DCP Midstream Partners LP : DCP Midstream Partners Reports Strong Second Quarter 2013 Results

   DCP Midstream Partners LP : DCP Midstream Partners Reports Strong Second
                             Quarter 2013 Results

                                                    News Release
                                             www.dcppartners.com
               MEDIA AND INVESTOR RELATIONS CONTACT: Andrea Attel
August 6, 2013 Phone:                                303/605-1741
               24-Hour:                              720/235-6433

      DCP MIDSTREAM PARTNERS REPORTS STRONG SECOND QUARTER 2013 RESULTS

  *Second quarter 2013 Distributable Cash Flow up over 200 percent from
    second quarter 2012

  *Dropped down the LaSalle Plant in the DJ Basin and a one-third interest in
    the 435-mile Front Range Pipeline with a combined investment of over $400
    million

  *Quarterly distribution increase in line with 2013 distribution growth
    forecast

DENVER - DCP Midstream Partners, LP (NYSE: DPM), or the Partnership, today
reported financial results for the three and six months ended June 30, 2013.
The table below reflects the results for the three and six months ended June
30, 2013 and 2012 on a consolidated basis and for the 2012 periods as
originally reported.

SECOND QUARTER 2013 SUMMARY RESULTS

                            Three Months Ended           Six Months Ended
                                 June 30,                    June 30,
                                  2012      As      2013    2012        As
                          2013    ^(3)   Reported   ^(3)   ^(3)(4)   Reported
                                         in 2012                      in 2012
                                              (Unaudited)
                                  (Millions, except per unit amounts)
Net income                                                                
attributable to        $   102 $   85 $       79 $  154 $    119 $       102
partners^(1)(5)
Net income per limited                                                     
partner unit - basic   $  1.11 $ 1.33 $     1.33 $ 1.64 $   1.64 $     1.64
and diluted^(^1)(5)
Adjusted EBITDA^(2)    $   79 $   44 $       35 $  173 $    146 $      
                                                                           119
Adjusted net income                                                      
attributable to        $   44 $   20 $       14 $  106 $    78 $        61
partners^(2)
Adjusted net income
per limited partner    $  0.36 $ 0.08 $     0.08 $ 0.97 $   0.81 $      
unit^(2) - basic and                                                      0.81
diluted
Distributable cash     $   68 $  ** $       22 $  145 $     ** $        77
flow^(2)

(1)     Includes non-cash commodity derivative mark-to-market gains of $58
million and $65 million for the three months ended June 30, 2013 and 2012,
respectively. Includes non-cash commodity derivative mark-to-market gains of
$48 million and $42 million for the six months ended June 30, 2013 and 2012,
respectively.

(2)     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.

(3)     Includes our 80 percent interest in the Eagle Ford system,
retrospectively adjusted. We acquired a 33.33 percent interest in the Eagle
Ford system in November 2012, and a 46.67 percent interest in March 2013.
Transfers of net assets between entities under common control are accounted
for as if the transactions had occurred at the beginning of the period, and
prior years are retrospectively adjusted to furnish comparative information
similar to the pooling method. In addition, results are presented as
originally reported in 2012 for comparative purposes.

(4)    Includes our 100 percent interest in Southeast Texas,
retrospectively adjusted. We acquired a 33.33 percent interest in Southeast
Texas in January 2011, and a 66.67 percent interest in March 2012. Transfers
of net assets between entities under common control are accounted for as if
the transactions had occurred at the beginning of the period, and prior years
are retrospectively adjusted to furnish comparative information similar to the
pooling method. In addition, results are presented as originally reported in
2012 for comparative purposes.

(5)    The Partnership recognized $3 million of lower of cost or market
adjustments during the three and six months ended June 30, 2013, and $14
million and $19 million of lower of cost or market adjustments during the
three and six months ended June 30, 2012, respectively.

