Eagle Rock Energy Partners, L.P. ("Eagle Rock" or the
"Partnership") (Nasdaq:EROC) today announced its unaudited
financial results for the full year 2014 and three months ended
December 31, 2014.
Fourth Quarter 2014 Highlights
- Distributable cash flow per unit increased 17% over third
quarter 2014 to $0.12/unit, equivalent to $17.9 million
- Announced a distribution of $0.07/unit for the fourth quarter,
or $0.28/unit annualized
- Distribution coverage of 1.7x distributable cash flow for the
fourth quarter
- Average daily production of 75.4 MMcfe/d in the fourth quarter
compared to 75.1 MMcfe/d in the third quarter 2014
- Adjusted EBITDA of $34.5 million for the fourth quarter
compared to $35.4 million for the third quarter 2014, as lower
realized prices were partially offset by higher production volumes,
lower operating costs and lower G&A
- Total liquidity of $268 million at year-end, including the
market value of the Regency Energy Partners, L.P. ("Regency")
common units owned by the Partnership
- Leverage ratio of 2.2x as of December 31, 2014
Joseph A. Mills, the Partnership's Chairman and Chief Executive
Officer, stated, "2014 was a transformational year for Eagle Rock.
We successfully closed the sale of our Midstream business to
Regency and embarked on our new path as a pure-play upstream master
limited partnership. The current low commodity price
environment presents opportunities for Eagle Rock as we look to
grow the Partnership. Our strong hedge portfolio, coupled
with our ample liquidity and low leverage ratio, positions the
Partnership in 2015 to make accretive acquisitions, reduce the
overall production decline rate and grow distributable cash
flow."
Fourth Quarter 2014 Financial and Operating
Results
Significant results from continuing operations for the fourth
quarter of 2014:
- Adjusted EBITDA of $34.5 million, compared to $35.4 million for
third quarter 2014, as lower commodity prices were partially offset
by higher production, lower operating costs and lower G&A.
- Distributable Cash Flow of $17.9 million or $0.12/unit, a 17%
increase as compared to third quarter 2014 distributable cash flow
per unit.
- Net Loss of $344.6 million, driven largely by impairment
charges primarily related to the impact of lower commodity prices
on the Partnership's oil and gas reserves, mainly in the Golden
Trend, Anadarko and Big Escambia Creek areas.
- Participated in 7 gross (0.2 net) non-operated wells in the
Mid-Continent region and drilled and completed 1 gross (0.6 net)
operated well in the Alabama region. Additionally, conducted
1 gross (1.0 net) workover and 1 gross (0.04 net)
recompletion.
- Total production was 6.94 Bcfe, compared to 6.90 Bcfe in third
quarter 2014. Average daily production was 75.4 MMcfe/d, compared
to 75.1 MMcfe/d in third quarter 2014.
- Oil production increased 5% quarter over quarter from 338 MBbl
to 357 MBbl
- NGL production increased quarter over quarter from 297 MBbl to
298 MBbl
- Natural gas production decreased 3% quarter over quarter from
3.09 Bcf to 3.01 Bcf
- The overall increase in production volumes was primarily due to
strong performance from four non-operated (Briar Unit) wells in the
prolific horizontal Woodford "SCOOP" play, and one operated well
completed in the Alabama region
- Product revenue of $43.1 million, down 20% compared to $53.6
million for third quarter 2014, due to lower commodity prices
partially offset by higher production volumes.
- Realized commodity derivative gains of $8.7 million, compared
to $1.3 million for third quarter 2014, due to lower commodity
prices.
- Cash Distributions of $4.0 million received on the Regency
common units held by the Partnership.
- Operating expenses, including taxes, of $12.9 million, 7% lower
than third quarter 2014, primarily due to lower estimated severance
taxes resulting from decreased sales revenue.
- General and administrative expenses of $8.5 million (excluding
amortization of expenses pursuant to the Long-Term Incentive Plan),
down 9% from third quarter 2014.
- Operating income, excluding an impairment charge of $378.6
million, increased to $92.5 million as compared to operating
income, excluding an impairment charge of $17.3 million, of $32.8
million for third quarter 2014, primarily due to unrealized gains
on commodity derivatives.
- Maintenance capital expenditures of $14.6 million as compared
to $14.5 million spent in the third quarter 2014.
