BreitBurn Energy Partners L.P. Reports Fourth Quarter Results and Record Full Year Production and EBITDA; Provides Full Year

  BreitBurn Energy Partners L.P. Reports Fourth Quarter Results and Record
  Full Year Production and EBITDA; Provides Full Year 2014 Guidance

Business Wire

LOS ANGELES -- February 27, 2014

BreitBurn Energy Partners L.P. (the “Partnership”) (NASDAQ:BBEP) today
announced financial and operating results for the fourth quarter and full year
of 2013 as well as public guidance for its expected performance in 2014,
excluding any future acquisitions.

Key Highlights:

  *For the fourth quarter of 2013, net production increased 40% and Adjusted
    EBITDA, a non-GAAP measure, increased 50% from the fourth quarter of 2012.
    For the full year 2013, net production and Adjusted EBITDA increased 32%
    and 34%, respectively, from 2012.
  *Oil and natural gas liquid (NGL) production increased to a record
    quarterly high of 1.9 MMBoe, a 90% increase from the fourth quarter of
    2012.
  *Annualized monthly distributions of $1.97 per unit as paid on February 14,
    2014, attributable to the fourth quarter of 2013, represent a 4.8%
    increase over the annualized quarterly distribution of $1.88 per unit for
    the fourth quarter of 2012.
  *For the fourth quarter of 2013, the Partnership drilled 27 gross (25.7
    net) wells and completed 9 gross (6.4 net) workovers.
  *On December 30, 2013 the Partnership completed acquisitions of oil and gas
    properties in the Permian Basin for approximately $302 million.
  *For the fourth quarter of 2013, increased distributable cash flow, a
    non-GAAP financial measure, to $55.4 million which represented a 43%
    increase from the fourth quarter of 2012.

Management Commentary

Halbert Washburn, CEO, said: “The Partnership had a very active 2013,
completing approximately $1.2 billion in acquisitions, doubling our organic
development expenditures, expanding our presence into the mid-continent, and
significantly increasing our liquids reserves and production. Although we had
a variety of challenges during the fourth quarter, we grew the business
significantly in 2013 and are pleased to report record annual production and
Adjusted EBITDA. 2013 also marked BreitBurn’s 25-year anniversary. We have a
long history of operating effectively and successfully pursuing our
growth-through-acquisitions strategy. Looking forward to 2014, our large
portfolio of high quality assets, a robust capital program, and ample
financial flexibility should serve as a strong foundation for continued
growth. We are very optimistic about our prospects for 2014 and are targeting
at least $600 million in new acquisitions during the year.”

Fourth Quarter 2013 Operating and Financial Results Compared to Third Quarter
2013

  *Total production was 3,086 MBoe in the fourth quarter of 2013 compared to
    3,098 MBoe in the third quarter of 2013. Average daily production was 33.5
    MBoe/day in the fourth quarter of 2013 compared to 33.7 MBoe/day in the
    third quarter of 2013.

       *Oil production was 1,704 MBbl compared to 1,681 MBbl in the third
         quarter of 2013.
       *NGL production was 205 MBbl compared to 207 MBbl in the third quarter
         of 2013.
       *Natural gas production was 7,060 MMcf compared to 7,258 MMcf in the
         third quarter of 2013.

