Vanguard Natural Resources' CEO Discusses Q1 2014 Results - Earnings Call Transcript

Apr.30.14 | About: Vanguard Natural (VNR)

Vanguard Natural Resources, LLC (NYSE:VNR)

Q1 2014 Earnings Conference Call

April 30, 2014 10:30 AM ET

Executives

Lisa Godfrey – Investor Relations

Scott W. Smith – President, Chief Executive Officer and Director

Richard A. Robert – Executive Vice President, Chief Financial Officer and Secretary

Britt Pence – Executive Vice President-Operations

Analysts

Ethan Bellamy – Robert W. Baird & Co.

Kevin Smith – Raymond James

Spiro M. Dounis – JPMorgan Securities LLC

John Ragozzino – RBC Capital Markets

Bernard Colson – Oppenheimer

Operator

Good morning, ladies and gentlemen and thank you for standing by. Welcome to the Vanguard Natural Resources’ First Quarter 2014 Earnings Call. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session; instructions will be provided at that time. (Operator Instructions) I would like to remind everyone that this conference call is being recorded today, April 30, 2014.

I will now turn the conference over to Lisa Godfrey. Please go ahead.

Lisa Godfrey

Thank you. Good morning, everyone and welcome to the Vanguard Natural Resources, LLC first quarter 2014 earnings conference call. We appreciate you joining us today. On the call this morning are Scott Smith, our President and Chief Executive Officer; Richard Robert, our Executive Vice President and Chief Financial Officer, and Britt Pence, our Executive Vice President of Operations.

If you would like to listen to a replay of today’s call, it will be available through May 30, 2014 and may be accessed by calling 303-590-3030 and using the pass code 4679258#. A webcast archive will also be available on the Investor Relations page of the company’s website at www.vnrllc.com and will be accessible online for approximately 30 days.

For more information, or if you would like to be on our e-mail distribution list to receive future news releases, please contact me at 832-327-2234 or via e-mail at lgodfrey@vnrllc.com. This information was also provided in yesterday’s earnings release.

Please note the information reported on this call speaks only as of today, April 30, 2014. And therefore, you are advised that time-sensitive information may no longer be accurate as of the time of any replay.

Before we get started, please note that some of the comments today could be considered forward-looking statements and are based on certain assumptions and expectations of management. For a detailed list of all the risk factors associated with our business, please refer to our 10-Q, which is expected to be filed by tomorrow May 1, 2014, and will also be available on our website under the Investor Relations tab and on EDGAR. Also on the Investor Relations tab of our website, under Presentations, you can find the first quarter 2014 earnings results supplemental presentation.

Now, I would like to turn the call over to Scott Smith, President and Chief Executive Officer of Vanguard Natural Resources.

Scott W. Smith

Thanks, Lisa and thanks everyone for joining us on the call this morning to discuss our – to go over our first quarter 2014 results. I’ll start with a brief summary of our recently closed acquisition and then review our operational results and capital spending for the first quarter. Lastly, I’ll discuss our acquisition outlook for the year. Then we’ll turn the call over to Richard for the financial discussions and then we’ll open the line up for Q&A.

As I mentioned on our last conference call, the Pinedale acquisition is the largest investment we have made to date in a natural gas property, and it’s the second largest transaction we have done in our history. With this acquisition, we’ve established a non-operated position in one of the most prolific natural gas deals in United Sates, primarily operated by two of the leading independent oil and gas companies in the Rockies, that being Ultra petroleum and QEP Resources. Both of these companies have demonstrated the ability to consistently achieve best-in-class operating results, while lowering development cost.

Since 2006, both operators have reported total well cost decreasing almost 30% and the drilling costs continued to decline due to efficiencies in drilling and completion practices. Along with the proven geology and long history of performance for the PDP wells, we felt this is also the perfect asset for Vanguard to introduce a growth component to its capital spending strategy.

Not only has the drilling proven in this area to be very successful, with the PUD inventory we acquired, we believe we and our partners will be developing this field for over 10 years, making this growth sustainable over the long term.

Please note that although the Pinedale acquisition we had on October 1 2013 effective date, the acquisition didn’t close until of January 31. So, our first quarter results only include the benefits from the acquisition for two months. We have transitioned the accounting functions from Anadarko, and are diligently working with Ultra and QEP to streamline the information we receive from them so that we are kept abreast the current and planned developments on the operational front.

During the first quarter, we did not benefit from much of the uplift in the Pinedale due to Anadarko having elected not to participate in a subset of the wells prior to October effective date, and some of these non-consented wells were just being completed by QEP and Ultra in the first quarter.

