DCP Midstream Partners Reports Third Quarter 2012 Results

DCP Midstream Partners, LP (NYSE: DPM), or the Partnership, today reported financial results for the three and nine months ended September 30, 2012. The table below reflects results for the three and nine months ended September 30, 2012 and 2011 on a consolidated basis and results for the 2011 periods as originally reported.

THIRD QUARTER AND YEAR TO DATE SUMMARY RESULTS
       
Three Months Ended Nine Months Ended
September 30, (2) (3) September 30, (2) (3)
  2012         2011    

AsReportedin 2011
      2012       2011    

AsReportedin 2011
(Unaudited)
(Millions, except per unit amounts)
               
Net income attributable to partners $ 1.3 $ 68.5 $ 66.3 $ 103.7 $ 116.2 $ 101.9
Net (loss) income per limited partner unit - basic $ (0.16 ) $ 1.35 $ 1.35 $ 1.37 $ 1.93 $ 1.93
Net (loss) income per limited partner unit - diluted $ (0.16 ) $ 1.35 $ 1.35 $ 1.36 $ 1.93 $ 1.93
Adjusted EBITDA(1) $ 47.1 $ 38.9 $ 32.3 $ 165.7 $ 157.8 $ 129.6
Adjusted net income attributable to partners(1) $ 23.8 $ 8.1 $ 7.0 $ 84.8 $ 68.9 $ 55.5
Adjusted net income per limited partner unit(1) - basic and diluted $ 0.22 $ 0.02 $ 0.02 $ 1.01 $ 0.87 $ 0.87
Distributable cash flow(1) $ 35.4 ** $ 27.6 $ 112.3 ** $ 113.0
 
(1)   Denotes a financial measure not presented in accordance with U.S. generally accepted accounting principles, or GAAP. Each such non-GAAP financial measure is defined below under “Non-GAAP Financial Information”, and each is reconciled to its most directly comparable GAAP financial measures under “Reconciliation of Non-GAAP Financial Measures” below.
(2) In March 2012, the Partnership completed the contribution from DCP Midstream, LLC (“DCP Midstream”) of the remaining 66.7 percent interest in DCP Southeast Texas Holdings, GP, in a transaction between entities under common control. This transfer of net assets between entities under common control was accounted for as if the transaction had occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information similar to the pooling method. In addition, results are presented as originally reported in 2011 for comparative purposes.
(3) We recognized lower of cost or market adjustments during the three and nine months ended September 30, 2012 and 2011. Includes non-cash commodity derivative mark-to-market of $(22.9) million and $61.1 million for the three months ended September 30, 2012 and 2011, respectively, and $19.3 million and $49.0 million for the nine months ended September 30, 2012 and 2011, respectively.
** Distributable cash flow has not been calculated under the pooling method.
 

DROP DOWN OF A ONE-THIRD INTEREST IN THE EAGLE FORD JOINT VENTURE

Effective November 1, 2012, we formed a joint venture with DCP Midstream, LLC (“DCP Midstream”) and completed a drop down of a one-third interest in the Eagle Ford system. The $438.3 million transaction, which is subject to certain customary working capital and other purchase price adjustments, was financed at closing through a $343.5 million, 2-year term loan and the issuance of 1,912,663 DPM common units to DCP Midstream. In conjunction with the transaction, DCP Midstream provided a three-year direct commodity price hedge for the Partnership’s one-third interest.

The Eagle Ford system is synergistic with the Partnership’s Eagle Plant and includes:

  • five cryogenic processing plants with 760 million cubic feet per day processing capacity
  • approximately 6,000 miles of gathering systems
  • three fractionators with approximately 36,000 barrels per day capacity
  • production from 900,000 acres supported by acreage dedications or throughput commitments under long-term predominantly percent-of-proceeds agreements
  • favorable access to interstate and intrastate gas markets
  • access to Sand Hills pipeline delivering NGLs to the Mont Belvieu and Gulf Coast petrochemical markets

This immediately accretive transaction provides long-term cash flows to support continued distribution growth.