** Distributable cash flow has not been calculated under the pooling method.

DROPPED DOWN LASALLE PLANT AND FRONT RANGE PIPELINE

On August 5, 2013, the Partnership completed the dropdowns from DCP Midstream,
the owner of our general partner, of the LaSalle Plant and a one-third
interest in the Front Range Pipeline at a combined investment of over $400
million, including follow on capital. The transactions, which are subject to
certain purchase price adjustments, were financed at closing through
borrowings under the Partnership's revolving credit facility.

The LaSalle Plant is part of the DCP enterprise's ongoing program to expand
its gathering and processing presence in the prolific DJ Basin.

LaSalle Plant highlights include:

  *110 million cubic feet per day (MMcf/d) deep-cut cryogenic processing
    plant under construction with plans to expand to 160 MMcf/d in the first
    half of 2014

  *A 15-year fee-based processing agreement with DCP Midstream providing a
    fixed demand charge, along with a throughput fee on all volumes processed

This fee-based plant will become part of an eight-plant system with
approximately 600 MMcf/d of total processing capacity owned by the DCP
enterprise. These plants serve producers in the quickly growing Niobrara shale
play that is part of the DJ Basin. The LaSalle Plant is expected to be in
service in the second half of 2013. The total investment for the LaSalle Plant
is $242 million, of which $209 million was paid at closing with an estimated
$33 million for the cost to complete and expand the plant to 160 MMcf/d.

Front Range Pipeline highlights include:

  *One-third interest in Front Range Pipeline, an NGL pipeline with
    affiliates of Enterprise Products Partners L.P. and Anadarko Petroleum
    Corporation, each owning a one-third interest, which is operated by
    Enterprise 

  *Fee-based revenues backstopped by ship or pay arrangements with DCP
    Midstream and Anadarko 

  *435-mile, 16-inch diameter natural gas liquids (NGL) pipeline

  *150,000 barrels per day of NGL pipeline capacity, expandable to
    approximately 230,000 barrels per day 

The Front Range Pipeline will provide much needed takeaway capacity for the
expanding production of natural gas liquids in the DJ Basin, serving the
Niobrara shale play. The pipeline will originate in Weld County, Colorado, and
extend approximately 435 miles to Skellytown, Texas. With connections to the
Enterprise-operated Mid-America and Texas Express pipelines, the Front Range
Pipeline will provide producers in the DJ Basin with reliable takeaway
capacity and market access to the Gulf Coast, the largest NGL market in the
United States. The pipeline operator expects the Front Range Pipeline to be
mechanically complete in the fourth quarter of 2013. The total investment for
the one-third interest in Front Range Pipeline is $172 million, of which $86
million was paid at closing with an estimated $86 million for the cost to
complete construction.

SECOND QUARTER HIGHLIGHTS

  *We are on target to deliver on the key elements of our 2013 business plan

  *
       *Second quarter 2013 Distributable Cash Flow was up over 200 percent
         from second quarter 2012 

       *Financial results in line with 2013 Distributable Cash Flow forecast

       *Quarterly distribution increase in line with 2013 distribution growth
         forecast

  *With the dropdown of the additional 47 percent interest in the Eagle Ford
    system in the first quarter and the completion of the LaSalle Plant and
    Front Range Pipeline dropdowns, we have exceeded our $1 billion of
    targeted dropdowns in 2013 and are on track to deliver approximately $2.7
    billion of dropdowns and organic growth in 2013/2014.

In summary, our dropdown strategy with DCP Midstream, visible pipeline of
organic growth projects, as well as solid financial results, position us well
to achieve our 2013 forecast.

PRESIDENT'S PERSPECTIVE

"I couldn't be more pleased with our second quarter results," said Bill
Waldheim, president of the Partnership. "The year-to-date financial results
and distribution growth are in line with our 2013 forecast. With the
completion of the dropdowns of the fee-based LaSalle Plant and Front Range
Pipeline, we are expanding into another high growth area. This is the second
year in a row that we have exceeded our $1 billion of targeted dropdowns. Once
these assets are placed into service they will be accretive and are another
example of how we are partnering with our general partner to fund the growth
of the DCP enterprise."

