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BreitBurn Energy Partners L.P. (NASDAQ:BBEP)

Q3 2013 Earnings Conference Call

November 6, 2013 01:00 PM ET

Executives

Greg Brown - Executive Vice President, General Counsel, and Chief Administrative Officer

Hal Washburn - Chief Executive Officer

Mark Pease - President and COO

Jim Jackson - Chief Financial Officer

Analysts

John Ragozzino - RBC Capital Markets

Ethan Bellamy - Baird

Michael Peterson - MLV & Company

Noel Parks - Ladenburg Thalmann

Kevin Smith - Raymond James

Dan Guffey - Stifel

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the BreitBurn Energy Partners' Investor Conference Call. The partnership's news release made earlier today is available from its website at www.breitburn.com. During the presentation 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. (Operator Instructions).

As a reminder this call is being recorded November 06, 2013. A replay of the call will be accessible until midnight Wednesday, November 13th, by dialing 877-870-5176 and entering conference ID 5755701. 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 the call over to Greg Brown, BreitBurn’s Executive Vice President, General Counsel, and Chief Administrative Officer. Please go ahead sir.

Greg Brown

Thank you, operator and good morning everyone. Participating with me this morning are Hal Washburn, BreitBurn's CEO; Mark Pease, BreitBurn's President and Chief Operating Officer and Jim Jackson, BreitBurn’s Chief Financial Officer. After our formal remarks, we will open the call up for questions from security 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 are 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 we projected over the course of the year.

A detailed discussion of many of these uncertainties are set forth in the cautionary statement relative to forward-looking information section of today’s release and under the heading Risk Factors incorporated by reference from our Annual Report on Form 10-K currently on file for the year ended December 31, 2012, 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, the partnership undertakes no obligation to update publicly any forward-looking statements to reflect new information.

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 as management believes it provides additional information relative to the performance of the partnership's business such as our ability to meet our debt covenant compliance test. Distributable cash flow is used by management as a tool to measure the cash distributions we could pay to our unit holders, its financial measure indicates to investors whether or not we are generating cash flow at a level it can support our distribution rate to our unit holders. 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 out of the way, let me turn the call over to Hal.

Hal Washburn

Thanks you, Greg. Welcome everyone and thank you for joining us today to discuss our third quarter 2013 results. We are very pleased to announce another quarter of record operating and financial results. We delivered record quarterly net production for the second consecutive quarter of $3.1 million barrels of oil equivalent, which represented a 26% increase from the prior quarter and the 43% increase from the third quarter of 2012.

Production results for the quarter benefited from significant organic growth driven by our capital program and the added production for the Whiting acquisition. The liquids productions also reached to record quarterly high of $1.9 million barrels and now accounts for 61% of total net production as compared to 45% of total net production just one year ago.

This significant shift in our production mix is the result of our 2011 and 2012 capital programs that targeted high margins liquids oriented development opportunities and our acquisition efforts targeting principally oil related opportunities as well. So far we are very pleased with the outcome. We have increased our exposure to oil which allows us to maximize returns based on commodity prices. Yet our portfolio also gives us ample flexibility to pursue gas projects when gas prices recover.

For the remainder of 2013 and in the 2014 we will continue to be very active particularly with oil related development opportunities in our newly acquired Oklahoma properties as well as in Texas and California.

Our financial results this quarter were also very good. Adjusted EBITDA for the third quarter was $112.1 million, which was a record quarterly high for the partnership for the second consecutive quarter. Adjusted EBITDA for the third quarter increased 32% from the prior quarter and 46% from the third quarter of 2012. Given our strong performance this quarter and our outlook for the remainder of the year, we remain confident in our ability to deliver on our second half 2013 public guidance that we announced in June.

I'd like to give you a brief post closing update on the Whiting acquisition. As you know we closed the acquisition on July 15, Whiting continue to operate the properties through October 31 as part of the transition services agreement. We assumed operations on November 1 and the transition has gone very well. Production has been running slightly above our valuation forecast since closing. Mark will provide further details on our Oklahoma operations later in this call.

Turning to distributions, we announced last week our third quarter distribution of $0.4875 or $1.95 per unit on an annualized basis, payable November 14th to record holders as of November 11th. This represents a 4.8% increase from the third quarter of 2012 and is our 14th consecutive quarterly increase. As I have said before, future distribution growth is supported by the quality of our asset base, our organic growth prospects, ongoing acquisition success and a strong hedge portfolio.

As highlighted in our earnings release issued this morning, I'm very pleased to announce that our Board of Directors has approved a change in the partnership's distribution payment policy from a quarterly payment schedule to a monthly payment schedule beginning with the distributions relating to the fourth quarter of 2013. The expected monthly payment schedule which begins in January 2014 is further detailed in our earnings press release. Our decision to change distribution payment policy was made after hearing many of our investors voice their preference for receiving more frequent cash flow from BreitBurn and their other yield oriented investments. We believe that this change addresses growing demand for investment options paying monthly distributions and will more efficient return capital to our investors. Gathering and responding to investor feedback is a very important part of our business.

