Eagle Rock Energy Partners, L.P. ("Eagle Rock" or the
"Partnership") (Nasdaq:EROC) today announced its unaudited
financial results for the three months ended March 31, 2015.
First Quarter 2015 Highlights
- Average daily production was 79.7 MMcfe/d, a 5.7% increase over
fourth quarter 2014
- Distributable cash flow of $11.9 million, equivalent to
$0.08/unit
- Announced a distribution of $0.07/unit for the first quarter,
or $0.28/unit annualized
- Distribution coverage of 1.12x Distributable Cash Flow for the
first quarter; expect to be at or above 1.0x coverage for the full
year 2015
- Adjusted EBITDA of $25.5 million for the first quarter,
compared to $34.5 million for the fourth quarter 2014, as lower
realized prices were partially offset by higher production volumes
and lower operating costs
- Total liquidity of $231 million as of March 31, 2015, including
the market value of the Regency Energy Partners, L.P. ("Regency")
common units owned by the Partnership
- Leverage ratio of 1.8x as of March 31, 2015
- Placed additional hedges on ~86% of expected NGL volumes for
the remainder of 2015, providing greater cash flow protection
Joseph A. Mills, the Partnership's Chairman and Chief Executive
Officer, stated, "Eagle Rock had a strong first quarter, especially
given the tumultuous commodity price environment. We increased our
daily production by 6% over fourth quarter 2014 volumes, and we are
realizing meaningful reductions to our operating and capital costs
while at the same time reducing our leverage to 1.8x LTM EBITDA. We
have maintained significant liquidity and protected the
distribution with our strong hedge portfolio."
Mills added, "The Partnership continues to remain very active in
its business development efforts, evaluating more than $1 billion
worth of MLP-appropriate asset acquisition opportunities year to
date. We continue to take a patient approach to acquisitions, and
we expect to have an opportunity to utilize our liquidity to make a
meaningful accretive acquisition in 2015 that will enable us to
achieve greater scale and diversify our asset base while growing
distributable cash flow."
First Quarter 2015 Financial and Operating
Results
Significant results from continuing operations for the first
quarter of 2015:
- Adjusted EBITDA of $25.5 million, compared to $34.5 million for
fourth quarter 2014, as lower commodity prices were partially
offset by higher production volumes and lower operating costs.
- Distributable Cash Flow of $11.9 million or $0.08/unit,
compared to $0.12/unit for fourth quarter 2014.
- Net Loss of $58.7 million, driven by $68.3 million of
impairment charges primarily related to the impact of lower
commodity prices on the Partnership's oil and gas reserves, mainly
in the Arkoma and Permian areas.
- Participated in 20 gross (3.2 net) wells in the Mid-Continent
region, of which 4 gross (2.7 net) were Eagle Rock operated wells.
Additionally, conducted 1 gross (1 net) workover.
- Total production was 7.17 Bcfe, compared to 6.94 Bcfe in fourth
quarter 2014. Average daily production was 79.7 MMcfe/d, compared
to 75.4 MMcfe/d in fourth quarter 2014.
- Oil production decreased 2% quarter over quarter from 357 MBbl
to 349 MBbl
- NGL production increased 10% quarter over quarter from 298 MBbl
to 327 MBbl
- Natural gas production increased 4% quarter over quarter from
3.01 Bcf to 3.11 Bcf
- The overall increase in production volumes was primarily due to
strong production from three completed operated wells in the Golden
Trend play; one completed operated, plus a number of non-operated,
wells in the prolific horizontal Woodford "SCOOP" play; and other
prior period adjustments
- Golden Trend well results:
- McLemore 1-29, which the Partnership operates with an 84%
working interest, had an IP30 of 792 boe/d
- 21 Ranch 1-16, which the Partnership operates with a 69%
working interest, had an IP30 of 1,797 boe/d
- Brown 1-29, which the Partnership operates with an 89% working
interest, had an IP30 of 680 boe/d
- SCOOP well results:
- Linton 1-05-32XH, which the Partnership operates with a 31%
working interest, had an IP30 of 1,532 boe/d
- Product revenue of $29.5 million, compared to $43.1 million for
fourth quarter 2014, due to lower commodity prices partially offset
by higher production volumes.