CONSOLIDATED FINANCIAL RESULTS

Consolidated results are shown using the pooling method of accounting, which
includes results associated with DCP Midstream's ownership interests in the
Eagle Ford system and Southeast Texas during its periods of ownership. While
the Partnership hedges the majority of its commodity risk, prior period
results reflect DCP Midstream's unhedged portion of its ownership interest in
the Eagle Ford system and Southeast Texas during those periods.

Adjusted EBITDA for the three months ended June 30, 2013, increased to $79
million from $44 million for the three months ended June 30, 2012. Adjusted
EBITDA for the six months ended June 30, 2013, increased to $173 million from
$146 million for the six months ended June 30, 2012. These results reflect
increased volumes on our Eagle Ford system, the dropdown of the Mont Belvieu
fractionators and higher margins at the Marysville storage facility, partially
offset by hedge settlement timing on storage. Adjusted EBITDA for the three
and six months ended June 30, 2012, included a non-cash write down of $14
million and $15 million, respectively, to reflect propane inventory carrying
costs at the lower of cost or market price ("LCM Adjustment") for our
wholesale propane logistics segment.

On July 25, 2013, the Partnership announced a quarterly distribution of $0.71
per limited partner unit. This represents an increase of 1.4 percent over the
last quarterly distribution and an increase of 6 percent over the distribution
declared in the second quarter of 2012. Our distributable cash flow of $68
million for the three months ended June 30, 2013, provided a 1.0 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 1.1 times.

OPERATING RESULTS BY BUSINESS SEGMENT

Natural Gas Services - Adjusted segment EBITDA increased to $72 million for
the three months ended June 30, 2013, from $69 million for the three months
ended June 30, 2012, reflecting higher volumes at our Eagle Ford system and
the operation of our fee-based wholly-owned Eagle Plant, partially offset by
hedge settlement timing on storage.

Adjusted segment EBITDA decreased to $137 million for the six months ended
June 30, 2013, from $161 million for the six months ended June 30, 2012,
reflecting hedge settlement timing on storage, lower NGL prices, lower volumes
across certain of our assets and timing of operating expenses, partially
offset by higher volumes at our Eagle Ford system, the operation of our
fee-based wholly-owned Eagle Plant and higher unit margins attributable to our
natural gas storage and pipeline assets.

Results are shown using the pooling method of accounting, which includes the
additional 47 percent of the Eagle Ford system for the three months ended
March 31, 2013, and 80 percent of the Eagle Ford system for the six months
ended June 30, 2012. Results also include 67 percent of Southeast Texas for
the three months ended March 31, 2012. These results reflect the unhedged
portion of the Eagle Ford system and Southeast Texas associated with DCP
Midstream's ownership interest during those periods.

NGL Logistics - Adjusted segment EBITDA increased to $22 million for the three
months ended June 30, 2013, from $11 million for the three months ended June
30, 2012. Adjusted segment EBITDA increased to $45 million for the six months
ended June 30, 2013, from $23 million for the six months ended June 30, 2012.
These results reflect the July 2012 dropdown of the Mont Belvieu
fractionators, higher margins at the Marysville storage facility and higher
throughput on certain of our pipelines.

Wholesale Propane Logistics - Adjusted segment EBITDA increased to $1 million
for the three months ended June 30, 2013, from a loss of $19 million for the
three months ended June 30, 2012, reflecting increased unit margins and the
2012 LCM Adjustment of $14 million.

Adjusted segment EBITDA increased to $23 million for the six months ended June
30, 2013, from a loss of $1 million for the six months ended June 30, 2012.
The 2013 results reflect increased unit margins and the exporting of propane
from the Chesapeake terminal partially offset by a non-cash write off of a
discontinued construction project. 2012 results reflect the LCM Adjustment of
$15 million and reduced demand as a result of near record warm weather.