CEO PERSPECTIVE

“Year to date financial results and distribution growth were in line with our 2012 forecast,” said Mark Borer, chief executive officer of the Partnership. “We continue to execute on co-investment with our general partner with this expanded investment in the Eagle Ford shale. This transaction brings our 2012 co-investment to approximately $960 million, in excess of our 2012 target and well on our way to meeting our targeted $3 billion of growth for 2012 through 2014.”

CONSOLIDATED FINANCIAL RESULTS

Adjusted EBITDA for the three months ended September 30, 2012 increased to $47.1 million from $38.9 million for the three months ended September 30, 2011. Adjusted EBITDA for the nine months ended September 30, 2012 increased to $165.7 million from $157.8 million for the nine months ended September 30, 2011. Adjusted EBITDA for the nine months ended September 30, 2012 includes a non-cash lower-of-cost-or-market “LCM” inventory adjustment.

On October 29, 2012, we announced a quarterly distribution of $0.68 per limited partner unit. This represents an increase of 1.5 percent over the last quarterly distribution and an increase of 6.3 percent over the distribution declared in the third quarter of 2011. Our distributable cash flow of $35.4 million for the three months ended September 30, 2012 provided a 0.7 times distribution coverage ratio adjusted for the timing of actual distributions paid during the quarter. The distribution coverage ratio adjusted for the timing of actual distributions paid during the last four quarters was approximately 0.9 times.

OPERATING RESULTS BY BUSINESS SEGMENT

Natural Gas Services — Adjusted segment EBITDA increased to $42.5 million for the three months ended September 30, 2012 from $38.8 million for the three months ended September 30, 2011. These results reflect the addition of the remaining 49.9% interest in East Texas and the Crossroads system acquisition, partially offset by lower commodity prices. 2011 results reflect planned turnaround activity and an extended planned third party outage at our Wyoming asset.

Adjusted segment EBITDA increased to $162.1 million for the nine months ended September 30, 2012 from $142.6 million for the nine months ended September 30, 2011, reflecting the addition of the remaining 49.9% interest in East Texas, the Crossroads system acquisition, and higher results in Southeast Texas, partially offset by lower commodity prices.

NGL Logistics — Adjusted segment EBITDA increased to $15.8 million for the three months ended September 30, 2012 from $9.4 million for the three months ended September 30, 2011, reflecting higher throughput on our pipelines and the July 2012 acquisition of the Mont Belvieu fractionators.

Adjusted segment EBITDA increased to $38.8 million for the nine months ended September 30, 2012 from $26.7 million for the nine months ended September 30, 2011, reflecting higher throughput on our pipelines as well as growth from the Wattenberg pipeline expansion project, the DJ Basin fractionators acquired in March 2011, and the July 2012 acquisition of the Mont Belvieu fractionators.

Wholesale Propane Logistics — Adjusted segment EBITDA decreased to $(0.1) million for the three months ended September 30, 2012 from $2.7 million for the three months ended September 30, 2011, reflecting reduced volumes and lower margins partially offset by a modest recovery in the non-cash LCM inventory adjustment recorded in the second quarter of 2012.

Adjusted segment EBITDA decreased to $(1.2) million for the nine months ended September 30, 2012 from $23.7 million for the nine months ended September 30, 2011, reflecting the non-cash LCM inventory adjustment recorded in the second quarter of 2012 and decreased volumes as a result of near record warm weather.

CORPORATE AND OTHER

Decreased depreciation and amortization expense for the three and nine months ended September 30, 2012, as compared to the three months and nine months ended September 30, 2011, reflect a change in the estimated useful lives of our assets. Additionally, interest expense for the three months ended September 30, 2012, is lower due to higher capitalized interest, partially offset by higher debt. For the nine months ended September 30, 2012 interest expense reflects higher debt, partially offset by higher capitalized interest.