During our due diligence, we did not forecast any production from the non-consented wells, so our valuation properly excluded them, but we had assumed that the operators would have completed the work on these wells in the fourth quarter, in those wells we did have a working interest for models coming online sooner in the first quarter.

Bottom line is, we had to tweak our model to reflect the timing of new wells where we had our working interest. That being said, we did not spend as much of capitals forecast in the Pinedale, but expected this will normalize towards the end of the second quarter, as both Ultra and QEP are each trying a four-rig program.

All-in-all, this was not the start we were anticipating with this acquisition, but fortunately it’s not the core results for underperformance, it was due to a delay in the drilling of wells where VNR has a working interest.

Besides the capital program, the PDP production is at or above our forecast, differentials in transportation costs are better than we had model. As Richard will get into later, we have not only hedged the basis at a better price than we had forecasted, but the unhedged portion is participating in additional timing of the differential.

Now, I’ll review our production results and capital spending. Average daily production for the first quarter was 268 million cubic feet equivalent per day, up 21% over the 221 million cubic feet per day produced in the fourth quarter of 2013, and a 35% increase over the 199 million cubic feet equivalent per day produced in the first quarter of 2013.

Production for the quarter was approximately 66% natural gas; 20% oil; and 14% NGLs. However, even with our significant increase in natural gas production, our revenues are still more weighted to liquids with 45% coming from oil; 14% from NGLs with the balance from natural gas.

Because the Pinedale acquisition did not impact January, the first quarter production rate is not run rate to calculate what our current production is at. For example in March, our production was approximately 309 million cubic feet equivalent per day with 68% natural gas, 17% oil and 15% NGLs. Our production is projected to continue increasing over the year, as we spend more capital, especially at the Pinedale.

Turing to our capital spending; during the quarter we spent approximately $31 million, our capital program was highlighted by our activity in the Woodford, Permian and to a lesser extent to Pinedale. To quickly recap, in Arkoma Basin we drilled and completed five operated horizontal Woodford wells for an approximate 40% working interest in Pittsburgh County, Oklahoma.

We also participated in the drilling of three horizontal wells and the completion of 13 horizontal Woodford wells in Hughes and Coal Counties, Oklahoma with working interest ranging from 1% to 13.5%.

In total, these wells had a gross seven day IP of just over 52 million cubic feet equivalent per day – 52 million cubic feet per day just over 2,500 barrels of NGLs or which equates to about 8.3 million cubic feet of gas per day and 415 barrels of NGLs next to Vanguard.

In the Fayetteville, we participated in the drilling of 8 gross or 0.5 a well net and the completion of 16 gross or 0.7 net horizontal wells mostly in Cleburne and Van Buren counties. These wells added just over 2 million equivalent feet per day net. In the Woodford, I also want to highlight our workover program, where we had a quite a bit of success acidizing wells and started installing artificial lift equipment.

During the first quarter, we completed work on 17 wells at a net cost of $1 million, for a total net uplift of 2,500 Mcfe per day. These projects generate returns in excess of 100%, and we’re looking forward to continue in this program on our 2014 inventory.

Our Permian recompletion and frac program continues to perform well. During the first quarter, we completed 10 workovers, which included 1 frac and recompletion and nine acid jobs. These projects added a gross uplift of 10 barrels of oil per day and 208 Mcf per day, or 9 barrels per day and 177 Mcf per day net with a total investment of $650,000. The range recompletion program has historically achieved high rates of return. We have at least 6 fracs planned for the second quarter of 2014.

Also in the Permian, Vanguard participated in two horizontal Wolfcamp wells. Per a format agreement, we were carried for a 25% working interest in the Atlantic exploration (indiscernible) number 2 well in Ward County, Texas. This well was very successful, as it had a high seven-day IP of 831 barrels of oil per day, and just under a million cubic feet of gas per day, which equates to about 250 net BOE per day to Vanguard.

In Dawson County, we participated with a 35% working interest in the Diamondback Kent well and 8,500 foot horizontal well, which is situated in the Northern portion of the Midland Basin. The well was stimulated with 36 frac stages at the end of March and it is still cleaning up. Lastly, I want to add that about half of the capital spend in the quarter was deployed in March. So as you would expect, we won’t see any benefit from those investments until the second quarter.

Looking to the balance of the year, we are anticipating a capital spend between $105 million and $110 million over the next three quarters, which includes both maintenance and growth capital. Let me quickly go into some of the more details and some of the larger capital outlays that we plan.

