QR Energy's (QRE) CEO Alan Smith on Q1 2014 Results - Earnings Call Transcript

| About: QR Energy, (QRE)


Q1 2014 Earnings Conference Call

May 7, 2014 10:00 AM ET


Alan Smith - CEO

John Campbell - President and COO

Cedric Burgher - CFO


Kevin Smith - Raymond James

Noel Parks - Ladenburg Thalmann

John Ragozzino - RBC Capital Markets


Welcome to QR Energy’s First Quarter 2014 Results and Outlook Conference Call. My name is Tanya, and I will be your operator for today’s call. On the line we have Chief Executive Officer, Alan Smith; President and Chief Operating Officer, John Campbell; and Chief Financial Officer, Cedric Burgher.

Before we begin the call, listeners are reminded that QR energy we use forward-looking statements as defined by securities laws. These statements reflect current views with regards to features and are subject to various risks, uncertainties and assumptions. The results may differ materially from those conveyed in forward-looking statements. For a complete list of these risk factors, please read QR Energy’s 10-Q, which is field with the Securities and Exchange Commission this morning. This document is available on the company’s web site under the Investor Relations tab. Additionally, during the course of today’s discussion QR’s Energy will refer to adjusted EBITDA, distributable cash flow and the distribution cover ratio as important metrics for evaluating QR Energy’s performance. Please note that these are non-GAAP financial measures and they are reconciled to their most directly comparable GAAP measures on the last page of this morning’s press release.

All lines have been placed on mute to prevent any background noise. After the speakers’ remarks there will be a question-and-answer session. (Operator Instructions)

Now I will turn the call over to Chief Executive Officer, Alan Smith.

Alan Smith

Thank you Tanya and good morning everyone. Thank you for joining us this morning as we discuss our first quarter earnings and operational results.

I will begin the call today by providing a brief overview of our operations and discuss the recently approved increase to 2014 capital budget. John will then provide a detailed operational update and Cedric will close the prepared remarks with an overview of our financial performance.

Or first quarter results were largely in line with expectations with the exception of 650 BOEs per day, of weather downtime experienced in the Permian and East Texas areas. First quarter production came in at 18,900 BOEs per day. LOE was $22.40 per BOE and G&A came in below our guidance. This is also a great reflection on our employees and their continued focus on maximizing efficiency while conducting business operations.

Since our last conference call on March we have been very busy executing capital program and continued to be successful with our pursuit of smaller bolt-on transactions in the East Texas area. In the first quarter, we were able to close approximately $32 million of East Texas’s bolt-on in areas where we have existing personnel and operational infrastructures. We continue to have discussions with a number of parties looking to divest their positions in the East Texas area.

As to the A&D markets, they began the year a bit slow but they picked up in the past couple of months, and we are aware of a number of MLP top opportunities that are expected to come to the market over the next several months. We’re always evaluating opportunities that fits the MLP strategy of mature legacy assets that have lower decline in required minimal maintenance CapEx.

Moving on to our increased capital program. This morning we announced and $82 million increase to our 2014 capital program, bringing the new total 2014 capital budget to a $182 million. The 82% increase from the original budget resulted from an extensive internal asset review the reveal a significant number of low-risk opportunities. To give you background on our inventory capital project we have spent considerable time over the past 9 to 12 months, staffing our assets with the appropriate level of chemical expertise. As part of our year-end reserve process, we challenged our technical personnel to identify additional proved and probable inventory.

They responded by discovering a deep inventory of overweighted opportunities that offer repeatable low-risk projects across, and Jay regions. We have reviewed data from the wells we have recently drilled, various work over projects that had been completed as well as additional projects that were identified based upon asset operator activity. These successful results we reviewed led to the increased capital program that will be primarily executed beginning in the third quarter of this year.

