EV Energy Partners' CEO Discusses Q4 2013 Results - Earnings Call Transcript

| About: EV Energy (EVEP)

EV Energy Partners, L.P. (NASDAQ:EVEP)

Q4 2013 Earnings Conference Call

March 3, 2014, 09:00 AM EST

Executives

John B. Walker – Executive Chairman

Mark A. Houser – President and Chief Executive Officer

Michael E. Mercer – Chief Financial Officer and Senior Vice President

Analysts

Kevin C. Smith – Raymond James & Associates, Inc.

Ethan H. Bellamy – Robert W. Baird & Co.

Bernie L. Colson – Oppenheimer & Co., Inc.

Praneeth Satish – Wells Fargo

Abhishek Sinha – Wunderlich Securities

Adam Leight – RBC Capital Markets LLC

Daniel D. Guffey – Stifel, Nicolaus & Co., Inc.

Operator

Welcome to the EV Energy Partners' Fourth Quarter and Yearend 2013 Earnings Conference Call on Monday, 3, March 2014. (Operator Instructions) This morning, EV Energy Partners' issued a press release announcing quarterly and yearend 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 or 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 to differ from management's expectation.

I will now hand the conference over to John Walker, Executive Chairman; Mark Houser, President and CEO; and Mike Mercer, Senior VP and CFO. Please go ahead.

John Walker

Thank you, Kirsten, this is John Walker, good morning, everyone and thanks for joining us today. Mike Mercer and Mark Houser are in Florida at the Raymond James 35th Annual Institutional Investors Conference, where they will be speaking later today and I’m in [Cavo] [ph] at the Citibank Conference where most of our competitors and about 150 CEOs are gathered.

For the fourth quarter our overall performance was in line with our weather adjusted expectations, which Mike will review in more detail. This winter’s weather has benefited natural gas prices, but as with most in our industry, has presented us with some challenges. It affected our production by 10% to 15% on a few of the days in December, January and February, and in the midstream reduced producer’s deliverability at the wellhead into the Utica East Ohio and Cardinal Gathering Systems.

The connecting laterals to the ATEX ethane system were also delayed by a few weeks because of the weather. Our drilling and acquisition program for 2013 produced excellent results with proved reserves increasing by 32%. On a price neutral basis our reserve replacement cost was $1.01 per mcfe. Our base business outside of our Utica acreage and midstream positions continues to provide us with increasing opportunity. The Barnett Shale is performing well and our large and integrated position is creating more incremental upside in several parts of the field.

Drilling activity in the Eagle Ford in an around our awesome chart producing acreage is accelerating significantly and there also continues to be growing rig activity in the Mancos shale near our San Juan Basin asset. We see the A&D [ph] market strengthening this year and EVEP will be evaluating opportunities to participate in that increased activity. EVEP’s big brother EnerVest will probably be buying something in excess of $2 billion this year and that could create some opportunities also for EVEP.

In the Utica midstream which includes our investment in the UEO processing and fractionation business and the Cardinal gathering business, we expect a significant ramp up and throughput and cash flow throughout this year, beginning probably later this month. The second UEO 200 million cubic feet per day train began commissioning as planned in November and is now fully up and running. Its complementary de-ethanizer at train 2 will soon be online.

We continue to expect the next two processing trains to come online during the second and third quarters this year. Train 1’s de-ethanizer tower has started up in February. In addition UEO is close to increasing the commitments to the system up to 1.2 billion to 1.3 billion cubic feet of throughput per day, compared to the 800 million cubic feet per day, currently in place or being constructed.

As you’re aware, UEO dominates the heart of the wet gas window. The Cardinal gathering business also continues to increase capacity, as well as turning wells in line. Gathering volumes have been restricted over the last couple of months due to severe winter weather but also ramping up. The average volume into UEO over the past five days has averaged 360 million cubic feet per day and there have been peak intraday rates of 420 million cubic feet per day, well above the nameplate capacity.

it’s projected that because trains 1 and 2 can process as much as 20% more than nameplate capacity that only one additional 200 million cubic feet per day train will be necessary to process the 1.2 billion cubic feet to 1.3 billion cubic feet unless additional volume commitments are garnered by UEO. as midstream capacity from UEO and others continues to increase we believe the midstream constraint from Utica production that have existed over the past year will be eliminated and there will be much clear visibility of the productive capacity of the wells in the Utica.

Obviously, that means higher calculable value of our acreage in Carroll County and other high wet gas counties. Not only do we continue to pursue the sale of our acreage in the wet gas involved oil windows, we believe that our tag-along rights in the Cardinal and UEO systems are very valuable.

