Breitburn Energy Partners LP (NASDAQ:BBEP) today announced
financial and operating results for the third quarter 2015.
Key Highlights
- Reported third quarter total production
of 5 MMBoe, in line with Breitburn's guidance.
- Reported pre-tax lease operating
expenses of $99.3 million, or $19.83 per Boe, in line with
Breitburn's guidance.
- Reported Adjusted EBITDA, a non-GAAP
financial measure, of $156.3 million.
- Reported G&A expenses, excluding
unit-based compensation, of $16.9 million in the third quarter
compared to $16.8 million in the second quarter. Excluding $3.1
million of integration and acquisition costs in the third quarter
and $2.7 million of integration and acquisition costs in the second
quarter, G&A expenses improved to $2.76 per Boe in the third
quarter compared to $2.81 per Boe in the second quarter.
- Reported distributable cash flow of
$51.5 million, or $0.24 per common unit, and distribution coverage
ratio of 1.9x 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, total estimated production is 77% hedged for the remainder of
2015, 72% in 2016, and 45% in 2017 at attractive prices. The
estimated value of Breitburn's commodity hedge portfolio was
approximately $668 million as of September 30th.
- Borrowing base of $1.8 billion on bank
credit facility remains unchanged through April 2016, resulting in
liquidity of approximately $526 million as of quarter end.
Management Commentary
Halbert S. Washburn, Breitburn’s Chief Executive Officer, said:
"I am pleased with our third straight quarter of solid operating
results since we acquired QR Energy last November. Our production
is on track to achieve our 20 million Boe full year 2015 production
target with our reduced $200 million capital program. We remain
focused on reducing our lease operating and G&A expenses, and
those third quarter results are in line with our expectations.
Earlier this year, we laid out a strategy of operating within our
cash flow, reducing and high grading capital spending, lowering
operating and G&A costs, decreasing debt, and increasing
liquidity, and we continue to execute on all aspects of our
plan."
Third Quarter 2015 Operating and
Financial Results Compared to Second Quarter 2015
- Total production was 5,008 MBoe in the
third quarter of 2015 compared to 5,015 MBoe in the second quarter
of 2015. Average daily production was 54.4 MBoe/day in the third
quarter of 2015 compared to 55.1 MBoe/day in the second quarter of
2015.
- Oil production decreased to 2,741 MBbl
compared to 2,822 MBbl in the second quarter of 2015.
- NGL production increased to 485 MBbl
compared to 483 MBbl in the second quarter of 2015.
- Natural gas production increased to
10,689 MMcf compared to 10,264 MMcf in the second quarter of
2015.
- Adjusted EBITDA was $156.3 million in
the third quarter of 2015 compared to $162.9 million (including
$1.1 million of restructuring costs) in the second quarter of 2015,
a 4% decrease primarily due to lower commodity prices, lower oil
production, and one less Florida oil shipment, partially offset by
higher commodity derivative settlements and higher gas
production.
- Net loss attributable to common
unitholders was $1,339 million, or $6.17 per diluted common unit,
in the third quarter of 2015, which included non-cash impairments
of long-lived assets of $1,440 million, or $6.80 per unit,
primarily related to the impact of the drop in commodity prices on
our projected net revenues for certain of our oil and gas
properties, compared to net loss of $316.2 million, or $1.46 per
diluted common unit, in the second quarter of 2015, which included
a non-cash goodwill impairment charge of approximately $95.9
million, or $0.45 per unit.
- Oil, NGL and natural gas sales revenues
were $153.3 million in the third quarter of 2015 compared to $189.6
million in the second quarter of 2015, primarily reflecting lower
realized oil and NGL prices, lower oil production, and one less
Florida oil shipment, partially offset by higher gas
production.
- Lease operating expenses, which include
district expenses, processing fees and transportation costs but
exclude taxes, were $19.83 per Boe in the third quarter of 2015
compared to $18.72 per Boe in the second quarter of 2015, a 6%
increase primarily due to additional spending of $5 million for a
well reactivation program in the Midland Basin.
- General and administrative expenses,
excluding non-cash unit-based compensation costs, were $16.9
million in the third quarter of 2015 compared to $16.8 million in
the second quarter of 2015. Excluding $3.1 million of integration
and acquisition costs in the third quarter and $2.7 million of
integration and acquisition costs in the second quarter, G&A
expenses improved to $13.8 million, or $2.76 per Boe, in the third
quarter compared to $14.1 million, or $2.81 per Boe, in the second
quarter.