Full Year 2014 Financial and Operating
Results
Significant results from continuing operations for full year
2014:
- Adjusted EBITDA of $120.9 million, compared to $119.8 million
attributable to the Upstream business for full year 2013.
- Distributable Cash Flow of $42.4 million, compared to $47.8
million attributable to the Upstream business for full year
2013.
- Net Loss of $139.9 million, driven largely by impairment
charges primarily related to the impact of lower commodity prices
on the Partnership's oil and gas reserves, mainly in the Golden
Trend, Anadarko and Big Escambia Creek areas.
- Drilled and completed 10 gross (8.6 net) operated wells and
participated in 15 gross (1.7 net) non-operated wells in the
Mid-Continent region, and drilled and completed 2 gross (1.3 net)
operated wells in the Alabama region. Additionally, conducted
15 gross (12.6 net) workovers and 7 gross (4.7 net)
recompletions.
- Total production was 26.8 Bcfe, compared to 27.1 Bcfe for full
year 2013. Average daily production was 73.5 MMcfe/d, compared to
74.2 MMcfe/d for full year 2013.
- Oil production increased 7% year over year from 1.2 MMBbl to
1.3 MMBbl
- NGL production was flat year over year at 1.2 MMBbl
- Natural gas production decreased 6% year over year from 12.8
Bcf to 12.0 Bcf
- Overall production was impacted by severe weather in early 2014
and third party plant and pipeline curtailments in our Permian and
Mid-Continent operations in Q2 and Q4.
- NGL and gas production were impacted by third party operational
interference on two wells in the Mid-Continent region and delays in
timing of well completions in Alabama and the Mid-Continent.
- Oil production increased primarily due to strong results from
four non-operated (Briar Unit) wells completed in the prolific
horizontal Woodford "SCOOP" play in Q3.
- Product revenue of $203.8 million, compared to $200.6 million
for full year 2013, due to higher gas prices partially offset by
lower gas production volumes, and lower crude prices partially
offset by higher crude production volumes.
- Realized commodity derivative gains of $4.7 million, compared
to $15.6 million for full year 2013.
- Cash Distributions of $8.0 million received on the Regency
units held by the Partnership.
- Operating expenses, including taxes, of $56.6 million, 4%
higher than full year 2013, primarily due to higher operations and
maintenance costs.
- General and administrative expenses of $39.0 million (excluding
amortization of expenses pursuant to the Long-Term Incentive Plan),
down 9% from full year 2013, primarily due to the divestment of the
Partnership's former midstream business.
- Operating income, excluding an impairment charge of $395.9
million, increased to $108.8 million as compared to the operating
income, excluding an impairment charge of $214.3 million, of $0.4
million for full year 2013, primarily due to unrealized gains on
commodity derivatives.
- Maintenance capital expenditures of $58.5 million, an increase
of $12.3 million as compared to $46.2 million spent for the full
year 2013, due primarily to the addition of more properties, higher
decline rates from the SCOOP drilling program and specific
maintenance projects at the Partnership's Big Escambia Creek
facility.
Year-End Proved Reserves
Based on SEC pricing, proved reserves at year-end 2014 were
estimated to be 318.2 Bcfe, a decrease of 8% from year-end
2013. Total production for 2014 was 26.8 Bcfe, or 73.5
MMcfe/d, a decrease of 0.9% from total production in 2013. The
Partnership's extensions and discoveries in 2014 were 42.8 Bcfe,
which represents a production replacement rate of 160%. Total
2014 year-end reserves were lower as compared to 2013 due to, among
other things, downward adjustments to the future projections on
certain developed and undeveloped proved reserve cases primarily
associated with our Golden Trend field and higher operating cost
assumptions in certain areas. As of December 31, 2014,
approximately 79% of the Partnership's total proved reserves were
classified as proved developed.
Regency Unit Sale and Eagle Rock Common Unit Repurchase
Program
As of February 23, 2015, the Partnership had sold approximately
4.1 million Regency units received as part of the consideration for
the Midstream Business Contribution, and proceeds were
approximately $104 million. These proceeds were used to fund the
Partnership's common unit repurchase program, pay down debt and for
general corporate purposes. Eagle Rock may continue to sell
the approximately 4.1 million remaining Regency common units in
order to further strengthen liquidity.
