Breitburn Energy Partners LP (NASDAQ:BBEP) today announced
financial and operating results for the second quarter 2015 and
provided second half 2015 guidance.
Key Highlights
- Closed the $1 billion strategic
investment led by EIG Global Energy Partners on April 8th,
resulting in approximately $500 million of current available
liquidity.
- Reported total production of 5.0 MMBoe,
in-line with Breitburn's 2015 guidance.
- Increased Adjusted EBITDA, a non-GAAP
financial measure, to $162.9 million (including costs of $1.1
million for restructuring), a 48% increase from the second quarter
of 2014 and a 10% increase from the first quarter of 2015.
- Reduced lease operating expenses to
$18.72 per Boe in the second quarter of 2015, 6% lower than the
first quarter of 2015 and 14% lower than the fourth quarter of
2014.
- Reported distributable cash flow of
$58.5 million, or $0.27 per common unit, and distribution coverage
ratio of 2.16x based on current monthly distribution of $0.04166
per common unit, or $0.50 per common unit on an annualized
basis.
- Based on Breitburn's current commodity
hedge portfolio and assuming second half 2015 guidance production
rate as set forth below, Breitburn's total production is 77% hedged
for the remainder of 2015, 65% in 2016, and 41% in 2017 at
attractive prices. The mark-to-market value of Breitburn's
commodity hedge portfolio was approximately $544 million as of June
30th and approximately $670 million as of July 31st.
Management Commentary
Halbert S. Washburn, Breitburn’s Chief Executive Officer, said:
"We are very pleased to report another solid quarter with
production, cost reductions, and Adjusted EBITDA in-line with our
guidance for the first half of the year. We have completed the
integration of the QR Energy assets and our diverse portfolio
continues to perform as expected in this challenging environment.
Earlier this year, we announced a number of steps to address what
we thought could be an extended period of weak commodity pricing.
Those steps included dramatically reducing our capital budget,
implementing an aggressive program to reduce operating costs and
completing a significant workforce reduction plan. In addition, in
April we raised almost $1 billion in external capital and reset our
borrowing base to $1.8 billion, without a scheduled redetermination
until April of 2016. We also reset our common unit distribution to
$0.50 per unit. As a result of these actions, we currently have
approximately $500 million of available liquidity under our credit
facility, are on track to reduce bank debt throughout the year and
have an excellent distribution coverage ratio of 2.16 times this
quarter."
Mr. Washburn continued, "In addition, we continue to evaluate
the most attractive alternatives for maximizing the value of our
substantial acreage position in the Midland Basin. With over 22,000
gross surface acres and approximately 360 net identified locations,
we have the ability to add meaningful production and reserves to
our base business over the course of the next few years. This
acreage provides us with significant strategic and operating
flexibility particularly in the current commodity price
environment."
Second Quarter 2015 Operating and
Financial Results Compared to First Quarter 2015
- Total production was 5,015 MBoe in the
second quarter of 2015 compared to 5,051 MBoe in the first quarter
of 2015. Average daily production was 55.1 MBoe/day in the second
quarter of 2015 compared to 56.1 MBoe/day in the first quarter of
2015.
- Oil production decreased to 2,822 MBbl
compared to 2,890 MBbl in the first quarter of 2015.
- NGL production increased to 483 MBbl
compared to 459 MBbl in the first quarter of 2015.
- Natural gas production increased to
10,264 MMcf compared to 10,211 MMcf in the first quarter of
2015.
- Adjusted EBITDA was $162.9 million
(including $1.1 million of restructuring costs) in the second
quarter of 2015 compared to $148.6 million (including $4.1 million
of restructuring costs) in the first quarter of 2015, a 10%
increase primarily due to higher oil sales revenue and lower lease
operating and G&A expenses, partially offset by lower commodity
derivative settlements.
