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BreitBurn Energy Partners L.P (NASDAQ:BBEP)

Q3 2011 Earnings Conference Call

November 8, 2011 1:00 PM ET

Executives

Greg Brown – EVP and General Counsel

Hal Washburn – CEO

Randy Breitenbach – President

Mark Pease – COO

Jim Jackson – CFO

Analysts

Ethan Bellamy – Robert W. Baird & Co

Mike Jones – Imperial Capital

T J Schultz – RBC Capital Markets

Michael Blum – Wells Fargo

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the BreitBurn Energy Partners Investors Conference Call. This Partnership's news release made earlier today is available from its website at, www.breitburn.com.

During the presentation, all participants will be in a listen-only mode. After, securities analysts and institutional portfolio managers will be invited to participate in a question-and-answer session. (Operator instruction)

As a reminder, this call is being recorded and it will be available for replay until midnight, Tuesday, November 22 by dialing 877-870-5176 and entering the conference ID 715054. 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 Greg Brown, Executive Vice President and General Counsel of BreitBurn. Please go ahead, Sir.

Greg Brown

Thanks, operator and good morning. Presenting this morning are, Hal Washburn, BreitBurn's CEO; Randy Breitenbach, BreitBurn's President; Mark Pease, BreitBurn's Chief Operating Officer, and Jim Jackson, BreitBurn's Chief Financial Officer. After their formal remarks, the call will be open for questions from securities analysts and institutional investors.

Let me remind you that today's conference call contains projections, guidance, and other 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 of our 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 these uncertainties is 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 for the year ended December 31, 2010, 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 or events.

Additionally, during the course of today's discussion, management will refer to adjusted EBITDA, which is a non-GAAP financial measure, when discussing the Partnership's financial results. Adjusted EBITDA is reconciled to its most directly comparable GAAP measure in the earnings press release made earlier this morning and posted on the Partnership's website.

This non-GAAP financial measure should not be considered as an alternate to GAAP measures, such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance. 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.

This non-GAAP financial measure 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 in the same manner.

With that, let me turn the call over to Hal.

Hal Washburn

Thank you, Greg. Welcome everyone, and thank you for joining us today to discuss our third quarter. I’m pleased to report we had another quarter of operating financial performance. We closed with a net production increase from the prior quarter and adjusted EBITDAs and our run rate consistent with the high-end of our 2011 guidance range.

We’re also very pleased to have completed $340 million of acquisitions in the Rocky Mountains. In July, we closed a $57 million acquisition in eastern Wyoming and on October 06, we completed second acquisition in southwestern Wyoming for $283 million. I’ll talk more on these acquisitions later.

Let me start by discussing the few key quarterly highlights. During the third quarter, we produced 1.681 million barrels of oil equivalent of oil and natural gas or 18,273 BOE per day. Overall production increased from the prior quarter and was in line with our forecast with strong performance coming from both of our divisions.

Oil, gas and NGL sales revenues, including realized gains on commodity derivative instruments were very strong in this quarter, approximately$105 million, 13% higher than the prior quarter, primarily due to the timing of the crude oil sales in Florida.

Our lease operating expenses were above the high end of the guidance range due to the seasonal nature of our well servicing, maintenance and workover activities. Adjusted EBITDA for the third quarter was $52.9 million, which on an annualized basis is trending above the high end of our guidance range. As I mentioned earlier, we're pleased to have completed two strategic acquisitions during the quarter.

On October 6th, we completed our acquisition in natural gas and oil properties at attractive valuation metrics in the Evanston and Green River Basins of southwest Wyoming for approximately $283 million.

We acquired these assets from Cabot Oil & Gas Corporation. We believe these long-lived assets are excellent MLP properties with very predictable and low decline production profiles, high operating margins and low risk exploitation and development opportunities.

Shortly, following the execution of the purchase agreement, the Partnership entered into natural gas hedges for the period covering 2011 due 2015 at attractive prices. These hedges lock in our acquisition economics.

