News Column

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

August 5, 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. During the three months ended June 30, 2014, we paid three monthly cash distributions at the rate of $0.1658 per Common Unit per month, totaling approximately $59.5 million, or $0.4974 per Common Unit. On July 1, 2014, we announced a cash distribution to unitholders for the first monthly payment attributable to the second quarter of 2014 at the rate of $0.1675 per Common Unit, which was paid on July 16, 2014 to the record holders of Common Units at the close of business on July 11, 2014. On July 30, 2014, we announced a cash distribution to unitholders for the second monthly payment attributable to the first quarter of 2014 at the rate of $0.1675 per Common Unit, to be paid on August 14, 2014 to the record holders of Common Units at the close of business on August 11, 2014. 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. In May 2014, we sold 8.0 million 8.25% Series A Cumulative Redeemable Perpetual Preferred Units ("Preferred Units") in a public offering at a price of $25.00 per Preferred Unit, resulting in proceeds of $193.2 million, net of underwriting discount and offering expenses. The Preferred Units rank senior to the Common Units with respect to the payment of current distributions. We used the net proceeds from this offering to repay indebtedness outstanding under our credit facility. Distributions on Preferred Units are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by our board of directors out of legally available funds for such purpose. We will pay cumulative distributions in cash on the Preferred Units on a monthly basis at a monthly rate of $0.171875 per unit. During the three months ended June 30, 2014, we recognized $1.8 million of accrued distributions on the Preferred Units, which were calculated from the date of issuance to June 30, 2014 and are included in the distributions to preferred unitholders on the consolidated statements of operations. The initial distribution on the Preferred Units of $0.309375 was paid on July 15, 2014. On July 1, 2014, we declared a cash distribution for our Preferred Units of $0.171875 per unit expected to be paid on August15, 2014 to preferred unitholders of record at the close of business on July 31, 2014. On July 30, 2014, we declared a cash distribution for our Preferred Units of $0.171875 per unit expected to be paid on September 15, 2014 to preferred unitholders of record at the close of business on August 29, 2014. The monthly distribution rate is equal to an annual distribution of $2.0625 per Preferred Unit. 22 --------------------------------------------------------------------------------