- Net loss attributable to common
unitholders was $316.2 million, or $1.46 per diluted common unit,
in the second quarter of 2015, which includes a non-cash goodwill
impairment charge of $95.9 million, or $0.45 per unit, compared to
net loss of $63.0 million, or $0.29 per diluted common unit, in the
first quarter of 2015, which included non-cash impairment charges
of approximately $59.1 million, or $0.28 per unit.
- Oil, NGL and natural gas sales revenues
were $189.6 million in the second quarter of 2015 compared to
$162.6 million in the first quarter of 2015, primarily reflecting
higher realized oil and NGL prices.
- Lease operating expenses, which include
district expenses, processing fees and transportation costs but
exclude taxes, were $18.72 per Boe in the second quarter of 2015
compared to $19.81 per Boe in the first quarter of 2015, a 6%
decrease primarily due to cost cutting efforts, lower fuel and
utility costs, and lower workover expense.
- General and administrative expenses,
excluding non-cash unit-based compensation costs, were $16.8
million in the second quarter of 2015 compared to $25.3 million in
the first quarter of 2015, primarily due to cost cutting efforts
(including reduction in workforce) and $1.9 million lower
integration costs.
- Losses on commodity derivative
instruments were $93.4 million in the second quarter of 2015
compared to gains of $137.2 million in the first quarter of 2015,
primarily due to an increase in oil and natural gas futures prices
during the second quarter of 2015. Derivative instrument settlement
receipts were $100.6 million in the second quarter of 2015 compared
to receipts of $126.4 million in the first quarter of 2015,
primarily due to higher oil prices.
- NYMEX WTI oil spot prices averaged
$57.85 per Bbl and Brent oil spot prices averaged $61.65 per Bbl in
the second quarter of 2015 compared to $48.49 per Bbl and $53.98
per Bbl, respectively, in the first quarter of 2015. Henry Hub
natural gas spot prices averaged $2.75 per Mcf in the second
quarter of 2015 compared to $2.90 per Mcf in the first quarter of
2015.
- Average realized crude oil, NGL and
natural gas prices, excluding the effects of commodity derivative
settlements, were $53.29 per Bbl, $18.35 per Bbl and $2.57 per Mcf,
respectively, in the second quarter of 2015 compared to $43.62 per
Bbl, $16.54 per Bbl and $3.05 per Mcf, respectively, in the first
quarter of 2015.
- Oil, NGL and natural gas capital
expenditures were $58 million in the second quarter of 2015,
compared to $73 million in the first quarter of 2015.
- Distributable cash flow, a non-GAAP
financial measure, was $58.5 million in the second quarter of 2015
compared to $60.7 million in the first quarter of 2015.
Second Half 2015 Guidance (Assuming No
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 Breitburn'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 and
gas will continue at levels that allow for economic production of
these products. The production, transportation and marketing of oil
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, including the
inability to obtain expected supply of CO2. Breitburn's estimates
are based on certain other assumptions, such as well performance,
which may actually prove to vary significantly from those assumed.
Lease operating costs, including 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. Lease 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, and 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 foregoing
guidance does not constitute any form of guarantee, assurance or
promise that the matters indicated will actually be achieved.
Rather, the foregoing guidance 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)
Second Half 2015
Guidance(1)
Total Production (MBoe): 9,620 —
10,220 Oil Production (MBbls) 5,400 — 5,800 NGL Production
(MBbls) 850 — 950 Natural Gas Production (MMcfe)
20,220 — 20,820 Average Price
Differential %: WTI Oil Price Differential % 89 % — 95%
Brent Oil Price Differential %(2)
87 % — 93% NGL Price Differential % (of WTI) 32 % — 38% Natural Gas
Price Differential % 100 % —
105%
Oil, NGL, and Natural Gas Sales
Revenue(3)
$317,000 — $363,000 Realized Hedge Gains / (Losses)
$237,000
Other Revenue(4)
$11,000 — $13,000
Lease Operating Expenses / Boe(5)
$18.75 — $20.75
Other Operating Expenses(6)
$9,000 — $10,000 Production / Property Taxes (% of Sales Revenue)
8.25 % — 8.75% G&A (Excl. Unit Based Compensation) $30,000 —
$32,000
Adjusted EBITDA(7)
$315,000 — $340,000
Cash Interest Expense(8)
$95,000 — $98,000
Preferred Equity Distributions(9)
$8,250
Maintenance Capital Expenditures(10)
$103,000
Distributable Cash Flow(11)
$105,000 — $135,000
Units Outstanding(12)
219,000
DCF per Unit $0.48 — $0.62
Common Unit DCF Coverage Ratio(13)
1.92x — 2.47x
(1)
Breitburn’s second half 2015 guidance is
based on flat $50 per barrel WTI crude oil, $55 per barrel Brent
crude oil, and $3.00 per Mcf natural gas price levels for second
half 2015.