CAPITALIZATION

At September 30, 2012, we had $1,038 million of total debt outstanding comprised of $598 million of senior notes, $300 million outstanding under our revolver and $140 million outstanding under the July 2012 term loan. Total unused revolver capacity was approximately $700 million. Our leverage ratio pursuant to our credit facility for the quarter ended September 30, 2012, was approximately 3.3 times. Our effective interest rate on our overall debt position, as of September 30, 2012, was 3.5 percent.

COMMODITY DERIVATIVE ACTIVITY

The objective of our commodity risk management program is to protect downside risk in our distributable cash flow. We utilize mark-to-market accounting treatment for our commodity derivative instruments. Mark-to-market accounting rules require companies to record currently in earnings the difference between their contracted future derivative settlement prices and the forward prices of the underlying commodities at the end of the accounting period. Revaluing our commodity derivative instruments based on futures pricing at the end of the period creates an asset or liability and associated non-cash gain or loss. Realized gains or losses from cash settlement of the derivative contracts occur monthly as our physical commodity sales are realized or when we rebalance our portfolio. Non-cash gains or losses associated with the mark-to-market accounting treatment of our commodity derivative instruments do not affect our distributable cash flow.

For the three months ended September 30, 2012, commodity derivative activity and total revenues included non-cash losses of $22.9 million. This compares to non-cash gains of $61.1 million for the three months ended September 30, 2011. The $3.0 million net hedge receipts for the three months ended September 30, 2012 did not include any amount for the Southeast Texas Storage business. The $6.5 million net hedge payments for the three months ended September 30, 2011 included receipts of $1.5 million for the Southeast Texas Storage business and $8.0 million of net payments for the balance of our commodity hedging program. For the nine months ended September 30, 2012, commodity derivative activity and total revenues included non-cash gains of $19.3 million. This compares to non-cash gains of $49.0 million for the nine months ended September 30, 2011. The $30.8 million net hedge receipts for the nine months ended September 30, 2012 were receipts of $29.6 million for commodity derivative activities related to the Southeast Texas Storage business and receipts of $1.2 million for the balance of our commodity hedging program. The $21.0 million net hedge payments for the nine months ended September 30, 2011 were receipts of $2.9 million for the Southeast Texas Storage business and $23.9 million of net payments primarily for the balance of our commodity hedging program. While our earnings will continue to fluctuate as a result of the volatility in the commodity markets, our commodity derivative contracts mitigate a portion of the risk of weakening commodity prices thereby stabilizing distributable cash flows.

EARNINGS CALL

DCP Midstream Partners will hold a conference call to discuss third quarter results on Wednesday, November 7, 2012 at 10:00 a.m. ET. The dial-in number for the call is 1-888-771-4371 in the United States or 1-847-585-4405 outside the United States. A live webcast of the call can be accessed on the Investor section of DCP Midstream Partners’ website at www.dcppartners.com. The call will be available for replay one hour after the end of the conference until 10:00 a.m. ET on November 14, 2012, by dialing 1-888-843-7419 in the United States or 1-630-652-3042 outside the United States. The replay conference number is 33575569. A replay, transcript and presentation slides in PDF format will also be available by accessing the Investor section of the partnership’s website.

NON-GAAP FINANCIAL INFORMATION

This press release and the accompanying financial schedules include the following non-GAAP financial measures: distributable cash flow, adjusted EBITDA, adjusted segment EBITDA, adjusted net income attributable to partners, and adjusted net income per unit. The accompanying schedules provide reconciliations of these non-GAAP financial measures to their most directly comparable GAAP financial measures. Our non-GAAP financial measures should not be considered in isolation or as an alternative to our financial measures presented in accordance with GAAP, including net income or loss attributable to partners, net cash provided by or used in operating activities or any other measure of liquidity or financial performance presented in accordance with GAAP as a measure of operating performance, liquidity or ability to service debt obligations and make cash distributions to unitholders. The non-GAAP financial measures presented by us may not be comparable to similarly titled measures of other companies because they may not calculate their measures in the same manner.

