Filed by Breitburn Energy Partners LP
Commission File No. 001-33055
Pursuant to Rule 425 Under the Securities Act of 1933
And Deemed Filed Pursuant to Rule 14a-12
Under the Securities Exchange Act of 1934
Subject Company: QR Energy, LP
Commission File No. 001-35010
This filing relates to a proposed business combination involving QR Energy, LP, a Delaware limited partnership (“QR Energy”) and Breitburn Energy Partners LP, a Delaware limited partnership (“Breitburn”).
Breitburn Energy Partners LP
Third Quarter 2014 Results Conference Call
November 5, 2014
Operator:
Ladies and gentlemen, thank you for standing by. Welcome to the Breitburn Energy Partners Investor Conference Call. Breitburn’s press release issued earlier today is available from its website at www.breitburn.com. During the presentation, our participants will be in a listen-only mode. Afterwards, securities analysts and institutional portfolio managers will be invited to participate in a question and answer session. If you have a question at that time, you will need to press star, one, on your telephone. As a reminder, this call is being recorded today. A replay of the call will be accessible until midnight Wednesday, November 12th by dialing 877-870-5176 and entering conference ID 6782123. International callers should dial 858-384-5517. An archive of this call will also be available on the Breitburn website at www.breitburn.com.
I would now like to turn this call over to Antonio D’Amico, Vice President, Investor Relations and Government Affairs of Breitburn. Please go ahead, sir.
Antonio D’Amico:
Thank you and good morning everyone. Participating with me this morning are Hal Washburn, our CEO; Mark Pease, our President and Chief Operating Officer; and Jim Jackson, Chief Financial Officer. Please note that later in the call we will be referring to a slide deck which you can find in the Events and Presentations section of the Investor Relations tab on our website. After our formal remarks, we will open the call for questions from securities analysts and institutional investors.
Let me remind you that today’s conference call contains forward-looking statements within the meaning of the Federal Securities Laws. All statements other than statements of historical facts that address future activities and outcomes are forward-looking statements. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ materially from those expressed or implied in such statements. These forward-looking statements represent our best estimates today and are based upon our current expectations and assumptions about future developments, many of which are beyond our control. Actual conditions and those assumptions may and probably will change from those projected over the course of the year. A detailed discussion of many of these uncertainties is set forth in the Cautionary Statement relative to forward-looking information section that is contained in today’s earnings press release and under the heading Risk Factors which is incorporated by reference from our Annual Report on Form 10-K, currently on file for the year ended December 31st, 2013, and our quarterly reports on Form 10-Q, our current reports on Form 8-K, and our other filings with the Securities and Exchange Commission. Except where legally required, Breitburn undertakes no obligation to update publicly any forward-looking statements to reflect new information or events.
Additionally, during the course of today’s discussion, Management will refer to adjusted EBITDA and distributable cash flow which are non-GAAP financial measures and are reconciled to their most directly comparable GAAP measures in our earnings press release issued this morning. Management believes that these non-GAAP financial measures enhance comparability to prior periods. Adjusted EBITDA is presented because Management believes it provides additional information relative to the performance of Breitburn’s business, such as our ability to meet our debt covenant compliance tests. Distributable cash flow is used by Management as a tool to measure the cash distributions we could pay to our unitholders. This financial measure indicates to investors whether or not we are generating cash flow at a level that can support our distribution rate to our unitholders. These non-GAAP financial measures may not be comparable to similarly titled measures of other publicly traded partnerships or limited liability companies because all companies may not calculate Adjusted EBITDA or distributable cash flow in the same manner.
With that, let me turn the call over to Hal.
Hal Washburn:
Thank you, Antonio. Welcome everyone and thank you for joining us today to discuss our third quarter results and our plans in the Permian. When we discuss our horizontal drilling program in the Permian later in the call, we will be referring to a slide deck which you can find in the Investor Relations tab on our website.