While this acquisition increases our exposure to natural gas, the acquisition economics are strong based in the current gas strip and we think natural gas is attractively valued relative to oil. In addition, the acquisition improves our overall lease operating expense metrics and adds to our inventory of low risk development drilling opportunities.

Our experienced operating team – operations team is currently interrogating these assets and exploring the potential of over 90 proven undeveloped drilling locations in over 600 potential drilling locations.

We estimate net production to average approximately 30 million cubic feet per day for 2012. We also closed the acquisition of oil properties in the Greasewood Field located in Niobrara County, Wyoming for approximately $57 million on July 28. The acquisition added approximately 500 BOE per day to our production in the area and the performance has improved from there.

Once again, we believe that these high quality assets are great addition to our portfolio and we expect to realize operational synergies by leveraging our strong management team working in that region.

These Wyoming acquisitions are key to our growth through acquisition strategy and generate incremental distributable cash flow per unit to support our continued distribution growth.

Turning to our distributions, we recently announced our third quarter distribution of $1.74 per common unit on an annualized basis, which will be payable on November 04 to the record holders of common units at the close of business tomorrow. This represented 3% increase in the prior quarter and 11.5% increase from the third quarter 2010 distribution. Further this marks are sixth consecutive quarterly distribution increase since May of 2010.

The Partnership's results in the third quarter reflect the consistent and predictable nature of our business, our ongoing focus on operating performance and our ability to successfully execute on our growth through acquisition strategy. With that, I’ll turn the call over to Randy who will discuss selective results for the quarter and recap our hedging activity. Randy?

Randy Breitenbach

Thanks, Hal. I’ll start by addressing our third quarter commodity hedging activity and provide an overview of the impact of these derivative instruments on our financial results.

For the third quarter of 2011, crude oil, natural gas and NGL revenues, including realized gains or losses on commodity derivative instruments, totaled $105 million, compared to $93 million in the second quarter of 2011. Quarterly revenues included realized gains on commodity derivative instruments of $8.1 million in the quarter as compared to realized losses of $1.8 million in the second quarter.

Realized natural gas prices for the third quarter averaged $6.72 per Mcf, compared to NYMEX natural gas prices of $4.06 per Mcf. Realized crude oil and liquids prices averaged $81.50 per barrel for the quarter, while NYMEX crude prices averaged $89.49 for the quarter. Non-cash unrealized gains from commodity derivative instruments for the third quarter were $170.7 million, reflecting the significant decrease in oil futures prices during the quarter.

As per our hedging activity, we had a very active quarter. First, we hedged production associated with the acquisitions announced during the quarter to lock in the economics. Second, we converted hedges in our portfolio from WTI to Brent for our California crude. And third, we continue to layer in new hedges on our base production in the outer years opportunistically.

For the Cabot acquisition, we entered into natural gas hedges through 2015 on approximately 30.5 million MMBtus at a weighted average price of $5.11. In summary, our hedge portfolio secures the expected economics associated with our acquisitions and current production and mitigates commodity price volatility.

We also took steps to address the significant dislocations in what historically has been a very stable relationship between WTI and the posted prices received by the partnership for our California crude oil production, as you know, a significant portion of our oil production comes from California.

Recently, oversupply issues at Oklahoma, Cushing has caused WTI prices to dislocate and trade significantly below world market prices. Due to the lack of pipeline access to the California market, local California price postings are generally tied to the price of water-borne barrels entering California.

Going forward, management believes that Brent prices will correlate better with local California postings. As a result, the partnership has terminated a portion of the WTI hedges and rehedged the same volume and tenure against Brent.

In October, the partnership terminated certain crude oil fixed price swaps at NYMEX WTI prices for $33.8 million and entered into new crude oil fixed price swaps at IPE Brent prices. The new 2012 through 2014 crude oil fixed price swaps cover approximately 2.6 million barrels of oil and have a weighted average swap price of $99.75.

A detailed list of the terminated WTI swap contract and the IPE Brent contracts which replace them are included in our earnings press release issued earlier this morning and will also be included in the subsequent events section of our 10-Q to be filed shortly.