Merger with QR Energy

On July 23, 2014, we, our General Partner and Boom Merger Sub, LLC, a direct wholly owned subsidiary of the Partnership ("Merger Sub"), entered into an Agreement and Plan of Merger (the "Merger Agreement") with QR Energy, LP ("QR Energy") and QRE GP, LLC ("QRE"). QR Energy is a publicly traded, Delaware limited partnership engaged in the acquisition, exploitation, development and production of oil and natural gas properties located in Alabama, Arkansas, Florida, Kansas, Louisiana, Michigan, New Mexico, Oklahoma and Texas. As of December 31, 2013, their total estimated proved reserves were approximately 109.1 MMBoe, of which approximately 77% were oil and NGLs and 85% were classified as proved developed reserves. Their average production for the year ended December 31, 2013 was 17.9 MBoe/d. Pursuant to the Merger Agreement, we will acquire QR Energy in exchange for our Common Units, implying a transaction value of approximately $3.0 billion, including the assumption of approximately $1,012 million of QR Energy's existing net debt and the payment of $350 million cash to the holders of the outstanding Class C Convertible Preferred Units of QR Energy (each, a "Class C Unit"). The Merger Agreement provides that, upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will be merged with and into QR Energy, with QR Energy continuing as the surviving entity and a direct wholly owned subsidiary of the Partnership (the "Merger"). Under the terms of the Merger Agreement, each outstanding common unit representing a limited partner interest in QR Energy (a "QR Energy Common Unit") and Class B Unit representing a limited partner interest in QR Energy (a "Class B Unit") will be converted into the right to receive 0.9856 newly issued Breitburn Common Units (the "Merger Consideration"). A number of Class B Units issuable upon a change of control of QR Energy equal to (i) 6,748,067, minus (ii) the excess of (A) the number of performance units that vest and are settled in QR Energy Common Units in connection with the Merger over (B) 383,900 will be issued and treated as outstanding Class B Units and converted into the right to receive the Merger Consideration. Each outstanding Class C Unit of QR Energy will be converted into the right to receive cash in an amount equal to $350 million divided by the number of Class C Units outstanding immediately prior to the effective time of the Merger. In no event will we be obligated to issue in excess of 72,001,686 Breitburn Common Units as part of the Merger Consideration. In connection with the Merger Agreement, each award of restricted QR Energy Common Units issued under QR Energy's equity plans that is subject to vesting or forfeiture, that is subject to time-based vesting and that is outstanding and unvested immediately prior to the effective time of the Merger will become fully vested and will be converted into the right to receive the Merger Consideration. Each award of performance units with respect to QR Energy Common Units issued under QR Energy's equity plans that is outstanding immediately prior to the effective time of the Merger will vest and be settled in a number of QR Energy Common Units determined based on actual attainment of the applicable performance goal(s) as of two business days prior to the effective time of the Merger, and the resulting QR Energy Common Units will be converted into the right to receive the Merger Consideration. The completion of the Merger is subject to satisfaction or waiver of customary closing conditions, including (1) the adoption of the Merger Agreement by holders of a majority of the outstanding QR Energy Common Units, Class B Units and Class C Units, voting as a single class, (2) the effectiveness of a registration statement on Form S-4, (3) the approval for listing of the Partnership Common Units issuable as part of the Merger Consideration on the NASDAQ and (4) other customary conditions such as expiration of the waiting period under the Hart-Scott-Rodino Act. The Merger Agreement contains certain termination rights for both the Partnership and QR Energy and further provides that, upon termination of the Merger Agreement, under certain circumstances, either party may be required to reimburse the other party's expenses up to $16,425,000, and QR Energy may be required to pay the Partnership a termination fee equal to $64,875,000 less any previous expense reimbursement by QR Energy. On July 23, 2014, we also entered into a Transaction, Voting and Support Agreement (the "Voting Agreement") with each of Quantum Resources A1, LP, Quantum Resources B, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC (collectively, the "Fund Unitholders"), and each of QR Holdings (QRE), LLC and QR Energy Holdings, LLC (collectively, the "Management Unitholders" and, together with the Fund Unitholders, the "QR Energy Unitholders") with respect to the Merger Agreement. The Voting Agreement generally requires that the QR Energy Unitholders vote or cause to be voted all QR Energy Common Units, Class B Units and Class C Units owned by such QR Energy Unitholder in favor of the merger and against alternative transactions. The Voting Agreement also provides that, upon termination of the Merger Agreement and QR Energy's acceptance of an alternative transaction, each QR Energy Unitholder may be required to pay the Partnership a termination fee equal to the lesser of (1) such QR Energy Unitholder's pro rata share 23 -------------------------------------------------------------------------------- of 2% of the equity value of such alternative transaction or (2) the excess of the aggregate consideration paid to such QR Energy Unitholder in such alternative transaction over the aggregate consideration that would have been received by such QR Energy Unitholder under the Merger Agreement. Subject to certain exceptions, the Voting Agreement will terminate upon the earlier of (i) the consummation of the Merger and (ii) the termination of the Merger Agreement. On July 23, 2014, we also entered into a Registration Rights Agreement (the "Registration Rights Agreement") with each of QR Holdings (QRE), LLC, QR Energy Holdings, LLC, Quantum Resources B, LP, Quantum Resources A1, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC (collectively, the "Fund"). Under the Registration Rights Agreement, we are required to file or cause to be filed with the SEC a registration statement with respect to the public resale of our Common Units issued to the Fund as part of the Merger Consideration. We are required to file or cause to be filed the registration statement within 90 following the closing under the Merger Agreement and are required to cause the registration statement to become effective as soon as reasonably practicable thereafter but in no event later than 120 after the closing under the Merger Agreement. The Merger Agreement, the Voting Agreement and the Registration Rights Agreement and the above descriptions have been included to provide investors and security holders with information regarding the terms of the Merger Agreement, the Voting Agreement and the Registration Rights Agreement. They are not intended to provide any other factual information about the Partnership, QR Energy or their respective subsidiaries or affiliates or equityholders. In connection with the closing of the Merger, we intend to refinance the outstanding debt of QR Energy under its credit facility, which was approximately $715 million as of June 30, 2014, and are also considering refinancing options for QR Energy's 9.25% senior notes due in 2020 with an aggregate principal amount of $300 million. We have received a firm commitment from Wells Fargo Bank, N.A. to increase the borrowing base under our credit facility to $2.5 billion in connection with the Merger.



