EV Energy Partners, L.P. (NASDAQ:EVEP)
Q3 2013 Earnings Call
November 12, 2013, 11:00 AM ET
John Walker - Executive Chairman of the Board
Mark Houser - President, Chief Executive Officer and Director
Michael Mercer - Chief Financial Officer and Senior Vice President
Kevin Smith - Raymond James
John Ragozzino - RBC Capital Markets
Ethan Bellamy - Baird
Welcome to EV Energy Partners' third quarter 2013 earnings conference call on Tuesday, November 12, 2013. (Operator Instructions) This morning, EV Energy Partners' issued a press release announcing quarterly results. That release along with additional financial and operational information and reconciliations for non-GAAP financial measures is available on EVEP's website at www.evenergypartners.com.
Please refer to the forward-looking statements in the earnings press release, which state that statements made during this call that refer to management expectations and our future predictions are forward-looking statements intended to be covered by the Safe Harbor provision of the Securities Act, as there are many factors which could cause results that different from management's expectation.
I will now hand the call over to John Walker, Executive Chairman; Mark Houser, President and CEO; and Mike Mercer, Senior VP and CFO. Please go ahead.
Thank you, Ron, and good morning, everyone. We had another good quarter, in which base operations were in line with expectations. In October, we closed our first Utica acreage sale and we continue to work on Utica sales effort as well as the volatile oil window joint ventures. We will announce further sales as purchasing sales are signed.
Also recently, we closed on our previously announced Barnett acquisition. The midstream Utica East Ohio asset build-out continues to move forward, and finally we enhanced our liquidity through a successful equity offering in October. And relevant to that last statement, I'd like to start off by talking about the equity offering that we closed on October 23.
We sold 5,750,000 units for total net proceeds of $208 million. As many of you know, we are investing in the Utica East Ohio in Cardinal Gas Services midstream facilities, which have been funded with bank debt. We expected to offset the leverage by purchasing improved producing assets with Utica acreage sales proceeds, but the process has taken longer than anticipated.
Therefore, we believe it was prudent to reduce our leverage by paying down some of our outstanding borrowings under the credit facility with the equity offering. This has not changed our sales process or goal or intent to sell all our majority of all of our acreage position in the Utica Shale.
As infrastructure continues to be developed, we believe the Utica assets are becoming more valuable. The proceeds from the offering provide both liquidity and flexibility, while we work through the sales process and ramp up the midstream cash flow.
I would like to take a note, that in the offering, I personally purchased $5 million in units and Mark Houser purchased $0.5 million in units, all at the same price in terms of the public.
Now, a few comments about our base assets. We had strong production performance this quarter due to our Barnett Shale and Austin Chalk drilling programs and overall good production management by our operations team. We started to exploit more opportunities across our existing assets, including potential development of the Mancos Shale acreage within our San Juan position.
And a recently renegotiated agreement to amend our deep rights interest with Apache in the Eagle Ford Shale located below our very large Austin Chalk position. EVEP along with other interested entities will participate with Apache and Halcon in three upcoming wells.
In the midstream, the first trains of UEO's processing and fractionation are now up and running and our processing is hitting capacity at times. The primary bottleneck has been Tennessee Gas Pipeline, rejecting gas trains with high ethane content. We expect this to greatly improve when our deethanizer comes online at the beginning of 2014.
Our next train is scheduled to start processing rich gas in December, and the third and fourth trains are scheduled to come on line in the second and third quarters of next year. We are pleased with the progress so far and the quality of operations performed by momentum.
I want to give you a quick update on the first Utica Shale divestiture we announced in August, in which EVEP is selling 4,345 acres in the wet gas window for approximately $56 million, subject to customary closing conditions and purchase price adjustments.
The first $41 million was closed last month with additional closings before the end of the year. We've utilized these proceeds in like-kind exchange to fund our previously announced Barnett Shale acquisition, which recently closed. Mark, will discuss the details of this acquisition later.
At our last earnings call, I spoke about our plans regarding the volatile oil window. We continue to work with a privately held company with Utica acreage near ours to form one or more joint ventures with service companies, and technically confident oil shale experienced E&P companies.
Two hours ago, I kicked off the Jefferies Energy Conference with comments about the A&D market and the projected pipeline of deals, which began increasing in about August of this year and we believe will continue to increase into 2014.