One of our primary focuses during the third quarter was to move our pending acquisition of QR Energy forward so that we could close as soon as possible, and we appear to be ahead of our original schedule. Back in August, we received notice of early termination of the waiting period under Hart Scott Rodino, and more recently on October 17th, our Registration Statement was declared effective by the SEC, allowing the QR Energy unitholder vote to be set for November 18th. We need a simple majority of the votes cast, and by way of reminder, approximately 37% of the voting unitholders have already agreed to vote in favor of the transaction. We would expect to close on or before by November 21st.
The QR Energy acquisition will be the largest in Breitburn’s history and we are excited about what it means for our company. Upon closing, we will be the second largest upstream MLP by a long shot in a business where size and scope matters. We will be geographically diverse with production coming from seven different areas throughout the United States. Our expanded size and footprint will present us with greater opportunities and in turn allow us to high-grade our capital budget to focus on those properties with the best rates of return. We like having the flexibility to pick and choose to develop only the best products—projects, especially in this current commodity price environment. The Breitburn team has been working very hard to ensure a seamless integration of our two engineering-centric companies once the deal closes.
Before turning the call over to Mark and Jim, who will discuss our operating and financial results in more detail, let me briefly review some of our third quarter highlights. As we all know, during the third quarter oil prices started moving off the high that they hit back in June. In light of this downward movement in the price of crude, we are especially pleased with our team’s efforts during the third quarter to reduce leases operating expenses across all of our properties. Not only did we reduce LOE per BOE by 11% compared to the previous quarter, we also drove LOE per BOE lower than the same period last year. We think this is particularly important in light of the current price environment.
We delivered solid financials during the third quarter, reporting Adjusted EBITDA of $118.7 million for the third quarter, which is a record quarterly high for Breitburn and an 8% increase from the second quarter. The increase was primarily the result of higher oil sales volume and lower commodity derivative settlements. In anticipation of the QR Energy acquisition closing in the coming weeks, we held our monthly cash distribution steady at $0.1675 cents per unit or approximately $2.01 per unit on an annualized basis. This represents a 3% increase over the third quarter of 2013. You will recall that we have agreed to recommend to our Board that it raise our distribution to $2.08 per common unit on an annualized basis upon the closing of the QR Energy transaction.
Finally, I wanted to make sure to mention how excited we are about our recent strategic acquisition of additional acreage in the Permian. As Mark will show you, this new acreage is very complementary to our existing footprint in the Midland Basin and gives us a very cohesive position in our primary horizontal development area in the Permian. With higher rates of returns than vertical wells, our horizontal program in the Permian makes even more sense if the current oil strip stays at this level for a prolonged period. We believe that this strategic acquisition enhances the net asset value of Breitburn’s Permian Basin position now and in the future.
With that I’ll turn it over to Mark Pease.
Mark Pease:
Thanks, Hal. The third quarter was very busy as we spent about $108 million in capital to drill and complete 85 gross, 55.6 net wells and to complete 25 gross, 22.6 net workovers during the quarter. This is almost double the number of wells drilled by Breitburn in any prior quarter and reflects the ramp up and efficiencies of our drilling and completion programs. Our drilling time in Texas has been reduced from 20 days to 16 days per well during 2014. Total production for the third quarter was approximately 3.4 million barrels of oil equivalent. Our average daily production for the third quarter was 36,450 barrels of oil equivalent per day, an 8% increase compared to the third quarter of 2013. Production mix for the quarter was 57% oil, 7% NGLs, and 36% natural gas.
Lease operating expenses and processing fees for the third quarter, excluding production and property taxes, were $18.70 per BOE, which is down 11% compared to the second quarter LOE. We saw significant reductions in LOE in California and Texas, mainly as a result of lower well servicing costs, lower facility repair costs, and lower rental equipment costs. In light of the declining oil prices mentioned by Hal, we are especially proud of the focus and effort our field and office production teams and what they have demonstrated in keeping those costs down. The entire team has been very proactive on reducing LOE.
Let me spend a few minutes highlighting some key operations and then we’ll go into a little more detail on the Permian Basin.