I want to give you a few stats on the new development working capital program. 51% will be drilling and completion projects, 33% will be work over and recompletions and 16% will be for facilities and equipment upgrades. John will elaborate more on specific projects in his section by area. 2014 capital will be allocated, 35% to the Ark-La-Tex, 35% to the Jay Field, and 29% to the Permian area and the remainder split across the mid-continent and Gulf Coast properties.

We expect to begin receiving drilling rigs for new wells in the Ark-La-Tex area, the Jay Field and the Permian area in the third quarter. Given that the capital program is weighted towards the second half of the year, there will be moderate production impact in 2014, with the bulk of the production net worth occurring in 2015.

Before turning the call over to John, I would like to give out some sea of thank you to our organization, and our employees for all their hard work that went into our current quarter performance and the increased capital program, we’re all excited about executing the mid capital program this year and have plenty of liquidity to fund the program. We are still very focused on evaluating acquisitions that fit our strategy and these efforts will continue throughout 2014.

Thank you again for your time this morning and now I’ll turn the call over to our President and Chief Operating Officer, John Campbell.

John Campbell

Thank you, Alan. In the first quarter our operations team done a great job executing our business plan of maximizing production from our existing assets base while assimilating the new bolt-on properties into the portfolio. For the quarter, we increased production to 18,900 Boes per day or 2% above the fourth quarter achieving our stated guidance range despite the second consecutive quarter of weather related downtime while severe colder weather was experienced across our entire asset base. Our East Texas and Permian basin areas were the most impacted. We estimate the total impact from downtime during the quarter to be approximately 650 Boes per day. Our product mix continues to be liquids weighted comprised of 73% liquids or approximately 59% crude oil and 13% natural gas liquids.

We anticipate the ratio to slightly improve as we execute our 2014 budget. LOE in the first quarter was 38.1 million or $22.40 per Boe in line with our stated guidance of $21 to $23 per Boe. LOE during the quarter was up 1.1 million over the fourth quarter primarily due to additional cost associated with the newly purchased East Texas bolt-on property and higher fuel cost in the Jay field. Helping to offset these items was Permian’s controllable LOE costs continuing to improve specifically down 30% quarter-over-quarter. Total capital spending for the first quarter was 33 million including 18 million of maintenance capital or approximately 28% of EBITDA.

Moving now to the capital program, we’re very encouraged by the project we have in our portfolio. I will now discuss some highlights from our core operating areas during the quarter and provide a little more detail on how the growth capital in 2014 will be allocated. In the Jay field we continue to see positive results from the capital invested. It is currently a miscible nitrogen flood with the key goals being, one injectable water in nitrogen in nitrogen into the field, and two keep the operating running with high run time. We have been very successful with this since the dropdown and it shows in the solid production performance.

During the quarter we actively returned wells to production conducted core tubing work to cleanout wells and add purse to maximize injection. And we continue to focus on plant expansion to be able to move more volumes through the plant. In the second half of the year, we will continue these type of projects additionally in the third quarter we will add a second work over rig and a drilling rig with plans to drill three to five new wells. At Jay we controlled over 14,400 net acres, current wells spacing is approximately 200 acres per well.

Based on our latest petro physical and reservoir study work, we believe there is significantly more remained all in place in previous estimated had indicated. Pending the results of our 2014 program, we anticipate that a multiyear low risk infield drilling program will be needed to fully exploit the field. The new wells will be vertically drilled to approximately 16,000 feet targeting the Smackover Formation and are expected to have an average well cost of less than 5 million per well. We’ll look forward to providing update later in the year.

Moving now to the Ark-La-Tex area, we continue to be active with approximately eight workover rigs running at any given time concentrated in the East Texas oil field. These rigs are actively and returning well to production conducting cleanouts and completing ESP installation. In addition to the typical blocking and tackling type workover projects, we’re actively drilling in a couple of the Ark-La-Tex areas. In Smith County Texas, we spot our first Cotton Valley horizontal well in the Overton field under a partnership agreement with the private operator. The well is currently drilling in the lateral portion at approximately 14,000 feet with a planned total measured depth of 16,000 feet.

