10-Q 1 bbep9301310q.htm 10-Q BBEP 9.30.13 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 September 30, 2013
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. 
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 5, 2013, the registrant had 99,679,860 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,” “intend,” “future,” “affect,” “expect,” “will,” “plan,” “anticipate,” 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; 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 derivative instruments 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, 2012, as amended by Amendment No 1. to our Annual Report on Form 10-K for the year December 31, 2012 (our “2012 Annual Report”), in Part II—Item 1A of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, as amended by Amendment No. 1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, our quarterly report on form 10-Q for the quarter ended June 30, 2013 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
Consolidated Balance Sheets
(Unaudited)
Thousands
 
September 30,
2013
 
December 31,
2012
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash
 
$
2,818

 
$
4,507

Accounts and other receivables, net
 
115,931

 
67,862

Derivative instruments (note 4)
 
16,558

 
34,018

Related party receivables (note 5)
 
530

 
1,413

Inventory (note 6)
 
11,118

 
3,086

Prepaid expenses
 
3,071

 
2,779

Intangibles, net (note 3)
 
6,554

 

Total current assets
 
156,580

 
113,665

Equity investments
 
7,126

 
7,004

Property, plant and equipment
 
 
 
 
Oil and gas properties
 
4,409,806

 
3,363,946

Other assets
 
15,986

 
14,367

 
 
4,425,792

 
3,378,313

Accumulated depletion and depreciation (note 7)
 
(813,713
)
 
(666,420
)
Net property, plant and equipment
 
3,612,079

 
2,711,893

Other long-term assets
 
 
 
 
Intangibles, net (note 3)
 
6,693

 

Derivative instruments (note 4)
 
71,085

 
55,210

Other long-term assets
 
46,893

 
27,722

 
 
 
 
 
Total assets
 
$
3,900,456

 
$
2,915,494

 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable
 
$
50,653

 
$
42,497

Derivative instruments (note 4)
 
12,388

 
5,625

Revenue and royalties payable
 
26,576

 
22,262

Wages and salaries payable
 
12,154

 
10,857

Accrued interest payable
 
29,467

 
13,002

Accrued liabilities
 
36,645

 
20,997

Total current liabilities
 
167,883

 
115,240

 
 
 
 
 
Credit facility (note 8)
 
1,090,000

 
345,000

Senior notes, net (note 8)
 
755,699

 
755,696

Deferred income taxes (note 10)
 
2,739

 
2,487

Asset retirement obligations (note 11)
 
111,642

 
98,480

Derivative instruments (note 4)
 
1,775

 
4,393

Other long-term liabilities
 
4,431

 
4,662

Total liabilities
 
2,134,169

 
1,325,958

Commitments and contingencies (note 12)
 


 


Equity
 
 
 
 
Partners' equity (note 13)
 
1,766,287

 
1,589,536

 
 
 
 
 
Total liabilities and equity
 
$
3,900,456

 
$
2,915,494

 
 
 
 
 
Common Units issued and outstanding
 
99,680

 
84,668


See accompanying notes to consolidated financial statements.

2


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

 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
Thousands of dollars, except per unit amounts
 
2013

2012
 
2013
 
2012
Revenues and other income items
 
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquid sales
 
$
197,413

 
$
111,700

 
$
467,061

 
$
300,688

(Loss) gain on commodity derivative instruments, net (note 4)
 
(54,765
)
 
(69,418
)
 
(11,948
)
 
1,865

Other revenue, net
 
737

 
796

 
2,197

 
2,848

Total revenues and other income items
 
143,385

 
43,078

 
457,310

 
305,401

Operating costs and expenses
 
 
 
 
 
 
 
 
Operating costs
 
68,502

 
50,048

 
181,889

 
142,203

Depletion, depreciation and amortization
 
60,125

 
37,270

 
154,456

 
109,068

General and administrative expenses
 
16,116

 
13,721

 
44,695

 
40,321

Loss on sale of assets
 
77

 
68

 
139

 
222

Total operating costs and expenses
 
144,820

 
101,107

 
381,179

 
291,814

 
 
 
 
 
 
 
 
 
Operating (loss) income
 
(1,435
)
 
(58,029
)
 
76,131

 
13,587

 
 
 
 
 
 
 
 
 
Interest expense, net of capitalized interest
 
23,548

 
15,362

 
60,387

 
43,231

Loss on interest rate swaps (note 4)
 

 
242

 

 
926

Other expense (income), net
 
4

 
17

 
(5
)
 
36

 
 
 
 
 
 
 
 
 
(Loss) income before taxes
 
(24,987
)
 
(73,650
)
 
15,749

 
(30,606
)
 
 
 
 
 
 
 
 
 
Income tax expense (benefit) (note 10)
 
24

 
(647
)
 
628

 
(201
)
 
 
 
 
 
 
 
 
 
Net (loss) income
 
(25,011
)
 
(73,003
)
 
15,121

 
(30,405
)
 
 
 
 
 
 
 
 
 
Less: Net income attributable to noncontrolling interest
 

 

 

 
(62
)
 
 
 
 
 
 
 
 
 
Net (loss) income attributable to the partnership
 
$
(25,011
)
 
$
(73,003
)
 
$
15,121

 
$
(30,467
)
 
 
 
 
 
 
 
 
 
Basic net (loss) income per common unit (note 13)
 
$
(0.25
)
 
$
(1.00
)
 
$
0.15

 
$
(0.44
)
Diluted net (loss) income per common unit (note 13)
 
$
(0.25
)
 
$
(1.00
)
 
$
0.15

 
$
(0.44
)

See accompanying notes to consolidated financial statements.


3


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

 
 
Nine Months Ended
 
 
September 30,
Thousands of dollars
 
2013
 
2012
Cash flows from operating activities
 
 
 
 
Net income (loss)
 
$
15,121

 
$
(30,405
)
Adjustments to reconcile to cash flows from operating activities:
 
 
 
 
Depletion, depreciation and amortization
 
154,456

 
109,068

Unit-based compensation expense
 
14,700

 
16,855

Loss (gain) on derivative instruments
 
11,948

 
(939
)
Derivative instrument settlements
 
3,633

 
62,877

Prepaid premiums on derivative instruments
 

 
(13,303
)
Income from equity affiliates, net
 
(122
)
 
356

Deferred income taxes
 
252

 
(503
)
Loss on sale of assets
 
139

 
222

Other
 
3,989

 
3,366

Changes in net assets and liabilities
 
 
 
 
Accounts receivable and other assets
 
(62,882
)
 
2,878

Inventory
 
(8,032
)
 
1,208

Net change in related party receivables and payables
 
883

 
2,329

Accounts payable and other liabilities
 
32,857

 
12,267

Net cash provided by operating activities
 
166,942

 
166,276

Cash flows from investing activities
 
 
 
 
Property acquisitions
 
(861,601
)
 
(313,404
)
Capital expenditures
 
(191,472
)
 
(77,699
)
Proceeds from sale of assets
 
226

 
863

Net cash used in investing activities
 
(1,052,847
)
 
(390,240
)
Cash flows from financing activities
 
 
 
 
Issuance of common units
 
285,011

 
370,504

Distributions
 
(137,447
)
 
(93,734
)
Proceeds from long-term debt
 
1,381,000

 
1,066,885

Repayments of long-term debt
 
(636,000
)
 
(1,109,000
)
Change in bank overdraft
 
(316
)
 
(2,299
)
Debt issuance costs
 
(8,032
)
 
(9,346
)
Net cash provided by financing activities
 
884,216

 
223,010

Decrease in cash
 
(1,689
)
 
(954
)
Cash beginning of period
 
4,507

 
5,328

Cash end of period
 
$
2,818

 
$
4,374


See accompanying notes to consolidated financial statements.