California was our second busiest area behind Texas during the third quarter. We spent $32 million in capital drilling 33 wells and completing 10 workovers. The new drill wells were all in the Belridge Field and we are pleased with the way the reservoir at Belridge is responding to our drilling program. The workovers were mainly in the Santa Fe Springs and East Coyote fields. These capital projects added net initial production of about 1600 barrels of oil equivalent per day. As I mentioned earlier, we saw significant savings in controllable LOE in California, which was about $7 million lower than the prior quarter. These savings were primarily a result of reduced costs for contract labor and rentals, lower facility repair costs and improved efficiency of well work.
Moving to the Postle area in Oklahoma, we are starting to see the results of our CO2 injection efforts at the North East Hardesty Unit. As I mentioned on our last earnings call, we started CO2 injection in the North East Hardesty Unit in five new flood patterns during the second quarter of the year. The reservoir is responding as expected and production has increased about 175 barrels of oil equivalent per day from these five patterns. We plan to start CO2 injection into 15 more patterns in Northeast Hardesty in early 2015, and each pattern is expected to reach peak production of 50-60 barrels of oil per day.
Looking at Oklahoma as a whole, production for the year is performing very much in line with our expectations coming in just below our forecast. However, Q3 production came in at 582,000 barrels of oil equivalent, which was down 6% compared to second quarter production. For the most part, this decline was the result of a larger volume of CO2 being required to support base production than what was originally forecast. This resulted in a slightly steeper decline in base production and some deferred PUD development. We are working on increasing our CO2 supply and continue to be confident in the long-term success of our existing CO2 floods and in our ability to leverage our position in the area to develop new opportunities. We had a very good quarter on controllable LOE with it coming in about $3 million or $5.15 per barrel below forecast. Improved methods driving lower well service costs and strong operating cost control focus by our field group were the two main factors in this reduction.
Now let’s talk about the Permian Basin. I would like to direct you to the slide deck that is available for your viewing on our Investor Relation tab on our website.
As we mentioned during our last call, we have spent a great deal of time and effort analyzing the performance of thousands of vertical and horizontal wells, both Breitburn operated and those operated by other companies. Based on those analyses, we said that we were transitioning to a horizontal well development program. The combination of continued strong production results coming from horizontal wells close to our acreage, and the closing of the Antares acquisition on October 24th, has accelerated that transition.
By the end of the first quarter of 2015, we expect to have drilled 15 vertical wells. Other than those wells, we have no plans to drill additional vertical wells. We see the horizontal wells as providing us much higher rates of returns and much more financial structuring flexibility, particularly during periods of low crude prices.
On Page 3 of the slide deck, you will note that the newly acquired Antares acreage shown in green sits right in the middle of our primary horizontal development area in Howard County and is a very good fit with our existing acreage. We acquired approximately 4,600 gross, 3,600 net acres which represent 67% and 64% increases, respectively, to Breitburn’s previous acreage position in this area. All of the acreage is company-operated and by the end of the first quarter next year we expect it all to be held by production. The estimated average daily net production for October from these properties was approximately 600 barrels of oil equivalent per day.
Turning to Slide 4, the new acreage is contiguous with our existing acreage in Howard County which will greatly facilitate the creation of horizontal drilling units and allow us to pursue our horizontal drilling program in a much more effective and efficient manner. This new acreage adds 32 potential horizontal locations to our existing inventory and, assuming five different productive zones, we see the potential for about 160 laterals. We expect to develop the area using approximately 7,000 foot laterals.
Now let’s move to Slide 5. While we recognize that any drilling program has risk, we believe those risks are significantly reduced by the number of successful horizontal wells surrounding our acreage. As you can see on this slide, there are at least four horizontal wells in our primary development area and an additional six horizontals in the nearby surrounding area; all have had positive results, mostly from the Wolfcamp A, but also from the Wolfcamp B and the lower Spraberry. One of these wells is the Willbanks 16-15 where we have a non-operated working interest. The operator of the Willbanks well has already applied for a permit to drill a second bench in which Breitburn will participate.
