Eagle Rock Energy Partners, L.P. (NASDAQ:EROC)
Q2 2014 Earnings Conference Call
July 31, 2014 02:00 PM ET
Chad Knips - Director of Corporate Finance and IR
Joe Mills - Chairman and CEO
Bob Haines – CFO
Joe Schimelpfening - SVP, Upstream Business
Shneur Gershuni - UBS
John Ragozzino - RBC Capital Markets
Praneeth Satish - Wells Fargo
Eric Anderson - Hartford Financial
Good day, ladies and gentlemen, and welcome to the Eagle Rock Energy Partners Second Quarter 2014 Earnings Conference Call. At this time all participants are in a listen-only mode (Operator Instructions) As a reminder, this call is being recorded. I would now like to turn the call over to Mr. Chad Knips, Director of Corporate Finance and Investor Relations.
Sir, the floor is yours.
Thank you, Nicholas, and thank you to our unit holders, analysts and other interested parties for joining us today on Eagle Rock Energy's second quarter 2014 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. And 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 our partnership's SEC filings, including in our 2013 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. You may also access both the second quarter 2014 earnings press release and a transcript of 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, estimates of maintenance CapEx, 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. Presenters on this earnings call may use the non-GAAP financial measures of adjusted EBITDA and distributable cash flow. You may find a reconciliation of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with accounting principles generally accepted in United States or GAAP on our website at Press Releases at www.eaglerockenergy.com.
I will now turn the call over to Joe Mills, our Chairman and CEO, for a review of the quarter.
Great, thank you Chad. Good afternoon ladies and gentlemen and thank you for joining us for our second quarter 2014 earnings call. The second quarter is a very busy quarter for us, in marking the culmination of our contribution of our Midstream business to Regency Energy Partners for a total consideration of $1.34 billion.
As we previously discussed we signed the contribution agreement to contribute our Midstream business Regency on December 23, 2013 and obtained our unit holder approval to close the transaction on April 29 of this year. Unfortunately, the Federal Trade Commission shows the Eagle Rock and Regency a second request for additional information and documents pursuant to their regulatory review of the contribution under the Hart-Scott-Rodino Antitrust Improvement Act of 1976.
The second request was received on February 27, of this year and after months of providing the government mountains of information on June 27, the FTC notified us of their vote to close our investigation of the contribution. Because the FTC closed our investigation in its entirety, no concessions, divestitures or additional remedies were necessary to obtain clearance to close. Eagle Rock and Regency moved very quickly thereafter and on June 30, we successfully closed the contribution transaction. Total consideration of the transaction was $1.34 billion made up as follows.
We received $576.2 million of cash plus we received 8,245,859 Regency common units which were valued at approximately $265 million based on the closing price of Regency common unit on June 30. In addition to the exchange of $498.9 million base amount of newly issued Regency notes for $498.9 million base amount of Eagle Rock existing 8 and 3/8 senior notes which are due in June 2019.
Following the bond exchange, there remains $51.1 million of Eagle Rock senior notes still outstanding and after obtaining a sufficient number of consent as part of the exchange offer, we have eliminated substantially all of the restricted covenants and certain events of default under the indenture that governs those notes. I want to thank the many current and former Eagle Rock employees who worked tirelessly over the past seven months to close this important and transformative transaction.
I would also like to thank and congratulate the Regency management and employees who also worked very hard and co-operated with us in achieving this very favorable outcome for both companies. We are confident Regency will be able to integrate and maximize the potential of the Eagle Rock Midstream assets and our former employees into their business plan.
Because all significant closing conditions to the contribution, transaction were completed during the second quarter, we are required to treat the Midstream business as assets and liabilities held for sale and discontinued operations and cannot include the associated revenue or expenses in our reported earnings for the second quarter.
Although we received the benefit of those revenues and paid the expenses, we must classify them as discontinued operations which caused us to have a messy financial quarter. For the second quarter, we reported adjusted EBITDA of approximately $25 million, if we would have been able to include Midstream results; we would have recorded adjusted EBITDA of approximately $51 million. Bob Haines, our CFO will go through the details of our financial results in a few minutes.
With the closing of this contribution transaction, Eagle Rock is now a pure play upstream MLP and we are excited about our future. Our current balance sheet and liquidity position is strong and positions us to commence growing as a pure play upstream MLP. Pro forma for the closing of the Midstream transaction, Eagle Rock now has approximately $370 million of liquidity in the form of a $120 million of availability under our credit facility and approximately $250 million of Regency units that have no lock-ups and are expected to be registered for resale pursuant to the S3 that Regency filed on July 22 with the Securities and Exchange commission which has not yet been declared effective.
