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Eagle Rock Energy Partners, L.P. (NASDAQ:EROC)

Q4 2012 Earnings Call

February 26, 2013 2:00 pm ET

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, Principal Accounting 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

Analysts

James Spicer - Wells Fargo Securities, LLC, Research Division

Sunil Sibal - Citigroup Inc, Research Division

TJ Schultz - RBC Capital Markets, LLC, Research Division

Michael D. Peterson - MLV & Co LLC, Research Division

Eric B. Anderson - Hartford Financial Management, Inc.

Jeffrey Rudner

Operator

Good day, ladies and gentlemen, and welcome to the Eagle Rock Energy Partners Fourth Quarter 2012 Earnings Conference Call. [Operator Instructions] as a reminder, this conference call is being recorded. I would now like introduce your host for today's conference, Mr. Adam Altsuler. Sir, you may -- Director of Corporate Finance and Investor Relations. Sir, you may begin.

Adam Altsuler

Thank you, Kate, and thank you to our unitholders, analysts and other interested parties for joining us today on Eagle Rock Energy's fourth quarter and full year 2012 earnings call.

Before we get started commenting on our fourth 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, if 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 is included in the partnership's SEC filings, including in our 2012 Annual Report on Form 10-K, which we intend to file on or around February 27, 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 fourth quarter 2012 earnings press release and a transcript to this call on our website at www.eaglerockenergy.com.

Management may 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 mandates or our ability to consummate accretive growth projects differ from current expectations. Actual future distributions will be determined, declared and paid at the discretion of the Board of Directors.

I'll 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 another solid quarter to finish a good year in 2012. For the fourth quarter, we reported adjusted EBITDA of $66.2 million, up 12% as compared to our third quarter adjusted EBITDA of approximately $59 million. Distributable cash flow totaled $29.5 million, up 9% as compared to our third quarter. For the year, Eagle Rock reported $245 million of adjusted EBITDA and distributable cash flow totaling $129 million. This represented an 18% increase to our adjusted EBITDA as compared to 2011 and an 8% increase to our distributable cash flows as compared to 2011. This increase was despite a very challenging commodity price environment, especially the meaningful drop in natural gas and NGL prices during the year. 2012 was a year of achievement and overcoming challenges for Eagle Rock. We made significant progress strengthening our 2 businesses while overcoming weak price realizations, which impacted our financial results. We significantly increased the scale of our Midstream business with the acquisition of BP's Texas Panhandle Midstream assets and the successful startup of our newest cryogenic processing facility, the Woodall Plant, while our Upstream business delivered 25% more oil and gas production in 2012 as compared to 2011.

The acquisition from BP was a meaningful contributor to our improved results in the fourth quarter. We closed this acquisition on October 1, and assumed operational control of the assets on January 1 of this year. We are very pleased with the acquisition and the impact it is having on our growing Texas Panhandle business. The newly-acquired assets contributed over $6.8 million of adjusted EBITDA to our fourth quarter results.

During the past 6 months, we have negotiated and executed meaningful gathering and processing agreements with BP and Anadarko covering new dedication areas of over 1.2 million additional acres in the prolific Texas Panhandle and East Texas basins. We feel that our Midstream business has very strong momentum today.

We are currently in active negotiations with several large oil and gas operators, specifically in the Panhandle, to execute significant additional acreage dedications under fee-based arrangements. We believe our gathering footprint is enabling us to reach more active producers in the area under favorable fixed-fee commercial terms.

Our Upstream business had a solid year drilling in the Cana, Woodford and Golden Trend plays of Western Oklahoma. We reported total proved reserves at year-end 2012 of 58.3 million barrels of oil equivalent, which is down approximately 6% from our year-end 2011 reserves. Reserves were lower primarily due to the sale of our non-core Barnett Shale assets in December of last year for $15 million and to negative revisions to our natural gas reserves as a result of lower natural gas prices, which combined were greater than the increases to reserves related to extensions and discoveries and positive performance.

Due to lower natural gas prices, we reclassified approximately 7 million barrels of oil equivalent from proved to contingent resource reserves, which represents approximately 11% of our total 2011 year-end proved reserve base.

Total production for 2012 was slightly over 5 million barrels of oil equivalent or approximately 13,800 barrels of oil equivalent per day, and we replaced 174% of our total production during the year through our drill bit activity at a unit development cost of $22.08 per barrel of oil equivalent. Approximately 76% of the total proved reserves as of December 31, 2012, are classified as proved developed.

In addition, during the fourth quarter, we successfully concluded Phase 1 of our SO2 reduction project at our Big Escambia Creek Field in Southern Alabama. This important project involved a 24-day turnaround during the quarter where we shut the field down to install a superclass unit to reduce our SO2 emissions to meet a required step-down under our existing environmental permit. This turnaround negatively impacted our adjusted EBITDA by $6 million during the quarter. I'm very pleased to report, however, that the field is performing extremely well, and we've seen significantly improved recoveries of sulfur, as well as significant reductions in SO2 emissions to levels well below our step-down permit levels, all consistent with our plans.

Now focusing on the details of each of our operating business results. First, our Midstream Business. Operating income in the fourth quarter of 2012 increased by approximately $6.5 million or 138% as compared to the third quarter of 2012, despite lower average realized prices for NGLs and condensate. This increase was attributable to the additional volumes and associated cash flows from the newly-acquired assets and to improve run times and recoveries at certain of our Panhandle processing plants. Given the low price of ethane relative to the strength of natural gas prices during the fourth quarter, we were rejecting ethane at our plants that are capable of efficiently rejecting ethane. Given the continuing softness of ethane prices at Mont Belvieu and Conway and the relative strength of natural gas prices, it makes economic sense to reject ethane today.