Operational Focus and Capital Expenditures

In the first six months of 2014, our oil, NGL and natural gas capital expenditures, including capitalized engineering costs, totaled $168 million, compared to approximately $112 million in the first six months of 2013. We spent approximately $114 million in Texas, $25 million in California, $16 million in Oklahoma, $7 million in Florida, $3 million in Wyoming and $3 million in Michigan. In the first six months of 2014, we drilled and completed 53 productive wells in Texas, six productive wells in California, two productive wells in Wyoming and one well in Michigan. We also performed workovers on 11 wells in Oklahoma, three wells in Michigan and two wells in Florida. In 2014, our crude oil, NGL and natural gas capital spending program, including capitalized engineering costs and excluding acquisitions, is expected to be between $338 million and $348 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 or reserves. We plan to drill 199 wells with 188 wells expected in Texas and California and 11 wells expected in Wyoming and Michigan. Without considering potential acquisitions, we expect our second half of 2014 production to be between 6.8 MMBoe and 7.2 MMBoe, and expect our full year 2014 production to be between 13.4 MMBoe and 13.8 MMBoe. We have revised our production outlook principally due to lower than expected performance from our operations in the Permian Basin. In addition, we are evaluating our options for the development of our Permian Basin assets and intend to begin drilling horizontal wells in late 2014.



Commodity Prices

In the second quarter of 2014, the NYMEX WTI spot price averaged $103 per barrel, compared with approximately $94 per barrel in the second quarter of 2013. In the first six months of 2014, the NYMEX WTI spot price averaged $101 per barrel and ranged from a low of $91 per barrel to a high of $108 per barrel. In 2013, the NYMEX WTI spot price averaged approximately $98 per barrel. In the second quarter of 2014, the Henry Hub natural gas spot price averaged $4.61 per MMBtu compared with approximately $4.02 per MMBtu in the second quarter of 2013. In the first six months of 2014, the Henry Hub spot price averaged $4.83 and 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 second quarter of 2014, the MichCon natural gas spot price averaged $4.99 per MMBtu compared with approximately $4.33 per MMBtu in the second quarter of 2013. 24

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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 six months ended June 30, 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 delayed the issuance of permits relating to hydraulic fracturing in that field. However, we received the permits during the second quarter of 2014, and the delay was 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. 25 --------------------------------------------------------------------------------



Results of Operations

The table below summarizes certain of our results of operations for the periods indicated. The data for the periods reflect our results as they are presented in our unaudited consolidated financial statements included elsewhere in this report. Thousands of dollars, Three Months Ended June 30, Increase/ Six Months Ended June 30, Increase/ except as indicated 2014 2013 (Decrease) % 2014 2013 (Decrease) % Total production (MBoe) 3,373 2,453 920 38 % 6,592 4,799 1,793 37 % Oil (MBbl) 1,901 1,164 737 63 % 3,700 2,265 1,435 63 % NGLs (MBbl) 279 123 156 127 % 537 228 309 136 % Natural gas (MMcf) 7,163 6,994 169 2 % 14,134 13,838 296 2 % Average daily production (Boe/d) 37,069 26,956 10,113



38 % 36,422 26,516 9,906 37 % Sales volumes (MBoe)

