Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message| ()  

Executives

Adam Altsuler - Director of Corporate Finance and Investor Relations of Eagle Rock Energy G&P LLC

Joseph A. Mills - Chairman of Eagle Rock Energy G&P LLC, Chief Executive Officer of Eagle Rock Energy G&P LLC and Member of Enterprise Risk Committee

Jeffrey P. Wood - Chief Financial Officer of Eagle Rock Energy G&P LLC, Senior Vice President of Eagle Rock Energy G&P LLC and Treasurer of Eagle Rock Energy G&P LLC

Joseph E. Schimelpfening - Senior Vice President of Upstream & Minerals Business of Eagle Rock Energy G&P Llc - General Partner of General Partner

Analysts

Kevin A. Smith - Raymond James & Associates, Inc., Research Division

TJ Schultz - RBC Capital Markets, LLC, Research Division

Heejung Ryoo - Barclays Capital, Research Division

Jeffrey Rudner

Jim Spicer - Wells Fargo & Company

Eric B. Anderson - Hartford Financial Management, Inc.

Eagle Rock Energy Partners, L.P. (EROC) Q2 2012 Earnings Call August 2, 2012 2:00 PM ET

Operator

Welcome to the Q2 2012 Eagle Rock Energy Earnings Conference Call. My name is Anthony, and I will be your operator for today's call. [Operator Instructions] Please note that this conference is being recorded. I would now like to turn the call over to Adam Altsuler. Mr. Altsuler, you may begin.

Adam Altsuler

Thank you, Anthony. And thank you to our unitholders, analysts and other interested parties for joining us today on Eagle Rock Energy's second quarter 2012 earnings call.

Before we get started commenting on our second quarter results, there are a few legal items that we would like to cover. First, I want to point out that remarks and answers to questions by partnership representatives on today's call may refer to or contain forward-looking statements. Such remarks or answers are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. Such statements speak only as of today's date or are different as of the date specified. The partnership assumes no responsibility to update any forward-looking statements as of any future date. The partnership has included in its SEC filings cautionary language identifying important factors, but not necessarily all factors, that could cause actual results to be materially different from those set forth in any forward-looking statements. A more complete discussion of these risks included in the partnership's SEC filings, including in our 2011 Annual Report on form 10-K as well as any other public filings. Our SEC filings are publicly available on the SEC's EDGAR system. Also, you may access both the second quarter 2012 earnings press release and a transcript of this call on our website at www.eaglerockenergy.com.

Management will discuss its views on future distributions during this call. Management's objective around future distribution recommendations are subject to change should factors affecting the general business climate, market conditions, commodity prices, our specific operations, performance of our underlying assets, applicable regulatory mandate or our ability to consummate accretive growth projects differ from current expectations. For example, our future distribution recommendations may be lower than current guidance should the current weakness in natural gas prices and NGLs in particular persist beyond early 2013 and impact our and our producer-customers' drilling plans. Actual future distributions will be determined, declared and paid at the discretion of the Board of Directors.

I will now turn the call over to Joe Mills, our Chairman and CEO, for a review of the quarter.

Joseph A. Mills

Good. Thank you, Adam. Good afternoon, ladies and gentlemen. Thank you for joining us today.

We had a decent quarter despite meaningful, unscheduled downtime at 2 of our largest processing facilities and experienced significantly lower commodity prices. We reported adjusted EBITDA of approximately $58 million, down as compared to our first quarter EBITDA of almost $63 million. Distributable cash flow totaled $31.6 million.

Significant events affecting our results this quarter were the incident on our Phoenix-Arrington Ranch Plant in Hemphill County, Texas, which we did discuss with you on our last earnings call and unscheduled downtime at our Big Escambia Creek processing facility located in Southern Alabama. We will discuss the operational issues in more detail in a few minutes.

In addition to these operational issues, we did experience continued downward pressure in commodity prices. Oil, natural gas and NGLs were all down during the quarter. We are hopeful that we've seen the bottom for this year in all the commodities as they have rebounded somewhat since the second quarter.

Jeff's going to highlight in more detail the impact of prices on our financials but suffice to say the downward pressure impacted our results. Despite this volatility, though, our hedge portfolio continues to substantially mitigate the resulting lower operating revenues from these declines in commodity prices.

Offsetting all this negative news, though, was our successful start-up of our newest cryogenic processing facility in the Texas Panhandle, our Woodall plant, and the restart of our Phoenix Plant at the end of the quarter. We're very pleased and excited about Woodall, and I'll share a few more details around this in a few minutes.

Our Upstream business continues to have good drilling results, and absent the downtime at Big Escambia Creek, we would have grown our daily volumes by over 2% as compared to our first quarter daily average. Normalizing our results for the quarter absent the operational issues, we would have delivered a $62 million quarter, which would have been flat to our first quarter.

In light of the challenging commodity price environment and the operational issues we experienced during the quarter, we elected to hold our distribution flat at $0.22 per common unit, payable on August 14 to unitholders of record as of August 7. We announced last week that we do not anticipate at this time achieving our targeted $1 per common unit distribution by the fourth quarter of this year.

Given the very meaningful full drop in commodity prices and our expectation that these low prices could persist into early 2013 in particular around NGL prices, we made the prudent decision to slow the rate of increase in our distribution, and we expect to maintain or slightly increase our distribution through the end of this year as we continue to execute on our organic growth projects and strengthen our coverage. All actual distributions, of course, will be determined, declared and paid at the discretion of our Board of Directors.

Now turning to some details about each of our operating business results. First, our Midstream business. Operating income, which does exclude the impact of any hedge receipts, for the Midstream business in the second quarter decreased by approximately $3 million compared to the first quarter. This decrease was due to lower average realized prices and a 12% and a 5% decrease in gathered volumes and equity condensate volumes, respectively, all driven primarily by plant downtime. The incident in our Phoenix facility was the significant contributing factor in our lower gathered volumes during the quarter. Gathered Panhandle volumes were down approximately 16% with combined equity NGL and condensate volumes down approximately 8% as compared to our first quarter.

As we discussed in our last call, on April 30, we had a serious incident at our Phoenix facility, which damaged our inlet headers and required a complete shutdown of the facility for 60 days. Phoenix is our largest midstream processing facility in the Texas Panhandle, and the downtime affected our revenues and the throughput of our customer producers.

The impact of this incident on our quarter results totaled $2.8 million between the lost revenues and repairs, which is consistent with the guidance we have previously provided. We carry both property insurance with a $500,000 deductible and business interruption insurance with a 30-day deductible. And therefore, we expect to recover a substantial portion of the $2.8 million sometime in the near future.

We did restart Phoenix on July 2. The plant is currently running well, between 40 million to 45 million cubic feet a day, and we're continuing to increase this throughput as we work through the start-up issues. We hope to be closer to 60 million to 70 million per day in the very, very near future.

