Eagle Rock Reports Third Quarter 2012 Financial Results

Eagle Rock Reports Third Quarter 2012 Financial Results

HOUSTON, Oct. 31, 2012 (GLOBE NEWSWIRE) -- Eagle Rock Energy Partners, L.P.
(together with its subsidiaries, "Eagle Rock" or the "Partnership")
(Nasdaq:EROC) today announced its unaudited financial results for the three
months ended September 30, 2012. Key financial results with respect to third
quarter 2012 included the following:

  *Reported Adjusted EBITDA of $59.1 million, up from the $57.7 million
    reported for the second quarter of 2012, despite lower
    quarter-over-quarter crude oil and natural gas liquids (NGL) prices.
  *Reported Distributable Cash Flow of $27.0 million, a decrease as compared
    to the $31.6 million reported for the second quarter of 2012, primarily
    resulting from higher maintenance capital expenditures and higher interest
    expense during the quarter.
  *Announced a quarterly distribution with respect to the third quarter of
    2012 of $0.22 per common unit, equivalent to $0.88 per unit on an
    annualized basis.This distribution is equal to the distribution paid for
    the second quarter 2012 and represents a 10% increase over that paid for
    the third quarter of 2011.
  *Reported a Net Loss of $106.9 million compared to Net Income of $61.8
    million reported for the second quarter of 2012; the decrease was driven
    almost entirely by unrealized mark-to-market losses on commodity hedges
    and impairments, both of which are non-cash charges to earnings.

Other notable financial and operational activities of the Partnership since
June 30, 2012, included the following:

  *Closed the acquisition of BP America Production Company's ("BP") midstream
    assets in the Texas Panhandle (the "BP Acquisition") on October 1, 2012,
    for total consideration of $230.6 million in cash. In conjunction with the
    acquisition, Eagle Rock entered into a 20-year, fixed-fee gas gathering
    and processing agreement with BP covering a dedicated acreage area.
  *Announced an amendment to Eagle Rock's existing gas gathering and
    processing agreement with Anadarko E&P Company LP to, among other things,
    (i) expand the original dedication area by adding a 10-year dedication for
    any new wells drilled in an additional area of approximately 800,000 acres
    in western Louisiana and (ii) provide for a fixed-fee gathering
    arrangement for all new wells spud on or after April 1, 2012 in either the
    original or additional dedication areas.
  *Announced the Upstream component of the borrowing base under the
    Partnership's senior secured credit facility was increased by 17% to $400
    million by its commercial lenders as part of its regularly scheduled
    semi-annual redetermination.
  *Completed a public offering of 10,120,000 common units for total net
    proceeds of approximately $84.5 million on August 17, 2012. The
    Partnership used the proceeds to repay a portion of the outstanding
    borrowings under its revolving credit facility in advance of funding the
    BP Acquisition on October 1, 2012.
  *Completed a private offering of $250 million of 8.375% senior unsecured
    notes on July 13, 2012, due 2019.The Partnership used the proceeds to
    repay outstanding borrowings under its revolving credit facility.

"We posted a solid quarter despite a continuing challenging commodity price
environment," said Joseph A. Mills, Eagle Rock's Chairman and Chief Executive
Officer. "We have further positioned Eagle Rock for future growth and greater
cash flow stability with the BP Acquisition and the expansion of our
relationship with Anadarko in western Louisiana, both of which are
meaningfully based on fixed-fee contract structures. In addition, we continue
to focus our Upstream capital activity in the Golden Trend and the Southeast
Cana Woodford plays and to further evaluate the full resource potential of our
acreage position in the South Central Oklahoma Oil Province ("SCOOP") area."

Update Regarding BP Acquisition and Integration

On October 1, 2012, the Partnership completed the acquisition of BP's Sunray
and Hemphill processing plants and associated 2,500 mile gathering system
serving the liquids-rich Texas Panhandle (the "BP Panhandle System") for
$230.6 million, as adjusted under the Purchase and Sale Agreement. As of
September 30, 2012, $22.8 million was held as a deposit on the acquisition.
The remaining purchase price was funded on October 1, 2012, through borrowings
on the Partnership's revolving credit facility.

In addition, Eagle Rock and BP entered into a 20-year, fixed-fee gas gathering
and processing agreement.Under the agreement, Eagle Rock is gathering and
processing BP's natural gas production from existing connected wells, and BP
has committed itself and its farmees to Eagle Rock for the term of the
agreement, under substantially the same gas gathering and processing terms,
for all future natural gas production from new wells drilled within an initial
two-year period from closing, subject to mutually-agreed extensions, and
within a two-mile radius of the BP Panhandle System. The BP Panhandle System
gathering volumes in the first half of 2012 averaged approximately 180 MMcf/d,
and the Partnership expects to continue to grow its overall gathering volumes
from the Texas Panhandle area based on expected drilling programs of BP and
third party producers active in the area.

Eagle Rock is currently in the process of integrating the BP Panhandle System
with its existing system in the area, which will result in approximately 6,463
miles of combined gathering pipelines serving over 5,000 wells and over 480
MMcf/d of combined processing capacity in the Texas Panhandle; an additional
60 MMcf/d of capacity is expected to come on-line in the first half of 2013
following the completion of Eagle Rock's Wheeler Plant. The combined system
will strengthen Eagle Rock's position in the growing Granite Wash, Cleveland,
Tonkawa and Hogshooter plays and provide increased flexibility and capacity in
serving its producer customers.

As anticipated at the time of the announcement of the acquisition, Eagle Rock
expects the integration of the two systems, including the planned
interconnects, to be completed in the second quarter of 2013 and to result in
future cost savings and an enhanced ability to optimize the total gathering
and processing capacity.

