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

Q4 2012 Earnings Call

March 01, 2013, 09:00 am ET

Executives

John Walker - Executive Chairman

Mike Mercer - SVP & CFO

Mark Houser - President & CEO

Ron Gajdica - SVP, Acquisitions

Analysts

Ethan Bellamy‎ - Robert W. Baird

John Ragozzino - RBC Capital Markets

Kevin Smith - Raymond James

Michael Peterson - MLV & Company

Praneeth Satish - Wells Fargo

Noah Lerner - Hartz Capital

Brett Reilly - Credit Suisse

Operator

Ladies and gentlemen welcome to the EV Energy Partners’ Fourth Quarter Earnings Conference Call on 1, March 2013. For today’s presentation, all participants will be in a listen-only mode. After the presentation, there will be an opportunity to ask questions. (Operator Instructions)

I will now hand the conference over to John Walker, Executive Chairman. Please go ahead, sir.

John Walker

Thank you. Good morning everyone. I am in Abilene, Texas and the rest of our management team is in Houston. Thanks for joining us today.

Before we get started, I would like to direct you to the slide deck we will be referring to during our call this morning. You will find a PDF of the presentation on EV Energy Partners’ website under Investor Relations, Presentation and Events schedule. The web address is www.evenergypartners.com. You may want to take a moment to go ahead and open those slides.

Please note, our Safe Harbor clause on slide two and we will be making forward-looking statements.

I am going to defer comments on our fourth quarter and full-year 2012 results and move directly to an update on our Utica sale process. We opened the data rooms to sell our operated acreage this past summer. After obtaining additional drilling results we took bids in late October. There was one bid on the overall core position, multiple bids on four packages as well as individual bids on some of the counties.

As a reminder, EnerVest and Chesapeake have the largest blocks of acreage in the wet gas and volatile oil windows. We were initially offered several properties in exchange for some or all of our Utica holdings. Our valuation of the exchange properties from potential buyers was below the expectations of the parties offering those properties.

Therefore a deal was not going to be reached in exchange for those properties. We reverted to all cash offers with a confidence that we could complete a 1031 tax free exchange through EnerVest drop-downs or third party acquisitions. We spent considerable amount of time on a large transaction for most of these counties and that negotiation is still showing progress. In addition, we have reopened negotiations on two Northern counties with multiple parties. Some companies continue to press us into selling individual counties which may do if the price is right.

I want to share with you that I am disappointed that we've not executed the purchase and sale agreement yet. Fundamentally, the bids have to meet our expectation county-by-county and terms must also be acceptable and must conform to standard industry terms. I am leading the negotiations with a highly experienced team and I want to repeat we're not going to do a transaction that does not deliver an attractive price and acceptable terms. We will announce each deal as it is signed, but I believe that the process could take anywhere from a month to the remainder of the year. Believe me; I am spending an overwhelming amount of my time on this important process.

In my view, development drilling in the wet gas window continues to demonstrate ever increasing flow rates and steadily decreasing cost to develop. All existing wet gas pipelines are full; awaiting the delayed start-up of the Natrium plant in West Virginia. In addition, by early summer, UEO, Buckeye in which we own a 21% interest and a MarkWest plant, both will be processing and fractionating the NGL stream. Thus far, the industry is committed approximately $6 billion to the Utica Midstream infrastructure and that was prior to Kinder Morgan’s recent announcement of a possible processing and fractionation facility in Tuscarawas County.

By being patient, we believe that we will be able to demonstrate to that the sale of the approximately $100,000 networking interest acres being offered should enable us to use the proceeds to purchase assets on a tax free, equity free, debt free basis. We will have at least 70,000 more acres to sell, retain or exchange in Ohio and Western Pennsylvania.

The EVEP investments in Cardinal Gas Services and UEO Buckeye processing and fractionating systems will offer steady, but rapidly growing EBITDA to our entity. We expect that the Midstream will generate $50 million to $70 million pre-year in EBITDA once it's up and running. The approximate 2% over write in about 880,000 acres in Ohio could generate in excess of $50 million pre-year within five years. In Utica, we will just keep on going. And then it's our job to continue to position the company in other attractive basins.

Relative to our fourth quarter, we exceeded guidance. This was done with very little on the way of producing property acquisitions last year and with reduced capital expenditures, because of wet gas process and natural gas liquid process.

EVEP and EnerVest had good finding cost, lower LOE, lower drilling inflation cost and steadily better results from our major basin, the Barnett Shale which Mark will talk about a little bit later. In a few minutes Mark will discuss all of our operations, but first I want to turn it over to Mike Mercer who will provide an analysis of our financial results. Mike?

Mike Mercer

Thank you, John. I am going to review our results for the fourth quarter and full-year and summarize our guidance for 2013. We will also discuss our recent additions to our natural gas and crude oil hedges.

