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Mid-Con Energy Partners, LP (NASDAQ:MCEP)

Q4 2013 Earnings Conference Call

March 5, 2014 11:00 AM ET

Executives

Craig George – Chairman

Jeff Olmstead – President and CFO

Nathan Pekar – VP, Business Development, General Counsel and Secretary

Randy Olmstead – CEO

Michael Wiggins – COO

Analysts

John Ragozzino – RBC Capital Markets

Ben Wyatt – Stephens, Inc.

Noel Parks – Ladenburg Thalmann

Operator

Good day, ladies and gentlemen and welcome to Mid-Con Energy Partners Fourth Quarter and Full Year 2013 Earnings Conference Call. At this time all participants are in a listen-only mode. Later we’ll conduct a question-and-answer session and instructions will be given at that time. (Operator Instructions). As a reminder this conference call maybe recorded.

I would now like to hand the conference over to Mr. Craig George, Chairman. Sir, you may begin.

Craig George

Thanks Syed and once again welcome to Mid-Con Energy Partners fourth quarter and full year 2013 conference call. Among those with us on the call today are Randy Olmstead, CEO; Jeff Olmstead, President and CFO; Mike Wiggins, COO; Dave Culbertson, Chief Accounting Officer; Nathan Pekar, General Counsel; Matt Lewis, Financial and Investor Relations Associate; and Krista McKinney, Investor Relations Associate.

As you all know we released earnings last night and we also released information about an acquisition on Monday. So we have several things to talk about this morning, including some detail about the acquisition and of course our quarterly and full year results as-well-as guidance for 2014. In just a minute Jeff will lead us through information about results, the acquisition and guidance and then we’ll open the call to questions.

If you would like to follow along with this PowerPoint presentation, just go to our website midconenergypartners.com, then in the Investor Relations section, click on Events and Presentations.

Before Jeff gets started I need to make a forward-looking statement comment, specifically that this call includes forward-looking statements, that is statements related to future and not past events within the meaning of Federal Securities Laws. Forward-looking statements are based on our current expectations and include any statement that does not directly relate to a current or historical fact. For further explanation you can refer to slide two of today’s presentation.

Now I’ll turn it over to Jeff.

Jeff Olmstead

Thanks, Craig. Good morning. Again if you are following live – following along with the presentation I will start on slide three with just of course introductory comments the end of 2013 and start of 2014 it was sort of an exciting time for us here at Mid-Con Energy Partners. We finished 2013 with our second consecutive year of 4% distribution growth while maintaining both conservative coverage and debt levels.

In addition earlier this week, last Friday we closed on our first acquisition or drop down through one of our affiliated entities Mid-Con Energy III. This was the first step of our 2014 growth plan that we target will be another year of approximately 4% distribution growth. As we will discuss in a few minutes this growth is expected to come from continuing to execute our long-term development plan for existing waterfloods and adding new properties through multiple drop down or third party acquisitions. Organic growth combined with acquisitions should allow us to meet or exceed or meet our targets for 2014 and leave with us a healthy balance sheet for continued growth beyond 2014.

With that I’ll jump into the presentation with the highlights from 2013 starting on slide three. Production for 2013 averaged 2,542 barrels of oil equivalent per day. This was a 33% increase over the 1,907 Boe per day in 2012. Production for the fourth quarter of 2013 averaged 2,543 barrels of oil equivalent per day which was an approximate 12% increase over the fourth quarter of 2012.

Net reserves as audited by Cawley, Gillespie increased by approximately 6% year-over-year from $13.1 million barrels of oil equivalent at December 31, 2012 to $13.9 million barrels of oil equivalent at December 31, 2013. The reserves were 98% oil and 76% proved developed as of 12/31/13 both on a Boe basis.

Adjusted EBITDA for 2013 was approximately $60 million which is a 26% increase from the $47.7 million in adjusted in EBITDA in 2012. And as I stated a few minutes ago our distribution rate increased approximately 4% to $0.495 per unit for the quarter ended December 31, 2012 to $0.515 per unit for the quarter ended December 31, 2013.

Finally we executed one bolt-on acquisition in 2013 with acquisition of additional working interest in Northeastern and Southern Oklahoma in May.