(2)
Approximately 15% of estimated crude oil
production is expected to be sold based on Brent pricing.
(3)
Range based on the low and high values of
production and differentials as set forth above.
(4)
Primarily consists of $9-$10 million in
revenue related to the East Texas Salt Water Disposal System.
(5)
Lease operating expenses include
processing fees, district expenses and transportation costs.
(6)
Represents costs related the East Texas
Salt Water Disposal System.
(7)
Assuming the high and low range of
Breitburn’s second half 2015 Guidance, Adjusted EBITDA is expected
to range between $315 million and $340 million, and is comprised of
estimated net loss (before non-cash compensation and non-cash
distributions paid-in-kind to holders of 8.0% Series B Preferred
Units) between ($136) million (low end of Adjusted EBITDA) and
($108) million (high end of Adjusted EBITDA), plus unrealized
losses on commodity derivative instruments of $151 million, plus
DD&A of $191 million, plus interest expense between $95 million
(high end of Adjusted EBITDA) and $98 million (low end of Adjusted
EBITDA), plus preferred distributions to holders of 8.25% Series A
Preferred Units of $8.25 million. Differences between actual and
forecast prices could result in changes to unrealized gains or
losses on commodity derivative instruments, DD&A, including
potential impairments of long-lived assets, and ultimately, net
income.
(8)
Typically, Breitburn’s borrowings under
its credit facility are based on 1-month LIBOR plus an applicable
spread ranging from 175 bps to 275 bps. Cash interest expense
assumes a 1-month LIBOR rate of 0.20%.
(9)
Reflects cash distributions paid to
holders of 8.25% Series A Cumulative Redeemable Perpetual Preferred
Units and assumes that distributions owed to holders of 8.0% Series
B Perpetual Convertible Preferred Units will be paid in kind.
(10)
Maintenance capital expenditures exclude
information technology spending of approximately $3.2 million.
Maintenance 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
flat over a multi-year period.
(11)
Range based on (i) low end of EBITDA less
high end of interest expense, maintenance capital, and preferred
distributions and (ii) high end of EBITDA less the low end of
interest expense, maintenance capital, and preferred
distributions.
(12)
Includes all common units expected to
receive distributions in cash.
(13)
Assumes constant annualized distribution
rate of $0.50/unit.
Impact of Derivative
Instruments
Breitburn uses commodity derivative instruments to mitigate
risks associated with commodity price volatility and to help
maintain cash flows for operating activities, acquisitions, capital
expenditures and distributions. Breitburn does not enter into
derivative instruments for speculative trading purposes. Since
Breitburn does not use hedge accounting to account for its
derivative instruments, changes in the fair value of derivative
instruments are recorded in Breitburn’s earnings during 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 Breitburn’s ability to pay
cash distributions for the reporting periods presented.