For the fourth quarter, adjusted EBITDAX was $69.6 million which is a 28% year-over-year increase primarily due to acquisitions completed during the fourth quarter of 2011 and a 3% increase over the third quarter of 2012. Distributable cash flow for the quarter was $37.9 million, a 23% increase year-over-year and a 7% increase over the third quarter. Distributions for the fourth quarter which were paid on February 14th or $33.4 million.

For the fourth quarter, production was 10.8 Bcf of natural gas, 277,000 barrels of crude oil and 476,000 barrels of NGLs or 15.3 Bcfe. This is a 38% increase from the fourth quarter of 2011 of 11.1 Bcf, once again primarily due to the acquisitions we completed during the fourth quarter of 2011 and a 2% increase from the third quarter 2012 production of 15 Bcfe.

Our fourth quarter net loss was $9.9 million or $0.23 per basic and diluted weighted average LP unit outstanding, but there are several items I would note that were included in that loss. The $9.6 million of unrealized losses on commodity and interest rate derivatives, $0.6 million of non-cash realized losses related to commodity industry derivatives, $1.1 million of dry hole and exploration costs, $4 million of non-cash compensation related costs contained in G&A and $16.7 million of impairment costs primarily related to writedowns on our East Texas natural gas assets due to declines in natural gas prices.

Now for full year 2012 results. For 2012, adjusted EBITDA and distributable cash flow were $267.5 million and $142.4 million respectively. These were increases of 26% and 13% over 2011, once again primarily due to two Barnett Shale acquisitions we completed during the fourth quarter of ’11 and distributions related to the full-year 2012 were $132.4 million as compared to distributable cash flow of $142.4 million.

For 2012, production was 42.5 Bcfe of natural gas, 1.1 million barrels of crude oil and 1.7 million barrels of natural gas liquids, or 59.6 Bcfe. This is a 45% increase over 2011 production of 41.2 Bcfe primarily due to fourth quarter 2011 acquisitions. 2012 net loss was $16.3 million or a loss of $0.38 per basic and diluted weighted average unit outstanding, once again several items to note in that $16 million loss were $48.3 million of unrealized losses on commodity and interest rate derivatives, $2.6 million of non-cash realized losses related to commodity and industry derivatives, $1.7 million of non-cash charges related to lease operating expense. It had to do with oil and tanks purchased in connection with 2011 acquisitions, $6.8 million of dry hole and exploration costs, $16.4 million of non-cash compensation related costs contained in G&A as well as $1 million of due diligence and other transaction costs for acquisitions completed in 2011 that were included in G&A and finally completed in 2012.

$34.5 million of impairment charges primarily related to writedowns as I mentioned earlier in the fourth quarter on East Texas properties and in the prior quarter on mid-continent natural gas assets and finally $0.8 million of non-cash deferred income taxes. Now what I would like to do is turn to our Utica Midstream investments.

At the end of 2012, we completed an agreement to increase our investment in Utica East Ohio from 8% to 21%. UEO which is operated by Momentum with Access Midstream as the other investor is constructing processing, fractionation and storage facilities for Utica Shale production.

Our other Utica Midstream investment is Cardinal Gas Services in which we own a 9% interest with Access Midstream as operator and Total as the other investor. Cardinal or CGS is constructing an operating and gathering system in the Utica. Mark Houser will go into more details in his review but I would like to point out to you that there is additional information on both UEO and Cardinal assets and as well as expected investment in cash flow levels contained in the accompanying slide presentation that is available for viewing or download on our website.

As you can see, we're making a large midstream investment in the Utica Shale which we expect to generate significant cash flows and distributable cash flow per unit, once these assets are fully in service.

Now with regard to guidance, we’ve also published detailed guidance by quarter for 2013 in the press release and also have an annual summary in the slide deck. I will move into each guidance by quarter but some of the highlights on an annualized basis are as follows. The production guidance range for the year is a 154.2 to 168.7 million cubic feet per day.

Natural gas and crude oil price differential estimates range versus NYMEX are 92% to 98% for crude oil and 93% to 100% for natural gas. Net transportation margin for third-party volumes is 1.6 million to 1.8 million. Lease operating expenses which includes gathering and transportation cost on our properties are 95 million to 105 million.

Production cash as a percentage of revenue are estimated to 3.9% to 4.2%. Cash, G&A expense, which excludes any potential acquisition related due diligence and transaction expenses is $21 million to $24 million. The first quarter reflects a slightly higher relative cost on cash G&A due to cash cost that we have related to annual restrictive unit investing in January as is typical each year.

In addition, our expected share of EBITDA from our Utica Shale midstream investments that I discussed as well as a small amount that will begin to get from our overwriting royalty interest range is from $6 million to $10 million. E&P capital expenditures are projected at $90 million to $110 million, which is down from last year and does not include any amounts for acquisitions of oil and gas properties.

Midstream CapEx related to UEO and CGS, our Utica Midstream investments is estimated $230 million to $250 million. As you can see if you look on the slide presentation, 2013 is expected to be by far the peak CapEx year for these investments and we would expect to have over two-thirds of the plan capital on these investments spend by this year end.