Overall we had an excellent quarter. We've been very successful in integrating the newly acquired assets in Oklahoma, growing production organically and improving our distribution coverage ratio throughout the year as planned. We've had a tremendous amount of growth year-to-date and we're looking forward to the balance of 2013. Our acquisition and evaluations team continues to seek out new opportunities and what remains a very robust market. We're looking to bolt-on oil and gas acquisitions in areas where we currently operate as well as in new areas. Year-to-date our acquisition and evaluations team has looked at over 360 deals, has fully evaluated almost 20 and we've completed three.

Looking forward, we believe we're well positioned to continue executing on our growth through acquisition strategy. As I've mentioned before we're closely monitoring the market for opportunistic financing opportunities to reduce leverage and fund future growth. We're also examining the combination of financing methods that are suitable for the partnership and are confident in our ability to quickly execute on those transactions when the time is right.

With that we look forward to a strong finish to 2013 and continued growth in 2014. I want to thank the BreitBurn team for their hard work and dedication and our investors for their continued support.

With that I’ll turn the call over to Mark, who will discuss operating results for the quarter.

Mark Pease

Thanks Hal. We had a very solid third quarter from an operation standpoint. And we are pleased to see our 2013 capital program continuing to deliver strong results. We completed 54 gross, 51.1 net drilled wells and 19 workovers during the third quarter, which added total incremental net initial production of approximately 2,730 barrels of oil equivalent per day.

As planned at start of the year, Q3 activity was a significant ramp up from the 38 drilled wells and 21 workovers that were completed in the second quarter. And I am pleased to announce that for the second consecutive quarter, we delivered record net quarterly production of 3.1 million barrels of oil equivalent, which was above the midpoint of our guidance range.

Liquids production was another record quarterly high at 1.9 million barrels of oil equivalent, which represented a 94% increase from the third quarter of 2012. And a 47% increase from the second quarter of 2013. As Hal mentioned earlier, the increase in liquids production this quarter was a result of strong organic growth and the addition of the Oklahoma assets from the Whiting acquisition. Excluding the Whiting acquisition, production from our legacy assets was up about 3% from the prior quarter.

As you can see from the increased activity and organic production growth, we are pleased with the rate at which we are deploying capital across our asset base and with the result that it’s delivering. We spent a total of about $87 million in capital this quarter which was virtually all focused on higher margin oil projects. This is up 30% from the second quarter primarily due to increases in both Florida and Texas activity and to the ongoing work program on the properties from the Whiting acquisition.

Our production mix for the quarter was about 61% oil and NGLs and 39% natural gas compared to 52% oil and NGLs and 48% natural gas for the prior quarter. Lease operating expenses and processing fees for the third quarter excluding production and property taxes were $18.76 per Boe compared to last quarter’s $19.79 per Boe. This reduction was primarily due to lower expenses in California and Florida and Oklahoma lease operating expenses being lower than the company average prior to the acquisition.

Overall LOE for the third quarter is well within our guidance range. With the success of our capital program and our continued focus on controlling cost, we are well positioned to meet our second half 2013 operating guidance.

Now I will walk through different operating areas by state. First let’s talk about California. We had another quarter of very operating results from our California sales. Production for the third quarter came in at 458,000 barrels of oil equivalent which was better than forecast and 8% higher than the prior quarter. And our second quarter was about 13% higher than the first quarter. Year-over-year Q3 2013 California production was up 55% compared to Q3 2012. Capital expenditures in California totaled $23 million for the third quarter and included 20 drilled wells and 4 workovers. Much of the production increase this quarter can be attributed to our Belridge Field for the new drilled wells are performance very well due mainly to optimizing the completion and stimulation procedures.

For the quarter we completed 14 new wells at the Belridge Field, eight producers and six injectors. And we completed six new wells in our Santa Fe Springs Field, five producers and one injector. In total capital activity for the quarter added incremental net initial production of about 870 barrels of oil equivalent per day which is above our pre-drill expectations.

Facility work is ongoing at Belridge and Santa Fe Springs to not only accommodate production from our current activity, but also to handle production from future drilling and recompletion activity. The production in treating equipment in the Belridge and Santa Fe Springs Fields is currently fully utilized. Additional production capability will be added in 2014 to handle the significant future development that we see in both fields.

California controllable LOE was $13.3 million or $28.98 per Boe for the quarter which was 19% lower on a per Boe basis than the prior quarter primarily due to higher oil production from our capital program and less well maintenance work.

California continuous to be a key area of focused due to our concentration of oil assets that still have large amounts of oil in place. Moreover, our California assets have responded very well to our work programs and continue to drill the results that meet or exceed expectations. And we expect to remain very active here for the remainder of the year and into 2014.