For 2014, we expect to participate in at least eight to 10 wells in the volatile oil window, several of which EnerVest will be the operator. Two of these wells are already drilled and one recently has come online. We believe we have a lot of good opportunities to grow our base business, both organically and through acquisitions.

we look forward to this year as we begin to see the benefit of our midstream capital investment and our Utica acreage and possibly, the midstream monetization efforts. We are also focused on getting our distribution coverage back [over one] [ph]. in a few minutes, Mark Houser will discuss our operations in more detail, but first I want to turn it over to Mike Mercer who will provide an analysis of our financial results. Mike?

Michael E. Mercer

Thank you, John. I’m going to review our results for the fourth quarter and full year 2013 and summarize our guidance for 2014. I’ll also discuss our additions to our natural gas and crude oil hedges that we’ve put in place since our November third quarter conference call.

For the fourth quarter, adjusted EBITDAX was $53.7 million, which is a 23% decrease from the fourth quarter of 2012, primarily due to the decrease in cash settlements on commodity derivatives from 2012 to 2013, and flat compared to the third quarter of 2013.

Distributable cash flow for the quarter was $26.7 million, a 30% year-over-year decrease also primarily due to the cash settlements – lower cash settlements and commodity derivatives I just mentioned, and a 3% increase over the third quarter of 2013, distributions for the quarter which were paid on February 14 were $38.7 million.

For the fourth quarter, production was 10.8 Bcf of natural gas, 240,000 barrels of crude oil and 580,000 barrels of NGLs or 170 million cubic feet equivalent per day. This represents a 3% increase over the fourth quarter of 2012 production and a 2% increase over the third quarter of 2013 production.

As John mentioned, December weather, primarily in our Barnett Shale area had a slight negative impact on our fourth quarter production. In addition, the cold weather, unusually cold weather that we had in Ohio did have an impact on our midstream business, which Mark will discuss further a little bit later.

Our fourth quarter net loss was $50.2 million or a net loss of $1.05 per basic and diluted weighted average limited partner unit outstanding. Several items that I would note that were included in the net loss, were a $77 million non-cash impairment charge, mostly related to the write-down of assets in the Permian basin due to affects of future oil and natural gas commodity prices, unexpected future net cash flows. A $41.3 million gain on the sale of Utica acreage, $21 million, $21.2 million of non-cash losses on commodity and interest rate derivatives and $4.4 million of non-cash compensation related costs contained in G&A.

Now for the full year results for 2013 adjusted EBITDAX and distributable cash flow were $209 million and $106 million which is a 22% and 29% decrease respectively from 2012. As with the fourth quarter, this was largely due to the decrease in cash settlements on commodity derivatives in 2013 as compared to 2012, partially offset by the increase in the sales price per unit of natural gas in 2013 versus 2012. Distributions related to 2013 were $145 million or 2013 production was 42.7 Bcf of natural gas 1 million barrels of crude oil and 2.1 million barrels of natural gas liquids or a 169 million cubic feet equivalent per day.

This is a 3% increase over 2012 production primarily due to our drilling program as well as the acquisition of some Barnett Shale properties that closed during the fourth quarter, 2013 net loss was $76.2 million or a $1.76 per basic and diluted weighted average limited partner unit outstanding. Once again several items to note that were included in that, were $85.3 million of impairment charges primarily attributable as I had mentioned earlier to a fourth quarter write-down of Permian Basin assets, $47.3 million of non-cash losses on commodity and interest rate derivatives primarily the settled and future periods. A $41.3 million gain on the sales of Utica acreage in the fourth quarter, $17.5 million of non-cash compensation costs and G&A and $2.4 million of dry hole and exploration costs.

Now with regard to guidance, we’ve published guidance for 2014 in the press release that was published earlier this morning. We present guidance ranges for the first quarter of 2014 and then for the second through fourth quarters of 2014 combined. However, since we have a significant ramp up in our midstream expected cash flow this year, we do provide specifically or quarterly guidance ranges, for our midstream segment in a guidance footnote in the press release.

Some of the highlights on an annualized basis regarding guidance are as follows; Production guidance range for the year is a 169 million to a 182 million cubic feet equivalent per day. Natural gas and crude oil price differential estimates versus NYMEX range from 94% to 99% for crude oil and 90% to 94% for natural gas and net transportation margin for third-party volumes with a range is 900,000 to 1.5 million. Lease operating expenses which include gathering and transportation costs on our properties range from $102 million to $112 million.