We expect the Regency units to provide liquidity for our acquisition growth strategy down the road. Because a portion of the contribution consideration was in Regency units, we have deferred a portion of the tax gain from the Midstream business contribution. Any sale of the Regency unit will accelerate the tax deferred gain. We will carefully analyze the impact this may have on our unit holders as part of our consideration of potential sales of Regency units in particular in calendar year 2014.
Today, our leverage ratio is a very healthy 2.15 times, down from the 5.7 times prior to closing of the contribution transaction. We do not expect to have to issue any equity in the near-term to fund our acquisitions.
Depending on our acquisition activity, we will evaluate accessing the high yield markets later this year in order to manage our capital structure and provide additional liquidity for our growth strategy. In a few minutes, I will discuss in more detail our go forward view and our plans. Turning to our operational performance during the second quarter, our upstream production averaged 71 million cubic feet equivalent per day which was essentially flat to the first quarter of this year. We maintained two operated rigs during the quarter and brought online three operated wells. Negatively impacting our volumes during the quarter with third party pipeline curtailments in our Permian and Mid-Continent operations, from completion delays in two of our Alabama well and less than expected production from the few Golden Trend wells that we drilled earlier this year.
Beginning with our SCOOP horizontal Woodford play, we completed two operated wells, the McLemore 1-20H and Maddox 1-17H both located in Grady County, Oklahoma. The Maddox well had a gross production rate in the first 30 days of 575 barrels oil per day and over 2 million cubic feet per day with Eagle Rock owning a 52% working interest and the McLemore well had a gross production rate in the first 30 days of over 315 barrels of oil per day and 2.1 million cubic feet per day with Eagle Rock owning about a 42% working interest.
We are pleased with the economic performance of both these wells as initial oil production rates have exceeded our expectations although the initial gas production rates are less than the area offsets. We are currently drilling our fifth operated SCOOP well, the Linton 1-532XH well in Grady County, Oklahoma with a 43% working interest.
This deeper test of the Woodford formation will be an extended reach lateral of approximately 8,800 feet with a total growth completed well cost of approximately $15 million. In addition to maintaining one operated rig, we continue to participate with Continental resources and new field exploration in wells where they operate and we have a non-operated position.
We are currently participating in four new field operated extended reach later wells which are all located in Garvin County, Oklahoma with a 36% working interest. All four of these wells in the same field development program have been drilled with three of these wells fracked already to-date and fourth well is currently being fracked.
New field has done a great job drilling these four wells within pre-drill expectations of approximately $14 million per well. The wells are expected to be brought online late in third quarter. These wells are very important to our expected production growth during the second half of this year with their initial production rates expected to contribute 400 to 500 barrels equivalent per day per well net to our interest.
Our total net investment in these four well program will be approximately $21 million of which $12.5 million has already been spent during the first half of 2014. With these important wells online in addition to other Eagle Rock operated wells coming online, we expect to average between 73 million to 78 million cubic feet equivalent per day during the second half of 2014.
Our production growth is back ended -- backend loaded to the second half of 2014 and we expect a 3% to 8% volume growth as compared to our first half of 2014 volume rate.
In our Golden Trend field of Oklahoma we continue to operate one rig drilling for the Bromide sands, which is an all varying formation. During the second quarter we drilled three wells and brought online a Scott 3-17 in which we have a 100% working interest, it has met our pre-drill expectation averaging over 254 barrels of oil per day and over 429 Mcf per day during its first 30 days of production.
Since the second quarter was completed we brought online the Stir family 2-15 well with a 98% working interest which is averaged over 550 barrels of oil per day and 1.1 million cubic feet per day in its first three weeks to sales. We have been generally encouraged by Oklahoma-Bromide program drilling results in the Northwestern portion of our Golden Trend Field. However, we have seen production results that can have a high degree of variability in the trend.
Our 3D seismic survey assists us in reducing the risk of faulting out respective sections of the Bromide sands but it does not resolve the reservoir porosity and permeability characteristics. The Bromide’s porosity and permeability along with sand thickness, ultimately drives well performance. We continue to high grade our drilling locations in this important area to further drive and improve our drilling program results.
Turning to Midstream very quickly, our Midstream operations did perform well during the quarter. Volumes were close to flat quarter-over-quarter in both Panhandle and East Texas were normalized with prior period adjustments and non-recurring effects removed. Both the Panhandle and East Texas EBITDA contributions were better than first quarter but overall Midstream was down quarter-over-quarter due to the significant contribution our gas marketing and trading business made in the first quarter during the extreme cold weather periods of market volatility.
Since we have to report the Midstream business as discontinued operations, we will not provide any further detail or guidance on the call today regarding that business.
Now, I’ll turn the call over to Mr. Bob Haines for further discussion of our financial results during the quarter.