4


Notes to Consolidated Financial Statements

1.  Organization and Basis of Presentation

The accompanying unaudited consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our 2012 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, 2013, our operating results for the three months and nine months ended September 30, 2013 and 2012, and our cash flows for the nine months ended September 30, 2013 and 2012 have been included.  Operating results for the three months ended September 30, 2013 are not necessarily indicative of the results that may be expected for the year ended December 31, 2013.  The consolidated balance sheet at December 31, 2012 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 2012 Annual Report.

We follow the successful efforts method of accounting for oil and 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.

2.  New Accounting Standards

In December 2011, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that requires companies to disclose information about financial instruments that have been offset and related arrangements to enable users of a company’s financial statements to understand the effect of those arrangements on its financial position. We are 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 ASU requires retrospective application. We adopted this ASU effective January 1, 2013, and expanded our financial statement disclosures. The adoption of this ASU did not have an impact on our financial position, results of operations or cash flows.

3. Acquisitions

We account for acquisitions using the acquisition method of accounting. The initial accounting applied to our acquisitions at the time of the purchase may not be complete and adjustment to provisional accounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition date prior to concluding on the final purchase price of an acquisition.

Our purchase price allocations are based on discounted cash flows, quoted market prices and estimates made by management, and the most significant assumptions are those related to the estimated fair values assigned to oil and natural gas properties with proved reserves. To estimate the fair values of acquired properties, estimates of oil and natural gas reserves are prepared by management in consultation with independent engineers. We apply estimated future prices to the estimated reserve quantities acquired, and estimate future operating and development costs to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted average cost of capital.

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

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

5




Oklahoma Panhandle Acquisitions

On July 15, 2013, we completed the acquisition of certain oil and natural gas and midstream assets located in Oklahoma, New Mexico and Texas, certain carbon dioxide (“CO2”) supply contracts, certain crude oil swaps and interests in certain entities from Whiting Oil and Gas Corporation (“Whiting”) for approximately $833 million in cash (the “Whiting Acquisition”). We used borrowings under our credit facility to fund this acquisition. The preliminary purchase price for this acquisition was allocated to the assets acquired and liabilities assumed as follows:

Thousands of dollars
 

Oil and gas properties - proved
 
$765,390
Oil and gas properties - unproved
 
52,585

Derivative assets - current
 
15

Intangibles
 
14,739

Derivative assets - long-term
 
16,183

Other long-term assets
 
1,032

Derivative liabilities - current
 
(6,347
)
Accrued liabilities
 
(2,000
)
Asset retirement obligations
 
(8,219
)

 
$833,378
Thousands of dollars
 

Purchase price paid
 
$832,247
Estimated pending post-closing adjustments
 
1,131


 
$833,378

Whiting novated to us derivative contracts, with a counterparty that is a participant in our current credit facility, consisting of NYMEX West Texas Intermediate (“WTI”) fixed price crude oil swaps covering a total of approximately 5.4 million barrels of future production in 2013 through 2016 at a weighted average hedge price of $95.44 per Bbl, which were valued as a net asset of $9.9 million at the acquisition date. The preliminary purchase price allocation also included finite-lived intangibles valued at $14.7 million relating to two CO2 purchase contracts that we received in the acquisition.  We will be amortizing the contracts based on the amount of CO2 purchases made in each period over the contracts’ respective lives, with the first one expiring in December 2014, and the second one expiring in September 2023. In each of the three months and nine months ended September 30, 2013, we recorded $1.5 million in amortization for these contracts.

The preliminary purchase price allocation is based on discounted cash flows, quoted market prices and estimates made by management, with the most significant assumptions related to the estimated fair values assigned to oil and natural gas properties with proved reserves. To estimate the fair values of these properties, estimates of oil and natural gas reserves were prepared by management in consultation with independent engineers. We applied estimated future prices to the estimated reserve quantities acquired, and estimated future operating and development costs to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues were discounted using a market-based weighted average cost of capital rate of approximately 10%. We also employed a third-party valuation firm to assist in the valuation of the associated facilities, including pipelines, gathering lines and processing facilities.


We also completed the acquisition of additional interests in certain of the acquired assets in the Oklahoma Panhandle from other sellers for an additional $30 million in July 2013, subject to customary post-closing adjustments (together with the Whiting Acquisition, the “Oklahoma Panhandle Acquisitions”). We used borrowings under our credit facility to fund these acquisitions.


6


Acquisition-related costs for the Oklahoma Panhandle Acquisitions were $2.9 million in the nine months ended September 30, 2013 and were reflected in general and administrative (“G&A”) expenses on the consolidated statements of operations. In each of the three months and nine months ended September 30, 2013, we recorded $52.3 million in sales revenue and $13.4 million in lease operating expenses, including production and property taxes, from our Oklahoma Panhandle Acquisitions.

Permian Basin Acquisitions

On July 2, 2012, we completed acquisitions of oil and natural gas properties located in the Permian Basin in Texas from Element Petroleum, LP and CrownRock, L.P. for approximately $148 million and $70 million, respectively. On December 28, 2012, we completed the acquisition of additional oil and natural gas properties, additional net working interests and interests in undeveloped drilling locations in the Permian Basin in Texas from CrownRock, L.P., Lynden USA Inc. and Piedra Energy I, LLC for approximately $164 million, $25 million and $10 million, respectively. The final purchase price for each of the 2012 acquisitions in the Permian Basin were primarily allocated to oil and natural gas properties, which included $52.5 million of unproved oil and gas properties, with $44.3 million related to Element Petroleum, LP acquisition and $8.2 million related to the first CrownRock, L.P, acquisition. Acquisition-related costs for the July 2, 2012 acquisitions from Element Petroleum, LP and CrownRock, L.P. were $1.0 million and were recorded in general and administrative expenses on the consolidated statements of operations. Acquisition-related costs for the December 28, 2012 acquisitions from CrownRock, L.P., Lynden USA Inc. and Piedra Energy I, LLC, were $0.5 million and were recorded in general and administrative expenses on the consolidated statements of operations. During the three months and nine months ended September 30, 2013, we recorded $23.7 million and $65.1 million, respectively, in sales revenue and $5.3 million and $15.5 million, respectively, in lease operating expenses, including production and property taxes, from our Permian Basin properties. During the three months and nine months ended September 30, 2012, we recorded $9.2 million and $9.2 million, respectively, in sales revenue and $1.8 million and $1.8 million, respectively, in lease operating expenses, including production and property taxes, from our Permian Basin properties.