We plan to spot a second Overton horizontal well immediately following this well. We also plan to drill two additional wells in late 2014. These wells are expected to cost less than 6 million per well. We have a 50% working interest in these wells which includes a 25% carried working interest. We believe that this area could have room for over 20 horizontal locations. First out in Cherokee County we’re pleased to announce that we have secured a power solution and have begun to optimize production in our Neches field. During the quarter, we completed a new 33,000 barrels per day water injection well and began our capital workover program including pump speedups returning to productions and recompletion.

The field is currently producing over 950 Boes per day which is around 80 Boes per day above our plan. The team is also evaluating a possible infield drilling program for late 2014. In Great Country Texas in our grate water area we completed operations on recompletions to the Travis Peak and Pettet zones. These zones are primarily all productive in our area and have favorable economics. The current combined production from these five wells in excess of 150 Boes per day. Our current plan includes 15 to 20 recompletions per year over the next several years for this year.

The team is also evaluating several incremental opportunities including additional horizontal drilling on our existing acreage. In Claiborne Parish Louisiana in the Homer Field during the first quarter we drilled three vertical wells targeting the Clear Fork formation at around 1100 feet.

Based on logs, cores, and initial tests with high oil cuts there appears to be a significant amount of remaining unswept movable oil in place. The field currently produces a little over 400 BOEs per day through old style open hole spotted liner completions. Prior to QR energy, the most recent oil drilled was in 1982, and has produced over 100,000 barrels of oil. Based on a new reservoir data the team believes the potential exists more than doubled field reserves and production through infill drilling and selective perforating and acidizing these wells. The team is currently planning to drill two new water injectors, five to ten new producers, and return several wells to production before year-end.

Moving a little north to Miller County, Arkansas, in the in the Doucette [ph] field we plan to substantially increase activity in second half of the year. We drilled two wells since the fourth quarter which found favorable net take and reservoir pressure in the target Cotton Valley sands. Completion operations are in progress, with very encouraging initial results. First quarter activity included a very successful recompletion as per program. The latest well, the packs on number five had initial test rate of over 200 BOEs per day which significantly exceeded our expectations. Our results and study work to date have prompted our decision to increase our 2014 budget to drill an additional 10 to 12 wells in 2014. The Doucette field offers a multiyear inventory of low-risk drilling opportunities. Our wells are currently on 20 acres to 40 acres spacing. Nearby operators are successfully redeveloping the field on 5 acres to 10 acres spacing. Conservative estimate to 10 acres spacing would imply potential inventory of around a 100 wells for QR Energy. We look forward to keeping you updated on this program as well.

Switching to the Permian basin, we have been very active and we will continue to invest additional capital in areas where we have experienced recent success. In the second half of the year we plan to drill approximately 12 wells in five different areas. In Howard County, Texas in the Tahoma [ph] field we drilled a well in the first quarter which was encouraging. The Rig D2 [ph] was a vertical well drilled to approximately 9000 feet targeting a strong Cline and Wolfcamp formation. The well has been online for over 30 days and is currently producing 190 BOEs per day, of which 90% is oil. We plan to drill 2 to 3 additional wells in the area during the third quarter. In Glascock County Texas in the Garden City area, we have drilled to wells to date, the TXL 3-3 and the Glass #7 targeting the strong Cline and Wolfcamp formations. Both wells came online in April and early production results were in line with our expectations.

The operator to the south recently applied for amended field roads to allow for 40 acre internal wells. This would provide us with the potential to increase our locations in this field. We are closely monitoring this and expect to hear something by the end of the second quarter. We plan to drill two additional vertical wells before year-end. In Mitchell County Texas in the Turner-Gregory Field we’ve drilled and placed over 8 wells targeting the Clearfork formation. These are shallow inexpensive wells that produce 100% oil. We have four more wells playing in the Turner-Gregory Field in 2014. In Crane County Texas, we are currently working with a non-operated project with a private operator. In the first part of the year, we have completed three wells all targeting the Devonian, Woodford and Barnett and Penn formation. The first well’s average production or the first 30 days has been 90 BOEs per day, 80% oil, and is in line with expectations.