- Gains on commodity derivative
instruments were $253 million in the third quarter of 2015 compared
to losses of $93.4 million in the second quarter of 2015, primarily
due to a decrease in oil and natural gas futures prices during the
third quarter of 2015. Derivative instrument settlement receipts
were $129 million in the third quarter of 2015 compared to receipts
of $100.6 million in the second quarter of 2015, primarily due to
lower oil prices.
- NYMEX WTI oil spot prices averaged
$46.64 per Bbl and Brent oil spot prices averaged $50.41 per Bbl in
the third quarter of 2015 compared to $57.85 per Bbl and $61.65 per
Bbl, respectively, in the second quarter of 2015. Henry Hub natural
gas spot prices averaged $2.76 per Mcf in the third quarter of 2015
compared to $2.75 per Mcf in the second quarter of 2015.
- Average realized crude oil, NGL and
natural gas prices, excluding the effects of commodity derivative
settlements, were $43.38 per Bbl, $12.44 per Bbl and $2.76 per Mcf,
respectively, in the third quarter of 2015 compared to $53.29 per
Bbl, $18.35 per Bbl and $2.57 per Mcf, respectively, in the second
quarter of 2015.
- Oil, NGL and natural gas capital
expenditures were $46 million in the third quarter of 2015 compared
to $58 million in the second quarter of 2015.
- Distributable cash flow, a non-GAAP
financial measure, was $51.5 million in the third quarter of 2015
compared to $58.5 million in the second quarter of 2015.
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
September 30, 2015 and 2014, and the three months ended June 30,
2015:
Three Months Ended September 30,
June 30, September 30,
Thousands of dollars, except as indicated 2015
2015 2014 Oil sales $ 117,743 $ 154,425 $ 176,986 NGL
sales 6,032 8,861 9,582 Natural gas sales 29,550 26,350 29,578 Gain
(loss) on commodity derivative instruments 253,012 (93,432 )
146,171
Other revenues, net (a)
5,922 6,504 1,585 Total revenues $ 412,259 $
102,708 $ 363,902 Lease operating expenses before taxes (b)
$ 99,318 $ 93,858 $ 62,714 Production and property taxes (c) 13,249
15,348 16,327 Total lease operating expenses 112,567
109,206 79,041 Purchases and other operating costs
367 421 102 Salt water disposal costs 4,205 4,053 — Change in
inventory (2,004 ) 2,157 3,761 Total operating costs $
115,135 $ 115,837 $ 82,904 Lease operating expenses
before taxes per Boe (b) $ 19.83 $ 18.72 $ 18.70 Production and
property taxes per Boe (c) 2.65 3.06 4.87 Total lease
operating expenses per Boe $ 22.48 $ 21.78 $ 23.57
General and administrative expenses (excluding non-cash unit-based
compensation) $ 16,916 $ 16,778 $ 12,908 Net (loss)
income attributable to the partnership $ (1,327,929 ) $ (305,707 )
$ 130,643 Less: Distributions to Series A preferred unitholders
4,125 4,125 4,125 Less: Non-cash distributions to Series B
preferred unitholders 7,145 6,408 — Less: Net (loss) income
attributable to participating units (31,662 ) (7,858 ) 1,868 Net
(loss) income attributable to common unitholders $ (1,307,537 ) $
(308,382 ) $ 124,650 Total production (MBoe) (d) 5,008 5,015
3,353 Oil (MBbl) 2,741 2,822 1,904 NGLs (MBbl) 485 483 253 Natural
gas (MMcf) 10,689 10,264 7,178 Average daily production (Boe/d)
54,435 55,110 36,450 Sales volumes (MBoe) (e) 4,980
5,089 3,412 Average realized sales price (per Boe)
(f) (g) $ 30.78 $ 37.24 $ 63.33 Oil (per Bbl) (f) (g) 43.38 53.29
90.12 NGLs (per Bbl) (f) 12.44 18.35 37.87 Natural gas (per Mcf)
(f) $ 2.76 $ 2.57 $ 4.12 (a) Includes revenue
from the East Texas Salt Water Disposal System of $4.1 million,
$4.0 million and zero for the three months ended September 30,
2015, June 30, 2015, and September 30, 2014, respectively. (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 2,713 MBbl, 2,896 MBbl and 1,964 MBbl for the three