- Realized commodity derivative gains of $14.4 million, compared
to $8.7 million for fourth quarter 2014, due to lower commodity
prices.
- Cash distributions of $2.1 million received on the Regency
common units held by the Partnership, compared to $4.0 million in
fourth quarter 2014, due to the sale of Regency units by the
Partnership.
- Operating expenses, including taxes, of $11.5 million, 11%
lower than fourth quarter 2014, primarily due to lower service
costs and lower severance taxes resulting from decreased sales
revenue.
- General and administrative expenses, net of severance payments,
(excluding amortization of expenses pursuant to the Long-Term
Incentive Plan) were $8.5 million for the first quarter 2015, flat
as compared to fourth quarter 2014.
- Operating income decreased to $15.0 million (excluding an
impairment charge of $68.3 million) as compared to operating income
of $92.5 million for fourth quarter 2014 (excluding an impairment
charge of $378.6 million), primarily due to lower commodity prices
and a decrease in unrealized gains on commodity derivatives.
- Maintenance capital expenditures of $10.3 million, as compared
to $14.6 million spent in the fourth quarter 2014. Maintenance
capital requirements in 2015 are expected to be $3.3 million per
month, down from $4.5 million per month in 2014, as a result of
meaningful reductions to capital costs in the Partnership's
operations.
Regency Unit Sale
As of April 28, 2015, the Partnership had sold approximately 5.7
million Regency units received as part of the consideration for the
Midstream Business Contribution, and proceeds were approximately
$140.4 million. These proceeds were used to fund the Partnership's
common unit repurchase program, pay down debt and for general
corporate purposes. Eagle Rock plans to continue to sell the
majority of the approximately 2.5 million remaining Regency common
units in the near term in order to further strengthen
liquidity.
Capitalization and Liquidity Update
As of March 31, 2015, the Partnership's total liquidity was $231
million. The Partnership's borrowing base under its senior
secured credit facility totaled $320 million, and based on
outstanding borrowings, the Partnership had approximately $158
million of availability under its senior secured credit
facility. As of March 31, 2015 the market value of the 3.2
million remaining Regency units held by the Partnership was $72.9
million.
On April 1, 2015, the Partnership's borrowing base decreased
from $320 million to $270 million, as expected, as part of the
regularly scheduled semi-annual redetermination by its commercial
lenders. The decrease was primarily driven by lower commodity
prices. As of April 28, 2015, the Partnership's total
liquidity was approximately $164 million, comprised of
approximately $108 million of availability under its senior secured
credit facility and approximately 2.5 million Regency units valued
at $56 million.
As of March 31, 2015, the Partnership had 150.9 million common
units outstanding eligible to receive the distribution, including
1.9 million unvested restricted common units issued under the
Partnership's Amended and Restated Long-Term Incentive
Plan. As of April 28, 2015, the Partnership had 150.8 million
common units outstanding eligible to receive the distribution,
including 1.8 million unvested restricted common units issued under
its Amended and Restated Long-Term Incentive Plan.
In order to preserve liquidity for potential acquisition
opportunities, the Partnership has not repurchased any of its units
since its last update as of February 23, 2015. The common unit
repurchase program of up to $100 million is still in effect until
March 2016, and Eagle Rock has repurchased 8.6 million units to
date for total consideration of $22 million.
Second Quarter and Full Year 2015 Guidance
During the second quarter of 2015, the Partnership plans to
spend approximately $21 million on capital expenditures, and
expects $10 million to be categorized as maintenance capital
expenditures and $11 million to be categorized as growth capital
expenditures. Subject to results from the Partnership's
drilling program, the Partnership expects production to average
between 76 and 79 MMcfe/d during second quarter 2015.