Pursuant to its previously announced common unit repurchase
program, as of February 23, 2015 the Partnership had repurchased
approximately 8.6 million common units for a total consideration of
approximately $22 million. These repurchase amounts are not
indicative of the Partnership's go-forward repurchasing plan, and
any future repurchases will be at management's discretion. The
repurchase program does not obligate the Partnership to acquire
any, or any specific number of, units and may be discontinued at
any time.
Capitalization and Liquidity Update
As of December 31, 2014, the Partnership's total liquidity was
$268.5 million. The Partnership's borrowing base under its
senior secured credit facility totaled $320 million, and based on
outstanding borrowings, the Partnership had approximately $107
million of availability under its senior secured credit
facility. As of December 31, 2014 the market value of the 6.7
million remaining Regency units held by the Partnership was $159.7
million. The Partnership's cash balance at the end of the
fourth quarter was $1.3 million. As of February 23, 2015, the
Partnership's total liquidity was approximately $233 million,
comprised of approximately $134 million of availability under its
senior secured credit facility and approximately 4.1 million
Regency units valued at $99 million.
As of December 31, 2014, the Partnership had 152.2 million
common units outstanding eligible to receive the distribution,
including 2.1 million unvested restricted common units issued under
the Partnership's Amended and Restated Long-Term Incentive
Plan. The Partnership had 150.9 million total common units
outstanding eligible to receive the distribution as of February 23,
2015, including 1.9 million unvested restricted common units issued
under its Amended and Restated Long-Term Incentive Plan.
First Quarter and Full Year 2015 Guidance
During the first quarter of 2015, the Partnership plans to spend
approximately $27 million on capital expenditures and expects $14
million to be categorized as maintenance capital expenditures and
$13 million to be categorized as growth capital
expenditures. Subject to results from the Partnership's
drilling program, the Partnership expects to average between 73 and
75 MMcfe/d during first quarter 2015.
For full year 2015, the Partnership plans to spend approximately
$72 million on capital expenditures, and expects $54 million to be
categorized as maintenance capital expenditures and $18 million to
be categorized as growth capital expenditures. This is a
reduction of 46% as compared to 2014 total capital expenditures of
$134 million. Subject to results from the Partnership's
drilling program, the Partnership expects to average between 74 and
76 MMcfe/d for full year 2015. The Partnership currently
expects its quarterly General & Administrative expenses,
excluding amortization of expenses related to its Long Term
Incentive Plan, to average a run rate between $7.3 and $7.7 million
per quarter during 2015.
Hedging Update
The Partnership employs risk mitigation strategies to protect
its cash flows and reduce volatility in the Partnership's cash
flows from commodity price fluctuations. One important risk
mitigation strategy is the use of commodity price hedging to lock
in stable cash flows. As of February 25, 2015, the
Partnership's hedge portfolio had an estimated mark-to-market value
of approximately $100 million. The Partnership's estimated
hedge profile is as follows:
|
2015E |
2016E |
2017E |
2018E |
2019E |
Oil Production Hedged: |
|
|
|
|
|
% Oil Hedged |
87% |
73% |
35% |
31% |
27% |
Average WTI Strike Price ($/Bbl) |
$89.88 |
$84.66 |
$88.02 |
$87.50 |
$87.07 |
Average LLS Strike Price ($/Bbl) |
-- |
-- |
$91.25 |
$90.75 |
$90.25 |
Natural Gas and Ethane Production
Hedged: |
|
|
|
|
|
% Natural Gas and Ethane Hedged |
78% |
69% |
-- |
-- |
-- |
Average Henry Hub Strike Price ($/MMbtu) |
$4.07 |
$4.25 |
-- |
-- |
-- |
Natural Gas Liquids Production
Hedged: |
|
|
|
|
|
% NGL (>C2) Hedged |
23% |
-- |
-- |
-- |
-- |
Average Propane Strike Price ($/Gal) |
$0.531 |
-- |
-- |
-- |
-- |
Average N Butane Strike Price ($/Gal) |
$0.650 |
-- |
-- |
-- |
-- |
Average I Butane Strike Price ($/Gal) |
$0.660 |
-- |
-- |
-- |
-- |
Average Pentanes Strike Price ($/Gal) |
$1.115 |
-- |
-- |
-- |
-- |
Note: Percent-hedged depicted against midpoint of 2015
production guidance (i.e., 75 MMcfe/d) held flat for 2015 and (for
ease of modeling but not as guidance) for 2016 through 2019.