We define distributable cash flow as net cash provided by or used in operating activities, less maintenance capital expenditures, net of reimbursable projects, plus or minus adjustments for non-cash mark-to-market of derivative instruments, proceeds from divestiture of assets, net income attributable to non-controlling interests net of depreciation and income tax, net changes in operating assets and liabilities, and other adjustments to reconcile net cash provided by or used in operating activities. Historical distributable cash flow is calculated excluding the impact of retrospective adjustments related to any acquisitions presented under the pooling method. Maintenance capital expenditures are capital expenditures made where we add on to or improve capital assets owned, or acquire or construct new capital assets, if such expenditures are made to maintain, including over the long term, our operating or earnings capacity. Non-cash mark-to-market of derivative instruments is considered to be non-cash for the purpose of computing distributable cash flow because settlement will not occur until future periods, and will be impacted by future changes in commodity prices. Distributable cash flow is used as a supplemental liquidity and performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess our ability to make cash distributions to our unit holders and our general partner.

We define adjusted EBITDA as net income or loss attributable to partners less interest income, noncontrolling interest in depreciation and income tax expense and non-cash commodity derivative gains, plus interest expense, income tax expense, depreciation and amortization expense and non-cash commodity derivative losses. The commodity derivative non-cash losses and gains result from the marking to market of certain financial derivatives used by us for risk management purposes that we do not account for under the hedge method of accounting. These non-cash losses or gains may or may not be realized in future periods when the derivative contracts are settled, due to fluctuating commodity prices. We define adjusted segment EBITDA for each segment as segment net income or loss attributable to partners less non-cash commodity derivative gains for that segment, plus depreciation and amortization expense and non-cash commodity derivative losses for that segment, adjusted for any non-controlling interest on depreciation and amortization expense for that segment. Our adjusted EBITDA equals the sum of our adjusted segment EBITDAs, plus general and administrative expense.

Adjusted EBITDA is used as a supplemental liquidity and performance measure and adjusted segment EBITDA is used as supplemental performance measure by our management and we believe by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess:

  • financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
  • our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing methods or capital structure;
  • viability and performance of acquisitions and capital expenditure projects and the overall rates of return on investment opportunities; and
  • performance of our business excluding non-cash commodity derivative gains or losses;
  • in the case of Adjusted EBITDA, the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, make cash distributions to our unitholders and general partners, and finance maintenance capital expenditures.

We define adjusted net income attributable to partners as net income attributable to partners, plus non-cash derivative losses, less non-cash derivative gains. Adjusted net income per unit is then calculated from adjusted net income attributable to partners. These non-cash derivative losses and gains result from the marking to market of certain financial derivatives used by us for risk management purposes that we do not account for under the hedge method of accounting. Adjusted net income attributable to partners and adjusted net income per unit are provided to illustrate trends in income excluding these non-cash derivative losses or gains, which may or may not be realized in future periods when derivative contracts are settled, due to fluctuating commodity prices.

ABOUT DCP MIDSTREAM PARTNERS

DCP Midstream Partners, LP (NYSE: DPM) is a midstream master limited partnership engaged in the business of gathering, compressing, treating, processing, transporting, storing and selling natural gas; producing, fractionating, transporting, storing and selling NGLs and condensate; and transporting, storing and selling propane in wholesale markets. DCP Midstream Partners, LP is managed by its general partner, DCP Midstream GP, LLC, which is wholly owned by DCP Midstream, LLC, a joint venture between Spectra Energy and Phillips 66. For more information, visit the DCP Midstream Partners, LP website at www.dcppartners.com.

CAUTIONARY STATEMENTS

This press release may contain or incorporate by reference forward-looking statements as defined under the federal securities laws regarding DCP Midstream Partners, LP, including projections, estimates, forecasts, plans and objectives. Although management believes that expectations reflected in such forward-looking statements are reasonable, no assurance can be given that such expectations will prove to be correct. In addition, these statements are subject to certain risks, uncertainties and other assumptions that are difficult to predict and may be beyond our control. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from what management anticipated, estimated, projected or expected.