Now let’s talk about Texas, it’s our most active area based on 2013 capital spending. Net production for the quarter came in at 367,000 barrels of oil equivalent which was below our forecast, but 3% higher than the prior quarter due to the new drilled wells that are being brought online. We continue to see gas curtailment impacting production though on a reduced rate compared to the prior quarter due to the installation of booster compression on the WTG system and start up of the new plant on the DCP system. We are working closely with the gathering and processing companies to maximize production and minimize curtailment. Production is also impacted during the quarter by some well buyers and we are continuing to refine our artificial lift designs.

Capital expenditures in Texas totaled $33 million for the quarter and included the drilling and completion of 16 gross, 14.1 net new drilled wells compared to 14 gross, 10.5 net new drilled wells in the second quarter. In total capital activity for the quarter had an incremental net initial production of about 1,200 barrels of oil equivalent per day which is consistent with our pre-drill forecast.

In Texas, we have a big rig count of five rigs running in the third quarter including our first BreitBurn operated rig. We currently have two BreitBurn operated rigs and one non-operated rig running for a total of three rigs. We expect to run three to four rigs for the remainder of the year and by year-end the majority of the drilling operations will transition from CrownQuest to BreitBurn.

Controllable LOE for the quarter was approximately $3.7 million or $10.9 per B0E, up from the $8.43 per BOE in second quarter mainly due to the increased well servicing cost I mentioned earlier.

Now let's move North to Wyoming. Production for the quarter was 655,000 barrels of oil equivalent which was slightly above forecast and essentially flat compared to the prior quarter. The Greasewood Field in Eastern Wyoming continues to respond favorably to the expanded water flood. And the three wells we drilled in the field during Q3 came on production better than our pre-drill forecast.

Capital expenditures in Wyoming for the quarter were about $7.9 million, which included completing a total of 10 drilled wells and 6 workovers. Wyoming operating team has done a good job controlling operating costs as controllable LOE for the quarter was $7.3 million or $11.21 per Boe which was under forecast and lower than the $12.32 per Boe and $11.49 per Boe that we reported for the first and second quarters respectively.

Okay. Let’s go South now to Florida. Production for the quarter was 175,000 barrels of oil equivalent which represented 10% increase from the prior quarter’s production of 159,000 barrels of oil equivalent. Production increased in Q3 despite significant downtime from oil this quarter which lowered production about 250 barrels of oil per day more than normal. We added two members to the Florida team during the quarter to help increase activity level. Senior [foremen] who has moved from our Michigan operations and a production engineer who will be located in the Florida office.

During the quarter we completed the Bear Island 3-7 drill well which tested essentially all water. Earlier in the year water production in Raccoon Point 2710 was reduced from 2,660 barrels of water per day to 2,030 barrels of water per day and oil production increased from 65 barrels of oil per day to 82 barrels oil per day by pumping a chemical water shut-off treatment to isolate high permeability water zones. We're currently evaluating Bear Island 3-7 for similar treatment. Controllable LOE for the quarter was about $9.2 million and slightly above forecast but was 10% below Q2 LOE on a per BOE basis. Oil production which on scheduled for two barge shipments during the third quarter.

The second shipment was scheduled for September 16. However, the barge was not release from the port because of mechanical issues. This delayed our second shipment into early October. We have completed two shipments today in Q4 and have a third shipment scheduled from mid-December.

Going back up north for Michigan, Indiana and Kentucky production was above our forecast at 861,000 barrels of oil equivalent for the quarter and was relatively flat compared to the prior quarter. We are continuing to see better than forecasted production in the [non-interim], in both the newly drilled DRZ oil wells at Beaver Creek and in the existing Prairie du Chien wells.

LOE for the quarter was about 11% below forecast on per BOE basis through the strong focus on cost. Capital expenditures in Michigan totaled about $2.2 million for the quarter and included the completion of three drill wells for recompletions and free facility optimization projects. These projects added 250 barrels of oil equivalent per day of net initial production which was about doubled the pre-drill expectation.

Lastly I want to spend some time on our recently acquired assets in Oklahoma, Panhandle, Texas and New Mexico. We assumed operations following the expiration of the transition services at [Greenhut Whiting] on October 31, 2012. Transition went smoothly and I’ll talk more about that in a minute.

For the third quarter production was 583,000 barrels of oil equivalent which was a little above our forecast. Controllable LOE came in at about $9.3 million and that was about 7% below forecast. Capital activity for the quarter totaled $9 million and consisted of five drill wells and five workovers at deposit field. The drilling activity was combination of infield and step out drilling to complete CO2 flood patterns.

In addition 16 CO2 wells were drilled [Libi Ranch] and two were completed and tested the total of 3.8 million cubic feet of CO2 per day which was better than the full year forecast. The pipeline in compressor installations were completed during the third quarter and the [Libi Ranch] facility started up last week. We expect it to be delivering 10 million cubic feet a day of CO2 to us by the end of November.

