Mid-Con Energy Partners' (MCEP) CEO Jeff Olmstead on Q2 2016 Results - Earnings Call Transcript

| About: Mid-Con Energy (MCEP)

Mid-Con Energy Partners (NASDAQ:MCEP)

Q2 2016 Earnings Conference Call

August 2, 2016 9:00 AM ET

Executives

Randy Olmstead – Executive Chairman

Jeff Olmstead – President, Chief Executive Officer and Director

Matt Lewis – Chief Financial Officer

Sherry Morgan – Chief Accounting Officer

Mike Peterson – Vice President and Chief Financial Officer

Analysts

Carlos Newall – Raymond James

Lin Shen – HITE

Mitchell Lipton – Mohr Partners

Operator

Good day, ladies and gentlemen, and welcome to the Second Quarter 2016 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions] As a reminder, this conference is being recorded.

I’d like to introduce your host for today’s conference Randy Olmstead, Executive Chairman. Sir, you may begin.

Randy Olmstead

Thank you, Tiara. Good morning and welcome to the Mid-Con Energy Partners second quarter 2016 conference call. Today we’re getting Tulsa, Oklahoma, our new headquarters. Tulsa has always been the base of our operation team and we welcome Jeff Olmstead, CEO; and Matt Lewis, our new CFO to Tulsa as they have completed a transition from Dallas. Also present for today’s call are Sherry Morgan, Chief Accounting Officer; Chad McLawhorn, Vice President General Counsel; Chad Roller, Vice President of Exploitation; and Larry Morphew, Executive Vice President of Operations.

Yesterday, we’ve released quarterly earnings, which will be discussed by Jeff and Matt shortly. If you’d like to follow along with our PowerPoint presentation just go to our website, midconenergypartners.com, then to the Investor Relations section and 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 the federal securities laws. Forward-looking statements are based on our current expectations and include any statement that does not directly relate to current or historical facts. For further explanation, you can refer to Slide 2 of today’s presentation.

Now, I’ll turn it over to Jeff.

Jeff Olmstead

Thank you. Good morning to everyone. Thank you for your participation on the call today. The past quarter and especially the past few weeks have been very busy and very transformational for Mid-Con. Along with our continued focus on cost and debt reduction, we’ve been looking for ways to not only solidify our balance sheet, but also continue to adapt to lower oil prices.

If you’re following along with the presentation, please turn with me to Slide 4, highlights of our Permian bolt-on acquisition. Yesterday, we announced the execution of the definitive agreement to purchase approximately 1.5 million barrels of oil equivalent in Nolan County, Texas, for $19.5 million, subject to customary post-closing adjustments. This acquisition will be funded through a private financing with investors including affiliates of Bonanza Capital, Investor John Goff and Swank Capital.

As of the end of the second quarter, these efforts are currently averaging 368 barrels of oil equivalent per day and are located near some of our better performing existing properties in Nolan County. Along with the waterflood potential we see in these assets, we also believe there are some additional upside of infill drilling and some improvements in field level. Our approach to the development of these assets will be similar to the successful approach we have taken on our other Permian properties that we acquired in 2014.

Turning to Slide 5, on Thursday, we closed our previously announced Hugoton sales. We sell those assets for approximately $18 million. And as previously announced in our borrowing base press release in May, we only had a $5 million borrowing base reduction with the sale of these properties. The sale of the Hugoton assets, which had some of the highest operating cost in our portfolio combined with acquiring the Nolan County assets, potential acquisition, which will be some of the lowest operating cost in our portfolio, allows us to further lower our overall operating costs across our portfolio.

This follows the strategy we have been executing of lowering operating costs and looking for opportunities in current oil prices. As I mentioned before, the Permian assets, potential of the acquired Permian assets have both primary and secondary potential. The secondary potential gives us the opportunity to add reserves in this area if the waterflood development is successful. Perhaps most importantly, this potential acquisition along with the financing returns us to a conforming borrowing base.