  *Adjusted EBITDA was $109.4 million in the fourth quarter of 2013 compared
    to $112.1 million in the third quarter of 2013.
  *Net loss attributable to the Partnership, including the effect of
    derivative instruments, was $58.8 million, or $0.52 per diluted common
    unit, in the fourth quarter of 2013, compared to a net loss of $25.0
    million, or $0.25 per diluted common unit, in the third quarter of 2013.
  *Oil, NGL and natural gas sales revenues were $193.6 million in the fourth
    quarter of 2013, down from $197.4 million in the third quarter of 2013,
    primarily reflecting lower oil realized prices and lower natural gas sales
    volumes, partially offset by higher oil sales volumes and slightly higher
    natural gas and NGL realized prices.
  *Lease operating expenses, which include district expenses, processing fees
    and transportation costs, were $20.56 per Boe in the fourth quarter of
    2013 compared to $18.96 per Boe in the third quarter of 2013.
  *General and administrative expenses, excluding non-cash unit-based
    compensation, were $2.83 per Boe in the fourth quarter of 2013 compared to
    $3.62 per Boe in the third quarter of 2013.
  *Losses on commodity derivative instruments were $17.2 million in the
    fourth quarter of 2013 compared to losses of $54.8 million in the third
    quarter of 2013, which primarily reflected a decrease in oil futures
    prices during the fourth quarter of 2013. Derivative instrument settlement
    receipts were $4.5 million in the fourth quarter of 2013 compared to
    settlement payments of $6.3 million in the third quarter of 2013.
  *WTI oil spot prices averaged $97.44 per barrel and Brent oil spot prices
    averaged $109.22 per barrel in the fourth quarter of 2013 compared to
    $105.83 per barrel and $110.23 per barrel, respectively, in the third
    quarter of 2013. Henry Hub natural gas spot prices averaged $3.85 per Mcf
    in the fourth quarter of 2013 compared to $3.55 per Mcf in the third
    quarter of 2013.
  *Realized oil, NGL and natural gas prices excluding the effects of
    commodity derivative settlements, averaged $88.77 per Boe, $42.17 per Boe
    and $3.75 per Mcf, respectively, in the fourth quarter of 2013, compared
    to $100.94 per Boe, $38.11 per Boe, and $3.69 per Mcf, respectively, in
    the third quarter of 2013.
  *Oil and gas capital expenditures totaled $96 million in the fourth quarter
    of 2013 compared to $87 million in the third quarter of 2013.
  *Distributable cash flow, a non-GAAP financial measure, was $55.4 million
    in the fourth quarter of 2013 compared to $64.6 million in the third
    quarter of 2013. Distributable cash flow per common unit was $0.46 in the
    fourth quarter of 2013 compared to $0.64 in the third quarter of 2013.

Full Year 2013 Results

  *The Partnership completed approximately $1.2 billion in total
    acquisitions.
  *Total production was 10,983 MBoe in 2013, an increase of 32% from 2012 and
    a record high for the Partnership.
  *Adjusted EBITDA was $370.4 million, an increase of 34% from 2012 and a
    record high for the Partnership.
  *Net loss attributable to the Partnership was $43.7 million, or $0.43 per
    diluted common unit, in 2013 compared to net loss of $40.8 million, or
    $0.56 per diluted common unit, in 2012.
  *Total oil, NGL and natural gas sales were $660.7 million in 2013, an
    increase of 60% from 2012.
  *For the full year 2013, the Partnership drilled 138 gross (121.6 net)
    wells and completed 61 gross (54.8 net) workovers.
  *Full year lease operating expenses per Boe were $19.69, which was 3%
    higher than 2012.
  *Full year general and administrative expenses, excluding unit-based
    compensation, were $3.53 per Boe, which was 12% lower than 2012.
  *Realized oil and NGL prices, excluding the effect of commodity derivative
    instruments, for 2013 were $88.75 per barrel and $35.25, respectively
    compared to NYMEX WTI oil prices of $97.97 per barrel. Average realized
    natural gas prices, excluding the effect of commodity derivative
    instruments, were $3.82 per Mcf, compared to Henry Hub prices of $3.73 per
    Mcf.
  *Oil and gas capital expenditures were $295 million, an increase of 93%
    from 2012.
  *Distributable cash flow, a non-GAAP financial measure, was $200.3 million
    in 2013 compared to $153.0 million in 2012.

2013 Estimated Proved Reserves

Total estimated proved reserves as of December 31, 2013 were 214.3 MMBoe. The
standardized measure of discounted future net cash flows related to our
estimated proved reserves was approximately $3.2 billion. Of the total
estimated proved reserves, 53% were oil, 7% were NGLs and 40% were natural
gas; 81% were classified as proved developed; and 27% were located in
Michigan, 20% in Oklahoma, 19% in Texas, 17% in Wyoming, 11% in California and
5% in Florida, with less than 1% in Indiana and Kentucky. As of December31,
2012, our total estimated proved reserves were 149.4 MMBoe. The unweighted
average first-day-of-the-month oil and natural gas prices used to determine
our total estimated proved reserves as of December31, 2013 were $96.94 Bbl of
oil for WTI NYMEX, $108.32 per Bbl of oil for ICE Brent and $3.67 per MMBtu of
natural gas for Henry Hub.