Thank you, Joe. Effective June 27, 2014 Midstream business was reclassified as assets and liabilities, out for sale and discontinued operations. We reported on a consolidated basis, adjusted EBITDA of 24.9 million for the second quarter which was down by 1.2 million or 5% over the first quarter.
Our reported DCF for the quarter is 3.9 million. Our Board of Directors has elected not to make a distribution this quarter. Realized natural gas prices were down 12% as they have stabilized since first quarter price spikes caused by the winter weather and limited volumes in storage.
Realized NGL prices were also down 16% with higher realized crude and sulfur prices partially offsetting the other lower commodity prices, these differences quarter-over-quarter lower revenues 2.4 million.
Second quarter daily production of 71.2 million Mcfe per day. Production rates were 1 million Mcfe per day lower compared to first quarter due to timing of well completion and third party pipeline curtailments in our Permian and Midcontinent operations.
Third party curtailments impacted revenue approximately $500,000. Overall, second quarter leased operating expenses including severance packages were 14.5 million, 700,000 less than first quarter due to slightly lower work-over and planned operating expenses. G&A expenses were $12 million for the second quarter a decrease of $1.3 million compared to first quarter while this is an improvement only specific identifiable miles of G&A expenses were allocated discontinued operations.
Expenses related to both internal and external shared services cannot be allocated discontinued operations, that we have been able to allocate these expenses we would have realized that higher adjusted EBITDA for the second quarter. Over the next six months, we anticipate the approximate quarterly run rate fall significantly as our upstream business model takes form. This continued G&A improvement will positively impact adjusted EBITDA over the next several quarters.
We recorded a $2.2 million realized hedge loss in the second quarter compared to 3.1 billion realized hedge loss in the first quarter. We have not added any hedges in the recent months but now that the Regency transaction has closed, we are focused on increasing our hedge portfolio and seeking opportunities into some of our near proxy hedges into direct product hedges.
With the sale over Midstream business, we expect our hedge counter parties to agree to hedge for longer periods of time based on our proved reserves. We expect the tenor of any new hedges will allow us to go out as far as four to six years.
Our latest hedging presentation is available on our website which now reflects only the hedges remaining for Upstream business and all the hedges associated with the Midstream business have been removed since they were novated to Regency but canceled as part of the Midstream contribution.
Turning to our liquidity picture, we amended our revolving credit facility in May, which provided us with covenant relief a borrowing base of 819 million of which the Upstream component was 330 million. We ended the quarter with total borrowings of approximately 1.3 billion comprised of our senior unsecured notes and borrowings under our revolving credit facility. As of June 30, our liquidity was approximately 46 million and we have 769 million outstanding on our revolver. On July 1, after the closing of the Regency transaction, we paid down our credit facility to 198 million, providing approximately 132 million of liquidity. Our next borrowing base redetermination with our lender group will occur on September 1, 2014 pursuant to our amended credit facility.
With that I will turn the call back to Joe.
Thank you, Bob, appreciate that. Okay, so as we discussed earlier, we are now focused on a feature as a pure play upstream MLP. With our ample liquidity and low leverage ratio, we believe we have sufficient financial horsepower to make accretive acquisitions in the next six months. We intend to recommend to our Board of Directors the reinstatement of a distribution to our unit holders for the third quarter of 2014 which will be payable in November of this year, all subject to our Board’s approval and the operating performance of our underlying business.
The upstream M&A markets have been very active over the past six months. We are currently evaluating multiple opportunities and have every intention of making an accretive acquisition this year that will bolster our distributable cash flow. We are focused on making acquisitions of long-life, shallow decline conventional assets with a bias toward natural gas. Our current decline rate averages 22% annually. We intend to meaningfully reduce our decline over the near-term to achieve a stable production profile which will enhance our ability to generate sustainable and growing distributable cash flows.
Our current assets can deliver growing production and cash flow by continuing the pace of our drilling program at SCOOP will only extend our speed decline. Our plans are to acquire several low decline accretive acquisitions and look to slow the development of or divest portions of our SCOOP assets which will help arrest our decline rate and reduce our overall CapEx spend rate. While we are pleased with the overall drilling results at SCOOP, we also realized that these assets are not a perfect fit for smaller upstream MPL and we continue to look at opportunities to maximize the potential of these important assets.
We are considering opportunities to bring in a financial JV partner to the area or possibly trade or outright monetize our position to enable us to acquire assets that would fit better in our portfolio. With the continued success rate at SCOOP, we do expect to get a higher realization from these assets. Given the positive drilling activity and successful results by us and our competitors in the SCOOP play, we remain open to opportunities to monetize or trade these assets in the near future. With the Midstream contribution complete, we are winding down the final affairs of the Midstream business including some final departures of personnel associated with our Midstream business that were not hired by Regency.
As the dust settles over the next six months, we expect our quarterly G&A rate expenses to decrease to an approximate run rate of between $8.2 million to $8.7 million per quarter.