Now let’s talk a little bit more about the transition. Overall the transition of the assets is going well and we’ve been working hard to ensure that we have the right people and the proper spots to ensure a smooth transition and a successful operation. We hired all the staff in the field which was critical to prevent a hiccup in the field activities and we were very pleased about that. We attempted to hire five or six sliding technical staff that had been working with possible assets but were not successful. This was the risk we had recognized so we quickly implemented our backup plan and moved the team of very strong performing BreitBurn employees to the possible project. They work side by side with the winding group in Midland for two months prior to BreitBurn taking over and we are confident transition was made efficiency and effectively. Transfer of knowledge, technology and capability will be very important to BreitBurn going forward.

As we’ve said before having control of the CO2 transportation infrastructure it will be very important and value adding to the fields we purchased and we believe it will be a differentiating factor as we continue growth in the area. From an operations perspective, we are very excited about specific assets we purchased and the presence we now have established in that area. There are numbers of other fields in that area that are excellent candidates for CO2 flooding and we believe that present good opportunities for us.

So the first three quarters of the year were very busy with third quarter activity ramping up significantly compared to the first and second quarters as we planned at start of the year. As outlined in our second half guidance with the possible acquisition we now expect December 2013 exit rate to be between 34,700 and 36,100 barrels of oil equivalent per day and oil and NGL will make up about 64% of our production and we expect to be well within guidance on all of our operating metrics.

With that, I will turn the call over to Jim.

Jim Jackson

Thank you, Mark. I would like to start by giving some additional commentary on our financial performance during the quarter, then provide an update on our hedging activity and conclude with the discussion of our liquidity position and financial strategy.

Adjusted EBITDA for the third quarter of 2013 was approximately $112.1 million compared to $84.8 million in the second quarter of 2013. As Hal mentioned earlier, the increase was the result of higher crude oil and natural gas production from the Oklahoma properties, increased oil production from our 2013 capital program, higher overall realized crude oil prices and as Mark detailed the team also did a very effective job of controlling cost across the operations during the quarter.

One other important item relating to adjusted EBITDA, adjusted EBITDA was impacted by $5 million in the quarter by the timing of shipments coming out of our Florida operation. As many of you know, revenues and expenses for our quarter production are recorded when the crude oil was ultimately delivered via barge to the purchasers. As Mark mentioned, we had expected to record two shipments and sales of [ford] crude in third quarter. However, the most recent shipment was not offloaded to final purchaser until after the end of this quarter. Therefore, our adjusted EBITDA for the quarter does not reflect at early October sale.

Losses on commodity derivative instruments for the third quarter were $54.8 million compared to gains of $67 million in the prior quarter. The loss was due to an increase in crude oil future prices during the quarter and derivative settlement payments net of receipts were $6.3 million in the third quarter of 2013 compared to settlements received of $4.8 million in the second quarter of 2013.

Note that these net settlement payments and receipts exclude prepaid premiums paid in 2012 related to the crude oil derivatives settled during the three months ended September 30 and June 30, 2013 of $1.2 million each.

As I mentioned on our last earnings call, these prepaid premiums related to option premiums we purchased in 2012 in conjunction with some of our acquisitions. We have not incurred prepaid options premiums in 2013 and did not enter any prior to 2012.

For the third quarter, we reported a net loss, including the effect of derivative instruments of approximately $25 million or $0.25 per diluted common unit as compared to a net gain of $76.4 million or $0.75 per diluted common unit for the second quarter of 2013. The decrease was primarily due to higher oil prices compared to the prior quarter and their effect on the fair value of our derivative instruments which are reported in earnings.

Cash interest expense for the third quarter of 2013 was $21.7 million compared to $17.1 million in the second quarter of 2013. The quarter-over-quarter increase is primarily due to the additional interest expense related to the funding of Whiting related acquisition indebtedness.

Now I'd like to discuss distributable cash flow for the quarter. Distributable cash flow was approximately $64.6 million in the third quarter. This amount reflects adjusted EBITDA of $112.1 million, less cash interest expense of $21.7 million, and maintenance capital of approximately $25.8 million. We defined maintenance capital as that amount of annual investment required to keep production approximately flat during the next five years and this amount is consistent with our second half 2013 guidance for maintenance capital.

On a per unit basis distributable cash flow was approximately $0.64 per unit. Our coverage ratio for the quarter based on the $0.48 and $0.75 distribution to be paid on November 14th was 1.3 times. As we outlined at the beginning of this year we had planned for our distributable cash flow and distribution coverage ratio to ramp up quarter-over-quarter throughout the year as we successfully executed on our expanded oil focused capital program. Thus, our 1.3 times coverage ratio is the expected improvement of the second quarter ratio of one-times. With regard to product pricing realized crude oil and liquids prices excluding the effects of commodity derivative instruments were $93.73 per barrel, compared to NYMEX crude oil spot prices of approximately $105.83 per barrel. Brent crude oil spot prices, which are an important benchmark for our California oil production, averaged $110.23 per barrel in the third quarter of 2013 compared to $102.57 in the second quarter of 2013.

