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BREITBURN ENERGY PARTNERS L.P. - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations

May 8, 2014

You should read the following discussion and analysis in conjunction with Management's Discussion and Analysis in Part II-Item 7 of our 2013 Annual Report and the consolidated financial statements and related notes therein. Our 2013 Annual Report contains a discussion of other matters not included herein, such as disclosures regarding critical accounting policies and estimates and contractual obligations. You should also read the following discussion and analysis together with Part II-Item 1A "-Risk Factors" of this report, the "Cautionary Statement Regarding Forward-Looking Information" in this report and in our 2013 Annual Report and Part I-Item 1A "-Risk Factors" of our 2013 Annual Report. Overview We are an independent oil and 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, NGL and natural gas reserves located primarily in: the Antrim Shale and several non-Antrim formations in Michigan; the Oklahoma Panhandle; the Permian Basin in Texas; the Evanston, Green River, Wind River, Big Horn and Powder River Basins in Wyoming; the Los Angeles and San Joaquin Basins in California; the Sunniland Trend in Florida; and the New Albany Shale in Indiana and Kentucky.



2014 Highlights

During the three months ended March 31, 2014, we paid three monthly cash distributions at the rate of $0.1642 per Common Unit per month, totaling approximately $58.7 million, or $0.4926 per Common Unit.

On April 1, 2014, we announced a cash distribution to unitholders for the first monthly payment attributable to the first quarter of 2014 at the rate of $0.1658 per Common Unit, which was paid on April 16, 2014. On April 24, 2014, we announced a cash distribution to unitholders for the second monthly payment attributable to the first quarter of 2014 at the rate of $0.1658 per Common Unit, to be paid on May 14, 2014 to the record holders of Common Units at the close of business on May 5, 2014. In February 2014, we entered into the Eleventh Amendment to the Second Amended and Restated Credit Agreement, which eliminated the Maximum Total Leverage Ratio (defined as the ratio of total debt to EBITDAX) and Maximum Senior Secured Leverage Ratio (defined as the ratio of senior secured indebtedness to EBITDAX) requirements and added a provision requiring us to maintain an Interest Coverage Ratio (defined as EBITDAX divided by Consolidated Interest Expense) for the four quarters ending on the last day of each quarter beginning with the fourth quarter of 2013 of no less than 2.50 to 1.00. The amendment also provides that we cannot incur senior unsecured debt in excess of our borrowing base in effect at the time of the issuance of such debt. In April 2014, in connection with the regularly scheduled borrowing base redetermination, we entered into the Twelfth Amendment to the Second Amended and Restated Credit Agreement which provides for an increased borrowing base of $1.6 billion with a total lender commitment of $1.4 billion and an extension of the term of the credit facility for one year until May 9, 2017.



Operational Focus and Capital Expenditures

In the first three months of 2014, our oil, NGL and natural gas capital expenditures totaled $79 million, compared to approximately $45 million in the first three months of 2013. We spent approximately $53 million in Texas, $12 million in California, $9 million in Oklahoma, $3 million in Florida, $1 million in Wyoming and $1 million in Michigan. In the first three months of 2014, we drilled and completed 21 productive wells in Texas, six productive wells in California and one productive well in Wyoming. We also performed workovers on two wells in Oklahoma. In 2014, our crude oil, NGL and natural gas capital spending program, including capitalized engineering costs and excluding acquisitions, is expected to be between $325 million and $345 million. This compares with approximately $295 million in 2013. In 2014, we anticipate spending approximately 92% principally on oil projects in Texas, California and Oklahoma and approximately 8% principally on oil projects in Florida, Wyoming and Michigan. We anticipate 85% of our total capital spending will be focused on drilling and rate-generating projects that are designed to increase or add to production 20 -------------------------------------------------------------------------------- or reserves. We plan to drill 168 wells with 156 wells expected in Texas and California and 12 wells expected in Wyoming, Michigan and Florida. Without considering potential acquisitions, we expect our 2014 production to be between 13.6 MMBoe and 14.4 MMBoe. Commodity Prices In the first quarter of 2014, the NYMEX WTI spot price averaged $99 per barrel, compared with approximately $94 per barrel in the first quarter of 2013. In the first three months of 2014, the NYMEX WTI spot price ranged from a low of $91 per barrel to a high of $105 per barrel. In 2013, the NYMEX WTI spot price averaged approximately $98 per barrel. In the first quarter of 2014, the Henry Hub natural gas spot price averaged $5.18 per MMBtu compared with approximately $3.49 per MMBtu in the first quarter of 2013. In the first three months of 2014, the Henry Hub spot price ranged from a low of $3.95 per MMBtu to a high of $8.15 per MMBtu. In 2013, the Henry Hub natural gas spot price averaged approximately $3.73 per MMBtu. In the first quarter of 2014, the Michcon natural gas spot price averaged $7.68 per MMBtu compared with approximately $3.50 per MMBtu in the first quarter of 2013.