AEO Acquisition
    
On November 30, 2012, we completed the acquisition of principally oil properties from American Energy Operations, Inc. (“AEO”) located in the Belridge Field in Kern County, California (the “AEO Acquisition”) for approximately $38 million in cash and 3 million of our common units representing limited partner interests in us (“Common Units”). Of the final purchase price of $38 million in cash and $56 million in Common Units, $97.8 million was allocated to oil and natural gas properties and $4.0 million was allocated to ARO. Acquisition-related costs for the AEO Acquisition were $0.4 million and were recorded in general and administrative expenses on the consolidated statements of operations. Revenues and expenses from the AEO properties are reflected in our consolidated statements of operations beginning December 1, 2012. During the three months and nine months ended September 30, 2013, we recorded $12.7 million and $27.8 million, respectively, in sales revenue and $1.7 million and $4.8 million, respectively, in lease operating expenses, including production and property taxes, from the properties acquired in the AEO Acquisition.

NiMin Acquisition

In June 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 (the “NiMin Acquisition”). The final purchase price for this acquisition was approximately $95 million in cash, which was primarily allocated to oil and natural gas properties (including $36.2 million in unproved properties) and included $1.7 million of ARO. Acquisition-related costs for the NiMin Acquisition were $0.4 million and were reflected in general and administrative expenses on the consolidated statements of operations. Revenues and expenses from the NiMin properties are reflected in our consolidated statements of operations beginning June 28, 2012. During the three months and nine months ended September 30, 2013, we recorded $4.6 million and $11.9 million, respectively, in sales revenue and $1.7 million and $4.5 million, respectively, in lease operating expenses, including production and property taxes, from our NiMin properties. During the three months and nine months ended September 30, 2012, we recorded $3.2 million and $3.3 million, respectively, in sales revenue and $1.7 million and $1.7 million, respectively, in lease operating expenses, including production and property taxes, from the properties acquired in the NiMin Acquisition.


7


Pro Forma

The following unaudited pro forma financial information presents a summary of our combined statements of operations for the three months and nine months ended September 30, 2013 and 2012, assuming the Whiting Acquisition and additional acquired assets in the Oklahoma Panhandle acquisitions had been completed in January 1, 2012, the AEO Acquisition, the NiMin Acquisition and the 2012 acquisitions from Element Petroleum, LP, CrownRock, L.P., Piedra Energy I, LLC and Lynden USA Inc. had been completed on January 1, 2011. The pro forma results reflect the results of combining our statements of operations with the results of operations from all of our 2012 and 2013 acquisitions, adjusted for (1) the assumption of ARO and accretion expense for the properties acquired, (2) depletion and depreciation expense applied to the adjusted purchase price of the properties acquired, and (3) interest expense on additional borrowings necessary to finance the acquisitions, including the amortization of debt issuance costs.  The pro forma financial information is not necessarily indicative of the results of operations if these acquisitions had been effective January 1, 2012 or 2011.

 
 
Pro Forma
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Thousands of dollars, except per unit amounts
 
2013
 
2012
 
2013
 
2012
Revenues
 
$
151,994

 
$
120,938

 
$
579,766

 
$
569,004

Net income (loss) attributable to the partnership
 
(21,311
)
 
(41,528
)
 
63,518

 
78,031

 
 
 
 
 
 
 
 
 
Net income (loss) per common unit:
 
 
 
  
 
 
 
 
Basic
 
$
(0.21
)
 
$
(0.42
)
 
$
0.63

 
$
0.77

Diluted
 
$
(0.21
)
 
$
(0.42
)
 
$
0.62

 
$
0.77


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

Commodity Activities

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


8


We had the following commodity derivative contracts in place at September 30, 2013:
 
Year

2013

2014

2015

2016

2017

2018
Oil Positions:
 
 
 
 
 
 
 
 
 
 
 
Fixed Price Swaps - NYMEX WTI
 
 
 
 
 
 
 
 
 
 
 
 Hedged Volume (Bbl/d)
13,016

 
11,314

 
10,189

 
6,711

 
5,471

 
493

Average Price ($/Bbl)
$
95.26

 
$
93.67

 
$
94.71

 
$
86.97

 
$
83.38

 
$
82.20

Fixed Price Swaps - ICE Brent
 
 
 
 
 
 
 
 
 
 
 
 Hedged Volume (Bbl/d)
4,200

 
4,800

 
3,300

 
4,300

 
298

 

Average Price ($/Bbl)
$
97.57

 
$
98.88

 
$
97.73

 
$
95.17

 
$
97.50

 
$

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

 
1,000

 
1,000

 

 

 

Average Floor Price ($/Bbl)
$
77.00

 
$
90.00

 
$
90.00

 
$

 
$

 
$

Average Ceiling Price ($/Bbl)
$
103.10

 
$
112.00

 
$
113.50

 
$

 
$

 
$

Collars - ICE Brent
 
 
 
 
 
 
 
 
 
 
 
Hedged Volume (Bbl/d)

 

 
500

 
500

 

 

Average Floor Price ($/Bbl)
$

 
$

 
$
90.00

 
$
90.00

 
$

 
$

Average Ceiling Price ($/Bbl)
$

 
$

 
$
109.50

 
$
101.25

 
$

 
$

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

 
500

 
500

 
1,000

 

 

Average Price ($/Bbl)
$
90.00

 
$
90.00

 
$
90.00

 
$
90.00

 
$

 
$

Total:
 
 
 
 
 
 
 
 
 
 
 
Hedged Volume (Bbl/d)
18,716

 
17,614

 
15,489

 
12,511

 
5,769

 
493

Average Price ($/Bbl)
$
95.01

 
$
94.78

 
$
94.75

 
$
90.15

 
$
84.11

 
$
82.20

 
 
 
 
 
 
 
 
 
 
 
 
Gas Positions:
 
 
 
 
 
 
 
 
 
 
 
Fixed Price Swaps - MichCon City-Gate
 
 
 
 
 
 
 
 
 
 
 
Hedged Volume (MMBtu/d)
37,000

 
7,500

 
7,500

 
17,000

 
10,000

 

Average Price ($/MMBtu)
$
6.50

 
$
6.00

 
$
6.00

 
$
4.46

 
$
4.48

 
$

Fixed Price Swaps - Henry Hub
 
 
 
 
 
 
 
 
 
 
 
Hedged Volume (MMBtu/d)
27,100

 
38,600

 
43,200

 
20,700

 
5,571

 

Average Price ($/MMBtu)
$
4.68

 
$
4.80

 
$
4.83

 
$
4.24

 
$
4.51

 
$

Puts - Henry Hub
 
 
 
 
 
 
 
 
 
 
 
Hedged Volume (MMBtu/d)

 
6,000

 
1,500

 

 

 

Average Price ($/MMBtu)
$

 
$
5.00

 
$
5.00

 
$

 
$

 
$

Total:
 
 
 
 
 
 
 
 
 
 
 
Hedged Volume (MMBtu/d)
64,100

 
52,100

 
52,200

 
37,700

 
15,571

 

Average Price ($/MMBtu)
$
5.73

 
$
4.99

 
$
5.00

 
$
4.34

 
$
4.49

 
$

 
 
 
 
 
 
 
 
 
 
 
 
 Calls - Henry Hub
 
 
 
 
 
 
 
 
 
 
 
Hedged Volume (MMBtu/d)
30,000

 
15,000

 

 

 

 

Average Price ($/MMBtu)
$
8.00

 
$
9.00

 
$

 
$

 
$

 
$

Deferred Premium ($/MMBtu)
$
0.08

 
$
0.12

 
$

 
$

 
$

 
$


During the nine months ended September 30, 2013, we did not enter into any derivative instruments that required pre-paid premiums. During the nine months ended September 30, 2012, we paid $13.3 million in premiums on commodity derivative instruments that related to future periods.