The key risk factors that may have a direct bearing on the Partnership’s results of operations and financial condition are described in detail in the Partnership’s periodic reports most recently filed with the Securities and Exchange Commission, including its most recent Form 10-K and most recent Form 10-Q. Investors are encouraged to closely consider the disclosures and risk factors contained in the Partnership’s annual and quarterly reports filed from time to time with the Securities and Exchange Commission. The Partnership undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Information contained in this press release is unaudited, and is subject to change.
       

DCP MIDSTREAM PARTNERS, LP

FINANCIAL RESULTS AND

SUMMARY BALANCE SHEET DATA

(Unaudited)
 
Three Months Ended Nine Months Ended
September 30, September 30,
  2012         2011      

AsReportedin 2011
      2012         2011      

AsReportedin 2011
(Millions, except per unit amounts)
Sales of natural gas, propane, NGLs and condensate $ 305.8     $ 496.1     $ 290.4 $ 1,089.4     $ 1,652.7     $ 1,043.2
Transportation, processing and other 45.0 42.8 40.8 130.7 122.2 114.9
(Loss) gain from commodity derivative activity, net   (19.9 )       54.7         52.1         50.1         28.2         24.5  
Total operating revenues 330.9 593.6 383.3 1,270.2 1,803.1 1,182.6
Purchases of natural gas, propane and NGLs (268.0 ) (449.0 ) (257.3 ) (973.4 ) (1,464.3 ) (906.6 )
Operating and maintenance expense (35.7 ) (36.7 ) (31.5 ) (91.7 ) (91.3 ) (77.3 )
Depreciation and amortization expense (14.8 ) (25.9 ) (20.6 ) (49.6 ) (74.9 ) (60.6 )
General and administrative expense (11.1 ) (12.0 ) (9.4 ) (34.0 ) (35.2 ) (27.0 )
Other income   0.1         0.2         0.2         0.4         0.4         0.4  
Total operating costs and expenses   (329.5 )       (523.4 )       (318.6 )       (1,148.3 )       (1,665.3 )       (1,071.1 )
Operating income 1.4 70.2 64.7 121.9 137.8 111.5
Interest expense (8.1 ) (8.6 ) (8.6 ) (31.8 ) (25.0 ) (25.0 )
Earnings from unconsolidated affiliates 8.9 6.9 10.0 16.6 17.1 28.6
Income tax expense (0.3 ) (0.4 ) (0.2 ) (1.0 ) (0.9 ) (0.4 )
Net (income) loss attributable to noncontrolling interests   (0.6 )       0.4         0.4         (2.0 )       (12.8 )       (12.8 )
Net income attributable to partners 1.3 68.5 66.3 103.7 116.2 101.9
Net income attributable to predecessor operations - (2.2 ) - (2.6 ) (14.3 ) -
General partner’s interest in net income   (10.8 )       (6.8 )       (6.8 )       (29.4 )       (18.5 )       (18.5 )
Net (loss) income allocable to limited partners $ (9.5 )     $ 59.5       $ 59.5       $ 71.7       $ 83.4       $ 83.4  
 
Net (loss) income per limited partner unit—basic $ (0.16 )     $ 1.35       $ 1.35       $ 1.37       $ 1.93       $ 1.93  
Net (loss) income per limited partner unit—diluted $ (0.16 )     $ 1.35       $ 1.35       $ 1.36       $ 1.93       $ 1.93  
 
Weighted-average limited partner units outstanding—basic   58.7         44.1         44.1         52.5         43.2         43.2  
Weighted-average limited partner units outstanding—diluted   58.7         44.2         44.2         52.6         43.2         43.2  
 
   

 
   

 
   

