Breitburn Energy Partners LP (NASDAQ:BBEP) today announced
financial and operating results for the fourth quarter and full
year 2015 as well as operational guidance for its expected
performance in 2016.
Key Highlights
- Annual production of 20.2 million Boe,
at high-end of guidance, with average daily production of 55,288
Boe/d for the year.
- Adjusted EBITDA, a non-GAAP financial
measure, increased to $169 million in 4Q15, 8.2% higher than 3Q15,
despite lower realized oil and NGL prices. 2015 Adjusted EBITDA of
$636.8 million (including acquisition and integration costs of
$12.6 million and restructuring costs of $5 million) was in line
with guidance.
- Pre-tax lease operating expenses were
$17.74/Boe in 4Q15, 10.5% lower than 3Q15 and 18.5% lower than
4Q14. 2015 pre-tax lease operating expenses were $19.02/Boe, at
low-end of guidance.
- G&A expenses, excluding acquisition
and integration costs and non-cash unit based compensation, were
$2.48/Boe in 4Q15, 9.4% lower than 3Q15 and the best quarter in
Breitburn’s history. 2015 G&A expenses, excluding acquisition
and integration costs and non-cash unit based compensation, were
$3.02/Boe, 13% lower than 2014.
- The estimated fair value of Breitburn’s
commodity hedge portfolio was approximately $666 million as of
December 31, 2015.
Management Commentary
Halbert S. Washburn, Breitburn’s Chief Executive Officer, said:
“We were very proactive last year in adapting to a volatile
commodity price environment. We had strong operating and financial
results, with production coming in at the high end of our guidance
and our capital, operating, and G&A costs performing in line
with or better than our guidance. We were also one of the first oil
and gas companies to raise significant capital last year, and
through our financing and cost cutting efforts, we were able to
reduce our bank borrowings by nearly $1 billion in 2015. In light
of the ongoing weakness in commodity prices, we are cutting our
2016 capital program by 60% to approximately $80 million, but
because of our quality, long-lived, low-decline assets we only
expect a 9% reduction to our 2016 production. With the continued
hard work of our experienced team, we believe we are
well-positioned to execute our operating plan successfully again
this year.”
Fourth Quarter 2015 Operating and
Financial Results Compared to Third Quarter 2015
- Total production was 5,106 MBoe in the
fourth quarter of 2015 compared to 5,008 MBoe in the third quarter
of 2015. Average daily production was 55.5 MBoe/day in the fourth
quarter of 2015 compared to 54.4 MBoe/day in the third quarter of
2015.
- Oil production increased to 2,795 MBbl
compared to 2,741 MBbl in the third quarter of 2015
- NGL production increased to 526 MBbl
compared to 485 MBbl in the third quarter of 2015
- Natural gas production increased to
10,712 MMcf compared to 10,689 MMcf in the third quarter of
2015
- Adjusted EBITDA was $169 million in the
fourth quarter of 2015 compared to $156.3 million in the third
quarter of 2015, an 8.2% increase. The increase was primarily due
to higher commodity derivative instrument settlement receipts,
lower operating costs, higher sales volume, and lower G&A
expenses, partially offset by lower oil, natural gas and NGL sales
revenue due to lower average realized commodity prices.
- Net loss attributable to common
unitholders was $902.3 million, or $4.25 per diluted common unit,
in the fourth quarter of 2015, which included non-cash impairment
charges of approximately $878.3 million, or $4.14 per common unit,
primarily related to the impact that further deterioration in
forecast future commodity prices had on our projected net revenues
for certain of our oil and gas properties, compared to net loss of
$1.3 billion, or $6.17 per diluted common unit, in the third
quarter of 2015, which included non-cash impairment charges of
approximately $1.4 billion, or $6.80 per unit.
- Oil, NGL and natural gas sales revenues
were $139.7 million in the fourth quarter of 2015 compared to
$153.3 million in the third quarter of 2015, primarily due to lower
realized oil and natural gas prices, partially offset by higher
sales volumes.
- Lease operating expenses, which include
district expenses, processing fees, and transportation costs but
exclude taxes, were $17.74 per Boe in the fourth quarter of 2015
compared to $19.83 per Boe in the third quarter of 2015. The
decrease was due to lower operating costs, lower workover expenses
and continued focus on lowering costs.
