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

Q1 2012 Results Earnings Call

May 07, 2012 1:00 PM ET

Executives

Greg Brown – Executive Vice President and General Counsel

Hal Washburn – Chief Executive Officer

Randy Breitenbach – President

Mark Pease – Chief Operating Officer

Jim Jackson – Chief Financial Officer

Analysts

John Ragozzino – RBC Capital Markets

Bernie Colson – Global Hunter

Ethan Bellamy – Baird

Kevin Smith – Raymond James

Michael Blum – Wells Fargo

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the BreitBurn Energy Partners Inventor Conference Call. The Partnership’s new 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. 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, Monday, May 7, 2012. A replay of the call will be accessible until midnight, Monday, May 21st by dialing 877-870-5176 and entering the conference ID 7248609. International callers should dial 858-384-5517, an achieve 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, everyone. 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 projects, guidance and other forward-looking statements within the meaning of the Federal Securities law. All statements, other than statements of historical fact, 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, 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, 2011 and our quarterly reports on From-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 publically 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 or cash flow from operating activities or any other GAAP measure of liquidity or financial performance.

Adjusted EBITDA is presented because management believes it provides additional information relative to the performance of the Partnership’s business. This non-GAAP financial measure may not be comparable to similarly titled measures of other publically traded partnership’s, limited liability companies because all companies may not calculate adjusted EBITDA in the same manner.

Now, with that, let me turn the cal over to Hal.

Hal Washburn

Thank you, Greg. Welcome, everyone and thank you for joining us today to discuss our first quarter of 2012. We completed this quarter with consistent operating and financial performance, and we are also very pleased to announce an excellent bolt-on acquisition in the Big Horn Basin, Wyoming, and an increase in our 2012 capital program based on the success of our recent drilling projects in California.

Let me start by discussing a few key quarterly highlights. During the first quarter, we produced 1.987 million Boe of oil and natural gas were 21,800 Boe per day. Our oil and NGL production was 859,000 barrels and our natural gas production was 6.8 Bcf.

Net production on an annualized basis is trending with our guidance range despite seasonal weather related restrictions on our production. Our operations team effectively and efficiently carried out our capital and operating plans during the quarter.

For the first quarter 2012, including realized gains of commodity derivative instruments, oil and NGL sales revenues were approximately $70 million and natural gas sales were approximately $42 million for a total of $112 million.

This is slightly lower than the fourth quarter of 2011, due primarily to the delay of Florida crude oil shipment from late March to the 1st week of April, and lower natural gas sales revenues during the quarter.

As you may recall, unlike most of our properties, crude oil sales from our Florida fields are made in periodic large barge shipments. Although, this shipment included approximately 420,000 net barrels of crude oil that was produced in the first quarter. The sale actually occurred in Partnership’s second quarter. Accordingly the Partnership’s second quarter adjusted EBITDA will include this Florida sale.

EBITDA was $61.4 million for the first quarter down from $64.4 million in the fourth quarter of 2011. We estimate that had the delayed Florida sale occurred in the first quarter would have contributed approximately $5 million of additional EBITDA. In the first quarter our lease operating expenses on annualized basis of $38.1 million were within our guidance range.

Turning to our distributions, we’re very pleased to announce the first quarter distribution of $0.455 per unit or $1.82 on an annualized basis. This represents a 9% increase from first quarter 2011 distributions and further, this marks our eight consecutive quarterly distribution increase.

As we said before, we're well-positioned financially to be an active acquirer in 2012. On April 25th, we announced our third Wyoming acquisition that will grow our key operating area in the Big Horn Basin and increase our exposure to crude oil.

We are acquiring a 100% oil properties in Park County in Wyoming for approximately $98 million from Legacy Energy, Inc., a wholly-owned subsidiary of NiMin Energy Corp.

Wyoming is home to many of our legacy properties and oil producing assets. This is a great bolt-on acquisition where the properties are joining our exciting Big Horn Basin operations, allowing us to leverage our regional operating expertise. The property is mature, have long-live reserves and significant original oil in place. They are great compliment to our asset portfolio. Additionally, we’ve identified numerous infill drilling opportunities that were add to our production growth.