2014 Guidance (Assuming no future acquisitions)

The following guidance is subject to all of the cautionary statements and
limitations described below and under the caption "Cautionary Statement
Regarding Forward-Looking Information." In addition, estimates for the
Partnership's future production volumes are based on, among other things,
assumptions of capital expenditure levels and the assumption that market
demand and prices for oil, NGLs and gas will continue at levels that allow for
economic production of these products. The production, transportation and
marketing of oil, natural gas liquids and gas are extremely complex and are
subject to disruption due to transportation and processing availability,
mechanical failure, human error, weather and numerous other factors. The
Partnership's estimates are based on certain other assumptions, such as well
performance, which may actually prove to vary significantly from those
assumed. Operating costs, which include major maintenance costs, vary in
response to changes in prices of services and materials used in the operation
of our properties and the amount of maintenance activity required. Operating
costs, including taxes, utilities and service company costs, move
directionally with increases and decreases in commodity prices, and we cannot
fully predict such future commodity or operating costs. Similarly, interest
rates and price differentials are set by the market and are not within our
control. They can vary dramatically from time to time. Capital expenditures
are based on our current expectations as to the level of capital expenditures
that will be justified based upon the other assumptions set forth below as
well as expectations about other operating and economic factors not set forth
below. The guidance below does not constitute any form of guarantee, assurance
or promise that the matters indicated will actually be achieved. Rather, the
table simply sets forth our best estimate today for these matters based upon
our current expectations about the future based upon both stated and unstated
assumptions. Actual conditions and those assumptions may, and probably will,
change over the course of the year.

($ in 000s)                           FY 2014 Guidance
Total Production (MBoe):                13,600       -          14,400
Oil Production (MBbls)                     7,900         -           8,400
NGL Production (MBbls)                     1,125         -           1,225
Gas Production (MMcfe)                     27,500        -           28,600
December 2014 Exit Rate (Boe/d)            38,400        -           40,800
Average Price Differential %:
WTI Oil Price Differential %               88.0    %     -           96.0    %
Brent Oil Price Differential %^(1)         92.0    %     -           96.0    %
NGL Price Differential % (of WTI)          37.5    %     -           42.5    %
Gas Price Differential %                   100.0   %     -           103.0   %
Other Revenue^(2)                        $ 3,500         -         $ 4,500
Operating Costs / Boe^(3)(4)             $ 18.50         -         $ 20.50
Production / Property Taxes (% of          6.50    %     -           7.00    %
oil & natural gas revenue)
G&A (Excl. Unit Based                    $ 51,000        -         $ 53,000
Compensation)
Cash Interest Expense^(5)                $ 117,000       -         $ 120,000
Adjusted EBITDA^(6)                      $ 500,000       -         $ 510,000
Capital Expenditures^(7):
Maintenance Capital                                   $ 125,000
Growth Capital                        $ 200,000    -        $ 220,000 

(1)    Approximately 24% of oil production is expected to be sold based on
          Brent pricing.
(2)       Primarily comprised of pipeline revenues and equity earnings in
          affiliate.
          Operating Costs include lease operating costs, processing fees,
          district expense, and transportation expense. Expected
(3)       transportation expense totals approximately $6.0 million in 2014,
          largely attributable to our Florida production. Excluding
          transportation expense, our estimated operating costs range per Boe
          is approximately $18.00 - $20.00.
          Operating Costs are based on flat $95 per barrel WTI oil, $105 per
(4)       barrel Brent oil, and $4.00 per Mcfe natural gas price levels for
          2014. Operating costs generally move with commodity prices but do
          not typically increase or decrease as rapidly as commodity prices.
          The Partnership typically borrows on a 1-month LIBOR basis, plus an
(5)       applicable spread. Estimated cash interest expense assumes a 1-month
          LIBOR rate of 0.25%.
          Assuming the high and low range of our guidance, Adjusted EBITDA is
          expected to range between $500 million and $510 million, and is
          comprised of estimated net income (before non-cash compensation)
          between $131 million and $144 million, plus losses on commodity
          derivative instruments of $22 million, less net payments for
          derivative contracts settled during the period of $28 million, plus
          DD&A of $255 million, plus interest expense between $117 million
(6)       (high end of Adjusted EBITDA) and $120 million (low end of Adjusted
          EBITDA). Estimated 2014 net income is based on oil prices of $95 per
          barrel for WTI oil, $105 per barrel for Brent oil and $4.00 per Mcfe
          for natural gas. Consequently, differences between actual and
          forecast prices could result in changes to gains or losses on mark
          to market of commodity derivative instruments, DD&A, including
          potential impairments of long-lived assets, and ultimately, net
          income.
          Total Capital Expenditures for 2014 excludes capital expense for
          acquisitions as well as information technology spending. Maintenance
(7)       capital is defined as the estimated amount of investment in capital
          projects and obligatory spending on existing facilities and
          operations needed to hold production approximately constant for the
          period.