The Partnership has not entered into any additional commodity
hedges since its last hedging update on February 25, 2015. The
latest presentation can be accessed by going to
www.eaglerockenergy.com: select Investor Relations, then select
Presentations.
2014 K-1 Tax Information
2014 tax packages, including Schedule K-1, are expected to be
available online through Eagle Rock's website and mailed in
mid-March.
Fourth Quarter and Full Year 2014 Conference Call
Information
Eagle Rock will hold a conference call to discuss its fourth
quarter 2014 financial and operating results on Thursday, February
26, 2015 at 2:00 p.m. Eastern Time (1:00 p.m. Central Time).
Interested parties may listen to the earnings conference call live
over the Internet or via telephone. To listen live over the
Internet, participants are advised to log on to the Partnership's
web site at www.eaglerockenergy.com and select the "Events &
Presentations" sub-tab under the "Investor Relations" tab. To
participate by telephone, the call in number is (877)
293-5457, conference ID
72079318. Participants are advised to dial
into the call at least 15 minutes prior to the call. An audio
replay of the conference call will also be available for thirty
days by dialing (855) 859-2056, conference ID
72079318. In addition, a replay of the audio
webcast will be available by accessing the Partnership's web site
after the call is concluded.
About the Partnership
Eagle Rock is a growth-oriented master limited partnership
engaged in (a) the exploitation, development, and production of oil
and natural gas properties and (b) ancillary gathering,
compressing, treating, processing and marketing services with
respect to its production of natural gas, natural gas liquids,
condensate and crude oil.
Use of Non-GAAP Financial Measures
This news release and the accompanying schedules include the
non-generally accepted accounting principles, or non-GAAP,
financial measures of Adjusted EBITDA and Distributable Cash Flow.
The accompanying non-GAAP financial measures schedules (after the
financial schedules) provide reconciliations of these non-GAAP
financial measures to their most directly comparable financial
measures calculated and presented in accordance with accounting
principles generally accepted in the United States, or GAAP.
Non-GAAP financial measures should not be considered alternatives
to GAAP measures such as net income (loss), operating income
(loss), cash flows from operating activities or any other GAAP
measure of liquidity or financial performance.
Eagle Rock defines Adjusted EBITDA as net income (loss) plus or
(minus) income tax provision (benefit); interest-net, including
gains and losses arising from interest rate risk management
instruments that settled during the period and other expense;
depreciation, depletion and amortization expense; impairment
expense; other operating expense, non-recurring; other non-cash
operating and general and administrative expenses, including
non-cash compensation related to the Partnership's equity-based
compensation program; mark-to-market (gains) losses on commodity
and interest rate risk management related instruments; (gains)
losses on discontinued operations; and other (income) expense.
Eagle Rock uses Adjusted EBITDA as a measure of its core
profitability to assess the financial performance of its assets.
Adjusted EBITDA also is used as a supplemental financial measure by
external users of Eagle Rock's financial statements such as
investors, commercial banks and research analysts. For example, the
Partnership's lenders under its revolving credit facility use a
variant of its Adjusted EBITDA in a compliance covenant designed to
measure the viability of Eagle Rock and its ability to perform
under the terms of the revolving credit facility; Eagle Rock,
therefore, uses Adjusted EBITDA to measure its compliance with its
revolving credit facility. Eagle Rock believes that investors
benefit from having access to the same financial measures that its
management uses in evaluating performance. Adjusted EBITDA is
useful in determining Eagle Rock's ability to sustain or increase
distributions. By excluding unrealized derivative gains (losses), a
non-cash, mark-to-market benefit (charge) which represents the
change in fair market value of the Partnership's executed
derivative instruments and is independent of its assets'
performance or cash flow generating ability, Eagle Rock believes
Adjusted EBITDA reflects the Partnership's ability to generate cash
sufficient to pay interest costs, support its level of
indebtedness, make cash distributions to its unitholders and
finance its maintenance capital expenditures. Eagle Rock further
believes that Adjusted EBITDA also portrays the underlying
performance of its operating assets by isolating the performance of
its operating assets from the impact of an unrealized, non-cash
measure designed to portray the fluctuating inherent value of a
financial asset. Similarly, by excluding the impact of
non-recurring discontinued operations, Adjusted EBITDA provides
users of the Partnership's financial statements a picture of its
current assets' cash generation ability, independently from that of
assets which are no longer a part of its operations.