With regard to hedges, over the last few months we have add a significant increase in our future natural gas, there has been a significant increase in future natural gas in crude oil prices over those that prevailed earlier in 2012 and in January we entered into additional hedges for 2014 and 2015 and you can see in the press release those specific additional hedges that we put in place since the end of the year as well as our current hedge position as of the end of February.

What I would like to do now is turn it over to Mark Houser for review of our year end reserves and our operations.

Mark Houser

Thank you, Mike. And I apologize in advance for my (inaudible) I got to Houston winter cold. Over the next few minutes, I plan to discuss our overall reserves, our 2012 and early 2013 operating performance outside the Utica and our operating plans for 213 over 2013 overall. I’ll then spend sometime updating our Utica acreage position discussing Utica operational activity and provide more detail on our midstream activity in Ohio. The presentation hopefully will give you more color and how we are capturing opportunities in the Utica.

Our SEC year end proved reserves are 905 Bcf equivalent of which 33% of oil and natural gas liquid, 67% are natural gas. Our reserves are 76% pre-developed with an RP ratio of over 15 years. Last year, we were 29% oil in NGL and 68% pre-developed and had an RP ratio over 18 years. The prices used in determining our SEC estimate in that proved reserves.

At year end, we were 94.71 for barrel of oil and $2.76 from per million BTU of natural gas. The 276 was 32% lower than last year’s SEC price of 412. The decrease in natural gas and NGL prices from 2011 to 2012 has significant impact on our estimated net proved reserves at year end 2012.

These price changes caused reserves to decrease by 270 Bcf or 23.6% from 2011 to 2012. On a price neutral basis, EVEP is estimated net proved reserves at December year end would have increased by 2.6% over year end in 2011 reserves. On a net same price neutral basis, our reserve replacement ratio was 157% of 2012 production. Oil and reserve replacement cost for 2012 again on price neutral basis were $1.78 per Mcf equivalent and for the past three years have averaged a $1.38 per mcf equivalent.

Now looking at production and operating expenses, EVEP’s net production increased by about 4% from January to December and was within our projected guidance range despite investing about 13% less in upstream capital than anticipated. Most of this growth was attributable to the Barnett Shale which had a production increase of over 10% during this period. 2012 lease operating expenses were 3% below budget and $104 million. These savings were led by the Barnett Shale and the Austin Chalk. Operated and direct lease operating expenses was below budget on the majority of EVEP’s assets for 2012.

Now looking at capital expenditures, 2012 upstream capital expenditures were $130 million or $30 million under our original midpoint of guidance. As activity slowed down in the Mid-Continent and Austin Chalk areas due to low natural gas and NGL prices. Our largest CapEx program was in the Barnett where we spent $68 million. This resulted in 70 gross wells or 21 net being drilled versus our 90 gross wells we originally planned.

We also shifted our capital from the dry gas in the southern areas to the more liquids oriented areas primarily in Montage and Wise counties. Drilling days in the overall Barnett dropped from 13 to 11 days during 2012, an 11% improvement. Drilling days in the combo area dropped from 19 to 14 days and two of our last four combo area wells were drilled in under 10 days. Completion costs dropped in the overall Barnett by 11% during 2012 mainly due to lower frac costs and we see that trend continuing.

Barnett well performance has been quite good with fourth quarter wells turned in line having initial 30 day rates that were 16% higher than we at AFP across the Barnett. In the Austin Chalk we drilled seven gross wells during 2012. Our latest multi-stage frac well, the Bowen Ranch well which was spurred in the fourth quarter is currently flow testing over 600 barrels and 1300 Mcfe a day, greater than 2700 Psi flowing pressure of low grade well.

We used packers plug and purp on this which is a little bit different than we've been using and we are really encouraged by that and intend to apply that on some additional locations. We also invested $111 million in acquisitions during the year. Of this $36 million was spent on follow-on acquisitions in the Barnett Shale and Mid Con and $75 million after purchase price adjustments was used to purchase Utica acreage. This Utica acreage provided a more attractive overall package of operating acreage within the portfolio and it is part of the acreage currently being marketed.

For 2013 we will stay focused on our 20% hurdle rate on IRR and are targeting up to a $110 million for E&P capital of which about $90 million will be spent on drilling and completing a 156 gross wells. Of that $90 million $66 million will be for drilling 70 gross wells in the Barnett. The remaining capital will be somewhat evenly distributed between our other wells in the Austin Chalk, Mid Continent and Conventional Appalachia. These areas particularly the Chalk where we control over 800,000 gross acreages could also provide additional growth opportunities in the Eagle Bond, Eagle Ford and [Taylor Sands].

Now moving on to the Utica; overall EVEP owns over 170,000 acres in Eastern Ohio. In Northwestern Pennsylvania that lies within publicly defined Utica windows. To provide more information for you, we have divided this in to two separate areas. Slide five shows the approximately 100,000 acres that EVEP is currently marketing and is in various stages of negotiations at this time. Putting in to perspective, that's within a total of 335,000 being marketed by the total EnerVest group of companies.