Impact of Derivative Instruments

The Partnership uses commodity derivative instruments to mitigate the risks
associated with commodity price volatility and to help maintain cash flows for
operating activities, acquisitions, capital expenditures and distributions.
The Partnership does not enter into derivative instruments for speculative
trading purposes. Because the Partnership does not use hedge accounting to
account for its derivative instruments, changes in the fair value of
derivative instruments are recorded in earnings each reporting period. These
non-cash changes in the fair value of derivatives do not affect Adjusted
EBITDA, cash flow from operations, distributable cash flow or the
Partnership’s ability to pay cash distributions for the reporting periods
presented.

Total losses from commodity derivative instruments were approximately $17.2
million for the fourth quarter of 2013, which include $4.5 million net
receipts for contracts that settled during the period.

Production, Statement of Operations, and Realized Price Information

The following table presents production, selected income statement and
realized price information for the three months ended December 31, 2013 and
2012, the three months ended September 30, 2013 and the full year results for
2013 and 2012:

                Three Months Ended                       Year Ended December 31,
                 December     September    December                  
                 31,           30,           31,
Thousands of
dollars,         2013          2013          2012          2013          2012
except as
indicated
Oil sales        $ 158,456     $ 162,709     $ 85,639      $ 530,625     $ 326,130
NGL sales          8,644         7,888         845           22,558        3,858
Natural gas        26,504        26,816        26,695        107,482       83,879
sales
(Loss) gain on
commodity          (17,234 )     (54,765 )     3,715         (29,182 )     5,580
derivative
instruments
Other             978         737         700         3,175       3,548   
revenues, net
Total revenues   $ 177,348    $ 143,385    $ 117,594    $ 634,658    $ 422,995 
Lease
operating
expenses and     $ 63,439      $ 58,731      $ 41,769      $ 216,275     $ 159,289
processing
fees (a)
Production and
property taxes    11,295      14,476      10,962      46,220      33,634  
(b)
Total lease
operating        $ 74,734     $ 73,207     $ 52,731     $ 262,495    $ 192,923 
expenses
Purchases and
other              440           226           267           1,321         1,577
operating
costs
Change in         5,758       (4,931  )    578         (995    )    1,279   
inventory
Total
operating        $ 80,932     $ 68,502     $ 53,576     $ 262,821    $ 195,779 
costs
Lease
operating
expenses, pre    $ 20.56       $ 18.96       $ 18.88       $ 19.69       $ 19.15
taxes, per Boe
(a)
Production and
property taxes     3.66          4.67          4.96          4.21          4.04
per Boe (b)
Total lease
operating         24.22       23.63       23.84       23.90       23.19   
expenses per
Boe
General and
administrative
expenses         $ 8,742      $ 11,227     $ 9,815      $ 38,752     $ 33,281  
(excluding
unit-based
compensation)
Net loss
attributable     $ (58,792 )   $ (25,011 )   $ (10,334 )   $ (43,671 )   $ (40,801 )
to the
partnership
                                                                         
Total
production         3,086         3,098         2,212         10,983        8,318
(MBoe) (c)
Oil (MBbl)         1,704         1,681         972           5,651         3,652
NGL (MBbl)         205           207           33            640           138
Natural gas        7,060         7,258         7,243         28,156        27,997
(MMcf)
Average daily
production        33,542      33,674      24,044      30,091      22,726  
(Boe/d)
Sales volumes     3,163       3,027       2,203       10,988      8,334   
(MBoe) (d)
Average
realized sales   $ 61.10       $ 65.16       $ 51.29       $ 51.29       $ 49.57
price (per
Boe) (e) (f)
Oil (per Bbl)      88.77         100.94        88.75         88.75         92.18
(e) (f)
NGLs (per Bbl)     42.17         38.11         25.61         35.25         27.96
(e)
Natural gas       3.75        3.69        3.69        3.82        3.00    
(per Mcf) (e)

(a) Includes lease operating expenses, district expenses, transportation expenses
and processing fees.
(b) Includes ad valorem and severance taxes.
(c) Natural gas is converted on the basis of six Mcf of gas per one Bbl of oil
equivalent. This ratio reflects an energy content equivalency and not a price or
revenue equivalency. Given commodity price disparities, the price for a Bbl of oil
equivalent for natural gas is significantly less than the price for a Bbl of oil.
(d) Oil sales were 1,782 (MBbl), 1,610 (MBbl), 963 (MBbl), 5,563 (MBbl) and 3,530
(MBbl) for the three months ended December 31, 2013 September 30, 2013 and December
31, 2012 and for the twelve months ended December 31, 2013 and 2012, respectively.
(e) Excludes the effect of commodity derivative settlements.
(f) Includes oil purchases.