At the closing of the Permian acquisition and subject to their execution of the 10th amendment, our lenders have unanimously approved an increase in our borrowing base to $140 million. As of August 1st, we had approximately $139 million borrowed. We still have some work to do to create some additional liquidity, but this is a big step towards returning – return to a growing – to growing the partnership rather than simply defending our debt in phase of lower prices. I want to commend and thank our entire team, who worked so hard to navigate through this period to find both organic and outside opportunities.

Now turning to Slide 6, the second quarter highlights. During the second quarter, we averaged 4,077 barrels of oil equivalent per day production. This was down approximately 5% from the previous quarter. Our focus has been on maintaining economic production of reducing costs especially from uneconomic wells at current prices. In the first quarter, we outlined a number of steps we have taken to control costs including shutting-in a number of wells. In addition to well shut-ins, our team in the field has been very careful not to spend money repairing wells to go down if it wouldn’t be economic at current prices to do so.

These wells are on leases and waterflood units that are held by other production, which allows us to be selective on when and where we choose to spend capital to repair rod parts, casing leaks, pump repairs and other well work that just frequently need. This will result in temporary loss of production, but typically does not cost us any reserves in long run. Consequently lease operating expenses were down were approximately $5.8 million, which was also down about 5% from the first quarter.

As a result operating cost per barrel of oil equivalent was essentially flat with the first quarter at $15.57 per BOE. Resulting adjusted EBITDA was approximately $11.6 million, this was a decrease in the first quarter, which was predominately associated to the lower realized hedge amounts we had in the second quarter as compared to the first quarter. As I mentioned earlier, this cash flow combined with the Hugoton sale has allowed us to reduce debt down to approximately $139 million as of today.

Turning to Slide 7 and 8, 2016 capital expenditures. We spent approximately $1.4 million during the quarter on two new producing wells and 9 recompletions. This capital was directed to Northeastern Oklahoma and the Permian core areas, where we have the lowest cost in our portfolio. This is slightly lower than we had anticipated in the beginning of the year. And I have mentioned earlier, we continue to watch oil prices and try to rationalize our spending when and where it makes the most economic sense.

Looking at Slide 9, we have budgeted just over $5 million in capital spend for the remainder of 2016. Again, this would be primarily spent in Northeastern Oklahoma in the Permian core areas and we will continue to adjust our budget up or down as prices dictate.

With that I will turn it over to Matt Lewis, our new CFO, who will walk you through our financial results.

Matt Lewis

Thank you, Jeff, and good morning to everyone listening on the call. If you would please turn with me to Slide 11, in this table select financial and operating results for the second quarter 2016 are compared to the preceding quarter and same period prior year. As Jeff previously mentioned, year-over-year variances and daily average production primarily reflects in our view the successful execution of well level cost savings initiatives completed in January 2016. This resulted in the temporary shut-in of approximately 184 uneconomic producing wells.

Additionally, during the second quarter 2016, we elected to defer certain workover expenses, which contributed to a 5% decline sequentially. In terms of pricing, Mid-Con Energy realized $39.83 per BOE in the second quarter 2016. This represented an increase of 38% sequentially, primary due to higher TI [ph] pricing. However, once you include the impact of cash settlements for matured derivatives and net of premiums operating revenues of $47.19 per BOE were flat for the first quarter of 2016 and decreased 17% from the same period prior year.

Total operating costs and expenses were $18.4 million during the second quarter of 2016. This included 4.5 million in non-cash impairment charges recognized during the quarter. Approximately 3.6 million of which was related to an impairment of assets held for sale and 0.9 million was related to one of our Permian properties.

Net interest and other expenses totaled $2 million during the second quarter of 2016 declining 6% sequentially due to lower debt outstanding but increasing 12% year over year as a result of the higher pricing grid established during our fall 2015 borrowing base re-determination.

In summary Mid-Con Energy reported a net loss of $15.8 million during the second quarter of 2016 with key variances attributable to non-cash impairment charges and the unfavorable net effect of unsettled commodity derivatives.