During the second half of 2014, we planned to spend approximately $57 million on capital expenditures with 27 million of it to be categorized as maintenance capital and 30 million to be categorized as growth capital. For comparison, we spend a total of $77 million in the first six months of 2014 with 29 million of it categorized as maintenance, CapEx and 48 million is growth.
In 2015 and beyond, we expect our maintenance CapEx to average between 55 million and 60 million per year and our growth capital to average between 35 million to 45 million per year to grow our reserves, production and distributable cash flow.
These CapEx figures do not include any capital for acquisitions. We anticipate acquiring between $300 million to $400 million per year of appropriate MLP assets that will fit our acquisition strategy and capital structure. We plan on being opportunistic in the acquisition arena but we will focus on acquisitions that fit our strategic plan and fit the MLP model.
I want to thank the lender group led by Wells Fargo for working with us over the past six months and facilitating the contribution of our Midstream business to Regency.
I also want to again thank the former and current Eagle Rock employees who have really worked hard to bring to a successful conclusion the Regency transaction and transform us into pure play upstream MLP.
We are very excited about the future and with that we will now open the call for questions.
(Operator Instructions). And our first question comes from the line of Shneur Gershuni with UBS. Your line is now open. Please proceed with your question.
Shneur Gershuni - UBS
First question, throughout the reporting season that we've heard so far from some of the E&P companies and so forth, definitely been a lot of excitement in SCOOP and STACK plays and so forth. I was wondering if you can sort of talk about your opportunity and if you can now talk about in a context of, we have seen some other upstream MLPs sort of take high decline rates but IRR opportunities and look to swap them for assets that have much lower decline rate and more predictable cash flows and is that sort of a process that you may be considering kind of as you go forward?
Yes, as I said in my prepared remarks, we really have been very happy with the results executed, there is no doubt that our result as well as those of our competitors in the immediate area and certainly led by continental new field, that we're very excited about what we are seeing. So, from a results standpoint and an IRR standpoint these are exceptional assets and we have a sufficient drilling inventory to keep one rig running for the next several years in this exciting play.
It’s a complicated play and that there is a lot of structure here, there is a shallow oil play going on around our Global Trend acreage and a little bit north and then as you move south it gets deeper but a little bit gas here and certainly more NGL rich. You’ll hear some of our competitors talk about the condensate window and some of the results there and by the way that is where our the Briar wells that we are participating with new fields is down in that deeper gas condensate window that I alluded to earlier that should be coming on here in the third quarter.
So while the results have been good we also recognized, I mean it is a smaller, today, smaller Upstream MLP, the capital requirements here are pretty extraordinary. So first off, the shallower wells cost anywhere between $8 million $10 million to drill each not for a single lateral i.e. just one section all of the 5,000 foot lateral. A lot of our competitors are now moving to these extended laterals and in fact our Linton well that we just spud is an extended lateral well and it is going to be about 8800 foot lateral.
These wells are begin to deeper, covering few sections, but they are going to be in the call it $13 million to $15 million range depending on the depths, but the results looks very good and quite frankly from a type curve they appear to have more stable decline versus the single laterals obviously you have a lot more extended age, a lot more of the formation exposed to the well bore.
So, for us, while we like the results $10 million to $15 million wells, where we’ve got anywhere from a third up to 50 to 60% working interest is pretty aggressive capital requirement in our structure. The other challenge that we are seeing out here and again this is very similar to what we are seeing in a lot of these shale plays, is the development is moving to not only the extended laterals but drilling all the wells in the section at the same time. So, in that sense, we are seeing per section anywhere from four to seven wells per section is what is going to be required to develop this area.
Many of our competitors are moving in two rigs at a time per section and drilling all four to seven wells simultaneously, which means that you are tying up a lot of capital four to six months before you start seeing first production and then they frac them all at once and bring them online. That's in fact what’s happening to us with the Briar wells, Newfield and Eagle Rock spud those wells back in February and we won't see first production until sometime in the mid to late third quarter.
So it’s that kind of program that's challenging for us to devote that kind of capital long term and really be able to keep up with our competitors while we like what we see and we certainly have been able to keep up with our competitors longer term this maybe a better fit for SECOR with either a bigger balance sheet or with more exploration type capital they can deploy here.
So, you are right, we see some of our competitors trade assets, these high quality shale type assets for more appropriate MLP assets and we certainly are looking to maybe do something similar to that, those are always challenging to do trade as we all know that thing is impossible, we’ve seen others do it but that's something that we would certainly consider for the right asset that could fit into our structure.
So, I do think you will see us -- for now we are happy to continue to develop our assets but if the right opportunity comes along for us to either divest or bring in a partner or trade the asset we would certainly look to do that.