Non-GAAP Financial Measures

This press release, the financial tables and other supplemental information,
including the reconciliations of certain non-generally accepted accounting
principles (“non-GAAP”) measures to their nearest comparable generally
accepted accounting principles (“GAAP”) measures, may be used periodically by
management when discussing the Partnership's financial results with investors
and analysts, and they are also available on the Partnership's website under
the Investor Relations tab.

Among the non-GAAP financial measures used are “Adjusted EBITDA” and
“distributable cash flow.” These non-GAAP financial measures should not be
considered as alternatives to GAAP measures, such as net income, operating
income, cash flow from operating activities or any other GAAP measure of
liquidity or financial performance. Management believesthat these non-GAAP
financial measures enhance comparability to prior periods.

Adjusted EBITDA is presented as management believes it provides additional
information relative to the performance of the Partnership's business, such as
our ability to meet our debt covenant compliance tests. Distributable cash
flow is used by management as a tool to measure the cash distributions we
could pay to our unitholders. This financial measure indicates to investors
whether or not we are generating cash flow at a level that can support our
distribution rate to our unitholders. These non-GAAP financial measures may
not be comparable to similarly titled measures of other publicly traded
partnerships or limited liability companies because all companies may not
calculate Adjusted EBITDA or distributable cash flow in the same manner.

Adjusted EBITDA

The following table presents a reconciliation of net income and net cash flows
from operating activities, our most directly comparable GAAP financial
performance and liquidity measures, to Adjusted EBITDA for each of the periods
indicated.


                   Three Months Ended                       Year Ended December 31,
                      December     September    December                   
                      31,           30,           31,
Thousands of          2013          2013          2012 (a)      2013           2012 (a)
dollars
Reconciliation
of net loss to
Adjusted
EBITDA:
Net loss
attributable to       $ (58,792 )   $ (25,011 )   $ (10,334 )     ($43,671 )     (40,801 )
the Partnership
                                                                               
Loss (gain) on
commodity               17,234        54,765        (3,715  )     29,182         (5,580  )
derivative
instruments
Commodity
derivative
instrument              4,450         (6,323  )     22,455        8,083          87,605
settlements (b)
(c)
Depletion,
depreciation
and                     62,400        59,764        40,350        216,495        137,252
amortization
expense
Impairments             54,012        361           147           54,373         12,313
Interest
expense and             26,680        23,548        17,975        87,067         61,206
other financing
costs
Loss on
interest rate           -             -             175           -              1,101
swaps (d)
Loss on sale of         (2,154  )     77            264           (2,015   )     486
assets
Income tax
expense                 277           24            285           905            84
(benefit)
Unit-based
compensation           5,270       4,889       5,329       19,955       22,184  
expense (e)
Adjusted EBITDA       $ 109,377     $ 112,094     $ 72,931      $ 370,374      $ 275,850
                                                                               
Less:
                                                                               
Maintenance           $ 29,217      $ 25,782      $ 16,774      $ 89,267       $ 63,446
capital (f)
Cash interest          24,741      21,748      17,421      80,767       59,382  
expense (g)
Distributable
cash flow
available to          $ 55,419     $ 64,564     $ 38,736     $ 200,340     $ 153,022 
common
unitholders
                                                                               
Distributable
cash flow             $ 0.46        $ 0.64        $ 0.45        $ 1.88         $ 1.95
available per
common unit (h)
Common unit
distribution          0.93x         1.31x         0.95x         0.97x          1.06x
coverage
                                                                               
Reconciliation
of net cash
flows from
operating
activities to
Adjusted
EBITDA:
                                                                               
Net cash
provided by           $ 90,224      $ 69,520      $ 25,506      $ 257,166        191,782
operating
activities
                                                                               
Increase in
assets net of
liabilities             (5,680  )     20,663        27,655        32,105         22,492
relating to
operating
activities
Interest                24,654        21,721        19,885        80,617         61,807
expense (d) (i)
Income from
equity                  (67     )     121           (131    )     (55      )     (487    )
affiliates, net
Incentive
compensation            (21     )     -             (82     )     (21      )     (82     )
expense (f)
Income taxes            267           69            98            562            400
Non-controlling         -             -             -             -              (62     )
interest
                                                                          
Adjusted EBITDA       $ 109,377    $ 112,094    $ 72,931     $ 370,374     $ 275,850 
                                                                               