As of September 30, 2013, premiums paid in 2012 related to oil and natural gas derivatives to be settled in the fourth quarter of 2013 and beyond were as follows:
 
 
Year
Thousands of dollars
 
2013
 
2014
 
2015
 
2016
 
2017
 
2018
Oil
 
$
1,233

 
$
4,479

 
$
4,683

 
$
7,438

 
$
734

 
$

Natural gas
 
$

 
$
4,015

 
$
1,989

 
$
952

 
$

 
$



9


Interest Rate Activities

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. In order to mitigate our interest rate exposure, we have in the past entered, and may in the future enter, into interest rate derivative contracts, indexed to 1-month LIBOR, to fix a portion of floating LIBOR-based debt under our credit facility. As of September 30, 2013 and December 31, 2012, we had no interest rate swaps in place.

Fair Value of Financial Instruments
 
The following table presents the fair value of our derivative instruments, none of which are designated as hedging instruments:
Balance sheet location, thousands of dollars
 
Oil Commodity Derivatives
 
Natural Gas
Commodity Derivatives
 
Commodity Derivatives Netting (a)
 
Total Financial Instruments
 
 
 
 
 
 
 
 
 
As of September 30, 2013
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
Current assets - derivative instruments
 
$
3,210

 
$
28,370

 
$
(15,022
)
 
$
16,558

Other long-term assets - derivative instruments
 
53,144

 
26,997

 
(9,056
)
 
71,085

Total assets
 
56,354

 
55,367

 
(24,078
)
 
87,643

 
 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
 
Current liabilities - derivative instruments
 
(26,685
)
 
(725
)
 
15,022

 
(12,388
)
Long-term liabilities - derivative instruments
 
(10,327
)
 
(504
)
 
9,056

 
(1,775
)
Total liabilities
 
(37,012
)
 
(1,229
)
 
24,078

 
(14,163
)
 
 
 
 
 
 
 
 
 
Net assets
 
$
19,342

 
$
54,138

 
$

 
$
73,480

 
 
 
 
 
 
 
 
 
As of December 31, 2012
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
Current assets - derivative instruments
 
$
4,270

 
$
46,724

 
$
(16,976
)
 
$
34,018

Other long-term assets - derivative instruments
 
38,919

 
33,443

 
(17,152
)
 
55,210

Total assets
 
43,189

 
80,167

 
(34,128
)
 
89,228

 
 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
 
Current liabilities - derivative instruments
 
(21,665
)
 
(936
)
 
16,976

 
(5,625
)
Long-term liabilities - derivative instruments
 
(18,769
)
 
(2,776
)
 
17,152

 
(4,393
)
Total liabilities
 
(40,434
)
 
(3,712
)
 
34,128

 
(10,018
)
 
 
 
 
 
 
 
 
 
Net assets
 
$
2,755

 
$
76,455

 
$

 
$
79,210


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


10


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

Thousands of dollars
 
Oil Commodity
Derivatives (a)
 
Natural Gas
Commodity Derivatives (a)
 
Interest Rate
Derivatives (b)
 
Total Financial Instruments
Three Months Ended September 30, 2013
 
 
 
 
 
 
 
 
Net (loss) gain
 
$
(62,770
)
 
$
8,005

 
$

 
$
(54,765
)
Three Months Ended September 30, 2012
 
 
 
 
 
 
 
 
Net loss
 
$
(53,180
)
 
$
(16,238
)
 
$
(242
)
 
$
(69,660
)
Nine Months Ended September 30, 2013
 
 
 
 
 
 
 
 
Net (loss) gain
 
$
(22,072
)
 
$
10,124

 
$

 
$
(11,948
)
Nine Months Ended September 30, 2012
 
 
 
 
 
 
 
 
Net (loss) gain
 
$
(7,988
)
 
$
9,853

 
$
(926
)
 
$
939


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

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

Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date.  Level 2 – Inputs that are observable other than quoted prices that are included within Level 1.  Level 2 includes financial instruments that are actively traded but are valued using models or other valuation methodologies.  We consider the over-the-counter (“OTC”) commodity and interest rate swaps in our portfolio to be Level 2.  Level 3 – Inputs that are not directly observable for the asset or liability and are significant to the fair value of the asset or liability.  Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models.  Certain OTC derivative instruments that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3.  As of September 30, 2013 and December 31, 2012, 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, 2013 and 2012. Our policy is to recognize transfers between levels as of the end of the period.
 
Our Treasury/Risk Management group calculates the fair value of our commodity and interest rate swaps and options.  We compare these fair value amounts to the fair value amounts we receive from counterparties on a monthly basis.  Any differences are resolved and any required changes are recorded prior to the issuance of our financial statements.

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

11



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

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

Thousands of dollars
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
 
 
 
 
 
 
 
As of September 30, 2013
 
 
 
 
 
 
 
 
Assets (liabilities)
 
 
 
 
 
 
 
 
Crude Oil
 
 
 
 
 
 
 
 
Crude oil swaps
 
$

 
$
8,799

 
$

 
$
8,799

Crude oil collars
 

 

 
3,819

 
3,819

Crude oil puts
 

 

 
6,724

 
6,724

Natural Gas
 
 
 
 
 
 
 
 
Natural gas swaps
 

 
51,781

 

 
51,781

Natural gas calls
 

 

 
(868
)
 
(868
)
Natural gas puts
 

 

 
3,225

 
3,225

Net Assets
 
$

 
$
60,580

 
$
12,900

 
$
73,480

 
 
 
 
 
 
 
 
 
As of December 31, 2012
 
 
 
 
 
 
 
 
Assets (liabilities)
 
 
 
 
 
 
 
 
Crude Oil
 
 
 
 
 
 
 
 
Crude oil swaps
 
$

 
$
(12,413
)
 
$

 
$
(12,413
)
Crude oil collars
 

 

 
4,024

 
4,024

Crude oil puts
 

 

 
11,144

 
11,144

Natural Gas
 
 
 
 
 
 
 
 
Natural gas swaps
 

 
74,782

 

 
74,782

Natural gas calls
 

 

 
(1,489
)
 
(1,489
)
Natural gas puts
 

 

 
3,162

 
3,162

Net Assets
 
$

 
$
62,369

 
$
16,841

 
$
79,210



12


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

 
 
Three Months Ended September 30,
 
 
2013
 
2012
Thousands of dollars
 
Oil
 
Natural Gas
 
Oil
 
Natural Gas
Assets (a):
 
 
 
 
 
 
 
 
Beginning balance
 
$
15,412

 
$
2,054

 
$
22,062

 
$
22,242

Derivative instrument settlements (b)
 
(125
)
 
(225
)
 
3,968

 
10,515

Gain (loss) (b)(c)
 
(4,744
)
 
528

 
(16,499
)
 
(23,173
)
Purchases (b)(d)
 

 

 

 
1,252

Ending balance
 
$
10,543

 
$
2,357

 
$
9,531

 
$
10,836

 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30,
 
 
2013
 
2012
Thousands of dollars
 
Oil
 
Natural Gas
 
Oil
 
Natural Gas
Assets (a):
 
 
 
 
 
 
 
 
Beginning balance
 
$
15,169

 
$
1,672

 
$
8,509

 
$
37,049

Derivative instrument settlements (b)
 
(125
)
 
(667
)
 
9,425

 
33,143

Gain (loss) (b)(c)
 
(4,501
)
 
1,352

 
(8,403
)
 
(64,386
)
Purchases (b)(d)
 

 

 

 
5,030

Ending balance
 
$
10,543

 
$
2,357

 
$
9,531

 
$
10,836


(a) We had no changes in fair value of our derivative instruments classified as Level 3 related to sales or issuances.
(b) Included in (loss) gain on commodity derivative instruments, net on the consolidated statements of operations.
(c) Represents gain (loss) on mark-to-market of derivative instruments.
(d) Relates to natural gas put options entered into in June 2012 and crude oil options entered into in August 2012.
    