Slide 6 highlights the EVEP operating acreage that is not currently being marketed, which includes 17,000 net acres in Pennsylvania as well as our non-operating acreage in Ohio. Our plan for our retained operating acreage are to monitor industry development in and around our acreage positions and to strategically drill and/or monetize as appropriate. EVEP’s non-operating position is about 16,000 acres, mostly within the Chesapeake, Total and EVEP EnerVest joint venture. That position has given us great insight in to the Utica.

Please refer to the slide 7. In addition to our working interest ownership in the acreage I just described, we also hold an overwriting royalty interest in roughly 880,000 of gross acres of Utica shale properties in Ohio. Our overwriting interest averaged 2.7% on approximately 415,000 operating gross acres and 1.3% on approximately 465,000 non-operated acres. As John described earlier, these overrides can create significant cash flow over time.

At this early stage, it is challenging to forecast the timing and success of development wells. Most of the drilling activity is occurring in the wet gas window. Therefore if you assume only 75% of the window gets developed under modest development condition and use current type curve economics, we estimates these overrides could generate 50 million of EBITDA in the five years, which John mentioned earlier. Again this assumes no value for any acreage other than the wet gas and is based on about drilling about 60 wells a year on this acreage.

Putting in perspective, Chesapeake is drilling 370 wells in just the next two years. Contributions from other product windows could make cash flow even higher. Now looking at Utica activity, as you can see in slide 8, industry activity has been increasing all over the Utica, where there are currently around 30 rigs running, over 500 permitted wells and around 250 wells spud.

Most of the activity has been focused on the wet gas window. Chesapeake remains most active operator having permitted over 330 wells and has or is currently drilling a 174 wells. Most of the activity has been in the joint venture between us, Chesapeake and Total and EnerVest. Chesapeake has operated in the JVs about 133 wells in 2012, it expects spud around 240 wells in 2013. They have 15 rigs running in the first quarter 2013 and will have 16 rigs running for the remainder of the year. Their drilling efficiency continues to improve and drilling time has continually decreased and lateral link has been increasing. 36 wells in which EnerVest has an interest are currently shut-in and many more of that EnerVest does not have an interest in we understand are waiting on processing capacity to become available, when the Dominion Natrium plant opens in April.

Further local processing capacity will be available in June, when the Utica East Ohio facilities are available. I will seek more about UEO in a moment. Geographically Chesapeake has been focused on Carroll County; however the Permian activity has expanded north into Columbiana and south to the boarder with Harrison County.

Utica development activity has also increased in the southern portion of the [play] with Gulfport, Antero and PDC announcing good results on several new wells in the oil and gas window. Other operators are also ramping up activity in the south, including Hess, XTO and CNX.

The expansion of the Utica drilling activity to the west in to the [Lydall] window has been measured. CNX has permitted six wells in the west Tuscarawas County and has drilled three of them so far. EVEP has a working interest in one this wells, which has been completed but not turned in line.

The other wells are in various stages of drilling and completion with the exception of one well with reported flow test result of the peak rate of 400 barrels accrued per day. In the northern part of the play, several companies have been active. BP acquired approximately 80,000 acres last year in Trumbull and Mahoning and is preparing its first drilling unit.

Halcon has drilled four well in the Pennsylvania Utica and has permitted an additional two wells in Trumbull County, Ohio. Hilcorp., Chevron, Range and Shell have also drilled in the Pennsylvania Utica. Now following up on John’s opening remarks, I would like to spend some time briefing you on our Utica midstream investments and strategies going forward.

As many of you know processing and fractionation assets are new for us. We are making these investments because we believe they will generate a predictable cash flow stream, good rates of return as well as being complementary to our Utica acreage position. These investments should meaningfully add to our future EBITDAX and distributable cash flow per unit. The next few slides will highlight these two investments.

As you can see on slide nine EVEP owns 21% interest at UEO which is a high pressure gathering processing and fractionation system that will be capable of processing 800 million cubic feet per day of wet gas, fractionating 135 barrels per day of NGL and have onsite storage of about 870,000 barrels of purity components. This is the largest processing and fractionation project so far in the Utica Shale.

As Mike mentioned, we increased our ownership from 8% to 21% by committing some of our operated acreage to the facility. Momentum, a very experienced midstream development company is the operator and 30% owner. Access Midstream Partners holds the other 49%. Because UEO generates revenues based on feed, it is not directly subject to commodity price fluctuation. The contracted fee structure includes the find fees for gathering, processing, transporting and fractionating.

Most of the 900,000 plus acres dedicated to the UEO system are controlled under our joint venture with Chesapeake, Total and EnerVest and the production is delivered through Cardinal Gas Services. Start-up of the first 200,000 Mcf per day wet gas processing train at the Kensington plant and the first 90,000 barrels per day of fractionation capacity at the Harrison Hub fractionation complex is planned for mid-year.