months ended September 30, 2015, June 30, 2015 and September 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 September 30,
June 30, September 30,
Thousands of dollars, except as indicated 2015
2015 2014 Reconciliation of net income to Adjusted
EBITDA: Net (loss) income attributable to the partnership $
(1,327,929 ) $ (305,707 ) $ 130,643 Gain (loss) on commodity
derivative instruments (253,012 ) 93,432 (146,171 ) Commodity
derivative instrument settlement receipts (payments) (a) (b)
128,969 100,576 (3,704 ) Depletion, depreciation and amortization
expense 117,464 109,447 72,671 Impairments of oil and natural gas
properties 1,440,167 — 29,434 Impairments of goodwill — 95,947 —
Interest expense and other financing costs 51,915 62,007 29,494
(Gain) loss on sale of assets (7,459 ) 122 (63 ) Income tax expense
14 259 532 Unit-based compensation expense (c) 6,360 6,084 5,829
Restructuring costs - unit-based compensation (192 ) 721 —
Adjusted EBITDA $ 156,297 $ 162,888 $ 118,665 Less:
Maintenance capital (d) $ 52,000 $ 52,000 $ 33,434 Cash interest
expense 48,654 48,250 27,849 Distributions to Series A preferred
unitholders (e) 4,125 4,125 4,125
Distributable cash flow available to common unitholders $ 51,518
$ 58,513 $ 53,257 Distributable cash
flow available per common unit (f) $ 0.237 $ 0.270 $ 0.390 Common
unit distribution coverage (g) 1.90x 2.16x 0.78x
Reconciliation of net cash flows from operating activities to
Adjusted EBITDA: Net cash provided by operating
activities $ 136,239 $ 73,796 $ 103,807 Increase (decrease) in
assets net of liabilities relating to operating activities (29,063
) 40,736 (13,160 ) Interest expense (h) 48,562 48,197 27,729 Income
from equity affiliates, net 163 172 191 Noncontrolling interest (91
) (126 ) — Income taxes 488 259 98 Gain on marketable securities —
(146 ) —
Adjusted EBITDA $ 156,297 $
162,888 $ 118,665 (a) Excludes premiums paid
at contract inception related to those derivative contracts that
settled during the applicable periods of: $ 1,681 $ 1,663
$
2,141
(b) Includes net cash settlements on derivative instruments for: -
Oil settlements received (paid): $ 112,437 $ 83,265
$
(7,940
) - Natural gas settlements received: $ 16,532 $ 17,311
$
4,236
(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 November 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 17,504 14,519 1,493 1,000 Average Price
($/Bbl) $ 93.27 $ 83.62 $ 82.81 $ 64.02 $ 56.35 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 24,804 14,817 1,493 1,000 Average
Price ($/Bbl) $ 93.46 $ 85.79 $ 83.11 $ 64.02 $ 56.35
Gas
Positions: Fixed Price Swaps - MichCon City-Gate Volume
(MMBtu/d) 17,500 29,000 24,000 17,500 10,000 Average Price
($/MMBtu) $ 4.26 $ 3.91 $ 3.71 $ 3.10 $ 3.15 Fixed Price Swaps -
Henry Hub Volume (MMBtu/d) 54,891 42,050 21,016 2,870 — Average
Price ($/MMBtu) $ 4.84 $ 4.02 $ 4.29 $ 3.74 $ — 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 (b) $ 0.69 (c) $ — $ — Total: Volume (MMBtu/d) 92,311
83,030 56,056 20,370 10,000 Average Price ($/MMBtu) $ 4.76 $ 3.98 $
3.98 $ 3.19 $ 3.15 (a) Deferred premiums of $0.64 apply to
420 MMBtu/d of the 2015 volume. (b) Deferred premiums of $0.66
apply to 11,350 MMBtu/d of the 2016 volume. (c) Deferred premiums
of $0.69 apply to 10,445 MMBtu/d of the 2017 volume.
Premiums paid in 2012 related to oil and natural gas derivatives
to be settled after September 30, 2015, are as follows:
Year Thousands of dollars
2015 2016 2017 Oil
$ 1,180 $ 7,438 $ 734 Natural gas $ 501 $ 952 $ —
Other Information
Breitburn will host a conference call Thursday, November 5,
2015, at 11:00 am (EST) to discuss Breitburn’s third quarter 2015
results. The conference call may be accessed by calling
888-389-5988 (international callers dial 719-325-2464) or via
webcast at http://ir.breitburn.com/.