On a natural gas side, available realized natural gas prices for the third quarter excluding the effects of commodity derivative instruments, averaged $3.69 per Mcf compared to Henry Hub natural gas spot prices of $3.56 per Mcf.

Consistent with our hedging strategy, we expanded our hedge portfolio significantly during the quarter. During the quarter we added WTI swaps, totaling approximately 8.1 million barrels at weighted average price of approximately $91 per barrel. These new volumes cover production between the third quarter of 2013 and the first quarter of 2016.

Assuming we won’t production constant through 2017 as the levels indicated in our second half 2013 guidance, we are approximately 86% hedged for the remainder of 2013, 77% hedged for 2014, 71% for 2015, 55% for 2016 and 25% for 2017.

Average annual prices during this period range between $84.11 and $95.01 per barrel oil and $4.34 and $5.73 per MMBtu forecast. I would like to note that our goal is to consistently hedge a high percentage of future production with swaps and costless collars. 96% of our hedge portfolio consists of swaps and costless collars and only 4% is comprised to put options. We will evaluate adding additional oil and gas hedges throughout the rest of the year to maximize the economics of our current and future production.

An updated version of our commodity price protection portfolio presentation summarizing our hedges will be available in the events and presentation section of the Investor Relations tab on our website later this morning.

As per our liquidity position; our outstanding debt balance as of September 30th was approximately $1.8 billion and consisted of borrowings of $1.09 billion under our credit facility plus approximately $756 million in senior notes. As of today we have approximately $1.13 billion outstanding under our credit facility which has a borrowing base of $1.5 billion and an elected commitment amount of $1.4 billion. So we have just under $300 million in liquidity which is more than adequate to fund our operating needs.

Our debt to LTM pro forma, adjusted EBITDA ratio for the third quarter was slightly below four times which is well within our leverage ratio covenant for our credit facility. Recall that our credit facility has a relax set of covenants for a period of five quarters following the Whiting transaction which enhances our flexibility and considering variety of financial options. As always we are watching the markets closely for opportunities to reduce our short term debt and fund our future growth.

This concludes our formal remarks. Operator, you may now open the call for questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) Our first question comes from John Ragozzino with RBC Capital Markets.

John Ragozzino - RBC Capital Markets

Hey, good morning everybody.

Hal Washburn

Hey, John. How are you?

Jim Jackson

Good morning.

John Ragozzino - RBC Capital Markets

Doing great, but long day, it’s by the fourth call, so I’ll keep this quick. Can you guys, please just provide us the [data, this is probably 10-K fully redundant] to go over this. But my question is still commenting about the recent correspondence with the SEC, can you just kind of lay that up? There is clear response for everyone so there is no more confusion [for an analyst] to answer anymore?

Jim Jackson

Sure, John. It’s Jim Jackson. I appreciate the question. So our 10-K was reviewed in normal course by the SEC they had a series of comments for us all which we responded to. We have sense for them that they don’t have any further issues as it relates to their review of the K. And we are not aware of any other open items that they are focused on related to BreitBurn or our business. All of that correspondence has made public. I am happy to answer detailed questions but the important thing is they have completed their review from our perspective.

John Ragozzino - RBC Capital Markets

Perfect. Thank you, Jim. As operator ship of the past last transfer for you guys. Do you foresee any potential hurdles or risks that specifically associated with the difficulties that you guys encountered in recruiting a couple of the key technical people from Whiting?

Mark Pease

John, this is Mark Pease. We knew that that was a risk when we went into it. So I'm sure you can appreciate, we’ve had a pretty robust backup plan. And so the minute we knew that they won't going to come on board, we’ve had a team of people ready to go. So we actually moved into Midland. So they spent two months out in Midland. We had either 5 or 6 people out there full time for two months. And Whiting folks were very, very well with us and very, very closely. So from a long-term issue, I see no issues at all. We had some very good people and they really grab a hold of it and they're running with it.

John Ragozzino - RBC Capital Markets

Great. You guys are clearly not strangers when it comes to really bringing every drop of oil out of some of your existing fields with the use of enhanced recovery technique such as water floods and steam injection stuff in California. When you think about the Postle field, is there anything that you guys were surprised to learn or expect to learn going forward that if you are able to identify would you get a chance to look on Postle and perhaps you could describe any value of these potential intellectual synergies if you will that you may be able to [distracting] your existing assets?

Hal Washburn

Well, I don't think that we got a lot of surprises and we're certainly still getting our arms around that. I think as we said last quarter and for those of you that follow Whiting, Whiting did a very good out there. So the field was up well run. We're obviously going to go in and look at it from a little bit different perspective, see if there is some voice we can improve efficiencies.