The second and third 200 million Mcf per day trains at Kensington should be operational by year end and the 200 million per day Leesville plant and incremental 45,000 barrel per day of fractionation capacity at Harrison should be in operation by mid-2014. The associated storage at the Harrison Hub fractionation complex will be in concert with the processing plant. The system maybe further expanded if additional acreage is dedicated or volumetric guarantees are committed by other operators or if the forecasted throughput exceeds the system capacity. This expansion potential offers future upside at low incremental costs.

Turning to slide 10, EVEP owns 9% of Cardinal Gas Services or CGS which is a low pressure gathering system currently in service and under expansion. CGS gathers gas from our joint venture with Chesapeake, Total and EnerVest and has the ability to deliver that gas into the UEO system. Access Midstream is the operator with the 66% share and Total holds the other 25%.

We are already generating EBITDAX under a cost of service agreement where CGS collects gathering fees that are reset annually to meet our fixed internal rate of return and is therefore not directly subject to commodity price fluctuations either. There is also upside potential on CGS as the joint venture drilling activity increases.

As you can see on slide 11, EVEP estimate that share of the total net capital for these two midstream projects to be between $335 million and $395 million with $230 million to $250 million budgeted to be spent this year. We project these investments will generate $50 million to $70 million of EBITDAX per year once both system are complete and fully operational, and to be accretive to distributable cash flow per unit.

So as John said earlier, along with our acreage, we have significant exposure to the Utica through our Midstream investments and overwriting royalty interest. We intend to develop and manage these assets to realize the greatest value possible for your unitholders.

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

John Walker

Thanks Mark. I wanted to clarify on the processing of UEO; it’s 135,000 barrels a day, right Mark?

Mark Houser

Yes.

John Walker

Okay, thank you. In closing, I want to reemphasize the steps we're taking to unlock the value we're creating for our unitholders. Again, we intend to complete the sale of our 100,000 net working interest Utica acres so that we can reinvest the proceeds in to cash generated assets and a tax free, equity free and debt free transaction. We also have at least 70,000 acres to sell, retain or exchange in Ohio and Western Pennsylvania and we believe that our overwriting royalty interest in the Utica play would generate significant cash flows. In addition, both Cardinal gathering and UEO processing and fractionating systems will provide long-term cash flows that are not directly related or subject to commodity, price or frac spread movement. Going forward, we believe that the future is bright for EVEP as we capitalize on these value added opportunities while pursuing a fundamental strategy of acquiring reserves to replace our production and grow our distributable cash flow per unit.

Operator, we are now ready for questions.

Question-and-Answer Session

Operator

Thank you, sir. (Operator Instructions) The first question comes from Ethan Bellamy from Baird. Please go ahead.

Ethan Bellamy‎ - Robert W. Baird

Hey good morning guys. What's in the bid out spread on the cash offers right now; is it concerns on geology, the locations, the commodity prices title or what’s the delta between you and the bidders?

Mark Houser

Ethan, we are not going to really comment on price or additional details as we are in active negotiation and we just don't think that’s prudent to do in a public market.

Ethan Bellamy‎ - Robert W. Baird

Okay. For the asset exchange you looked at, how long did it take you to diligence those assets and was that a good face bid, or are they been crafty, where was the valuation gap?

Mark Houser

We are not going to comment on, well, go ahead John.

John Walker

Yeah, I will take that for a second. I think that were good type of offers, but in terms of and there were some good properties in that process, but from our standpoint it’s just like buying assets, we can't pay two, five and six for assets and deliver return and some of these folks just wanted too much money.

Ethan Bellamy‎ - Robert W. Baird

Okay.

John Walker

And then the problem of doing a transaction where you are trying to do an exchange is you are really doing two deals and we just finally decided we would revert to all cash offers because it was too hard trying to take two deals rather than one complex deal.

Ethan Bellamy‎ - Robert W. Baird

Okay. So John the legacy kind of core growth strategy of drop-downs in third party A&D has really been on a hold for sometime during this monetization process; is there some point if you don't get what you want for the acreage that you kind of revert to that strategy?

John Walker

Well, we listen to our unitholders in deferred acquisitions last year, as we pledged that we would and as we said we are in active negotiations, so I expect to see results from that and as I said, I am disappointed that we haven't been able to report those yet.

Operator

Thank you. The next question comes from John Ragozzino from RBC Capital Markets. Please go ahead.

John Ragozzino - RBC Capital Markets

Can you comment a little bit on the current supply and demand bounce for acreage in the Utica and particularly with the details in terms of the total amount of acreage being packaged or bring to market currently?

Mark Houser

Yeah, this is Mark and I’ll take that, I guess generally in the what appear to be more active areas there is actually a limited amount of the very active dynamic wet gas window in particularly and even in for oil window, there is really a limited amount of acreage for sale, as we understand and most of the larger packages are further out West.