An archived edition of the conference call will also be available
through November 12th by calling 877-870-5176 (international
callers dial 858-384-5517) and entering replay PIN 9034747 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
September 30, December 31, Thousands
of dollars 2015 2014 ASSETS Current
assets Cash $ 12,091 $ 12,628 Accounts and other receivables,
net 135,479 166,436 Derivative instruments 400,857 408,151 Related
party receivables 2,069 2,462 Inventory 3,371 3,727 Prepaid
expenses 12,654 7,304 Total current assets 566,521
600,708
Equity investments 6,473 6,463
Property, plant
and equipment Oil and natural gas properties 7,908,709
7,736,409 Other property, plant and equipment 141,047 60,533
8,049,756 7,796,942 Accumulated depletion and depreciation
(3,161,636 ) (1,342,741 ) Net property, plant and equipment
4,888,120 6,454,201
Other long-term assets Intangibles, net
1,538 8,336 Goodwill — 92,024 Derivative instruments 267,681
319,560 Other long-term assets 119,715 157,042
Total assets $ 5,850,048 $ 7,638,334
LIABILITIES AND EQUITY Current liabilities Accounts
payable $ 63,921 $ 129,270 Current portion of long-term debt 603
105,000 Derivative instruments 5,289 5,457 Distributions payable
733 733 Current portion of asset retirement obligation 2,390 4,948
Revenue and royalties payable 42,454 40,452 Wages and salaries
payable 22,264 22,322 Accrued interest payable 42,989 20,672
Production and property taxes payable 30,838 25,207 Other current
liabilities 6,644 7,495 Total current liabilities
218,125 361,556 Credit facility 1,253,000 2,089,500 Senior notes,
net 1,788,466 1,156,560 Other long-term debt 2,397 1,100
Total long-term debt 3,043,863 3,247,160 Deferred income
taxes 2,269 2,575 Asset retirement obligation 247,317 233,463
Derivative instruments 1,421 2,269 Other long-term liabilities
24,615 25,135 Total liabilities 3,537,610 3,872,158
Equity Series A preferred units, 8.0 million units
issued and outstanding at each of September 30, 2015 and December
31, 2014 193,215 193,215 Series B preferred units, 48.0 million and
0 units issued and outstanding at September 30, 2015 and December
31, 2014, respectively 347,454 — Common units, 211.8 million and
210.9 million units issued and outstanding at September 30, 2015
and December 31, 2014, respectively 1,765,689 3,566,468 Accumulated
other comprehensive loss (576 ) (392 ) Total partners' equity
2,305,782 3,759,291 Noncontrolling interest 6,656 6,885
Total equity 2,312,438 3,766,176
Total liabilities and equity $ 5,850,048 $ 7,638,334
Breitburn Energy Partners LP and
Subsidiaries Unaudited Consolidated Statements of
Operations Three Months Ended
Nine Months Ended September 30,
September 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 $ 153,325 $
216,146 $ 505,584 $ 658,753 Gain (loss) on commodity derivative
instruments, net 253,012 146,171 296,772 (21,057 ) Other revenue,
net 5,922 1,585 18,895 4,240 Total
revenues and other income items 412,259 363,902 821,251 641,936
Operating costs and expenses Operating costs 115,135
82,904 348,950 248,161 Depletion, depreciation and amortization
117,464 72,671 336,735 204,417 Impairments of oil and natural gas
properties 1,440,167 29,434 1,499,280 29,434 Impairments of
goodwill — — 95,947 — General and administrative expenses 23,276
18,737 78,400 53,886 Restructuring costs (278 ) — 6,413 — (Gain)
loss on sale of assets (7,459 ) (63 ) (7,322 ) 357 Total
operating costs and expenses 1,688,305 203,683
2,358,403 536,255
Operating (loss)
income (1,276,046 ) 160,219 (1,537,152 ) 105,681
Interest expense, net of capitalized interest 50,919 29,494 151,988
90,360 Loss on interest rate swaps 996 — 3,411 — Other expenses
(income), net (137 ) (450 ) (579 ) (1,223 ) Total other expense
51,778 29,044 154,820 89,137
(Loss) income before taxes (1,327,824 ) 131,175 (1,691,972 )
16,544 Income tax expense 14 532 365
384
Net (loss) income (1,327,838 ) 130,643
(1,692,337 ) 16,160 Less: Net income attributable to