I would like to reiterate that our hedge portfolio remains a key strength for the partnership in managing commodity price volatility, stabilizing revenues and cash flows and supporting our borrowing base. A significant portion of our oil and gas volumes are well protected at attractive prices through 2015.

Assuming the midpoint of 2011, production guidance has held flat. And based on our previously announced levels for our two most recent acquisitions, our production is hedged at approximately 73% for the fourth quarter of 2011, 70% in 2012, 68% in 2013, 46% in 2014, and 36% in 2015.

Average annual prices during this period range between $80.84 and $101 per barrel for oil and $5.43 and $7.27 per MMBtu for gas. An updated commodity price protection portfolio presentation will be posted in the Presentations section of our website today.

With that, I’ll turn the call over to Mark who will provide an operations update and further discuss our recent acquisitions. Mark?

Mark Pease

Thanks, Randy. I would like to start by saying that we are very pleased to have closed the acquisition of the Greasewood Field in Wyoming. It is going to be an excellent asset for the company. BreitBurn took over operations in July and the numbers that we are reporting for this quarter include the Greasewood operating results. In the third quarter, we produced 1.68 million barrels of oil equivalent or 18,300 barrels per day. This is a 1% increase from second quarter 2011 production of 1.66 million barrels of oil equivalent and is right in the middle of our 2011 guidance range. The production split for the quarter was approximately 49% crude oil and NGLs and 51% natural gas.

Total capital expenditures in the third quarter $22.3 million. This is down compared to the second quarter expenditures which were $28.1 million. Year to date, we’ve spent about $60 million and excluding expenditures planned for the new acquisitions, we are expecting full-year spending to be within the guidance range that we announced earlier this year. Including acquisitions, we expect to spend approximately $80 million for the year.

For the third quarter, lease operating expenses and processing fees, excluding transportation expenses, increased to $36.4 million, or $21.66 BOE. This is up from $30.6 million or $18.41 per BOE in the second quarter.

As we have previously discussed, the third quarter is typically scheduled as the most active quarter for routine maintenance work. This allows the work in our northern locations, primarily Michigan and Wyoming to be done during the summer months, which helps keep costs down.

Some of the main areas where went up compared to the second quarter were well servicing, compressor maintenance on both company operated and non-operated properties and facilities maintenance and repairs. The other fact that has influenced Q3 operating expense is the continued strong price for crude oil. This has put upward pressure on our costs throughout the year.

Year to date, the cost of materials and services have increased 10% to 15% and the availability of some services, primarily frac jobs in Wyoming continues to be a challenge. Our operating teams put a strong focus on controlling costs and we expect Q4 costs to come down compared to Q3, excluding the additional expenses from the new acquisitions. For the full year, again, excluding the new acquisitions, we expect to be about in the middle of our guidance range for lease operating costs.

Now, let’s discuss the third quarter performance at our two operating divisions. Production in the eastern division which consists of Michigan, Indiana, and Kentucky and is primarily natural gas was about 3% below the prior quarter. Third quarter controllable lease operating expenses for the eastern division were above the second quarter expenses mainly due to the increased activity level in the summer months.

Capital spending in the eastern division for the third quarter totaled $6 million and consisted of 16 drill wells, 14 recompletions and one facility optimization project. The program added net production of about 3 million cubic feet equivalent per day.

In the western division, which includes California, Florida and Wyoming, including the recent Greasewood acquisition, third quarter production which is primarily crude oil came in about 8% higher than second quarter production.

We had good production growth in both Wyoming and Florida which grew 16% and 11% respectively. Controllable LOE for the quarter was higher than the second quarter mainly due to higher than average well pulling activity in our California and Wyoming fields and the major workover in Florida.

Capital spending in the western division for the third quarter totaled $15.7 million and consisted of one drill well in Florida, three drill wells in California and seven drill wells in Wyoming. The program generated very good results at a net initial production of about 500 barrels of oil per day.

Now, let’s talk acquisitions. I’d like to give an update on both of the recent acquisitions we made in Wyoming. As discussed on our earnings call last quarter, the acquisition of the Greasewood Field in the Powder River Basin closed and BreitBurn took over operations on July 28. We have an excellent operating team in Wyoming and they very quickly made an impact.