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
June 30, 2015 and 2014, and the three months ended March 31,
2015:
Three Months Ended June 30,
March 31, June 30, Thousands
of dollars, except as indicated 2015 2015
2014 Oil sales $ 154,425 $ 123,843 $ 173,948 NGL sales 8,861
7,591 10,675 Natural gas sales 26,350 31,189 34,428 (Loss) gain on
commodity derivative instruments (93,432 ) 137,192 (127,000 ) Other
revenues, net (a) 6,504 6,469 1,071 Total
revenues $ 102,708 $ 306,284 $ 93,122 Lease
operating expenses before taxes (b) $ 93,858 $ 100,079 $ 70,923
Production and property taxes (c) 15,348 13,544
16,001 Total lease operating expenses 109,206 113,623
86,924 Purchases and other operating costs 421 158
110 Salt water disposal costs 4,053 4,021 — Change in inventory
2,157 176 (3,974 ) Total operating costs $ 115,837
$ 117,978 $ 83,060 Lease operating expenses
before taxes per Boe (b) $ 18.72 $ 19.81 $ 21.03 Production and
property taxes per Boe (c) 3.06 2.68 4.74
Total lease operating expenses per Boe $ 21.78 $ 22.49
$ 25.77 General and administrative expenses
(excluding non-cash unit-based compensation) $ 16,778 $
25,335 $ 10,322 Net loss attributable to the
partnership $ (305,707 ) $ (58,825 ) $ (104,725 ) Less:
distributions to Series A preferred unitholders 4,125 4,125 1,833
Less: non-cash distributions to Series B preferred unitholders
6,408 — — Net loss attributable to common
unitholders $ (316,240 ) $ (62,950 ) $ (106,558 ) Total
production (MBoe) (d) 5,015 5,051 3,373 Oil (MBbl) 2,822 2,890
1,901 NGLs (MBbl) 483 459 279 Natural gas (MMcf) 10,264 10,211
7,163 Average daily production (Boe/d) 55,110 56,122
37,069 Sales volumes (MBoe) (e) 5,089 4,999
3,289 Average realized sales price (per Boe) (f) (g) $ 37.24
$ 32.52 $ 66.59 Oil (per Bbl) (f) (g) 53.29 43.62 95.74 NGLs (per
Bbl) (f) 18.35 16.54 38.26 Natural gas (per Mcf) (f) $ 2.57
$ 3.05 $ 4.81 (a) Includes revenue from the
East Texas Salt Water Disposal System of $4.0 million, $4.1 million
and zero for the three months ended June 30, 2015, March 31, 2015
and June 30, 2014. (b) Includes district expenses, processing fees
and transportation costs. (c) Includes ad valorem and severance
taxes. (d) 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. (e) Oil sales were 2,896 MBbl, 2,835 MBbl and 1,817 MBbl for
the three months ended June 30, 2015, March 31, 2015 and June 30,
2014, respectively. (f) Excludes the effect of commodity derivative
settlements. (g) Includes the per Boe effect of crude oil
purchases.
Non-GAAP Financial
Measures
This press release, including 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 Breitburn’s financial results with
investors and analysts, and they are also available at
www.breitburn.com.
“Adjusted EBITDA” and “distributable cash flow” are among the
non-GAAP financial measures used in this press release. 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 believes that these
non-GAAP financial measures enhance comparability to prior
periods.