Moving to slide four, the earnings summary, starting on the right side of the slide with full year results; Again total production for 2013 was approximately 928,000 barrels of oil equivalent or 2,542 Boe per day which resulted in revenues from oil and gas sales including the effect of hedges of approximately $85.7 million. Total revenues, including the effect of hedges was approximately $86 million or growth of approximately 32% over 2012.

Production for the fourth quarter of 2013 was 243,000 barrels of oil equivalent or 2,543 Boe per day, which is a 12% increase over the 208,000 barrels of oil equivalent or 2,261 Boe per day in the fourth quarter of ‘12. This resulted in a $21.5 million in revenue before the effect of hedging and $21.7 million after the effect of hedging which was a 15% increase over the $18.9 million in revenues after the effect of hedging for the fourth quarter of 2012. And as you can see at the bottom of the slide EBITDA margins continue to be in excess of $60 per Boe as a result of sales coming from 99% oil.

Moving to slide five the production and this production and resulting EBITDA resulted in distributable cash flow of $12.3 million in the quarter for this quarter ending 12/31/13 and 49.1 million for the year ending 12/31/13 after subtracting tax interest expense paid and the provision for maintenance CapEx.

Total distributions for the year were $2.05 per unit while maintaining coverage around 1.2 times throughout the year. As the debate seems to continue in the market about how different partnerships calculate distribution coverage we state that Mid-Con continues to calculate the maintenance CapEx as the amount necessary to properly maintain injection across our wells over the long-term and growth CapEx as the amount necessary to spend to grow production reserves over the long term. We looked at several other methods to check to see that our numbers are in-line to make sure we’re not out of the ballpark with what we’re using.

Moving to slide six distribution history, total distribution increases since the IPO have been approximately 8%. As I stated earlier distribution rose approximately 4% in each of the last few years, we are just over $4 per unit paid in total all while maintaining healthy coverage and debt levels and we’re reiterating more of the same in 2014. The $2.05 per unit paid out combined with unit price appreciation resulted in 33% total return to investors in 2013.

Moving to slide seven we continue to maintain what we feel is a conservative balance sheet. At the end of the year we have liquidity of $39.4 million, including $38 million available under the revolver and $1.4 million of cash. The $14.4 million of EBITDA for the fourth quarter or $57.6 million annualized results in a debt-to-EBITDA of 1.94 times. And while this is getting to the higher end of our desired range I think you will see that our 2014 growth and acquisition plans include bringing this number down to more comfortable and historic levels for Mid-Con.

Our borrowing base was increased from $130 million to $150 million in November of ‘13 and at same time the maturity was extended to November of 2018. Our next scheduled borrowing base review is in April and we’ll provide an update after this is completed.

Looking to slide eight which outlines our existing hedge profile we did layer on some additional hedges in both ‘14 and ‘15 along with the acquisition we announced Monday, based on the midpoint of our 2014 guidance we had just over 80% of our expected production from our existing assets hedged in 2014 with an average swap price of $93.74.

In 2015 we have just under 20% of total production hedged for the year again, again based on the 2014 guidance midpoint. However, if you look at the details on slide 21 the appendix you will see that this – all of this hedging has been in the first and second quarters, so there is higher percentage in the first half of the year with no hedges yet in the second half of the year. We’ll continue to follow this closely we’ll layer on additional hedges in both the first and second half as we see prudent.

Looking to slides nine, ten and eleven, the capital expenditures we continue to be active in both drilling new producers and injectors and converting existing producers to injectors. Total CapEx for the fourth quarter was $3.8 million which included drilling three new producers and one new water supply well in Northeastern Oklahoma. We also converted four wells from production to injection, two in each Northeast Oklahoma and Hugoton areas.

Total CapEx for 2013 was $22.3 million which resulted in 31 new wells being drilled and 10 wells being converted from production to injection. This activity was spread out across three core areas as outlined in slide 11. We do still have several wells waiting on completion and permit but as you can see this number has come down considerably since the middle of the year and we expect to begin to see the benefit of all this work and this growth from the middle of 2014 and beyond.

Going to slides 12 to 13 you see a breakdown of year-end reserves, as audited by Cawley, Gillespie were 15.9 million barrels of oil equivalent, this again was a 6% growth in reserves over the year-end 2012 and reserves at the year-end were classified similarly as 98% oil and 76% proved and developed on a Boe basis.