For full year 2015, the Partnership plans to spend approximately
$75 million on capital expenditures, and expects $40 million to be
categorized as maintenance capital expenditures and $35 million to
be categorized as growth capital expenditures. Subject to
results from the Partnership's drilling program, the Partnership
expects production to average between 75 and 78 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. The Partnership expects distributable cash flow to be at
or above 1.0x coverage for the full year 2015.
Hedging Update
The Partnership employs risk mitigation strategies to protect
its cash flows and reduce volatility in cash flows from commodity
price fluctuations. One important risk mitigation strategy is
the use of commodity price hedging to stabilize cash flows. As
of March 31, 2015, the Partnership's hedge portfolio had an
estimated mark-to-market value of approximately $100
million. As of April 29, 2015, the Partnership's estimated
hedge profile is as follows:
|
Rem 2015E(1) |
2016E |
2017E |
2018E |
2019E |
Oil Production Hedged: |
|
|
|
|
|
% Oil Hedged |
85% |
72% |
34% |
30% |
27% |
Average WTI Strike Price ($/Bbl) |
$89.88 |
$84.66 |
$88.02 |
$87.50 |
$87.07 |
Average LLS Strike Price ($/Bbl) |
-- |
-- |
$91.25 |
$90.75 |
$90.25 |
Natural Gas and Ethane Production
Hedged: |
|
|
|
|
|
% Natural Gas and Ethane Hedged |
77% |
68% |
15% |
-- |
-- |
Average Henry Hub Strike Price ($/MMbtu) |
$4.07 |
$4.25 |
$3.34 |
-- |
-- |
Natural Gas Liquids Production
Hedged: |
|
|
|
|
|
% NGL (>C2) Hedged |
86% |
-- |
-- |
-- |
-- |
Average Propane Strike Price ($/Gal) |
$0.564 |
-- |
-- |
-- |
-- |
Average N Butane Strike Price ($/Gal) |
$0.672 |
-- |
-- |
-- |
-- |
Average I Butane Strike Price ($/Gal) |
$0.675 |
-- |
-- |
-- |
-- |
Average Pentanes Strike Price ($/Gal) |
$1.187 |
-- |
-- |
-- |
-- |
(1) May 1 – Dec 31, 2015. |
Note: Percent-hedged depicted against
midpoint of 2015 production guidance (i.e., 76.5 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 April 29, 2015. The latest
presentation can be accessed by going to www.eaglerockenergy.com:
select Investor Relations, then select Presentations.
First Quarter 2015 Conference Call
Information
Eagle Rock will hold a conference call to discuss its first
quarter 2015 financial and operating results on Thursday, April 30,
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 19487996. 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 19487996. 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 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, including
the Form 10-Q to be filed for the quarter ended March 31, 2015, 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 March
31, |
Three Months Ended December 31, |
|
2015 |
2014 |
2014 |
REVENUE: |
|
|
|
Natural gas, natural gas liquids, oil,
condensate and sulfur sales |
$ 29,513 |
$ 55,084 |
$ 43,115 |
Unrealized commodity derivative gains
(losses) |
8,230 |
(6,895) |
85,862 |
Realized commodity derivative gains