As ReportedDecember 31,2011
 

September 30,2012
   

December 31,2011
   
(Millions)
 
Cash and cash equivalents $ 8.4 $ 7.6 $ 6.7
Other current assets 262.2 346.1 233.2
Property, plant and equipment, net 1,673.8 1,499.4 1,181.8
Other long-term assets   573.0       424.3       481.9
Total assets $ 2,517.4     $ 2,277.4     $ 1,903.6
 
Current liabilities $ 295.7 $ 380.5 $ 269.2
Long-term debt 1,038.3 746.8 746.8
Other long-term liabilities 41.9 51.8 46.7
Partners’ equity 1,107.7 885.9 628.5
Noncontrolling interests   33.8       212.4       212.4
Total liabilities and equity $ 2,517.4     $ 2,277.4     $ 1,903.6
 
                       

DCP MIDSTREAM PARTNERS, LP

RECONCILIATION OF NON-GAAP FINANCIAL MEASURES

(Unaudited)
 
Three Months Ended Nine Months Ended
September 30, September 30,
  2012         2011      

AsReportedin 2011
      2012         2011      

AsReportedin 2011
(Millions, except per unit amounts)
Reconciliation of Non-GAAP Financial Measures:
Net income attributable to partners $ 1.3 $ 68.5 $ 66.3 $ 103.7 $ 116.2 $ 101.9
Interest expense 8.1 8.6 8.6 31.8 25.0 25.0
Depreciation, amortization and income tax expense, net of noncontrolling interests 14.8 22.9 17.4 49.5 65.6 50.8
Non-cash commodity derivative mark-to-market   22.9         (61.1 )       (60.0 )       (19.3 )       (49.0 )       (48.1 )
Adjusted EBITDA 47.1 38.9 32.3 165.7 157.8 129.6
Interest expense (8.1 ) (8.6 ) (8.6 ) (31.8 ) (25.0 ) (25.0 )
Depreciation, amortization and income tax expense, net of noncontrolling interests (14.8 ) (22.9 ) (17.4 ) (49.5 ) (65.6 ) (50.8 )
Other   (0.4 )       0.7         0.7         0.4         1.7         1.7  
Adjusted net income attributable to partners 23.8 $ 8.1   7.0 84.8 $ 68.9   55.5
Maintenance capital expenditures, net of reimbursable projects (3.6 ) (2.6 ) (11.2 ) (6.6 )
Distributions from unconsolidated affiliates, net of earnings (1.4 ) 2.3 (0.7 ) 7.7
Depreciation and amortization, net of noncontrolling interests 14.6 17.2 48.5 50.4
Proceeds from sale of assets, net of noncontrolling interests 0.1 2.3 0.2 2.5
Impact of minimum volume receipt for throughput commitment 1.8 1.4 5.3 3.5
Adjustment to remove impact of Southeast Texas pooling - - (17.3 ) -
Other   0.1     -     2.7     -  
Distributable cash flow(1) $ 35.4   $ 27.6   $ 112.3   $ 113.0  
 
Adjusted net income attributable to partners $ 23.8 $ 8.1 $ 7.0 $ 84.8 $ 68.9 $ 55.5
Adjusted net income attributable to predecessor operations - (1.1 ) - (2.6 ) (13.3 ) -
Adjusted general partner’s interest in net income   (10.9 )       (6.3 )       (6.3 )       (29.3 )       (18.0 )       (18.0 )
Adjusted net income allocable to limited partners $ 12.9       $ 0.7       $ 0.7       $ 52.9       $ 37.6       $ 37.5  
 
Adjusted net income per limited partner unit - basic and diluted $ 0.22       $ 0.02       $ 0.02       $ 1.01       $ 0.87       $ 0.87  
 