- General and administrative expenses,
excluding non-cash unit-based compensation costs, were $14.5
million in the fourth quarter of 2015 (including acquisition and
integration costs of $1.8 million) compared to $16.9 million in the
third quarter of 2015 (including acquisition and integration costs
of $3.2 million). The decrease was primarily due to lower
integration costs and lower employee related expenses.
- Gains on commodity derivative
instruments were $141.8 million in the fourth quarter of 2015
compared to gains of $253 million in the third quarter of 2015,
primarily due to increases in oil and natural gas futures prices
during the fourth quarter of 2015. Derivative instrument settlement
receipts were $144.1 million in the fourth quarter of 2015 compared
to receipts of $129 million in the third quarter of 2015, primarily
due to lower oil prices.
- NYMEX WTI oil spot prices averaged
$41.94 per Bbl and Brent oil spot prices averaged $43.56 per Bbl in
the fourth quarter of 2015 compared to $46.64 per Bbl and $50.41
per Bbl, respectively, in the third quarter of 2015. Henry Hub
natural gas spot prices averaged $2.12 per Mcf in the fourth
quarter of 2015 compared to $2.76 per Mcf in the third quarter of
2015.
- Average realized crude oil, NGL, and
natural gas prices, excluding the effects of commodity derivative
settlements, averaged $37.31 per Bbl, $13.03 per Bbl and $2.32 per
Mcf, respectively, in the fourth quarter of 2015 compared to $43.38
per Bbl, $12.44 per Bbl and $2.76 per Mcf, respectively, in the
third quarter of 2015.
- Oil, NGL and natural gas capital
expenditures were approximately $36 million in the fourth quarter
of 2015 compared to $46 million in the third quarter of 2015.
Full Year 2015 Results
- Total production was 20.2 million Boe
in 2015 compared to 14.1 million Boe in 2014. Production volumes
increased by 6.1 million Boe, or 43%, primarily due to production
from properties acquired in the QRE merger.
- Adjusted EBITDA was $636.8 million in
2015 (including acquisition and integration costs of $12.6 million
and restructuring costs of $5 million) compared to $473.8 million
in 2014. The increase reflects the full year effect of the QRE
merger, higher commodity derivative instrument settlement receipts
and lower operating costs, partially offset by lower oil, natural
gas and NGL sales revenue due to lower average realized commodity
prices.
- Net loss attributable to common
unitholders was $2.6 billion, or $12.39 per diluted common unit, in
2015, which included non-cash impairment charges of approximately
$2.4 billion, or $11.24 per common unit, compared to a net income
of $411.3 million, or $3.02 per diluted common unit, in 2014, which
included non-cash impairment charges of approximately $149 million,
or $1.11 per common unit.
- Total oil, NGL and natural gas sales
were $645.3 million in 2015, a decrease of 25% from 2014 primarily
due to lower commodity prices partially offset by higher volumes
from the full year effect of production from properties acquired in
the QRE merger.
- Lease operating expenses, which include
district expenses, processing fees, and transportation costs but
exclude taxes, were $383.8 million compared to $291.4 million in
2014, reflecting the full year effect of lease operating costs from
properties acquired in the QRE merger.
- General and administrative expenses,
excluding unit-based compensation related costs but including $12.6
million in acquisition and integration costs, were $73.5 million
compared to $63.6 million in 2014, which included $14 million in
acquisition and integration costs. The increase was primarily due
to higher payroll expense for additional personnel attributable to
the QRE merger.
- Gains on commodity derivative
instruments were $438.6 million in 2015 compared to gains of $566.5
million in 2014. Derivative instrument settlement receipts were
$500 million in 2015 compared to receipts of $27.8 million in 2014,
primarily due to lower oil prices.
- Average realized oil and NGL prices,
excluding the effect of commodity derivative instruments, for 2015,
were $44.46 per Bbl and $15.02 per Bbl, respectively, compared to
NYMEX WTI oil prices of $48.49 per barrel. Average realized natural
gas prices, excluding the effect of commodity derivative
instruments, were $2.67 per Mcf compared to Henry Hub prices of
$2.62 per Mcf.