(losses) |
14,370 |
(3,138) |
8,716 |
Other revenue |
9 |
152 |
40 |
Total revenue |
52,122 |
45,203 |
137,733 |
|
|
|
|
COSTS AND EXPENSES: |
|
|
|
Operations and maintenance |
10,082 |
11,498 |
10,558 |
Taxes other than income |
1,388 |
3,791 |
2,354 |
General and administrative |
10,989 |
13,290 |
9,663 |
Impairment |
68,344 |
-- |
378,587 |
Depreciation, depletion and amortization |
14,645 |
20,406 |
22,615 |
Total costs and expenses |
105,448 |
48,985 |
423,777 |
OPERATING LOSS |
(53,326) |
(3,782) |
(286,044) |
OTHER (EXPENSE) INCOME: |
|
|
|
Interest expense, net |
(2,318) |
(4,754) |
(2,357) |
Realized interest rate derivative (losses)
gains |
(940) |
(1,708) |
140 |
Unrealized interest rate derivative (losses)
gains |
(2,126) |
1,418 |
(932) |
Loss on short-term investments |
(2,004) |
-- |
(62,028) |
Other income, net |
2,135 |
1 |
4,211 |
Total other (expense) income |
(5,253) |
(5,043) |
(60,966) |
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME
TAXES |
(58,579) |
(8,825) |
(347,010) |
INCOME TAX BENEFIT |
(826) |
(865) |
(2,767) |
LOSS FROM CONTINUING OPERATIONS |
(57,753) |
(7,960) |
(344,243) |
DISCONTINUED OPERATIONS, NET OF TAX |
(966) |
(10,603) |
(348) |
NET LOSS |
$ (58,719) |
$ (18,563) |
$ (344,591) |
|
|
Eagle Rock Energy Partners,
L.P. |
Consolidated Balance
Sheets |
($ in thousands) |
(unaudited) |
|
|
|
|
March 31, 2015 |
December 31,
2014 |
ASSETS |
|
|
CURRENT ASSETS: |
|
|
Cash and cash equivalents |
$ 37 |
$ 1,343 |
Short-term investments |
72,924 |
153,448 |
Accounts receivable |
32,931 |
39,596 |
Risk management assets |
47,392 |
44,805 |
Prepayments and other current assets |
11,764 |
9,911 |
Total current assets |
165,048 |
249,103 |
PROPERTY, PLANT AND EQUIPMENT - Net |
432,291 |
487,988 |
INTANGIBLE ASSETS - Net |
3,023 |
3,072 |
DEFERRED TAX ASSET |
1,805 |
2,315 |
RISK MANAGEMENT ASSETS |
50,007 |
46,490 |
OTHER ASSETS |
5,063 |
5,307 |
TOTAL ASSETS |
$ 657,237 |
$ 794,275 |
|
|
|
LIABILITIES AND MEMBERS'
EQUITY |
|
|
CURRENT LIABILITIES: |
|
|
Accounts payable |
$ 38,145 |
$ 49,226 |
Accrued liabilities |
7,575 |
8,053 |
Taxes payable |
2,212 |
2,246 |
Total current liabilities |
47,932 |
59,525 |
LONG-TERM DEBT |
212,762 |
263,343 |
ASSET RETIREMENT OBLIGATIONS |
47,575 |
47,907 |
DEFERRED TAX LIABILITY |
28,921 |
30,321 |
OTHER LONG TERM LIABILITIES |
5,270 |
4,709 |
|
|
|
MEMBERS' EQUITY |
314,777 |
388,470 |
TOTAL LIABILITIES AND MEMBERS' EQUITY |
$ 657,237 |
$ 794,275 |
|
|
Eagle Rock Energy Partners,
L.P. |
Upstream Operations
Information |
(unaudited) |
|
|
|
|
|
Three Months Ended March
31, |
Three Months Ended December
31, |
|
2015 |
2014 |
2014 |
Upstream |
|
|
|
Production: |
|
|
|
Oil and condensate (Bbl) |
349,221 |
317,126 |
356,831 |
Gas (Mcf) |
3,110,234 |
2,952,149 |
3,005,606 |
NGLs (Bbl) |
327,481 |
273,673 |
298,160 |
Total Mcfe |
7,170,446 |
6,496,943 |
6,935,552 |
|
|
|
|
Sulfur (long ton) |
23,847 |
24,461 |
24,483 |
|
|
|
|
Realized prices, excluding derivatives: |
|