3,289 2,528 761 30 % 6,522 4,798 1,724 36 % Average realized sales price (per Boe) (a)(b) $ 66.59$ 58.98$ 7.61 13 % $ 67.83$ 56.14$ 11.69 21 % Oil (per Bbl) (a)(b) 95.74 93.95 1.79 2 % 93.91 92.40 1.51 2 % NGLs (per Bbl) 38.26 26.8 11.46 43 % 40.48 26.43 14.05 53 % Natural gas (per Mcf) (b) $ 4.81 $ 4.22 $ 0.59 14 % 5.65 3.91 1.74 45 % Oil sales $ 173,948$ 116,508$ 57,440 49 % $ 341,034$ 209,460$ 131,574 63 % NGL sales 10,675 3,297 7,378 224 % 21,740 6,026 15,714 261 % Natural gas sales 34,428 29,481 4,947 17 % 79,833 54,162 25,671 47 % Gain (loss) on commodity derivative instruments (127,000 ) 66,993 (193,993 ) N/A (167,228 ) 42,817 (210,045 ) (491 )% Other revenues, net 1,071 702 369 53 % 2,655 1,460 1,195 82 % Total revenues 93,122 216,981 (123,859 ) (57 )% 278,034 313,925 (35,891 ) (11 )% Lease operating expenses before taxes (c) 70,923 48,544 22,379 46 % 137,913 94,105 43,808 47 % Production and property taxes (d) 16,001 11,066 4,935 45 % 31,660 20,449 11,211 55 % Total lease operating expenses 86,924 59,610 27,314 46 % 169,573 114,554 55,019 48 % Purchases and other operating costs 110 337 (227 ) (67 )% 324 655 (331 ) (51 )% Change in inventory (3,974 ) 1,287 (5,261 ) N/A (4,640 ) (1,822 ) (2,818 ) 155 % Total operating costs $ 83,060$ 61,234$ 21,826 36 % $ 165,257$ 113,387$ 51,870 46 % Lease operating expenses before taxes per Boe $ 21.03$ 19.79$ 1.24 6 % $ 20.92$ 19.61$ 1.31 7 % Production and property taxes per Boe 4.74 4.51 0.23 5 % 4.80 4.26 0.54 13 % Total lease operating expenses per Boe $ 25.77$ 24.30$ 1.47 6 % $ 25.72$ 23.87$ 1.85 8 % Depletion, depreciation and amortization ("DD&A") $ 68,245$ 46,541$ 21,704 47 % $ 131,746$ 94,331$ 37,415 40 % DD&A per Boe 20.23 18.97 1.26 7 % 19.99 19.66 0.33 2 % G&A expenses $ 16,420$ 13,716$ 2,704 20 % $ 35,149$ 28,579$ 6,570 23 % (a) Includes crude oil purchases. (b) Excludes the effect of commodity derivative settlements. (c) Includes district expenses, transportation expenses and processing fees. (d) Includes ad valorem and severance taxes. 26 --------------------------------------------------------------------------------



Comparison of Results for the Three Months and Six Months Ended June 30, 2014 and 2013

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

Production

For the three months ended June 30, 2014, total production was 3,373 MBoe compared to 2,453 MBoe for the three months ended June 30, 2013, primarily due to 616 MBoe from our Oklahoma properties acquired in July 2013, a 352 MBoe increase in production from our Texas properties acquired in December 2013 and 41 MBoe higher California production, primarily from our Santa Fe Springs field, partially offset by 52 MBoe and 32 MBoe lower production in Michigan and Wyoming, respectively, primarily due to natural field declines. For the six months ended June 30, 2014, total production was 6,592 MBoe compared to 4,799 MBoe for the six months ended June 30, 2013, primarily due to 1,249 MBoe from our Oklahoma properties acquired in July 2013, a 638 MBoe increase in production from our Texas properties acquired in December 2013, and 108 MBoe higher California production, primarily from our Santa Fe Springs field, partially offset by 101 MBoe, 51 MBoe and 43 MBoe lower production in Michigan, Wyoming and Florida, respectively, primarily due to severe winter weather and natural field declines.



Oil, NGL and natural gas sales

Total oil, natural gas liquid ("NGL") and natural gas sales revenues increased $69.8 million in the three months ended June 30, 2014, compared to the three months ended June 30, 2013. Crude oil revenues increased $57.4 million due to higher oil sales volumes and slightly higher oil sales prices, primarily due to production from our 2013 Oklahoma and Texas acquisitions, in addition to higher California production. NGL revenues increased $7.4 million due to higher NGL sales volumes and higher NGL sales prices, primarily due to production from our 2013 Oklahoma and Texas acquisitions. Natural gas revenues increased $4.9 million, primarily due to higher natural gas prices and slightly higher natural gas production. Realized prices for crude oil, excluding the effect of derivative instruments, increased $1.79 per Boe, or 2%, in the three months ended June 30, 2014 compared to the three months ended June 30, 2013. Realized prices for NGLs, excluding the effect of derivative instruments, increased $11.46 per Boe, or 43%, in the three months ended June 30, 2014 compared to the three months ended June 30, 2013. Realized prices for natural gas, excluding the effect of derivative instruments, increased $0.59 per Mcf, or 14%, in the three months ended June 30, 2014 compared to the three months ended June 30, 2013. Total oil, NGL and natural gas sales revenues increased $173.0 million in the six months ended June 30, 2014, compared to the six months ended June 30, 2013. Crude oil revenues increased $131.6 million due to higher oil sales volume and slightly higher oil sales prices primarily due to production from our 2013 Oklahoma and Texas acquisitions. NGL revenues increased $15.7 million due to higher NGL sales volumes and higher NGL prices, primarily due to production from our 2013 Oklahoma and Texas acquisitions. Natural gas revenues increased $25.7 million, primarily due to higher natural gas prices, particularly in Michigan due to severe winter weather, and slightly higher natural gas production. Realized prices for crude oil, excluding the effect of derivative instruments, increased $1.51 per Boe, or 2%, in the six months ended June 30, 2014 compared to the six months ended June 30, 2013. Realized prices for NGLs, excluding the effect of derivative instruments, increased $14.05 per Boe, or 53%, in the six months ended June 30, 2014 compared to the six months ended June 30, 2013. Realized prices for natural gas, excluding the effect of derivative instruments, increased $1.74 per Mcf, or 45%, in the six months ended June 30, 2014 compared to the six months ended June 30, 2013.