Liquidity
As of February 25, 2016, we had approximately $1.2 billion in
borrowings outstanding under our credit facility. The borrowing
base at December 31, 2015 was $1.8 billion and is scheduled to be
redetermined in April 2016, at which time we expect it to be
significantly decreased. Although our lenders have the discretion
to redetermine the borrowing base below our current outstanding
borrowings, we do not expect that to occur in April 2016. If
commodity prices remain depressed or further decline, we expect our
borrowing base to be reduced again at the subsequent borrowing base
redetermination in October 2016, which could further impact and
limit our liquidity.
2015 Estimated Proved
Reserves
Total estimated proved reserves as of December 31, 2015, were
239.3 MMBoe compared to total estimated proved reserves of 315.3
MMBoe as of December 31, 2014. The standardized measure of
discounted future net cash flows related to our estimated proved
reserves was approximately $1.3 billion as of December 31, 2015,
compared to approximately $4.5 billion as of December 31, 2014. Of
the total estimated proved reserves, 54% were oil, 8% were NGLs and
38% were natural gas, and 80% were classified as proved developed.
Set forth below is a breakdown of Breitburn’s total estimated
proved reserves among its seven operating areas:
% Estimated Proved Operating
Area Reserves Midwest 21.5% Ark-La-Tex 19.6% Permian
Basin 18.7% Mid-Continent 13.5% Rockies 10.7% Southeast 8.5%
California 7.5%
The unweighted average first-day-of-the-month oil and natural
gas prices used to determine our total estimated proved reserves as
of December 31, 2015, were $50.28 per Bbl of oil for WTI NYMEX
and $2.59 per MMBtu of natural gas for Henry Hub.
2016 Operational Guidance (Excludes
Acquisitions, Divestitures or Financing
Transactions)
Breitburn’s 2016 Operational Guidance is subject to all of the
cautionary statements and limitations described below and therein
and under the caption “Cautionary Statement Regarding
Forward-Looking Information.” 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, and estimated future volumes
may be lower due to the impact of wells being shut-in or not being
repaired due to their being uneconomic at current or commodity
prices. 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 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. Breitburn’s
2016 Operational Guidance does not constitute any form of
guarantee, assurance or promise that the matters indicated will
actually be achieved; rather it 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)
2016 Operational
Guidance (1) Total Production (MBoe):
17,000 — 19,700 Oil Production (MBbls) 9,000 — 10,500 NGL
Production (MBbls) 1,750 — 1,950 Natural Gas Production (MMcfe)
37,500 — 43,500 Average Price Differential %:
WTI Oil Price Differential % 85.0% — 93.0% NGL Price Differential %
(of WTI) 30.0% — 50.0% Natural Gas Price Differential %
100.0% — 105.0%
Oil, NGL, and Natural Gas Sales Revenue
(2)
$330,000 — $430,000
Other Revenue (3)
$25,000 — $33,000
Lease Operating Expenses / Boe (4)
$18.00 — $20.00
Other Operating Expenses (5)
$16,000 — $18,000 Production / Property Taxes (% of Sales Revenue)
8.00% — 8.50%
G&A (Excluding Unit Based
Compensation) (6)
$56,000 — $60,000
Adjusted EBITDA (7)
$490,000 — $525,000
Cash Interest Expense (8)
$191,000 — $197,000
Preferred Equity Distributions (9)
$16,500
Capital Expenditures (10)
$80,000
(1) Breitburn’s 2016 Operational Guidance is based on
flat $30 per barrel WTI crude oil, $30 per barrel Brent crude oil
and $2.30 per Mcf natural gas prices and excludes acquisitions,
divestitures or financing transactions. Operating costs and capital
expenditures generally track commodity prices but they do not
increase or decrease as quickly as commodity prices. (2) Range
based on the low and high values of production and differentials as
set forth above. (3) Primarily consists of other revenues from the
East Texas Salt Water Disposal System and the Postle Field in OK.