The second and third wells were fraced and came online in the last week of April. We are currently receiving flow back data and are encouraged. We plan to participate in 2 to 4 additional wells with this operator in 2014. And finally in Lea County, New Mexico, in the M-State field we drilled the M-State number 12, targeting the Blambleberry [ph] formation, which is currently producing over 290 BOEs per day, 60% oil. The well has been online for 45 days and held up nicely. We will spud the next M-State well towards end of the third quarter. As you can see we have a lot of projects performing well that’s just a nice inventory of repeatable opportunities. I would like to stress that our drilling activities are targeting wells that had been drilled and proven low-risk areas. We’re also very focused on maintaining a base decline rate appropriate for any upstream MLP. At year-end or decline rate was approximately 10%, given these wells are in low declined and mature fields. We anticipate that the new activity will not materially change our overall decline rate of 10%.

Looking at or forward guidance we anticipate second quarter production to be in the range of 19,200 BOEs to 19,800 BOEs per day, and annual production to be 19,900 BOE to 20,500 BOEs per day which again does not include potential acquisitions. Due to the timing of a drilling activities occurring in the second half of the year, the full benefit of 2014 capital budget increase will be visible in 2015. We are currently forecasting to exit the year producing approximately 22,000 BOEs per day. That rate is of course subject to timing and other assumptions but it demonstrates potential value-add from our increased capital investment. LOE is anticipated remained in the $21 to $23 per Boe range for both second quarter and the full year.

Now, I will turn it over to Cedric for review of our operating financial results.

Cedric Burgher

Thank you, John. During the first quarter, we increased total revenue to $122.6 million or approximately 3% above the fourth quarter, but saw lower adjusted EBITDA of 64.8 million and lower distributable cash flow of 30.9 million. As John discussed in his remark, colder weather experienced in the East Texas and the Permian during the quarter took higher margin oil production offline. Additionally, cash flow was also lowered due to lower realized hedging revenue during the quarter from higher price hedges rolling off coupled with increased index prices.

Despite the downtime in production and hedging impact, the coverage ratio in the first quarter was still 1.0 times. For the quarter including hedges are average realized oil and natural gas prices were $93.23 per barrel and $6.18 per Mcf receptively. NGLs had an average price of 35 to 58 per barrel. It should be noted that during the first quarter we made a onetime noncash adjustment associated with a non-operated property that impacted a few items one being our realized natural gas price. Excluding the adjustment the true dollar amount would have been $40.86 per barrel which is approximately 43% of WTI.

Total G&A for the quarter was $10.2 million, which includes non-cash amortization expense of $1.8 million related to long-term incentive unit awards. Cash G&A was $8.4 million, which was below our guidance of $9 million to $10 million. Excluding the effect of any acquisitions, we anticipate cash G&A to continue to be in the $9 million to $10 million range in the second quarter with full year cash G&A expectations to be in the $32 million to $35 million range.

Our interest expense for the period was approximately $12.2 million, which reflects interest payments on our debt as well as a non-cash gain on interest rate hedges in the amount of $1.0 million. Our all-in effective interest rate for the quarter including the senior notes and interest rate swaps was approximately 4.9%.

During our semiannual borrowing base redetermination process for our revolving credit facility, our borrowing base was reduced from $950 million to $900 million. This reduction was primarily a result of the roll off of higher priced oil and natural gas hedges and the compression of LLS to WTI differentials over the past 12 months. At March 31st including the reduction, we had approximately 199 million of availability under our credit facility which combined with 23 million of cash on our balance sheet provides the company with current total liquidity of approximately 220 million.