If you turn to Page 6, we provide further detail about the performance of the Wolfcamp in Element and Athlon wells close to our acreage and also in the Pioneer wells in the Martin and Midland counties. As you can see, the performance of both sets of wells has variability, but these two sets are overall very similar. This gives us a lot of confidence and comfort in the parameters that we are using to develop our economic and development plans.
Page 7 shows the performance for the lower Spraberry, for the Element Wright 44-41 well in Howard County, an Athlon well in Martin County, and a curve showing a 7-well average for a set of wells operated by Pioneer in Martin and Midland counties. Very good performance is exhibited by all these wells.
Page 8 summarizes our acreage position pre and post Antares, and identifies the benches that present opportunities for us. Our primary focus now will be on the Wolfcamp A and B and the Lower Spraberry, and in our primary development area alone, we’ve identified 135 possible net horizontal laterals. If you include the Upper and Middle Spraberry, which have not been extensively tested in our area but are being tested elsewhere in the Permian Basin, the number of potential net horizontal laterals increases by 90 for a combined total of 225. Assuming our acreage in Martin and Howard County gets fully developed at some point, the number of total net laterals is 618. This represents a lot of running room for development. Assuming a single horizontal rig, our primary development area has a 19-year inventory of locations and over our entire acreage position, we have an inventory of approximately 50 years. As I’ll discuss on Slide 11, we are currently evaluating a number of options to accelerate that development timeframe.
Slide 9 shows the relative location in the wellbore and approximate depth of the various zones that we believe have potential. The Wolfcamp A, Wolfcamp B and lower Spraberry, which have all been tested close to our acreage, are shown on the right side of the page and the other potential zones are shown on the left side.
As I mentioned earlier, we are already participating in the outside operated Wilbanks well. We intend to start drilling with a company operated horizontal rig in February, as shown in Slide 10. We do not intend to fund all of our horizontal opportunities on our own, but our current plan is to run one Breitburn-funded rig from February through December of 2015. We will use the information we gather from the funded wells to assist us in our continuing discussions with other interested operators and financial sponsors. As our discussions with those parties progress, we will likely add more rigs later next year and into 2016. We are confident that there is a win-win path forward for Breitburn and potential third-party investors and partners to make horizontal wells in the Permian Basin more MLP friendly.
Slide 11 shows a number of possible strategic options that are being evaluated, and we do intend to evaluate all options. The options we are considering are: financial sponsor investment, JV or Farmout, acreage trade or swap, trade for producing assets, and a sale or divestiture. In the end, we believe the value of our position is great and that one or some combination of the foregoing options will add significant value to our position. We are very excited about this new development phase.
With that, I’ll turn the call over to Jim.
Jim Jackson:
Thank you, Mark. I’ll start by reviewing selected results for the third quarter and then discuss our recent financing activities and liquidity profile.
Adjusted EBITDA for the third quarter was $118.7 million, an 8% increase from the $110.0 million during the second quarter, principally due to lower commodity derivative settlement payments, higher oil sales volume partially offset by lower commodity prices, particularly in crude oil. We reported approximately $3.7 million in commodity derivative instrument settlement payments this quarter compared to $17.0 million in the prior quarter, primarily due to lower crude oil prices during the quarter. Realized crude oil prices were about 6% lower than the second quarter.
Realized oil, NGL and natural gas prices, excluding the effects of commodity derivative settlements, averaged $90.12 per barrel, $37.87 per barrel and $4.12 per Mcf, respectively, in the third quarter, compared to $95.74 per barrel, $38.26 per barrel and $4.81 per Mcf, respectively, in the second quarter. Brent crude oil spot prices, which are an important benchmark for our California oil production, averaged $101.90 per barrel in the third quarter compared to $109.69 in the second quarter.
Turning to earnings, we recorded a net gain attributable to our common unitholders of approximately $126.5 million or $1.03 per diluted common unit for the third quarter, which includes $149.0 million of non-cash gains on derivative instruments, as compared to a net loss of $106.6 million or $0.89 per diluted common unit for the second quarter which included $110.0 million of non-cash losses on derivative instruments. By way of reminder, the large swing in our earnings results is primarily due to the fact that we do not account for our derivative instruments as cash flow hedges for financial reporting purposes and instead we mark-to-market the value of our portfolio and recognize changes in fair value immediately in our earnings.