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 ended March 31, 2014, the monthly fee paid by PCEC for indirect expenses was $700,000. In March 2014, the expiration of the term for the current monthly fee of $700,000 was extended from August 31, 2014, to December 31, 2014, and, to the extent the term of the administrative services agreement is renewed past December 31, 2014, the monthly fee will be redetermined biannually thereafter.



Hydraulic Fracturing

During 2013, the California Legislature passed SB 4 which became effective on January 1, 2014. SB 4 specifically authorizes hydraulic fracturing and certain other completion stimulation techniques throughout California, subject to additional regulatory requirements. Final regulations implementing SB 4 will not be issued until later in the year or early 2015. In November 2013, the California Department of Conservation released proposed regulations to implement SB 4 and issued currently effective interim rules. The interim rules require approval of Well Stimulation Treatment Notices before starting stimulation treatment, disclosure of the fluids used and, adoption of groundwater monitoring and water management plans. They also govern resident notifications, storage and handling of fluids and well integrity. The only hydraulic fracturing planned in California for 2014 is in the Belridge field in western Kern County. The SB4 permit implementation process has delayed the issuance of permits relating to hydraulic fracturing in that field by a number of weeks. However, we currently anticipate receiving permits there during the second quarter of 2014. The current delays are not material to the Partnership as a whole. Several local jurisdictions in California have proposed various forms or moratoria or bans on hydraulic fracturing. In some cases, these discussed measures include broad terms which, if enacted, could affect current operations. To our knowledge, only one such local jurisdiction where we have production - the City of Los Angeles - is currently considering such a proposal. The actual language of such a proposal has not been released and thus its potential effect cannot be fully assessed at this time. However, our production within the city limits is small and does not involve hydraulic fracturing. Therefore, we do not believe that any current local proposal will have a material adverse effect on the Partnership as a whole. 21 --------------------------------------------------------------------------------



Results of Operations

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



March 31, Increase/

Thousands of dollars, except as indicated 2014 2013 (Decrease) % Total production (MBoe) 3,219 2,346 873 37 % Oil (MBbl) 1,799 1,102 697 63 % NGLs (MBbl) 258 104 154 148 % Natural gas (MMcf) 6,971 6,844 127 2 % Average daily production (Boe/d) 35,768 26,070 9,698 37 % Sales volumes (MBoe) 3,233 2,270 963 42 % Average realized sales price (per Boe) (a)(b) $ 69.12 $ 52.96$ 16.16 31 % Oil (per Bbl) (a)(b) 92.12 90.53 1.59 2 % NGLs (per Bbl) 42.89 25.99 16.90 65 % Natural gas (per Mcf) (b) $ 6.51 $ 3.61$ 2.90 80 % Oil sales $ 167,086$ 92,952$ 74,134 80 % NGL sales 11,065 2,729 8,336 305 % Natural gas sales 45,405 24,681 20,724 84 % Loss on commodity derivative instruments (40,228 ) (24,176 ) (16,052 ) 66 % Other revenues, net 1,584 758 826 109 % Total revenues $ 184,912$ 96,944$ 87,968 91 %



Lease operating expenses before taxes (c) $ 66,990 $

45,561 $ 21,429 47 % Production and property taxes (d) 15,659 9,383 6,276 67 % Total lease operating expenses 82,649



54,944 27,705 50 %

Purchases and other operating costs $ 214 $ 318 $ (104 ) (33 )% Change in inventory (666 ) (3,109 ) 2,443 n/a Total operating costs $ 82,197$ 52,153$ 30,044 58 % Lease operating expenses before taxes per Boe $ 20.81 $ 19.42$ 1.39 7 % Production and property taxes per Boe 4.86 4.00 0.86 22 %



Total lease operating expenses per Boe $ 25.67 $

23.42 $ 2.25 10 %

Depletion, depreciation and amortization ("DD&A") $ 63,501$ 47,790$ 15,711 33 % DD&A per Boe 19.73 20.37 (0.64 ) (3 )% G&A $ 18,729$ 14,863$ 3,866 26 % (a) Includes crude oil purchases. (b) Excludes the effect of commodity derivative settlements. (c) Includes lease operating expenses, district expenses, transportation expenses and processing fees. (d) Includes ad valorem and severance taxes. 22 --------------------------------------------------------------------------------