Our current liquidity will allow us to execute the 2014 capital program and continue to pursue smaller bolt-on acquisitions in East Texas. Hedges going to the second quarter are still very strong. We have hedged approximately 10,100 barrels per day of oil and approximately 31.4 million cubic feet per day of natural gas. Based on first quarter production levels, our current oil and natural gas production remains approximately 81% hedged for 2014.

During the quarter, we established an at-the money equity program which to-date we have not issued any units. As we have previously stated the ATM program allows us to opportunistically access the equity capital markets timely and at a lower cost than traditional equity financing methods. We continue to monitor the equity capital markets and our liquidity levels. We still view this as just another financing tool in the toolbox and one that works very effectively executing our bolt-on acquisition strategy. Next week on May 14th we will pay the second monthly cash distribution attributable to the first quarter of $16.25 per unit to all common and class B units.

And with that, this concludes the prepared remarks portion of our call. We are all very excited to about our capital program in 2014. We have the staff and the resources to execute our strategy and we look forward to delivering strong operational results. Thank you for your time this morning and we are now ready to open the line for questions.

Question-and-Answer Session


(Operator Instructions) Our first question comes from the line of Kevin Smith from Raymond James. Your line is open.

Kevin Smith - Raymond James

It kind of sounds like your decision to increase capital spending is a strategic multiyear shift to focus more on organic growth. Is that fair or am I reading too much into it?

Alan Smith

I think we owed it to ourselves, Kevin, to do this deep dive assessment of our inventory. We got staffed up away the way we want to get staffed and I think that we done a lot of hard work on that, so I think that the result of that effort has definitely turned out to the significant additional inventory for us. So we just like having the ability to go execute on these low risks type projects they happened to be all weighed which we think is a good thing from a margin perspective. And it makes us -- while we are still alive on acquisitions over time. We’ll certainly be very active in the acquisition market. I think this allows us to also focus and extract the value in this asset base that we kind of new, was there, but we just needed to spend a lot of time with the teams. So once we got it fully staffed the way we wanted to be able to do that. So I think that your assessment is right. There be probably higher amount of growth capital spend based on these inventory. But that certainly does not mean that we will not be actively pursuing acquisition market.

Kevin Smith - Raymond James

Okay, I appreciate the color. Is that any of the wells that you’re drilling not proved, or is this very much going to PUD and PD and Ps?

Alan Smith

That’s very much going to be proved reserves in the Jay area, as well as the Doucette area, and then the Permian. All tell you it’s all proved stuff, then we may not have a book because you know we haven’t been really focused on booking a lot of PUD opportunities, but come midyear, we feel like all of this is proved stuff that will be done.

Kevin Smith - Raymond James

Okay. And, then lastly, just one housekeeping sort of item. Can you discuss the $3.6 million in acquisition and transaction costs that got incurred this quarter?

Alan Smith

A lot of that is legal expense and a little bit of banking expense related to the bolt-on, primarily.


(Operator Instructions). The next one comes from Noel Parks from Ladenburg Thalmann; your line is open.

Noel Parks - Ladenburg Thalmann

Great. I just had a few things. In East Texas the new drilling for the Cotton Valley horizontals, I just was curious. You gave us an idea of the well costs and so forth. What do the returns look like for those? And how do those sort of compare to your opportunities in the overall portfolio?

Alan Smith

Today the returns are in the high 20% and low 30% rate of return, and so I will tell you that those are almost the lower end of our portfolio. What we have done there is, we did a deal with a private operator that’s very active in the area, say like they can drill the wells cheaper than that we could drill the wells for. And then we have carried interest in that, 25% carried interest in the first four wells which significantly enhances our economics. This is sort of one another thing I wanted to clarify the transaction expenses also included freeze related to the GP buyout that we executed in the beginning of the quarter, I apologize.

Noel Parks - Ladenburg Thalmann

Actually, no problem. That actually is maybe connected to one other thing I wanted to ask. I did notice that the -- you said the G and A came in a good bit lower in the quarter than you'd expected. I wonder, was some of that because you had some of the activity wound up in those other categories, in the transaction categories, et cetera?