Shneur Gershuni - UBS
Okay, two follow up questions one directly to this one. There has been a lot of asset packages that have pooled recently, are data rooms still very active? I realize you’ve been tied up with the whole Midstream proposal and not able to necessarily participate but is this isn’t come and gone or are there a lot of data rooms available and you're looking at that ready?
No. So, we no doubt we’ve seen a lot of really quality MLP assets come on the market in the past six months and thank you for that. I too agree, we have been pretty focused on the Midstream sale obviously our balance sheet was in a position that we could be an active participant in some of the processes until we got through the Midstream contribution transaction.
But with all that behind us we are seeing a lot of quality MLP friendly assets on the market, we are active currently in several processes both data room as well as one on one discussions with a number of companies that’s why I said earlier I feel pretty confident saying, I mean certainly our intent is to make an accretive acquisition sometime this year that will be meaningful to our partnership and bolster our distributable cash flows.
So, we do think as the industry has positioned there, you see a lot of the larger companies streamlining their portfolio of assets and so they are divesting of what is non-core to them. The good news is that’s the kind of quality assets that we are looking for. So, I think you will see, we are excited about the M&A market, so I am going to tell you that the M&A market isn’t active or that there is a lot of competition, there is. So, there is no doubt that we will have to be smart and aggressive in making a successful acquisition.
A number of our peers have made some pretty big deals of late that we would like to think that that will keep them occupied for a while. Given our much stronger balance sheet, our ability to be both competitive and aggressive, we think will give us hopefully an edge in making some successful acquisitions.
Shneur Gershuni - UBS
Okay, one last final question if I may. The distribution, according to the press releases you said that you would like to resume the distribution in November. I was wondering if you can give some color on what resume means. Is it resume at the previous level, so if you can’t comment on the specific number, if you can sort of talk about how you are thinking about DCF coverage is going to be higher now because you are a little bit more commodity sensitive than you were before. Just sort of any color on how we can read the tea leaves in sort of establishing our forecast going forward?
Well, no doubt that I would love to give you a number but unfortunately I am not in the position to do that today. Clearly, the Board and I are spending a lot of time looking at our business; some of the results that we expect here in the near-term in helping establish that distribution for the third quarter. I can tell you this, whatever distribution we established clearly needs to be sustainable. We have been through a tough period of time here when we had to not only reduce our distribution and eventually suspend it, none of that has been fun and certainly everybody around this table is equally incentivized to get that distribution reinstated as well as get it to as high a level as possible.
But I do think whatever distribution is established, it’s got to be sustainable, number one. Number two is, we do want to maintain an appropriate coverage ratio. We have seen -- I mean certainly we were victims of it, we have seen others where coverage has gotten pretty thin and in a lot of cases companies are below one-time coverage and we really don’t want to find ourselves in that situation again. Given that we are much more commodity sensitive today than we have been historically, we do think whatever distribution is established needs to be sustainable, needs to have an appropriate coverage level call it 1.1 to 1.2 times coverage that allows us then to really weather the price volatility in our business. So, that’s probably about the best I can say at this point but hopefully that gives you a little bit of color.
Our next question comes from the line of John Ragozzino with RBC Capital Markets. Your line is now open. Please proceed with your question.
John Ragozzino - RBC Capital Markets
Bob, this one is for you, can you give us a little more elaboration on the key drivers of the significant reduction in G&A that you look going forward and maybe give us a bit of a color on the timing that you expect for the realization of these cost savings?
Right now with the discontinued operations they have to be specific in identifiable cost related the discontinued operation. We have a lot of, this quarter we had employees with shared services that we were not able to allocate to that who have since left the business. We also have cost like auditing, insurance and other outside services that we cannot allocate anything to the discontinued operation, so you will see a stair step decrease to the G&A over the next couple of quarters.
And John, I might be able to -- I might just elaborate a little bit more on that and Bob is exactly right. This was obviously a messy quarter, a lot of - to the discontinued operations. There is G&A that we would have liked to and felt like we could allocate to the discontinued operations but under GAAP we're really not allowed to.
So, a little bit a messy quarter from a G&A standpoint and adjusted EBITDA. I will say though that from a personnel standpoint and I am proud of this, Regency hired a very large number of our Midstream employees which we were glad to see but we were probably close to 600 employees prior to the Midstream contribution and today we are about 175. So, we had a very meaningful reduction in our employee count both G&A as well as OpEx.
And Bob is exactly right, when you go forward things like insurance, our plant and property insurance is coming down obviously substantially with the sale of the Midstream business, allocation of rents for our office space here. So, things like that are going to help us reduce our G&A. We still have a few Midstream people still on the payroll as they assist us in the wind down of the business. You can imagine it was a large complicated transaction, so I think this quarter, third quarter there will be a little bit of additional G&A associated with the Midstream wind down. Obviously some of the expenses associated with the transaction are still flowing through our income statement. So, I think as we approach 2015 you will see us achieve that call it $8.2 million to $8.5 million run rate I think that’s kind of where we’ll end up probably early ’15.