So, we're very excited about the Postle asset. There is another field there as well called the Northeast Hardesty Field that we’ve bought as part of the process, but we will eventually get CO2 to that field. And I don’t know how familiar you all with CO2 process John, but when you put that in a reservoir you recover oil that would not otherwise be recovered. I mean you could water flood a field for now forever and never get same amount of oil out that you get with CO2. So we like having the access for that CO2. There are number of other fields up in that area that we currently don’t own that are very good candidates for CO2 flooding. We think having access to CO2 and owning the infrastructure up there will give us the leg up and look at those fields and potentially acquire them.

John Ragozzino - RBC Capital Markets

Okay, great. Moving over to the Permian, have you guys identified an inventory of horizontal project that you’d like to share with us and then maybe give any thought to how -- into that way?

Hal Washburn

Yeah, yeah, I am sure John if I said no to that you’d be surprised. We have looked at that log. We're very pleased with the vertical drilling program. We're actually evaluating some horizontal wells as part of our 2014 capital budget. So I'll be surprised if you don’t see us doing a little bit horizontal drilling out there. It’s definitely moving towards the acreage that we have. So we're looking at that hard.

John Ragozzino - RBC Capital Markets

Okay. And just one more quick one and this is perhaps you don’t get to often, but can you share the breakeven [RIN] price that you see on development projects on the field. And then taking that one step further at what price do you call to shut-in completely?

Mark Pease

John the -- field is not owned by BreitBurn Energy Partners, so I can’t really comment on that.

John Ragozzino - RBC Capital Markets

I see. Okay.

Mark Pease

Yeah. I just really can’t comment on that on this call if you like to circle back with us we can handle that.

John Ragozzino - RBC Capital Markets

No problem, I apologize. Thanks a lot.

Mark Pease

Thank you.

Operator

Our next question comes from Ethan Bellamy with Baird.

Ethan Bellamy - Baird

Hey guys. Jim can you tell me about your maintenance capital calculation please?

Hal Washburn

Yeah. Ethan this is Hal, I’ll do that. Obviously that’s something has been of focus for few months now. And we've been very consistent the way we've looked at maintenance capital historically and we continue to look at the same way. And as we’ve said we laid out quite a bit of detail on our website under the tab frequently asked questions. We look at our reserves in our five year plan. And we look at that period. And it’s important to know that our reserves are fully determined. There is not just an [audit], it is fully a determined reserve by third-party engineers with the newly acquired assets. But we look at that period and our maintenance capital is the amount of money it takes us annually to hold a relative production flat over that period of time.

We do that analysis every year in conjunction with our planning fourth following year, our capital budgeting et cetera. And we also do it, in conjunction with acquisitions. We are in that training process now for 2014 as Mark said. But it’s important to know we look at our maintenance capital it’s consistent with our historical capital efficiency. We look at a base decline over the next five years of about 10% per year. And if you look at what our capital efficiency has been, it’s about $30,000 per barrel, per flowing barrel. So you can do the math on that just to come up with kind of our maintenance capital requirements. They vary, we don’t high grade projects. We’re looking our entire portfolio, but it is a rigorous approach and it is based on our third-party reserves.

Ethan Bellamy - Baird

Okay. What’s going on with California crude oil prices right now and what kind of oil differential should we be looking at for the fourth quarter?

Hal Washburn

That kind of moving around the last month or two they dropped down a little bit, but we don’t believe that the historical connections between California brand have moved much. You see these kind of variations, I think a lot of it has to do with just refineries out here. As you know we don’t have any physical interconnect between California and the rest of US. We produce somewhat less than half of the barrels in the California that are refineries use in California. So the rest of barrels are coming in by tankers and a small amount by rail. So you see it move around as refineries go online, go offline as they have turnarounds, but we generally think that overtime the relationship between California crude and brand appears to be strong.

Ethan Bellamy - Baird

Okay. Anything new on Utica and Michigan?

Hal Washburn

We continue to monitor it and we understand that some new wells have been drilled down some of our acreage to the South. We don’t have any official reports, but we have heard information about some of these wells that could be encouraging if it appears to be true.

Ethan Bellamy - Baird

Okay. And then just one housekeeping item. Could you refresh me on how many crude oil shipments out of Florida we are looking at per year and how big those barges are, I just, we just never seem to be able to get that shipment schedule right I want to make sure we get it right going forward?

Mark Pease

Yeah. Ethan, this is Mark. What we’ve budgeting for this year were eight shipments. And our shipment size depends a little bit on barge size, but it typically runs about 110,000 or 120,000 barrels per shipment. We had problems with the barge, I mentioned earlier put the second shipment in the third quarter, but actually had to ship barges and got a little bit smaller barge out there, so it was just under 100,000 barrels. But they typically run 110,000 to 120,000 and the budget take the year.

Ethan Bellamy - Baird

Okay. And how many for the rest of the year?

Mark Pease

We have already done two in the fourth quarter, Ethan and we have one more budgeted for mid December and then we will have three in Q4.

Ethan Bellamy - Baird

Got it. And just one point of clarification on your proprietary remarks, you talked about other CO2 floating opportunities, are you talking about just the Hardesty Field or are there other potential M&A targets or AND targets or are there other floods where somebody else might want to do that and they could just be a CO2 customer from you?