Gain (loss) on commodity derivative instruments

Loss on commodity derivative instruments for the three months ended June 30, 2014 was $127.0 million compared to a gain of $67.0 million during the three months ended June 30, 2013. Commodity derivative instrument settlement payments net of receipts were $17.0 million for the three months ended June 30, 2014 compared to net receipts of $4.8 million during the same period in 2013, which primarily reflects higher oil settlement payments compared to prior year due to higher average crude oil prices and lower average crude oil hedge prices as well as lower natural gas settlement receipts due to higher natural gas prices. Loss on commodity derivative instruments for the six months ended June 30, 2014 was $167.2 million compared to a gain of $42.8 million during the six months ended June 30, 2013. Commodity derivative instrument settlement payments net of receipts were $30.5 million for the six months ended June 30, 2014 compared to net receipts of $10.0 million during the same 27 -------------------------------------------------------------------------------- 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 June 30, 2014 increased $22.4 million compared to the three months ended June 30, 2013. The increase in pre-tax lease operating expenses reflects our 2013 Oklahoma and Texas acquisitions. On a per Boe basis, pre-tax lease operating expenses were 6% higher than the three months ended June 30, 2013 at $21.03 per Boe, primarily due to higher well services and fuel and utility costs, primarily in California and Texas. Production and property taxes for the three months ended June 30, 2014 totaled $16.0 million, which was $4.9 million higher than the three months ended June 30, 2013, primarily from our 2013 Oklahoma and Texas acquisitions and higher commodity prices. On a per Boe basis, production and property taxes for the three months ended June 30, 2014 were $4.74 per Boe, which was 5% higher than the three months ended June 30, 2013, primarily due to higher oil production as a percentage of total production, higher crude oil prices and higher natural gas prices, particularly in Michigan. Pre-tax lease operating expenses, including district expenses, transportation expenses and processing fees, for the six months ended June 30, 2014 increased $43.8 million compared to the six months ended June 30, 2013. The increase in pre-tax lease operating expenses reflects our 2013 Oklahoma and Texas acquisitions. On a per Boe basis, pre-tax lease operating expenses were 7% higher than the six months ended June 30, 2013 at $20.92 per Boe, primarily due to higher well services, fuel and utility costs, primarily in California. Production and property taxes for the six months ended June 30, 2014 totaled $31.7 million, which was $11.2 million higher than the six months ended June 30, 2013, primarily due to higher production and property taxes from our 2013 Oklahoma and Texas acquisitions and higher commodity prices. On a per Boe basis, production and property taxes for the six months ended June 30, 2014 were $4.80 per Boe, which was 13% higher than the six months ended June 30, 2013, primarily due to higher oil production as a percentage of total production, higher crude oil prices and higher 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. For the three months ended June 30, 2014, the change in inventory account amounted to a credit of $4.0 million compared to a charge of $1.3 million during the same period in 2013. The credit to inventory during the three months ended June 30, 2014 reflects a lower volume of crude oil sold than produced while the charge during the three months ended June 30, 2013 reflects a higher volume of crude oil sold than produced during the periods due to the timing of Florida sales. For the six months ended June 30, 2014, the change in inventory account amounted to a credit of $4.6 million compared to a credit of $1.8 million during the same period in 2013. The credit to inventory during the six months ended June 30, 2014 and June 30, 2013 reflect a higher volume of crude oil produced than sold during the periods due to the timing of Florida sales.