John Ragozzino - RBC Capital Markets
With respect to the Regency units, you mentioned that there was no current restrictions in place in terms of potential liquidation and that you were looking into the potential tax implications. Do you have a specific time frame in mind when you will likely have that completely liquidated and access that wealth of additional capital?
I don’t have any clear timeline. So, as we talked about on earlier calls when we first announced the deal, clearly there is a - by taking back units in the contribution we were able to defer some of the taxable gain to our unit holders. We believe Regency’s got a great business plan; obviously they will [calling up] [ph] a nice distribution that we will be taking as a part of those common units. I think the right answer is obviously they’re not effective right now, we have no lockups but the S 3 is not effective so they are really tradable today but they could be - or they will be down the road.
I would say certainly over the course of the next couple of years and that’s we’ve said before we would look to monetize those assets and that’s all a function of our acquisition strategy and how we manage our capital structure going forward. We clearly -- while we have room to grow our debt capacity given our leverage, we don’t ever want to get back to where we were so we are going to be pretty judicious around our capital structure going forward.
So, I think short answer is especially with the tax deferred gain, we want to be very careful about how we monetize those and over what time period to mitigate that tax impact to our unit holders.
John Ragozzino - RBC Capital Markets
Okay, and during the prepared remarks you also mentioned some negative impact to production volumes driven by infrastructure related constraints and third party issues. Can you quantify that for us?
Yes, it was about 1 million cubic feet a day during the quarter between really two separate events, one in the Permian and one in our Mid-con operations that unfortunately both were unscheduled turnarounds of third party Midstream plants and that unfortunately affected us to the tune of about a million cubic feet a day.
John Ragozzino - RBC Capital Markets
Okay, just one more for me and I'll hop back in the queue. With respect to the extended lateral test, the four well program, can you give us the basic type curve profile? Specifically gross IPs, first year declines, EURs. I think you mentioned the $15 million D&C and possibly a three stream product split. If you can hit all that in one mouthful?
Absolutely, I’m going to let Joe Schimelpfening, who runs our Upstream Business discuss that.
So, the deep extended laterals like the ones that Joe mentioned that are just being fracked or just fracked, and last one is being fracked now, we are looking at total reserves in the neighborhood of that 2.3 million barrels equivalent. That's on an unprocessed basis, processed basis is more like 2.8 million barrels equivalent is what we're using with our type curve the initial rate again this is in the deeper part of the play that is significantly more gassy than what we have up and around our Golden Trend area. So initial rates are approximately 7 million a day gross, about 700 barrels a day oil, and the type curves, of course are hyperbolic decline [inaudible] factors that in the 1 to 1.5 range and initial decline rates in the 88 to high 90s depending on the area. So, drill cost I think Joe mentioned are just shy of about $14 million completed per well.
Thank you. Our next question comes from the line of Praneeth Satish with Wells Fargo, your line is now open, please proceed with your question.
Praneeth Satish - Wells Fargo
Most of my questions were answered, but I guess just two more quick ones for me. In terms of acquisitions that you're looking at over the course of the year, I mean are you looking to do one large deal or maybe a series of smaller packages? I guess what's the size of the deals that you're looking at currently?
Yes, thank you Praneeth, it’s a great question. Well, I would tell you that it’s just as much work to do one big deal as it does one little deal. So, clearly we prefer to do something that is in impactful, that helps not only most of our DCF but really gets us more some more real estate to work with in terms of in field development and growth opportunities.
You really – you can’t pick those out every time. Obviously the bigger the deal the more competition it draws. That’s kind of the nice thing is that we can for us today doing a $100 million deal will move the needle where it's for a lot of our competitors they are not even looking at that or it tends to be too small for them. And we think that’s actually a positive for us.
So I also -- if all else equal, I'd love to do several smaller deals just so that you have the diversification of the assets rather than concentration of one big deal but obviously depending on the big deal and where the assets are located that in of itself could be diversified.
I would tell you that today we are looking at several that kind of fall in the middle, so we have a few that are larger and we have a couple that are smaller that we are looking at and we think all of them combined, could make for a great, really first six months out of the gate for Eagle Rock and really move the -- both our DCF as well as our production rate and very importantly start to mitigate our decline. I talked about that in the prepared text. We are very focused on that, any acquisitions we make clearly have to have the right criteria. We are looking for long-life shallow decline type decline assets to help really flatten or reduce our current decline rate and that is going to be an important objective for us in the next call it 12 months.
Praneeth Satish - Wells Fargo
And where do you think the leverage ratio could go to later this year after you complete your acquisition strategy, I guess where are you comfortable taking it?