CORPORATE AND OTHER

The changes in depreciation and amortization expense for the three and six
months ended June 30, 2013, as compared to the three and six months ended June
30, 2012, reflect growth, as well as a change in the estimated useful lives of
our assets.

CAPITALIZATION

At June 30, 2013, the Partnership had $1,740 million of total debt outstanding
comprised of $1,590 million of senior notes and $150 million outstanding under
our revolver. Total unused revolver capacity was approximately $850 million.
Our leverage ratio pursuant to our credit facility for the quarter ended June
30, 2013, was approximately 3.7 times. Our effective interest rate on our
overall debt position, as of June 30, 2013, was 3.7 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 assets or liabilities and associated non-cash gains or losses.
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 June 30, 2013, commodity derivative activity and
total revenues included non-cash gains of $58 million. This compares to
non-cash gains of $65 million for the three months ended June 30, 2012. Net
hedge cash settlements for the three months ended June 30, 2013, were receipts
of $13 million. Net hedge cash settlements for the three months ended June 30,
2012, were receipts of $10 million.

For the six months ended June 30, 2013, commodity derivative activity and
total revenues included non-cash gains of $48 million. This compares to
non-cash gains of $42 million for the six months ended June 30, 2012. Net
hedge cash settlements for the six months ended June 30, 2013, were receipts
of $23 million. Net hedge cash settlements for the six months ended June 30,
2012, were receipts of $28 million. While our earnings will continue to
fluctuate as a result of the volatility in the commodity markets, our
commodity derivative contracts mitigate a substantial 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 second quarter
results on Wednesday, August 7, 2013, at 9:00 a.m. ET. The dial-in number for
the call is 1-800-446-1671 in the United States or 1-847-413-3362 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
conference confirmation number for login is 35272692. The call will be
available for replay one hour after the end of the conference until Midnight
ET on August 20, 2013, by dialing 1-888-843-7419 in the United States or
1-630-652-3042 outside the United States. The replay conference number is
35272692. 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 limited partner unit. The accompanying schedules
provide reconciliations of these non-GAAP financial measures to their most
directly comparable GAAP financial measures. The Partnership's non-GAAP
financial measures should not be considered in isolation or as an alternative
to its financial measures presented in accordance with GAAP, including
operating revenues, 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
noncontrolling 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, the
Partnership's 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 and
interest rates. Distributable cash flow is used as a supplemental liquidity
and performance measure by the Partnership's management and by external users
of its financial statements, such as investors, commercial banks, research
analysts and others, to assess the Partnership's ability to make cash
distributions to its unitholders and its 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
noncontrolling interest on depreciation and amortization expense for that
segment. The Partnership's adjusted EBITDA equals the sum of its 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 the
Partnership's management and by external users of its financial statements,
such as investors, commercial banks, research analysts and others to assess:

financial performance of the Partnership's assets without regard to financing
methods, capital structure or historical cost basis;

the Partnership's 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;

performance of the Partnership's business excluding non-cash commodity
derivative gains or losses; and

in the case of Adjusted EBITDA, the ability of the Partnership's assets to
generate cash sufficient to pay interest costs, support its indebtedness, make
cash distributions to its unitholders and general partner, 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 limited partner 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 limited partner 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, LP, which in
turn is managed by its general partner, DCP Midstream GP, LLC, or the General
Partner, which is wholly-owned by DCP Midstream, LLC, a joint venture between
Phillips 66 and Spectra Energy. 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 the Partnership's 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 annual and quarterly reports most recently filed with the
Securities and Exchange Commission and other such matters discussed in the
"Risk Factors" section of the Partnership's most recent Annual Report on Form
10-K and subsequent Quarterly Reports on Form 10-Q filed with the Securities
and Exchange Commission. 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 forward looking statements contained herein speak as of the
date of this announcement. 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             Six Months Ended
                              June 30,                      June 30,
                                         As                              As
                      2013    2012    Reported     2013      2012     Reported
                                       in 2012                        in 2012
                                (Millions, except per unit amounts)
Sales of natural                                                          
gas, propane, NGLs  $   643 $   543 $       297 $  1,311 $  1,333 $     784
and condensate 
Transportation,
processing and           61      50          42       124       102         85
other 
Gains from
commodity                71      75          75        71        70         70
derivative
activity, net
   Total operating      775     668         414     1,506     1,505        939
   revenues 
Purchases of
natural gas,          (573)   (490)      (274)   (1,159)   (1,186)     (706)
propane and NGLs 
Operating and
maintenance expense   (51)   (50)       (30)     (96)     (92)      (56)