The largest component of our capital program will be the Pinedale assets, and this is also where all of our growth CapEx will be focused. As I previously mentioned, Ultra and QEP each plan to drill eight wells a month for a total of 16 gross wells, where we will have a working interest. This equates to against four rigs running by each operator for the balance of the year.

Our drilling and completion costs are forecasted to be between $3.8 million and $4.2 million per well gross. All the wells are drilled vertically to depths of 10,500 feet to 13,300 feet, will be completed using approximately 16 frac stages and take about between 10 and 12 days from spud to setting production casing. Some of the wells at Anadarko had previously nonconsented to will be completed in the second quarter and our capital program will get back on track to the 16 gross wells per month.

We are already back on schedule with Ultra, which is about two-thirds of our capital spend and our interesting QEP’s activities will be back as planned towards the end of the second quarter.

The Permian is expected to be our second most active area in 2014. This encompasses our successful range Permian recompletion project that we began last year. And as we previously mentioned, we participated in the two horizontal Wolfcamp projects and potential revisions could include growth CapEx in the Permian Wolfcamp horizontal play with both Diamondback and Atlantic.

Atlantic has the option for one more well on our Miller lease in our form out agreement under 120 day drilling obligation. And in Boston County with Diamondback, we have an interest in over 6800 gross acres, 2400 net of the company adjacent and surrounding the Diamondback where we jointly drilled.

We think Diamondback will start the second well in our jointly owned acreage in the second quarter at the results of the camp well meets their expectations. As I previously mentioned in our conference calls, in the Woodford we have an active drilling program with Jones as well as having other non-operated drilling activities that are currently underway.

With respect to acquisitions, we are seeing quite a bit of quality deal flow and our team is evaluating numerous transactions of various sizes. At our sides in a track record of successful transactions I am confident we are seeing all of the sizable opportunities that are come to the market.

While it remains a very competitive market for MLP type asset, I continue to believe, we are well positioned to be very competitive on the quality asset packages that best in our business model. With the introduction of the growth capital into our strategy, we feel we’ll be more competitive bidding on assets that may have a larger drilling component than we have looked at in the past.

That being said, we will continue to be disciplined in our approach to evaluating acquisitions. Assets that have a growth component need to have a repeatable joint program that just like the Pinedale assets can be executed for many years to come. As we’ve always said with other by nothing that’s $10 million on a marginal transaction that is an accretive. Our goal has always been to grow cash flow which ultimately benefits our unitholders in the form of increased distributions.

With that I’ll turn the call over to Richard.

Richard A. Robert

Okay. Thank you, Scott. Good morning everyone. I would like to start this morning by first discussing our quarterly financial results then turn to my regular update on our hedging portfolio and liquidity, and then I’ll review our outlook for the balance of the year.

As far as our financial results. We reported adjusted EBITDA of approximately $90 million for the first quarter, an increase of 24% when compared to the $72 million reported in the first quarter of 2013, and an increase of 21% from the $74 million reported in the fourth quarter of 2013.

Obviously this increase was attributable to having the Pinedale acquisition contribute two months to our financial results. That being said EBITDA was lower than what we had anticipate for the quarter by approximately $4 million. This is primarily attributable to two items.

First, a delay in revenue associated with new Pinedale wells that were non-consented prior to VNR’s acquisition as Scott discussed. And second capital delays in the Woodford due to weather which move completions in the March and delayed associated revenue by couple of months.

Before I get into the Pinedale and Woodford, let me discuss differentials as this is something I regularly review. WTI oil prices increased from the fourth quarter to first quarter, but our hedges less than the impact of this increase in our revenues. The primary driver of our Ohio oil revenues was that old differentials company wide strengthened by almost $5 per barrel from the fourth quarter.

This was not a surprise as discussed in our last earnings call we are anticipating some improvements in the 2014 Big Horn differential, which has a large impact to our company differential. January had a $23 differential, but we have seen significant improvement in February as it came down to approximately $14, and then in March widen slightly to approximately $14.75.

And we are currently seeing this level in April. We are anticipating that during the middle of the year the negative differential here will improve a bit more and then begin to widen beginning in September as we’ve seen them past. After taking into account, the differential and our hedges, our average realized oil price, including hedges increased by approximately $5.60 in the first quarter. Gas realizations averaged approximately 78% of NYMEX and increased quarter-over-quarter. This may seem like a relatively low realization but keep in mind that this also includes our transportation costs.