Through minor facility modifications and by changing down whole pumps and select wells, gross production has increased from 800 barrels of oil per day to a 1000 barrels oil per day and we believe there are additional production improvements that can be made in the field. BreitBurn has a net revenue interest of about 61%.

We currently have four approved drilling locations and plans for the first well around the 1st of December. These wells should be complete in the first quarter of 2012 and based on their results and our current interpretation of the field, we expect to do additional drilling next year. In short, the Greasewood Field has exceeded our acquisition expectations to date.

Moving southwest in Wyoming to the Green River and Evanston Basins, the acquisition of the properties from Cabot closed on October 6, and we took over operations the same day. The integration of these properties is going smoothly and our operating and technical teams are in place and focused on these assets. Production is coming in at forecast.

Concerning future activity, we’ve said previously that there are hundreds of potential locations. So, it is an area with significant opportunity. We are currently working on high grading these opportunities to ensure that we optimize the company-wide portfolio for our 2012 capital program.

One last note, with the addition of our new acquisitions in Wyoming, we’ll be renaming our divisions from eastern and western to northern which will include Michigan, Wyoming, Indiana and Kentucky and southern which will include California and Florida. This will rebalance the workload for the teams and hopefully, we’ll appear logical than having Florida in our western division. With that, I’ll turn the call over to Jim.

Jim Jackson

Thank you, Mark. Total revenues were $277.6 million in the third quarter versus $142.4 million in the second quarter of 2011. Total revenues include unrealized gains and losses recorded during the period which are non-cash items.

Our third quarter revenues included $170.7 million in unrealized gains on commodity derivative instruments, as compared to $48.2 million of unrealized gains on commodity derivative instruments in the second quarter of 2011.

Unrealized gains during the third quarter were primarily due to a decrease in crude oil futures prices during the quarter and the effect those prices had on the valuation of our derivative contracts.

We recorded net income of $178.2 million or $2.87 per diluted common unit for the third quarter of 2011, as compared to $57.5 million, or $0.92 per unit in the prior quarter. The increase in net income compared to the second quarter was primarily due to higher realized and unrealized gains on commodity derivatives during the period.

As Randy mentioned, oil and natural gas revenues, including realized gains and losses on commodity derivative instruments were$105 million in the third quarter compared to $93 million in the second quarter. The increase primarily reflects the timing of crude oil sales in Florida with two Florida sales occurring in the third quarter of 2011 versus just one sale in the second quarter. As you may recall, we produce inventory in Florida and ship to market as needed.

We currently expect to have two Florida sales in the fourth quarter, although we expect the second sale to be slightly smaller than our typical sale of 120,000 barrels.

General and administrative expenses, excluding, non-cash unit based compensation expense were $8.6 million or $5.09 per BOE in the third quarter versus $6.2 million or $3.74 per BOE in the second quarter of 2011. Our results for the third quarter included approximately $1 million of acquisition-related costs, including legal and other professional services, as well as personnel additions and higher accruals for short term incentive compensation. ‘

For the nine months ended September 30, 2011, G&A, excluding non-cash unit based compensation, was $21.8 million or $4.38 per BOE produced. Excluding the acquisition related costs discussed above, G&A per BOE was $4.18 for each barrel produced for the nine months ended September 30, 2011.

Third quarter adjusted EBITDA was $52.9 million, up from the prior quarter and trending above the high end of our guidance range. The increase was largely due to the timing of crude oil sales in Florida which impacted oil and gas sales revenue, offset by higher lease operating expenses. This total is after the G&A related costs incurred in the quarter mentioned above.

Production and property taxes totaled $6.7 million in the third quarter, up from $6.2 million in the second quarter, primarily due to our having two Florida in the third quarter as compared to only one in the second quarter. Net interest and other financing costs, excluding realized and unrealized gains and losses on interest rate swaps were $9.3 million in the third quarter of 2011, compared to $9.1 million in the prior quarter.