(a) Adjusted EBITDA for the three and twelve months ended December 31, 2012 was conformed
to exclude $5.1 million and $19.9 million related to "Net operating cash flow from
acquisitions, effective date through closing date."
(b) Excludes
premiums paid
at contract
inception
related to            $ 1,233       $ 1,233       $ 517         $ 4,893        $ 859
those
derivative
contracts that
settled during
the periods of:
(c) Includes
net cash
settlements on
derivative
instruments:
- Oil
settlements           $ (7,378  )   $ (17,905 )   $ 4,701       $ (36,183  )   $ 3,855
received (paid)
of:
- Natural gas
settlements           $ 11,828      $ 11,583      $ 17,754      $ 44,266       $ 83,750
received of:
(d) Includes
settlements
paid on               $ -           $ -           $ 3,196       $ -            $ 5,469
interest rate
derivatives of:
(e) Represents non-cash long-term unit-based incentive compensation expense.
(f) Maintenance Capital is management's estimate of the investment in capital projects and
obligatory spending on existing facilities and operations needed to hold production
approximately constant for the period.
(g) Excludes $2.5 million loss on termination of interest rate swaps for the three and
twelve months ended December 31, 2012.
(h) Reflects common units outstanding (including outstanding LTIP grants) at each
distribution record date.
(i) Excludes amortization of debt issuance costs and amortization of senior note
discount/premium.


Hedge Portfolio Summary

The table below summarizes the Partnership’s commodity derivative hedge
portfolio as of February 26, 2014. Please refer to the updated Commodity Price
Protection Portfolio via our website for additional details related to our
hedge portfolio.

                
                     Year
                     2014         2015         2016      2017      2018
Oil
Positions:
Fixed Price
Swaps -
NYMEX WTI
Volume                  13,814        12,689       9,211      7,971      493
(Bbls/d)
Average
Price                $  92.30      $  93.01      $ 86.73    $ 84.23    $ 82.20
($/Bbl)
Fixed Price
Swaps - ICE
Brent
Volume                  4,800         3,300        4,300      298        -
(Bbls/d)
Average
Price                $  98.88      $  97.73      $ 95.17    $ 97.50    $ -
($/Bbl)
Collars -
NYMEX WTI
Volume                  1,000         1,000        -          -          -
(Bbls/d)
Average
Floor Price          $  90.00      $  90.00      $ -        $ -        $ -
($/Bbl)
Average
Ceiling              $  112.00     $  113.50     $ -        $ -        $ -
Price
($/Bbl)
Collars -
ICE Brent
Volume                  -             500          500        -          -
(Bbls/d)
Average
Floor Price          $  -          $  90.00      $ 90.00    $ -        $ -
($/Bbl)
Average
Ceiling              $  -          $  109.50     $ 101.25   $ -        $ -
Price
($/Bbl)
Puts -
NYMEX WTI
Volume                  500           500          1,000      -          -
(Bbls/d)
Average
Price                $  90.00      $  90.00      $ 90.00    $ -        $ -
($/Bbl)
Total:
Volume                  20,114        17,989       15,011     8,269      493
(Bbls/d)
Average
Price                $  93.70      $  93.54      $ 89.48    $ 84.71    $ 82.20
($/Bbl)
                                                                       
Gas
Positions:
Fixed Price
Swaps -
MichCon
City-Gate
Volume                  7,500         7,500        17,000     10,000     -
(MMBtu/d)
Average
Price                $  6.00       $  6.00       $ 4.46     $ 4.48     $ -
($/MMBtu)
Fixed Price
Swaps -
Henry Hub
Volume                  41,600        47,700       24,700     8,571      1,870
(MMBtu/d)
Average
Price                $  4.75       $  4.77       $ 4.23     $ 4.39     $ 4.15
($/MMBtu)
Puts -
Henry Hub
Volume                  6,000         1,500        -          -          -
(MMBtu/d)
Average
Price                $  5.00       $  5.00       $ -        $ -        $ -
($/MMBtu)
Total:
Volume                  55,100        56,700       41,700     18,571     1,870
(MMBtu/d)
Average
Price                $  4.95       $  4.94       $ 4.32     $ 4.44     $ 4.15
($/MMBtu)
                                                                       
Calls -
Henry Hub
Volume                  15,000        -            -          -          -
(MMBtu/d)
Average
Price                $  9.00       $  -          $ -        $ -        $ -
($/MMBtu)
Deferred
Premium              $  0.12       $  -          $ -        $ -        $ -
($/MMBtu)
                                                                       
Premiums paid in 2012 related to oil and natural gas derivatives to be settled
in 2014 and beyond are as follows:

                     Year
Thousands            2014          2015          2016       2017       2018
of dollars
Oil                  $  4,479      $  4,683      $ 7,438    $ 734      $ -
Natural gas          $  4,015      $  1,989      $ 952      $ -        $ -
                                                                         