As you may know, EnerVest Institutional Funds has been very active in market and anticipate closing over $1.4 billion of acquisitions this year, increasing the pool of potential future drop downs to EVEP. At EVEP, we are evaluating both third-party alongside and drop down acquisitions.
With that, I will turn it over to Mike, for comments on our financials, and then to Mark to further discuss our operations.
Thank you, John. For the third quarter, adjusted EBITDAX was $53.9 million, a 2% increase versus the second quarter of 2013 and a 20% decrease from the third quarter of 2012. Distributable cash flow for the quarter was $25.9 million, a 1% decrease from the second quarter of 2013 and a 27% decrease versus the third quarter of 2012.
Distributions for the third quarter payable on November 14 to unitholders of record, as of November 7, will be approximately $38 million. This includes a distribution on the 5.75 million common unit sold on October. But the distributable cash flow does not have the benefit of the lower interest for the quarter from the repayment of debt under the credit facility, since the offering occurred, after the end of the third quarter.
The decline in adjusted EBITDAX and distributable cash flow versus the third quarter of 2012 is primarily due to decreases in realized gains on commodity derivatives on hedges we have entered into, back when commodity prices were significantly higher in 2008, partially offset by an increase in the sales price per unit of natural gas and crude oil.
For the third quarter, production was 10.6 Bcf of natural gas, 279,000 barrels of crude oil and 538,000 barrels of natural gas liquids or a 168 Mmcfe per day. This is a 3% decreased from the second quarter 2013 production of a 172 million cubic feet equivalents per day and a 3% increase over the third quarter of 2012, production of 163 Mmcfe per day.
I'd like to note that third quarter net loss was $12.3 million or $0.29 per basic and diluted weighted average limited partnership unit outstanding. Several items to note that were included in that loss were; $16.5 million of unrealized losses on commodity and interest rate derivatives, related to changes in mark-to-market value on future settlements of derivatives; $0.5 million of non-cash realized losses related to derivatives; $1.2 million of dry hole and exploration costs; $4.3 million of non-cash compensation related costs contained in G&A; and $100,000 of non-cash leasehold impairment charges.
Now, with regard to capital expenditures, our E&P CapEx for the quarter was $24.6 million, in line with our quarterly average for the first half of the year and our midstream CapEx for UEO and Cardinal was $51.7 million consistent with our second quarter midstream CapEx level.
Our share of EBITDAX from unconsolidated affiliates, which is primarily UEO and Cardinal, was $800,000 for the quarter, which was below our guidance range that we have provided in February of $2.2 million to $3.6 million. This is a timing issue and ramp up of cash flow from these assets, and not in any way a change in expectations. These non-GAAP measures are reconciled in our earnings release.
We believe fourth quarter EBITDAX should increase significantly in the midstream, but will likely be around the lower-end of our previously provided guidance on midstream cash flows. It is also just timing related.
We're in the budgeting process at this time, but do not see anything that would cause us to adjust expected EBITDA ranges for 2014 and beyond that we have previously provided in our presentations. Mark Houser will discuss our Utica midstream operations in more detail.
Two other items I'd like to mention are that our borrowing base was increased to $730 million in our semi-annual scheduled review in October. And several natural gas hedges were added since the end of the third quarter related to our Barnett Shale acquisition, and these are detailed at the end of the press release.
I would now like to turn it over to Mark Houser, for a review of our operations.
Thanks, Mike, and good morning. I'll start first with our midstream activity, which consists of Utica East Ohio, where we own 21% and Cardinal Gas gathering systems, where we own 9%. Those activities are progressing pretty much on plan.
Cardinal now has 256 wells connected, a 183 miles of pipe operational. They've installed over 50,000 horsepower of compression and have achieved peak daily production of 295 million cubic feet per day.
During the quarter, Chesapeake turned in line over 60 wells and they reported average initial production rate of over 6.6 million cubic feet per day per well. Cardinal is currently connecting about 20 wells per month and we expect them to continue to do so for the foreseeable future.
The September fire Blue Racer's Natrium plant has impacted Cardinal Gas gathering systems by recreating some of the gas processing bottleneck that have been alleviated this summer. However, a substantial amount of rich gas production originally dedicated to Natrium has been diverted to UEO Kensington, while Natrium is offline. Allowing the first train at UEO to process about a 162 million cubic feet and a 182 million cubic feet gas per day and approaching nameplate capacity of 200 million cubic feet per day on some days. The gas has been delivered to the Kensington plant via both the medium pressure Tennessee Gas Pipeline and the UEO high-pressure spine.