For Level 3 derivative instruments measured at fair value on a recurring basis as of September 30, 2013, the significant unobservable inputs used in the fair value measurements were as follows:

 
 
Fair Value at
 
Valuation
 
 
 
 
Thousands of dollars
 
September 30, 2013
 
Technique
 
Unobservable Input
 
Range
Oil Options
 
$
10,543

 
Option Pricing Model
 
Oil forward commodity prices
 
$83.87/Bbl - $102.22/Bbl
 
 
 
 
 
 
Oil volatility
 
16.18% - 22.29%
 
 
 
 
 
 
Own credit risk
 
5%
Natural Gas Options
 
2,357

 
Option Pricing Model
 
Gas forward commodity prices
 
$3.50/MMBtu - $4.26/MMBtu
 
 
 
 
 
 
Gas volatility
 
20.32% - 30.33%
 
 
 
 
 
 
Own credit risk
 
5%
Total
 
$
12,900

 
 
 
 
 
 

    

13


For Level 3 derivative instruments measured at fair value on a recurring basis as of December 31, 2012, the significant unobservable inputs used in the fair value measurements were as follows:

 
 
Fair Value at
 
Valuation
 
 
 
 
Thousands of dollars
 
December 31, 2012
 
Technique
 
Unobservable Input
 
Range
Oil Options
 
$
15,169

 
Option Pricing Model
 
Oil forward commodity prices
 
$86.78/Bbl - $110.46/Bbl
 
 
 
 
 
 
Oil volatility
 
20.56% - 27.53%
 
 
 
 
 
 
Own credit risk
 
5%
Natural Gas Options
 
1,672

 
Option Pricing Model
 
Gas forward commodity prices
 
$3.35/MMBtu - $4.87/MMBtu
 
 
 
 
 
 
Gas volatility
 
20.55% - 35.88%
 
 
 
 
 
 
Own credit risk
 
5%
Total
 
$
16,841

 
 
 
 
 
 

Credit and Counterparty Risk

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of derivative instruments and accounts receivable.  Our derivative instruments expose us to credit risk from counterparties.  As of September 30, 2013, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank, National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia, BNP Paribas, Royal Bank of Canada and Toronto-Dominion Bank.  We periodically obtain credit default swap information on our counterparties.  As of September 30, 2013, each of these financial institutions had an investment grade credit rating.  Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default.  As of September 30, 2013, our largest derivative asset balances were with Wells Fargo Bank, National Association, Credit Suisse Energy LLC and Citibank, N.A., which accounted for approximately 31%, 24% and 13% of our net derivative asset balances, respectively.  

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 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.  For the three months and nine months ended September 30, 2013, the monthly fee paid by PCEC for indirect expenses was $700,000. The current monthly fee will be in effect through August 31, 2014 and, to the extent the term of the administrative services agreement is renewed, will be redetermined biannually thereafter. 
  
At September 30, 2013 and December 31, 2012, we had current receivables of $0.4 million and $1.2 million, respectively, due from PCEC related to the administrative services agreement, employee-related costs and oil and natural gas sales made by PCEC on our behalf from certain properties.  For the three months ended September 30, 2013 and 2012, the monthly charges to PCEC for indirect expenses totaled $2.1 million and $2.1 million, respectively, and charges for direct expenses including payroll and administrative costs totaled $2.9 million and $2.3 million, respectively. For the nine months ended September 30, 2013 and 2012, the monthly charges to PCEC for indirect expenses totaled $6.3 million and $5.9 million, respectively, and charges for direct expenses including payroll and administrative costs totaled $7.3 million and $6.3 million, respectively.

At September 30, 2013 and December 31, 2012, we had receivables of $0.1 million and $0.2 million, respectively, due from certain of our other affiliates, primarily representing investments in natural gas processing facilities, for management fees due from them and operational expenses incurred on their behalf.    

14


6.  Inventory

Our crude oil inventory from our Florida operations was $11.1 million at September 30, 2013 and $3.1 million at December 31, 2012.  In the nine months ended September 30, 2013, we sold 511 gross MBbls and produced 596 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.

7.  Impairments

We assess our developed and undeveloped oil and natural gas properties, finite-lived intangibles 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 . For purposes of performing an impairment test, the undiscounted future cash flows are based on total proved and risk-adjusted probable and possible reserves, forecasted using five-year NYMEX forward strip prices at the end of the period and escalated, along with expenses and capital, starting from year six forward at 2.5% per year. For impairment charges recorded in 2012, the associated property’s expected future net cash flows were discounted using an estimated weighted average cost of capital that approximated 10%. We consider the inputs for our impairment calculations to be Level 3 inputs. The impairment reviews and calculations are based on assumptions that are consistent with our business plans.

We assess our developed and undeveloped oil and natural gas properties, other long-lived assets and finite-lived intangibles for possible impairment periodically and whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. 

During the three months and nine months ended September 30, 2013, we recorded impairments of approximately $0.4 million, including $0.2 million for a Florida property and $0.2 million related to a few smaller Michigan properties. During the three months ended September 30, 2012, we recorded no impairments. During the nine months ended September 30, 2012, we recorded non-cash impairment charges of approximately $11.6 million, respectively, primarily related to uneconomic proved properties in Michigan, Indiana and Kentucky due to decreases in natural gas prices. The impairments are reflected in depletion, depreciation and amortization on the consolidated statements of operations and in accumulated depletion and depreciation on the consolidated balance sheets.

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

8.  Long-Term Debt

Credit Facility

BreitBurn Operating L.P. (“BOLP”), as borrower, and we and our wholly-owned subsidiaries, as guarantors, have a $3.0 billion revolving credit facility with Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and Issuing Lender, and a syndicate of banks (as amended, the “Second Amended and Restated Credit Agreement”) with a maturity date of May 9, 2016.