On Slide 12 we’ve provided a reconciliation of net loss to non-GAAP measures of adjusted EBITDA and distributable cash flow. During the second quarter of 2016 Mid-Con Energy’s adjusted EBITDA totaled $11.6 million. This amount was down 13% sequentially and 10% from the second quarter of 2016 due to lower sales volumes and lower cash settlements on mature derivatives partially offset by reductions in LOE and cash G&A.

After subtracting $1.8 million in cash interest expense and $1.2 million in estimated maintenance CapEx distributable cash flow of $8.6 million decreased 17% quarter over quarter and 2% year over year. On Slide 13, we highlight the partnerships overall improvement in total cash operating expenses per BOE since the second quarter of 2014, a trend that continued during our most recent quarter.

Total cash operating expenses inclusive of interests were $25.57 per BOE during the second quarter of 2016. This was a decrease of 3% sequentially and 9% year over year. In terms of expense categories that we have some ability to control approximately three quarters of this underlying cost structure was attributable to LOE and G&A. And for reference since the second quarter of 2014 each of these two categories have posted improvements in excess of 40%.

Moving on to Slide 14, our quarterly hedge schedule is presented as of August 01. On July 01, 2016 we completed a hedge restructuring per Amendment No. 9 to the Credit Agreement which resulted in the early monetization of existing 3Q 2016 hedge positions. Volumes in amounts were replaced with at-the-market swaps in equal amounts and net proceeds from the restructuring of approximately $4.3 million were used to reduce borrowings outstanding under the revolver. Percentages hedged are calculated based on the midpoint of our updated 2016 production guidance of 4050 BOE per day.

In summary our current hedge portfolio includes a combination of swaps, cost [ph] of collars and deferred premium puts covering an average of approximately 81% of our production in 2016. 64% in 2017 and 36% in 2018 with average Floor Strike prices of about $43.89 per barrel.

To provide you with a leverage and liquidity update please turn with me to Slide 15. On June 01, we completed our spring 2016 borrowing base re-determination. As detailed in Amendment No. 9 to our credit agreement our borrowing base of $163 million was comprised of a $53 million permitted over advance expiring on November 01, 2016 and a $110 million conforming tranche.

As Jeff mentioned post Hugoton divestiture the conforming tranche would step down to a $105 million. Although the terminology for the two tranche structure was amended between the fall 2015 and spring 2016 re-determinations. We were pleased to announce in June that continued support from our lender group remained unchanged.

At June 30, 2016 Mid-Con Energy reported $162 million in debt outstanding and a liquidity position that included approximately $4 million in cash. Calculated total leverage was 2.71 times an improvement from the first quarter of 2016 measurement period and well within our four times financial covenant.

The key take away on this slide is the dotted bar on the right side of the chart. Since quarter-end the partnership has relied on excess cash flow net proceeds from the July hedge restructuring and closing of the Hugoton divestiture to pay down an additional $22.7 million in debt. As a result Mid-Con Energy had $139.3 million in debt outstanding as of August first 2016. And perhaps more importantly we are pleased to announce the results of a non-scheduled borrowing base re-determination effective upon closing the Permian asset purchase. Our senior lenders have committed to establish a conforming borrowing base of $140 million, subject to execution of Amendment No. 10.

Our next scheduled borrowing base re-determination will occur on or around November 01, 2016. Over the remainder of the year, we expect to continue operating within cash flow and improving liquidity under the borrowing base via continued debt reduction.

Finally on Slide 16. We have provided updated full year 2016 guidance to reflect the closing of the Hugoton divestiture on July 28 and a pro-forma impact of the previously announced Permian acquisition, which we expect to close on or around August 12.

Full year 2016 production guidance ranges 3850 to 4250 BOE’s per day or 4000 BOE per day at the midpoint. LOE guidance ranges $14.50 to $17.50 per BOE or $16 per BOE at the midpoint. This reflects an 11% decrease to previous LOE guidance based on improving operational efficiencies realized year-to-date and a favorable impact we expect to see in our current run rate LOE after exchanging the high operating cost profile of the Hugoton core area with pending Permian bolt on properties that recently averaged $12 per BOE.