(4) Pre-tax lease operating expenses include processing fees,
district expenses, and transportation costs. (5) Represents costs
related to the East Texas Salt Water Disposal System. (6) Excludes
approximately $10 million in long-term compensation and severance
payments paid in cash. (7) Assuming the high and low ranges of
production and LOE guidance (and the midpoint for the remaining
guidance components), Adjusted EBITDA is expected to range between
$490 million and $525 million, and is comprised of estimated net
loss (before non-cash compensation and non-cash distributions
paid-in-kind to holders of 8% Series B Preferred Units) between
($541) million (low end of Adjusted EBITDA) and ($500) million
(high end of Adjusted EBITDA), plus unrealized losses on commodity
derivative instruments of $385 million, plus DD&A of $433
million, plus interest expense between $191 million (high end of
Adjusted EBITDA) and $197 million (low end of Adjusted EBITDA),
plus preferred distributions to holders of 8.25% Series A Preferred
Units of $16.5 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 0.50%. (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% Series B Perpetual
Convertible Preferred Units will be paid in kind. (10) Capital
expenditures exclude information technology spending of $1.7
million and capitalized engineering of $4.3 million.
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 and distributable cash flow 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
December 31, 2015 and 2014, the three months ended September 30,
2015, and the full year results for 2015 and 2014:
Three Months Ended
Year Ended December 31,
September 30, December 31,
December 31, Thousands of dollars, except as
indicated 2015 2015 2014 2015
2014 Oil sales $ 108,024 $ 117,743 $
151,335 $ 504,035 $ 669,355 NGL sales 6,852 6,032 9,709 29,336
41,031 Natural gas sales 24,812 29,550 36,023 111,901 145,434
Gain on commodity derivative
instruments
141,842 253,012 587,590 438,614 566,533 Other revenues, net
5,934 5,922 3,376 24,829
7,616 Total revenues 287,464
412,259 788,033 1,108,715
1,429,969 Lease operating expenses (a) 90,563 99,318 90,768
383,827 291,395 Production and property taxes (b) 9,033
13,249 14,084 51,174
62,071 Total lease operating expenses 99,596
112,567 104,852 435,001
353,466 Purchases and other operating costs 2,119 367
299 3,056 725 Salt water disposal costs 2,408 4,205 2,168 14,687
2,168 Change in inventory 2,116 (2,004 )
201 2,445 (678 ) Total operating costs
106,239 115,135 107,520
455,189 355,681 Lease operating expenses, pre
taxes, per Boe (a) $ 17.74 $ 19.83 $ 21.77 $ 19.02 $ 20.65
Production and property taxes per Boe (b) 1.77
2.65 3.38 2.54 4.40 Total
lease operating expenses per Boe 19.51 22.48
25.15 21.56 25.05 General
and administrative expenses (excluding non-cash unit-based
compensation) 14,508 16,916
28,116 73,537 63,562 Net (loss) income
attributable to the partnership (890,878 ) (1,327,929 ) 405,173
(2,583,339 ) 421,333 Basic net (loss) income per unit $
(4.25 ) $ (6.17 ) $ 2.28 $ (12.39 ) $ 3.04 Diluted net (loss)
income per unit $ (4.25 ) $ (6.17 ) $ 2.27 $ (12.39 ) $ 3.02
Total production (MBoe) (c) 5,106 5,008 4,170 20,180 14,114 Oil
(MBbl) 2,795 2,741 2,327 11,248 7,931 NGLs (MBbl) 526 485 368 1,953
1,157 Natural gas (MMcf) 10,712 10,689 8,847 41,876 30,159 Average
daily production (Boe/d) 55,500 54,435
45,313 55,288 38,670 Sales
volumes (MBoe) (d) 5,151 4,980
4,022 20,219 13,956 Average realized
sales price (per Boe) (e) (f) $ 26.72 $ 30.78 $ 48.96 $ 31.80 $
61.30 Oil (per Bbl) (e) (f) 37.31 43.38 69.36 44.46 86.08 NGLs (per
Bbl) (e) 13.03 12.44 26.38 15.02 35.46 Natural gas (per Mcf) (e) $
2.32 $ 2.76 $ 4.07 $ 2.67 $ 4.82 (a) Includes
district expenses, processing fees, and transportation expenses.