Activity in the Texas Panhandle remains robust with approximately 10 active
rigs in the area dedicated to the combined Eagle Rock and BP Panhandle systems
and over 400 wells permitted over the past six months in the Texas Panhandle
region.

Update Regarding Construction of the Wheeler Processing Plant

In 2011, the Partnership announced plans for an additional high-efficiency
cryogenic processing plant to be installed in the Texas Panhandle – the
Wheeler Plant.

Construction of the 60 MMcf/d Wheeler Plant, located in Wheeler County, and
associated gathering and compression infrastructure is expected to be
completed in the first half of 2013 at a cost of approximately $67 million, of
which $32.4 million was spent through September 30, 2012. The addition of the
Wheeler Plant to the Partnership's existing processing infrastructure in the
Texas Panhandle Segment is in response to incremental processing demand driven
by continued drilling activity in the Granite Wash, Cleveland and Tonkawa
plays.

Amendment to Existing Gathering and Processing Agreement with Anadarko E&P
Company LP

On October 3rd, the Partnership announced that it had entered into an
Amendment (the "Amendment") to its existing Gas Gathering and Processing
Agreement (the "Agreement") with Anadarko E&P Company LP ("Anadarko") to
support Anadarko's drilling program in western Louisiana.The Amendment, among
other things, (i) expands the original dedication area of approximately 1.1
million acres (which remains life-of-lease dedicated) by adding a 10-year
dedication for any new wells drilled in an additional area of approximately
800,000 acres in western Louisiana, (ii) provides for a fixed gathering fee
arrangement (rather than a commodity-price sensitive processing fee) for all
wells spud on or after April 1, 2012 in either the original or additional
dedication areas, and (iii) revises the mechanism that provides for Eagle
Rock's recovery of capital expenditures for connecting its pipelines to
Anadarko-operated wells spud on or after April 1, 2012.

Update Regarding the Partnership's Position in the South Central Oklahoma Oil
Province ("SCOOP")

Eagle Rock's Golden Trend field and Southeast Cana leasehold are located in
the heart of the South Central Oklahoma Oil Province ("SCOOP") in Grady,
McClain and Garvin Counties, Oklahoma recently highlighted by Continental
Resources Inc. and other producers. The Partnership owns approximately 14,000
net acres in the "SCOOP" area that produce from multiple formations including
horizontal completions in the Woodford shale. During most of 2012, the
Partnership has operated three drilling rigs and participated in third party
operated wells in the Golden Trend and Southeast Cana, drilling both vertical
tests through multiple formations and horizontal Woodford wells.Eagle
Rock'sinitial operated Southeast Cana horizontal Woodford well, the Beckham
1-27H, is producing to sales and averaged 4.3 MMcfd and 197 Bopd in its first
thirty days of production.A second operated well and two non-operated wells
are currently drilling, and a third non-operated well is waiting on
completion.

"We are excited about both our and the industry's production results from the
Woodford horizontal drilling in Southeast Cana," said Joseph A. Mills, Eagle
Rock's Chairman and Chief Executive Officer."Our Golden Trend field and
primary term leasehold in Southeast Cana are extremely well-positioned in the
de-risked portion of this extended Woodford horizontal drilling play."

Third Quarter 2012 Financial and Operating Results

During the fourth quarter of 2011, the East Texas/Louisiana, South Texas and
Gulf of Mexico segments were collapsed into a single reporting segment and a
new Marketing and Trading reporting segment was created.The Midstream
Business's financial results are now reported in the following segments: (i)
Texas Panhandle, which no longer includes the results of the Partnership's
Marketing and Trading operations, (ii) East Texas and Other Midstream, which
consolidates Eagle Rock's former East Texas/Louisiana, South Texas and Gulf of
Mexico segments, and (iii) Marketing and Trading, which is a new reporting
segment. Operating results for the reportable segments have been recast for
2011 to reflect these changes.The Partnership's Upstream segment and
functional (Corporate) segments were not affected.

The following discussion of Eagle Rock's operating income by business segment
compares the Partnership's financial results in the third quarter of 2012 to
those of the second quarter of 2012. The Partnership believes comparing these
periods is more illustrative of current operating trends than comparing the
current quarter to results achieved in the third quarter of 2011. Please refer
to the financial tables at the end of this release for further detailed
information.

Midstream Business – Operating income from continuing operations, excluding
the impact of impairments, for the Midstream Business in the third quarter of
2012 decreased by approximately $3.8 million compared to the second quarter of
2012.This decrease was due to lower average NGL and condensate realized
prices and a 13% decrease in combined equity NGL and condensate volumes.
Midstream gathered volumes rose compared to the second quarter as a result of
increased volumes in the Partnership's Texas Panhandle segment, which were
attributable to a full quarter of service from the Woodall and
Phoenix-Arrington Ranch Plants and higher gathering volumes resulting from
increased drilling in the area as compared to the second quarter. These gains
were offset by lower gathering volumes in the Partnership's East Texas and
Other segment, primarily associated with loss of production in the Gulf of
Mexico due to Hurricane Isaac, which formed on August 21, 2012, and continued
production declines in South Texas.

In the Texas Panhandle, gathered volumes were up approximately 37%, with
combined equity NGL and condensate volumes down approximately 15%, compared to
the second quarter of 2012.The decline in combined equity NGL and condensate
volumes was partially attributable to reduced efficiencies at the
Partnership's Phoenix-Arrington Ranch Plant, which was placed back into
service on July 2, 2012 after an incident in April 2012 caused the plant to be
shut down. Due to re-start issues, however, the Phoenix-Arrington Ranch Plant
continues to operate at reduced NGL recovery rates.