Adjusted EBITDA is presented because management believes it
provides additional information relative to the performance of
Breitburn’s assets, without regard to financing methods or capital
structure. Distributable cash flow is used by management as a tool
to measure the cash distributions we could pay to our unitholders,
and 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 loss 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 June 30,
March 31, June 30, Thousands
of dollars, except as indicated 2015 2015
2014 Reconciliation of net loss to Adjusted
EBITDA: Net loss attributable to the partnership $ (305,707 ) $
(58,825 ) $ (104,725 ) Loss (gain) on commodity derivative
instruments 93,432 (137,192 ) 127,000 Commodity derivative
instrument settlement receipts (payments) (a) (b) 100,576 126,357
(17,024 ) Depletion, depreciation and amortization expense 109,447
109,824 68,245 Impairments of oil and natural gas properties —
59,113 — Impairments of goodwill 95,947 — — Interest expense and
other financing costs 62,007 41,477 30,208 Loss on sale of assets
122 15 334 Income tax expense (benefit) 259 92 (159 ) Unit-based
compensation expense (c) 6,084 6,927 6,098 Restructuring costs -
unit-based compensation 721 814
—
Adjusted EBITDA $ 162,888 $ 148,602 $ 109,977 Less:
Maintenance capital (d) $ 52,000 $ 45,000 $ 26,999 Cash interest
expense 48,250 38,729 28,399 Distributions to Series A preferred
unitholders (e) 4,125 4,125
1,833 Distributable cash flow available to common
unitholders $ 58,513 $ 60,748 $ 52,746
Distributable cash flow available per common unit (f) 0.270 0.282
0.431 Common unit distribution coverage (g) 2.16x 2.26x 0.86x
Reconciliation of net cash flows from operating
activities to Adjusted EBITDA: Net cash provided by
operating activities $ 73,796 $ 141,149 $ 74,798 Increase
(decrease) in assets net of liabilities relating to operating
activities 40,736 (30,968 ) 7,300 Interest expense (h) 48,197
38,729 28,178 Income from equity affiliates, net 172 (325 ) (388 )
Noncontrolling interest (126 ) 93 — Income taxes 259 (76 ) 89 Gain
on marketable securities (146 ) — —
Adjusted EBITDA $ 162,888 $ 148,602 $
109,977 (a) Excludes premiums paid at contract
inception related to those derivative contracts that settled during
the applicable periods of: $
1,663
$
1,645
$
2,118
(b) Includes net cash settlements on derivative instruments for: -
Oil settlements received (paid):
83,265
111,879
(18,125
)
- Natural gas settlements received: $
17,311
$
14,478
$
1,101
(c) Represents non-cash long-term unit-based incentive compensation
expense. (d) 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
flat over a multi-year period. (e) Does not include paid-in-kind
distributions on Series B Preferred Units. (f) Based on common
units outstanding (including outstanding LTIP grants) at each
distribution record date within the periods. (g) Does not include
Series B Preferred Units on an as converted basis. (h) Excludes
amortization of debt issuance costs and amortization of senior note
discount/premium.
Summary of Commodity Derivative
Instruments
The table below summarizes Breitburn’s commodity derivative
hedge portfolio as of August 5, 2015. For an overview of
Breitburn's commodity hedge portfolio, please refer to the Summary
of Commodity Price Protection Portfolio at www.breitburn.com.
Year 2015 2016
2017 2018
2019 Oil Positions: Fixed Price Swaps -
NYMEX WTI Volume (Bbl/d) 20,043 15,504 13,519 493 — Average Price