Cash interest expense for the third quarter was $27.8 million compared to $28.4 million in the second quarter.
Distributable cash flow was $53.3 million in the third quarter compared to $52.7 million in the second quarter. This amount reflects Adjusted EBITDA of $118.7 million, less cash interest expense of $27.8 million, less accrued distributions of $4.1 million on our Series A preferred units, and less an estimated amount for maintenance capital of approximately $33.4 million.
Distributable cash flow in the third quarter was $0.39 per common unit versus $0.43 per common unit in the second quarter. However, accounting for the 14 million unit equity deal that we did in October to prefund a portion of the cash consideration in the QR Energy transaction, we generated $0.435 of distributable cash flow per unit which is—in the third quarter which is just slightly ahead of Q2.
Now I’d like to provide a brief update on our hedge book. Based on our current hedge book and our third quarter production run rate, our production is hedged at 84% in the fourth quarter of 2014, 76% in 2015, 60% in 2016 and 31% in 2017. Average annual prices during these periods range between $93.87 and $84.71 per barrel for oil, and $4.95 and $4.44 per MMBtu for gas. As we’ve mentioned in the past, QR Energy’s hedge portfolio is very similar to our own, as it also stated, our strategy has been to build a book opportunistically at attractive prices and historically we have hedged aggressively in conjunction with our acquisitions which we plan to continue doing going forward.
An updated version of Breitburn’s commodity price protection portfolio presentation summarizing our hedges will be available in the Events & Presentations section of the Investor Relations tab on our website later this morning.
Now I’d like to review our recent financing activities. On October 6th, we successfully launched and completed a 14 million unit offering of common units; price to the public was $18.64 per unit. We received net proceeds of approximately $252 million, which were used to reduce outstanding borrowings under our bank credit facility. As we noted in our announcement of the QR Energy acquisition, we have received a firm commitment from Wells Fargo to increase our credit facility to $2.5 billion in connection with the closing. That deal has been fully syndicated to a group of 35 banks. We intend to use that increased capacity in part to repay QR Energy’s existing bank debt, redeem its Class C convertible preferred units and refinance the outstanding QR Energy senior notes in connection with closing. Our successful equity offering allowed us to pre-fund some of the cash requirements in connection with the closing. We are pleased to have completed the offering despite the recent market volatility.
As for our liquidity position, our current outstanding debt balance is approximately $1.7 billion and consists of borrowings of $590 million under our credit facility and approximately $1.16 billion in outstanding senior notes. Our total undrawn capacity in our credit facility, based on the $1.6 billion borrowing base and with the elected commitments from existing lenders of $1.4 billion, is $810 million.
With that, we've concluded our formal remarks. Operator, you may now open the call for questions.
Operator:
Yes, sir, thank you. If you would like to ask a question, please signal by pressing star, one, on your telephone keypad. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal time to reach our equipment.
Once again, that is star, one, to ask a question. We'll pause for just a moment to allow everyone the opportunity to signal for questions.
We will take our first question from Abhi Rajendran with Credit Suisse. Please go ahead.
Abhi Rajendran:
Hi. How are you guys?
Hal Washburn:
Good. How are you?
Abhi Rajendran:
Good. A couple of quick questions. You mentioned on the hedging side, just following up on that, what are you guys seeing just in terms of like the hedging market? Given some of the recent commodity weakness, you know, how are you guys playing that? And how are you looking to kind of play that, I guess over the near term, and then looking out to the next couple of years?
Hal Washburn:
This is Hal. We are very well hedged today, and we are pro forma for the closing transaction with QR energy, so we don't have a need at this point to go into the markets. We have, and we will continue to as Jim mentioned, hedge aggressively on acquisitions, and historically that's been a large part of how we’ve built our hedge book in other years, and we will continue to do that. So in conjunction with acquisitions going forward, we will hedge 80% or more of expected production for three, four or five years. We'll continue to do that. But really, right now, we have a very strong hedge book and we're comfortable with where we are absent new acquisitions.