The addition of the Pinedale assets along with a tightening basis differential also helped improved this quarter-over-quarter. In the Pinedale, we assumed a basis differential of $0.26 and an additional $0.95 per Mcf after transportation. From a basis differential perspective, we were able to hedge this risk 20% better than forecasted at a weighted average differential of negative $0.20.

On the transportation side, this is coming in at almost half of what we had modeled during the acquisition evaluation. The combination of these two factors will prove be very impactful to our revenues as more gas production comes online due to the drilling program. The pricing of natural gas liquids or NGLs also improved over the quarter. Average realized NGL pricing in the first quarter was approximately $36.70 per barrel, which was better than our guidance expectations.

Since our NGLs are largely unhedged, the recent pricing increases from these loads add and will continue to have a positive impact on our revenues. As I alluded to earlier, the reasons for our lower than expected adjusted EBITDA was due to lower production in the Woodford and Pinedale. As we discussed on our last conference call, we experienced downtime just like many of our peers during November and December, due to severe winter weather and infrastructure issues. Fortunately, we did not experience any material long term damage, but our production was temporarily curtailed or shut in and this lasted into January.

This also impacted our capital plans in the first quarter, primarily in the Woodford, where completions were delayed about a month due to the severe weather we experienced. We also had some additional downtime, where offset wells or shut in while these wells are being fracked. However, we are close to forecast for April. That should be back in line with our expectations by May. That being said, the over lining in this is that our operations are already back on track and we should see a significant increase in production beginning in the second quarter.

As Scott mentioned, in the Pinedale, the lower than expected production is also a timing issue. Anadarko had previously gone non-consent on a number of wells before we agreed to purchase the assets. Although, this impacted our revenues in this area, what is most important is that it is not due to poor performance from wells currently producing or new wells being drilled, just a delay.

There is a backlog of non-consent wells that Ultra and QEP are working through and ensure they will get to the wells we are participating in. It is important to note that we knew that there were wells that Anadarko went non-consent on and we didn’t taper them in our acquisition. It would be different if we did put value on wells that we didn’t own. While we didn’t know that would take this long to get through all of those non-consent wells. So, we haven’t lost any revenue, it’s just shifted out a couple of months.

In terms of our external cash flow, the first quarter of 2014 totaled approximately $42 million or $0.52 per common unit, generating a coverage ratio of about 0.83 times based on our current monthly distribution of $0.21 per month beginning in February or $0.62 and $0.75 for the first quarter. I predicted a coverage ratio of approximately one times for the first quarter on our last earnings call, but we ended up approximately $8 million short of achieving that prediction.

Let me take a moment to reconcile why we were $8 million short. I’ve explained that we were $4 million short of our internal EBITDA expectation due to the weather-related production delays in the Woodford, as well as the lower Pinedale production from Anadarko non-consent issue, which is also a timing issue.

However, the delay in completions is just a delay. The remaining $4 million shortfall was related to the significant amount of capital expenditures incurred primarily in March. Although, we did realize a lower capital spend in Pinedale, it was more than offset by higher spending elsewhere. This is a situation that we must accept when over half of our capital spent for the year is on non-operated properties.

It is more difficult to predict with certainty, exactly which month the capital will be spent. This is why I consistently say that coverage ratios are very important, but should be computed on an annual basis, because capital spending may not be consistent from quarter-to-quarter.

Although, I was wrong in the first quarter, I will be deterred, and I will give another prediction for the second quarter expected production. Adjusted EBITDA and distribution coverage in a moment, but first let me discuss our hedging portfolio.

During the first quarter and into April, we’ve been very active in adding new hedges as a result of the Pinedale acquisition, and recent increases in the oil curve in 2015. On a total basis, our natural gas has hedged 85% in 2014; 92% in 2015; 85% in 2016; and 47% in 2017, all at weighted average prices of about $4.42.

I’ll note that this does not assume any CapEx plans in 2015 and beyond. So specifically, in the Pinedale where there is a significant amount of drilling anticipated for years to come, we are not as heavily hedged as this would indicate.

In terms of oil, 2014 expected oil production is 94% hedged, 2015 is 68% hedged and 2016 is 24% hedged, all at a weighted average price of approximately $92.43 per barrel. Recently, we were able to take advantage of increases in the oil curve to layer on additional 3-way collars in 2015. Specifically, we added 1,000 barrels per day in the first half of 2015, then 500 barrels per day in the third quarter of 2015, and finally 500 barrels per day in the second half of 2015.