We are targeting $300 million to $500 million in oil and gas acquisition this year and are well-positioned to reach that target. We have a borrowing base of $850 million and we currently have $84 million drawn on the credit facility, given us great flexibility to finance additional acquisitions.

We’ve also been very successful in raising capital. In the last 19 months we’ve raised approximately $267 million in equity and $555 million in long-term high-yield bonds at attractive pricing.

Our proven track record is successfully raising capital, and sourcing and closing acquisitions leaves us well-positioned to accelerate our acquisition activity in the months and years ahead.

Turning briefly to our Greasewood and Cabot acquisitions, we are very pleased to have successfully integrated these assets and see our operating team delivering excellent results from both of them. Mark will provide an update on the Greasewood and Cabot acquisitions later in the call.

As we’ve said before, we continue to focus our capital program on projects that we yield the best economics based on commodity prices. This year we planned to increase our capital program by $19 million or 28% to pursue additional oil drilling opportunities in California, where we had very good recent results and where we also receive very attractive base pricing, which is well above WTI.

We also continue to monitor the positive drilling results from other operators in the Michigan, Utica Collingwood and believe this play could provide significant value for BreitBurn as we have over a 130,000 net acres in the area. Mark will give an update on Utica Collingwood later in the call.

The Partnership’s performance for the first quarter of 2012 reflects the consistent and predictable nature of our business, successful execution of our operating capital plan and our ability to execute on our growth through acquisition strategy. We continue to emphasis consistent cash flow generation to support a strong coverage ratio and distribution growth.

With that, I’ll turn the call over to Randy who will discuss selected results for the quarter and recap our hedging activity. Randy?

Randy Breitenbach

Thanks, Hal. I’ll start by addressing our first quarter commodity hedging activity and provide an overview of the impact of these derivative instruments in our financial results. For the first quarter of 2012, crude oil, natural gas and NGL revenues totaled $94 million, compared to $109.7 million in the fourth quarter of 2011. The decrease was primarily due to lower sales volume from the timing of our Florida sales, lower natural gas prices and natural gas production.

Our hedging activity continues to play integral role in the mitigating commodity price volatilities, particularly with natural gas. Our realized natural gas prices for the first quarter averaged $6.18 per Mcf, compared with Henry Hub natural gas spot prices of $2.44 per Mcf.

On the oil side, average realized crude oil and liquids prices were $90.36 per barrel, compared to NYMEX crude oil spot prices of approximately $102.98 per barrel for the same period.

Brent crude oil spot prices which are an important benchmark for our California oil production averaged $118.71 per barrel in the first quarter of 2011, compared to $109.42 in the fourth quarter of 2011.

Non-cash unrealized losses from commodity derivative instruments for the first quarter were $53.6 million, primarily due to an increase in oil future prices during the quarter, partially offset by a decrease in natural gas future prices.

Consistent with our hedging strategy in the past, we immediately entered into new hedges with the NiMin acquisition. On April 25, 2012, we entered into swaption contract that provide an option to hedge a total of 510,168 barrels of future crude oil production associated with the NiMin acquisition at current NiMin, excuse me, NYMEX WTI market prices ranging from $104.80 per barrel in 2012 to $88.45 per barrel in 2017. These swaption contracts have an exercise date of July 31, 2012.

We continued to opportunistically layer in new hedges, so far in 2012 we’ve extended our commodity protection portfolio hedging approximately 1.8 million barrels of oil product for a period covering 2014 through 2016 at an average price of $95.34 per barrel. Assuming the mid-point of 2012 production guidance is held flat, our production is hedged at 75% in 2012, 74% in 2013, 55% in 2014 and 53% in 2015, and 9% in 2016.

Average annual prices during this period ranged between $92.05 and $101 per barrel of oil, and $5.43 and $7.06 per MMBtu per gas. We will continue to evaluate and opportunistically add to our hedging portfolio in the future.

An updated presentation of the Partnership’s commodity price protection portfolio, as of May 7, 2012 will be made available in the Events and Presentations section of the Investor Relations tab on our website.

With that, I’ll turn you over to Mark Pease who will provide you with additional details of our operating performance. Mark?