|
|
Oil and condensate (per Bbl) |
$38.17 |
$85.56 |
$63.05 |
Gas (Mcf) |
$2.76 |
$4.95 |
$3.87 |
NGLs (Bbl) |
$15.63 |
$41.90 |
$24.04 |
Sulfur (long ton) |
$104.44 |
$77.05 |
$74.78 |
|
|
|
|
Operating statistics: |
|
|
|
Operating costs per Mcfe (incl production
taxes) (1) |
$1.40 |
$2.14 |
$1.66 |
Operating costs per Mcfe (excl production
taxes) (1) |
$1.21 |
$1.56 |
$1.32 |
Operating (loss) income per Mcfe (2) |
$(8.98) |
$3.11 |
$(53.27) |
|
|
|
|
Drilling program (gross wells): |
|
|
|
Development wells |
20 |
4 |
8 |
Completions |
20 |
4 |
8 |
Workovers |
1 |
5 |
4 |
Recompletions |
0 |
1 |
1 |
|
|
|
|
(1) Excludes post-production
costs of $1,398 and $1,371, respectively, for the three months
ended March 31, 2015 and 2014 and $1,388 for the three months ended
December 31, 2014. |
|
|
|
|
(2) Excludes general and
administrative expenses, commodity risk management activities and
depreciation expense related to corporate type assets. |
|
|
Eagle Rock Energy Partners,
L.P. |
GAAP to Non-GAAP
Reconciliations |
($ in thousands) |
(unaudited) |
|
|
|
|
|
Three Months Ended March
31, |
Three Months Ended December
31, |
|
2015 |
2014 |
2014 |
Net loss to Adjusted EBITDA |
|
|
|
Net loss, as reported |
$ (58,719) |
$ (18,563) |
$ (344,591) |
Depreciation, depletion and amortization |
14,645 |
20,406 |
22,615 |
Impairment |
68,344 |
-- |
378,587 |
(Gain) loss from risk management activities,
net |
(19,534) |
10,323 |
(93,786) |
Total commodity derivative settlements |
13,430 |
(4,846) |
8,856 |
Non-cash mark-to-market of Upstream product
imbalances |
126 |
(6) |
2 |
Restricted units non-cash amortization
expense |
1,856 |
2,583 |
1,208 |
Income tax benefit |
(826) |
(865) |
(2,767) |
Interest - net including realized risk
management instruments and other expense |
3,257 |
6,461 |
2,006 |
Discontinued operations |
966 |
10,603 |
348 |
Loss on short-term investments |
2,004 |
-- |
62,028 |
Adjusted EBITDA |
$ 25,549 |
$ 26,096 |
$ 34,506 |
|
|
|
|
Net loss to Distributable Cash Flow |
|
|
|
Net loss, as reported |
$ (58,719) |
$ (18,563) |
$ (344,591) |
Depreciation, depletion and amortization
expense |
14,645 |
20,406 |
22,615 |
Impairment |
68,344 |
-- |
378,587 |
(Gain) loss from risk management activities,
net |
(19,534) |
10,323 |
(93,786) |
Total derivative settlements |
13,430 |
(4,846) |
8,856 |
Capital expenditures-maintenance related |
(10,326) |
(15,009) |
(14,584) |
Non-cash mark-to-market of Upstream product
imbalances |
126 |
(6) |
2 |
Restricted units non-cash amortization
expense |
1,856 |
2,583 |
1,208 |
Income tax benefit |
(826) |
(865) |
(2,767) |
Cash income taxes |
(98) |
-- |
-- |
Discontinued operations |
966 |
10,603 |
348 |
Loss on short-term investments |
2,004 |
-- |
62,028 |
Distributable Cash Flow |
$ 11,868 |
$ 4,626 |
$ 17,916 |
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
(MM) (NASDAQ:EROC)
Historical Stock Chart
From Jun 2024 to Jul 2024
(MM) (NASDAQ:EROC)
Historical Stock Chart
From Jul 2023 to Jul 2024