Abhi Rajendran:
Okay, got it. Then, just kind of again, given the recent commodity volatility, obviously you guys are focused on QRE at the moment, but what are you guys seeing sort of generally on the M&A landscape in terms of sellers, and multiples and willingness to sell, and things like that? Just any color there would be helpful.
Hal Washburn:
Sure. You know, we've been in this business for 26-plus years. We've been through a lot of cycles and what we find is when there's rapid change in commodity prices, either up or down, buyers and sellers' expectations take a bit of time to align, and so we haven't seen any significant acquisitions being done since kind of the prices really started moving in the summer. However, there's a lot of properties on the market and we're seeing a lot of things. I think that prices should be somewhat lower, on most of the properties that we're looking at, at least oil producing properties, than might have been in the first or second quarter of this year.
Abhi Rajendran:
Okay.
Hal Washburn:
But one other thing to keep in mind, historically, as a company, we have really thrived in the down markets. We’ve grown the company significantly historically when commodity prices were lower cycles and we like the position we find ourselves in, and hope to be able to take advantage of that if those opportunities do come up.
Abhi Rajendran:
Great, and then one last quick one from me. Previously, you guys had put out, I think, a second half production guidance of 6800/7200 MBOE. I think you had highlighted a couple of things in the third quarter that affected production, so should we sort of think about maybe the low end of that range for the second half now? Just any color there would be helpful on how we should think about the fourth quarter?
Hal Washburn:
I think we'll be around the low end of that range.
Abhi Rajendran:
Okay. Great, thanks very much.
Operator:
Next question comes from Sunil Sibal with Seaport Global Securities.
Sunil Sibal:
Hi guys. A couple of quick ones for me. First of all, you know, starting with the horizontal drilling program. I was wondering if you could talk a little bit about your overall capital needs there, if you continue with that one (inaudible) program through 2015, and also if you could talk a little bit about break even economics or IRRs, both in your prime development area and the tier one area.
Hal Washburn:
Sure. Mark, why don't you handle that one?
Mark Pease:
Yes. This is Mark Pease. Talking about the capital needs, right now we're looking at about $8.6 million per well, and you drill a well plus or minus one well a month. So, you know, when you look at 2015, we'll be just for the one rig a little over $100 million. We gave a fair amount of color during the prepared remarks about the other options we're considering, so I think the right way to think about it is we're committing to a little over 100 million for the one company-funded rig, and that we're looking very diligently for other options for those other rigs. So we will certainly keep the external world posted as we start putting some of those deals together.
On the economic side of things, you know, we've done a lot of work. Of course all the benches are not created equal. As you go back, there are a lot of industry-type curves out there that you can look at. But, you know, what we're seeing with our analyses that we've done, you know, if you assume our current well cost, and I think everybody on the phone knows there's a real close tie to materials, and equipment at services prices, and what the cost of—and what the price of oil is. We're already seeing downward pressure on our costs because of that if we use our current well costs. We—you know, we'll generate a decent rate of return, again, depending on which zone, somewhere in the $60 to $70 range. The better zones are somewhat lower than that. So, again, we’ve got room to run and keep the program going.
Hal Washburn:
One other thing to note on the horizontal program is we're actually lowering the capital intensity of our program by moving from vertical to horizontal, so we’re actually spending less capital for similar or better results in ‘15 by going to horizontal.
Sunil Sibal:
Okay, that's helpful. Then thinking in terms of, you know, other options,I think you guys previously alluded to that and you talked about previous calls. If you do see gas prices fairing better or at least relatively to oil prices, you do have other options to kind of ramp up your production from more gassier areas, and I was wondering if we could touch upon that a little bit. How are you guys thinking about that in the current price environment?