Cash interest expense which includes realized losses on interest rate derivative contracts, but excludes unrealized gains and losses on interest rate derivative contracts, as well as debt amortization costs totaled $9.3 million in the third quarter of 2011, as compared to $8.9 million in the prior quarter. The increase was principally due to additional borrowings in the third quarter used to fund the Greasewood acquisition.

Let me now turn to our liquidity position, our outstanding long-term debt as of September 30th was $511.5 million and consistent with borrowings of $211 million under our credit facility and $305 million in senior notes. This includes $4.5 million in unamortized discount on the senior notes.

As of October 31, we have $505 million in borrowings outstanding under the credit facility. And our October 31, debt balance included approximately $270 million in additional borrowings used to fund the balance of the Cabot acquisition consideration and closing, as well as $33.8 million recently paid to terminate a portion of our WTI swaps, as discussed previously.

Effective October 11, 2011, the partnership’s borrowing base under the existing credit facility with its 15-member bank group was increased to $850 million from $735 million. The partnership currently has approximately $345 million of undrawn capacity under the credit facility. The credit facility expires in May of 2016. This concludes our formal remarks. Operator, you may now open the call for questions.

Question-and-Answer Session

Operator

Thank you. (Operator instructions) And we’ll hear first from Ethan Bellamy with Baird.

Ethan Bellamy – Robert W. Baird & Co

Hi, guys. Two questions, with respect to BreitBurn Energy company in the (inaudible) Field, can you give us the status on that, or is there any change there? And then secondly, has there been any conversation with (inaudible) with respect to the equity overhang there? Thanks.

Hal Washburn

Take the first one on Quicksilver, we haven’t had any discussions with Quicksilver about their units and their position. So, we are not – don’t know any more than what’s up probably. As far as BreitBurn Energy company, the auction of the BreitBurn Energy company assets has been completed and a decision has been made to not move forward on the sale of those assets at this time.

Ethan Bellamy – Robert W. Baird & Co

Great. Thank you very much.

Operator

Thank you. And we will take our next question from Mike Jones with Imperial Capital.

Mike Jones – Imperial Capital

Hi, good afternoon and good morning, guys.

Hal Washburn

Hi, Mike.

Mike Jones – Imperial Capital

If you think about the normalized cost inflation, the system, you had about $3 increase, you noted workovers and seasonal, what’s sort of the normalized that you will see [ph] maybe in the fourth quarter?

Hal Washburn

Hey, Mark, would you take that one?

Mark Pease

You bet. The question was about, you had normalized inflation in cost, was that the question, Mike?

Mike Jones – Imperial Capital

Yes, if you are seeing the increased third over second, most of it being seasonal, is there – but you are also seeing that cyclical and we are going to see recurring going forward?

Mark Pease

Yes, it’s tied pretty closely to the comment I made about overall increases of costs and services. We work hard to keep those down. But right now, we are seeing somewhere around 10%. So, that’s probably a good estimate recognizing that things are never exactly quarter to quarter or month to month.

Mike Jones – Imperial Capital

Okay. And then the second was the seasonality in your natural gas pricing, how do you expect that to kind of change as you move into Wyoming?

Hal Washburn

This is Hal. We aren’t – we hedge very aggressively and have a good big chunk of that production hedge currently, the seasonal nature of the production pricing, it’s kind of been muted recently. It seems to not be impacted by seasonality at this point.

Mike Jones – Imperial Capital

Okay. That’s all I had. Good quarter.

Hal Washburn

Thank you.

Operator

And we will take our next question from Evanley [ph] with RBC Capital Markets.

Unidentified Analyst

Let me just follow up with – on the last question. In your hedging the Rockies, is that – you are just moving that out over a strip [ph] period?

Hal Washburn

Yes, we are – I apologize. I spoke over the last part of your question.

Unidentified Analyst

I think you can answer it.

Hal Washburn

We take – when we hedge our production for exactly that reason and we don’t like to see the bumps and the seasonality. So, we’ll do an average strip for the year. And in fact, what we did in a lot of our hedging here just to simplify and also kind of take out some of the – some either the contango or backwardation in the curve, we’ll hedge out all of our production which is what we did with the Cabot acquisition for a four-year period and that was the average of $5.11.