Equity volumes were also negatively impacted by constrained processing
capacity at the 60 MMcf/d Woodall Plant, located in Hemphill County, Texas,
which was placed into service on May 30, 2012. Throughput at the plant peaked
at over 45 MMcf/d in early June before Woodall Plant throughput was
constrained as a result of a third-party incident on June 5, 2012 involving
the residue gas pipeline downstream ofEagle Rock'splant tailgate. The
Partnership mitigated this reduced flow by utilizing capacity on a back-up
residue outlet but constraints remained on the ability to flow at full
capacity. In September, the Partnership connected into a new residue outlet,
which has fully alleviated the processing restrictions, and the Woodall Plant
is currently running at full capacity. Eagle Rock estimates that its results
were negatively impacted by this downstream incident by approximately $2.5
million during the quarter.

The Partnership's Texas Panhandle segment is currently gathering approximately
420 MMcf/d, which consists of 225 MMcf/d attributable to legacy Eagle Rock
processing facilities and approximately 195 MMcf/d attributable to the
recently acquired BP Texas Panhandle assets.

In the East Texas and Other Midstream segment, gathered volumes were down
approximately 7%, with combined equity NGL and condensate volumes also down
approximately 7%, compared to the second quarter of 2012. The decrease in
gathered volumes and combined equity NGL and condensate volumes was due to
natural declines in the production of existing wells, loss of production in
the Gulf of Mexico due to Hurricane Isaac, and reduced drilling activity in
South Texas.Partially offsetting the declines, gathering volumes around the
Partnership's systems servicing the liquids-rich Austin Chalk play in East
Texas increased approximately 3% as compared to the second quarter of 2012.

The Partnership's Yscloskey Plant in Louisiana, in which Eagle Rock has a
non-operated ownership interest, suffered significant damage from Hurricane
Isaac in August 2012. The Yscloskey Plant has been shut down since that time.
The Partnership estimates that its results were negatively impacted by
approximately $250,000 during the quarter as a consequence of the Yscloskey
Plant downtime.

The Marketing and Trading segment includes the financial results of the
Partnership's crude oil and condensate marketing, and natural gas marketing
and trading operations. Eagle Rock's crude oil and condensate marketing
effort was established in 2010 to develop and implement marketing uplift
strategies for crude and condensate in Alabama and in the Texas Panhandle.
Eagle Rock's natural gas marketing and trading operations were established in
2011 to capitalize on physical and financial natural gas marketing and trading
opportunities that extend from the Partnership's upstream and midstream
assets. Operating income for the Marketing and Trading segment in the third
quarter of 2012, including intercompany sales and intersegment cost of sales,
increased by approximately $337,000, or 52%, compared to the second quarter of
2012, primarily due to higher natural gas prices during the quarter and
increased throughput.

In addition, timing of the Partnership's condensate sales in Alabama were
negatively impacted by Hurricane Isaac, which made landfall on the coasts of
Louisiana and Alabama in August 2012. Due to the storm, all maritime commerce
in the region, including barge operations into and out of oil storage and
processing facilities such asthe Partnership'sleased storage at a
third-party terminal in Mobile, Alabama, was halted. The storm and subsequent
clean-up and repair operations caused Eagle Rock's inventory levels to
increase by about 50,000 barrels, which negatively impacted the Partnership's
results by approximately $2.8 million during the quarter (recorded in the
Corporate Segment as an intercompany elimination). Barge operations resumed
during the second week of October, and the Partnership has since sold its
excess inventory.Eagle Rock expects its condensate inventory levels to return
to normal levels in the fourth quarter.

Upstream Business - Operating income for Eagle Rock's Upstream Business in the
third quarter of 2012, excluding the impact of impairments, increased by
approximately$5.0 million, or 51%, compared to the second quarter of
2012.The increase was attributable to increased production and lower unit
operating costs during the quarter, which were partially offset by lower
realized crude oil, NGL and sulfur prices.

Production volumes in the Upstream Business averaged 85.3 MMcfe/d during the
quarter, an increase of approximately 3% compared to the second quarter of
2012. The production increase was driven primarily by the Partnership's
drilling program in the Mid-Continent and by improved run-times at its Big
Escambia Creek facility.

Total capital expenditures for the Upstream Segment in the third quarter were
approximately $43.8 million, down by approximately $1.8 million as compared to
the second quarter of 2012. Through the third quarter of 2012, the Partnership
has spent approximately $8.6 million in capital expenditures related to
previously-disclosed upgrades to its Alabama operations in order to fulfill
permit obligations and comply with new environmental standards. The
Partnership expects to spend a total of approximately $60 million on these
upgrades through 2014, inclusive of the $8.6 million spent through the third
quarter of 2012.

Corporate Segment – Operating loss for the Corporate segment, excluding the
impact of unrealized derivative gains and losses, was $4.3 million for the
third quarter of 2012 as compared to a loss of $2.6 million for the second
quarter of 2012. The decrease was attributable to lower realized commodity
derivative gains and intercompany eliminations for the third quarter, which
was partially offset by lower General and Administrative expenses for the
quarter compared to the second quarter of 2012.

Total revenue for the third quarter of 2012, excluding the impact of Eagle
Rock's realized and unrealized commodity derivative gains and losses, was
$198.9 million, up 7% compared with the $186.4 million reported for the second
quarter of 2012.The increase in revenue was primarily due to increased sales
of natural gas, NGLs, crude oil, condensate and sulfur as compared to the
second quarter of 2012.Eagle Rock recorded an unrealized loss on commodity
derivatives of $51.3 million in the third quarter 2012, as compared to an
unrealized gain on commodity derivatives of $79.5 million in the second
quarter 2012.Unrealized gain (loss) on commodity derivatives is a non-cash,
mark-to-market amount.