Production taxes as a percent of revenue are estimated 3.4% to 4% of revenue. SG&A expense which excludes any potential acquisition related due diligence expenses is $21.5 million to $26.5 million. The first quarter G&A expense reflects slightly higher relative cost on cash G&A due to the cash cost that we have related to annual restricted unit investing in January as is typical for us each year. Also, our production guidance for the first quarter includes an estimate of the impact of the unusually cold winter weather on expected production as well as on the midstream business in Ohio.

The E&P capital expenditures are projected generally inline with last year at $95 million to $115 million and these amounts do not include anything for any acquisitions that we might make of oil and gas properties during the year. Moving the Midstream, our expected share of EBITDA from our Utica Shale midstream investments as well as a small amount from our overwriting royalty interest ranges from $33.5 million to $40 million for the full year. However, I would note the expected ramp in midstream EBITDA throughout the year as additional UEO processing and fractionation capacity comes online and as Cardinal Gas Services continue its gathering system expansion.

For the first quarter, our EBITDA guidance range for the midstream is $3 million to $4.5 million rising to a fourth quarter range of $11 million to $14 million with additional increases expected beyond 2014. I would like to note that the first quarter guidance includes an estimate of the impact of winter weather on well production and deliverability into the UEO and Cardinal systems, which Mark Houser will discuss further in his comments. Midstream CapEx related to UEO and Cardinal is estimated to range between $115 million and $135 million.

In December, we entered into the natural gas hedges for 2014, 2015 and 2016 and I’ll refer you to the press release for specific details on those additional hedged positions as well as our overall hedged portfolio.

Now I’ll turn it over to Mark Houser for a review of our yearend reserves and our operations.

Mark A. Houser

Thank you Mike. Over the few minutes I’m planning to further discuss our Utica Upstream and midstream operation. I’ll then spend sometime talking about our reserves, operating performance on base and some potential growth areas going forward. In the Utica Shale industry activity is high and there are currently 36 rigs running in the play. Most of the activity is in the wet gas window. Most active operator in the play is Chesapeake and EnerVest participates in most of the Chesapeake wells through our joint venture.

Chesapeake plans to run eight rigs for the remainder of 2014 down from nine last year. It still plans to drill the same number of wells around 180, because drilling has become more efficient. To-date EnerVest has participated in 252 wells in 11 counties providing great insight into the Utica play. EVEP has directly participated with a small interest in 21 gross wells with 16 of those wells drilled in 2013.

Production performance and EUR continues to improve with the JV of west gas window type curve now forecasting an EUR of 6.9 Bcf equivalent in our key area of Carroll County. Drilling costs and time to drill continue to decrease and lateral length are increasing, gathering and midstream bottlenecks are being addressed and we expect that wells will finally flow at unconstrained rate later this spring in summer.

In the volatile oil window activity is also increasing, EQT recently announced plans for follow-up on their 2013 volatile oil wells with an additional 21 wells to be drilled on 2014, this is certainly encouraging, EVEP will receive several AFEs from EQT as part of our non-operating position. We will closely monitor their activity and results and apply learning’s to our own activity.

EnerVest has an interest in two additional wells in the volatile window, one with Chesapeake that will be turned online later this summer and another with Halcon, the Halcon well has been turned inline and the initial rates are encouraging. All this activity is potentially very leveraging for EVEP, because of our larger acreage position in the volatile oil window. We still intend to form a joint venture and have been in discussions with potential partners to participate in a number of wells to demonstrate the economic viability of the volatile window. Along with EnerVest we plan to drill at least two volatile oil window wells later this year.

Now on to our Utica midstream investments, as a reminder EVEP owns 9% interest in Cardinal Gas Services and a 21% interest in Utica East Ohio, both of which provide midstream services to producers in the Utica shale. Cardinal now has over 300 wells connected and another 80 plus wells waiting to be turned inline. Compression continues to be added at key gathering points and proved budget increasing every month.

At UEO, our second 200 million cubic feet per day processing train at the Kensington plant came online in December brining current gas production capacity up to 400 million cubic feet per day. The first de-ethanizer tower at the Harrison Fractionation facility is now operational, allowing Kensington plant to process ethane. Ethane is being delivered from Harrison to the ATEX path line for transport to develop. Furthermore, with ethane being removed from the residual gas stream meaning pipeline spec will no be a problem.

The third 200 million cubic feet per day train at Kensington and an incremental 45,000 barrels per day of fractionation capacity at Harrison should be operational in the second quarter. There are also additional third-party volumes between 300 million and 500 million cubic feet per day that we are pursuing, which could increase our capacity up to 1.2 billion cubic feet per day over time.