Mark Pease

Thank you, Randy. I’ll run the results at the Partnership level and then discuss some of the details by division. In the first quarter, we produced about 2 million barrels of oil equivalent or 21,800 barrels of oil equivalent per day, which is within our 2012 guidance range.

Production was about 3% below the prior quarter, primarily due to weather related downtime in Michigan and Wyoming, and some mechanical downtime in Florida. First quarter 2012 production was up 21%, compared to first quarter 2011 production of approximately 18,100 barrels of oil equivalent per day.

The production split for the quarter was approximately 43% crude oil and NGLs, and 57% natural gas. With the recently announced NiMin acquisition and the increased capital spending on California oil projects, we expect to exit the year with production evenly balanced between crude oil and natural gas.

We continued to focus our capital program on projects that deliver the best return to the company based on current commodity prices, having a portfolio of assets with both oil and natural gas opportunities, allows us to do that. As such, the capital budget for 2012 is focused primarily on oil projects.

Capital expenditures from our oil and gas activities in the first quarter were $16.1 million, which is consistent with the midpoint of our original guidance for capital expenditures of about $68 million.

As Hal mentioned earlier, we have recently increased our estimated 2012 capital expenditures by $19 million for additional oil well drilling in our Santa Fe Springs Field in California.

We are presently drilling in Santa Fe Springs and the added funds will allow our continuous drilling program into the middle of the fourth quarter. These oils are 100% oil and have very strong economics at current oil prices. Excluding acquisitions, we expect midpoint capital spending to be approximately $87 million for the year.

For the first quarter, lease operating expenses including processing fees and transportation expenses were $38.1 million or $19.60 per barrel oil equivalent, which is below the midpoint of our guidance range. This is up about 4% from the $18.44 per Boe in the fourth quarter of 2011.

The increase is primarily due to higher winter operating costs, but the costs of services and materials are also being pressured by the continuing strong commodity price for oil. For the full year, excluding acquisitions, we expect to be about in the middle of our guidance range for lease operating cost.

Now, let’s discuss the first quarter performance of our two operating divisions. Production in the Northern Division, which consists of Michigan, Wyoming, Indiana and Kentucky, averaged about a 100 million cubic feet equivalent per day. This is down about 3.7% from prior quarter’s production of 103.9 million cubic feet equivalent per day.

Drop in production is mainly due to winter weather in our northern locations and natural decline of the fields. First quarter per unit lease operating expenses for the Northern Division were 11% higher than the prior quarter, due to the winter weather and the slightly lower produced volumes.

Capital spending in the Northern Division for the first quarter totaled $4 million and consisted of three drill wells, five workovers and one facility optimization project. The program added incremental net production of about 260 barrels of oil per day and 300 Mcf per day.

In the Southern Division, which includes California and Florida, first production averaged approximately 5,175 barrels of oil equivalent per day, which was up slightly compared to fourth quarter 2011 production of approximately 5,130 barrels of oil equivalent per day.

Lease operating expenses for the quarter averaged $36.07 per Boe, which was about 6% lower than last quarter’s average of $38.63 per Boe. Expenses for the quarter were lower, primarily due to lower fuel consumption and lower repair and maintenance costs in Florida.

Capital spending in the Southern Division for the first quarter totaled $12.1 million, slightly higher than forecast due to faster drilling in Florida. Spending for the quarter consisted of two drills wells in Florida and one drill well in Oklahoma -- one drill well in California. The one well that was completed during the quarter added net initial production of about 140 barrels of oil per day. Two of the wells were still drilling at the end of the quarter.

Now, I’d like to give an update on the Greasewood and Cabot acquisitions we made in Wyoming last year. We have successfully integrated these two acquisitions and are pleased with the results

The Greasewood field in Eastern Wyoming is exceeding our forecast. Three new drill wells were completed in the quarter, with 30-day initial drill gross production of over 300 barrels of oil per day, double what was forecast. A 3D seismic shoot, additional drilling and water flood enhancement are planned later in the year for this field.

The Southwest Wyoming properties purchased from Cabot late last year are performing at forecast and we are preparing the development opportunities for when gas prices increase.