The last couple of slides in our presentation relate to our growth plan guidance for 2014. We expect to continue to see production growth of our legacy assets as well as make acquisitions from both third-parties and from our affiliates. We are targeting another year of approximately 4% distribution growth while lowering debt-to-EBITDA to prepare for growth in 2015 and beyond.

Moving to slide 15 you see the capital budgets for the year, we expect to spend approximately $30 million of total CapEx. This includes CapEx from the assets acquired last week. This is broken down by both maintenance and growth CapEx at the right side of the slide and further broken down in to core area on the left side. This year you can see CapEx more evenly spread out across three core areas as we’ll see uptick in spending in Northeastern Oklahoma and both increase in injection in existing zones, recompleting some new wells in new zones and drilling producers and injectors.

Looking at slide 16 you will see we’ve completed our first drop-down that we announced on Monday, our acquisition from our affiliate Mid-Con Energy III. The acquisition closed last Friday February 28 and had an effective date of January 1st. We paid a total of $41 million for the properties. This consisted approximately $7 million of cash paid from drawing down on revolver and 1.5 million units with an approximate value of $34 million. The value of the units was based on the 21 day trailing volume weighted average price with a 2.5% discount.

The assets are all on our existing core areas with Ona and Midwell and Eva South all being in 20 miles of our existing assets in the Oklahoma Panhandle and the Walnut Hills being directly south of the Battle Spring unit in Southern Oklahoma. The Bivins Ranch waterflood is Mid-Con Energy Partners entering into Texas, to evolve into the partnership Mid-Con Energy operating has been developing this asset for several years and full time staff already looks after day-to-day operations there.

Some transaction metrics are highlighted on right side of the slide, average production 2013 was 349 barrels of oil per day or just under $120,000 per floating barrel paid. Estimated crude reserves as audited by Cawley, Gillespie as of December 31, ‘13 were just over 1.6 million barrels oil equivalent and were 79% proved developed and 100% oil.

Cash flows from these properties averaged approximately $625,000 per month in 2013 which results in roughly 5.5 times trailing 12 month cash flow being paid on the transaction. We expect some additional production growth in these assets in 2014 and ‘15 however at minimum cost as most of CapEx has already been spent prior to dropping them down.

We expect additional assets to be ready for drop down in the second half of 2014 although exact dates are not determined yet. Additionally we have seen an uptick in potential third-party assets that we’ve made bids on the last 60 days so we could see some additional third-party transactions prior to another affiliate directed transaction or drop down.

All this leaves us finally to looking at slide 17 as we’ve provided guidance for 2014. This is based on the existing assets in the partnership. This is not included in any expected growth from additional acquisitions or affiliates or third-parties. As you can see we expect production to average between 2,800 and 3,000 barrels of oil equivalent per day based on a full year basis, that also assumes the acquisition – the additional barrels from the acquisition as of March 1st.

We expect production taxes to be higher this year, around 7% of total revenue as the Oklahoma secondary tax credit has now expired for most of our existing assets. We also expect LOE on a per barrel oil equivalent basis to increase to approximately $20 per barrel of oil equivalent for 2014. We expect production growth from the assets to offset both the increases in NOE in production Texas as well as offset lower realized pricing as our hedges in 2014 are several dollars below what they were in 2013.

This is all expected to result in EBITDA of just over $6 million at the midpoint of the guidance range. Along with this guidance we expect to make additional acquisitions for affiliates and third parties that will allow us to grow beyond what we have presented here. We are targeting distribution growth of 4% for the year with the accretive acquisitions we expect to be able to lower debt-to-EBITDA by the end of the year and to be prepared for additional growth in 2015 and beyond.

That kind of summarizes our prepared comments and with that we open up to any questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from John Ragozzino from RBC Capital Markets. Your line is open please go head.

John Ragozzino – RBC Capital Markets

Hi good morning gentlemen.

Craig George

Good morning John.

John Ragozzino – RBC Capital Markets

I am sorry I may have missed this but can you quantify maybe the impact that was either associated with weather and also the transfer of several wells that went from producers to injectors?

Craig George

So the impact from weather like anybody we have – we operate in Oklahoma where it does get icy we get cold the impact was – we haven’t quantified but it was short in duration, we didn’t have weeks of downtime or anything of that nature so we haven’t gone out quantified what the impact was. It’s going to be similar to other operators in Oklahoma a day here and there but nothing significant.