($/Bbl) $ 93.27 $ 88.07 $ 85.05 $ 82.20 $ — Fixed Price Swaps - ICE
Brent Volume (Bbl/d) 3,300 4,300 298 — — Average Price ($/Bbl) $
97.73 $ 95.17 $ 97.50 $ — $ — Collars - NYMEX WTI Volume (Bbl/d)
2,025 1,500 — — — Average Floor Price ($/Bbl) $ 90.00 $ 80.00 $ — $
— $ — Average Ceiling Price ($/Bbl) $ 111.73 $ 102.00 $ — $ — $ —
Collars - ICE Brent Volume (Bbl/d) 500 500 — — — Average Floor
Price ($/Bbl) $ 90.00 $ 90.00 $ — $ — $ — Average Ceiling Price
($/Bbl) $ 109.50 $ 101.25 $ — $ — $ — Puts - NYMEX WTI Volume
(Bbl/d) 500 1,000 — — — Average Price ($/Bbl) $ 90.00 $ 90.00 $ — $
— $ — Total: Volume (Bbl/d) 26,368 22,804 13,817 493 — Average
Price ($/Bbl) $ 93.46 $ 89.01 $ 85.32 $ 82.20 $ —
Gas
Positions: Fixed Price Swaps - MichCon City-Gate Volume
(MMBtu/d) 16,658 25,000 20,000 7,000 4,000 Average Price ($/MMBtu)
$ 4.33 $ 4.03 $ 3.84 $ 3.23 $ 3.30 Fixed Price Swaps - Henry Hub
Volume (MMBtu/d) 54,891 36,050 19,016 1,870 — Average Price
($/MMBtu) $ 4.84 $ 4.24 $ 4.43 $ 4.15 $ — Collars - Henry Hub
Volume (MMBtu/d) 18,000 630 595 — — Average Floor Price ($/MMBtu) $
5.00 $ 4.00 $ 4.00 $ — $ — Average Ceiling Price ($/MMBtu) $ 7.48 $
5.55 $ 6.15 $ — $ — Puts - Henry Hub Volume (MMBtu/d) 1,920 11,350
10,445 — — Average Price ($/MMBtu) $ 4.78 $ 4.00 $ 4.00 $ — $ —
Deferred Premium ($/MMBtu) $ 0.64 (a) $ 0.66 $ 0.69 $ — $ — Total:
Volume (MMBtu/d) 91,469 73,030 50,056 8,870 4,000 Average Price
($/MMBtu) $ 4.78 $ 4.13 $ 4.10 $ 3.42 $ 3.30 Basis Swaps-
Henry Hub Volume (MMBtu/d) 14,400 — — — — Average Price ($/MMBtu) $
(0.19 ) $ — $ — $ — $ —
(a) Deferred premiums of $0.64 apply to
420 MMBtu/d of the 2015 volume.
Premiums paid in 2012 related to oil and natural gas derivatives
to be settled after June 30, 2015, are as follows:
Year Thousands of dollars 2015
2016 2017
2018 2019 Oil $ 2,361 $ 7,438 $ 734 $ —
$ — Natural gas $ 1,003 $ 952 $ — $ — $ —
Other Information
Breitburn will host a conference call Thursday, August 6, 2015,
at 12:00 pm (EDT) to discuss Breitburn’s second quarter 2015
results. The conference call may be accessed by calling
888-417-8465 (international callers dial 719-325-2215) or via
webcast at http://ir.breitburn.com/.
An archived edition of the conference call will also be available
through August 13th by calling 877-870-5176 (international callers
dial 858-384-5517) and entering replay PIN 6137597 or by visiting
http://ir.breitburn.com/. Breitburn
will take questions from securities analysts and institutional
portfolio managers; the call is open to all other interested
parties on a listen-only basis.
About Breitburn Energy Partners
LP
Breitburn Energy Partners LP is a publicly traded, independent
oil and gas master limited partnership focused on the acquisition,
development, and production of oil and gas properties throughout
the United States. Breitburn’s producing and non-producing crude
oil and natural gas reserves are located in the following seven
producing areas: Ark-La-Tex, Michigan/Indiana/Kentucky, the Permian
Basin, the Mid-Continent, the Rockies, Florida, and California. See
www.breitburn.com for more information.
Cautionary Statement Regarding
Forward-Looking Information
This press release contains forward-looking statements relating
to Breitburn'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,” 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 Breitburn'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,
Breitburn 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.