Residue gas from the Kensington has been transported via Tennessee Gas Pipeline. Unfortunately Tennessee Gas Pipeline has been unable to take full delivery due to BTU constraints and market conditions. Our second, third and fourth 200 million a day gas processing trains are under construction as we speak. The second train is schedule to start processing in December.
In addition, our first fractionation train in UEO at Harrison plant is online, although, not yet at full capacity due to ethane rejection in the market. As we expect ethane to be processed once the ATEX pipeline from Ohio to the Gulf Coast becomes operational in late December, and the Harrison Hub deethanizer becomes operational in early January.
Construction for the second and third fractionation trains is underway and is expected to eventually add 90,000 barrels a day to the existing 45,000 barrels per day capacity. The upstream Utica production continues to be curtailed due to midstream and marketing constrains. New wells are being turned in line each month, but overall production has been slow to increase. By the middle of 2014, we expect that Utica wells will finally be able to produce at their full unconstrained rates and system throughput on both Cardinal and UEO will increase significantly.
Mike mentioned, we are in the 2014 budget process. To swipe some of these constrains, we remain comfortable with our current midstream EBITDA ranges we have previously provided in our presentations as we move out into 2014 and beyond.
Now, I'll move to the upstream, and I'll start with CapEx. Our upstream E&P CapEx of $24.6 million for the quarter was once again driven mostly by the Barnett Shale, the Austin Chalk and some conventional infill drilling in Appalachia. This is down a bit from last quarter partly due to timing, but mostly because of the drop from three rigs down to two in the Barnett, which I'll touch on in a moment.
Our combined total CapEx from the beginning of the year is consistent with guidance. Going to the Barnett, in September, we along with EnerVest institutional fund partnerships announced the Barnett Shale acquisition from Carrizo Oil and Gas. EVEP has a 31% working interest, which is in line with our existing working interest in our Barnett assets. The purchase price at the initial November 1 closing, which accounts for about 90% of the asset was $59 million net to EVEP.
This acquisition qualifies for lifetime exchange status in consideration of the Utica Shale divestiture we announced in August. These bolt-on assets are very complementary to our strong operating position within the Barnett Shale. Our team has demonstrated exploitation track record in the Barnett and we'll leverage their expertise with these new high-quality gas properties.
The Barnett reservoir within these new leases has estimated gas in place of 150 Bcf to 200 Bcf per 648 resection and the existing wells drilled have estimated ultimate recoveries averaging over 5 billion cubic feet per well. We believe these properties will provide very attractive future development opportunities even at current and lower gas prices.
In our existing Barnett operations, we ran two rigs for the third quarter and intend to continue to run at that level through the rest of the year. We turned in line 15 wells this quarter, which were on budget in terms of cost, but initial production rates were higher than our estimates about 14% with an average initial production rate of 1.9 million cubic feet per day.
On average, our Barnett wells include 14 to 16 stages at 250 to 300 foot spacing and 4,000 feet lateral. Costs have been running in the ballpark of $2 million to $2.8 million per well depending on the area and the average drill and complete cost per foot of horizontal length is running under 700 per foot, which is an 11% increase year-over-year.
On average, our overall third quarter production rate for the Barnett was 78 million cubic feet equivalent per day. And at the end of October, we turned in four wells at Rocky Creek East. These wells are performing very well. The four wells are chocked back at the moment to about 4 million cubic feet per day per well due to pipeline constraints.
One of the wells in particular, had an initial production rate of 5.7 million cubic feet per day, one of our highest IPs to date. We're on target to drill 63 wells by yearend, which should put EVEP's Barnett capital spending for the year at approximately 64 million. We're also working on several cost saving initiatives in the Barnett, and some re-completion opportunities and believe each of these initiatives will also deliver further long-term value to our investors.
So now if I move to the Chalk, this quarter our focus has been on oil-rich development opportunities with our multi-stage frac well. On our last call, we mentioned the new multi-stage frac well called the [ph] Borgstedt, which was completed in late July. Since then, we've drilled two other wells or EVEP owns an approximately 13% interest.