We expect this dynamic to persist throughout 2013. On a positive note, we've seen the differential between Conway and Mont Belvieu significantly contract, which is helping our receipt price for the NGL barrels we sell at Conway. In the Texas Panhandle, gathered volumes were up over 100% -- 103% with combined equity NGL and condensate volumes up almost 83%, as compared to our third quarter. Gathering NGL and condensate volumes were higher as compared to the third quarter due primarily to the additional volumes from the newly-acquired assets.

We're very pleased with the acquisition of the BP asset and the long-term strategic relationship we have now established with BP. BP remains one of the largest producers and leasehold owners in the Texas Panhandle. BP and its drilling partners have historically been active drillers in this prolific area, and we anticipate they will continue to be very active for the foreseeable future. We currently anticipate we'll connect over 65 new wells across the newly-acquired assets, i.e. the BP assets, and including our own legacy assets, we could see new well connects in the 80 to 100 new wells connected in 2013. This will be a meaningful driver to our growing gas, gathering and processing throughput. The drilling economics for the Granite Wash, the Cleveland, the Tonkawa and now the Hogshooter formations still remain very attractive to the producers, and drilling activity levels remain very high in the Panhandle.

We are moving forward aggressively with the integration of the BP assets with our current systems in the area. We expect most of the system integration to be completed later this year. And when it is, the new Eagle Rock Panhandle system will comprise over 6,000 miles of gathering pipeline serving over 5,000 wells and over 480 million cubic feet a day of cryogenic processing capacity, with an additional 60 million cubic feet a day of cryogenic processing capacity to come online in the first half of 2013 following the completion of our Wheeler Plant.

We have successfully integrated the back office operations and staffing of the new BP assets, and we are focused on extracting the cost synergies. Our Wheeler Plant construction remains on budget and on schedule. And upon its successful commissioning, which we anticipate will be in late May of this year, Eagle Rock will become one of the larger Midstream providers in the Texas Panhandle.

Given the continued focus by the producers on drilling for liquid-rich reservoirs and the growing inventory of crude and condensate levels in the Texas Panhandle, we are complementing our gathering and processing business with a new crude and condensate logistics business to capture opportunities in the Panhandle. We are pleased to announce that on January 7 of this year, we commissioned our new condensate transloader operations near Pampa, Texas. We built 2 transloaders, which will transfer condensate from trucks to rail cars to improve our netback prices for our own equity condensate barrels today. We have moved up to 2,400 barrels per day from trucks to rail tankers since we commissioned the transloaders. We currently operate the transloaders 5 to 6 days per week during daylight hours only. We are receiving many inquiries from producers to move their product. Total cost to build and commission the transloaders was approximately $2.2 million, and we anticipate this will generate a rate of return in excess of 50% at a 2.5x multiple. We are evaluating additional crude and condensate logistic opportunities in the Panhandle in our growing marketing and trading segment.

Activity in the Panhandle remains robust with approximately 92 rigs active in the basin, and 15 are drilling on acreage dedicated to the combined Eagle Rock and BP Panhandle systems. That makes up 16% of the total rig count in the Panhandle today is operating on Eagle Rock acreage.

Turning now to our East Texas and other Midstream segment, gathered volumes though were down 12.3%, with equity NGL and condensate volumes up slightly compared to the third quarter. The decrease in gathered volumes was due to natural declines in the production of the existing wells and the loss of production in the Gulf of Mexico due to Hurricane Isaac. As we previously discussed, our Yscloskey Plant in South Louisiana, in which we own a non-operated ownership interest, suffered significant damage from Hurricane Isaac back in August of last year. The Yscloskey Plant has been shut down since that time and is expected to remain shut down for an indefinite period of time. Gathering volumes associated with the Yscloskey Plant for the first 6 months of 2012 averaged approximately 52 million cubic feet a day and were primarily tied to fee-based contracts.

The Yscloskey Plant contributed approximately $500,000 of adjusted EBITDA to our partnership for the first 6 months of 2012. And while not material, we are disappointed in this outcome. Partially offsetting the declines in this segment, we experienced a 2% increase in gathered volumes servicing the liquids-rich Austin Chalk play in East Texas, which continues to see drilling activity by several large producers. Our East Texas processing assets are operating at approximately 70% utilization of our total processing capacity in the area. The Austin Chalk play remains the primary driver in our volume growth in this area. Currently, there are 4 rigs drilling in the Austin Chalk play in the East Texas and Western Louisiana portions of the play closest to our Midstream footprint, and 2 of these rigs are drilling on acres dedicated to Eagle Rock.

We continue to monitor drilling activity in the immediate area around our assets that's associated with the horizontal Woodbine and Tuscaloosa Marine Shale. There is continued leasing in both of these plays, but no material production results to report at this point.

Turning now to our Upstream business. We continue to execute on our drilling activity in the SCOOP region of Western Oklahoma. During the fourth quarter, we maintained a 3 operated rigs drilling in the Mid-Continent area, of which 1 rig was devoted to our Southeast Cana Shale program and 2 rigs to our Golden Trend program. Eagle Rock's Golden Trend field and the Southeast Cana leasehold are all located in the heart of the South Central Oklahoma Oil Province, or better known as SCOOP play, located in Grady, McClain and Garvin Counties, Oklahoma. Eagle Rock owns approximately 14,000 net acres in the larger SCOOP area that produce from multiple formations, including horizontal completions in the Woodford shale. For 2013, we have reduced our operated rig count from 3 to 2 primarily to reduce our overall capital spend rate. At this time, we are running 2 rigs, and we expect to maintain 1- to 2-rig program throughout 2013. Assuming a 2-rig program throughout 2013, we expect to grow our production approximately 3% to 4% as compared to 2012 after excluding the effects of the sale of our non-core Barnett assets.

Our drilling focus continues to be on liquids-rich production. We do not plan on any dry gas drilling in 2013. During 2012, we drilled and completed 33 total wells, of which 11 were proved undeveloped locations and 12 were operated by Eagle Rock. We also maintain a very active recompletion and workover program throughout our Upstream portfolio.