Comparison of Results for the Three Months Ended March 31, 2014 and 2013

The variances in our results were due to the following components:

Production

For the three months ended March 31, 2014, total production was 3,219 MBoe compared to 2,346 MBoe for the three months ended March 31, 2013, primarily due to 632 MBoe from our Oklahoma properties acquired in July 2013, a 286 MBoe increase in production from our Texas properties acquired in December 2013, and 67 MBoe higher California production, primarily from our Santa Fe Springs field, partially offset by 50 MBoe and 19 MBoe lower production in Michigan and Wyoming, respectively, primarily due to severe winter weather and natural field declines, and 43 MBoe lower Florida production primarily due to well work during the quarter.



Oil, natural gas and NGL sales

Total oil, natural gas liquid ("NGL") and natural gas sales revenues increased $103.2 million in the three months ended March 31, 2014, compared to the three months ended March 31, 2013. Crude oil revenues increased $74.1 million due to higher oil prices and higher oil sales volumes, primarily due to production from our Oklahoma Panhandle Acquisitions and our Permian Basin Acquisitions. NGL revenues increased $8.3 million due to higher NGL prices and higher NGL sales volumes, primarily due to production from our 2013 Oklahoma and Texas acquisitions. Natural gas revenues increased $20.7 million, primarily due to higher natural gas prices, particularly in Michigan due to cold winter weather, and slightly higher natural gas production. Realized prices for crude oil, excluding the effect of derivative instruments, increased $1.59 per Boe, or 2%, in the three months ended March 31, 2014 compared to the three months ended March 31, 2013. Realized prices for NGLs, excluding the effect of derivative instruments, increased $16.90 per Boe, or 65%, in the three months ended March 31, 2014 compared to the three months ended March 31, 2013. Realized prices for natural gas, excluding the effect of derivative instruments, increased $2.90 per Mcf, or 80%, in the three months ended March 31, 2014 compared to the three months ended March 31, 2013.



Loss on commodity derivative instruments

Loss on commodity derivative instruments for the three months ended March 31, 2014 was $40.2 million compared to a loss of $24.2 million during the three months ended March 31, 2013. Commodity derivative instrument settlement payments net of receipts were $13.5 million for the three months ended March 31, 2014 compared to net receipts of $5.2 million during the same period in 2013, which primarily reflects natural gas settlement payments due to higher natural gas prices compared to natural gas settlement receipts in the prior year as well as higher oil settlement payments compared to prior year due to higher average crude oil prices and lower average crude oil hedge prices. Lease operating expenses Pre-tax lease operating expenses, including district expenses, transportation expenses and processing fees, for the three months ended March 31, 2014 increased $21.4 million compared to the three months ended March 31, 2013. The increase in pre-tax lease operating expenses reflects our Oklahoma Panhandle Acquisitions and our Permian Basin Acquisitions. On a per Boe basis, pre-tax lease operating expenses were 7% higher than the three months ended March 31, 2013 at $20.81 per Boe, primarily due to higher well services and fuel and utility costs. Production and property taxes for the three months ended March 31, 2014 totaled $15.7 million, which was $6.3 million higher than the three months ended March 31, 2013, primarily due to higher production and property taxes from our Oklahoma Panhandle Acquisitions and our Permian Basin Acquisitions. On a per Boe basis, production and property taxes for the three months ended March 31, 2014 were $4.86 per Boe, which was 22% higher than the three months ended March 31, 2013, primarily due to higher oil production as a percentage of total production, higher crude oil prices and natural gas prices, particularly in Michigan.



Change in inventory

In Florida, our 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. Sales occur on average every six to eight weeks. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are credited to operating costs through the change in inventory account. Production expenses are charged to operating costs through the change in inventory account when they are sold. 23 -------------------------------------------------------------------------------- For the three months ended March 31, 2014, the change in inventory account amounted to a credit of $0.7 million compared to a credit of $3.1 million during the same period in 2013. The credit to inventory during the three months ended March 31, 2014 reflects the higher cost of oil produced during the quarter compared to the oil sold during the quarter, primarily due to well repairs. The credit to inventory during the three months ended March 31, 2013 reflects a lower volume of crude oil sold than produced during the quarter.



Depletion, depreciation and amortization

DD&A totaled $63.5 million, or $19.73 per Boe, during the three months ended March 31, 2014, a decrease of approximately 3% per Boe from the same period a year ago. The decrease in DD&A per Boe compared to three months ended March 31, 2013 was primarily due to lower Michigan DD&A rates driven by higher reserves related to an increase in natural gas prices during the fourth quarter of 2013 and lower Texas DD&A rates driven by higher reserves related to increases in commodity prices and our 2013 drilling activities.