Because of the shape of the oil curve it has made sense for us to layer in hedges for specific parts of the year in 2015, rather than the full year, which is why you see us add hedges just in the first half of the year, then the third quarter, and then lastly the second half.

In doing so, we have been able to secure attractive pricing for more of our oil production in the first half of 2015, where we are now over 75% hedged, and as time goes by, we will continue adding hedges to more fully secured oil pricing for the second half.

More details regarding our current hedge portfolio and percent hedge can be found in the supplemental Q1 2014 information package posted to our website.

Let me turn to our credit facility and liquidity for a quick update. With the inclusion of our recently closed Pinedale acquisition and our semi-annual borrowing base re-determination, our borrowing base was increased by $225 million to $1.525 billion.

In addition, we are amending the size of our facility from the current $1.5 billion to $3.5 billion. We feel this will give us ample room to grow as we continue to make accretive acquisitions. As of today, Vanguard has $759 million in outstanding borrowings under the revolver, which provides us with approximately $775 million in current liquidity after taking into consideration the $1.525 billion borrowing base and $10 million in cash on our balance sheet.

In November last year, we instituted our new ATM program, which allows us to sell both common and preferred units at market prices during the normal trading day. Since that time, we’ve raised approximately $59 million via our common units and $1 million via our preferred units. We were very pleased with the performance of this program and absent any large acquisitions. This will be our preferred method of raising capital via the equity markets.

At the beginning of March, we issued class B preferred units for total net proceeds of $170 million. These units were essentially identical through our class A units and trade under the ticker symbol VNRBP on the NASDAQ. We continue to feel that as the preferred MLP market continues to grow, this will become a more and more important part of our long-term financing strategy and are very pleased by the demand for our second offering. In addition with this new issue, it should improve the liquidity and our preferred and allow us to raise more preferred capital via our ATM going forward.

Finally let me turn to our outlook for the balance of the year. As noted in our guidance issued in February, we are expecting some good results in 2014. So the question that some may had is do feel is this necessary to adjust our previously provided guidance for 2014 as a result of the production delays experienced in the first quarter. The answer is no.

We are aware of enough good things happening in our asset portfolio that we think will offset the delays we have experienced thus far. Based on current strip pricing, the second quarter we are expecting average daily production of between 310 and 320 MMcfe per day, adjusted EBITDA of between $103 million and $105 million, and distribution coverage range of between 1.05 to 1.1 times depending on the timing of capital expenditures.

This concludes my comments and we’d be happy to answer any questions at this time.

Question-and-Answer Session

Operator

Ladies and gentlemen, we will now conduct the question-and-answer session. [Operator Instruction] And your first question comes from Ethan Bellamy. Please go ahead.

Ethan Bellamy – Robert W. Baird & Co.

Hey guys good morning. With respect to the CapEx being deployed primarily on vertical gas wells, I have to think that you guys are one of the single biggest drillers and kind of a contrarian strategy. Can you help us to put that CapEx deployment into context with respect to all the other inventories you have and is that better IRR sources that lower execution risk there or some combination of both?

Unidentified Company Representative

I’d say all of the above. The Pinedale drilling is vertical, it’s very (indiscernible) fracs vertically and as we have shown in our IR presentation that as Ultra shows in their IR presentations, QEP shows in there, I mean the rates of returns are significantly better than what we find in other horizontal place that we participated in. That being depending on the EUR, the returns are well over 50%. So from our perspective that’s a program that we’re happy to participate in. And we like the fact that we’re producing gas up in the west in the rocks. We’re not going to have to compete with Marcellus and Utica production and so we think ultimately there is differentials are going to be better in that area than they will be in the east. So in terms of growing production somewhere, we think growing gas production in that area specifically is going to bear fruit over time.

Ethan Bellamy – Robert W. Baird & Co.

Okay. What percent of your basis have you hedged there, and what’s unhedged for the balance of year, and will we see layer on more basis hedges to protect against the potential blowout in the summer?

Scott W. Smith

We are heavily hedged this year for 2014, I’d say somewhere in the neighborhood of 80% probably, 80% to 90%, and then in 2016, we’re pretty close to being fully hedged now. The basis has come in significantly over the last few days actually, and where we had been modeling 40 plus set differentials, we were able hedge at $0.22 yesterday, and $0.24 in next year. So we’re fairly fully hedged in 2015, as well, and somewhat in 2016 and 2017 as well.

Ethan Bellamy – Robert W. Baird & Co.

Okay. That’s helpful.

Richard A. Robert

Basically, we – anytime we can get locked; the market tightens to the point where we – and we have orders in that are substantially better that what we modeled when we did the acquisition, we’re going to take advantage of it.