On May 30, we successfully started up our Woodall Plant, our newest cryogenic processing facility servicing the producers in the Granite Wash play. Within days of start-up, we had the throughput growing to over 40 million cubic feet a day before a third-party residue gas outlet pipeline had a severe incident on June 5, which did curtail the amount of gas we could process at Woodall. This was very unfortunate and completely out of our control and contributed to our lower-volume throughput during the quarter as we waited for the third-party residue outlet pipeline to make their necessary repairs. Since that time, we've been allowed to resume deliveries into the residue line but at a constrained rate. We have been able to activate a second residue outlet, but it is not able to handle all the volume we can send to them. So now, between the 2 residue outlets, we are currently processing over 35 million cubic feet a day. Production in the core of the Granite Wash continues to be robust, and we believe there is ample inlet gas to fill the facility to its full 60 million-a-day capacity once the rate allowance on the third-party pipeline is increased.

With the restart of the Phoenix Plant and now the start-up of Woodall, Eagle Rock has today approximately 190 million cubic feet a day of high-efficiency cryogenic processing capacity serving the Granite Wash.

The Granite Wash continues to be very active drilling play with over 52 rigs running in the counties of Hemphill, Wheeler and Roberts County. The formation continues to deliver strong, drill economics even in the face of these lower NGL pricing environments.

In addition to the Granite Wash, though, you see -- we're seeing producers now targeting the Cleveland, the Tonkawa, the Hogshooter and other formations in the immediate area, which only adds to the need for incremental processing capacity. Currently, 5 wells are drilling off -- are drilling or awaiting completion work on acres dedicated to Eagle Rock, and we expect that number of activity to remain constant or rise throughout this year.

Construction of our 60 million-a-day Wheeler Plant, which we announced late last year, is -- which is to be located in Wheeler County, Texas, and all the associated gathering and compression equipment continues and is expected to be completed in the first half of 2013 at a cost of approximately $63 million, of which $15.3 million has now been spent through the end of the second quarter. The addition of the Wheeler Plant to our existing processing infrastructure in the Panhandle is in response -- a continued response, to incremental processing needs driven by increased drilling activity by producers in the Granite Wash play. Once Wheeler is online, Eagle Rock will have over 250 million cubic feet a day of cryogenic processing capacity in this exciting area.

Turning now to our East Texas and other Midstream segment, gathered volumes were down approximately 9% with combined equity NGL and condensate volumes down around 7% compared to the first quarter. The decrease in gathered volumes was primarily due to declines in our Gulf of Mexico area where we own nonoperated interest in 2 large, coastal processing plants. Most of these plants experienced downtime or curtailed volumes for a number of reasons, including various offshore platforms being shut in during the quarter and issues with residue pipeline outlets.

Our Gulf of Mexico operations are relatively low margin per unit of throughput, so the impact is felt much more on volumes than in our gross margins. Gathering volumes, though, associated with our Austin Chalk play actually increased approximately 6% during the quarter due to the continued successful drilling by several large producers targeting this liquids-rich play. Currently, we're running at about 70% utilization of our total processing capacity in the East Texas area.

The Austin Chalk play remains the primary driver in our volume growth in the East Texas area. Drilling activity remains robust as operators continue to expand the play to the east into Louisiana. Today, there are 8 rigs drilling in the Austin Chalk play in the counties of Pope, Tyler and Newton counties, Texas and also Vernon Parish, Louisiana. Of the 8 total rigs that are active, 5 are drilling on acres dedicated to Eagle Rock.

Regarding the Tuscaloosa Marine Shale that we keep hearing a lot about, we continue to monitor leasing and drilling activity in the general area. The majority of the drilling in the play today still remains concentrated in the Eastern Louisiana and Western Mississippi, which is much further to the east for our current systems.

Operators are evaluating drilling plans to test the formation in the immediate area much closer to our pipeline systems, but given the current commodity prices, these operators are seeking joint venture partners to diversify their CapEx risk and we expect this will slow down any drilling plans they may have for the second half of this year closer to our systems. We continue to discuss with these operators their infrastructure needs, and we intend to be opportunistic in establishing a gathering and processing infrastructure position in this emerging play.

Now turning to our Upstream business. We continue to execute on our drilling program while we monitor commodity prices. Our upstream footprint remains a highly diversified portfolio of assets and established crude and liquids-rich natural gas plays. Our assets are strategically located in the Mid-Continent, Permian Basin, Southern Alabama and, of course, East Texas.

Operating income, excluding the impact of any hedge receipts, decreased by $10 million compared to the first quarter. The decrease was attributable to lower realized natural gas, NGL and crude prices and slightly lower production during the quarter.

Production volumes averaged approximately 83 million cubic feet equivalent per day during the quarter, which was a decrease of almost 2% as compared to our first quarter. The production decrease was caused by unscheduled downtime at our Big Escambia Creek processing facility in Alabama. We had to conduct unscheduled maintenance at our facility, which processes our upstream production in Southern Alabama, during both May and June.

The BEC facility was taken down for 8 days in mid-May and then for another 7 days at the beginning of June. Both times, we made repairs to our sulfur recovery unit. As we previously discussed with you, we plan to replace the sulfur recovery unit in 2013 to meet existing SO2 emission requirements, also to improve our run times, extend the useful life of the plant and increase the throughput of gas into our plant. We expect to stay in approximately $50 million on all these upgrades through 2013, and approximately $2.7 million of that was spent on the SRU upgrade project during the second quarter. Jeff's going to highlight the impact of the spending in a minute and he'll -- and also touch on how it impacts our view of maintenance capital.

Since the June shutdown, the plant has operated at normal levels, and one of the benefits we expect from this upgrade, the SRU upgrade, is greater reliability and less unscheduled downtime like we saw during the quarter. In total, the impact of the unscheduled turnarounds reduced second quarter production by almost 4 million cubic feet a day and negatively impacted adjusted EBITDA by approximately $4.3 million. Without this downtime, total production for the Upstream business for the second quarter would have actually increased by approximately 2% over the first quarter production levels.

Total CapEx for the Upstream segment in the quarter was almost $45 million, up by $21 million as compared to the first quarter. Our drilling and recompletion program developed 15 Bcfe during the quarter at an overall unit development cost of $2.60 per Mcfe, placing 4 operated wells and 5 nonoperated wells to sales.

During the quarter, we maintained 3 operated rigs drilling in the Mid-Con area with one rig devoted to our Cana Shale program and 2 rigs to our Golden Trend program. We expect to maintain this 3-rig drilling program for the balance of 2012. With the decline in natural gas prices and now NGL prices, we continue to adjust our drilling program to achieve mid-teen-or-better returns and deliver on our production volume forecast.