I’d like to now turn to the acquisition of the oil properties in the Big Horn Basin in Wyoming that we announced on April 25th. This is our third acquisition in Wyoming in the last nine months. We are very excited to add a great bolt-on acquisition in a region where we have a significant presence.

The properties produced 100% oil, have long remaining lives and have significant oil remaining in place. The total net acreage position is 3,200 acres and is predominantly held by production.

Since the properties are close to our existing Big Horn operations, we plan to leverage our team that currently works the area and begin developing the numerous infill drilling locations later this year. The properties are 100% operated, with an average working interest greater than 90% and they produced approximately 600 barrels of oil per day net in March.

We believe this acquisition is a great compliment for our existing asset portfolio and we’ll provide meaningful production growth, adding to our cash flow generation. As Hal mentioned earlier, we are targeting $300 million to $500 million in acquisitions this year. As we speak, we are actively seeking new opportunities in line with our growth through acquisition strategy.

As mentioned in our last earnings call, we continued to monitor the activity in the Collingwood Utica where we hold more than 130,000 net acres that are primarily held by production.

Encana’s two horizontal drill wells completed last quarter continue to produce the sales, but there is no production update from what was given in the last earnings call. Encana’s plans are to continue the testing and development of the play.

Also in Northern Michigan, the A-1 Carbonate, which is a liquids rich play is being tested by Devon. They plan to drill approximately 15 wells in 2011 and 2012. We are excited about this activity in Michigan and continue to monitor the developments.

With that, I’ll turn the call over to Jim.

Jim Jackson

Thank you, Mark. Total revenues including unrealized gains and losses recorded during the period were $59.1 million in the first quarter. Our first quarter revenues included $17.6 million in realized gains on commodity derivative instruments and $53.6 million in non-cash unrealized losses on commodity derivative instruments.

We recorded a net loss of $50 million or $0.76 per diluted common unit for the first quarter 2012, as compared to a net loss of $30.3 million or $0.51 per diluted common unit in the prior quarter. The increase in net loss compared to the fourth quarter of 2011 was primarily due to lower revenues related to crude oil and gas sales.

As Randy mentioned, oil and natural gas sales revenues including realized gains and losses on commodity derivative instruments were $111.6 million in the first quarter of 2012, down from $117.6 million in the fourth quarter of 2011.

As Hal explained, the decrease was primarily due to the delay of Florida crude oil shipment from late March to the first week of April and lower natural gas sales revenue during the quarter.

General and administrative expenses excluding non-cash unit-based compensation expense were $8.1 million or $4.07 per Boe in the first quarter of 2012, versus $9.5 million or $4.59 per Boe in the fourth quarter of 2011. General and administrative expenses for the quarter were within our 2012 guidance range.

First quarter adjusted EBITDA was $61.4 million, down slightly from the prior quarter adjusted EBITDA of $64.4 million. The decrease was largely due to the timing of the crude oil sales in Florida, as mentioned earlier and lower natural gas sales revenues.

As Hal mentioned, we estimate that had the delayed Florida sale occurred in the first quarter, it would have contributed approximately $5 million of additional EBITDA.

Production and property taxes totaled $7.6 million in the first quarter, down from $7.9 million in the fourth quarter of 2011, primarily due to lower severance taxes in Wyoming and Michigan.

Net interest and other financing costs, excluding realized and unrealized gains and losses on interest rate swaps were $13.8 million in the first quarter of 2012, compared to [$9.3] 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 $13 million in the first quarter of 2012 as compared to $10.4 million in the prior quarter. Both the increase in net interest and cash interest expense were primarily due to the addition of new senior notes earlier this year.

Let me briefly talk about our equity and debt offerings that were completed this quarter. On February 8 of 2012, the Partnership completed a public offering of 9.2 million common units. In addition, on January 13, 2012, the Partnership completed a private offering of $250 million in aggregate principal amount of [7.875%] notes due 2022.

The net proceeds from both transactions were used to reduce borrowings under the Partnership’s bank credit facility and further increase our financial flexibility to pursue additional acquisition opportunities.

As for our liquidity, our outstanding debt balance as of March 31, 2012 was approximately $634 million and consisted of borrowings of $85 million under our credit facility and approximately $549 million in senior notes. This includes $6.3 million in unamortized discount on the senior notes.