Ethan Bellamy – Robert W. Baird & Co.

Richard, with respect to, just one housekeeping question, on the ATM program, what’s been the issue year-to-date, please.

Richard A. Robert

Well it was $59 million since December, and I’d say year-to-date that number is probably $38 million, $39 million, $40 million somewhere around that level.

Ethan Bellamy – Robert W. Baird & Co.

All right. Thank you. I appreciate it.

Richard A. Robert

Thanks, Ethan. And keep in mind, I mean we’ve had a fairly significant blackout period, so we obviously are subject blackout periods, and that program, I expect will continue to accelerate as our blackout period or less for the quarters and for the year.

Ethan Bellamy – Robert W. Baird & Co.

Okay. Thank you.

Operator

And your next question comes from Kevin Smith. Please go ahead?

Kevin Smith – Raymond James

Good morning, gentlemen.

Scott W. Smith

Good morning.

Kevin Smith – Raymond James

Scott, with the potential for a second horizontal well with Diamondback, is that something you’d need to raise capital or change your capital budget for, excuse me or is that something you’re going to shift around your capital budget?

Scott W. Smith

It’s again, we would say, they do go ahead and propose another well, and we’ll see what happens probably in the next couple months, it’s an areas if we’d like, the returns look good again, we can always increase our budget to accommodate that, and I think we’ve said that before that might be a growth capital opportunity for us.

But again, we’re not going change our budget today, and again it’s not that much money, I mean it’s 35% of an $8 million well, so – and I can’t imagine it mostly might drill two more this year, so but we’re cautiously optimistic, but I know the Diamondback guys would probably did visiting on that, this well in particular on their call next week.

Kevin Smith – Raymond James

Gotcha. And is there any other uptime for the Diamondback and its acreage, any other potential for may be in the Permian or is this really the kind of extent of it?

Scott W. Smith

No, we’re also – I think we mentioned with Atlantic, we are participating in a well right now with them, it’s in Ward County, we have a 25% interest, it’s again a horizontal Wolfcamp, again heading on to the success we could potentially see another offset to the Miller, and I…

Kevin Smith – Raymond James

How to deal with that part?

Scott W. Smith

And we also have opportunities that (indiscernible) did in a recent presentation, we take the deal with Athlone, where they are going to be drilling a series of wells, we have five well carry in two different areas, I think they will probably get through those wells this year, so I don’t envision us probably having a lot of joint operations with them and we have a principle we’re actually paying for well cost. But it hopefully they’re going to drill five nice wells and we’re going to set ourselves that for a pretty nice capital program going into next year.

Unidentified Company Representative

And there are few other deals that we’re working on at the moment. Similar type deals to the excellent deal that, I’ve gotten that question so many times, but what we have in the Permian that we actually have put together a slide that we’re going to present at the next investor conference at…

Unidentified Company Representative

NAPTP.

Unidentified Company Representative

NAPTP, which shows kind of what we’ve done in the Permian the deals that we’re working on.

Kevin Smith – Raymond James

Okay very helpful. And then lastly from me and I mean this is exact point in your prepared remarks, but just to be clear, where are we on the backlog at the non-consent wells, work to that inventory and still may be when did that shift from non-consent to working wells that you guys have working interest in?

Unidentified Company Representative

We are not through that all of them being work through yet, there are just a couple of wells with Ultra actually I think we had two in the second quarter. And we had rest here, its looks like there’s 27 total wells in the second quarter that would, if they prosecute those wells we wouldn’t have an interest in, but I know we have approved just at the end of February we approved the participation in 21 wells. So it’s really a matter of how the scheduling of those wells gets done.

Unidentified Company Representative

Yes that’s the QEP wells that he was referring to. And the QEP is so much more than Ultra because of QEP’s policy to not complete wells during the winter, that’s really the impetus for being for this dragging on into the second quarter. Now they are obviously completing wells a lot faster than they are drilling wells. So they are working through that inventory fairly quickly and we anticipate that they’ll be done with that inventory in the second quarter.

Unidentified Company Representative

And then QEP is a smaller percentage I mean Ultra is roughly two thirds and QEP is roughly a third of the total activity.

Unidentified Company Representative

Yeah, we have a higher interest in Ultra wells than we do in QEP wells.

Kevin Smith – Raymond James

All right. That’s all I have. Thanks.

Unidentified Company Representative

Okay Kevin.

Operator

And your next question comes from Spiro Dounis. Please go ahead.