Other Information

The Partnership will host an investor conference call to discuss its results
today at 9:00 a.m. (Pacific Time). Investors may access the conference call
over the Internet via the Investor Relations tab of the Partnership's website
(www.breitburn.com), or via telephone by dialing 888-437-9445 (international
callers dial +1-719-457-2697) a few minutes prior to register. Those listening
via the Internet should go to the site 15 minutes early to register, download
and install any necessary audio software. In addition, a replay of the call
will be available through March 6, 2014 by dialing 877-870-5176 (international
callers dial +1-858-384-5517) and entering replay PIN 7789996, or by going to
the Investor Relations tab of the Partnership's website (www.breitburn.com).
The Partnership will take live questions from securities analysts and
institutional portfolio managers; the complete call is open to all other
interested parties on a listen-only basis.

About BreitBurn Energy Partners L.P.

BreitBurn Energy Partners L.P. is a publicly traded independent oil and gas
master limited partnership focused on the acquisition, exploitation,
development and production of oil and gas properties. The Partnership’s
producing and non-producing oil and natural gas reserves are located in
Michigan, Oklahoma, Texas, Wyoming, California, Florida, Indiana and Kentucky.
See www.BreitBurn.com for more information.

Cautionary Statement Regarding Forward-Looking Information

This press release contains forward-looking statements relating to the
Partnership’s operations that are based on management's current expectations,
estimates and projections about its operations. Words and phrases such as
“believes,” “expect,” “future,” “impact,” “guidance,” “will be,” “future” and
variations of such words and similar expressions are intended to identify such
forward-looking statements. These statements are not guarantees of future
performance and are subject to certain risks, uncertainties and other factors,
some of which are beyond our control and are difficult to predict. These
include risks relating to the Partnership’s financial performance and results,
availability of sufficient cash flow and other sources of liquidity to execute
our business plan, prices and demand for natural gas and oil, increases in
operating costs, uncertainties inherent in estimating our reserves and
production, our ability to replace reserves and efficiently develop our
current reserves, political and regulatory developments relating to taxes,
derivatives and our oil and gas operations, risks relating to our acquisitions
and the factors set forth under the heading “Risk Factors” incorporated by
reference from our Annual Report on Form 10-K filed with the Securities and
Exchange Commission, and if applicable, our Quarterly Reports on Form 10-Q and
our Current Reports on Form 8-K. Therefore, actual outcomes and results may
differ materially from what is expressed or forecasted in such forward-looking
statements. The reader should not place undue reliance on these
forward-looking statements, which speak only as of the date of this press
release. Unless legally required, the Partnership undertakes no obligation to
update publicly any forward-looking statements, whether as a result of new
information, future events or otherwise. Unpredictable or unknown factors not
discussed herein also could have material adverse effects on forward-looking
statements.


BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Balance Sheets
                                                        
                                                             
                                             December 31,    December 31,
Thousands                                    2013            2012
ASSETS
Current assets
Cash                                         $ 2,458         $ 4,507
Accounts and other receivables, net            96,862          67,862
Derivative instruments                         7,914           34,018
Related party receivables                      2,604           1,413
Inventory                                      3,890           3,086
Prepaid expenses                              3,334         2,779     
Total current assets                           117,062         113,665
Equity investments                             6,641           7,004
Property, plant and equipment
Oil and gas properties                         4,818,639       3,363,946
Other assets                                  21,338        14,367    
                                               4,839,977       3,378,313
Accumulated depletion and depreciation        (924,601  )    (666,420  )
Net property, plant and equipment              3,915,376       2,711,893
Other long-term assets
Intangibles, net                               11,679          -
Derivative instruments                         71,319          55,210
Other long-term assets                         74,205          27,722
                                                            
Total assets                                 $ 4,196,282    $ 2,915,494 
LIABILITIES AND EQUITY
Current liabilities
Accounts payable                             $ 69,809        $ 42,497
Derivative instruments                         24,876          5,625
Revenue and royalties payable                  26,233          22,262
Wages and salaries payable                     15,359          10,857
Accrued interest payable                       19,690          13,002
Accrued liabilities                           26,922        20,997    
Total current liabilities                      182,889         115,240
                                                             
Credit facility                                733,000         345,000
Senior notes, net                              1,156,675       755,696
Deferred income taxes                          2,749           2,487
Asset retirement obligation                    123,769         98,480
Derivative instruments                         2,560           4,393
Other long-term liabilities                   4,820         4,662     
Total liabilities                              2,206,462       1,325,958
                                                             