In terms of the effect of converting producers to injectors we’ve never quantified that because it can be misleading answer. As I tried to describe on the conference call last time that I did a very poor job of explaining to you, as those wells go up and down in total fluids depending on where the water roll back is, yes we might be giving up some production today but then you are getting in another well in a different part of unit at a different time. I think as we get into our Analyst Day in a couple of weeks with maps, and when Mike goes into kind of the fundamentals of waterflood it would be easier to explain then.

John Ragozzino – RBC Capital Markets

Okay. I look forward to it. You gave a little bit of color as far as the LOE guidance for next year and indicating that beyond that production, is there any specific driver you can point to that are driving the increase in the absolute dollar per unit?

Jeff Olmstead

Yeah. It’s basically as waterfloods are maturing if you look at Southern Oklahoma the water cut is coming up there some and as waterfloods mature, especially ones that are higher on the curve your total volume of fluids you are moving is increasing to get the same amount of oil out of the ground and so it’s just a matter of as these floods get bigger and mature, the cost does go up a little bit. In this case we do have growth in ‘ 14 that going to offset it and we’ll just have to look at as we get towards latter part of the year what it will do for 2015 and ‘16. That’s most of the reason why.

John Ragozzino – RBC Capital Markets

Okay. And then along the same lines for those types of properties do you have any anticipation of significant lumpy investment requirements for additional water handling capacity or is it fairly smooth trend upwards overtime as we grow and you have additional water handling needs that you take care on what is required facilities upgrades that are large and mature and – every couple of years?

Jeff Olmstead

Yeah. It all depends on what relative time you are talking about. If you are looking at it year-over-year, it’ll probably be smooth, you look at it the quarter-over-quarter you could have some lumpiness because as the water flow, as the water bank moves you do have wells that have smaller pumps on them but now require larger pumps to handle all of that water. At the same time you are able to move some of the pumps to wells that have watered out that don’t need much capacity, more to the ones outside of it. So you will have periods where you do have some uptick in spending on equipment but again on a year-over-year basis it should be fairly smooth, quarter-to-quarter it may be little lumpy.

John Ragozzino – RBC Capital Markets

Thanks. So it’s nothing like a cyclic steam type of injection process where every so often you need to drop $75 million to $100 million on new steam facilities in order to keep you trajectory, it’s nothing anything like that at all?

Craig George

You are just talking about pump sizes, on just upgrade your pump sizes on certain wells.

John Ragozzino – RBC Capital Markets

Okay. Great thanks. And then just one more housekeeping question. Last year’s first quarter non-cash stock comp number was pretty significant relative to the other quarters. Should we expect a similar year or similar size non-cash comps number for the first quarter of ‘14 and what is it with respect to that, is that the big bonus that they pay you every year?

Jeff Olmstead

It is the [altips] that you pay management and staff, yes.

Craig George

And this should be of similar size.

John Ragozzino – RBC Capital Markets

Okay great. Thanks very much guys.

Operator

Thank you. Our next question comes from Jason [Ward from Baird]. Your line is open. Please go ahead.

Unidentified Analyst

Yeah. Hi guys. Just on the line for Eaton this morning. Just one question regarding the maintenance CapEx, was that lower number sort of the result of any weather delays in Q4 and if so do you expect any of that sort of to be pushed out to the following quarters this year?

Jeff Olmstead

I don’t believe it’s really to weather delays, we did have – the guys could not operate the rigs, especially out in the panhandle where the wind was high and temperatures were so cold, but nothing that really delayed us weeks and months at a time, it was just a couple of days I think the fundamental part of CapEx in the fourth quarter being lower is just timing when things needed to be done, half of the work done on the fourth quarter was conversions, conversions are not as capital intensive as drilling new wells are, so that kind of the reason why.

Unidentified Analyst

Got it. Okay. Thanks. That’s helpful. That’s all I have.

Operator

Thank you. And our next question comes from Ben Wyatt from Stephens. Your line is open. Please go ahead.

Ben Wyatt – Stephens, Inc.

Good morning guys. Congrats on the first drop down from Friday, just curious you guys could give us some color maybe is this kind of the size and kind of maybe should we expect something similar as we kind of move forward with dropdowns from the affiliates?