Eagle Rock's Adjusted EBITDA definition may not be comparable to
Adjusted EBITDA or similarly titled measures of other entities, as
other entities may not calculate Adjusted EBITDA in the same manner
as Eagle Rock. Eagle Rock has reconciled Adjusted EBITDA to the
GAAP financial measure of net income (loss) at the end of this
release.
Adjusted EBITDA does not include interest expense, income taxes
or depreciation and amortization expense. Because we have borrowed
money to finance our operations, interest expense is a necessary
element of our costs and our ability to generate net income.
Because we use capital assets, depreciation and amortization are
also necessary elements of our costs. Therefore, any measures that
exclude these elements have material limitations. To compensate for
these limitations, we believe that it is important to consider both
net income (loss) and net cash flows provided by operating
activities determined under GAAP, as well as Adjusted EBITDA, to
evaluate our performance and liquidity. Adjusted EBITDA should not
be considered an alternative to net income, operating income, cash
flows provided by operating activities or any other measure of
financial performance presented in accordance with GAAP.
Distributable Cash Flow is defined as Adjusted EBITDA minus: (i)
maintenance capital expenditures; (ii) cash interest expense; (iii)
cash income taxes; and (iv) the addition of losses or subtraction
of gains relating to other miscellaneous non-cash amounts affecting
net income (loss) for the period. Maintenance capital expenditures
represent capital expenditures necessary to maintain the
Partnership's production. We estimate these amounts based on
current projections and expectations, and do not undertake to
adjust any historical amounts based on the actual impact of such
expenditures on production. As a result, the included amount of
maintenance capital expenditures could fail to maintain production
if actual performance does not meet the Partnership's projections
and expectations, including, without limitation, on account of: (i)
unanticipated mechanical issues; (ii) unanticipated delays; (iii)
poorer than expected production performance of the Partnership's
new wells and recompletions; and/or (iv) unanticipated loss of, or
higher than anticipated decline in, existing production.
Distributable Cash Flow is a significant performance metric used
by senior management to compare cash flows generated by the
Partnership (excluding growth capital expenditures and prior to the
establishment of any retained cash reserves by the Board of
Directors) to the cash distributions expected to be paid to
unitholders. Using this metric, management can quickly compute the
coverage ratio of estimated cash flows to planned cash
distributions. This financial measure also is important to
investors as an indicator of whether the Partnership is generating
cash flow at a level that can sustain, or support an increase in,
quarterly distribution rates. Actual distributions are set by the
Board of Directors.
The GAAP measure most directly comparable to Distributable Cash
Flow is net income (loss). Eagle Rock's Distributable Cash Flow
definition may not be comparable to Distributable Cash Flow or
similarly titled measures of other entities, as other entities may
not calculate Distributable Cash Flow (and Adjusted EBITDA, on
which it builds) in the same manner as Eagle Rock. Eagle Rock has
reconciled Distributable Cash Flow to the GAAP financial measure of
net income (loss) at the end of this release.
Forward-Looking Statements
This news release may include "forward-looking statements." All
statements, other than statements of historical facts, included in
this press release that address activities, events or developments
that the Partnership expects, believes or anticipates will or may
occur in the future are forward-looking statements and speak only
as of the date on which such statement is made. These statements
are based on certain assumptions made by the Partnership based on
its experience and perception of historical trends, current
conditions, expected future developments and other factors it
believes are appropriate under the circumstances. Such statements
are subject to a number of assumptions, risks and uncertainties,
many of which are beyond the control of the Partnership. These
include, but are not limited to, risks related to volatility of
commodity prices; drilling and geological / exploration risks;
market demand for crude oil, natural gas and natural gas liquids;
our ability to make favorable acquisitions; the effectiveness of
the Partnership's hedging activities; the availability of local,
intrastate and interstate transportation systems and other
facilities to transport crude oil, natural gas and natural gas
liquids; competition in the oil and gas industry; the Partnership's
ability to obtain credit and access the capital markets; general
economic conditions; and the effects of government regulations and
policies. Should one or more of these risks or uncertainties occur,
or should underlying assumptions prove incorrect, the Partnership's
actual results and plans could differ materially from those implied
or expressed by any forward-looking statements. The Partnership
assumes no obligation to update any forward-looking statement as of
any future date. For a detailed list of the Partnership's risk
factors, please consult the Partnership's Form 10-K, filed with the
SEC for the year ended December 31, 2014 and the Partnership's
Forms 10-Q filed with the SEC for subsequent quarters as well as
any other public filings and press releases.