Hal Washburn:
Sure. You know, as you know, we have two main gas-producing regions, Southwestern Wyoming, and the Northern Michigan, primarily the Antrim shale. Both of those areas, we have virtually all of our acreage or virtually all of our acreage held by production so we have no need to drill development wells. But we have hundreds of held-by-production development locations in each of those areas, and they really vary by area. But, you know, we probably start drilling some of the best of those when we see gas north of five, and we're pretty comfortable that that's going to last. As we see gas go up from there, into six, or better, I think a lot more becomes economic and attractive for us. So we do have a significant exposure of natural gas and that's by design; that’s important to us. We talked about diversification of commodity repeatedly, and that is important to us, and one of the reasons that we have the portfolio that we have today.
Sunil Sibal:
Okay. That's helpful, and the last one from me. I think if you just compare your hedge portfolio between the second quarter, and this quarter, probably there was very small movement, and I was kind of wondering how you are thinking of this going forward, especially as you manage costs. Do you definitely have seen a—although you’ve come down significantly during the quarter, but would you like to manage your hedge book as you're managing your costs? How do you guys go about that process?
Hal Washburn:
Sure, we're constantly looking at our hedge book. We have focused, as Mark discussed, a lot on cost control, and reducing costs, and very successful at that. A key part of our business strategy, and has been since the first days. On the hedge book, we're very comfortable with where it is today. The hedge book that QR brings to the combined entity is very complementary to ours, and we don't feel a need to be in the market today. We will hedge all acquisitions—we always have and we always will—very aggressively. So likely in commodity price environment like today, you’ll likely see us adding to our hedge book in conjunction with acquisitions, and probably not adding a lot right now in the existing portfolio.
Sunil Sibal:
Okay, and then on the LOE front, how much more cushion do you guys have in terms of squeezing those costs, especially as you see commodity prices environment kind of maybe gives you a little bit more pricing power?
Hal Washburn:
Sure. We are constantly working on the price or the cost side of the equation. Our supply chain group is seeking out best contracts. Certainly expect to see costs of goods and services come down to reflect the lower oil price environment we're in today. That generally takes some time, so you don't see the costs of goods and services coming down as quickly as you do, or going up, frankly, as quickly as you do with the underlying commodity, but we do certainly expect to see that come down. We've historically seen kind of somewhere around 25% of movement in price being reflected in reduction in costs.
Sunil Sibal:
Okay, thanks guys. That's it for me.
Hal Washburn:
Thank you.
Operator:
Our next question comes from Praneeth Satish with Wells Fargo.
Hal Washburn:
Hey, Praneeth.
Praneeth Satish:
Hey, good afternoon. Just a couple of quick questions here. So I guess you mentioned the capital intensity in the Permian will decrease after you start up after the horizontal program. I was wondering if you could just break out exactly, just so we have it, how much capital is spent this year on the vertical program in 2014? Just trying to see what the net change would be.
Mark Pease:
Yeah, we can. It will take me just a second to get there, Praneeth.
Hal Washburn:
You know, it will go down. It will be roughly100 million for the one vertical rig and then compared to what we spent this year -- excuse me, one horizontal rig compared to what we spent this year, and Mark's getting those numbers for us.
Praneeth Satish:
Okay. We can keep going to the next question. I guess if we get to Q3, looking at the timeline in the back in terms of when a third-party investor can be brought into the program, if we get to that date and a third party isn’t found, is that something you would consider drilling within Breitburn itself, given that the returns are pretty good? I guess basically it would imply going from a one rig to two or three-rig program. I guess how do you think about that?
Hal Washburn:
You're not likely to see us pick up four rigs, company-funded. We're going to be stingy with our capital this year in light of the movement in commodity prices. You know, this reflects what we believe we can accomplish from a land and operations perspective, and we feel comfortable that that we'll be able to come to an agreement with partners. But you're not going to see us jump into this and take on four rigs company-funded without partners.
Praneeth Satish:
Got it.
Mark Pease:
Cost for Texas, you know, right now we're forecasting about $210 million in drilling Texas for 2014.
Praneeth Satish:
Okay. Got it. That helps. Then the last question I had was just, I didn't know if you've looked at all in terms of if you did just execute on the one rig, horizontal Wolfcamp program in 2015, where would that take your decline rate at the end of the year? And I guess just more broadly speaking, how do you think about managing the higher decline rate of these wells within the MLP structure?