General and administrative expenses

Our G&A expenses totaled $18.7 million and $14.9 million for the three months ended March 31, 2014 and 2013, respectively. This included $6.5 million and $4.8 million, respectively, in non-cash unit-based compensation expense related to employee incentive plans. G&A expenses, excluding non-cash unit-based compensation, were $12.2 million and $10.1 million for the three months ended March 31, 2014 and 2013, respectively. The increase was primarily due to higher payroll expense for additional personnel attributable to acquisitions and higher acquisition evaluation and integration costs. On a per Boe basis, G&A expenses excluding non-cash unit-based compensation were $3.78 and $4.29 for the three months ended March 31, 2014 and 2013, respectively. The increase in unit-based compensation expense was primarily due to additional personnel and $0.6 million from an increase in the 2013 CPU performance factor from 1.0 to 1.25 (see Note 13).



Interest expense, net of amounts capitalized

Our interest expense totaled $30.7 million and $18.4 million for the three months ended March 31, 2014 and 2013, respectively. The increase in interest expense was primarily due to $7.9 million higher interest related to 2022 Senior Notes issued in November 2013 and $3.5 million higher credit facility interest expense as a result of increased borrowings and slightly higher interest rates.



Interest expense excluding debt amortization, totaled $28.5 million and $17.2 million for the three months ended March 31, 2014 and 2013, respectively.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from operations and amounts available under our credit facility. Our primary uses of cash have been for our operating expenses, capital expenditures and cash distributions to unitholders. To fund certain acquisition transactions, we have historically used borrowings under our credit facility, accessed the private placement markets and issued equity as partial consideration. As market conditions have permitted, we have also engaged in asset sale transactions and equity and debt offerings. In the future, we intend to access the public and private capital markets to fund certain acquisitions and refinancing transactions.



Distributions

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. We changed our distribution payment policy from a quarterly payment schedule to a monthly payment schedule beginning with the distributions relating to the fourth quarter of 2013.



During the three months ended March 31, 2014, we paid three monthly cash distributions at the rate of $0.1642 per Common Unit per month, totaling approximately $58.7 million, or $0.4926 per Common Unit.

24 -------------------------------------------------------------------------------- On April 1, 2014, we announced a cash distribution to unitholders for the first monthly payment attributable to the first quarter of 2014 at the rate of $0.1658 per Common Unit, which was paid on April 16, 2014. On April 24, 2014, we announced a cash distribution to unitholders for the second monthly payment attributable to the first quarter of 2014 at the rate of $0.1658 per Common Unit, to be paid on May 14, 2014 to the record holders of Common Units at the close of business on May 5, 2014.



Cash Flows

Operating activities. Our cash flows from operating activities for the three months ended March 31, 2014 were $116.3 million, compared to $58.9 million for the three months ended March 31, 2013. The increase in cash flows from operating activities was primarily due to higher operating income, driven by our 2013 acquisitions and higher commodity prices, particularly natural gas prices in Michigan and NGL prices in Oklahoma and Texas, and changes in working capital during the three months ended March 31, 2014. Investing activities. Net cash used in investing activities during the three months ended March 31, 2014 and 2013 was $97.6 million and $40.6 million, respectively. During the three months ended March 31, 2014, we spent $93.1 million on capital expenditures, primarily for drilling and completion activities, and $2.5 million on property acquisitions. During the three months ended March 31, 2013, we spent $38.1 million on capital expenditures, primarily for drilling and completion activities, and $2.5 million on property acquisitions. Financing activities. Net cash used in financing activities for the three months ended March 31, 2014 and 2013 was $19.4 million and $15.1 million, respectively. During the three months ended March 31, 2014, we increased our outstanding borrowings under our credit facility by approximately $42.0 million. We had total outstanding borrowings, net of unamortized discount on our senior notes, of approximately $1.93 billion at March 31, 2014 and $1.89 billion at December 31, 2013. During the three months ended March 31, 2014, we received net proceeds of $0.2 million from the issuance of Common Units, made cash distributions of $59.6 million, borrowed $199.0 million and repaid $157.0 million under our credit facility. During the three months ended March 31, 2013, we received net proceeds of $285.2 million from the issuance of Common Units, made cash distributions of $40.6 million, borrowed $72.0 million and repaid $332.0 million under our credit facility.