John Ragozzino - RBC Capital Markets

Okay. And looking at reserves a reduction there based on gas rights; do you anticipate any potential reductions in the borrowing base associated with that as they just look at the collateral?

Mark Houser

We are in the process and will be going through – resuming a borrowing base review over the next month or so, and generally what we are seeing as we haven't seen a change in price decks from what we have seen so far versus our last review, and commodity prices have held natural gas prices have held reasonably well.

Operator

Our next question comes from Kevin Smith from Raymond James. Please go ahead.

Kevin Smith - Raymond James

Thanks for all the updates. Mark, can I talk about your rig count assumptions to how we get to the overwriting royalty interest, do you have similar kind of assumptions for midstream that you can walk us through?

Mark Houser

Ron Gajdica is here and he’s been really our guy doing the analysis on the Midstream and on our override. So I'll let him take that. Ron maybe first on the override rig activity and the next on kind of our schedule for our Midstream.

Ron Gajdica

Kevin on the override you are correct that a drilling plan assumption has to be assumed and we have assumed what we think is a fairly conservative drilling plan and but obviously that is subject to anybody’s guess as to what the drilling activity will be over a 10 to 15 year period. So there's quite a bit our subjectivity to that.

Regarding the part of your question on UEO development plan assumptions we are relying on the operator forecast and we are not making our own (inaudible) forecast, we are just relying on what the operator is providing to us to make our projections. And it seems to be a reasonable forecast but once again subject to lots of uncertainty at this early stage in the development of the play.

Mark Houser

I guess just one comment on that is most of that production is tied to the Chesapeake joint venture and that Chesapeake has some financial commitments relative to drilling activity which they are actually exceeding…

Ron Gajdica

For a period of time.

Mark Houser

For a period of time.

Kevin Smith - Raymond James

Okay, in most of the production both on the royalty interest and the Midstream assets?

Mark Houser

That's for the midstream assets, the royalty is tied to anchorage all over the State of Ohio, it’s actually State of Ohio.

Operator

Our next question comes from Michael Peterson from MLV & Company. Please go ahead.

Michael Peterson - MLV & Company

I have a question regarding strategy, but I would like to begin by thanking you for the level of disclosure you included this morning and that's quite helpful. With regard to the Midstream, the materiality and the tenor of your investments that you detailed 2013 through ’16 suggest that you maybe heading towards a two segment business model, between upstream and Midstream operations. Any color you might be able to share on this strategy would be helpful?

Mark Houser

John, do you want to comment initially on that and I'll follow-up.

John Walker

Well, in some ways we've been in the Midstream business from inception and we have gathering systems in other areas but we are not in processing and fractionating in other areas and the reason that we were interested in having a significant ownership interest in both gathering as well as processing fractionation was because it was tied to our assets and we believe that its extremely attractive and offers us all kinds of options.

You know, cash flow is very steady and the returns are very good and it’s complementary to what we are doing but do not interpret this as EVEP becoming a Midstream company. We will possibly continue to have gathering systems and things of that sort and if processing plant is part of an acquisition or part of assets we will be doing that but we don't plan on going out and buying, processing and gathering assets as part of our acquisition program.

Mark Houser

Just one other comment on that is that part of the reason we're willing to make investment is that we have a lot of confidence and momentum which is the developer of these asset, they have great track record at building successful Midstream facilities overtime and we feel very good about that investment opportunity.

Operator

Thank you. Our next question comes from Praneeth Satish from Wells Fargo. Please go ahead.

Praneeth Satish - Wells Fargo

Just wondering on the midstream side whether you could talk about the competitive landscape in the Utica, I mean, what's the likelihood of further expansions there above what you have announced and what kind of returns should we expect on any incremental capital that you spend there?

Ron Gajdica

There are a number of entities that are either committed to or contemplating building a Midstream infrastructure to service the Utica production and that would include both processing and fractionation and transportation. Obviously, our Utica East Ohio processing and fractionation project will be so far the largest in the Utica but there are others that have been announced.

Several companies have made press releases about their plans to build infrastructure. I think when you put it all together, we mentioned that there was about $6 billion being invested in Utica Midstream at this point in time, which is very significant and I think that there will be plenty of processing and fractionation capacity to handle the upstream production volume.

We do have dedicated acreage to the Utica East Ohio systems. So we feel comfortable there are facilities will be closed to full if not meaning to be expanded overtime. There are a number of additional business development opportunities that momentum operator is pursuing, which should just add to the economic value of our investments. So yes, there is competition but we feel good about our position and what we have contractually locked in to our position.

Mike Mercer

The problem right now is that wet gas lines are full and Natrium of course is significantly delay and so if new Utica well wet gas comes on it's backing off something else. And so until Natrium is on and UEOs on etcetera, you really can't determine doing much about production from even the wet gas segment, which is de-risk at this time actually improving as I said but we just need some processing and fractionation and that’s what we are waiting now.

Praneeth Satish - Wells Fargo

Thanks great. And just one more from me, do you have an estimates for maintenance CapEx in 2013? I didn’t see that in guidance table.