Our initial operated Southeast Cana horizontal Woodford well, the Beckham 1-27H, continues to perform very well. Eagle Rock operates the Beckham well with 100% working interest and a 76% net revenue interest. We have recently TD-ed our second operated horizontal Woodford well, the Kelly 1-2H well, with a 68% working interest. We are frac-ing this well this very week. The Kelly 1-2 is located approximately 2 miles Southeast of our Beckham well. We remain pleased so far with the drilling and production results in the area, and we believe we have a significant resource potential on our large acreage position.

Operating income in our Upstream business for the fourth quarter decreased by approximately $2 million or 13% as compared to the third quarter of last year. The decrease was primarily due to lower production during the quarter associated with our previously discussed turnaround at the Big Escambia Creek facility, which again is located in Southern Alabama, and lower crude oil NGLs and sulfur prices.

Production volumes in our Upstream business averaged 12,900 barrels of oil equivalent per day during the quarter, which was a decrease of almost 10% as compared to the third quarter. This reduction though was entirely driven by the turnaround at BEC and some additional compression issues that we had in our East Texas operations. Those have since been resolved and production has increased since the end of last quarter.

Focusing on our Big Escambia Creek Field, since the turnaround, the field is performing very well and sulfur recoveries have increased while SO2 emissions have been reduced well below the current permitted levels. The next phase of the SO2 emissions reduction project involves potential upgrades to the existing sulfur recovery unit. We expect to replace the incinerator in the sulfur recovery unit in 2014 at a cost of almost $15 million. We are procuring the engineering and long lead time items during 2013 with expected completion in 2014.

The final phase of the project will occur in 2015 and 2016 while we are evaluating the replacement of the remaining portions of the sulfur recovery unit. Once this is concluded, we expect to recognize operational cost savings and improve the overall reliability of the facility in addition to recovering more of the marketable elemental sulfur from the well stream.

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

Jeffrey P. Wood

All right. Thank you, Joe. As mentioned, we reported adjusted EBITDA for the fourth quarter of approximately $66 million. That represents a 12% increase to the $59 million that we reported for the third quarter of 2012. Fourth quarter results benefited from a strong contribution from our newly-acquired assets in the Texas Panhandle. As Joe mentioned, the former BP Midstream system contributed almost $7 million of adjusted EBITDA in the latest quarter. With this and the generally stronger run times and recoveries in the Panhandle segment, the overall contribution to adjusted EBITDA from our Midstream Business was up over 50% relative to the third quarter.

These factors more than offset the lower contribution from the Upstream segment in the quarter due to the scheduled downtime of our Big Escambia Creek Field in Southern Alabama, where we completed the installation of additional sulfur recovery equipment at that facility. We estimate the downtime and additional operating costs associated with that project to have negatively affected our adjusted EBITDA for the fourth quarter by approximately $6 million.

On a commodity price front, crude oil and natural gas liquids prices were down quarter-over-quarter. Average WTI spot prices were down approximately 5% from the third quarter, with our realized prices for condensate down even further as that product has become somewhat oversupplied in the Texas Panhandle area.

Meanwhile, the NGL price environment continue to be a challenge and to weigh on results, although the impact was muted again this quarter by our strong hedge portfolio. While composite NGL prices remained somewhat stable in the fourth quarter, they remain severely depressed from the levels we saw last year. And prices on the light end of the barrel continue to deteriorate from their already low levels that we saw in the third quarter.

Ethane, which makes up the majority of the NGL stream by volume, is down a remarkable 70% over the course of 2012. And propane, the second largest component, ended the year down over 35%. The bright side to all of this is that we have hopefully reached the point where the light end of the NGL barrel does not have room to fall much farther. Ethane is at or below its price parity point with residue gas, and we are seeing the supply response in the form of widespread ethane rejection. Propane, meanwhile, should see near-term relief in the form of greater exports, including from the expansion of enterprises existing export terminal on the Gulf Coast mid this year. We feel very good about delivering solid results in the face of this extended downturn in liquids prices, and we believe that maintaining good liquidity, focusing on balance sheet strength and continuing to hedge aggressively are all prudent objectives in this environment, given that we are unsure how long the NGL pricing weakness will persist.

Now speaking of hedging, our extensive hedge portfolio provided its intended protection again during the quarter. We recognized $12.9 million of realized settlements on our commodity derivatives portfolio during the quarter, that's down slightly from last quarter. We have continued to opportunistically add hedges in recent months, particularly on the outer part of the curve. So far in 2013, we have added a Cal '15 crude hedge at a strike price north of $90 a barrel and a 3-year hedge for natural gas at $4.16 per MMBtu covering the years 2014 through 2016.

These hedges, as is the case with the vast majority of our hedge portfolio, were done in the form of swaps at prevailing market prices and without any upfront costs to Eagle Rock. We did file an updated hedging presentation to our website last night, so I encourage you to review that if you would like greater detail on our derivatives portfolio.

Finally, on the commodity price front, sulfur traded at $160 per long ton during the fourth quarter at the Tampa, Florida pricing hub. Prices recently settled for the first quarter of 2013 at $150 per long ton. We have seen some small declines in the market price for sulfur for several quarters now, but at current prices sulfur remains a very profitable byproduct of our Upstream operations in Southern Alabama and East Texas.