Lastly we budgeted $8 million in total capital spending for 2016 reflecting a slight decrease of approximately $11 million from previous guidance. Please note that our capital budget is subject to change as commodity prices fluctuate over the second half of the year. With that being said I would like to turn the call over back to Jeff for closing remarks.

Jeff Olmstead

Thanks Matt and before we leave the guidance slide I would reiterate what Matt said. The guidance that we have put our there is basically based on what the current strip would look like if prices were to move up or down from the current standpoint. We would adjust accordingly, we could add CapEx, we could subtract CapEx, which of course will have an effect on the potential production, and we could choose to add some of the wells back on line that we have shut in or we’ve left out due to repair work, or we could shut some additional wells. And so this number is our best estimate with the current price structure and we’ll adjust as accordingly as prices move up or down. The price structure and we’ll adjust accordingly as prices move up or down.

With that I want to thank again our entire team for their efforts in continuing to move Mid-Con forward. Our cost controls and Hugoton sale and the proposed Permian acquisition pull us to a return to conforming borrowing base that provide a platform for future growth going forward.

I want to thank our staff, lenders and investors for the continued support that’s helping Mid-Con adapt to lower oil price environment and hopefully setting us up for future success. With that Tiara we’ll open it up to questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Carlos Newall from Raymond James. Your line is open.

Carlos Newall

Good morning gentlemen. Thanks for taking my question. Congratulations on getting your borrowing base back into conforming status. We have seen a lot of borrowing based facilities limit dividend payments, if the borrower – if the borrower is 90% drawn. So my question is, given you’re still tight liquidity, what limitations if any do you have on paying a preferred dividend?

Sherry Morgan

On the preferred dividend right now as long as we’re within the conforming number, the preferred dividend is approved, the common distribution we will have to create some additional liquidity. We don’t at this point have that number outlined. But we will outline it in future quarters as we create that liquidity.

Carlos Newall

Okay great. That’s some nice color. Just a follow-up question, do you have any confidence that your borrowing base won’t get reduced this coming fall?

Sherry Morgan

If you can give me with any confidence what the price of oil will be and what strip will look like, I can answer your question. But again prices kind of stay where they are or where they have been, I feel comfortable we’re kind of in the same range. If they dropped $4 or $5 five, I’d say all that’s or off they go $4 or $5, you could even see an increase. But, yes I mean, I think, it all depends on where prices are, what their trend is and how banks are seeing the price decks once we get into the fall. Obviously it significantly affects where the borrowing base stays where it is, or whether it goes up or down.

Carlos Newall

That’s very helpful. That’s it for me. Thank you.

Operator

Thank you. And our next question comes from the line of Lin Shen from HITE. Your line is open.

Lin Shen

Hey good morning gentlemen. Thanks for taking my question.

Sherry Morgan

Sure.

Lin Shen

Also congratulations for the recent transaction. I have two questions. First, I want ask that how should we think about your ongoing hedging strategy? I notice that you’ve been hedging gradually, I don’t know the prize. I’m assuming when the oil was about a $50. So how should we think about ongoing hedging strategy?

Jeff Olmstead

Yes sure, I mean, I think it will be similar to what we’ve done. We’ve sort of got into that roughly two years of hedges out there, we’ll continue to layer on kind of in that outer year. I guess we’re more like two and a half years, you get to that outer six months, will probably be similar where we are now, more or like a third of what production is expected from a guidance standpoint. In the near kind of year and a half to two years, we’ll be more in the two thirds range like we are.

Lin Shen

Okay. And how about the price, do you prefer, I mean do you think that may be you want to hedge when oil is above some threshold like $50, you want to start to think about that, or you would always put on regarded the price?

Jeff Olmstead

Yes at this point in time we’ve just been kind of layering on as each quarter rolls off. Even if $50, that’s not the price I want long-term, so I’m not interested in adding them from much longer than that, but we’re trying to protect sort of near-term next couple years cash flow and protected that as well. So I don’t have a target price for you know that I would all of a sudden hedge three or four years. That’s sort of made quarter-by-quarter by our Board as we discuss it.