In July 2013, we entered into the Ninth Amendment to the Second Amended and Restated Credit Agreement, which increased our aggregate maximum credit amount from $1.5 billion to $3.0 billion, increased our borrowing base to $1.5 billion and increased the aggregate commitment of all lenders to $1.4 billion. The amendment also increased flexibility for

15


the Total Leverage Ratio (defined as the ratio of total debt to EBITDAX) for the next five quarters and added a new Senior Secured Leverage Ratio (defined as the ratio of senior secured indebtedness to EBITDAX) that will be applied until the earlier of the end of the second quarter of 2014 and our receipt of net cash proceeds from the issuance of Common Units of at least $350 million. The Ninth Amendment provides that we are required to maintain a Total Leverage Ratio as of the last day of each quarter, on a last 12-month basis, of no more than 4.75 to 1.00 through the first quarter of 2014, no more than 4.50 to 1.00 through the second quarter of 2014, no more than 4.25 to 1.00 through the third quarter of 2014 and thereafter no more than 4.00 to 1.00. We also are required to maintain a Senior Secured Leverage Ratio as of the last day of each quarter, on a last 12-month basis, of no more than 3.00 to 1.00 through the fourth quarter of 2013 and no more than 2.75 to 1.00 through the second quarter of 2014. The numerator of each of these ratios automatically decreases by .25 or .50 if we receive net cash proceeds from the issuance of Common Units of, at least, $175 million or, with respect to the Total Leverage Ratio, $350 million, respectively, but in no event will the Total Leverage Ratio be reduced to less than 4.00 to 1.00.

As of September 30, 2013 and December 31, 2012, our borrowing base was $1.5 billion and $1.0 billion, respectively, and the aggregate commitment of all lenders was $1.4 billion and $900 million, respectively.

As of September 30, 2013 and December 31, 2012, we had $1.1 billion and $345 million, respectively, in indebtedness outstanding under our credit facility. At September 30, 2013, the 1-month LIBOR interest rate plus an applicable spread was 2.4306% on the 1-month LIBOR portion of $1,087 million and the prime rate plus an applicable spread was 4.50% on the prime portion of $3 million. At September 30, 2013, we had $15.2 million of unamortized debt issuance costs related to our credit facility.

As of September 30, 2013 and December 31, 2012, we were in compliance with our credit facility’s covenants.

Senior Notes

We have $305 million in aggregate principal amount of 8.625% Senior Notes due 2020 (the “2020 Senior Notes”), which had a carrying value of $301.5 million, net of unamortized discount of $3.5 million, as of September 30, 2013. In addition, we have $450 million in aggregate principal amount of 7.875% Senior Notes due 2022 (the “2022 Senior Notes”), which had a carrying value of $454.2 million, net of unamortized premium of $4.2 million, as of September 30, 2013. At September 30, 2013, we had $14.7 million of unamortized debt issuance costs related to our Senior Notes.

Interest on our senior notes is payable twice a year in April and October.

As of September 30, 2013, the fair value of our 2020 Senior Notes and 2022 Senior Notes was estimated to be $322.4 million and $450.4 million, respectively, based on prices quoted from third-party financial institutions. We consider the inputs to the valuation of our senior notes to be Level 2, as fair value was estimated based on prices quoted from third-party financial institutions.

As of September 30, 2013 and December 31, 2012, we were in compliance with the covenants under our senior notes.

Interest Expense

Our interest expense is detailed as follows:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
Thousands of dollars
 
2013
 
2012
 
2013
 
2012
Credit agreement (including commitment fees)
 
$
6,313

 
$
2,804

 
$
9,718

 
$
5,846

Senior notes
 
15,436

 
11,557

 
46,308

 
33,843

Amortization of discount and deferred issuance costs
 
1,826

 
1,041

 
4,423

 
3,582

Capitalized interest
 
(27
)
 
(40
)
 
(62
)
 
(40
)
Total
 
$
23,548

 
$
15,362

 
$
60,387

 
$
43,231



16


9. Condensed Consolidating Financial Statements

We and BreitBurn Finance Corporation, as co-issuers, and certain of our subsidiaries, as guarantors, issued the 2020 Senior Notes and the 2022 Senior Notes. Effective April 1, 2012, we and PCEC agreed to dissolve BreitBurn Energy Partners I, L.P. (“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 consolidating financial statements as we have no independent assets or operations, BreitBurn Finance Corporation, the subsidiary co-issuer that does not guarantee our senior notes, is a 100% owned finance subsidiary. Additionally, all of our material subsidiaries are 100% owned and have guaranteed our senior notes, and all of the guarantees are full, unconditional, joint and several.

Each guarantee of each of the 2020 Senior Notes and the 2022 Senior Notes is subject to release in the following customary circumstances:

(1)
a disposition of all or substantially all the assets of the guarantor subsidiary (including by way of merger or consolidation) to a third person, provided the disposition complies with the applicable indenture,
(2)
a disposition of the capital stock of the guarantor subsidiary to a third person, if the disposition complies with the applicable indenture and as a result the guarantor subsidiary ceases to be our subsidiary,            
(3)
the designation by us of the guarantor subsidiary as an Unrestricted Subsidiary as defined in the applicable indenture,
(4)
legal or covenant defeasance of such series of senior notes or satisfaction and discharge of the related indenture,
(5)
the liquidation or dissolution of the guarantor subsidiary, provided no default under the applicable indenture exists, or
(6)
the guarantor subsidiary ceases both (a) to guarantee any other indebtedness of ours or any other guarantor subsidiary and (b) to be an obligor under any bank credit facility.

10.  Income Taxes

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

Our deferred federal income tax liability was $2.7 million and $2.5 million at September 30, 2013 and December 31, 2012, respectively.  The following table presents our income tax expense (benefit) for the three months and nine months ended September 30, 2013 and 2012

 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
Thousands of dollars
 
2013
 
2012
 
2013
 
2012
Federal income tax expense (benefit)
 
 
 
 
 
 
 
 
Current
 
$
41

 
$
(65
)
 
$
67

 
$
199

Deferred (a)
 
(45
)
 
(629
)
 
252

 
(503
)
State income tax expense (b)
 
28

 
47

 
309

 
103

Total
 
$
24

 
$
(647
)
 
$
628

 
$
(201
)

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


17


11.  Asset Retirement Obligations

ARO is based on our net ownership in wells and facilities and our estimate of the costs to abandon and remediate those wells and facilities together with our estimate of the future timing of the costs to be incurred.  Payments to settle ARO occur over the operating lives of the assets, estimated to range from less than one year to 50 years.  Estimated cash flows have been discounted at our credit-adjusted risk-free rate of 7% and adjusted for inflation using a rate of 2%.  Our credit-adjusted risk-free rate is calculated based on our cost of borrowing adjusted for the effect of our credit standing and specific industry and business risk.

We consider the inputs to our ARO valuation to be Level 3, as fair value is determined using discounted cash flow methodologies based on standardized inputs that are not readily observable in public markets.

Changes in ARO for the period ended September 30, 2013 and the year ended December 31, 2012 are presented in the following table:
 
 
Nine Months Ended
 
Year Ended
Thousands of dollars
 
September 30, 2013
 
December 31, 2012
Carrying amount, beginning of period
 
$
98,480

 
$
82,397

Acquisitions
 
8,219

 
6,279

Liabilities incurred
 
90

 
2,468

Liabilities settled
 
(430
)
 
(86
)
Revisions
 

 
1,553

Accretion expense
 
5,283

 
5,869

Carrying amount, end of period
 
$
111,642

 
$
98,480


12.  Commitments and Contingencies

In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit.  These obligations primarily cover self-insurance and other programs where governmental organizations require such support.  These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon.  At September 30, 2013 and December 31, 2012, we had surety bonds for $17.1 million and $16.2 million, respectively.  At both September 30, 2013 and December 31, 2012, we had approximately $1.0 million and $0.3 million in letters of credit outstanding, respectively.