We recorded a net loss in the fourth quarter of approximately $55 million that was driven primarily by impairment charges in both segments. We continued to see the effect of declining gas prices on our Upstream pud inventory and in volumes through certain of our Midstream systems associated with dry gas fields. Absent the impairment charges and the unrealized gains and losses on our derivatives, net income for the quarter would have been a positive $4.8 million. We also posted a solid increase in our distributable cash flow for the fourth quarter. We reported total DCF of $29.5 million, that represents an increase of 9% from the DCF we've reported in the third quarter. The increase was driven by our improved operating results and adjusted EBITDA. As you know, we paid a distribution of $0.22 per unit with respect to the fourth quarter on February 14, 2013. Our distributable cash flow on a per unit basis represented a coverage of 0.9x on net distribution for the quarter. Now our improved distributable cash flow for the fourth quarter was in spite of reporting higher maintenance capital relative to the third quarter. Most of this increase in maintenance capital was a result of higher spending on the first phase of our SO2 emissions reduction project at our Big Escambia Creek facility, which again processes our Upstream production in Southern Alabama. We have been discussing this project for over 1 year, and as Joe mentioned, we were very pleased to see the first phase be implemented so successfully. We classified approximately $6.2 million of the project's capital spending as maintenance CapEx during the fourth quarter. This is more than double the maintenance CapEx related to the SO2 project that we recognized in the third quarter that represents over 50% of our total maintenance capital for the fourth quarter.

We classify the majority of the spending on the SO2 project as maintenance capital even though it is a onetime event and should not negatively impact our DCF after we complete the full project. If you adjust for the SO2 maintenance CapEx, our normalized DCF for the fourth quarter was $0.24 per unit, and we generated distribution coverage of 1.1x. Further, we do expect that maintenance CapEx associated with this SO2 project to be lower in the coming quarters than it was in the fourth, and that should enhance our reported DCF going forward.

Turning to our liquidity picture, we incurred new borrowings under our credit facility at the beginning of the fourth quarter when we closed on the acquisition of BP's Midstream assets in the Texas Panhandle. That funding on October 1 totaled over $200 million. Of course, we have prepared for that in advance through our senior notes issuance in July and the equity offering in August. Even with that, the acquisition funding left us with less dry powder under the facility than we'd normally like to see. To deal with this, we went out to our lending group in December and received increased commitments under our existing credit facility. Total commitments were increased from $675 million up to $820 million. Now the facility is designed with an accordion feature that easily accommodate increases like this, but to a total commitment level of $1.2 billion.

The increase in commitments to $820 million was accomplished primarily through our existing lenders, and we were pleased to have Whitney Bank join the group, which now totals 15 banks. We appreciate the continued support of all of our lenders and believe the increase in commitment demonstrates the great relationship that we have with our banking group.

After the additional borrowings and the increase in commitments, we ended the fourth quarter with over $190 million of availability under the facility. And that takes into account about $609 million of outstanding borrowings and approximately $19 million of outstanding letters of credit at the end of the quarter.

Our leverage metrics did step up in the quarter due to the borrowings for the Texas Panhandle acquisition, a key metric, which is total debt to adjusted EBITDA or leverage ratio, which have been running consistently around 3.5x for several quarters, moved up to over 4x at the end of the year. This is higher than our desired long-term level, and we expect to push it down over time in part due to higher EBITDA contributions from the acquired assets as we complete the integration of the former BP system with our existing Panhandle system.

We also expect our leverage ratios to benefit from our reduced capital program in 2013 relative to 2012. Last year, we had our highest level of organic spending in our history at over $300 million as we worked on the construction of 2 processing plants and maintained a very active drilling program. We expect capital spending absent acquisitions to decline by approximately $100 million in 2013 to just over $200 million. Of that total we expect to classify approximately $70 million as maintenance CapEx.

Simultaneous with the increase in commitments, we obtained a temporary step-up in the total leverage ratio under the facility, the maximum total leverage ratio allowed from 4.5x to 4.75x, and that's good through the third quarter of this year. In addition, we put in place a new senior secured leverage ratio through the same time period and obtained an increase in the amount of our permitted other investments. Now while we don't think we'll need the step-up in the leverage ratio, our lending group was willing to give it at no additional cost, and it does help us sleep a little better while we integrate the acquired BP assets.

Overall, we are very pleased with our financial results for the quarter and our financial and strategic position as we head into 2013. On one final note, we are running ahead of schedule in processing our K-1 tax forms this year. In fact, we are expecting electronic access of the K-1s to go live any minute. If you are a holder of Eagle Rock units at any point in 2012, the K-1 will be mailed to you. If you'd like to access it sooner, you can do so via our website at www.eaglerockenergy.com, where there is a link on the homepage for you to retrieve your K-1s.

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

Joseph A. Mills

Thank you, Jeff. We're feeling very positive about the long-term prospects of both of our businesses. The acquisition of BP's Midstream assets in the Panhandle is an important milestone in our corporate growth and really strengthens our overall Midstream Business, and creates a strong franchise in the Panhandle.

We could not be more pleased to have BP as one of our largest customers and establishing a long-term relationship under a fixed-fee gathering and processing agreement. Given the activity levels we see in the Panhandle, especially around the newly-acquired system, we are anticipating a very active year at our Midstream Business and anticipate continuing to grow our fixed-fee revenues from this important area.

We are equally pleased about the expansion of our strategic relationship with Anadarko Petroleum in the Austin Chalk, East Texas and Western Louisiana that we announced during the fourth quarter. Anadarko has always been one of our most important customers, and we're very excited that they chose to dedicate an area equal to almost 800,000 acres to Eagle Rock to continue gathering and processing their production as they drill in the Austin Chalk and other formations in Western Louisiana.

This dedication is in addition to the existing 1.1 million acres we have from prior agreements for a total of almost 2 million acres in East Texas and Western Louisiana. The amendment negotiated with Anadarko was for a 10-year dedication on the new acreage and amends our fee arrangement to be fixed-fee on any new wells they drill after April 1 of last year. These 2 substantial agreements show our resolve in moving toward more fixed-fee gathering and processing arrangements to reduce the commodity exposure of our Midstream Business.