Mike Mercer

We don't publish maintenance capital ahead of time. It's something that we review each quarter, as we move to quarterly results with our board. So, it will although I believe that we, if you look at us and know us historically we have had a relatively consistent policy.

Operator

Thank you. Our next question comes from Noah Lerner from Hartz Capital. Please go ahead.

Noah Lerner - Hartz Capital

I guess, I just want to make sure. I understood some of the comments that Mark had made regarding the acreage its not being marketed, to-date my recollection was that to plan was that once that first package is resolved to go actively market those, it seems like a minimum debt whole process has been delayed into at least 2014 and we might decide to actually hold on some of that, is that a fair take away from the comments?

Mark Houser

No, it is not true, yeah John go ahead.

John Walker

Yeah, I mean, I think I have tried to give us a room okay, amongst to the remainder of this year in terms of the expected sales of our operating position. And so we are in active negotiations right now and we anticipate selling some or all of that position this year.

Noah Lerner - Hartz Capital

Right, no I was referred to the non… process start and it was supposed to a tier process once the operating that --- there has been a slight and delay in the non-operating parts

John Walker

Yeah, because we focused on the operated and we have had focus through non-op (inaudible) we are having casual discussions and we will focus on that as we complete working interest for the operated part, but I think it’s possible that we can get that done this year also.

Mark Houser

Yeah, John, well for EVEP 70,000 we are calling not being marketed currently acreage most of that is operated and some of that is now again in Pennsylvania as well. A couple of things that are happening is as we go through this process, some of the potential, some of the bidders are actually interested in buying perhaps op and non-op and (inaudible), so that is being looked at. So as John said we have active activity going on relative to sell. We are not contemplating any sort of interest in really retaining this acreage over time, we are just again trying to manage it for the best price and letting some of the play kind of comes to us in some of the areas.

Noah Lerner - Hartz Capital

I guess the other question is with $250 million of pending CapEx this year for the build out of the Midstream, I'm going to take a wild guess and presume at this point that there will be some equity that might need to be raised. And I'm just curious based on the fact that we really haven't seen any material distribution increases over the last three years or so, I'm just curious if management is inclined to recommend to the Board some type of idea or waiver or any new units issued until we get more clarity on some of these sales of the land packages.

Mike Mercer

I guess I would note that right now the general partner is receiving 2%, minimum 2% of the distributions currently so there's no IBR payment currently being made. And you are right we do have a significant amount of capital this year that's going into the midstream. But as you can see from the slides, it will start to generate some pretty significant cash flow here starting next year and ramping up over the next year or two. As far as future distribution levels and all of that, raises in distributions that's something that we don't typically comment on until we actually announce the distribution change.

Mark Houser

And our plans remain the same in terms of monetizing some or all of this Utica acreage to help in terms of the funding of future activities.

Mike Mercer

Yeah, in price Noah, I mentioned equity free, we sell the Utica there's no need to go into the equity market.

Operator

Our next question comes from Brett Reilly with Credit Suisse.

Brett Reilly - Credit Suisse

So quickly on the $75 million that you spent to purchase the acreage in the Utica, could you give a little color on how many acreages were purchased and maybe the location of those acres.

Mark Houser

We will not comment on how many acres were purchased. It’s a competitive thing. It is within the kind of east central Ohio area, but we are not going to comment on that again for competitive reasons and the 75 is the same number as the 83 million we talked about previously, there's been some purchase price adjustments through normal due diligence.

Brett Reilly - Credit Suisse

Could we read into the bump in Utica acres to 170,000 from 150,000 is kind of the number that you purchased.

Mark Houser

No, that's part of it, but again we also had some acreage in other places that we really haven't talked about before that we've now brought in so no you can't read into that the exact number.

Brett Reilly - Credit Suisse

And then quickly sort of back to financing, can you talk a little bit about the change in the debt covenant in the 10-K.

Mike Mercer

Sure. We recently negotiated a change in our debt covenants that runs due March 30 next year to provide the senior secured debt-to-EBITDA ratio of 3:1. As we had mentioned earlier in the call several times, we are making significant investments in the midstream this year that won't generate cash flow until really beginning in 2014 and beyond but that has significant value to it and we are also in the current process for monetizing a large part of our acreage, which as John said, we do expect to complete this year. So that was the reason for the changes. We have some debt funding on that midstream, and the amendment was recently completed with a 100% approval from our banks.

Operator

Thank you. We have a follow-up question from Ethan Bellamy from Baird. Please go ahead.

Ethan Bellamy - Robert W. Baird

The Gulfport [western] transaction and roughly 10K an acre, is that a comparable transaction in your view; the Total deal was now pretty stale in the rear view mirror. I just want to see if that had any influence on valuation in your view?

Mark Houser

I think things evolve in market, Ethan, and we are not really going to comment on what the market is for given areas. We will understand this better as things move along in terms of development of the play. Certainly, some of the Gulfport wells and others in that area are encouraging but there are encouraging wells in other part that we really can’t comment on kind of valuations in that regard.