Depletion, depreciation and amortization

DD&A totaled $68.2 million, or $20.23 per Boe, during the three months ended June 30, 2014, an increase of approximately 7% per Boe from the same period a year ago. The increase in DD&A per Boe compared to three months ended June 30, 2013 was primarily due to higher oil production as a percentage of total production and higher DD&A rates in California and Texas due to increased drilling activities. DD&A totaled $131.7 million, or $19.99 per Boe, during the six months ended June 30, 2014, an increase of approximately 2% per Boe from the same period a year ago. The increase in DD&A per Boe compared to six months ended June 30, 2013 was primarily due to higher oil production as a percentage of total production and higher California DD&A rates, partially offset by lower Michigan DD&A rates driven by higher reserves related to an increase in natural gas prices. 28 --------------------------------------------------------------------------------



General and administrative expenses

Our G&A expenses totaled $16.4 million and $13.7 million for the three months ended June 30, 2014 and 2013, respectively. This included $6.1 million and $5.0 million, respectively, in non-cash unit-based compensation expense related to employee incentive plans. G&A expenses, excluding non-cash unit-based compensation, were $10.3 million and $8.7 million for the three months ended June 30, 2014 and 2013, respectively. The increase was primarily due to higher payroll expense for additional personnel attributable to acquisitions. On a per Boe basis, G&A expenses excluding non-cash unit-based compensation were $3.06 and $3.56 for the three months ended June 30, 2014 and 2013, respectively. The decrease in G&A expenses per Boe was primarily due to lower acquisition evaluation and integration costs as well as higher production from the 2013 acquisitions. The increase in unit-based compensation expense was primarily due to additional personnel. Our G&A expenses totaled $35.1 million and $28.6 million for the six months ended June 30, 2014 and 2013, respectively. This included $12.6 million and $9.8 million, respectively, in non-cash unit-based compensation expense related to employee incentive plans. G&A expenses, excluding non-cash unit-based compensation, were $22.5 million and $18.8 million for the six months ended June 30, 2014 and 2013, respectively. The increase was primarily due to higher payroll expense for additional personnel attributable to acquisitions. On a per Boe basis, G&A expenses excluding non-cash unit-based compensation were $3.41 and $3.91 for the six months ended June 30, 2014 and 2013, respectively. The decrease in G&A expenses per Boe was primarily due to lower acquisition evaluation and integration costs as well as higher production from the 2013 acquisitions. The increase in unit-based compensation expense was primarily due to additional personnel and 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 $30.2 million and $18.4 million for the three months ended June 30, 2014 and 2013, respectively. The increase in interest expense was primarily due to $7.9 million related to the 2022 Senior Notes issued in November 2013 and $3.5 million in higher credit facility interest expense as a result of increased borrowings and higher interest rates. Interest expense, excluding debt amortization, totaled $28.3 million and $17.1 million for the three months ended June 30, 2014 and 2013, respectively. Our interest expense totaled $60.9 million and $36.8 million for the six months ended June 30, 2014 and 2013, respectively. The increase in interest expense was primarily due to $15.8 million related to the 2022 Senior Notes issued in November 2013 and $6.9 million in higher credit facility interest expense as a result of increased borrowings and higher interest rates. Interest expense, excluding debt amortization, totaled $56.9 million and $34.2 million for the six months ended June 30, 2014 and 2013, respectively.



Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from operations, amounts available under our credit facility and equity and debt offerings. 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.



Preferred Equity Offering

In May 2014, we sold 8.0 million Series A Preferred Units at a price to the public of $25.00 per Series A Preferred Unit, resulting in proceeds of $193.2 million, net of underwriting discount and offering expenses of $6.8 million.