Yes, that’s a great question. So, long-term, we'd like to try and manage our business to be, call it in the 3.5 times leverage ratio long term. I would tell you that I think in the near-term, we will very carefully stair step up to that level even with acquisitions. I mentioned earlier that we would look to the high yield markets, at reaccessing those markets sometime middle to later this year depending on our acquisition activity.
Obviously we have the ability at the right time to monetize some of the Regency unit, so that again will help our financing and our ability to make accretive acquisitions.
So, we clearly are going to manage our capital structure very carefully, I think long-term 3.5 times is really a comfort zone for us. Again we have seen a lot of our competitors and we were there too, pushing that 4 to 4.5 times or even higher. We don’t want to find ourselves there again.
Our next question comes from the line of (Aria Cole with Cole Capital) [ph]. Your line is now open. Please proceed with your question.
Question number one, as I am sure you know the Regency Energy Partners currently is paying you a 6.5% annual dividend. When you look at that income that you are earning, to what degree does that act as a minimal hurdle rate, the sort of returns you are looking to get from any acquisition and the reason I asked that is maybe you can correct me, you are welcome to correct me. But theoretically, the income you are earnings from Regency in the future, you could potentially flow through to the MLP holders of Eagle Rock, I am presuming best case that you would want to make acquisitions that hopefully would enhance the yield you are currently earning on that -- from that security?
Yes, so let me see if I can answer may be there are two parts to that question, so first off, may be the easier one to answer is, so the distribution that we received from Regency, depending on -- and the accounting rules are a little bit more complicated here but we certainly intend to treat that as adjusted EBITDA. Having said that, we actually have to look at what their net income is and make sure that it is not a return of capital because if it is then we cannot treat it as adjusted EBITDA at least that portion that is associated with the return of capital.
So, maybe more simply said as long as Regency is maintaining a solid coverage and generating positive income then all that can be treated as adjusted EBITDA for our purposes. Now I can tell you that we clearly could count every penny as distributable cash flow, so for purposes of our unit holders what we will count is DCF. We can count anything that we receive from Regency as distributable cash flow, so clearly it will go to boost our distributions as well.
It’s just how we treat it as adjusted EBITDA, there is a little bit more complexity than just sales. And right now we would expect to get -- I saw where they declared their dividend or distribution here the other day. We probably would get in the order of $15 million to $16 million a year of revenue/adjusted EBITDA from them via their distribution prior to any sale.
Now as for what does it for our acquisitions, unfortunately of course the upstream MLP space is competitive and obviously there is lot of MLPs as well as private equity money chasing deals, I think to say in fairness to, for us to be able to buy something with a better yield, we think it will be a better yield but it will be at 6.5% that’s aggressive. What we do think though is given the multiple, because once we reinstated distribution and clearly you look at the upstream MLP space and we all trade in the, call it, 8% to 10% yield range, clearly any acquisition that we make will be accretive to our cash flows. And so therefore, we expect that it will, on the multiple basis and on accretion basis, be more than offset than what we are giving up on the Regency distribution, I think that’s probably the best way to say it.
Okay, and then regarding the Golden Triangle assets that you may decide to dispose of in the future. In the M&A space, if you are looking at what are the valuation multiples that people are primarily doing, looking at [inaudible] this property? Production per barrel, NAV, etc. I'm trying to get a sense of if you’d be comfortable [inaudible] based on just regular reference metrics, what sort of value that asset would be worth to another buyer.
I think I follow your question. So, in the upstream space -- so in the midstream space I will start with that, you see valuations anywhere from nine times to 15 times so some pretty aggressive valuations around midstream assets. In the upstream space what we see is anywhere between five and seven times the trailing cash flows as what assets are selling for, clearly the longer life shallow decline oily type assets tend to get a little bit more of a premium call it a 6.5 to 7.5 times multiple whereas gassier assets tends to be trading little bit lower multiple mainly because of the near term cash flows given where commodity prices are.
The dollar per flowing barrel or dollar per flowing Mcfe that’s a tough one to answer because a lot of has to do with where is that asset located; clearly the Permian, and I’ve talked about this on other calls, areas that we like and that we’re certainly focused on, we like the Mid-continent a lot, clearly we have a strong asset base there that’s any acquisitions could be very complementary too. We like East Texas a lot, we like Southern Alabama, which are clearly in our core areas. We love the Permian but so does everybody else and so to that point the valuations in the Permian are extremely rich right now. So, I don’t think you will see us actively in the Permian just because the competitive arena there is so expensive, very difficult, you can make accretive deals it’s just less accretive. So, I think you’ll see us stay away from the Permian, focus more in the Mid-Continent, East Texas, South Alabama; we are looking at the Rockies, we see some excellent opportunities up there that could be oilier and so you may see us enter the Rockies at some point in the near term.