All three wells have been turned to sales after reaching IP rates in excess of 500 barrels per day and over 2 million cubic feet of gas per day. Some of the best wells we've drilled. These wells cost about $6 million on average and have expected rates of return of well over 50%. We are so pleased with the success of these wells today, that we've actually shifted capital from our conventional chalk program in favor of this multi-stage frac initiative through the rest of 2013 and into 2014.
Two additional wells were drilled in the last month and another is waiting on completion. We're encouraged by the early flowback rates on these wells. Expect us to spud one additional well before the end of the year, bringing this year's total to seven chalk multi-stage well. The team also brought on two new multi-stage reentry pilot wells in the third quarter. These wells successfully lower the cost of the previous reentry program by 75%.
Each well is costing about $1 million and produces 100 barrels per day or more. Due to better than expected fluid rates, these wells were recently converted to gas lift, and production rates continue increasing and again we have well over 1,600 producing wells and many of these are candidates for these type of reentries over time.
And John, mentioned it, there seems to be growing interest in the Eagle Ford Shale, potentially located with our Austin Chalk position. EnerVest recently signed an agreement to amend our de-fracs with Apache to convert our override to a 50-50 working interest. EVEP along with our EnerVest institutional funds have over 400,000 gross acres in this joint venture with Apache. Please remember, EVEP's average working interest in all Chalk and Eagle Ford assets is about 13.5%, while EnerVest institutional funds have the reminder.
We expect to participate in the drilling of three Brazos County Eagle Ford wells in the fourth quarter, two with Apache and one with Halcon, and several more potential locations in 2014. Collectively, our company's are also studying other deep horizons in an effort to generate new reserves from our existing leasehold.
And now I'll move further west to the San Juan. Our San Juan Permian assets performed as expected this quarter. The first quarter of this year, the SUGS plant was down and production was therefore restricted. We regained lost production with the Flush production coming online in the second quarter. And finally, the third quarter has performed as anticipated from production level, as well as from an operation standpoint.
In addition, we've been seeing activity pick up in the Mancos Shale, in which EVEP has about 22,000 net acres. Mancos and Gallup horizontal activities heating up the basin with Encana and Williams, WPX reporting encouraging results from early well. Our San Juan team drilled the Hickory Apache 125 number 17 to a total depth of 8,000 feet in October. We believe this well will test, 80 acre infill potential for the conventional Dakota Sand.
If successful, there at least nine offset 80 acre locations possible on EVEP acreage, but while we are drilling the well the team took the opportunity to run a full suite of open hole logs and acquired multiple sidewalk bores in the upper and lower Dakota Sands, Gallup sandstone and Mancos Shale.
We believe both the Gallup and Mancos are well developed on our acreage, which falls in the wet gas to early oil window. Core results are expected this quarter. We expect this data in combination with the data gathered over other EnerVest properties in the basin, will help delineate potential sweet spots in the Gallup and Mancos. The team will be assessing options to develop the Gallup and Mancos horizontally in 2014.
So going overall production, EVEP's production levels and recent drilling results are encouraging. Many of our assets such as Appalachian Michigan have relatively flat production and low decline curves, while production areas like Barnett, Chalk and Mid-continent continue to grow. Recent weekly production is running a bit above the mid-point of guidance again this fourth quarter. However, any plan or pipeline downtime in our areas has been insignificant.
For the remainder of the year, we believe it's sticking to your current production guidance, plus an estimated 11 million cubic feet per day, for November and December for the Barnett Shale acquisition is appropriate.
In summary, we had a good quarter, base production all over operations performed very well. As we continue to strive for our operational excellence, our Barnett bolt-on acquisition has added additional untapped reserves and we will continue to pursue open acreage moving forward.
With that I'll turn it back to John.
Well, in closing on our formal remarks, our existing asset areas continue to perform well and we see attractive and appropriate growth opportunities going forward. Our midstream assets are beginning to generate cash flow and we will continue to focus on maximizing value of our Utica acreage through acreage sales and joint ventures. Utica drilling continues at a brisk space, although much of the existing Utica production is constrained significantly by midstream capacity restrictions. The build-out of the midstream infrastructure continues to develop, which we believe is helping the valuation of our overall acreage position.
Next year, when the Natrium processing plant returns to operations, other processing plants startup, the ATEX ethane pipeline is on stream and additional gas compression capacity is installed in the gathering system, we expect individual well rates to increase significantly. Our liquidity has meaningfully improved and we anticipate ramping up our A&D activities moving forward.