Mark Pease

I think actually all the above, Ethan. Hardesty we already own, so we will certainly be consider (inaudible). There are a number of other fields out there that we don’t currently own that there will be more oil produced out of those fields by putting CO2 in them. So whether we acquire them and put CO2 in them and do it ourselves or whether or not we sell CO2 to someone that will be part of the discussion and deal making going forward. But there are number of fields out there that are CO2 candidates.

Ethan Bellamy - Baird

Excellent. Thanks so much.

Hal Washburn

Thank you.

Operator

Our next question comes from Michael Peterson with MLV & Company.

Michael Peterson - MLV & Company

Good day, everyone. Hey, how are you? Got a follow-up to Ethan’s question to Mark with regard to the Postle Field, Mark you have talked a lot about the growth potential in terms of sourcing CO2 to fields not yet within the portfolio as a real driver of growth. When you think about that strategy are you more limited in acquiring the acreage or sourcing the CO2 on the other side of your pipe?

Mark Pease

Michael, I think it's certainly a good question. We're getting our arms around a number of other options for additional CO2. And we don't know all the answers to those yet. Obviously first order of business is to take care of Postle and Northeast Hardesty. But as we can access more CO2, so I will start looking harder to other fields. So I think the other fields that are up there I think that it’s pretty obvious which fields there are and which ones are top candidates, so then goes to your question whether or not we can make a deal with the companies that currently own them.

Michael Peterson - MLV & Company

Okay. Santa Fe Springs and my understanding is you’re processing 3D seismic that that process is underway. When might we have some visibility on development plans there, first part of the question? And the next part of the question, as you look at what seems to be favorable economics out of California, as well as out of Texas, how do you think about allocating capital between those two opportunity sets?

Mark Pease

Okay. Well, On Santa Fe Springs, we're really looking at two I think key things out there. First of all, we got, I don't know how familiar you are with it, Michael, but it's a big fixed section, a number of productive zones. A couple of those zones have been the primary target over the last 80 to 100 years. So what the seismic is doing is helping us to look deeper. So we're looking at some deeper targets there. And we're in the process of interpreting our seismic right now. The other thing we’ll do with the 3D seismic is we think that with some of the signatures and comparing it or aligning up and correlating those signatures with our current development program and the zones that have been produced on time. We think it will help us go to areas where we have higher oil cuts and areas that haven’t been fully swept by the existing water flood. So it’s really two things, we think it’s going to help us in the zones that are very developed, but we think it’s going to help us deeper. So I think that’s something that we're very excited about and we certainly get the initial interpretation out there and we like what we're seeing.

As far as allocating between California and Texas, we go through a very robust budget process. We actually start late in summer and it runs two to three months. We essentially look at every opportunity in the company and based on cost and commodity prices in those specific areas, we high grade those opportunities. So when you say we're going to go to California or Texas (inaudible) cost and prices are at time, right now both those areas are very attractive to us with the current oil price.

Hal Washburn

Michael just let me just amplify or talk a little bit more about that. I mean one of the great things about our portfolio today is that we do have a lot of opportunities to put capital work in different areas. Mark mentioned oil opportunities in California, Texas, Oklahoma one of things remind us at some point in time gas prices are going to strengthen and we have a significant portfolio of gas opportunities to. So we have these opportunities that we're going to exploit in immediate term and a lot of them, they are very compelling, but let’s not forget long-term we have 100 if not well north of 1,000 gas opportunities to pursue within the portfolio.

Michael Peterson - MLV & Company

Sure. And I don’t think the Michigan portfolio is lost on any of the call. If I can do a brief follow-up on Mark’s comments as you think about the economics and certainly a robust portfolio that you have to choose from, would you also consider some of the decline rates with Texas maybe having arguably more attractive economics but certainly more steep declines than what you might find in California, would that also be a consideration or others two independent issues?

Hal Washburn

I mean we look at all that together. What we do is put together a model capital program if you will for the next year, we overlay that on our current base business and we see what it looks like and then we stand quite a bit of time working that to make it lines up and achieve what we’re going to achieve. So again we understand that Texas is a steep initial decline, great rate of return, but it does certainly impact your best decline, the great thing about Texas is when you get out of few years it’s a pretty flat decline.

Michael Peterson - MLV & Company

Okay. I appreciate all of your comments guys. Congratulations on nice quarter.

Mark Pease

Before we go to the next, I wanted to comment on a question I think for Michael or maybe from Ethan earlier. On the Florida barge shipments, I think that the last three shipments of the year going to be like 90,000 to 95,000 barrels rather than the larger 110,000 barrels. So if you’re doing modeling, I think you are kind of in that range per barrel or per shipment.

Operator

Our next question comes from Noel Parks with Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann

Just a couple of things. I just wanted to follow up on and probably get after the, but you are talking in Belridge about doing a different stimulation treatment out there that had I guess some sort of improved results but I just wanted to feel little more about that?