BBEP-IR
Breitburn Energy Partners LP and Subsidiaries
Unaudited Consolidated Balance Sheets
June 30, December 31, Thousands of
dollars 2015 2014 ASSETS Current
assets Cash $ 9,525 $ 12,628 Accounts and other receivables,
net 154,309 166,436 Derivative instruments 309,239 408,151 Related
party receivables 297 2,462 Inventory 1,342 3,727 Prepaid expenses
7,439 7,304 Total current assets 482,151 600,708
Equity investments 6,310 6,463
Property, plant and
equipment Oil and natural gas properties 7,866,044 7,736,409
Other property, plant and equipment 140,054 60,533
8,006,098 7,796,942 Accumulated depletion and depreciation
(1,609,796 ) (1,342,741 ) Net property, plant and equipment
6,396,302 6,454,201
Other long-term assets Intangibles 2,044
8,336 Goodwill — 92,024 Derivative instruments 235,554 319,560
Other long-term assets 123,182 157,042
Total
assets $ 7,245,543 $ 7,638,334
LIABILITIES AND EQUITY Current liabilities Accounts
payable $ 77,722 $ 129,270 Current portion of long-term debt 421
105,000 Derivative instruments 5,388 5,457 Distributions payable
732 733 Current portion of asset retirement obligation 3,912 4,948
Revenue and royalties payable 46,838 40,452 Wages and salaries
payable 20,146 22,322 Accrued interest payable 19,772 20,672
Production and property taxes payable 25,214 25,207 Other current
liabilities 6,805 7,495 Total current liabilities
206,950 361,556 Credit facility 1,309,000 2,089,500 Senior
notes, net 1,787,887 1,156,560 Other long-term debt 2,579
1,100 Total long-term debt 3,099,466 3,247,160 Deferred
income taxes 2,743 2,575 Asset retirement obligation 243,243
233,463 Derivative instruments 2,082 2,269 Other long-term
liabilities 24,711 25,135 Total liabilities 3,579,195
3,872,158
Equity Series A preferred units, 8.0
million units issued and outstanding at each of June 30, 2015 and
December 31, 2014 193,215 193,215 Series B preferred units, 47.2
million and 0 units issued and outstanding at June 30, 2015 and
December 31, 2014, respectively 341,700 — Common units, 211.7
million and 210.9 million units issued and outstanding at June 30,
2015 and December 31, 2014, respectively 3,124,808 3,566,468
Accumulated other comprehensive loss (333 ) (392 ) Total partners'
equity 3,659,390 3,759,291 Noncontrolling interest 6,958
6,885
Total equity 3,666,348 3,766,176
Total liabilities and equity $ 7,245,543 $ 7,638,334
Breitburn Energy Partners LP and
Subsidiaries Unaudited Consolidated Statements of
Operations Three Months Ended
Six Months Ended June 30, June
30, Thousands of dollars, except per unit amounts
2015 2014 2015
2014 Revenues and other income items Oil,
natural gas and natural gas liquid sales $ 189,636 $ 219,051 $
352,259 $ 442,607 (Loss) gain on commodity derivative instruments,
net (93,432 ) (127,000 ) 43,760 (167,228 ) Other revenue, net 6,504
1,071 12,973 2,655 Total revenues and
other income items 102,708 93,122 408,992 278,034
Operating
costs and expenses Operating costs 115,837 83,060 233,815
165,257 Depletion, depreciation and amortization 109,447 68,245
219,271 131,746 Impairments of oil and natural gas properties — —
59,113 — Impairments of goodwill 95,947 — 95,947 — General and
administrative expenses 22,862 16,420 55,124 35,149 Restructuring
costs 1,773 — 6,691 — Loss on sale of assets 122 334
137 420 Total operating costs and expenses 345,988
168,059 670,098 332,572
Operating loss (243,280 ) (74,937 ) (261,106 ) (54,538 )
Interest expense, net of capitalized interest 61,404 30,208
101,069 60,866 Loss on interest rate swaps 603 — 2,415 — Other
expenses (income), net 35 (261 ) (442 ) (773 ) Total other
expense 62,042 29,947 103,042 60,093
Loss before taxes (305,322 ) (104,884 ) (364,148 )
(114,631 ) Income tax expense (benefit) 259 (159 )
351 (148 )