In November, there was a brief period of time when the processing train was shut in, in order to hook up the second train. Fourth quarter EBITDA was affected by that. Also, cold weather impacted upstream production, the Cardinal gathering system and indirectly, UEO processing and fractionation.

we expect that Cardinal and UEO throughput will continue to ramp up as weather improves, and as wet gas window development continues. As an example, while the winter cold is limited consistent peak flow early in this project, McKinsey’s new plant has produced over 400 million cubic feet per day nameplate capacity, several days and has averaged 360 million per day the past five days.

Cash flow from both these investments is increasing and will continue to increase throughout the year. our midstream capital investments today, it is $250 million and we’ve planned to spend an additional $115 million to $135 million in 2014.

Moving on to our base business, SEC year-end proved reserves are 14 trillion cubic feet equivalent, of which 31% are oil, and NGLs and 69% in natural gas. Our reserves are 68% proved developed with an R/P ratio of 19 years. The prior year, our reserves were 33% oil and NGLs, 67% natural gas and 76% proved developed with an R/P of over 15 years.

So proved reserves have increased by about 287 billion cubic feet equivalent or 32% over year-end 2012. The reserve replacement rate was 565% at a cost of $0.48 per Mcfe. Clearly, we benefitted from the year-over-year increase in prices required in calculating SEC reserves. Even with the positive revision effects removed, our replacement rate was 268% at a cost of $1.01 per Mcfe. Further, even if we excluded acquisitions, our reserve replacement rate without price revisions was still 156% at a cost of $1.06 per Mcfe.

Now looking at production and operating expenses, overall, production for the fourth quarter was in line with expectation, although slightly impacted by the unusual winter weather about 3 million cubic feet per day in the quarter. The Barnett and Mid-Continent were the areas most affected by the freezing weather.

The impacts were necessarily, because of freeze-offs at the well head, but most are because the water trucks weren’t able to make it through the icy conditions to drain the tanks where water collected during production. And for those of that were in the Dallas are during early December, what I’m talking about in terms of icy roads.

Weather has also impacted production levels for the first quarter of 2014, adjustments are reflected in the first quarter guidance we published in our press release. LOE came in as expected. The year-end upstream capital expenditures were $105 million which is within the guidance range.

Our largest CapEx program was in the Barnett where we spent $61 million to drill 79 gross wells. Our Barnett team delivered exactly what they set out to achieve, production goals were met with 7% less capital than budgeted, and new drills are consistently exceeding initial projections due to improving geologic and engineering practices.

Our team has worked more diligently to pool leases into units, acquire offset leases and apply advanced land development techniques to conjoin leases. These efforts have resulted in the ability to drill longer, more efficient laterals; we’re averaging about 500 feet longer now and increase IP rates on new wells.

In the fourth quarter, a total of 11 wells were brought online in the Barnett with an average initial rate of 2.3 million cubic feet per day, which actually included one dry hole, for an average drill and complete cost of $2.3 million. IP rates were 30% higher than we had anticipated.

The success of these longer laterals in addition to better commodity pricing, accounted for the most of the uplift we saw in Barnett reserves. During the fourth quarter, we also closed $66 million of follow-on acquisitions in the Barnett. These acquisitions include some of the most prolific, potential wells in our Barnett portfolio. We have expedited the permitting process for these drilling locations. we are working to ramp up our activity as early as the second half of 2014.

In the Austin Chalk, the EnerVest family is the number producer with approximately 800,000 gross acres and over 1,500 wellbores producing. EVEP’s 13.5% working interest produces over 12 million cubic feet per day. In terms of performance, the Chalk team really hit it out of the park [ph] last year; our drilling program had tremendous success with our new wells which are producing individually at rates over 500 drills per day. And our multi-stage reentry wells which at 1 million for work over have provided a cost effective way to boost production.

Production came in over budget, lifting costs were lower than anticipated and operated direct lease operating expenses came in under budget by 8%. We continue to assess the potential in the Eagle Ford Shale located beneath our Austin Chalk position. I mentioned in last quarter’s conference call, EnerVest signed an agreement to amend our deep rights with Apache for a override to a 50/50 working interest in over 400,000 gross acres. Although the numbers are still being refined, we believe that EVEP holds deep rights to approximately 20,000 net acres that are perspective for the Eagle Ford.

The EnerVest family plans to drill a well at Lee County, in the second quarter of this year. We also expect to participate in the drilling of over 25 non-op wells collectively there are 19 rigs running in the area and 15 of them are near our acreage position. It’s still early days, but the amount of activity pushing forward is encouraging and we are taking a proactive approach and trying to determine the viability of the Eagle Ford in this area.