Depreciation and
amortization          (23)   (15)       (10)     (43)     (49)      (34)
expense 
General and
administrative        (16)   (17)       (11)     (32)     (36)      (22)
expense 
                                                                 
Other expense           -      -        -       (4)      -        -
                                                                             
   Total operating
   costs and          (663)   (572)      (325)   (1,334)   (1,363)     (818)
   expenses 
Operating income       112      96          89       172       142        121
Interest expense     (14)   (11)       (11)     (26)     (24)      (24)
Earnings from
unconsolidated            8       2           2        16         8          8
affiliates 
Income tax expense      -      -              (1)      (1)       (1)
                                          - 
Net income
attributable to        (4)    (2)        (1)      (7)      (6)       (2)
noncontrolling
interests 
   Net income
   attributable to      102      85          79       154       119        102
   partners 
Net income
attributable to         -     (6)             (6)     (20)       (3)
predecessor                               - 
operations 
General partner's
interest in net       (16)   (10)       (10)     (31)     (18)      (18)
income 
Net income
allocable to        $    86 $    69 $        69 $     117 $      81 $       81
limited partners 
Net income per
limited partner     $  1.11 $  1.33 $      1.33 $    1.64 $    1.64 $     1.64
unit-basic and
diluted
Weighted-average
limited partner
units
outstanding-basic
and diluted            77.3    51.9        51.9      71.3      49.4       49.4

                                                                  As Reported
                                   June 30,     December 31,      December 31,
                                     2013           2012              2012
                                                   (Millions)
Cash and cash equivalents       $        9 $          $            1
                                                             2
Other current assets                   411                 366            308
Property, plant and equipment,        2,679               2,550          1,727
net 
Other long-term assets                  840                 685            936
Total assets                    $    3,939 $             3,603 $        2,972
Current liabilities             $      410 $               345 $          234
Long-term debt                       1,740               1,620          1,620
Other long-term liabilities             39                  44             35
Partners' equity                     1,533               1,405          1,048
Noncontrolling interests               217                 189             35
Total liabilities and equity    $    3,939 $             3,603 $        2,972

                          DCP MIDSTREAM PARTNERS, LP
                RECONCILIATION OF NON-GAAP FINANCIAL MEASURES
                                 (Unaudited)