Revenues less cost of goods sold associated with the sale of crude oil,
natural gas, NGLs, condensate and sulfur decreased by approximately $1.0
million relative to the second quarter of 2012, driven primarily by lower
average realized NGL and crude prices. Adjusted EBITDA for the third quarter
of 2012 was $59.1 million, up 3% from the second quarter of 2012, and
Distributable Cash Flow was $27.0 million for the third quarter of 2012, down
14% as compared to the second quarter of 2012. The decrease was attributable
to higher interest expense following the senior notes issuance in July 2012
and to higher maintenance capital spending. The Partnership recorded $2.8
million of maintenance capital in the third quarter of 2012 related to the
Alabama facility upgrades discussed above, relative to $1.5 million of such
spending in the second quarter of 2012.

The Partnership recorded a net loss of approximately $106.9 million for the
third quarter of 2012, versus net income of $61.8 million for the second
quarter of 2012. The net loss was driven primarily by unrealized, non-cash
mark-to-market losses totaling $51.3 million on the Partnership's commodity
derivative portfolio and by an impairment charge of $55.9 million taken during
the quarter. The Partnership incurred impairment charges in its Upstream
Business related to its proved properties in the Barnett Shale that
experienced reduced revenues resulting from lower natural gas prices and
continuing relatively high operating costs associated with gas compression.
The Partnership also incurred impairment charges in its Midstream Business
primarily related to the substantial damage incurred at the Yscloskey
processing plant as a result of Hurricane Isaac in August 2012.

Third Quarter Distribution

On October 24, 2012, the Partnership declared a cash distribution of $0.22 per
common and restricted unit for the quarter ended September 30, 2012,
equivalent to $0.88 per unit on an annualized basis.This distribution is
equal to the distribution paid for the second quarter 2012 and represents a
10% increase over the distribution paid for the third quarter of 2011.The
distribution will be paid on Wednesday, November 14, 2012 to unitholders of
record as of the close of business on Wednesday, November 7, 2012.

Capitalization and Liquidity Update

Total debt outstanding as of September 30, 2012 was $875.4 million, consisting
of $544.4 million of senior unsecured notes (net of an unamortized debt
discount of $5.6 million) and borrowings of $331.0 million under the
Partnership's senior secured credit facility. Borrowings during the third
quarter of 2012 were primarily attributable to capital spending related to the
Partnership's Wheeler Plant and Big Escambia Creek facility, new drilling
activity in the Mid-Continent, and the $22.8 million deposit made for the BP
Acquisition.

On July 13, 2012, the Partnership completed the sale of an additional $250.0
million of 8.375% senior unsecured notes through a private placement exempt
from the registration requirements of the Securities Act of 1933. After the
original discount of $3.7 million and excluding related offering expenses, the
Partnership received net proceeds of approximately $246.3 million, which were
used to repay borrowings outstanding under its revolving credit facility.The
issuance supplemented the Partnership's prior $300 million of senior notes
issued in May 2011, all of which are treated as a single series.

On August 17, 2012, the Partnership completed a public offering of 10,120,000
common units for total net proceeds of approximately $84.5 million. The
Partnership used the proceeds to repay outstanding borrowings under its
revolving credit facility in advance of funding the BP Acquisition on October
1, 2012. In addition, Eagle Rock issued 691,020 common units in the third
quarter of 2012 under its equity shelf program for total net proceeds of
approximately $6.1 million.

Availability under the credit facility is subject to a borrowing base
comprised of two components: the upstream component and the midstream
component.As of September 30, 2012, the Partnership had approximately $328.5
million of availability under its credit facility, based on its outstanding
commitments, after taking into account $331 million of outstanding borrowings
and approximately $15.6 million of outstanding letters of credit. On October
1, 2012, Eagle Rock borrowed approximately $207.9 million under its credit
facility in connection with closing the BP Acquisition.

On October 9, 2012, the Partnership announced that the Upstream Segment
component of the borrowing base under its revolving credit facility was
increased to $400 million by its commercial lenders as part of its regularly
scheduled semi-annual borrowing base redetermination. This represents an
increase of $58 million from the previous level of $342 million. The
redetermined borrowing base was effective October 1, 2012, with no additional
fees or increase in interest rate spread incurred. The total borrowing
capacity under the Partnership's credit facility is limited to the lower of
the borrowing base and the total lender commitments, which remain unchanged at
$675 million.

As of September 30, 2012, the Partnership had 147.4 million units outstanding,
including unvested restricted common units outstanding under its Long-Term
Incentive Plan.

Hedging Update

The Partnership has entered into the following commodity hedges since its last
hedging update on August 1, 2012:

Transaction Date Product / (Type) Quantity    Price ($/MMBtu) Term
10/1/12          HH Natural Gas   150,000     $4.36           Cal. 2015
                (Swap)           MMbtu/month                
9/25/12          WTI Crude        30,000      $90.65          Cal. 2014
                (Swap)           Bbls/month                 
9/25/12          WTI Crude        15,000      $93.50          Cal. 2013
                (Swap)           Bbls/month                 
9/24/12          HH Natural Gas   400,000     $4.02           Cal. 2014
                (Swap)           MMbtu/month                
9/24/12          HH Natural Gas   300,000     $3.62           Cal. 2013
                (Swap)           MMbtu/month                

Details of the recent hedging transactions are included in the updated
Commodity Hedging Overview presentation Eagle Rock posted on October 31, 2012
to its website. The latest presentation can be accessed by going to
www.eaglerockenergy.com: select Investor Relations, then select Presentations.