Thank you. And Ron, we are ready for questions.
(Operator Instructions) And your first question comes from the line of Kevin Smith from Raymond James.
Kevin Smith - Raymond James
I know you guys touched on this in your prepared remarks, maybe I missed a little bit. But can you talk about why midstream revenues came in a little bit light? I figured that with Natrium down, Kensington would actually be utilized more. So help me fill in the holes there?
The main issue there Kevin is on Tennessee Gas, which is having to make sure the quality of the gas is proper, and they can only take so much ethane quality and so they've actually been reducing the takeaway. The plant's been capable and is run at full capacity on several days, but there is just being some slowness in that. And as John and I mentioned, with deethanizer coming online, which we're installing and should be online by the first week of January, that should help quite a bit. And also with ATEX coming online, which is also scheduled to come online around the January 1, that should alleviate the challenge there. But it's mainly being able to take the gas without ethane rejection.
Kevin, just to add on what Mark said, with ethane in it, the gas is at best 1,100 BTUs. And they're trying to mix it with dry gas to get it to their quality standard. And so on a daily basis, Tennessee will tell us how much that can take and it might be 150 million one day, 200 million another day, 125 million until we're significantly constrained.
And the biggest problem with our joint venture, with Chesapeake, is we had five wells, good wells come on last week, but the overall production didn't change, which means that it further choked back other wells. So the wells right now in the joint venture with Chesapeake are facing tremendous back pressure and are constrained.
And Kevin, one other comment on that is on Cardinal. With Natrium going down, Cardinal is putting all the wells online for the Chesapeake, Total, EnerVest joint venture. And Cardinal actually slowed their activity down a bit with Natrium being down to run the capital more parallel with when it's coming back online. So that had a bit of an impact on EBITDA as well.
But as we also mentioned, we're in the budget process now, but looking at Cardinal and UEO budgets both, as we move into next year, they are comfortable that we're going to be back to where the numbers we've shown for '14, '15 going forward, at this point look good.
Kevin Smith - Raymond James
But it shouldn't move significantly until we get into January?
It's moving some. We actually are going to have a better quarter, this quarter and the fourth quarter. Our EBITDA at least for the month of October looks good, better than we reported.
It is ramping up. We had $800,000 for the quarter, Kevin. And part of that too is just startup cost on the UEO facilities. But as I mentioned earlier for the fourth quarter, we would expect EBITDA somewhere around the lower end of our guidance we have put out before, which was I believe between $2.9 million and 4.9 million was the range.
So it's starting to ramp up, Kevin.
Kevin Smith - Raymond James
And then one other question and I'll jump off. Would you mind discussing the terms of your participation in the Eagle Ford? What's your working interest and how much capital is associated with that?
Well, it's a 50-50 joint venture with Apache, of course that's to the overall EnerVest family. And generally, EVEP owns about 13%, 13.5% of that. So it's multiplying that on. If it's a pure Apache/EnerVest acre, then EVEP will own 50% of it times 13.5%, so around 6.25%.
The drilling costs are going to run $8 million to $10 million for some of these wells initially. These are not inexpensive wells. But again, I think Halcon has been the one who has probably reported some results down in there. There have been some pretty good looking wells in that area. EnerVest and EVEP also have some acreage in part of the play that's outside of this joint venture, but it's a reasonably small amount.
Your next question comes from the line of John Ragozzino from RBC Capital Markets.
John Ragozzino - RBC Capital Markets
In most of times the offerings, you described the number of de-leveraging tools that you could have used in terms of alternatives to the common offering. Can you describe what, if anything, has changed between the time, call it in the middle of the summer, and the time of the offering that may have changed and decided to push you over the fence and just make that going to the equity offering?
John, I just think looking at our capital program in the midstream and where we were with our borrowing base that we just wanted to have more liquidity and flexibility in our capital structure and just felt it was prudent to do that to sell the equity at that time. It does give us quite a bit of flexibility going forward, both from the liquidity standpoint and from the potential for some not large, but modest acquisition activity outside the many acreage sales.
John Ragozzino - RBC Capital Markets
And then with the additional flexibility gained, is the urgency with which you're pursuing the sales of the remaining operating acreage change at all?
I think the urgency doesn't change. We're trying to sell that as quickly as we can for at a good appropriate price. And again, on that side of it, this is also gives us more flexibility as we talk to people about selling acreage.