As of May 7, we had $84 million in total borrowings outstanding under our credit facility. Effective April 6, 2012, the Partnership’s borrowing base under the existing credit facility was increased to $850 million from $788 million. The Partnership currently has approximately $766 million of undrawn capacity under its credit facility, which does not expire until May of 2016.

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

Question-and-Answer Session

Operator

(Operator Instructions) We will take our first question from John Ragozzino of RBC Capital Markets.

John Ragozzino – RBC Capital Markets

Good morning, gentlemen.

Hal Washburn

Good morning, John.

John Ragozzino – RBC Capital Markets

I just want to talk about the CapEx a little bit more. So you gave the initial guidance back in the 20th of February, it’s up to $87 million now. But you had done a $98 million deal in between them. Is there no additional spending been planned for the Wyoming Properties or is this all just going to California?

Hal Washburn

It’s all going to California as we say right now, John. I mean, we’ve done -- we’ve done drilling in Santa Fe Springs fields every year for the last eight or nine years and we monitored those results very closely. And we’ve had excellent results and with current commodity prices are, we wanted to put more money they are -- they are very predictable results and the economics were very strong in today’s prices.

Jim Jackson

John, you should expect us to update guidance once we know when we’re going to close this acquisition. And we’ve developed our capital spend program forward because it will be some infill drilling in the acquisition but at this point, we haven’t -- we don’t know the last closing date. So we’re not updating guidance at this point.

John Ragozzino – RBC Capital Markets

That makes sense. Thank you. And talking a little bit more about the Big Basin -- Big Horn Basins, can you just give a little bit more color on how this deal came about and then talk specifically about the potential for the upside and when it comes to down spacing. My understanding is that NiMin had a lot of really good results out there in the past and if you could give us a little more color, it would be great?

Hal Washburn

Sure. We -- when small group looking at this transaction fit perfectly for us just because the fields lie in, really kind of right in amongst our operations where we have very strong team and we’ve been actively operating. We have a very good knowledge and understanding of these fields. And we believe that the potential that they’ve shown is -- they've show has been good as you’ve commented and we had a lot of potential going forward.

The reserve numbers you’ve seen in the disclosures don’t include too much in the way of down spacing. However, we do think that potential exists.

Mark Pease

If I could, make one more comment. This is Mark. When we compare the fields that we bought was the NiMin acquisition to our existing fields out there. They have drilled on a much larger spacing. We believe there is, as Hal said, down spacing opportunity out there.

John Ragozzino – RBC Capital Markets

Great. Thank you. Now, just turning to the balance in the hedge book, if you target $300 million to $500 million deals that are so far annually or so. Just given what the hedge book looks like, is there a distinct preference for more oily asset packages? Are you trying to make that push towards, just getting away from the stigma of having a gas levered company?

Hal Washburn

Well, basically as you would expect, we’re somewhat a different. Again, we are buying cash flows and to the extent that we can get a gas property across the finish line that is accretive. Using current features curve than we really don’t have a strong preference but I do hear what you’re saying our mix on properties are slightly skewed towards gas now. It’s nice to keep it closer to 50, 50, with NiMin acquisition, it pushes us even closer to the 50, 50 reserve numbers.

But again, I think just overall, we’re looking at acquisitions that we think have significant potential, not necessarily gas or oil.

John Ragozzino – RBC Capital Markets

Understood.

Randy Breitenbach

One thing, John, one of the point and we noted it in the call, with the NiMin acquisition and increased spend in California, we expect to be at about 50, 50 by year-end on oil and gas.

John Ragozzino – RBC Capital Markets

Okay. Thanks. I just got one more. This is to both Randy and Hal and again may be coming across the wrong way, I just -- I think it’s kind of employing bad people here just from yourself as oppose to some of our guys. My question is between the management of BreitBurn, your responsibilities that Pacific Coast Energy, the recent offering of our IT and everything else, you guys have got going on in your plates, please talk a little bit about how you manage your priorities everyday and specifically in the context of ensuring BreitBurn unitholders that they are not at disadvantage?