In the San Juan Basin, EVEP owned over 20,000 net acres which we believe maybe perspective for the oil and gas wet windows of the Mancos Shale, we along with EnerVest plan to start searching for a JV partner this year, so far one vertical well has been drilled on EVEP acreage where sidewall cores have been taken for analysis. This well was completed in the deeper Dakota sands and initial rates was promising, leading us to plan for two more assessment wells this year. We are also paying close attention to offset operators at WPX and Encana.

On the upstream side for 2014, we will stay focused on our 20% IRR hurdle rates and are targeting a range of $95 million to $115 million per E&P capital, of which about $80 million is allocated for drilling and completing about 190 gross wells, of that $80 million, $28 million is allocated for drilling 71 gross wells in the Barnett remaining capital will be somewhat evenly distributed between our other wells in the Chalk, Mid-Continent and San Juan and Appalachia, in addition to the Eagle Ford participation, we will continue to update you on the progress throughout the year.

With that I will turn it back to John. John.

John B. Walker

Thank you, Mark and Mike and question, we’ll open for questions.

Question-and-Answer Session

Operator

Thank you sir. (Operator Instructions) Thank you. Our first question comes from Kevin Smith from Raymond James. Please go ahead with your question sir.

Kevin C. Smith – Raymond James & Associates, Inc.

Hi, good morning gentlemen.

John B. Walker

Hey, Kevin.

Mark A. Houser

Good morning.

Kevin C. Smith – Raymond James & Associates, Inc.

John, thank you for your comments on UEO and midstream constraints, at this point as you look at more capacity getting added, when do you see those [inaudible] being alleviated. Is there kind of a point where you think you cross over and you’ve got enough take away capacity?

John B. Walker

Yes, I think we’ll start saying that Kevin beginning in April, we’ve – obviously this has been very severe winter in Ohio, there were days it was minus 20 degrees, and that if there is any water in inline or anything it created freezing conditions, but I really do believe now that we’re – as both Mark and I mentioned we’ve seen Train 1 up 240 something million cubic feet a day and Train 2 in the 200 range.

So we really do believe that UEO has done a very good job of bringing their plants on stream, on time, but the weather has created the main constraints, and the other thing that we’re saying is UEO has been able since they are, as I said, in the heart of the wet gas window niche from Harrison to the north. They have been able to get a lot of commitments from - or they are very close to getting commitments from several third-parties.

Kevin C. Smith – Raymond James & Associates, Inc.

Got you.

Mark A. Houser

Kevin actually you’ll see in a couple of – later today in our presentation, I’ve got some charts and to John’s point, you’ll see that out of the midstream, I’d call the gathering and processing constraints are really going to be alleviated as we roll into the second quarter, and again, reiterating John has said and I have said, that we’ve had peak days of over 400 million a day and we’ve also increased our liquids production up to about 22,000 barrels per day as ATEX or as our de-ethanizers have been installed and we started moving ethane. so things are starting to loosen up.

Kevin C. Smith – Raymond James & Associates, Inc.

Perfect, great.

John B. Walker

Let me clarify Kevin, for you on – I said we expect that we’ll have 1.2 billion to 1.3 billion cubic feet a day of commitments, but we’ll only need nameplate capacity of 1 billion, really based upon the efficiency that we’re seeing we believe that five trains can handle that rather than six.

Kevin C. Smith – Raymond James & Associates, Inc.

Okay. And then just one other question, in Barnett, I know you were seeing a little bit of organic declines last quarter, where you shifted from two to three rigs, has all that decline been offset now and maybe where we stand on that?

Mark A. Houser

Well, I think we shifted from three to two rigs.

Kevin C. Smith – Raymond James & Associates, Inc.

I’m Sorry, yes.

Mark A. Houser

Yes, I mean the winter has been, I’d say late December through January has been really challenging out there as I mentioned, more due to ice and compression that has been due to the kind of the wells themselves. And we’re starting to manage through that and production has been ramping up, I’m looking at our weekly report and we’re back up kind of getting towards our budgeted levels, Kevin. But a lot of the challenges we face from not being able to haul off water that cause these wells to have a lot of water in the tubing and we’re having to unload that and get it back on – get it back off. So this has been a little bit of a longer drop than we thought, but we’re making good progress.

Kevin C. Smith – Raymond James & Associates, Inc.

Okay, thank you very much.

Operator

Thank you. Our next question comes from Ethan Bellamy from Robert W. Baird. Please go ahead with your question, sir.

Ethan H. Bellamy – Robert W. Baird & Co.

Hey, good morning guys.

John B. Walker

Hi, Ethan.

Ethan H. Bellamy – Robert W. Baird & Co.

The verbiage in the 10-K implies that you won’t need any equity financing in 2014. is that accurate?

