repay amounts outstanding under our credit facility.

In February 2012, we sold approximately 9.2 million Common Units at a price to the public of $18.80, resulting in proceeds net of underwriting discounts and estimated offering expenses of $166.0 million, which we used to repay outstanding debt under our credit facility.

On February 14, 2012, we paid a cash distribution for the fourth quarter of 2011 of approximately $27.0 million to our common unitholders of record as of the close of business on February 6, 2012. The distribution that was paid to unitholders was $0.4500 per Common Unit.

In April 2012, our borrowing base was redetermined and increased from $787.5 million to $850.0 million. Our next semi-annual borrowing base redetermination is scheduled for October 2012.

In May 2012, we entered into the Fifth Amendment to the Second Amended and Restated Credit Agreement, which increased the permitted amount of senior unsecured notes we may issue from $700 million to $1 billion.

On May 14, 2012, we paid a cash distribution for the first quarter of 2012 of approximately $31.5 million to our common unitholders of record as of the close of business on May 7, 2012. The distribution that was paid to unitholders was $0.4550 per Common Unit.

20



On July 31, 2012, we announced a cash distribution to unitholders for the second quarter of 2012 at the rate of $0.4600 per Common Unit, to be paid on August 14, 2012 to our common unitholders of record as of the close of business on August 10, 2012.
    
2012 Acquisitions

On June 28, 2012, we completed the acquisition of oil properties located in Park County in the Big Horn Basin of Wyoming from Legacy Energy, Inc., a wholly-owned subsidiary of NiMin, with an effective date of April 1, 2012. The properties are 100% oil and produced approximately 500 Boe/d in the second quarter of 2012. The purchase price for this acquisition was approximately $93 million.

On July 2, 2012, we completed the Element and CrownRock acquisitions to acquire oil and natural gas properties located in the Permian Basin in Texas with an effective date of March 1, 2012 for approximately $150 million and $70 million, respectively, subject to customary post-closing adjustments. The properties are 56% oil and produced approximately 1,940 Boe/day in the second quarter of 2012.

Operational Focus and Capital Expenditures

 In the first six months of 2012, our oil and natural gas capital expenditures totaled $44 million, compared to approximately $37 million in the first six months of 2011.  We spent approximately $21 million in Florida, $14 million in California, $6 million in Wyoming and $3 million in Michigan, Indiana and Kentucky.  In the first six months of 2012, we drilled and completed six wells in California, three wells in Wyoming and one well in Florida and completed 18 workovers in Michigan and seven workovers in Wyoming. In the first six months of 2012, we also completed two facility optimization projects in California, two in Michigan and one in Indiana.

In 2012, our crude oil and natural gas capital spending program, including projects for our properties acquired in 2012, is expected to be approximately $137 million, compared to $75 million in 2011. This reflects our original capital program of $68 million, a $19 million increase to our program in April 2012 to pursue attractive oil drilling opportunities in California where we receive Brent-based pricing, which has been above WTI for the past year, and an additional $50 million increase based on our recent acquisitions and our ongoing review. Of the $50 million, we plan to spend approximately $30 million to develop our recently acquired properties in the Permian Basin in Texas and the Big Horn Basin in Wyoming and the remaining $20 million on our legacy properties in Florida, Wyoming, California and Michigan. Based on our revised capital spending program, we expect our 2012 production to be between approximately 8.3 MMBoe and 8.6 MMBoe.

Commodity Prices

In the second quarter of 2012, the WTI spot price averaged $93 per barrel, compared with approximately $102 per barrel in the second quarter of 2011.  In the first six months of 2012, the WTI spot price averaged $98 per barrel, compared with $98 per barrel a year earlier.  The average WTI spot price in July 2012 was approximately $88 per barrel.  In 2011, the WTI spot price averaged approximately $95 per barrel.
 
In the second quarter of 2012, the Henry Hub natural gas spot price averaged $2.29 per MMBtu compared with approximately $4.38 per MMBtu in the second quarter of 2011.  In the first six months of 2012, the Henry Hub natural gas price averaged $2.36 per MMBtu, compared with $4.29 per MMBtu a year earlier. The Henry Hub natural gas spot price in July 2012 averaged approximately $2.95 per MMBtu.  In 2011, the Henry Hub natural gas spot price averaged $4.00 per MMBtu and ranged from a low of $2.84 per MMBtu to a high of $4.92 per MMBtu.