Thank you, our next question comes from the line of Eric Anderson with Hartford Financial. Your line is now open, please proceed with your question.
Eric Anderson - Hartford Financial
Thanks. Joe, as a point of clarification, do you have a preference in terms of where you're looking in terms of types of assets, dry gas, NGLs, black oil? Do you have a preference or you'll basically look at anything as long as it's accretive?
Well, we do look at anything and everything that’s accretive but I would tell you that we see more upside in natural gas and NGL type assets than we do oily assets, I mean clearly with oil prices at $100 the probability that oil will go from 100 to 120 is probably a lot less than the probability that gas could go from $4 to $5 over a defined period of time.
So, we are more focused on the gassy side, the gassy and NGL rich, we think certainly natural gas is appropriately priced today but with hopefully some upside; NGL is clearly -- and we’ve talked about this before on other calls obviously we have a large NGL base, even in our upstream business we had an enormous one to our Midstream but we've seen ethane and propane and all the butanes get beat down pretty hard over the past couple of years.
So, we do think as new crackers come on in ’16 and ’17 that there is probably more upside in the NGL barrel than there is in the oil barrel. So, yes I would say today we tend to be looking more at the gas/NGL rich reservoirs than just the outright black oil, black oil is just is very expensive. We are concerned about condensate prices in particular so that’s the other thing we monitor clearly with so much new production coming on across the country whether it be the Eagle Ford or the Niobrara or even our SCOOP play, that’s all condensate rich, it’s not really black oil it’s all condensate. So, we as an industry are flooding the market with a lot of this light end of the barrel.
We are hopeful to see more of these exports get approved only time will tell that should help the condensate barrel. So again natural gas is something that we like we think longer term; our ability to hedge it directly is very important and so I think you will see a few more gassy type deals in the near term.
Eric Anderson - Hartford Financial
Okay, and just a little bit of a clarification on the Briar wells. Does that arrangement that you've got with Newfield a little unusual in that you're participating with four wells, and I think the percentage interest is fairly meaningful? So is that a result of really contributing acreage or what's sort of the background there in terms of how that deal came to be?
Well first off it is not unusual at all. Clearly we have a very strong acreage position in and around this play, as you may be aware in Oklahoma or any play obviously interest are pooled together so obviously Newfield had some acreage, we had some acreage, we combined it in order to jointly drill these wells and so we ended up with a 36% interest in these two sections that they of course are operating with the majority interest but that is not uncommon and you’ll see that quite a bit; we do that with Continental and others, quite frankly in the Linton well that we’re drilling right now that we are operating is the same answer. We have a number of industry partners that have acreage in the area and they are participating with us as a non-operator. So, no, it’s a very common practice, certainly in Oklahoma with the forced pooling law that adds a little bit of nuance to it and certainly the forced pooling law, well just as it describes, it forces the pooling of interest and it really causes activity to occur. People can’t be passive and just sit on the sidelines during a forced pooling event. It requires you to do something. And so certainly that’s prompting us to continue to maintain our activity level and of course we use the forced pooling law to our advantage as well where we are the operator.
Eric Anderson - Hartford Financial
So, you are looking now to meaningful impacts when these wells start coming on with that type of a percentage interest?
Absolutely, like I said earlier I mean based on our view and offset results around the Briar wells, we believe that each of these wells will contribute 400 to 500 barrels oil equivalent per day per well net to our interest. So, simple math is we could have 1,600 to 2,000 barrels of oil equivalent per day coming online here. We make about 12,000 barrels a day and we will be bringing on 2,000 barrels a day, so you can do the math, it’s pretty impactful. Now, granted these all have pretty steep declines, these are our shale plays, so those are initial potential rates that I am quoting kind of first 30 day type potential rates. But Joe described the type curve earlier for these type of wells but they are going to have a meaningful impact to our bottom line in the second half of the year.
Thank you. And I am not showing any further questions in the queue. I would like to turn the call back over to management for any closing remarks.
Thank you, Nicholas. So, ladies and gentlemen, again I want to thank you for participating. We are excited. I don’t think you heard us talk about the Midstream business ever again. Going forward we are a pure play Upstream MLP today. Looking forward to acquisitions and starting to grow our platform again. So, I do want to thank you for both your time as well as your continued interest in Eagle Rock, and I do want to say a special thank you to all the Eagle Rock employees that are listening in, in particular the former Eagle Rock employees. Again, I want to thank you for all of your hard work over the past six months and helping us achieve successful transformation of our partnership.
So, with that thank you ladies and gentlemen and hope everybody has a good afternoon.
Ladies and gentlemen, thank you for participating in today’s conference. This does conclude the program and you may all disconnect. Have a good day everyone.
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