Our Upstream business is focused on delineating our reserve potential in the SCOOP area. We estimate the resource potential assuming 160-acre spacing would total almost 35 million barrels of oil equivalent. And at an 80-acre spacing, we could have over 55 million barrels of oil equivalent net to our interest. This is only for the Woodford resource potential. We estimate the resource potential for each of these Woodford wells, depending on the depth, to be between 800,000 barrels of oil equivalent up to 1.6 million barrels of oil equivalent per well.

Substantially, all of our acreage in this area is held by production so we do not have any imminent lease expiration issues, and this allows us to develop the area at a more moderate pace. We are evaluating our Woodford rights position and capital demands in this important play with the option to continue developing the resource potential ourselves at a moderate pace or to monetize part of our position in the play. Given the very substantial cost to drill these wells, it is prudent for us to explore ways to maximize the reserve potential and returns to our unitholders while limiting our capital requirements.

We are entertaining some inquiries from interested third parties to partner on our SCOOP acreage. We will evaluate the best method to improve the total returns to our unitholders from this important asset.

Eagle Rock remains well-positioned today to benefit from our 2 complementary businesses. We are focused on slowing down our CapEx spend rate and strengthening our balance sheet and leverage ratio levels as we navigate this continued period of lower commodity prices. Our business plan and our diversified model remain strong as we look forward to 2013 and beyond. We made a decision to pause our distribution growth last quarter given the continued meaningful drop in commodity prices. In the near term, we plan on strengthening our distribution coverage as we get greater clarity on commodity prices and execute on the near-term goals of integrating the newly-acquired Panhandle assets, solidifying our resource potential in the SCOOP area and strengthening our balance sheet.

The company has a deep portfolio of opportunities to capitalize on, and we're excited about the future of Eagle Rock. As Jeff mentioned earlier, for 2013, we expect to have a total capital budget of $208 million, which is down by almost 1/3 as compared to what we spent in 2012. We anticipate spending $88 million in our Midstream Business to further integrate our newly-acquired Panhandle assets and complete the Wheeler Plant, which is scheduled for May startup of this year. And we also anticipate spending about $118 million in our Upstream business, generally expected to focus on drilling in the SCOOP area and work around our Alabama operations. The successful integration of the newly-acquired Panhandle assets and quality execution of our ongoing organic growth and drilling projects remains our primary focus. As always though, we remain very active in the acquisition arena as we look for complimentary and accretive bolt-on acquisitions that we believe can deliver long-term value and accretion to our company. There are numerous attractive assets on the market today for both our Midstream and Upstream businesses, and we are evaluating various opportunities.

On a final note, I'm sure each of you have heard or read about the record blizzard that hit the Texas Panhandle in the past 24 hours. It was a record 17 inches of snowfall and tropical storm force winds across the area. Eagle Rock personnel worked very hard during the storm to keep power plants running. We suffered minimal downtime from our processing facilities, but there has been reduced gas flow due to wells being shut in by our producer customers. It is too early to assess the financial impact, but we do not expect it to be material to our financial results during this quarter.

I want to thank all the Eagle Rock employees who work very hard everyday to safely and efficiently and profitably grow our partnership and our cash distributions to you, our unitholders. With that, we'll now open it up to questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of James Spicer with Wells Fargo.

James Spicer - Wells Fargo Securities, LLC, Research Division

I guess you assumed control of the BP assets on January 1. Can you provide a little bit more specifics as to the integration activities over the next 6 to 12 months? And on a related note, the $6.8 million in EBITDA that were contributed from those assets during the quarter, how do you see that changing as a result of the integration?

Joseph A. Mills

Yes. Thank you, James, great questions. Well, first off, yes, so in terms of the integration, integration's going very well. As I mentioned in my prepared text there, obviously, all the back office integration is completed. And so we now have full operational day-to-day control over these assets, and we could not be more pleased. The truth is we're seeing more opportunities, in particular around operational synergies, as well as cost improvements, in particular around the operating costs. So we think there'll be improvements there, which obviously goes right to our bottom line in terms of adjusted EBITDA. In terms of the physical integration, as you may recall from our dialogue when we first bought these assets, there are several very important interconnects that we are working on. One on the west side that would integrate our Stinnett system with Sunray where we can move very valuable rich gas that also has helium and nitrogen up to Sunray, which has the capability of extracting both the nitrogen and the helium. That is well underway. We are looking at purchasing a pipeline that is in the area that will allow us to do that interconnect. That's going to take a little bit of time. We have a deal with the current operator. Unfortunately, it's a FERC-regulated line, so it's going to have to be spun down, but that'll take call it, 4 to 5 months. So we think by midyear, that project will be done, and there'll be significant cost, as well as production enhancements there. On the east side, in fact on March 1, this Friday, the first of our interconnects is being tied in along with some compression that allows us now to start moving gas from the east side, the BP's east side of the newly-acquired assets east side down toward our Phoenix and Woodall Plants. And that's the first of 3 interconnects that we'll be doing this year. So we feel like we are on schedule, quite frankly probably a little ahead of schedule on the integration, the physical integration. The truth is we see a lot of opportunities. I've mentioned there are 15 rigs running on the combined systems today. So we're getting a lot of interest from producers in terms of the capacity. It's clearly bringing on Wheeler. Our Wheeler Plant later this year in May is going to be important as we continue to see growing, gathering production. I mentioned the OpEx savings. I think there's some real opportunities there, actually even more than we thought. And so that kind of goes to your question about the $6.8 million of adjusted EBITDA. We're very pleased, quite frankly that's ahead of our early projections in terms of what we thought these assets would contribute. I think there'll be improvements to that number throughout the quarters this year. Obviously, we don't give guidance, financial guidance, but suffice to say, I think we'll do better than that number kind of going forward each quarter.