Focusing now on the Cana Shale program, activity in the trend continues to expand from the core area of Canadian County, Oklahoma towards the southeast as operators such as Continental, Marathon and Newfield push the extent of the play.

Recent industry results in the Southeast Cana Shale trend have been very encouraging. On our last conference call, we discussed this emerging area, which is located very near to our Golden Trend field in Grady and Garvin counties, Oklahoma. In this area, we see average thicknesses of 200 feet or better in the Woodford section comparable -- which is comparable to the core area of the Cana in Canadian County.

Several operators have recently announced very positive initial rates and expected EURs in the Southeast Cana area. Currently, we control about 2,400 net acres, and we continue to add to our leasehold position every day.

We're drilling our first operating well in this area, the -- we call it the Beckham 1-27H well, which is located in Garvin County; as well as, we're participating in a nonoperated well located in Grady County. Both wells are horizontal and are currently drilling in the targeted Woodford formation. We will test our acreage in the Southeast Cana area, and then make further determinations as to our Cana activity for the second half of this year.

In the Golden Trend area, we will average 2 operated rigs throughout the balance of this year. We are drilling liquid-rich vertical wells that encounter multiple pay zones from the Bromide formation up to the Viola, the Hunton, the Woodford, Sycamore and Springer formations.

The Golden Trend will continue to be a focus area for us throughout 2012. We have sufficient drilling inventory to maintain 2 operated rigs running through 2013.

I'll now turn the call over to Jeff to review in more detail our financial results.

Jeffrey P. Wood

Okay. Thank you, Joe. As mentioned, our reported adjusted EBITDA for the second quarter of approximately $58 million was down relative to the almost $63 million that we reported for the first quarter of 2012. We faced a number of challenges during the quarter, both in the form of falling commodity prices and plant downtime due to operational issues that negatively impacted our financial results. Despite this, the decline in our adjusted EBITDA was relatively muted, which we believe shows the strength of our diversified business model and of our hedging portfolio.

Commodity prices fell across-the-board in the second quarter. The average price of WTI crude declined by almost 10%, including a stretch in late June where it fell below $80 per barrel, before recovering to its current levels just under $90 per barrel. Average natural gas prices also declined sequentially quarter-over-quarter, although we did see a recovery after they bottomed out in late April.

Of course, what received the most attention during the quarter was the weakness in natural gas liquids prices, which, prior to the second quarter, had been a real source of strength to the gathering and processing sector and to liquids-centric producers like us. At the light end of the NGL barrel, which comprises the majority of the typical NGL stream by volume, was especially hard hit. Average ethane and propane prices during the second quarter declined by over 20% relative to their levels in the first quarter. The heavier liquids suffered as well with butanes and pentanes down approximately 15%.

We've made no secret that we are a liquids-focused company in both our business segments. So like many of our peers, we felt the effect of the price changes during the quarter.

We've also highlighted for several quarters now our exposure to the Conway, Kansas NGL hub, both from our equity liquids generated from our Midstream operations in the Texas Panhandle and our Upstream operations throughout Oklahoma.

To date, pipeline infrastructure has not kept pace with the increase in liquids production coming out of the many prolific plays, including the Granite Wash, Cana Shale and Golden Trend that we are associated with, leading into Conway. With limited storage and market outlets as compared to the primary U.S. hub at Mont Belvieu, this influx of liquids has negatively impacted price at Conway for several quarters.

During the second quarter, overall demand concerns and continued robust supply created a glut of liquids at Conway, and we saw certain liquids touch historic lows. Ethane prices at Conway fell to $0.04 per gallon in June from their average of $0.27 per gallon in the first quarter, and propane touched $0.50 per gallon from its average of over $1 per gallon in the first quarter. This was a major driver behind our $3 million decrease in Midstream operating income from first to second quarter.

So that's the dark cloud for the gathering and processing industry and Eagle Rock. The good news is that the silver lining is pretty thick. First, the commodity price impact on our results was mitigated substantially by our extensive hedge portfolio. In other words, our hedges did exactly what they were designed to do: smooth our cash flows during periods of commodity price volatility. As a reminder, we are 89% hedged on our total crude and heavy liquids exposure for the remainder of 2012, and 80% of our liquids -- and 80% of our heavy liquid exposure, including our expected propane volumes, is hedged directly by product. In fact, our Mont Belvieu propane hedges are set at strike prices north of $1.35 per gallon, and we have Conway propane hedges at $1.18 per gallon and those are well above current market prices. As a result of our strong NGL and natural gas hedges, we recognized over $16 million of realized commodity derivative gains in the quarter.

The second layer of the silver lining is that liquids prices have stabilized after rebounding off of June's lows. While still not where we would like them to be, the night is no longer falling. Ethane at Mont Belvieu is up 12% over the past month, and propane is up 6%. Further, natural gas has continued its upward trend, and the current spot price around $3.20 per Mmbtu is up almost 50% from the lows we saw in mid-June.

The third point of good news is that help is on the way to reduce the bottleneck issues at Conway. Several important pipeline projects are in various stages of development to transport natural gas liquids from the Mid-Continent area to Mont Belvieu. We expect that by mid- to late 2013, there will be sufficient capacity to narrow the differential between Conway and Mont Belvieu to the cost of transportation. In fact, ONEOK, who we sell our liquids to in the Panhandle, yesterday predicted that spread would fall to $0.08 per gallon by the beginning of 2014. So we believe the end is in sight to be able to stop suffering through these wide differentials, which are generally difficult to hedge away.

Moving away from NGL prices. Our favorite product, sulfur, continued its strong price run. Sulfur prices have settled into a favorable range over the past several quarters. Sulfur traded at $180 per long ton during the second quarter at the Tampa, Florida pricing hub, which was a slight improvement over the $172 per long ton in the first quarter. Prices recently settled for the third quarter as well, down only slightly at $170 per long ton, so we should continue to enjoy the benefits of being one of the large elemental sulfur producers in the country.

Joe covered the operational challenges we experienced in our Midstream and Upstream businesses during the quarter, so I won't cover that again here except to better quantify their impact.

We estimate that the Phoenix incident negatively impacted adjusted EBITDA by approximately $2.8 million, both from increased operating cost for repairs and from lost margins. Further, we estimate the third-party pipeline outage that reduced throughput at our Woodall Plant to have negatively impacted adjusted EBITDA by approximately $600,000. The impact of these events on our Midstream business was partially offset by the recovery of about $2.9 million in insurance proceeds related to downtime at our Cargray plant in the first quarter of 2011.

In our Upstream business, Joe discussed the downtime associated with the 2 unscheduled turnarounds at our Big Escambia Creek facility supporting our Southern Alabama production. We estimate these occurrences combined negatively impacted Upstream EBITDA by approximately $4.3 million.