|
|
|
|
|
|
Eagle Rock Energy Partners,
L.P. |
Consolidated Statement of
Operations |
($ in thousands) |
(unaudited) |
|
|
|
|
|
|
|
Three Months Ended |
Twelve Months Ended |
Three Months Ended |
|
December 31, |
December 31, |
September 30, |
|
2014 |
2013 |
2014 |
2013 |
2014 |
REVENUE: |
|
|
|
|
|
Natural gas, natural gas liquids, oil,
condensate and sulfur sales |
$ 43,115 |
$ 51,233 |
$ 203,792 |
$ 200,608 |
$ 53,626 |
Unrealized commodity derivative gains
(losses) |
85,862 |
(7,058) |
89,762 |
(19,494) |
26,700 |
Realized commodity derivative gains |
8,716 |
3,497 |
4,669 |
15,557 |
1,267 |
Other revenue |
40 |
83 |
(19) |
701 |
(369) |
Total revenue |
137,733 |
47,755 |
298,204 |
197,372 |
81,224 |
|
|
|
|
|
|
COSTS AND EXPENSES: |
|
|
|
|
|
Operations and maintenance |
10,558 |
11,374 |
43,670 |
41,426 |
10,707 |
Taxes other than income |
2,354 |
3,198 |
12,925 |
12,928 |
3,184 |
General and administrative |
9,663 |
12,965 |
47,193 |
53,131 |
12,235 |
Impairment |
378,587 |
151,058 |
395,892 |
214,286 |
17,305 |
Depreciation, depletion and amortization |
22,615 |
23,617 |
85,579 |
89,444 |
22,259 |
Total costs and expenses |
423,777 |
202,212 |
585,259 |
411,215 |
65,690 |
OPERATING (LOSS) INCOME |
(286,044) |
(154,457) |
(287,055) |
(213,843) |
15,534 |
OTHER (EXPENSE) INCOME: |
|
|
|
|
|
Interest expense, net |
(2,357) |
(4,578) |
(15,247) |
(18,789) |
(3,188) |
Realized interest rate derivative gains
(losses) |
140 |
(1,727) |
(5,023) |
(6,756) |
(1,738) |
Unrealized interest rate derivative (losses)
gains |
(932) |
1,389 |
3,289 |
5,652 |
1,657 |
Loss on short-term investments |
(62,028) |
-- |
(62,028) |
-- |
-- |
Other income (expense), net |
4,211 |
2 |
8,294 |
(30) |
4,080 |
Total other (expense) income |
(60,966) |
(4,914) |
(70,715) |
(19,923) |
811 |
(LOSS) INCOME FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES |
(347,010) |
(159,371) |
(357,770) |
(233,766) |
16,345 |
INCOME TAX BENEFIT |
(2,767) |
(1,335) |
(5,403) |
(5,595) |
(886) |
(LOSS) INCOME FROM CONTINUING OPERATIONS |
(344,243) |
(158,036) |
(352,367) |
(228,171) |
17,231 |
DISCONTINUED OPERATIONS, NET OF TAX |
(348) |
(10,896) |
212,460 |
(49,808) |
249,057 |
NET (LOSS) INCOME |
$ (344,591) |
$ (168,932) |
$ (139,907) |
$ (277,979) |
$ 266,288 |
|
|
|
Eagle Rock Energy Partners,
L.P. |
Consolidated Balance
Sheets |
($ in thousands) |
(unaudited) |
|
|
|
|
December 31,
2014 |
December 31,
2013 |
ASSETS |
|
|
CURRENT ASSETS: |
|
|
Cash and cash equivalents |
$ 1,343 |
$ 76 |
Short-term investments |
153,448 |
-- |
Accounts receivable |
39,596 |
17,250 |
Risk management assets |
44,805 |
5,559 |
Prepayments and other current assets |
9,911 |
6,123 |
Assets held for sale |
-- |
1,259,382 |
Total current assets |
249,103 |