noncontrolling interest 91 — 124 —
Net (loss) income attributable to the partnership
(1,327,929 ) 130,643 (1,692,461 ) 16,160 Less:
Distributions to Series A preferred unitholders 4,125 4,125 12,375
5,958 Less: Non-cash distributions to Series B preferred
unitholders 7,145 — 13,553 — Less: Net (loss) income attributable
to participating units (31,662 ) 1,868 (40,612 ) 40
Net (loss) income attributable to common unitholders
$ (1,307,537 ) $ 124,650 $ (1,677,777 ) $ 10,162
Basic net (loss) income per common unit $ (6.17 ) $ 1.03
$ (7.94 ) $ 0.08 Diluted net (loss) income per common
unit $ (6.17 ) $ 1.03 $ (7.94 ) $ 0.08
Weighted average number of units used to calculate basic and
diluted net (loss) income per unit (in thousands): Basic
211,766 120,473 211,369 119,806 Diluted 211,766 121,250 211,369
120,544
Breitburn Energy Partners LP and
Subsidiaries Unaudited Consolidated Statements of
Comprehensive (Loss) Income
Three Months EndedSeptember
30,
Nine Months EndedSeptember
30,
Thousands of dollars, except per unit amounts 2015
2014 2015 2014
Net (loss) income $ (1,327,838 ) $ 130,643 $ (1,692,337 ) $
16,160
Other comprehensive loss, net of tax: Change
in fair value of available-for-sale securities (a) (463 ) —
(537 ) — Total other comprehensive loss (463 ) — (537 ) —
Total comprehensive (loss) income (1,328,301 )
130,643 (1,692,874 ) 16,160 Less: Comprehensive loss
attributable to noncontrolling interest (303 ) — (229 ) —
Comprehensive (loss) income attributable to the
partnership $ (1,327,998 ) $ 130,643 $ (1,692,645 ) $
16,160 (a) Net of income tax benefit of $0.4 million and
$0.3 million for the three months and nine months ended September
30, 2015.
Breitburn Energy Partners LP and
Subsidiaries Unaudited Consolidated Statements of Cash
Flows Nine Months Ended September
30, Thousands of dollars 2015
2014 Cash flows from operating activities Net
(loss) income $ (1,692,337 ) $ 16,160 Adjustments to reconcile to
cash flow from operating activities: Depletion, depreciation and
amortization 336,735 204,417 Impairment of oil and natural gas
properties 1,499,280 29,434 Impairment of goodwill 95,947 —
Unit-based compensation expense 20,714 18,440 (Gain) loss on
derivative instruments (293,361 ) 21,057 Derivative instrument
settlement receipts (payments) 351,518 (34,228 ) Income from equity
affiliates, net (10 ) 90 Deferred income taxes (306 ) 153 (Gain)
loss on sale of assets (7,322 ) 357 Other 14,348 5,172 Changes in
net assets and liabilities
Accounts receivable and other assets 22,251 (3,345 ) Inventory 356
(528 ) Net change in related party receivables and payables 393
1,095 Accounts payable and other liabilities 2,978 36,642
Net cash provided by operating activities 351,184
294,916
Cash flows from investing activities Property
acquisitions (17,160 ) (6,422 ) Capital expenditures (226,718 )
(293,275 ) Proceeds from sale of assets 9,441 366 Proceeds from
sale of available-for-sale securities 3,631 — Purchases of
available-for-sale securities (3,803 ) — Other (853 ) (9,242 ) Net
cash used in investing activities (235,462 ) (308,573 )
Cash
flows from financing activities
Proceeds from issuance of preferred units,
net
337,895 193,215
Proceeds from issuance of common units,
net
4,768 25,917 Distributions to preferred unitholders (12,375 )
(5,225 ) Distributions to common unitholders (108,283 ) (181,430 )
Proceeds from issuance of long-term debt, net 1,203,400 693,000
Repayments of long-term debt (1,512,500 ) (707,000 ) Change in bank
overdraft (39 ) (2,417 ) Debt issuance costs (29,125 ) (1,634 ) Net
cash (used in) provided by financing activities (116,259 ) 14,426
(Decrease) increase in cash (537 ) 769
Cash
beginning of period 12,628 2,458
Cash end of
period $ 12,091 $ 3,227
View source
version on businesswire.com: http://www.businesswire.com/news/home/20151105005699/en/
Breitburn Energy Partners LPAntonio D'AmicoVice President,
Investor Relations & Government AffairsorJessica TangInvestor
Relations Manager213-225-0390