                         Three Months Ended             Six Months Ended
                              June 30,                      June 30,
                                          As                            As
                      2013     2012    Reported     2013     2012    Reported
                                        in 2012                       in 2012
                                (Millions, except per unit amounts)
Reconciliation of
Non-GAAP Financial
Measures:
Net income
attributable to    $    102 $     85 $        79 $    154 $    119 $       102
partners
 Interest expense        14       11          11       26       24          24
 Depreciation,
 amortization and
 income tax
 expense, net of
 noncontrolling
 interests               21       13          10       41       45          35
 Non-cash
 commodity            (58)    (65)       (65)    (48)    (42)       (42)
 derivative
 mark-to-market
Adjusted EBITDA          79       44          35      173      146         119
 Interest expense     (14)    (11)       (11)    (26)    (24)       (24)
 Depreciation,
 amortization and
 income tax
 expense, net of
 noncontrolling
 interests            (21)    (13)       (10)    (41)    (45)       (35)
 Other                  -       -              -         1           1
                                           - 
Adjusted net
income                   44 $     20          14      106 $     78          61
attributable to
partners
 Maintenance
 capital
 expenditures, net
 of reimbursable
 projects              (3)                 (4)    (10)                 (8)
 Distributions
 from
 unconsolidated           3                    1        6                    1
 affiliates, net
 of earnings
 Depreciation and
 amortization, net       21                    9       40                   34
 of noncontrolling
 interests
 Impact of minimum
 volume receipt
 for throughput
 commitment               2                    2        4                    3
 Discontinued
 construction                                                       
 projects               -                 -         4                - 
 Adjustment to
 remove impact of                          
 pooling                -                 -      (6)                (17)
 Other                    1                        1                    3
                                           - 
Distributable cash $     68          $        22 $    145          $        77
flow^(1)
Adjusted net
income             $     44 $     20 $        14 $    106 $     78 $        61
attributable to
partners
 Adjusted net
 income                                    
 attributable to        -      (6)       -      (6)    (20)        (3)
 predecessor
 operations
 Adjusted general
 partner's            (16)    (10)       (10)    (31)    (18)       (18)
 interest in net
 income
Adjusted net
income allocable   $     28 $      4 $         4 $     69 $     40 $        40
to limited
partners
Adjusted net
income per limited $   0.36 $   0.08 $      0.08 $   0.97 $   0.81 $      0.81
partner unit -
basic and diluted
Net cash provided
by operating       $    123 $      3 $        11 $    270 $     47 $        72
activities
 Interest expense        14       11          11       26       24          24
 Distributions
 from
 unconsolidated        (3)      -         (1)     (6)      -         (1)
 affiliates, net
 of earnings
 Net changes in
 operating assets        11       99          80    (54)      127          68
 and liabilities
 Net income
 attributable to
 noncontrolling
 interests, net of
 depreciation and
 income tax            (6)     (4)        (1)    (10)    (10)        (2)
 Discontinued                                                       
 construction           -       -        -      (4)      -        - 
 projects
 Non-cash
 commodity            (58)    (65)       (65)    (48)    (42)       (42)
 derivative
 mark-to-market
 Other, net            (2)      -             (1)        -       
                                           -                          - 
Adjusted EBITDA    $     $     $      $     $     $     
                       79     44        35     173     146        119
 Interest expense,
 net of derivative    (14)                (11)    (26)                (20)
 mark-to-market
 and other
 Maintenance
 capital
 expenditures, net     (3)                 (4)    (10)                 (8)
 of reimbursable
 projects
 Distributions
 from
 unconsolidated           3                    1        6                    1
 affiliates, net
 of earnings
 Adjustment to                             
 remove impact of       -                 -      (6)                (17)
 pooling
 Discontinued                                                       
 construction           -                 -         4                - 
 projects
 Other                    3                    1        4                    2
Distributable cash $     68          $        22 $    145          $        77
flow^(1)

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        Six Months Ended
                                     June 30,                 June 30,
                               2013     As Reported     2013     As Reported
                                          in 2012                  in 2012
                                      (Millions, except as indicated)
Reconciliation of Non-GAAP
Financial Measures:
Distributable cash flow     $   68   $          22   $  145   $          77
Distributions declared      $   72   $          49   $  141   $          92
Distribution coverage ratio    0.94 x          0.44 x   1.03 x          0.84 x
- declared 
Distributable cash flow     $   68   $          22   $  145   $          77
Distributions paid          $   69   $          43   $  123   $          80
Distribution coverage ratio    0.99 x          0.51 x   1.18 x          0.97 x
- paid 