Spiro M. Dounis – JPMorgan Securities LLC

Hey, good morning everyone thanks for taking my question. Just I had a quick question on this potential deals I think you mentioned in 2013 you did about 30 deals, I was wondering how that level of activity compares to so far in 2014 what you are seeing out there?

Unidentified Company Representative

Well. We didn’t quite that main deals.

Spiro M. Dounis – JPMorgan Securities LLC

You bid on 30 deals.

Unidentified Company Representative

We’ve done, let me not confuse with legacy there’s...

Unidentified Company Representative

No we didn’t make a lot obviously make, we do make a lot of bids and obviously our hit rate is probably…

Unidentified Company Representative

Less than 5%

Unidentified Company Representative

Less than 5%, but our deal flow is excellent, as I said we’re seeing all of I think every opportunity is out there, people know we have money. Our balance sheet is in great shape to be able to take advantage of opportunities. There are a lot of quality assets coming to market and we’re seeing, there are some very large packages coming from some of the larger independents. So I’m very optimistic about this year being able to hopefully, obviously we started out well, but I think, this could be one of the largest years in our history with what we’re already seeing in the market.

Spiro M. Dounis – JPMorgan Securities LLC

Got it. Very helpful. And then just around the CapEx, its sounds like if you could move around a bit from quarter-to-quarter going forward. To the extent you guys think you might fall below coverage may be in another quarter, I guess what risk or what quarters do you believe is most that risk of something like that tends to be happening again?

Unidentified Company Representative

Well, I’d like to think that we’re not at risk for the remainder of the year, now that we have three months of Pinedale in every quarter from here on now that Pinedale deal is a very nicely accretive deal for us. So, it isn’t – we don’t – we aren’t aware of any concentration of capital to be spent over the next three quarters, it may vary a little bit from time-to-time because as I said a lot of our CapEx is non-operated. So, we don’t know exactly when it will be spent, but as far as we know there isn’t going to be any concentration in anyone particular quarter. So, it is our expectation to be above one times for each of the remaining three quarters.

Spiro M. Dounis – JPMorgan Securities LLC

Got it, great. Thanks, that’s it from me.

Unidentified Management Representative

Sure.

Operator

Your next question comes from John Ragozzino. Please go ahead.

John Ragozzino – RBC Capital Markets

Hi, good morning gentlemen.

Unidentified Management Representative

Good morning, John.

Unidentified Management Representative

Good morning, John.

John Ragozzino – RBC Capital Markets

Do you guys feel that there is going to be a bit of an increased appetite for carrying a little bit more leverage on the balance sheet, given the fact that you laid out a bit of a strategy that entails more reliance on the ATM to raise equity, which I got to think assets a bit longer than the traditional organized strategy in following any sort of transaction?

Unidentified Management Representative

Yes, I mean, there is certainly a willingness to delever overtime as oppose doing in one quick swap with an overnight offering. Clearly our cost of capital is significantly reduced, when we do it under the ATM. We don’t have the disruptions in our equity unit price that often enthuse after an overnight offering, so I think basically our unit holders will benefit one from a more stable unit price and number two by issuing fewer units because our cost of capital is going to be issued at a better price under the ATM. So, yes, I think you could expect that we’ll delever over a longer period of time. But it is our expectation as I said on our last call. We are going to be – our expectation is to be about 3.1 times for 2014 – by the end of 2014.

John Ragozzino – RBC Capital Markets

Okay, that’s helpful. And then I may have missed it earlier in the call, but CapEx for 3Q, 4Q do you expect a similar trend as we saw last year or is there going to be any additional guidance you can give us in terms of quarter-on-quarter sequential directions in capital spending?

Unidentified Management Representative

Yes, as I mentioned, we’re not seeing any major concentrations of capital in any particular quarter going forward. It may vary somewhat it’s likely, but not significantly. I expect probably the run rate that we saw this quarter, it maybe a little bit more in the next three quarters. As we mentioned, we expect $105 million to $110 million of capital for the remainder of the year.

At this point relatively equalize I suppose, I mean obviously we’ll have a better grasp on that after this quarter. Because of the QVP non-consent, we may spend a little bit less capital this quarter. But for all we know, there may be some other non-op stuff going on in Fayetteville and another areas in Woodford that may take its place. Nothing too significant.

John Ragozzino – RBC Capital Markets

All right, one more big picture question. Do you see any convergence in the outlook of buyers and seller of oil assets due to the shape of the futures curve that may fuel additional deal flow than what we was being year-to-date this year?