Michael E. Mercer

Ethan, we don’t comment on equity financings that we might or might not consider. It’s just our policy not to - if we launch an equity offering, we’ll launch one, but we don’t discuss those ahead of time.

Ethan H. Bellamy – Robert W. Baird & Co.

All right. How much do you expect the override to contribute in 2014?

Michael E. Mercer

That’s not going to be – it’s going to be a very small chunk, we believe out of the overall amount that we have for our midstream in overrides amounts, it will be single-digit amount out of the guidance range for that area.

Ethan H. Bellamy – Robert W. Baird & Co.

All right, thank you.

Operator

Thank you. our next question comes from Bernie Colson from Oppenheimer. Please go ahead with your question, sir.

Bernie L. Colson – Oppenheimer & Co., Inc.

Good morning.

John B. Walker

Hi, Bernie.

Bernie L. Colson – Oppenheimer & Co., Inc.

One, kind of specific question and then a general question on the hedge portfolio, if I’m not mistaken that the 2014 oil hedges are significantly higher than the oil production expected to be. Is that…

John B. Walker

Yes, we effectively had in place Bernie, crude hedges effectively dirty hedging NGLs.

Bernie L. Colson – Oppenheimer & Co., Inc.

Okay.

John B. Walker

And we look at the potential of effectively unwinding some of those, or effectively swapping them into direct NGL hedges. I mean we’ll continue to look at that with the intent of those was to the dirty hedge on the NGLs. Back when we put in a lot of those in place, there – the NGL market was a lot more limited in the ability to hedge. And so we were using dirty hedges there, but that’s the reason.

Bernie L. Colson – Oppenheimer & Co., Inc.

Okay. and then I’d love it if you could kind of give us some color on the hedge portfolio generally. There are no hedges – oil hedges in 2016 or forward. And so if you just talk about, I mean is that a reflection of your view on the oil market fundamentals or…

John B. Walker

We’re always looking at hedging opportunities Bernie and intend to layer them in over time. And we would expect to add some more hedges as we go through this year, further out into 2016, possibly even further and then even if you look at 2015, on our oil, I know you didn’t mention it, but we have only a couple of thousand barrels of liquids hedged for 2015. So as we move forward we will look to add on to those hedges.

Ethan H. Bellamy – Robert W. Baird & Co.

Okay, so not taking, I mean you are not making a statement here that you think, that you think the forward-curve is wrong or that you have an analysis that suggest that the marginal barrel of oil is going to cost more than what we see in the current forward-curve?

John B. Walker

Always hesitant to make projections about the forward-curve and whether it’s right or wrong, and you got good chance of being wrong there if you do, but yes the forward-curve is backwardated on crude, for 2015 it’s in the high 80s, so we are bit under 90, and in 2016 it’s down towards the mid or 80s or below, but we are not making a statement on that.

Ethan H. Bellamy – Robert W. Baird & Co.

Okay. Thank you.

Operator

Thank you, and our next question comes from Praneeth Satish from Wells Fargo. Please go ahead with your question.

Praneeth Satish – Wells Fargo

Hi, good morning. Just a couple of quick questions. I guess in the past you have provided at one point, long-term guidance for the overriding royalty interest, and where cash flows could go to over time. Just wondering if you could update us on the trajectory of cash flows there whether anything has changed.

John B. Walker

I think at one point we had tried to give people a sense of what the overrides could do overtime, it wasn’t really a forecast year-over-year, It was an assumption about, at some point down the road in the future, once there has been a lot of drilling occur in the Utica to give a sense of magnitude of what those could become under a bunch of different assumptions that we made at the time. But we haven’t really done a long-term forecast, year-by-year on the overrides.

Mark A. Houser

Let me comment on that guys, just as John mentioned and I mentioned we are having a lot more transparency in terms of the wet gas window. A lot of acreage, a lot of the wells drilled are in that area. And we expect – we are seeing some income coming from our override now. It’s just been small, but as this midstream really starts to unleash and become less of a constraint. We anticipate of seeing some growth in our overrides, and we’ll start reporting on that more as you see it go into later in this year. Again the midstream debottlenecking is going to help us a lot to have more clarity on what the growth trend is on that.

Praneeth Satish – Wells Fargo

Okay. And I apologize if I missed it. Did you provide your maintenance CAPEX forecast for 2014?

John B. Walker

We do not publish forecast of estimated maintenance capital. Going forward we never have since we went public. Our board periodically meets and reviews that. And we determine the estimated maintenance capital more on a quarterly basis is where is result occur, but we don’t publish a forecast for maintenance capital or for EBITDA.

Praneeth Satish – Wells Fargo

Got it. Okay thank you.