The initial distribution of $0.309375 per Series A Preferred Unit was paid on July 15, 2014. On July 1, 2014, we declared a cash distribution for our Series A Preferred Units of $0.171875 per Preferred Unit expected to be paid on August15, 2014 to preferred unitholders of record at the close of business on July 31, 2014. On July 30, 2014, we declared a cash distribution for our Preferred Units of $0.171875 per Preferred Unit expected to be paid on September 15, 2014 to preferred unitholders of record at the close of business on August 29, 2014. The monthly distribution rate is equal to an annual distribution of $2.0625 per Preferred Unit. 29 --------------------------------------------------------------------------------



Distributions on Common Units

Our Second Amended and Restated Agreement of Limited Partnership 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 June 30, 2014, we paid three monthly cash distributions at the rate of $0.1658 per Common Unit per month, totaling approximately $59.5 million, or $0.4974 per Common Unit.

During the six months ended June 30, 2014, we paid six monthly cash distributions, the first three distributions at the rate of $0.1642, and the last three distributions at the rate of $0.1658 per Common Unit per month, totaling approximately $118.2 million, or $0.9900 per Common Unit.

On July 1, 2014, we announced a cash distribution to unitholders for the first monthly payment attributable to the second quarter of 2014 at the rate of $0.1675 per Common Unit, which was paid on July 16, 2014.

On July 30, 2014, we announced a cash distribution to unitholders for the second monthly payment attributable to the second quarter of 2014 at the rate of $0.1675 per Common Unit, to be paid on August 14, 2014 to the record holders of Common Units at the close of business on August 11, 2014.



Cash Flows

Operating activities. Our cash flows from operating activities for the six months ended June 30, 2014 were $191.1 million compared to $97.4 million for the six months ended June 30, 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 six months ended June 30, 2014. Investing activities. Net cash used in investing activities during the six months ended June 30, 2014 and 2013 was $196.6 million and $185.4 million, respectively. During the six months ended June 30, 2014, we spent $188.8 million on capital expenditures, primarily for drilling and completion activities, $5.1 million on CO2 advances and $2.7 million on property acquisitions. During the six months ended June 30, 2013, we spent $100.2 million on capital expenditures, primarily for drilling and completion activities and $86.0 million on a deposit for oil and gas properties. Financing activities. Net cash flows from financing activities for the six months ended June 30, 2014 and 2013 was $12.1 million and $85.6 million, respectively. During the six months ended June 30, 2014, we decreased our outstanding borrowings under our credit facility by approximately $77.5 million. We had total outstanding borrowings, net of unamortized discount on our senior notes, of approximately $1.81 billion at June 30, 2014 and $1.89 billion at December 31, 2013. During the six months ended June 30, 2014, we received net proceeds of $193.4 million and $20.3 million from the issuance of Preferred Units and Common Units, respectively, made cash distributions of $120.1 million, borrowed $466.0 million and repaid $543.5 million under our credit facility. During the six months ended June 30, 2013, we received net proceeds of $285.0 million from the issuance of Common Units, made cash distributions of $88.8 million, borrowed $397.0 million and repaid $507.0 million under our credit facility.



Senior Notes

As of June 30, 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 June 30, 2014 and December 31, 2013, we had a $3.0 billion credit facility with a maturity date of May 9, 2017 and May 9, 2016, respectively. At June 30, 2014 and December 31, 2013, our borrowing base was $1.6 billion and $1.5 billion, respectively, and the aggregate commitment of all lenders was $1.4 billion at each date. 30

-------------------------------------------------------------------------------- As of June 30, 2014 and August 4, 2014, we had $656 million and $687.5 million, respectively, in indebtedness outstanding under the Second Amended and Restated Credit Agreement. As of June 30, 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 regularly scheduled borrowing base redetermination is in 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 June 30, 2014 and August 4, 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. In connection with the closing of the Merger, we intend to refinance the outstanding debt of QR Energy under its credit facility, which was approximately $715 million as of June 30, 2014, and are also considering refinancing options for QR Energy's 9.25% senior notes due in 2020 with an aggregate principal amount of $300 million. We have received a firm commitment from Wells Fargo Bank, N.A. to increase the borrowing base under our credit facility to $2.5 billion in connection with the Merger.



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 June 30, 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 June 30, 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 June 30, 2014, our largest derivative asset balances were with Toronto-Dominion Bank, Bank of Montreal and Barclays Bank PLC, which accounted for approximately 43%, 26% and 14% of our derivative asset balances, respectively. Except for the issuance of Preferred Units and Common Units and the amendments to our credit facility, we had no material changes to our financial contractual obligations during the six months ended June 30, 2014. 31 --------------------------------------------------------------------------------



Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of June 30, 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


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