Craig George

My general counsel is shaking his head I am not allowed to answer that. You know from a size standpoint, I’ll try to get an answer that I give you the proper guidance about overstepping my bounds from a regulatory standpoint, say it Nathan or you want me to say it…

Nathan Pekar

The four that our [inaudible] actually will target, idea is and it’s similar to the types of ranges we have been looking at before.

Jeff Olmstead

Coming back to two that are similar, yeah we don’t have any dropdowns that are in the several hundred million dollar range if you will, again it all depends on what you consider relative.

Randy Olmstead

Ben this is Randy from the standpoint we are executing our business plan by building our pipeline and some assets are small and some assets are larger. It is difficult for us to be able to forecast and provide you that kind of guidance because it truly depends on the results in the field and how good the floods are working and how we are able to forecast that and then when we drop them down then we have the forecast for our distribution and associated depth. So we are building our pipeline and I would expect that future dropdowns if that came from our properties or future acquisitions this should be on the lower end.

Ben Wyatt – Stephens, Inc.

Okay. That’s helpful. Thanks Randy. Randy another one how should we think of maybe production you might have alluded to it but kind of throughout the year should we may be look at it as more little backend loaded in ‘14 or how should we think of it?

Randy Olmstead

I do think the growth first quarter we probably expect to be a little similar to what fourth quarter was, not a huge uptick other than of course the acquisition but really the growth is more kind of second quarter and beyond.

Ben Wyatt – Stephens, Inc.

Got you. And then maybe just one more if I can. How kind of – if you guys can maybe just talk a little bit about the revision you had on the oil side, the revision upward doesn’t pass on the gas side, but maybe just what properties we are talking about that added back on the reserves there?

Jeff Olmstead

You will look at it if you go into slide 13, the 400,000 barrels…

Ben Wyatt – Stephens, Inc.

264 from oil and just curious if you guys have any color around that or if it’s not material for you guys?

Michael Wiggins

This is Mike Wiggins. The revisions are primarily related to adjustments in some of our legacy assets in Northeast Oklahoma that are performing better due to the activities that we’ve done in 2013 and additional improvement in injection capacity there, that’s a significant part of that revision upward there in the oil and also we had some adjustment in South Oklahoma but the majority of it comes from Northeast Oklahoma, a little bit from Southern Oklahoma and some in the Hugoton area.

Ben Wyatt – Stephens, Inc.

That’s it. Well very good guys. I appreciate the color and keep up the work.

Operator

Thank you. (Operator Instructions). And our next question comes from the line of Noel Parks from Ladenburg Thalmann. Your line is open. Please go ahead.

Noel Parks – Ladenburg Thalmann

Good morning.

Jeff Olmstead

Good morning Noel.

Noel Parks – Ladenburg Thalmann

I sorry if I missed this earlier but do you have any thoughts on just general trends with the service cost and equipment cost are relatively flat assumptions going into 2014 budget or changes one way or the other?

Michael Wiggins

This is Mike Wiggins again. Our service costs are relatively stable but they are steadily increasing not significantly but we have a typical type increase that we would expect, that’s been captured in our capital budget for the year.

Noel Parks – Ladenburg Thalmann

And as far as equipment you talked about for example pumps and so forth?

Michael Wiggins

I am not sure I understood the question?

Craig George

All those cost going up?

Jeff Olmstead

In terms of cost of pumping unit and down well pumps and…

Michael Wiggins

Actually for us we have not seen a significant increase on a unit basis for capital equipment as far as pumping units that kind of facility equipment as well, it’s been all relatively flat.

Noel Parks – Ladenburg Thalmann

Okay, great. And I think that’s all for me. Thanks.

Operator

Thank you. (Operator Instructions). I am showing no one in queue at this time. I’d like to hand the conference back over to management for closing remarks.

Craig George

Well thank you again everybody for the interest and for the time and for the investments. To the extent you do have follow-up questions that you didn’t get into this, some of us will be travelling next couple of days but there will be people here at the Dallas office to take questions as well, or you can get through to me on the cellphone if you need continued detail on what we presented. Again thank you very much and we will talk to many of you soon I am sure.

Operator

Thank you. And ladies and gentlemen thank you for participating in today’s conference. This concludes our program for today. You may all disconnect and have a wonderful day.

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