                        Three Months Ended              Six Months Ended
                             June 30,                       June 30,
                                          As                             As
                    2013      2012     Reported    2013      2012     Reported
                                       in 2012                        in 2012
                               (Millions, except per unit amounts)
Natural Gas
Services
Segment:
Financial
results:
Segment net
income           $     111 $     106 $       94 $     150 $     146 $      116
attributable to
partners
 Non-cash
 commodity           (58)     (49)      (49)     (49)     (26)      (26)
 derivative
 mark-to-market
 Depreciation
 and                    21        14          8        39        45         30
 amortization
 expense
 Noncontrolling
 interests on         (2)      (2)        -       (3)      (4)       (1)
 depreciation
 and income tax
Adjusted segment $      72 $      69 $       53 $     137 $     161 $      119
EBITDA
Operating and
financial data:
 Natural gas
 throughput          2,264     2,216      1,607     2,285     2,250      1,644
 (MMcf/d)
 NGL gross
 production        112,785   105,282     62,771   113,446   105,709     62,978
 (Bbls/d)
 Operating and
 maintenance     $      43 $      42 $       23 $      81 $      77 $       41
 expense
NGL Logistics
Segment:
Financial
results:
Segment net
income           $      20 $      10 $       10 $      42 $      20 $       20
attributable to
partners
 Depreciation
 and                     2         1          1               3          3
 amortization                                         3
 expense
Adjusted segment $      22 $      11 $       11 $      45 $      23 $       23
EBITDA
Operating and
financial data:
 NGL pipelines
 throughput         93,306    72,786     72,786    88,800    77,740     77,740
 (Bbls/d)
 Operating and
 maintenance     $       4 $       4 $        4 $       8 $       8 $        8
 expense
Wholesale
Propane
Logistics
Segment:
Financial
results:
Segment net
income (loss)    $       1 $    (3) $     (3) $      21 $      14 $       14
attributable to
partners
 Non-cash
 commodity             -      (16)      (16)         1     (16)      (16)
 derivative
 mark-to-market
 Depreciation
 and                   -        -         -          1         1          1
 amortization
 expense
Adjusted segment $       1 $   (19) $    (19) $      23 $    (1) $     (1)
EBITDA
Operating and
financial data:
 Propane sales      12,286    11,641     11,641    23,024    23,010     23,010
 volume (Bbls/d)
 Operating and
 maintenance     $       4 $       4 $        4 $       7 $       7 $        7
 expense

                          DCP MIDSTREAM PARTNERS, LP
                RECONCILIATION OF NON-GAAP FINANCIAL MEASURES
                                 (Unaudited)

                                                                     Twelve
                                                                  months ended
                                                                    June 30,
                           As          As                           2013 (As
                        Reported    Reported                       Originally
                         in Q312     in Q412    Q113    Q213     Reported)
                            (Millions, except as indicated)
Net income
attributable to       $         1 $        64 $     52 $    102 $          219
partners
 Maintenance capital
 expenditures, net of                                             
 reimbursable                                                  
 projects                   (4)       (6)     (7)     (3)          (20)
 Depreciation and
 amortization
 expense, net of
 noncontrolling             
 interests                   15          14       19       21             69
 Non-cash commodity
 derivative                    23        (2)       10    (58)          (27)
 mark-to-market 
 Distributions from
 unconsolidated
 affiliates, net of
 earnings                   (1)           1        3        3              6
 Impact of minimum
 volume receipt for             2        (6)        2        2            - 
 throughput commitment
 
 Discontinued                           
 construction                 -        -         4      -               4
 projects
 Adjustment to remove                   (6)      -            (6)
 impact of pooling          -        - 
 Other                       (1)           3      -         1              3
Distributable cash    $        35 $        68 $     77 $     68 $          248
flow 
Distributions         $        53 $        54 $     69 $     72 $          248
declared 
Distribution coverage       0.67x       1.25x    1.12x    0.94x          1.00x
ratio - declared
Distributable cash    $        35 $        68 $     77 $     68 $          248
flow 
Distributions paid   $        49 $        53 $     54 $     69 $          225
Distribution coverage       0.72x       1.29x    1.43x    0.99x          1.10x
ratio - paid 

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