(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 2,841 MBbl, 2,713 MBbl and 2,180 MBbl for the three
months ended December 31, 2015, September 30, 2015 and December 31,
2014, respectively, and 11,287 MBbl and 7,773 MBbl for the twelve
months ended December 31, 2015 and 2014, respectively. (e) Excludes
the effect of commodity derivative settlements. (f) Includes oil
purchases.
Non-GAAP Financial
Measures
This press release, including the financial tables and other
supplemental information and 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
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.
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
(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
Year Ended December 31,
September 30, December 31,
December 31, Thousands of dollars, except as
indicated 2015 2015 2014 2015
2014 Reconciliation of net income
(loss) to Adjusted EBITDA: Net (loss) income attributable to
the partnership $ (890,878 ) $ (1,327,929 ) $ 405,173 $ (2,583,339
) $ 421,333
Gain on commodity derivative
instruments
(141,842 ) (253,012 ) (587,590 ) (438,614 ) (566,533 ) Commodity
derivative instrument settlements (a) (b) 144,083 128,969 62,053
499,985 27,825 Depletion, depreciation and amortization expense
123,312 117,464 87,292 460,047 291,709 Impairment of oil and
natural gas properties 878,335 1,440,167 119,566 2,377,615 149,000
Impairment of goodwill — — — 95,947 — Interest expense and other
financing costs 50,319 51,915 36,110 205,718 126,470 (Gain) loss on
sale of assets (1,542 ) (7,459 ) 306 (8,864 ) 663 Income tax
expense (benefit) 1,162 14 (457 ) 1,527 (73 ) Unit-based
compensation expense (c) 6,091 6,360 4,947 25,462 23,387
Restructuring costs - unit-based compensation —
(192 ) — 1,343 —
Adjusted EBITDA 169,040 156,297 127,400 636,827 473,781
Less: Maintenance capital (d) $ 51,000 $ 52,000 $ 43,714 $ 200,000
$ 133,079 Cash interest expense 48,374 48,654 35,651 184,007
120,470 Distributions to preferred unitholders 4,125
4,125 4,125 16,500
10,083
Distributable cash flow available to common
unitholders $ 65,541 $ 51,518 $ 43,910 $
236,320 $ 210,149 Distributable cash flow
available per common unit (e) (f) $ 0.296 $ 0.237 $ 0.207 $ 1.086 $
1.431
Common unit distribution coverage (f)
n/a
1.90x
0.83x
3.26x
0.81x
Reconciliation of net cash flows from operating
activities to Adjusted EBITDA: Net cash provided by
operating activities $ 85,521 $ 136,239 $ 62,839 $ 436,705 $
357,755 Increase (decrease) in assets net of liabilities relating
to operating activities 35,665 (29,063 ) 29,199 16,369 (4,057 )
Interest expense (g) 48,364 48,562 35,563 183,852 120,143 Income
from equity affiliates, net 94 163 (88 ) 104 (178 ) Noncontrolling
interest (202 ) (91 ) 17 (326 ) 17 Income taxes (413 ) 488 (130 )
258 101 Gain on marketable securities 11 —
— (135 ) —
Adjusted
EBITDA $ 169,040 $ 156,297 $ 127,400 $
636,827 $ 473,781
(a)
Excludes premiums paid at contract
inception related to those derivative contracts that settled during
the applicable periods of:
$
1,682
$
1,681
$
2,141
$
6,672
$
8,494
(b)
Includes net cash settlements on
derivative instruments for:
- Oil settlements received:
123,492
112,437
55,975
431,073
18,230
- Natural gas settlements received:
20,592
16,532
6,078
68,913
9,595
(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)
Based on common units outstanding
(including outstanding LTIP grants) at each distribution record
date within the periods.
(f)
Third quarter 2014 includes the effect of
the offering of 14 million common units in October 2014. Fourth
quarter 2014 includes only 41 days of QR Energy operating results,
$11.7 million of acquisition and integration costs, and the effect
of 71.5 million common units issued in connection with the QR
Energy merger.
(g)
Excludes amortization of debt issuance
costs and amortization of senior note discount/premium.