Operator

Thank you. Our next question comes from Abhi Sinha from Wunderlich Securities. Please go ahead.

Abhishek Sinha – Wunderlich Securities

Yes, hi good morning everybody. Just wanted to ask you if you could provide any update on your potential margin [ph] of the midstream assets, any strategy behind that, the way I am looking at it is like are these I mean potential assets divestiture for Utica and the Midstreams, are these independent events. So let’s suppose if you are not able to sell Utica for the rest of the year any of the assets, would that accelerate your potential midstream assets divestiture, I’m just trying to get my heads around that.

Mark A. Houser

I’ll jump in and John you can as well, but again those are really separate issues selling Utica acreage versus selling our Midstream. We’re as John mentioned in his notes, we have tag along rights on both assets. And we are in very close contact with our working interest partners, our larger working interest partners on both of those. And as opportunity presents themselves that make sense for EVEP, we’ll consider the sale of that.

At the same time, we are working on Utica sales as they come to us and we feel like again as John mentioned with our wet gas window production coming up a good bit, we should see more clarity there. So again we’re saying those are independent decision, but the drilling three different options we have for potential assets sale over the next while that we are paying very close attention to and again, as John mentioned, that can help us a lot on our goal for coverage improvement at all and so we’re very sensitive to that.

Abhishek Sinha – Wunderlich Securities, Inc.

Thanks. and just as a follow-up, out of that 115 to 135 CapEx in the midstream in 2014. How much of that is going from UEO. UEO versus cardinal, how does that break down?

John B. Walker

Maybe we have that, generally over time, if you look at the overall portfolio UEO is about 70% and Cardinal is about 30%, as far as the CapEx split. But for 2014, UEO is probably a little bit more than 70% of that for 2014.

Abhishek Sinha – Wunderlich Securities, Inc.

Okay. Sure, that’s all I have. Thank you very much.

Operator

Thank you. Our next question comes from Adam Leight from RBC Capital Markets. Please go ahead with your question.

Adam Leight – RBC Capital Markets LLC

Hey, good morning.

John B. Walker

Good morning, Adam.

Adam Leight – RBC Capital Markets LLC

Just a follow-up if I could on the maintenance CapEx question, just how should we be thinking about this went down considerably in 2013 and as a percentage of the EBITDA, just could you walk us through what – how you are thinking about and how we should think about it?

John B. Walker

On our estimated maintenance capital, which is something that’s defined in our partnership agreement, Adam. We periodically review it, and with our Board, and our conflicts committee of our Board. and as you know in the partnership agreement, it’s defined as the amount that we believe is necessary on a going forward basis to maintain production and reserves, including over the long-term. so it’s not necessarily a one – it’s not a one-year spend number. But we’ll – Adam, we look at a lot of things over time, what are our – the acquisition market is, in other words, for properties that are similar to our portfolio relatively long-lived gas oriented 15 to 20-year R/P properties, what is the acquisition market like and what are the costs there, both on kind of a current basis and as best we can estimate what they might be going forward in the future for a period of time.

We look at our portfolio internally with regard to drilling opportunities and the potential to add to proved reserves as we drill up PUDs, through probable’s and possible and what that will cost and look at all of those things in setting that right. And clearly, it came down on an absolute basis over time, but a lot of that is just if you look at what’s happened with the acquisition market as an example, last year for properties that are kind of gas oriented along with properties, the typical deal was around $1 an Mcfe, or a little bit less.

And if you look at our reserve replacement rate, this past year, Mark mentioned this, if you look at it on our total reserve replacement rate and cost, it was 500 something percent at $0.48 an Mcfe. Now as Mark mentioned in this, we have in the presentation, that we’re preparing today, we realize and that a lot of that is due to price revisions, in other words, the gas price increased substantially from the 2012 reserve report to the 2013 reserve report. so what we also did is ran it on a price neutral basis, in other words, we pulled out all the positive revisions on pricing that occurred on our proved reserves to more realistically show what the results were and even pulling out acquisitions, just looking at our drilling results excluding acquisitions and excluding the benefit of price revisions, our reserve replacement rate was about 150% at a – right around $1 an Mcfe. So we look at a lot of things on that, it’s not a formula, set formula on determining that. We look at a lot of factors in that. Is that helpful?

Adam Leight – RBC Capital Markets LLC

That’s all helpful. How about directionally in 2014 given what you are seeing out there?

John B. Walker

On maintenance capital?

Adam Leight – RBC Capital Markets LLC

Yes.

John B. Walker

As I said, we published it quarterly with our results as we determined that we don’t make forecast of it.