Unidentified Analyst

Great. Can you give us a sense of what your current company-wide production is?

Jim Jackson

Yes, I mean, it’s consistent with what we had in the third quarter, plus the incremental from Cabot. We forecasted Cabot for 2012 at about $30 million which includes some of the impact of some drilling, but not meaningful below that today.

Mark Pease

It’s coming in right where we expected it to be, I guess is probably the easiest way to say that?

Hal Washburn

If you do that math, it adds to about 23,300 plus or minus today.

Jim Jackson

Yes, BOE per day.

Hal Washburn

23,300 BOE per day.

Unidentified Analyst

And then on the bank facility, what’s general comfort level on how much drawn relative to the borrowing base?

Hal Washburn

Jim?

Jim Jackson

Yes, Adam [ph], it’s Jim. Generally speaking, well, right now we have, call it, $350 million of undrawn capacity. We think that’s ample given our business environment. So we are comfortable at this level and as we’ve said in the past, will continue to be drawn at different levels based on acquisition activity and financing activity. So, we are comfortable at this level and we have plenty of liquidity right now.

Unidentified Analyst

And then lastly, following up on that last statement, integration of the existing acquisitions, can you – when is the soonest you could proceed, if available, for the next acquisition?

Hal Washburn

Really in a position, guys. We are fortunate that we have had no real issues on integration. We’ve had two acquisitions in the Rockies where we have one of our largest and most experienced operating team. So, integration issues so far have been very minor. And we are in a position from an operational perspective of looking at acquisitions immediately.

Unidentified Analyst

That’s all from me. Thanks.

Hal Washburn

Thank you.

Operator

Thank you. (Operator instructions) And we’ll now take a question from T J Schultz with RBC Capital Markets.

T J Schultz – RBC Capital Markets

Hi, guys. Just a couple of things, really quick, I guess first on the Cabot is kind of clarification, as you look at the ramp in production there into 2012, is that expected to average 30 million a day in 2012, or can you just kind of discuss as the drilling opportunities present themselves, how we should look at that production ramp in over the next 12 months or so?

Hal Washburn

I think you should just look at it on an average. We’re not getting into an aggressive drilling program there. You are not going to see a big ramp in production. $30 million average for the year is probably a pretty good way to view it.

T J Schultz – RBC Capital Markets

Okay. I guess

Hal Washburn

TJ –

T J Schultz – RBC Capital Markets

Yes, go ahead.

Hal Washburn

TJ, I’ll make one more comment about that, because I think it’s really important. There is a wide range of productivity and well types there. So, what that does is, give us flexibility that we can go through and look at an asset base and really, high grade and that’s what we are working hard on right now. And we’ll make sure that plug in the wells that, again, that with the best overall return for the company. I mean, that’s our goal here and we want to compare across all the opportunities set in the corporation and that’s how we’ll go by that process.

T J Schultz – RBC Capital Markets

Okay. I guess just lastly, in Florida, I think you are planning to drill a test well, any update on that well?

Hal Washburn

Mark?

Mark Pease

Yes, we have that well there and pleased with the results of the well, well is on production. And overall, we continue to be pleased with the Florida program, not unlike other drilling programs, you are not able to well [ph] the same. We’ve had some – we had some really good wells and we’ve had one or two that aren’t so good. But overall, the program has generated a very good rate of return. We are actually moving the drilling rig from our Raccoon Point Field to another field up there to test some of the same ideas and concept to West Felda Field. So we believe we are going to be able to generate a few locations in each of fields or at least, some of the fields for the next few years. So, overall, we are really encourage with the results and glad we have the rig down there working.

T J Schultz – RBC Capital Markets

Okay. I guess just clarification on Ethans [ph] question on BC, so the auction process in that, those were not sold at all to – not even to a third party, is that correct?

Hal Washburn

That is correct.

T J Schultz – RBC Capital Markets

Okay. Great, thanks.

Operator

And we’ll now hear from Michael Blum with Wells Fargo.

Michael Blum – Wells Fargo

Hi, good morning, guys.