Lin Shen

Great, and also, I mean given you have a tight borrowing capacity and also the cost MLP is – the cost MLP market is relatively high. So how should we think about your compatible one day when you are competing with other may be productive firm or other firm to acquire new assets?

Jeff Olmstead

Sure I mean competitive advantage is we think is what we’ve always thought it was, is our ability to create reserves from secondary potential from waterflooding. Don’t know that, if we didn’t see opportunities that others didn’t see, we wouldn’t out there bidding down things and we wouldn’t be able to bid on things that other people would not bid so to speak.

So certainly if it’s just a primary type asset with primary reserves, I think, at any given time, we’re going to get up bid. If it’s an asset that has secondary potential, that’s where we think we have a competitive advantage that we see stuff that others don’t or see things that others couldn’t do quite at the cost or the efficiency that we could. So that’s still what we think our competitive advantage is.

Lin Shen

And…

Jeff Olmstead

You’re right it’s not going to be on cost of capital, it’s not going to be our willingness to pay off the future reserves, it’s going to be our willingness to pay for what we believe is secondary potential not captured improved reserves and not captured by most people’s evaluations.

Lin Shen

Great, do you see there’s a potential like more opportunity now than it used to be like two years ago, given their whole market of kind of stressed?

Jeff Olmstead

I would think so, just because people aren’t as excited about old properties. If you go back to two years ago, the problem we had was even stuff that we saw potential in nobody wanted so their oil because when oil $100, that was something they wanted to hold on to and they wanted too big of a premium. Today as that’s a second potential or generally more striper type, marginal type production and people are more willing to discuss at this point, now we’re still willing to give it away, there’s still a bit of aspiring in most opportunities, but places where there’s secondary potential and where there’s a willing seller, I think we can make the transactions and we’re the one [indiscernible].

Lin Shen

Great, thank you very much. I appreciate it.

Jeff Olmstead

Sure.

Lin Shen

Thanks.

Operator

[Operator Instructions] And our next question comes from the line of Mitchell Lipton from Mohr Partners. Your line is open.

Mitchell Lipton

Hi how are you guys?

Jeff Olmstead

Hi good morning.

Mitchell Lipton

Question for you is, I’ve noticed that there been a fair amount of sales in the last three, four, five months, the EOG deal, I think it was Devon. And I know that those are probably not equivalent to your assets. However, are you able to talk at all about the market in terms of values because it would appear to me as if at the very least we’ve hit bottom and there’s actually people out there that are looking to acquire assets right now, in the marketplace.

Jeff Olmstead

Yes I don’t think that’s been any [indiscernible], but everybody wants to buy when the perceived market is down. As Lynn mentioned before, the competitive landscape has gotten even more competitive and if not less, so as you have a lot of money in private equity and capital from other companies who have no debt who are very interested in buying assets at low prices, just as we are. The difficulty becomes if you don’t have a willing seller in most cases why would you sell when prices are down.

So we either have to find the asset to get we’re willing to pay premium because their secondary potential will be on that premium or maybe there’s a distress type situations to come around. At this point in time, again we announced a transaction this week. We’re just coincided with the life of that company where they were instant selling and we saw some waterflood potential we are willing to pay what we thought it was a premium to get it.

Mitchell Lipton

I see, and I guess what I was going with that as, it prepared to me as it maybe pricing has come up some. And I wondered if you might be able to expand on how that impacts your asset base or is my assumption wrong that pricing is come up and it’s not at the distress levels that you might have seen a year or so ago?

Jeff Olmstead

I guess it’s certainly better than it was in the spring, it wouldn’t before was in the 20s. It’s obviously not what it was when we had $70, $80, $90 certainly we have an increase in our borrowing base that was partially due to the acquisition of properties that was partially due to the increase in prices, banks are willing to use to evaluate those reserves. So that certainly brings up the value of all the assets. I’m not sure if I getting – if I’m answering just to your question or if I’m answering which you’re trying to ask and…

Mitchell Lipton

No, no. I think you are – I just in terms of I look at the PV-10 and the excuse me – if I pronounce wrong, who gotten sale I think it was on your PV-10 at $12 million and one-off at $18 million which, just frankly I thought was favorable and I guess what I’m going with that is when I look at the balance of your asset base. If you apply that type of premium to it, it would bode well for the company’s asset base, can you comment on that at all?