Senior Notes

As of March 31, 2014, we had $305 million in 8.625% senior notes due 2020 and $850 million in 7.875% senior notes due 2022. See Note 7 for a discussion of our senior notes. Credit Agreement



At each of March 31, 2014 and December 31, 2013, we had a $3.0 billion credit facility with a maturity date of May 9, 2016. At each of March 31, 2014 and December 31, 2013, our borrowing base was $1.5 billion and the aggregate commitment of all lenders was $1.4 billion.

In February 2014, we entered into the Eleventh Amendment to the Second Amended and Restated Credit Agreement, which eliminated the Maximum Total Leverage Ratio (defined as the ratio of total debt to EBITDAX) and Maximum Senior Secured Leverage Ratio (defined as the ratio of senior secured indebtedness to EBITDAX) requirements and added a provision requiring us to maintain an Interest Coverage Ratio (defined as EBITDAX divided by Consolidated Interest Expense) for the four quarters ending on the last day of each quarter beginning with the fourth quarter of 2013 of no less than 2.50 to 1.00. The amendment also provides that we cannot incur senior unsecured debt in excess of our borrowing base in effect at the time of the issuance of such debt. EBITDAX is not a defined GAAP measure. The Second Amended and Restated Credit Agreement defines EBITDAX as consolidated net income plus exploration expense, interest expense, income tax provision, DD&A, unrealized loss or gain on derivative instruments, non-cash charges, including non-cash unit-based compensation expense, loss or gain on sale of assets (excluding loss or gain on monetization of derivative instruments for the following 12 months), cumulative effect of changes in accounting principles, pro forma results from acquisitions and cash distributions received from our unrestricted entities (as defined in the Second Amended and Restated Credit Agreement) and excluding income from our unrestricted entities. 25

-------------------------------------------------------------------------------- In April 2014, in connection with the regularly scheduled borrowing base redetermination, we entered into the Twelfth Amendment to the Second Amended and Restated Credit Agreement which provides for an increased borrowing base of $1.6 billion with a total lender commitment of $1.4 billion and an extension of the term of the credit facility for one year until May 9, 2017. As of March 31, 2014 and May 7, 2014, we had $775 million and $827 million, respectively, in indebtedness outstanding under the Second Amended and Restated Credit Agreement. As of March 31, 2014, the lending group under the Second Amended and Restated Credit Agreement included 22 banks. Of the $1.4 billion in total commitments under our credit facility, Wells Fargo Bank, National Association held approximately 12% of the commitments. Fifteen banks held between 3.5% and 6.8% of the commitments, including Bank of Montreal, The Bank of Nova Scotia, Union Bank, N.A., Barclays Bank PLC, Citibank, N.A., Royal Bank of Canada, Sovereign Bank, N.A., The Royal Bank of Scotland plc, U.S. Bank National Association, Compass Bank, Comerica Bank, Credit Suisse AG, Cayman Islands Branch, J.P. Morgan Chase, N.A., Sumitomo Mitsui Banking Group and Toronto Dominion (Texas), LLC, with each of the remaining lenders holding 2.5% of the commitments. In addition to our relationships with these institutions under our credit facility, from time to time we engage in other transactions with a number of these institutions. Such institutions or their affiliates may serve as underwriter or initial purchaser of our debt and equity securities and/or serve as counterparties to our commodity and interest rate derivative contracts.



Our next borrowing base redetermination is scheduled for October 2014.

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; 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 Second Amended and Restated Credit Agreement includes a restriction on our ability to make a distribution unless, after giving effect to such distribution, we remain in compliance with all terms and conditions of our credit facility. As of March 31, 2014 and May 7, 2014 we were in compliance with our debt covenants. 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.



Contractual Obligations and Commitments

On July 15, 2013, we completed the acquisition of the Whiting Assets. As part of this acquisition, we assumed the obligation to purchase a minimum daily volume of CO2 over the next 20 years. 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. See Note 11 to the consolidated financial statements within this report for a discussion of our future minimum commitments under these purchase agreements. 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 March 31, 2014, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank, National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia, BNP Paribas, Royal Bank of Canada and Toronto-Dominion Bank. We periodically obtain credit default swap information on our counterparties. As of March 31, 2014, each of these financial institutions had an investment grade credit rating. Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default. As of March 31, 2014, our largest derivative asset balances were with Wells Fargo Bank, National Association, Credit Suisse Energy LLC and Citibank, N.A., which accounted for approximately 30%, 27% and 14% of our derivative asset balances, respectively.



Except for the issuance of Common Units and the amendments to our credit facility, we had no material changes to our financial contractual obligations during the three months ended March 31, 2014.

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Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of March 31, 2014 and December 31, 2013.

New Accounting Standards

See Note 1 to the consolidated financial statements within this report for a discussion of new accounting standards applicable to us.


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Source: Edgar Glimpses