So to put it all together, we estimate our adjusted EBITDA for the quarter was negatively impacted to the tune of approximately $4.8 million from the plant downtime, net of our prior year insurance recoveries collected in this quarter. That would imply a normalized adjusted EBITDA for the quarter of $62.5 million, which is roughly equivalent to our first quarter results, despite the downturn in commodity prices.

Turning to net income, we recorded income in the second quarter of approximately $62 million versus a net loss of approximately $50 million for the first quarter. As usual, the main driver behind the delta is a change in noncash, unrealized commodity derivative gains and losses on our hedging portfolio.

Now turning to our liquidity position. We ended the second quarter with approximately $886 million of total debt outstanding. That's up about $70 million from the end of the first quarter as we completed construction of the Woodall Plant, continued our spending on the Wheeler plant and continued our upstream drilling program.

Our credit profile remained strong as of the end of the quarter. Our key metric of total debt-to-adjusted EBITDA was 3.5x at the end of the quarter, which is within our desired long-term range of 3 to 3.5, despite the increased spending and the negative EBITDA impact of prices and plant downtime.

We were running a little skinny in terms of liquidity at June 30, and we addressed this issue shortly after quarter's end by issuing $250 million of senior unsecured notes on July 10. The notes were sold as an add-on to our existing 8 3/8% senior notes due 2019 and will be treated as a single class of debt under the same indenture as our previously outstanding $300 million of notes. We used the net proceeds of the notes issuance to repay amounts outstanding under our credit facility. Pro forma for the senior unsecured notes offering, we had approximately $320 million of availability under the facility based on our current commitments.

We also received proceeds of approximately $13 million on the May 15, 2012, final exercise date of our warrants. On that date, all remaining unexercised warrants expired, so there are no longer warrants outstanding and, obviously, the warrants ceased trading.

In terms of hedging, really not surprisingly given the price environment, we were less active in adding new hedges to our portfolio during the past several months. We did have some Cal 15 [ph] natural gas hedges at $4.18 per Mmbtu, and we adjusted one of our crude hedges to better reflect current market conditions.

As we discussed on the last call, early in the second quarter, we added 2,013 direct NGL hedges. And in retrospect, those turned out to be at very attractive prices.

We expect to continue to be well insulated from commodity price volatility in the near and medium term given our extensive hedge portfolio. We are almost 90% hedged on our crude and heavy liquids exposure for the rest of the year at an average strike price of over $85 per barrel. We remain well hedged for these products in '13 at 84% of expected equity volumes at an even more attractive average strike price of $95.75 per barrel. On the natural gas and ethane side, we are almost 80% hedged for the remainder of the year at an attractive price of $5.71 per Mmbtu and approximately 70% hedged in 2013 at a price of $5.22 per Mmbtu.

If you want to know further about our recent hedging activity, we did post an updated hedge presentation to our website last night, which covers our full hedged portfolio.

Following the high-yield issuance in July, we had more fixed interest rate swaps than we had floating-rate exposure. So as a result, we elected to terminate 2 existing floating-to-fixed interest rate hedges that had original maturity dates of December 31, 2012. These hedges were well out of the money, and our termination costs was $3.8 million. The good news is that we should get approximately this amount back in the form of lower realized interest expense for the rest of this year.

So we reported distributable cash flow of $31.6 million for the second quarter. As you saw last week, we announced a distribution at an annualized run rate of $0.88 per unit, which is consistent with our run rate for the first quarter and a 17% increase from the annualized distribution we paid for the second quarter of 2011.

Our coverage was narrower this quarter due to the plant downtime and lower commodity prices, though we still maintain the coverage ratio of 1.05x for the quarter.

Finally, we've been discussing for some time now our major upgrade project at our Big Escambia Creek facility in Southern Alabama to upgrade the sulfur recovery unit. As Joe mentioned, this project will enable us to meet SO2 emissions requirements and will enhance our ability to recover valuable sulfur while making the facility more reliable. This past quarter was the first in which we had meaningful spending on this upgrade project. We spent a total of $2.7 million on the project during the quarter. After a thorough analysis of the benefits of the project relative to its cost, we have determined that 55% of the project spending will be classified as maintenance capital. As a result, maintenance capital in the second quarter includes $1.5 million of spending on this SO2 project to upgrade the sulfur recovery unit. For the entire project to be classified as gross spending, instead of any in maintenance, our coverage for the quarter would have been 1.1x.

So with that, I will turn the call back over to Joe for additional comments before we open it to questions.

Joseph A. Mills

Thank you, Jeff. As I mentioned earlier, I really do believe we had a decent quarter given some of the operational challenges and the meaningful fall in commodity prices. Absent our operational challenges, we would have delivered a $62 million quarter, which would have been on the high end of expectations.

The Phoenix incident was very unfortunate, but we have the facility back online and is performing well. With Phoenix and now Woodall both online, we will continue to see growing volumes in the Granite Wash play. Based on the producers' activity, we are pushing forward with the construction of our Wheeler Plant with a view it will be online in mid-2013.

Earlier, Jeff described our very strong hedge portfolio and how it smoothes our cash flow during these times of high volatility in the commodity price cycle, which is exactly what it's supposed to do. Notwithstanding this, though, the meaningful reduction in overall commodity prices, and in particular NGL prices, does have an important impact on our near-term view of revenues from our Midstream -- for both of our businesses -- both Midstream and Upstream businesses.

The U.S. economy continues to be stuck in neutral, while the European economy is now receding back into a recession. We remain vigilant of macroeconomic events impacting our business as well as the impact of drilling decisions by our producer customers. We expect, and are now seeing, a slight pullback of drilling by the E&P industry targeting liquid-rich natural gas plays, in particular the Mid-Continent. This is a clear and appropriate reaction by the producers to the dramatic fall in NGL prices and the bottleneck issues at Conway. However, we believe this is a temporary pullback. Our belief is that NGL prices have hit bottom, or hopefully have hit bottom, especially ethane, and we're hopeful that we will see a recovery in the price of the NGL barrel into 2013.

As Jeff just mentioned, during the second quarter, we saw realized ethane prices fall at Conway, where the majority of our NGL product is sold, by an average of over 60%, while propane fell an average of 30%. We cannot ignore this reality. Fortunately, we are seeing improvement in overall NGL prices as they have rebounded slightly from the bottom last quarter.

While we are cautiously optimistic, we cannot ignore the current challenging NGL price environment, nor can we predict the timing or extent of the full recovery in NGL prices, especially ethane and propane prices. It is with this backdrop that we made the decision to slow the rate of increase in our distribution. Frac spreads have fallen by 38% since the beginning of this year, but a larger percentage of this reduction has been in the light end of the NGL barrel, both ethane and propane.

You will recall we established the goal of achieving a $1 dollar distribution last year when natural gas prices were over $4 an Mcf, oil was over $106 a barrel and the combined Eagle Rock-NGL barrel was at $53. We've seen a 23% decline in natural gas prices since that time, a 16% decline in oil prices and a 35% decline in the NGL barrel.