Hal Washburn

Sure John. And if you look back to when we did the IPO in 2006, we split the business at that point in the two sets of properties, one February, well into the MLP and one set of properties, we didn’t. So from day one, we’ve been running these two separate businesses. The properties that are in PCOT continue to have significant development requirements, each capital requirements that’s why they don’t fit in BBEP, they did in 2006, they don’t today.

We focus very hard on running both sides of the business and we’re very focussing on both Pacific Coast and BBEP and continue to operate them. We believe efficiently, effectively as we have for the last six years.

Randy Breitenbach

I would further that by saying drilling no real significant changes in what we’ve been doing for the past six years, what we did do is spin-off a portion in (inaudible) but it’s a passive trust. It’s not an MLP type trust.

Albeit we believe the performance is what will be significant and it really shouldn’t impact 1,000 mines time but I also would say that you’ve seen that I’m at the President position at BBEP and that is a step back slightly in responsibility. Similarly, Hal has taken that same position at PCEC. So there is some separation of responsibility whose held more accountable but all -- I don’ think there is a significant change anywhere.

John Ragozzino – RBC Capital Markets

Thanks very much guys. I appreciate it.

Mark Pease

John, this is Mark. I’ll tell you from an operational standpoint, there are just other groups of fields for us. So we just work right across them.

John Ragozzino – RBC Capital Markets

Excellent. Thanks a lot.

Hal Washburn

Sure.

John Ragozzino – RBC Capital Markets

Thank you.

Operator

And we will take our next question from Bernie Colson, Global Hunter.

Bernie Colson – Global Hunter

Hi Burn.

Hal Washburn

Good morning Bernie.

Bernie Colson – Global Hunter

On the additional LA drilling, it doesn’t seem like the environment is much different now than it has been. So just wondering what change of thinking and what’s driving that?

Hal Washburn

Bernie, one of the things to keep in mind is that we do receive a pretty significant premium to WTI based on where Brent trades today on all of our California cruise priced against the marginal water borne barrels. So the economics on all drilling projects are very robust and we basically, in response to, for gas prices over the last six months really focussed our engineering and geologic and geoscience efforts on the oilfields. So we spent more time looking at the oil properties and less time looking at the gas properties. So we had more resources allocated.

Randy Breitenbach

And a little bit down in the details Bernie, but we had very, very good results from our program in 2011. We changed our completion methodology slightly there that we think contributed to those results, so a combination of that plus we’ve done some things out there to increase our infrastructure, increase our electrical capacity which powers the equipment, also increase our water handling capacity which handles our injection water. So there’s a lots of things but we’re excited to get all that in place and get additional wells ready to go.

Bernie Colson – Global Hunter

Okay. And then, secondly, I was hoping you could talk about the seasonal -- sorry -- about the seasonal production to clients, I mean, if you rewind a year ago, we were down, kind of, sequentially in the same percentage range and it just seems like the winters were so different that we were trying to, kind of, figure out what the nuances now, how we should expect that seasonality to work in the future?

Mark Pease

This is Mark. It’s not always the case but almost always. When you start working in Northern Michigan and in Wyoming in the winter, it is just difficult to keep the same amount of uptime if you will in all your facilities in oil which you have in the summer, so not always but usually.

The first quarter, we have a decline in production due to freeze offs and cold weather and trying to get drilling rigs move around and work over rigs move around. I mean, that’s really what you’re seeing there. It’s just not easy to get things done and keep gas wells unfrozen, those type of things.

Hal Washburn

I mean, I think you should expect that going forward whether the winters are severe like they were the year before or mild this year. One thing we just don’t schedule as much in the winter. You can’t tell in advance what the winters are going to be like and so you just don’t plan to do as much. And so that has just a kind of impact, it’s always going to be there.

Bernie Colson – Global Hunter

Okay. Yeah. That’s really helpful. And then last one for me is, are you guys -- I know you were -- kind of the goal for 2012 was the distribution of 8% to 10%. And clearly, it is a bit of deceleration in your sequential increase, just wondering if you are sticking to that goal or what that looks like.