James Spicer - Wells Fargo Securities, LLC, Research Division

Great, that's helpful, I appreciate it. The next question I had is on the SCOOP. You mentioned in your remarks that you were entertaining discussions with third parties. Just wondering if you can provide any thoughts around how you're thinking about a potential structure, whether it would cover your entire SCOOP acreage or just a portion of it, whether it would be kind of a 50-50 JV or a minority interest-type deal? Any more thoughts around that?

Joseph A. Mills

That's a great question, James. Well, first off, we have been approached by numerous parties, very interested in either partnering with us or outright purchasing our position in the SCOOP area. I'll be honest with you, it's kind of all across the board. Some have approached us about just buying the Woodford rights and allowing us to keep certainly all of the up-hole rights, where obviously we produce a lot of oil and gas today. We've also received inquiries by just outright monetizing our entire position in the SCOOP play. I'll be honest, it's too early to say. We are currently evaluating. Really, we're still assessing what we think the Woodford potential is. We have not engaged with anybody to be clear. As I mentioned earlier, we are in fact frac-ing our Kelly well today. In fact, we started, I guess, it's fifth stage is ongoing right now. Yes, so we're -- this is a 10 -- no, 13 stages and we're on stage 5 as we speak. So clearly, once we see some results off this well in the next couple of weeks, it will really validate what we already think is going on out here. So it's probably a little early for me to say exactly how this will all play itself out, but it is important to note we're getting a lot of interest. We like what we see, given that everything we own is basically held by production. We think we're in a pretty -- we're in a sweet spot and we don't find ourselves compelled to have to rush and do anything just yet. So we want to make sure that whatever steps we take, we're maximizing the value proposition of our underlying position.

Operator

Our next question comes from the line of Sunil Sibal with Citigroup.

Sunil Sibal - Citigroup Inc, Research Division

Starting off on the Upstream side of things. Could you quantify the production from the non-core Barnett assets that you sold? And then what was your exit rate coming out in terms of the total production?

Joseph A. Mills

Yes. So for the Barnett, it was producing, was it 4 million a day?

Jeffrey P. Wood

Yes. So we averaged in 2012, we averaged about 5.1 million a day for our Barnett assets that we divested.

Joseph A. Mills

And then the exit rate for last year was 77 million?

Jeffrey P. Wood

Yes, 77 million a day.

Joseph A. Mills

Right, which was low, of course, because of the shutdown at BEC, which didn't come back on until right there at the end of the year. So that was about 4 million a day that was shut in because of the Big Escambia Creek turnaround. All normalized, it's about 80 million a day, a little bit over 80 million a day.

Sunil Sibal - Citigroup Inc, Research Division

Okay. And then your expectation, I know previously you had talked about your sort of exit rates next year. How should we think about that number with this asset sale?

Joseph A. Mills

Yes. So for this year, for 2013, and again after we normalize for the sale of the Barnett assets, we expect to see probably an exit rate around 82 million to 83 million cubic feet a day. So that's about a 3% increase to our exit rate of last year.

Sunil Sibal - Citigroup Inc, Research Division

Okay. Then on the Midstream side of things, so the turbo expander project on the Phoenix plant. So has that been completed?

Jeffrey P. Wood

Yes. Thank you for asking that. Yes, we -- I'm pleased to say we replaced or actually repaired and reinstalled the expander at Phoenix in early December. And since that time, that plant has been operating very well and that certainly contributed during the month of December to the improved recoveries that we saw in the Panhandle. And it couldn't have come at a better time, just given all the activity that we're seeing around us, the drilling activity.

Sunil Sibal - Citigroup Inc, Research Division

Yes. And then I think in the press release, you did talk about the recovery improvements partly because of, I guess, Phoenix and then also from the BP assets. Now how should we be thinking about your NGL recovery going -- NGL as well as condensate recoveries in '13? A further improvement from the fourth quarter levels?

Joseph A. Mills

I'm sorry. Could you answer?

Unknown Executive

With the recovery levels, of all of our plants, as Joe said, now in full operation including the turbo expander replacement at Phoenix. Our recovery levels are just that where we need those plants and what they're designed for. With Wheeler coming on in the second quarter of this year, we'll see our average across our systems actually increase in terms of recovery. And as you rightfully said, the plants for BP have added to that system recovery as well. So we're looking forward to a year of actually good recoveries across the whole other NGL [indiscernible].

Sunil Sibal - Citigroup Inc, Research Division

Okay. And then a couple of housekeeping items. What was your CapEx spend for the full year in '12 on the Upstream side?

Jeffrey P. Wood

Yes. See for 2012, $158 million is what we spent in the Upstream business.

Sunil Sibal - Citigroup Inc, Research Division

Okay. And what was the unit count at the end of the year?

Jeffrey P. Wood

It's about 147 million units.

Operator

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

TJ Schultz - RBC Capital Markets, LLC, Research Division

I guess just on the Upstream first. How are your, I guess, options there going to impact whether you run 1 or 2 rigs this year? I guess the question is, will you drill another horizontal well there without a partner or would you just focus on the Golden Trend until you figure out your options?

Joseph A. Mills

That's a great question, TJ. Yes, so I mentioned earlier, we have 2 rigs running right now and both are vertical wells in the Golden Trend. So after we TD-ed the Kelly well, we did release that rig. So we could frac and kind of assess what the results are. Right now, our intentions are we probably wouldn't pick up a second rig for that play, the horizontal Woodford play until probably May or June. We'd like to see some production results. There is obviously, as we look at some of these ideas or proposals that we're seeing, which could drive exactly to your question, meaning if we find a partner that wants the joint venture with us, where we'll still operate and obviously they'll pay a disproportionate amount of the capital costs, I would imagine that we'll pick up a rig sooner and possibly even 2 rigs in that play. If we outright monetize, well, then you know that answer, we won't have any rigs running there. So the right answer is we have laid down the rigs at the Southeast Cana for now as we assess kind of what direction we want to go with our SCOOP acreage. But our plan is, probably in any event, is to pick up a rig and start drilling horizontal again come May or June of this year.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Okay. Well, I mean I guess, how long a process do you expect it to take for you guys to continue figuring out these options? And with the SCOOP acreage, is this...