Hal Washburn:
Sure. Well, you know, this actually won't impact our—or we don't expect it to impact our overall decline because we're basically replacing vertical wells with a similar decline profile with horizontal wells, but one of the reasons why we're looking at, you know, rigs two, three, and four, in other sorts of structures, is to make them, as we said earlier, more MLP-friendly. Several of the structures we’re looking at give the disproportionate share of production, and with it the high decline, to the financial partner, to the operating partner. So we're looking at different ways to synthetically take the high decline initial production out of the Breitburn portfolio.
Praneeth Satish:
Got it. Thank you.
Hal Washburn:
Sure.
Operator:
Next question comes from Bill Gerding with Citi.
Hal Washburn:
Hi, Bill.
Bill Gerding:
Hi guys. Just real quick, did I hear right that the closing is on or before November 21st?
Hal Washburn:
Yes, assuming the election on November 18th, we will close it on or before the 21st.
Bill Gerding:
Okay, perfect. Then just as far as logistics, are you taking these out because you need to be able to pledge those assets to upsize the revolver, or what’s kind of the reasoning for that?
Mark Pease:
Yes, that's exactly correct.
Bill Gerding:
Okay, perfect. Do you plan on using the equity claw provision in the bonds to take it out?
Mark Pease:
You know, we're looking at all of our options there, but I think it's fair to assume we'll take advantage of that, yes.
Bill Gerding:
Okay. Perfect. That's it for me.
Mark Pease:
Okay. Thanks.
Hal Washburn:
Thanks, Bill.
Operator:
Next question comes from Jeff Robertson with Barclays.
Hal Washburn:
Hey Jeff.
Jeff Robertson:
Hal, you've already answered my question.
Hal Washburn:
Okay, thanks.
Operator:
We go again to Sunil Sibal with Seaport Global Securities.
Sunil Sibal:
Hi, guys, one quick follow-up for me. Previously you had guided to an exit rate of 38—call it 1,400 to 48,800 on the total production. How should we think about that with what you're seeing right now?
Hal Washburn:
With the transition away from the vertical drilling, I think we're probably not going to hit that exit rate because we're laying down vertical rigs and preparing to drill horizontals. As Mark said, we're just drilling obligation wells from now on on the vertical program.
Sunil Sibal:
Okay. Thanks, guys.
Operator:
As a reminder, star, one, if you do have a question, and we will take our next question from Jeremy Tonet with JPMorgan
Unidentified Speaker:
Hey guys. It’s actually (Inaudible) filling in for Jeremy.
I just wanted to go back to the Permian. Did you guys say earlier that returns are in the 60 to 70% range at current oil pricing? Did I hear that correctly?
Hal Washburn:
What we said was we had acceptable rates of returns down—depending on the zone—in 60 to 70, or lower.
Unidentified Speaker:
Sixty (cross talking).
Hal Washburn:
Sixty or seventy dollars per barrel or lower.
Unidentified Speaker:
Got you, okay. I see. Then considering obviously the significant move in oil, how has that changed discussions with potential partners? I guess you guys are still seeing a lot of interest there?
Hal Washburn:
Yes. There's still a lot of interest. I mean obviously the discussions are all very fluid however the economics are compelling at today's oil prices, and they really are compelling with lower oil prices. So, I think there's a lot of interest in doing something, and we do have a position, a very valuable position, and so we continue to be excited, and there continues to be a lot of interest.
Unidentified Speaker:
Okay, great. Thanks, guys. That's all I had.
Hal Washburn:
Thank you.
Operator:
As a reminder, it is star, one, if you do have a question; that is star, one.
There are no further questions at this time. I would like to turn the conference over to Management for closing remarks.
Hal Washburn:
Thank you, Operator. On behalf of Mark, Jim and Antonio and the entire Breitburn team, I want to thank everyone on the call today for their participation. Operator, you may now bring this call to a close.
Operator:
Thank you. Ladies and gentlemen, that does conclude today’s conference. We do thank you for your participation and you may now disconnect. Have a great rest of your day.