In July 2012, in conjunction with the Partnership's issuance of $250.0 million
of senior unsecured notes, which increased its fixed interest rate exposure,
the Partnership terminated the full $200.0 million notional amount of its
existing 4.295% and 4.095% fixed rate interest rate swaps at a cost of $3.9
million.

Third Quarter Earnings Conference Call Information

The third quarter 2012 earnings conference call will be held at 2:00 p.m.
Eastern Time (1:00 p.m. Central Time) on Thursday, November 1, 2012.

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 43758738.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
43758738.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

The Partnership is a growth-oriented master limited partnership engaged in two
businesses: a) midstream, which includes (i) gathering, compressing, treating,
processing and transporting natural gas; (ii) fractionating and transporting
natural gas liquids (NGLs); (iii) crude oil logistics and marketing; and (iv)
natural gas marketing and trading; and b) upstream, which includes exploiting,
developing, and producing hydrocarbons in oil and natural gas properties.

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 realized interest rate risk
management instruments 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; unrealized (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 more accurately 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 more accurately 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 more accurate 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. For example,
the Partnership includes in Adjusted EBITDA the actual settlement revenue
created from its commodity hedges by virtue of transactions undertaken by it
to reset commodity hedges to prices higher than those reflected in the forward
curve at the time of the transaction or to purchase puts or other similar
floors despite the fact that the Partnership excludes from Adjusted EBITDA any
charge for amortization of the cost of such commodity hedge reset transactions
or puts. Eagle Rock has reconciled Adjusted EBITDA to the GAAP financial
measure of net income (loss) at the end of this release.

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 made to
replace partially or fully depreciated assets; to meet regulatory
requirements; to maintain the existing operating capacity of the Partnership's
gathering, processing and treating assets or to maintain the Partnership's
natural gas, NGL, crude or sulfur 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. See the
example given above for Adjusted EBITDA related to amortization of costs of
commodity hedges, including costs of hedge reset transactions. Eagle Rock has
reconciled Distributable Cash Flow to the GAAP financial measure of net
income/(loss) at the end of this release.

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; market demand for crude oil, natural gas and
natural gas liquids; the effectiveness of the Partnership's hedging
activities; the Partnership's ability to retain key customers; the
Partnership's ability to continue to obtain new sources of crude oil and
natural gas supply; 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 Securities and Exchange Commission ("SEC") for the year ended
December 31, 2011 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
                    Three Months Ended      Nine Months Ended      Months
                                                                    Ended
                    September 30,           September 30,          June 30,
                    2012         2011       2012        2011       2012
REVENUE:                                                        
Natural gas, natural
gas liquids, oil,    $184,494   $264,119 $580,152  $732,491 $172,945
condensate and
sulfur sales
Gathering,
compression,         13,604      11,567    35,566     37,116    10,451
processing and
treating fees
Unrealized commodity
derivative (losses)  (51,305)    97,011    13,426     86,164    79,502
gains
Realized commodity
derivative gains     15,802      (2,698)   38,428     (17,958)  16,463
(losses)
Other revenue        794         141       3,976      1,406     3,043
Total revenue        163,389     370,140   671,548    839,219   282,404
                                                               
COSTS AND EXPENSES:                                             
Cost of natural gas
and natural gas      110,430     166,293   338,798    486,286   97,914
liquids
Operations and       27,074      24,897    81,685     66,323    27,562
maintenance
Taxes other than     4,748       4,556     14,518     13,061    4,620
income
General and          16,807      16,068    52,384     43,746    18,736
administrative
Other operating      --         --       --        (2,893)   --
income
Impairment           55,900      9,870     122,824    14,754    21,402
Depreciation,
depletion and        40,395      35,040    118,043    90,314    38,354
amortization
Total costs and      255,354     256,724   728,252    711,591   208,588
expenses
OPERATING(LOSS)     (91,965)    113,416   (56,704)   127,628   73,816
INCOME
OTHER INCOME                                                    
(EXPENSE):
Interest expense,    (14,199)    (10,050)  (35,087)   (19,579)  (10,647)
net
Realized interest
rate derivative      (1,733)     (3,713)   (8,578)    (13,374)  (3,470)
losses
Unrealized interest
rate derivative      615         (3,165)   4,418      2,191     2,007
(losses) gains
Other (expense)      1           (3)       (44)       (167)     4
income, net
Total other income   (15,316)    (16,931)  (39,291)   (30,929)  (12,106)
(expense)
(LOSS) INCOME FROM
CONTINUING           (107,281)   96,485    (95,995)   96,699    61,710
OPERATIONS BEFORE
INCOME TAXES
INCOME TAX BENEFIT   (386)       (1,077)   (556)      (1,810)   (79)
(LOSS) INCOME FROM
CONTINUING           (106,895)   97,562    (95,439)   98,509    61,789
OPERATIONS
DISCONTINUED
OPERATIONS, NET OF   --         (197)     --        210       --
TAX
NET (LOSS) INCOME    $(106,895) $97,365  $(95,439) $98,719  $61,789




Eagle Rock Energy Partners, L.P.
Consolidated Balance Sheets
($ in thousands)
(unaudited)
                                                      
                                    September 30, 2012 December 31, 2011
ASSETS                                                 
CURRENT ASSETS:                                        
Cash and cash equivalents            $194             $877
Accounts receivable                  96,637            97,832
Risk management assets               33,963            13,080
Prepayments and other current assets 13,547            13,739
Total current assets                 144,341           125,528
PROPERTY, PLANT AND EQUIPMENT- Net  1,792,414         1,763,674
INTANGIBLE ASSETS- Net              85,917            109,702
DEFERRED TAX ASSET                   1,449             1,432
RISK MANAGEMENT ASSETS               14,354            24,290
OTHER ASSETS                         44,414            21,062
TOTAL                                $2,082,889       $2,045,688
                                                      