Hal Washburn

Bernie, I mean, our goal is to be at the top of the group in distribution growth. And I think it took 8% to 10% last year. This year our goal is to be at the top. We can get 8% to 10% that would be fantastic with gas prices where they are. You know, that’s going to require some good acquisitions to get there but our goal is to be at the top.

Bernie Colson – Global Hunter

Okay. All right. Thank you.

Operator

And we will take our next question from Ethan Bellamy of Baird.

Ethan Bellamy – Baird

Hi, guys. Few questions for you. I know NiMin has some other properties in the same San Joaquin Basin. Did you look at those and potentially buying all of NiMin and if you like the properties whose valuation an issue, or was tactfully buying C-Corp a more, a bigger impairment?

Hal Washburn

Really, we look at California properties, it’s a fire flood. It’s something we weren’t comfortable with technically and we decided to pass. So we didn’t even get into valuations. We just decided it wasn’t something that would fit very well for us.

Ethan Bellamy – Baird

Okay. I guess more broadly and just you, kind of, continue that being one of the things, Hal, that you talked about in the breakout session, the IPAA was a lot of work been done by service providers that potentially try to mitigate that tax leakage of MLP buying a C-Corp. Should we put you guys in camp of potentially looking out of bigger acquisition that might be in C-Corp form?

Hal Washburn

I have got pages and pages of ways to do it. But it’s not particularly efficient, but the arbitrage is pretty significant, especially with some of these beaten down C-Corps. So we look at it. There is a lot of tax leakage but if you can make the economics work on an aftertax basis, it’s something that’s attractive. The opportunities are out there. So, property deals are a lot easier that now if we have the right opportunity in C-Corp -- we’ll certainly look at it.

Ethan Bellamy – Baird

Okay. And then with respect to the ranges on the targeted acquisitions and obviously, that $500 million number is a pretty big number. Can you kind of handicap the probability of getting to that top end $500 million, and if so what you think it might be like or would it be a series of $100 million deals or is that at the top end of the range predicated on one big $200 million or $300 million acquisition?

Hal Washburn

It’s certainly easier to do, if you’re having one big deal. We’ve really good at the deals though in this kind of $50 million to $150 million range and in that scenario, that’s really sweat spot for us. So, in all likely you’ll see a series of those source of deals and we can get $500 million at the outstanding year for us. We feel very comfortable that we’ve got enough opportunities to get to $300 million level. So we’ve got a great team. We’re seeing a lot of deals. We’re evaluating a lot of deals and we’re confident that the deals flows out there and we can make the deals get into five to stretch but we feel comfortable with $300 million this year.

Ethan Bellamy – Baird

Okay. Some questions on Florida. Can you give us a sense for the frequency of the marine shipping out of Florida? I’m trying -- just trying to understand how lumpy be the cash flows are going to be and if this issue on the revenue recognition is going to pop-up in a later quarter?

And then after that, with the production coming out of Florida, what if any extra challenges or risks does hurricane activity present you there and as the infrastructure and production capability robust against storm activity?

Mark Pease

Okay. This is Mark. First question about frequency, we did a shipment about once every two months. And we try to time them, just so we don’t have to go through all explanation that we just did. We try to time and so we get it in, of course, through the end of the quarter. They don’t always work out that way.

So we are always balancing that question of should we do a parcel shipment that’s maybe a little bit more expensive for barrel and we try to avoid doing that. So balance every -- other months to answer that question.

As far as the hurricane, these fields have been down there since -- well the new wells have been down there since the mid 90s. The fields were recovered back in the 70s. We’ve been drilling out there now for more than two years straight. And we certainly have -- when storms come, we batten things down and get ready for. But we haven’t had any issues with them. I mean not to say that we can’t but we haven’t had. And they are very -- it’s conventional facilities with tank battery and what not.

So I mean the guys know how to get ready for those things when they come and so far, it haven’t been an issue.

Ethan Bellamy – Baird

Okay. Jim, one housekeeping question, when do you expect to file the Q, please?

Jim Jackson

Ethan, it’s Jim. We’ll file -- we expect to file the Q tomorrow.

Ethan Bellamy – Baird

All right. Thanks so much.

Jim Jackson

Thank you.

Operator

And we will take our next question coming from Kevin Smith of Raymond James.