Partners' equity                              1,989,820     1,589,536 
                                                             
Total liabilities and equity                 $ 4,196,282    $ 2,915,494 
                                                             
Common units outstanding                       119,170         84,668
                                                             
                                               -               -
                                                                         


BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Statements of Operations
                                                
                         Three Months Ended          Twelve Months Ended
                         December 31,                December 31,
Thousands of
dollars, except          2013         2012          2013         2012
per unit amounts
                                                                   
Revenues and other
income items
Oil, NGL and             $ 193,604     $ 113,179     $ 660,665     $ 413,867
natural gas sales
Gain (loss) on
commodity                  (17,234 )     3,715         (29,182 )     5,580
derivative
instruments, net
Other revenue, net        978         700         3,175       3,548   
Total revenues and         177,348       117,594       634,658       422,995
other income items
Operating costs
and expenses
Operating costs            80,933        53,576        262,822       195,779
Depletion,
depreciation and           62,400        40,350        216,495       137,252
amortization
Impairments                54,012        147           54,373        12,313
General and
administrative             14,012        15,144        58,707        55,465
expenses
(Gain) Loss on            (2,154  )    264         (2,015  )    486     
sale of assets
                                                                   
Operating (loss)           (31,855 )     8,113         44,276        21,700
income
                                                                   
Interest expense,
net of capitalized         26,680        17,975        87,067        61,206
interest
Loss on interest           -             175           -             1,101
rate swaps
Other expense             (20     )    12          (25     )    48      
(income), net
Total other               26,660      18,162      87,042      62,355  
expense
                                                                   
Loss before taxes          (58,515 )     (10,049 )     (42,766 )     (40,655 )
                                                                   
Income tax expense        277         285         905         84      
                                                                   
Net loss                   (58,792 )     (10,334 )     (43,671 )     (40,739 )
                                                                   
Less: Net income
attributable to            -             -             -             (62     )
noncontrolling
interest
                                                                
Net loss
attributable to           (58,792 )    (10,334 )    (43,671 )    (40,801 )
the partnership
                                                                   
Basic net loss per       $ (0.52   )   $ (0.13   )   $ (0.43   )   $ (0.56   )
unit
Diluted net loss         $ (0.52   )   $ (0.13   )   $ (0.43   )   $ (0.56   )
income per unit
                                                                             


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


                                            Twelve Months Ended
                                               December 31,
Thousands of dollars                           2013            2012
                                                                
Cash flows from operating activities
Net loss                                       $ (43,671    )   $ (40,739    )
Adjustments to reconcile net loss to
cash flow from operating activities:
Depletion, depreciation and amortization         216,495          137,252
Impairments                                      54,373           12,313
Unit-based compensation expense                  19,955           22,266
(Gain) loss on derivative instruments            29,182           (4,479     )
Derivative instrument settlements                8,083            84,615
Prepaid premiums on derivative                   -                (30,043    )
instruments
Settlement payments on terminated                -                (2,479     )
derivative instruments
Income from equity affiliates, net               (55        )     487
Deferred income taxes                            262              (316       )
(Gain) loss on sale of assets                    (2,015     )     486
Other                                            5,163            4,472
Changes in assets and liabilities:
Accounts receivable and other assets             (29,322    )     6,759
Inventory                                        (804       )     1,638
Net change in related party receivables          (1,191     )     2,832
and payables
Accounts payable and other liabilities          711            (3,282     )
Net cash provided by operating                  257,166        191,782    
activities
Cash flows from investing activities
Property acquisitions                            (1,175,817 )     (562,356   )
Capital expenditures                             (266,308   )     (135,932   )
Other                                            (26,661    )     -
Proceeds from sale of assets                    2,981          1,129      
Net cash used in investing activities           (1,465,805 )    (697,159   )
Cash flows from financing activities
Issuance of common units                         618,013          370,234
Distributions                                    (186,868   )     (132,420   )
Proceeds from issuance of long-term              2,276,000        1,502,885
debt, net
Repayments of long-term debt                     (1,487,000 )     (1,223,000 )
Change in book overdraft                         2,013            (3,176     )
Debt issuance costs                             (15,568    )    (9,967     )
Net cash provided by financing                  1,206,590      504,556    
activities
Decrease in cash                                 (2,049     )     (821       )
Cash beginning of period                        4,507          5,328      
Cash end of period                             $ 2,458         $ 4,507      

BBEP-IR

Contact:

BreitBurn Energy Partners L.P.
James G. Jackson
Executive Vice President and Chief Financial Officer
213-225-5900 x273
or
Jessica Tang
Investor Relations
213-225-5900 x210
 
Press spacebar to pause and continue. Press esc to stop.