The fundamentals of our business plan are intact, and our diversified business model and hedge portfolio remain a strength for our company. The company is financially strong, and we will focus on maintaining our current distribution of $0.88 annualized and grow modestly from there while we see a recovery in commodity prices and the effects of our organic growth projects.

We have been pleasantly surprised at natural gas prices climbing back to the low $3 range. Our expectation is they will remain range bound in the high $2 to low $3 range for the rest of this summer given the hot summer plaguing the rest of the country. If we have a decent winter, this will help natural gas prices as well as propane prices, which could set the stage for a rebound to these commodity prices in 2013.

Our hedge portfolio remained strong and will protect the current distribution while we bring online additional projects like our Wheeler Plant in the Texas Panhandle. We will focus on executing on our visible organic growth projects and increasing our coverage ratio during this period of low commodity prices.

For the balance of 2012, we will continue to build out our Panhandle infrastructure, which should continue to positively contribute to our cash flows and expect to grow our Upstream volumes by over 2% as we drill on our expansive acreage position in the Mid-Continent. Execution on all of our ongoing organic growth projects remains our primary focus.

As always, though, we are actively evaluating acquisition opportunities for both Midstream and Upstream assets. We are seeing a number of attractive opportunities in the market today. Any acquisition activity, of course, will be driven by long-term accretion to our distributable cash flow.

I want to thank all Eagle Rock employees who work hard every day to safely, efficiently and profitably grow our partnership. With that, we will now open the floor to questions.

Question-and-Answer Session

Operator

[Operator Instructions] We have a question online from Kevin Smith of Raymond James.

Kevin A. Smith - Raymond James & Associates, Inc., Research Division

With the NGL prices that you guys outlined [indiscernible] clearly in your call, any change in what are you guys doing with the E&P drilling activity? I know you mentioned that you're still making somewhere close to high teens to maybe low 20s rates of return, but any thoughts about slowing down activity or any of that?

Joseph A. Mills

Yes, no, they're -- great question, Kevin. Well, you may recall last time we talked on the last quarterly call, we actually had cut about $20 million of CapEx out of our Upstream budget. Primarily, we had a drilling program slated to be drilled in the Arkoma, which was all just dry gas. Clearly, that didn't meet our hurdle rate expectations. So we are deferring that program that acreage is all held by production, so it's not going anywhere. We have -- so that's one. We are still evaluating whether or not we will slow down the drilling activity. In Golden Trend in particular, of course, all that is held by production, and we're still achieving very good rates of return on those drilling programs. Remember, those are vertical wells that have multiple pay zones. The Cana is the one that we certainly are monitoring and adjusting accordingly. We talked last time that as gas prices slid into the low $2 range and even the high $1s, we signaled that we clearly would look to slow down, if not shut down, the Cana. With natural gas prices having bounced back at least to the high $2s, low $3s, it still supports our drilling program in terms of the expectations. I touched on it, but -- and clearly, in our next investor presentation, we'll be giving a lot more color around this. But this -- the Southeast Cana area is pretty exciting. It's -- some of the recent results from some of our competitors, these are -- these wells are exceeding those mid-teen-to-20% rate of return type expectations. These wells are coming on -- some of the offsets have come on at 7 million a day-plus, plus the liquids, 200 to 300 barrels of NGLs. And so at those rates, those are very profitable wells even in this low price or low-NGL-price environment. So we clearly -- as I said earlier, we're definitely evaluating the program. We are drilling our first key well being the Beckham. It directly offsets several of the wells that have been recently announced by, again, several of the large competitors in the area that made quite a splash with some of their IP rates. So we're optimistic. We're in a good drilling area. I think, as I said earlier, depending on results, we will certainly take additional course corrections, which could include slowing down the program if that's the right decision.

Kevin A. Smith - Raymond James & Associates, Inc., Research Division

What's your NGL prices there? Are you getting Conway or Mont Belvieu?

Jeffrey P. Wood

Well, let's say -- well, we actually get both. I'm going to defer to Joe Schimelpfening here, who'll give you a little detail around that.

Joseph E. Schimelpfening

Yes, Kevin. We get both. It depends on the gatherer and processor we go to. I would say the majority of our production in Golden Trend, which is where we make all of our NGLs gets Mont Belvieu pricing currently.

Joseph A. Mills

Well, that helps a lot.

Kevin A. Smith - Raymond James & Associates, Inc., Research Division

And just one last question and I'll move on to a different topic. How much of E&P CapEx is nonop?

Joseph A. Mills

Well, it's actually come way down. At one point, we had expected a lot more nonop activity, but no surprise, we are seeing other operators slow their activity down but it...

Jeffrey P. Wood

Yes, Kevin. We really, in the -- we saw a fair amount of capital in the first quarter. We've seen - as Joe said, we've seen a slow way down. So total for the year, it's going to be in the neighborhood of $40 million of nonop capital for 2012.

Kevin A. Smith - Raymond James & Associates, Inc., Research Division

Got you. Okay. And then, do you have an estimate how much you expect to spend for sulfur on the third quarter? For some reason, I was thinking it's going to be a little bit higher in the second quarter combined.

Joseph A. Mills

Well, yes. We don't have -- well, let me say it this way, yes, sulfur -- the SRU unit. Yes, so no doubt that our spend rate is going to jump up significantly in the third and fourth quarter. Recall there are kind of 2 phases to this SRU unit upgrade that we talked about, so bear with me for a minute. The first phase is we're installing what's called a superclass unit. And then we're also going to replace the third condenser bed. So out of the $50 million, roughly $20 million of it will be spent this year. So let's say $3 million was spent in the second quarter, so we got about $17 million to be spent in the next 2 quarters. So it's going to start to ramp up pretty considerably. The overlay on top of that, that we are now starting to spend money on the SRU upgrade itself, the replacement of the SRU unit. Remember, those are really 2 -- while it affects the same unit, it's really 2 different projects, so one is putting the superclass at the end of existing SRU unit, and then we will replace that unit with the second SRU unit next year. So I think the short answer is our expectations is...

Jeffrey P. Wood

$7.5 million.

Joseph A. Mills

$7.5 million? Yes, about $7.5 million should be spent in the third quarter.

Kevin A. Smith - Raymond James & Associates, Inc., Research Division

Got you, very helpful. And then last, any activity on the aftermarket equity program?

Jeffrey P. Wood

Kevin, I'll take that one, and just give me a second here. To catch everybody up, so during the second quarter, we call it an ATM program. It's an aftermarket equity program through which we may issue common units from time to time. And we set the aggregate market value of that at $100 million. As of June 30, no units have been issued under that program.

Operator

Our next question comes from TJ Schultz with RBC Capital Markets.