Net loss (305,581 ) (104,725 )
(364,499 ) (114,483 ) Less: Net income attributable to
noncontrolling interest 126 — 33 —
Net loss attributable to the partnership (305,707 ) (104,725
) (364,532 )
(114,483
) Less: Distributions to Series A preferred unitholders
4,125 1,833 8,250 1,833 Less: Non-cash distributions to Series B
preferred unitholders 6,408 — 6,408 —
Net loss attributable to common unitholders $ (316,240 ) $
(106,558 ) $ (379,190 ) $ (116,316 ) Basic net loss per
common unit $ (1.46 ) $ (0.89 ) $ (1.75 ) $ (0.97 ) Diluted net
loss per common unit $ (1.46 ) $ (0.89 ) $ (1.75 ) $ (0.97 )
Breitburn Energy Partners LP and Subsidiaries
Unaudited Consolidated Statements of Comprehensive Income
Three Months Ended June 30,
Six Months Ended June 30, Thousands of dollars,
except per unit amounts 2015 2014
2015 2014 Net loss $ (305,581 )
$ (104,725 ) $ (364,499 ) $ (114,483 )
Other
comprehensive (loss) income, net of tax: Change in fair value
of available-for-sale securities (a) (74 ) — 99 —
Total other comprehensive (loss) income (74 ) — 99
—
Total comprehensive loss (305,655 )
(104,725 ) (364,400 ) (114,483 ) Less: Comprehensive income
attributable to noncontrolling interest 97 — 74
—
Comprehensive loss attributable to the
partnership $ (305,752 ) $ (104,725 ) $ (364,474 ) $ (114,483 )
(a) Net of income taxes benefit of less than $0.1 million
and income tax expense of less than $0.1 million for the three
months and six months ended June 30, 2015.
Breitburn Energy Partners LP and Subsidiaries Unaudited
Consolidated Statements of Cash Flows
Six Months Ended June 30, Thousands of dollars
2015 2014 Cash flows from
operating activities Net loss $ (364,499 ) $ (114,483 )
Adjustments to reconcile to cash flow from operating activities:
Depletion, depreciation and amortization 219,271 131,746 Impairment
of oil and natural gas properties 59,113 Impairment of goodwill
95,947 — Unit-based compensation expense 14,545 12,647 (Gain) loss
on derivative instruments (41,345 ) 167,228 Derivative instrument
settlement receipts (payments) 224,007 (30,524 ) Income from equity
affiliates, net 153 281 Deferred income taxes 168 (281 ) Loss on
sale of assets 137 420 Other 12,818 3,487 Changes in net assets and
liabilities Accounts receivable and other assets 8,656 2,097
Inventory 2,385 (5,347 ) Net change in related party receivables
and payables 2,165 1,322 Accounts payable and other liabilities
(18,576 ) 22,516 Net cash provided by operating activities
214,945 191,109
Cash flows from investing
activities Property acquisitions (17,663 ) (2,684 ) Capital
expenditures (170,634 ) (188,758 ) Proceeds from sale of assets —
542 Proceeds from sale of available-for-sale securities 3,480 —
Purchases of available-for-sale securities (3,637 ) — Other (853 )
(5,706 ) Net cash used in investing activities (189,307 ) (196,606
)
Cash flows from financing activities Proceeds from
issuance of preferred units, net 337,895 193,397 Proceeds from
issuance of common units, net 4,925 20,273 Distributions to
preferred unitholders (8,250 ) — Distributions to common
unitholders (81,183 ) (120,059 ) Proceeds from issuance of
long-term debt, net 1,043,400 466,000 Repayments of long-term debt
(1,296,500 ) (543,500 ) Change in bank overdraft 126 (2,425 ) Debt
issuance costs (29,154 ) (1,632 ) Net cash (used in) provided by
financing activities (28,741 ) 12,054
(Decrease) increase
in cash (3,103 ) 6,557
Cash beginning of period 12,628
2,458
Cash end of period $ 9,525 $
9,015
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version on businesswire.com: http://www.businesswire.com/news/home/20150806005534/en/
Breitburn Energy Partners LPAntonio D'AmicoVice President,
Investor Relations & Government AffairsorJessica TangInvestor
Relations Manager213-225-0390