Mark Pease

Yeah Noel, this is Mark. Really what we have done is a pretty big section out there and what we have done is added more frac stages in that, so instead of doing a couple stages that we are trying to cover that entire internal, we’ve added a couple of more stages in there. So I think what it’s doing for us is making sure that we are getting stimulation across the entire interval and often more scientific than that.

Noel Parks - Ladenburg Thalmann

Okay. (inaudible) at their island, are you talking a treatment if I understood it lock off certain zone, is that expensive item or kind of just more or less routine sort of item?

Mark Pease

Yeah, I mean, this is not a real expensive item, certainly not like going out and trying to do recompletion or big frac job. The thing that surprise us a little bit about the 3-7, when we logged, the logs were actually very encouraging, looks like pretty high oil saturation, some would brought it online. We didn’t really understand why we are seeing so much water production and I think the assessment we work through is we have some high permeability strikes. So we think by pumping in this chemical treatment maybe we can shut off some of those high permeability strikes that are apparently water production and then that should allow more oil to flow into well bore.

Noel Parks - Ladenburg Thalmann

Thanks that’s all for me.

Operator

Our next question comes from Kevin Smith with Raymond James.

Kevin Smith - Raymond James

I might have missed this Mark, but did you mention how much midstream capacity is getting out in 2014 to California?

Mark Pease

How much midstream capacity?

Kevin Smith - Raymond James

Yeah, but you’re adding some more takeaway capacity on your California properties, you mentioned that in your prepared remarks?

Mark Pease

Yeah, so it’s not so much midstream Kevin, I mean we are essentially at capacity of our facilities, I am talking our producing facilities, so treating equipment in Belridge and Santa Fe Springs. So we see a lot of them hold potential in both those fields and have pretty robust development programs plan for the next few years, so we are working on expanding those facilities in both fields to take care of some more organic drilling.

Kevin Smith - Raymond James

Okay, do you have any sort of levels of how much expansion you’re going to be able to do?

Mark Pease

We are working on that right now, Kevin. I mean Santa Fe Springs fields big complex field and it’s located in LA, so we are thinking a little hard about what is the right size for the next expansion base and we have a team of people working on that right now. Belridge is little more straightforward, it’s usually get work done out there and so we are working through both studies right now.

Hal Washburn

Kevin, it is important to notice, it’s not takeaway capacity or really even gas process. We are literally just talking about separating water and oil and take it injection capacity to handle additional increase -- or the increase production of crude oil and associated water. So it takes separators in the like and injection pumps. We are not talking about pipelines and other things like that, so it’s not takeaway capacity constraint, it’s more just surface facility constraint.

Kevin Smith - Raymond James

And then just one last question. Now that you kind of layered in extremely MLP friendly asset like Postle, have you changed any of your thoughts about what's the appropriate amount of leverage is for this company?

Jim Jackson

Kevin, it's Jim. Really unchanged in terms of our view of run rate leverage going forward. We are focused on running the business at around 3 times leverage that’s total that the pro forma LTM EBITDA, that's principally unchanged over the last five years. So I think the fact that Postle which is kind of a perfect MLP asset and our strategy of always adding the right kinds of assets means that it’s really not driving a change in how we think about leveraging the business.

Kevin Smith - Raymond James

Okay. That's all I had. Thanks.

Operator

(Operator Instructions). Our next question comes from Dan Guffey with Stifel.

Dan Guffey - Stifel

Hi guys, you talked about generating organic growth in the quarter and throughout the year. I'm wondering if you can quantify 2013 organic growth and then keeping your capital plan assuming kind of a flat run rate in the current capital plan, kind of what you had achieved over 12 month period?

Jim Jackson

Yeah Dan. So we are going to, we expect to hit our guidance. And so I think you can pretty well figure out what sort of growth is implied in that, in 2013. As far as ‘14 and going forward, we obviously haven't released any guidance for ‘14 and clearly not anything perhaps to that. But we said that we will expect to grow the business through acquisitions and our development drilling program is designed to achieve kind of low to mid single digit growth rate, but the idea is really that kind of holding your production flat over the long-term with your organic capital program with some slightly growth in mid single digits and then the real growth driven by acquisitions.

Dan Guffey - Stifel

Okay. And sorry if I missed this, I think you said your overall corporate decline rate right now is around 10%, is that correct?

Jim Jackson

Yeah. I think if you look over the next five years for the whole portfolio including parcel you’re going to kind of be in that 10% range annualized for five years.

Dan Guffey - Stifel

Okay. That’s all I had guys. Thanks.

Operator

It appears there are no further questions at this time. I’d like to turn the conference back to management for any additional or closing remarks.

Hal Washburn

Thank you, Operator. On behalf of Mark, Jim, Greg and the rest of the BreitBurn team, I thank everyone on the call today for their participation. Operator, you may now bring this call to a close.

Operator

This concludes today’s conference. Thank you for your participation.

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