Unidentified Management Representative

I think obviously from a buyer’s perspective, they look at what they can hedge as the price, at least financial type buyers just like the MLP (indiscernible). Other maybe private equity and those type of companies that have a different view and say look, we know it’s variously backwardation especially when you get to 17, 18. Firstly I think that way because there is no liquidity in the back of the curve. There is no trading out there so there is basically no reason for it to come up. But every month, we continue to see the price come up.

So, the sellers I think there are lot of them, they still want to sell into this market, there happen to look fairly large oil transactions in the market here recently and I don’t think that’s going to stop. But [we also get] (ph) sold and I think that must be very lousy premiums typically for oil assets even with a backwardated curve. If I say a lower PV for the asset, we have that price with the idea of the expectation at the back end is going to come up.

John Ragozzino – RBC Capital Markets

Gotcha. Alright. That’s all I’ve got. Thanks very much guys.

Unidentified Company Representative

Thank you.

Operator

Your next question comes from Bernard Colson. Please go ahead.

Bernard Colson – Oppenheimer

Good morning. Just a question particular about the preferred securities and how are the rating agencies treating those securities.

Unidentified Company Representative

My understanding is that the rating agencies provide 50% equity debt treatment for that security.

Bernard Colson – Oppenheimer

Okay. And then, from a bank covenant standpoint, how they treat?

Unidentified Company Representative

All equity.

Bernard Colson – Oppenheimer

All equity.

Unidentified Company Representative

Which seems to be the more reasonable number for me since it is perpetual preferred equity. I mean that’s why the call it equity and that’s why it’s perpetual just like our common. So I don’t distinguish a difference frankly, we pay a distribution are common and we pay a distribution on our preferred, so there is similar securities. So I’m not clench here whether rating agencies would try to treat them differently.

Bernard Colson – Oppenheimer

Okay, that’s my only question. Thanks.

Unidentified Company Representative

Sure. Thank you.

Operator

Your next question comes from Ethan Bellamy. Please go ahead.

Ethan Bellamy – Robert W. Baird & Co.

Hi, guys. I’m just going to share some of my ignorance here, but what’s the payable cycle on a non-op well AFE and does that vary by operator, and is that service work build in and paid in on an aggregate basis through the operator.

Unidentified Company Representative

Both QEP and Ultra we just get sales, we make the elections and we just get billed for our join operating sale every month. It’s kind of just – we’re not cash calling us ahead for drilling cost. We had a relationship and we had – we met with these folks, didn’t look at our work. You don’t have to worry about us paying our bills and everything, so it’s just a – literally just every month we get a bill as part of the normal process that will have whatever cost we are incurred during that month.

Ethan Bellamy – Robert W. Baird & Co.

Got it. So you basically sweeping and trued up at the end of every calendar month.

Unidentified Company Representative

Fine, and then we’re selling our own production, we’re marketing our own gas production, as well as the NGL, so we’re taking the gross working interest gas and marketing that ourselves. So from a revenue perspective, we’re getting paid in 25 of every month whenever we sold a (indiscernible).

Ethan Bellamy – Robert W. Baird & Co.

Okay. And those bills that you’re getting from – from alternative QEP, is that for bills that they received in the month or is that for bills they received from service providers that was done in the prior month.

Unidentified Company Representative

Yeah, I mean its – Thursday always a lag, I mean you got a process to payables and then Belden. So there is usually – some operators are better than other operators. I mean, it’s not unusual that we have operators put in a bill that was incurred three months ago. It just – maybe they disputed the bill, and finally when it got resolved they put it through their joint interest bill. So, typically they are better than that, but sometimes they are not.

Scott W. Smith

They’re not paying their drilling contractors ahead of that.

Ethan Bellamy – Robert W. Baird & Co.

Yes, okay. All right, I appreciate that. Thank you.

Scott W. Smith

Thank you.

Operator

Mr. Smith there are no further questions at this time. Please continue?

Scott W. Smith

Okay, thanks again operator. I appreciate everyone joining us this morning. Again, as I said during the call, on the acquisitions front we are seeing lots of opportunities. I’m very excited about what we’re seeing in the market. I think this year has the potential to be the biggest year in our company’s history, and we look forward to continuing to move on the growth track that we’ve had. So, next call will be in August.

Unidentified Company Representative

Earnings call.

Scott W. Smith

Yeah, late July or August. And we look forward to buzzing you then. Thanks again for joining us.

Operator

Ladies and gentlemen that concludes the conference call for today. Thank you for participating. Please disconnect your lines.

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