Natural gas prices have declined substantially in the last year. We have hedged more than two-thirds of our expected 2012 natural gas production at an average price of $7.10 per MMBtu. See Note 3 to the consolidated financial statements in this report for a summary of our natural gas derivative contracts through 2016. Sustained low prices for natural gas may reduce the amounts that we would otherwise have available to pay expenses, make distributions to our unitholders and service our indebtedness.


21


BreitBurn Management

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 manages the operations of PCEC, our predecessor, and provides administrative services to PCEC under an administrative services agreement. These services include operational functions such as exploitation and technical services, petroleum and reserves engineering and executive management, and administrative services such as accounting, information technology, audit, human resources, land, business development, finance and legal. These services are provided in exchange for a monthly fee for indirect expenses and reimbursement for all direct expenses, including incentive compensation plan costs and direct payroll and administrative costs related to PCEC's properties and operations. 

On May 8, 2012, Pacific Coast Oil Trust (the "Trust"), which was formed by PCEC, completed its initial public offering (the "Trust IPO").  We have no direct or indirect ownership interest in PCEC or the Trust.  As part of the Trust IPO, PCEC conveyed net profits interests in its oil and natural gas production from certain of its properties to the Trust in exchange for Trust units.  PCEC's assets consist primarily of producing and non-producing crude oil reserves located in Santa Barbara, Los Angeles and Orange Counties in California, including certain interests in the East Coyote and Sawtelle Fields.  Prior to the Trust IPO, PCEC operated the East Coyote and Sawtelle Fields for the benefit of itself and us, who owned the non-operated interests in the East Coyote and Sawtelle Fields.  PCEC owned an average working interest of approximately 5% in the two fields and held a reversionary interest in both fields, which was expected to result in an increase in PCEC's ownership interests in the properties during the second quarter of 2012. 
Effective April 1, 2012 and pursuant to an agreement with us, PCEC's ownership interest in both of these fields was increased. As a result of that agreement, our average working interest in both fields decreased from approximately 95% to approximately 62%.  In addition, we became the operator of both these fields and will no longer pay an operating fee to PCEC. 
On May 8, 2012, BreitBurn Management entered into the Third Amended and Restated Administrative Services Agreement with PCEC, pursuant to which the parties agreed to increase the monthly fee charged by BreitBurn Management to PCEC for indirect costs. Prior to the Trust IPO, the 2012 monthly fee charged by BreitBurn Management to PCEC for indirect costs was set at $571,000, and the two parties agreed to increase that monthly fee to $700,000.  The new monthly fee will be in effect from April 1, 2012 through August 31, 2014 and will be redetermined biannually thereafter.  In connection with the Trust IPO, we also amended the Omnibus Agreement with PCEC to remove our right of first offer with respect to the sale of assets by PCEC.

22


Results of Operations

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

 
 
Three Months Ended
June 30,
 
Increase/
 
 
 
Six Months Ended June 30,
 
Increase/
 
 
Thousands of dollars, except as indicated
 
2012
 
2011
 
Decrease
 
%

 
2012
 
2011
 
Decrease
 
%

Total production (MBoe)
 
1,953

 
1,662

 
291

 
18
 %
 
3,940

 
3,291

 
649

 
20
 %
Oil and NGLs (MBoe)
 
815

 
782

 
33

 
4
 %
 
1,674

 
1,555

 
119

 
8
 %
Natural gas (MMcf)
 
6,824

 
5,277

 
1,547

 
29
 %
 
13,593

 
10,415

 
3,178

 
31
 %
Average daily production (Boe/d)
 
21,457

 
18,265

 
3,192

 
17
 %
 
21,647

 
18,182

 
3,465

 
19
 %
Sales volumes (MBoe)
 
2,013

 
1,621

 
392

 
24
 %
 
3,912

 
3,303

 
609

 
18
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average realized sales price (per Boe) (a) (b)
 
$
59.54

 
$
57.29

 
$
2.25

 
4
 %
 
$
59.12

 
$
58.05

 
$
1.07

 
2
 %
Oil and NGLs (per Boe) (a) (b)
 
92.08

 
79.48

 
12.60

 
16
 %
 
91.27

 
76.49

 
14.78

 
19
 %
Natural gas (per Mcf) (a)
 
5.74

 
6.42

 
(0.68
)
 
(11
)%
 
5.96

 
6.89