Summary of Commodity Derivative
Instruments
The table below summarizes Breitburn’s commodity derivative
hedge portfolio as of February 25, 2016. Please refer to the
Commodity Price Protection Portfolio at breitburn.com for
additional information related to our hedge portfolio.
Year 2016
2017 2018
2019 Oil Positions: Fixed Price
Swaps - NYMEX WTI Volume (Bbl/d) 17,504 14,519 1,493 1,000 Average
Price ($/Bbl) $ 83.62 $ 82.81 $ 64.02 $ 56.35 Fixed Price Swaps -
ICE Brent Volume (Bbl/d) 4,300 298 — — Average Price ($/Bbl) $
95.17 $ 97.50 $ — $ — Collars - NYMEX WTI Volume (Bbl/d) 1,500 — —
— Average Floor Price ($/Bbl) $ 80.00 $ — $ — $ — Average Ceiling
Price ($/Bbl) $ 102.00 $ — $ — $ — Collars - ICE Brent Volume
(Bbl/d) 500 — — — Average Floor Price ($/Bbl) $ 90.00 $ — $ — $ —
Average Ceiling Price ($/Bbl) $ 101.25 $ — $ — $ — Puts - NYMEX WTI
Volume (Bbl/d) 1,000 — — — Average Price ($/Bbl) $ 90.00 $ — $ — $
— Total: Volume (Bbl/d) 24,804 14,817 1,493 1,000 Average Price
($/Bbl) $ 85.79 $ 83.11 $ 64.02 $ 56.35
Gas
Positions: Fixed Price Swaps - MichCon City-Gate Volume
(MMBtu/d) 29,000 24,000 17,500 10,000 Average Price ($/MMBtu) $
3.91 $ 3.71 $ 3.10 $ 3.15 Fixed Price Swaps - Henry Hub Volume
(MMBtu/d) 42,050 21,016 2,870 — Average Price ($/MMBtu) $ 4.02 $
4.29 $ 3.74 $ — Collars - Henry Hub Volume (MMBtu/d) 630 595 — —
Average Floor Price ($/MMBtu) $ 4.00 $ 4.00 $ — $ — Average Ceiling
Price ($/MMBtu) $ 5.55 $ 6.15 $ — $ — Puts - Henry Hub Volume
(MMBtu/d) 11,350 10,445 — — Average Price ($/MMBtu) $ 4.00 $ 4.00 $
— $ — Deferred Premium ($/MMBtu) $ 0.66 (a) $ 0.69 (b) $ — $ —
Total: Volume (MMBtu/d) 83,030 56,056 20,370 10,000 Average Price
($/MMBtu) $ 3.98 $ 3.98 $ 3.19 $ 3.15 (a) Deferred
premiums of $0.66 apply to 11,350 MMBtu/d of the 2016 volume. (b)
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 in 2016 and beyond were as follows:
Year Thousands of dollars
2016 2017
2018 2019 Oil $ 7,438 $ 734 $ —
$ — Natural gas 952 — — —
Other Information
Breitburn will host a conference call Friday, February 26, 2016,
at 9:00 a.m. (ET) to discuss Breitburn’s fourth quarter and full
year 2015 results. The conference call may be accessed by calling
888-461-2024 (international callers dial 719-325-2494) or via
webcast at http://ir.breitburn.com/.
An archived edition of the conference call will also be available
through March 4th by calling 877-870-5176 (international callers
dial 858-384-5517) and entering replay PIN 919731 or by visiting
http://ir.breitburn.com/.