Hal Washburn

Hi, Michael

Michael Blum – Wells Fargo

Maybe just staying on BC for a minute, so I guess what is the status going forward? Will these now b e offered out to third party, could you come back around and could the Partnership come back around quite easily [ph] in the future? Just kind of how does this move forward from here?

Hal Washburn

So, Michael, the properties were offered to BBEP as per the – under this agreement. They were then offered to third parties and that’s process that’s just completed and did not result in a sale. So, at this point, the process is done and we are moving forward.

Michael Blum – Wells Fargo

Does that preclude the Partnership from buying them in the future?

Hal Washburn

No. I mean, we’ll really just back to where we were before the process started. There is no provision on the Partnership doing anything.

Michael Blum – Wells Fargo

Okay, got it. Another question just on the hedges, and I apologize, I just haven’t had a chance to walk through all the details on that, but just in broad strokes, were you able – are you – in terms of price levels, are you – did you swap out equivalent prices or just swap at higher prices, or lower prices, just can you directionally talk about what you (inaudible).

Jim Jackson

Yes, directionally it was up. The mark to market on the WTI hedges, that we terminated and we are below the market, so there was a cost associated with doing that. But then we also picked up the additional incremental benefit of the spread between WTI and Brent which, as I’ve said earlier, has spread out, because WTI no longer really reflects the value of our crude in California. In fact, our crude in California is trading at a premium to brand.

So, going forward, obviously, really what we are trying to do here, we are not trying to make money through the hedging program or trying a lock-in or sell, pre-sell our barrels. And the best way for us to do that is to have production better correlate to future posting that we think we are selling it on. And it because obvious to us because of the dislocation in supply demand and WTI, Cushing – or excuse me, in Oklahoma, Cushing that Brent was going to correlate better with California barrels, given they are ocean-borne distribution and access. So, we felt that it made sense for us to convert approximately in the same amount of barrels that we produce in California which is around approximately 3,000 barrels per day of the mix we converted from WTI to Brent for ’12 and ’13 and a portion of ’14 and we are still moving forward on finishing that as well.

Michael Blum – Wells Fargo

Great. Thank you very much, guys.

Jim Jackson

Thank you.

Operator

Thank you. (Operator instructions) And we will hear from Mike Jones with Imperial Capital.

Mike Jones – Imperial Capital

Hi, guys. A quick follow up on CapEx, if I think about your 2012 [ph] or sort of quarter on quarter run rate in the east of $6 million and then in the west at $15.1 million, you annualize that and have the acquisition, I am getting something above $100 million for 2012, and do you kind of plan to update that and if those numbers are somewhat accurate?

Jim Jackson

Hey, Mike, it’s Jim. With respect to guidance on 2012, we’ll issue that in 2012, probably the first quarter generally around when we release fourth quarter and full year results.

Mike Jones – Imperial Capital

Okay. Would it be fair to say that those quarterly levels, plus acquisition, could be indicative of what you are going to do in ’12?

Jim Jackson

We don’t see a meaningful – Mike we are not

Mike Jones – Imperial Capital

I’m sorry.

Jim Jackson

We don’t see a meaningful change in the base capital spend. It’s not going to – we don’t, at least today, of course, see it going up dramatically or down dramatically. So, if you kind of look at what we guided to this year, that we will spend on our base business, plus the acquisition. So, I think it’s probably a fair way to model it prior to us actually guiding for 2012.

Mike Jones – Imperial Capital

Okay. And can you just remind what maintenance capital will be in the Cabot acreage of 30 million a day, where do you guys say it will be?

Jim Jackson

No, I don’t think we’ve actually come up with the maintenance number, but what we did say was, it was pretty consistent with the existing business and the existing business is $45 million, at the midpoint, $40 million, $50 million range for maintenance capital.

Mike Jones – Imperial Capital

Got it. Thank you.

Operator

Thank you. And we have no additional questions at this time. Mr. Washburn, I’ll turn the call back over to you for any additional or closing remarks.

Hal Washburn

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

Operator

Thank you. And this does conclude today’s conference call. Thank you everyone for joining us. You may now disconnect.

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