Ethan Bellamy - Robert W. Baird

Ken, wrote a pretty good article in the American Oil & Gas reporter about what the wet gas type curve might look like? Can you give us a sense of how many of those locations you might have in the Op and non-Op packages?

Mike Mercer

I guess really we cannot, generally speaking with a 5,000 foot lateral, a drilling unit would encompass approximately 138 acres per well and you can do the math of taking gross acres and dividing by a 138 to get a number of gross well locations. Obviously, there is some inefficiency in the formation of drilling units, not every acre will get included in a drilling unit. But that’s about the best you can do in terms of forecasting number of wells over a 10 to 15 year period. No company has drilling plans beyond the next year or two that have been publicly or even privately summarized. So you just have to look at acreage numbers and make your own projection from that.

Operator

Thank you. You have a follow-up question from John Ragozzino from RBC Capital Markets. Please go ahead.

John Ragozzino - RBC Capital Markets

Just going back to some of the comments you made on the nice drilling efficiency gains you saw on the Barnett. When you consider some of the softness in the service cost environmental and a lot of its dry gas shale plates and combine those with some of the self made gains you are seeing on the drilling side. What do you think as far as additional cost savings and what is that ultimately take some of the IRRs economics of these wells?

Mark Houser

Well so far the air is that we are focusing on or kind of Wise and Denton, Montague, Parker, Tarrrant and Hood and the liquid areas and even combo areas. And again we are seeing as I have mentioned we have a kind of a minimum hurdle rate of 20% and in all those areas we are still seeing kind of hurdle, targeted AFPs and results that mere exceed those results. So I think costs are moving down, I think the part of the challenge is that they only move down so far before some of the service companies moves their assets to other places such as in the [Midland] Basin, which is that far away.

So we will continue to buy cost and continue to just hone in on trying to target areas that deliver that kind of return and so far our Barnett teams have done a great job in keeping our cost down through learning how to do it better and also through continuing to just work with the service company in terms of getting cost down.

John Walker

But Mark and Mike would point out that (inaudible) the service company but we were able to negotiate just because the scale that we have in Barnett, we were able to negotiate an extended term deal in the Barnett at very attractive frac cost?

John Ragozzino - RBC Capital Markets

So you are seeing some buoyancy in terms of rig rates and service cost just because of the proximity of the Permian?

Mark Houser

Well, you are just seeing some exit, we have seen some capacity exit from the Barnett to move to the Permian, now that being the case we still are able to negotiate the rates, the better rates that John alluded to.

John Ragozzino - RBC Capital Markets

Okay, and then one just final question, can you give us a quick update on how the Frank well is holding up and perhaps any other updates on any other noteworthy wells that have been drilled in the oil window recently?

Mark Houser

Well, we have really three wells EVEP does, the Habrun, the Franc and the Cairns. Well the Frank and the Habrun are both really kind of removed from infrastructure, we flow tested those initially but we are working on pipeline on those. The Cairns actually I was looking and Rex has made an announcement on a well in Carroll and we look back at o our 90 day rate on the Cairns, and the Cairns has a 90 day rate of about 864 Mcf a day residue and 168 barrels a day of NGL and about 200 barrels a day of condensate, which is about 512 Boe a today.

And Rex’s well was about 424 Boe a today for that 90 day rates. So that well looks like a good well and I want to reemphasize something John said, these are pipeline restricted right now because there is some back pressure. This general back pressure issue is tied to the lack of access of pipelines for NGLs right now.

So the Cairns well is doing well, the Habrun and the Frank’s really we just have the ability to pump them very much. They are both pumping oil wells but we haven't really gotten any good rates beyond the initial rates we mentioned. As I mentioned the oil window for a few reasons is just moving slower.

Operator

Our last question comes from Abhishek (inaudible) from Bank of America.

Unidentified Analyst

Just wanted to clarify something and correct me if I'm wrong but now I see part of the proceeds because your asset swap is off the table so I see part of the proceeds from Utica monetization going to some Midstream CapEx and/or maintaining distribution revenue, distribution level, or the company might have to issue equities. So how should I think about them?

Mike Mercer

No I don't think we ever stated that we would expect any proceeds from Utica acreage sales to go to the midstream. That's just being funded with under currently under bank borrowings. It’s more likely that we would do like kind of exchange on with producing oil and gas properties.

Unidentified Analyst

So you have enough liquidity to fulfill all the CapEx needs for the year and maintain the distribution level.

Mike Mercer

We project that we do yeah.

Operator

Thank you. I'll now hand the call back to John Walker for closing remarks.

John Walker

Well, thank you everyone. We enjoyed the call today and look forward to visiting with you in three months or earlier if we have significant announcements.

Operator

Thank you. This concludes the EV Energy Partners fourth quarter earnings conference call. Thank you for participating. You may now disconnect.

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