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 Ark-La-Tex; the
Midwest; the Permian Basin; the Mid-Continent; the Rockies; the
Southeast; 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,” “forecast” 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
Consolidated Balance Sheets
December 31, December 31,
Thousands of dollars 2015 2014 ASSETS
Current assets Cash $ 10,464 $ 12,628 Accounts and other
receivables, net 128,589 166,436 Derivative instruments 439,627
408,151 Related party receivables 2,274 2,462 Inventory 926 3,727
Prepaid expenses 6,447 7,304
Total
current assets 588,327 600,708
Equity investments 6,567
6,463
Property, plant and equipment Oil and natural gas
properties 7,898,117 7,736,409 Other property, plant and equipment
188,795 60,533 8,086,912 7,796,942
Accumulated depletion and depreciation (4,154,030 )
(1,342,741 ) Net property, plant and equipment 3,932,882 6,454,201
Other long-term assets Goodwill — 92,024 Derivative
instruments 226,764 319,560 Other long-term assets 117,872 165,378
Total assets $ 4,872,412 $ 7,638,334
LIABILITIES AND EQUITY Current liabilities Accounts
payable $ 50,412 $ 129,270 Current portion of long-term debt
154,000 105,000 Derivative instruments 4,462 5,457 Distributions
payable 733 733 Current portion of asset retirement obligation
2,341 4,948 Revenue and royalties payable 35,462 40,452 Wages and
salaries payable 21,654 22,322 Accrued interest payable 19,517
20,672 Production and property taxes payable 24,292 25,207 Other
current liabilities 5,133 7,495 Total
current liabilities 318,006 361,556 Credit facility 1,075,000
2,089,500 Senior notes, net 1,789,219 1,156,560 Other long-term
debt 2,938 1,100 Total long-term debt
2,867,157 3,247,160 Deferred income taxes 3,844 2,575 Asset
retirement obligation 252,037 233,463 Derivative instruments 255
2,269 Other long-term liabilities 25,218
25,135 Total liabilities 3,466,517 3,872,158
Equity
Series A preferred units, 8.0 million units issued and outstanding
at December 31, 2015 and December 31, 2014 193,215 193,215 Series B
preferred units, 48.8 million and 0 units issued and outstanding at
December 31, 2015 and December 31, 2014, respectively 353,471 —
Common units, 213.5 million and 210.9 million units issued and
outstanding at December 31, 2015 and December 31, 2014,
respectively 852,114 3,566,468 Accumulated other comprehensive loss
(229 ) (392 ) Total partners' equity 1,398,571
3,759,291 Noncontrolling interest 7,324 6,885
Total equity 1,405,895 3,766,176
Total liabilities and equity $ 4,872,412 $
7,638,334
Breitburn Energy Partners LP and
Subsidiaries Consolidated Statements of Operations
Three Months Ended
Year Ended December 31, December 31,
Thousands of dollars, except per unit amounts 2015
2014 2015
2014 Revenues and other income items Oil,
natural gas and natural gas liquid sales $ 139,688 $ 197,067 $
645,272 $ 855,820 Gain on commodity derivative instruments, net
141,842 587,590 438,614 566,533 Other revenue, net 5,934
3,376 24,829 7,616
Total revenues and other income items 287,464 788,033 1,108,715
1,429,969
Operating costs and expenses Operating costs
106,239 107,520 455,189 355,681 Depletion, depreciation and
amortization 123,312 87,292 460,047 291,709 Impairment of oil and
natural gas properties 878,335 119,566 2,377,615 149,000 Impairment
of goodwill — — 95,947 — General and administrative expenses 20,599
33,063 98,999 86,949 Restructuring costs (49 ) — 6,364 — (Gain)
loss on sale of assets (1,542 ) 306
(8,864 ) 663 Total operating costs and expenses
1,126,894 347,747 3,485,297
884,002
Operating (loss) income
(839,430 ) 440,286 (2,376,582 ) 545,967 Interest expense, net of
capitalized interest 51,039 36,600 203,027 126,960 Gain on interest
rate swaps (720 ) (490 ) 2,691 (490 ) Other income, net (235
) (523 ) (814 ) (1,746 ) Total other expense
50,084 35,587 204,904
124,724
(Loss) income before taxes (889,514 )
404,699 (2,581,486 ) 421,243 Income tax expense (benefit)
1,162 (457 ) 1,527 (73 )
Net
(loss) income (890,676 ) 405,156 (2,583,013 ) 421,316 Less: Net