1,288,390 |
PROPERTY, PLANT AND EQUIPMENT - Net |
487,988 |
824,451 |
INTANGIBLE ASSETS - Net |
3,072 |
3,268 |
DEFERRED TAX ASSET |
2,315 |
1,438 |
RISK MANAGEMENT ASSETS |
46,490 |
3,871 |
OTHER ASSETS |
5,307 |
6,132 |
TOTAL ASSETS |
$ 794,275 |
$ 2,127,550 |
|
|
|
LIABILITIES AND MEMBERS'
EQUITY |
|
|
CURRENT LIABILITIES: |
|
|
Accounts payable |
$ 49,226 |
$ 50,158 |
Accrued liabilities |
8,053 |
23,162 |
Taxes payable |
2,246 |
149 |
Risk management liabilities |
-- |
8,360 |
Liabilities held for sale |
-- |
637,738 |
Total current liabilities |
59,525 |
719,567 |
LONG-TERM DEBT |
263,343 |
757,480 |
ASSET RETIREMENT OBLIGATIONS |
47,907 |
37,306 |
DEFERRED TAX LIABILITY |
30,321 |
34,097 |
RISK MANAGEMENT LIABILITIES |
-- |
2,826 |
OTHER LONG TERM LIABILITIES |
4,709 |
2,395 |
|
|
|
MEMBERS' EQUITY |
388,470 |
573,879 |
TOTAL LIABILITIES AND MEMBERS' EQUITY |
$ 794,275 |
$ 2,127,550 |
|
|
|
|
|
|
Eagle Rock Energy Partners,
L.P. |
Upstream Operations
Information |
(unaudited) |
|
|
|
|
|
|
|
Three Months Ended |
Twelve Months Ended |
Three Months Ended |
|
December 31, |
December 31, |
September 30, |
|
2014 |
2013 |
2014 |
2013 |
2014 |
Upstream |
|
|
|
|
|
Production: |
|
|
|
|
|
Oil and condensate (Bbl) |
356,831 |
327,679 |
1,312,749 |
1,222,270 |
338,462 |
Gas (Mcf) |
3,005,606 |
3,239,438 |
11,995,478 |
12,804,475 |
3,094,006 |
NGLs (Bbl) |
298,160 |
289,584 |
1,158,158 |
1,155,639 |
296,686 |
Total Mcfe |
6,935,552 |
6,943,016 |
26,820,920 |
27,071,929 |
6,904,894 |
|
|
|
|
|
|
Sulfur (long ton) |
24,483 |
25,365 |
97,033 |
105,394 |
22,534 |
|
|
|
|
|
|
Realized prices, excluding derivatives: |
|
|
|
|
|
Oil and condensate (per Bbl) |
$63.05 |
$85.67 |
$80.07 |
$87.34 |
$85.66 |
Gas (Mcf) |
$3.87 |
$3.53 |
$4.27 |
$3.53 |
$3.92 |
NGLs (Bbl) |
$24.04 |
$37.73 |
$33.83 |
$35.12 |
$34.70 |
Sulfur (long ton) |
$74.78 |
$31.53 |
$84.94 |
$76.38 |
$97.55 |
|
|
|
|
|
|
Operating statistics: |
|
|
|
|
|
Operating costs per Mcfe (incl production
taxes) (1) |
$1.66 |
$1.94 |
$1.89 |
$1.84 |
$1.77 |
Operating costs per Mcfe (excl production
taxes) (1) |
$1.32 |
$1.48 |
$1.41 |
$1.36 |
$1.30 |
Operating (loss) income per Mcfe (2) |
($53.27) |
($19.78) |
($12.29) |
($5.72) |
$0.07 |
|
|
|
|
|
|
Drilling program (gross wells): |
|
|
|
|
|
Development wells |
8 |
8 |
27 |
45 |
8 |
Completions |
8 |
8 |
27 |
45 |
8 |
Workovers |
1 |
8 |
15 |
24 |
5 |
Recompletions |
1 |
2 |
7 |
10 |
1 |
|
|
|
|
|
|
|
|
|
|
|
|
(1) Excludes post-production
costs of $1,388, $5,973, $1,109 and $4,572, respectively, for the
three months and year ended December 31, 2014 and 2013,
respectively and $1,702 for the three months ended September 30,
2014. |
|
|
|
|
|
|
(2) Excludes general and
administrative expenses, commodity risk management activities and