LIABILITIES AND MEMBERS' EQUITY                        
CURRENT LIABILITIES:                                   
Accounts payable                     $135,960         $145,985
Accrued liabilities                  29,753            12,734
Taxes payable                        372               487
Risk management liabilities          1,396             11,649
Total current liabilities            167,481           170,855
LONG-TERM DEBT                       875,446           779,453
ASSET RETIREMENT OBLIGATIONS         35,145            33,303
DEFERRED TAX LIABILITY               43,898            45,216
RISK MANAGEMENT LIABILITIES          3,012             6,893
OTHER LONG TERM LIABILITIES          2,522             2,621
COMMITMENTS AND CONTINGENCIES                          
MEMBERS' EQUITY:                                       
Members' equity                      955,385           1,007,347
TOTAL                                $2,082,889       $2,045,688





Eagle Rock Energy Partners, L.P.
Segment Summary
Operating Income
($ in thousands)
(unaudited)
                                                             
                Three Months Ended       Nine Months Ended      Three Months
                                                                  Ended
                September 30,            September 30,           June 30,
                2012         2011        2012         2011       2012
Midstream                                                     
Revenues:                                                     
Natural gas,
natural gas      $147,099   $213,593  $468,355   $624,939 $140,324
liquids, oil and
condensate sales
Intercompany
sales - natural  (2,846)     (1,403)    (7,809)     (1,403)   (2,113)
gas
Gathering and
treating         13,604      11,567     35,566      37,116    10,451
services
Other            --         --        2,864       --       2,864
Total revenue    157,857     223,757    498,976     660,652   151,526
Cost of natural
gas, natural gas 110,430     166,293    338,798     486,286   97,914
liquids, oil and
condensate
Intersegment
elimination -    8,598       8,825      32,612      29,817    10,383
cost of
condensate
Operating costs                                               
and expenses:
Operations and   17,647      16,716     53,178      48,081    18,164
maintenance
Impairment       35,840      --        101,979     4,560     20,617
Depreciation,
depletion and    16,488      16,093     49,735      48,250    16,565
amortization
Total operating
costs and        69,975      32,809     204,892     100,891   55,346
expenses
Operating
(loss)income    (31,146)    15,830     (77,326)    43,658    (12,117)
from continuing
operations
Discontinued     --         (197)      --         (194)     --
Operations (1)
Operating (loss) $(31,146)  $15,633   $(77,326)  $43,464  $(12,117)
income
                                                             
Upstream (2)                                                  
Revenues:                                                     
Oil and          $14,376    $17,269   $44,088    $33,799  $12,247
condensate sales
Intersegment
sales -          11,431      7,451      34,226      29,975    10,306
condensate
Natural gas      8,324       16,014     22,474      31,294    6,832
sales (3)
Intersegment
sales - natural  2,846       1,403      7,809       1,403     2,113
gas
Natural gas
liquids sales    10,979      12,186     34,060      29,678    10,340
(4)
Sulfur Sales (5) 3,716        5,057       11,175       12,781     3,202
Other            794         141        1,112       1,406     179
Total revenue    52,466      59,521     154,944     140,336   45,219
Operating costs                                               
and expenses:
Operations and   14,175      12,737     43,025      31,369    14,018
maintenance (1)
Intersegment
operations and   --         --        --         --       --
maintenance
Impairment       20,060      9,870      20,845      10,194    785
Depreciation,
depletion and    23,484      18,636     67,070      41,046    21,366
amortization
Total operating
costs and        57,719      41,243     130,940     82,609    36,169
expenses
Operating (loss) $(5,253)   $18,278   $24,004    $57,727  $9,050
income
                                                             
Corporate and                                                 
Other
Revenues:                                                     
Unrealized
commodity        $(51,305)  $97,011   $13,426    $86,164  $79,502
derivative
(losses) gains
Realized
commodity        15,802      (2,698)    38,428      (17,958)  16,463
derivative
gains(losses)
Intersegment
elimination -    (11,431)    (7,451)    (34,226)    (29,975)  (10,306)
sales of
condensate
Total revenue    (46,934)    86,862     17,628      38,231    85,659
Costs and                                                     
expenses:
Intersegment
elimination -    (8,598)     (8,825)    (32,612)    (29,817)  (10,383)
cost of
condensate
General and      16,807      16,068     52,384      43,746    18,736
administrative
Intersegment
elimination -    --         --        --         (66)      --
operations and
maintenance
Other operating  --         --        --         (2,893)   --
Income
Depreciation,
depletion and    423         311        1,238       1,018     423
amortization
Operating (loss) $(55,566)  $79,308   $(3,382)   $26,243  $76,883
income
                                                             
(1) Includes natural gas sales of $66 from the East Texas and Other Midstream
Texas Segment to the Upstream Segment for the nine months ended September 30,
2011, respectively.
(2)Includes operations related to the Crow Creek Acquisition starting on May
3, 2011.
(3) Revenues include a change in the value of product imbalances of $18,
$(37), $(38) and $22 for the three and nine months ended September30, 2012
and 2011, respectively, and $(49) for the three months ended June30, 2012.
(4) Revenues include a change in the value of product imbalances of $(215) ,
$(301), $270 and $155 for the three and nine months ended September30, 2012
and 2011, respectively, and $(257) for the three months ended June30, 2012.
(5) Revenues include a change in the value of product imbalances of $(32) ,
$0, $(125) and $(54) for the three and nine months ended September30, 2012
and 2011, respectively, and $(2) for the three months ended June30, 2012.