TJ Schultz - RBC Capital Markets, LLC, Research Division

I guess just on the Woodall plant, the throughput, the residue gas line incident. Just -- I guess the question is what kind of visibility do you all have on the constraints for that residue line being lifted? And if you do have some visibility kind of compared to your normal course, can you try to quantify what the impact of some of those constraints may be on third quarter?

Joseph A. Mills

Yes. I'll take that one, TJ. Unfortunately, the visibility is low. I really can't -- or I shouldn't say who the residue pipeline, but it's a big company and very -- one of the major outlets. So this doesn't just impact us, it impacts a number of other processes in the area. It's unfortunate there was this incident downstream of our plant and involved us all. They -- the repairs have been made from what we understand, but I understand they have some regulatory issues that they're dealing before they can bring it back up to its full throughput capacity. And so it's that limitation that's keeping us, along with others, constrained coming out of this area. As I mentioned in my prepared text, we moved pretty quickly to activate a second residue outlet. Unfortunately, that outlet is also constrained, but we hope that hopefully soon, next 30 to 45 days, the second outlet will be de-bottleneck some of its issues, and we'll be able to then start moving may be a lot more volume to the second outlet. And that just assumes that the first outlet, they don't ever get their issue resolved. I mean, they will at some point. Again, it's kind of regulatory in nature from what we understand. So I think the short answer is unfortunately, it does continue to impact our third quarter. At this point, I cannot quantify it to you. I can say to you that we're expecting to be running at about 50% of throughput capacity. That's kind of where we are right now, 35 million a day. We keep pushing every chance we get to cram a little bit more in there, but they're holding us back. I can assure you though, we have the gas. That is -- if there's anything -- any takeaway is that Woodall came on well. We have ample gas upstream of us that we think -- you may recall, I'd originally said we didn't expect to fill Woodall up until the end of the year. We can fill it today, but only through the issues of the residue outlet. So hopefully, it will be resolved soon, but there will be some impact in the third quarter.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Got it. So you're saying that once these issues do get resolved that the ability to increase to the 60 million is pretty quick, right?

Joseph A. Mills

That is correct.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Okay. I guess just generally in the Mid-Con, can you just comment kind of what, if any level, of ethane rejection you're seeing?

Joseph A. Mills

Well, from us, very little. Really effectively, our plan -- now Woodall has the ability to reject ethane. Of course, we're not pushing enough of -- enough gas through it right now, so efficiently, reject ethane. But really, the rest of our plants are not efficient enough to reject ethane. So currently, we are not rejecting ethane anywhere across our plants. Our problem gets into if we try and reject ethane then we're really rejecting big chunks of the propane too. So at this point, we are not rejecting ethane. We're pushing it all down the line and -- sorry, or extracting it. And I think that's part of the problem. We know others are rejecting ethane. And we've actually -- it's causing problems in the pipelines because people are bumping Btu specs. And so it's becoming a little bit more challenge for everybody because of that fact.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Okay, great. I guess just moving over to Upstream on the Southeast Canada. When do you expect to complete the Bakken well? And can you give any kind of indication what you're seeing for well cost in that part of the play?

Joseph E. Schimelpfening

Yes. In Southeast Cana, the well costs are in the neighborhood about $9.5 million completed. And the first well, the well that we're operating right now we're expecting that to be on production in mid or late September. We just started the lateral here in last week, and as far as the nonoperating well that we have right now, it's probably in that same time frame.

Jeffrey P. Wood

Yes. And TJ, on that note, the costs are a little bit higher here because this is a little bit deeper and a little more pressure. And that probably part of the reason you're seeing that much better rates from some of these wells, but it is a little deeper and a little more pressure, a little hotter. And so for that reason, costs are a little bit higher.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Okay, great. I guess just lastly, just a clarification on the $50 million upgrade cost, I guess, what you're spending in the second half of this year, I think around $20 million you said. What of that would you bucket as maintenance CapEx, or is it just 55% of that is maintenance as well?

Jeffrey P. Wood

Yes. So -- sorry, TJ, it's the latter. So what we did is kind of took a look at the overall project and we said of all the various things that this does, including increase sulfur recovery, reduced turnaround time, increased operating efficiency, all the things that have a growth-type component to this, we measure those versus the cost of the whole program. And that turned out to be frankly almost half. So we took a little bit of a conservative front there, and then said we're going to do 45% growth and 55% maintenance throughout just -- that's going to be our split for every dollar that's spent on this SRU project.

Operator

Our next question comes from Helen Ryoo of Barclays.

Heejung Ryoo - Barclays Capital, Research Division

So just following up on that -- the upgrade project that you're allocating 55% to maintenance CapEx, how does that change your maintenance CapEx expectation for the year in 2012?

Joseph A. Mills

Well, I mean, all things being equal, it's probably internally, at least, it lowers it a little bit. We were -- we have -- before this quarter, this is the first one where we really spent any significant dollars, and before this, we were just internally -- before we have done our analysis, we're taking a little more conservative view on the mix between maintenance and growth. So at least on our internal projections, it helps. From a DCF standpoint, now obviously, just our raw spending, the fact that $0.55 out of every dollar we spend is going to impact DCF, again, all things being equal, lowers it. But we were actually pleased when we sat down and really took a hard look at the math of how many areas that this is actually going to be very helpful to our overall operations in Southern Alabama.

Heejung Ryoo - Barclays Capital, Research Division

Okay. I think in my note I had you guys guiding towards maybe $53 million in Upstream maintenance CapEx and $22 million in Midstream. Is that still a good number to use for the year, or does this change in how you account for this reduced the Midstream side of this maintenance CapEx and therefore, reduce the full year maintenance CapEx to something below $75 million, which I had in my notes?

Jeffrey P. Wood

Yes, it probably helps marginally, Helen.

Heejung Ryoo - Barclays Capital, Research Division

Marginally, so not a big, big change for the year?

Joseph A. Mills

That's correct. And Helen, remember that this project is in our Upstream business. So any reduction would be Upstream maintenance CapEx not the Midstream.

Heejung Ryoo - Barclays Capital, Research Division

Okay. Got it, got it. And I guess you said for the year or so, just to be super clear, I mean, out of the 50% -- the 55% of the 50%, which is 27%, is that -- that's the total spending related to this in 2012 and '13, right?

Joseph A. Mills

Yes, that's correct.

Heejung Ryoo - Barclays Capital, Research Division

Okay, okay. All right. And then just the 45% of that will go to gross CapEx. And you mentioned you did that because there is some growth component to it. What's a good rate of return to use for what's being allocated to the growth CapEx side?

Jeffrey P. Wood

Well, Helen, we talked about that early on in one of these calls. And I think what we've consistently said is while this does provide a number of positive things, it's not a project that we would do absent being kind of required to from an environmental and regulatory standpoint. So we had, early on, said it would be low to mid-single-digits type. Our -- I think again, we found that there's probably a few more positives than we have initially thought. But this is -- I would still say this is a sub-10% IRR-type project. And again, not one that neatly fits into the bands of what we would otherwise look to do.