Net cash provided by operating activities $ 87.2 $ 74.7 $ 60.3 $ 158.8 $ 181.0 $ 148.9
Interest expense 8.1 8.6 8.6 31.8 25.0 25.0
Distributions from unconsolidated affiliates, net of earnings 1.4 (1.0 ) (2.3 ) 0.7 (2.7 ) (7.7 )
Net changes in operating assets and liabilities (71.0 ) 29.6 38.0 (2.7 ) 28.8 37.6
Net income or loss attributable to noncontrolling interests, net of depreciation and income tax (0.9 ) (3.0 ) (3.0 ) (3.1 ) (23.0 ) (23.0 )
Non-cash commodity derivative mark-to-market 22.9 (61.1 ) (60.0 ) (19.3 ) (49.0 ) (48.1 )
Other, net   (0.6 )       (8.9 )       (9.3 )       (0.5 )       (2.3 )       (3.1 )  
Adjusted EBITDA 47.1 $ 38.9   32.3 165.7 $ 157.8   129.6
Interest expense, net of derivative mark-to-market and other (8.1 ) (8.6 ) (31.8 ) (25.0 )
Maintenance capital expenditures, net of reimbursable projects (3.6 ) (2.6 ) (11.2 ) (6.6 )
Distributions from unconsolidated affiliates, net of earnings (1.4 ) 2.3 (0.7 ) 7.7
Proceeds from sale of assets, net of noncontrolling interest 0.1 2.3 0.2 2.5
Adjustment to remove impact of Southeast Texas pooling - - (17.3 ) -
Other   1.3     1.9     7.4     4.8  
Distributable cash flow(1) $ 35.4   $ 27.6   $ 112.3   $ 113.0  
 

(1)  Distributable cash flow has not been calculated under the pooling method.
               

DCP MIDSTREAM PARTNERS, LP

RECONCILIATION OF NON-GAAP FINANCIAL MEASURES

SEGMENT FINANCIAL RESULTS AND OPERATING DATA

 (Unaudited)
 
Three Months Ended Nine Months Ended
September 30, September 30,
2012    

AsReportedin 2011
    2012    

AsReportedin 2011
(Millions, except as indicated)
Reconciliation of Non-GAAP Financial Measures:
Distributable cash flow $ 35.4 $ 27.6 $ 112.3 $ 113.0
Distributions declared $ 52.6     $ 34.9     $ 144.6     $ 102.3
Distribution coverage ratio — declared 0.67x     0.79x     0.78x     1.10x
 
Distributable cash flow $ 35.4 $ 27.6 $ 112.3 $ 113.0
Distributions paid $ 49.4     $ 34.0     $ 128.7     $ 97.5
Distribution coverage ratio — paid 0.72x     0.81x     0.87x     1.16x
 
    Three Months Ended     Nine Months Ended
September 30, September 30,
  2012         2011      

AsReportedin 2011
      2012         2011      

AsReportedin 2011
(Millions, except per unit amounts)
Natural Gas Services Segment:                
Financial results:
Segment net income attributable to partners $ 9.5 $ 80.4 $ 75.4 $ 125.6 $ 135.8 $ 112.8
Non-cash commodity derivative mark-to-market 20.8 (61.0 ) (59.9 ) (5.4 ) (49.7 ) (48.8 )
Depreciation and amortization expense 12.5 22.8 17.5 43.0 66.7 52.4
Noncontrolling interests on depreciation and income tax   (0.3 )       (3.4 )       (3.4 )       (1.1 )       (10.2 )       (10.2 )
Adjusted segment EBITDA $ 42.5       $ 38.8       $ 29.6       $ 162.1       $ 142.6       $ 106.2  
 
Operating and financial data:
Natural gas throughput (MMcf/d) 1,659 1,367 1,164 1,648 1,429 1,220
NGL gross production (Bbls/d) 62,232 50,369 37,676 62,729 54,010 39,701
Operating and maintenance expense $ 26.9 $ 28.0 $ 22.8 $ 67.8 $ 69.0 $ 55.0
 