income (loss) attributable to noncontrolling interest 202
(17 ) 326 (17 )
Net (loss)
income attributable to the partnership (890,878 )
405,173 (2,583,339 ) 421,333 Less:
Distributions to Series A preferred unitholders 4,125 4,125 16,500
10,083 Less: Non-cash distributions to Series B preferred
unitholders 7,264 — 20,817 — Less: Net income (loss) attributable
to participating units — 3,927 — 5,348 Less: Distributions on
participating units in excess of earnings — —
1,731 —
Net (loss) income
used to calculate basic and diluted net (loss) income per unit
$ (902,267 ) $ 397,121 $ (2,622,387 ) $ 405,902
Basic net (loss) income per unit $ (4.25 ) $ 2.28 $
(12.39 ) $ 3.04 Diluted net (loss) income per unit $ (4.25 )
$ 2.27 $ (12.39 ) $ 3.02
Breitburn
Energy Partners LP and Subsidiaries Consolidated Statements
of Comprehensive Income Year
Ended December 31, Thousands of dollars, except per unit
amounts 2015 2014 Net
(loss) income $ (2,583,013 ) $ 421,316
Other
comprehensive (loss) income, net of tax: Change in fair value
of available-for-sale securities (a) (402 ) (189 ) Pension and
post-retirement benefit actuarial gain (loss) (b) 677
(473 ) Total other comprehensive income (loss), net of tax
275 (662 )
Total comprehensive (loss)
income (2,582,738 ) 420,654 Less:
Comprehensive income (loss) attributable to noncontrolling interest
438 (287 )
Comprehensive (loss) income
attributable to the partnership $ (2,583,176 ) $ 420,941
(a) Net of income taxes of $0.3 million and $0.1
million for the years ended December 31, 2015 and 2014,
respectively. (b) Net of income tax (benefit) expense of $(0.1)
million and $0.2 million for the years ended December 31, 2015 and
2014, respectively.
Breitburn Energy Partners LP
and Subsidiaries Consolidated Statements of Cash Flows
Year Ended December 31,
Thousands of dollars 2015
2014 Cash flows from operating activities Net
(loss) income $ (2,583,013 ) $ 421,316 Adjustments to reconcile net
(loss) income to cash flow from operating activities: Depletion,
depreciation and amortization 460,047 291,709 Impairment of oil and
natural gas properties 2,377,615 149,000 Impairment of goodwill
95,947 — Unit-based compensation expense 26,805 23,387 Gain on
derivative instruments (435,923 ) (567,024 ) Derivative instrument
settlement receipts 494,234 26,806 Income from equity affiliates,
net (104 ) 178 Deferred income taxes 1,269 (174 ) (Gain) loss on
sale of assets (8,864 ) 663 Other 16,142 6,204 Changes in assets
and liabilities: Accounts receivable and other assets 35,367 41,754
Inventory 2,801 163 Net change in related party receivables and
payables 188 142 Accounts payable and other liabilities
(45,806 ) (36,369 ) Net cash provided by operating
activities 436,705 357,755
Cash
flows from investing activities Property acquisitions (18,201 )
(401,465 ) Capital expenditures (269,350 ) (417,755 ) Other (853 )
(18,283 ) Proceeds from sale of assets 14,547 499 Proceeds from
sale of available-for-sale securities 3,875 — Purchases of
available-for-sale securities (4,021 ) — Net
cash used in investing activities (274,003 ) (837,004
)
Cash flows from financing activities Proceeds from
issuance of preferred units, net 337,238 193,215 Proceeds from
issuance of common units, net 3,008 277,613 Distributions to
preferred unitholders (16,502 ) (9,350 ) Distributions to common
unitholders (126,188 ) (264,585 ) Proceeds from issuance of
long-term debt, net 1,378,338 2,457,600 Repayments of long-term
debt (1,711,500 ) (1,785,000 ) Senior note redemption — (352,531 )
Change in book overdraft 11 (2,434 ) Debt issuance costs
(29,271 ) (25,109 ) Net cash (used in) provided by financing
activities (164,866 ) 489,419
(Decrease)
increase in cash (2,164 ) 10,170
Cash beginning of
period 12,628 2,458
Cash end of
period $ 10,464 $ 12,628
View source
version on businesswire.com: http://www.businesswire.com/news/home/20160226005193/en/
Breitburn Energy Partners LPAntonio D’AmicoVice President,
Investor Relations & Government AffairsorJessica TangInvestor
Relations Manager(213) 225-0390