Joseph A. Mills

Probably not too long. I mean, you can imagine the level of interest is pretty strong. And obviously, there's a lot of drilling going on around us. So we're seeing what those results look like. And no, I can tell you that Continental and Newfield, Marathon are all having some pretty exceptional results as they highlighted on their conference calls. So I think the short answer is it won't take us very long. We like what we see though. I mean, I'll be honest again given that we have no pressure to drill, I mean because of all our acreage is held by production. Well, I think we have the luxury of time to make sure that we take the next prudent step. I think what is important is we have reduced our CapEx spend rate for the year, which we think is important. And of course, a big chunk of that is in the Upstream business. So again, to put it in context, we're planning on about $118 million capital spend in '13 as compared to $158 million that we spent in the Upstream business in 2012. So where you're seeing that impact is mainly around the drill bit. So we're just slowing down. We still will see production growth, like I said 3% to 4% for the year, even with lower activity levels.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Okay, good. I guess on the condensate transloader project that you talked about, obviously solid returns. What's the potential to kind of replicate that in larger scale as producers look for the right condensate markets?

Joseph A. Mills

That's a great -- we actually think it's very scalable. We are working on several projects. The Panhandle is seeing the same both challenges as well as opportunities that we're seeing in the Permian regarding liquid productions. So clearly with the Hogshooter, in particular the Hogshooter, as well Linn, and others, Apache are certainly focused on some of these really liquids-rich plays. There's no pipelines, no crude or condensate pipelines coming out of the Panhandle today. So really, it all is being moved by truck. And so that's where we see the opportunity. We think this is scalable. Number one, in fact, like I said, we're getting approached by a lot of large producers to move these barrels. We could easily build additional transloaders. The truth is the next step rather than build transloaders, and we actually cited this next to one of our main processing plants, being our Gray facility, the next step for us would be rack loading, building a rack loading facility with storage, and we are evaluating that very potential right now. And that could be in the 25,000 to 50,000 barrel a day storage facility. So that's how we would scale this operation pretty quickly.

Operator

[Operator Instructions] Our next question comes from the line of Michael Peterson with MLV.

Michael D. Peterson - MLV & Co LLC, Research Division

I have 2 questions this morning, both of them follow-ups. First one will be a follow-up from James' first question. Joe, when you talk about your efforts in terms of integration in the Panhandle, recognizing that it's probably going to take you 12 to 18 months, and I appreciate the details you've provided on that, is there any reason for us to expect that some of the operational synergies and end-cost benefits that we're likely to see would occur anytime before 2014?

Joseph A. Mills

The answer to that is yes, definitely. I would say probably not before midyear. But for sure, we expect to see some of those operational synergies and cost improvements by mid this year, mid-2013.

Michael D. Peterson - MLV & Co LLC, Research Division

Okay. So we can see some of those benefits even in advance of completing the integration efforts?

Joseph A. Mills

That is correct. Yes, actually the way it's going to work, Michael, is that there are several integration opportunities. And so obviously, as we complete each one, I think we'll see improvements. They won't all be completed until probably early '14, so that's when you'll see the maximum benefit. But you'll see benefits throughout the year.

Michael D. Peterson - MLV & Co LLC, Research Division

Okay, very good. Second question regards capital allocation between your 2 business segments. In light of the challenging NGL and the condensate market environment, what were the key metrics that you considered when comparing the Upstream versus Midstream investment opportunities in 2013, particularly in light of the capital budget you just shared with us?

Joseph A. Mills

That's a great question, Michael, thank you. Well, we've always been very public about this, and so happy to revisit it. We target an 18% rate of return in our Midstream Business, and we target about a 20%-plus rate of return in our Upstream business. Historically, our Upstream business just because every dollar we invest in the drill bit, we can see a return a lot faster. From the time we spud a well to the time it's online, it's typically less than 6 months. It's typically 75 to 90 days. So call it 3 months. So from a return standpoint, we get our DCF back a lot faster in the Upstream business. Given the deep inventory of drilling locations we have in the Upstream business, that's part of the reason you're seeing more capital allocated toward it. We clearly love our Midstream Business. We'd like to continue to grow it. The bulk of the capital, to put it in comparison, last year in the Midstream Business, we spent $145 million. But as Jeff alluded to, a big chunk of that was we had 2 plants going on at the same -- the construction of 2 new plants, 1 being Woodall and the other 1 being Wheeler. Of course, Woodall was completed, and we're just now finishing up Wheeler. We don't have any current other major construction projects scheduled in the Midstream Business today. Now I just talked about with James Spice -- or excuse me, with TJ, that we are looking at possibly scaling this condensate business that we've started up, and that could be a pretty sizable project. That would be, obviously, commence mid this year with targeted startup sometime in 2014. So our budget could increase in the Midstream Business, but that's -- we're still evaluating that opportunity today.

Operator

Our next question comes from the line of Eric Anderson with Hartford Financial.

Eric B. Anderson - Hartford Financial Management, Inc.

Joe, I wonder if I could follow-up just a little bit more on the condensate discussion. Are you talking about an operating facility that other, that producers are driving their own trucks, too? And then they're loading that on rail cars? Or are you -- you have your own trucks that are going out to producers and bringing back condensate? I wonder if you could just clarify that a little bit?