Heejung Ryoo - Barclays Capital, Research Division

Okay, understood. And just moving onto your comment about ethane rejection and the fact that you're not rejecting ethane because of your -- how your plant is set up. But -- so does that mean that with the very low price environment we saw in June, that some of your keep-whole contracts were generating negative cash flow? Or did you have some conditioning language that provided some fixed floor to that, and therefore, despite not being able to reject ethane, you weren't necessarily having a negative cash flow situation?

Joseph A. Mills

Yes. I think, Helen, we -- the biggest keep-whole contract we have has a minimum floor in it, meaning, we get a fixed minimum floor kind of irregardless of what the ethane price is. So I think the short answer is I don't -- we did not go upside down, it probably 8 inch of margin of that fixed floor. But we never went upside down in that contracts.

Jeffrey P. Wood

And I guess I would just further say, almost all of our keep-whole exposure is on the west side of the Panhandle, so none of our new contracts are keep-whole-like. That is only legacy contracts and the West side of our Panhandle. That's a very heavy barrel relative to what we're getting at our East side. We didn't see nearly the negative price implications of those differentials on the heavier end of the barrel. So Joe's right, we got some protection on the floor, and the other thing that's really mitigated it is that it's a heavier barrel.

Operator

Our next question comes from Jeff Rudner of UBS.

Jeffrey Rudner

Just a little bit of confusion on my part about the dividend policy going forward, particularly, into next year. I know you indicated that you don't plan on raising the dividend to $0.25 a quarter based on the current levels of product prices. But into 2013, if product prices would remain roughly at the levels they are at now, would you, at least, be able to maintain the $0.22 per quarter dividend possibly increasing it, but hopefully not decreasing it?

Jeffrey P. Wood

Yes. That is a correct statement. And that's an important point. I don't want it to get lost that all that Joe mentioned, this was not a great quarter, but it was a solid quarter. And we still feel very good about the business so while the rate of the increase here is slowing, giving -- given prices, we still feel very good about the $0.22.

Operator

Our next question comes from James Spicer of Wells Fargo.

Jim Spicer - Wells Fargo & Company

A couple of questions for you. First of all on the Upstream side, what's the overall decline rate on your Upstream portfolio today?

Joseph A. Mills

Total production, of course, with our drilling activity now, we are growing production quarter-on-quarter. As far as our base production, it's probably in the neighborhood of 9% to 12%, maybe something in that range.

Jim Spicer - Wells Fargo & Company

Okay. And how much of your Upstream production comes from the Cana?

Joseph A. Mills

Today, 16% of our production is coming off Cana. So about 13 million, 14 million cubic feet equivalent per day. And that's up from 0, 12 months ago or less than 12 months ago.

Jim Spicer - Wells Fargo & Company

Right, right. And I have in my notes that I think your most recent guidance for Upstream production for the year is at 90 million cubic feet a day average. Do you guys -- how do you feel about that number today?

Joseph A. Mills

Yes, I think we'll be very close to that number, maybe slightly below that. We think our exit rate for the year is still going to be in that $94 million a day range.

Jim Spicer - Wells Fargo & Company

Okay. And then moving on to Midstream. And you guys alluded to this a little bit, but we certainly heard various producers talking about slowing down activity in the Granite Wash due to NGL prices, or at the very least, targeting some of the oilier horizons you talked about. It doesn't sound like that's really had an impact on your business so far. And I'm just wondering at what point, if trends continue, that would start to have an impact? And if it doesn't, why -- why not?

Joseph A. Mills

Great question. I'll take a first stab at that. As I said in my prepared text, we have seen a little bit of a pullback, but honestly, not dramatic. Today, there's still 52 rigs running in those 3 counties that I talked about, which, of course, where our systems are located. Of the 52, 30 rigs are running at Wheeler County alone. And of course, that's very close to where we put our Woodall plant in, and of course, that's exactly where we're putting our Wheeler plant, which should come online next year. In our discussions with the producers, while NGL certainly have hurt them and they are slowing down, and you're right, several of the -- I've listened to a couple of the conference calls, and certainly, some of our producer customers are redirecting capital or slowing down in the face of these lower prices. We haven't seen any kind of material shutdown. In fact, today, right now, there are at least 5 rigs running on us, which is really higher than we've seen historically. Typically we've had 2 to 4 rigs running on us, so we're a little on the higher end right now, 5. We are anticipating some slowdown. That's part of the reason, again, in our prepared commentary that we started to slow the rate of our distribution growth down. And some of that's reflected in the fact that we do expect these guys to pull back a little bit. But as I said earlier, I think it's a temporary pullback. The economics of this play still are some of the strongest of any of the certainly gas, liquid -- or liquid-rich gas plays out there. And you're correct that we are seeing them now move over to targeting the Hogshooter or even the Tonkawa, which are oilier plays, but still have a lot of associated gas that has to be processed. So while they redirect away from the Granite Wash, they're chasing the Tonkawa or the Hogshooter. They're still bringing on pretty big gas wells, but not as big as the Granite Wash, but they're still very, very profitable. And that gas has to be processed. So at least right now, I don't envision any scenario that rig activity just drops off in half. It could definitely slow down, but we don't envision a dramatic drop off.

Jim Spicer - Wells Fargo & Company

That's very helpful. My last question is on the -- at the market equity issuance program, what's the primary criteria for your deciding if and when to issue equity? Is it more sort of focused on leverage and maintaining leverage in a certain area? Or is it a more oriented share price and taking advantage of that?

Joseph A. Mills

James, I really appreciate the question. And you're going to guess this may have come from someone outside of me, but unfortunately, for regulatory reasons, because there's an ongoing offering, we cannot further discuss details of the program outside the information we've already provided on the call, and we'll file publicly on EDGAR. Sorry about that.

Operator

Our next question comes from Eric Anderson of Hartford Financial.

Eric B. Anderson - Hartford Financial Management, Inc.

Just wanted to say, with regards to holding the distribution flat for a quarter or 2, I think it makes a lot of sense especially, since, I would argue, you weren't getting credit for it, and it has been a very volatile environment. So I think being prudent is the right way to go. Joe, you touched on the Austin Chalk play in your prepared remarks. I'm wondering if you can give us a little bit color in terms of what type of growth are you seeing now versus, for example, a year ago? And then compare -- and compare that to possibly what might be going on a year from now. In other words, is this an area that's really being ramped up, or is it more of an incremental deployment of capital by a couple of the large operators?