Alan Smith

You know, Noel, I think a little bit was related to the allocation between ourselves and the private side of the business, the sponsor. Also just a little bit of this reduction in direct cost as well.

Noel Parks - Ladenburg Thalmann

Okay. Great . And also, in Jay Field, I heard you say that there were signs of actually more oil in place than was known before. And I was surprised to hear, for such an old field and mature field, that you -- that you would find more of the oil in place. Can you just talk about a little bit about how you -- how you arrived at that?

Alan Smith

Yes, I think one of the things that we have been doing out there that’s been responsible for all of good results out there, is we have been going into wells and cleaning wells out. And so, parts of the field are seeing water injection and production that hasn't seen this in the last 20 years. So we are accessing more of the reservoir today with these cleanups and we work for, and you know it was performing very well. So that along with some of the reserve oil and petro-physical work that we have done, looking for the bank oil and that kind of stuff, leads us to believe that there is quite a bit of addition of oil left were recovered out here.

Noel Parks - Ladenburg Thalmann

Can you give us a sense of -- I don't know -- incrementally [higher oil in place] number? Is it maybe a couple percentage points, which in a large field could move the needle, I realize.

Alan Smith

Yes, I mean, you know this is a billion barrel oilfield is recovered, in approximately half of that, I think our proven reserves at year-end where around 18 to 20 million barrels. So a 1% increase in the type of numbers can be a really large percentage increased to the number that we currently have booked.

Noel Parks - Ladenburg Thalmann

Got you. That’s all I had.


Your next question comes from the line of John Ragozzino from RBC Capital Markets. Your line is open.

John Ragozzino - RBC Capital Markets

Cedric, you got the better part of eight months left for this year at the higher -- or the faster development pace with the higher CapEx spend. CapEx is up $82 million -- or 82%, I'm sorry. And the midpoint of production guidance is only up 3%. Can you help reconciliation those two numbers for me?

Cedric Burgher

Yes, what you’re seeing is that the lion’s share of that additional activity is in the third and fourth quarter and so you don’t see the benefit from that capital activity until really 2015 like I said if you look at our production today for the quarter we’re around 19,000 barrels a day. We anticipate going out into the year around 23,000 barrels a day so you really see the uptick in production from that capital program in 2015.

John Ragozzino - RBC Capital Markets

Okay. And then taking that for the other 16% of the CapEx budget that's been on the facilities and equipment upgrades. Are there any identifiable projects that have got a meaningful or material impact on either improving volumes or significantly reducing costs? Would you care to share anything of that -- of those with us?

Alan Smith

Well, the majority of the CapEx has been at Jay, will be spent at Jay where we’re continuing to upsize the plant out there to move more fluid both water, nitrogen oil and gas throughout the field.

John Ragozzino - RBC Capital Markets

Okay. And then -- forgive me if I missed this at the beginning but we had a previously announced $70 million in first quarter acquisitions. Was there any detail that you gave that I did not get at the beginning of the call that were associated with those transactions or is it something we can discuss offline?

Alan Smith

No, I don’t’ think we’ve -- yes the 70 was since the August acquisition last year just to clarify that some was into 2013, but no I don’t think we really provide any more information that what we’ve already given. And really about 32 that was an East Texas acquisition that was predominately gas and then the balance of that was the bolt-on in East Texas field.

John Ragozzino - RBC Capital Markets

Okay, fair enough. Thanks for the clarification. I apologize. That's all I've got for you. Thanks guys.


There are no further questions at this time. We’ll turn the call back over to presenters.

Alan Smith

Okay, well, we certainly appreciate everyone’s time this morning. As you know, if you have any further questions, feel free to all call, Josh or Cedric, and we’ll get you those answers pronto. So thanks for your time this morning.


This concludes today’s conference call. You may now disconnect.

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