Joseph A. Mills

No, that's a great question. Thank you, Eric. Well, so today, we are currently moving our own equity barrels, so really to give you more detail about what we're doing. So as you know, we obviously have a pretty substantial condensate, a net equity condensate barrels because of our contract mix with our current producer base. And so -- and as Jeff alluded to in his commentary, we've seen some degradation of price around the condensate barrel, and that's not unique to the Panhandle. We're seeing that kind of around the country. And so as a way to improve our netbacks, we built these transloaders to at first start moving our own equity barrels. Today, we are only moving our own equity barrels to receive this price uplift. So what we do is we have a -- we signed a long-term agreement with a trucking company that has dedicated trucks exclusive to Eagle Rock, and we're bringing barrels from our own processing facilities to this transloader, which is just outside of Tampa, and loading it on to rail cars and getting a much better price or a lower hauling price for our own commodity. Because of the success of this, our startup, we're getting a lot of inquiries from producers that would then do exactly what you're saying. They would then haul, we could either do it for them with our relationship with our trucking company or they could bring their own trucks from their batteries with condensate to our transloader, and then we would load it off of their trucks on to rail cars. So that's the business that we're building. We're getting a lot of interest from producers. But quite frankly, we've been approached by one of our competitors that can't move their condensate out. And so they've asked us to make them a proposal to do the same thing with their condensate. So we think this business is scalable. The next step would be to build this rack loading facility where, same question, trucks would bring condensate to our storage facility, 25,000 to 50,000 barrel a day storage facility. We would unload their trucks into our facility, and then using a rack loading, we would then move it onto rail cars. That's kind of Phase 2, and that's what we're evaluating right now.

Eric B. Anderson - Hartford Financial Management, Inc.

So if this really sort of took off, would you have to look at possibly leasing some rail cars or try to get some capacity locked up here?

Joseph A. Mills

Definitely, absolutely. In fact, that's been -- that's a great question. I'm sure you're keeping up. Rail cars are a premium today. And whether it's being hauling crude out of the Bakken or out of the Permian, that is a -- new rail cars are very much at a premium. We have secured rail cars. We're working with another producer -- or excuse me, another crude logistics company. We think this business can be scalable. We're really looking at several opportunities in this area. I'm hopeful we'll have more to share on that here in the next, call it, 3 to 6 months.

Eric B. Anderson - Hartford Financial Management, Inc.

Okay. And if I could ask another question about in the Panhandle. You alluded to a couple of possible acreage dedications that you've been working on up there. If they come to pass, what -- would there be any kind of significant capital expenditures, requirements that would go along with those?

Joseph A. Mills

Yes, there could be. Thanks for that question, Eric. We're very -- we're actively in discussion with several large operators out here. The short answer to your question is there's not a -- the good news is there's not a whole lot of significant capital requirements associated with these new agreements. Just given the sheer scope of our footprint, our gathering footprint, many of these producers are nearby, and that's not to say that we won't have to lay pipelines to them. We will, but they're not long lays. And so that's probably the best news is that these would be meaningful operators, large acreage dedications and minimal CapEx to hook them up.

Eric B. Anderson - Hartford Financial Management, Inc.

And these will be new relationships or sort of add-ons to existing?

Joseph A. Mills

Both, both. yes, both. It's both new as well expanding ongoing commercial relationships.

Operator

Our next question comes from the line of Jeff Rudner with UBS.

Jeffrey Rudner

A question for either Jeff or Joe or both regarding the dividend. If possible, I'd like to get a little bit more clarity on the dividend going forward. I know this past quarter was the fourth quarter we paid the dividend at $0.22 per unit. But the coverage ratio was 0.9. Would you anticipate being able to maintain the dividend at $0.22 per quarter for the rest of the year?

Jeffrey P. Wood

Yes. So this is Jeff. I'll take the first shot at that. I guess what I'll start with is, that we don't really give forward guidance on our distribution. That is absolutely at the discretion of our board. What I can tell you is that obviously, we don't take dividend increases like we'd make in the past lightly. We always do that with an eye to the sustainability of those distributions. So we wouldn't have gone to the $0.22 per unit if we didn't feel comfortable that, that was sustainable. And as you may remember, or at least those of you that have been unitholders for a while, we had been talking about further increases in the distribution. And since that time, at least through '12, the board has decided to hold the $0.22 constant. And that, of course, is due to a number of factors. I mean, as I mentioned, NGL, ethane, in particular, fell 70% over the course of 2012. That's an important product that we produce, both in our Midstream and Upstream businesses. And then the second item that kind of weighs on the DCF, and that really was one of the major drivers to the coverage ratio of 0.9 in the quarter, was all of the spending that we're doing in that facility in Southern Alabama. As I mentioned in my remarks, we spent over $6 million -- well, well over $6 million around that project over the quarter. We've classified over $6 million of it as maintenance capital. And if you back that amount out, which while we certainly think it's appropriately classified as maintenance, not growth capital, it is sort of onetime spending, you back that out and we were at 1.1x. And I guess all of that just to say that no one is more interested in distribution increases than the team sitting around the room here. And we realize how important that is to both you guys and all of our unitholders. So that's why we do things like the BP acquisition. It's why we do things like continue to drill attractive locations on the Upstream side is to generate higher cash flows that we can then pay out to you.

Operator

I'm not showing any further questions at this time. I'd like to turn the call back to Joe Mills for closing remarks.

Joseph A. Mills

Well, thank you. Well, first off, thank you for participating in today's call. I think second, I hope you can tell we're very pleased with the fourth quarter results. I think it's important, to Jeff's very good commentary right there at the end, absent the shutdown at BEC, which impacted our adjusted EBITDA by almost $6 million, we would have reported a record quarter of almost $72 million. So we feel very good, very excited about 2013. We're very pleased. The Midstream Business is definitely has a lot of momentum behind it. We think our Upstream business with SCOOP has a lot of momentum behind. So we're looking forward to a very active 2013. So with that, I appreciate everybody's time and attention, and we look forward to talking to you here very soon. Thank you.

Operator

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may all disconnect. Everyone, have a great day.

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