depreciation expense related to corporate type assets |
|
|
|
|
|
|
Eagle Rock Energy Partners,
L.P. |
GAAP to Non-GAAP
Reconciliations |
($ in thousands) |
(unaudited) |
|
|
|
|
|
|
|
Three Months Ended |
Twelve Months Ended |
Three Months Ended |
|
December 31, |
December 31, |
September 30, |
|
2014 |
2013 |
2014 |
2013 |
2014 |
Net income (loss) to Adjusted EBITDA |
|
|
|
|
|
Net (loss) income, as reported |
$ (344,591) |
$ (168,932) |
$ (139,907) |
$ (277,979) |
$ 266,288 |
Depreciation, depletion and amortization |
22,615 |
23,617 |
85,579 |
89,444 |
22,259 |
Impairment |
378,587 |
151,058 |
395,892 |
214,286 |
17,305 |
Loss (gain) from risk management activities,
net |
(93,786) |
3,899 |
(92,697) |
5,041 |
(27,886) |
Total derivative settlements |
8,856 |
1,770 |
(354) |
8,801 |
(471) |
Non-cash mark-to-market of Upstream product
imbalances |
2 |
1 |
(2) |
(1) |
3 |
Restricted units non-cash amortization
expense |
1,208 |
2,643 |
8,198 |
10,392 |
2,948 |
Income tax benefit |
(2,767) |
(1,335) |
(5,403) |
(5,595) |
(886) |
Interest - net including realized risk
management instruments and other expense |
2,006 |
6,303 |
20,016 |
25,575 |
4,886 |
Discontinued operations |
348 |
10,896 |
(212,460) |
49,808 |
(249,057) |
Loss on short-term investments |
62,028 |
-- |
62,028 |
-- |
-- |
Adjusted EBITDA |
$ 34,506 |
$ 29,920 |
$ 120,890 |
$ 119,772 |
$ 35,389 |
|
|
|
|
|
|
Net income (loss) to Distributable Cash
Flow |
|
|
|
|
|
Net (loss) income, as reported |
$ (344,591) |
$ (168,932) |
$ (139,907) |
$ (277,979) |
$ 266,288 |
Depreciation, depletion and amortization
expense |
22,615 |
23,617 |
85,579 |
89,444 |
22,259 |
Impairment |
378,587 |
151,058 |
395,892 |
214,286 |
17,305 |
Loss (gain) from risk management activities,
net |
(93,786) |
3,899 |
(92,697) |
5,041 |
(27,886) |
Total derivative settlements |
8,856 |
1,770 |
(354) |
8,801 |
(471) |
Capital expenditures-maintenance related |
(14,584) |
(14,548) |
(58,458) |
(46,200) |
(14,547) |
Non-cash mark-to-market of Upstream product
imbalances |
2 |
1 |
(2) |
(1) |
3 |
Restricted units non-cash amortization
expense |
1,208 |
2,643 |
8,198 |
10,392 |
2,948 |
Income tax benefit |
(2,767) |
(1,335) |
(5,403) |
(5,595) |
(886) |
Cash income taxes |
-- |
(201) |
-- |
(201) |
-- |
Discontinued operations |
348 |
10,896 |
(212,460) |
49,808 |
(249,057) |
Loss on short-term investments |
62,028 |
-- |
62,028 |
-- |
-- |
Distributable Cash Flow |
$ 17,916 |
$ 8,868 |
$ 42,416 |
$ 47,796 |
$ 15,956 |
CONTACT: Eagle Rock Energy Partners, L.P.
Bob Haines, 281-408-1303
Senior Vice President and Chief Financial Officer
Chad Knips, 281-408-1203
Director, Corporate Finance and Investor Relations
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