Eagle Rock Energy Partners, L.P.
Midstream Segment
Operating Income
($ in thousands)
(unaudited)
                                                             
                   Three Months Ended    Nine Months Ended      Three Months
                                                                  Ended
                   September 30,         September 30,           June 30,
                   2012        2011      2012         2011       2012
Texas Panhandle                                               
Revenues:                                                     
Natural gas,
natural gas         $60,213   $90,420 $189,230   $304,813 $55,937
liquids, oil and
condensate sales
Intersegment sales
- natural gas and   28,025     26,247   72,514      26,247    19,043
condensate
Gathering,
compression,        4,708      4,892    13,510      12,905    3,852
processing and
treating services
Other               --        --      2,864       --       2,864
Total revenue       92,946     121,559  278,118     343,965   81,696
Cost of natural
gas, natural gas    67,098     87,797   189,703     247,512   51,117
liquids, oil and
condensate
Operating costs and                                           
expenses:
Operations and      12,705     10,826   37,342      31,434    12,399
maintenance
Impairment          --        --      --         4,560     --
Depreciation,
depletion and       10,164     9,145    29,554      27,382    9,873
amortization
Total operating     22,869     19,971   66,896      63,376    22,272
costs and expenses
Operating income    $2,979    $13,791 $21,519    $33,077  $8,307
                                                             
East Texas and                                                
Other Midstream
Revenues:                                                     
Natural gas,
natural gas         $26,130   $59,590 $98,398    $193,785 $30,998
liquids, oil and
condensate sales
Intercompany Sales  10,020     4,330    26,471      4,330     6,928
- natural gas
Gathering,
compression,        8,896      6,675    22,056      24,211    6,599
processing and
treating services
Total revenue       45,046     70,595   146,925     222,326   44,525
Cost of natural
gas, natural gas    33,145     56,536   111,203     176,202   32,550
liquids and
condensate
Operating costs and                                       
expenses:
Operations and      4,940      5,888    15,833      16,645    5,764
maintenance
Impairment          35,840     --      101,979     --       20,617
Depreciation,
depletion and       6,232      6,948    20,034      20,868    6,667
amortization
Total operating     47,012     12,836   137,846     37,513    33,048
costs and expenses
Operating income
(loss) from         (35,111)   1,223    (102,124)   8,611     (21,073)
continuing
operations
Discontinued        --        (197)    --         (194)     --
Operations
Operating income    $(35,111) $1,026  $(102,124) $8,417   $(21,073)
(loss)
                                                             
Marketing and                                                 
Trading
Revenues:                                                     
Natural gas, oil
and condensate      $60,756   $63,583 $180,727   $126,341 $53,389
sales
Intercompany sales
- natural gas and   (40,891)   (31,980) (106,794)   (31,980)  (28,084)
condensate
Total revenue       19,865     31,603   73,933      94,361    25,305
Cost of natural gas
and natural gas     10,187     21,960   37,892      62,572    14,247
liquids
Intersegment cost
of sales -          8,598      8,825    32,612      29,817    10,383
condensate
Operating costs and                                           
expenses:
Operations and      2          2        3           2         1
maintenance
Depreciation,
depletion and       92         --      147         --       25
amortization
Total operating     94         2        150         2         26
costs and expenses
Operating income    $986      $816    $3,279     $1,970   $649




Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)
                                                               
                                                                    Three
                   Three Months Ended      Nine Months Ended      Months
                                                                    Ended
                   September 30,           September 30,           June 30,
                   2012         2011       2012         2011       2012
Gas gathering
volumes - (Average                                              
Mcf/d)
Texas Panhandle     183,415     163,665   159,229     154,011   133,590
East Texas and      248,094     312,103   268,512     331,003   265,472
Other Midstream
Total               431,509     475,768   427,741     485,014   399,062
                                                               
NGLs - (Net equity                                              
Bbls)
Texas Panhandle (1) 228,696     231,965   855,499     609,097   297,688
East Texas and      81,997      114,280   258,322     345,255   84,981
Other Midstream
Total               310,693     346,245   1,113,821   954,352   382,669
                                                               
Condensate - (Net                                               
equity Bbls)
Texas Panhandle (1) 164,246     260,228   499,660     728,860   163,320
East Texas and      7,010       10,519    28,737      35,426    10,403
Other Midstream
Total               171,256     270,747   528,397     764,286   173,723
                                                               
Natural gas short
position - (Average                                             
MMbtu/d)
Texas Panhandle     (990)       (7,418)   (4,661)     (5,517)   (5,629)
East Texas and      392         1,758     1,482       1,963     3,952
Other Midstream
Total               (598)       (5,660)   (3,179)     (3,554)   (1,677)
                                                               
Average realized                                                
NGL price - per Bbl
Texas Panhandle     $ 36.23      $ 53.39    $ 39.55      $ 55.28    $ 38.30
East Texas and      $ 32.24      $ 52.57    $ 39.45      $ 51.13    $ 39.72
Other Midstream
Weighted Average    $ 34.89      $ 53.08    $ 39.51      $ 53.51    $ 38.85
                                                               
Average realized
condensate price -                                              
per Bbl
Texas Panhandle     $ 81.08      $ 79.43    $ 86.74      $ 82.31    $ 82.29
East Texas and      $ 91.57      $ 93.82    $ 100.66     $ 94.28    $ 103.71
Other Midstream
Total               $ 81.82      $ 79.74    $ 87.94      $ 83.31    $ 83.90
                                                               
Average realized
natural gas price -                                             
per MMbtu
Texas Panhandle     $ 2.64       $ 3.86     $ 2.37       $ 3.95     $ 1.93
East Texas and      $ 2.85       $ 4.36     $ 2.67       $ 4.42     $ 2.22
Other Midstream
Total               $ 2.71       $ 4.05     $ 2.48       $ 4.14     $ 2.04
                                                               
(1) Effective January 2012, reported NGL volumes include those volumes
recovered from our equity condensate through stabilization. These NGL volumes
were previously reported as condensate. This change results in an increase to
reported NGLs equity barrels and a corresponding decrease to reported
condensate equity barrels.