That wouldn't fully anticipate joint venture ramps up to over 1 billion cubic feet a day and we see the actual potential and production rates from these wells, I think that's going to significantly help us in Carroll County where EVEP as well as the other EnerVest institutional funds have a big position.
And basically, I think that you saw in the first transaction with AEP, we have certain targets where we think the actual value should be and basically as people hit our targets they win the acreage. We've had in some areas as many as five offers in one area by the same company, they know my price and until they hit the price they're not going to get it and somebody else will get it and they won't.
So I know Wall Street is not patient, but this is too valuable not to be patient. And so as I said, when purchasing sales are signed, we will let you know. And it is absolutely the highest priority at EnerVest to do these sales, but we're not going to give our acreage away.
And just reiterating some thing John said and we said in the prepared remarks that Chesapeake turned in 60 wells that they reported average production rates of over 6.6 million a day per well. So the wells that are coming online are good. Again, there is some chocking going on right now because of infrastructure, which should be alleviated over the next several months.
Kind of backing down our other wells.
John Ragozzino - RBC Capital Markets
And then you also mentioned in the prepared remarks, the inclusion of a potential private third-party with respect to the joint venture in the volatile oil window, was this previously disclosed or did I missed that?
Nom, that's been disclosed before. There's another private party with acreage actually. There is a couple of others that are interested, but one we're formally working with that has acreage, that sharing in cost and other things that are required to kind of move through this process.
And this work is being done in Tuscarawas and Stark Counties.
Your next question comes from the line of Ethan Bellamy from Baird
Ethan Bellamy - Baird
Let me follow-up on Jay's line of questioning. With respect to the financing, if you don't sell anymore Utica acreage, will you need more equity capital to finance the midstream?
No. We do not believe we will.
Ethan Bellamy - Baird
What's your best guess on timing of the disposition of the midstream interests?
I think at this point, that will happen. Clearly when it does, we're a minority-interest owner in that with a 21% interest, Momentum is the operator, but I think they build on these to get further along.
Ethan Bellamy - Baird
Do you anticipate your number one strategy is still tagging along with an overall sale by Momentum rather than just selling your stake?
Momentum is well respected within the midstream business. They have built out and sold three previous well-positioned midstream assets in the past. Again, as I've said they're the only ones, to my knowledge, that have brought their assets on time, as well as on budget. We are extremely pleased with their operations. We believe that they are catering to the heart of the Utica play. But again, our objective and their objective and the person that runs the Momentum is a close good friend of mine.
And I think that that something is really a great asset of EVEP, very few companies have the opportunity to sell something for a multiple of the cost that they put in, in the kind of multiple that this kind of asset position demands. And obviously, that will have a great impact on EVEP. And I think that on an overnight situation, we will not have some of the questions about liquidity and others that we've had over the past year.
Ethan Bellamy - Baird
With respect to the assets that are at EnerVest that you have been developing and you've also been very acquisitive. Can you quantify for us, either on a reserves basis or maybe on EBITDA basis, how much is there that might be suitable for dropdown? And handicap the possibility of a dropdown over the next six to 12 months?
Well, at EnerVest including EVEP, we have 6.7 trillion cubic feet equivalent of reserves and we have 5.6 million acres of land. And with the acquisitions that we announced yesterday, with EnerVest Limited, which is about $1.3 billion. At yearend, we'll be producing something in that order of about 830 million cubic feet equivalent per day.
So we're a pretty large player in a lot of basins, and that helps EVEP because of the size and scale that we bring. And the basins would be appropriate for EVEP, would be the ones that would have a higher component of PDP, without the demands of negative cash flows at some of these place do have. So we have plenty of those within the EnerVest family.
Ethan, I'll add just a little bit to that. Really the areas that among others we like a lot for EVEP overtime are Appalachian, Michigan, the San Juan Basin, the Chalk, the Barnett and then our Utica as well all kind of fit the criteria. And in terms of handicapping, what will happen several of these assets are owned by some of the older funds with EnerVest. And so they're motivated to sell. And so if there is kind of the timing where it fits EVEP and the funds', both desires, that could happen fairly quickly.
There are no further questions at this time, please continue.
Ron, thank you. And thank you to everyone that was a participant in the call. And we look forward to future announcements and further communications with you as this quarter unfolds.
Ladies and gentlemen, this concludes the conference call for today. Thank you for participating, you may now disconnect your lines.
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