Kevin Smith – Raymond James

Hi. Good afternoon.

Hal Washburn

Hi, Kevin.

Mark Pease

Kevin.

Kevin Smith – Raymond James

Give a feel for the timing at the increase CapEx, whether, quarters, it should hit and when should we see maybe a boost in production?

Mark Pease

Yeah. Kevin, this is Mark. We actually had three wells in California in our regional budget, and we are on our second well right now. And these aren’t very long wells. That wells would take 10 days or couple of week. So we’re actually -- we keep the rig running. So here in an about a month, you’ll start seeing the impact of that additional CapEx. And then the wells are come on pretty quickly after we drill them down.

Each well in and of itself is not a big -- huge wells. But cumulative by the end of the year, we have an additional 11 wells on. They should be a few 100 barrels a day over and above how we would execute at the year.

Kevin Smith – Raymond James

Got you. There is 11 addition to the three you are modeling. So 14 total to say, accurate?

Mark Pease

That’s correct.

Kevin Smith – Raymond James

Got you.

Mark Pease

And we’re looking hard to see if we can keep that rig busy all year. We are just not quite there yet.

Kevin Smith – Raymond James

Okay. When would you have to lay down that rig based off of your current joint plan?

Mark Pease

But right now, we are looking at mid-ish October.

Kevin Smith – Raymond James

Thank you. And then one other question, you mentioned I guess in your prepared remarks that you put on the well in California, Florida that added 140. Was that from California?

Mark Pease

No. That was well and the West Felda field in Florida.

Kevin Smith – Raymond James

Got you. Is it horizontal well?

Mark Pease

Yeah, sir.

Kevin Smith – Raymond James

Okay. All right. That answers all my questions. Thank you.

Mark Pease

Thank you.

Operator

(Operator Instructions) We will take our next question from Michael Blum of Wells Fargo.

Michael Blum – Wells Fargo

Hi. Good morning, everyone.

Hal Washburn

Good morning.

Michael Blum – Wells Fargo

Just another question on the wells in California, you mentioned the returns are pretty good. Can you provide any numbers around that, what does returns look like?

Hal Washburn

Today’s price is greater than a 100%.

Michael Blum – Wells Fargo

I guess balance for the year. Can you -- my other question was on your hedge book, what is your thought these days in terms of adding additional hedges on the natural gas side. Obviously, your current hedges are well-above market. Are you comfortable of today’s strip adding gas hedges and if not, where does that strip need to get to for you start liking into additional hedges there?

Hal Washburn

Yeah. I mean of course, Michael, we are open to layering in some additional gas hedges. We would like to -- how this exposure to what we hope to be a long-term upward trend in gas prices. I mean if we believe again, I hate to put too much credence on forecasters, but I mean you had roughly come out a couple weeks ago saying gas will be $7.50 by December.

Obviously, I think it’s easily on the optimistic side. But there are fundamentals that could drive that the extra supply and demand dynamics differently than what we’ve seen. I mean we’ve been hit heavily with the combination of forced, drilling. I know, other really fundamental economics as well as incredible over supply and a ridiculously warm winter. And you, kind of, had everything hit at the same time, and you don’t want to. You don’t necessarily want to lock-in long-term prices when you are at the lower end of the price well.

But obviously, we have the benefit of being very well hedged this year and even greater percentage of our production is hedge in 2013. So we have some time to sit and work through this. But at some point, we are going to have to lock some of these down. So we understand where we are and what are our future cash flow, and distributable cash flow requirements will be.

Michael Blum – Wells Fargo

Sure.

Mark Pease

And Michael, one other thing I know we talked about this, New York but, in a way we present the hedge going forward is based on holding production flat at the mid point for this year’s guidance.

Obviously, with our capital program being focused on oil, you are going to see oil production growing. You are going to gas production naturally coming down somewhat. So we actually have a higher percentage hedge in future years and you probably see just looking at the presentation just given the convention news by us and by all that appears.

Michael Blum – Wells Fargo

Got it. Thank you, guys.

Hal Washburn

Thank you.

Operator

There are no further questions. Mr. Washburn, I’ll turn the call back over to you for any closing remarks.

Hal Washburn

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

Operator

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

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