Jeff Olmstead

Certainly, if we got similar type valuations that would be great across the asset base, I think one important thing to note in the Hugoton. You had a situation were that’s the highest costs asset – those are the highest cost, highest operating cost, highest lifting cost from a drilling per foot maybe a little higher drilling cost out there in our entire portfolio so we had an unsolicited bid as you said that we felt was at a premium. It makes sense to sell it to apply that same valuation whether you did it on the per barrel reserves in the ground. If you did it on per barrel of current production you really have to look at the underlying cash flow.

And certainly if we can get the cash flow multiples applied to the rest of our assets, the valuation of the company would be significantly more than it is. But I think the seller there saw potential to buy some assets – I’m the buyer there saw potential to buy some assets hold them for a better day. And we’re talking double-digits of trailing cash flow on that asset sale. You apply double-digits to our current cash flow and the market value become – would be significantly higher than it is today.

Mitchell Lipton

And then just one last question on the recent, the Permian bolt-on acquisition.

Jeff Olmstead

Yes.

Mitchell Lipton

I guess what I’m – what I would ask is when you quantify that do you see the potential for additional opportunity there. So does that potential and it – forgive me if this is you know a dumb question but does that potential acquits to more proven reserves than are being reported – than what you are reporting now or acquit to opportunities that you feel might lead to being able to get more BOE on a daily basis out of those assets than are being reported is that really what its all about?

Mike Peterson

It really is, we don’t quantify what would be considered probable or possible reserves or in this case waterflood potential reserves but everything we’ve ever acquired. We’ve acquired because we believe it has secondary potential that is above what the current proved reserves are that has risk in it because we’ve got to get the waterfloods going. It’s got to be a response. Some of our waterfloods works, some of our waterfloods don’t. So we don’t try to quantify that upside until we’ve seen a response and we have proven reserves to do so, but yes. Anything just about everything we’ve ever purchased. We purchased it because we believe with waterflood potential we can add reserves in the long run.

Mitchell Lipton

And I’m sorry one last question. And when will we have a good idea of – or when will you be able to report whether there is actually further upside to those – to the Permian bolt-on assets. At what point do you think you’ll be able to quantify that?

Mike Peterson

When we – wouldn’t make sense to start spending money and getting Jackson going into the ground and then we see a response or don’t see a response. And so that can be a function of price as much as time, oil is $39 or whatever we dipped into yesterday, it wouldn’t make sense to go start putting injection into the ground. If oil continues to go up we get in the high 40s or low 50s we will probably start spending that money to start that injection. And then the response time depending on the reservoir can take 6, 8, 9 months, it can take 18 months. So we’ll be able to give more color once we start that injection. But that’s going to be a function of price not time.

Mitchell Lipton

Got you. Well, thank you. I think a great execution on what you’ve been able to accomplish since the first of the year. I appreciate it.

Mike Peterson

Thank you, thanks for the questions.

Operator

Thank you. [Operator Instructions] At this time, I’m showing no further questions in the queue. I would like to turn the call back over to Jeff Olmstead for closing remarks.

Jeff Olmstead

Well, thank you and again thank you everyone for the participation on the call today. We are extremely excited about the announcements will be able to put out the last couple of weeks, in the last couple of days I guess really. Look forward to the time when prices continue to go up, no come back down forward to the time when prices continue to go up. No come back down and get some more work growing some more capital going to the ground. If you have follow-on questions as you get through the material again we are officially out of the Dallas office and here in Tulsa. Please call the Tulsa office and we will be happy to address it all. Thank you everyone.

Operator

Ladies and gentlemen, thank you for your participation in today’s conference. This concludes the program. You may now disconnect. Everyone have a great day.

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