Joseph A. Mills

All right. Great question, Eric. Well, listen, I appreciate your commentary and thoughts around the distribution and -- our distribution guidance. As for the Chalk, yes, so actually, activity level right now is as high as we've seen it in a long time. If you go back over time, anywhere from 3 to 5 rigs, maybe as many as 6 rigs have been kind of the norm. I remember back in 2007, kind of at the peak or the financial crisis, and when commodity prices were really at their all-time highs, we saw as many as 11 rigs running, whereas today we have 8. And so as you compare and contrast where we are today to last year, activity is definitely up. I think last year, we probably had 5 rigs running in the play. And now, we're at 8. And again, 5 of those were on us. As you look forward, based on the discussions we've had with certain of these producers, and by the way, these are some of the big guys and there's not -- there are some smaller independents, but then there's a handful of big players, big E&P companies that are in this play, they seem to be very optimistic around economics. I mean, in fact, just early this week, we had a 15 million a day well be turned on and very rich in liquids. And so you see some really nice wells, and remember, this all goes straight down to Mont Belvieu, so they're getting Mont Belvieu pricing, which certainly helps the economics considerably. We see the play continuing to move into the east over to Louisiana. We know leasing activity, and we don't know how much of that is really targeting the Chalk versus how much is targeting the Tuscaloosa Marine Shale. But we know there's been a lot of leasing activity kind of all around us in Vernon Parish, Louisiana and continuing back to the east. I'm sure that's a combination of both Chalk and Tuscaloosa players. So right now, we still remain very positive. You may recall in the last call, I guided to that we still are evaluating the potential to put in another plant. We have a site called the Masters Creek site, where there used to be a processing plant years ago before we actually owned these assets. It -- the interconnects are there to existing big interstate pipes. We can easily drop a 25 million to 50 million a day cryogenic facility there, all depending on the activity levels. So I think the short answer is we are still optimistic around the activity level that we see out there. So far, the degradation in price has not slowed these guys down. And I think a large part of it is because they're getting Mont Belvieu price, but they certainly seem to be still pretty positive. That's not to say that we won't see them drop a couple of rigs and go back to 5 to 6, but that's kind of been historical averages, 4 to 6 rigs running. So we don't see that slowing -- getting below that level.

Eric B. Anderson - Hartford Financial Management, Inc.

All right. And then are you seeing any Woodbine activity, sort of come your way, to the East Texas system?

Joseph A. Mills

We are. I touched on that last time. I didn't really say much on it this call. Thank you for bringing it up. We are seeing Woodbine activity mainly on one of our East Texas mainline. Now, one of our challenge -- we have a dry -- that's our dry gas system, which is all fixed feed. And obviously, the Woodbine a liquid-rich play. So we are talking to several producers about what they're doing and whether or not we can support them. Obviously, we could put in JT Skids so -- to knock out some of the liquids. And so I still see that as an opportunity. I will comment that very interesting enough, one of the producers that we support right in the heart of our Chalk play has bought on a very nice Woodbine well. It was a vertical well, not horizontal. And I think that person is looking at potentially going horizontal. So that could be an expanding play right underneath this -- right there in the heart of Chalk area.

Eric B. Anderson - Hartford Financial Management, Inc.

I've been told that there are number of producers in the Woodbine that are actually flaring the gas.

Joseph A. Mills

I heard the same. A lot of it is back toward Madisonville, which is much further to the west of us, and again, we are reaching out there. Unfortunately, our systems don't touch those. But it is not to say that we couldn't build and/or provide them some sort of capabilities. But obviously, that's going to require link pipes and getting dedications and all that. Yes. So we're definitely in discussions, and we're well aware that there's going to be a-- there is a crying need for additional infrastructure over in that area. And that's truly not very far from where we are. But it would be a new expansion of our current system, which is what we're looking for.

Eric B. Anderson - Hartford Financial Management, Inc.

Are producers allowed to flare indefinitely, or is there a time limit in the State of Texas for it?

Joseph A. Mills

Yes. I can say that it's not indefinite. The state gives them an allowable and certain period of time. Now granted, well, sometimes it depends on how much gas they're flaring. But I can assure you, the state doesn't like them to do that. Same thing in Louisiana. You'll see them flare gas for a short period of time, but they can't do that indefinitely.

Operator

Our next question comes from TJ Schultz.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Just a follow-up, and kind of back to the maintenance CapEx line, Helen's point, I guess you're basically lowering maintenance CapEx here by $22 million, $23 million at this reallocation. So just not sure I follow the comment that your $75 million guidance number for this year only comes down marginally. I guess is there something else here I'm missing?

Jeffrey P. Wood

Yes. Sorry, TJ. That was -- we may not have made that clear as we should. We had-- while we had never given specific percentage breakout for growth versus maintenance on that total spend, I think what we've said historically is that we expect the majority of that spending to be classified as maintenance CapEx. So it's just dependent on what percentage you would associate with majority. And so to the extent that you would have assumed that majority represented, say, 75% maintenance, 25% growth, we're backing that off by 20 percentage points here. But if your majority was on 51% maintenance capital, then it's actually going to increase the amount of maintenance capital that we'd actually report. So sorry about the confusion. Hopefully, that clears it up. We have always said that the majority of this is going to be maintenance capital. And I think in our heads, it has been maybe a little bit more than 55% before we really sat down with some better data to do the numbers. And so that was the point.

TJ Schultz - RBC Capital Markets, LLC, Research Division

So it was closer to that 75-25 split before?

Jeffrey P. Wood

Yes. Although, again, it just depends on who you ask. We never gave a percentage split before.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Okay, fair enough. I just -- lastly, any update on the potential for the cryo at Masters Creek?

Joseph A. Mills

Well, that's what -- yes, I'm just commenting on that to Eric, the question right before. We are still evaluating it, but no firm decision to move forward there. Part of it goes to -- TJ, what I was saying, the Tuscaloosa Marine Shale, people are -- while there's still a lot of activity, most of it is really back in Eastern Louisiana or Western Mississippi, so still a long way away from us. We know several operators are -- there's been a lot of leasing. We know that several are looking for joint venture partners in order to kind of help mitigate their CapEx risk. So they may be slowing down their drilling plans for this year. Until we start seeing measurable activity around that play or continued successful drilling in the Chalk moving into Louisiana, we're not prepared to move forward yet. But we certainly are evaluating what's the right timing for a possible add -- an additional cryo at Masters Creek.

Operator

[Operator Instructions] At this time, I show no further questions.

Joseph A. Mills

Right. Well, Anthony, thank you. Ladies and gentlemen, thank you very much. Again, we feel good about the quarter. We have gotten some of those operational issues behind us, so we are looking forward to improving results for the remainder of this year. So thank you again. We look forward to talking to you all hopefully very, very soon.

Operator

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Eagle Rock Energy Partners, L.P. Management Discusses Q2 2012 Results - Earnings Call Transcript
This Transcript
All Transcripts