Michael E. Mercer

I think that directionally what we are seeing is, we’re seeing as John mentioned pretty active A&D market; reserve multiples in the area for acquisition multiples haven’t changed that much to the areas we’re looking at. We’re not looking to acquire heavily in some of the harder areas like Permian, and at the same time we will be adding as we grow our EBITDA on our midstream the Maintenance capital requirement for the midstream will be lighter than it will be for the Upstream so that will – will there be some adjustments there, it not material right now, but overtime there will get to be a bigger number and we are still working on that to really assess the maintenance capital required for UEO and Cardinal…

Adam Leight – RBC Capital Markets LLC

Okay, thanks a lot guys.

Operator

Thank you we have a follow up question from Bernard Col from Oppenheimer. Please go ahead sir.

Bernie L. Colson – Oppenheimer & Co., Inc.

Hey guys, I was curious if you would be interested, you mentioned that an acquisition number of potential at EnerVest, would you be willing to talk some about the inventory that’s currently at EnerVest even any color would be good if you could quantify, that would be great, but…

Mark A. Houser

Yes and Bernie that will come out in the presentation we’re about to make, but if you look at…

John B. Walker

Well I would note too that that – for those on the call, that presentation is available on our website now. It’s the presentation at the Raymond James Conference later today and it’s available for view and downloading currently.

Mark A. Houser

We have about at the EnerVest private equity fund level, we have about 3.3 Bcf of proved reserves, just ball parking it, probably half of that overtime is available potentially for EVEP. I’ll referenced recently we’ve just done a sale into third-party market out of EnerVest in the Permian area that we are drilling up type of asset that EVEP would be interested in, but they have a lot of kind of long-life gas and oil reserves in places that EVEP likes, such as the Appalachian, such as the Barnett overtime, also San Juan Basin and the Chalk or areas that the EnerVest knows, the EVEP knows and there could be some opportunity overtime for that.

Bernie L. Colson – Oppenheimer & Co., Inc.

Okay. Thank you.

Operator

Thank you. Our next question comes from Daniel Guffey from Stifel. Please go ahead with your question.

Daniel D. Guffey – Stifel, Nicolaus & Co., Inc.

Just one from me, guys, do you think the unconstrained production you guys are going to see in the wet gas window in the Utica, sometimes second quarter will be the main driver that closes the bid spread on that wet gas acreage and in addition, what else do you see closing that spread?

John B. Walker

This is John. I do think that in the second quarter, we will start seeing the potential of the wet gas window, as you’re aware compares themselves where there are some really good quality wells, but once those wells go into production, condensate drops out, they become 85% to 90% dry gas, whereas our projection based upon very limited production until this point and its Harrison and above will be the primary center of the wet gas production as well as wet gas process. And so we’re really in a very interesting point in the second quarter and the, production will be ramping up significantly, if there will be basically quadrupling over the course of the final three quarters of the year. And so that has the potential not only to generate the revenue in production, but maybe, it’s important to us able to substantiate the value of the Carroll County or the midstream that’s been utilized in the heart of that wet gas.

Daniel D. Guffey – Stifel, Nicolaus & Co., Inc.

I guess the follow-up in Carroll County of the 21 gross wells you guys have drilled or participated excuse me, to-date and 16 in 2013, how many of those are in that Carroll County acreage?

John B. Walker

Well, by far the majority has been drilling of the Chesapeake joint venture has been in Carroll County. Columbiana and Harrison obviously are one or two, but Chesapeake is now this year starting to drill in the Baltimore window and other places too, so that would be…

Mark A. Houser

Yes Bernie perhaps or Dan sorry. Perhaps more important is I think I mentioned EnerVest has participated 352 wells in 11 counties, but most of that to-date has been in Carroll County, so there is a lots of activities that’s been there. Now that is actually starting to evolve a bit, Chesapeake is starting to drill in a few other counties and also moved some of their drilling back west more into what perceived as the oiler, part of the play that’s again as I mentioned we just drilled with Chesapeake our first well, I think it been completed right now in what we consider the oil window of the joint venture brand with Chesapeake.

Daniel D. Guffey – Stifel, Nicolaus & Co., Inc.

Thanks guys.

Operator

Thank you sir. We have no further questions at this time, please continue with any further points you wish to raise.

John B. Walker

Okay thanks Kirsten and we appreciate all of you joining us on the call. We do believe that we are entering a very important period for not only EVEP, but the industry in the Utica, we are optimistic that this will be a very good year for us. If you have further questions, please give us a call when we return to Huston and thank you and have a good day.

Operator

Thank you ladies and gentlemen, that concludes today's EV Energy Partners’ fourth quarter and yearend 2013 earnings conference call. Thank you for participating, you may now disconnect.

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