Purchase Contracts

On July 15, 2013, we completed the acquisition of the Whiting Assets.  The Whiting Assets include the Postle Field, which currently has active CO2 enhanced recovery projects, and the Northeast Hardesty Unit, both of which are located in Texas County, Oklahoma. We have a contracted supply of CO2 in the Bravo Dome Field in New Mexico, with step-in rights, for 129,000,000 Mcf over 10 to 15 years, which we expect to provide volumes in excess of those required to produce our estimated proved reserves when coupled with recycled CO2. Under the take-or-pay provisions of these purchase agreements, we are committed to buying certain volumes of CO2 for use in our enhanced recovery project being carried out at the Postle field. We are obligated to purchase a minimum daily volume of CO2 (as calculated on an annual basis) or else pay for any deficiencies at the price in effect when the minimum delivery was to have occurred. The CO2 volumes planned for use in our enhanced recovery projects in the Postle Field currently exceed the minimum daily volumes specified in these agreements. Therefore, we expect to avoid any payments for deficiencies.  The table below shows our future minimum commitments under these purchase agreements as of September 30, 2013:



Year Ending December 31,




Thousands of dollars
 
2013
 
2014
 
2015
 
2016
 
2017
 
Thereafter
 
Total
Purchase contracts
 
$
2,434

 
$
6,930

 
$
18,539

 
$
14,638

 
$
15,663

 
$
66,841

 
$
125,045




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13.  Partners’ Equity

In February 2013, we sold 14.95 million Common Units at a price to the public of $19.86 per Common Unit, resulting in proceeds of $285.0 million (net of underwriting discount and offering expenses).

During the nine months ended September 30, 2013, we issued 0.1 million Common Units to employees and non-employee directors for Convertible Phantom Units (“CPUs”) and Restricted Phantom Units (“RPUs”) that vested in January 2013.

At September 30, 2013 and December 31, 2012, we had approximately 99.7 million and 84.7 million Common Units outstanding, respectively.  At September 30, 2013 and December 31, 2012, there were approximately 2.1 million and 0.9 million, respectively, of units outstanding under our Long-term Incentive Plan (“LTIP”) that were eligible to be paid in Common Units upon vesting.

Cash Distributions

On February 14, 2013, we paid a cash distribution of approximately $39.8 million, or $0.4700 per Common Unit. On May 14, 2013, we paid a cash distribution of approximately $47.3 million, or $0.4750 per Common Unit. On August 14, 2013, we paid a cash distribution of approximately $47.8 million, or $0.4800 per Common Unit.

During the three months and nine months ended September 30, 2013, we also paid $0.8 million and $2.4 million, respectively, in cash at a rate equal to the distributions paid to our holders of Common Units to holders of outstanding unvested RPUs issued under our LTIP.

On February 14, 2012, we paid a cash distribution of approximately $27.0 million, or $0.4500 per Common Unit. On May 14, 2012, we paid a cash distribution of approximately $31.5 million, or $0.4550 per Common Unit. On August 14, 2012, we paid a cash distribution of approximately $31.8 million, or $0.4600 per Common Unit.

During the three months and nine months ended September 30, 2012, we also paid $1.2 million and $3.5 million, respectively, in cash at a rate equal to the distributions paid to our holders of Common Units to holders of outstanding unvested RPUs.

Income per Unit

FASB Accounting Standards require use of the “two-class” method of computing earnings per unit for all periods presented.  The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of common unit and participating security as if all earnings for the period had been distributed.  Unvested restricted unit awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation.  Our unvested RPUs and 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 per common unit.


19


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
 
Nine Months Ended
 
 
September 30,
 
September 30,
Thousands, except per unit amounts
 
2013
 
2012
 
2013
 
2012
 
 
 
 
 
 
 
 
 
Net (loss) income attributable to the partnership
 
$
(25,011
)
 
$
(73,003
)
 
$
15,121

 
$
(30,467
)
Distributions on participating units not expected to vest
 
4

 

 
15

 

Net (loss) income attributable to holders of Common Units and participating securities
 
$
(25,007
)
 
$
(73,003
)
 
$
15,136

 
$
(30,467
)
Weighted average number of units used to calculate basic and diluted net income per unit:
 
 
 
 
 
 
 
 
Common Units
 
99,680

 
72,894

 
97,982

 
69,363

Participating securities (a)
 

 

 
1,652

 

Denominator for basic income per common unit
 
99,680

 
72,894

 
99,634

 
69,363

Dilutive units (b)
 

 

 
355

 

Denominator for diluted income per common unit
 
99,680

 
72,894

 
99,989

 
69,363

Net (loss) income per common unit
 
 
 
 
 
 
 
 
Basic
 
$
(0.25
)
 
$
(1.00
)
 
$
0.15

 
$
(0.44
)
Diluted
 
$
(0.25
)
 
$
(1.00
)
 
$
0.15

 
$
(0.44
)

(a) The three months ended September 30, 2013 and 2012 and the nine months ended September 30, 2012 exclude 1,729, 2,557 and 2,513, respectively, of potentially issuable weighted average RPUs and CPUs from participating securities, as we were in a loss position.
(b) The three months ended September 30, 2013 and 2012 and the nine months ended September 30, 2012 exclude 384, 59 and 57, 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.

14.  Unit and Other Valuation-Based Compensation Plans

Unit-based compensation expense for the three months and nine months ended September 30, 2013 was $4.9 million and $14.7 million, respectively, and for the three months and nine months ended September 30, 2012 was $5.7 million and $16.9 million, respectively. During the nine months ended September 30, 2013, the board of directors of BreitBurn GP, LLC (our “General Partner”) approved the grant of approximately 1.2 million of RPUs and CPUs to employees of BreitBurn Management under our LTIP.  Our outside directors were issued less than 0.1 million RPUs under our LTIP during the nine months ended September 30, 2013.  The fair market value of the RPUs granted during 2013 for computing compensation expense under FASB Accounting Standards averaged $20.84 per unit.

During the three months and nine months ended September 30, 2013, we paid zero and $0.6 million, respectively, for taxes withheld on RPUs vested during the period.  During the three months and nine months ended September 30, 2012, we paid nothing for taxes withheld on RPUs vested during the period.

As of September 30, 2013, we had $27.8 million of total unrecognized compensation costs for all outstanding awards.  The majority of this amount is expected to be recognized over the period from October 1, 2013 to December 31, 2015. For detailed information on our various compensation plans, see Note 17 to the consolidated financial statements included in our 2012 Annual Report.


20


15.  Subsequent Events

Distributions

On October 30, 2013, we announced a cash distribution to holders of Common Units for the third quarter of 2013 at the rate of $0.4875 per Common Unit, to be paid on November 14, 2013 to our holders of Common Units of record as of the close of business on November 11, 2013.

On October 30, 2013, we amended our First Amended and Restated Agreement of Limited Partnership by adopting Amendment No. 5. Amendment No. 5 provides that, at the discretion of our General Partner, we may pay quarterly distributions within 45 days following the end of each quarter or in three installments within 17, 45 and 75 days following the end of each quarter. The Partnership intends to change its distribution payment policy from a quarterly payment schedule to a monthly payment schedule beginning with the distributions relating to the fourth quarter of 2013. The payment of monthly distributions is expected to commence in January 2014.