NGL Logistics Segment:
Financial results:
Segment net income attributable to partners $ 14.2 $ 7.0 $ 7.0 $ 34.2 $ 20.6 $ 20.6
Depreciation and amortization expense   1.6         2.4         2.4         4.6         6.1         6.1  
Adjusted segment EBITDA $ 15.8       $ 9.4       $ 9.4       $ 38.8       $ 26.7       $ 26.7  
 
Operating and financial data:
NGL pipelines throughput (Bbls/d) 69,863 68,564 68,564 75,115 57,802 57,802
Operating and maintenance expense $ 5.1 $ 5.5 $ 5.5 $ 12.8 $ 11.3 $ 11.3
 
Wholesale Propane Logistics Segment:
Financial results:
Segment net (loss) income attributable to partners $ (2.8 ) $ 2.1 $ 2.1 $ 10.8 $ 20.9 $ 20.9
Non-cash commodity derivative mark-to-market 2.1 (0.1 ) (0.1 ) (13.9 ) 0.7 0.7
Depreciation and amortization expense   0.6         0.7         0.7         1.9         2.1         2.1  
Adjusted segment EBITDA $ (0.1 )     $ 2.7       $ 2.7       $ (1.2 )     $ 23.7       $ 23.7  
 
Operating and financial data:
Propane sales volume (Bbls/d) 9,128 15,257 15,257 18,383 23,944 23,944
Operating and maintenance expense $ 3.7 $ 3.2 $ 3.2 $ 11.1 $ 11.0 $ 11.0
 
                   

DCP MIDSTREAM PARTNERS, LP

RECONCILIATION OF NON-GAAP FINANCIAL MEASURES

(Unaudited)
 
Q411     Q112     Q212     Q312    

TwelveMonths EndedSeptember30, 2012
(Millions)
 
Net income attributable to partners $ 4.7 $ 23.3 $ 79.1 $ 1.3 $ 108.4
Net income related to retrospective pooling of Southeast Texas   (6.2 )       -       -       -       (6.2 )
Net (loss) income attributable to partners as originally reported $ (1.5 )     $ 23.3     $ 79.1     $ 1.3     $ 102.2  
 
                   
Q411     Q112     Q212     Q312    

TwelveMonths EndedSeptember 30,2012
 
(Millions, except as indicated)
 
Net (loss) income attributable to partners $ (1.5 ) $ 23.3 $ 79.1 $ 1.3 $ 102.2
Maintenance capital expenditures, net of reimbursable projects (2.9 ) (3.3 ) (4.3 ) (3.6 ) (14.1 )
Depreciation and amortization expense, net of noncontrolling interests 17.0 24.8 9.1 14.6 65.5
Non-cash commodity derivative mark-to-market 25.4 22.6 (64.8 ) 22.9 6.1
Distributions from unconsolidated affiliates, net of earnings 1.6 (0.1 ) 0.8 (1.4 ) 0.9
Proceeds from sale of assets, net of noncontrolling interests 1.4 - 0.1 0.1 1.6
Impact of minimum volume receipt for throughput commitment (4.4 ) 1.6 1.9 1.8 0.9
Non-cash interest rate derivative mark-to-market 0.5 1.2 (0.4 ) (0.4 ) 0.9
Adjustment to remove impact of Southeast Texas pooling - (17.3 ) - - (17.3 )
Other   0.3         2.2         0.4         0.1         3.0  
Distributable cash flow $ 37.4       $ 55.0       $ 21.9       $ 35.4       $ 149.7  
Distributions declared $ 36.7       $ 42.6       $ 49.4       $ 52.6       $ 181.3  
Distribution coverage ratio — declared 1.02x 1.29x 0.44x 0.67x 0.83x
 
Distributable cash flow $ 37.4       $ 55.0       $ 21.9       $ 35.4       $ 149.7  
Distributions paid $ 34.9       $ 36.7       $ 42.6       $ 49.4       $ 163.6  
Distribution coverage ratio — paid 1.07x 1.50x 0.51x 0.72x 0.92x
 

Copyright Business Wire 2010

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