 


Eagle Rock Energy Partners, L.P.
Upstream Operations Information
(unaudited)
                                                                
                                                                     Three
                    Three Months Ended      Nine Months Ended      Months
                                                                     Ended
                    September 30,           September 30,           June 30,
                    2012        2011        2012        2011        2012
Upstream                                                         
Production:                                                      
Oil and condensate   310,349     302,766     900,873     772,350     266,580
(Bbl)
Gas (Mcf)            4,177,156   4,274,811   12,614,258  8,272,176   4,341,298
NGLs (Bbl)           301,644     227,614     848,047     533,223     267,673
Total Mcfe           7,849,113   7,457,091   23,107,779  16,105,615  7,546,811
                                                                
Sulfur (long ton)    28,414      27,706      79,111      71,509      21,705
                                                                
Realized prices,
excluding                                                        
derivatives: (1)
Oil and condensate   $83.16    $81.65    $86.93    $82.57    $84.60
(per Bbl)
Gas (Mcf)            $2.67     $4.08     $2.40     $3.95     $2.06
NGLs (Bbl)           $36.40    $52.35    $40.16    $55.37    $38.63
Sulfur (long ton)    $130.77   $187.03   $141.27   $179.48   $147.55
                                                                
Operating                                                        
statistics:
Operating costs per
Mcfe (incl           $1.60     $1.57     $1.69     $1.88     $1.68
production taxes)
(2)
Operating costs per
Mcfe (excl           $1.11     $1.07     $1.18     $1.23     $1.18
production taxes)
(2)
Operating income per $(0.67)   $2.45     $1.04     $3.58     $1.20
Mcfe
                                                                
Drilling program                                                 
(gross wells):
Development wells    6           13          25          32          9
Completions          6           13          25          32          9
Workovers            10          5           19          13          4
Recompletions        4           4           7           8           1
                                                                
(1) Calculation does not include impact of product                 
imbalances.
(2) Excludes post-production costs of $1,601 and $4,068 for the three and
nine months ended September30, 2012, respectively, $1,031 for both the three
and nine months ended September30, 2011 and $1,319 June30, 2012.




Eagle Rock Energy Partners, L.P.
GAAP to Non-GAAP Reconciliations
($ in thousands)
(unaudited)
                                                                  
                                                                       Three
                        Three Months Ended     Nine Months Ended     Months
                                                                       Ended
                        September 30,          September 30,          June 30,
                        2012         2011      2012        2011       2012
Net (loss) income to                                               
Adjusted EBITDA
Net (loss) income, as    $(106,895) $97,365 $(95,439) $98,719  $61,789
reported
Depreciation, depletion  40,395      35,040   118,043    90,314    38,354
and amortization
Impairment               55,900      9,870    122,824    14,754    21,402
Risk management interest
related instruments -    (615)       3,165    (4,418)    (2,191)   (2,007)
unrealized
Risk management
commodity related        51,305      (97,011) (13,426)   (86,164)  (79,502)
instruments - unrealized
Other Operating Income   --         --      --        (2,893)   --
Non-cash mark-to-market
of Upstream product      229         (107)    338        (123)     307
imbalances
Unrealized losses
(gains) from other       157         (538)    427        (538)     473
derivative activity
Restricted units
non-cash amortization    3,080       1,507    8,092      3,441     2,818
expense
Income tax (benefit)     (386)       (1,077)  (556)      (1,810)   (79)
provision
Interest - net including
realized risk management 15,931      13,766   43,709     33,120    14,113
instruments and other
expense
Other income             --         --      --        --       --
Discontinued operations  --         197      --        (210)     --
Adjusted EBITDA          $59,101    $62,177 $179,594  $146,419 $57,668
                                                                  
Net (loss) income to                                               
Distributable Cash Flow
                                                                  
Net (loss) income, as    $(106,895) $97,365 $(95,439) $98,719  $61,789
reported
Depreciation, depletion  40,395      35,040   118,043    90,314    38,354
and amortization expense
Impairment               55,900      9,870    122,824    14,754    21,402
Risk management interest
related                  (615)       3,165    (4,418)    (2,191)   (2,007)
instruments-unrealized
Risk management
commodity related
instruments and other    51,462      (97,549) (12,999)   (86,702)  (79,029)
derivative activity -
unrealized
Capital
expenditures-maintenance (15,982)    (11,980) (35,824)   (30,311)  (11,816)
related
Non-cash mark-to-market
of Upstream product      229         (107)    338        (123)     307
imbalances
Restricted units
non-cash amortization    3,080       1,507    8,092      3,441     2,818
expense
Other Operating Income   --         --      --        (2,893)   --
Income tax (benefit)     (386)       (1,077)  (556)      (1,810)   (79)
provision
Cash income taxes        (185)       (325)    (749)      (802)     (189)
Discontinued operations  --         197      --        (210)     --
Distributable Cash Flow  $27,003    $36,106 $99,312   $82,186  $31,550

CONTACT: Eagle Rock Energy Partners, L.P.

         Jeff Wood, 281-408-1203
         Senior Vice President and Chief Financial Officer

         Adam Altsuler, 281-408-1350
         Director, Corporate Finance and Investor Relations

company logo
 
Press spacebar to pause and continue. Press esc to stop.