    


21


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 2012 Annual Report and the consolidated financial statements and related notes therein.  Our 2012 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 2012 Annual Report and Part I—Item 1A “—Risk Factors” of our 2012 Annual Report.

Overview

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

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

Our core investment strategy includes the following principles:

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 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 2013.

2013 Acquisitions

On July 15, 2013, we completed the acquisition of the Whiting Assets from Whiting. We acquired the Whiting Assets for a preliminary purchase price of approximately $833.4 million in cash. Also, in July 2013, we completed the acquisition of additional interests in certain of the acquired assets in the Oklahoma Panhandle from other sellers for an additional approximately $30.2 million, subject to customary post-closing adjustments. The Whiting Assets include the Postle Field, which currently has active CO2 enhanced recovery projects, and the Northeast Hardesty Unit, both of which are located in Texas County, Oklahoma. We have a contracted supply of CO2 in the Bravo Dome Field in New Mexico, with step-in rights, for 129,000,000 Mcf over 10 to 15 years, which we expect will provide the volumes required to produce our estimated proved reserves when coupled with recycled CO2. The Postle Field includes 227 gross producing wells and 174 gross injectors, and the Northeast Hardesty Unit includes 24 gross producing wells and 17 gross injectors. As part of the acquisition and the purchase of additional interests, we are also the sole owner of the Dry Trails gas plant located in Texas County, Oklahoma and the 120-mile Transpetco Pipeline, a CO2 transportation pipeline delivering product from New Mexico to the Postle Field in Oklahoma. We funded the purchase price for the Whiting Acquisition and the acquisition of additional interests in certain of the acquired assets in the Oklahoma Panhandle with borrowings under our credit facility.

Our management’s review of the estimated proved reserves relating to the Whiting Acquisition indicated estimated proved reserves of 41.4 MMBoe, with an estimated proved reserve life index of approximately 15 years, as of June 30, 2013, which estimated proved reserves were determined using prices of $91.60 per barrel of oil and $3.44 per MMBtu of gas. Such prices were determined using the average of the historical first-day-of-the-month prices for the 12 months ended June 30, 2013 in accordance with Securities and Exchange Commission guidelines. Approximately 95% of these reserves were oil and NGLs, approximately 70% were proved developed and approximately 68% were proved developed producing as of June 30,

22


2013. Management’s estimate of the average daily production per day for September 2013 from the Whiting Assets was approximately 7,275 Boe, which was comprised of approximately 83% crude oil, 13% NGLs and 4% natural gas. In 2013 to date, the price per barrel of oil for our production from the Whiting Assets represented an approximately $8 discount to the NYMEX WTI benchmark price. Reserve engineering is a complex and subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates prepared by one engineer may vary from those prepared by another. Estimates of proved reserves for our recently acquired Oklahoma properties as of December 31, 2013 will be prepared by Cawley, Gillespie & Associates, Inc. using the information available at that time. Upon completion of their review, the estimate of the proved reserves for our oil and natural gas properties as of December 31, 2013 will be different from our management’s estimate of the proved reserves for our Oklahoma oil and natural gas properties as of June 30, 2013 as described above.

2013 Highlights

In February 2013, we sold approximately 14.95 million Common Units at a price to the public of $19.86 per Common Unit, resulting in proceeds of $285.0 million (net of underwriting discounts and estimated offering expenses), which we used to repay outstanding debt under our credit facility.

On February 14, 2013, we paid a cash distribution of approximately $39.8 million, or $0.4700 per Common Unit. On May 14, 2013, we paid a cash distribution of approximately $47.3 million, or $0.4750 per Common Unit. On August 14, 2013, we paid a cash distribution of approximately $47.8 million, or $0.4800 per Common Unit. On October 30, 2013, we announced a cash distribution to holders of Common Units for the third quarter of 2013 at the rate of $0.4875 per Common Unit, to be paid on November 14, 2013 to our holders of Common Units of record as of the close of business on November 11, 2013.

In July 2013, we entered into the Ninth Amendment to the Second Amended and Restated Credit Agreement, which increased our aggregate maximum credit amount from $1.5 billion to $3.0 billion, increased our borrowing base to $1.5 billion and increased the aggregate commitment of all lenders to $1.4 billion. The amendment also increased flexibility for the Total Leverage Ratio (defined as the ratio of total debt to EBITDAX) for the next five quarters, absent any refinancing, and added a new Senior Secured Leverage Ratio (defined as the ratio of senior secured indebtedness to EBITDAX) that will be applied through the second quarter of 2014, absent any refinancing.
    
Operational Focus and Capital Expenditures

 In the first nine months of 2013, our oil and natural gas capital expenditures totaled $198 million, compared to approximately $93 million in the first nine months of 2012.  We spent approximately $73 million in Texas, $64 million in California, $24 million in Wyoming, $20 million in Florida, $9 million in Oklahoma and $8 million in Michigan.  In the first nine months of 2013, we drilled and completed 38 wells in Texas, 40 wells in California, 22 wells in Wyoming, 3 wells in Oklahoma, 3 wells in Michigan and 1 well in Florida. We also performed workovers on 18 wells in Wyoming, 17 wells in Michigan, 12 wells in California and 5 wells in Oklahoma.

In 2013, our crude oil and natural gas capital program is expected to be approximately $271 million. This compares with approximately $153 million in 2012. We plan to principally target oil projects and expect to spend approximately 84% of our capital budget in California, Florida, Texas and Oklahoma and approximately 16% in Michigan, Wyoming, Indiana and Kentucky. We anticipate that approximately 90% of our total capital spending will be focused on drilling and rate-generating projects that are designed to increase production or reserves. Including production from our Oklahoma Panhandle acquisitions and without considering potential future acquisitions, we expect our 2013 production to be approximately 11.0 MMBoe.

Commodity Prices

In the third quarter of 2013, the NYMEX WTI spot price averaged $106 per barrel, compared with approximately $92 per barrel in the third quarter of 2012.  In the first nine months of 2013, the WTI spot price averaged $98 per barrel, compared with $96 per barrel a year earlier. The average NYMEX WTI spot price in October was approximately $101 per barrel, and in the first nine months of 2013, the NYMEX WTI spot price ranged from a low of $87 per barrel to a high of $111 per barrel. In 2012, the NYMEX WTI spot price averaged approximately $94 per barrel.
 

23


In the third quarter of 2013, the Henry Hub natural gas spot price averaged $3.55 per MMBtu compared with approximately $2.88 per MMBtu in the third quarter of 2012.  In the first nine months of 2013, the Henry Hub natural gas price averaged $3.69 per MMBtu, compared with $2.54 per MMBtu a year earlier. The Henry Hub natural gas spot price in October averaged approximately $3.68 per MMBtu and in the first nine months of 2013, the Henry Hub spot price ranged from a low of $3.08 to a high of $4.38.  In 2012, the Henry Hub natural gas spot price averaged approximately $2.75 per MMBtu.

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 properties and operations.  For the three months and nine months ended September 30, 2013, the monthly fee paid by PCEC for indirect expenses was $700,000. The monthly fee of $700,000 will be in effect through August 31, 2014 and, to the extent the term of the administrative services agreement is renewed, will be redetermined biannually thereafter. 


24


Results of Operations

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